Docoh
Loading...

HPK HighPeak Energy

Filed: 17 May 21, 4:02pm
 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 


 

FORM 10-Q

 


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

 

For the quarterly period ended March 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: 333-248898

 


 

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 Commons Stock

HPKEW

The Nasdaq Stock Market LLC

 

Not applicable

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

 


 

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes ☐     No

 

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes ☒     No

 

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

 

Large accelerated filer

Accelerated filer

 

Non-accelerated filer

Smaller reporting company

 
  

Emerging growth company

 

 

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

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ☐     No

 

As of May 14, 2021, there were 92,675,898 shares of common stock, par value $0.0001 per share, issued and outstanding.

 

 

 

 

 

HIGHPEAK ENERGY, INC.

TABLE OF CONTENTS

 

  

Page

Definitions of Certain Terms and Conventions Used Herein

1

Cautionary Statement Concerning Forward-Looking Statements

5
 

PART I. FINANCIAL INFORMATION

 

Item 1.

Condensed Consolidated and Combined Financial Statements (Unaudited)

6
 

Condensed Consolidated Balance Sheets

6
 

Condensed Consolidated and Combined Statements of Operations

7
 

Condensed Consolidated Statement of Changes in Stockholders’ Equity (Successor)

8
 

Condensed Consolidated Statement of Changes in Partners’ Capital (Predecessor)

9
 

Condensed Consolidated and Combined Statements of Cash Flows

10
 

Notes to Condensed Consolidated and Combined Financial Statements

11

Item 2.

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

24

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

32

Item 4.

Controls and Procedures

33
 

PART II. OTHER INFORMATION

 

Item 1.

Legal Proceedings

34

Item 1A.

Risk Factors

34

Item 6.

Exhibits

35

Signatures

  

 

 

 
 
 

HIGHPEAK ENERGY, INC.

 

Definitions of Certain Terms and Conventions Used Herein

 

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

 

 

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

 

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

 

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

 

"Boe" means a barrel of oil equivalent and is a standard convention used to express oil and natural gas volumes on a comparable 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 oil or NGL.

 

"Boe/d" means Boe per day.

 

"Bopd" means one barrel of oil per day.

 

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

 

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

 

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

 

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

 

“Completion” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

 

“Contingent Value Right” or “CVR” refers to contractual contingent value rights, representing the right, under certain circumstances, to receive additional shares of HighPeak Energy common stock, if necessary, to satisfy a 10% preferred simple annual return, subject to a floor downside per-share price of $4.00, as measured on August 21, 2022 or February 21, 2023 (with an equivalent number of shares of HighPeak Energy common stock held by HighPeak I and HighPeak II being collectively forfeited).

 

"DD&A" means depletion, depreciation and amortization expense.

 

1

 

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

"MBbl" means one thousand Bbls.

 

"MBoe" means one thousand Boes.

 

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

 

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

 

"MMBbl" means one million Bbls.

 

"MMBtu" means one million Btus.

 

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

 

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

 

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

 

2

 

 

"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 an oil or natural gas well or lease.

 

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

 

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

 

“Predecessors” refers to, collectively, HPK LP and HighPeak I and individually from the period from October 1, 2019 to August 21, 2020 to HPK LP and for all prior periods, HighPeak I.

 

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

 

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

 

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

 

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

 

“Proved developed nonproducing reserves” means developed nonproducing reserves.

 

“Proved developed producing reserves” means developed producing reserves.

 

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

 

“Proved reserves” Those quantities of oil and 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 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 oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

  

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

  

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

 

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

 

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

 

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

 

3

 

 

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

 

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

 

“Reserves” Reserves are estimated remaining quantities of oil and 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 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 oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

 

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

 

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

 

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

 

"SEC" means the United States Securities and Exchange Commission.

 

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

 

“Spacing” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 100-acre spacing, and is often established by regulatory agencies.

 

“Sponsor” means HighPeak Pure Acquisition, LLC, a Delaware limited liability company.

 

“Spot market price” The cash market price without reduction for expected quality, transportation and demand adjustments.

 

“Standardized measure” Discounted future net cash flows estimated by applying year-end prices to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

 

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

 

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

 

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

 

"U.S." means the United States.

 

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

 

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

 

“Working 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 oil produced from fields in western Texas and is a grade of oil used as a benchmark in oil pricing.

 

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

 

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

 

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.

 

4

 

 

Cautionary Statement Concerning Forward-Looking Statements

 

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

 

 

the length, scope and severity of the ongoing coronavirus disease 2019 (“COVID-19”) pandemic, including the effects of related public health concerns and the impact of continued actions taken by governmental authorities and other third parties in response to the pandemic and its impact on commodity prices, supply and demand considerations, and storage capacity;

 

 

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

 

 

the supply and demand for 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,” included in the Company’s Annual Report on Form 10-K filed on March 15, 2021 and “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part I, Item 3. Quantitative and Qualitative Disclosures about Market Risk,” included in this Quarterly Report on Form 10-Q, and elsewhere in this Report.

 

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

 

Additionally, we caution you that reserve engineering is a process of estimating underground accumulations of 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 oil, NGL and natural gas that are ultimately recovered.

 

5

 

 

 

PART I. FINANCIAL INFORMATION

 
 

ITEM 1. CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (UNAUDITED)

 

 

HighPeak Energy, Inc.

Condensed Consolidated Balance Sheets

(in thousands, except share data)

 

  

March 31,

2021

  

December 31,

2020

 
  

(Unaudited)

     
ASSETS        

Current Assets:

        

Cash and cash equivalents

 $9,638  $19,552 

Accounts receivable

  16,915   7,722 

Subscription receivable

  -   3,596 

Prepaid expenses

  816   2,254 

Inventory

  109   121 

Deposits

  50   50 

Total current assets

  27,528   33,295 

Oil and natural gas properties, using the successful efforts method of accounting:

        

Proved properties

  433,693   367,372 

Unproved properties

  131,709   152,741 

Accumulated depletion, depreciation and amortization

  (30,392

)

  (17,477

)

Total oil and natural gas properties, net

  535,010   502,636 

Other property and equipment, net

  1,044   1,092 

Other noncurrent assets

  745   907 

Total assets

 $564,327  $537,930 
LIABILITIES AND STOCKHOLDERS' EQUITY        

Current liabilities:

        

Accounts payable - trade

 $12,760  $7,581 

Accrued liabilities

  20,525   12,374 

Other current liabilities

  1,520   2,480 

Total current liabilities

  34,805   22,435 

Noncurrent liabilities:

        

Deferred income taxes

  40,013   38,898 

Asset retirement obligations

  2,481   2,293 

Other

  52   78 

Commitments and contingencies (Note 9)

        

Stockholders' equity:

        

Preferred stock, $0.0001 par value, 10,000,000 shares authorized, none issued and outstanding at March 31, 2021 and December 31, 2020

  -   - 

Common stock, $0.0001 par value, 600,000,000 shares authorized, 92,675,898 and 91,967,565 shares issued and outstanding at March 31, 2021 and December 31, 2020, respectively

  9   9 

Additional paid-in capital

  589,432   581,426 

Accumulated deficit

  (102,465

)

  (107,209)

Total stockholders' equity

  486,976   474,226 

Total liabilities and stockholders' equity

 $564,327  $537,930 

 

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

 

6

 

 

 

HighPeak Energy, Inc.

Condensed Consolidated and Combined Statements of Operations

(in thousands, except per share data)

(Unaudited)

 

  

Three Months Ended

March 31,

 
  

2021

  

2020

 
  

Successor

  

Predecessor

 

Operating Revenues:

        

Crude oil sales

 $24,870  $4,524 

NGL and natural gas sales

  847   99 

Total operating revenues

  25,717   4,623 

Operating Costs and Expenses:

        

Oil and natural gas production

  2,227   2,389 

Production and ad valorem taxes

  1,664   308 

Exploration and abandonments

  191   3 

Depletion, depreciation and amortization

  12,963   3,356 

Accretion of discount on asset retirement obligations

  35   34 

General and administrative

  1,759   2,861 

Stock-based compensation

  966   - 

Total operating costs and expenses

  19,805   8,951 

Income (loss) from operations

  5,912   (4,328

)

Interest income

  1   - 

Interest expense

  (54

)

  - 

Other expense

  -   (76,503

)

Income (loss) before income taxes

  5,859   (80,831

)

Income tax expense

  1,115   - 

Net income (loss)

 $4,744  $(80,831

)

Earnings per share:

        

Basic net income

 $0.05     

Diluted net income

 $0.05     
         

Weighted average shares outstanding:

  92,592     

Basic

  95,482     

Diluted

        

 

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

 

7

 

 

 

 

HighPeak Energy, Inc.

Condensed Consolidated Statement of Changes in Stockholders' Equity (Successor)

(in thousands)

(Unaudited)

 

Three Months Ended March 31, 2021

             
  

Shares

Outstanding

  

Common

Stock

  

Additional

Paid-in

Capital

  

Retained

Earnings

(Accumulated

Deficit)

  

Total

Stockholders'

Equity

 

Balance, December 31, 2020

  91,968  $9  $581,426  $(107,209

)

 $474,226 

Exercise of warrants

  554   -   5,466   -   5,466 

Stock-based compensation costs:

                    

Shares issued upon options being exercised

  154   -   1,574   -   1,574 

Compensation costs included in net income

  -   -   966   -   966 

Net income

  -   -   -   4,744   4,744 

Balance, March 31, 2021

  92,676  $9  $589,432  $(102,465

)

 $486,976 

 

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

 

8

 

 

HighPeak Energy, Inc.

Condensed Consolidated Statement of Changes in Partners' Capital (Predecessor)

(in thousands)

(Unaudited)

 

Three Months Ended March 31, 2020

         
  

General

Partner

Capital

  

Limited

Partners'

Capital

  

Total

Partners'

Capital

 

Balance, December 31, 2019

 $-  $464,716  $464,716 

Cash capital contributions

  -   54,000   54,000 

Net loss

  -   (80,831

)

  (80,831

)

Balance, March 31, 2020

 $-  $437,885  $437,885 

 

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

 

9

 

 

 

HighPeak Energy, Inc.

Condensed Consolidated and Combined Statements of Cash Flows

(in thousands)

(Unaudited)

 

  

Three Months Ended March 31,

 
  

2021

  

2020

 
  

Successor

  

Predecessor

 

CASH FLOWS FROM OPERATING ACTIVITIES:

        

Net income (loss)

 $4,744  $(80,831

)

Adjustments to reconcile net income (loss) to net cash provided by operations:

        

Exploration and abandonment expense

  49   3 

Depletion, depreciation and amortization expense

  12,963   3,356 

Accretion expense

  35   34 

Stock-based compensation expense

  966   - 

Amortization of debt issuance costs

  29   - 

Loss on terminated acquisition

  -   76,500 

Deferred income taxes

  1,115   - 

Changes in operating assets and liabilities:

        

Accounts receivable

  (9,193

)

  1,019 

Inventory and other current assets

  (12

)

  (834

)

Accounts payable and accrued liabilities

  677   6,781 

Net cash provided by operating activities

  11,373   6,028 

CASH FLOWS FROM INVESTING ACTIVITIES:

        

Additions to oil and natural gas properties

  (44,875

)

  (47,658

)

Changes in working capital associated with oil and natural gas property additions

  13,263   8,933 

Acquisitions of oil and natural gas properties

  (309

)

  (3,333

)

Issuance of notes receivable

  -   (3,982

)

Other property additions

  -   (50

)

Extension payment on acquisition

  -   (11,000

)

Net cash used in investing activities

  (31,921

)

  (57,090

)

CASH FLOWS FROM FINANCING ACTIVITIES:

        

Proceeds from exercises of warrants

  5,466   - 
Proceeds from subscription receivable from exercises of warrants  3,596   - 

Proceeds from exercises of stock options

  1,574   - 

Debt issuance costs

  (2

)

  - 

Contributions from partners

  -   54,000 

Net cash provided by financing activities

  10,634   54,000 

Net (decrease) increase in cash and cash equivalents

  (9,914

)

  2,938 

Cash and cash equivalents, beginning of period

  19,552   22,711 

Cash and cash equivalents, end of period

 $9,638  $25,649 
         

Supplemental disclosure of non-cash transactions:

        

Interest paid

 $4  $- 

Income taxes paid

 $-  $- 

Additions to asset retirement obligations

 $153  $97 

 

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

 

10

 

 

HIGHPEAK ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

(Unaudited)

 

 

 

 

NOTE 1. Organization and Nature of Operations

 

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

 

HighPeak Energy’s common stock and warrants are listed and traded on the Nasdaq Global Market (the "Nasdaq") under the ticker symbols “HPK” and “HPKEW,” respectively. HighPeak Energy’s Contingent Value Rights (“CVRs”) are currently traded on the Over-The-Counter market, although the Company has applied for listing on the Nasdaq. The Company is an independent oil and natural gas exploration and production company that explores for, develops and produces oil, NGL and natural gas in the Permian Basin in West Texas, more specifically, the Midland Basin. Our acreage is composed of two core areas with the northern block named Flat Top and the southern block named Signal Peak.

 

 

 

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

 

Presentation. In the opinion of management, the unaudited interim condensed consolidated and combined financial statements of the Company as of March 31, 2021 and December 31, 2020 and for the three months ended March 31, 2021 (Successor), and for the three months ended March 31, 2020 (Predecessor) include all adjustments and accruals, consisting only of normal, recurring adjustments and accruals necessary for a fair presentation of the results for the interim periods in conformity with generally accepted accounting principles in the United States ("GAAP"). The operating results for the three months ended March 31, 2021 are not indicative of results for a full year.

 

Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted in accordance with the rules and regulations of the United States Securities and Exchange Commission (the "SEC"). These unaudited interim condensed consolidated and combined financial statements should be read together with the consolidated and combined financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2020.

 

Principles of consolidation. The condensed consolidated and combined financial statements include the accounts of the Company and its wholly owned subsidiaries since August 22, 2020, and its Predecessors and their wholly owned subsidiaries since their acquisition or formation for all periods prior to August 21, 2020. All material intercompany balances and transactions have been eliminated. Certain reclassifications have been made to prior period amounts to conform to the current period’s presentation.

 

Use of estimates in the preparation of financial statements. Preparation of the Company's unaudited interim condensed consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion of oil and natural gas properties and evaluations for impairment of proved and unproved oil and natural gas properties, in part, is determined using estimates of proved, probable and possible oil, NGL and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved, probable and possible reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves, commodity price outlooks and future undiscounted and discounted net cash flows. Other items subject to such estimates and assumptions include, but are not limited to, the carrying value of oil and natural gas properties, asset retirement obligations, equity-based compensation and estimates of income taxes. Actual results could differ from the estimates and assumptions utilized.

 

Cash and cash equivalents. The Company’s cash and cash equivalents include depository accounts held by banks with original issuance maturities of 90 days or less.  The Company’s cash and cash equivalents are generally held in financial institutions in amounts that may exceed the insurance limits of the Federal Deposit Insurance Corporation.  However, management believes that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected.

 

11

 

Accounts receivable. The Company’s accounts receivables are primarily comprised of oil, NGL and natural gas sales receivables, a current U.S. federal income tax receivable, joint interest receivables and other receivables for which the Company does not require collateral security. The Company’s share of oil, NGL and natural gas production is sold to various purchasers who must be prequalified under the Company’s credit risk policies and procedures. The Company records allowances for doubtful accounts based on the age of accounts receivables and the financial condition of its purchasers. The Company’s credit risk related to collecting accounts receivables is mitigated by using credit and other financial criteria to evaluate the credit standing of the entity obligated to make payment on the accounts receivable, and where appropriate, the Company obtains assurances of payment, such as a guarantee by the parent company of the counterparty or other credit support.

 

As of March 31, 2021 and December 31, 2020, the Company’s accounts receivables primarily consist of amounts due from the sale of crude oil, NGL and natural gas of $13.4 million and $4.2 million, respectively, and are based on estimates of sales volumes and realized prices the Company anticipates it will receive, a current U.S. federal income tax receivable of $3.2 million and $3.2 million, respectively, and joint interest receivables of $311,000 and $345,000, respectively. The Company routinely reviews outstanding balances and establishes allowances for bad debts equal to the estimable portions of accounts receivable for which failure to collect is considered probable. As of March 31, 2021 and December 31, 2020, the Company had no allowance for doubtful accounts.

 

Subscription receivable. In accordance with the Financial Accounting Standards Board ("FASB") Accounting Standards Codification (“ASC”) 505-10-45-2, “Receivables for Issuance of Equity, the Company recorded a subscription receivable as of December 31, 2020 related to the exercise of warrants prior to December 31, 2020 as the cash was collected before the financial statements were issued or available to be issued.  Prior to December 31, 2020, 312,711 warrants were exercised for cash proceeds of $3.6 million.  Due to the timing of the exercises, the shares underlying the warrants were issued in December 2020 and the proceeds were received subsequent to December 31, 2020.  The outstanding proceeds were recorded as a subscription receivable in the accompanying balance sheets as of December 31, 2020. There is no subscription receivable as of March 31, 2021 as all cash related to exercises of warrants was received prior to the balance sheet date.

 

Inventory. Inventory is comprised primarily of oil and natural gas drilling or repair items such as tubing, casing, proppant used to fracture-stimulate oil and natural gas wells, water, chemicals, operating supplies and ordinary maintenance materials and parts. The materials and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is carried at the lower of cost or net realizable value, on a weighted average cost basis. Valuation allowances for materials and supplies inventories are recorded as reductions to the carrying values of the materials and supplies inventories in the Company’s condensed consolidated balance sheet and as charges to other expense in the condensed consolidated statements of operations. The Company’s materials and supplies inventory as of March 31, 2021 and December 31, 2020 is $109,000 and $120,000, respectively, and the Company has not recognized any valuation allowance to date.

 

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

 

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

 

Due to the capital-intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather the Company’s ongoing efforts and expenditures related to accurately predict the hydrocarbon recoverability based on well information, gaining access to other companies’ production data in the area, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, the Company’s assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found sufficient proved reserves to sanction the project or is noncommercial and is charged to exploration and abandonment expense. See Note 5 for additional information.

 

The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves for leasehold costs and proved reserves for drilling, completion and other oil and natural gas property costs. Costs of unproved leasehold costs are excluded from depletion until proved reserves are established or, if unsuccessful, impairment is determined.

 

Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion, depreciation and amortization, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recorded until an entire amortization base is sold. However, gain or loss is recorded from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base.

 

12

 

The Company performs assessments of its long-lived assets to be held and used, including proved oil and natural gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows is less than the carrying amount of the assets. In these circumstances, the Company recognizes an impairment charge for the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets.

 

Unproved oil and natural gas properties are periodically assessed for impairment on a project-by-project basis. These impairment assessments are affected by the results of exploration activities, commodity price outlooks, planned future sales or expirations of all or a portion of such projects. If the estimated future net cash flows attributable to such projects are not expected to be sufficient to fully recover the costs invested in each project, the Company will recognize an impairment charge at that time.

 

Other property and equipment, net. Other property and equipment is recorded at cost. The carrying values of other property and equipment, net of accumulated depreciation of $285,000 and $237,000 as of March 31, 2021 and December 31, 2020, respectively, are as follows (in thousands):

 

  

March 31,

2021

  

December 31,

2020

 

Land

 $725  $725 

Information technology

  250   292 

Transportation equipment

  39   41 

Leasehold improvements

  20   24 

Field equipment

  10   10 

Total other property and equipment, net

 $1,044  $1,092 

 

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

 

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

 

Debt issuance costs. The Company has paid a total of $407,000 in debt issuance costs, $2,000 of which was incurred during the three months ended March 31, 2021, related to its new revolving credit facility. Amortization based on the straight-line method over the term of the revolving credit facility which approximates the interest rate method was $29,000 and zero during the three months ended March 31, 2021 and 2020, respectively. As of March 31, 2021 and December 31, 2020, the net debt issuance costs are included in noncurrent assets on the accompanying consolidated balance sheet due to the fact that the revolving credit facility was undrawn at the time. In the future, these net costs will be included with long-term debt, if any, in accordance with GAAP. See Note 6 for additional information regarding the Company’s new revolving credit facility.

 

Leases. The Company enters into leases for drilling rigs, storage tanks, equipment and buildings and recognizes lease expense on a straight-line basis over the lease term. Lease right-of-use assets and liabilities are initially recorded on the lease commencement date based on the present value of lease payments over the lease term. As most of the Company’s lease contracts do not provide an implicit discount rate, the Company uses its incremental borrowing rate, which is determined based on information available at the commencement date of a lease. Leases may include renewal, purchase or termination options that can extend or shorten the term of a lease. The exercise of those options is at the Company’s sole discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease term is required. Leases with an initial term of 12 months or less are not recorded as lease right-of-use assets and liability. See Note 9 for additional information.

 

Accounts payable and accrued liabilities. Accounts payable and accrued liabilities as of March 31, 2021 and December 31, 2020 totaled approximately $34.8 million and $22.4 million, respectively, including trade accounts payable, revenues payable and accruals for capital expenditures, operating and general and administrative expenses, operating leases and other miscellaneous items.

 

Asset retirement obligations. The Company records a liability for the fair value of an asset retirement obligation in the period in which the associated asset is acquired or placed into service, if a reasonable estimate of fair value can be made. Asset retirement obligations are generally capitalized as part of the carrying value of the long-lived asset to which it relates. Conditional asset retirement obligations meet the definition of liabilities and are recorded when incurred and when fair value can be reasonably estimated. See Note 7 for additional information.

 

13

 

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

 

The Company enters into contracts with purchasers to sell its oil and natural gas production. Revenue on these contracts is recognized in accordance with the five-step revenue recognition model prescribed in ASC 606. Specifically, revenue is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under the oil and natural gas marketing contracts is typically received from the purchaser one to two months after production. At March 31, 2021 and December 31, 2020, the Company had receivables related to contracts with purchasers of approximately $13.4 million and $4.2 million, respectively. 

 

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

 

Natural Gas Contracts. The majority of the Company’s natural gas is sold at the lease location, which is generally when control of the natural gas has been transferred to the purchaser. The natural gas is sold under (i) percentage of proceeds processing contracts or (ii) a hybrid of percentage of proceeds and fee-based contracts. Under the majority of the Company’s contracts, the purchaser gathers the natural gas in the field where it is produced and transports it to natural gas processing plants where NGL products are extracted. The NGL products and remaining residue natural gas are then sold by the purchaser. Under percentage of proceeds and hybrid percentage of proceeds and fee-based contracts, the Company receives a percentage of the value for the extracted liquids and the residue natural gas. Since control of the natural gas transfers upstream of the transportation and processing activities, revenue is recognized as the net amount received from the purchaser.

 

The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption in accordance with ASC 606. The exemption, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

 

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

 

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

 

The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. If all or a portion of the unrecognized tax benefit is sustained upon examination by the taxing authorities, the tax benefit will be recognized as a reduction to the Company’s deferred tax liability and will affect the Company’s effective tax rate in the period it is recognized. See Note 12 for addition information.

 

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

 

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

 

14

 

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

 

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

 

Stock-based compensation. Stock-based compensation expense for stock options (“Equity Awards”) is measured at the grant date or modification date, as applicable, using the fair value of the award, and is recorded, net of forfeitures, on a straight-line basis over the requisite service period of the respective award. The fair value of Equity Awards is determined on the grant date or modification date, as applicable, using a Black-Scholes option valuation model with the following inputs; (i) the grant date’s closing stock price, (ii) the exercise price of the stock options, (iii) the expected term of the stock option, (iv) the estimated risk-free adjusted interest rate for the duration of the option’s expected term, (v) the expected annual dividend yield on the underlying stock and (vi) the expected volatility over the option’s expected term.

 

Stock-based compensation for HighPeak Energy common stock issued to directors with no restrictions thereon, is measured at the grant date using the fair value of the award and is recorded as stock-based compensation in the accompanying financial statements immediately. If restricted stock is awarded to employees or directors in the future, as the case may be, stock-based compensation will be recognized on a straight-line basis over the requisite service period of the respective award.

 

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

 

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

 

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

 

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

 

15

 

 

NOTE 3. Acquisitions

 

During the three months ended March 31, 2021 and 2020, the Company spent a total of $309,000 and $3.3 million, respectively, to acquire primarily undeveloped acreage, and in the case of the 2020 period, three vertical producing properties and two salt-water disposal wells in and around the Company’s existing properties for future exploration activities in the Midland Basin.

 

Grenadier Acquisition. In June 2019, HighPeak Energy Assets II, LLC (“HighPeak Assets II”) signed a purchase and sale agreement with Grenadier Energy Partners II, LLC (“Grenadier”) to acquire substantially all the oil and natural gas assets of Grenadier, effective June 1, 2019, subject to certain customary closing adjustments for a total purchase price of $615.0 million. Since HighPeak Assets II was contributed to the Predecessor in the HPK LP business combination, this purchase and sale agreement became part of the Predecessor effective October 1, 2019. A nonrefundable deposit of $61.5 million was paid to Grenadier in 2019 in addition to a $15.0 million nonrefundable extension payment in 2020 to extend the potential closing to May 2020. The Grenadier Acquisition was terminated in April 2020 and was not consummated and therefore a charge to expense of $76.5 million was recognized during the three months ended March 31, 2020.

 

 

 

NOTE 4. Fair Value Measurements

 

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

 

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

 

 

Level 1 – quoted prices for identical assets or liabilities in active markets.

 

Level 2 – quoted prices for similar assets or liabilities in active markets; quoted prices for identical assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability (e.g., interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means.

 

Level 3 – unobservable inputs for the asset or liability, typically reflecting management’s estimate of assumptions that market participants would use in pricing the asset or liability. The fair values are therefore, determined using model-based techniques, including discounted cash flow models.

 

Assets and liabilities measured at fair value on a recurring basis. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level of input that is significant to the measurement in its entirety.

 

The Company did not have any assets or liabilities that are measured at fair value on a recurring basis as of March 31, 2021 or December 31, 2020.

 

Assets and liabilities measured at fair value on a nonrecurring basis. Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances. Specifically, (i) stock-based compensation is measured at fair value on the date of grant based on Level 2 inputs based upon market data, (ii) the oil and natural gas properties of HighPeak Assets II that were contributed to the Predecessor discussed further and in more detail in Note 10 were measured at current estimated fair value using Level 3 inputs based upon market conditions in the area, and (iii) the estimates and fair value measurements used for the evaluation of proved property for potential impairment using Level 3 inputs based upon market conditions in the area. The Company assesses the recoverability of the carrying amount of certain assets and liabilities whenever events or changes in circumstances indicate the carrying amount of an asset or liability may not be recoverable. These assets and liabilities can include inventories, proved and unproved oil and natural gas properties and other long-lived assets that are written down to fair value when they are impaired or held for sale. The Company did not record any impairments to proved or unproved oil and natural gas properties for the periods presented in the accompanying condensed consolidated and combined financial statements.

 

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

 

16

 

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

 

Proved Properties. The Company performs assessments of its proved oil and natural gas properties accounted for under the successful efforts method of accounting whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows is less than the carrying amount of the assets. In these circumstances, the Company recognizes an impairment charge for the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets.

 

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

 

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

 

 

 

NOTE 5. Exploratory Well Costs

 

The Company capitalizes exploratory well and project costs until a determination is made that the well or project has either found proved reserves, is impaired or is sold. The Company's capitalized exploratory well and project costs are included in proved properties in the condensed consolidated balance sheets. If the exploratory well or project is determined to be impaired, the impaired costs are charged to exploration and abandonments expense.

 

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

 

  

Three Months Ended March 31,

 
  

2021

  

2020

 
  

Successor

  

Predecessor

 

Beginning capitalized exploratory well costs

 $32,592  $11,427 

Additions to exploratory well costs

  42,098   46,865 

Reclassification to proved properties

  (67,445

)

  (17,315

)

Exploratory well costs charged to exploration and abandonment expense

  -   - 

Ending capitalized exploratory well costs

 $7,245  $40,977 

 

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

 

 

 

Note 6. Long-Term Debt

 

Revolving Credit Facility. In December 2020, the Company entered into a revolving credit facility with Fifth Third Bank, National Association (“Fifth Third”) as the administrative agent and sole lender (“Revolving Credit Facility”) that matures on June 17, 2024. The Revolving Credit Facility has an initial borrowing base of $40 million. The Company elected to reduce the aggregate elected commitments under the Revolving Credit Facility to $20 million. The borrowing capacity under the Revolving Credit Facility is equal to the lowest of (i) the borrowing base (which currently stands at $40.0 million), (ii) the aggregate elected commitments (which currently stand at $20.0 million) and (iii) $500.0 million. As of March 31, 2021 and December 31, 2020, the Company had no outstanding borrowings under the Revolving Credit Facility. Borrowings under the Revolving Credit Facility bear interest, at the option of the Company, based on (a) a rate per annum equal to the higher of (i) the prime rate announced from time to time by Fifth Third, (ii) the weighted average of the rates on overnight federal funds transactions with members of the Federal Reserve System during the last preceding business day plus 0.5 percent or (iii) the Adjusted LIBOR Rate, plus a margin (the “Applicable Margin”), which is currently 3.25 percent and is also determined by the Borrowing Base Utilization Percentage as defined in the Revolving Credit Facility. Letters of credit outstanding under the Revolving Credit Facility are subject to a per annum fee, representing the Applicable Margin plus 0.125 percent. The Company also pays commitment fees on undrawn amounts under the Revolving Credit Facility equal to 0.50 percent. Borrowings under the Revolving Credit Facility are secured by a first lien security interest on substantially all assets of the Company and its restricted subsidiaries, including mortgages on the Company’s and its restricted subsidiaries’ oil and natural gas properties.  The Revolving Credit Facility is scheduled to have the borrowing base redetermined semiannually in April and October. Additionally, the Company and Fifth Third each have the option for a wild card evaluation between redeterminations.  In March 2021, the Company’s borrowing base and bank commitments under the Revolving Credit Facility were increased to $50 million, subject to finalization of customary documentation.

 

17

 

The Revolving Credit Facility requires the maintenance of a ratio of total debt to EBITDAX, subject to certain adjustments, not to exceed 3.00 to 1.00 as of the last day of any fiscal quarter (commencing with the fiscal quarter ending June 30, 2021 since the Company has yet to borrow under the Revolving Credit Facility) and a current ratio, subject to certain adjustments of at least 1.00 to 1.00 as of the last day of any fiscal quarter.

 

The Company has limited equity cure rights for a breach of the above-listed financial covenants. Additionally, the Revolving Credit Facility contains additional restrictive covenants that limit the ability of the Company and its restricted subsidiaries to, among other things, incur additional indebtedness, incur additional liens, make investments and loans, enter into mergers and acquisitions, make or declare dividends and other payments, enter into certain hedging transactions, sell assets and engage in transactions with affiliates. The Revolving Credit Facility contains customary mandatory prepayments, including a monthly mandatory prepayment if the Consolidated Cash Balance (as defined in the Revolving Credit Agreement) is in excess of $20.0 million. In addition, the Revolving Credit Agreement is subject to customary events of default, including a change in control. If an event of default occurs and is continuing, the administrative agent or the majority of the lenders may accelerate any amounts outstanding and terminate lender commitments.

 

 

 

Note 7. Asset Retirement Obligations

 

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

 

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

 

  

Three Months Ended March 31,

 
  

2021

  

2020

 
  

Successor

  

Predecessor

 

Beginning asset retirement obligations

 $2,293  $2,212 

Liabilities incurred from new wells

  163   97 

Revision of estimates (a)

  (10

)

  - 

Accretion of discount

  35   34 

Ending asset retirement obligations

 $2,481  $2,343 

 

(a) 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.

 

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

 

 

 

NOTE 8. Incentive Plans

 

401(k) Plan. The HighPeak Energy Employees, Inc 401(k) Plan (the “401(k) Plan”) is a defined contribution plan established under Section 401 of the Internal Revenue Code of 1986, as amended (the "Code"). As of October 1, 2020, all regular full-time and part-time employees of the Company are eligible to participate in the 401(k) Plan after three continuous months of employment with the Company. Participants may contribute up to 80 percent of their annual base salary into the 401(k) Plan. Matching contributions are made to the 401(k) Plan in cash by the Company in amounts equal to 100 percent of a participant’s contributions to the 401(k) Plan up to four percent of the participant’s annual base salary (the “Matching Contribution”). Each participant’s account is credited with the participant’s contributions, Matching Contributions and allocations of the 401(k) Plan’s earnings. Participants are fully vested in their account balances at their eligibility date. During the three months ended March 31, 2021 and 2020, the Company contributed $56,000 and zero to the 401(k) Plan, respectively.

 

Long-Term Incentive Plan. The Company’s 2020 Long-Term Incentive Plan (“LTIP”) provides for the granting of stock awards, stock options, dividend equivalents and substitute awards to directors, officers and employees of the Company. The number of shares available for grant pursuant to awards under the LTIP are as follows:

 

  

March 31,

2021

 

Approved and authorized awards

  11,907,006 

Awards granted under plan

  (9,767,995

)

Awards available for future grant

  2,139,011 

 

18

 

Stock Options. Stock options were granted to employees on August 24, 2020. Stock-based compensation expense related to the Company’s stock options for the three months ended March 31, 2021 and 2020 was $966,000 and zero, respectively, and as of March 31, 2021 and December 31, 2020 there was $2.9 million and $3.8 million, respectively, of unrecognized stock-based compensation expense related to unvested stock-based compensation awards. The unrecognized compensation expense will be recognized on a straight-line basis over the remaining vesting periods of the awards, which is a period of less than two years.

 

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

 

  

Stock

Options

  

Exercise

Price

  

Remaining

Term in

Years

  

Intrinsic

Value (in

thousands)

 

Outstanding at August 22, 2020

  -             

Awards granted

  9,705,495  $10.00         

Outstanding at December 31, 2020

  9,705,495  $10.00   9.7  $57,942 

Exercised

  (154,268

)

 $10.00         

Outstanding at March 31, 2021

  9,551,227  $10.00   9.4  $- 
                 

Vested at December 31, 2020

  7,204,163  $10.00   9.7  $43,009 

Exercisable at December 31, 2020

  7,204,163  $10.00   9.7  $43,009 
                 

Vested at March 31, 2021

  7,049,895  $10.00   9.4  $- 

Exercisable at March 31, 2021

  7,049,895  $10.00   9.4  $- 

 

Stock Issued to Directors. Stock was issued to the outside directors of the Company in November 2020 in the amount of 12,500 shares for each outside director, totaling 62,500 shares. There were no restrictions of these shares. Therefore stock-based compensation expense was recognized immediately upon the issuance of these shares in the amount of $302,000 which was based upon the closing price of the stock on the date the stock issuance was approved by the board of directors of the Company.

 

 

 

NOTE 9. Commitments and Contingencies

 

Leases. The Company adopted ASC Topic 842, “Leases” electing the transition method which permits entities to change the date of initial application to the beginning of the year of adoption and to recognize the effects of applying the new standard as a cumulative-effect adjustment to the opening balance of retained earnings. The Company elected this transition approach, however the cumulative impact of adoption in the opening balance of retained earnings as of January 1, 2020 was zero. Therefore, as of March 31, 2021 and December 31, 2020 the Company had operating right-of-use assets totaling $371,000 and $506,000, respectively, included in other noncurrent assets and operating lease liabilities totaling $374,000 and $508,000, respectively, $322,000 and $430,000, respectively, of which are included in other current liabilities and $52,000 and $78,000, respectively, are included in other noncurrent liabilities on the accompanying condensed consolidated balance sheets. The Company does not currently have any finance right-of-use leases. Maturities of the operating lease obligations are as follows (in thousands):

 

  

March 31,

2021

 

Remainder of 2021

 $328 

2022

  53 

Total lease payments

  381 

Less present value discount

  (7

)

Present value of lease liabilities

 $374 

 

Legal actions. From time to time, the Company may be a party to various proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings and claims will not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company records reserves for contingencies when information available indicates that a loss is probable, and the amount of the loss can be reasonably estimated.

 

19

 

Indemnifications. The Company has agreed to indemnify its directors, officers and certain employees and agents with respect to claims and damages arising from acts or omissions taken in such capacity, as well as with respect to certain litigation.

 

Environmental. Environmental expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Environmental expenditures that extend the life of the related property or mitigate or prevent future environmental contamination are capitalized. Liabilities for expenditures that will not qualify for capitalization are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability is fixed or reliably determinable. Environmental liabilities normally involve estimates that are subject to revision until settlement or remediation occurs.

 

Salt-Water Disposal Commitments. The Company has committed to deliver a total of 5.5 MMBbl of produced water for disposal with two different third-party salt-water disposal companies, including 2.5 MMBbl between September 30, 2020 and September 30, 2021 and 3.0 MMBbl between July 24, 2020 and July 24, 2022. As of March 31, 2021, the Company has delivered approximately 2.1 MMBbl and 1.7 MMBbl, respectively under the two agreements. Both agreements require a payment for any volumes not delivered should the Company not perform under the agreements, indicating a remaining monetary commitment of approximately $760,000 as of March 31, 2021. Given the current production levels coupled with the wells planned to come on production during the remainder of 2021 and in to 2022, the Company expects to meet the volume commitments under these agreements.

 

 

 

NOTE 10. Related Party Transactions

 

General and Administrative Expenses. The general partner of HPK LP utilized HighPeak Energy Management, LLC (the “Management Company”) to provide services and assistance to conduct, direct and exercise full control over the activities of HPK LP per its Partnership Agreement. However, the Management Company is funded via payments from the parent companies of HighPeak I and HighPeak II pursuant to their respective Limited Partnership Agreements, as amended. Therefore, HPK LP reimbursed the parent companies of HighPeak I and HighPeak II for actual costs incurred by the Management Company. During the three months ended March 31, 2020, HPK LP paid $1.5 million each to the parent companies of HighPeak I and HighPeak II of which $2.2 million is included in general and administrative expenses in the accompanying results of operations for the three months ended March 31, 2020. Effective upon closing of the HighPeak business combination, the Management Company is no longer being paid by the Company as all costs directly attributable to the Company are paid by the Company going forward.

 

 

 

NOTE 11. Major Customers

 

Lion Oil Trading and Transportation, LLC (“Lion”) purchased approximately 96% of the Company’s crude oil, NGL and natural gas during the three months ended March 31, 2021. Enlink Crude Purchasing, LLC purchased approximately 88% of the Company’s crude oil, NGL and natural gas during the three months ended March 31, 2020. Based on the current demand for oil and natural gas and the availability of other purchasers, management believes the loss of these major purchasers would not have a material adverse effect on our financial condition and results of operations because crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

 

 

 

NOTE 12. Income Taxes

 

On March 27, 2020, the Coronavirus Aid, Relief and Economic Security Act ("CARES Act") was signed into law. The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer social security payments, net operating loss carryback periods, alternative minimum tax credit refunds, modifications to the net interest deduction limitations and technical corrections to tax depreciation methods for qualified improvement property. The Company continues to examine how the CARES Act may impact its business, results of operations, financial condition and liquidity.

 

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

 

  

Three

Months Ended

March 31,

2021

 

Current tax expense

 $- 

Deferred tax expense

  1,115 

Income tax expense

 $1,115 

 

20

 

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

 

  

Three

Months Ended

March 31,

2021

 

Income tax expense at U.S. federal statutory rate

 $1,230 

Limited tax benefit due to stock-based compensation

  (109

)

Other

  (6

)

Income tax expense

 $1,115 

Effective income tax rate

 

19.0

%

 

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities were as follows as of March 31, 2021 and December 31, 2020 (in thousands):

 

  

March 31,

2021

  

December 31,

2020

 

Deferred tax assets:

        

Net operating loss carryforwards

 $15,300  $9,725 

Stock-based compensation

  3,234   3,124 

Other

  31   31 

Less: Valuation allowance

  -   - 

Net deferred tax assets

  18,565   12,880 

Deferred tax liabilities:

        

Oil and natural gas properties, principally due to differences in basis and depreciation and the deduction of intangible drilling costs for tax purposes

  (58,578

)

  (51,778

)

Net deferred tax liabilities

 $(40,013

)

 $(38,898

)

 

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

 

As required by ASC Topic 740, “Income Taxes,” (“ASC 740”) the Company uses reasonable judgments and makes estimates and assumptions related to evaluating the probability of uncertain tax positions. The Company bases its estimates and assumptions on the potential liability related to an assessment of whether the income tax position will “more likely than not” be sustained in an income tax audit. Based on that analysis, the Company believes the Company has not taken any material uncertain tax positions, and therefore has not recorded an income tax liability related to uncertain tax positions. However, if actual results materially differ, the Company’s effective income tax rate and cash flows could be affected in the period of discovery or resolution. The Company also reviews the estimates and assumptions used in evaluating the probability of realizing the future benefits of the Company’s deferred tax assets and records a valuation allowance when the Company believes that a portion or all the deferred tax assets may not be realized. If the Company is unable to realize the expected future benefits of its deferred tax assets, the Company is required to provide a valuation allowance. The Company uses its history and experience, overall profitability, future management plans, tax planning strategies, and current economic information to evaluate the amount of valuation allowance to record. As of March 31, 2021 and December 31, 2020, the Company has not recorded a valuation allowance for deferred tax assets arising from its operations because the Company believes they meet the “more likely than not” criteria as defined by the recognition and measurement provisions of ASC 740. However, the Company may not realize the $18.6 million and $12.9 million in deferred tax assets it has as of March 31, 2021 and December 31, 2020, respectively, if the estimates and assumptions used in evaluating the probability of realizing the future benefits of the Company's deferred tax assets change, which would affect the Company’s effective income tax rate and cash flows in the period of discovery or resolution.

 

On December 27, 2020, the Consolidated Appropriations Act was signed into law, an omnibus spending bill to fund the federal government that also includes an array of COVID-related tax relief for individuals and businesses.  The tax-related measures contained in the Consolidated Appropriations Act revise and expand provisions enacted earlier in the year by the Families First Coronavirus Response Act and the CARES Act.  The Consolidated Appropriations Act also extends a number of expiring tax provisions. Additionally, the Act provides for a 100% deduction for certain business meals incurred in calendar years 2021 and 2022, which were deductible at 50% for the year ending December 31, 2020. In addition, on March 11, 2021, the American Rescue Plan Act was signed into law, which includes additional COVID-related tax relief for individuals and businesses. The Company determined that income tax effects related to the passage of the Consolidated Appropriations Act and the American Rescue Plan Act were not material to the financial statements for the three months ended March 31, 2021.

 

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

 

21

 

 

NOTE 13. Earnings Per Share

 

The Company uses the treasury stock method of calculating earnings per share because certain of the Company’s unvested stock-based awards qualify as participating securities. 

 

The Company’s basic earnings per share attributable to common stockholders is computed as (i) net income as reported attributable to common stockholders, (ii) less participating basic earnings (iii) divided by weighted average basic common shares outstanding. The Company’s diluted earnings per share attributable to common stockholders is computed as (i) basic earnings attributable to common stockholders, (ii) plus reallocation of participating earnings (iii) divided by weighted average diluted shares outstanding. The components of basic and diluted earnings per share attributable to common stockholders are as follows (in thousands):

 

  

Successor

 
  

Three

Months Ended

March 31,

2020

 

Net income attributable to common stockholders

 $4,744 

Participating share-based earnings (a)

  - 

Basic and diluted net income attributable to common stockholders

 $4,744 
     

Basic weighted average shares outstanding

  92,592 

Dilution attributable to stock-based compensation awards

  2,890 

Diluted weighted average shares outstanding

  95,482 

 

 

(a)

Participating earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Unexercised stock option awards do not participate in undistributed net losses as they are not contractually obligated to do so.

 

 

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

 

 

 

NOTE 14. Stockholders Equity (Successor)

 

At March 31, 2021 and December 31, 2020, the Company had 92,675,898 and 91,967,565 shares of common stock outstanding, respectively, 9,500,174 and 10,225,472 warrants outstanding, respectively, with an exercise price of $11.50 per share that expire on August 21, 2025 and 10,209,300 and 10,209,300 CVRs outstanding, respectively that give the holders a right to receive up to 2.125 shares of HighPeak Energy common stock per CVR to satisfy the Preferred Returns (with an equivalent number of shares of Company common stock held by HighPeak I and HighPeak II being collectively forfeited in connection therewith).  As such, HighPeak I and HighPeak II have placed a total of 21,694,763 shares of common stock of the Company in escrow. 

 

 

 

NOTE 15. Partners Capital (Predecessor)

 

Allocation of partners net profits and losses. Net income or loss and net gain or loss on investments of the Predecessor for the period are allocated among its partners in proportion to the relative capital contributions made to the Predecessor. The Predecessor realized a net loss of $80.8 million for the three months ended March 31, 2020.

 

Partners distributions. The proceeds distributable by the Predecessor (which shall include all proceeds attributable to the disposition of investments, net of expenses) is distributable in accordance with their respective Partnership Agreements.

 

22

 

 

NOTE 16. Subsequent Events

 

Commodity Derivative Financial Instruments. In April of 2021, the Company entered into commodity derivative financial instruments with Fifth Third to hedge a portion of its crude oil production. Details of the contracts are as follows:

 

  

2021

  

2022

 
  

Second

Quarter

  

Third

Quarter

  

Fourth

Quarter

  

Total

  

First

Quarter

  

Second

Quarter

  

Total

 

Oil Price Swaps - WTI: (a)

                            

Volume (Bbls)

  152,500   230,000   230,000   612,500   225,000   75,000   300,000 

Price per Bbl

 $61.40  $61.40  $61.40  $61.40  $61.40  $61.40  $61.40 

 

 

(a)

These oil derivative contracts are settled based on the NYMEX – WTI calendar month average futures price.

 

Crude oil marketing contract. In May 2021, the Company entered into a crude oil marketing contract with Lion as the purchaser and DKL Permian Gathering, LLC (“DKL”) as the gatherer and transporter. The contract includes the Company’s current and future crude oil production from its horizontal wells in Flat Top where DKL will construct an oil gathering system and custody transfer meters to all the Company’s central tank batteries. The oil gathering system and custody transfer meters are expected to be operational by October 2021. The contract contains a minimum volume commitment commencing October 2021 based on the gross barrels delivered at the Company’s central tank battery facilities and is 5,000 Bopd for the first year, 7,500 Bopd for the second year and 10,000 Bopd for the remaining eight years of the contract. However, the Company has the ability under the contract to cumulatively bank excess volumes delivered to offset future minimum volume commitments. The Company believes it will meet the minimum volume commitments based on the Company’s current gross production levels and the current Flat Top development plan.

 

Natural gas purchasing replacement contract. In May 2021, the Company entered into a replacement gas purchase contract with WTG Gas Processing, L.P. (“WTG”) as the gatherer, processor and purchaser of the Company’s current and future gross natural gas production in Flat Top. The replacement contract provides the Company with improved natural gas and NGL pricing and requires WTG to expand its current low-pressure gathering system, which eliminates the need for in-field compression in Flat Top to accommodate the Company’s increased natural gas production volumes based on the current plan of development. In exchange for the improved pricing terms and expansion of the gathering system, the Company will provide WTG with certain aid-in-construction payments. The replacement contract does not contain minimum volume commitments.  Once operational, the expanded natural gas gathering system will reduce flaring and the emission of greenhouse gases.

 

23

 

 

 

PART I. FINANCIAL INFORMATION

 

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

The following discussion and analysis is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with our historical consolidated and combined financial statements and related notes. This discussion contains certain forwardlooking statements reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. These forward-looking statements involve risks and uncertainties and actual results and the timing of events may differ materially from those contained in these 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 oil, NGL and natural gas, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties. Please read Cautionary Statement Regarding ForwardLooking Statements. We assume no obligation to update any of these forwardlooking statements, except as required by applicable law.

 

Overview

 

HighPeak Energy, Inc., a Delaware corporation, was formed in October 2019 solely for the purpose of combining the businesses of Pure and HPK LP, referred to herein as the “HighPeak business combination,” which was completed on August 21, 2020. HPK LP was formed in August 2019 for the purpose combining the assets of HighPeak I and HighPeak II into one entity. HighPeak I was formed in June 2014 for the purpose of acquiring, exploring and developing 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 north eastern part of the oil-rich Midland Basin. As of March 31, 2021, the assets consisted of two highly contiguous leasehold positions of approximately 58,452 gross (50,635 net) acres, approximately 37% of which were held by production, with an average working interest of 87%. Our acreage is composed of two core areas with the northern block named Flat Top and the southern block named Signal Peak. Approximately 97% of the operated acreage provides for horizontal wells with lateral lengths of 10,000 feet or greater. For the three months ended March 31, 2021, approximately 95% and 5% of production from the assets were attributable to liquids (both oil and NGL) and natural gas, respectively. As of March 31, 2021, HighPeak Energy was drilling with one (1) rig. We are the operator on approximately 95% of the net acreage across our assets. Further, as of March 31, 2021, there were approximately 124 gross (80.0 net) producing wells, including 28 gross (26.6 net) horizontal wells, with total sales volumes of approximately 7,263 Boe/d in March 2021. In addition, as of March 31, 2021, the Company was in the process of drilling two (2) wells and was in various stages of completing eight (8) wells.

 

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 three months ended March 31, 2020 and the Company for the three months ended March 31, 2021. At the Closing of the HighPeak business combination on August 21, 2020, the Company’s “predecessors” for accounting purposes were HPK LP for the period from October 1, 2019 through August 21, 2020 and HighPeak I from January 1, 2017 through September 30, 2019 (collectively, the “Predecessors”).

 

Outlook

 

HighPeak Energy’s financial position and future prospects, including its revenues, operating results, profitability, liquidity, future growth and the value of its assets, depend primarily on prevailing commodity prices. The oil and natural gas industry is cyclical and commodity prices are highly volatile. For example, during the period from January 1, 2018 through March 31, 2021, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $16.70 to a high of $70.76, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.50 to a high of $4.72. 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. Due to the absence of any debt, the Company has not historically entered into any hedges. With the addition of the Revolving Credit Facility in December 2020, HighPeak Energy entered into hedging arrangements in late-April 2021, prior to borrowing under the Revolving Credit Facility that is anticipated in the second quarter of 2021.

 

24

 

Financial and Operating Performance

 

The Company's financial and operating performance for the three months ended March 31, 2021 and 2020 included the following highlights:

 

Net income was $4.7 million ($0.05 per diluted share) compared with a net loss of the Company’s Predecessor of $80.8 million for three months ended March 31, 2021 and 2020, respectively. The primary components of the $85.6 million increase in net income include:

 

 

a $76.5 million charge to expense during the three months ended March 31, 2020 related to an acquisition that was terminated in April 2020 primarily attributable to the downturn in oil prices related to COVID-19 whereby the Company had paid a $61.5 million nonrefundable deposit during 2019 plus a $15 million extension payment paid in 2020 that was also nonrefundable;

 

 

a $21.1 million increase in oil, NGL and natural gas revenues due to a 270% increase in daily sales volumes resulting from the Company’s successful horizontal drilling program in the Permian Basin, in addition to a 52% increase in average realized commodity prices per Boe; and

 

 

a $1.1 million decrease in general and administrative expenses primarily as a result of more general and administrative costs being allocated to drilling and completion operations and construction projects and producing properties due to increased activity and well count in the 2021 period compared with 2020, no business combination charges in 2021 compared with 2020, lower salaries and benefits due to the reduction in workforce that was initiated in the early stages of the COVID-19 pandemic in 2020 and lower exploration general and administrative expenses that are classified as exploration and abandonment expense now that they are identifiable and not included as a component of administration fees paid to a management company; and

 

 

a $162,000 decrease in the Company's oil and natural gas production costs due to the completion of the Company’s water disposal system infrastructure that came online in January 2021 coupled with the decreased reliance on generators for power along with other cost reduction efforts implemented by the company in response to the downturn in crude oil prices in 2020 as a result of the COVID-19 pandemic;

 

partially offset by:

 

 

a $9.6 million increase in depletion, depreciation and amortization expense due to a 270% increase in overall sales volumes, plus a 5% increase in the depletion, depreciation and amortization rate from $25.83 to $27.25 per Boe, primarily as a result of costs incurred on the Company’s water disposal infrastructure which do not directly increase proved reserves and recently completed wells which did not meet the SEC guidelines to be included in our proved reserves as of March 31, 2021 ;

 

 

a $1.4 million increase in the production and ad valorem taxes due partially to an increase in production taxes per Boe from $1.67 to $2.53, or 51%, due to higher overall realized prices of 52% and an increase in ad valorem taxes per Boe from $0.70 to $0.97, or 39%, due to a greater proportion of horizontal wells which are valued higher for tax purposes in Texas;

 

 

a $1.1 million increase in the Company’s income tax expense due to the net income experienced during the three months ended March 31, 2021 and the fact that the Predecessor was a pass through entity for income tax purposes and did not recognize any tax expense or benefit on their financial statements;

 

25

 

 

a $966,000 increase in stock-based compensation expense related to stock options that were granted in August 2020 upon the Company’s going public; and

 

 

a $188,000 increase in exploration and abandonment expenses primarily as a result of exploration general and administrative expenses that are being classified as a part of exploration and abandonment expense now that they are identifiable and not merely a component of administration fees paid to a management company plus $49,000 in abandoned leasehold costs related to various undeveloped leasehold costs that the Company opted not to renew.

 

During the three months ended March 31, 2021, average daily sales volumes totaled 5,290 Boe/d, compared with 1,428 Boe/d during the same period in 2020, an increase of 270% over the same period in 2020, due to the Company's successful horizontal drilling program in the Permian Basin.

 

Weighted average realized oil prices per Bbl increased during the three months ended March 31, 2021 to $58.36, compared with $40.76 for the same period in 2020. Weighted average NGL prices per Bbl increased during the three months ended March 31, 2021 to $27.82, compared with $12.29 for the same period in 2020. Weighted average natural gas prices per Mcf increased to $2.23 during the three months ended March 31, 2021, compared with $0.07 during the same period in 2020.

 

Cash provided by operating activities totaled $11.4 million for the three months ended March 31, 2021, compared with $6.0 million for the three months ended March 31, 2020.

 

Recent Events

 

Revolving Credit Facility. The Company entered into its Revolving Credit Facility in December 2020, but as of March 31, 2021, had not drawn on the Revolving Credit Facility. The Company anticipates that it will begin to draw on the Revolving Credit Facility in the second quarter of 2021 which currently has a $40.0 million borrowing base, but only a $20.0 million commitment at the Company’s election. In March 2021, the Company’s borrowing base was increased to $50.0 million, and the Company received an increased commitment to $50.0 million, subject to finalization of customary documentation.

 

Exercises of Warrants and Options. During the three months ended March 31, 2021, the Company received cash of $9.1 million related to the exercise of 788,009 of its $11.50 warrants and $1.6 million cash related to the exercise of 154,268 of stock options by employees of the Company.

 

Crude oil marketing contract. In May 2021, the Company entered into a crude oil marketing contract with Lion Oil Trading and Transportation, LLC (“Lion”) as the purchaser and DKL Permian Gathering, LLC (“DKL”) as the gatherer and transporter. The contract includes the Company’s current and future crude oil production from its horizontal wells in Flat Top where DKL will construct an oil gathering system and custody transfer meters to all the Company’s central tank batteries. The oil gathering system and custody transfer meters are expected to be operational by October 2021. This system will reduce the Company’s cost to transport its crude oil to market and significantly reduce the trucking traffic in and around our development at Flat Top. The contract contains a minimum volume commitment commencing October 2021 based on the gross barrels delivered at the Company’s central tank battery facilities and is 5,000 Bopd for the first year, 7,500 Bopd for the second year and 10,000 Bopd for the remaining eight years of the contract. However, the Company has the ability under the contract to cumulatively bank excess volumes delivered to offset future minimum volume commitments. The Company believes it will meet this minimum volume commitments based on the Company’s current gross production levels and the current Flat Top development plan.

 

Natural gas purchasing replacement contract. In May 2021, the Company entered into a replacement gas purchase contract with WTG Gas Processing, L.P. (“WTG”) as the gatherer, processor and purchaser of the Company’s current and future gross natural gas production in Flat Top. The replacement contract provides the Company with improved natural gas and NGL pricing and requires WTG to expand its current low-pressure gathering system, which eliminates the need for in-field compression in Flat Top to accommodate the Company’s increased natural gas production volumes based on the current plan of development. In exchange for the improved pricing terms and expansion of the gathering system, the Company will provide WTG with certain aid-in-construction payments. The replacement contract does not contain minimum volume commitments. Once operational, the expanded natural gas gathering system will reduce flaring and the emission of greenhouse gases. 

 

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

 

Derivative Financial Instruments

 

Derivative financial instrument exposure. At March 31, 2021, the Company was not a party to any derivative financial instruments.

 

New commodity derivative contracts. Subsequent to March 31, 2021, the Company entered into derivative contracts to hedge a portion of estimated future production. Refer to Note 16 of the Notes to Consolidated and Combined Financial Statements included in “Item 1. Condensed Consolidated and Combined Financial Statements (Unaudited)” for additional information regarding these commodity derivative contracts.

 

26

 

Operations and Drilling Highlights

 

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

 

  

Three Months

Ended March 31,

2021

 

Oil (Bbls)

  4,735 

NGL (Bbls)

  294 

Natural Gas (Mcf)

  1,568 

Total (Boe)

  5,290 

 

The Company's liquids production was 95 percent of total production on a Boe basis for the three months ended March 31, 2021.

 

Costs incurred are as follows (in thousands):

 

  

Three Months

Ended March 31,

2021

 

Unproved property acquisition costs

 $309 

Proved acquisition costs

  - 

Total acquisitions

  309 

Development costs

  2,777 

Exploration costs

  42,098 

Total finding and development costs

  45,184 

Asset retirement obligations

  154 

Total costs incurred

 $45,338 

 

The following table sets forth the total number of horizontal wells drilled and completed during the three months ended March 31, 2021:

 

  

Three Months Ended March 31, 2021

 
  

Drilled

  

Completed

 
  

Gross

  

Net

  

Gross

  

Net

 

Flat Top area

  4   4   6   5.2 

Signal Peak area

  2   1.4   -   - 

Total

  6   5.4   6   5.2 

 

The Company currently plans to operate one (1) drilling rig and an average of one (1) frac fleet in the Permian Basin during the remainder of 2021. However, the scope, duration and magnitude of the direct and indirect effects of the COVID-19 pandemic are continuing to evolve and in ways that are difficult or impossible to anticipate. Given the dynamic nature of this situation, the Company is maintaining flexibility in its capital plan and will continue to evaluate drilling and completion activity on an economic basis, with future activity levels assessed monthly.

 

During the three months ended March 31, 2021, the Company successfully completed and placed on production six horizontal wells in the Flat Top area, five (5) of which are in the Wolfcamp A and one (1) of which is in the Lower Spraberry formations. The Company had eight (8) wells in various stages of completion as of March 31, 2021, five (5) of which are in the Wolfcamp A and one (1) of which is in the Lower Spraberry formations located in the Flat Top area and one is in the Wolfcamp D and one is in the Wolfcamp C formations in the Signal Peak area. Subsequent to the end of the quarter, we placed six of these wells on production and many have begun to produce oil. As of March 31, 2021, the Company was in the process of drilling two (2) wells in the Flat Top area, one (1) in the Wolfcamp A and one (1) in the Lower Spraberry formations.

 

27

 

Results of Operations

 

Factors Affecting the Comparability of the Predecessor Historical Financial Results

 

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

 

 

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

 

 

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

 

 

During the three months ended March 31, 2020, HPK LP recognized a charge to expense of $76.5 million related to the termination of the Grenadier Acquisition.

 

Three Months Ended March 31, 2021 Compared with Three Months Ended March 31, 2020

 

Oil, NGL and natural gas revenues.

 

Average daily sales volumes are as follows:

 

  

Three Months Ended March 31,

     
  

2021

  

2020

  

% Change

 
  

Successor

  

Predecessor

     

Oil (Bbls)

  4,735   1,220   288%

NGL (Bbls)

  294   134   119%

Natural Gas (Mcf)

  1,568   445   252%

Total (Boe)

  5,290   1,428   270%

 

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

 

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

 

  

Three Months Ended March 31,

     
  

2021

  

2020

  

% Change

 
  

Successor

  

Predecessor

     

Oil per Bbl

 $58.36  $40.76   43%

NGL per Bbl

 $27.82  $12.29   126%

Natural Gas per Mcf

 $2.23  $0.07   3,086%

Total per Boe

 $54.01  $35.58   52%

 

Oil and natural gas production costs.

 

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

 

  

Three Months Ended March 31,

     
  

2021

  

2020

  

% Change

 
  

Successor

  

Predecessor

     

Lease operating expenses

 $2,227  $2,389   (7)%

Lease operating expenses per Boe

 $4.68  $18.39   (75)%

 

28

 

The decrease in lease operating expenses can primarily be attributed to the completion of the Company’s water disposal system infrastructure that came online in January 2021 coupled with the decreased reliance on generators for power and other cost reduction efforts implemented by the company in response to the downturn in crude oil prices in 2020 as a result of the COVID-19 pandemic.

 

Production and ad valorem taxes.

 

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

 

  

Three Months Ended March 31,

     
  

2021

  

2020

  

% Change

 
  

Successor

  

Predecessor

     

Production and ad valorem taxes

 $1,664  $308   440%

 

In general, production taxes and ad valorem taxes are directly related to commodity production volume and price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxes are based upon current year commodity prices.

 

Production and ad valorem taxes per Boe are as follows:

 

  

Three Months Ended March 31,

     
  

2021

  

2020

  

% Change

 
  

Successor

  

Predecessor

     

Production taxes per Boe

 $2.53  $1.67   51%

Ad valorem taxes per Boe

 $0.97  $0.70   39%

 

The increase in production taxes per Boe for the three months ended March 31, 2021, compared with the same period in 2020, was primarily due to the 52% increase in realized prices. The increase in ad valorem taxes per Boe for the three months ended March 31, 2021, compared with the same period in 2020, was primarily due to a large number of wells that have come on production during 2020 which did not incur ad valorem tax in 2020  and for which 2021 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.

 

Depletion, depreciation and amortization expense.

 

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

 

  

Three Months Ended March 31,

     
  

2021

  

2020

  

% Change

 
  

Successor

  

Predecessor

     

DD&A expense

 $12,963  $3,356   286%

DD&A expense per Boe

 $27.22  $25.83   5%

 

The increase in DD&A was primarily due to the increased production associated with our successful horizontal drilling program. Also, the increase in DD&A per Boe was primarily the result of costs incurred on the Company’s water disposal infrastructure which do not directly increase proved reserves and recently completed wells which did not meet the SEC guidelines to be included in our proved reserves as of March 31, 2021 .

 

General and administrative expense.

 

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

 

  

Three Months Ended March 31,

     
  

2021

  

2020

  

% Change

 
  

Successor

  

Predecessor

     

General and administrative expense

 $1,759  $2,861   (39)%

General and administrative expense per Boe

 $3.69  $22.03   (83)%

Stock based compensation expense

 $966  $-   100%

 

29

 

The decrease in general and administrative expense for the three months ended March 31, 2021, compared with the same period in 2020, is primarily a result of more general and administrative costs being allocated to drilling and completion operations and construction projects and producing properties due to increased activity and well count, no business combination charges in 2021, lower salaries and benefits due to the reduction in workforce that was initiated in the early stages of the COVID-19 pandemic in 2020 and lower exploration general and administrative expenses that are being classified as a part of exploration and abandonment expense now that they are identifiable and not included as a component of administration fees paid to a management company.

 

The increase in noncash stock-based compensation expense is due to stock options being granted to officers and employees upon completion of the business combination.

 

Income tax expense.

 

  

Three Months Ended March 31,

     
  

2021

  

2020

  

% Change

 
  

Successor

  

Predecessor

     

Income tax expense

 $1,115  $-   100%

Effective income tax rate

  19.0%  0.0%  100%

 

The change in income tax expense during the three months ended March 31, 2021, compared with the same period in 2020, was due to the fact that the Predecessor was treated as a partnership for U.S. federal income tax purposes and, as such, the partners of the Predecessor reported their share of the Company’s income or loss on their respective income tax returns.  In contrast, HighPeak Energy is a corporation and is subject to U.S. federal income taxes on any income or loss following the business combination on August 21, 2020.  The effective income tax rate differs from the statutory rate primarily due to permanent differences between GAAP income and taxable income. See Note 12 of Notes to Consolidated Financial Statements included in "Item 1. Condensed Consolidated and Combined Financial Statements (Unaudited)" for additional information.

 

Liquidity and Capital Resources

 

Liquidity. In response to the COVID-19 pandemic and commensurate decrease in oil, NGL and natural gas prices, the Company took steps during 2020 to reduce, defer or cancel certain planned capital expenditures, shut-in the majority of its production and reduce its overall cost structure commensurate with its expected level of activities. During July 2020, the Company began putting its wells back on production based on the recovery of oil and natural gas prices. Subsequent to the Closing of the HighPeak business combination, the Company began completing the twelve (12) wells that were drilled but not yet completed when operations were shut down early in 2020. The Company also began running one (1) drilling rig in September 2020. The Company drilled and completed a salt-water disposal well near the center of our current northern acreage operating area and completed phase one of a water disposal infrastructure system to dispose the water that we anticipate producing with the development drilling planned in 2021 and beyond. Also, in late December 2020, the Company entered into a Revolving Credit Facility with an initial borrowing base of $40.0 million; however, the Company elected to reduce the aggregate elected commitments to $20.0 million.  The Revolving Credit Facility remained undrawn at March 31, 2021. Associated with the Revolving Credit Facility, the Company is required to enter into commodity hedging instruments, which it did in April 2021, to protect against price fluctuations on a portion of its proved developed producing reserves commencing prior to drawing on the Revolving Credit Facility. See Note 16 of the Notes to Consolidated and Combined Financial Statements included in “Item 1. Condensed Consolidated and Combined Financial Statements (Unaudited)” for additional information regarding these commodity derivative contracts.

 

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

 

As of March 31, 2021, the Company had no outstanding borrowings and approximately $20.0 million available to borrow under its Revolving Credit Facility. The Company also had unrestricted cash on hand of $9.6 million as of March 31, 2021. In March 2021, the Company’s borrowing base and bank commitments under the Revolving Credit Facility were increased to $50.0 million, subject to finalization of customary documentation.

 

The Company's primary needs for cash are for (i) capital expenditures, (ii) acquisitions of oil and natural gas properties, (iii) payments of contractual obligations, and (iv) working capital obligations. Funding for these cash needs may be provided by any combination of the Company's sources of liquidity. Although the Company expects that its sources of funding will be adequate to fund its 2021 planned capital expenditures and provide adequate liquidity to fund other needs, no assurance can be given that such funding sources will be adequate to meet the Company's future needs.

 

2021 capital budget. The Company has set its capital budget for 2021 at approximately $115 to $125 million for drilling, completion, facilities and equipping oil wells plus $20 to $25 million for field infrastructure buildout and other costs. HighPeak Energy expects to fund its forecasted capital expenditures with cash on its balance sheet, cash generated by operations and through borrowings under its Revolving Credit Facility. The Company's capital expenditures for the three months ended March 31, 2021 were $45.2 million.

 

30

 

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

 

  

Three Months Ended March 31,

     
  

2021

  

2020

  

% Change

 
  

Successor

  

Predecessor

     

Net cash provided by operating activities

 $11,373  $6,028   89%

Net cash used in investing activities

 $(31,921) $(57,090)  (44)%

Net cash provided by financing activities

 $10,634  $54,000   (80)%

 

Operating activities. The increase in net cash flow provided by operating activities for the three months ended March 31, 2021, compared with 2020, was primarily related to higher revenues associated with increased production volumes as a result of our successful horizontal drilling program and increased realized prices. Partially offsetting this increase was a greater accounts receivable balance resulting from the higher oil, NGL and natural gas revenues related to increased sales volumes and realized prices in the current period.

 

Investing activities. The decrease in net cash used in investing activities for the three months ended March 31, 2021, compared with 2020, was primarily due to decreases in additions to oil and natural gas properties as the Company was running two rigs for a portion of the 2020 period compared with only one rig in 2021 and decreases in oil and natural gas acquisition costs. During the prior year period, the Company also funded an extension payment of $11.0 million related to an acquisition in 2020 that was terminated and funded notes receivable to Pure of $4.0 million related to the HighPeak business combination.

 

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

 

 

2021: The Company received $9.1 million from the exercise of 788,009 of the Company’s $11.50 warrants and $1.6 million from the exercise of 154,268 of stock options by employees of the Company.

  

 

 

2020: The Company’s Predecessors received $54.0 million in capital contributions from its partners.

 

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

 

New Accounting Pronouncements

 

Our historical condensed consolidated and combined financial statements and related notes to condensed consolidated and combined financial statements contain information that is pertinent to our management’s discussion and analysis of financial condition and results of operations. Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires that our management make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. However, the accounting principles used by us generally do not change our reported cash flows or liquidity. Interpretation of the existing rules must be done, and judgments made on how the specifics of a given rule apply to us.

 

In management’s opinion, the more significant reporting areas impacted by management’s judgments and estimates are the choice of accounting method for oil and natural gas activities, oil and natural gas reserve estimation, asset retirement obligations, impairment of long-lived assets, valuation of stock-based compensation, valuation of business combinations, accounting and valuation of nonmonetary transactions, litigation and environmental contingencies, valuation of financial derivative instruments, uncertain tax positions and income taxes.

 

Management’s judgments and estimates in all the areas listed above are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known.

 

There have been no material changes in our critical accounting policies and procedures during the three months ended March 31, 2021. See our disclosure of critical accounting policies in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2020, filed with the SEC on March 15, 2021.

 

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

 

31

 

 

ITEM 3.     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

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

 

During the period from January 1, 2018 through March 31, 2021, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $16.70 to a high of $70.76, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.50 to a high of $4.72. 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. A $1.00 per barrel increase (decrease) in the weighted average oil price for the three months ended March 31, 2021 would have increased (decreased) the Company’s revenues by approximately $1.8 million on an annualized basis and a $0.10 per Mcf increase (decrease) in the weighted average natural gas price for the three months ended March 31, 2021 would have increased (decreased) the Company’s revenues by approximately $57,000 on an annualized basis.

 

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

 

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

 

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

 

The average forward prices based on March 31, 2021 market quotes were as follows:

 

  

Remainder of

2021

  

Year Ending

December 31,

2022

 

Average forward NYMEX oil price per Bbl

 $57.95  $54.23 

Average forward NYMEX natural gas price per MMBtu

 $2.76  $2.64 

 

The average forward purchase prices based on May 12, 2021 market quotes were as follows:

 

  

Remainder of

2021

  

Year Ending

December 31,

2022

 

Average forward NYMEX oil price per Bbl

 $65.19  $61.55 

Average forward NYMEX natural gas price per MMBtu

 $3.05  $2.77 

 

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

 

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

 

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

 

32

 

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

 

ITEM 4.     CONTROLS AND PROCEDURES

 

Evaluation of Disclosure Controls and Procedures

 

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

 

Changes in Internal Control over Financial Reporting

 

There have been no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the three months ended March 31, 2021 that have materially affected or are reasonably likely to materially affect the Company’s internal control over financial reporting.

 

33

 

 

PART II. OTHER INFORMATION

 

ITEM 1.     LEGAL PROCEEDINGS

 

The Company is party to various proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings and claims will not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future results of operations.

 

ITEM 1A.     RISK FACTORS

 

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

 

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

 

34

 

 

HIGHPEAK ENERGY, INC.

 

ITEM 6.   EXHIBITS

 

Exhibit

 

Number

Description

  

2.1+

Business Combination Agreement, dated as of May 4, 2020, by and among Pure Acquisition Corp., HighPeak Energy, Inc., Pure Acquisition Merger Sub, Inc., HighPeak Energy, LP, HighPeak Energy II, LP, HighPeak Energy III, LP, HPK Energy, LLC, and, solely for limited purposes specified therein, HighPeak Energy Management, LLC (incorporated by reference to Annex A to the Companys Registration Statement on Form S-4 and Form S-1 (File No. 333-235313) filed with the SEC on August 5, 2020.

  

2.2

First Amendment to Business Combination Agreement, dated as of June 12, 2020, by and among, Pure Acquisition Corp., HighPeak Energy, Inc., Pure Acquisition Merger Sub, Inc., HighPeak Energy, LP, HighPeak Energy II, LP, HighPeak Energy III, LP, HPK Energy, LLC and HighPeak Energy Management, LLC (incorporated by reference to Annex A-I to the Companys Registration Statement on Form S-4 and Form S-1 (File No. 333-235313) filed with the SEC on August 5, 2020).

  

2.3

Second Amendment to Business Combination Agreement, dated as of July 1, 2020, by and among, Pure Acquisition Corp., HighPeak Energy, Inc., Pure Acquisition Merger Sub, Inc., HighPeak Energy, LP, HighPeak Energy II, LP, HighPeak Energy III, LP, HPK Energy, LLC and HighPeak Energy Management, LLC (incorporated by reference to Annex A-II to the Companys Registration Statement on Form S-4 and Form S-1 (File No. 333-235313) filed with the SEC on August 5, 2020).

  

2.4

Third Amendment to Business Combination Agreement, dated as of July 24, 2020, by and among, Pure Acquisition Corp., HighPeak Energy, Inc., Pure Acquisition Merger Sub, Inc., HighPeak Energy, LP, HighPeak Energy II, LP, HighPeak Energy III, LP, HPK Energy, LLC and HighPeak Energy Management, LLC (incorporated by reference to Annex A-III to the Companys Registration Statement on Form S-4 and Form S-1 (File No. 333-235313) filed with the SEC on August 5, 2020).

  

3.1

Amended and Restated Certificate of Incorporation of HighPeak Energy, Inc. (incorporated by reference to Exhibit 3.1 to the Companys Current Report on Form 8-K (File No. 001-39464) filed with the SEC on August 27, 2020).

  

3.2

Amended and Restated Bylaws of HighPeak Energy, Inc. (incorporated by reference to Exhibit 3.1 to the Companys Current Report on Form 8-K (File No. 001-39464) filed with the SEC on November 9, 2020). 

  

4.1

Registration Rights Agreement, dated as of August 21, 2020, by and among HighPeak Energy, Inc., HighPeak Pure Acquisition, LLC, HighPeak Energy, LP, HighPeak Energy II, LP, HighPeak Energy III, LP and certain other security holders named therein (incorporated by reference to Exhibit 4.4 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on August 27, 2020).

  

4.2

Stockholders’ Agreement, dated as of August 21, 2020, by and among HighPeak Energy, Inc., HighPeak Pure Acquisition, LLC, HighPeak Energy, LP, HighPeak Energy II, LP, HighPeak Energy III, LP, Jack Hightower and certain directors of Pure Acquisition Corp. (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on August 27, 2020). 

  

4.3

Amendment and Assignment to Warrant Agreement, dated as of August 21, 2020, by and among Pure Acquisition Corp., Continental Stock Transfer & Trust Company and HighPeak Energy, Inc. (incorporated by reference to Exhibit 4.2 to the Company’s Registration Statement on Form S-4 and Form S-1 (File No. 333-235313) filed with the SEC on August 5, 2020).

  

4.4

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

  

10.1

Contingent Value Rights Agreement, dated as of August 21, 2020, by and among HighPeak Energy, Inc., HighPeak Pure Acquisition, LLC, HighPeak Energy, LP, HighPeak Energy II, LP and Continental Stock Transfer & Trust Company, as rights agent (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on August 27, 2020).

  

10.2

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

 

35

 

10.3

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

  

10.4

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

  

10.5

Form of Indemnification Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 333-235313) filed with the SEC on November 9, 2020).

  

10.6+

Credit Agreement, dated as of December 17, 2020, among HighPeak Energy, Inc., as Borrower, Fifth Third Bank, National Association, as administrative agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on December 18, 2020).

  

16.1

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

  

31.1*

Certification of the Companys Chief Executive Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241)

  

31.2*

Certification of the Companys Chief Financial Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241)

  

32.1**

Certification of the Companys Chief Executive Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350)

  

32.2**

Certification of the Companys Chief Financial Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350)

  
  

101.INS**

XBRL Instance Document

  

101.SCH**

XBRL Taxonomy Extension Schema Document

  

101.CAL**

XBRL Taxonomy Extension Calculation Linkbase Document

  

101.DEF**

XBRL Taxonomy Extension Definition Linkbase Document

  

101.LAB**

XBRL Taxonomy Extension Label Linkbase Document

  

101.PRE** 

XBRL Taxonomy Extension Presentation Linkbase Document

_________________

*

Filed herewith.

**

Furnished herewith.

+

Certain schedules, annexes or exhibits have been omitted pursuant to Item 601(a)(5) of Regulation S-K but will be furnished supplementally to the SEC upon request.

 

36

 

 

HIGHPEAK ENERGY, INC.

 

 

SIGNATURES

 

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

 

 

HIGHPEAK ENERGY, INC.

  

May 17, 2021

By:

/s/ Steven Tholen

  

Steven Tholen

  

Chief Financial Officer

   

May 17, 2021

By:

/s/ Keith Forbes

  

Keith Forbes

  

Vice President and Chief Accounting Officer

 

37