10-Q 1 hpe20240331_10q.htm FORM 10-Q hpe20240331_10q.htm
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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, 2024

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: 001-39464

 


 

 

HighPeak Energy, Inc.

 
 

(Exact name of Registrant as specified in its

charter)

 

 


 

Delaware

84-3533602

(State or other jurisdiction of incorporation or

organization)

(I.R.S. Employer Identification

No.)

   

421 W. 3rd St., Suite 1000

76102

Fort Worth, Texas

(Zip Code)

(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 Common Stock

 

HPKEW

 

The Nasdaq Stock Market LLC

 


 

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

Yes ☒    No

 

 

 

 

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

Yes ☒    No

 

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

 

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

   

Emerging growth company

 

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

 

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

Yes     No

 

As of May 6, 2024, there were 127,855,429 shares of common stock, par value $0.0001 per share, issued and outstanding.

 

 

 

 

 

HIGHPEAK ENERGY, INC.

TABLE OF CONTENTS

 

 

Page

Definitions of Certain Terms and Conventions Used Herein

1

Cautionary Statement Concerning Forward-Looking Statements

5

PART I. FINANCIAL INFORMATION

Item 1.

Condensed Consolidated Financial Statements (Unaudited)

6

 

Condensed Consolidated Balance Sheets

6

 

Condensed Consolidated Statements of Operations

7

 

Condensed Consolidated Statements of Changes in Stockholders’ Equity

8

 

Condensed Consolidated Statements of Cash Flows

9

 

Notes to Condensed Consolidated Financial Statements

10

Item 2.

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

29

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

40

Item 4.

Controls and Procedures

41

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

41

Item 1A.

Risk Factors

41

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

42

Item 5.

Other Information

42

Item 6.

Exhibits

43

Signatures

 

44

 

 

 

 

 

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:

 

 

“10.000% Senior Notes” means the $225.0 million aggregate principal amount of our 10.000% Senior Notes due 2024, which were issued pursuant to an indenture in February 2022 and repaid in full in September 2023.

 

“10.625% Senior Notes” means the $250.0 million aggregate principal amount of our 10.625% Senior Notes due 2024, $225.0 million of which were issued pursuant to an indenture in November 2022 and $25.0 million of which were issued pursuant to an indenture in December 2022 and repaid in full in September 2023.

 

“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.

 

“ASC” means Accounting Standards Codification.

 

“ASU” means Accounting Standards Update.

 

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

 

“Bbl” means a standard barrel containing 42 United States gallons.

 

“Bcf” means one billion cubic feet.

 

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

 

“Boepd” means Boe per day.

 

“Bopd” means one barrel of crude oil per day.

 

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

 

“Collateral Agency Agreement” means the Company’s Collateral Agency Agreement, dated as of September 12, 2023, by and among HighPeak Energy, Inc., Texas Capital Bank, as collateral agent, Chambers Energy Management, LP, as term representative, Mercuria Energy Trading SA, as first-out representative prior to giving effect to that certain Collateral Agency Joinder – Additional First-Out Debt, dated as of November 1, 2023, and Fifth Third Bank, National Association as first-out representative after giving effect to that certain Collateral Agency Joinder – Additional First-Out Debt, dated as of November 1, 2023.

 

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

 

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

 

“Credit Agreement” means the Term Loan Credit Agreement and the Senior Credit Facility Agreement.

 

“DD&A” means depletion, depreciation and amortization.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

1

 

 

“Extension well” An extension well is a well drilled to extend the limits of a known reservoir.

 

“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 Senior Credit Facility Agreement, dated March 29, 2024, by and among HighPeak Energy, Inc., as borrower, Fifth Third Bank, National Association, as administrative agent, the guarantors party thereto and the lenders party thereto.

 

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

 

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

 

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

 

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

 

“HH” means Henry Hub, a distribution hub in Louisiana that serves as the delivery location for natural gas futures contracts on the NYMEX.

 

“HighPeak Energy” or the “Company” means HighPeak Energy, Inc. and its subsidiaries.

 

“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.

 

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

 

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

 

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

 

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

 

“MBbl” means one thousand Bbls.

 

“MBoe” means one thousand Boes.

 

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

 

“MMBbl” means one million Bbls.

 

“MMBtu” means one million Btus.

 

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

 

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

 

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

 

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

 

“NYMEX” means the New York Mercantile Exchange.

 

“OPEC” means the Organization of Petroleum Exporting Countries.

 

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

 

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

 

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

 

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

 

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

 

“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.

 

2

 

 

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

 

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

 

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

 

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

 

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

 

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

   

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

   

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

   

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

   

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

   

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

 

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

 

“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 or enhancing existing 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.

 

3

 

 

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

 

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

 

“SEC” means the United States Securities and Exchange Commission.

 

“Senior Credit Facility Agreement” means the Company’s Credit Agreement, dated as of November 1, 2023, among HighPeak Energy, Inc., as Borrower, Fifth Third Bank, National Association, as administrative agent and collateral agent, and the lenders party thereto.

 

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

 

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

 

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

 

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

 

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

 

“Term Loan Credit Agreement” means the Company’s Term Loan Credit Agreement, dated as of September 12, 2023, by and between HighPeak Energy, Inc., as borrower, Texas Capital Bank, as administrative agent, Chambers Energy Management, LP, as collateral agent, and the lenders from time-to-time 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.

 

“U.S.” means the United States.

 

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

 

“Wellbore” The hole drilled by the bit that is equipped for crude oil and 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 crude oil, natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.

 

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

 

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

 

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

 

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

 

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

 

4

 

 

Cautionary Statement Concerning Forward-Looking Statements

 

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

 

 

our ability to refinance or pay, when due, the principal of, interest or other amounts due in respect of our indebtedness;

 

our liquidity, cash flow and access to capital;

 

the supply and demand for and market prices of crude oil, NGL, natural gas and other products or services, and the associated impact of our hedging policies relating thereto;

 

capital expenditures and other contractual obligations, including our obligations under our Term Loan Credit Agreement and Senior Credit Facility Agreement;

 

the results of our ongoing strategic alternatives review process;

 

political instability or armed conflict in crude oil or natural gas producing regions, such as the ongoing war between Russia and Ukraine, the Israel-Hamas conflict and the Israel-Iran conflict;

 

volatility in the political, legal and regulatory environments ahead of the upcoming U.S. presidential election;

 

the integration of acquisitions;

 

the availability of capital resources;

 

production and reserve levels;

 

drilling and completion risks;

 

inflation rates and the impacts of associated monetary policy responses, including increased interest rates and resulting pressures on economic growth;

 

economic and competitive conditions;

 

the impacts of revising our drilling plan during the year transitioning to an increased or decreased rig count from time to time;

 

weather conditions;

 

epidemics or pandemics, including the effects of related public health concerns and the impact of continued actions taken by governmental authorities and other third parties in response to pandemics and their impact on commodity prices, supply and demand considerations, and storage capacity;

 

the availability of goods and services and supply chain issues;

 

legislative, regulatory or policy changes;

 

regulatory and related policy actions intended by federal, state and/or local governments to reduce fossil fuel use and associated carbon emissions, to drive the substitution of renewable forms of energy for crude oil and natural gas, which may over time reduce demand for crude oil, NGL and natural gas, including as a result of the Inflation Reduction Act of 2022 (“IRA 2022”) or otherwise;

 

our ability to predict and manage the effects of actions of OPEC and agreements to set and maintain production levels, including as a result of recent production cuts by OPEC;

 

cyber-attacks;

 

occurrence of property acquisitions or divestitures;

 

the securities or capital markets and our ability to access such markets on attractive terms or at all, and related risks such as general credit, liquidity, market and interest-rate risks; and

 

other factors disclosed under “Part I, Items 1 and 2. Business and Properties,” “Part I, Item 1A. Risk Factors,” “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk,” included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2023 filed with the SEC on March 6, 2024 (“Annual Report”) and this Quarterly Report, under “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Part II, Item 1A. Risk Factors” and “Part I, Item 3. Quantitative and Qualitative Disclosures about Market Risk.”

 

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.

 

5

 

 

 

PART I. FINANCIAL INFORMATION

 

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

HighPeak Energy, Inc.

Condensed Consolidated Balance Sheets

(in thousands, except share data)

 

   

March 31,

2024

   

December 31,

2023

 
   

(Unaudited)

         

ASSETS

               

Current assets:

               

Cash and cash equivalents

  $ 173,380     $ 194,515  

Accounts receivable

    109,005       94,589  

Inventory

    11,179       7,254  

Prepaid expenses

    2,772       995  

Derivative instruments

    2,639       31,480  

Total current assets

    298,975       328,833  

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

               

Proved properties

    3,487,622       3,338,107  

Unproved properties

    72,997       72,715  

Accumulated depletion, depreciation and amortization

    (814,961

)

    (684,179

)

Total crude oil and natural gas properties, net

    2,745,658       2,726,643  

Other property and equipment, net

    3,563       3,572  

Derivative instruments

    1,380       16,059  

Other noncurrent assets

    5,116       5,684  

Total assets

  $ 3,054,692     $ 3,080,791  

LIABILITIES AND STOCKHOLDERS EQUITY

               

Current liabilities:

               

Current maturities of long-term debt

  $ 120,000     $ 120,000  

Accrued capital expenditures

    49,232       39,231  

Accounts payable – trade

    47,273       63,583  

Revenues and royalties payable

    29,344       29,724  

Other accrued liabilities

    19,580       19,613  

Derivative instruments

    16,440       13,054  

Advances from joint interest owners

    4,845       262  

Accrued interest

    847       1,398  

Operating leases

    400       528  

Total current liabilities

    287,961       287,393  

Noncurrent liabilities:

               

Long-term debt, net

    1,004,798       1,030,299  

Deferred income taxes

    198,757       197,068  

Asset retirement obligations

    13,685       13,245  

Derivative instruments

    1,054       65  

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, 2024 and December 31, 2023

           

Common stock, $0.0001 par value, 600,000,000 shares authorized, 127,855,383 and 128,420,923 shares issued and outstanding at March 31, 2024 and December 31, 2023, respectively

    13       13  

Additional paid-in capital

    1,184,371       1,189,424  

Retained earnings

    364,053       363,284  

Total stockholders’ equity

    1,548,437       1,552,721  

Total liabilities and stockholders equity

  $ 3,054,692     $ 3,080,791  

 

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

 

6

 

 

 

HighPeak Energy, Inc.

Condensed Consolidated Statements of Operations

(in thousands, except per share data)

(Unaudited)

 

   

Three Months Ended March 31,

 
   

2024

   

2023

 

Operating Revenues:

               

Crude oil sales

  $ 282,369     $ 215,696  

NGL and natural gas sales

    5,395       8,098  

Total operating revenues

    287,764       223,794  

Operating Costs and Expenses:

               

Crude oil and natural gas production

    30,271       32,942  

Production and ad valorem taxes

    14,402       12,297  

Exploration and abandonments

    498       2,164  

Depletion, depreciation and amortization

    130,850       81,131  

Accretion of discount

    239       118  

General and administrative

    4,685       2,502  

Stock-based compensation

    3,798       4,054  

Total operating costs and expenses

    184,743       135,208  

Other expense

    1        

Income from operations

    103,020       88,586  

Interest income

    2,392       30  

Interest expense

    (43,634

)

    (26,972

)

Gain (loss) on derivative instruments, net

    (53,043

)

    3,120  

Income before income taxes

    8,735       64,764  

Provision for income taxes

    2,297       14,507  

Net income

  $ 6,438     $ 50,257  

Earnings per share:

               

Basic net income

  $ 0.05     $ 0.41  

Diluted net income

  $ 0.05     $ 0.39  
                 

Weighted average shares outstanding:

               

Basic

    125,696       111,055  

Diluted

    129,641       117,765  
                 

Dividends declared per share

  $ 0.040     $ 0.025  

 

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

 

7

 

 

 

HighPeak Energy, Inc.

Condensed Consolidated Statements of Changes in Stockholders' Equity

(in thousands)

(Unaudited)

 

Three Months Ended March 31, 2024

                         
   

Shares

Outstanding

   

Common

Stock

   

Additional

Paid-in-Capital

   

Retained

Earnings

   

Total

Stockholders' Equity

 

Balance, December 31, 2023

    128,421     $ 13     $ 1,189,424     $ 363,284     $ 1,552,721  

Dividends declared ($0.04 per share)

                      (5,137

)

    (5,137

)

Dividend equivalents declared on outstanding stock options ($0.04 per share)

                      (532

)

    (532

)

Repurchased shares under buyback program

    (566 )           (8,851 )           (8,851 )

Exercise of warrants

                             

Stock-based compensation costs:

                                       

Shares issued upon options being exercised

                             

Compensation costs included in net income

                3,798             3,798  

Net income

                      6,438       6,438  

Balance, March 31, 2024

    127,855     $ 13     $ 1,184,371     $ 364,053     $ 1,548,437  

 

Three Months Ended March 31, 2023

                         
   

Shares

Outstanding

   

Common

Stock

   

Additional

Paid-in-Capital

   

Retained Earnings

   

Total

Stockholders' Equity

 

Balance, December 31, 2022

    113,165     $ 11     $ 1,008,896     $ 160,740    

$

1,169,647  

Dividends declared ($0.025 per share)

                      (2,829

)

    (2,829

)

Dividend equivalents declared on outstanding stock options ($0.025 per share)

                      (288

)

    (288

)

Exercise of warrants

                2             2  

Stock-based compensation costs:

                                       

Shares issued upon options being exercised

    12             148             148  

Compensation costs included in net income

                4,054             4,054  

Net income

                      50,257       50,257  

Balance, March 31, 2023

    113,177     $ 11     $ 1,013,100     $ 207,880     $ 1,220,991  

 

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

 

8

 

 

 

HighPeak Energy, Inc.

Condensed Consolidated Statements of Cash Flows

(in thousands)

(Unaudited)

 

   

Three Months Ended

March 31,

 
   

2024

   

2023

 

CASH FLOWS FROM OPERATING ACTIVITIES:

               

Net income

  $ 6,438     $ 50,257  

Adjustments to reconcile net income to net cash provided by operations:

               

Provision for deferred income taxes

    1,688       14,507  

Loss (gain) on derivative instruments, net

    53,043       (3,120 )

Cash paid on settlement of derivative instruments

    (5,148

)

    (2,194

)

Amortization of debt issuance costs

    2,053       2,668  

Amortization of discounts on long-term debt

    2,453       4,290  

Stock-based compensation expense

    3,798       4,054  

Accretion expense

    239       118  

Depletion, depreciation and amortization expense

    130,850       81,131  

Exploration and abandonment expense

    274       1,950  

Changes in operating assets and liabilities:

               

Accounts receivable

    (14,414

)

    15,617  

Prepaid expenses, inventory and other assets

    (4,722

)

    (2,567

)

Accounts payable, accrued liabilities and other current liabilities

    (5,113 )     23,295  

Net cash provided by operating activities

    171,439       190,006  

CASH FLOWS FROM INVESTING ACTIVITIES:

               

Additions to crude oil and natural gas properties

    (147,698

)

    (379,103

)

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

    1,705       65,062  

Acquisitions of crude oil and natural gas properties

    (2,171

)

    (5,463

)

Other property additions

    (59

)

    (18

)

Net cash used in investing activities

    (148,223

)

    (319,522

)

CASH FLOWS FROM FINANCING ACTIVITIES:

               

Repayments under Term Loan Credit Agreement

    (30,000 )      
Repurchased shares under buyback program     (8,764 )      
Dividends paid     (5,050 )     (2,776 )
Dividend equivalents paid     (530

)

    (282

)

Debt issuance costs     (7

)

    (544 )

Borrowings under Prior Credit Agreement

          150,000  

Proceeds from exercises of stock options

          148  

Proceeds from exercises of warrants

          2  

Net cash (used in) provided by financing activities

    (44,351

)

    146,548  

Net (decrease) increase in cash and cash equivalents

    (21,135

)

    17,032  

Cash and cash equivalents, beginning of period

    194,515       30,504  

Cash and cash equivalents, end of period

  $ 173,380     $ 47,536  
                 

Supplemental cash flow information:

               

Cash paid for interest

  $ 39,678     $ 18,078  

Cash paid for income taxes

           

Supplemental disclosure of non-cash transactions:

               

Additions to asset retirement obligations

    201       768  

 

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

 

9

 

 

HIGHPEAK ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

 

 

NOTE 1. Organization and Nature of Operations

 

HighPeak Energy, Inc. ("HighPeak Energy" or the "Company,") is a Delaware corporation, formed in October 2019. See the Company’s Annual Report on Form 10-K for the year ended December 31, 2023 , filed with the U.S. Securities and Exchange Commission (“SEC”) on March 6, 2024, for further information regarding the formation of the 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. 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 primarily in Howard and Borden Counties. Our acreage is composed of two core areas, Flat Top primarily in the northern portion of Howard County extending into southern Borden County, southwest Scurry County and northwest Mitchell County and Signal Peak in the southern 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 financial statements of the Company as of March 31, 2024 and for the three months ended March 31, 2024 and 2023 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, 2024 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 SEC. These unaudited interim condensed consolidated financial statements should be read together with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2023.

 

Principles of consolidation. The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries since their acquisition or formation. All material intercompany balances and transactions have been eliminated.

 

Use of estimates in the preparation of financial statements. Preparation of the Company's condensed consolidated 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 condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion of crude oil and natural gas properties is determined using estimates of proved crude oil, NGL and natural gas reserves and evaluations for impairment of proved and unproved crude oil and natural gas properties, in part, is determined using estimates of proved and risk adjusted 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, if needed, evaluations for impairment of proved 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. In addition, evaluations for impairment of unproved crude oil and natural gas properties on a project-by-project basis are also subject to numerous uncertainties including, among others, estimates of future recoverable reserves, results of exploration activities, commodity price outlooks, planned future sales or expirations of all or a portion of such projects. 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, expected credit losses 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.

 

10

 

 

Accounts receivable. As of March 31, 2024 and December 31, 2023, the Company’s accounts receivables primarily consist of amounts due from the sale of crude oil, NGL and natural gas of $99.4 million and $82.5 million, respectively, and are based on estimates of sales volumes and realized prices the Company anticipates it will receive, joint interest receivables of $6.4 million and $4.4 million, respectively, current U.S. federal income tax receivables of $2.8 million and $3.2 million, respectively, and receivables related to settlements of derivative contracts of $446,000 and $4.5 million, respectively. The Company’s share of crude oil, NGL and natural gas production is sold to various purchasers who must be prequalified under the Company’s credit risk policies and procedures. The Company’s credit risk related to collecting accounts receivables is mitigated by using credit and other financial criteria to evaluate the credit standing of the entity obligated to make payment on the accounts receivable, and where appropriate, the Company obtains assurances of payment, such as a guarantee by the parent company of the counterparty or other credit support.

 

Accounts receivable are stated at amounts due from purchasers or joint interest owners, net of an allowance for expected losses as estimated by the Company when collection is doubtful. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable from purchasers or joint interest owners outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance for each type of receivable by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for expected losses. As of March 31, 2024 and December 31, 2023, the Company had no allowance for credit losses related to accounts receivable.

 

Concentration of credit risk. The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with significant purchasers. For the three months ended March 31, 2024 and the year ended December 31, 2023, sales to the Company’s largest purchaser accounted for approximately 76% and 82%, respectively, and sales to the Company’s second largest purchaser accounted for approximately 17% and 14%, respectively, of the Company’s total crude oil, NGL and natural gas sales revenues. The Company generally does not require collateral and does not believe the loss of these particular purchasers 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.

 

Inventory. Inventory is comprised primarily of crude oil and natural gas drilling and completion or repair items such as pumps, tubing, casing, vessels, operating supplies and ordinary maintenance materials and parts. The materials and supplies inventory is primarily acquired for use in future drilling and completion 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, 2024 and December 31, 2023 is $11.2 million and $7.3 million, respectively, and the Company has not recognized any valuation allowance to date.

 

Prepaid expenses. Prepaid expenses are comprised primarily of caliche that will be used on future locations and roads in our development areas, fees related to strategic alternatives that will be deducted from eventual commissions on a future transaction, prepaid insurance costs that will be amortized over the life of the policies, tubulars and proppant that the Company has prepaid the suppliers to guarantee their availability when needed for our current drilling program and prepaid agency fees and software maintenance fees that will be amortized over the life of the contracts. Prepaid expenses as of March 31, 2024 and December 31, 2023 are $2.8 million and $1.0 million, respectively.

 

11

 

 

Crude oil and natural gas properties. The Company utilizes the successful efforts method of accounting for its crude oil and natural gas properties. Under this method, all costs associated with productive 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 condensed consolidated balance sheet following the completion of drilling unless both of the following conditions are met: (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

 

Due to the capital-intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather the Company’s ongoing efforts and expenditures related to accurately predict the hydrocarbon recoverability based on well information, gaining access to other companies’ production data in the area, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, the Company’s assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found sufficient proved reserves to sanction the project or is noncommercial and is charged to exploration and abandonment expense. See Note 6 for additional information.

 

The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves for leasehold costs and proved developed 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 are credited to proved or unproved crude oil and 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. If there is an indication the carrying value of the assets may not be recovered, an impairment loss is recognized 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 estimates of future recoverable reserves, 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 $935,000 and $904,000 as of March 31, 2024 and December 31, 2023, respectively, are as follows (in thousands):

 

   

March 31,

2024

   

December 31,

2023

 

Land

  $ 2,139     $ 2,139  

Transportation equipment

    688       689  

Buildings

    527       530  

Leasehold improvements

    205       209  

Field equipment

    3       4  

Furniture and fixtures

    1       1  

Total other property and equipment, net

  $ 3,563     $ 3,572  

 

Other property and equipment are depreciated over their estimated useful life on a straight-line basis. Land is not depreciated. Transportation equipment is generally depreciated over five years, buildings are generally depreciated over forty years, field equipment is generally depreciated over seven years and furniture and fixtures is generally depreciated over five years. Leasehold improvements are amortized over the lesser of their estimated useful lives or the underlying terms of the associated leases.

 

12

 

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, 2024 and December 31, 2023, the Company had aid-in-construction assets totaling $4.7 million and $5.2 million, respectively, included in other noncurrent assets. The Company has received and will continue to receive payments based on gross system throughput, including any third-party natural gas that is potentially tied into the Flat Top gathering system in the future. The contract calls for future aid-in-construction fundings if expansions of the system are necessary as determined in the sole discretion of the Company.

 

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 liabilities. See Note 10 for additional information.

 

Current liabilities. Current liabilities as of March 31, 2024 and December 31, 2023 totaled approximately $288.0 million and $287.4 million, respectively, including current maturities of long-term debt, trade accounts payable, accrued capital expenditures, revenues and royalties payable, derivative liabilities and accruals for operating and general and administrative expenses, interest expense, operating leases, dividends and dividend equivalents and other miscellaneous items.

 

Debt issuance costs and original issue discount. The Company has paid a total of $25.1 million in debt issuance costs, $7,000 and $28.4 million of which were incurred during the three months ended March 31, 2024 and the year ended December 31, 2023, respectively, primarily related to the completion of the Term Loan Credit Agreement and Senior Credit Facility Agreement and amendments to the Prior Credit Agreement. Amortization based on the straight-line method over the terms of the Term Loan Credit Agreement, Senior Credit Facility Agreement, Prior Credit Agreement, 10.000% Senior Notes and 10.625% Senior Notes which approximates the effective interest method was $2.1 million and $2.7 million during the three months ended March 31, 2024 and 2023, respectively. In addition, the Company realized a total of $64.8 million in original issue discounts on the issuance of its Term Loan Credit Agreement, 10.000% Senior Notes and 10.625% Senior Notes that is being amortized over the life of the agreements which approximates the effective interest method and was $2.5 million and $4.3 million during the three months ended March 31, 2024 and 2023, respectively. All unamortized debt issuance costs and discounts as of the termination of the Prior Credit Agreement and redemption of the 10.000% Senior Notes and 10.625% Senior Notes during September 2023 were charged to expense and included in loss on extinguishment of debt in the year ended December 31, 2023. See Note 7 for more information. As of March 31, 2024 and December 31, 2023, the remaining net debt issuance costs and discounts related to the Term Loan Credit Agreement are netted against the outstanding long-term debt on the accompanying condensed consolidated balance sheets.

 

Asset retirement obligations. The Company records a liability for the fair value of an asset retirement obligation in the period in which the associated asset is acquired or placed into service if a reasonable estimate of fair value can be made. Asset retirement obligations are generally capitalized as part of the carrying value of the long-lived asset to which it relates. Conditional asset retirement obligations meet the definition of liabilities and are recorded when incurred and when fair value can be reasonably estimated. See Note 8 for additional information.

 

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

 

The Company enters into contracts with purchasers to sell its crude oil, NGL and natural gas production. Revenue on these contracts is recognized in accordance with the five-step revenue recognition model prescribed in ASC 606. Specifically, revenue is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the crude oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under the crude oil and natural gas marketing contracts is typically received from the purchaser one to two months after the date of sale. As of March 31, 2024 and December 31, 2023, the Company had receivables related to contracts with purchasers of approximately $99.4 million and $82.5 million, respectively.

 

13

 

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 condensed consolidated statements of operations as they represent part of the transaction price of the contract.

 

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

 

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

 

Derivatives. All the Company’s derivatives are accounted for as non-hedge derivatives and are recorded at estimated fair value in the condensed consolidated balance sheets. All changes in the fair values of its derivative contracts are recorded as gains or losses in the earnings of the periods in which they occur. The Company enters into derivatives under master netting arrangements, which, in an event of default, allows the Company to offset payables to and receivables from the defaulting counterparty. The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net current or noncurrent derivative assets or net current 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 not established a valuation allowance as of March 31, 2024 or December 31, 2023.

 

Tax benefits from an uncertain tax positions are recognized only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. If all or a portion of the unrecognized tax benefit is sustained upon examination by the taxing authorities, the tax benefit will be recognized as a reduction to the Company’s deferred tax liability and will affect the Company’s effective tax rate in the period it is recognized. See Note 13 for additional information.

 

14

 

Tax-related interest charges are recorded as interest expense and any tax-related penalties as other expense in the condensed consolidated statements of operations of which there have been none to date.

 

The Company is also subject to Texas Margin Tax. The Company realized $223,000 and zero in current Texas Margin Tax during the three months ended March 31, 2024 and 2023, respectively, in the accompanying condensed consolidated financial statements.

 

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

 

Stock-based compensation for restricted stock awarded to outside directors, employee members of the Board and certain other employees is measured at the grant date using the fair value of the award and is recognized on a straight-line basis over the requisite service period of the respective award.

 

Segments. Based on the Company’s organizational structure, the Company has one 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.

 

Recently adopted accounting pronouncements. In June 2016, the FASB issued ASU 2016-13, “Financial Instruments – Credit Losses”. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investment in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. The Company adopted this update effective January 1, 2023. The adoption of this update did not have a material impact on the Company’s financial position, results of operations or liquidity since it does not have a history of credit losses.

 

New accounting pronouncements not yet adopted. In December 2023, the FASB issued ASU 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures,” which enhances the transparency and decision usefulness of income tax disclosures. The amendments address more transparency about income tax information through improvements to income tax disclosures primarily related to the rate reconciliation and income taxes paid information. The ASU also includes certain other amendments to improve the effectiveness of income tax disclosures. The amendments in this ASU are effective for public business entities for annual periods beginning after December 15, 2024 on a prospective basis. The Company is currently evaluating the impact of this standard on its disclosures.

 

In November 2023, the FASB issued ASU 2023-07, “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures.” This ASU updates reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses and information used to assess segment performance. The amendments in this ASU are effective for public entities for fiscal years beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024. The Company is currently evaluating the impact of this standard on its disclosures.

 

In March 2024, the SEC adopted new climate rules that require a wide range of climate-related disclosures, including material climate-related risks, information on climate-related targets or goals that are material to the registrant’s business, results of operations or financial condition, Scope 1 and Scope 2 greenhouse gas emissions on a phased-in basis by large accelerated filers and accelerated filers when those emissions are material and the filing of an attestation report covering the same, and disclosure of the financial statement effects of severe weather events and other natural conditions including costs and losses. Compliance dates under the final rule are phased in by registrant category. Multiple lawsuits have been filed challenging the SEC’s new climate rules, which have been consolidated and will be heard in the U.S. Court of Appeals for the Eighth Circuit. In April 2024, the SEC issued an order staying the final rules until judicial review is complete. The Company is currently evaluating the impact of the final rules on its disclosures.

 

The Company considers the applicability and the impact of all ASUs. ASUs were assessed and determined to be either not applicable, the effects of adoption are not expected to be material or are clarifications of ASUs previously disclosed.

 

15

 

 

 

NOTE 3. Acquisitions

 

During the three months ended March 31, 2024 and 2023, the Company incurred a total of $2.2 million and $5.5 million, respectively, in acquisition costs primarily to acquire crude oil and natural gas leases largely contiguous to its Flat Top and Signal Peak operating areas.

 

 

 

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. Assets and liabilities measured at fair value on a recurring basis as of March 31, 2024 and December 31, 2023 are as follows (in thousands):

 

   

As of March 31, 2024

 
   

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 – current

  $     $ 2,639     $     $ 2,639  

Commodity price derivatives – noncurrent

          1,380             1,380  

Total assets

          4,019             4,019  

Liabilities:

                               

Commodity price derivatives – current

          16,440             16,440  

Commodity price derivatives – noncurrent

          1,054             1,054  

Total liabilities

          17,494             17,494  

Total recurring fair value measurements, net

  $     $ (13,475

)

  $     $ (13,475

)

 

16

 

   

As of December 31, 2023

 
   

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 – current

  $     $ 31,480     $     $ 31,480  

Commodity price derivatives – noncurrent

          16,059             16,059  

Total assets

          47,539             47,539  

Liabilities:

                               

Commodity price derivatives – current

          13,054             13,054  

Commodity price derivatives – noncurrent

          65             65  

Total liabilities

          13,119             13,119  

Total recurring fair value measurements, net

  $     $ 34,420     $     $ 34,420  

 

Commodity price derivatives. The Company’s commodity price derivatives are currently made up of crude oil swap contracts, enhanced collars, deferred premium put options and basis swaps. The Company measures derivatives using an industry-standard pricing model that is provided by the counterparties. 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 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 and (iii) asset retirement obligations are measured at estimated fair value on the date the liabilities are incurred using Level 3 inputs based on expected future costs to retire the assets, market conditions and estimated lives of the assets. 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 financial statements.

 

Financial instruments not carried at fair value. As of March 31, 2024 and December 31, 2023, the Company had no financial instruments that are not carried at fair value in the consolidating balance sheets. The Company has other financial instruments consisting primarily of cash and cash equivalents, accounts receivable, accounts payable, long-term debt (specifically the Term Loan Credit Agreement and Senior Credit Facility Agreement), and other current assets and liabilities that approximate fair value due to the nature of the instrument and their relatively short maturities.

 

17

 

 

NOTE 5. Derivative Financial Instruments

 

The Company primarily utilizes commodity swap contracts, deferred premium put options and enhanced collars to (i) reduce the effect of price volatility on the commodities the Company produces and sells, (ii) support the Company’s capital budgeting and expenditure plans, (iii) protect the Company’s commitments under the Term Loan Credit Agreement and Senior Credit Facility Agreement and (iv) support the payment of contractual obligations.

 

The following table summarizes the effect of derivative instruments on the Company’s condensed consolidated statements of operations (in thousands):

 

   

Three Months Ended

March 31,

 
   

2024

   

2023

 
                 

Noncash gain (loss) on derivative instruments, net

  $ (47,895

)

  $ 5,314  

Cash paid on settlement of derivative instruments, net

    (5,148

)

    (2,194 )

Gain (loss) on derivative instruments, net

  $ (53,043

)

  $ 3,120  

 

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 Cushing and Argus WTI Midland crude oil prices. As such, the Company primarily uses NYMEX WTI Cushing derivative contracts as well as Argus WTI Midland basis swaps to manage future crude oil price volatility. The Argus WTI Midland basis differential represents the amount of premium to NYMEX WTI Cushing.

 

The Company’s outstanding NYMEX WTI Cushing and Argus WTI Midland crude oil derivative instruments as of March 31, 2024 and the weighted average crude oil prices and premiums payable per barrel for those contracts are as follows:

 

                       

Swaps

   

Enhanced Collars & Deferred

Premium Puts

 

Settlement

Month

 

Year

 

Type of

Contract

 

Bbls

Per

Day

   

Index

 

Price per

Bbl

   

Floor or

Strike

Price per

Bbl

   

Ceiling

Price per

Bbl

   

Deferred

Premium

Payable per

Bbl

 

Crude Oil:

                                                   

Apr – Jun

 

2024

 

Swap

    4,000    

WTI Cushing

  $ 84.00     $     $     $  

Apr – Jun

 

2024

 

Basis Swap

    25,000    

Argus WTI Midland

  $ 1.12     $     $     $  

Apr – Jun

 

2024

 

Collar

    5,500    

WTI Cushing

  $     $ 69.73     $ 95.00     $ 0.61  

Apr – Jun

 

2024

 

Put

    14,000    

WTI Cushing

  $     $ 60.41     $     $ 5.00  

Jul – Sep

 

2024

 

Swap

    4,000    

WTI Cushing

  $ 84.00     $     $     $  

Jul – Sep

 

2024

 

Basis Swap

    25,000    

Argus WTI Midland

  $ 1.12     $     $     $  

Jul – Sep

 

2024

 

Collar

    1,500    

WTI Cushing

  $     $ 69.00     $ 95.00     $ 0.85  

Jul – Sep

 

2024

 

Put

    14,000    

WTI Cushing

  $     $ 60.41     $     $ 5.00  

Oct – Dec

 

2024

 

Swap

    5,500    

WTI Cushing

  $ 76.37     $     $     $  

Oct – Dec

 

2024

 

Basis Swap

    25,000    

Argus WTI Midland

  $ 1.12     $     $     $  

Oct – Dec

 

2024

 

Collar

    10,600    

WTI Cushing

  $     $ 65.68     $ 90.32     $ 1.85  

Oct – Dec

 

2024

 

Put

    2,000    

WTI Cushing

  $     $ 58.00     $     $ 5.00  

Jan – Mar

 

2025

 

Swap

    5,500    

WTI Cushing

  $ 76.37     $     $     $  

Jan – Mar

 

2025

 

Collar

    8,000    

WTI Cushing

  $     $ 65.00     $ 90.00     $ 2.12  

Jan – Mar

 

2025

 

Put

    2,000    

WTI Cushing

  $     $ 58.00     $     $ 5.00  

Apr – Jun

 

2025

 

Swap

    5,500    

WTI Cushing

  $ 76.37     $     $     $  

Apr – Jun

 

2025

 

Collar

    7,000    

WTI Cushing

  $     $ 65.00     $ 90.08     $ 2.28  

Apr – Jun

 

2025

 

Put

    2,000    

WTI Cushing

  $     $ 58.00     $     $ 5.00  

Jul – Sep

 

2025

 

Swap

    3,000    

WTI Cushing

  $ 75.85     $     $     $  

Jul – Sep

 

2025

 

Collar

    7,000    

WTI Cushing

  $     $ 65.00     $ 90.08     $ 2.28  

Jul – Sep

 

2025

 

Put

    2,000    

WTI Cushing

  $     $ 58.00     $     $ 5.00  

 

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

 

18

 

Net derivative liabilities associated with the Company’s open commodity derivative instruments by counterparty are as follows (in thousands):

 

   

As of

March 31,

2024

 

Macquarie Bank Limited

  $ (11,413

)

Wells Fargo Bank, National Association

    (1,629

)

Mercuria Energy Trading SA

    (806

)

Fifth Third Bank, National Association

    373  
    $ (13,475

)

 

 

 

NOTE 6. Exploratory/Extension Well Costs

 

The Company capitalizes exploratory/extension wells 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/extension well and project costs are included in proved properties in the condensed consolidated balance sheets. If the exploratory/extension well or project is determined to be impaired, the impaired costs are charged to exploration and abandonments expense.

 

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

 

   

Three Months

Ended

March 31,

2024

 

Beginning capitalized exploratory/extension well costs

  $ 40,888  

Additions to exploratory/extension well costs

    25,818  

Reclassification to proved properties

    (41,299

)

Exploratory/extension well costs charged to exploration and abandonment expense

    (229 )

Ending capitalized exploratory/extension well costs

  $ 25,178  

 

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

 

 

 

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,

2024

   

December 31,

2023

 

Term Loan Credit Agreement due 2026

  $ 1,170,000     $ 1,200,000  

Senior Credit Facility Agreement due 2026

           

Discounts, net (a)

    (24,609 )     (27,062 )

Debt issuance costs, net (b)

    (20,593 )     (22,639 )

Total debt

    1,124,798       1,150,299  

Less current maturities of long-term debt

    (120,000

)

    (120,000

)

Long-term debt, net

  $ 1,004,798     $ 1,030,299  

 


 

(a)

Discounts as of March 31, 2024 and December 31, 2023 consisted of $30.0 million in discounts less accumulated amortization of $5.4 million and $2.9 million, respectively.

 

(b)

Debt issuance costs as of March 31, 2024 and December 31, 2023 consisted of $25.1 million and $25.0 million, respectively, in costs less accumulated amortization of $4.5 million and $2.4 million, respectively.

 

19

 

Term Loan Credit Agreement. On September 12, 2023, the Company entered into a Term Loan Credit Agreement with Texas Capital Bank (“Texas Capital”) as the administrative agent and Chambers Energy Management, LP (“Chambers”) as collateral agent and lenders from time-to-time party thereto to establish a term loan (“Term Loan Credit Agreement”) totaling $1.2 billion in borrowings, less a 2.5% original issue discount of $30.0 million at closing and customary debt issuance costs which totaled approximately $24.0 million. The Term Loan Credit Agreement matures on September 30, 2026. Loans under the Term Loan Credit Agreement bear interest at a rate per annum equal to the Adjusted Term SOFR (as defined in the Term Loan Credit Agreement) plus an applicable margin of 7.50%. To the extent that a payment default exists and is continuing, at the election of the Required Lenders (as defined in the Term Loan Credit Agreement) under the Term Loan Credit Agreement, all amounts outstanding under the Term Loan Credit Agreement will bear interest at 2.00% per annum above the rate and margin otherwise applicable thereto. The Company is able to repay any amounts borrowed prior to the maturity date, subject to a concurrent payment of (i) the Make-Whole Amount (as defined in the Term Loan Credit Agreement) for any optional prepayment prior to the date 18 months after the closing date, (ii) 1.00% of the principal amount being repaid for any optional prepayment on or after the date 18 months after the closing date but prior to the date 24 months after the closing date and (iii) without any premium for any optional prepayment on or after the date that is 24 months after the closing date. The Term Loan Credit Agreement is guaranteed by the Company and certain of its subsidiaries and is secured by a first lien security interest in substantially all assets of the Company and certain of its subsidiaries.

 

The Term Loan Credit Agreement also contains certain financial covenants, including (i) an asset coverage ratio that may not be less than 1.50 to 1.00 and (ii) a total net leverage ratio that may not exceed 2.00 to 1.00. Additionally, the Term Loan Credit Agreement contains additional restrictive covenants that limit the ability of the Company and its restricted subsidiaries to, among other things, incur additional indebtedness (with such exceptions including, among other things, a super priority revolving credit facility limited to $100 million), incur additional liens, make investments and loans, enter into mergers and acquisitions, materially increase dividends and other payments, enter into certain hedging transactions, sell assets, engage in transactions with affiliates and make certain capital expenditures based on the Company’s total net leverage ratio.

 

The Term Loan Credit Agreement contains customary mandatory prepayments, including quarterly installments of $30.0 million in aggregate principal amount which began March 31, 2024, the prepayment of gross proceeds from an incurred indebtedness other than Permitted Indebtedness (as defined in the Term Loan Credit Agreement), the prepayment of net cash proceeds for asset sales and hedge terminations in excess of $20.0 million within one calendar year, and prepayments of Excess Cash Flow (as defined in the Term Loan Credit Agreement) which began with the fiscal quarter ending March 31, 2024. In addition, the Term Loan Credit Agreement is subject to customary events of default, including a change in control. If an event of default occurs and is continuing, the collateral agent or the majority lenders may accelerate any amounts outstanding and terminate lender commitments.

 

Collateral Agency Agreement. On September 12, 2023, the Company entered into a collateral agency agreement (the “Collateral Agency Agreement”) among the Company, Texas Capital, as collateral agent, Chambers, as term representative, and Mercuria Energy Trading SA as first-out representative prior to giving effect to that certain Collateral Agency Joinder – Additional First-Out Debt, dated as of November 1, 2023 and Fifth Third Bank, National Association as first-out representative after giving effect to that certain Collateral Agency Joinder – Additional First-Out Debt, dated as of November 1, 2023.

 

The Collateral Agency Agreement provides for the appointment of Texas Capital, as collateral agent, for the present and future holders of the first lien obligations (including the obligations of the Company and certain of its subsidiaries under the Term Loan Credit Agreement) to receive, hold, administer and distribute the collateral that is at any time delivered to Texas Capital or the subject of the Security Documents (as defined in the Collateral Agency Agreement) and to enforce the Security Documents and all interests, rights, powers and remedies of Texas Capital with respect thereto or thereunder and the proceeds thereof.

 

Senior Credit Facility Agreement. On November 1, 2023, the Company entered into a credit agreement with Fifth Third Bank, National Association (“Fifth Third”) as the administrative agent and as the collateral agent and a number of banks included in the syndicate to establish a senior revolving credit facility (“Senior Credit Facility Agreement”) that matures on September 30, 2026. The Senior Credit Facility Agreement has aggregate maximum commitments of $100.0 million and effective March 29, 2024 pursuant to the First Amendment, current commitments of $100.0 million. Loans under the Senior Credit Facility Agreement bear interest at either the Adjusted Term SOFR (as defined in the Senior Credit Facility Agreement) or the Base Rate (as defined in the Senior Credit Facility Agreement) at the Company’s option, plus an applicable margin ranging (i) for Adjusted Term SOFR loans, from 4.00% to 5.00%, and (ii) for Base Rate loans, from 3.00% to 4.00%, in each case calculated based on the ratio at such time of the outstanding principal loan amounts to the aggregate amount of lenders’ commitments. To the extent that a payment default exists and is continuing, at the election of the Required Lenders (as defined in the Senior Credit Facility Agreement) under the Senior Credit Facility Agreement, all amounts outstanding under the Senior Credit Facility Agreement will bear interest at 2.00% per annum above the rate and margin otherwise applicable thereto. The Company is able to repay any amounts borrowed prior to the maturity date without premium or penalty. The Senior Credit Facility Agreement is guaranteed by the Company and certain of its subsidiaries and is secured by a first lien security interest in substantially all assets of the Company and certain of its subsidiaries.

 

20

 

Prior Credit Agreement. In December 2020, the Company entered into a Credit Agreement with Fifth Third as the administrative agent and sole lender to establish a revolving credit facility (the “Prior Credit Agreement”) that was set to mature on June 17, 2024. In March 2023, the Company entered into the Eighth Amendment to, among other things, (a) increase the borrowing base to $700.0 million, (b) add an aggregate elected commitments concept at an initial amount of $575.0 million, (c) provide that the applicable margin shall be determined in reference to such aggregate elected commitments (as opposed to being determined in reference to the borrowing base before giving effect to the Eighth Amendment), (d) modify the permitted dividends and distributions conditions such that minimum availability under the credit facility must be 25% of such aggregate elected commitments (as opposed to the borrowing base before giving effect to the Eighth Amendment), (e) permit quarterly dividends and distributions in an amount not to exceed $4.0 million provided that there is no default and that after giving effect thereto and any concurrent borrowing, the Company is in pro forma compliance with its financial covenants, (f) require the Company, on or before June 30, 2023, to redeem or refinance the 10.000% Senior Notes, allocate a portion of its cash flow that will retire the 10.000% Senior Notes on or before November 30, 2023 or amend the terms of the 10.000% Senior Notes to extend the scheduled repayment thereof to no earlier than February 15, 2025, (g) permit the redemption of Specified Additional Debt (defined in the Prior Credit Agreement to mean any unsecured senior, senior subordinated or subordinated Debt of the Borrower incurred after the Effective Date and any refinancing of such Debt, including without limitation, the 10.000% Senior Notes; provided that any such Debt may be refinanced only to the extent that the aggregate principal amount of such refinanced Debt does not result in an increase in the principal amount thereof plus amounts to fund any original issue discount or upfront fees relating thereto plus amounts to fund accrued interest, fees, expenses and premiums, with all Capitalized terms defined in such Prior Credit Agreement) with the proceeds of Loans if pre-approved by all Lenders provided that there is no default and that after giving effect thereto, the Company is in pro forma compliance with its financial covenants and (h) add Texas Capital Bank as a Lender.

 

In July 2023, the Company entered into the Ninth Amendment to, among other things, provide for (i) a waiver of the minimum current ratio covenant for the fiscal quarter ended June 30, 2023 under the Prior Credit Agreement, (ii) a waiver of the failure to subject one or more certain accounts to an Account Control Agreement within the period provided in the Prior Credit Agreement, (iii) a postponement of the April 2023 borrowing base redetermination until September 2023, (iv) a postponement of the date on which the Company was previously obligated thereunder to either extend the maturity of the 10.000% Senior Notes due February 2024, redeem or refinance the 10.000% Senior Notes or allocate a portion of the Company’s cash flow satisfactory to the Administrative Agent and the Majority Lenders that will retire the 10.000% Senior Notes on or before November 30, 2023 to September 1, 2023 or such later date as agreed to in writing by the Majority Lenders in their reasonable discretion, (v) certain pricing increases and additional minimum hedging requirements, (vi) an additional requirement to deliver a 13-week cash flow forecast on a weekly basis through completion of the September 2023 borrowing base redetermination and (vii) a temporary restriction on borrowing further amounts under the Prior Credit Agreement until the Company has received at least $95 million of net proceeds from the sales of the Company’s equity securities, which has been subsequently satisfied and the restriction no longer applies.

 

In connection with the entry into the aforementioned Term Loan Credit Agreement, the Prior Credit Agreement was terminated, all outstanding obligations for principal, interest and fees were paid off in full, and all liens securing such obligations and guarantees of such obligations and securing any letter of credit or hedging obligations (other than those novated pursuant to the terms of the Term Loan Credit Agreement) permitted by the Prior Credit Agreement to be secured by such liens were released. In addition, unamortized debt issuance costs as of the termination date of $2.7 million were charged to expense and included in loss on extinguishment of debt during the third quarter of 2023.

 

10.000% Senior Notes. In February 2022, the Company issued $225.0 million aggregate principal amount of its 10.000% Senior Notes due 2024 (“10.000% Senior Notes”), which were set to mature on February 15, 2024. The Company received proceeds of $202.9 million, net of $22.1 million of issuance costs and discounts. The net proceeds were used to pay down the balance of the Prior Credit Agreement to zero at closing and to fund our ongoing capital development program with subsequent draws on the Prior Credit Agreement. Interest on the 10.000% Senior Notes was payable on February 15 and August 15 of each year. In connection with the aforementioned Term Loan Credit Agreement, the 10.000% Senior Notes were redeemed at a redemption price of 100% of the principal amount thereof plus accrued and unpaid interest and fees. In addition, unamortized discounts and debt issuance costs as of the redemption date of $3.2 million and $1.5 million, respectively, were charged to expense and included in loss on extinguishment of debt during the third quarter of 2023.

 

10.625% Senior Notes. In November 2022 and December 2022, the Company issued $225.0 million and $25.0 million, respectively, under separate indentures, of its 10.625% Senior Notes due 2024 (“10.625% Senior Notes”), which were set to mature on November 15, 2024. The Company received proceeds of $223.7 million, net of $26.3 million of issuance costs and discounts. The net proceeds were used to reduce the outstanding balance of the Prior Credit Agreement at closing and for general corporate purposes. Interest on the 10.625% Senior Notes was payable on May 15 and November 15 of each year. In addition, the Company paid additional interest of $8.3 million in June 2023 in accordance with the indentures whereby if the Company did not receive a rating increase by June 30, 2023, it was required to pay said additional interest that is included in interest expense during the nine months ended September 30, 2023. In connection with the aforementioned Term Loan Credit Agreement, the 10.625% Senior Notes were redeemed at a redemption price of 100% of the principal amount thereof plus accrued and unpaid interest and fees, plus the applicable premium calculated as $4.5 million, which was the present value at September 14, 2023 of all required interest payments due on the 10.625% Senior Notes through November 15, 2023. In addition, unamortized discounts and debt issuance costs as of the redemption date of $11.7 million and $3.7 million, respectively, were charged to expense and included in loss on extinguishment of debt during the third quarter of 2023.

 

The Term Loan Credit Agreement and the Senior Credit Facility Agreement have hedging requirements to which the Company adheres.

 

21

 

 

 

NOTE 8. Asset Retirement Obligations

 

The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and remediation of 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,

2024

 

Beginning asset retirement obligations

  $ 13,245  

Liabilities incurred from new wells

    201  

Accretion of discount

    239  

Ending asset retirement obligations

  $ 13,685  

 

As of March 31, 2024 and December 31, 2023, all asset retirement obligations are considered noncurrent and classified as such in the accompanying condensed consolidated balance sheets.

 

 

 

NOTE 9. Incentive Plans

 

401(k) Plan. The HighPeak Energy Employees, Inc 401(k) Plan (the “401(k) Plan”) is a defined contribution plan established under Section 401 of the Internal Revenue Code of 1986, as amended (the “Code”). All regular full-time and part-time employees of the Company are eligible to participate in the 401(k) Plan after three continuous months of employment with the Company. Participants may contribute up to 80 percent of their annual base salary into the 401(k) Plan. Matching contributions are made to the 401(k) Plan in cash by the Company in amounts equal to 100 percent of a participant’s contributions to the 401(k) Plan up to four percent of the participant’s annual base salary (the “Matching Contribution”). Each participant’s account is credited with the participant’s contributions, Matching Contributions and allocations of the 401(k) Plan’s earnings. Participants are fully vested in their account balances at their eligibility date. During the three months ended March 31, 2024 and 2023, the Company contributed $201,000 and $81,000 to the 401(k) Plan, respectively.

 

Long-Term Incentive Plan. The Company’s Second Amended & Restated Long Term Incentive Plan (“LTIP”) provides for the grant of stock options, restricted stock, stock awards, dividend equivalents, cash awards and substitute awards to officers, employees, directors and consultants of the Company. The number of shares available for grant pursuant to awards under the LTIP as of March 31, 2024 and December 31, 2023 are as follows:

 

   

March 31,

2024

   

December 31,

2023

 

Approved and authorized shares

    16,414,015       16,414,015  

Shares subject to awards issued under plan

    (15,756,458

)

    (15,759,791

)

Shares available for future grant

    657,557       654,224  

 

Stock options. Stock option awards were granted to employees on August 24, 2020, November 4, 2021, May 4, 2022, August 15, 2022 and July 21, 2023. Stock-based compensation expense related to the Company’s stock option awards for the three months ended March 31, 2024 and 2023 was $52,000 and $314,000, respectively, and as of March 31, 2024 there was $49,000 of unrecognized stock-based compensation expense related to unvested stock option awards. The unrecognized compensation expense will be recognized on a straight-line basis over the remaining vesting periods of the awards, which is a period of less than one year. The 1,949,000 stock options granted in July 2023 were 100% vested upon grant on July 21, 2023. However, to encourage long-term alignment with the Company stockholders, the stock options are not exercisable until the earlier of (i) August 31, 2026, (ii) upon a change in control or (iii) upon the death or disability of the grantee.

 

22

 

 

The Company estimates the fair value 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

   

Average

Exercise

Price

   

Remaining

Term in

Years

   

Intrinsic

Value (in

thousands)

 

Outstanding at December 31, 2022

    11,517,228     $ 12.20       7.9     $ 128,429  

Awards granted

    1,949,000       10.50                  

Exercised

    (11,834

)

  $ 12.52                  

Forfeitures

    (5,333

)

  $ 24.83                  

Outstanding at December 31, 2023

    13,449,061     $ 11.95       6.3     $ 47,672  

Forfeitures

    (3,333 )   $ 29.67                  

Outstanding at March 31, 2024

    13,445,728     $ 11.95       6.1     $ 65,821  
                                 

Vested at December 31, 2023

    13,387,074     $ 11.88       6.3     $ 47,672  

Exercisable at December 31, 2023

    11,438,074     $ 12.12       6.9     $ 40,383  
                                 

Vested at March 31, 2024

    13,387,074     $ 11.88       6.1     $ 65,821  

Exercisable at March 31, 2024

    11,438,074     $ 12.12       6.7     $ 55,550  

 

Restricted stock issued to employee members of the Board and certain employees. A total of 1,500,500 shares of restricted stock was approved by the Board to be granted to certain employee members of the Board of the Company on November 4, 2021, which vest on the three -year anniversary of such grant assuming the employees remain in his or her position as of the anniversary date. Therefore, stock-based compensation expense of $1.8 million and $1.8 million was recognized during the three months ended March 31, 2024 and 2023, respectively, and the remaining $4.2 million as of March 31, 2024 will be recognized over the remaining restricted period, which was based upon the closing price of the stock on the date of the restricted stock issuance. The Board also approved a total of 600,000 shares of restricted stock to be granted to certain employees of the Company on June 1, 2022, which vest on November 4, 2024, assuming the employees remain in his or her position as of that date. Therefore, stock-based compensation expense of $1.8 million and $1.8 million was recognized during the three months ended March 31, 2024 and 2023, respectively, and the remaining $4.1 million as of March 31, 2024 will be recognized over the remaining restricted period, which was based upon the closing price of the stock on the date of the restricted stock issuance.

 

Stock issued to outside directors. A total of 58,767 shares of restricted stock was approved by the Board to be granted to the outside directors of the Company on June 1, 2023, which will vest at the next annual meeting, assuming the Board members maintain their positions on the Board. Therefore, stock-based compensation expense of $189,000 was recognized during the three months ended March 31, 2024 and the remaining $126,000 will be recognized during the second quarter of 2024, which was based upon the closing price of the stock on the date of the restricted stock issuance. In addition, a total of 21,184 shares of restricted stock was approved by the Board to be granted to the outside directors of the Company on June 1, 2022, which vested during the second quarter of 2023. Therefore, stock-based compensation expense of $183,000 was recognized during the three months ended March 31, 2023, which was based upon the closing price of the stock on the date of the restricted stock issuance.

 

 

 

NOTE 10. Commitments and Contingencies

 

Leases. The Company follows ASC Topic 842, “Leases” to account for its operating and finance leases. Therefore, as of March 31, 2024 the Company had right-of-use assets totaling $382,000 included in other noncurrent assets and operating lease liabilities totaling $400,000 included in current liabilities, and as of December 31, 2023 the Company had right-of-use assets totaling $510,000 included in other noncurrent assets and operating lease liabilities totaling $528,000 included in current 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,

2024

 

Remainder of 2024