HighPeak Energy, Inc. (Form: 10-K, Received: 03/15/2021 17:12:27)

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

Presentation. The accompanying consolidated and combined financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). In the opinion of management, all adjustments, consisting of normal and recurring accruals considered necessary for a fair presentation, have been included. Certain prior period amounts have been reclassified to conform to the current presentation on the accompanying consolidated and combined financial statements. In connection with the preparation of the consolidated and combined financial statements, the Company evaluated subsequent events after the balance sheet date of December 31, 2020, through the date of this report.

The accompanying consolidated and combined statement of operations and the consolidated and combined statement of cash flows for the period from January 1, 2020 through August 21, 2020 are those of HPK Energy, LP, a Delaware limited partnership ("HPK LP") which is the predecessor to HighPeak Energy prior to the HighPeak business combination between the Company, Pure and HPK LP that closed on August 21, 2020 (the “HighPeak business combination”). The accompanying consolidated and combined statement of operations and consolidated and combined statement of cash flows for the year ended December 31, 2019 are those of HighPeak Energy, LP, a Delaware limited partnership ("HighPeak I") which is the predecessor to HPK LP prior to the HPK LP business combination that closed on October 1, 2019 (the “HPK LP business combination”) and those of HPK LP from October 1, 2019 through December 31, 2019. HPK LP and HighPeak I are individually and collectively referred to as the "Predecessors" herein. However, if we refer to the "Company" for a date or activity prior to August 21, 2020, we are also referring to the Predecessors. See Note 10 for further information regarding the two aforementioned business combinations. The following table details the year ended December 31, 2019 and its components of individual line items and how they were combined for presentation on the face of the accompanying financial statements.

	Predecessors for the Year Ended December 31, 2019
(in thousands)	HPK LP from August 28, 2019 (Inception) through December 31, 2019			HighPeak I for the Year Ended December 31, 2019			Eliminations			Combined Year Ended December 31, 2019
Operating Revenues:
Crude oil sales	$	3,695		$	4,154					$	7,849
Natural gas and NGL sales		163			103						266
Total operating revenues		3,858			4,257						8,115
Operating Costs and Expenses:
Oil and natural gas production		1,578			1,794						3,372
Production and ad valorem taxes		188			261						449
Exploration and abandonments		33			2,817						2,850
Depletion, depreciation and amortization		1,612			2,657						4,269
Accretion of discount on asset retirement obligations		34			38						72
General and administrative		6,159			2,523						8,682
Total operating costs and expenses		9,604			10,090						19,694
Loss from operations		(5,746	)		(5,833	)					(11,579	)
Equity in losses of affiliate		-			(3,175	)		3,175			-
Net loss	$	(5,746	)	$	(9,008	)	$	3,175		$	(11,579	)



CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(5,746	)	$	(9,008	)	$	3,175		$	(11,579	)
Adjustments to reconcile net loss to net cash provided by (used in) operations:
Exploration and abandonment expense		33			2,817			-			2,850
Depletion, depreciation and amortization expense		1,612			2,657			-			4,269
Accretion expense		34			38			-			72
Equity in loss off affiliate		-			3,175			(3,175	)		-
Changes in operating assets and liabilities:
Accounts receivable		(1,355	)		1,425			-			70
Inventory and other current assets		(88	)		(121	)		-			(209	)
Accounts payable and accrued liabilities		3,010			745			-			3,755
Net cash provided by (used in) operating activities		(2,500	)		1,728			-			(772	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and natural gas properties		(45,318	)		(15,687	)		-			(61,005	)
Changes in working capital associated with oil and natural gas property additions		19,097			5,585			-			24,682
Acquisitions of oil and natural gas properties		(2,456	)		(8,462	)		-			(10,918	)
Investment in affiliate		-			(7,796	)		7,796			-
Issuance of notes receivable		(4,193	)		-			-			(4,193	)
Net cash used in investing activities		(32,870	)		(26,360	)		7,796			(51,434	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Contributions from partners		58,081			23,738			(7,796	)		74,023
Net cash provided by financing activities		58,081			23,738			(7,796	)		74,023
Net increase (decrease) in cash and cash equivalents		22,711			(894	)		-			21,817
Cash and cash equivalents, beginning of period		-			894			-			894
Cash and cash equivalents, end of period	$	22,711		$	-		$	-		$	22,711

See Note 10 for information regarding the HighPeak business combination and the HPK LP business combination and how they were accounted for in the accompanying financial statements.

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 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 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 oil and gas properties and evaluations for impairment of proved and unproved oil and gas properties, in part, is determined using estimates of proved, probable and possible oil and 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 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 oil and natural gas properties, asset retirement obligations, equity-based compensation 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. The Company’s accounts receivable are primarily comprised of oil and gas sales receivables, a current U.S. federal income tax receivable, joint interest receivables and other receivables for which the Company does not require collateral security. The Company’s share of oil and gas production is sold to various purchasers who must be prequalified under the Company’s credit risk policies and procedures. The Company records allowances for doubtful accounts based on the age of accounts receivables and the financial condition of its purchasers. 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.

As of December 31, 2020 and 2019, the Company’s accounts receivables primarily consist of amounts due from the sale of crude oil, natural gas and natural gas liquids of $4.2 million and $2.9 million, respectively, and are based on estimates of sales volumes and realized prices the Company anticipates it will receive, a current U.S. federal income tax receivable of $3.2 million and zero, respectively, related to U.S. federal income taxes paid prior to the HighPeak business combination that will be received by carrying back and utilizing the net operating losses generated from August 22, 2020 through December 31, 2020, and joint interest receivables of $345,000 and $440,000, respectively. 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 December 31, 2020 and 2019, the Company had no allowance for doubtful accounts recorded.

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 are issued or available to be issued. Prior to December 31, 2020, 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.

Notes receivable. Pursuant to an agreement between HPK LP and Pure, whereby Pure obtained extensions to complete its initial business combination to August 21, 2020, HPK LP made loans to Pure totaling $11.7 million and $4.2 million as of August 21, 2020 and December 31, 2019, respectively. The Company routinely reviews outstanding balances and establishes allowances for bad debts equal to the estimable portions of notes receivable for which failure to collect is considered probable. As of December 31, 2019, the Company had no allowance for doubtful accounts recorded. See additional information regarding Pure and the notes receivable cancellations in relations to the HighPeak business combination in Note 10.

Deposits. During 2019, HPK LP paid $61.5 million to Grenadier Energy Partners II, LLC (“Grenadier”) as a non-refundable deposit for an acquisition (the “Grenadier Acquisition”) and an additional $15.0 million extension payment was paid in 2020 that was to be accounted for as additional consideration for the Grenadier Acquisition upon closing. The Grenadier Acquisition was terminated in April 2020 and the $76.5 million in deposits and extension payments were charged to expense. In addition, the Company has paid the Texas Railroad Commission $50,000 in lieu of a plugging bond as statutorily required.

Inventory. Inventory is comprised primarily of oil and gas drilling or repair items such as tubing, casing, proppant used to fracture-stimulate oil and gas wells, water, chemicals, operating supplies and ordinary maintenance materials and parts. The materials and supplies inventory is primarily acquired for use in future drilling operations 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 December 31, 2020 and 2019 is $120,000 and $184,000, respectively, and the Company has not recognized any valuation allowance to date.

Oil and gas properties. The Company utilizes the successful efforts method of accounting for its oil and 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 5 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 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 and charged, respectively, to accumulated depletion, depreciation and amortization, 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 oil and 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 oil and 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. During the period from August 22, 2020 to December 31, 2020, the Company recognized an impairment of $4.8 million related to various leasehold costs that the Company was not successful in obtaining extensions on that is included in exploration and abandonment expenses in the accompanying consolidated and combined financial statements.

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 $237,000 and $46,000 as of December 31, 2020 and 2019, respectively, are as follows:

	Successor		Predecessors
	December 31, 2020		December 31, 2019
	(in thousands)
Land	$	725	$	580
Information technology		292		459
Transportation equipment		41		-
Leasehold improvements		24		37
Field equipment		10		12
Total other property and equipment, net	$	1,092	$	1,088

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.

Debt issuance costs. In December 2020, the Company paid $405,000 in debt issuance costs related to its new revolving credit facility. Amortization of $4,000 based on the straight-line method over the term of the credit facility which approximates the interest rate method was recognized in 2020 and included in interest expense on the accompanying statement of operations. 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 credit facility was undrawn at the time. In the future, these net costs will be included with long-term debt, if any, in accordance with GAAP. See Note 6 for additional information regarding the Company’s new 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 not recorded as lease right-of-use assets and liability. See Note 9 for additional information.

Accounts payable and accrued liabilities. Accounts payable and accrued liabilities as of December 31, 2020 and 2019 totaled approximately $22.4 million and $31.0 million, respectively, including trade accounts payable, 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 7 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 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 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 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 oil and natural gas marketing contracts is typically received from the purchaser one to two months after production. At December 31, 2020 and 2019, the Company had receivables related to contracts with purchasers of approximately $4.2 million and $2.9 million, respectively.

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

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 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 12 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 options (“Equity 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 Equity 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 directors with no restrictions thereon, as was the case with the 62,500 shares issued in November 2020 to the non-management directors, is measured at the grant date using the fair value of the award and is recorded as stock-based compensation in the accompanying financial statements immediately. If restricted stock is awarded to employees or directors in the future, as the case may be, stock-based compensation will be recognized on a straight-line basis over the requisite service period of the respective award.

Segments. Based on the Company’s organizational structure, the Company has one operating segment, which is 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 oil throughout the world and when combined with pressures on the global supply-demand balance for oil and related products, resulted in significant volatility in 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 oil demand, which negatively impacted the Company's results of operations and led to a significant reduction in the Company's 2020 capital activities.

Adoption of new accounting standards. In February 2016, the FASB issued Accounting Standards Update ("ASU") 2016-02, "Leases (Topic 842)" ("ASC 842"), which supersedes the lease recognition requirements in ASC 840, "Leases" ("ASC 840"), and requires lessees to recognize lease assets and lease liabilities for those leases previously classified as operating leases. The Company adopted ASC 842 as of August 22, 2020 using the modified retrospective transition method. The Company elected to apply the transition guidance under ASU 2018-11, "Leases (Topic 842) Targeted Improvements," in which ASC 842 is applied at the adoption date, while the comparative periods will continue to be reported in accordance with historic accounting under ASC 840. This standard does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained.

ASC 842 allowed for the election of certain practical expedients at adoption to ease the burden of implementation. At implementation, the Company elected to (i) maintain the historical lease classification for leases prior to August 22, 2020, (ii) maintain the historical accounting treatment for land easements that existed at adoption, (iii) use historical practices in assessing the lease term of existing contracts at adoption, (iv) combine lease and non-lease components of a contract as a single lease and (v) not record short-term leases in the consolidated balance sheet, all in accordance with ASC 842.

The adoption of ASC 842 did not have a material impact on the consolidated statements of operations and had no impact on the Company's cash flows. The Company did not record a change to its opening retained earnings as of August 22, 2020, as there was no material change to the timing or pattern of recognition of lease costs due to the adoption of ASC 842.

New accounting pronouncements. In June 2016, the FASB issued ASU 2016-13, "Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments" ("ASU 2016-13"). ASU 2016-13 replaces the incurred loss impairment model with an expected credit loss impairment model for financial instruments, including trade receivables. The amendment requires entities to consider forward-looking information to estimate expected credit losses, resulting in earlier recognition of losses for receivables that are current or not yet due, which were not considered under the previous accounting guidance. The Company has evaluated the ASU 2016-03 and does not believe its adoption will have a material impact on the Company’s consolidated financial statements.

In December 2019, the FASB issued ASU 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes” (“ASU 2019-12”). The amendments in this update remove certain exceptions of Topic 740 including: exception to the incremental approach for intraperiod tax allocation when there is a loss from continuing operations and income or gain from other items; exception to the requirement to recognize a deferred tax liability for equity method investments when a foreign subsidiary becomes an equity method investment; exception to the ability not to recognize a deferred tax liability for a foreign subsidiary when a foreign equity method investment becomes a subsidiary; exception to the general methodology for calculating income taxes in an interim period when a year-to-date loss exceeds the anticipated loss for the year. There are also additional areas of guidance in regards to franchise and other taxes partially based on income and the interim recognition of enactment of tax laws and rate changes. The provisions of this ASU are effective for years beginning after December 15, 2020.

In March 2020, the FASB issued ASU 2020-04, “Reference Rate Reform (ASC 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (“ASU 2020-04”). This ASU provides temporary optional expedients and exceptions to GAAP guidance on contract modifications and hedge accounting to ease the financial reporting burdens of the expected market transition from LIBOR and other interbank offered rates to alternative reference rates, such as the SOFR. Entities can elect not to apply certain modification accounting requirements to contracts affected by reference rate reform if certain criteria are met. An entity that makes this election would not have to remeasure the contracts at the modification rate date or reassess a previous accounting determination. Entities can also elect various optional expedients that would allow them to continue applying hedge accounting relationships affected by reference rate reform if certain criteria are met.

In January 2021, the FASB issued ASU 2021-01, “Reference Rate Reform (Topic 848): Scope” (“ASU 2021-01”). This ASU clarifies that all derivative instruments affected by changes to the interest rates used for discounting, margining or contract price alignment (“The Discounting Transition”) are in the scope of ASC 848 and therefore qualify for the available temporary optional expedients and exceptions. As such, entities that employ derivatives that are the designated hedged item in a hedge relationship where perfect effectiveness is assumed can continue to apply hedge accounting without de-designating the hedging relationship to the extent such derivatives are impacted by the Discounting Transition.

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

NOTE 10. Related Party Transactions

HPK LP Business Combination. Effective October 1, 2019, HighPeak I and HighPeak Energy II, LP (“HighPeak II”) contributed cash and wholly owned subsidiaries, HighPeak Energy Assets, LLC, HighPeak Assets II, LLC and HighPeak Energy Holdings, LLC to HPK LP in return for limited partnership interest in HPK LP. Subsequent to the HPK LP business combination referenced in the preceding sentence and in 2019, HighPeak I contributed an additional $805,000 and HighPeak II contributed an additional $25.8 million in cash to HPK LP. During the period from January 1, 2020 through August 21, 2020, HighPeak II contributed an additional $54.0 million in cash to HPK LP. Also, during the period from January 1, 2020 through August 21, 2020, HPK LP made distributions to HighPeak I and HighPeak II of $2.8 million in total. Therefore, just prior to the HighPeak business combination which closed on August 21, 2020, HighPeak I and HighPeak II owned approximately 51.9% and 48.1% of HPK LP, respectively.

Since HighPeak I is the predecessor to HPK LP, its consolidated statement of operations and consolidated statement of cash flows for the nine months ended September 30, 2019 have been included in the accompanying financial statements for comparative purposes. However, HighPeak II’s results of operations are significant and as such HighPeak II’s consolidated statement of operations is shown below for additional comparative and informational purposes (in thousands).

	Nine Months Ended September 30, 2019
Operating Revenues:
Crude oil sales	$	719
Natural gas and natural gas liquid sales		223
Total operating revenues		942
Operating costs and expenses:
Oil and natural gas production		1,190
Production and ad valorem taxes		59
Exploration and abandonment		756
Depletion, depreciation and amortization		650
Accretion of discount on asset retirement obligations		86
General and administrative		2,891
Abandoned project		1,122
Total operating costs and expenses		6,754
Loss from operations		(5,812	)
Interest income		107
Net loss	$	(5,705	)

HighPeak Business Combination. On August 21, 2020, the Company completed the HighPeak business combination between the Company, Pure, HPK LP, HighPeak I, and HighPeak II. HighPeak I and HighPeak II contributed their partnership interests in HPK LP to the Company in return for 76,383,054 shares of publicly traded common stock of the Company. The table below shows the construction of the beginning balance sheet of the Company on August 22, 2020 upon the closing of the HighPeak business combination (in thousands).

	(a)			(b)			(c)		(d)			(e)			(f)
	HPK LP			Pure			HighPeak Employees, Inc.		Issuance of HighPeak Energy Common Stock			Cash Offering Costs			Deferred Tax Liability			Beginning Balance Sheet on August 22, 2020
Cash and cash equivalents	$	1,943		$	1		$	99	$	92,554		$	(8,114	)	$	-		$	86,483
Accounts receivable		3,001			-			26		-			-			-			3,027
Total current assets		4,944			1			125		92,554			(8,114	)		-			89,510
Total oil and gas properties, net		452,039			-			-		-			-			-			452,039
Other property and equipment, net		436			-			-		-			-			-			436
Total assets	$	457,419		$	1		$	125	$	92,554		$	(8,114	)	$	-		$	541,985
Current liabilities	$	35,794		$	2,025		$	77	$	(9,538	)	$	-		$	-		$	28,358
Deferred income tax liability		-			-			-		-			-			39,946			39,946
Notes payable (receivable)		(11,675	)		11,675			-		-			-			-			-
Asset retirement obligations		2,398			-			-		-			-			-			2,398
Partners' capital		521,682			-			-		(521,682	)		-			-			-
Common stock		-			-			-		9			-			-			9
Additional paid-in capital		-			(13,699	)		48		623,765			(8,114	)		(39,946	)		562,054
Accumulated deficit		(90,780	)		-			-		-			-			-			(90,780	)
Total stockholders' equity/partner's capital		430,902			(13,699	)		48		102,092			(8,114	)		(39,946	)		471,283
Total liabilities and stockholders' equity/partners' capital	$	457,419		$	1		$	125	$	92,554		$	(8,114	)	$	-		$	541,985

	(a)	Represents HPK LP’s condensed consolidated balance sheet estimated as of August 21, 2020.
	(b)	Represents Pure’s condensed consolidated balance sheet estimated as of August 21, 2020 after taking into account: (i) the closing of its trust account, (ii) the redemption of Pure’s Class A Common Stock by the former public stockholders of Pure that elected to redeem, (iii) paying out the cash consideration to those former public stockholders of Pure who elected to remain and (iv) the conversion of the remaining shares of Pure’s Class A Common Stock to HighPeak Energy common stock upon the closing of the HighPeak business combination. The $13.7 million reduction to equity is considered noncash offering costs on the condensed consolidated statement of changes in stockholders’ equity.
	(c)	Represents the balance sheet of HighPeak Energy Employees, Inc which was acquired by the Company for $10.00 upon the closing of the HighPeak business combination.
	(d)	Represents the issuance by the Company of 91,592,354 shares of common stock, 10,538,183 warrants and 10,209,300 Contingent Value Rights upon the closing of the HighPeak business combination. The reduction to accounts payable of $9.5 million represents those vendors of HPK LP that purchased shares under the Forward Purchase Agreement Amendment in the HighPeak business combination in lieu of being paid cash for the majority of their outstanding balances.
	(e)	Represents the cash costs paid for the offering of the aforementioned shares in addition to the cash costs that had previously been incurred by Pure of $13.7 million in column (b).
	(f)	Represents the beginning deferred tax liability of the Company given the combination of all the entities, most of which originated from HPK LP which was a partnership for U.S. federal income tax purposes and therefore did not record a deferred tax liability.

Pursuant to the Business Combination Agreement, among other things, (a) MergerSub merged with and into Pure, with Pure surviving as a wholly owned subsidiary of the Company, (b) each outstanding share of Pure’s Class A Common Stock and Pure’s Class B Common Stock (other than certain shares of Pure’s Class B Common Stock that were surrendered for cancellation by Pure’s Sponsor) were converted into the right to receive (A) one share of HighPeak Energy common stock (and cash in lieu of fractional shares), 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 that exceeded $10.00 per share at the closing, without interest, in each case, totaling approximately $767,902, (ii) one CVR for each one whole share of HighPeak Energy 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 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 common stock held by HighPeak I and HighPeak II being collectively forfeited) and (iii) one warrant to purchase HighPeak Energy common stock for each one whole share of HighPeak Energy common stock (excluding fractional shares) issued to holders of Pure’s Class A Common Stock pursuant to clause (A), (c) the HPK Contributors (A) contributed their limited partner interests in HPK LP to the Company in exchange for HighPeak Energy common stock and the general partner interests in HPK LP to a wholly owned subsidiary of the Company 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 were cancelled in connection with the closing of the HighPeak business combination and (d) following the consummation of the foregoing transactions, the Company 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.

HighPeak I and HighPeak II collectively received 76,383,054 shares of HighPeak Energy common stock pursuant to the Business Combination Agreement. Further, certain of the Company’s executive officers and directors received the consideration provided by the HighPeak business combination through their ownership of Pure’s Class A Common Stock. Steven W. Tholen, the Company’s Chief Financial Officer received 5,000 shares of HighPeak Energy common stock, 5,000 CVRs and 5,000 warrants in exchange for shares of Pure’s Class A Common Stock owned by him prior to the HighPeak business combination. Michael L. Hollis, the Company’s President and member of the Company’s board of directors (the “Board”), received 16,802 shares of HighPeak Energy common stock, 16,802 CVRs and 20,382 warrants in exchange for shares of Pure’s Class A Common Stock and Pure’s warrants, respectively, owned by him prior to the HighPeak business combination. Further, Rodney L. Woodard, the Chief Operating Officer of the Company, received 14,000 shares of HighPeak Energy common stock, 14,000 CVRs and 14,000 warrants in exchange for shares of Pure’s Class A Common Stock and Pure’s warrants, respectively, owned by him prior to the HighPeak business combination.

Unaudited Pro Forma Operating Results. The following unaudited pro forma combined financial information has been prepared as if the HighPeak business combination and the HPK LP business combination had taken place on January 1, 2019. The unaudited pro forma consolidated financial information has been prepared using the reverse merger business combination method of accounting in accordance with GAAP. The information reflects pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable and the estimated tax impacts of the pro forma adjustments.

The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the business combinations taken place on January 1, 2019; furthermore, the financial information is not intended to be a projection of future results (in thousands, except per share amounts).

	(Unaudited Pro Forma) Year Ended December 31,
	2020			2019
Total revenues	$	24,623		$	9,057
Net income attributable to Common Stock		(23,310	)		(8,838	)
Basic and diluted net loss per share		(0.25	)		(0.10	)

Contingent Value Rights. At the closing of the HighPeak business combination, the Company entered into the Contingent Value Rights Agreement (the “CVR Agreement”) by and among, the Company, Pure’s Sponsor, HighPeak I, HighPeak II (together with HighPeak I, the “CVR Sponsors”) and Continental Stock Transfer & Trust Company, in its capacity as Rights Agent (the “Rights Agent”) whereby it issued 10,209,300 CVRs. The CVR Agreement provides for, among other things, the CVRs, which represent contractual rights to receive a contingent payment (in the form of additional shares of HighPeak Energy common stock, or as otherwise specified in the CVR Agreement) in certain circumstances that were issued to the holders of shares of Pure’s Class A Common Stock that participated in the HighPeak business combination and certain qualified institutional buyers and accredited investors, including certain affiliates and officers of the Company, that purchased forward purchase units of the Company pursuant to the Forward Purchase Agreement Amendment (as defined below). Pursuant to the CVR Agreement, holders of CVRs in whose name a CVR is registered in the CVR registrar maintained by the Rights Agent at any date of determination are being provided with a significant valuation protection through the opportunity to obtain additional contingent consideration in the form of additional shares of HighPeak Energy common stock if the trading price of HighPeak Energy’s common stock is below the price that would provide the holders of CVRs with a 10% preferred simple annual return on their shares of common stock held at Closing (based on a $10.00 per share price at the closing of the HighPeak business combination), subject to a floor downside per-share price of $4.00 (the “Preferred Returns”), either at (i) the date to be specified by the CVR Sponsors, 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 (ii) in certain circumstances, the occurrence of certain change of control events with respect to the Company’s business, including certain mergers, consolidation and asset sales. If any additional shares of HighPeak Energy common stock are issued to Qualifying CVR Holders (as defined in the CVR Agreement) pursuant to the CVR Agreement, the CVR Sponsors will collectively forfeit an equivalent number of shares they own that are currently in escrow to the Company for cancellation. The Preferred Returns could entitle a Qualifying CVR Holder to receive up to 2.125 shares of HighPeak Energy common stock per CVR. Following the closing, the CVR Sponsors collectively placed 21,694,763 shares in escrow, which equaled the maximum number of additional shares of HighPeak Energy common stock issuable pursuant to the CVR Agreement, which such shares will be released either to the Company for cancellation in connection with the satisfaction of any Preferred Returns or back to the CVR Sponsors, collectively, as applicable, following the maturity date under the CVR Agreement.

Stockholders’ Agreement. At the closing of the HighPeak business combination, Pure’s Sponsor, HighPeak I, HighPeak II, HighPeak III and Jack Hightower (collectively, with each of their respective affiliates and permitted transferees, the “Principal Stockholder Group”), on the one hand, and the Company, on the other hand, entered into a Stockholders’ Agreement (the “Stockholders’ Agreement”), which governs certain rights and obligations following the HighPeak business combination. Under the Stockholders’ Agreement, the Principal Stockholder Group will be entitled, based on its percentage ownership of the total amount of HighPeak Energy common stock issued and outstanding immediately following the closing (the “Original Shares”) and provided that the Original Shares constitute not less than the percentage of the then outstanding total voting securities of the Company set forth below, to nominate a number of directors for appointment to the Board as follows:

●

for so long as (i) the Principal Stockholder Group beneficially owns at least 35% of the Original Shares and (ii) the Original Shares constitute at least 30% of the Company’s then-outstanding voting securities, the Principal Stockholder Group can designate up to four (4) nominees, and if the Principal Stockholder Group owns less than 50% of the total outstanding voting securities, at least one nominee shall be independent as defined by applicable listing standards;

	●	for so long as (i) the Principal Stockholder Group beneficially owns less than 35% but at least 25% of the Original Shares and (ii) the Original Shares constitute at least 25% of the Company’s then-outstanding voting securities, the Principal Stockholder Group can designate up to three (3) nominees;
	●	for so long as (i) the Principal Stockholder Group beneficially owns less than 25% but at least 15% of the Original Shares and (ii) the Original Shares constitute at least 15% of the Company’s then-outstanding voting securities, the Principal Stockholder Group can designate up to two (2) nominees; and
	●	if (i) the Principal Stockholder Group beneficially owns less than 15% but at least 5% of the Original Shares and (ii) the Original Shares constitute at least 7.5% of the Company’s then-outstanding voting securities, the Principal Stockholder Group can designate one (1) nominee.

If at any time the Principal Stockholder Group owns less than 5% of the Original Shares or the Original Shares constitute less than 7.5% of the Company’s then-outstanding voting securities, it will cease to have any rights to designate individuals for nomination to the Board.

For so long as the Principal Stockholder Group has the right to designate at least one director for nomination under the Stockholders’ Agreement, the Company will take all Necessary Action (as defined therein) to ensure that the number of directors serving on the Board shall not exceed seven (7). For so long as the Principal Stockholder Group owns a number of shares of HighPeak Energy common stock equal to at least (i) 20% of the Original Shares and (ii) 7.5% of the then-outstanding voting securities of the Company, the Company and the Principal Stockholder Group shall have the right to have a representative appointed to serve on each committee of the Board (other than the audit committee) for which any such representative is eligible pursuant to applicable laws and the Nasdaq. For so long as the Principal Stockholder Group has the right to designate one or more individuals for nomination to the Board, the Principal Stockholder Group shall have the right to appoint one (1) non-voting observer to the Board.

The Stockholders’ Agreement also includes customary restrictions on the transfer of equity securities to certain persons acquiring beneficial ownership. Pursuant to the Stockholders’ Agreement, the Principal Stockholder Group will agree not to transfer, directly or indirectly, any equity securities of the Company for a period of 180 days after the Closing, subject to certain customary exceptions. The Stockholders’ Agreement will terminate as to each stockholder upon the time at which the Principal Stockholder Group no longer has the right to designate an individual for nomination to the Board under the Stockholders’ Agreement and as to a member of the Principal Stockholder Group that no longer owns any of the Original Shares.

Registration Rights Agreement. At the closing of the HighPeak business combination, the Company entered into the Registration Rights Agreement (the “Registration Rights Agreement”), by and among the Principal Stockholder Group and certain other security holders named therein, pursuant to which the Company will be obligated, subject to the terms thereof and in the manner contemplated thereby, to register for resale under the Securities Act of 1933, as amended (the “Securities Act”) all or any portion of the shares of HighPeak Energy common stock that the holders named thereto hold as of the date of such agreement and that they may acquire thereafter, including upon the conversion, exchange or redemption of any other security therefor (the “Registrable Securities”). The Company has agreed to file and cause to become effective a registration statement covering the Registrable Securities held by such holder making a demand for registration, provided that no fewer than the amount of Registrable Securities representing the lesser of (i) $25 million or (ii) all Registrable Securities owned by such holder, as applicable, are covered under the holder’s demand for registration. The holders can submit a request beginning immediately after the HighPeak business combination. Under the Registration Rights Agreement, the holders also have “piggyback” registration rights exercisable at any time that allow them to include the shares of HighPeak Energy common stock that they own in certain registrations initiated by the Company, provided that such holder elects to include its Registrable Securities in an amount not less than $5 million. Subject to customary exceptions, holders will also have the right to request one or more underwritten offerings of Registrable Securities, provided, that, they hold at least $5 million in Registrable Securities and each such offering include a number of Registrable Securities equal to the lesser of (i) $25 million and (ii) all of the Registrable Securities owned by such holders as of the date of the request. In the event that the sale of registered securities under a registration statement would require disclosure of certain material non-public information not otherwise required to be disclosed, the Company may postpone the effectiveness of the applicable registration statement or require the suspension of sales thereunder. The Company may not delay or suspend a registration statement on more than two (2) occasions for more than sixty (60) consecutive calendar days or more than ninety (90) total calendar days, in each case, during any twelve (12) month period.

Forward Purchases. In connection with the closing of the HighPeak business combination, the Company also issued shares of HighPeak Energy common stock, warrants and CVRs (the “Forward Purchases”) to certain qualified institutional buyers and accredited investors (the “Forward Purchase Investors”) pursuant to that certain Amended & Restated Forward Purchase Agreement, dated as of July 24, 2020 (the “Forward Purchase Agreement Amendment”), by and among the Company, each party designated as a purchaser therein (including purchasers that subsequently joined prior to the closing of the HighPeak business combination as parties thereto), HighPeak Energy Partners, LP, and, solely for the limited purposes specified therein, Pure.

Prior to the closing of the HighPeak business combination, and subsequent to the Company’s entry into the Forward Purchase Agreement Amendment, an aggregate of 8,976,875 forward purchase units (with each forward purchase unit consisting of one share of HighPeak Energy common stock, one warrant and one CVR), for aggregate consideration of approximately $89.8 million in a private placement pursuant to the Assignment and Joinder agreements under and pursuant to the Forward Purchase Agreement Amendment. The proceeds from the Forward Purchases were used to fund a portion of the minimum equity consideration condition to closing required to effect the HighPeak business combination pursuant to the Business Combination Agreement.

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 period from January 1, 2020 through August 21, 2020, HPK LP paid $2.4 million each to the parent companies of HighPeak I and HighPeak II of which $4.7 million is included in general and administrative expenses in the accompanying results of operations for the period from January 1, 2020 through August 21, 2020. Effective upon closing of the HighPeak business combination, the Management Company will no longer be paid by the Company as all costs directly attributable to the Company will be paid by the Company going forward.

In October 2020, the Company paid G4 Companies, LLC, a company wholly owned by a director of the Company, $1.5 million for the design of a full-scale model for a water recycle and purification treatment facility that the Company plans to construct in our development area to handle produced water in an environmentally friendly manner. Phase I and II water testing has already been completed to ascertain the viability of such a system. The timing of the construction of the facility is still under review and consideration.

Note 17 – Supplemental Oil and Gas Disclosures (Unaudited)

Net Capitalized Costs

The following table reflects the capitalized costs of natural gas and oil properties and the related accumulated depletion (in thousands):

	Successor			Predecessors
	December 31, 2020			December 31, 2019
	(in thousands)
Proved properties	$	367,372		$	178,835
Unproved properties		152,741			227,525
Total capitalized costs		520,113			406,360
Less: accumulated depletion		(17,477	)		(1,566	)
Net capitalized costs	$	502,636		$	404,794

Cost Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development

The following table reflects costs incurred in oil, natural gas and NGL property acquisition, development and exploratory activities (in thousands):

	Year Ended December 31, 2020
	Successor			Predecessors
	August 22, 2020 through December 31, 2020			January 1, 2020 through August 21, 2020		Year Ended December 31, 2019
Acquisition costs:
Proved properties	$	-		$	585	$	4,635
Unproved properties		1,181			2,753		6,288
Total acquisition costs		1,181			3,338		10,923
Exploration costs		52,837			48,801		59,349
Development costs		11,757			863		54
Oil and gas expenditures		65,775			53,002		70,326
Asset retirement obligations, net		(105	)		98		316
Total costs incurred	$	65,670		$	53,100	$	70,642

Results of Operations for Oil, Natural Gas and NGL Producing Activities

The following table reflects the Partnership’s results of operations for oil, natural gas and natural gas liquids producing activities (in thousands):

	Year Ended December 31, 2020
	Successor			Predecessors
	August 22, 2020 through December 31, 2020			January 1, 2020 through August 21, 2020			Year Ended December 31, 2019
Oil, NGL and natural gas sales	$	16,400		$	8,223		$	8,115
Lease operating expenses		2,653			4,870			3,372
Production and ad valorem taxes		886			566			449
Exploration and abandonment expense		5,032			4			2,850
Depletion, depreciation and amortization expense		9,877			6,385			4,269
Accretion of discount on asset retirement obligations		51			89			72
Results of operations from oil and gas production activities	$	(2,099	)	$	(3,691	)	$	(2,897	)

Oil, Natural Gas and NGL Reserves

Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first day of the month spot prices prior to the end of the reporting period. These prices as of December 31, 2020 and 2019 were $39.57 and $55.69 per barrel for crude oil and $1.985 and $2.578 per MMBtu for natural gas, respectively. The estimated realized prices used in computing the Company’s reserves as of December 31, 2020 were as follows: (i) oil - $38.08 per barrel, (ii) natural gas - ($1.304) per Mcf, and (iii) NGL - $12.27 per barrel. The estimated realized prices used in computing the Partnership’s reserves as of December 31, 2019 were as follows: (i) oil - $50.57 per barrel, (ii) natural gas - $0.10 per Mcf, and (iii) NGL - $21.17 per barrel. All prices are net of adjustments for regional basis differentials, treating costs, transportation, gas shrinkage, gas heating vale (BTU content) and/or crude quality and gravity adjustments.

The proved reserve estimates as of December 31, 2020 and 2019 were prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”), independent reserve engineers, and reflect the Company’s current development plans. All estimates of proved reserves are determined according to the rules prescribed by the SEC in existence at the time estimates were made. These rules require that the standard of “reasonable certainty” be applied to proved reserve estimates, which is defined as having a high degree of confidence that the quantities will be recovered. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as more technical and economic data becomes available, a positive or upward revision or no revision is much more likely than a negative or downward revision. Estimates are subject to revision based upon a number of factors, including many factors beyond the Company’s control, such as reservoir performance, prices, economic conditions, and government restrictions. In addition, results of drilling, testing, and production subsequent to the date of an estimate may justify revision of that estimate.

Reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. Estimating quantities of proved oil and natural gas reserves is a complex process that involves significant interpretations and assumptions and cannot be measured in an exact manner. It requires interpretations and judgment of available technical data, including the evaluation of available geological, geophysical and engineering data. The accuracy of any reserve estimate is highly dependent on the quality of available data, the accuracy of the assumptions on which they are based upon, economic factors, such as oil and natural gas prices, production costs, severance and excise taxes, capital expenditures, workover and remedial costs, and the assumed effects of governmental regulation. In addition, due to the lack of substantial, if any, production data, there are greater uncertainties in estimating PUD reserves, proved developed non-producing reserves and proved developed reserves that are early in their production life. As a result, the Company’s reserve estimates are inherently imprecise.

The meaningfulness of reserve estimates is highly dependent on the accuracy of the assumptions on which they were based. In general, the volume of production from oil and natural gas properties the Company owns declines as reserves are depleted. Except to the extent the Company conducts successful exploration and development activities or acquires additional properties containing proved reserves, or both, the Company’s proved reserves will decline as reserves are produced.

The following table reflects changes in proved reserves during the periods indicated:

	Crude Oil (MBbl)			Natural Gas (MMcf)			NGL (MBbl)			Total (MBoe)
*Predecessors*
Proved Reserves at January 1, 2019		2,914			809			222			3,271
Contribution from HighPeak II		973			569			78			1,146
Extensions and discoveries		5,413			2,528			759			6,593
Revisions of previous estimates		217			887			290			655
Production		(145	)		(139	)		-			(168	)
Proved Reserves at December 31, 2019		9,372			4,654			1,349			11,497
Purchase of minerals in place		44			36			-			50
Extensions and discoveries		1,008			252			67			1,117
Revisions of previous estimates		(1,555	)		(1,144	)		(374	)		(2,120	)
Production		(236	)		(87	)		(20	)		(270	)
Proved Reserves at August 21, 2020		8,633			3,711			1,022			10,274

*Successor*
Proved Reserves at August 22, 2020		8,633			3,711			1,022			10,274
Extensions and discoveries		11,977			5,215			1,433			14,279
Revisions of previous estimates		(1,180	)		(875	)		(277	)		(1,603	)
Production		(398	)		(112	)		(18	)		(435	)
Proved Reserves at December 31, 2020		19,032			7,939			2,160			22,515

At December 31, 2020, the Company had approximately 22,515 MBoe of proved reserves. Effective August 21, 2020, the HighPeak business combination included estimated proved reserves totaling 10,274 MBoe. For the period from August 22, 2020 to December 31, 2020, extensions and discoveries increased proved reserves by 14,279 MBoe as a result of: (i) drilling 3 gross (3.0 net) exploratory wells that were on production as of December 31, 2020, (ii) 9 gross (8.9 net) exploratory wells that were in the final stages of completion as of December 31, 2020, and (iii) the addition of 15 gross (12.4 net) PUDs. Downward revisions of previous estimates of 1,603 MBoe for the period from August 22, 2020 to December 31, 2020 were primarily the result of: (i) negative revisions of 1,112 MBoe due to technical revisions attributable to decreased well performance and adjustments to our PUD estimates, (ii) negative revisions of 409 MBoe related to PUDs removed from the development program, (iii) negative revisions of approximately 98 MBoe primarily due to decreases in oil, natural gas and NGL prices and increased price differentials, (iv) partially offset by positive revisions of approximately 16 MBoe related to decreased forecasted operating expenses. The net increase in proved reserves was partially offset by 435 MBoe in production during the period from August 22, 2020 to December 31, 2020. The Company’s current development plan reflects allocation of capital with a focus on efficiencies, recoveries and rates of return.

At August 21, 2020, the Company had approximately 10,274 MBoe of proved reserves. During the period from January 1, 2020 to August 21, 2020, the Company acquired interests in three (3) producing vertical wells near its area of operation which included estimated proved reserves totaling 50 MBoe. For the period from January 1, 2020 to August 21, 2020, extensions and discoveries increased proved reserves by 1,117 MBoe as a result of: (i) drilling 3 gross (3.0 net) exploratory wells that were on production as of August 21, 2020. Revisions of previous estimates of 2,120 MBoe for the period from January 1, 2020 to August 21, 2020 were primarily the result of: (i) negative revisions totaling approximately 1,975 MBoe due to technical revisions attributable to decreased well performance of offset horizontal wells resulting in lessoned projected performance and adjustments to PUD estimates, (ii) negative revisions of approximately 173 MBoe primarily due to decreases in oil, natural gas and NGL prices and increased price differentials, and (iii) partially offset by positive revisions of 28 MBoe due to decreased forecasted operating expenses. Adding to the net decrease in proved reserves was 270 MBoe in production during the period from January 1, 20202 to August 21, 2020.

At December 31, 2019, the Predecessors had approximately 11,497 MBoe of proved reserves. Effective October 1, 2019, the contribution of a subsidiary to the Predecessors by HighPeak II included estimated proved reserves totaling 1,146 MBoe. For the year ended December 31, 2019, extensions and discoveries increased proved reserves by 6,593 MBoe as a result of: (i) drilling or participating in the drilling of 2 gross (1.8 net) exploratory wells that were on production as of December 31, 2019, (ii) 5 gross (5.0 net) exploratory wells that were being drilled or pending completion as of December 31, 2019, and (iii) the addition of 13 gross (4.4 net) PUDs. Revisions of previous estimates of 655 MBoe for the year ended December 31, 2019 were primarily the result of: (i) negative revisions totaling approximately 80 MBoe due to reductions in pricing and increases in pricing differentials, (ii) negative revisions of approximately 54 MBoe primarily due to increased forecasted operating expenses, and (iii) positive revisions of 789 MBoe due to improvements in well performance attributable to improved well performance of offset horizontal wells resulting in improved projected performance of these PUDs. The net increase in proved reserves was offset by 168 MBoe in production during the year ended December 31, 2019.

The following table sets forth the Partnership’s estimated quantities of proved developed and proved undeveloped oil, natural gas and natural gas liquid reserves:

	Successor December 31, 2020		Predecessors December 31, 2019
Proved Developed Reserves ⁽¹⁾
Oil (MBbl)		8,730		4,091
Natural gas (MMcf)		3,572		1,952
Natural gas liquids (MBbl)		957		548
Total (MBoe)		10,282		4,964
Proved Undeveloped Reserves
Oil (MBbl)		10,302		5,281
Natural gas (MMcf)		4,367		2,702
Natural gas liquids (MBbl)		1,203		801
Total (MBoe)		12,233		6,533
Total Proved Reserves
Oil (MBbl)		19,032		9,372
Natural gas (MMcf)		7,939		4,654
Natural gas liquids (MBbl)		2,160		1,349
Total (MBoe)		22,515		11,497

⁽¹⁾

As of December 31, 2020 and 2019, proved developed reserves includes proved developed non-producing reserves of 4,517 and 3,101 MBbl of crude oil, 1,912 and 1,454 MMcf of natural gas and 517 and 447 MBbl of natural gas liquids, respectively.

Standardized Measure of Discounted Future Net Cash Flows

The following table reflects the Partnership’s standardized measure of discounted future net cash flows relating from its proved crude oil, natural gas and natural gas liquids reserves (in thousands):

	Successor December 31, 2020			Predecessors December 31, 2019
Future cash inflows	$	740,859		$	502,961
Future production costs		(217,025	)		(127,897	)
Future development costs		(117,887	)		(78,360	)
Future income tax expense		(25,824	)		(2,640	)
Future net cash flows		380,123			294,064
Discount to present value at 10% annual rate		(157,931	)		(154,043	)
Standardized measure of discounted future net cash flows	$	222,192		$	140,021

⁽¹⁾

Effective beginning on August 22, 2020 and as of December 31, 2020, the Company is treated as a corporation for U.S. federal income tax purposes. Accordingly, “future income tax expense” above includes estimates of future federal income taxes and margin / franchise taxes in Texas that may be incurred by the Company. As of December 31, 2019, the Predecessors were each treated as a partnership for U.S. federal income tax purposes. Accordingly, federal taxable income and losses were reported on the income tax returns of the Predecessor’s partners. The Predecessors were subject to margin / franchise taxes in Texas, which is reflected as “Future income tax expense”.

The following table reflects the principal changes in the standardized measure of discounted future net cash flows attributable to the Partnership’s proved reserves (in thousands):

	Year Ended December 31, 2020 (2)			Year Ended December 31, 2019 (2)
Standardized measure of discounted future net cash flows, beginning of year	$	140,021		$	31,118
Contribution of HighPeak II to Predecessors		-			10,488
Sales of oil and natural gas, net of production costs		(15,648	)		(4,294	)
Extensions and discoveries, net of future development costs		172,478			85,626
Net changes in prices and production costs		(50,728	)		(6,755	)
Changes in estimated future development costs		6,466			9,483
Purchases of minerals in place		600			14
Revisions of previous quantity estimates		(41,646	)		8,232
Accretion of discount		14,134			3,165
Net changes in income taxes ⁽¹⁾		(10,675	)		(857	)
Net changes in timing of production and other		7,190			3,801
Standardized measure of discounted future net cash flows, end of year	$	222,192		$	140,021

⁽¹⁾

Effective with the HighPeak business combination that closed on August 21, 2020, the oil and gas properties became owned by HighPeak Energy, which is treated as a corporation for U.S. federal income tax purposes. As such, the “Net change in income taxes” in the table above for the year ended December 31, 2020 reflects the change in tax status applicable to the operations of the oil and gas properties. Prior to the HighPeak business combination, the Predecessors were each treated as a partnership for U.S. federal income tax purposes. Accordingly, federal taxable income and losses relating to the operation of the oil and gas properties were reported on the income tax returns of the Predecessors’ partners. The Predecessors were subject to margin / franchise taxes in Texas, which is reflected as “Net change in income taxes” in the table above for the year ended December 31, 2019.

⁽²⁾

The year ended December 31, 2020 in the table above reflects the change in standardized measure from that of HPK LP, our Predecessor, as of December 31, 2019 to that of the Company as of December 31, 2020 and amounts are combined for the period from January 1, 2020 to August 21, 2020 of HPK LP and from August 22, 2020 to December 31, 2020 of the Company. There was no third-party reserve report prepared as of August 21, 2020 from which to compute a standardized measure from as of that date. The year ended December 31, 2019 in the table above reflects the change in standardized measure from that of HighPeak I, HPK LP’s Predecessor, as of December 31, 2018 to that of HPK LP as of December 31, 2019 and amounts are combined for the period from January 1, 2019 to September 30, 2019 of HighPeak I and from October 1, 2019 to December 31, 2019 of HPK LP. There was no third-party reserve report prepared for HighPeak I as of October 1, 2019 from which to compute a standardized measure from as of that date. We believe the table above accurately reflects the change in standardized measure for the Predecessors and Successor in a meaningful context.

Title of each class	Trading Symbol	Name of each exchange on which registered

Common Stock, par value $0.0001 per share	HPK	The Nasdaq Stock Market LLC
Warrants to purchase Common Stock	HPKEW	The Nasdaq Stock Market LLC

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
Items 1 and 2.	Business and Properties	6
Item 1A.	Risk Factors	22
Item 1B.	Unresolved Staff Comments	49
Item 3.	Legal Proceedings	49
Item 4.	Mine Safety Disclosures	49
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	50
Item 6.	Selected Financial Data	51
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	52
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	62
Item 8.	Financial Statements and Supplementary Data	63
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	93
Item 9A.	Controls and Procedures	93
Item 9B.	Other Information	93
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	93
Item 11.	Executive Compensation	94
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	94
Item 13.	Certain Relationships and Related Transactions, and Director Independence	94
Item 14.	Principal Accountant Fees and Services	97
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	98
Item 16.	Form 10-K Summary	100
Signatures		101

	•	*"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 oil equivalent and is a standard convention used to express oil and gas volumes on a comparable oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of six thousand cubic feet of gas to one Bbl of oil or natural gas liquid.
	•	*"Boe/d"* means Boe per day.
	•	*"Bopd"* means one barrel of 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, HighPeak III, 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 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).
	•	"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 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 an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
	•	*“Differential*” An adjustment to the price of oil, natural gas or natural gas liquids from an established spot market price to reflect differences in the quality and/or location of 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 oil or 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.
	•	*“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 oil or natural gas.
	•	*“HighPeak business combination*” means the transactions contemplated by 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.
	•	*“HighPeak III*” means HighPeak Energy III, 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 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 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 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"* or “*natural gas liquids*” means natural gas liquids, which are the heavier hydrocarbon liquids that are separated from the gas stream; such liquids include ethane, propane, isobutane, normal butane and natural 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 an 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.
	•	*“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” means developed nonproducing reserves.
	•	“Proved developed producing reserves” means developed producing reserves.
	•	*“Proved developed reserves*” 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 oil and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

	(i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or 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 oil elevation and the potential exists for an associated gas cap, proved 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.

	•	*“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 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 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 oil and 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 oil and 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 oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.
	•	*“Resources*” Quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations.
	•	*“Revolving Credit Facility*” refers to the Company’s senior secured reserve-based lending facility which matures June 17, 2024.
	•	*“Royalty*” An interest in an 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.
	•	*“Service well*” A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include 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 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 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 oil produced from fields in western Texas and is a grade of oil used as a benchmark in 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.

	As of December 31, 2020
Proved Developed Reserves:
Oil (MBbl)		8,730
Natural Gas (MMcf)		3,572
NGL (MBbl)		957
Total (MBoe)		10,282
Proved Undeveloped Reserves:
Oil (MBbl)		10,302
Natural Gas (MMcf)		4,367
NGL (MBbl)		1,203
Total (MBoe)		12,233
Total Proved Reserves:
Oil (MBbl)		19,032
Natural Gas (MMcf)		7,939
NGL (MBbl)		2,160
Total (MBoe)		22,515

	Predecessors
	Total (MBoe)
Proved undeveloped reserves at January 1, 2020		6,534
Conversions into proved developed reserves		(529	)
Revisions		(241	)
Proved undeveloped reserves at August 21, 2020		5,764

	●	Extensions and discoveries of 7,015 MBoe related to new proved undeveloped locations added as a result of HighPeak Energy’s drilling activities; and
	●	Downward revisions of 546 MBoe including 409 MBoe related to proved undeveloped locations that were removed from the development plan due to the Company’s election not to renew certain leases, 102 MBoe related to adjustments to forecasts and 35 MBoe attributable to a decrease in oil, natural gas and NGL prices.

	●	Conversions into proved developed reserves of 529 MBoe as a result of the Company’s ongoing drilling program in early 2020 and prior to the Company shutting down its drilling program in the late 2020 first quarter due to COVID-19 and the downturn in oil prices.
	●	Downward revisions of 241 MBoe including 181 MBoe resulting from adjustments to our forecasts and 60 MBoe resulting from a decrease in oil, natural gas and NGL prices.

	Proved Developed		Proved Undeveloped		Total Proved
Estimated future net cash flows	$	229,599	$	177,896	$	407,495
Present value of estimated future net cash flows	$	162,582	$	72,908	$	235,490
Present value of future income taxes/abandonment costs					$	(13,298	)
Standardized measure					$	222,192

	Oil							Gas
	Gross		Net		Average Working Interest			Gross		Net		Average Working Interest
*Horizontal:*
Operated		19		18.3		96	%		-		-		n/a
Non-operated		-		-		n/a			-		-		n/a
*Vertical:*
Operated		35		30.9		88	%		6		4.5		75	%
Non-operated		49		11.6		24	%		6		2.0		33	%
*Total:*
Operated		54		49.1		91	%		6		4.5		75	%
Non-operated		49		11.6		24	%		6		2.0		33	%

Developed Acres(1)(4)				Undeveloped Acres(4)				Total Acres
Gross(2)		Net(3)		Gross(2)		Net(3)		Gross(2)		Net(3)
	15,602		11,100		43,490		39,536		59,092		50,636

2021			2022			2023			2024			2025			Thereafter
30,257			2,430			112			5,522			-			-

	Period from August 22, 2020 through December 31, 2020 (Successor)				Period from January 1, 2020 through August 21, 2020 (Predecessors)				Year Ended December 31, 2019				Year Ended December 31, 2018
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Development wells:
Productive		-		-		1		1.0		1		0.8		-		-
Dry		-		-		-		-		-		-		-		-
Exploratory wells:
Productive		14		13.8		6		6.0		2		2.0		1		0.8
Dry		-		-		-		-		-		-		-		-
Service wells:
Salt-Water Disposal		1		1.0		-		-		-		-		-		-

	Years Ended December 31,
Major Customers	2020			2019			2018
Lion Oil Trading and Transportation, LLC		80	%		*			*
Enlink Crude Purchasing, LLC		17	%		67	%		32	%
Sunoco Partners Marketing & Terminals, LP		*			21	%		49	%

	●	Oil, natural gas and NGL prices are volatile and sustained periods of low, or further declines in, oil, natural gas and NGL prices could adversely affect HighPeak Energy’s business, financial condition and results of operations.
	●	The recent and ongoing outbreak of COVID-19 and other pandemic outbreaks could negatively impact HighPeak Energy’s business and results of operation.
	●	The marketability of HighPeak Energy’s production is dependent upon transportation, storage and other facilities, certain of which it does not control. If these facilities are unavailable, HighPeak Energy’s operations could be interrupted, and its revenues reduced.
	●	Certain factors could require HighPeak Energy to write-down the carrying values of its properties, including commodity prices decreasing to a level such that future undiscounted cash flows from its properties are less than their carrying value.
	●	HighPeak Energy’s development projects and acquisitions will require substantial capital expenditures. HighPeak Energy may be unable to obtain required capital or financing on satisfactory terms, which could reduce its ability to access or grow production and reserves.
	●	Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect HighPeak Energy’s business, financial condition or result of operations.
	●	Restrictions in HighPeak Energy’s Revolving Credit Facility and any future debt agreements could limit HighPeak Energy’s growth and ability to engage in certain activities.
	●	Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of reserves.
	●	HighPeak Energy is not the operator on all its acreage or drilling locations, and, therefore, HighPeak Energy is not able to control the timing of exploration or development efforts, associated costs or the rate of production of any non-operated assets.
	●	The Company’s assets are located in the north eastern portion of the Midland Basin, making HighPeak Energy vulnerable to risks associated with operating in a limited geographic area.
	●	HighPeak Energy may incur losses as a result of title defects in the properties in which it invests.
	●	The development of estimated PUDs may take longer and may require higher levels of capital expenditures than anticipated. Therefore, estimated PUDs may not be ultimately developed or produced.
	●	Unless HighPeak Energy replaces its reserves with new reserves and develops those new reserves, its reserves and production will decline, which would adversely affect future cash flows and results of operations.
	●	Conservation measures and technological advances could reduce or slow the demand for oil and natural gas.
	●	HighPeak Energy depends upon a small number of significant purchasers for the sale of most of its oil, natural gas and NGL production. The loss of one or more of such purchasers could, among other factors, limit HighPeak Energy’s access to suitable markets for the oil, natural gas and NGL it produces.
	●	HighPeak Energy’s operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to its business activities.
	●	HighPeak Energy may incur substantial losses and be subject to substantial liability claims as a result of operations. Additionally, HighPeak Energy may not be insured for, or insurance may be inadequate to protect HighPeak Energy against, these risks.
	●	HighPeak Energy may be unable to make additional attractive acquisitions or successfully integrate acquired businesses with its current assets, and any inability to do so may disrupt its business and hinder its ability to grow.
	●	Certain of HighPeak Energy’s properties are subject to land use restrictions, which could limit the manner in which HighPeak Energy conducts business.
	●	The unavailability or high cost of drilling rigs, equipment, supplies, personnel, frac crews and oilfield services could adversely affect HighPeak Energy’s ability to execute its development plans within its budget and on a timely basis.
	●	Should our operators fail to comply with all applicable regulatory agency administered statutes, rules, regulations and orders, our operators could be subject to substantial penalties and fines.
	●	The operations of HighPeak Energy are subject to a series of risks arising out of the threat of climate change that could result in increased operating costs, limit the areas in which HighPeak Energy may conduct oil and natural gas exploration and production activities and reduce demand for the oil and natural gas HighPeak Energy produces.
	●	Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect HighPeak Energy’s production.
	●	Legislation or regulatory initiatives intended to address seismic activity could restrict HighPeak Energy’s drilling and production activities, as well as HighPeak Energy’s ability to dispose of produced water gathered from such activities, which could have a material adverse effect on its future business.
	●	Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect HighPeak Energy’s ability to conduct drilling activities in areas where it operates.

	●	There are inherent limitations in all control systems, and misstatements due to error or fraud that could seriously harm HighPeak Energy’s business may occur and not be detected.
	●	HighPeak Energy’s business could be adversely affected by security threats, including cyber-security threats, and related disruptions.

	●	The HighPeak Group, including the Principal Stockholder Group, has significant influence over HighPeak Energy.
	●	HighPeak Energy’s only significant asset is its ownership of 100% of the operating companies acquired in the business combination and cash on hand after the Closing of the business combination, and such ownership may not be sufficient to pay dividends on its common stock or satisfy its other financial obligations.
	●	Because HighPeak Energy has a limited operating history, it may be difficult to evaluate its ability to successfully implement its business strategy.
	●	HighPeak Energy is a “controlled company” within the meaning of Nasdaq Rules and, as a result, qualifies for exemptions from certain corporate governance requirements. As a result, you do not have the same protections afforded to stockholders of companies that are subject to such requirements.
	●	HighPeak Energy may be required to take write-downs or write-offs, restructuring and impairment or other charges that could have a significant negative effect on HighPeak Energy’s financial condition, results of operations and stock price, which could cause you to lose some or all your investment.
	●	The terms of our warrants may be amended in a manner that may be adverse to holders of our warrants with the approval by the holders of at least 50% of our then-outstanding warrants.
	●	A significant portion of HighPeak Energy’s total outstanding shares are restricted from immediate resale but may be sold into the market in the near future. This could cause the market price of HighPeak Energy common stock to drop significantly, even if HighPeak Energy’s business is doing well.
	●	There can be no assurance that HighPeak Energy common stock issued, including issuable upon exercise of our warrants or upon satisfaction of conditions under the CVR Agreement with respect to the CVRs, will remain listed on the Nasdaq, or that HighPeak Energy will be able to comply with the continued listing standards of the Nasdaq.
	●	HighPeak Energy is an emerging growth company within the meaning of the Securities Act, and if HighPeak Energy takes advantage of certain exemptions from disclosure requirements available to emerging growth companies, this could make HighPeak Energy’s securities less attractive to investors and may make it more difficult to compare its performance with other public companies.
	●	Under certain circumstances, the Contingent Value Rights will have no value and will be automatically terminated without any further consideration.
	●	A market for the CVRs may not develop and, even if a market for the CVRs does develop, there can be no assurance the extent to which trading of the CVRs will lead to an illiquid trading market with respect to such CVRs, which would adversely affect the liquidity and price of the CVRs.

	●	worldwide and regional economic conditions impacting the global supply and demand for oil, natural gas and NGL;

	●	the price and quantity of foreign imports of oil, natural gas and NGL;

	●	domestic and global political and economic conditions, socio-political unrest and instability, terrorism or hostilities in or affecting other producing regions or countries, including the Middle East, Africa, South America and Russia;

	●	the occurrence or threat of epidemic or pandemic diseases, such as the recent and ongoing outbreak of COVID-19, or any government response to such occurrence or threat;

	●	actions of the Organization of the Petroleum Exporting Countries (“OPEC”), its members and other state-controlled oil companies relating to oil price and production controls;

	●	the level of global exploration, development and production;

	●	the level of global inventories;

	●	prevailing prices on local price indexes in the areas in which HighPeak Energy operates;

	●	the proximity, capacity, cost and availability of gathering and transportation facilities;

	●	localized and global supply and demand fundamentals and transportation availability;

	●	the cost of exploring for, developing, producing and transporting reserves;

	●	weather conditions and natural disasters;

	●	technological advances affecting energy consumption;

	●	the price and availability of alternative fuels;

	●	expectations about future commodity prices; and

	●	U.S. federal, state and local and non-U.S. governmental regulation and taxes.

	●	the prices at which HighPeak Energy’s production is sold;

	●	proved reserves;

	●	the amount of hydrocarbons HighPeak Energy is able to produce from its wells;

	●	HighPeak Energy’s ability to acquire, locate and produce new reserves;

	●	the amount of HighPeak Energy’s operating expenses;

	●	cash settlements from HighPeak Energy’s derivative activities;

	●	HighPeak Energy’s ability to obtain additional debt financing, including increases to the Revolving Credit Facility;

	●	the duration of economic uncertainty surrounding the COVID-19 pandemic;

	●	the duration and uncertainty of OPEC+’s agreement not to increase production above agreed levels and the compliance by its members with their respective production quotas during the term of the agreement;

	●	HighPeak Energy’s ability to obtain storage capacity for the oil it produces;

	●	restrictions in the instruments governing HighPeak Energy’s debt on HighPeak Energy’s ability to incur additional indebtedness; and

	●	HighPeak Energy’s ability to access the public or private capital markets.

	●	landing its wellbore in the desired drilling zone;

	●	staying in the desired drilling zone while drilling horizontally through the formation;

	●	running its casing the entire length of the wellbore; and

	●	being able to run tools and other equipment consistently through the horizontal wellbore.

	●	the ability to fracture stimulate the planned number of stages;

	●	the ability to run tools the entire length of the wellbore during completion operations; and

	●	the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

	●	delays imposed by, or resulting from, compliance with regulatory requirements, including limitations on wastewater disposal, emission of GHGs and hydraulic fracturing;

	●	pressure or irregularities in geological formations;

	●	shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;

	●	equipment failures, accidents or other unexpected operational events;

	●	lack of available gathering facilities or delays in construction of gathering facilities;

	●	lack of available capacity on interconnecting transmission pipelines;

	●	lack of availability of water and electricity;

	●	adverse weather conditions;

	●	issues related to compliance with environmental regulations;

	●	environmental hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

	●	declines in oil and natural gas prices;

	●	limited availability of financing on acceptable terms;

	●	title issues; and

	●	other market limitations in HighPeak Energy’s industry.

	●	require HighPeak Energy to dedicate a portion of cash flow from operations to service its debt, thereby reducing the cash available to finance operations and other business activities and could limit its flexibility in planning for or reacting to changes in its business and the industry in which it operates;

	●	increase vulnerability to economic downturns and adverse developments in HighPeak Energy’s business;

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

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

	●	limit management’s discretion in operating HighPeak Energy’s business.

	●	the timing and amount of capital expenditures;

	●	the operator’s expertise and financial resources;

	●	the approval of other participants in drilling wells;

	●	the selection of technology; and

	●	the rate of production of reserves, if any.

	●	the CAA, which restricts the emission of air pollutants from many sources, imposes various pre-construction, monitoring and reporting requirements and is relied upon by the EPA as authority for adopting climate change regulatory initiatives relating to GHG emissions;

	●	the CWA, which regulates discharges of pollutants from facilities and sources to federal waters and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the United States;

	●	the OPA, which imposes liabilities for removal costs and damages arising from an oil spill into waters of the United States;

	●	the Safe Drinking Water Act (“SDWA”), which ensures the quality of the nations’ public drinking water through adoption of drinking water standards and control over the subsurface injection of fluids into belowground formations;

	●	the Resource Conservation and Recovery Act (“RCRA”), which imposes requirements for the generation, treatment, storage, transport, disposal and cleanup of non-hazardous, hazardous and solid wastes;

	●	the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), which imposes liability on generators, transporters and those who arrange for transportation or disposal of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur, as well as imposes liability on present and certain past owners and operations of sites where hazardous substance releases have occurred or are threatening to occur;

	●	the ESA, which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating limitations or restrictions or a temporary, seasonal or permanent ban on operations in affected areas; and

	●	The OSHA, under which federal Occupational Safety and Health Administration and similar state agencies have promulgated regulations limiting exposures to hazardous substances in the workplace and imposing various worker safety requirements.

	●	environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline contamination, damage to natural resources or wildlife, or the presence of endangered or threatened species;

	●	abnormally pressured formations;

	●	mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

	●	fires, explosions and ruptures of pipelines;

	●	personal injuries and death;

	●	natural disasters; and

	●	terrorist attacks targeting oil and natural gas related facilities and infrastructure.

	●	injury or loss of life;

	●	damage to and destruction of property, natural resources and equipment;

	●	pollution and other environmental or natural resource damage;

	●	regulatory investigations and penalties; and

	●	repair and remediation costs.

	●	unexpected drilling conditions;

	●	title issues;

	●	pressure or lost circulation in formations;

	●	equipment failures or accidents;

	●	adverse weather conditions;

	●	compliance with environmental and other governmental or contractual requirements; and

	●	increases in the cost of, and shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.

	●	actual or anticipated fluctuations in our financial results or the financial results of companies perceived to be similar to us;

	●	the market volatility resulting from sustained uncertainty surrounding the COVID-19 outbreak;

	●	changes in the market’s expectations about our operating results;

	●	success of our competitors;

	●	our operating results failing to meet the expectation of securities analysts or investors in a particular period;

	●	changes in financial estimates and recommendations by securities analysts concerning us or the market in general;

	●	operating and stock price performance of other companies that investors deem comparable to us;

	●	changes in laws and regulations affecting our business;

	●	commencement of, or involvement in, litigation involving us;

	●	changes in our capital structure, such as future issuances of securities or the incurrence of additional debt;

	●	the volume of shares of HighPeak Energy common stock available for public sale;

	●	any major change in our Board or management;

	●	sales of substantial amounts of HighPeak Energy common stock by the HighPeak Group, our directors, executive officers or significant stockholders, or the perception that such sales could occur; and

	●	general economic and political conditions such as recessions, interest rates, fuel prices, international currency fluctuations, OPEC+’s ability to continue to agree to limit production among its members and acts of war or terrorism.