0001792849 HighPeak Energy, Inc. false --12-31 FY 2021 0.0001 0.0001 10,000,000 10,000,000 0 0 0 0 0.0001 0.0001 600,000,000 600,000,000 96,774,185 96,774,185 91,967,565 91,967,565 0.125 0.125 0 0 0 0 0 3 5 7 1 2 0 0 2017 2018 2019 2020 0 0 0 1 0 3 4 2 3 1 8 0 0 11.50 10,209,300 2.125 3 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. Represents HPK LP’s condensed consolidated balance sheet estimated as of August 21, 2020. 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. 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. 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). Effective with the HighPeak business combination that closed on August 21, 2020, the crude oil and natural 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 crude oil and natural gas properties. Prior to the HighPeak business combination, the Predecessor was treated as a partnership for U.S. federal income tax purposes. Accordingly, federal taxable income and losses relating to the operation of the crude oil and natural gas properties were reported on the income tax returns of the Predecessor’s partners. The Predecessor was subject to margin / franchise taxes in Texas, which is reflected as “Net change in income taxes” in the table above. Debt issuance costs as of December 31, 2021 consisted of $2.6 million in costs less accumulated amortization of $502,000. Debt issuance costs as of December 31, 2020 of $401,000, net of accumulated amortization of $4,000, were classified in other noncurrent assets on the accompanying balance sheet due to the fact that the Company had no outstanding debt at that time. Certain unvested restricted stock awarded to outside directors represent participating securities because they participate in nonforfeitable dividends with the common equity holders of the Company. Vested stock options represent participating securities because they participate in dividend equivalents with the common equity holders of the Company. Participating earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Certain unvested restricted stock awarded to employee members of the board of directors do not represent participating securities because, while they participate in dividends with the common equity holders of the Company, the dividends associated with such unvested restricted stock are forfeitable in connection with the forfeitability of the underlying restricted stock. Unvested stock options do not represent participating securities because, while they participate in dividend equivalents with the common equity holders of the Company, the dividend equivalents associated with unvested stock options are forfeitable in connection with the forfeitability of the underlying stock options. The 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. We believe the table above accurately reflects the change in standardized measure for the Predecessor and Successor in a meaningful context. 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. The revisions to the Company’s asset retirement obligation estimates are primarily due to changes in estimated costs based on experience with the properties and their expected useful lives. 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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________________

 

FORM 10-K

______________________________

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

 

For the fiscal year ended December 31, 2021

or

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

 

For the transition period from ________ to ________

Commission File Number: 333-39464

______________________________

HighPeak Energy, Inc.

(Exact name of Registrant as specified in its charter)

______________________________

 

Delaware

84-3533602

(State or other jurisdiction of incorporation or

organization)

(I.R.S. Employer Identification

No.)

 

421 W. 3rd St., Suite 1000

Fort Worth, Texas 76102

(Address of principal executive offices and zip code)

 

(817) 850-9200

(Registrant's telephone number, including area code)

 

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

 

Title of each class

Trading Symbol

 

Name of each exchange on which registered

         

Common Stock, par value $0.0001 per share

HPK

 

The Nasdaq Stock Market LLC

Warrants to purchase Common Stock

HPKEW

 

The Nasdaq Stock Market LLC

 

Securities registered pursuant to Section 12(g) of the Act: None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Act. Yes ☐  No

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ☐  No

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒     No

 

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒     No

 

 

 

 

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

 

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

   

Emerging growth company

 

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

 

Indicate by checkmark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 762(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐     No

 

As of June 30, 2021, the aggregate market value of the Common Stock of the Registrant held by non-affiliates was $48,747,167, based on the closing price as reported on the Nasdaq Global Market of $10.23.

 

Number of shares of Common Stock outstanding as of March 3, 2022 – 96,822,600.

 

DOCUMENTS INCORPORATED BY REFERENCE:

 

(1)

Portions of the Definitive Proxy Statement for the Company’s Annual Meeting of Stockholders to be held in June 2022, which will be filed with the U.S. Securities and Exchange Commission within 120 days of December 31, 2021, are incorporated into Part III of this Annual Report on Form 10-K.

 

 

 

 

 

HIGHPEAK ENERGY, INC.

TABLE OF CONTENTS

 

   

Page

Definitions of Certain Terms and Conventions Used Herein

1

Cautionary Statement Concerning Forward-Looking Statements

6

 

PART I

 

Items 1 and 2.

Business and Properties

8

Item 1A.

Risk Factors

25

Item 1B.

Unresolved Staff Comments

55

Item 3.

Legal Proceedings

55

Item 4.

Mine Safety Disclosures

55
 

PART II

 

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

56

Item 6.

[Reserved]

56

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

57

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

71

Item 8.

Financial Statements and Supplementary Data

73

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

105

Item 9A.

Controls and Procedures

105

Item 9B.

Other Information

105

Item 9C.

Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

 
 

PART III

 

Item 10.

Directors, Executive Officers and Corporate Governance

105

Item 11.

Executive Compensation

105

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

105

Item 13.

Certain Relationships and Related Transactions, and Director Independence

106

Item 14.

Principal Accountant Fees and Services

106

 

PART IV

 

Item 15.

Exhibits, Financial Statement Schedules

106

Item 16.

Form 10-K Summary

108

Signatures

109

 

 

 
 

 

HIGHPEAK ENERGY, INC.

 

Definitions of Certain Terms and Conventions Used Herein

 

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

 

 

"3-D seismic" means three-dimensional seismic data which is geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than two-dimensional data.

 

"Basin" means a large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

 

"Bbl" means a standard barrel containing 42 United States gallons.

   

“Bcf means one billion cubic feet.

 

"Boe" means a barrel of crude oil equivalent and is a standard convention used to express crude oil and natural gas volumes on a comparable crude oil equivalent basis. Natural gas equivalents are determined under the relative energy content method by using the ratio of six thousand cubic feet of natural gas to one Bbl of crude oil or NGL.

 

"Boepd" means Boe per day.

 

"Bopd" means one barrel of crude oil per day.

 

"Btu" means British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.

 

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

 

“Closing” means the closing of the HighPeak business combination between the Company, Pure, HPK LP, HighPeak I and HighPeak II on August 21, 2020.

 

“common stock” or “HighPeak Energy common stock” means the Company’s common stock, par value $0.0001 per share.

 

“Completion” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil and natural gas, or 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).

 

1

 

 

“Credit Agreement” means the Company’s Credit Agreement, dated as of December 17, 2020, as amended from time to time, among HighPeak Energy, Inc., as Borrower, Fifth Third Bank, National Association, as administrative agent, and the Lenders party thereto.

 

“DD&A means depletion, depreciation and amortization.

 

“Development costs” Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the crude oil and natural gas. For a complete definition of development costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(7).

 

“Development project” A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

 

“Development well” A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

 

“Differential” An adjustment to the price of crude oil, NGL or natural gas from an established spot market price to reflect differences in the quality and/or location of crude oil, NGL or natural gas.

 

“Dry hole” or “dry well” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

 

“Economically producible” The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

 

“EUR” or “Estimated ultimate recovery” The sum of reserves remaining as of a given date and cumulative production as of that date.

 

“Exploratory well” An exploratory well is a well drilled to find a new field, to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir or to extend the limits of an existing reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well as those items are defined by the SEC.

 

“FASB” Financial Accounting Standards Board.

 

“Field” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

 

“First Amendment” means the First Amendment to Credit Agreement, dated as of June 23, 2021, among HighPeak Energy, Inc., as Borrower, Fifth Third Bank, National Association, as administrative agent, and the Guarantors and Lenders party thereto.

 

“Formation” A layer of rock which has distinct characteristics that differs from nearby rocks.

 

"GAAP" means accounting principles generally accepted in the United States of America.

 

“Gross wells” means the total wells in which a working interest is owned.

 

“Held by production” Acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of crude oil or natural gas.

 

“HighPeak business combination” means the transactions detailed in the Business Combination Agreement, which closed on August 21, 2020.

 

"HighPeak Energy" or the "Company" means, at the time of and after the HighPeak business combination, HighPeak Energy, Inc. and its subsidiaries (the “Successor”) and, prior to the HighPeak business combination, the Predecessor.

 

“HighPeak Energy Acquisition” means HighPeak Energy Acquisition Corp., a Delaware corporation. 

“HighPeak Group” means HighPeak Pure Acquisition, LLC, a Delaware limited liability company, and wholly owned subsidiary of HighPeak I, the HPK Contributors and Jack Hightower and each of their respective affiliates and certain permitted transferees, collectively.

 

“HighPeak I” means HighPeak Energy, LP, a Delaware limited partnership.

 

“HighPeak II” means HighPeak Energy II, LP, a Delaware limited partnership.

 

“Horizontal drilling” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

 

“HPK Contributors” means HighPeak I, HighPeak II and HPK GP.

 

“HPK GP” means HPK Energy, LLC, a Delaware limited liability company.

 

“HPK LP” means HPK Energy, LP, a Delaware limited partnership.

 

“Hydraulic fracturing” is the technique of stimulating the production of hydrocarbons from tight formations. The Company routinely utilizes hydraulic fracturing techniques in its drilling and completion programs. The process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.

 

“Lease operating expenses” The expenses of lifting crude oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, workover, marketing and transportation costs, insurance and other expenses incidental to production, but excluding lease acquisition or drilling or completion expenses.

 

"MBbl" means one thousand Bbls.

 

2

 

 

"MBoe" means one thousand Boes.

 

"Mcf" means one thousand cubic feet and is a measure of natural gas volume.

 

“MergerSub” means Pure Acquisition Merger Sub, Inc., a Delaware corporation.

 

"MMBbl" means one million Bbls.

 

"MMBtu" means one million Btus.

 

"MMcf" means one million cubic feet and is a measure of natural gas volume.

 

“Net acres” The percentage of total acres an owner has out of a particular number of gross acres or a specified tract. As an example. an owner who has 50% interest in 100 gross acres owns 50 net acres.

 

“Net production” Production that is owned by us, less royalties and production due others.

 

"NGL" means natural gas liquids, which are the heavier hydrocarbon liquids that are separated from the natural gas stream; such liquids include ethane, propane, isobutane, normal butane and gasoline.

 

"NYMEX" means the New York Mercantile Exchange.

 

"OPEC" means the Organization of Petroleum Exporting Countries.

 

“Operator” The individual or company responsible for the exploration and/or production of a crude oil or natural gas well or lease.

 

“Plugging” A downhole tool that is set inside the casing to isolate the lower part of the wellbore.

 

“Pooling” The bringing together of small tracts or fractional mineral interests in one or more tracts to form a drilling and production unit for a well under applicable spacing rules.

 

“Predecessor” refers to HPK LP for the period from January 1, 2020 to August 21, 2020.

 

“Production costs” Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. For a complete definition of production costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(20).

 

“Productive well” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

 

“Proration unit” A unit that can be effectively and efficiently drained by one well, as allocated by a governmental agency having regulatory jurisdiction.

 

“Prospect” A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

 

“Proved developed nonproducing reserves” or “PDNP” means proved reserves that are developed nonproducing reserves.

 

“Proved developed producing reserves” or “PDP” means proved reserves that are developed producing reserves.

 

“Proved developed reserves” means proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods and can be expected to be recovered through extraction technology installed and operational at the time of the reserve estimate and can be subdivided into PDP and PDNP reserves.

 

“Proved reserves” Those quantities of crude oil and natural gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

   

(i)  The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible crude oil or natural gas on the basis of available geoscience and engineering data.

   

(ii)  In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty.

   

(iii)  Where direct observation from well penetrations has defined a highest known crude oil elevation and the potential exists for an associated natural gas cap, proved crude oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

   

(iv)  Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

   

(v)  Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

 

3

 

 

“PUD” or “Proved undeveloped reserves” Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Undrilled locations can be classified as having PUDs only if a development plan has been adopted indicating that such locations are scheduled to be drilled within five (5) years, unless specific circumstances justify a longer time.

 

“Pure” means Pure Acquisition Corp., a Delaware corporation and wholly owned subsidiary of the Company.

 

“PV-10” When used with respect to crude oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10%. PV-10 is not a financial measure calculated in accordance with GAAP and generally differs from standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor standardized measure represents an estimate of the fair market value of our crude oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

 

“Realized price” The cash market price less all expected quality, transportation and demand adjustments.

 

“Recompletion” The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

 

“Reserves” Reserves are estimated remaining quantities of crude oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering crude oil and natural gas or related substances to market, and all permits and financing required to implement the project.

 

“Reservoir” A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

 

“Resources” Quantities of crude oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations.

 

“Revolving Credit Facility” refers to the Company’s senior secured reserve-based lending facility which matures June 17, 2024.

 

“Royalty” An interest in a crude oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof) but does not require the owner to pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

 

“SEC means the United States Securities and Exchange Commission.

 

“Second Amendment” means the Second Amendment to Credit Agreement, dated as of October 1, 2021, among HighPeak Energy, Inc., as Borrower, Fifth Third Bank, National Association, as administrative agent, and the Guarantors and Lenders party thereto.

 

“Service well” A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include natural gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

 

“Spacing” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 100-acre spacing, the distance between horizontal wellbores, e.g. 880-foot spacing or the number of wells per section, e.g. 6-well spacing. It is often established by regulatory agencies and/or the operator to optimize recovery of hydrocarbons.

 

“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” The present value (discounted at an annual rate of 10 percent) of estimated future net revenues to be generated from the production of proved reserves net of estimated income taxes associated with such net revenues, as determined in accordance with FASB guidelines as well as the rules and regulations of the SEC, without giving effect to non-property related expenses such as indirect general and administrative expenses, and debt service or to DD&A. Standardized measure does not give effect to derivative transactions.

 

“Stratigraphic test well” A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

 

“Third Amendment” means the Third Amendment to Credit Agreement, dated as of February 9, 2022, among HighPeak Energy, Inc., as Borrower, Fifth Third Bank, National Association, as administrative agent, and the Lenders party thereto.

 

4

 

 

“Undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas regardless of whether such acreage contains proved reserves.

 

“Unit” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

 

“U.S. means the United States.

 

“warrants” means warrants to purchase one share of HighPeak Energy common stock at a price of $11.50 per share.

 

“Wellbore” The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.

 

“Working interest” The right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.

 

“Workover” Operations on a producing well to restore or increase production.

 

“WTI means West Texas Intermediate, a light sweet blend of crude oil produced from fields in western Texas and is a grade of crude oil used as a benchmark in crude oil pricing.

 

With respect to information on the working interest in wells and acreage, “net” wells and acres are determined by multiplying “gross” wells and acres by the Company’s working interest in such wells or acres. Unless otherwise specified, wells and acreage statistics quoted herein represent gross wells or acres.

 

All currency amounts are expressed in U.S. dollars.

 

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

 

5

 

 

Cautionary Statement Concerning Forward-Looking Statements

 

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

 

 

the length, scope and severity of the ongoing coronavirus disease (“COVID-19”) pandemic, including the effects of related public health concerns and the impact of continued actions taken by governmental authorities and other third parties in response to the pandemic and its impact on commodity prices, supply and demand considerations, and storage capacity;

 

 

political instability or armed conflict in crude oil or natural gas producing regions, such as the escalating tensions currently occurring between Russia and Ukraine;

 

 

the market prices of crude oil, NGL, natural gas and other products or services;

 

 

the supply and demand for crude oil, NGL, natural gas and other products or services;

 

 

production and reserve levels;

 

 

drilling risks;

 

 

economic and competitive conditions;

 

 

the availability of capital resources;

 

 

capital expenditures and other contractual obligations;

 

 

weather conditions;

 

 

inflation rates;

 

 

the availability of goods and services;

 

 

legislative, regulatory or policy changes;

 

 

cyber-attacks;

 

 

occurrence of property acquisitions or divestitures;

 

 

the integration of acquisitions;

 

 

the securities or capital markets and related risks such as general credit, liquidity, market and interest-rate risks; and

 

 

other factors disclosed under “Part I, Items 1 and 2. Business and Properties”, “Part I, Item 1A. Risk Factors”, “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk,” and elsewhere in this Report.

 

6

 

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

 

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

 

7

 

 

HIGHPEAK ENERGY, INC.

 

 

PART I

 

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

 

Overview

 

HighPeak Energy, a Delaware corporation formed on October 29, 2019, is an independent crude oil and natural gas company engaged in the acquisition, development and production of crude oil, NGL and natural gas reserves. The Company’s assets are primarily located in Howard County, Texas, which lies within the northeastern part of the crude oil-rich Midland Basin. The Company holds two significant contiguous land positions with the northern position referred to as the Flat Top area and the southern position referred to as the Signal Peak area.

 

HighPeak Energy focuses on the Midland Basin and specifically the Howard County area of the Midland Basin. Over the last eight decades the Howard County area of the Midland Basin was partially developed with vertical wells using conventional methods, and has recently experienced significant redevelopment activity in the Lower Spraberry and Wolfcamp A formations utilizing modern horizontal drilling technology, with some operators having additional success developing the Middle Spraberry, Jo Mill, Wolfcamp B and Wolfcamp D formations, through the use of modern, high-intensity hydraulic fracturing techniques, decreased frac spacing, increased proppant usage and increased lateral lengths. Our interpretation of available IHS Markit data shows that Howard County has high crude oil mix percentage. The high margins driven by higher crude oil percentages, has encouraged a high level of drilling activity since 2016 through June 2021 and resulted in significant production growth compared with other counties in the Midland Basin.

 

The Company’s assets include certain rights, title and interests in crude oil and natural gas assets located primarily in Howard County, Texas, which lies within the northeastern part of the crude oil-rich Midland Basin. As of December 31, 2021, the Company’s assets consisted of two generally contiguous leasehold positions of approximately 82,023 gross (62,603 net) acres covering various subsurface depths, approximately 44% of which were held by production, with an average working interest of approximately 76%. We operate approximately 90% of the net acreage across the Company’s assets and approximately 98% of the net operated acreage provides for horizontal well locations with lateral lengths of 10,000 feet or greater in the formations covered by the Company’s assets. HighPeak Energy’s horizontal development drilling plan is initially focused on the Wolfcamp A and Lower Spraberry formations with additional wells planned in the Wolfcamp B and Wolfcamp D formations. We plan on utilizing multi-well pad development to lower drilling and completion cycle times, create infrastructure and facility economies of scale, reduce overall costs, and to optimize and maximize crude oil and natural gas recoveries, return on investment and value creation.

 

Available Information

 

The mailing address of HighPeak Energy’s principal executive office is 421 W. 3rd Street, Suite 1000, Fort Worth, Texas 76102. HighPeak Energy’s telephone number is (817) 850-9200. At December 31, 2021, HighPeak Energy had 30 full-time employees.

 

HighPeak Energy files or furnishes annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The SEC maintains a website (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers, including HighPeak Energy, that file electronically with the SEC.

 

The Company makes available free of charge through its website (www.highpeakenergy.com) its Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after it electronically files such material with, or furnishes it to, the SEC. In addition to the reports filed or furnished with the SEC, HighPeak Energy publicly discloses information from time to time in its press releases and investor presentations that are posted on its website or publicly during accessible investor conferences. Such information, including information posted on or connected to the Company’s website, is not a part of, or incorporated by reference in, this Annual Report or any other document the Company files with or furnishes to the SEC.

 

HighPeak Energy’s common stock and warrants are listed on the Nasdaq Global Market (“Nasdaq”) under the symbols “HPK” and “HPKEW,” respectively. HighPeak Energy’s CVRs are quoted on the Over-The-Counter Market (the “OTC”) under the symbol “HPKER.” Further, the Company has applied to list the CVRs on the Nasdaq. There is no assurance, however, that the CVRs will be listed on the Nasdaq.

 

8

 

Properties

 

The Company’s assets are located in the northeastern part of the Midland Basin. The majority of the acreage position is located across the eastern half of Howard County in two largely contiguous acreage blocks, the northern position of which is referred to as the Flat Top area and the southern position of which is referred to as the Signal Peak area. The Midland Basin is part of the Permian Basin of West Texas and Eastern New Mexico. The Permian Basin covers an area of about 96,000 square miles and is comprised of five (5) sub-regions including the Midland Basin, the Central Basin Platform, the Delaware Basin, the Northwest Shelf and the Eastern Shelf. The Central Basin Platform (“CBP”) is a central uplift, with the Delaware Basin located to the west of the CBP, and the Midland Basin located to the east of the CBP. The bulk of the Permian Basin’s increase in crude oil production since 2007 has come from several target zones including the Spraberry and Wolfcamp formations. The Permian Basin has produced billions of barrels of crude oil and natural gas and is estimated by the United States Geologic Survey to contain significant remaining hydrocarbon potential.

 

Through December 31, 2021, the Company (i) has drilled and completed a total of 44 gross (42.5 net) horizontal producing wells across our assets, (ii) has drilled and placed in operation 2 gross (2.0 net) salt-water disposal wells, (iii) has drilled an additional 22 gross (18.0 net) horizontal producing wells that are either awaiting completion or in various stages of completion, (iv) is in the process of drilling 5 gross (5.0 net) horizontal producing wells and (v) is in the process of drilling 1 gross (1.0 net) horizontal salt-water disposal well. The production from these wells is primarily sourced from the Lower Spraberry Shale and the Wolfcamp formations.

 

HighPeak Energy is currently developing its properties using four (4) drilling rigs and two (2) frac crews. Please see “Risk Factors—Risks Related to Our Business—Crude Oil, NGL and natural gas prices are volatile. Sustained periods of low, or declines in, crude oil, NGL and natural gas prices could adversely affect HighPeak Energy’s business, financial condition and results of operations and its ability to meet its capital expenditure obligations and other financial commitments” and “Risk Factors—Risks Related to Our Business —The ongoing outbreak of COVID-19 and other pandemic outbreaks could negatively impact HighPeak Energy’s business and results of operations.” HighPeak Energy expects to fund its forecasted capital expenditures with cash on its balance sheet, cash generated by operations, through borrowings under the Credit Agreement, proceeds from the issuance and sale of the 2024 Notes (as defined below) and, depending on market circumstances, potential future debt or equity offerings.

 

 

HighPeak Energy has discretion to modify its capital program. Because HighPeak Energy operates a high percentage of its acreage, capital expenditure amounts and timing are largely discretionary and within its control. HighPeak Energy determines its capital expenditures depending on a variety of factors, including, but not limited to, the success of its drilling activities, prevailing and anticipated prices for crude oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, drilling and acquisition costs and the level of participation by other working interest owners. A deferral of planned capital expenditures, particularly with respect to drilling and completing new wells, could result in a reduction in anticipated production and cash flows. Additionally, if HighPeak Energy curtails or reallocates priorities in its drilling program, HighPeak Energy may lose a portion of its acreage through lease expirations. However, in the event of any such curtailment or reallocation of priorities, HighPeak Energy would expect to prioritize lease retention to minimize any expirations.

 

Reserve Summary

 

The estimated proved reserves of the Company’s assets as of December 31, 2021 and 2020 were prepared by Cawley, Gillespie and Associates, Inc. (“CG&A”). As of December 31, 2021 and 2020, the Company’s assets contained 64,213 and 22,515 MBoe, respectively, of estimated proved reserves. In addition, as of December 31, 2021 and 2020, the estimated proved reserves of the Company’s assets were estimated by CG&A to be 92% and 94% crude oil and NGL, respectively, and 8% and 6% natural gas, respectively. The following table provides summary information regarding the estimated proved reserves data of the Company’s assets based on the 2021 Reserve Report and 2020 Reserve Report (each defined below) as of December 31, 2021 and 2020, respectively:

 

As of Date

 

Proved Total

(MBoe)(1)

   

% Crude Oil &

NGL

   

%

Developed

 

December 31, 2021

    64,213       92

%

    45

%

December 31, 2020

    22,515       94

%

    46

%

 

 


(1)

The estimated net proved reserves were determined using the unweighted arithmetic average first-day-of-the month prices for the prior twelve (12) months in accordance with guidelines established by the SEC. As of December 31, 2021 and 2020, for crude oil and NGL volumes, this average WTI spot price of $66.56 and $39.57 per barrel, respectively, was adjusted for quality, transportation and a regional price differential. As of December 31, 2021 and 2020, for natural gas volumes, the average Henry Hub spot price of $3.598 and $1.985 per MMBtu, respectively, was adjusted for energy content, gathering, transportation and processing fees and a regional price differential. All prices are held constant throughout the lives of the properties. As of December 31, 2021 and 2020, the average adjusted prices realized over the remaining lives of the Company’s assets by CG&A were $66.10 and $38.08 per barrel of crude oil, $29.76 and $12.27 per barrel of NGL and $0.786 and -$1.304 per Mcf of natural gas, respectively.

 

9

 

Reserve Data

 

Preparation of Reserve Estimates

 

The reserve estimates as of December 31, 2021 and 2020 included in this Annual Report are based on evaluations prepared by CG&A in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC (individually, the “2020 Reserve Report” and the “2021 Reserve Report” and, collectively the “Reserve Reports”). CG&A was selected for their historical experience and geographic expertise in engineering similar resources. The summary information pertaining to reserve estimates as of December 31, 2021 and 2020, respectively, of HighPeak Energy, prepared by CG&A, were led by W. Todd Brooker. Mr. Brooker is a Licensed Professional Engineer in the State of Texas and has been practicing at CG&A for 29 years and, including such 29 years, has over 31 years of total prior industry experience. Copies of the Reserve Reports are attached to this Annual Report as Exhibits 99.1 and 99.2.

 

Proved reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience 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. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to EUR with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease. The technical and economic data used in the estimation of the proved reserves include, but are not limited to, well logs, geologic maps, well-test data, production data (including flow rates), well data (including lateral lengths), historical price and cost information, and property ownership interests. CG&A uses this technical data, together with standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy. The proved developed reserves and EURs per well are estimated using performance analysis, analogs and volumetric analysis. The estimates of the proved developed reserves and EURs for each developed well are used to estimate the proved undeveloped reserves for each proved undeveloped location (utilizing type curves, statistical analysis, and analogy).

 

Internal Controls

 

The internal staffs of petroleum engineers and geoscience professionals at HighPeak Energy work closely with their independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to their independent reserve engineers in the preparation of their reserve report. Periodically, HighPeak Energy’s technical teams meet with the independent reserve engineers to review properties and discuss methods and assumptions used to prepare reserve estimates for the Company’s assets.

 

Reserve engineering is a subjective process of estimating volumes of economically recoverable crude oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, estimates of economically recoverable crude oil, NGL and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices, future production rates and costs. Please read the section entitled “Risk Factors” appearing elsewhere in this Annual Report.

 

The reserve estimates as of December 31, 2021 and 2020, respectively, were prepared by geologists and reservoir engineers who integrate geological, geophysical, engineering and economic data to produce high quality reserve estimates and economic forecasts. The process was supervised by Christopher Mundy, Vice President, Reserves and Evaluations, for HighPeak Energy, who has approximately 25 years of experience in crude oil and natural gas operations, reservoir engineering and management, reserves management, unconventional and conventional reservoir characterization and strategic planning.

 

The reserve estimation process and the reserve estimates of the Company’s assets as of December 31, 2021 and 2020, respectively, were reviewed and approved by our technical staff, other members of senior management and our Chief Executive Officer. The Reserve Reports prepared by CG&A contain further discussion of the reserve estimates and the procedures used in connection with its preparation.

 

10

 

The reserve estimates as of December 31, 2021 and 2020, included in this Annual Report are based on evaluations prepared by the independent petroleum engineering firm CG&A representing 100% of the Company’s assets’ total net proved reserves in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. The Independent Reserve Engineers were selected for their historical experience and geographic expertise in engineering similar resources.

 

Estimated Proved Reserves

 

The following tables present the estimated net proved crude oil and natural gas reserves as of December 31, 2021 and 2020, based on the Reserve Reports of the Company’s assets as of such date.

 

   

Proved Reserve Volumes

 
   

Crude Oil

(MBbls)

   

NGL

(MBbls)

   

 

Natural Gas

(MMcf)

   

Total

(MBoe)

   

%

 

As of December 31, 2021:

                                       

Developed

    22,610       3,540       14,611       28,585       45 %

Undeveloped

    29,215       3,838       15,450       35,628       55 %

Total proved reserves

    51,825       7,378       30,061       64,213       100 %

As of December 31, 2020:

                                       

Developed

    8,730       957       3,572       10,282       46 %

Undeveloped

    10,302       1,203       4,367       12,233       54 %

Total proved reserves

    19,032       2,160       7,939       22,515       100 %

 

Development of Proved Undeveloped Reserves

 

The following table summarizes the changes in HighPeak Energy’s proved undeveloped reserves during the period from August 22, 2020 through December 31, 2020 and for the year ended December 31, 2021 (the “Successor Period”):

 

   

Successor

 
   

Total (MBoe)

 

Proved undeveloped reserves at August 22, 2020

    5,764  

Extensions and discoveries

    7,015  

Revisions

    (546

)

Proved undeveloped reserves at December 31, 2020

    12,233  

Extensions and discoveries

    26,806  

Sales of minerals-in-place

    (184

)

Conversions into proved developed reserves

    (3,186

)

Revisions

    (41

)

Proved undeveloped reserves at December 31, 2021

    35,628  

 

The following table summarizes the changes in proved undeveloped reserves of the Predecessor during the period from January 1, 2020 through August 21, 2020 (the “Predecessor Period”):

 

   

Predecessor

 
   

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  

 

As of December 31, 2021, HighPeak Energy’s assets contained approximately 35,628 MBoe of proved undeveloped reserves, consisting of 29,215 MBbl of crude oil, 3,838 MBbl of NGL and 15,450 MMcf of natural gas. As of December 31, 2020, HighPeak Energy’s assets contained approximately 12,233 MBoe of proved undeveloped reserves, consisting of 10,302 MBbl of crude oil, 1,203 MBbl of NGL and 4,367 MMcf of natural gas. Proved undeveloped reserves will be converted from undeveloped to developed as we drill and complete each location and the wells begin production.

 

11

 

Proved undeveloped reserves changed during the Successor Period for the year ended December 31, 2021 primarily as a result of the following significant factors:

 

 

Extensions and discoveries of 26,806 MBoe related to new proved undeveloped locations added as a result of HighPeak Energy’s drilling activities;

 

Sales of minerals-in-place of 184 MBoe related to the divestiture of nonoperated non-core undeveloped drilling locations to a third party operator;

 

Conversions into proved developed reserves of 3,186 MBoe related to locations that were successfully drilled and completed during the year ended December 31, 2021; and

 

Downward revisions of 41 MBoe including downward adjustments of 350 MBoe related to forecasts and 32 MBoe primarily related to increased forecasted operating expenses, partially offset by an increase of 341 MBoe attributable to an increase in crude oil, NGL and natural gas prices.

 

Proved undeveloped reserves changed during the Successor Period from August 22, 2020 through December 31, 2020 primarily as a result of the following significant factors:

 

 

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 crude oil, NGL and natural gas prices.

 

Proved undeveloped reserves changed during the Predecessor Period primarily as a result of the following significant factors:

 

 

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 late in the first quarter of 2020 due to COVID-19 and the downturn in crude oil prices; and

 

Downward revisions of 241 MBoe including 181 MBoe resulting from adjustments to our forecasts and 60 MBoe resulting from a decrease in crude oil, NGL and natural gas prices.

 

To date, the Company invested the majority of its capital budget to drill unproved locations rather than convert proved undeveloped reserves to proved developed reserves. A portion of the Company’s development capital invested during the Successor Period was for the development of a water infrastructure system and the drilling of salt-water disposal wells to facilitate the Company’s increased water production, reduce its future water costs and reduce the use of trucking for its produced water disposal activities.

 

As of December 31, 2021, all of our proved undeveloped reserves are scheduled to be developed within five years from the date they were initially recorded.

 

PV-10

 

PV-10 is a non-GAAP financial measure and differs from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. We refer to PV-10 as the present value of estimated future net cash flows of estimated proved reserves using a discount rate of 10%. This amount includes projected revenues, estimated production costs, estimated future development costs and estimated cash flows related to future asset retirement obligations.

 

Unlike PV-10, the standardized measure deducts future U.S. federal income taxes and Texas margin taxes and abandonment obligations on wells with no proved reserves as of December 31, 2021 and 2020, respectively. Neither PV-10 nor standardized measure represents an estimate of the fair market value of the applicable crude oil and natural gas properties. It is industry standard to 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.

 

The following tables present the undiscounted estimated future net cash flows, PV-10 and standardized measure of the proved reserves of the Company at December 31, 2021 and 2020 (in thousands):

 

As of December 31, 2021

 

Proved

Developed

   

Proved

Undeveloped

   

Total Proved

 

Estimated future net cash flows

  $ 1,178,041     $ 1,236,250     $ 2,414,291  

Present value of estimated future net cash flows

  $ 742,037     $ 596,156     $ 1,338,193  

Present value of future income taxes/abandonment costs

                  $ (219,384

)

Standardized measure

                  $ 1,118,809  

 

12

 

 

As of December 31, 2020

 

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  

 

Estimated future net cash flows represents the estimated future revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using pricing differentials and costs under existing economic conditions as of December 31, 2021 and 2020, and assuming commodity prices as set forth below. For the purpose of determining prices used in our reserve reports, in accordance with SEC guidelines, CG&A uses the unweighted arithmetic average of the prices on the first day of each month in the 12-month period ended December 31, 2021 and 2020. These prices were $66.56 and $39.57 per Bbl for crude oil and $3.598 and $1.985 per MMBtu for natural gas, respectively, before adjustment for energy content, gathering, transportation and processing fees and basis differential adjustments. The average adjusted prices realized over the remaining lives of the Company’s assets by CG&A were $66.10 and $38.08 per barrel of crude oil, $29.76 and $12.27 per barrel of NGL and $0.786 and -$1.304 per Mcf of natural gas as of December 31, 2021 and 2020, respectively. These prices should not be interpreted as a prediction of future prices. The amounts shown do not give effect to non-property-related expenses, such as corporate general and administrative expenses and debt service, or to DD&A.

 

Production, Revenue and Price History

 

For a description of historical production, revenues, average sales prices and unit costs of the Company, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations.”

 

The following tables summarize the average net sales volumes, average unhedged sales prices by product and lease operating expenses of the Company for the years ended December 31, 2021 and 2020:

 

   

Year Ended December 31, 2021

 
   

Crude Oil

   

NGL

   

Natural Gas

   

Total

         
   

Sales

Volumes

   

Average

Sales

Price

   

Sales

Volumes

   

Average

Sales

Price

   

Sales

Volumes

   

Average

Sales

Price

   

Sales

Volumes

   

Average

Sales

Price

   

Lease

Operating

Expense

 
   

(MBbl)

   

($/Bbl)

   

(MBbl)

   

($/Bbl)

   

(MMcf)

   

($/Mcf)

   

(MBoe)

   

($/Boe)

   

($/Boe)

 
      3,002     $ 70.10       224     $ 35.11       1,020     $ 3.88       3,396     $ 64.82     $ 7.38  

Average net daily sales volumes (Boepd)

                                                    9,304                  

 

   

Year Ended December 31, 2020

 
   

Crude Oil

   

NGL

   

Natural Gas

   

Total

         
   

Sales

Volumes

   

Average

Sales

Price

   

Sales

Volumes

   

Average

Sales

Price

   

Sales

Volumes

   

Average

Sales

Price

   

Sales

Volumes

   

Average

Sales

Price

   

Lease

Operating

Expense

 
   

(MBbl)

   

($/Bbl)

   

(MBbl)

   

($/Bbl)

   

(MMcf)

   

($/Mcf)

   

(MBoe)

   

($/Boe)

   

($/Boe)

 
      634     $ 37.96       38     $ 14.06       199     $ 1.04       705     $ 34.94     $ 10.68  

Average net daily sales volumes (Boepd)

                                                    1,925                  

 

13

 

Productive Wells

 

Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and crude oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which HighPeak Energy holds an interest, and net wells are the sum of the fractional working interests owned in gross wells. The following table sets forth information relating to the productive wells in which HighPeak Energy holds a working interest as of December 31, 2021.

 

   

Crude Oil

   

Natural Gas

 
   

Gross

   

Net

   

Average

Working

Interest

   

Gross

   

Net

   

Average

Working

Interest

 

Horizontal:

                                               

Operated

    43       41.5       97

%

                n/a  

Non-operated

    16       5.8       37

%

                n/a  

Vertical:

                                               

Operated

    30       26.1       87

%

    5       3.8       75

%

Non-operated

    147       27.3       19

%

    5       1.3       25

%

Total:

                                               

Operated

    73       67.6       93

%

    5       3.8       75

%

Non-operated

    163       33.1       20

%

    5       1.3       25

%

 

Acreage

 

The following table sets forth certain information regarding the total developed and undeveloped acreage in which HighPeak Energy holds an interest as of December 31, 2021. Approximately 44% of the net acreage of HighPeak Energy was held by production at December 31, 2021.

 

Developed Acres(1)(4)

   

Undeveloped Acres(4)

   

Total Acres

 

Gross Acres(2)

   

Net Acres(3)

   

Gross Acres(2)

   

Net Acres(3)

   

Gross Acres(2)

   

Net Acres(3)

 
38,282       25,600       43,741       37,003       82,023       62,603  

 

 

(1)

Developed acres are acres spaced or assigned to productive wells or wells capable of production.

 

(2)

A gross acre is an acre in which HighPeak Energy holds a working interest. The number of gross acres is the total number of acres in which HighPeak Energy holds a working interest.

 

(3)

A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

 

(4)

Minor amounts of our developed and undeveloped acres do not cover all formation depths in underlying acreage.

 

Undeveloped Acreage Expirations

 

The following table sets forth the number of total net undeveloped acres as of December 31, 2021 across HighPeak Energy’s properties that will expire in 2022, 2023, 2024, 2025, 2026 and thereafter, unless production is established within the spacing units covering the acreage prior to the expiration dates or unless such leasehold rights are extended or renewed.

 

2022

    21,155  

2023

    2,716  

2024

    6,030  

2025

     

2026

     

Thereafter

    4,962  
      34,863  

 

With respect to the 21,155 net acres expiring in 2022 across our properties, HighPeak Energy intends to retain substantially all 21,155 net acres through initiating completion operations of existing wells and the drilling of new wells, with the remaining net acreage being retained either through lease renewals or extensions. HighPeak Energy intends to retain substantially all of its undeveloped acreage through its development plan. Please see “Item 1A. Risk Factors – Risks Related to Our Business – Certain of the undeveloped leasehold acreage of HighPeak Energy’s assets is subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are renewed.”

 

14

 

Drilling Activities

 

The following table describes new development and exploratory wells drilled within the Company’s assets during the year ended December 31, 2021 and the period from August 22, 2020 through December 31, 2020 (Successor), and the period from January 1, 2020 through August 22, 2020 and the year ended December 31, 2019 (Predecessor). The information should not be indicative of future performance, nor should it be assumed there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. As of December 31, 2021 and not included in the following table, were 6 gross (6.0 net) wells in the process of being drilled, including 1 gross (1.0 net) salt-water disposal well, and 22 gross (18.0 net) wells in the process of being completed. As of December 31, 2021, HighPeak Energy was running a three-rig program and was in the process of rigging up a fourth rig. Our development program may change based on capital availability and other factors.

 

   

Year Ended

December 31, 2021

(Successor)

   

Period from August 22,

2020 through

December 31, 2020

(Successor)

   

Period from January 1,

2020 through August

21, 2020 (Predecessor)

   

Year Ended

December 31,

2019 (Predecessor)

 
   

Gross

   

Net

   

Gross

   

Net

   

Gross

   

Net

   

Gross

   

Net

 

Development wells:

                                                               

Productive

    5       5.0                   1       1.0       1       0.8  

Dry

                                               

Exploratory wells:

                                                               

Productive

    25       19.5       14       13.8       6       6.0       2       2.0  

Dry

                                               

Service wells:

                                                               

Salt-Water Disposal

    1       1.0       1       1.0                          

 

Delivery Commitments

 

Beginning October 2021, the Company has a minimum volume commitment under its crude oil marketing agreement in its Flat Top area whereby it must deliver minimum gross volumes to its central tank battery facilities of 5,000 Bopd for the first year, 7,500 Bopd for the second year and 10,000 Bopd for the remaining eight years of the contract. However, the Company has the ability under the contract to cumulatively bank excess volumes delivered to offset future minimum volume commitments. For the period from October 1, 2021 to December 31, 2021, the Company had delivered approximately 17,247 Bopd under the contract, beginning to bank excess volumes at the outset. There are no material commitments to deliver a fixed and determinable quantity of natural gas production from the Company’s assets to customers under existing contracts. In addition, the Company has committed to deliver a total of 3.0 MMBbl of produced water for disposal with a third-party salt-water disposal company between July 24, 2020 and July 24, 2022. As of December 31, 2021, the Company has delivered approximately 2.5 MMBbl under the agreement. The agreement requires a payment for any volumes not delivered should the Company not perform under the agreement, indicating a remaining monetary commitment of approximately $236,000 as of December 31, 2021. Given the current production levels coupled with the wells planned to come on production in 2022 and beyond, the Company expects to meet the volume commitments under both of these agreements.

 

Operations

 

General

 

As of December 31, 2021, HighPeak Energy’s properties consisted of 82,023 gross (62,603 net) acres with an average working interest of approximately 76%.

 

Facilities

 

Production facilities related to HighPeak Energy’s properties are located near the producing wells and consist of salt-water disposal wells and related facilities, a salt-water disposal pipeline system throughout our northern acreage, storage tanks, two-phase and/or three-phase separation equipment, flowlines, metering equipment and safety systems. Predominant artificial lift methods include electrical submersible pumps (“ESP”), rod pumps and some plunger lifts. HighPeak Energy’s mostly contiguous acreage position allows for optimized capital expenditures for production facilities and associated water handling infrastructure.

 

Our properties are well serviced by existing crude oil, natural gas and water infrastructure and gathering systems. Currently, all the crude oil production is transported by truck using a competitive bidding process that has resulted in attractive terms relative to market indices. The natural gas production from our properties is gathered by third-party processors with the majority of the natural gas production currently processed to extract NGL. The extracted liquids and residue natural gas are sold to various intrastate and interstate markets on a competitive pricing basis.

 

15

 

Marketing and Customers

 

The following table sets forth the percentage of revenues attributable to customers who have accounted for 10% or more of revenues attributable to the Company’s assets during the years ended December 31, 2021, 2020 and 2019.

 

   

Years Ended December 31,

 

Major Customers

 

2021

   

2020

   

2019

 

Lion Oil Trading and Transportation, LLC

    94

%

    80

%

    *  

Enlink Crude Purchasing, LLC

    *       17

%

    67

%

Sunoco Partners Marketing & Terminals, LP

    *       *       21

%

 

* Less than 10%.

 

No other purchaser accounted for 10% or more of revenue attributable to the Company’s assets on a combined basis in the years ended December 31, 2021, 2020 or 2019. The loss of any such purchaser could adversely affect revenues attributable to the Company’s assets in the short term. Please see “Risk Factors—Risks Related to Our Business—HighPeak Energy depends upon a small number of significant purchasers for the sale of most of its crude oil, NGL and natural gas production. The loss of one or more of such purchasers could, among other factors, limit HighPeak Energy’s access to suitable markets for the crude oil, NGL and natural gas it produces.”

 

For crude oil sales, HighPeak Energy currently is party to a ten-year contract, with production being converted from trucked sales to piped sales with the construction of a crude oil gathering system directly connected to the refinery by the purchaser in our Flat Top area. Currently, crude oil sales are being trucked in our Signal Peak acreage until we have critical mass such that a pipeline system there would be feasible. The Flat Top crude oil contract is at known and published indices with a fixed primary term and an evergreen option thereafter. The contract contains a minimum volume commitment that commenced on October 1, 2021 based on the gross barrels delivered at the Company’s central tank battery facilities and is 5,000 Bopd for the first year, 7,500 Bopd for the second year and 10,000 Bopd for the remaining eight years of the contract. However, the Company has the ability under the contract to cumulatively bank excess volumes delivered to offset future minimum volume commitments. For the period from October 1, 2021 to December 31, 2021, the Company has delivered approximately 17,247 Bopd under the contract. The remaining monetary commitment as of December 31, 2021, if the Company never delivers any additional volumes under the agreement, is approximately $24.4 million. In addition, HighPeak Energy sells its natural gas production from the Company’s assets to multiple third-party purchasers pursuant to the terms of natural gas processing and purchase contracts at varying rates. The natural gas production is gathered and processed under agreements with a primary term and generally an evergreen extension option.

 

Competition

 

The crude oil and natural gas industry is intensely competitive, and HighPeak Energy competes with other companies that have greater resources. Many of these companies not only explore for and produce crude oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive crude oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than HighPeak Energy’s financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low crude oil and natural gas market prices. HighPeak Energy’s larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than HighPeak Energy can, which could adversely affect HighPeak Energy’s competitive position, as applicable. HighPeak Energy’s ability to acquire additional properties and to discover reserves in the future will be dependent upon its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because HighPeak Energy will have fewer financial and human resources than many companies in their industry, HighPeak Energy may be at a disadvantage in bidding for exploratory prospects and producing crude oil and natural gas properties.

 

There is also competition between crude oil and natural gas producers and other industries producing energy and fuel. For example, HighPeak Energy also faces indirect competition from alternative energy sources, including wind and solar. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which HighPeak Energy operates. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon HighPeak Energy’s future operations as related to the Company’s assets. Such laws and regulations may substantially increase the costs of developing crude oil and natural gas and may prevent or delay the commencement or continuation of a given operation. HighPeak Energy’s larger competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than HighPeak Energy can, which would adversely affect HighPeak Energy’s competitive positions, as applicable. See “Item 1A. Risk Factors—Risks Related to Our Business—Competition in the crude oil and natural gas industry is intense, which will make it more difficult for HighPeak Energy to acquire properties, market crude oil or natural gas and secure trained personnel.”

 

16

 

Seasonality of Business

 

Weather conditions can affect the demand for, and prices of, crude oil and natural gas. Demand for natural gas is typically higher in the fourth and first quarters resulting in higher prices while the demand for crude oil is typically higher during the second and third quarters. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

 

Title to Properties

 

As is customary in the crude oil and natural gas industry, HighPeak Energy, as operator of the Company’s assets, initially conducts (at minimum) a cursory review of the title to properties in connection with acquisition of leasehold acreage. HighPeak Energy has also obtained title opinion coverage on a majority of the Company’s assets and has performed customary reviews of the title to substantially all of the Company’s assets. Additionally, at such time as HighPeak Energy determines to conduct drilling operations on those properties, HighPeak Energy will conduct a thorough title examination, will obtain division order title opinions, and will perform curative work with respect to any significant defects that may exist prior to: (i) commencement of drilling operations; and (ii) the initial disbursement of associated revenues. HighPeak Energy has obtained title opinions on substantially all its producing properties. The crude oil and natural gas properties within the Company’s assets are subject to customary royalty and other interests, liens for current taxes and other burdens which HighPeak Energy believes does not materially interfere with the use of, or affect the carrying value of, the properties.

 

Prior to completing an acquisition of producing crude oil and natural gas properties, HighPeak Energy may perform title reviews on the most significant leases and may obtain a title opinion, obtain an updated title opinion or review previously obtained title opinions.

 

HighPeak Energy believes it has satisfactory title to all the material properties within the Company’s assets in accordance with standards generally accepted in the crude oil and natural gas industry. Although title to the Company’s assets is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the crude oil and natural gas industry, none of these liens, restrictions, easements, burdens or encumbrances will likely materially detract from the value of the properties within the Company’s assets or from HighPeak Energy’s interests in these properties or materially interfere with HighPeak Energy’s use of these properties in the operation of their business. In addition, HighPeak Energy believes they have obtained sufficient rights-of-way grants and permits from public authorities and private parties for them to operate their business in all material respects as described in this Annual Report.

 

Crude Oil and Natural Gas Leases

 

The typical crude oil and natural gas lease agreement covering the properties within the Company’s assets provides for the payment of royalties to the mineral owner for all crude oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on the properties within the Company’s assets are approximately 25%.

 

Regulation of the Crude Oil and Natural Gas Industry

 

Our operations are substantially affected by federal, state and local laws and regulations. Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the crude oil and natural gas industry are regularly considered by Congress, the states, Federal Energy Regulatory Commission (“FERC”), the U.S. Environmental Protection Agency (“EPA”), the Department of Transportation (“DOT”), other federal agencies and the courts. We cannot predict when or whether any such proposals may become effective. We do not believe that we would be affected by any such action materially differently than similarly situated competitors.

 

In addition, unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered.

 

Regulation of Production of Crude Oil and Natural Gas

 

Crude oil and natural gas production and related operations are substantially affected by federal, state and local laws and regulations. In particular, crude oil and natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All the jurisdictions in which the Company’s assets are located have statutory provisions regulating the development and production of crude oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Crude oil and natural gas operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of crude oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

 

17

 

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Such laws and regulations are frequently amended or reinterpreted. Therefore, it is not possible to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the crude oil and natural gas industry are regularly considered by Congress, the states, FERC, the EPA, the DOT, other federal agencies and the courts. It is not possible to predict when or whether any such proposals may become effective.

 

Federal, state and local statutes and regulations require permits for drilling, salt-water disposal and pipeline operations, drilling bonds and reports concerning operations. The Company’s assets are located in Texas, which regulates drilling and operating activities by, among other things, requiring permits for the drilling of wells, maintaining bonding requirements to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells.

 

The laws of Texas also govern a number of conservation matters, including provisions for the unitization or pooling of crude oil and natural gas properties, the establishment of maximum allowable rates of production from crude oil and natural gas wells, the regulation of well spacing or density and plugging and abandonment of wells. The effect of these regulations is to limit the amount of crude oil and natural gas that the wells within the Company’s assets can produce and to limit the number of wells or the locations that can be drilled within the Company’s assets, although operators can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, various states impose a production or severance tax with respect to the production and sale of crude oil, NGL and natural gas within its jurisdiction. The failure to comply with these rules and regulations can result in substantial penalties.

 

Regulation Affecting Sales and Transportation of Commodities

 

Sales prices of crude oil, NGL and natural gas are not currently regulated and are made at market prices. Although prices of these energy commodities are currently unregulated, Congress historically has been active in their regulation. We cannot predict whether new legislation to regulate crude oil and natural gas, or the prices charged for these commodities might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, the proposals might have on our operations. Sales of crude oil and natural gas may be subject to certain state and potentially federal reporting requirements.

 

The price and terms of service of transportation of the commodities, including access to pipeline transportation capacity, are subject to extensive federal and state regulation. Such regulation may affect the marketing of crude oil and natural gas produced, as well as the revenues received for sales of such production. Gathering systems may be subject to state ratable take and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination, crude oil and natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase, or accept for gathering, without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes may affect whether and to what extent gathering capacity is available for crude oil and natural gas production, if any, of the drilling program and the cost of such capacity. Further, state laws and regulations govern rates and terms of access to intrastate pipeline systems, which may similarly affect market access and cost.

 

The FERC regulates interstate natural gas pipeline transportation rates and service conditions. The FERC is continually proposing and implementing new rules and regulations affecting interstate transportation. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and to promote market transparency. We do not believe that our drilling program will be affected by any such FERC action in a manner materially differently than other similarly situated natural gas producers.

 

Gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states onshore and in state waters. Although the FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, the FERC’s determinations as to the classification of facilities is done on a case-by-case basis. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

 

18

 

In addition to the regulation of natural gas pipeline transportation, the FERC has jurisdiction over the purchase or sale of natural gas or the purchase or sale of transportation services subject to the FERC’s jurisdiction pursuant to the Energy Policy Act of 2005. Under this law, it is unlawful for “any entity,” including producers such as us, that are otherwise not subject to the FERC’s jurisdiction under the Natural Gas Act of 1938 to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. The FERC’s rules implementing this provision make it unlawful, in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud, to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading or to engage in any act or practice that operates as a fraud or deceit upon any person. The Energy Policy Act of 2005 also gives the FERC authority to impose civil penalties for violations of the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 up to $1,269,500 per day per violation (adjusted annually based on inflation). The anti-manipulation rule applies to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under Order 704 (defined below).

 

In December 2007, the FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”). Under Order 704, any market participant, including a producer such as us, that engages in wholesale sales or purchases of natural gas that equal or exceed 2.2 million MMBtus of physical natural gas in the previous calendar year, must annually report such sales and purchases to the FERC on Form No. 552 on May 1 of each year. Form No. 552 contains aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize or contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 is intended to increase the transparency of the wholesale natural gas markets and to assist the FERC in monitoring those markets and in detecting market manipulation.

 

The FERC also regulates rates and service conditions for interstate transportation of liquids, including crude oil and NGL, under the Interstate Commerce Act (the “ICA”). Prices received from the sale of liquids may be affected by the cost of transporting those products to market. The ICA requires that pipelines maintain a tariff on file with the FERC. The tariff sets forth the established rates as well as the rules and regulations governing the service. The ICA requires, among other things, that rates and terms and conditions of service on interstate common carrier pipelines be “just and reasonable.” Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential. Shippers have the power to challenge new and existing rates and terms and conditions of service before the FERC.

 

Rates of interstate liquids pipelines are currently regulated by the FERC primarily through an annual indexing methodology, under which pipelines increase or decrease their rates in accordance with an index adjustment specified by the FERC. For the five-year period beginning on July 1, 2016, the FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 1.23%. This adjustment is subject to review every five (5) years. Under the FERC’s regulations, a liquids pipeline can request the authority to charge market-based rates for transportation service if it satisfies certain criteria, and also can request a rate increase that exceeds the rate obtained through application of the indexing methodology by using a cost-of-service approach, but only after the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology. Increases in liquids transportation rates may result in lower revenue and cash flows.

 

In addition, due to common carrier regulatory obligations of liquids pipelines, capacity must be prorated among shippers in an equitable manner in the event there are nominations in excess of capacity. Therefore, requests for service by new shippers or increased volume by existing shippers may reduce the capacity available to us. Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that we rely upon for liquids transportation could have a material adverse effect on our business, financial condition, results of operations and cash flows. However, we believe that access to liquids pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

 

Intrastate liquids pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate liquids pipeline regulation and the degree of regulatory oversight and scrutiny given to intrastate liquids pipeline rates, varies from state to state. We believe that the regulation of liquids pipeline transportation rates will not affect our operations in any way that is materially different from the effects on our similarly situated competitors.

 

In addition to the FERC’s regulations, we are required to observe anti-market manipulation laws with regard to our physical sales of energy commodities. In November 2009, the FTC issued regulations pursuant to the Energy Independence and Security Act of 2007 intended to prohibit market manipulation in the petroleum industry. Violators of the regulations face civil penalties of up to $1,210,340 per violation per day (adjusted annually based on inflation). In July 2010, Congress passed the Dodd-Frank Act, which incorporated an expansion of the authority of the Commodity Futures Trading Commission (“CFTC”) to prohibit market manipulation in the markets regulated by the CFTC. This authority, with respect to crude oil swaps and futures contracts, is similar to the anti-manipulation authority granted to the FTC with respect to crude oil purchases and sales. In July 2011, the CFTC issued final rules to implement its new anti-manipulation authority. The rules subject violators to a civil penalty of up to the greater of $1,162,183 (adjusted annually based on inflation) or triple the monetary gain to the person for each violation.

 

19

 

Regulation of Environmental and Occupational Safety and Health Matters

 

Crude oil and natural gas development operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing occupational safety and health, the discharge of materials into the environment or otherwise relating to environmental protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations may require the acquisition of a permit before drilling or other regulated activity commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines; govern the sourcing and disposal of water used in the drilling and completion process; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier, seismically active areas and other protected areas; require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; establish specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of production.

 

The regulatory burden on the crude oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly construction, drilling, water management, completion, emission or discharge limits or waste handling, disposal or remediation obligations could increase the cost to our operators of developing our properties. Moreover, accidental releases or spills may occur in the course of operations on our properties, causing our operators to incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons.

 

The following is a summary of the more significant existing environmental and occupational health and safety laws and regulations, as amended from time to time, to which operations related to the Company’s assets may be subject.

 

Hazardous Substances and Waste Handling

 

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered responsible for the release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the disposal site or the site where the release occurred and persons that disposed or arranged for the disposal or the transportation for disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The failure of an operator other than the Company to comply with applicable environmental regulations may, in certain circumstances, be attributed to the Company.

 

The Resource Conservation and Recovery Act (“RCRA”) and analogous state laws, impose detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced waters and other wastes associated with the development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the EPA or state agencies under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws. Moreover, it is possible that these particular crude oil and natural gas development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in the costs to manage and dispose of generated wastes. In addition, in the course of operating the Company’s assets, it is possible that some amounts of ordinary industrial wastes will be generated, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics.

 

The Company’s assets consist of numerous properties that have been used for crude oil and natural gas development and production activities for many years. Hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from properties within the Company’s assets, or on, under or from other locations, including off-site locations, where such substances have been taken for recycling or disposal. In addition, some of the properties within the Company’s assets have been operated by third-parties or by previous owners or operators who have treated and disposed of hazardous substances, wastes or petroleum hydrocarbons. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, the Company could be required to undertake responsive or corrective measures with respect to the Company’s assets, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.

 

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Water Discharges, Fluid Disposal and NORM

 

The Water Pollution Control Act, also known as the Clean Water Act (“CWA”) and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other crude oil and natural gas wastes, into or near navigable waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”). The scope of jurisdiction under the CWA has been subject to several rulemakings by the EPA in recent years and is subject to ongoing litigation; additionally, in December 2021, the EPA and Corps published the first of two proposed rulemakings, including a definition largely in keeping with a broader pre-2015 definition and related regulatory guidance and case law. A second proposed rulemaking expanding on this definition is expected later in 2022. Therefore, the future reach of the CWA is uncertain at this time. To the extent any rule expands the scope of the CWA’s jurisdiction, the Company could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Obtaining permits has the potential to delay the development of crude oil and natural gas projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of crude oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.

 

Pursuant to these laws and regulations, the Company may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of crude oil.

 

The primary federal law related specifically to crude oil spill liability is the Oil Pollution Act (“OPA”), which amends and augments the crude oil spill provisions of the CWA and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of crude oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. For example, operators of certain crude oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of a crude oil discharge or that poses the substantial threat of discharge is one type of “responsible party” who is liable. The OPA applies joint and several liability, without regard to fault, to each liable party for crude oil removal costs and a variety of public and private damages. Although defenses exist, they are limited.

 

Fluids resulting from crude oil and natural gas production, consisting primarily of salt-water, are disposed by injection in belowground disposal wells regulated under the Underground Injection Control (“UIC”) program and analogous state laws. The UIC program requires permits from the EPA or an analogous state agency for the construction and operation of disposal wells, establishes minimum standards for disposal well operations, and may restrict the types and quantities of fluids that may be disposed. In addition, state and federal regulatory agencies have focused on a possible connection between crude oil and natural gas activity and induced seismicity. For example, in 2015, the United States Geological Study identified eight states, including Texas, with areas of induced seismicity that could be attributed to fluid injection or crude oil and natural gas extraction.

 

In response to these concerns, some states, including Texas, have imposed additional requirements for the permitting of produced water disposal wells, such as volume and pressure limitations or seismicity thresholds for temporary cessations of activity. In September 2021, the Texas Railroad Commission (“TRRC”) issued a notice to operators in the city of Midland area to reduce daily injection volumes following multiple earthquakes above 3.5 magnitude over an 18-month period. The notice also required disposal well operators to provide injection data to TRRC staff to further analyze seismicity in the area. Subsequently, the TRRC ordered the indefinite suspension of all deep produced water injection wells in the area, effective December 31, 2021. While the ultimate outcome of these outcomes is uncertain, the adoption and implementation of any new laws or regulations that restrict our operators’ ability to use hydraulic fracturing or dispose of produced water gathered from drilling and production activities by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring them to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of operations.

 

In addition, naturally occurring radioactive material (“NORM”) is brought to the surface in connection with crude oil and natural gas production. Comprehensive federal regulation does not currently exist for NORM; however, the EPA has studied the impacts of technologically enhanced NORM, and several states, including Texas, regulate the disposal of NORM. Concerns have arisen over traditional NORM disposal practices (including discharge through publicly owned treatment works into surface waters), which may increase the costs associated with management of NORM. To the extent that federal or state regulation increases the compliance costs for NORM disposal, operators may incur additional costs that may make some properties unprofitable to operate.

 

Air Emissions

 

The Clean Air Act (“CAA”) and comparable state laws restrict the emission of air pollutants from many sources (e.g., compressor stations), through the imposition of air emissions standards, construction and operating permitting programs and other compliance requirements. These laws and regulations may require the Company to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard for ozone from 75 to 70 parts per billion and completed attainment/non-attainment designations in July 2018. While the EPA has determined that counties in which the Company currently operates are in attainment with the new ozone standards, these determinations may be revised in the future. Additionally, although the EPA announced in December 2020 that it intended to leave ozone NAAQS unchanged at 70 parts per billion, this decision has been subject to legal challenges, and the Biden Administration has announced plans to reconsider this standard. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new facilities or modify existing facilities in these newly designated non-attainment areas and result in increased expenditures for pollution control equipment, the costs of which could be significant.

 

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In addition, the EPA has adopted new rules under the CAA that require the reduction of volatile organic compounds from certain fractured and refractured crude oil and natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. In addition, the regulations place new requirements to detect and repair volatile organic compounds at certain crude oil and natural gas facilities. In May 2016, the EPA also finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the crude oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of crude oil and natural gas projects and increase the costs of development, which costs could be significant.

 

Regulation of Greenhouse Gas Emissions

 

At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted rules under authority of the CAA that, among other things, establish prevention of significant deterioration (“PSD”) construction and Title V operating permit reviews for greenhouse gases (“GHG”) emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions. Under these regulations, facilities required to obtain PSD permits must meet “best available control technology” standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the U.S., including, among others, onshore and offshore production facilities, which include certain of our operators’ operations. The EPA has expanded the GHG reporting requirements to all segments of the crude oil and natural gas industry, including gathering and boosting facilities as well as completions and workovers from hydraulically fractured crude oil wells.

 

Federal agencies also have begun directly regulating emissions of methane from crude oil and natural gas operations. For example, in June 2016, the EPA published New Source Performance Standards, known as Subpart OOOOa, that requires certain new, modified or reconstructed facilities in the crude oil and natural gas sector to reduce these methane gas emissions. Although, in September 2020, the Trump Administration published regulations to rescind methane specific requirements and remove the transmission and storage segments from the crude oil and natural gas source category, the U.S. Congress approved, and President Biden signed into law, a resolution under the Congressional Review Act to repeal the September 2020 revisions, effectively reinstating the prior standards. Additionally, in November 2021, the EPA issued a proposed rule that, if finalized, would establish OOOOb as a new source and OOOOc as first-time existing source standards of performance for methane and VOC emissions for crude oil and natural gas source category. Owners or operators of affected emission units or processes would have to comply with specific standards of performance that may include leak detecting using optical gas imaging and subsequent repair requirements, reduction of regulated emissions through capture and control systems, zero-emission requirements for certain equipment or processes, operations and maintenance requirements and requirements for “green well” completions. The EPA plans to issue a supplemental proposal enhancing the proposed rulemaking in 2022 that will contain proposed rule text, which was not included in the November 2021 proposed rule, and anticipates issuing a final rule by the end of 2022. Several states have also adopted rules to control and minimize methane emissions from the production of crude oil and natural gas, and others have considered or may consider doing so in the future.

 

At the international level, in December 2015, the United States and 194 other participating countries adopted the Paris Agreement, which calls for each participating country to establish their own nationally determined standards for reducing carbon output. President Biden recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing again at the 26th Conference to the Parties on the UN Framework Convention on Climate Change (“COP26”), during which multiple announcements were made, including a call for parties to eliminate fossil fuel subsidies and pursue further action on non-CO2 GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. The impacts of these actions cannot be predicted at this time.

 

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The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions for our operators, and could have a material adverse effect on our business, financial condition and results of operations. On January 27, 2021, President Biden signed an executive order calling for substantial action on climate change, including, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across agencies and economic sectors. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. In late 2020, the Federal Reserve announced it has joined the Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused on addressing climate-related risks in the financial sector and, in November 2021, issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Limitation of investments in and financing for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities. Ultimately, this could make it more difficult for operators to secure funding for exploration and production activities. Additionally, activist shareholders have introduced proposals that may seek to force companies to adopt aggressive emission reduction targets or restrict more carbon-intensive activities. While we cannot predict the outcomes of such proposals, they could make it more difficult for operators to engage in exploration and production activities. In addition, the SEC has announced that it will propose rules that, amongst other matters, will establish a framework for the reporting of climate risks. However, no such rules have been proposed to date, and we cannot predict what any such rules may require. To the extent the rules impose additional reporting obligations, we could face increased costs. Finally, many scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climate events that could have an adverse effect on the Company’s operations. For more information, please see our risk factor titled “The operations of HighPeak Energy are subject to a variety of risks arising from climate change.”

 

Hydraulic Fracturing Activities

 

Hydraulic fracturing is an important and common practice that is used to stimulate production of crude oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is regularly used by operators of the Company’s assets. Hydraulic fracturing is typically regulated by state crude oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act (“SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. The EPA has issued final regulations under the CAA establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing, and also finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

 

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, the TRRC has adopted a “well integrity rule,” which updated the requirements for drilling, putting pipe down and cementing wells. The rule also imposes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.

 

Certain governmental reviews are either underway or have been conducted that focus on the environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances.

 

Compliance with existing laws has not had a material adverse effect on operations related to the Company’s assets, but if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where the Company’s assets are located, operators could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells.

 

Endangered Species Act and Migratory Birds

 

The Endangered Species Act (“ESA”) and (in some cases) comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. The U.S. Fish and Wildlife Service (“FWS”) may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for crude oil and natural gas development. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the FWS was required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. The agency missed the deadline but continues to review species for listing under the ESA. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (“MBTA”). The federal government in the past has pursued enforcement actions against crude oil and natural gas companies under the MBTA after dead migratory birds were found near reserve pits associated with drilling activities. Although the Department of Interior under the Trump Administration issued a rulemaking revoking its prior enforcement policy and concluded that an incidental take is not a violation of the MBTA, the Biden Administration has published a final rule rescinding this rulemaking, in addition to publishing an advanced notice of proposed rulemaking to codify a new definition for take that includes such incidental take as a violation of the MBTA. In any event, the identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause increased costs arising from species protection measures or could result in limitations on development activities that could have an adverse impact on the ability to develop and produce reserves within the Company’s assets. For example, a review is currently pending to determine whether the dunes sagebrush lizard should be listed and, on June 1, 2021, the FWS proposed to list two distinct population segments of the lesser prairie-chicken under the ESA. If these species or others are listed, the FWS and similar state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. If a portion of the Company’s assets were to be designated as a critical or suitable habitat, it could adversely impact the value of the Company’s assets.

 

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Occupational Safety and Health Act

 

The Company will be subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. Violations can result in civil or criminal penalties as well as required abatement. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that the Company organizes and/or disclose information about hazardous materials used or produced in its operations and that this information be provided to employees, state and local governmental authorities and citizens.

 

Related Permits and Authorizations

 

Many environmental laws require permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation or other crude oil and natural gas activities, and require maintaining these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal or litigation, which could in certain cases delay or halt projects and cease production or operation of wells, pipelines and other operations related to the Company’s assets.

 

Related Insurance 

 

The Company maintains insurance against some risks associated with above or underground contamination that may occur as a result of development activities. However, this insurance is limited to activities at the well site and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by the Company.

 

Human Capital

 

We believe that our employees are the foundation to fostering the safe operation of our assets. We foster a collaborative, inclusive and safety-minded work environment, focused on working safely every day. We seek to identify qualified internal and external talent for our organization, enabling us to execute on our strategic objectives.

 

As of December 31, 2021, we employed 30 full-time employees dedicated to operating the Company’s assets. In connection with the HighPeak business combination, the Company acquired the entity that employs the employees dedicated to operating its assets and retained such employees that are necessary to efficiently operate its assets. None of these employees are covered by collective bargaining agreements, and we consider our employee relations to be good.

 

Employee Health and Safety

 

Safety is important to us and begins with the protection and safety of our employees, contractors and communities where we operate. We value people above all else and remain committed to making safety and health our top priority. We continually seek to maintain and deepen our safety culture by providing a safe working environment that encourages active employee engagement, including implementing safety programs to achieve improvements in our safety culture.

 

The Company has taken steps to keep its employees safe during the COVID-19 pandemic by implementing preventative measures and developing response plans intended to minimize unnecessary risk of exposure and infection among its employees. The Company has also modified certain business practices (including those related to non-operational employee work locations, such as a significant reduction in physical participation in meetings, events and conferences) to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, and other governmental and regulatory authorities.

 

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Diversity and Inclusion

 

We are committed to fostering a work environment in which all employees treat each other with dignity and respect. This commitment extends to providing equal employment and advancement opportunities based on merit and experience. We continually strive to attract a diverse workforce by identifying potential candidates to advance and strengthen our human capital management program.

 

Our employee demographic profile allows us to promote inclusion of thought, skill, knowledge and culture across our operations to achieve our social obligations and commitments.

 

Talent Development and Retention

 

We value and provide opportunities for cross training and increased responsibilities, including leadership learning. These efforts allow us to recruit from within our organization for future vocational and occupational opportunities. Our management promotes formal and informal learning and development throughout the organization. We offer developmental programs focused on building the skills of our employees and to help advance employee careers, knowledge, and skillsets through training and related programs.

 

Legal Proceedings

 

The Company is not party to lawsuits related to its assets other than those arising in the ordinary course of business or that will be retained by the contributors. Due to the nature of the crude oil and natural gas business, HighPeak Energy may, from time to time, be involved in other routine litigation or subject to disputes or claims related to the operation of the Company’s assets, including workers’ compensation claims and employment related disputes. In the opinion of management, none of these other pending litigation, disputes or claims against HighPeak Energy, if decided adversely, would have a material adverse effect on the Company’s assets.

 

Offices

 

The principal field office for HighPeak Energy is located at 303 West Wall Street, Suite 2202, Midland, Texas 79701.

 

ITEM 1A. RISK FACTORS

 

There are many factors that may affect our business, financial condition and results of operations and investments in us. Security holders and potential investors in our securities should carefully consider the risk factors set forth below, as well as the discussion of other factors that could affect us or investments in us included elsewhere in this Annual Report. If one or more of these risks were to materialize, our business, financial condition or results of operations could be materially and adversely affected. These known material risks could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.

 

We are providing the following summary of the risk factors contained in our Annual Report to enhance the readability and accessibility of our risk factor disclosures. We encourage our stockholders to carefully review the full risk factors contained in this Annual Report in their entirety for additional information regarding the risks and uncertainties that could cause our actual results to vary materially from recent results or from our anticipated future results.

 

Risks Related to Our Business

 

 

Crude oil, NGL and natural gas prices are volatile and sustained periods of low, or declines in, crude oil, NGL and natural gas prices could adversely affect HighPeak Energy’s business, financial condition and results of operations.

 

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 increase production and reserves.

 

The ongoing outbreak of COVID-19 and other pandemic outbreaks could negatively impact HighPeak Energy’s business and results of operation.

  Political instability or armed conflict in crude oil or natural gas producing regions, such as the escalating tensions currently occurring between Russia and Ukraine.
 

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, in whole or in part, 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 crude oil and natural gas properties, including commodity prices decreasing to a level such that future undiscounted cash flows from its properties are less than their carrying value.

 

Drilling for and producing crude oil and natural gas are high risk activities with many uncertainties that could adversely affect HighPeak Energy’s business, financial condition or results of operations.

 

We have entered into certain long-term contracts that require us to pay fees to our service providers based on minimum volumes regardless of actual volume throughput and that may limit our ability to use other service providers.

 

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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 non-operated assets.

 

The identified drilling locations on HighPeak Energy’s assets are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, HighPeak Energy may not be able to raise the entire amount of capital that would be necessary to drill such locations.

 

Adverse weather conditions may negatively affect HighPeak Energy’s operating results and drilling activities.

 

HighPeak Energy’s operations are substantially dependent on the availability of sand and water. Restrictions on its ability to obtain sand and water may have an adverse effect on its financial condition, results of operations and cash flows.

 

The Company’s assets are located in the northeastern 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 crude oil and natural gas.

 

HighPeak Energy depends upon a small number of significant purchasers for the sale of most of its crude oil, NGL and natural gas production. The loss of one or more of such purchasers could, among other factors, limit HighPeak Energy’s access to suitable markets for the crude oil, NGL and natural gas 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 increasing attention to ESG matters that may impact its business.

 

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 variety of risks arising from climate change.

 

Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the completion of crude 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.

 

Risks Related to Ownership of our Securities

 

 

The HighPeak Group, including the Principal Stockholder Group, has significant influence over HighPeak Energy.

 

HighPeak Energy is a “controlled company” within the meaning of Nasdaq rules and 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 not exempt from such corporate governance 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 of your investment.

 

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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 takes advantage of certain exemptions from disclosure requirements available to emerging growth companies, which could make its common stock 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.

 

Risks Related to Our Business

 

Crude Oil, NGL and natural gas prices are volatile. Sustained periods of low, or declines in, crude oil, NGL and natural gas prices could adversely affect HighPeak Energys business, financial condition and results of operations and its ability to meet its capital expenditure obligations and other financial commitments.

 

The prices HighPeak Energy receives for its crude oil, NGL and natural gas production heavily influence its revenue, profitability, access to capital, future rate of growth and the carrying value of its properties. The markets for crude oil and natural gas have been volatile historically and are likely to remain volatile in the future. For example, during the period from January 1, 2018 through December 31, 2021, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $16.70 to a high of $81.22, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.50 to a high of $6.20. For the month of April 2020, the calendar month average NYMEX WTI crude oil price was $16.70 per Bbl and the last trading day NYMEX natural gas price was $1.63 per MMBtu. The fall in prices was a result of OPEC and other crude oil producing nations (“OPEC+”) being unable to reach an agreement on production levels for crude oil, which resulted in Saudi Arabia and Russia initiating efforts to increase production. The convergence of these events, along with the significantly reduced demand because of the COVID-19 pandemic, created an unprecedented global crude oil and natural gas supply and demand imbalance, reduced global crude oil and natural gas storage capacity, caused crude oil and natural gas prices to decline significantly and resulted in continued volatility in crude oil, NGL and natural gas prices into the second quarter of 2020. In April 2020, extreme shortages of transportation and storage capacity caused the NYMEX WTI front month crude oil price for May 2020 delivery to drop to -$37.63 per barrel on the second to last day of the trading period for the contract. This single day of negative pricing resulted from the holders of expiring May 2020 crude oil purchase contracts being unable or unwilling to take physical delivery of crude oil and accordingly forced to make payments to purchasers of such contracts to transfer the corresponding purchase obligations. Prices have recovered from their April 2020 lows, with the calendar month average NYMEX WTI crude oil price of $71.69 per Bbl and the last trading day NYMEX natural gas price of $5.44 per MMBtu for the month of December 2021. However, there can be no certainty that commodity prices will sustain at these levels or continue to increase.

 

Likewise, NGL, which are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which has different uses and pricing characteristics, have also fluctuated widely during this period. The prices HighPeak Energy receives for its production, and the levels of HighPeak Energy’s production, will depend on numerous factors beyond HighPeak Energy’s control, which include the following:

 

 

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

   

 

 

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

   

 

 

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 OPEC, its members and other state-controlled crude oil companies relating to crude oil price and production controls;

   

 

 

the level of global exploration, development and production;

   

 

 

the level of global inventories;

 

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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.

 

Lower commodity prices may reduce HighPeak Energy’s cash flow and borrowing ability. If HighPeak Energy is unable to obtain needed capital or financing on satisfactory terms, its ability to develop future reserves could be adversely affected. Also, using lower prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits. In addition, sustained periods with lower crude oil and natural gas prices may adversely affect drilling economics and HighPeak Energy’s ability to raise capital, which may require it to re-evaluate and postpone or eliminate its development program, and result in the reduction of some proved undeveloped reserves and related standardized measure. If HighPeak Energy is required to curtail its drilling program, HighPeak Energy may be unable to hold leases that are scheduled to expire, which may further reduce reserves. As a result, a substantial or extended decline in commodity prices may materially and adversely affect HighPeak Energy’s future business, financial condition, results of operations, liquidity and ability to finance planned capital expenditures.

 

HighPeak Energys 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 increase production and reserves.

 

The crude oil and natural gas industry is capital-intensive. HighPeak Energy has evaluated multiple development scenarios under multiple potential commodity price assumptions. Under its four-rig development scenario, HighPeak Energy would expect to incur approximately $715 to $760 million of capital expenditures for drilling, completion, facilities and equipping costs and $35 to $40 million for field infrastructure, land and other costs during 2022. The ability to make these capital expenditures will be highly dependent on the price of crude oil and available funding of HighPeak Energy. Commodity prices have already recovered from their April 2020 lows, with the calendar month average NYMEX WTI price of $71.69 per Bbl and last trading day NYMEX natural gas price of $5.44 per MMBtu for the month of December 2021. HighPeak Energy ran a one-rig program since September 2020 and increased to a two-rig program beginning in July 2021, a three-rig program beginning in November 2021 and a four-rig program beginning in January 2022. However, HighPeak Energy recognizes that commodity prices remain highly volatile and that its liquidity is limited, and as a result, there is no certainty that HighPeak Energy will operate a four-rig development program in the future.

 

HighPeak Energy expects to fund its forecasted capital expenditures with cash on its balance sheet, cash generated by operations, through borrowings under the Credit Agreement, proceeds from the issuance and sale of the 2024 Notes and, depending on market circumstances, potential future debt or equity offerings. For terms of the Revolving Credit Facility, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Liquidity.”

 

Cash flows from operations are subject to significant uncertainty. As a result, the amount of liquidity that HighPeak Energy will have in the future is uncertain.

 

HighPeak Energy’s financing needs may require it to alter or increase its capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of additional indebtedness would require that an additional portion of cash flow from operations be used for the payment of interest and principal on its indebtedness, thereby further reducing its ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities would be dilutive to existing stockholders. The actual amount and timing of future capital expenditures may differ materially from estimates as a result of, among other things: commodity prices; actual drilling results; the availability of drilling rigs and other services and equipment; and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in actual capital expenditures, which would negatively impact HighPeak Energy’s ability to increase production.

 

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HighPeak Energy’s cash flow from operations and access to capital are subject to a number of variables, including:

 

 

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 crude 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.

 

Should HighPeak Energy’s revenues or the borrowing base under the Revolving Credit Facility decrease as a result of lower crude oil, NGL and natural gas prices, operational difficulties, declines in reserves or for any other reason, HighPeak Energy may have limited ability to obtain the capital necessary to sustain operations at expected levels. If additional capital is needed, HighPeak Energy may not be able to obtain debt or equity financing on terms acceptable to it, if at all. If cash flow generated by HighPeak Energy’s operations or available debt financing, including borrowings under the Revolving Credit Facility, are insufficient to meet its capital requirements, the failure to obtain additional financing could result in a curtailment of the development of HighPeak Energy’s properties, which in turn could lead to a decline in reserves and production and could materially and adversely affect HighPeak Energy’s business, financial condition and results of operations. If HighPeak Energy seeks and obtains additional financing, subject to the restrictions in the instruments governing its existing debt, the addition of new debt to existing debt levels could intensify the operational risks that HighPeak Energy will face. Further, adding new debt could limit HighPeak Energy’s ability to service existing debt service obligations.

 

The ongoing outbreak of COVID-19 and other pandemic outbreaks could negatively impact HighPeak Energys business and results of operations.

 

HighPeak Energy may face additional risks related to the ongoing outbreak of COVID-19 pandemic or other future pandemic outbreaks. International, federal, state and local public health and governmental authorities took extraordinary and wide-ranging actions to contain and combat the outbreak and spread of COVID-19 in regions across the United States and the world, including mandates for many individuals to substantially restrict daily activities and for many businesses to curtail or cease normal operations. While some of these restrictions have been lifted in many countries, including the United States, to the extent the COVID-19 outbreak worsens, governments may reimpose similar restrictions. The extent to which the COVID-19 outbreak or any other pandemic impacts HighPeak Energy’s results will depend on future developments, which are highly uncertain and cannot be predicted, including new information which may emerge concerning the severity of COVID-19 and the actions to contain COVID-19 or treat its impact, among others.

 

For example, prices decreased to a level in April 2020 that caused HighPeak Energy to halt its drilling program and to curtail a substantial portion of its existing production. However, prices increased and HighPeak Energy management began returning wells to production in mid-July 2020. Commodity prices recovered from their April 2020 lows, with the calendar month average NYMEX WTI price of $71.69 per Bbl and last trading day NYMEX natural gas price of $5.44 per MMBtu for the month of December 2021.  However, HighPeak Energy recognizes that commodity prices remain highly volatile and that its liquidity may be limited, and as a result, there is no certainty that HighPeak Energy will operate a four-rig drilling program in the future.

 

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The marketability of HighPeak Energys production is dependent upon transportation, storage and other facilities, certain of which it does not control. If these facilities are unavailable, in whole or in part, HighPeak Energys operations could be interrupted, and its revenues reduced.

 

The marketability of HighPeak Energy’s crude oil and natural gas production depends in part upon the availability, proximity and capacity of transportation, processing and storage facilities owned and operated by third parties. Any significant interruption in service from, damage to, or lack of available capacity in these systems and facilities may result in the shutting-in of producing wells or the delay or discontinuance of development plans for our properties. Federal and state regulation of crude oil, NGL and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines or processing facilities, infrastructure or capacity constraints, and general economic conditions could adversely affect our ability to produce, gather, process, transport or market crude oil, NGLs and natural gas. In addition, even if these systems and facilities remain open generally, certain quality specifications implemented thereby may restrict our ability to utilize such systems and facilities. Further, insufficient production from wells to support the construction of pipeline facilities by purchasers or a significant disruption in the availability of HighPeak Energy’s or third-party transportation facilities or other production facilities could adversely impact HighPeak Energy’s ability to deliver to market or produce crude oil and natural gas and thereby cause a significant interruption in HighPeak Energy’s operations. If, in the future, HighPeak Energy is unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounters production related difficulties, it may be required to shut in or curtail production. Any such shut-in or curtailment, or an inability to obtain favorable terms for delivery of the crude oil and natural gas produced from HighPeak Energy’s fields, would materially and adversely affect its financial condition and results of operations.

 

Production may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline, gathering, processing or transportation system access or capacity, field labor issues or strikes, or we might voluntarily curtail production in response to market or other conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flows and results of operations.

 

Certain factors could require HighPeak Energy to shut-in production or cease its capital expenditure program.

 

During 2020, the reduction in global demand caused by COVID-19, coupled with the recent actions of foreign crude oil producers such as Saudi Arabia and Russia, materially decreased global crude oil prices and generated a surplus of crude oil. This significant surplus created a saturation of storage and caused imminent crude storage constraints, which led to, and in the future may further lead to the shut-in of production of our wells due to lack of sufficient markets or lack of availability and capacity of processing, gathering, storing and transportation systems. Additionally, several state crude oil and natural gas authorities, including the TRRC, implemented or considered implementing crude oil and natural gas production limits in an effort to stabilize declining commodity prices. To the extent adopted, such production limits could not only reduce our revenue, but also, if wells are required to be shut-in for extended periods of time due to such production limits, result in expenditures related to well plugging and abandonment. Cost increases necessary to bring wells back online may be significant enough that such wells would become uneconomic at low commodity price levels, which may lead to decreases in HighPeak Energy’s proved reserve estimates and potential impairments and associated charges to its earnings. HighPeak Energy curtailed the majority of its production in April 2020. However, prices increased, and HighPeak Energy management began returning its wells to production in mid-July 2020. As of December 31, 2021, HighPeak Energy was running a three-rig program and was in the process of adding a fourth rig which it hopes to keep running for the duration of 2022. HighPeak Energy will continue to monitor the extent by which prices continue to increase and/or stabilize as we execute our capital expenditure program. Any shut in or curtailment of the crude oil, NGL and natural gas produced from HighPeak Energy’s fields could adversely affect its financial condition and results of operations.

 

Certain of the undeveloped leasehold acreage of HighPeak Energys assets is subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are renewed.

 

As of December 31, 2021, approximately 44% of HighPeak Energy’s acreage was held by production. The leases for net acreage not held by production will expire at the end of their primary term unless production is established in paying quantities under the units containing these leases or the leases are extended or renewed. From 2022 through 2024, approximately 34%, 4% and 10%, respectively, of the acreage associated with the leases are set to expire. If the leases expire and HighPeak Energy is unable to renew the leases, HighPeak Energy will lose its right to develop the related properties. Although HighPeak Energy intends to hold substantially all these leases through its development drilling program or extend substantially all the net acreage associated with identified drilling locations through a combination of exploratory and development drilling, a portion of such leases may be extended or renewed. Additionally, any payments related to such extensions or renewals may be more than anticipated. Please see “Items 1 and 2: Business and Properties—Reserve Data—Undeveloped Acreage Expirations” for more information regarding acreage expirations and our plans for extending our acreage. HighPeak Energy’s ability to drill and develop its acreage and establish production to maintain its leases depends on a number of uncertainties, including crude oil, NGL and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors.

 

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Certain factors could require HighPeak Energy to write-down the carrying values of its crude oil and natural gas properties, including commodity prices decreasing to a level such that future undiscounted cash flows from its properties are less than their carrying value.

 

Accounting rules require that HighPeak Energy periodically review the carrying value of its properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, HighPeak Energy may be required to write-down the carrying value of its properties. A write-down constitutes a non-cash impairment charge to earnings. Historically, crude oil, NGL and natural gas prices have been volatile. For example, during the period from January 1, 2018 through December 31, 2021, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $16.70 to a high of $81.22, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.50 to a high of $6.20.

 

Likewise, NGL, which are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which has different uses and pricing characteristics, have also fluctuated widely during this period.

 

Sustained levels of depressed commodity prices, or further decreases, in the future could result in impairments of HighPeak Energy’s properties, which could have a material adverse effect on results of operations for the periods in which such charges are taken. HighPeak Energy could experience material write-downs as a result of lower commodity prices or other factors, including low production results or high lease operating expenses, capital expenditures or transportation fees.

 

Part of HighPeak Energys business strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

 

HighPeak Energy’s operations involve utilizing some of the latest drilling and completion techniques as developed by HighPeak Energy and its service providers. The difficulties HighPeak Energy may face drilling horizontal wells may include, among others:

 

 

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.

 

Difficulties that HighPeak Energy may face while completing its wells include the following, among others:

 

 

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.

 

Use of new technologies may not prove successful and could result in significant cost overruns or delays or reductions in production, and, in extreme cases, the abandonment of a well. In addition, certain of the new techniques HighPeak Energy adopts may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing. Furthermore, the results of drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer and emerging formations and areas have limited or no production history and, consequently, HighPeak Energy may be more limited in assessing future drilling results in these areas. If its drilling results are less than anticipated, the return on investment for a particular project may not be as attractive as anticipated, and HighPeak Energy could incur material write downs of unevaluated properties and the value of undeveloped acreage could decline in the future.

 

For example, potential complications associated with the new drilling and completion techniques that HighPeak Energy intends to utilize may cause HighPeak Energy to be unable to develop its assets in line with current expectations and projections. Further, recent well results may not be indicative of HighPeak Energy’s future well results.

 

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Drilling for and producing crude oil and natural gas are high risk activities with many uncertainties that could adversely affect HighPeak Energys business, financial condition or results of operations.

 

HighPeak Energy’s future financial condition and results of operations will depend on the success of its development, production and acquisition activities, which are subject to numerous risks beyond its control, including the risk that drilling will not result in commercially viable crude oil and natural gas production.

 

HighPeak Energy’s decisions to develop or purchase prospects or properties will depend, in part, on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “—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.” In addition, the cost of drilling, completing and operating wells will often be uncertain.

 

Further, many factors may curtail, delay or cancel scheduled drilling operations, including:

 

 

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 crude oil and natural gas leaks, crude 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 crude oil and natural gas prices;

   

 

 

limited availability of financing on acceptable terms;

   

 

 

title issues; and

   

 

 

other market limitations in HighPeak Energy’s industry.

 

We have entered into certain long-term contracts that require us to pay fees to our service providers based on minimum volumes regardless of actual volume throughput and that may limit our ability to use other service providers.

 

From time to time, HighPeak Energy has entered into and may in the future enter into certain crude oil, natural gas or produced water gathering or transportation agreements, natural gas processing agreements, NGL transportation agreements, produced water disposal agreements or similar commercial arrangements with midstream companies. Certain of these agreements require HighPeak Energy to meet minimum volume commitments, often regardless of actual throughput.

 

The Company has committed to deliver 3.0 MMBbls of produced water for disposal with a third-party salt-water disposal company between July 24, 2020 and July 24, 2022. As of December 31, 2021, the Company has delivered approximately 2.5 MMBbls under the contract. The contract requires a payment for any volumes not delivered should the Company not perform under the agreements, indicating a remaining monetary commitment of approximately $236,000 as of December 31, 2021. Given the production levels coupled with the wells planned to come on production during the remainder of 2022, the Company expects to meet the volume commitment under this agreement.

 

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In May 2021, the Company entered into a crude oil marketing contract with Lion Oil Trading & Transportation, LLC (“Lion”) as the purchaser and DKL Permian Gathering, LLC (“DKL”) as the gatherer and transporter. The contract includes the Company’s current and future crude oil production from its horizontal wells in Flat Top where DKL is in the process of constructing a crude oil gathering system and custody transfer meters to all the Company’s central tank batteries. The contract contains a minimum volume commitment commencing October 2021 based on the gross barrels delivered at the Company’s central tank battery facilities and is 5,000 Bopd for the first year, 7,500 Bopd for the second year and 10,000 Bopd for the remaining eight years of the contract. However, the Company has the ability under the contract to cumulatively bank excess volumes delivered to offset future minimum volume commitments. For the period from October 1, 2021 to December 31, 2021, the Company has delivered approximately 17,247 Bopd under the contract. The remaining monetary commitment at December 31, 2021, assuming the Company never delivers another barrel of crude oil, was $24.4 million. The Company believes it will meet the minimum volume commitment based on the Company’s current gross production levels and the current Flat Top development plan.

 

If HighPeak Energy has insufficient production to meet the minimum volume commitments under any of these agreements, HighPeak Energy’s cash flow from operations will be reduced, which may require HighPeak Energy to reduce or delay its planned investments and capital expenditures, or seek alternative means of financing, all of which may have a material adverse effect on HighPeak Energy’s results of operation.

 

Our current and future debt levels may limit our flexibility to obtain financing and to pursue other business opportunities.

 

As of December 31, 2021, after giving effect to our recent offering of 2024 Notes in February 2022 and the uses of proceeds therefrom, we had approximately $225 million of outstanding indebtedness, including $225 million of our 2024 Notes and no indebtedness outstanding under our Revolving Credit Facility, and available capacity under our Revolving Credit Facility of $138.8 million. Our level of indebtedness could have important consequences to us, including the following:

 

 

Our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired, or such financing may not be available on favorable terms;

   

 

 

covenants contained in our existing and future credit and debt agreements and the indenture governing the 2024 Notes will require us to meet financial tests that may affect our financial flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

   

 

 

a substantial portion of our cash flow is required to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and payments of our debt obligations, including the 2024 Notes;

   

 

 

our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally; and

   

 

 

our flexibility in responding to changes in business and economic conditions may be limited.

 

Any of these factors could result in a material adverse effect on our business, financial condition, results of operations, business prospects and ability to satisfy our obligations under the 2024 Notes and our Revolving Credit Facility.

 

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all. The amount of cash we have available for distribution to holders of our common units depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.

 

HighPeak Energy may not be able to generate sufficient cash to service all its indebtedness and may be forced to take other actions to satisfy its debt obligations that may not be successful.

 

As of December 31, 2021, after giving effect to our recent offering of 2024 Notes in February 2022 and the uses of proceeds therefrom, we had approximately $225 million of outstanding indebtedness, including $225 million of our 2024 Notes and no indebtedness outstanding under our Revolving Credit Facility, and available capacity under our Revolving Credit Facility of $138.8 million.

 

In June 2021, the Company entered into the First Amendment, to among other things, (i) complete the semi-annual borrowing base redetermination process, which increased the borrowing base from $40.0 million to $125.0 million and (ii) modify the terms of the Credit Agreement to increase the aggregate elected commitments from $20.0 million to $125.0 million. In October 2021, the Company entered into the Second Amendment to, among other things, (i) complete a semi-annual borrowing base redetermination process, which increased the borrowing base from $125 million to $195 million and (ii) modify the terms of the Credit Agreement to increase the aggregate elected commitments from $125 million to $195 million. In February 2022, the Company entered into the Third Amendment to, among other things, reduce the borrowing base from $195 million to $138.8 million due to the issuance of $225.0 million 10.00% senior unsecured notes due in 2024. The Company borrowed or expects to borrow under the Revolving Credit Facility to fund its development program and general corporate purposes, which may include accelerating drilling and development activities given the current commodity price environment and funding further acquisition and consolidation of bolt-on assets. The Company may seek to further increase the borrowing base under the Revolving Credit Facility or otherwise seek to incur additional indebtedness.

 

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HighPeak Energy’s ability to make scheduled payments on or to refinance its indebtedness obligations under the Revolving Credit Facility, the 2024 Notes or other debt financing sources HighPeak Energy decides to utilize, will depend on HighPeak Energy’s financial condition and operating performance, which are subject to prevailing commodity prices, economic and competitive conditions, industry cycles and certain financial, business and other factors affecting HighPeak Energy’s operations, many of which are beyond HighPeak Energy’s control. HighPeak Energy may not be able to maintain a level of cash flow from operating activities sufficient to permit HighPeak Energy to pay the principal, premium, if any, and interest on its indebtedness.

 

If HighPeak Energy’s cash flow and capital resources are insufficient to fund debt service obligations, HighPeak Energy may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance existing indebtedness. HighPeak Energy’s ability to restructure or refinance indebtedness will depend on the condition of the capital markets and its financial condition at such time. Any refinancing of indebtedness may be at higher interest rates and may require HighPeak Energy to comply with more onerous covenants, which could further restrict business operations. The terms of the Revolving Credit Facility, the Indenture governing the 2024 Notes and HighPeak Energy’s future debt instruments may restrict it from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis may result in a reduction of HighPeak Energy’s credit rating, which could harm its ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, HighPeak Energy could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. The Revolving Credit Facility and the Indenture governing the 2024 Notes limit, and any other debt financing HighPeak Energy enters into may limit, HighPeak Energy’s ability to dispose of assets and use the proceeds from such dispositions. HighPeak Energy may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit HighPeak Energy to meet scheduled debt service obligations.

 

Restrictions in HighPeak Energys Revolving Credit Facility, the indenture governing the 2024 Notes and any future debt agreements could limit HighPeak Energys growth and ability to engage in certain activities.

 

The terms and conditions governing HighPeak Energy’s Revolving Credit Facility and the 2024 Notes currently, and any future additional indebtedness are expected to:

 

 

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.

 

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

 

Any significant reduction in HighPeak Energys borrowing base under the Revolving Credit Facility as a result of periodic borrowing base redeterminations or otherwise may negatively impact HighPeak Energys ability to fund its operations.

 

The Company had a borrowing base and aggregate elected commitments of $195.0 million with respect to its Credit Facility prior to the effective date of the Third Amendment in February 2022. In February 2022 and simultaneously with the issuance of $225.0 million of senior unsecured notes discussed later, the Company entered into the Third Amendment to the Credit Agreement to, among other things, (i) reduce the borrowing base from $195.0 million to $138.8 million and (ii) modify the terms of the Credit Agreement to reduce aggregate elected commitments from $195.0 million to $138.8 million. The Revolving Credit Facility limits the amounts HighPeak Energy can borrow up to the lesser of (i) the aggregate elected commitments of the lenders and (ii) a borrowing base amount, which the lenders will in good faith periodically redetermine, in accordance with their respective usual and customary crude oil and natural gas lending criteria, based upon the loan value of the proved crude oil and natural gas reserves located within the geographic boundaries of the United States included in the most recent reserve report provided to the lenders.

 

The Revolving Credit Facility requires scheduled semi-annual borrowing base redeterminations based on updated reserve reports. Additionally, the borrowing base is subject to unscheduled reductions due to certain issuances of new junior lien indebtedness, unsecured indebtedness or subordinated indebtedness, certain sales or acquisitions of borrowing base properties or early monetizations or terminations of certain hedge or swap positions. A reduced borrowing base could render HighPeak Energy unable to access adequate funding under the Revolving Credit Facility. Additionally, if the aggregate amount outstanding under the Revolving Credit Facility exceeds the borrowing base at any time, HighPeak Energy would be required to repay any indebtedness in excess of the borrowing base or to provide mortgages on additional borrowing base properties to eliminate such excess. As a result of a mandatory prepayment and/or reduced access to funds under the Revolving Credit Facility, HighPeak Energy may be unable to implement its drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on its financial condition and results of operations.

 

Hedging transactions expose HighPeak Energy to counterparty credit risk and may become more costly or unavailable.

 

HighPeak is required under its Revolving Credit Facility to enter into certain derivative instruments. Hedging transactions expose HighPeak Energy to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and HighPeak Energy may not be able to realize the benefit of the derivative contract. Derivative instruments also expose HighPeak Energy to the risk of financial loss in some circumstances, including when there is an increase in the differential between the underlying price in the derivative instrument and actual prices received or there are issues with regard to legal enforceability of such instruments.

 

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If HighPeak Energy enters into derivative instruments that require cash collateral and commodity prices or interest rates change in an adverse manner, our cash otherwise available for use in operations would be reduced which could limit HighPeak Energy’s ability to make future capital expenditures and make payments on indebtedness, and which could also limit the size of the borrowing base. Future collateral requirements will depend on arrangements with counterparties, highly volatile crude oil, NGL and natural gas prices and interest rates.

 

In addition, derivative arrangements could limit the benefits to be received from increases in the prices for natural gas, NGL and crude oil, which could also have an adverse effect on HighPeak Energy’s financial condition. If natural gas, NGL or crude oil prices upon settlement of derivative contracts exceed the price at which commodities have been hedged, HighPeak Energy will be obligated to make cash payments to counterparties, which could, in certain circumstances, be significant.

 

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In addition, U.S. regulators adopted a final rule in November 2019 implementing a new approach for calculating the exposure amount of derivative contracts under the applicable agencies’ regulatory capital rules, referred to as the standardized approach for counterparty credit risk (“SA-CCR”). As adopted, certain financial institutions are required to comply with the new SA-CCR rules beginning on January 1, 2022. The new rules could significantly increase the capital requirements for certain participants in the over-the-counter derivatives market in which HighPeak Energy participates. These increased capital requirements could result in significant additional costs being passed through to end-users or reduce the number of participants or products available in the over-the-counter derivatives market. The effects of these regulations could reduce HighPeak Energy’s hedging opportunities, or substantially increase the cost of hedging, which could adversely affect HighPeak Energy’s business, financial condition and results of operations.

 

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.

 

The process of estimating crude oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. For example, December 31, 2021 reserves were based on commodity prices that may prove to be higher than the prices received for HighPeak Energy’s future production. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves. To prepare the reserve estimates included in this Annual Report, CG&A analyzed available geological, geophysical, production and engineering data and projected the production rates and timing of development expenditures. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as crude oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

 

Actual future production, crude oil, NGL and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable crude oil and natural gas reserves may vary from the estimates included in this Annual Report. For instance, initial production rates reported by HighPeak Energy or other operators may not be indicative of future or long-term production rates, and recovery efficiencies may be worse than expected and production declines may be greater than estimated and may be more rapid and irregular compared with initial production rates. In addition, estimates of proved reserves may be adjusted to reflect additional production history, results of development activities, current commodity prices and other existing factors. Any significant variance could materially affect the estimated quantities and present value of reserves. Moreover, there can be no assurance that reserves will ultimately be produced or that proved undeveloped reserves will be developed within the periods anticipated.

 

You should not assume that the present value of future net revenues from the reserves presented in this Annual Report is the current market value of the estimated reserves of our assets. Actual future prices and costs may differ materially from those used in the present value estimate. If spot prices are below such calculated amounts, using more recent prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits.

 

The standardized measure of estimated reserves may not be an accurate estimate of the current fair value of estimated crude oil and natural gas reserves.

 

Standardized measure is a reporting convention that provides a common basis for comparing crude oil and natural gas companies subject to the rules and regulations of the SEC. Standardized measure requires historical twelve-month pricing as required by the SEC as well as operating and development costs prevailing as of the date of computation. Consequently, it may not reflect the prices ordinarily received or that will be received for crude oil and natural gas production because of varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the crude oil and natural gas properties. For example, historical twelve-month prices may prove to be higher than prices received for HighPeak Energy’s future production. As a result, estimates included in this Annual Report of future net cash flow may be materially different from the future net cash flows that are ultimately received. Therefore, the standardized measure of estimated reserves included in this Annual Report should not be construed as accurate estimates of the current fair value of such proved reserves.

 

Properties HighPeak Energy acquires may not produce as projected, and HighPeak Energy may be unable to determine reserve potential, identify liabilities associated with such properties or obtain protection from sellers against such liabilities.

 

During 2021, HighPeak Energy entered into multiple unrelated agreements to effect certain bolt-on acquisitions from various third parties, all of which having closed as of the date of this Annual Report, whereby it acquired a number of crude oil and natural gas properties, which aggregated to approximately 11,000 net acres. Acquiring crude oil and natural gas properties requires HighPeak Energy to assess reservoir and infrastructure characteristics, including such assets and/or other recoverable reserves, future crude oil and natural gas prices and their applicable differentials, development and operating costs, and potential liabilities, including environmental liabilities. In connection with these assessments, HighPeak Energy performs a review of the subject properties that it believes to be generally consistent with industry practices. Such assessments are inexact and inherently uncertain. For these reasons, the properties HighPeak Energy acquired, or may acquire in the future, may not produce as expected. In connection with the assessments, HighPeak Energy performs a review of the subject properties, but such a review may not reveal all existing or potential problems. In the course of due diligence, HighPeak Energy may not review every well, pipeline or associated facility. HighPeak Energy cannot necessarily observe structural and environmental problems, such as groundwater contamination, when a review is performed. HighPeak Energy may be unable to obtain contractual indemnities from the seller for liabilities created prior to HighPeak Energy’s purchase of the property. HighPeak Energy may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with its expectations. Additionally, the success of future acquisitions will depend on HighPeak Energy’s ability to integrate effectively the then-acquired business into its then-existing operations. The process of integrating acquired assets may involve unforeseen difficulties and may require a disproportionate amount of managerial and financial resources. HighPeak Energy’s failure to achieve consolidation savings, to incorporate the additionally acquired assets into its then-existing operations successfully, or to minimize any unforeseen operational difficulties, or the failure to acquire future assets at all, could have a material adverse effect on its financial condition and results of operations.

 

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HighPeak Energy is not the operator on all of 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, and could be liable for certain financial obligations of the operators or any of its contractors, to the extent such operator or contractor is unable to satisfy such obligations.

 

HighPeak Energy is not the operator on all its acreage or drilling locations, and there is no assurance that it will operate all of HighPeak Energy’s other future drilling locations. As a result, HighPeak Energy will have limited ability to exercise influence over the operations of the drilling locations operated by its partners, and there is the risk that HighPeak Energy’s partners may at any time have economic, business or legal interests or goals that are inconsistent with ours. Furthermore, the success and timing of development activities operated by its partners will depend on a number of factors that will be largely outside of HighPeak Energy’s control, including:

 

 

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.

 

This limited ability to exercise control over the operations and associated costs of some of HighPeak Energy’s drilling locations could prevent the realization of targeted returns on capital in drilling or acquisition activities. Further, HighPeak Energy may be liable for certain financial obligations of the operator of a well in which it owns a working interest to the extent such operator becomes insolvent and cannot satisfy such obligations. Similarly, HighPeak Energy may be liable for certain obligations of contractors to the extent such contractor becomes insolvent and cannot satisfy their obligations. The satisfaction of such obligations could have a material adverse effect on HighPeak Energy’s financial condition. For more information about certain of HighPeak Energy’s assets, see the sections entitled “Items 1 and 2: Business and Properties” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

The identified drilling locations on the HighPeak Energys assets are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, HighPeak Energy may not be able to raise the entire amount of capital that would be necessary to drill such locations.

 

HighPeak Energy’s management and technical teams have specifically identified and scheduled certain drilling locations as an estimation of future multi-year drilling activities on its assets. These drilling locations represent a significant part of HighPeak Energy’s growth strategy. HighPeak Energy’s ability to drill and develop these locations will depend on a number of uncertainties, including crude oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals, the cooperation of other working interest owners and other factors. Because of these uncertain factors, HighPeak Energy cannot be certain whether the numerous identified drilling locations will ever be drilled or if it will be able to produce natural gas or crude oil from these or any other drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the drilling locations are obtained, the leases for such acreage will expire.

 

As a result of the limitations described in this prospectus, HighPeak Energy may be unable to drill many of these identified locations. In addition, significant additional capital will be required over a prolonged period in order to pursue the development of these locations, and HighPeak Energy may not be able to raise or generate the capital required to do so. See “—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 increase production and reserves.” Any drilling activities HighPeak Energy is able to conduct on these locations may not be successful, may not result in production or additions to estimated proved reserves and could result in a downward revision of estimated proved reserves, which could have a material adverse effect on the borrowing base under the Revolving Credit Facility or future business and results of operations. Additionally, if HighPeak Energy curtails its drilling program, it may lose a portion of its acreage through lease expirations and may be required to reduce estimated proved reserves, which could reduce the borrowing base under the Revolving Credit Facility or any other debt financing entered into.

 

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Adverse weather conditions may negatively affect HighPeak Energys operating results and ability to conduct drilling activities.

 

Adverse weather conditions may cause, among other things, increases in the costs of, and delays in, drilling or completing new wells, power failures, temporary shut-in of production and difficulties in the transportation of crude oil, NGL and natural gas. Any decreases in production due to poor weather conditions will have an adverse effect on revenues, which will in turn negatively affect cash flow from operations. Climate change may also increase the frequency or intensity of such adverse weather conditions; for more information, see our risk factor titled “The operations of HighPeak Energy are subject to a variety of risks arising from climate change.”

 

HighPeak Energys operations are substantially dependent on the availability of sand and water. Restrictions on its ability to obtain sand and water may have an adverse effect on its financial condition, results of operations and cash flows.

 

Water is an essential component of crude oil and natural gas production during both the drilling and hydraulic fracturing processes. Drought conditions have persisted in the areas where the Company’s assets are located in past years. Such drought conditions can lead governmental authorities to restrict the use of water, subject to their jurisdiction, for hydraulic fracturing to protect local water supplies. Although HighPeak Energy may enter into a long-term contract for the supply of water, it currently procures local water for drilling on a well-to-well basis and currently recycles a significant portion of its produced water for completion operations. If HighPeak Energy is unable to obtain water to use in operations, it may need to be obtained from non-local sources and transported to drilling sites, resulting in increased costs, or HighPeak Energy may be unable to economically produce crude oil and natural gas, which could have a material and adverse effect on its financial condition, results of operations and cash flows.

 

The Companys assets are located in the northeastern Midland Basin, making HighPeak Energy vulnerable to risks associated with operating in a limited geographic area.

 

All HighPeak Energy’s producing properties are geographically concentrated in the northeastern Midland Basin. As a result, HighPeak Energy may be disproportionately exposed to various factors, including, among others: (i) the impact of regional supply and demand factors, (ii) delays or interruptions of production from wells in such areas caused by governmental regulation, (iii) processing or transportation capacity constraints, (iv) market limitations, (v) availability of equipment and personnel, (vi) water shortages or other drought related conditions or (vii) interruption of the processing or transportation of crude oil, NGL or natural gas. The concentration of the Company’s assets in a limited geographic area also increases its exposure to changes in local laws and regulations, certain lease stipulations designed to protect wildlife and unexpected events that may occur in the regions such as natural disasters, adverse weather, seismic events, industrial accidents or labor difficulties. Any one of these factors has the potential to cause producing wells to be shut-in, delay operations, decrease cash flows, increase operating and capital costs and prevent development of lease inventory before expirations. Any of the risks described above could have a material adverse effect on HighPeak Energy’s business, financial condition, results of operations and cash flow.

 

HighPeak Energy may incur losses as a result of title defects in the properties in which it invests.

 

The existence of a material title deficiency can render a lease worthless and adversely affect HighPeak Energy’s results of operations and financial condition. While HighPeak Energy typically obtains title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case HighPeak Energy may lose the lease and the right to produce all or a portion of the minerals under the property. Additionally, if an examination of the title history of a property reveals that a crude oil or natural gas lease or other developed right has been purchased in error from a person who is not the owner of the mineral interest desired, HighPeak Energy’s interest would substantially decline in value. In such cases, the amount paid for such crude oil or natural gas lease or leases would be lost.

 

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.

 

As of December 31, 2021, the Company’s assets contained 35,628 MBoe of proved undeveloped reserves, or PUDs, consisting of 29,215 MBbls of crude oil, 3,838 MBbls of NGL and 30,061 MMcf of natural gas. Development of these proved undeveloped reserves may take longer and require higher levels of capital expenditures than anticipated. Estimated future development costs relating to the development of such PUDs at December 31, 2021 are approximately $389.5 million over the next four (4) years. HighPeak Energy’s ability to fund these expenditures is subject to several risks. See “—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 increase production and reserves.” Delays in the development of reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the value of the estimated PUDs and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause HighPeak Energy to have to reclassify PUDs as unproved reserves. Furthermore, there is no certainty that HighPeak Energy will be able to convert PUDs to developed reserves or that undeveloped reserves will be economically viable or technically feasible to produce.

 

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Further, SEC rules require that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement may limit HighPeak Energy’s ability to book additional PUDs as it pursues its future drilling programs. As a result, HighPeak Energy may be required to write-down its PUDs if it does not drill those wells within the required timeframe. If actual reserves prove to be less than current reserve estimates, or if HighPeak Energy is required to write-down some of its PUDs, such reductions could have a material adverse effect on HighPeak Energy’s financial condition, results of operations and future cash flows.

 

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.

 

Producing crude oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless HighPeak Energy conducts successful ongoing exploration and development activities or continually acquires properties containing proved reserves, proved reserves will decline as those reserves are produced. HighPeak Energy’s future reserves and production, and therefore future cash flows and results of operations, are highly dependent on HighPeak Energy’s success in efficiently developing current reserves and economically finding or acquiring additional recoverable reserves. HighPeak Energy may not be able to develop, find or acquire sufficient additional reserves to replace future production. If HighPeak Energy is unable to replace such production, the value of its reserves will decrease, and its business, financial condition and results of operations would be materially and adversely affected.

 

Conservation measures and technological advances could reduce or slow the demand for crude oil and natural gas.

 

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to crude oil, NGL and natural gas, technological advances improving fuel economy and developments in energy generation and storage devices could reduce or slow the demand for crude oil, NGL and natural gas. The impact of the changing demand for crude oil, NGL and natural gas may have a material adverse effect on its business, financial condition, results of operations and cash flows.

 

HighPeak Energy depends upon a small number of significant purchasers for the sale of most of its crude oil, NGL and natural gas production. The loss of one or more of such purchasers could, among other factors, limit HighPeak Energys access to suitable markets for the crude oil, NGL and natural gas it produces.

 

HighPeak Energy expects to sell its production to a relatively small number of customers, as is customary in the crude oil and natural gas business. For the year ended December 31, 2021, there was one purchaser that accounted for approximately 94% and the years ended December 31, 2020 and 2019, there were two purchasers who accounted for approximately 97% and 88%, respectively, of the total revenue attributable to the Company’s assets. No other purchaser accounted for 10% or more of such revenues during such period. The loss of any such greater than 10% purchaser could adversely affect HighPeak Energy’s revenues in the short term. See the section entitled “Items 1 and 2: Business and Properties—Operations—Marketing and Customers” for additional information. HighPeak Energy expects to depend upon these or other significant purchasers for the sale of most of its crude oil and natural gas production. HighPeak Energy cannot ensure that it will continue to have ready access to suitable markets for its future crude oil and natural gas production.

 

HighPeak Energys 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’s operations will be subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, the occupational health and safety aspects of its operations or otherwise relating to the protection of the environment and natural resources. These laws and regulations may impose numerous obligations applicable to HighPeak Energy’s operations, including the acquisition of a permit or other approval before conducting regulated activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands, seismically active areas and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from HighPeak Energy’s operations. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, natural resource damages, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of HighPeak Energy’s operations. In addition, HighPeak Energy may experience delays in obtaining, or be unable to obtain, required permits, which may delay or interrupt its operations and limit growth and revenue.

 

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Certain environmental laws impose strict liability (i.e., no showing of “fault” is required) as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons or solid wastes have been stored or released. HighPeak Energy may be required to remediate contaminated properties owned or operated by it or facilities of third parties that received waste generated by operations regardless of whether such contamination resulted from the conduct of others or from consequences of its own actions that were in compliance with all applicable laws at the time those actions were taken. In connection with certain acquisitions, HighPeak Energy could acquire, or be required to provide indemnification against, environmental liabilities that could expose HighPeak Energy to material losses. In certain instances, citizen groups also have the ability to bring legal proceedings against HighPeak Energy if it is not in compliance with environmental laws, or to challenge its ability to receive environmental permits needed to operate. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of its operations. HighPeak Energy’s insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability.

 

For example, HighPeak Energy may incur significant costs and liabilities as a result of environmental requirements applicable to the operation of its wells, gathering systems and other facilities. These costs and liabilities could arise under a wide range of federal, state and local environmental laws and regulations, including the following federal laws and their state counterparts, as amended from time to time, among others:

 

 

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 a crude oil spill into waters of the United States;

   

 

 

the 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 RCRA, which imposes requirements for the generation, treatment, storage, transport, disposal and cleanup of non-hazardous, hazardous and solid wastes;

   

 

 

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

   

 

 

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.

 

Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective actions, the incurrence of capital expenditures, the occurrence of delays in the permitting, development or expansion of projects and the issuance of orders enjoining some or all of HighPeak Energy’s future operations in a particular area. It is not uncommon for neighboring landowners, employees and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, wastes or other materials into the environment. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment and more stringent laws and regulations may be adopted in the future.

 

To the extent HighPeak Energy’s operations are affected by national, regional, local and other laws, and to the extent such laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, HighPeak Energy’s business, prospects, financial condition or results of operations could be materially adversely affected.

 

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HighPeak Energy may incur increasing attention to ESG matters that may impact its business.

 

Businesses across all industries are facing increasing scrutiny from stakeholders related to their ESG practices. Businesses that do not adapt to or comply with investor or stakeholder expectations and standards, which are evolving, or which are perceived to have not responded appropriately to the growing concern for ESG issues, regardless whether there is a legal requirement to do so, may suffer from reputational damage and the business, financial condition and/or stock price of such business entity could be materially and adversely affected. Increasing attention to climate change, increasing societal expectations on businesses to address climate change, and potential consumer use of substitutes to energy commodities may result in increased costs, reduced demand for HighPeak Energy’s hydrocarbon products, reduced profits, increased investigations and litigation and negative impacts on its stock price and access to capital markets. Increasing attention to climate change, for example, may result in demand shifts for HighPeak Energy’s hydrocarbon products and additional governmental investigations and private litigation.

 

Moreover, while we may create and publish voluntary disclosures regarding ESG matters from time to time, certain statements in those voluntary disclosures may be based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. We may also announce participation in, or certification under, various third-party ESG frameworks in an attempt to improve our ESG profile, but such participation or certification may be costly and may not achieve the desired results. Additionally, while we may announce various voluntary ESG targets, such targets are aspirational. We may not be able to meet such targets in the manner or on such a timeline as initially contemplated, including but not limited to as a result of unforeseen costs or technical difficulties associated with achieving such results. To the extent we meet such targets, it may be achieved through various contractual arrangements, including the purchase of various credits or offsets that may be deemed to mitigate our ESG impact instead of actual changes in our ESG performance. Also, despite these aspirational goals and any other actions taken, we may receive pressure from investors, lenders, or other groups to adopt more aggressive climate or other ESG-related goals, but we cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles.

 

In addition, organizations that provided information to investors on corporate governance and related matters have developed rating processes for evaluating business entities on their approach to ESG matters. Currently, there are no universal standards for such scores or ratings, but the importance of sustainability evaluations is becoming more broadly accepted by investors and shareholders. Such ratings are used by some investors to inform their investment and voting decisions. Additionally, certain investors use these scores to benchmark businesses against their peers and if a business entity is perceived as lagging, these investors may engage with such entities to require improved ESG disclosure or performance. Moreover, certain members of the broader investment community may consider a business entity’s sustainability score as a reputational or other factor in making an investment decision. Consequently, a low sustainability score could result in exclusion of HighPeak Energy’s stock from consideration by certain investment funds, engagement by investors seeking to improve such scores and a negative perception of HighPeak Energy’s operation by certain investors. Additionally, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations. ESG matters may also impact our suppliers and customers, which may ultimately have adverse impacts on our operations.

 

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 will not be insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect its business, financial condition or results of operations.

 

HighPeak Energy’s development activities will be subject to all the operating risks associated with drilling for and producing crude oil and natural gas, including the possibility of:

 

 

environmental hazards, such as uncontrollable releases of crude 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;

 

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natural disasters; and

   

 

 

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

 

Any of these events could adversely affect HighPeak Energy’s ability to conduct operations or result in substantial loss as a result of claims for:

 

 

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.

 

HighPeak Energy may elect not to obtain insurance for any or all of these risks if it believes that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on business, financial condition and results of operations.

 

Properties that HighPeak Energy decides to drill may not yield crude oil or natural gas in commercially viable quantities.

 

Properties that HighPeak Energy decides to drill that do not yield crude oil or natural gas in commercially viable quantities will adversely affect its results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield crude oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of producing fields in the same area will not enable HighPeak Energy to know conclusively prior to drilling whether crude oil or natural gas will be present or, if present, whether crude oil or natural gas will be present in commercial quantities. HighPeak Energy cannot assure you that the analogies drawn from available data from other wells, more fully explored prospects or producing fields will be applicable to its drilling prospects. Further, HighPeak Energy’s drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:

 

 

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.

 

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.

 

HighPeak Energy may not be able to identify attractive acquisition opportunities that complement the Company’s assets or expand its business. In the event it identifies attractive acquisition opportunities, HighPeak Energy may not be able to complete the acquisition or do so on commercially acceptable terms. Competition for acquisitions may also increase the cost of, or cause HighPeak Energy to refrain from, completing acquisitions.

 

The success of completed acquisitions will depend on HighPeak Energy’s ability to integrate effectively the acquired business into its then-existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of its managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that it will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. HighPeak Energy’s failure to achieve consolidation savings, to integrate the acquired businesses and assets into its then-existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on its financial condition and results of operations.

 

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In addition, the Revolving Credit Facility and the indenture governing the 2024 Notes impose certain limitations on its ability to enter into mergers or combination transactions and to incur certain indebtedness, which could indirectly limit its ability to acquire assets and businesses.

 

Certain of HighPeak Energys properties are subject to land use restrictions, which could limit the manner in which HighPeak Energy conducts business.

 

Certain of HighPeak Energy’s properties are subject to land use restrictions, which could limit the manner in which HighPeak Energy conducts business. Such restrictions could affect, among other things, access to and the permissible uses of facilities as well as the manner in which HighPeak Energy produces crude oil and natural gas and may restrict or prohibit drilling in general. The costs incurred to comply with such restrictions may be significant, and HighPeak Energy may experience delays or curtailment in the pursuit of development activities and perhaps even be precluded from the drilling of wells.

 

The unavailability or high cost of drilling rigs, equipment, supplies, personnel, frac crews and oilfield services could adversely affect HighPeak Energys ability to execute its development plans within its budget and on a timely basis.

 

The demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the crude oil and natural gas industry, can fluctuate significantly, often in correlation with crude oil, NGL and natural gas prices, causing periodic shortages of equipment, supplies and needed personnel. HighPeak Energy’s operations will be concentrated in areas in which oilfield activity levels have previously increased rapidly. If that were to happen again, demand for drilling rigs, equipment, supplies and personnel may increase the costs for these services. Access to transportation, processing and refining facilities in these areas may become constrained resulting in higher costs and reduced access for those items. Historically, crude oil, NGL and natural gas prices have been volatile. For example, during the period from January 1, 2018 through December 31, 2021, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $16.70 to a high of $81.22, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.50 to a high of $6.20. For the month of April 2020, the calendar month average NYMEX WTI crude oil price was $16.70 and last trading day NYMEX natural gas price was $1.63 per MMBtu. However, prices have since increased. To the extent commodity prices improve in the future, the demand for and prices of these goods and services are likely to increase and HighPeak Energy could encounter delays in or an inability to secure the personnel, equipment, power, services, resources and facilities access necessary for it to resume or increase HighPeak Energy’s development activities, which could result in production volumes being below its forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on cash flow and profitability. Furthermore, if it is unable to secure a sufficient number of drilling rigs at reasonable costs, HighPeak Energy may not be able to drill all of its acreage before its leases expire.

 

HighPeak Energy could experience periods of higher costs if commodity prices rise and inflation may adversely affect our operating results. These increases in cost could reduce profitability, cash flow and ability to complete development activities as planned.

 

Historically, capital and operating costs have risen during periods of increasing crude oil, NGL and natural gas prices. Inflationary factors such as increases in the labor costs, material costs and overhead costs may adversely affect our operating results. These cost increases have resulted from a variety of factors that HighPeak Energy will be unable to control, such as increases in the cost of electricity, steel and other raw materials; increased demand for labor, services and materials as drilling activity increases; and increased taxes Such costs may rise faster than increases in HighPeak Energy’s revenue if commodity prices rise, thereby negatively impacting its profitability, cash flow and ability to complete development activities as scheduled and on budget. A high rate of inflation, including a continuation of inflation at the current rate, may have an adverse effect on HighPeak Energy’s operating results. This impact may be magnified to the extent that HighPeak Energy’s ability to participate in the commodity price increases is limited by its derivative activities, if any.

 

HighPeak Energy may be involved in legal proceedings that could result in substantial liabilities.

 

Like many crude oil and natural gas companies, HighPeak Energy may be involved from time to time in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of its business. Such proceedings are inherently uncertain, and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on HighPeak Energy because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in its business practices, which could materially and adversely affect its business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

 

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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.

 

Under the Energy Policy Act of 2005, FERC has civil penalty authority under the Natural Gas Act of 1938 to impose penalties for current violations of up to $1,269,500 per day for each violation (annually adjusted for inflation) and disgorgement of profits associated with any violation. While our operators’ operations have not been regulated by the FERC as a natural gas company under this law, the FERC has adopted regulations that may subject certain of our operators’ otherwise non-FERC jurisdictional facilities to the FERC annual reporting requirements. Our operators also must comply with the anti-market manipulation rules enforced by the FERC. Additional rules and legislation pertaining to those and other matters may be considered or adopted by the FERC from time to time. Additionally, the FTC has regulations intended to prohibit market manipulation in the petroleum industry with authority to fine violators of the regulations civil penalties of up to $1,210,340 per day (annually adjusted for inflation) and the CFTC prohibits market manipulation in the markets regulated by the CFTC, including similar anti-manipulation authority with respect to crude oil swaps and futures contracts as that granted to the CFTC with respect to crude oil purchases and sales. The CFTC rules subject violators to a civil penalty of up to the greater of $1,191,842 per day (annually adjusted for inflation) or triple the monetary gain to the person for each violation. Failure to comply with those regulations in the future could subject our operators to civil penalty liability, as described in “Items 1 and 2: Business and Properties—Regulation of the Crude Oil and Natural Gas Industry.”

 

The operations of HighPeak Energy are subject to a variety of risks arising from climate change.

 

The threat of climate change continues to attract considerable attention in the United States and in foreign countries. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions. As a result, crude oil and natural gas exploration and production operations are subject to a series of regulatory, political, litigation and financial risks associated with the production and processing of fossil fuels and emission of GHGs.

 

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, with the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted rules that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. The regulation of methane from crude oil and natural gas facilities has been subject to uncertainty in recent years. Although, in September 2020, the Trump Administration revised prior promulgated regulations to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations, the U.S. Congress approved, and President Biden signed into law, a resolution under the Congressional Review Act to repeal the September 2020 revisions, effectively reinstating the prior standards. Additionally, in November 2021, the EPA issued a proposed rule that, if finalized, would establish OOOOb as new source and OOOOc as first-time existing source standards of performance for methane and VOC emissions for the crude oil and natural gas source category. Owners or operators of affected emission units or processes would have to comply with specific standards of performance that may include leak detecting using optical gas imaging and subsequent repair requirements, reduction of regulated emissions through capture and control systems, zero-emission requirements for certain equipment or processes, operations and maintenance requirements and requirements for “green well” completions. The EPA plans to issue a supplemental proposal enhancing the proposed rulemaking in 2022 that will contain proposed rule text, which was not included in the November 2021 proposed rule, and anticipates issuing a final rule by the end of 2022. Separately, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, the United Nations-sponsored “Paris Agreement” requires member states to submit non-binding, individually-determined reduction goals every five years after 2020. President Biden has recommitted the United States to the Paris Agreement and in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. In November 2021, the international community gathered again in Glasgow at the 26th Conference to the Parties on the UN Framework Convention on Climate Change (“COP26”), during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-CO2 GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. The impacts of these actions cannot be predicted at this time.

 

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Governmental, scientific and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by certain candidates in public office. On January 27, 2021, President Biden signed an executive order calling for substantial action on climate change, including, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry and increased emphasis on climate-related risks across agencies and economic sectors. Additional actions that could be pursued by the Biden Administration may include more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities. Litigation risks are also increasing, as a number of entities have sought to bring suit against crude oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to climate change or that such companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.

 

There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all their investments into other sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. For example, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing and/or underwriting activities to net zero by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. In late 2020, the Federal Reserve announced it has joined the NGFS and, in November 2021, issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Limitation of investments in and financing for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities. In addition, the SEC has announced that it will propose rules that, amongst other matters, will establish a framework for the reporting of climate risks. However, no such rules have been proposed to date, and we cannot predict what any such rules may require. To the extent the rules impose additional reporting obligations, we could face increased costs.

 

The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from crude oil and natural gas producers such as HighPeak Energy or otherwise restrict the areas in which HighPeak Energy may produce crude oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for or erode value for, the crude oil and natural gas that HighPeak Energy produces. Additionally, political, litigation and financial risks may result in HighPeak Energy’s restricting or cancelling crude oil and natural gas production activities, incurring liability for infrastructure damages as a result of climatic changes, or having an impaired ability to continue to operate in an economic manner. One or more of these developments could have a material adverse effect on HighPeak Energy’s business, financial condition and results of operations.

 

Finally, many scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climate events that could have an adverse effect on HighPeak Energy’s operations. If such effects were to occur, our development and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities either because of climate related damages to our facilities or in our costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship or by reducing demand for fossil fuels we provide, such as to the extent warmer winters reduce the demand for energy for heating purposes. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. At this time, we have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our operations. If we are forced to shut in production, we will likely incur greater costs to bring the associated production back online. Cost increases necessary to bring the associated wells back online may be significant enough that such wells would become uneconomic at low commodity price levels, which may lead to decreases in our proved reserve estimates and potential impairments and associated charges to our earnings.

 

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the completion of crude oil and natural gas wells and adversely affect HighPeak Energys production.

 

Hydraulic fracturing is an important and common practice that is used to stimulate production of crude oil and natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. HighPeak Energy expects to regularly use hydraulic fracturing as part of HighPeak Energy’s operations. Hydraulic fracturing is typically regulated by state crude oil and natural gas commissions, but certain federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Congress has, from time to time, considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect HighPeak Energy’s operations, but such additional federal regulation could have an adverse effect on its business, financial condition and results of operations.

 

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In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water under certain limited circumstances.

 

Moreover, some states and local governments have adopted, and other governmental entities are considering adopting, regulations that could impose more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations, including states in which our properties are located. For example, Texas, among others, has adopted regulations that impose new or more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. States could also elect to prohibit high volume hydraulic fracturing altogether. In addition to state laws, local land use restrictions, such as city ordinances may restrict drilling in general and/or hydraulic fracturing in particular. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where HighPeak Energy will operate, it could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells.

 

Legislation or regulatory initiatives intended to address seismic activity could restrict HighPeak Energys drilling and production activities, as well as HighPeak Energys ability to dispose of produced water gathered from such activities, which could have a material adverse effect on its future business.

 

State and federal regulatory agencies have at times focused on a possible connection between the hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between crude oil and natural gas activity and induced seismicity. For example, in 2015, the United States Geological Study identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or crude oil and natural gas extraction.

 

In addition, a number of lawsuits have been filed in other states, most recently in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. For example, Texas has imposed certain limits on the permitting or operation of disposal wells in areas with increased instances of induced seismic events. In some instances, regulators may also order that disposal wells be shut in. In September 2021, the TRRC issued a notice to operators in the city of Midland area to reduce daily injection volumes following multiple earthquakes above a 3.5 magnitude over an 18-month period. The notice also required disposal well operators to provide injection data to TRRC staff to further analyze seismicity in the area. Subsequently, the TRRC ordered the indefinite suspension of all deep oil and gas produced water injection wells in the area, effective December 31, 2021.

 

HighPeak Energy will likely dispose of large volumes of produced water gathered from its drilling and production operations by injecting it into wells pursuant to permits issued by governmental authorities overseeing such disposal activities. While these permits will be issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict HighPeak Energy’s ability to use hydraulic fracturing or dispose of produced water gathered from its drilling and production activities by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring HighPeak Energy to shut down disposal wells, could have a material adverse effect on its business, financial condition and results of operations.

 

Competition in the crude oil and natural gas industry is intense, which will make it more difficult for HighPeak Energy to acquire properties, market crude oil or natural gas and secure trained personnel.

 

HighPeak Energy’s ability to acquire additional prospects and to find and develop reserves in the future will depend on its ability to evaluate and select suitable properties for acquisitions and to consummate transactions in a highly competitive environment for acquiring properties, marketing crude oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the crude oil and natural gas industry. Many other crude oil and natural gas companies possess and employ greater financial, technical and personnel resources than HighPeak Energy. Those companies may be able to pay more for productive properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than HighPeak Energy’s financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than HighPeak Energy will be able to offer. The cost to attract and retain qualified personnel has historically continually increased due to competition and may increase substantially in the future. HighPeak Energy may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on its business.

 

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The loss of senior management or technical personnel could adversely affect operations.

 

HighPeak Energy will depend on the services of its senior management and technical personnel. HighPeak Energy does not plan to obtain any insurance against the loss of any of these individuals. The loss of the services of its senior management could have a material adverse effect on its business, financial condition and results of operations.

 

Increases in interest rates could adversely affect HighPeak Energys business.

 

HighPeak Energy will require continued access to capital and its business and operating results could be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. HighPeak Energy uses, and expects to continue to use debt financing, including borrowings under the Revolving Credit Facility, to finance a portion of its future growth, and these changes could cause its cost of doing business to increase, limit its ability to pursue acquisition opportunities, reduce cash flow used for drilling and place HighPeak Energy at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting its ability to finance its operations. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect its ability to achieve its planned growth and operating results.

 

HighPeak Energys use of seismic data is subject to interpretation and may not accurately identify the presence of crude oil and natural gas, which could adversely affect the results of its drilling operations.

 

Even when properly used and interpreted, seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. As a result, HighPeak Energy’s drilling activities may not be successful or economical. In addition, the use of advanced technologies, such as 3-D seismic data, requires greater pre-drilling expenditures than traditional drilling strategies, and it could incur losses as a result of such expenditures.

 

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect HighPeak Energys ability to conduct drilling activities in areas where it operates.

 

Crude oil and natural gas operations in HighPeak Energy’s operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Such restrictions may limit HighPeak Energy’s ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay HighPeak Energy’s operations or materially increase its operating and capital costs. Permanent restrictions imposed to protect threatened or endangered species, other protected species (such as migratory birds), or their habitat could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where HighPeak Energy operates as threatened or endangered could cause it to incur increased costs arising from species protection measures or could result in limitations on its activities that could have a material and adverse impact on its ability to develop and produce reserves. For example, a review is currently pending to determine whether the dunes sagebrush lizard should be listed and, on June 1, 2021, FWS proposed to list two distinct population segments of the lesser prairie-chicken under the act. If these species or others are listed, the FWS and similar state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of or access to federal, state and private lands. To the extent species are listed under the ESA or similar state laws, or previously unprotected species are designated as threatened or endangered in areas where our properties are located, operations on those properties could incur increased costs arising from species protection measures and face delays or limitations with respect to production activities thereon. For more information, see the section entitled “Items 1 and 2: Business and Properties—Regulation of Environmental and Occupational Safety and Health Matters— Endangered Species Act and Migratory Birds and Migratory Birds.”

 

HighPeak Energy may not be able to keep pace with technological developments in its industry.

 

The crude oil and natural gas industry is characterized by rapid and significant technological advancement and the introduction of new products and services using new technologies. As others use or develop new technologies, HighPeak Energy may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other crude oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may, in the future, allow them to implement new technologies before HighPeak Energy. HighPeak Energy may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies it expects to use were to become obsolete, HighPeak Energy’s business, financial condition or results of operations could be materially and adversely affected.

 

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There are inherent limitations in all control systems, and misstatements due to error or fraud that could seriously harm HighPeak Energys business may occur and not be detected.

 

HighPeak Energy’s management does not expect that HighPeak Energy’s internal and disclosure controls will prevent all possible error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, an evaluation of controls can only provide reasonable assurance that all material control issues and instances of fraud, if any, in HighPeak Energy have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Further, controls can be circumvented by the individual acts of some persons or by collusion of two or more persons. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

 

HighPeak Energys business could be adversely affected by security threats, including cyber-security threats, and related disruptions.

 

HighPeak Energy relies heavily on its information systems, and the availability and integrity of these systems is essential to conducting HighPeak Energy’s business and operations. As a producer of crude oil and natural gas, HighPeak Energy faces various security threats, including cyber-security threats, to gain unauthorized access to its sensitive information or to render its information or systems unusable, and threats to the security of its facilities and infrastructure or third-party facilities and infrastructure, such as gathering and processing and other facilities, refineries and pipelines. This risk may be heightened as a result of the remote working environment created by the COVID-19 outbreak. The potential for such security threats subjects its operations to increased risks that could have a material adverse effect on its business, financial condition, results of operations and cash flows.

 

HighPeak Energy’s implementation of various procedures and controls to monitor and mitigate such security threats and to increase security for its information, systems, facilities and infrastructure may result in increased costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of, or damage to, sensitive information or facilities, infrastructure and systems essential to its business and operations, as well as data corruption, communication interruptions or other disruptions to its operations, which, in turn, could have a material adverse effect on its business, financial position, results of operations and cash flows.

 

Risks Related to Ownership of our Securities

 

The HighPeak Group, including the Principal Stockholder Group, has significant influence over HighPeak Energy.

 

Prior to taking into account any adjustment relating to any shares that may be issued (or forfeited) pursuant to the Contingent Value Rights (and the surrender for cancellation by the Sponsor of an equivalent number of shares), the HighPeak Group owns approximately 84% of HighPeak Energy’s common stock as of December 31, 2021. HighPeak I, HighPeak II and Sponsor have placed into escrow at Closing 21,694,763 shares of HighPeak Energy common stock in connection with the issuance of the Contingent Value Rights. As long as the Principal Stockholder Group owns or controls a significant percentage of HighPeak Energy’s outstanding voting power, subject to the terms of the Stockholders’ Agreement (as defined below), they will have the ability to influence certain corporate actions requiring stockholder approval. Under the Stockholders’ Agreement, the Principal Stockholder Group will be entitled to nominate a specified number of directors for appointment to the Board so long as the Principal Stockholder Group meets certain ownership criteria outlined in the Stockholders’ Agreement. For more information about the Stockholders’ Agreement, see the section entitled “Certain Relationships and Related Transactions, and Director Independence.”

 

If HighPeak Energys operational and financial performance does not meet the expectations of investors, stockholders or financial analysts, the market price of our securities may decline.

 

If HighPeak Energy’s operational and financial performance does not meet the expectations of investors or securities analysts, the market price of our securities may decline. The market values of our securities may vary significantly from time to time.

 

In addition, fluctuations in the price of our securities could contribute to the loss of all or part of your investment. The trading price of our securities could be volatile and subject to wide fluctuations in response to various factors, some of which are beyond our control. Any of the factors listed below could have a material adverse effect on your investment in our securities and our securities may trade at prices significantly below the price you paid for them. In such circumstances, the trading price of our securities may not recover and may experience a further decline.

 

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Factors affecting the trading price of our securities may include:

 

 

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.

 

Broad market and industry factors may materially harm the market price of our securities irrespective of our operating performance. The stock market in general and the Nasdaq have experienced price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of the particular companies affected. The trading prices and valuations of these stocks, and of our securities, may not be predictable. A loss of investor confidence in the market for energy stocks or the stocks of other companies which investors perceive to be similar to us could depress our stock price regardless of our business, prospects, financial conditions or results of operations. A decline in the market price of our securities also could adversely affect our ability to issue additional securities and our ability to obtain additional financing in the future.

 

Because HighPeak Energy has a limited operating history, it may be difficult to evaluate its ability to successfully implement its business strategy.

 

Because of HighPeak Energy’s limited operating history, the operating performance of its future assets and business strategy are not yet proven. As a result, it may be difficult to evaluate HighPeak Energy’s business and results of operations to date and to assess its future prospects.

 

In addition, HighPeak Energy may encounter risks and difficulties experienced by companies whose performance is dependent upon newly acquired assets, such as failing to operate the Company’s assets as expected, higher than expected operating costs, equipment breakdown or failures and operational errors. As a result of the foregoing, HighPeak Energy may be less successful in achieving a consistent operating level capable of generating cash flows from operations compared with a company that has a longer operating history. In addition, HighPeak Energy may be less equipped to identify and address operating risks and hazards in the conduct of its business than those companies that have longer operating histories.

 

HighPeak Energy is acontrolled companywithin the meaning of Nasdaq rules and 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 not exempt from such corporate governance requirements.

 

The HighPeak Group collectively own a majority of HighPeak Energy’s outstanding voting stock. Therefore, HighPeak Energy is a controlled company within the meaning of Nasdaq corporate governance standards. Under Nasdaq rules, a company of which more than 50% of the voting power is held by an individual, company or group of persons acting together is a controlled company and may elect not to comply with certain Nasdaq corporate governance requirements, including the requirements that:

 

 

a majority of the Board consist of independent directors under Nasdaq rules;

 

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the nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and

   

 

 

the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.

 

HighPeak Energy has elected to rely on all of the exemptions for controlled companies provided for under the Nasdaq rules. These requirements will not apply to HighPeak Energy as long as it remains a controlled company.

 

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 Energys financial condition, results of operations and stock price, which could cause you to lose some or all of your investment.

 

Although HighPeak Energy conducted due diligence on the Company’s assets in connection with the HighPeak business combination, HighPeak Energy cannot assure you that this diligence revealed all material issues that may be present in the businesses of the Company’s assets, that it would be possible to uncover all material issues through a customary amount of due diligence, or that factors outside of HighPeak Energy’s control will not later arise. As a result, HighPeak Energy may be forced to later write-down or write-off assets, restructure HighPeak Energy’s operations, or incur impairment or other charges that could result in losses. Even if HighPeak Energy’s due diligence successfully identifies certain risks, unexpected risks may arise, and previously known risks may materialize in a manner not consistent with HighPeak Energy’s preliminary risk analysis. Even though these charges may be non-cash items and may not have an immediate impact on HighPeak Energy’s liquidity, the fact that HighPeak Energy reports charges of this nature could contribute to negative market perceptions about HighPeak Energy’s securities. In addition, charges of this nature may cause HighPeak Energy to be unable to obtain future financing on favorable terms or at all.

 

There is no guarantee that our warrants will be in the money at the time you choose to exercise them and the CVRs will be in the money at the time they become exercisable, and they may expire worthless.

 

The exercise price for our warrants is $11.50 per share of HighPeak Energy common stock, subject to certain adjustments. There is no guarantee that our warrants will be in the money at the time you choose to exercise them and the CVRs will be in the money following the time they become exercisable and prior to their expiration, and as such, our warrants and CVRs may expire worthless.

 

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.

 

Our warrants were issued in registered form under the Warrant Agreement Amendment. The Warrant Agreement Amendment provides that the terms of the warrants may be amended without the consent of any holder to cure any ambiguity or correct or supplement any defective provision but requires the approval by the holders of at least 50% of the then-outstanding warrants to make any other change or modification, including any amendment that adversely affects the interests of the registered holders of our warrants. Accordingly, HighPeak Energy, may amend the terms of its warrants in a manner adverse to a holder if holders of at least 50% of the then-outstanding warrants approve of such amendment. Although HighPeak Energy’s ability to amend the terms of its warrants with the consent of at least 50% of the then-outstanding warrants is unlimited and such amendments could, among other things, increase the exercise price of the warrants, shorten the exercise period or decrease the number of shares of HighPeak Energy common stock purchasable upon exercise of a warrant.

 

Warrants are exercisable for HighPeak Energy common stock and HighPeak Energys LTIP provides for a significant number of stock options, each of which could increase the number of shares eligible for future resale in the public market and result in dilution to stockholders.

 

The potential for the issuance of a substantial number of additional shares of HighPeak Energy common stock upon exercise of its warrants would increase the number of issued and outstanding shares of HighPeak Energy common stock and reduce the value of the shares issued and outstanding as of the date hereof. Additionally, the sale, or even the possibility of sale, of the shares underlying the warrants could have an adverse effect on the market price for HighPeak Energy’s common stock or on its ability to obtain future financing. If and to the extent these warrants are exercised, you may experience dilution to your holdings.

 

In addition, to attract and retain key management personnel and non-employee directors, HighPeak Energy has implemented a Long-Term Incentive Plan (“LTIP”), pursuant to which the Share Pool (as defined in the LTIP) is reserved and available for delivery with respect to Stock Awards (as defined in the LTIP). From time to time and prior to the expiration of the LTIP, the Share Pool will automatically be increased by (i) the number of shares of HighPeak Energy common stock issued pursuant to the LTIP and (ii) 13% of the number of shares of HighPeak Energy common stock that are newly issued by HighPeak Energy (other than those issued pursuant to the LTIP), including any shares issued upon the exercise of the warrants. As a result, HighPeak Energy could issue a significant number of stock options under the LTIP, including additional shares added to the LTIP upon the exercise of the warrants, which could further dilute your holdings.

 

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A significant portion of HighPeak Energys 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 Energys business is doing well.

 

In connection with the issuance of 10,209,300 Contingent Value Rights at the Closing, HighPeak I and HighPeak II, collectively, placed 21,694,763 shares of HighPeak Energy common stock into escrow which such Escrowed Shares will be released either to HighPeak Energy for cancellation in connection with the satisfaction of any Preferred Returns or back to HighPeak I and HighPeak II, collectively, as applicable, following the CVR Maturity Date (“Escrowed Shares,” “Preferred Returns” and “CVR Maturity Date,” each as defined in the Contingent Value Rights Agreement). Until such shares are released back to HighPeak I and HighPeak II, they may not be traded.

 

To the extent the Preferred Return is not met, shares of HighPeak Energy will be issued (and a corresponding number of shares of HighPeak Energy common stock will be released to HighPeak Energy from the escrow for cancellation). While this results in a net zero change in the outstanding shares of HighPeak Energy common stock, it will increase the number of shares eligible for resale in the public market. Sales of substantial numbers of such shares in the public market could adversely affect the market price of HighPeak Energy’s common stock. There would also be an increase in the number of shares of HighPeak Energy common stock eligible for resale in the public market if the Preferred Returns are met, pursuant to the Escrowed Shares being released to HighPeak I and HighPeak II. In either case, after the release of HighPeak Energy common stock from the escrow account, actual sales or the perception in the market that the holders of a large number of shares intend to sell shares, could reduce the market price of HighPeak Energy common stock. Regardless (i) if the Preferred Return is not met and shares of HighPeak Energy are issued with a corresponding number of Escrowed Shares released for cancellation or (ii) the Preferred Return is met and the Escrowed Shares are released to HighPeak I and HighPeak II, the total number of HighPeak Energy shares of common stock outstanding will not change.

 

If securities or industry analysts do not publish or cease publishing research or reports about HighPeak Energy, HighPeak Energys business or HighPeak Energys market, or if they change their recommendations regarding HighPeak Energy common stock adversely, the price and trading volume of HighPeak Energy common stock could decline.

 

The trading market for HighPeak Energy common stock will be influenced by the research and reports that industry or securities analysts may publish about HighPeak Energy, HighPeak Energy’s business, HighPeak Energy’s market, or HighPeak Energy’s competitors. If any of the analysts who may cover HighPeak Energy change their recommendation regarding HighPeak Energy common stock adversely, or provide more favorable relative recommendations about its competitors, the price of HighPeak Energy common stock would likely decline. If any analyst who may cover HighPeak Energy were to cease their coverage or fail to regularly publish reports on HighPeak Energy, HighPeak Energy could lose visibility in the financial markets, which could cause HighPeak Energy’s stock price or trading volume to decline.

 

The Amended and Restated Certificate of Incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholdersability to obtain a favorable judicial forum for disputes with us or our directors, officers or employees.

 

The Amended and Restated Certificate of Incorporation (“A&R Charter”) provides that, unless HighPeak Energy consents in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware (“Court of Chancery”) will, to the fullest extent permitted by applicable law and subject to applicable jurisdictional requirements, be the sole and exclusive forum for (i) any derivative action or proceeding as to which the Delaware General Corporation Law (“DGCL”) confers jurisdiction upon the Court of Chancery, (ii) any action asserting a claim of breach of a fiduciary duty owed by any director, officer or other employee of HighPeak Energy to HighPeak Energy or its stockholders, (iii) any action asserting a claim against HighPeak Energy, its directors, officers or employees arising pursuant to any provision of the DGCL, the A&R Charter or HighPeak Energy’s bylaws or (iv) any action asserting a claim against HighPeak Energy, its directors, officers or employees that is governed by the internal affairs doctrine, in each case except for such claims as to which (a) the Court of Chancery determines that it does not have personal jurisdiction over an indispensable party, (b) exclusive jurisdiction is vested in a court or forum other than the Court of Chancery or (c) the Court of Chancery does not have subject matter jurisdiction. The forum selection provision is not intended to apply to claims arising under the Securities Act or the Exchange Act. To the extent the provision could be construed to apply to such claims, there is uncertainty as to whether a court would enforce such provision in connection with such claims. Stockholders will not be deemed, by operation of Article 8 of the A&R Charter alone, to have waived claims arising under the federal securities laws and the rules and regulations promulgated thereunder.

 

If any action the subject matter of which is within the scope of the forum selection provision described in the preceding paragraph is filed in a court other than the Court of Chancery (or, if the Court of Chancery does not have jurisdiction, another state court or a federal court located within the State of Delaware) (a “Foreign Action”) in the name of any stockholder, such stockholder shall be deemed to have consented to (i) the personal jurisdiction of the state and federal courts located within the State of Delaware in connection with any action brought in any such court to enforce the forum selection provision (a “Foreign Enforcement Action”) and (ii) having service of process made upon such stockholder in any such Foreign Enforcement Action by service upon such stockholder’s counsel in the Foreign Action as agent for such stockholder.

 

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Any person or entity purchasing or otherwise acquiring any interest in shares of HighPeak Energy’s capital stock will be deemed to have notice of, and consented to, the provisions of our A&R Charter described in the preceding paragraph. This exclusive forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with HighPeak Energy or its directors, officers or other employees, which may discourage such lawsuits against HighPeak Energy and such persons. The enforceability of similar exclusive forum provisions in other companies’ certificates of incorporation has been challenged in legal proceedings, and it is possible that, in connection with one or more actions or proceedings described above, a court could rule that this provision in the A&R Charter is inapplicable or unenforceable. If a court were to find these provisions of the A&R Charter inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, HighPeak Energy may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect its business, financial condition or results of operations.

 

Changes in laws or regulations, or a failure to comply with any laws or regulations, may adversely affect HighPeak Energys business, investments and results of operations.

 

HighPeak Energy is subject to laws, regulations and rules enacted by national, regional and local governments and the Nasdaq. In particular, HighPeak Energy is required to comply with certain SEC, Nasdaq and other legal or regulatory requirements. Compliance with, and monitoring of, applicable laws, regulations and rules may be difficult, time consuming and costly. Those laws, regulations and rules and their interpretation and application may also change from time to time and those changes could have a material adverse effect on HighPeak Energy’s business, investments and results of operations. In addition, a failure to comply with applicable laws, regulations and rules, as interpreted and applied, could have a material adverse effect on HighPeak Energy’s business and results of operations.

 

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’s common stock and warrants are currently listed on the Nasdaq, which such listings includes its common stock, shares of its common stock issuable upon exercise of its warrants or upon satisfaction of conditions under the CVR Agreement with respect to the CVRs. If the Nasdaq delists HighPeak Energy’s common stock from trading on its exchange for failure to meet the listing standards, HighPeak Energy and its security holders could face significant material adverse consequences, such as:

 

 

a limited availability of market quotations for HighPeak Energy’s securities;

   

 

 

reduced liquidity for HighPeak Energy’s securities;

   

 

 

a determination that HighPeak Energy common stock is a “penny stock,” which will require brokers trading in HighPeak Energy common stock to adhere to more stringent rules and possibly result in a reduced level of trading activity in the secondary trading market for HighPeak Energy’s securities;

   

 

 

a limited amount of news and analyst coverage; and

   

 

 

a decreased ability to issue additional securities or obtain additional financing in the future.

 

The National Securities Markets Improvement Act of 1996, which is a federal statute, prevents or preempts the states from regulating the sale of certain securities, which are referred to as “covered securities.” Because HighPeak Energy’s securities are listed on the Nasdaq, they are covered securities. Although the states are preempted from regulating the sale of HighPeak Energy’s securities, the federal statute does allow the states to investigate companies if there is a suspicion of fraud, and, if there is a finding of fraudulent activity, then the states can regulate or bar the sale of covered securities in a particular case. Further, if HighPeak Energy were no longer listed on the Nasdaq, its securities would not be covered securities and HighPeak Energy would be subject to regulation in each state in which HighPeak Energy offers its securities.

 

Unanticipated changes in effective tax rates or laws or adverse outcomes resulting from examination of HighPeak Energys income or other tax returns could adversely affect HighPeak Energys financial condition, results of operations and cash flow.

 

HighPeak Energy is subject to tax by U.S. federal, state and local tax authorities. HighPeak Energy’s future effective tax rates could be subject to volatility or adversely affected by a number of factors, including:

 

 

changes in the valuation of HighPeak Energy’s deferred tax assets and liabilities;

 

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expected timing and amount of the release of any tax valuation allowances;

   

 

 

tax effects of stock-based compensation;

   

 

 

costs related to intercompany restructurings; or

   

 

 

changes in tax laws, regulations or interpretations thereof.

 

For example, in previous years, legislation has been proposed to eliminate or defer certain key U.S. federal income tax deductions historically available to crude oil and natural gas exploration and production companies. Such proposed changes have included: (i) a repeal of the percentage depletion allowance for crude oil and natural gas properties; (ii) the elimination of deductions for intangible drilling and exploration and development costs; (iii) the elimination of the deduction for certain production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. The passage of any legislation as a result of these proposals or other similar changes in U.S. federal income tax laws that alter, eliminate or defer these or other tax deductions utilized within the industry could adversely affect HighPeak Energy’s business, financial condition, results of operations and cash flows.

 

In addition, HighPeak Energy may be subject to audits of its income, sales and other transaction taxes by U.S. federal, state and local taxing authorities. Outcomes from these audits could have an adverse effect on HighPeak Energy’s financial condition and results of operations.

 

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, which could make HighPeak Energys common stock less attractive to investors and may make it more difficult to compare its performance with other public companies.

 

HighPeak Energy is an “emerging growth company” within the meaning of the Securities Act, as modified by the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”), and HighPeak Energy takes advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002, reduced disclosure obligations regarding executive compensation in HighPeak Energy’s periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved. As a result, HighPeak Energy’s stockholders may not have access to certain information they may deem important. HighPeak Energy could be an emerging growth company for up to five years, although circumstances could cause HighPeak Energy to lose that status earlier, including if the market value of HighPeak Energy’s equity held by non-affiliates exceeds $700 million as of any June 30 before that time, in which case HighPeak Energy would no longer be an emerging growth company as of the following December 31. HighPeak Energy cannot predict whether investors will find its securities less attractive because HighPeak Energy will rely on these exemptions. If some investors find HighPeak Energy’s common stock less attractive as a result of HighPeak Energy’s reliance on these exemptions, the trading prices of HighPeak Energy’s common stock may be lower than they otherwise would be, there may be a less active trading market for HighPeak Energy’s common stock and the trading prices of HighPeak Energy’s common stock may be more volatile.

 

Further, Section 102(b)(1) of the JOBS Act exempts emerging growth companies from being required to comply with new or revised financial accounting standards until private companies (that is, those that have not had a Securities Act registration statement declared effective or do not have a class of securities registered under the Exchange Act) are required to comply with the new or revised financial accounting standards. The JOBS Act provides that a company can elect to opt out of the extended transition period and comply with the requirements that apply to non-emerging growth companies but any such election to opt out is irrevocable. HighPeak Energy has elected not to opt out of such extended transition period, which means that when a standard is issued or revised and it has different application dates for public or private companies, HighPeak Energy, as an emerging growth company, can adopt the new or revised standard at the time private companies adopt the new or revised standard. This may make comparison of HighPeak Energy’s financial statements with another public company which is neither an emerging growth company nor an emerging growth company which has opted out of using the extended transition period difficult or impossible because of the potential differences in accounting standards used.

 

Under certain circumstances, the Contingent Value Rights will have no value and will be automatically terminated without any further consideration.

 

The terms of the Contingent Value Rights are governed by the Contingent Value Rights Agreement by and among HighPeak Energy, HighPeak I, HighPeak II, Sponsor and the Rights Agent.

 

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The CVR Holders are 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 a CVR Holder with a 10% preferred simple annual return (based on a $10.00 per share price at Closing), subject to a floor downside per-share price of $4.00, at the CVR Maturity Date. However, this contingent consideration, if applicable, will only be issued to Qualifying CVR Holders. To be a Qualifying CVR Holder, a CVR Holder must provide certain information required under the Contingent Value Rights Agreement. If the stock price has generated a 10% preferred simple annual return with respect to the shares of HighPeak Energy common stock as of the CVR Maturity Date, then no additional shares will be issued pursuant to the CVRs, the CVRs will have no value and the CVRs will be automatically terminated without any further consideration. As of March 3, 2022, the Company’s share price was $21.50 per share and if the share price is similar at the CVR Maturity Date, no additional shares will be issued pursuant to the CVRs, the CVRs will have no value and the CVRs will be automatically terminated without any further consideration.

 

Consideration owed to the holders of the Contingent Value Rights, if any, will not be delivered prior to the CVR Maturity Date, except in certain limited circumstances.

 

The Contingent Value Rights will mature on the earlier of (i) the date to be specified by HighPeak I, HighPeak II and Sponsor, 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 our business, including certain mergers, consolidations and asset sales. The calculation and satisfaction of any Preferred Returns will occur, if applicable, following the CVR Maturity Date in accordance with the terms of the Contingent Value Rights Agreement. Because no interest will accrue on the Contingent Value Rights, you will not receive any compensation for holding any Contingent Value Rights between the Closing and either the termination of such Contingent Value Rights or HighPeak Energy’s issuance of additional shares of HighPeak Energy common stock needed to satisfy any Preferred Return, if any.

 

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.

 

HighPeak Energy cannot predict the extent to which trading of the CVRs will lead to an illiquid trading market with respect to such CVRs or whether the market price of the CVRs will be volatile. The CVRs may fluctuate significantly due to general market and economic conditions. An active trading market for the CVRs may never develop or, if it does develop, it may not be sustained. In addition, the price of the CVRs can vary due to general economic conditions and forecasts, HighPeak Energy’s general business condition and the release of HighPeak Energy’s financial reports. Additionally, if the CVRs are never listed on a national securities exchange for any reason and may only be quoted on the OTC Bulletin Board, an inter-dealer automated quotation system for equity securities that is not a national securities exchange, the liquidity and price of the CVRs may be more limited than if they were quoted or listed on a national securities exchange. You may be unable to sell your CVRs unless a market can be established or sustained.

 

CVRs may entitle CVR Holders to shares of HighPeak Energy common stock at the CVR Maturity Date or otherwise will result in shares of HighPeak Energy common stock released to HighPeak I, HighPeak II and Sponsor, which, in either case, would increase the number of shares eligible for future resale in the public market.

 

The CVR Holders 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 CVR Holders with the Preferred Returns (based on a $10.00 per share price at Closing). The Preferred Returns could entitle a Qualifying CVR Holder (as defined in the CVR Agreement) to receive up to 2.125 shares of HighPeak Energy common stock per CVR.

 

At the Closing, HighPeak I, HighPeak II and Sponsor collectively placed a number of shares of HighPeak Energy common stock in escrow equal to the maximum number of additional shares of HighPeak Energy common stock issuable pursuant to the Contingent Value Rights Agreement, which Escrowed Shares will be released either to HighPeak Energy for cancellation in connection with the satisfaction of any Preferred Returns or back to HighPeak I, HighPeak II and Sponsor, collectively, as applicable, following the CVR Maturity Date. Until such shares are released back to HighPeak I, HighPeak II and Sponsor, they may not be traded.

 

To the extent the Preferred Return is not met, additional shares of HighPeak Energy will be issued (and a corresponding number of shares of HighPeak Energy common stock will be released to HighPeak Energy from the escrow for cancellation), which will increase the number of shares eligible for resale in the public market. Sales of substantial numbers of such shares in the public market could adversely affect the market price of HighPeak Energy’s common stock. There would also be an increase in the number of shares of HighPeak Energy common stock eligible for resale in the public market if the Preferred Returns are met, pursuant to the Escrowed Shares being released to HighPeak I, HighPeak II and Sponsor, as discussed above. Regardless (i) if the Preferred Return is not met and shares of HighPeak Energy are issued with a corresponding number of Escrowed Shares released for cancellation or (ii) the Preferred Return is met and the Escrowed Shares are released to HighPeak I and HighPeak II, the total number of HighPeak Energy shares of common stock outstanding will not change.

 

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ITEM 1B. UNRESOLVED STAFF COMMENTS

 

None.

 

 

ITEM 3. LEGAL PROCEEDINGS

 

The Company may be a party to various proceedings and claims incidental to its business from time to time. While many of these matters involve inherent uncertainty, the Company believes the amount of the liability, if any, ultimately incurred with respect to these proceedings and claims will not have a material adverse effect on the Company’s consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. See “Item 8. Financial Statements and Supplementary Data – Note 10” for additional information.

 

 

ITEM 4. MINE SAFETY DISCLOSURES

 

Not applicable.

 

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PART II

 

ITEM 5. MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 

Market Information

 

HighPeak Energy’s common stock and warrants are listed and traded on the Nasdaq under the symbols “HPK” and “HPKEW,” respectively. HighPeak Energy’s CVRs are quoted on the OTC market under the symbol “HPKER.”

 

Holders

 

As of March 3, 2022, there were 21 holders of record of HighPeak Energy common stock, 14 holders of record of HighPeak Energy’s warrants and 19 holders of record of HighPeak Energy’s CVRs.

 

Dividend Policy

 

On July 6, 2021, the Company announced the initiation of a quarterly cash dividend in the amount of $0.025 per share of our common stock payable quarterly which began with the third quarter of 2021 and continued in the fourth quarter of 2021 and first quarter of 2022. The Company also approved a special dividend of $0.075 per share of common stock that was paid in July 2021. The decision to pay any future dividends is solely within the discretion of, and subject to approval by, our board of directors. Our board of directors’ determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination. In addition, our Revolving Credit Facility places certain restrictions on our ability to pay cash dividends.

 

Stock Performance Graph

 

We are a smaller reporting company as defined in Rule 12b-2 under the Exchange Act. As a result, pursuant to Item 201(e) of Regulation S-K, we are not required to provide the information required by this Item.

 

 

ITEM 6. [RESERVED]

 

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

The following discussion and analysis should be read in conjunction with the other sections of this Annual Report, including but not limited to Items 1 and 2: Business and Properties—Regulation of the Crude Oil and Natural Gas Industry.” Historical financial statements and related notes included elsewhere in this Report. This discussion containsforwardlooking statementsreflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forwardlooking statements due to a number of factors. Factors that could cause or contribute to such differences include, but are not limited to, market prices for crude oil and natural gas, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this report. Please read Cautionary Statement Concerning ForwardLooking Statements. Also, please read the risk factors and other cautionary statements described underPart I, Item 1A. Risk Factors.We assume no obligation to update any of these forwardlooking statements, except as required by applicable law. See the Company's Annual Report on Form 10-K for the year ended December 31, 2020 filed with the SEC on March 15, 2021 for a discussion of the Company's 2020 results of operations as compared to the Company's 2019 results of operations.

 

Overview

 

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

 

The Company’s assets are located primarily in Howard County, Texas, which lies within the northeastern part of the crude oil-rich Midland Basin. As of December 31, 2021, the assets consisted of two highly contiguous leasehold positions of approximately 82,023 gross (62,603 net) acres, approximately 44% of which were held by production, with an average working interest of 76%. Our acreage is composed of two core areas, Flat Top to the north and Signal Peak to the south. We operate approximately 90% of the net acreage across the Company’s assets and approximately 98% of the net operated acreage provides for horizontal wells with lateral lengths of 10,000 feet or greater. For the year ended December 31, 2021, approximately 95% and 5% of sales volumes from the assets were attributable to liquids (both crude oil and NGL) and natural gas, respectively. As of December 31, 2021, HighPeak Energy was drilling with three (3) rigs and was in the process of rigging up a fourth rig. Further, as of December 31, 2021, the Company owned an interest in approximately 246 gross (105.7 net) producing wells, 78 gross (71.3 net) of which are operated by the Company, including 59 gross (47.4 net) horizontal wells, 43 gross (41.5 net) of which are operated by the Company. As of December 31, 2021, of the 64,213 MBoe of proved reserves associated with the assets, 45% were developed, 92% of which were liquids.

 

The markets for the commodities produced by our industry strengthened in 2021 as a result of increased demand outpacing increased supply for each of the commodities we produce. Prices for the commodities produced by our industry improved from historic lows in 2020, with crude oil and natural gas prices reaching their highest average annual price since 2014. However, commodity markets remain subject to heightened levels of uncertainty related to the COVID-19 pandemic and escalating tensions between Russia and Ukraine. Russian military incursion into Ukraine could give rise to regional instability and result in heightened economic sanctions by the U.S. and the international community that, in turn, could increase uncertainty with respect to global financial markets and production output from OPEC and other crude oil producing nations. Additionally, the COVID-19 pandemic remains a global health crisis and continues to evolve. Despite the emergence of new variants, deployment of vaccines and vaccine boosters to slow the spread of the COVID-19 virus has resulted in substantial improvements in global financial markets and public health. Disruption in financial and commodity markets and industry-specific impacts could result from future case surges or outbreaks, COVID-19 virus variants, the potential that current vaccines may be less effective or ineffective against future COVID-19 virus variants, and the risk that large groups of the population may not receive vaccinations against COVID-19, and as a result, may require us to adjust our business plan. Despite continuing impacts of the COVID-19 pandemic, geopolitical issues, and future uncertainty, we expect to maintain our ability to sustain strong operational performance and financial stability while maximizing returns, improving leverage metrics, and increasing the value of our Midland Basin assets.

 

The financial results as presented in this section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” consist of the historical results of HPK LP for the period from January 1, 2020 through August 21, 2020 and the Company from August 22, 2020 through December 31, 2021. At the Closing of the HighPeak business combination on August 21, 2020, the Company’s “predecessor” for accounting purposes was HPK LP for the period from January 1, 2020 through August 21, 2020 (the “Predecessor”).

 

Outlook

 

HighPeak Energy’s financial position and future prospects, including its revenues, operating results, profitability, liquidity, future growth and the value of its assets, depend heavily on prevailing commodity prices. The crude oil and natural gas industry is cyclical and commodity prices are highly volatile and subject to a high degree of uncertainty. For example, during the period from January 1, 2018 through December 31, 2021, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $16.70 to a high of $81.22, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.50 to a high of $6.20.

 

Based on current commodity prices and other factors, the Company currently plans to operate four (4) drilling rigs and an average of two (2) frac fleets in the Permian Basin during 2022. However, there are many factors and consequences beyond the Company's control, such as policies of the Biden Administration, economic downturn or potential recession, geo-political risks and additional actions by businesses, OPEC and other cooperating countries, and governments in response to the COVID-19 pandemic, that may have an impact on the Company’s future results and drilling plans. For additional information on the risks, see “Part I, Item 1A. Risk Factors”. Given the dynamic nature of this situation, the Company is maintaining flexibility in its capital plan and will continue to evaluate drilling and completion activity on an economic basis, with future activity levels assessed monthly.

 

57

 

Impact of Hedging

 

With the addition of the Revolving Credit Facility in December 2020, HighPeak Energy was required to and has entered into hedging arrangements. The Company’s outstanding crude oil derivative contracts and the weighted average crude oil prices per barrel for those contracts, including those contracts entered into subsequent to December 31, 2021, are as follows:

 

   

2022

   

2023

 
   

First

Quarter

   

Second

Quarter

   

Third

Quarter

   

Fourth

Quarter

   

Total

   

First

Quarter

   

Second

Quarter

   

Total

 

Crude Oil Price Swaps - WTI: (a)

                                                               

Volume (MBbls)

    966.4       1,039.8       456.4       487.4       2,950.0       441.0       200.2       641.2  

Price per Bbl

  $ 69.26     $ 71.96     $ 75.15     $ 70.14     $ 71.27     $ 70.05     $ 57.22     $ 66.04  

 

 

Impact of the COVID-19 Pandemic

 

The COVID-19 pandemic that resulted in a severe worldwide economic downturn in early 2020, significantly disrupting the demand for crude oil and natural gas throughout the world, and created significant volatility, uncertainty and turmoil in the crude oil and natural gas industry has largely recovered. The decrease in demand for crude oil combined with pressures on the global supply-demand balance for crude oil and related products, resulted in crude oil prices declining significantly beginning in late February 2020. The length of this demand disruption is unknown, and there is significant uncertainty regarding the long-term impact to global crude oil demand, which will ultimately depend on various factors and consequences beyond the Company's control, such as the duration and scope of the pandemic, the length and severity of the worldwide economic downturn, the ability of OPEC, Russia and other crude oil producing nations to manage the global crude oil supply, additional actions by businesses and governments in response to the pandemic, the economic downturn and the decrease in crude oil demand, the speed and effectiveness of responses to combat the virus and the time necessary to balance crude oil supply and demand to restore crude oil pricing. Although prices have recovered, the ongoing impact of COVID-19 on our business, employees and operations, including supply chain concerns, among others still continues to affect our industry. In response to these developments, the Company has implemented measures to mitigate the impact of the COVID-19 pandemic on its employees, operations and financial position. These measures include, but are not limited to, the following:

 

Employee Safety. The Company has taken steps to keep its employees safe during the COVID-19 pandemic by implementing preventative measures and developing response plans intended to minimize unnecessary risk of exposure and infection among its employees. The Company has also modified certain business practices (including those related to non-operational employee work locations, such as a significant reduction in physical participation in meetings, events and conferences) to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, and other governmental and regulatory authorities.

 

Materials Management. With the supply chain disruptions, overall inflation on materials in general and lack of availability of tubulars, vessels and pumps, the Company has implemented the precautionary measure of pre-ordering many of these types of equipment to ensure they are available when needed to continue our drilling program to minimize delays due to shortages.

 

Balance Sheet, Cash Flow and Liquidity. The Company has taken the following actions to strengthen its financial position and increase liquidity:

 

 

Maintained a strong balance sheet and pursued increased liquidity by issuing a small amount of equity and adding a credit facility with attractive interest rates.

 

Used derivative positions to reduce the effects of crude oil price volatility on its net cash provided by operating activities.

 

The Company continues to assess the global impacts of the COVID-19 pandemic and may modify its plans as the health and economic impacts of COVID-19 continue to evolve.

 

Financial and Operating Performance

 

The Company's financial and operating performance for the year ended December 31, 2021 included the following highlights:

 

 

Net income attributable to common stockholders for the year ended December 31, 2021 was $55.6 million ($0.54 per diluted share) compared with a combined net loss of the Company and its Predecessor of $101.5 million for the year ended December 31, 2020. The primary components of the $157.0 million increase in earnings attributable to common stockholders include:

 

 

a $195.5 million increase in crude oil and natural gas revenues due to a 383% increase in daily sales volumes due to the Company’s successful horizontal drilling program in the Permian Basin, plus an 86% increase in average realized commodity prices per Boe, excluding the effect of derivatives;

 

58

 

 

a decrease in other expense of $76.3 million primarily due to a charge to expense in 2020 related to an acquisition that was terminated in April 2020;

   

 

 

a $9.1 million decrease in stock-based compensation expense primarily attributable to stock options that were granted in August 2020 upon the closing of the HighPeak business combination whereby approximately 75% of the stock options vested immediately causing a charge to earnings; and

   

 

 

a $3.5 million decrease in exploration and abandonment expenses related to lower impairment of undeveloped leasehold costs that the Company was not successful in obtaining extensions on of $4.6 million during 2021 compared with 2020 partially offset by increased geophysical data purchases and geologic and geophysical personnel costs of $1.1 million during 2021 compared with 2020;

 

partially offset by:

 

 

a $48.9 million increase in DD&A expense due to a 383% increase in daily sales volumes, partially offset by an 17% decrease in the DD&A rate from $23.08 to $19.20 per Boe, both as a result of increased proved reserves due to the Company’s successful horizontal drilling program in the Permian Basin;

   

 

 

a $26.8 million increase in production costs, including production and ad valorem taxes, primarily attributable to the 383% increase in daily sales volumes as a result of the Company’s successful horizontal drilling program in the Permian Basin combined with 53% higher production and ad valorem taxes on a dollar per Boe basis due to higher overall realized prices of 86%;

   

 

 

a derivative loss of $26.7 million during the year ended December 31, 2021 compared with zero in the prior year consisting of $11.3 million in settlement payments on contracts that have expired and $15.4 million in net mark to market losses on contracts for future months;

   

 

 

a $21.1 million increase in the Company's income tax expense due to the net income experienced in 2021 compared with the net loss experienced in 2020 and the fact that the Predecessor was a pass through entity for income tax purposes and did not recognize any tax expense or benefit on their financial statements;

   

 

 

a $2.5 million increase in the Company's interest expense due to the borrowings on the Company’s revolving credit facility that began in early 2021; and

   

 

 

a $1.3 million increase in general and administrative costs due primarily to bonuses paid to HighPeak Energy employees compared with none in the prior year.

 

 

During the year ended December 31, 2021, average daily sales volumes totaled 9,304 Boepd, an increase of 383% over 2020, due to the Company's successful horizontal drilling program in the Permian Basin.

   

 

 

Weighted average realized crude oil prices per Bbl increased during the year ended December 31, 2021 to $70.10, excluding the effects of derivatives, compared with $37.96 for 2020. Weighted average realized NGL prices per Bbl increased during the year ended December 31, 2021 to $35.11, compared with $14.06 for 2020. Weighted average realized natural gas prices per Mcf increased to $3.88 during the year ended December 31, 2021, compared with $1.04 during 2020.

   

 

 

Cash provided by operating activities totaled $147.0 million for the year ended December 31, 2021.

   

 

 

The Company increased its borrowing capacity under its Revolving Credit Facility to $195 million with $100.0 million drawn as of December 31, 2021. The Company also raised $22.8 million of capital, net of offering costs, in October 2021 with the issuance of 2,530,000 shares of common stock. This capital gave the Company flexibility to increase its development drilling program from one to three rigs late in 2021 with the addition of a fourth rig underway at yearend. During the year, the Company placed 30 gross (24.5 net) horizontal wells on production, drilled and completed 1 gross (1.0 net) salt-water disposal well and completed $54.0 million in acquisitions of both producing properties and a significant amount of bolt-on undeveloped acreage increasing its drilling inventory. As of December 31, 2021, the Company was also in the process of drilling 5 gross (5.0 net) horizontal producers and 1 gross (1.0 net) salt-water disposal well and had 22 gross (18.0 net) horizontal producers either waiting on completion or in various stages of completion operations.

 

59

 

Operations and Drilling Highlights

 

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

 

   

Year Ended

December 31,

2021

 

Oil (Bbls)

    8,225  

NGL (Bbls)

    613  

Gas (Mcf)

    2,795  

Total (Boe)

    9,304  

 

The Company's liquids production was 95% of total production on a Boe basis for the year ended December 31, 2021.

 

Costs incurred are as follows (in thousands):

 

   

Year ended

December 31,

2021

 

Unproved property acquisition costs

  $ 20,792  

Proved acquisition costs

    33,253  

Total acquisitions

    54,045  

Development costs

    45,852  

Exploration costs

    190,346  

Total finding and development costs

    290,243  

Asset retirement obligations

    1,844  

Total costs incurred

  $ 292,087  

 

Development and exploration/extension drilling activity is as follows:

 

   

Year Ended December 31, 2021

 
   

Development/

Service

   

Exploration/

Extension

 

Beginning wells in progress

          4  

Well spud

    9       41  

Successful wells

    (3

)

    (23

)

Ending wells in progress

    6       22  

 

During the year ended December 31, 2021, the Company successfully drilled twenty-six (26) horizontal wells, of which twenty-one (21) horizontal wells were located in Flat Top, including one (1) salt-water disposal well, and five (5) were located in Signal Peak. Also, we had an additional twenty-eight (28) wells in progress as of December 31, 2021. At Flat Top, we had four (4) wells being drilled, including three (3) horizontal wells and one (1) salt-water disposal well and twenty (20) horizontal wells in various stages of completion. At Signal Peak, we had two (2) horizontal wells being drilled and two (2) horizontal wells in various stages of completion.

 

Results of Operations

 

Results of operations should be read together with the Company’s consolidated financial statements and related notes included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report. See the Company’s Annual Report on Form 10-K for the year ended December 31, 2020 filed with the SEC on March 15, 2021 for a discussion of the Company’s 2020 results of operations as compared with the Company’s 2019 results of operations.

 

Sources of Revenues

 

The Company’s revenues, which are entirely originated in the continental United States, are derived from the sale of crude oil and natural gas production and the sale of NGL that are extracted from natural gas during processing. For the years ended December 31, 2021 and 2020, revenues from our assets were derived approximately 96% and 98%, respectively, from crude oil sales and 4% and 2%, respectively, from NGL and natural gas sales.

 

The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with significant purchasers.  For the year ended December 31, 2021, sales to the Company’s largest purchaser accounted for approximately 94% of the Company’s total crude oil, NGL and natural gas sales revenues.  The Company generally does not require collateral and does not believe the loss of this particular purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in various regions.

 

The Company’s revenues are presented net of certain gathering, transportation and processing expenses incurred to deliver production of its assets’ crude oil, NGL and natural gas to the market. Cost levels of these expenses can vary based on the volume of crude oil, NGL and natural gas produced as well as the cost of commodity processing. Crude oil, NGL and natural gas prices are inherently volatile and are influenced by many factors outside the Company’s control. To reduce the impact of fluctuations in crude oil, NGL and natural gas prices on revenues, the Company may periodically enter into derivative contracts with respect to a portion of its estimated crude oil, NGL and natural gas production through various transactions that fix the future prices received.

 

60

 

Principal Components of Cost Structure

 

Costs associated with producing crude oil, NGL and natural gas are substantial. Some of these costs vary with commodity prices, some trend with the type and volume of production, and others are a function of the number of wells owned. The sections below summarize the primary operating costs typically incurred:

 

 

Lease Operating Expenses. Lease operating expenses (“LOE”) are the costs incurred in the operation of producing properties and workover costs. Expenses for utilities, direct labor, water injection and disposal, workover rigs and workover expenses, materials and supplies comprise the most significant portion of LOE. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to pumping equipment or surface facilities result in increased LOE in periods during which they are performed. Certain operating cost components are variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases. For example, power costs are incurred in connection with various production-related activities, such as pumping to recover crude oil and natural gas and separation and treatment of water produced in connection with crude oil and natural gas production.

 

   

The Company monitors the operation of its assets to ensure that it is incurring LOE at an acceptable level. For example, it monitors LOE per Boe to determine if any wells or properties should be shut in, recompleted or sold. This unit rate also allows the Company to monitor these costs to identify trends and to benchmark against other producers. Although the Company strives to reduce its LOE, these expenses can increase or decrease on a per-unit basis as a result of various factors as it operates its assets or makes acquisitions and dispositions of properties. For example, the Company may increase field-level expenditures to optimize their operations, incurring higher expenses in one quarter relative to another, or they may acquire or dispose of properties that have different LOE per Boe. These initiatives would influence overall operating cost and could cause fluctuations when comparing LOE on a period-to-period basis.

 

 

Production and other taxes. Production and other taxes are paid on produced crude oil and natural gas based on rates established by federal, state or local taxing authorities. In general, production and other taxes paid correlate to changes in crude oil, NGL and natural gas revenues. Production taxes are based on the market value of production at the wellhead. The Company is also subject to ad valorem taxes in the counties where production is located. Ad valorem taxes are based on the fair market value of the mineral interests for producing wells.

   

 

 

Depletion – Crude Oil and Natural Gas Properties. Depletion is the systematic expensing of the capitalized costs incurred to acquire and develop crude oil and natural gas properties. The Company uses the successful efforts method of accounting for crude oil and natural gas properties. Accordingly, all costs associated with acquisition, successful exploration wells and development of crude oil and natural gas reserves, including directly related overhead costs and asset retirement costs are capitalized. However, the costs of abandoned properties, exploratory dry holes, geophysical costs and annual lease rentals are charged to expense as incurred. All capitalized costs of crude oil and natural gas properties are amortized on the unit-of-production method using estimates of proved reserves. Any remaining investments in unproved properties are not amortized until proved reserves associated with the projects can be determined or until impairment occurs.

   

 

 

General and Administrative Expenses. General and administrative expenses (“G&A”) are costs incurred for overhead, including payroll and benefits for corporate staff and costs of maintaining a headquarters, costs of managing production and development operations, IT expenses and audit and other fees for professional services, including legal compliance and acquisition-related expenses.

 

Factors Affecting the Comparability of the Predecessor Historical Financial Results

 

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

 

 

The historical financial statements included herein are the financial statements of HPK LP for the period beginning January 1, 2020 and ending on August 21, 2020, as the Predecessor for financial reporting purposes;

 

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

 

61

 

 

our assets will incur certain additional general and administrative expenses related to being owned by a publicly traded company, that were not previously incurred in HPK LP’s cost structure, including, but not limited to, Exchange Act reporting expenses; expenses associated with compliance with the Sarbanes-Oxley Act of 2002; expenses associated with being listed on a national securities exchange; incremental independent auditor fees; incremental legal fees; investor relations expenses; registrar and transfer agent fees; incremental director and officer liability insurance costs and non-management director compensation;

 

the Predecessor completed acquisitions during the periods presented, including primarily the acquisition of undeveloped acreage and to a lesser extent producing properties and proved undeveloped reserves for approximately $3.3 million during the period from January 1, 2020 through August 21, 2020;

 

during the period beginning January 1, 2020 and ending on August 21, 2020, HPK LP recognized a charge to expense of $76.5 million related to the termination of the Grenadier Acquisition (as defined in “Item 8. Financial Statements and Supplementary Data;” and

 

Our Predecessor financed operations predominantly through equity financing, while beginning with the establishment of our Revolving Credit Facility in December 2020, continued borrowing base increases and our recent notes offering of 2024 Notes in February 2022, we have financed a significant portion of our operations and growth with indebtedness.

 

Results of Operations

 

Results of operations should be read together with the Company's consolidated financial statements and related notes included in "Item 8. Financial Statements and Supplementary Data" of this Annual Report on Form 10-K.

 

 

Crude Oil, NGL and natural gas revenues.

 

The Company’s revenues are derived from the sales of crude oil, NGL and natural gas production. Increases or decreases in the Company’s revenues, profitability and future production are highly dependent on commodity prices. Prices are market driven and future prices will fluctuate due to supply and demand factors, availability of transportation, seasonality, geopolitical developments and economic factors, among other items.

 

           

Year Ended December 31, 2020

         
   

Year Ended

December 31,

2021

   

August 22,

2020 through

December 31,

2020

   

January 1,

2020 through

August 21,

2020

   

Year to

Year

Change

 
   

Successor

   

Successor

   

Predecessor

         
   

(in thousands)

 

Crude oil, NGL and natural gas revenues

  $ 220,124     $ 16,400     $ 8,223     $ 195,501  

 

Average daily sales volumes are as follows:

 

           

Year Ended December 31, 2020

         
   

Year Ended

December 31,

2021

   

August 22,

2020 through

December 31,

2020

   

January 1,

2020 through

August 21,

2020

   

Year to

Year %

Change

 
   

Successor

   

Successor

   

Predecessor

         

Crude Oil (Bbls)

    8,225       3,017       1,007       375 %

NGL (Bbls)

    613       134       86       495 %

Natural Gas (Mcf)

    2,795       849       373       413 %

Total (Boe)

    9,304       3,292       1,154       383 %

 

The increase in average daily Boe sales volumes for the year ended December 31, 2021, compared with 2020 was due to the Company's successful horizontal drilling program.

 

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

 

           

Year Ended December 31, 2020

         
   

Year Ended

December 31,

2021

   

August 22,

2020 through

December 31,

2020

   

January 1,

2020 through

August 21,

2020

   

Year to

Year %

Change

 
   

Successor

   

Successor

   

Predecessor

         

Oil per Bbl

  $ 70.10     $ 40.15     $ 34.26       85 %

NGL per Bbl

  $ 35.11     $ 19.44     $ 9.31       150 %

Gas per Mcf

  $ 3.88     $ 1.45     $ 0.52       273 %

Total per Boe

  $ 64.82     $ 37.74     $ 30.44       86 %

 

62

 

The increase in prices for crude oil, NGL and natural gas for the year ended December 31, 2021, compared with 2020 was due to a higher commodity price environment.

 

Crude oil and natural gas production costs.

 

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

 

           

Year Ended December 31, 2020

         
   

Year Ended

December 31,

2021

   

August 22,

2020 through

December 31,

2020

   

January 1,

2020 through

August 21,

2020

   

Year to

Year %

Change

 
   

Successor

   

Successor

   

Predecessor

         

Crude oil and natural gas production costs

  $ 25,053     $ 2,653     $ 4,870       233 %

Crude oil and natural gas production costs per Boe

  $ 7.38     $ 6.10     $ 18.03       (31 )%

 

The increase in lease operating expenses can be attributed to the fact that by the end of 2021 we had ownership in fifty-nine (59) producing horizontal wells compared with nineteen (19) horizontal wells at the end of 2020. Likewise, the decrease in lease operating expense per Boe for the year ended December 31, 2021, compared with 2020, was primarily attributable to the increased production volumes associated with the higher well count. We anticipate continued reduction to the lease operating expense per Boe as we put more wells on production, start up our electrification project which will reduce the use of generators for power and continue to expand our salt-water collection and disposal system to decrease the use of trucks.

 

Production and ad valorem taxes.

 

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

 

           

Year Ended December 31, 2020

         
   

Year Ended

December 31,

2021

   

August 22,

2020 through

December 31,

2020

   

January 1,

2020 through

August 21,

2020

   

Year to

Year %

Change

 
   

Successor

   

Successor

   

Predecessor

         

Production and ad valorem taxes

  $ 10,746     $ 886     $ 566       1,799 %

 

In general, production taxes and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices and valuations as of the first of the year, whereas production taxes are based upon current year commodity prices and sales volumes.

 

Production and ad valorem taxes per Boe are as follows:

 

           

Year Ended December 31, 2020

         
   

Year Ended

December 31,

2021

   

August 22,

2020 through

December 31,

2020

   

January 1,

2020 through

August 21,

2020

   

Year to

Year %

Change

 
   

Successor

   

Successor

   

Predecessor

         

Production taxes per Boe

  $ 3.09     $ 1.78     $ 1.42       118 %

Ad valorem taxes per Boe

  $ 0.07     $ 0.26     $ 0.68       (90 )%

 

Production taxes per Boe for the year ended December 31, 2021, compared with 2020, increased primarily due to the 86% overall increase in commodity prices. The decrease in ad valorem taxes per Boe for the year ended December 31, 2021, compared with 2020, was primarily due to a significant number of wells that have come on production during 2021 that had no ad valorem tax in 2021 as 2022 will be the first year that they will be assessed ad valorem taxes. In Texas, ad valorem taxes are based on a valuation of the wells on January 1 of a given year.

 

63

 

Exploration and abandonments expense.

 

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

 

           

Year Ended December 31, 2020

         
   

Year Ended

December 31,

2021

   

August 22,

2020 through

December 31,

2020

   

January 1,

2020 through

August 21,

2020

   

Year to

Year %

Change

 
   

Successor

   

Successor

   

Predecessor

         

Geologic and geophysical data costs

  $ 807     $ 179     $ 3       351

%

Geologic and geophysical personnel costs

    487       4             6,857

%

Abandoned leasehold costs

    235       4,827             (95

)%

Plugging and abandonment expense

    20       22       1       (13

)%

Exploration and abandonments expense

  $ 1,549     $ 5,032     $ 4       (69

)%

 

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

 

Depletion, depreciation and amortization expense.

 

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

 

            Year Ended December 31, 2020          
   

Year Ended

December 31,

2021

   

August 22,

2020 through

December 31,

2020

   

January 1,

2020 through

August 21,

2020

   

Year to

Year %

Change

 
   

Successor

   

Successor

   

Predecessor

         

DD&A expense

  $ 65,201     $ 9,877     $ 6,385       301

%

DD&A expense per Boe

  $ 19.20     $ 22.73     $ 23.64       (17

)%

 

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

 

General and administrative expense.

 

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

 

           

Year Ended December 31, 2020

         
   

Year Ended

December 31,

2021

   

August 22,

2020 through

December 31,

2020

   

January 1,

2020 through

August 21,

2020

   

Year to

Year %

Change

 
   

Successor

   

Successor

   

Predecessor

         

General and administrative expense

  $ 8,885     $ 2,775     $ 4,840       17

%

General and administrative expense per Boe

  $ 2.62     $ 6.39     $ 17.92       (76

)%

Stock-based compensation expense

  $ 6,676     $ 15,776     $       (58

)%

 

The increase in general and administrative expense for the year ended December 31, 2021 is primarily as a result of increased employee count, salary increases, annual bonuses paid to employees in December 2021 and the increased administrative costs associated with being a public company, partially offset by more general and administrative costs being allocated to drilling and completion operations and construction projects and producing properties due to increased activity and well count in 2021 compared with 2020, no business combination charges in 2021 compared with 2020 and lower exploration general and administrative expenses that are classified as exploration and abandonment expense which are now identifiable and not included as a component of administration fees paid to a management company.

 

64

 

The decrease in noncash stock-based compensation expense is due to fewer awards being issued in 2021 as compared with 2020.

 

Interest expense.

 

           

Year Ended December 31, 2020

         
   

Year Ended

December 31,

2021

   

August 22,

2020 through

December 31,

2020

   

January 1,

2020 through

August 21,

2020

   

Year to

Year %

Change

 
   

Successor

   

Successor

   

Predecessor

         

Interest expense

  $ 2,484     $ 8     $       30,950

%

 

The increase in interest expense can be attributed to the fact that we entered into our Revolving Credit Facility in December 2020 and began drawing on it late in the second quarter of 2021. Interest expense for the year ended December 31, 2021 includes interest expense of $1.7 million, commitment fees of $245,000 and amortization of debt issuance costs of $498,000.

 

Derivative gain (loss), net.

 

           

Year Ended December 31, 2020

         
   

Year Ended

December 31,

2021

   

August 22,

2020 through

December 31,

2020

   

January 1,

2020 through

August 21,

2020

   

Year to

Year %

Change

 
   

Successor

   

Successor

   

Predecessor

         

Noncash derivative gain (loss), net

  $ (15,467

)

  $     $       100

%

Cash payments on settled derivative instruments, net

    (11,267

)

                100

%

Derivative gain (loss), net

  $ (26,734

)

  $     $       100

%

 

The Company primarily utilizes commodity swap contracts, collar contracts, collar contracts with short puts and basis swap contracts to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company’s annual capital budget and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company’s Credit Agreement and the indenture for the Company’s 2024 Notes require the Company to hedge certain quantities of its projected crude oil production. The Company may also, from time to time, utilize interest rate contracts to reduce the effect of interest rate volatility on the Company’s indebtedness. The above mark-to-market loss and cash settlements relate to crude oil derivative swap contracts.

 

 

Income tax expense.

 

           

Year Ended December 31, 2020

         
   

Year Ended

December 31,

2021

   

August 22,

2020 through

December 31,

2020

   

January 1,

2020 through

August 21,

2020

   

Year to

Year %

Change

 
   

Successor

   

Successor

   

Predecessor

         

Income tax expense (benefit)

  $ 16,904     $ (4,223 )   $       n/a  

Effective income tax rate

    23.3

%

    20.4 %     0.0

%