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, 20212022
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: 333-248898001-39464
HighPeak Energy, Inc. | ||
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Delaware | 84-3533602 |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
| 421 W. 3rd St., Suite 1000 | 76102 |
| Fort Worth, Texas | (Zip Code) |
| (Address of principal executive offices and zip code) |
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)
Not applicable
(Former name, former address and former fiscal year, if changed since last report)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Trading Symbol | Name of each exchange on which registered | ||
Common Stock, par value $0.0001 per share | HPK | The Nasdaq Stock Market LLC | ||
Warrants to purchase | 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 Registrantregistrant (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, 2021,12, 2022, there were 92,675,898104,704,073 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 | ||||
PART I. FINANCIAL INFORMATION | ||||
Item 1. | Condensed Consolidated | |||
Condensed Consolidated Balance Sheets | ||||
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Condensed Consolidated | 9 | |||
Condensed Consolidated | 10 | |||
Condensed Consolidated Statements of Cash Flows | ||||
Notes to Condensed Consolidated | ||||
Item 2. | Management's Discussion and Analysis of Financial Condition and Results of Operations | |||
Item 3. | Quantitative and Qualitative Disclosures About Market Risk | |||
Item 4. | Controls and Procedures | |||
PART II. OTHER INFORMATION | ||||
Item 1. | Legal Proceedings | |||
Item 1A. | Risk Factors | |||
Item 6. | Exhibits | |||
Signatures | 48 | |||
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. | |
“Bcf” means one billion cubic feet. | ||
• | "Boe" means a barrel of crude oil equivalent and is a standard convention used to express crude oil and natural gas volumes on a comparable crude oil equivalent basis. Natural | |
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• | "Bopd" means one barrel of crude oil per day. | |
• | "Btu" means British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit. | |
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• | “common stock” or “HighPeak Energy common stock” means the Company’s common stock, par value $0.0001 per share. | |
• | “Completion” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil and natural gas, | |
• | “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). | |
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• | “DD&A” means depletion, depreciation and |
• | “Development costs” Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the crude oil and natural gas. For a complete definition of development costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(7). | |
• | “Development project” A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project. | |
• | “Development well” A well drilled within the proved area of | |
• | “Differential” An adjustment to the price of crude oil, NGL or natural gas from an established spot market price to reflect differences in the quality and/or location of crude oil, NGL or natural gas. | |
• | “Dry hole” or “dry well” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. | |
• | “Economically producible” The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. | |
• | “EUR” or “Estimated ultimate recovery” The sum of reserves remaining as of a given date and cumulative production as of that date. | |
• | “Exploratory well” An exploratory well is a well drilled to find a new field, | |
• | “FASB” Financial Accounting Standards Board. | |
• | “Field” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations. |
• | “First Amendment” means the First Amendment to Credit Agreement, dated as of June 23, 2021, among HighPeak Energy, Inc., as Borrower, Fifth Third Bank, National Association, as administrative agent, and the Guarantors and Lenders party thereto. | |
• | “Formation” A layer of rock which has distinct characteristics that differs from nearby rocks. | |
• | "GAAP" means accounting principles generally accepted in the United States of America. | |
• | “Gross wells” | |
• | “Held by production” Acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of crude oil or natural gas. | |
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• | "HighPeak Energy" or the "Company" means | |
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• | “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. | |
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• | “Lease operating expenses” The expenses of lifting crude oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, workover, marketing and transportation costs, | |
• | "MBbl" means one thousand Bbls. |
• | "MBoe" means one thousand Boes. | |
• | "Mcf" means one thousand cubic feet and is a measure of natural gas volume. | |
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• | "MMBbl" means one million Bbls. | |
• | "MMBtu" means one million Btus. | |
• | "MMcf" means one million cubic feet and is a measure of natural gas volume. | |
• | “Net acres” The percentage of total acres an owner has out of a particular number of gross acres or a specified tract. As an example. an owner who has 50% interest in 100 gross acres owns 50 net acres. | |
• | “Net production” Production that is owned by us, less royalties and production due others. |
• | "NGL"means natural gas liquids, which are the heavier hydrocarbon liquids that are separated from the natural gas stream; such liquids include ethane, propane, isobutane, normal butane and gasoline. | |
• | "NYMEX" means the New York Mercantile Exchange. | |
• | "OPEC" means the Organization of Petroleum Exporting Countries. | |
• | “Operator” The individual or company responsible for the exploration and/or production of | |
• | “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. | |
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• | “Production costs” Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. For a complete definition of production costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(20). | |
• | “Productive well” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes. | |
• | “Proration unit” A unit that can be effectively and efficiently drained by one well, as allocated by a governmental agency having regulatory jurisdiction. | |
• | “Prospect” A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons. | |
• | “Proved developed nonproducing reserves” or “PDNP” means proved reserves that are developed nonproducing reserves. | |
• | “Proved developed producing reserves” or “PDP” means proved reserves that are developed producing reserves. | |
• | “Proved developed reserves” | |
• | “Proved reserves” Those quantities of crude oil and natural gas, which, by analysis of geosciences and engineering data, can be estimated |
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(i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible crude oil or natural gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known crude oil elevation and the potential exists for an associated natural gas cap, proved crude oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
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• | “Pure” means Pure Acquisition Corp., a Delaware corporation and wholly owned subsidiary of the Company. | |
• | “PV-10” When used with respect to crude oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10%. PV-10 is not a financial measure calculated in accordance with GAAP and generally differs from standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor standardized measure represents an estimate of the fair market value of our crude oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. |
• | “Realized price” The cash market price less all expected quality, transportation and demand adjustments. | |
• | “Recompletion” The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production. | |
• | “Reserves” Reserves are estimated remaining quantities of crude oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering crude oil and natural gas or related substances to market, and all permits and financing required to implement the project. | |
• | “Reservoir” A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs. | |
• | “Resources” Quantities of crude oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations. | |
• | “Revolving Credit Facility” | |
• | “Royalty” An interest in | |
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• | “Second Amendment” means the Second Amendment to Credit Agreement, dated as of October 1, 2021, among HighPeak Energy, Inc., as Borrower, Fifth Third Bank, National Association, as administrative agent, and the Guarantors and Lenders party thereto. | |
• | “Service well” A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include natural gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion. | |
• | “Spacing” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 100-acre spacing, | |
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• | “Spot market price” The cash market price without reduction for expected quality, transportation and demand adjustments. | |
• | “Standardized measure” | |
• | “Stratigraphic test well” A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area. | |
• | “Third Amendment” means the Third Amendment to Credit Agreement, dated as of February 9, 2022, among HighPeak Energy, Inc., as Borrower, Fifth Third Bank, National Association, as administrative agent, and the Lenders party thereto. |
• | “Undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas regardless of whether such acreage contains proved reserves. | |
• | “Unit” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement. | |
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• | “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. | |
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• | With respect to information on the working interest in wells and acreage, “ | |
• | 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.
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 |
● | political instability or armed conflict in crude oil or natural gas producing regions, such as the ongoing war between Russia and Ukraine; |
● | the market prices of crude oil, NGL, natural gas and other products or services; |
● | the supply and demand for crude oil, NGL, natural gas and other products or services; |
● | production and reserve levels; |
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● | 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 |
All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements. Except as required by law, the Company assumes no duty to update or revise its forward-looking statements based on changes in internal estimates or expectations or otherwise.
Additionally, we caution you that reserve engineering is a process of estimating underground accumulations of crude oil, NGL and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of crude oil, NGL and natural gas that are ultimately recovered.
PART I. FINANCIAL INFORMATION ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) |
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HighPeak Energy, Inc.
Condensed Consolidated Balance Sheets
(in thousands, except share data)
March 31, 2021 | December 31, 2020 | March 31, 2022 | December 31, 2021 | |||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||
| ASSETS | ||||||||||||||||
Current Assets: | ||||||||||||||||
Cash and cash equivalents | $ | 9,638 | $ | 19,552 | $ | 35,850 | $ | 34,869 | ||||||||
Accounts receivable | 16,915 | 7,722 | 46,167 | 39,378 | ||||||||||||
Subscription receivable | - | 3,596 | ||||||||||||||
Prepaid expenses | 816 | 2,254 | 15,080 | 7,154 | ||||||||||||
Inventory | 109 | 121 | 3,986 | 3,304 | ||||||||||||
Derivatives | 0 | 2,199 | ||||||||||||||
Deposits | 50 | 50 | 50 | 50 | ||||||||||||
Total current assets | 27,528 | 33,295 | 101,133 | 86,954 | ||||||||||||
Oil and natural gas properties, using the successful efforts method of accounting: | ||||||||||||||||
Crude oil and natural gas properties, using the successful efforts method of accounting: | ||||||||||||||||
Proved properties | 433,693 | 367,372 | 999,110 | 699,701 | ||||||||||||
Unproved properties | 131,709 | 152,741 | 137,765 | 108,392 | ||||||||||||
Accumulated depletion, depreciation and amortization | (30,392 | ) | (17,477 | ) | (99,442 | ) | (82,478 | ) | ||||||||
Total oil and natural gas properties, net | 535,010 | 502,636 | ||||||||||||||
Total crude oil and natural gas properties, net | 1,037,433 | 725,615 | ||||||||||||||
Other property and equipment, net | 1,044 | 1,092 | 1,637 | 1,600 | ||||||||||||
Other noncurrent assets | 745 | 907 | 4,515 | 4,791 | ||||||||||||
Total assets | $ | 564,327 | $ | 537,930 | $ | 1,144,718 | $ | 818,960 | ||||||||
| LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||||||||||||
Current liabilities: | ||||||||||||||||
Accounts payable - trade | $ | 12,760 | $ | 7,581 | $ | 59,062 | $ | 38,144 | ||||||||
Accrued liabilities | 20,525 | 12,374 | 58,083 | 32,409 | ||||||||||||
Derivatives | 51,758 | 13,591 | ||||||||||||||
Advances from joint interest owners | 4,067 | 10,841 | ||||||||||||||
Other current liabilities | 1,520 | 2,480 | 6,676 | 8,015 | ||||||||||||
Total current liabilities | 34,805 | 22,435 | 179,646 | 103,000 | ||||||||||||
Noncurrent liabilities: | ||||||||||||||||
Long-term debt, net | 203,197 | 97,929 | ||||||||||||||
Deferred income taxes | 40,013 | 38,898 | 55,490 | 55,802 | ||||||||||||
Derivatives | 5,342 | 4,075 | ||||||||||||||
Asset retirement obligations | 2,481 | 2,293 | 5,082 | 4,260 | ||||||||||||
Other | 52 | 78 | 2,080 | 831 | ||||||||||||
Commitments and contingencies (Note 9) | ||||||||||||||||
Commitments and contingencies (Note 10) | ||||||||||||||||
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 | ||||||||||||||
Preferred stock, $0.0001 par value, 10,000,000 shares authorized, none issued and outstanding at March 31, 2022 and December 31, 2021 | 0 | 0 | ||||||||||||||
Common stock, $0.0001 par value, 600,000,000 shares authorized, 103,810,939 and 96,774,185 shares issued and outstanding at March 31, 2022 and December 31, 2021, respectively | 10 | 10 | ||||||||||||||
Additional paid-in capital | 589,432 | 581,426 | 777,501 | 617,489 | ||||||||||||
Accumulated deficit | (102,465 | ) | (107,209 | ) | (83,630 | ) | (64,436 | ) | ||||||||
Total stockholders' equity | 486,976 | 474,226 | 693,881 | 553,063 | ||||||||||||
Total liabilities and stockholders' equity | $ | 564,327 | $ | 537,930 | $ | 1,144,718 | $ | 818,960 | ||||||||
The accompanying notes are an integral part of these condensed consolidated and combined financial statements.
HighPeak Energy, Inc.
Condensed Consolidated Statements of Operations
(in thousands, except per share data)
(Unaudited)
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Three Months Ended March 31, | ||||||||||||||||
2021 | 2020 | Three Months Ended March 31, | ||||||||||||||
Successor | Predecessor | 2022 | 2021 | |||||||||||||
Operating Revenues: | ||||||||||||||||
Crude oil sales | $ | 24,870 | $ | 4,524 | $ | 86,938 | $ | 24,870 | ||||||||
NGL and natural gas sales | 847 | 99 | 5,291 | 847 | ||||||||||||
Total operating revenues | 25,717 | 4,623 | 92,229 | 25,717 | ||||||||||||
Operating Costs and Expenses: | ||||||||||||||||
Oil and natural gas production | 2,227 | 2,389 | ||||||||||||||
Crude oil and natural gas production | 9,446 | 2,227 | ||||||||||||||
Production and ad valorem taxes | 1,664 | 308 | 5,006 | 1,664 | ||||||||||||
Exploration and abandonments | 191 | 3 | 209 | 191 | ||||||||||||
Depletion, depreciation and amortization | 12,963 | 3,356 | 17,024 | 12,963 | ||||||||||||
Accretion of discount on asset retirement obligations | 35 | 34 | ||||||||||||||
Accretion of discount | 54 | 35 | ||||||||||||||
General and administrative | 1,759 | 2,861 | 1,940 | 1,759 | ||||||||||||
Stock-based compensation | 966 | - | 3,976 | 966 | ||||||||||||
Total operating costs and expenses | 19,805 | 8,951 | 37,655 | 19,805 | ||||||||||||
Income (loss) from operations | 5,912 | (4,328 | ) | |||||||||||||
Interest income | 1 | - | ||||||||||||||
Income from operations | 54,574 | 5,912 | ||||||||||||||
Interest and other income | 250 | 1 | ||||||||||||||
Interest expense | (54 | ) | - | (5,252 | ) | (54 | ) | |||||||||
Other expense | - | (76,503 | ) | |||||||||||||
Income (loss) before income taxes | 5,859 | (80,831 | ) | |||||||||||||
Income tax expense | 1,115 | - | ||||||||||||||
Derivative loss, net | (66,394 | ) | 0 | |||||||||||||
Income before income taxes | (16,822 | ) | 5,859 | |||||||||||||
Income tax expense (benefit) | (312 | ) | 1,115 | |||||||||||||
Net income (loss) | $ | 4,744 | $ | (80,831 | ) | $ | (16,510 | ) | $ | 4,744 | ||||||
Earnings per share: | ||||||||||||||||
Basic net income | $ | 0.05 | ||||||||||||||
Diluted net income | $ | 0.05 | ||||||||||||||
Earnings (loss) per share: | ||||||||||||||||
Basic net income (loss) | $ | (0.17 | ) | $ | 0.05 | |||||||||||
Diluted net income (loss) | $ | (0.17 | ) | $ | 0.05 | |||||||||||
Weighted average shares outstanding: | 92,592 | |||||||||||||||
Basic | 95,482 | 95,841 | 92,592 | |||||||||||||
Diluted | 95,841 | 93,996 | ||||||||||||||
Dividends declared per share | $ | 0.025 | $ | — | ||||||||||||
The accompanying notes are an integral part of these condensed consolidated and combined financial statements.
HighPeak Energy, Inc.
Condensed Consolidated Statements of Changes in Stockholders' Equity
(in thousands)
(Unaudited)
Three Months Ended March 31, 2022 | ||||||||||||||||||||
Shares Outstanding | Common Stock | Additional Paid-in- Capital | Retained Earnings (Accumulated Deficit) | Total Stockholders' Equity | ||||||||||||||||
Balance, December 31, 2021 | 96,774 | $ | 10 | $ | 617,489 | $ | (64,436 | ) | $ | 553,063 | ||||||||||
Dividends declared ($0.025 per share) | — | 0 | 0 | (2,434 | ) | (2,434 | ) | |||||||||||||
Dividend equivalents declared on outstanding stock options ($0.025 per share) | — | 0 | 0 | (250 | ) | (250 | ) | |||||||||||||
Stock issued for acquisition | 6,960 | 0 | 156,599 | 0 | 156,599 | |||||||||||||||
Stock issuance costs | — | 0 | (55 | ) | 0 | (55 | ) | |||||||||||||
Exercise of warrants | 69 | 0 | 779 | 0 | 779 | |||||||||||||||
Stock-based compensation costs: | ||||||||||||||||||||
Shares issued upon options being exercised | 8 | 0 | 75 | 0 | 75 | |||||||||||||||
Compensation costs included in net income | — | 0 | 2,614 | 0 | 2,614 | |||||||||||||||
Net loss | — | 0 | 0 | (16,510 | ) | (16,510 | ) | |||||||||||||
Balance, March 31, 2022 | 103,811 | $ | 10 | $ | 777,501 | $ | (83,630 | ) | $ | 693,881 | ||||||||||
|
|
|
|
Three Months Ended March 31, 2021 | Three Months Ended March 31, 2021 | Three Months Ended March 31, 2021 | ||||||||||||||||||||||||||||||||||||||
Shares Outstanding | Common Stock | Additional Paid-in Capital | Retained Earnings (Accumulated Deficit) | Total Stockholders' Equity | 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 | 91,968 | $ | 9 | $ | 581,426 | $ | (107,209 | ) | $ | 474,226 | ||||||||||||||||||||
Exercise of warrants | 554 | - | 5,466 | - | 5,466 | 554 | 0 | 5,466 | 0 | 5,466 | ||||||||||||||||||||||||||||||
Stock-based compensation costs: | ||||||||||||||||||||||||||||||||||||||||
Shares issued upon options being exercised | 154 | - | 1,574 | - | 1,574 | 154 | 0 | 1,574 | 0 | 1,574 | ||||||||||||||||||||||||||||||
Compensation costs included in net income | - | - | 966 | - | 966 | |||||||||||||||||||||||||||||||||||
Compensation costs included in net loss | — | 0 | 966 | 0 | 966 | |||||||||||||||||||||||||||||||||||
Net income | - | - | - | 4,744 | 4,744 | — | 0 | 0 | 4,744 | 4,744 | ||||||||||||||||||||||||||||||
Balance, March 31, 2021 | 92,676 | $ | 9 | $ | 589,432 | $ | (102,465 | ) | $ | 486,976 | 92,676 | $ | 9 | $ | 589,432 | $ | (102,465 | ) | $ | 486,976 | ||||||||||||||||||||
The accompanying notes are an integral part of these condensed consolidated and combined financial statements.
HighPeak Energy, Inc. Condensed Consolidated Statements of Cash Flows |
|
(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 | ||||||
Three Months Ended March 31, | ||||||||
2022 | 2021 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||
Net income (loss) | $ | (16,510 | ) | $ | 4,744 | |||
Adjustments to reconcile net income (loss) to net cash provided by operations: | ||||||||
Exploration and abandonment expense | 32 | 49 | ||||||
Depletion, depreciation and amortization expense | 17,024 | 12,963 | ||||||
Accretion expense | 54 | 35 | ||||||
Stock-based compensation expense | 3,976 | 966 | ||||||
Amortization of debt issuance costs | 645 | 29 | ||||||
Amortization of original issue discount on senior notes | 893 | 0 | ||||||
Derivative-related activity | 41,633 | 0 | ||||||
Deferred income taxes | (312 | ) | 1,115 | |||||
Changes in operating assets and liabilities: | ||||||||
Accounts receivable | (6,789 | ) | (9,193 | ) | ||||
Prepaid expenses, inventory and other assets | (941 | ) | (12 | ) | ||||
Accounts payable, accrued liabilities and other current liabilities | 10,242 | 677 | ||||||
Net cash provided by operating activities | 49,947 | 11,373 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||
Additions to crude oil and natural gas properties | (165,099 | ) | (44,875 | ) | ||||
Changes in working capital associated with crude oil and natural gas property additions | 20,644 | 13,263 | ||||||
Acquisitions of crude oil and natural gas properties | (6,348 | ) | (309 | ) | ||||
Other property additions | (96 | ) | 0 | |||||
Net cash used in investing activities | (150,899 | ) | (31,921 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||
Proceeds from issuance of senior unsecured notes, net of discount | 210,179 | 0 | ||||||
Repayments under revolving credit facility | (115,000 | ) | 0 | |||||
Borrowings under revolving credit facility | 15,000 | 0 | ||||||
Proceeds from exercises of warrants | 779 | 5,466 | ||||||
Proceeds from subscription receivable from exercises of warrants | 0 | 3,596 | ||||||
Proceeds from exercises of stock options | 75 | 1,574 | ||||||
Debt issuance costs | (6,449 | ) | (2 | ) | ||||
Dividends paid | (2,382 | ) | 0 | |||||
Dividend equivalents paid | (214 | ) | 0 | |||||
Stock offering costs | (55 | ) | 0 | |||||
Net cash provided by financing activities | 101,933 | 10,634 | ||||||
Net increase (decrease) in cash and cash equivalents | 981 | (9,914 | ) | |||||
Cash and cash equivalents, beginning of period | 34,869 | 19,552 | ||||||
Cash and cash equivalents, end of period | $ | 35,850 | $ | 9,638 | ||||
Supplemental disclosure of non-cash transactions: | ||||||||
Interest paid | $ | 1,081 | $ | 4 | ||||
Income taxes paid | $ | 0 | $ | 0 | ||||
Stock issued for acquisition | $ | 156,600 | $ | 0 | ||||
Additions to asset retirement obligations | $ | 768 | $ | 153 | ||||
The accompanying notes are an integral part of these condensed consolidated and combined financial statements.
|
|
|
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.
HIGHPEAK ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
(Unaudited)
NOTE 1. Organization and Nature of Operations
HighPeak Energy, Inc. ("HighPeak Energy" or 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. 2019. See the Company’s Annual Report on Form 10-K10-K for the year ended December 31, 20202021 for further information regarding the business combination which resulted information of the Company becoming the parent company and Pure becoming a wholly owned subsidiary along with the businesses acquired.Company.
HighPeak Energy’s common stock and warrants are listed and traded on the Nasdaq Global Market (the "Nasdaq") under the ticker symbols “HPK” and “HPKEW,” respectively. HighPeak Energy’s Contingent Value Rights (“CVRs”) are currently traded on the Over-The-Counter market althoughunder the Company has applied for listing on the Nasdaq.ticker symbol “HPKER.” The Company is an independent crude oil and natural gas exploration and production company that explores for, develops and produces crude oil, NGL and natural gas in the Permian Basin in West Texas, more specifically, the Midland Basin.Basin in Howard and Borden Counties. Our acreage is composed of two core areas, withFlat Top in the northern block named Flat Topportion of Howard County extending into southern Borden County and Signal Peak in the southern block named Signal Peak.portion of Howard County.
NOTE 2. Basis of Presentation and Summary of Significant Accounting Policies
Presentation. In the opinion of management, the unaudited interim condensed consolidated and combined financial statements of the Company as of March 31, 2021 and December 31, 2020 2022 and for the three months ended March 31, 2021 (Successor), 2022 and for the three months ended March 31, 2020 (Predecessor)2021 include all adjustments and accruals, consisting only of normal, recurring adjustments and accruals necessary for a fair presentation of the results for the interim periods in conformity with generally accepted accounting principles in the United States ("GAAP"). The operating results for the three months ended March 31, 2021 2022 are not indicative of results for a full year.
Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted in accordance with the rules and regulations of the United States Securities and Exchange Commission (the "SEC"). These unaudited interim condensed consolidated 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-K10-K for the year ended December 31, 2020.2021.
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.formation. All material intercompany balances and transactions have been eliminated. Certain reclassifications have been made to prior period amounts to conform to the current period’s presentation.
Use of estimates in the preparation of financial statements. Preparation of the Company's unaudited interim condensed consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion of crude oil and natural gas properties and evaluations for impairment of proved and unproved crude oil and natural gas properties, in part, is determined using estimates of proved, probable and possible crude oil, NGL and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved, probable and possible reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved crude oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves, commodity price outlooks and future undiscounted and discounted net cash flows. Other items subject to such estimates and assumptions include, but are not limited to, the carrying value of crude oil and natural gas properties, asset retirement obligations, equity-based compensation, fair value of derivatives and estimates of income taxes. Actual results could differ from the estimates and assumptions utilized.
Cash and cash equivalents. The Company’s cash and cash equivalents include depository accounts held by banks with original issuance maturities of 90 days or less. The Company’s cash and cash equivalents are generally held in financial institutions in amounts that may exceed the insurance limits of the Federal Deposit Insurance Corporation. However, management believes that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected.
Accounts receivable. TheAs of March 31, 2022 and December 31, 2021, the Company’s accounts receivables are primarily comprisedconsist of amounts due from the sale of crude oil, NGL and natural gas of $41.1 million and $29.0 million, respectively, and are based on estimates of sales volumes and realized prices the Company anticipates it will receive, receivables arelated to refunds from pipe suppliers of zero and $3.2 million, respectively, current U.S. federal income tax receivable,receivables of $3.2 million and $3.2 million, respectively, joint interest receivables of $1.9 million and other$3.1 million, respectively, and receivables for which the Company does not require collateral security.related to settlements of derivative contracts of 0 and $771,000, respectively. The Company’s share of crude oil, NGL and natural gas production is sold to various purchasers who must be prequalified under the Company’s credit risk policies and procedures. The Company 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 2022 and December 31, 2020, 2021, the Company had no allowance for doubtful accounts.
Subscription receivable.Concentration of credit risk. In accordanceThe Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with significant purchasers. For the Financial Accounting Standards Board ("FASB") Accounting Standards Codification (“ASC”) 505-10-45-2, “Receivablesthree months ended March 31, 2022 and 2021, sales to the Company’s largest purchaser accounted for Issuanceapproximately 93% and 96%, respectively, of Equity,the Company’s total crude oil, NGL and natural gas sales revenues. The Company generally does not require collateral and does not believe the loss of this particular purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in various regions.
Prepaid expenses. ”Prepaid expenses are comprised primarily of tubulars that the Company recordedhas prepaid in order for the suppliers to produce the tubulars in time such as to guarantee their availability when we need them for our current drilling program, prepaid drilling and completion costs on wells being drilled and completed by third party operators where we own a subscription receivablenon-operated working interest, prepaid caliche that will be used on future locations and roads in our development areas, prepaid insurance costs, software maintenance costs and listing fees that will be amortized over the life of the policies and prepaid software maintenance fees that will be amortized over the life of the contracts. Prepaid expenses as of March 31, 2022 and 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 20202021 is $15.1 million 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.$7.2 million, respectively.
Inventory. Inventory is comprised primarily of crude oil and natural gas drilling or repair items such as tubing, casing, proppant used to fracture-stimulate crude oil and natural gas wells, water, chemicals, pumps, vessels, operating supplies and ordinary maintenance materials and parts. The materials and supplies inventory is primarily acquired for use in future drilling 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 2022 and December 31, 2020 2021 is $109,000$4.0 million and $120,000,$3.3 million, respectively, and the Company has not recognized any valuation allowance to date.
OilCrude oil and natural gas properties. The Company utilizes the successful efforts method of accounting for its crude oil and natural gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized while nonproductive exploration costs and geological and geophysical expenditures are expensed.
The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheet following the completion of drilling unless both of the following conditions are met: (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.
Due to the capital-intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather the Company’s ongoing efforts and expenditures related to accurately predict the hydrocarbon recoverability based on well information, gaining access to other companies’ production data in the area, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, the Company’s assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found sufficient proved reserves to sanction the project or is noncommercial and is charged to exploration and abandonment expense. See Note 56 for additional information.
The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves for leasehold costs and proved reserves for drilling, completion and other crude oil and natural gas property costs. Costs of unproved leasehold costs are excluded from depletion until proved reserves are established or, if unsuccessful, impairment is determined.
Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited to proved or unproved oil and charged, respectively, to accumulated depletion, depreciation and amortization,natural gas properties, as the case may be, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recorded until an entire amortization base is sold. However, gain or loss is recorded from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base.
The Company performs assessments of its long-lived assets to be held and used, including proved crude oil and natural gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows is less than the carrying amount of the assets. In these circumstances, the Company recognizes an impairment charge for the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets.
Unproved crude oil and natural gas properties are periodically assessed for impairment on a project-by-project basis. These impairment assessments are affected by the results of exploration activities, commodity price outlooks, planned future sales or expirations of all or a portion of such projects. If the estimated future net cash flows attributable to such projects are not expected to be sufficient to fully recover the costs invested in each project, the Company will recognize an impairment charge at that time.
Other property and equipment, net. Other property and equipment is recorded at cost. The carrying values of other property and equipment, net of accumulated depreciation of $285,000$497,000 and $237,000$438,000 as of March 31, 2021 2022 and December 31, 2020, 2021, respectively, are as follows (in thousands):
March 31, 2021 | December 31, 2020 | March 31, 2022 | December 31, 2021 | |||||||||||||
Land | $ | 725 | $ | 725 | $ | 1,122 | $ | 1,122 | ||||||||
Information technology | 250 | 292 | ||||||||||||||
Transportation equipment | 39 | 41 | 257 | 202 | ||||||||||||
Leasehold improvements | 20 | 24 | 167 | 143 | ||||||||||||
Information technology | 83 | 125 | ||||||||||||||
Field equipment | 10 | 10 | 8 | 8 | ||||||||||||
Total other property and equipment, net | $ | 1,044 | $ | 1,092 | $ | 1,637 | $ | 1,600 | ||||||||
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, transportationTransportation equipment is generally depreciated over five years, and field equipment is generally depreciated over seven years and information technology is generally depreciated over three years. Leasehold improvements are amortized over the lesser of their estimated useful lives or the underlying terms of the associated leases.
The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such assets are considered to be impaired, the impairment to be recorded is measured by the amount by which the carrying amount of the asset exceeds its estimated fair value. The estimated fair value is determined using either a discounted future cash flow model or another appropriate fair value method.
Aid-in-construction assets. As of March 31, 2022 and December 31, 2021, the Company has aid-in-construction assets totaling $3.8 million and $3.9 million, respectively, included in other noncurrent assets. The Company contracted with the natural gas gatherer and processor in its Flat Top area to construct a low-pressure gas gathering system to transport the Company’s natural gas to its processing facility. The Company agreed to incur the cost to construct the system in return for future payments based on gross throughput through the system, including any third-party natural gas that is potentially tied into the system in the future. Based on the Company’s current projections of its natural gas reserves in Flat Top, it is anticipated that the full amount will be paid back in less than four years. The contract calls for future aid-in-construction fundings if expansions of the system are necessary at the sole discretion of the Company.
Debt issuance costs.costs and original issue discount. The Company has paid a total of $407,000$9.0 million in debt issuance costs, $2,000$6.4 million of which was incurred during the three months ended March 31, 2021, 2022, related to the issuance of senior unsecured notes and its new revolving credit facility. Amortization based on the straight-line method over the termterms of the senior unsecured notes and the revolving credit facility which approximates the effective interest rate method was $29,000$644,000 and zero$29,000 during the three months ended March 31, 2021 2022 and 2020,2021, respectively. In addition, the company realized a $14.8 million discount on the issuance of its senior unsecured notes that is being amortized over the life of the notes which approximates the effective interest method and was $893,000 and 0 during the three months ended March 31, 2022 and 2021, respectively. As of March 31, 2021 2022 and December 31, 2020, 2021, the net debt issuance costs and discount are included in noncurrent assetsnetted against the outstanding long-term debt 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 generally not recorded as lease right-of-use assets and liability.liabilities. See Note 910 for additional information.
Accounts payable and accruedCurrent liabilities. Accounts payable and accruedCurrent liabilities as of March 31, 2021 2022 and December 31, 2020 2021 totaled approximately $34.8$179.6 million and $22.4$103.0 million, respectively, including trade accounts payable, derivative liabilities, revenues payable, advances from joint interest owners and accruals for capital expenditures, operating and general and administrative expenses, interest expense, operating leases, dividends and dividend equivalents and other miscellaneous items.
Asset retirement obligations. The Company records a liability for the fair value of an asset retirement obligation in the period in which the associated asset is acquired or placed into service, if a reasonable estimate of fair value can be made. Asset retirement obligations are generally capitalized as part of the carrying value of the long-lived asset to which it relates. Conditional asset retirement obligations meet the definition of liabilities and are recorded when incurred and when fair value can be reasonably estimated. See Note 78 for additional information.
Revenue recognition. The Company follows FASB ASC 606, “Revenue from Contracts with Customers,” (“ASC 606”) whereby the Company recognizes revenues from the sales of crude oil and natural gas to its purchasers and presents them disaggregated on the Company’s condensed consolidated and combined statements of operations.
The Company enters into contracts with purchasers to sell its crude oil and natural gas production. Revenue on these contracts is recognized in accordance with the five-stepfive-step revenue recognition model prescribed in ASC 606. Specifically, revenue is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the crude oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under the crude oil and natural gas marketing contracts is typically received from the purchaser one to two months after production. At As of March 31, 2021 2022 and December 31, 2020, 2021, the Company had receivables related to contracts with purchasers of approximately $13.4$41.1 million and $4.2$29.0 million, respectively.
Crude Oil Contracts. The Company’s crude oil marketing contracts transfer physical custody and title at or near the wellhead, which is generally when control of the crude oil has been transferred to the purchaser. The crude oil produced is sold under contracts using market-based pricing which is then adjusted for the differentials based upon delivery location and crude oil quality. Since the differentials are incurred after the transfer of control of the crude oil, the differentials are included in crude oil sales on the consolidated 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)606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
Derivatives. All of the Company’s derivatives are accounted for as non-hedge derivatives and are recorded at estimated fair value in the consolidated balance sheets. All changes in the fair values of its derivative contracts are recorded as gains or losses in the earnings of the periods in which they occur. The Company enters into derivatives under master netting arrangements, which, in an event of default, allows the Company to offset payables to and receivables from the defaulting counterparty. The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty.
The Company’s credit risk related to derivatives is a counterparties’ failure to perform under derivative contracts owed to the Company. The Company uses credit and other financial criteria to evaluate the credit standing of, and to select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, associated credit risk is mitigated by the Company’s credit risk policies and procedures.
The Company has entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note 5 for additional information.
Income taxes. The provision for income taxes is determined using the asset and liability approach of accounting for income taxes. Under this approach, deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the carrying amounts for income tax purposes and net operating loss and tax credit carryforwards. The amount of deferred taxes on these temporary differences is determined using the tax rates that are expected to apply to the period when the asset is realized or the liability is settled, as applicable, based on tax rates and laws in the respective tax jurisdiction enacted as of the balance sheet date.
The Company reviews its deferred tax assets for recoverability and establishes a valuation allowance based on projected future taxable income, applicable tax strategies and the expected timing of the reversals of existing temporary differences. A valuation allowance is provided when it is more likely than not (likelihood of greater than 50 percent) that some portion or all the deferred tax assets will not be realized. The Company has had not established a valuation allowance as of March 31, 2021 2022 and December 31, 2020.2021.
The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. If all or a portion of the unrecognized tax benefit is sustained upon examination by the taxing authorities, the tax benefit will be recognized as a reduction to the Company’s deferred tax liability and will affect the Company’s effective tax rate in the period it is recognized. See Note 1213 for addition information.
The Company records any tax-related interest charges as interest expense and any tax-related penalties as other expense in the condensed consolidated and combined statements of operations of which there have been none to date.
Prior to August 21, 2020, the Predecessors did not record a provision for U.S. federal income tax because the Predecessors were treated as partnerships for U.S. federal income tax purposes and, as such, the partners of the Predecessors reported their share of the Company’s income or loss on their respective income tax returns. The Predecessors were required to file tax returns on Form 1065 with the Internal Revenue Service (“IRS”). The 2017 to 2019 tax years remain open to examination.
The Predecessors recognize in their condensed consolidated and combined financial statements the effect of a tax position, if that position is more likely than not to be sustained upon examination, including resolution of any appeals or litigation processes, based upon the technical merits of the position. Tax positions taken related to the Predecessors’ status as limited partnerships, and state filing requirements have been reviewed, and management is of the opinion that they would more likely than not be sustained by examination. Accordingly, the Company has not recorded an income tax liability for uncertain tax benefits for periods prior to August 21, 2020. Under the new centralized partnership audit rules effective for tax years beginning after 2017, the IRS assesses and collects underpayments of tax from the partnership instead of from each partner. The partnership may be able to pass the adjustments through to its partners by making a push-out election or, if eligible, by electing out of the centralized partnership audit rules. The collection of tax from the partnership is only an administrative convenience for the IRS to collect any underpayment of income taxes including interest and penalties. Income taxes on partnership income, regardless of who pays the tax or when the tax is paid, is attributed to the partners. Any payment made by the Company as a result of an IRS examination will be treated as an expense from the Company in the condensed consolidated and combined financial statements.
The Company is also subject to Texas Margin Tax. The Company realized no Texas Margin Tax in the accompanying condensed consolidated and combined financial statements as we do not anticipate owing any Texas Margin Tax for the periods presented.
Stock-based compensation. Stock-based compensation expense for stock options (“Equity Awards”)option awards is measured at the grant date or modification date, as applicable, using the fair value of the award, and is recorded, net of forfeitures, on a straight-line basis over the requisite service period of the respective award. The fair value of Equity Awardsstock option awards is determined on the grant date or modification date, as applicable, using a Black-Scholes option valuation model with the following inputs; (i) the grant date’s closing stock price, (ii) the exercise price of the stock options, (iii) the expected term of the stock option, (iv) the estimated risk-free adjusted interest rate for the duration of the option’s expected term, (v) the expected annual dividend yield on the underlying stock and (vi) the expected volatility over the option’s expected term.
Stock-based compensation for HighPeak Energy common stock issued to outside directors with no restrictions thereon, is measured at the grant date using the fair value of the award and is recordedrecognized as stock-based compensation in the accompanying financial statements immediately. IfStock-based compensation for restricted stock is awarded to employees oroutside directors inand employee members of the future, asboard of directors is measured at the case may be, stock-based compensation will begrant date using the fair value of the award and is recognized on a straight-line basis over the requisite service period of the respective award.
Segments. Based on the Company’s organizational structure, the Company has one1 operating segment, which is crude oil and natural gas development, exploration and production. In addition, the Company has a single, company-wide management team that allocates capital resources to maximize profitability and measures financial performance as a single enterprise.
Impact of the COVID-19COVID-19 Pandemic. A novel strain of the coronavirus disease 2019 ("COVID-19"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-19COVID-19 a pandemic, and the President of the United States declared the COVID-19COVID-19 outbreak a national emergency. The COVID-19COVID-19 pandemic significantly affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the COVID-19COVID-19 pandemic resulted in travel restrictions, business closures and other restrictions that have disrupted the demand for crude oil throughout the world and when combined with pressures on the global supply-demand balance for crude oil and related products, resulted in significant volatility in crude oil prices beginning late February 2020. The length of this demand disruption is unknown, and there is significant uncertainty regarding the long-term impact of the effects of the COVID-19COVID-19 pandemic to global crude oil demand.
Adoption of new accounting standards. In December 2019, the FASB issued Accounting Standards Update (“ASU”) No. 2019-12, “Simplifying the Accounting for Income Taxes (Topic 740)”. The new guidance simplifies the accounting for income taxes by eliminating certain exceptions related to the approach for intra-period tax allocation, the methodology for calculating income taxes in an interim period, hybrid taxes, and the recognition of deferred tax liabilities for outside basis differences. It also clarifies and simplifies other aspects of the accounting for income taxes. Amendments are to be applied prospectively, except for certain amendments that are to be applied either retrospectively or with a modified retrospective approach through a cumulative effect adjustment recorded to retained earnings. The Company adopted ASU 2019-12 on January 1, 2021, which did not have a material impact on the Company's condensed consolidated and combined financial statements.
New accounting pronouncements. 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.
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 3.Acquisitions
Acquisitions. During the three months ended March 31, 2022, the Company incurred a total of $162.9 million in acquisition costs primarily related to a series of agreements to acquire various crude oil and natural gas properties contiguous to its Flat Top operating area in Borden and Howard counties, consisting of approximately 10,200 net acres and associated producing properties, water system infrastructure and in-field fluid gathering pipelines. Included in the acquisition costs is the issuance of 6,960,000 shares of HighPeak Energy common stock valued at $156.6 million on the date of closing. All of the aforementioned acquisitions were accounted for as asset acquisitions as substantially all of the gross assets acquired are concentrated in a group of similar identifiable assets. The consideration paid was allocated to the individual assets acquired and liabilities assumed based on their relative fair values. All transaction costs associated with the acquisitions were capitalized.
Contingent Acquisition. The Company is also party to an option agreement to acquire additional producing horizontal wells and acreage contiguous to its Flat Top Area for consideration of approximately 773,333 shares of HighPeak common stock, which may be adjusted for customary purchase price adjustments, should certain closing conditions come to fruition prior to May 31, 2022. At this time, it is unknown if this transaction will be consummated.
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 orAssets and liabilities that are measured at fair value on a recurring basis as of March 31, 2021 or 2022 and December 31, 2020.2021 are as follows (in thousands):
As of March 31, 2022 | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total | |||||||||||||
Assets: | ||||||||||||||||
Commodity price derivatives | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||
Liabilities: | ||||||||||||||||
Commodity price derivatives – current | 0 | 51,758 | 0 | 51,758 | ||||||||||||
Commodity price derivatives – noncurrent | 0 | 5,342 | 0 | 5,342 | ||||||||||||
Total liabilities | 0 | 57,100 | 0 | 57,100 | ||||||||||||
Total recurring fair value measurements | $ | 0 | $ | (57,100 | ) | $ | 0 | $ | (57,100 | ) | ||||||
As of December 31, 2021 | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total | |||||||||||||
Assets: | ||||||||||||||||
Commodity price derivatives | $ | 0 | $ | 2,199 | $ | 0 | $ | 2,199 | ||||||||
Liabilities: | ||||||||||||||||
Commodity price derivatives – current | 0 | 13,591 | 0 | 13,591 | ||||||||||||
Commodity price derivatives – noncurrent | 0 | 4,075 | 0 | 4,075 | ||||||||||||
Total liabilities | 0 | 17,666 | 0 | 17,666 | ||||||||||||
Total recurring fair value measurements | $ | 0 | $ | (15,467 | ) | $ | 0 | $ | (15,467 | ) | ||||||
Commodity price derivatives. The Company’s commodity price derivatives are currently made up entirely of crude oil swap contracts. The Company measures derivatives using an industry-standard pricing model that is provided by a third party. The inputs utilized in the third-party discounted cash flow and option-pricing models for valuing commodity price derivatives include forward prices for crude oil, contracted volumes, volatility factors and time to maturity, which are considered Level 2 inputs.
Assets and liabilities measured at fair value on a nonrecurring basis. Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances. Specifically, (i) stock-based compensation is measured at fair value on the date of grant based on Level 1 inputs for restricted stock awards or Level 2 inputs for stock option awards based upon market data, (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)(ii) the estimates and fair value measurements used for the evaluation of proved property for potential impairment using Level 3 inputs based upon market conditions in the area. The Company assesses the recoverability of the carrying amount of certain assets and liabilities whenever events or changes in circumstances indicate the carrying amount of an asset or liability may not be recoverable. These assets and liabilities can include inventories, proved and unproved crude oil and natural gas properties and other long-lived assets that are written down to fair value when they are impaired or held for sale. The Company did not record any impairments to proved or unproved crude oil and natural gas properties for the periods presented in the accompanying condensed consolidated and combined financial statements.
Financial instruments not carried at fair value. Carrying values and fair values of financial instruments that are not carried at fair value in the consolidating balance sheets are as follows (in thousands):
As of March 31, 2022 | As of December 31, 2021 | |||||||||||||||
Carrying Value | Fair Value | Carrying Value | Fair Value | |||||||||||||
Assets: | ||||||||||||||||
Cash and cash equivalents | $ | 35,850 | $ | 35,850 | $ | 34,869 | $ | 34,869 | ||||||||
Liabilities: | ||||||||||||||||
Long-term debt: | ||||||||||||||||
Senior notes (a) | $ | 205,052 | $ | 225,000 | $ | 0 | $ | 0 | ||||||||
(a) | Fair value is determined using Level 2 inputs. The Company’s senior unsecured notes are quoted, but not actively traded on major exchanges; therefore, fair value is based on periodic values as quoted on major exchanges. See Note 7 for additional information. |
The Company has other financial instruments consisting primarily of cash equivalents, accounts receivable, accounts payable, long-term debt, specifically the revolving credit facility, and other current assets and liabilities that approximate fair value due to the nature of the instrument and their relatively short maturities.
Impact of the COVID-19 pandemic on certain assets and liabilities measured at fair value on a nonrecurring basis.NOTE 5. Derivative Financial Instruments
Proved Properties. The Company performs assessments of its proved oil and natural gas properties accounted for under the successful efforts method ofaccounting 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 assessmentprimarily utilizes commodity swap contracts to (i) reduce the effect of price volatility on the commodities the Company produces and sells, and (ii) support the Company’s capital budgeting and expenditure plans, (iii) protect the Company’s borrowing base under its Revolving Credit Facility, (iv) adhere to the hedge obligations included in the senior unsecured notes and (v) support the payment of contractual obligations.
The following table summarizes the effect of derivatives on the Company’s consolidated statements of operations (in thousands):
Three Months Ended March 31, | ||||||||
2022 | 2021 | |||||||
Noncash derivative gain (loss), net | $ | (41,633 | ) | $ | 0 | |||
Derivative settlements, net | (24,761 | ) | 0 | |||||
Derivative gain (loss), net | $ | (66,394 | ) | $ | 0 | |||
Crude oil production derivatives. The Company sells its crude oil production at the lease and the sales contracts governing such crude oil production are tied directly to, or are correlated with, NYMEX WTI crude oil prices. As such, the Company uses NYMEX WTI derivative contracts to manage future crude oil price volatility.
The Company’s outstanding crude oil derivative contracts as of March 31, 2022 and the weighted average crude oil prices per barrel for those contracts are as follows:
| Remainder of 2022 | 2023 | |||||||||||||||||||||||||||
Second | Third | Fourth |
| First | Second |
| ||||||||||||||||||||||
| Total | Total | |||||||||||||||||||||||||||
Quarter | Quarter | Quarter | Quarter | Quarter | ||||||||||||||||||||||||
Crude Oil Price Swaps - WTI: | ||||||||||||||||||||||||||||
Volume (MBbls) | 1,039.8 | 456.4 | 487.4 | 1,983.6 | 441.0 | 200.2 | 641.2 | |||||||||||||||||||||
Price per Bbl | $ | 71.96 | $ | 75.15 | $ | 70.14 | $ | 72.25 | $ | 70.05 | $ | 57.22 | $ | 66.04 | ||||||||||||||
The Company uses credit and other financial criteria to evaluate the credit standings of, and to select, counterparties to its derivative financial instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its proved oilderivative financial instruments, associated credit risk is mitigated by the Company’s credit risk policies 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.procedures.
There is significant uncertainty surroundingNet derivative liabilities associated with 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.Company’s open commodity derivatives by counterparty are as follows (in thousands):
As of March 31, 2022 | ||||
Fifth Third Bank, National Association | $ | (35,464 | ) | |
Bank of America, National Association | (11,765 | ) | ||
Bank of Oklahoma, National Association | (7,939 | ) | ||
Citizens Bank, National Association | (1,932 | ) | ||
| $ | (57,100 | ) | ||
NOTE 5.6. Exploratory Well Costs
The Company capitalizes exploratory well and project costs until a determination is made that the well or project has either found proved reserves, is impaired or is sold. The Company's capitalized exploratory well and project costs are included in proved properties in the 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 | Three Months Ended March 31, 2022 | ||||||||||
Beginning capitalized exploratory well costs | $ | 32,592 | $ | 11,427 | $ | 28,076 | ||||||
Additions to exploratory well costs | 42,098 | 46,865 | 70,728 | |||||||||
Reclassification to proved properties | (67,445 | ) | (17,315 | ) | (74,081 | ) | ||||||
Exploratory well costs charged to exploration and abandonment expense | - | - | 0 | |||||||||
Ending capitalized exploratory well costs | $ | 7,245 | $ | 40,977 | $ | 24,723 | ||||||
All capitalized exploratory well costs have been capitalized for less than one year based on the date of drilling.
Note 6.NOTE 7. Long-Term Debt
The components of long-term debt, including the effects of debt issuance costs, are as follows (in thousands):
March 31, 2022 | December 31, 2021 | |||||||
10.00% Senior Notes due 2024 | $ | 225,000 | $ | 0 | ||||
Revolving Credit Facility due 2024 | 0 | 100,000 | ||||||
Debt issuance costs, net (a) | (7,876 | ) | (2,071 | ) | ||||
Discounts, net (b) | (13,927 | ) | 0 | |||||
Total debt | 203,197 | 97,929 | ||||||
Less current portion of long-term debt | 0 | 0 | ||||||
Long-term debt, net | $ | 203,197 | $ | 97,929 | ||||
(a) Debt issuance costs as of March 31, 2022 and December 31, 2021 consisted of $9.0 million and $2.6 million, respectively, in costs less accumulated amortization of $1.1 million and $502,000, respectively.
(b) Discounts as of March 31, 2022 and December 31, 2021 consisted of $14.8 million and zero, respectively, in discounts less accumulated amortization of $893,000 and zero, respectively.
Revolving Credit Facility. In December 2020, the Company entered into a revolving credit facilityCredit Agreement with Fifth Third Bank, National Association (“Fifth Third”) as the administrative agent and sole lender to establish a revolving credit facility (“Revolving Credit Facility”) that matures on June 17, 2024. The Revolving Credit Facility hashad an initial borrowing base of $40$40.0 million. TheHowever, the Company elected to reduce the aggregate elected commitments under the Revolving Credit Facility to $20$20.0 million. In June 2021, the Company entered into the First Amendment to, among other things, (i) complete the semi-annual borrowing base redetermination process which increased the borrowing base from $40.0 million to $125.0 million and (ii) modify the terms of the Credit Agreement to increase the aggregate elected commitments from $20.0 million to $125.0 million. A syndicate of banks joined the credit facility at differing levels of commitments with Fifth Third remaining the administrative agent. In October 2021, the Company entered into the Second Amendment to, among other things, (i) complete a semi-annual borrowing base redetermination process, which increased the borrowing base from $125.0 million to $195.0 million and (ii) modify the terms of the Credit Agreement to increase the aggregate elected commitments from $125.0 million to $195.0 million. In February 2022, the Company entered into the Third Amendment to, among other things, (i) reduce the borrowing base from $195.0 million to $138.8 million and (ii) modify the terms of the Credit Agreement to reduce the aggregate elected commitments from $195.0 million to $138.8 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)$138.8 million as of March 31, 2022), (ii)(ii) the aggregate elected commitments (which currently stand at $20.0 million) $138.8 million as of March 31, 2022) and (iii) $500.0 million. As of March 31, 2021 2022 and December 31, 2020, 2021, the Company had no0 and $100.0 million, respectively, outstanding borrowings under the Revolving Credit Facility. Borrowings under the Revolving Credit Facility bearprior to February 2022 bore interest, at the option of the Company, based on (a) a rate per annum equal to the higher of (i) the prime rate announced from time to time by Fifth Third, (ii) the weighted average of the rates on overnight federal funds transactions with members of the Federal Reserve System during the last preceding business day plus 0.5 percent orand (iii) the Adjusted LIBORLIBO Rate for one-month Interest Period, plus a margin (the “Applicable Margin”), which is currently 3.25 percent and is alsowas determined by the Borrowing Base Utilization Percentage as defined in the Revolving Credit Facility.Facility or (b) the LIBO Rate for a one, three or six month Interest Period multiplied by the Statutory Reserve Rate. As of February 2022, borrowings under the Revolving Credit Facility bear interest at the option of the Company, based on (a) the prime rate announced from time to time by Fifth Third or (b) a rate equal to the higher of (i) zero percent per annum and (ii) SOFR relating to quotations for 1 or 3 months. Letters of credit outstanding under the Revolving Credit Facility are subject to a per annum fee, representing the Applicable Margin plus 0.125 percent. The Company also pays commitment fees on undrawn amounts under the Revolving Credit Facility equal to 0.50 percent. Borrowings under the Revolving Credit Facility are secured by a first lien security interest on substantially all assets of the Company and its restricted subsidiaries, including mortgages on the Company’s and its restricted subsidiaries’ crude oil and natural gas properties. The Revolving Credit Facility is scheduled to have the borrowing base redetermined semiannually in April and October. Additionally, the Company and Fifth Third each have the option for a wild card evaluation between redeterminations. 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.
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.
Senior notes. In February 2022, the Company issued $225.0 million aggregate principal amount of 10.00% senior unsecured notes that will mature on February 15, 2024 (“Senior Notes”). The Company received proceeds, net of $21.2 million of issuance costs and discounts, of $203.8 million. The net proceeds were used to pay down the balance of our Revolving Credit Facility to zero and to fund our ongoing capital development program. Interest on the Senior Notes will be payable on August 15 and February 15 of each year.
Both the Revolving Credit Facility and the Senior Notes have hedging obligations that the Company adheres to.
Note 7.NOTE 8. Asset Retirement Obligations
The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the Company’s credit-adjusted risk-free rate that is utilized in the calculations of asset retirement obligations.
Asset retirement obligations activity is as follows (in thousands):
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 | ||||
|
Three Months Ended March 31, 2022 | ||||
Beginning asset retirement obligations | $ | 4,260 | ||
Liabilities incurred from wells acquired | 523 | |||
Liabilities incurred from new wells | 245 | |||
Accretion of discount | 54 | |||
Ending asset retirement obligations | $ | 5,082 | ||
As of March 31, 2021 2022 and December 31, 2020, 2021, all asset retirement obligations are considered noncurrent and classified as such in the accompanying consolidated balance sheet.
NOTE 8.9. Incentive Plans
401(k)401(k) Plan. The HighPeak Energy Employees, Inc 401(k)401(k) Plan (the “401(k)“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, allAll regular full-time and part-time employees of the Company are eligible to participate in the 401(k)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)401(k) Plan. Matching contributions are made to the 401(k)401(k) Plan in cash by the Company in amounts equal to 100 percent of a participant’s contributions to the 401(k)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)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 2022 and 2020,2021, the Company contributed $56,000$76,000 and zero$56,000 to the 401(k)401(k) Plan, respectively.
Long-Term Incentive Plan. The Company’s 2020 Long-TermAmended & Restated Long Term Incentive Plan (“LTIP”) provides for the grantinggrant of stock awards, stock options, dividend equivalents, cash awards and substitute awards to directors, officers and employees of the Company, as well as stock awards to directors of the Company. The number of shares available for grant pursuant to awards under the LTIP as of March 31, 2022 are as follows:
March 31,
| |||||
Approved and authorized awards | |||||
Awards | ( | ) | |||
Awards available for future grant | |||||
Stock Options. Stock optionsoption awards were granted to employees on August 24, 2020. 2020 and November 4, 2021. Stock-based compensation expense related to the Company’s stock optionsoption awards for the three months ended March 31, 2021 2022 and 20202021 was $966,000$525,000 and zero,$966,000, respectively, and as of March 31, 2021 2022 and December 31, 2020 2021 there was $2.9$1.3 million and $3.8$1.8 million, respectively, of unrecognized stock-based compensation expense related to unvested stock-based compensationstock option awards. The unrecognized compensation expense will be recognized on a straight-line basis over the remaining vesting periods of the awards, which is a period of less than two years.
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 either an index of exploration and production crude oil and natural gas companies or on a peer group of companies with similar characteristics of the Company on the date of grant since the Company had minimal or did not have any trading history. More detailed stock options activity and details are as follows:
Stock Options | Exercise Price | Remaining Term in Years | Intrinsic Value (in thousands) | |||||||||||||
Outstanding at 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 Options | Exercise Price | Remaining Term in Years | Intrinsic Value (in thousands) | |||||||||||||
Outstanding at December 31, 2020 | 9,705,495 | $ | 10.00 | 9.7 | $ | 57,942 | ||||||||||
Awards granted | 442,500 | $ | 14.36 | |||||||||||||
Exercised | (154,268 | ) | $ | 10.00 | ||||||||||||
Forfeitures | (10,000 | ) | $ | 10.00 | ||||||||||||
Outstanding at December 31, 2021 | 9,983,727 | $ | 10.19 | 8.7 | $ | 44,395 | ||||||||||
Exercised | (7,500 | ) | $ | 10.00 | ||||||||||||
Outstanding at March 31, 2022 | 9,976,227 | $ | 10.19 | 7.8 | $ | 119,781 | ||||||||||
Vested at December 31, 2021 | 8,551,070 | $ | 10.13 | 8.7 | $ | 38,556 | ||||||||||
Exercisable at December 31, 2021 | 8,551,070 | $ | 10.13 | 8.7 | $ | 38,556 | ||||||||||
Vested at March 31, 2022 | 8,543,570 | $ | 10.13 | 7.8 | $ | 103,110 | ||||||||||
Exercisable at March 31, 2022 | 8,543,570 | $ | 10.13 | 7.8 | $ | 103,110 | ||||||||||
Restricted Stock Issued to Directors.Employee Members of the Board. StockA total of 1,500,500 shares of restricted stock was issuedapproved by the board of directors to be granted to certain employee members of the outside directorsboard of the Company on November 4, 2021, which vest on the three-year anniversary of such grant assuming the employees remain in November 2020 inhis or her position as of the amount of 12,500 shares for each outside director, totaling 62,500 shares. There were no restrictions of these shares.anniversary date. Therefore, stock-based compensation expense of $1.8 million was recognized immediately uponduring the issuance of these shares inthree months ended March 31, 2022 and the amount of $302,000remaining $18.6 million will be recognized over the remaining restricted period, which was based upon the closing price of the stock on the date of the restricted stock issuanceissuance. The Company also entered into contractual equity-based bonuses with certain non-director employees of the Company whereby they will be eligible for a cash bonus on the three-year anniversary of such contract equal to the product of a total of 600,000 shares of stock times the closing stock price on said anniversary assuming the employees remain in his or her position as of the anniversary date plus accrued dividends. Therefore, stock-based compensation expense of $1.4 million was recognized during the three months ended March 31, 2022, and the remaining $11.5 million based on the closing stock price as of March 31, 2022 of $22.20 per share will be recognized over the remaining life of the contract. Since these awards are not considered equity awards, but rather liability awards, this liability of $1.9 million and $488,000 is carried in other noncurrent liabilities on the accompanying balance sheet as of March 31, 2022 and December 31, 2021, respectively.
Stock Issued to Outside Directors. A total of 67,779 shares of restricted stock was approved by the board of directors to be granted to the outside directors of the Company.Company on June 1, 2021, which vested in January 2022. Therefore, the remaining stock-based compensation expense of $284,000 was recognized during the three months ended March 31, 2022, which was based upon the closing price of the stock on the date of the restricted stock issuance.
NOTE 9.10. Commitments and Contingencies
Leases. The Company adoptedfollows 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 adoptionaccount for its operating 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.finance leases. Therefore, as of March 31, 2021 and December 31, 2020 2022 the Company had operating right-of-use assets totaling $371,000 and $506,000, respectively,$715,000 included in other noncurrent assets and operating lease liabilities totaling $374,000 and $508,000, respectively, $322,000 and $430,000, respectively,$723,000, $493,000 of which are included in other current liabilities and $52,000$230,000 of which are included in other noncurrent liabilities, and $78,000, respectively,as of December 31, 2021 the Company had right-of-use assets totaling $852,000 included in other noncurrent assets and operating lease liabilities totaling $856,000, $513,000 of which are included in other current liabilities and $343,000 of which are included in other noncurrent liabilities on the accompanying 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 | March 31, 2022 | |||||||
Remainder of 2021 | $ | 328 | ||||||
2022 | 53 | |||||||
Remainder of 2022 | $ | 397 | ||||||
2023 | 349 | |||||||
Total lease payments | 381 | 746 | ||||||
Less present value discount | (7 | ) | (23 | ) | ||||
Present value of lease liabilities | $ | 374 | $ | 723 | ||||
Legal actions. From time to time, the Company may be a party to various proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings and claims will not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company records reserves for contingencies when information available indicates that a loss is probable, and the amount of the loss can be reasonably estimated.
Indemnifications. The Company has agreed to indemnify its directors, officers and certain employees and agents with respect to claims and damages arising from acts or omissions taken in such capacity, as well as with respect to certain litigation.
Environmental. Environmental expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Environmental expenditures that extend the life of the related property or mitigate or prevent future environmental contamination are capitalized. Liabilities for expenditures that will not qualify for capitalization are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability is fixed or reliably determinable. Environmental liabilities normally involve estimates that are subject to revision until settlement or remediation occurs.
Salt-Water Disposal Commitments.Salt-water disposal commitments. The Company has committed to deliver a total of 5.53.0 MMBbl of produced water for disposal with two different third-partya third-party salt-water disposal companies, including 2.5 MMBblcompany 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, 2022, the Company has delivered approximately 2.12.7 MMBbl and 1.7 MMBbl, respectively under the two agreements. Both agreements requireagreement. The agreement requires a payment for any volumes not delivered should the Company not perform under the agreements,agreement, indicating a remaining monetary commitment of approximately $760,000$114,000 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.2022.
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 | ||
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.
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 | |||
|
|
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 partner’s net profits and losses. Net income or loss and net gain or loss on investments of the Predecessor for the period are allocated among its partners in proportion to the relative capital contributions made to the Predecessor. The Predecessor realized a net loss of $80.8 million for the three months ended March 31, 2020.
Partner’s distributions.The proceeds distributable by the Predecessor (which shall include all proceeds attributable to the disposition of investments, net of expenses) is distributable in accordance with their respective Partnership Agreements.
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 | ||||||||||||||
|
|
Crude oil marketing contract.delivery commitments. In May 2021, the Company entered into a crude oil marketing contract with Lion as the purchaser and DKL Permian Gathering, LLC (“DKL”) as the gatherer and transporter. The contract includes the Company’s current and future crude oil production from its horizontal wells in Flat Top where DKL will construct ana crude oil gathering system and custody transfer meters to all the Company’s central tank batteries. The 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. For the period from October 1, 2021 to March 31, 2022, the Company has delivered approximately 15,141 Bopd under the contract. The remaining monetary commitment as of March 31, 2022, if the Company believes it will meetnever delivers any additional volumes under the minimum volume commitments based on the Company’s current gross production levels and the current Flat Top development plan.agreement, is approximately $23.6 million.
Natural gas purchasing replacement contract. In May 2021, the Company entered into a replacement natural gas purchase contract with WTG Gas Processing, L.P. (“WTG”) as the gatherer, processor and purchaser of the Company’s current and future gross natural gas production in Flat Top. The replacement contract provides the Company with improved natural gas and NGL pricing and requires WTG to expand its current low-pressure gathering system, which eliminates the need for in-field compression in Flat Top to accommodate the Company’s increased natural gas production volumes based on the current plan of development. In exchange for the improved pricing terms and expansion of the gathering system, theThe Company will provide WTG with certain aid-in-construction payments.payments to be reimbursed over time based on throughput through the system. The replacement contract does not contain any minimum volume commitments. Once
Power contracts. In June 2021, the Company entered into a contract with Priority Power Management, LLC (“Priority Power”) whereby Priority Power will develop an electric high-voltage (“EHV”) substation, medium voltage distribution systems and a 13-megawatt direct current solar photovoltaic facility located on approximately 80 acres of land owned by the Company north of Big Spring, Texas in Howard County to provide for the Company’s electrical power needs in its Flat Top operating area including powering drilling rigs and day-to-day operations. The EHV substation will be interconnected with the ERCOT transmission grid in May 2022 via the local electric utility, have an initial capacity of up to 50 megavolt amperes and be designed for future expansion capability. The solar generation facility will be interconnected with the medium voltage distribution system that will be energized from the new EHV substation. Priority Power will develop, finance, engineer, construct, operate and maintain the project facilities.
Also in June 2021, the Company entered into a contract with Oncor Electric Delivery Company, LLC (“Oncor”) to construct certain facilities to deliver electricity to the aforementioned substation. In conjunction with this contract, the Company issued a $1.9 million letter of credit to Oncor until such time as the Company’s load meets or exceeds 12 megawatts as measured during any fifteen (15) minute interval on or before May 20, 2023.
Sand commitments.The Company is party to an agreement whereby it has agreed to purchase at least 600,000 tons of sand over a two-year period beginning at the commencement date of the sand mine being operational, which will be late in the expandedsecond quarter of 2022. There are stipulations in the agreement that reduce this commitment should we experience a downturn in oil prices. However, generally if the Company never takes delivery of any sand under the agreement, the monetary commitment as of March 31, 2022 is approximately $8.7 million.
NOTE 11. Related Party Transactions
Water Treatment. In September 2021, the Company entered into a contract with Pilot Exploration, Inc., (“Pilot”), whose President and CEO is an outside director of the Company, to deploy Pilot’s proprietary water treatment technology in the Company’s Flat Top area to treat up to 25,000 barrels of produced water per day such that it can be reused in the Company’s completion operations or sold to third parties for their completion operations. This contract was set to expire on March 1, 2022, however it was extended to July 1, 2022 based on the early results of the project. During the three months ended March 31, 2022, the Company paid $632,000 to Pilot for such services.
NOTE 12. Major Customers
Lion Oil Trading and Transportation, LLC (“Lion”) accounted for approximately 93% and 96% of the Company’s revenues during the three months ended March 31, 2022 and 2021, respectively. Based on the current demand for crude oil and natural gas gathering system will reduce flaring and the emissionavailability of greenhouse gases.other purchasers, management believes the loss of this major purchaser would not have a material adverse effect on our financial condition and results of operations because crude oil and natural gas are fungible products with well-established markets and numerous purchasers.
NOTE 13. Income Taxes
The Company’s income tax expense (benefit) attributable to income (loss) from operations consisted of the following (in thousands):
Three Months Ended March 31, | ||||||||
2022 | 2021 | |||||||
Current income tax expense (benefit): | ||||||||
Federal | $ | 0 |
| $ | 0 | |||
State | 0 |
| 0 | |||||
| Total current income tax expense (benefit) | 0 | 0 | ||||||
| Deferred income tax expense (benefit): | ||||||||
| Federal | (188 | ) | 1,115 | |||||
| State | (124 | ) | 0 | |||||
| Deferred income tax expense (benefit) | (312 | ) | 1,115 | |||||
| Total income tax expense (benefit) | $ | (312 | ) | $ | 1,115 | |||
The reconciliation between the income tax expense (benefit) 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, | ||||||||
2022 | 2021 | |||||||
Income tax expense (benefit) at U.S. federal statutory rate | $ | (3,533 | ) | $ | 1,230 | |||
Limited tax benefit due to stock-based compensation | 3,606 |
| (109 | ) | ||||
State deferred income taxes | (124 | ) | 0 |
| ||||
Other, net | (261 | ) | (6 | ) | ||||
| Income tax expense (benefit) | $ | (312 | ) | $ | 1,115 | |||
Effective income tax rate | 1.9 | % | 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, 2022 and December 31, 2021 (in thousands):
March 31, 2022 | December 31, 2021 | |||||||
Deferred tax assets: | ||||||||
Unrecognized derivative losses | $ | 12,329 | $ | 3,248 | ||||
Net operating loss carryforwards | 3,681 | 2,870 | ||||||
| Stock-based compensation | 1,357 | 4,373 | ||||||
Interest expense limitations | 968 | 0 | ||||||
Other | 293 | 31 | ||||||
Deferred tax assets | 18,628 | 10,522 | ||||||
Deferred tax liabilities: | ||||||||
Crude oil and natural gas properties, principally due to differences in basis and depreciation and the deduction of intangible drilling costs for tax purposes | (74,118 | ) | (66,324 | ) | ||||
Net deferred tax liabilities | $ | (55,490 | ) | $ | (55,802 | ) | ||
The effective income tax rate differs from the U.S. statutory rate of 21 percent primarily due to establishing a valuation allowance primarily related to stock-based compensation, deferred state income taxes and permanent differences between GAAP income and taxable income.
As required by ASC Topic 740, “Income Taxes,” (“ASC 740”) the Company uses reasonable judgments and makes estimates and assumptions related to evaluating the probability of uncertain tax positions. The Company bases its estimates and assumptions on the potential liability related to an assessment of whether the income tax position will “more likely than not” be sustained in an income tax audit. Based on that analysis, the Company believes the Company has not taken any material uncertain tax positions, and therefore has not recorded an income tax liability related to uncertain tax positions. However, if actual results materially differ, the Company’s effective income tax rate and cash flows could be affected in the period of discovery or resolution. The Company also reviews the estimates and assumptions used in evaluating the probability of realizing the future benefits of the Company’s deferred tax assets and records a valuation allowance when the Company believes that a portion or all the deferred tax assets may not be realized. If the Company is unable to realize the expected future benefits of its deferred tax assets, the Company is required to provide a valuation allowance. The Company uses its history and experience, overall profitability, future management plans, tax planning strategies, and current economic information to evaluate the amount of valuation allowance to record. As of March 31, 2022 and December 31, 2021, the Company had not recorded a valuation allowance for deferred tax assets arising from its operations because the Company believed they met the “more likely than not” criteria as defined by the recognition and measurement provisions of ASC 740. The Company reversed a portion of its deferred tax asset related to stock-based compensation based on the assumption that the tax deduction will be subject to IRC Section 162(m) limits when the stock options are exercised and the restricted stock vests. IRC Section 162(m) limits compensation deductions to $1.0 million per year for certain Company executives. This resulted in a $3.4 million reduction in the deferred tax asset and reduced the amount of income tax benefit realized during the three months ended March 31, 2022.
The Company is also subject to Texas Margin Tax. The Company realized no current Texas Margin Tax in the accompanying consolidated financial statements as we do not anticipate owing any Texas Margin Tax for 2022 or 2021. However, the Company has recognized a deferred Texas Margin Tax liability of $1.7 million and $1.8 million as of March 31, 2022 and December 31, 2021, respectively, in the accompanying consolidated financial statements.
NOTE 14. Earnings Per Share
The Company uses the two-class method of calculating earnings per share because certain of the Company’s stock-based awards qualify as participating securities.
The Company’s basic earnings per share attributable to common stockholders is computed as (i) net income as reported, (ii) less participating basic earnings (iii) divided by weighted average basic common shares outstanding. The Company’s diluted earnings per share attributable to common stockholders is computed as (i) basic earnings attributable to common stockholders, (ii) plus reallocation of participating earnings (iii) divided by weighted average diluted common shares outstanding.
The following table reconciles the Company’s earnings from operations and earnings attributable to common stockholders to the basic and diluted earnings used to determine the Company’s earnings per share amounts for the three months ended March 31, 2022 and 2021 under the two-class method (in thousands):
Three Months Ended March 31, | ||||||||
2022 | 2021 | |||||||
Net income as reported | $ | (16,510 | ) | $ | 4,744 | |||
Participating basic earnings (a) | (214 | ) | (336 | ) | ||||
Basic earnings attributable to common stockholders | (16,724 | ) | 4,408 | |||||
Reallocation of participating earnings | 0 | 2 | ||||||
Diluted net income attributable to common stockholders | $ | (16,724 | ) | $ | 4,410 | |||
Basic weighted average shares outstanding | 95,841 | 92,592 | ||||||
Dilutive warrants and unvested stock options | 0 | 1,404 | ||||||
Dilutive unvested restricted stock | 0 | 0 | ||||||
Diluted weighted average shares outstanding | 95,841 | 93,996 | ||||||
(a) | Certain unvested restricted stock awarded to outside directors represent participating securities because they participate in nonforfeitable dividends with the common equity holders of the Company. Vested stock options represent participating securities because they participate in dividend equivalents with the common equity holders of the Company. Participating earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Certain unvested restricted stock awarded to employee members of the board of directors do not represent participating securities because, while they participate in dividends with the common equity holders of the Company, the dividends associated with such unvested restricted stock are forfeitable in connection with the forfeitability of the underlying restricted stock. Unvested stock options do not represent participating securities because, while they participate in dividend equivalents with the common equity holders of the Company, the dividend equivalents associated with unvested stock options are forfeitable in connection with the forfeitability of the underlying stock options. |
The calculation for weighted average shares reflects shares outstanding over the reporting period based on the actual number of days the shares were outstanding.
NOTE 15. Stockholders’ Equity
Issuance of Common Stock. On March 25, 2022, the Company issued 6,960,000 shares of HighPeak Energy common stock related to the aforementioned crude oil and natural gas property acquisitions. The remaining 76,754 shares of HighPeak Energy common stock issued during the three months ended March 31, 2022 were the result of warrants and stock options being exercised.
Dividends and dividend equivalents. In January 2022, the board of directors of the Company approved a quarterly dividend of $0.025 per share of common stock outstanding which resulted in a total of $2.4 million in dividends being paid on February 25, 2022. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders and accrued a dividend equivalent per share to all unvested stock option holders payable upon vesting, which equates to a total payment of $214,000 in February 2022 and up to an additional $31,000 in August 2022, $2,000 in November 2022 and $2,000 in November 2023, assuming no forfeitures. In addition, the Company accrued an additional combined $53,000 in dividends on the restricted stock issued to management directors and equity-based bonus awards issued to non-director employees in November 2021 that will be payable upon vesting in November 2024.
Outstanding Securities. At March 31, 2022 and December 31, 2021, the Company had 103,810,939 and 96,774,185 shares of common stock outstanding, respectively, 9,422,741 and 9,500,166 warrants outstanding, respectively, with an exercise price of $11.50 per share that expire on August 21, 2025 and 10,209,300 and 10,209,300 CVRs outstanding, respectively, that give the holders a right to receive up to 2.125 shares of HighPeak Energy common stock per CVR to satisfy the Preferred Returns (with an equivalent number of shares of Company common stock held by HighPeak Energy, LP (“HighPeak I”) and HighPeak Energy II, LP (“HighPeak II”) being collectively forfeited in connection therewith). As such, HighPeak I and HighPeak II have placed a total of 21,694,763 shares of common stock of the Company in escrow.
NOTE 16. Subsequent Events
Hannathon Acquisition. In April 2022, the Company announced the signing of a purchase and sale agreement to acquire approximately 18,600 net acres from Hannathon Petroleum, LLC (“Hannathon”) and other non-operated working interest owners where HighPeak currently owns non-operated working interests in approximately 60% of the acquired gross acreage position. The acquired acreage position is largely contiguous to the Company’s existing Signal Peak area with significant existing production, cash flow and produced water handling infrastructure. Purchase consideration due to the sellers, subject to customary closing adjustments, is comprised of $255.0 million in cash and approximately 3.8 million shares of HighPeak Energy common stock. The cash consideration is anticipated to be funded through increased commitments under its Revolving Credit Facility and is expected to close early in the third quarter of 2022 and be accounted for as an asset acquisition.
Dividends and dividend equivalents. In April 2022, the board of directors of the Company declared a quarterly dividend of $0.025 per share of common stock outstanding which will result in a total of $2.6 million in dividends being paid on May 25, 2022. In addition, under the terms of the LTIP, the Company will pay a dividend equivalent per share to all vested stock option holders of $214,000 in May 2022 and will accrue a dividend equivalent per share to all unvested stock option holders which is payable upon vesting of up to an additional $31,000 in August 2022, $2,000 in November 2022 and $2,000 in November 2023, assuming no forfeitures. In addition, the Company will accrue an additional combined $53,000 in dividends on the restricted stock issued to management directors and equity-based bonus awards issued to non-director employees in November 2021 that will be payable upon vesting in November 2024.
Warrant exercises. Subsequent to March 31, 2022 through May 4, 2022, the Company has received an additional $6.9 million in proceeds from the exercise of 602,669 warrants and has issued 602,669 shares of HighPeak Energy common stock to the warrant holders as a result. In addition, the Company has issued an additional 290,465 shares of HighPeak Energy common stock as a result of a warrant holder completing a cashless exercise of 526,300 warrants. This brings the outstanding number of warrants to 8,293,772 subsequent to quarter end
Water treatment.In May 2022, the Company entered into a one-year agreement beginning on July 1, 2022 with Pilot, whose President and CEO is an outside director of the Company, to utilize Pilot’s proprietary water treatment technology in the Company’s Flat Top area to treat produced water such that it can be reused in the Company’s completion operations or sold to third parties for their completion operations. During the term of the agreement, the Company has agreed to a minimum volume commitment of 29.2 million barrels of produced water while maintaining the ability to bank excess produced water processed each month toward the minimum volume commitment. The monetary commitment, if the Company never delivers any produced water to be treated under the agreement, is approximately $6.0 million.
Stock-based compensation.On May 4, 2022, an additional 824,500 stock option awards were granted to employees of which 729,833 vest immediately and the remainder vest over the next two years. As such, stock-based compensation expense of $10.9 million will be recognized in future periods, $9.7 million and $10.2 million of which will be recognized during the second quarter of 2022 and the nine months ended December 31, 2022, respectively.
PART I. FINANCIAL INFORMATION
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with our historical consolidated and combined financial statements and related notes. This discussion contains certain “forward‑looking statements” reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. These forward-looking statements involve risks and uncertainties and actual results and the timing of events may differ materially from those contained in these forward‑looking statements due to a number of factors. Factors that could cause or contribute to such differences include, but are not limited to, market prices for crude oil, NGL and natural gas, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties. Please read “Cautionary Statement Regarding Forward‑Looking Statements.” We assume no obligation to update any of these forward‑looking statements, except as required by applicable law.
Overview
HighPeak Energy, Inc., a Delaware corporation, was formed in October 2019 solely for the purpose of combining the businesses of Pure and HPK LP, referred to herein as the “HighPeak business combination,” which was completed on August 21, 2020. HPK LP was formed in August 2019 for the purpose combining the assets of HighPeak I and HighPeak II into one entity. HighPeak I was formed in June 2014 for the purpose of acquiring, exploring and developing 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.
2019. The Company’s assets are located primarily in Howard County,and Borden Counties, Texas, which lieslie within the north easternnortheastern part of the crude oil-rich Midland Basin. As of March 31, 2021,2022, the assets consisted of two highly contiguous leasehold positions of approximately 58,45298,131 gross (50,635(72,820 net) acres, approximately 37%47% of which were held by production, with an average working interest of 87%74%. Our acreage is composed of two core areas, with the northern block named Flat Top to the north and Signal Peak to the southern block named Signal Peak. Approximately 97%south. We operate approximately 90% of the net acreage across the Company’s assets and approximately 90% of the net operated acreage provides for horizontal wells with lateral lengths of 10,000 feet or greater. For the three months ended March 31, 2021,2022, approximately 95%93% and 5%7% of productionsales volumes from the assets were attributable to liquids (both crude oil and NGL) and natural gas, respectively. As of March 31, 2021,2022, 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.five (5) rigs.
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 forAcquisitions
During the three months ended March 31, 2020 and2022, the Company for the three months ended March 31, 2021. At the Closingclosed on a series 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. Theacquisitions to acquire various crude oil and natural gas industry is cyclicalproperties contiguous to its Flat Top operating area in Borden and commodity prices are highly volatile. For example, duringHoward counties, consisting of approximately 10,200 net acres and associated producing properties, water system infrastructure and in-field fluid gathering pipelines. The company incurred $162.9 million in acquisition costs, including the period from January 1, 2018 through March 31, 2021, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a lowissuance of $16.70 to a high6,960,000 shares 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 undercommon stock valued at $156.6 million at closing. The acquisitions were accounted for as asset acquisitions and included 7 gross (4.4 net) producing horizontal wells and three vertical salt-water disposal wells and related water system infrastructure as well as approximately 40 gross proved undeveloped and probable horizontal drilling locations targeting the Revolving Credit Facility that is anticipated in the second quarter of 2021.Wolfcamp A.
Financial and Operating Performance
The Company's financial and operating performance for the three months ended March 31, 2021 and 20202022 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:
• | Net loss was $16.5 million (($0.17) per diluted share) for the three months ended March 31, 2022 compared with net income of $4.7 million for three months ended March 31, 2021. The primary components of the $21.2 million decrease 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;
• | a $66.4 million increase in the Company's net derivative loss as a result of its crude oil commodity contracts entered into during 2021 and the continued increase of crude oil prices thereafter; | |
• | a $7.2 million increase in lease operating expenses related primarily to the increased well count and production from the Company’s successful horizontal drilling program; | |
• | A $5.2 million increase in interest expense due to the issuance of two year 10.00% senior unsecured notes in February 2022, increased borrowings on the revolving credit facility early in the quarter and increased amortization of debt issuance costs and discounts; | |
• | a $4.1 million increase in DD&A expense due to a 128% increase in daily sales volumes, partially offset by a 42% decrease in the DD&A rate from $27.22 to $15.69 per Boe, both as a result of increased proved reserves due to the Company’s successful horizontal drilling program; | |
• | a $3.3 million increase in production and ad valorem taxes, primarily attributable to the 128% increase in daily sales volumes as a result of the Company’s successful horizontal drilling program combined with 32% higher production and ad valorem taxes on a dollar per Boe basis due to higher overall realized prices of 31%, excluding the effects of derivatives; | |
• | a $3.0 million increase in the Company's stock-based compensation expense primarily attributable to equity-based awards issued in late 2021; partially offset by: |
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 $66.5 million increase in crude oil, NGL and natural gas revenues due to a 128% increase in daily sales volumes resulting from the Company’s successful horizontal drilling program in addition to a 31% increase in average realized commodity prices per Boe, excluding the effects of derivatives; 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.
• | a $1.4 million decrease in the Company’s income tax expense due to the net loss realized during the three months ended March 31, 2022 compared with net income realized during the three months ended March 31, 2021 and the Company reversed a portion of its deferred tax asset related to stock-based compensation which resulted in a $3.4 million reduction in the deferred tax asset and reduced the amount of income tax benefit realized during the three months ended March 31, 2022. |
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.
• | During the three months ended March 31, 2022, average daily sales volumes totaled 12,052 Boe/d, compared with 5,290 Boe/d during the same period in 2021, an increase of 128% over the same period in 2021, due to the Company's successful horizontal drilling program and bolt-on acquisitions. |
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.
• | Weighted average realized crude oil prices per Bbl, excluding the effects of derivatives, increased during the three months ended March 31, 2022 to $96.15, compared with $58.36 for the same period in 2021. Weighted average NGL prices per Bbl increased during the three months ended March 31, 2022 to $41.33, compared with $27.82 for the same period in 2021. Weighted average natural gas prices per Mcf increased to $4.16 during the three months ended March 31, 2022, compared with $2.23 during the same period in 2021. |
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.
• | Cash provided by operating activities totaled $49.9 million for the three months ended March 31, 2022, compared with $11.4 million for the three months ended March 31, 2021. |
Recent Events
Senior Unsecured Notes. In February 2022, the Company issued $225.0 million of two year 10.00% senior unsecured notes (“Senior Notes”), netting proceeds of $210.2 million net of an originator discount. The proceeds were used to pay off the Revolving Credit Facility and to fund the Company’s 2022 capital drilling program.
Revolving Credit Facility. TheSimultaneous with the issuance of the Senior Notes, 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 beginThird Amendment to draw on the Revolving Credit Facility into, among other things, (i) reduce the second quarter of 2021 which currently has a $40.0 million borrowing base but only a $20.0from $195.0 million commitment atto $138.8 million and (ii) modify the Company’s election.terms of the Credit Agreement to reduce the aggregate elected commitments from $195.0 million to $138.8 million. In March 2021,connection with recently closed and recently announced acquisitions and the Company’sannual spring redetermination, the Company expects to expand its bank group and significantly increase the aggregate elected commitments and 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.on its Revolving Credit Facility.
Exercises of Warrants and Options.Acquisitions. During the three months ended March 31, 2021,2022, the Company received cashclosed on a series of $9.1 million relatedacquisitions to the exerciseacquire various crude oil and natural gas properties contiguous to its Flat Top operating area in Borden and Howard counties, consisting of 788,009 of its $11.50 warrantsapproximately 10,200 net acres and $1.6 million cash related to the exercise of 154,268 of stock options by employees of the Company.associated producing properties, water system infrastructure and in-field fluid gathering pipelines.
Crude oil marketing contract.Hannathon Acquisition. In May 2021,April 2022, the Company entered intoannounced the signing of a purchase and sale agreement to acquire approximately 18,600 net acres from Hannathon Petroleum, LLC (“Hannathon”) and other non-operated working interest owners where HighPeak currently owns non-operated working interests in approximately 60% of the acquired gross acreage position. The acquired acreage position is largely contiguous to the Company’s existing Signal Peak area with significant existing production that the Company expects to average approximately 5,000 Boepd for 2022, cash flow and produced water handling infrastructure. Purchase consideration due to the sellers, subject to customary closing adjustments, is comprised of $255.0 million in cash and approximately 3.8 million shares of HighPeak Energy common stock. The cash consideration is anticipated to be funded through increased commitments under its Revolving Credit Facility and is expected to close early in the third quarter of 2022.
Dividends and dividend equivalents. In January 2022, the board of directors of the Company approved a quarterly dividend of $0.025 per share of common stock outstanding which resulted in a total of $2.4 million in dividends being paid on February 25, 2022. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders and accrued a dividend equivalent per share to all unvested stock option holders payable upon vesting, which equates to a total payment of $214,000 in February 2022 and up to an additional $31,000 in August 2022, $2,000 in November 2022 and $2,000 in November 2023, assuming no forfeitures. In addition, the Company accrued an additional combined $53,000 in dividends on the restricted stock issued to management directors and equity-based bonus awards issued to non-director employees in November 2021 that will be payable upon vesting in November 2024.
Issuance of Common Stock. On March 25, 2022, the Company issued 6,960,000 shares of HighPeak Energy common stock related to one of the aforementioned crude oil marketing contract with Lion Oil Trading and Transportation, LLC (“Lion”) asnatural gas property acquisitions. The remaining 76,754 shares of HighPeak Energy common stock issued during the purchaserthree months ended March 31, 2022 were the result of warrants and DKL Permian Gathering, LLC (“DKL”) asstock options being exercised.
Production Curtailment and Subsequent Increase. During the gatherer and transporter. The contract includesfirst quarter of 2022, some of the Company’s currentproduction was curtailed due to offset frac operations near a considerable amount of its existing producing horizontal wells. As wells are being brought back online, production has continued to increase subsequent to quarter end averaging approximately 20,500 Boepd in April and future crude oilhas continued to increase thus far in May, setting up an expected significant increase in 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 yearsquarter 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. 2022.
COVID-19. The COVID-19 pandemic has negatively impacted the global economy, disrupted global supply chains and created significant volatility and disruption of financial and commodity markets. In addition, the pandemic has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities. As a result, there has been a significant reduction in demand for and prices of crude oil and natural gas, which has adversely affected our business. There continues to be uncertainty around the extent and duration of disruption, including any resurgence, and we expect that the longer the period of such disruption continues, the greater the adverse impact will be on our business. The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our results will depend on future developments, which are highly uncertain and cannot be predicted, including, but not limited to, the duration and spread of the outbreak, its severity, the actions taken by governmental authorities and third parties in response to the COVID-19 pandemic, its impact on the U.S. and world economies, the U.S. capital markets and market conditions, and how quickly and to what extent normal economic and operating conditions can resume.
Derivative Financial Instruments
Derivative financial instrument exposure. AtAs of March 31, 2021,2022, the Company was not a party to anythe following open derivative financial instruments.
| Remainder of 2022 | 2023 | |||||||||||||||||||||||||||
Second | Third | Fourth |
| First | Second |
| ||||||||||||||||||||||
| Total | Total | |||||||||||||||||||||||||||
Quarter | Quarter | Quarter | Quarter | Quarter | ||||||||||||||||||||||||
Crude Oil Price Swaps - WTI: | ||||||||||||||||||||||||||||
Volume (MBbls) | 1,039.8 | 456.4 | 487.4 | 1,983.6 | 441.0 | 200.2 | 641.2 | |||||||||||||||||||||
Price per Bbl | $ | 71.96 | $ | 75.15 | $ | 70.14 | $ | 72.25 | $ | 70.05 | $ | 57.22 | $ | 66.04 | ||||||||||||||
New commodity
The estimated fair value of the outstanding open derivative contracts. Subsequent tofinancial instruments as of March 31, 2021,2022 was $57.1 million which is included in current and noncurrent liabilities on the Company’s balance sheet as of March 31, 2022. During the three months ended March 31, 2022, the Company entered intorecognized a derivative contractsloss of $66.4 million, including a $41.6 million mark-to-market loss plus $24.8 million in payments related 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.monthly settlements.
Operations and Drilling Highlights
Average daily crude oil, NGL and natural gas sales volumes are as follows:
Three Months Ended March 31,
| ||||
Crude Oil (Bbls) | ||||
NGL (Bbls) | ||||
Natural Gas (Mcf) | ||||
Total (Boe) | ||||
The Company's liquids production was 9593 percent of total production on a Boe basis for the three months ended March 31, 2021.2022.
Costs incurred are as follows (in thousands):
Three Months Ended March 31, 2021 | Three Months Ended March 31, 2022 | |||||||
Unproved property acquisition costs | $ | 309 | $ | 36,790 | ||||
Proved acquisition costs | - | 126,158 | ||||||
Total acquisitions | 309 | 162,948 | ||||||
Development costs | 2,777 | 94,338 | ||||||
Exploration costs | 42,098 | 70,755 | ||||||
Total finding and development costs | 45,184 | 328,041 | ||||||
Asset retirement obligations | 154 | 775 | ||||||
Total costs incurred | $ | 45,338 | $ | 328,816 | ||||
The following table sets forth the total number of horizontal wells drilled and completed during the three months ended March 31, 2021:2022:
Three Months Ended March 31, 2021 | ||||||||||||||||||||||||||||||||
Drilled | Completed | Drilled | Completed | |||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||
Flat Top area | 4 | 4 | 6 | 5.2 | 21 | 16.8 | 19 | 15.0 | ||||||||||||||||||||||||
Signal Peak area | 2 | 1.4 | - | - | 5 | 4.3 | 1 | 1.0 | ||||||||||||||||||||||||
Total | 6 | 5.4 | 6 | 5.2 | 26 | 21.1 | 20 | 16.0 | ||||||||||||||||||||||||
The Company currently planswas running five (5) drilling rigs as of March 31, 2022 and two (2) frac fleets. We plan to operate one (1)run five (5) drilling rigrigs until we close the Hannathon acquisition in early third quarter 2022, at which time we expect to increase our activity to six (6) drilling rigs and an average of one (1)two (2) to three (3) frac fleet in the Permian Basin duringfleets for the remainder of 2021.the year. 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, 2021,2022, the Company successfully completed and placed on production sixnineteen (19) gross horizontal wells in the Flat Top area five (5) of which are in the Wolfcamp A and one (1) of which isgross horizontal well in the Lower Spraberry formations.Signal Peak area. The Company also completed drilling and placed in service one (1) salt-water disposal well in the Flat Top area. The Company had eight (8)twenty-seven (27) wells that had been drilled and were in various stages of completion as of March 31, 2021, five (5)2022, twenty-one (21) 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 onesix (6) of which 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, 2021,2022, the Company was in the process of drilling two (2)seven (7) horizontal wells in the Flat Top area one (1)and two (2) horizontal wells in the Wolfcamp A and one (1) in the Lower Spraberry formations.Signal Peak area.
Results of Operations
Factors Affecting the Comparability of the Predecessor Historical Financial Results
The comparability of the predecessor results of operations among the periods presented, and for future periods, is impacted by the following factors:
As a corporation, under the Code, HighPeak Energy is subject to U.S. federal income taxes at a statutory rate of 21% of pretax earnings. This is a significant change from the Predecessor’s historical results 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, 20202022
Crude Oil, NGL and natural gas revenues.
Average daily sales volumes are as follows:
Three Months Ended March 31, | ||||||||||||||||||||||||||||
2021 | 2020 | % Change | Three Months Ended March 31, | |||||||||||||||||||||||||
Successor | Predecessor | 2022 | 2021 | Change | % Change | |||||||||||||||||||||||
Oil (Bbls) | 4,735 | 1,220 | 288 | % | 10,047 | 4,735 | 5,312 | 112 | % | |||||||||||||||||||
NGL (Bbls) | 294 | 134 | 119 | % | 1,198 | 294 | 904 | 307 | % | |||||||||||||||||||
Natural Gas (Mcf) | 1,568 | 445 | 252 | % | 4,843 | 1,568 | 3,275 | 209 | % | |||||||||||||||||||
Total (Boe) | 5,290 | 1,428 | 270 | % | 12,052 | 5,290 | 6,762 | 128 | % | |||||||||||||||||||
The increase in average daily Boe sales volumes for the three months ended March 31, 2021,2022, compared with the same period in 20202021 was due to the Company's successful horizontal drilling program.program and bolt-on acquisitions.
The crude oil, NGL and natural gas prices that the Company reports are based on the market prices received for each commodity. The weighted average realized prices, excluding the effects of derivatives, are as follows:
Three Months Ended March 31, | ||||||||||||||||||||||||||||
2021 | 2020 | % Change | Three Months Ended March 31, | |||||||||||||||||||||||||
Successor | Predecessor | 2022 | 2021 | Change | % Change | |||||||||||||||||||||||
Oil per Bbl | $ | 58.36 | $ | 40.76 | 43 | % | $ | 96.15 | $ | 58.36 | $ | 37.79 | 65 | % | ||||||||||||||
NGL per Bbl | $ | 27.82 | $ | 12.29 | 126 | % | $ | 41.33 | $ | 27.82 | $ | 13.51 | 49 | % | ||||||||||||||
Natural Gas per Mcf | $ | 2.23 | $ | 0.07 | 3,086 | % | ||||||||||||||||||||||
Gas per Mcf | $ | 4.16 | $ | 2.23 | $ | 1.93 | 87 | % | ||||||||||||||||||||
Total per Boe | $ | 54.01 | $ | 35.58 | 52 | % | $ | 85.03 | $ | 54.01 | $ | 31.02 | 57 | % | ||||||||||||||
Crude Oil and natural gas production costs.
OilCrude 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 | )% | ||||||
Three Months Ended March 31, | ||||||||||||||||
2022 | 2021 | Change | % Change | |||||||||||||
Oil and natural gas production costs | $ | 9,446 | $ | 2,227 | $ | 7,219 | 324 | % | ||||||||
Oil and natural gas production costs per Boe | $ | 8.71 | $ | 4.68 | $ | 4.03 | 86 | % | ||||||||
The decreaseincrease in lease operating expensescrude oil and natural gas production costs can primarily be attributed to the completionCompany's successful horizontal drilling program bringing on a significant number of the Company’s water disposal system infrastructure that came online in January 2021 coupled with the decreased reliance on generatorsnewly completed producing wells, additional rentals and fuel for power generation and other cost reduction efforts implemented by the company in response to the downturnbolt-on acquisitions. The increase in crude oil pricesand natural gas production costs per Boe can be attributed to temporarily shutting in 2020a considerable amount of production early in the first quarter of 2022 for offset completion operations. However, operating expenses were not affected as a resultsignificantly by the shut-ins as the production volumes were. We anticipate this increase in operating costs per Boe to reverse beginning in the second quarter of 2022. Significant drivers to this decrease are associated with connecting wells and central tank batteries to the COVID-19 pandemic.electrical grid and removing rental power generators as well as increasing our daily production.
.
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 | % | ||||||
Three Months Ended March 31, | ||||||||||||||||
2022 | 2021 | Change | % Change | |||||||||||||
Production and ad valorem taxes | $ | 5,006 | $ | 1,664 | $ | 3,342 | 201 | % | ||||||||
In general, production taxes and ad valorem taxes are directly related to commodity production volumesales volumes and price changes; however, Texas ad valorem taxes are based upon an asset valuation assessed by the state as of January 1 of that particular year based on prior year commodity prices, whereas production taxes are based upon current year sales revenues at current commodity prices.
Production and ad valorem taxes per Boe are as follows:
Three Months Ended March 31, | ||||||||||||||||||||||||||||
2021 | 2020 | % Change | Three Months Ended March 31, | |||||||||||||||||||||||||
Successor | Predecessor | 2022 | 2021 | Change | % Change | |||||||||||||||||||||||
Production taxes per Boe | $ | 2.53 | $ | 1.67 | 51 | % | $ | 4.08 | $ | 2.53 | $ | 1.55 | 61 | % | ||||||||||||||
Ad valorem taxes per Boe | $ | 0.97 | $ | 0.70 | 39 | % | $ | 0.53 | $ | 0.97 | $ | (0.44 | ) | (45 | )% | |||||||||||||
The increase in production taxes per Boe for the three months ended March 31, 2021,2022, compared with the same period in 2020,2021, was primarily due to the 52%57% increase in realized prices. The increasedecrease in ad valorem taxes per Boe for the three months ended March 31, 2021,2022, compared with the same period in 2020,2021, was primarily duerelated to a large number ofthe new wells that have come on productioncame online during 2020 which did not incur ad2021. Ad valorem taxtaxes 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 valuationvaluations as of the wells on January 1 of a given year based on pricing data for the previous year. Therefore, a well does not incur any ad valorem taxes until the year following when it came on production.
Depletion, depreciationExploration and amortizationabandonments expense.
Depletion, depreciationExploration and amortization (“abandonment expense details are as follows (in thousands, except percentages):
Three Months Ended March 31, | ||||||||||||||||
2022 | 2021 | Change | % Change | |||||||||||||
Geologic and geophysical personnel costs | $ | 174 | $ | 142 | $ | 32 | 23 | % | ||||||||
Geologic and geophysical data costs | 35 | — | 35 | 100 | % | |||||||||||
Abandoned leasehold costs | — | 49 | (49 | ) | (100 | )% | ||||||||||
Exploration and abandonments expense | $ | 209 | $ | 191 | $ | 18 | 9 | % | ||||||||
DD&A”)&A expense.
DD&A expense and DD&A expense per Boe are as follows (in thousands, except percentages and per Boe amounts):
Three Months Ended March 31, | ||||||||||||||||||||||||||||
2021 | 2020 | % Change | Three Months Ended March 31, | |||||||||||||||||||||||||
Successor | Predecessor | 2022 | 2021 | Change | % Change | |||||||||||||||||||||||
DD&A expense | $ | 12,963 | $ | 3,356 | 286 | % | $ | 17,024 | $ | 12,963 | $ | 4,061 | 31 | % | ||||||||||||||
DD&A expense per Boe | $ | 27.22 | $ | 25.83 | 5 | % | $ | 15.69 | $ | 27.22 | $ | (11.53 | ) | (42 | )% | |||||||||||||
The increase in DD&A wasis primarily due to the increased production associated with our successful horizontal drilling program. Also,program and bolt-on acquisitions and the increasedecrease in DD&A per Boe was primarilyrate can be attributed to 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 .same.
General and administrative expense.
General and administrative expense and general and administrative expense per Boe as well as stock-based compensation expense are as follows (in thousands, except percentages and per Boe amounts):
Three Months Ended 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 | % | ||||||
Three Months Ended March 31, | ||||||||||||||||
2022 | 2021 | Change | % Change | |||||||||||||
General and administrative expense | $ | 1,940 | $ | 1,759 | $ | 181 | 10 | % | ||||||||
General and administrative expense per Boe | $ | 1.79 | $ | 3.69 | $ | (1.90 | ) | (51 | )% | |||||||
Stock-based compensation expense | $ | 3,976 | $ | 966 | $ | 3,010 | 312 | % | ||||||||
The decreaseincrease in general and administrative expense for the three months ended March 31, 2021, compared with the same period in 2020,2022 is primarily as a result of more general and administrative costs being allocated to drilling and completion operations and construction projects and producing properties due to increased activity and well count, no business combination charges in 2021, lower salaries and benefits related to the growth of the company. The decrease in the rate per Boe is the result of economies of scale and efficiencies gained as we bring additional wells on production due to 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.our successful horizontal drilling program.
The increase in noncash stock-based compensation expense is primarily due to stock options beingequity-based awards granted in late 2021.
Interest expense.
Three Months Ended March 31, | ||||||||||||||||
2022 | 2021 | Change | % Change | |||||||||||||
Interest expense on Senior Notes | $ | 2,813 | $ | — | $ | 2,813 | 100 | % | ||||||||
Interest expense on Revolving Credit Facility | 902 | 25 | 877 | 3,508 | % | |||||||||||
Amortization of discount | 893 | 29 | 864 | 2,979 | % | |||||||||||
Amortization of debt issuance costs | 644 | — | 644 | 100 | % | |||||||||||
| $ | 5,252 | $ | 54 | $ | 5,198 | 9,626 | % | |||||||||
The increase in interest expense can be attributed to officersthe fact that we entered into our Revolving Credit Facility in December 2020 and employees upon completionbegan drawing on it late in the second quarter of 2021. In addition, we issued $225.0 million of 10.00% senior unsecured notes in February 2022.
Derivative gain (loss), net.
Three Months Ended March 31, | ||||||||||||||||
2022 | 2021 | Change | % Change | |||||||||||||
Noncash derivative gain (loss), net | $ | (41,633 | ) | $ | — | $ | (41,633 | ) | 100 | % | ||||||
Cash payments on settled derivative instruments, net | (24,761 | ) | — | (24,761 | ) | 100 | % | |||||||||
Derivative gain (loss), net | $ | (66,394 | ) | $ | — | $ | (66,394 | ) | 100 | % | ||||||
The Company primarily utilizes commodity swap contracts, collar contracts, collar contracts with short puts and basis swap contracts to (i) reduce the business combination.effect of price volatility on the commodities the Company produces and sells or consumes, (ii) adhere to hedging obligations related to the senior unsecured notes and the Revolving Credit Facility, (iii) support the Company’s annual capital budget and expenditure plans and (iv) reduce commodity price risk associated with certain capital projects. The Company may also, from time to time, utilize interest rate contracts to reduce the effect of interest rate volatility on the Company’s indebtedness. The above mark-to-market loss and cash settlements relate to crude oil derivative swap contracts.
Income tax expense.
Three Months Ended March 31, | Three Months Ended March 31, | |||||||||||||||||||||||||||
2021 | 2020 | % Change | 2022 | 2021 | Change | % Change | ||||||||||||||||||||||
Successor | Predecessor | |||||||||||||||||||||||||||
Income tax expense | $ | 1,115 | $ | - | 100 | % | ||||||||||||||||||||||
Income tax expense (benefit) | $ | (312 | ) | $ | 1,115 | (1,427 | ) | (128 | )% | |||||||||||||||||||
Effective income tax rate | 19.0 | % | 0.0 | % | 100 | % | 1.9 | % | 19.0 | % | (17.1 | )% | (90 | )% | ||||||||||||||
The change in income tax expense during the three months ended March 31, 2021,2022, compared with the same period in 2020,2021, was due to the fact thatCompany realizing a net loss during the Predecessor was treated as a partnershipthree months ended March 31, 2022 compared with net income 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.three months ended March 31, 2021. The effective income tax rate differs from the statutory rate primarily due to a revision in the deferred tax asset related to certain stock-based compensation and permanent differences between GAAP income and taxable income. See Note 1213 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 ourunused borrowing capacity under its Revolving Credit Facility, (iv) on an opportunistic basis, issuances of debt or equity securities and (v) other sources, such as sales of nonstrategic assets.
In February 2022, the Company entered into the Third Amendment to the Revolving Credit facility simultaneous with the issuance of $225.0 million of two year 10.00% senior unsecured notes (“2024 Notes”) whereby it, among other things, (i) reduced the borrowing base from $195.0 million to $138.8 million and (ii) modified the terms of the Credit Agreement to reduce the aggregate elected commitments from $195.0 million to $138.8 million. As of March 31, 2021,2022, the Company had no outstandingzero in borrowings and approximately $20.0$136.8 million available to borrow under its Revolving Credit Facility. The Company also had unrestricted cash on hand of $9.6$35.9 million as of March 31, 2021.2022. In March 2021,connection with recently closed and recently announced acquisitions and the Company’sannual spring redetermination, the Company expects to expand its bank group and substantially increase the aggregate elected commitments and borrowing base and bank commitments under theon its Revolving Credit Facility were increased to $50.0 million, subject to finalization of customary documentation.Facility.
The Company's primary needs for cash are for (i) capital expenditures, (ii) acquisitions of crude oil and natural gas properties, (iii) payments of contractual obligations, and (iv) working capital obligations.obligations, and (v) general corporate purposes. Funding for these cash needs may be provided by any combination of the Company's sources of liquidity. Although the Company expects that its sources of funding will be adequate to fund its 20212022 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.
20212022 capital budget.The Company has set itsCompany’s revised capital budget for 2021 at2022 after the announcement of the Hannathon acquisition is expected to be in the range of approximately $115$790 to $125$860 million for drilling, completion, facilities and equipping crude oil wells plus $20$35 to $25$40 million for field infrastructure buildout and other costs. The revised 2022 capital budget excludes acquisitions, asset retirement obligations, geological and geophysical general and administrative expenses and corporate facilities. HighPeak Energy expects to fund its forecasted capital expenditures with cash on its balance sheet, cash generated by operations, and through borrowings under its Revolvingthe Credit Facility.Agreement, proceeds from the issuance and sale of the 2024 Notes and, depending on market circumstances, potential future debt or equity offerings. The Company's capital expenditures for the three months ended March 31, 20212022 were $45.2 million.$165.1 million, excluding acquisitions.
The budget above assumes that the Company will operate six (6) drilling rigs and an average of two (2) to three (3) frac fleets for the remainder of 2022. However, there are many factors and consequences beyond the Company's control, such as policies of the Biden Administration, economic downturn or potential recession, geo-political risks and additional actions by businesses, OPEC and other cooperating countries, and governments in response to the COVID-19 pandemic, that may have an impact on the Company’s future results and drilling plans. Given the dynamic nature of this situation, the Company is maintaining flexibility in its capital plan and will continue to evaluate drilling and completion activity on an economic basis, with future activity levels assessed monthly.
Capital resources. Cash flows from operating, investing and financing activities are summarized below (in thousands).
Three Months Ended March 31, | ||||||||||||||||||||||||||||
2021 | 2020 | % Change | Three Months Ended March 31, | |||||||||||||||||||||||||
Successor | Predecessor | 2022 | 2021 | Change | % Change | |||||||||||||||||||||||
Net cash provided by operating activities | $ | 11,373 | $ | 6,028 | 89 | % | $ | 49,947 | $ | 11,373 | $ | 38,574 | 339 | % | ||||||||||||||
Net cash used in investing activities | $ | (31,921 | ) | $ | (57,090 | ) | (44 | )% | $ | (150,899 | ) | $ | (31,921 | ) | $ | (118,978 | ) | 373 | % | |||||||||
Net cash provided by financing activities | $ | 10,634 | $ | 54,000 | (80 | )% | $ | 101,933 | $ | 10,634 | $ | 91,299 | 859 | % | ||||||||||||||
Operating activities. The increase in net cash flow provided by operating activities for the three months ended March 31, 2021,2022, compared with 2020,2021, was primarily related to higher revenues associated with increased production volumes as a result of our successful horizontal drilling program and bolt-on acquisitions and increased realized prices. 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 decreaseincrease in net cash used in investing activities for the three months ended March 31, 2021,2022, compared with 2020,2021, was primarily due to decreasesincreases in additions to crude oil and natural gas properties ascompared with the three months ended March 31, 2021, when the Company was running two rigs for a portion of the 2020 period compared withhad only one rig running compared with an average of four rigs running during the three months ended March 31, 2022, and increases in 2021 and decreases incash crude 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:
• | 2022: The Company received $210.2 million in net proceeds from the issuance of the 2024 Notes, borrowed $15.0 million on its Revolving Credit Facility and received $779,000 from the exercise of 67,719 of the Company’s $11.50 warrants and $75,000 from the exercise of 7,500 of stock options by employees of the Company. These cash inflows were partially offset by the Company paying $115.0 million to pay the balance of its Revolving Credit Facility off simultaneously with the issuance of the 2024 Notes and incurring $6.4 million of debt issuance costs primarily related to the 2024 Notes and $2.6 million in dividends and dividend equivalent payments. | |
• | 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. | |
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Contractual obligations. The Company's contractual obligations include leases (primarily related to contracted drilling rigs, equipment and office facilities), capital funding obligations, volume commitments, aid-in-construction obligations and other liabilities. Other joint owners in the properties operated by the Company could incur portions of the costs represented by these commitments.
Non-GAAP Financial Measures
EBITDAX represents net income (loss) before interest expense, interest and other income, income taxes, depletion, depreciation, and amortization, accretion of discount on asset retirement obligations, exploration and abandonment expense, non-cash stock-based compensation expense, derivative gains and losses net of settlements, gains and losses on divestitures and certain other items. EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. EBITDAX is a non-GAAP measure that we believe provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Credit Agreement based on EBITDAX ratios as further described in Note 7 of Notes to Consolidated Financial Statements included in “Item 1. Condensed Consolidated Financial Statements (Unaudited).” In addition, EBITDAX is widely used by professional research analysis and others in the valuation, comparison, and investment recommendations of companies in the crude oil and natural gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the EBITDAX amounts presented may not be comparable to similar metrics of other companies. Our Revolving Credit Facility provides a material source of liquidity for us. Under the terms of our Credit Agreement, if we failed to comply with the covenants that establish a maximum permitted ratio of total debt, as defined in the Credit Agreement, to EBITDAX, we would be in default, an event that would prevent us from borrowing under our Revolving Credit Facility and would therefore materially limit a significant source of our liquidity. In addition, if we are in default under our Revolving Credit Facility and are unable to obtain a waiver of that default from our lenders, lenders under that facility would be entitled to exercise all of their remedies for default.
The following table provides a reconciliation of our net income (loss) (GAAP) to EBITDAX (non-GAAP) for the periods presented (in thousands):
Three Months Ended March 31, | ||||||||
2022 | 2021 | |||||||
Net income (loss) | $ | (16,510 | ) | $ | 4,744 | |||
Interest expense | 5,252 | 54 | ||||||
Interest and other income | (250 | ) | (1 | ) | ||||
Income tax expense (benefit) | (312 | ) | 1,115 | |||||
Depletion, depreciation and amortization | 17,024 | 12,963 | ||||||
Accretion of discount | 54 | 35 | ||||||
Exploration and abandonment expense | 209 | 191 | ||||||
Stock-based compensation | 3,976 | 966 | ||||||
Derivative related noncash activity | 41,633 | — | ||||||
EBITDAX | $ | 51,076 | $ | 20,067 | ||||
New Accounting Pronouncements
Our historical condensed consolidated and combined financial statements and related notes to condensed consolidated and combined financial statements contain information that is pertinent to our management’s discussion and analysis of financial condition and results of operations. Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires that our management make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. However, the accounting principles used by us generally do not change our reported cash flows or liquidity. Interpretation of the existing rules must be done, and judgments made on how the specifics of a given rule apply to us.
In management’s opinion, the more significant reporting areas impacted by management’s judgments and estimates are the choice of accounting method for crude oil and natural gas activities, crude oil and natural gas reserve estimation, asset retirement obligations, impairment of long-lived assets, valuation of stock-based compensation, valuation of business combinations, accounting and valuation of nonmonetary transactions, litigation and environmental contingencies, valuation of financial derivative instruments, uncertain tax positions and income taxes.
Management’s judgments and estimates in all the areas listed above are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known.
There have been no material changes in our critical accounting policies and procedures during the three months ended March 31, 2021.2022. See our disclosure of critical accounting policies in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2020,2021, filed with the SEC on March 15, 2021.7, 2022.
New accounting pronouncements issued but not yet adopted. The effects of new accounting pronouncements are discussed in Note 2 of Notes to Condensed Consolidated and Combined Financial Statements included in "Item 1. Condensed Consolidated and Combined Financial Statements (Unaudited)."
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company’s major market risk exposure is the pricing it receives for its sales of crude oil, NGL and natural gas. Pricing for crude oil, NGL and natural gas has been volatile and unpredictable for several years, and HighPeak Energy expects this volatility to continue in the future.
During the period from January 1, 2018 through March 31, 2021,2022, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $16.70 to a high of $70.76,$108.26, 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$6.20. Excluding derivatives, a $1.00 per barrel increase (decrease) in the weighted average crude oil price for the three months ended March 31, 20212022 would have increased (decreased) the Company’s revenues by approximately $1.8$3.8 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$174,000 on an annualized basis.
Due to this volatility and obligations under the senior unsecured notes and the Revolving Credit Facility, the Company has begunbegan to use, commodity derivative instruments, such as swaps, collars puts and swaps,puts, to hedge price risk associated with a portion of anticipated production. These hedging instruments allow the Company to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in crude oil and natural gas prices and provide increased certainty of cash flows for its drilling program. These instruments provide only partial price protection against declines in crude oil and natural gas prices and may partially limit the Company’s potential gains from future increases in prices. The Company has entered into hedging arrangements to protect its capital expenditure budget and to protect its Revolving Credit Facility borrowing base. The Company does not enter into any commodity derivative instruments, including derivatives, for speculative or trading purposes.
The average forward prices based on March 31, 2022 market quotes were as follows:
Remainder of 2022 | Year Ending December 31, 2023 | |||||||
Average forward NYMEX crude oil price per Bbl | $ | 92.59 | $ | 83.59 | ||||
Average forward NYMEX natural gas price per MMBtu | $ | 5.76 | $ | 4.46 | ||||
The average forward prices based on May 12, 2022 market quotes were as follows:
Remainder of 2022 | Year Ending December 31, 2023 | |||||||
Average forward NYMEX crude oil price per Bbl | $ | 98.17 | $ | 86.92 | ||||
Average forward NYMEX natural gas price per MMBtu | $ | 7.82 | $ | 5.38 | ||||
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 toprimary concentration of credit risk are throughrisks is associated with (i) the collection of receivables resulting from the sale of crude oil and natural gas production due to the concentration of its crude oil and natural gas receivables with a few significant customers.customers and (ii) the risk of a counterparty’s failure to meet its obligations under derivative contracts with the Company. The inability or failure of the Company’s significant customers and/or counterparties to meet their obligations to the Company or their insolvency or liquidation may adversely affect the Company’s financial results.
The 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 customers and/or counterparties primarily by reviewing credit ratings, financial criteria and payment history. Where appropriate, the Company obtains assurances of payment, such as a guarantee by the parent company of the customer and/or counterparty or other credit support. The Company's crude oil and natural gas is sold to various purchasers who must be prequalified under the Company's credit risk policies and procedures. Historically, the Company's credit losses on crude oil, NGL and natural gas receivables have not been material.
The Company uses credit and other financial criteria to evaluate the credit standing of, and to select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, associated credit risk is mitigated by the Company's credit risk policies and procedures.
The Company 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, 20212022 that have materially affected or are reasonably likely to materially affect the Company’s internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
TheFrom time to time, the Company ismay be a party to various proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings and claims will not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future results of operations.
ITEM 1A. RISK FACTORS
In addition to the information set forth in this report, the risks that are discussed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2020,2021, 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. ThereExcept as set forth below, there has been no material change in the Company's risk factors that were described in the Company’s Annual Report on Form 10-K.
Risks Related to Our Business
Political instability or armed conflict in crude oil or natural gas producing regions, such as the ongoing war between Russia and Ukraine, could have a material adverse impact on our business, financial condition or future results.
Our business, financial condition and future results are subject to political and economic risks and uncertainties, including instability resulting from civil unrest, political demonstrations, mass strikes or armed conflict or other crises in oil or gas producing areas such as the ongoing war between Russia and Ukraine.
In late February 2022, Russian military forces commenced a military operation and invasion against Ukraine. The United States and other countries and certain international organizations have imposed broad-ranging economic sanctions on Russia and certain Russian individuals, banking entities and corporations as a response, and additional sanctions may be imposed in the future. The length, impact, and outcome of the ongoing war between Russia and Ukraine is highly unpredictable, which has created uncertainty for financial and commodity markets. While the Company does not have operations overseas, the conflict elevates the likelihood of supply chain disruptions, heightened volatility in oil and gas prices and negative effects on our ability to raise additional capital when required and could have a material adverse impact on our business, financial condition or future results.
These risks are not the only risks facing the Company. Additional risks and uncertainties not currently known to the Company or that it currently deems to be immaterial also may have a material adverse effect on the Company's business, financial condition or future results.
HIGHPEAK ENERGY, INC.
ITEM 6. EXHIBITS
Exhibit | |
Number | Description |
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3.1 | |
3.2 | |
4.1 | |
4.2 | |
4.3 | |
4.4 | |
10.1 | |
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_________________
* | Filed herewith. |
** | Furnished herewith. |
+ | Certain schedules, annexes or exhibits have been omitted pursuant to Item 601(a)(5) of Regulation S-K but will be furnished supplementally to the SEC upon request. |
HIGHPEAK ENERGY, INC.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned hereto duly authorized.
HIGHPEAK ENERGY, INC. | ||
May | By: | /s/ Steven Tholen |
Steven Tholen | ||
Chief Financial Officer | ||
May | By: | /s/ Keith Forbes |
Keith Forbes | ||
| ||
Vice President and Chief Accounting Officer | ||