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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


 

FORM 10-K

 


 

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

 

For the fiscal year ended December 31, 2023

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

Fort Worth, Texas 76102

(Address of principal executive offices and zip code)

 

(817) 850-9200

(Registrant's telephone number, including area code)

 

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

 

Title of each class

Trading Symbol

 

Name of each exchange on which registered

         

Common Stock, par value $0.0001 per share

HPK

 

The Nasdaq Stock Market LLC

Warrants to purchase Common Stock

HPKEW

 

The Nasdaq Stock Market LLC

 

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

 

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

 

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

 

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

 

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

 

 

 

 

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

 

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

   

Emerging growth company

 

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

 

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

 

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.

 

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

 

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

 

As of June 30, 2023, the aggregate market value of the common stock of the Registrant held by non-affiliates was $244,881,644 based on the closing price as reported on the Nasdaq Global Market of $10.88.

 

Number of shares of common stock outstanding as of February 29, 2024 – 128,420,923.

 

DOCUMENTS INCORPORATED BY REFERENCE:

 

(1)

Portions of the Definitive Proxy Statement for the Company’s Annual Meeting of Stockholders to be held in June 2024, which will be filed with the U.S. Securities and Exchange Commission within 120 days of December 31, 2023, are incorporated into Part III of this Annual Report on Form 10-K.

 

 

 

 

 

HIGHPEAK ENERGY, INC.

TABLE OF CONTENTS

 

   

Page

Definitions of Certain Terms and Conventions Used Herein

1

Cautionary Statement Concerning Forward-Looking Statements

6

PART I

Items 1 and 2.

Business and Properties

7

Item 1A.

Risk Factors

29

Item 1B.

Unresolved Staff Comments

60
Item 1C.  Cybersecurity 60

Item 3.

Legal Proceedings

60

Item 4.

Mine Safety Disclosures

60

PART II

Item 5.

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

61

Item 6.

Reserved

62

Item 7.

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

63

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

78

Item 8.

Financial Statements and Supplementary Data

79

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

108

Item 9A.

Controls and Procedures

108

Item 9B.

Other Information

108

Item 9C.

Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

108

PART III

Item 10.

Directors, Executive Officers and Corporate Governance

108

Item 11.

Executive Compensation

108

Item 12.

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

108

Item 13.

Certain Relationships and Related Transactions, and Director Independence

109

Item 14.

Principal Accountant Fees and Services

109

PART IV

Item 15.

Exhibits, Financial Statement Schedules

109

Item 16.

Form 10-K Summary

112

Signatures

113

 

 

 

 

 

HIGHPEAK ENERGY, INC.

 

Definitions of Certain Terms and Conventions Used Herein

 

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

 

 

“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.

 

1

 

 

 

“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.

 

“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.

 

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.

 

2

 

 

 

“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 HPK 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.

 

“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.

 

3

 

 

 

“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 having PUDs only if a development plan has been adopted indicating that such locations are scheduled to be drilled within five (5) years, unless specific circumstances justify a longer time.

 

“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.

 

“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.

 

4

 

 

 

“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 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.

 

5

 

 

Cautionary Statement Concerning Forward-Looking Statements

 

This Annual Report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included or incorporated by reference in this Annual 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 the 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 and the Israel-Hamas 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,” “Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk” and elsewhere in this Annual Report.

 

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

 

Additionally, we caution you that reserve engineering is a process of estimating underground accumulations of 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.

 

6

 

 

HIGHPEAK ENERGY, INC.

 

 

PART I

 

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

 

Overview

 

HighPeak Energy, Inc., a Delaware corporation formed on October 29, 2019, 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, Texas, and to a lesser extent Scurry and Mitchell Counties, which lie within the northeastern part of the crude oil-rich Midland Basin. 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.

 

HighPeak Energy focuses on the Midland Basin and specifically the Howard and Borden Counties area of the Midland Basin. Over the last eight decades the Howard and Borden Counties area of the Midland Basin was partially developed with vertical wells using conventional methods, and during the last decade has experienced significant redevelopment activity in the Lower Spraberry and Wolfcamp A formations utilizing modern horizontal drilling technology, with some operators having additional success developing the Middle Spraberry, Jo Mill, Wolfcamp B and Wolfcamp D formations, through the use of modern, high-intensity hydraulic fracturing techniques, decreased frac spacing, increased proppant usage and increased lateral lengths. Our interpretation of available IHS Markit data as well as our own drilling and completion results show that Howard and Borden Counties have a high crude oil mix percentage. 

 

The Company’s assets include certain rights, title and interests in crude oil and natural gas assets located primarily in Howard and Borden Counties, Texas, and to a lesser extent, Scurry and Mitchell Counties, Texas. As of December 31, 2023, the Company’s assets consisted of two generally contiguous leasehold positions of approximately 143,187 gross (131,636 net) acres covering various subsurface depths, approximately 64% of which were held by production, with an average working interest of approximately 92%. We operate approximately 98% of the net acreage across the Company’s assets. HighPeak Energy’s horizontal development drilling plan is currently focused on the Wolfcamp A and Lower Spraberry formations. We utilize multi-well pad development to lower drilling and completion cycle times and create infrastructure and facility economies of scale to reduce overall costs, optimize and maximize crude oil and natural gas recoveries, return on investment and value creation.

 

Available Information

 

The mailing address of HighPeak Energy’s principal executive office is 421 W. 3rd Street, Suite 1000, Fort Worth, Texas 76102. HighPeak Energy’s telephone number is (817) 850-9200. As of December 31, 2023, HighPeak Energy had forty-eight full-time employees.

 

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

 

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

 

HighPeak Energy’s common stock and warrants are listed on the Nasdaq Global Market (“Nasdaq”) under the symbols “HPK” and “HPKEW,” respectively.

 

Properties

 

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

 

7

 

 

HighPeak Energy developed its properties using up to six (6) drilling rigs and four (4) frac crews during the year ended December 31, 2023, ending the year using three (3) drilling rigs and one (1) frac crew.  The Company expects to average two (2) drilling rigs and one (1) frac crew during 2024 under our current development plan. HighPeak Energy expects to fund its forecasted capital expenditures with cash on its balance sheet and cash generated by operations.

 

 

HighPeak Energy has the discretion to modify its capital program. Because HighPeak Energy operates a high percentage of its acreage, capital expenditure amounts and timing are largely discretionary and within its control. HighPeak Energy determines its capital expenditures depending on a variety of factors, including, but not limited to, the success of its drilling activities, prevailing and anticipated prices for crude oil and natural gas, the availability of necessary equipment, infrastructure and capital, limitations on expenditures under certain leverage scenarios pursuant to the Term Loan Credit Agreement, the receipt and timing of required regulatory permits and approvals, drilling and acquisition costs and the level of participation by other working interest owners. A deferral of planned capital expenditures, particularly with respect to drilling and completing new wells, could result in a reduction in anticipated production and cash flows. Additionally, if HighPeak Energy curtails or reallocates priorities in its drilling program, HighPeak Energy may lose a portion of its acreage through lease expirations. However, in the event of any such curtailment or reallocation of priorities, HighPeak Energy would expect to prioritize lease retention to minimize any expirations.  Please see “Risk Factors—Risks Related to Our Business—Crude oil, NGL and natural gas prices are volatile. Sustained periods of low, or declines in, crude oil, NGL and natural gas prices could adversely affect HighPeak Energy’s business, financial condition and results of operations and its ability to meet its capital expenditure obligations and other financial commitments,” “Risk Factors—Risks Related to Our Business —HighPeak Energy’s development projects and acquisitions will require substantial capital expenditures. HighPeak Energy may be unable to obtain required capital or financing on satisfactory terms, including as a result of recent increases in cost of capital resulting from Federal Reserve policies or otherwise, which could reduce its ability to access or increase production and reserves” and “Risk Factors—Risks Related to Our Business—Certain of the undeveloped leasehold acreage of HighPeak Energy’s assets is subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are renewed.”

 

Reserve Summary

 

The estimated proved reserves of the Company’s assets as of December 31, 2023, 2022 and 2021 were prepared by Cawley, Gillespie and Associates, Inc. (“CG&A”). As of December 31, 2023, 2022 and 2021, the Company’s assets contained 154,162, 122,958 and 64,213 MBoe, respectively, of estimated proved reserves. In addition, as of December 31, 2023, 2022 and 2021, the estimated proved reserves of the Company’s assets were estimated by CG&A to be 91%, 92% and 92% crude oil and NGL, respectively, and 9%, 8% and 8% natural gas, respectively. The following table provides summary information regarding the estimated proved reserves data of the Company’s assets based on the 2023 Reserve Report, 2022 Reserve Report and 2021 Reserve Report (each defined below) as of December 31, 2023, 2022 and 2021, respectively:

 

As of Date

 

Proved Total

(MBoe)(1)

   

% Crude Oil &

NGL

   

%

Developed

 

December 31, 2023

    154,162       91

%

    52

%

December 31, 2022

    122,958       92

%

    50

%

December 31, 2021

    64,213       92

%

    45

%

 


(1)

The estimated net proved reserves were determined using the unweighted arithmetic average first-day-of-the month prices for the prior twelve (12) months in accordance with guidelines established by the SEC. As of December 31, 2023, 2022 and 2021, for crude oil and NGL volumes, this average WTI spot price of $78.22, $93.67 and $66.56 per barrel, respectively, was adjusted for quality, transportation and a regional price differential. As of December 31, 2023, 2022 and 2021, for natural gas volumes, the average HH spot price of $2.637, $6.358 and $3.598 per MMBtu, respectively, was adjusted for energy content, gathering, transportation and processing fees and a regional price differential. All prices are held constant throughout the lives of the properties. As of December 31, 2023, 2022 and 2021, the average adjusted prices realized over the remaining lives of the Company’s assets by CG&A were $78.13, $94.59 and $66.10 per barrel of crude oil, $17.33, $36.69 and $29.76 per barrel of NGL and $0.198, $4.871 and $0.786 per Mcf of natural gas, respectively.

 

8

 

 

Reserve Data

 

Preparation of Reserve Estimates

 

The reserve estimates as of December 31, 2023, 2022 and 2021 included in this Annual Report are based on evaluations prepared by CG&A in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC (individually, the “2023 Reserve Report,” the “2022 Reserve Report” and the “2021 Reserve Report” and, collectively the “Reserve Reports”). CG&A was selected for their historical experience and geographic expertise in engineering similar resources. The summary information pertaining to reserve estimates as of December 31, 2023, 2022 and 2021, respectively, of HighPeak Energy, prepared by CG&A, were led by W. Todd Brooker. Mr. Brooker is a Licensed Professional Engineer in the State of Texas and has been practicing at CG&A for 31 years and, including such 31 years, has over 33 years of total industry experience. Copies of the Reserve Reports are attached to this Annual Report as Exhibits 99.1, 99.2 and 99.3, respectively.

 

Proved reserves are those quantities of crude oil, NGL and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to EUR with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease. The technical and economic data used in the estimation of the proved reserves include, but are not limited to, well logs, geologic maps, well-test data, production data (including flow rates), well data (including lateral lengths), historical price and cost information, and property ownership interests. CG&A uses this technical data, together with standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy. The proved developed reserves and EURs per well are estimated using performance analysis, analogs and volumetric analysis. The estimates of the proved developed reserves and EURs for each developed well are used to estimate the proved undeveloped reserves for each proved undeveloped location (utilizing type curves, statistical analysis, and analogy).

 

Internal Controls

 

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

 

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

 

The reserve estimates as of December 31, 2023, 2022 and 2021, respectively, were prepared by geologists and reservoir engineers who integrate geological, geophysical, engineering and economic data to produce high quality reserve estimates and economic forecasts. The process was supervised by Christopher Mundy, Vice President, Reserves and Evaluations, for HighPeak Energy, who has approximately 27 years of experience in crude oil and natural gas operations, reservoir engineering and management, reserves management, unconventional and conventional reservoir characterization and strategic planning.

 

The reserve estimation process and the reserve estimates of the Company’s assets as of December 31, 2023, 2022 and 2021, respectively, were reviewed and approved by our technical staff, other members of senior management and our Chief Executive Officer. The Reserve Reports prepared by CG&A contain further discussion of the reserve estimates and the procedures used in connection with its preparation.

 

The reserve estimates as of December 31, 2023, 2022 and 2021, included in this Annual Report are based on evaluations prepared by the independent petroleum engineering firm CG&A representing 100% of the Company’s assets’ total net proved reserves in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. The Independent Reserve Engineers were selected for their historical experience and geographic expertise in engineering similar resources.

 

9

 

 

Estimated Proved Reserves

 

The following tables present the estimated net proved crude oil and natural gas reserves as of December 31, 2023, 2022 and 2021, based on the Reserve Reports of the Company’s assets as of such date.

 

   

Proved Reserve Volumes

 
   

Crude Oil

(MBbls)

   

NGL

(MBbls)

   

Natural Gas

(MMcf)

   

Total

(MBoe)

   

%

 

As of December 31, 2023:

                                       

Developed

    58,631       12,183       52,671       79,593       52

%

Undeveloped

    60,923       7,913       34,400       74,569       48

%

Total proved reserves

    119,554       20,096       87,071       154,162       100

%

As of December 31, 2022:

                                       

Developed

    47,845       7,968       32,669       61,258       50

%

Undeveloped

    50,971       6,401       25,969       61,700       50

%

Total proved reserves

    98,816       14,369       58,638       122,958       100

%

As of December 31, 2021:

                                       

Developed

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

%

Undeveloped

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

%

Total proved reserves

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

%

 

Development of Proved Undeveloped Reserves

 

The following table summarizes the changes in HighPeak Energy’s proved undeveloped reserves for the years ended December 31, 2021, 2022 and 2023:

 

   

Total (MBoe)

 

Proved undeveloped reserves at December 31, 2020

    12,233  

Extensions and discoveries

    26,806  

Sales of minerals-in-place

    (184

)

Conversions into proved developed reserves

    (3,186

)

Revisions

    (41

)

Proved undeveloped reserves at December 31, 2021

    35,628  

Extensions and discoveries

    37,394  

Purchases of minerals-in-place

    7,302  

Conversions into proved developed reserves

    (15,446

)

Revisions

    (3,178

)

Proved undeveloped reserves at December 31, 2022

    61,700  

Extensions and discoveries

    42,440  

Conversions into proved developed reserves

    (25,955

)

Sales of minerals-in-place

    (1,387

)

Revisions

    (2,229

)

Proved undeveloped reserves at December 31, 2023

    74,569  

 

10

 

 

As of December 31, 2023, HighPeak Energy’s assets contained approximately 74,569 MBoe of proved undeveloped reserves, consisting of 60,923 MBbl of crude oil, 7,913 MBbl of NGL and 34,400 MMcf of natural gas. As of December 31, 2022, HighPeak Energy’s assets contained approximately 61,700 MBoe of proved undeveloped reserves, consisting of 50,971 MBbl of crude oil, 6,401 MBbl of NGL and 25,969 MMcf of natural gas. As of December 31, 2021, HighPeak Energy’s assets contained approximately 35,628 MBoe of proved undeveloped reserves, consisting of 29,215 MBbl of crude oil, 3,838 MBbl of NGL and 15,450 MMcf of natural gas. Proved undeveloped reserves will be converted from undeveloped to developed as we drill and complete each location and the wells begin production.

 

Proved undeveloped reserves changed during the year ended December 31, 2023 primarily as a result of the following significant factors:

 

 

Extensions and discoveries of 42,440 MBoe related to new proved undeveloped locations added as a result of HighPeak Energy’s drilling activities;

 

Conversions into proved developed reserves of 25,955 MBoe related to locations that were successfully drilled and completed during the year ended December 31, 2023;

 

Sales of minerals-in-place of undeveloped reserves of 1,387 MBoe related to a farm out to another operator in return for a carried interest during the year ended December 31, 2023; and

 

Downward revisions of 2,229 MBoe including downward adjustments of approximately 1,748 MBoe related to forecasts, approximately 445 MBoe primarily attributable to a decrease in crude oil, NGL and natural gas prices and approximately 36 MBoe primarily related to increased forecasted operating expenses.

 

Proved undeveloped reserves changed during the year ended December 31, 2022 primarily as a result of the following significant factors:

 

 

Extensions and discoveries of 37,394 MBoe related to new proved undeveloped locations added as a result of HighPeak Energy’s drilling activities;

 

Purchases of minerals-in-place of 7,302 MBoe related to the acquisition of undeveloped drilling locations included;

 

Conversions into proved developed reserves of 15,446 MBoe related to locations that were successfully drilled and completed during the year ended December 31, 2022; and

 

Downward revisions of 3,178 MBoe including downward adjustments of approximately 3,636 MBoe related to forecasts and approximately 38 MBoe primarily related to increased forecasted operating expenses, partially offset by an increase of approximately 496 MBoe attributable to an increase in crude oil, NGL and natural gas prices.

 

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

 

 

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

 

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

 

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

 

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

 

Historically, the Company invested a significant amount of its capital budget to drill unproved locations rather than convert proved undeveloped reserves to proved developed reserves. However, in the years ended December 31, 2023 and 2022, $481.5 million and $391.3 million, respectively, of development capital expenditures were incurred primarily to convert proved undeveloped reserves to proved developed reserves, compared with $45.9 million in development capital expenditures in the year ended December 31, 2021.  Also, a portion of the Company’s development capital expenditures each year was for the continued development of a water infrastructure system and the drilling of salt-water disposal wells to facilitate the Company’s increased levels of produced water, reduce its future water sourcing costs by recycling produced water and reduce the use of trucking for its produced water disposal activities as well as the continued construction of central tank batteries for handling of the Company’s increasing production volumes.

 

As of December 31, 2023, all our proved undeveloped reserves are scheduled to be developed within five years from the date they were initially recorded.

 

11

 

 

PV-10

 

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

 

Unlike PV-10, the standardized measure deducts future U.S. federal income taxes and Texas margin taxes and abandonment obligations on wells with no proved reserves as of December 31, 2023, 2022 and 2021, respectively. Neither PV-10 nor standardized measure represents an estimate of the fair market value of the applicable crude oil and natural gas properties. It is industry standard to use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

 

The following tables present the undiscounted estimated future net cash flows, PV-10 and standardized measure of the proved reserves of the Company at December 31, 2023, 2022 and 2021 (in thousands):

 

As of December 31, 2023

 

Proved

Developed

   

Proved

Undeveloped

   

Total Proved

 

Estimated future net cash flows

  $ 3,205,041     $ 2,072,541     $ 5,277,582  

Present value of estimated future net cash flows

  $ 2,061,301     $ 822,766     $ 2,884,067  

Present value of future income taxes/abandonment costs

                    (276,363

)

Standardized measure

                  $ 2,607,704  

 

As of December 31, 2022

 

Proved

Developed

   

Proved

Undeveloped

   

Total Proved

 

Estimated future net cash flows

  $ 3,729,169     $ 3,160,098     $ 6,889,267  

Present value of estimated future net cash flows

  $ 2,319,958     $ 1,552,087     $ 3,872,045  

Present value of future income taxes/abandonment costs

                    (455,537

)

Standardized measure

                  $ 3,416,508  

 

As of December 31, 2021

 

Proved

Developed

   

Proved

Undeveloped

   

Total Proved

 

Estimated future net cash flows

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

Present value of estimated future net cash flows

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

Present value of future income taxes/abandonment costs

                    (219,384

)

Standardized measure

                  $ 1,118,809  

 

Estimated future net cash flows represents the estimated future revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using pricing differentials and costs under existing economic conditions as of December 31, 2023, 2022 and 2021, and assuming commodity prices as set forth below. For the purpose of determining prices used in our reserve reports, in accordance with SEC guidelines, CG&A uses the unweighted arithmetic average of the prices on the first day of each month in the 12-month period ended December 31, 2023, 2022 and 2021. These prices were $78.22, $93.67 and $66.56 per Bbl for crude oil and NGL and $2.637, $6.358 and $3.598 per MMBtu for natural gas, respectively, before adjustment for energy content, gathering, transportation and processing fees and basis differential adjustments. The average adjusted prices realized over the remaining lives of the Company’s assets by CG&A were $78.13, $94.59 and $66.10 per barrel of crude oil, $17.33, $36.69 and $29.76 per barrel of NGL and $0.198, $4.871 and $0.786 per Mcf of natural gas as of December 31, 2023, 2022 and 2021, respectively. These prices should not be interpreted as a prediction of future prices. The amounts shown do not give effect to non-property-related expenses, such as corporate general and administrative expenses and debt service, or to DD&A.

 

Production, Revenue and Price History

 

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

 

12

 

 

The following tables summarize the average net sales volumes, average unhedged sales prices by product and production costs of the Company for the years ended December 31, 2023, 2022 and 2021:

 

   

Year Ended December 31, 2023

 
   

Crude Oil

   

NGL

   

Natural Gas

   

Total

         
   

Sales

Volumes

   

Average

Sales

Price

   

Sales

Volumes

   

Average

Sales

Price

   

Sales

Volumes

   

Average

Sales

Price

   

Sales

Volumes

   

Average

Sales

Price

   

Production

Costs

 
   

(MBbl)

   

($/Bbl)

   

(MBbl)

   

($/Bbl)

   

(MMcf)

   

($/Mcf)

   

(MBoe)

   

($/Boe)

   

($/Boe)

 
      13,885     $ 78.26       1,547     $ 21.51       7,219     $ 1.56       16,635     $ 66.80     $ 8.74  

Average net daily sales volumes (Boepd)

                                                    45,577                  

 

   

Year Ended December 31, 2022

 
   

Crude Oil

   

NGL

   

Natural Gas

   

Total

         
   

Sales

Volumes

   

Average

Sales

Price

   

Sales

Volumes

   

Average

Sales

Price

   

Sales

Volumes

   

Average

Sales

Price

   

Sales

Volumes

   

Average

Sales

Price

   

Production

Costs

 
   

(MBbl)

   

($/Bbl)

   

(MBbl)

   

($/Bbl)

   

(MMcf)

   

($/Mcf)

   

(MBoe)

   

($/Boe)

   

($/Boe)

 
      7,562     $ 94.61       821     $ 35.67       3,323     $ 5.36       8,937     $ 84.56     $ 7.79  

Average net daily sales volumes (Boepd)

                                                    24,485                  

 

   

Year Ended December 31, 2021

 
   

Crude Oil

   

NGL

   

Natural Gas

   

Total

         
   

Sales

Volumes

   

Average

Sales

Price

   

Sales

Volumes

   

Average

Sales

Price

   

Sales

Volumes

   

Average

Sales

Price

   

Sales

Volumes

   

Average

Sales

Price

   

Production

Costs

 
   

(MBbl)

   

($/Bbl)

   

(MBbl)

   

($/Bbl)

   

(MMcf)

   

($/Mcf)

   

(MBoe)

   

($/Boe)

   

($/Boe)

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

Average net daily sales volumes (Boepd)

                                                    9,304                  

 

Productive Wells

 

Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and crude oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which HighPeak Energy holds an interest, and net wells are the sum of the fractional working interests owned in gross wells. The following table sets forth information relating to the productive wells in which HighPeak Energy holds a working interest as of December 31, 2023.

 

   

Crude Oil

   

Natural Gas

 
   

Gross

   

Net

   

Average

Working

Interest

   

Gross

   

Net

   

Average

Working

Interest

 

Horizontal:

                                               

Operated

    273       260.7       95 %                 n/a  

Non-operated

    18       1.2       7 %                 n/a  

Vertical:

                                               

Operated

    158       157.0       99 %     8       8.0       100 %

Non-operated

    5       2.0       40 %                 n/a  

Total:

                                               

Operated

    431       417.7       97 %     8       8.0       100 %

Non-operated

    23       3.2       14 %                 n/a  

 

Acreage

 

The following table sets forth certain information regarding the total developed and undeveloped acreage in which HighPeak Energy holds an interest as of December 31, 2023. Approximately 64% of the net acreage of HighPeak Energy was held by production as of December 31, 2023.

 

Developed Acres(1)(4)

   

Undeveloped Acres(4)

   

Total Acres

 

Gross Acres(2)

   

Net Acres(3)

   

Gross Acres(2)

   

Net Acres(3)

   

Gross Acres(2)

   

Net Acres(3)

 
86,198       81,813       56,989       49,823       143,187       131,636  

 

 

(1)

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

 

(2)

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

 

13

 

 

 

(3)

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

 

(4)

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

 

Undeveloped Acreage Expirations

 

The following table sets forth the number of total net undeveloped acres as of December 31, 2023 across HighPeak Energy’s properties that will expire in 2024, 2025, 2026, 2027, 2028 and thereafter, unless production is established within the spacing units covering the acreage prior to the expiration dates or unless such leasehold rights are extended or renewed.

 

2024

    27,424  

2025

    18,201  

2026

    1,664  

2027

    30  

2028

     

Thereafter

    320  
      47,639  

 

With respect to the 27,424 net acres expiring in 2024 across our properties, HighPeak Energy intends to retain substantially all 27,424 net acres through initiating completion operations of existing wells and the drilling of new wells, with the remaining net acreage being retained either through lease renewals or extensions. HighPeak Energy intends to retain substantially all of its undeveloped acreage through its development plan. Please see “Item 1A. Risk Factors – Risks Related to Our Business – Certain of the undeveloped leasehold acreage of HighPeak Energy’s assets is subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are renewed.”

 

Drilling Activities

 

The following table describes new development and exploratory/extension wells drilled within the Company’s assets during the years ended December 31, 2023, 2022 and 2021. The information should not be indicative of future performance, nor should it be assumed there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. As of December 31, 2023 and not included in the following table, were 10 gross (9.1 net) wells in the process of being drilled and 18 gross (13.4 net) wells either waiting on completion or in various stages of completion operations. In addition, the Company had three (3) gross (3.0 net) salt-water disposal wells in final stages of completion. As of December 31, 2023, HighPeak Energy was running a three-rig program. The Company expects to average two (2) drilling rigs and one (1) frac crew during 2024 under our current development plan. Our development program may change based on capital availability and other factors.

 

   

Year Ended December 31,

 
   

2023

   

2022

   

2021

 
   

Gross

   

Net

   

Gross

   

Net

   

Gross

   

Net

 

Development wells:

                                               

Productive

    57       49.5       28       23.4       5       5.0  

Dry

                                   

Exploratory/Extension wells:

                                               

Productive

    70       63.3       64       54.8       25       19.5  

Dry

                                   

Service wells:

                                               

Salt-Water Disposal

    3       3.0       4       4.0       1       1.0  

 

Delivery Commitments

 

Beginning October 2021, the Company has a minimum volume commitment under its crude oil marketing agreement in its Flat Top area whereby it must deliver minimum gross volumes to its central tank battery facilities of 5,000 Bopd for the first year, 7,500 Bopd for the second year and 10,000 Bopd for the remaining eight years of the contract. However, the Company has the ability under the contract to cumulatively bank excess volumes delivered to offset future minimum volume commitments. For the period from October 1, 2021 to December 31, 2023, the Company had delivered approximately 29,600 Bopd under the contract, banking excess volumes at the outset. Given the current production levels coupled with the wells planned to come on production in 2024 and beyond, the Company expects to meet the volume commitments under this agreement well in advance of the requirement. There are no material commitments to deliver a fixed and determinable quantity of natural gas production from the Company’s assets to customers under existing contracts.

 

14

 

 

Operations

 

General

 

As of December 31, 2023, HighPeak Energy’s properties consisted of 143,187 gross (131,636 net) acres with an average working interest of approximately 92%.

 

Facilities

 

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

 

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

 

Marketing and Customers

 

The following table sets forth the percentage of revenues attributable to customers who have accounted for 10% or more of revenues attributable to the Company’s assets during the years ended December 31, 2023, 2022 and 2021.

 

   

Years Ended December 31,

 

Major Customers

 

2023

   

2022

   

2021

 

DK Trading & Supply, LLC (“Delek”)

    82

%

    88

%

    94

%

Energy Transfer Crude Marketing, LLC (“ETC”)

    14

%

    *       *  

 

* Less than 10%.

 

No other purchaser accounted for 10% or more of revenue attributable to the Company’s assets on a combined basis in the years ended December 31, 2023, 2022 or 2021. The loss of any such purchaser could adversely affect revenues attributable to the Company’s assets in the short term. Please see “Risk Factors—Risks Related to Our Business—HighPeak Energy depends upon a small number of significant purchasers for the sale of most of its crude oil, NGL and natural gas production. The loss of one or more of such purchasers could, among other factors, limit HighPeak Energy’s access to suitable markets for the crude oil, NGL and natural gas it produces.”

 

For crude oil sales, HighPeak Energy currently is party to a ten-year contract with Delek, with production from Flat Top being mostly piped sales through a crude oil gathering system. Currently, the majority of our crude oil sales from Signal Peak are being trucked. The Flat Top crude oil contract is at known and published indices with a fixed primary term and an evergreen option thereafter. The contract contains a minimum volume commitment that commenced on October 1, 2021 based on the gross barrels delivered at the Company’s central tank battery facilities and is 5,000 Bopd for the first year, 7,500 Bopd for the second year and 10,000 Bopd for the remaining eight years of the contract. However, the Company has the ability under the contract to cumulatively bank excess volumes delivered to offset future minimum volume commitments. For the period from October 1, 2021 to December 31, 2023, the Company has delivered approximately 29,600 Bopd under the contract. The remaining monetary commitment as of December 31, 2023, if the Company never delivers any additional volumes under the agreement, is approximately $7.8 million. In addition, HighPeak Energy sells its natural gas production from the Company’s assets to multiple third-party purchasers pursuant to the terms of natural gas processing and purchase contracts at varying rates. The natural gas production is gathered and processed under agreements with a primary term and generally an evergreen extension option.

 

15

 

 

Competition

 

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

 

There is also competition between crude oil and natural gas producers and other industries producing energy and fuel. For example, HighPeak Energy also faces indirect competition from alternative energy sources, including wind and solar. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which HighPeak Energy operates, including recently passed legislation such as the IRA 2022. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon HighPeak Energy’s future operations as related to the Company’s assets. Such laws and regulations may substantially increase the costs of developing crude oil and natural gas and may prevent or delay the commencement or continuation of a given operation. HighPeak Energy’s larger competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than HighPeak Energy can, which would adversely affect HighPeak Energy’s competitive positions, as applicable. See “Item 1A. Risk Factors—Risks Related to Our Business—Competition in the crude oil and natural gas industry is intense, which will make it more difficult for HighPeak Energy to acquire properties, market crude oil or natural gas and secure trained personnel.”

 

Seasonality of Business

 

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

 

Title to Properties

 

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

 

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

 

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

 

16

 

 

Crude Oil and Natural Gas Leases

 

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

 

Regulation of the Crude Oil and Natural Gas Industry

 

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

 

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

 

Regulation of Production of Crude Oil and Natural Gas

 

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

 

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

 

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

 

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

 

Regulation Affecting Sales and Transportation of Commodities

 

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

 

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

 

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

 

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

 

In addition to the regulation of natural gas pipeline transportation, the FERC has jurisdiction over the purchase or sale of natural gas or the purchase or sale of transportation services subject to the FERC’s jurisdiction pursuant to the Energy Policy Act of 2005. Under this law, it is unlawful for “any entity,” including producers such as us, that are otherwise not subject to the FERC’s jurisdiction under the Natural Gas Act of 1938 to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. The FERC’s rules implementing this provision make it unlawful, in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud, to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading or to engage in any act or practice that operates as a fraud or deceit upon any person. The Energy Policy Act of 2005 also gives the FERC authority to impose civil penalties for violations of the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 up to $1,544,521 per day per violation (adjusted annually based on inflation). The anti-manipulation rule applies to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under Order 704 (defined below).

 

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

 

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

 

Rates of interstate liquids pipelines are currently regulated by the FERC primarily through an annual indexing methodology, under which pipelines increase or decrease their rates in accordance with an index adjustment specified by the FERC. In December 2020, the FERC concluded its five-year index review to establish the new inflationary adjustment for the five-year period commencing July 1, 2021, for liquid pipeline rates subject to indexing. In this review, the FERC considered changes to pipeline industry costs, including, among other things, the effects of the legislation known as the Tax Cuts and Jobs Act of 2017. The FERC issued an order on December 17, 2020 establishing an inflationary adjustment of Producer Price Index for Finished Goods (“PPI-FG”) plus 0.78% (PPI-FG+0.78%) for the five-year period commencing July 1, 2021 (the “December 2020 Order”). Numerous requests for rehearing were filed. On May 14, 2021, the FERC published the oil pricing index factor utilizing the inflationary adjustment factor established in the December 2020 Order, resulting in a negative percentage change of approximately 0.58% for the index year July 1, 2021 through June 30, 2022. On January 20, 2022, the FERC issued an order on rehearing in which it modified the methodology used to calculate the inflationary adjustment resulting in a revised inflationary adjustment for the five-year period commencing July 1, 2021, of PPI-FG minus 0.21% (PPI-FG-0.21%) (the “Rehearing Order”). As a result of the Rehearing Order, the index factor for the July 1, 2021 through June 30, 2022 index year now provides for a negative percentage change of approximately 1.6%. The FERC directed all oil pipelines to ensure their rates were consistent with the revised index factor effective March 1, 2022. Following the Rehearing Order, some parties sought rehearing with the FERC while others filed petitions for review with the Fifth Circuit and D.C. Circuit. On May 6, 2022, the FERC issued its order denying the rehearing requests. Additional petitions for review were filed with the D.C. Circuit after the May 6th order and the challenges have been consolidated at the D.C. Circuit. The appeal remains pending before the D.C. Circuit.

 

Under the FERC’s regulations, a liquids pipeline can request the authority to charge market-based rates for transportation service if it satisfies certain criteria, and also can request a rate increase that exceeds the rate obtained through application of the indexing methodology by using a cost-of-service approach, but only after the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology. Increases in liquids transportation rates may result in lower revenue and cash flows.

 

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

 

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

 

In addition to the FERC’s regulations, we are required to observe anti-market manipulation laws with regard to our physical sales of energy commodities. In November 2009, the FTC issued regulations pursuant to the Energy Independence and Security Act of 2007 intended to prohibit market manipulation in the petroleum industry. Violators of the regulations face civil penalties of up to $1,472,546 per violation per day (adjusted annually based on inflation). In July 2010, Congress passed the Dodd-Frank Act, which incorporated an expansion of the authority of the Commodity Futures Trading Commission (“CFTC”) to prohibit market manipulation in the markets regulated by the CFTC. This authority, with respect to crude oil swaps and futures contracts, is similar to the anti-manipulation authority granted to the FTC with respect to crude oil purchases and sales. In July 2011, the CFTC issued final rules to implement its new anti-manipulation authority. The rules subject violators to a civil penalty of up to the greater of $1,450,040 (adjusted annually based on inflation) or triple the monetary gain to the person for each violation.

 

Regulation of Environmental and Occupational Safety and Health Matters

 

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

 

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

 

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

 

Hazardous Substances and Waste Handling

 

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

 

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

 

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

 

Water Discharges, Fluid Disposal and NORM

 

The Water Pollution Control Act, also known as the Clean Water Act (“CWA”) and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other crude oil and natural gas wastes, into or near navigable waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”). The scope of jurisdiction under the CWA has been subject to several rulemakings by the EPA in recent years and is subject to ongoing litigation.  Most recently, following legal action on a January 2023 final rule which established a definition of “waters of the United States” based on the broader pre-2015 definition, the U.S. Supreme Court’s  decision in Sackett v. EPA, and the enactment of a subsequent September 2023 rule is enjoined subject to litigation, and the EPA and Corps are implementing the definition of “waters of the United States” consistent with the pre-2015 regulatory regime and the changes made by the Sackett decision, which utilizes the “continuous surface connection” test to determine if wetlands qualify as waters of the United States. In the remaining 23 states, the agencies are implementing the September 2023 rule, which amended the January 2023 rule to incorporate the Sackett decision. However, the September 2023 rule does not define the term “continuous surface connection,” and it is currently unclear how broadly the September 2023 rule and the Sackett decision will be interpreted by the agencies. Therefore, the future reach of the CWA is uncertain at this time. To the extent any rule further expands the scope of the CWA’s jurisdiction, the Company could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The timeliness associated with obtaining permits also has the potential to delay the development of crude oil and natural gas projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of crude oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.

 

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

 

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

 

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

 

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In response to these concerns, some states, including Texas, have imposed additional requirements for the permitting of produced water disposal wells, such as volume and pressure limitations or seismicity thresholds for temporary cessations of activity. In September 2021, the Texas Railroad Commission (“TRRC”) issued a notice to operators in the city of Midland area to reduce daily injection volumes following multiple earthquakes above 3.5 magnitude over an 18-month period. The notice also required disposal well operators to provide injection data to TRRC staff to further analyze seismicity in the area. Subsequently, the TRRC ordered the indefinite suspension of all deep produced water injection wells in the area, effective December 31, 2021. The response area has since been expanded following an additional earthquake in December 2022 to cover an additional 17 wells. Other seismic response areas have also been established, including the Northern Culberson-Reeves Seismic Response Area, where 23 deep disposal well permits were suspended in December 2023. While the ultimate outcome of these actions is uncertain, the adoption and implementation of any new laws or regulations that restrict our operators’ ability to use hydraulic fracturing or dispose of produced water gathered from drilling and production activities by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring them to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of operations.

 

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

 

Air Emissions

 

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

 

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

 

Regulation of Greenhouse Gas Emissions

 

At the federal level, no comprehensive climate change legislation has been implemented to date, though the recently-passed IRA 2022 advances numerous climate-related objectives. The EPA has, however, adopted rules under authority of the CAA that, among other things, establish prevention of significant deterioration (“PSD”) construction and Title V operating permit reviews for greenhouse gases (“GHG”) emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions. Under these regulations, facilities required to obtain PSD permits must meet “best available control technology” standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the U.S., including, among others, onshore and offshore production facilities, which include certain of our operators’ operations. The EPA has expanded the GHG reporting requirements to all segments of the crude oil and natural gas industry, including gathering and boosting facilities as well as completions and workovers from hydraulically fractured crude oil wells.

 

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Federal agencies also have begun directly regulating emissions of methane from crude oil and natural gas operations. For example, in June 2016, the EPA published New Source Performance Standards, known as Subpart OOOOa, that requires certain new, modified or reconstructed facilities in the crude oil and natural gas sector to reduce these methane gas emissions. Although, in September 2020, the Trump Administration published regulations to rescind methane specific requirements and remove the transmission and storage segments from the crude oil and natural gas source category, the U.S. Congress approved, and President Biden signed into law, a resolution under the Congressional Review Act to repeal the September 2020 revisions, effectively reinstating the prior standards. Additionally, in December 2023, the EPA finalized a rule that established OOOOb as more stringent new source and OOOOc as first-time existing source standards of performance for methane and VOC emissions for the crude oil and natural gas source category. Under the final rules, owners or operators of affected emission units or processes have two years to prepare and submit their plans to impose methane emission controls on existing sources.  The presumptive standards under the final rule are generally the same for both new and existing sources, including enhanced leak detection using optical gas imaging and subsequent repair requirements, reduction of regulated emissions through capture and control systems, zero-emission requirements for certain equipment or processes, operations and maintenance requirements and requirements for “green well” completions. The rule also revises requirements for fugitive emissions monitoring and repair as well as equipment leaks and the frequency of monitoring surveys, establishes a “super-emitter” response program to timely mitigate emissions events as detected by governmental agencies or qualified third parties, triggering certain investigation and repair requirements, and provides additional options for the use of advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions. However, it is likely that these requirements will be subject to legal challenges. Several states have also adopted rules to control and minimize methane emissions from the production of crude oil and natural gas, and others have considered or may consider doing so in the future.

 

At the international level, in December 2015, the United States and 194 other participating countries adopted the Paris Agreement, which calls for each participating country to establish their own nationally determined standards for reducing carbon output. President Biden recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing again at the 26th Conference to the Parties on the UN Framework Convention on Climate Change (“COP26”), during which multiple announcements were made, including a call for parties to eliminate fossil fuel subsidies and pursue further action on non-CO2 GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. These goals were reaffirmed in November 2022 at the 27th Conference of the Parties to the United Nations Framework Convention on Climate Change (“COP27”), where countries were also called upon to accelerate efforts towards the phase-out of inefficient fossil fuel subsidies. The United States also announced, in conjunction with the European Union and other partner countries, that it would develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. At the 28th Conference of the Parties (“COP28”), the parties signed onto an agreement to transition away from fossil fuels in energy systems and increase renewable energy capacity, though no timeline for doing so was set. While non-binding, the agreements coming out of COP28 could result in increased pressure among financial institutions and various stakeholders to reduce or otherwise impose more stringent limitations on funding for and increase potential opposition to the production and use of fossil fuels. Although no firm commitment or timeline to phase out all fossil fuels was made at COP27 or COP28, there can be no guarantee that countries will not seek to implement such a phase-out in the future. The impacts of these actions cannot be predicted at this time.

 

The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions for our operators, and could have a material adverse effect on our business, financial condition and results of operations. On January 27, 2021, President Biden signed an executive order calling for substantial action on climate change, including, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across agencies and economic sectors. In August 2022, the IRA 2022 was signed into law, which amends the CAA to establish the first-ever federal fee on methane emissions that exceed certain thresholds from sources required to report their GHG emissions to the EPA, including certain crude oil and natural gas operations. The methane emissions charge will start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and subsequent years. The methane emissions fee could increase our operating costs. Additionally, the IRA 2022 appropriates significant federal funding for renewable energy initiatives and incentives, which could accelerate the transition away from fossil fuels and therefore reduce demand for our products and adversely affect our business and results of operations. Other actions taken by the Biden Administration, states, or local jurisdictions in the future, such as limitations or bans on products that rely on crude oil and natural gas, could also reduce demand for our products.

 

There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. In late 2020, the Federal Reserve announced it has joined the Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused on addressing climate-related risks in the financial sector and, in November 2021, issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. In January 2023, the Federal Reserve issued instructions for a pilot climate scenario analysis being undertaken by six of the United States’ largest banks, which is expected to conclude at the end of 2023. Limitation of investments in and financing for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities. Ultimately, this could make it more difficult for operators to secure funding for exploration and production activities. Additionally, activist shareholders have introduced proposals that may seek to force companies to adopt aggressive emission reduction targets or restrict more carbon-intensive activities. While we cannot predict the outcomes of such actions, they could make it more difficult for operators to engage in exploration and production activities. In addition, the SEC has proposed rules that would require registrants to report climate-related risks and business strategies, and disclose information on Scope 1 and 2 GHG emissions and, in some cases, Scope 3 emissions. The final rule remains pending and the final form and substance of these requirements is not yet known. To the extent the rules impose additional reporting obligations, we could face increased costs. Additionally, certain states have enacted or are considering similar climate-related disclosure requirements. Enhanced climate-related disclosure requirements could increase operating costs and lead to reputational or other harm with customers, regulators, or other stakeholders to the extent that our disclosures do not meet their own standards or expectations. Consequently, we are also exposed to increased litigation risks relating to alleged climate-related damages resulting from our operations, statements alleged to have been made by us or others in our industry regarding climate change risks, or in connecting with any future disclosures we may make regarding reported emissions, particularly given the inherent uncertainties and estimation required with respect to calculating and reporting GHG emissions. Finally, many scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climate events that could have an adverse effect on the Company’s operations. For more information, please see our risk factor titled “The operations of HighPeak Energy are subject to a variety of risks arising from climate change.”

 

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Hydraulic Fracturing Activities

 

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

 

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

 

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

 

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

 

Endangered Species Act and Migratory Birds

 

The Endangered Species Act (“ESA”) and (in some cases) comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. The U.S. Fish and Wildlife Service (“FWS”) may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for crude oil and natural gas development. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the FWS was required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. The agency missed the deadline but continues to review species for listing under the ESA. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (“MBTA”). The federal government in the past has pursued enforcement actions against crude oil and natural gas companies under the MBTA after dead migratory birds were found near reserve pits associated with drilling activities. Although the Department of Interior under the Trump Administration issued a rulemaking revoking its prior enforcement policy and concluded that an incidental take is not a violation of the MBTA, the Biden Administration has published a final rule rescinding this rulemaking, in addition to publishing an advanced notice of proposed rulemaking to codify a new definition for take that includes such incidental take as a violation of the MBTA. In any event, the identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause increased costs arising from species protection measures or could result in limitations on development activities that could have an adverse impact on the ability to develop and produce reserves within the Company’s assets. For example, a review is currently pending to determine whether the dunes sagebrush lizard should be listed and, in November 2022 the FWS listed two distinct population segments of the lesser prairie-chicken under the ESA. If these species or others are listed, the FWS and similar state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. If a portion of the Company’s assets were to be designated as a critical or suitable habitat, it could adversely impact the value of the Company’s assets.

 

Occupational Safety and Health Act

 

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

 

Related Permits and Authorizations

 

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

 

Related Insurance 

 

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

 

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Human Capital

 

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

 

As of December 31, 2023, we employed forty-eight full-time employees dedicated to operating the Company’s assets. None of these employees are covered by collective bargaining agreements, and we consider our employee relations to be good.

 

Employee Health and Safety

 

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

 

The Company has taken steps to keep its employees safe during pandemics by implementing preventative measures and developing response plans intended to minimize unnecessary risk of exposure and infection among its employees. The Company has also modified certain business practices to conform to best practices encouraged by the Centers for Disease Control and Prevention, and other governmental and regulatory authorities.

 

Diversity and Inclusion

 

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

 

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

 

Talent Development and Retention

 

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

 

Legal Proceedings

 

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

 

Offices

 

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

 

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Board of Directors and Executive Officers

 

The following table sets forth information regarding the directors of our Board and certain executive officers:

 

Name

Age

Position

Jack Hightower

75

Chairman of the Board and Chief Executive Officer

Michael L. Hollis

48

President and Director

Rodney L. Woodard

68

Chief Operating Officer

Steven W. Tholen

73

Chief Financial Officer

Keith Forbes

61

Vice President and Chief Accounting Officer

Jay M. Chernosky

64

Director

Keith A. Covington

60

Director

Sharon F. Fulgham

46

Director

Larry C. Oldham

70

Director

Jason A. Edgeworth

39

Director

 

Jack Hightower has served as our Chairman of the Board and Chief Executive Officer (“CEO”) since 2019. Prior to the HighPeak business combination (the “HighPeak business combination” or, the “business combination”), Mr. Hightower served as Chairman of the board of directors, CEO and President of Pure Acquisition Corp. (“Pure”) since its incorporation in November of 2017. Mr. Hightower has over 50 years of experience in the oil and gas industry managing multiple exploration and production (“E&P”) platforms. Mr. Hightower currently serves as the Chairman of the board of directors and CEO of the general partners of funds affiliated with the Company and HighPeak Energy Partners, LP and HighPeak Energy Partners II, LP (the “HighPeak Funds”), a position held since 2014. Mr. Hightower served as Chairman, President and CEO of Bluestem Energy Partners, LP (“Bluestem”) from 2011 to 2013. Prior to forming Bluestem, Mr. Hightower served as Chairman, President, and CEO of Celero Energy II, LP (“Celero II”) from 2006 to 2009 and as Chairman, President and CEO of Celero Energy, LP (“Celero”) from 2004 to 2005. Prior to forming Celero, Mr. Hightower served as Chairman, President and CEO of Pure Resources, Inc. (“Pure Resources”) (NYSE: PRS), which became the 11th largest publicly traded independent E&P company in North America. In October 2002, Unocal tendered for the Pure Resources shares it did not already own. In March 1995, Mr. Hightower founded Titan (Nasdaq: TEXP), the predecessor to Pure Resources, and served as Chairman, President and CEO. Prior to founding Titan, Mr. Hightower served as Chairman, President and CEO of Enertex Inc., the general partner and operator of record for several oil and gas partnerships from 1991 to 1994. Mr. Hightower graduated from Texas Tech University in 1970 with Bachelor of Business Administration degrees in Administrative Finance and Money, Banking & Investments.

 

Michael L. Hollis has served as our President and as a member of our Board since August 2020. Prior to the HighPeak business combination, Mr. Hollis served as Pure’s President from December 2019 until August 2020. Prior to joining Pure, Mr. Hollis served as President and Chief Operating Officer (“COO”) of Diamondback Energy, Inc. (“Diamondback”) (Nasdaq: FANG), a Permian focused oil and gas producer, from January 2017 through September 2019, prior to which he served as COO since 2015 and Vice President of Drilling. Since 2011, Mr. Hollis also served on the board of directors for Diamondback as well as on the board of directors of Viper Energy Partners LP (Nasdaq: VNOM). Prior to his positions at Diamondback, Mr. Hollis was a Drilling Manager at Chesapeake Energy Corporation and also held roles of increasing responsibility in production, completions and drilling engineering at ConocoPhillips and Burlington Resources Inc. Mr. Hollis has over 20 years of oil and gas experience and graduated from Louisiana State University in 1998 with a Bachelor of Science in Chemical Engineering.

 

Rodney L. Woodard has served as our Chief Operating Officer since August 2020. Prior to the HighPeak business combination, Mr. Woodard served as Pure’s COO and served as a director of Pure’s board of directors since its inception in November 2017 and as HighPeak Energy’s COO since its inception in October 2019. Mr. Woodard has over 40 years of experience in the oil and gas industry as a CEO, COO, and leader of Engineering and Operations of numerous E&P companies. Mr. Woodard has served as the Executive Vice President & COO for the HighPeak Funds from 2017 to the present. From 2016 to 2017, Mr. Woodard presented portfolio company investment proposals to acquire and develop oil and gas assets in the Permian Basin to several private equity firms. Mr. Woodard served as the President and COO of Atlantic Resources Co., LLC (“Atlantic”) from 2015 to 2016. Prior to Atlantic, Mr. Woodard served as CEO and COO of Celero II, a Natural Gas Partners portfolio company, with operations principally in the Permian Basin from 2006 to 2015. Prior to Celero II, Mr. Woodard served as Executive Vice President and COO of Celero, a Quantum Energy Partners portfolio company from 2004 to 2006. From 2002 to 2004, Mr. Woodard was Vice President of Reserves and Evaluations with Pure Resources (NYSE: PRS) and was a co-founder of its predecessor, Titan Exploration (Nasdaq: TEXP). From 1986 to 1995, Mr. Woodard held various positions of increasing responsibility at Selma International Investments Ltd. From 1979 to 1986, Mr. Woodard held various positions at Delta Drilling Company, obtaining the position of Division Manager for West Texas. Mr. Woodard held various positions at Amoco Production Company from 1977 to 1979. Mr. Woodard graduated from The Pennsylvania State University in 1977 with a Bachelor of Science degree in Mechanical Engineering.

 

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Steven W. Tholen has served as our Chief Financial Officer (“CFO”) since HighPeak Energy’s inception in October 2019 and is a Corporate Finance Executive with over 30 years of experience in building, leading and advising corporations through complex restructurings, purchase and sales transactions, and capital market transactions. Mr. Tholen has served as the CFO for the HighPeak Funds since 2014. Previously, Mr. Tholen served as co-founder and Executive Vice President - Finance of Fieldco Construction Services, Inc., which provided oilfield construction services to clients throughout East Texas & Western Louisiana, from 2011 to 2014. From 2009 to 2013, Mr. Tholen served as founder and President of SDL&T Energy Partners, a source of equity & debt financing to fund energy companies and energy projects worldwide. From 2001 to 2008, Mr. Tholen was Senior Vice President & CFO of Harvest Natural Resources, Inc., an E&P company with properties in the United States, Venezuela, Indonesia, Gabon, and Russia. From 1995 to 2000, Mr. Tholen served as Vice President and CFO of Penn Virginia Corporation, an independent natural gas and oil company. From 1990 to 1995, Mr. Tholen was Treasurer/Manager of Business Administration of Cabot Oil & Gas Corporation, a North American independent natural gas producer. Mr. Tholen graduated from St. John’s University with a Bachelor of Science degree in Physics in 1971 and earned his Master of Business Administration in Finance from The University of Denver, Daniels School of Business in 1979.

 

Keith Forbes has served as our Vice President and Chief Accounting Officer (“CAO”) since November 2020 and previously served as our Vice President and Controller from our inception in October 2019 until November 2020. Mr. Forbes has over 30 years of experience in various field and corporate accounting functions and business organization functions for large, geographically diverse public companies. Before his appointment as CAO to HighPeak Energy, Mr. Forbes served as Vice President and Controller of the HighPeak Funds since 2017. Mr. Forbes additionally served as Director-Business Optimization at Quicksilver Resources Inc. from December 2015 through April 2016, and as Assistant Controller-Operations and Revenue at Quicksilver Resources Inc. from June 2012 through November 2015. Mr. Forbes is a certified public accountant in Texas. Mr. Forbes graduated from Pittsburg State University with a Bachelor of Business Administrations degree in Accounting in 1985.

 

Jay M. Chernosky has served on our Board since August 2020 and is currently a Principal of Travis Energy Partners LP since 2019, Jayco Holdings I, LP since 2005, Jayco Holdings II, LP since 2010, Jayco Holdings LLC since 2005, Bertrand Properties LP and Bertrand Properties, Inc. since 2000, Vargas Properties LP since 2022, which are private family-owned real estate and energy investment entities. Mr. Chernosky was previously a Managing Director of the Energy & Power Corporate & Investment Banking group at Wells Fargo Securities from 2009 until his retirement in 2019. Mr. Chernosky joined Wells Fargo’s predecessor firm Wachovia Securities (formerly First Union) in 1993 as a co-founder of the energy practice. Prior to joining Wells Fargo Securities, Mr. Chernosky worked in various capacities in the Energy Division of First City, Texas - Houston for 10 years. During his career, Mr. Chernosky was charged with developing strategic and financial ideas and solutions for relationships he managed for the bank and was also responsible for the origination and execution of public and private capital markets activities, including equities, bonds, convertibles, private placements, loan syndications and merger and acquisition advisory services. During this time, Mr. Chernosky’s primary focus was on the upstream sector of the oil and gas industry.

 

Currently, Mr. Chernosky serves on the board of directors of Colt Midstream LLC, a private gas gathering and processing company focused in the Fort Worth Basin of Texas since 2019. Mr. Chernosky also serves on the regional board of directors of OneGoal Houston, a non-profit organization geared to increase the success rate of college admission and graduation for youth attending high school in low-income districts since 2012. In addition, Mr. Chernosky serves on the Endowment Board of the Christian Community Service Center since 2010.

 

Mr. Chernosky has previously served on the board of directors and is an active member of the Houston Producers’ Forum, the Houston Energy Finance Group and the regional board of the Independent Petroleum Association of America. Mr. Chernosky graduated from The University of Texas at Austin with a Bachelor of Business Administration in 1981 and received a Master of Business Administration from the University of Houston in 1983. Mr. Chernosky is also a graduate of the Southwestern Graduate School of Banking at Southern Methodist University in 1993.

 

Keith A. Covington has served on our Board since August 2020 and is an active real estate investor specializing in residential properties in southern California for the past 28 years, most recently serving as a General Partner for Magnolia Partners since 2002.

 

Mr. Covington is an independent director on the board of directors of Gores Holdings IX, Inc. (Nasdaq: GHIX) (a Special Purpose Acquisition Company (“SPAC”)), and a member of both its audit and compensation committees since its January 2022 IPO for $525 million, which will target acquisitions in any industry or sector and will have an operational focus. Mr. Covington was an independent director on the board of directors of Gores Holdings VII, Inc., a SPAC, and a member of both its audit and compensation committees since its February 2021 IPO for $550 million, which was liquidated to stockholders at par in December 2022.

 

Mr. Covington was a founding board member of Pure Resources, an energy company engaged in the exploration and development of oil and gas properties which had a market capitalization of over $1 billion and served such directorship from 2000 to 2002. As an independent director for over two years, Mr. Covington served as chairman of the audit committee and member of the compensation committee of Pure Resources and was a co-member of the special committee responsible for evaluating, negotiating and recommending on behalf of company shareholders the acquisition of Pure Resources to Unocal Corporation (acquired by Chevron Corporation) in October 2002.

 

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Mr. Covington served in various capacities over 11 years at Davis Companies from 1991 to 2002, where he was Vice President and earlier served as Principal of Stone Canyon Venture Partners, LLC. Mr. Covington’s tenure included responsibility in the real estate and private equity/venture capital groups within the organization. Investment and operational experience within these areas included investments in trophy commercial and mixed-use real estate assets, gaming ventures, a chain of upscale health clubs, resort properties and hotels, a restaurant and a technology company. His responsibilities included extensive independent due diligence for potential acquisitions, financial analysis and comprehensive asset management for equity investments in real estate assets and operating companies valued at over $10 billion. Prior professional experience includes Janss Corporation, a Santa Monica, CA real estate developer where he was responsible for due diligence and financial structuring and leasing of residential and commercial real estate projects from 1989 to 1990. Mr. Covington started his career as a Financial Analyst at PaineWebber Group Inc. (UBS Investment Bank) in New York with experience in real estate investment banking transactions including sale/leasebacks and the firm’s largest initial public offering and real estate master limited partnership from 1985 to 1987. Mr. Covington received his Master of Business Administration from the Stanford Graduate School of Business and earned a Bachelor of Arts cum laude in Economics from Claremont McKenna College. Mr. Covington maintains a California real estate broker’s license and has maintained board governance expertise through participation in KPMG’s Audit Committee Institute. Mr. Covington has previously served as Chief Financial Officer for the El Segundo Senior Housing Board for over five years. 

 

Jason A. Edgeworth has served as an Investment and Asset Manager for the John Paul DeJoria family office since 2020 with responsibility for diligence, execution and investor relations.

 

Previously, Mr. Edgeworth served as an Executive Director of Investment & Merchant Banking at U.S. Capital Advisors LLC from 2013 to 2020. Mr. Edgeworth’s responsibilities included diligence, execution and investor communications with a focus on equity market transactions, including initial public offerings, follow on equity offerings, at-the-market equity offerings and preferred equity offerings, for public E&P companies and midstream companies. Mr. Edgeworth also advised on merchant banking and private equity transactions for the midstream and service sectors of the oil and gas industry both domestically and internationally.

 

From 2008 to 2012, Mr. Edgeworth served as an equity analyst at CLW Investments and Twin Eagle Resource Management and also AEW Europe and Curzon Global Partners where he focused on the energy sector and commercial and mixed-use real estate.

 

Mr. Edgeworth serves on or has served on the board of several companies including Borealis Alaska Oil, Inc. and Badger Midstream Energy, LP. Mr. Edgeworth graduated from the University of St. Andrews in 2008 with a Master of Arts in International Relations. Mr. Edgeworth is a Chartered Alternative Investment Analyst.

 

Sharon F. Fulgham has served on our Board since August 2020 and is currently a partner of the Fulgham Hampton Law Group since August 2017. Ms. Fulgham has also been associated with Carlisle Title since December 2016 and has been their corporate attorney since November 2019. Prior to working at Fulgham Law Firm, P.C., Ms. Fulgham was a partner at Kelly Hart & Hallman from January 2016 to November 2016 and an associate at Kelly Hart & Hallman from 2009 to 2016. During her legal career, Ms. Fulgham has represented numerous public and private companies in litigation matters including commercial and employment disputes. Specifically, she has extensive experience representing companies in the oil and gas sector, as well as experience in the title industry preparing title documents for real estate closings and instruction to brokers and realtors.

 

Over the past decade, Ms. Fulgham has served the Fort Worth community extensively through the Junior League of Fort Worth, Inc. (the “Junior League”), a charitable nonprofit organization of women committed to promoting volunteerism, developing the potential of women and improving communities, both as a community volunteer and in leadership roles within the organization. She served as Vice President of Administration and sat on the board of directors from 2015 to 2016. Ms. Fulgham is currently a sustaining member and served on the Junior League’s Legal Committee from 2019 to 2022. Ms. Fulgham is also involved in the Young Men’s Service League, a national nonprofit made up of mothers and their teenage sons who volunteer together to serve their local communities, and has served on the board of directors for the local chapter since 2021. Ms. Fulgham graduated cum laude from Texas Christian University with a Bachelor of Science in Biology in 2000 and went on to obtain her Juris Doctorate from the University of Houston in 2004.

 

Larry C. Oldham has served on our Board since August 2020 and currently serves as a Manager and Advisor of Gateway Royalty VI LLC (“Gateway VI”) since 2022. Gateway VI is the sixth entity of the Gateway Royalty companies, which were founded by Chris Oldham, Mr. Oldham’s son, and have been successful in acquiring oil and gas minerals and royalties in the Utica Shale since 2012. Mr. Oldham is also a Manager of Gateway Royalty III LLC since 2016, Gateway Royalty IV LLC since 2018 and Gateway Royalty V LLC since 2019. In addition, Mr. Oldham has been actively advising Gateway Royalty II LLC and Gateway Royalty I LLC since 2014 and 2012, respectively.

 

Additionally, Mr. Oldham serves as Manager of Oldham Properties, Ltd. since 1990. Mr. Oldham currently serves as an Operating Partner in Mountain Capital LLC, a private equity firm out of Houston, Texas since 2015 and has served on the board of directors of Saddleback Exploration Inc., a private oil and gas company headquartered in Tulsa, Oklahoma. Mr. Oldham is also a member of the board of directors of the West Texas A&M University Foundation.

 

In 1979, Mr. Oldham founded Parallel Petroleum Corporation (“Parallel”), an independent energy company headquartered in Midland, Texas, which engaged in the acquisition, development and production of long-lived oil and gas properties, primarily in the Permian Basin. Parallel completed its initial public offering in 1980 and in December 2009 was acquired by an affiliate of Apollo Global Management, Inc. (formerly known as Apollo Global Management, LLC), which was sold to Samsung C&T Corporation in December of 2011. Prior to the sale to Apollo Global Management, Inc., Mr. Oldham served as Parallel’s President from 1994 to 2009, Chief Executive Officer from 2004 to 2009 and director from 1979 until 2009. During Mr. Oldham’s years at Parallel, some of the most notable property acquisitions were the Fullerton Property in Andrews County, Diamond M Canyon Reef Field in Scurry County and the acquisition of all of Fina’s West Texas assets in July 1999. In 1992, Parallel was an early adopter of 3D seismic and drilled several Canyon Reef discoveries in Howard County, Texas and several discoveries in the Yegua/Frio Trend onshore the Gulf Coast of Texas. In 2005, horizontal drilling was successfully implemented in the Wolfcamp formation in New Mexico and the Barnett Shale in Tarrant County, Texas. In 2014, Parallel drilled the first of several horizontal wells in the Harris Field, which were large producing wells completed with engineered fracs. Parallel was the forerunner of this highly successful completion technique.

 

Prior to Parallel’s formation, Mr. Oldham was employed by Dorchester Gas Corporation from 1976 to 1979 and KPMG Peat Marwick, LLP from 1975 to 1976. Mr. Oldham earned a Bachelor of Business Administration in Accounting from West Texas State University (now West Texas A&M University) in 1975 and was a 2012 Distinguished Alumni Award recipient. Mr. Oldham is a certified public accountant and is a member of the Permian Basin Landman’s Association and the Permian Basin Producers Association.

 

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ITEM 1A. RISK FACTORS

 

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

 

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

 

Risks Related to Our Business

 

 

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

 

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of reserves.

 

HighPeak Energy’s development projects and acquisitions will require substantial capital expenditures. HighPeak Energy may be unable to obtain required capital or financing on satisfactory terms, including as a result of recent increases in cost of capital resulting from Federal Reserve policies or otherwise, which could reduce its ability to access or increase production and reserves.

 

Restrictions in the Term Loan Credit Agreement, the Senior Credit Facility Agreement and any future debt agreements could limit HighPeak Energy’s growth and ability to engage in certain activities.

 

Our ability to repurchase shares under our recently announced share repurchase program is subject to certain considerations, and any share repurchases thereunder could increase the volatility of our stock prices and could diminish our cash reserves.

 

Our existing and future indebtedness may adversely affect our cash flows and ability to operate our business, remain in compliance and repay our debt.

 

Our results of operations and cash flows vary significantly from year to year due to the cyclical nature of the crude oil and natural gas industry.
 

HighPeak Energy has experienced periods of higher costs as commodity prices have risen and inflation may adversely affect our operating results, which negatively impacts our profitability, cash flow and ability to complete development activities as planned. Continuing or worsening inflationary issues and associated changes in monetary policy have resulted in and may result in additional increases to the cost of our goods, services and personnel, which in turn could cause our capital expenditures and operating costs to rise.

 

Volatility in the political, legal and regulatory environment ahead of the upcoming U.S. presidential election and 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 OPEC+ policy decisions could have a material adverse impact on our business, financial condition or future results.
 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

Unless HighPeak Energy replaces its reserves with new reserves and develops those new reserves, its reserves and production will decline, which would adversely affect future cash flows and results of operations.

 

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

 

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HighPeak Energy may be unable to make additional attractive acquisitions or successfully integrate acquired businesses with its current assets, and any inability to do so may disrupt its business and hinder its ability to grow.

 

The unavailability or high cost of drilling rigs, equipment, supplies, personnel, frac crews and oilfield services due to commodity price volatility or supply constraints as a result of the conflict in Ukraine, the Israel-Hamas conflict, elevated interest rates and associated policies of the Federal Reserve could adversely affect HighPeak Energy’s ability to execute its development plans within its budget and on a timely basis and consequently could materially and adversely affect our cash flows and results of operations.

 

The IRA 2022 could accelerate the transition to a low carbon economy and could impose new costs on our operations.

 

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

 

Should our operators fail to comply with all applicable regulatory agency administered statutes, rules, regulations and orders, our operators could be subject to substantial penalties and fines.

 

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

 

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

 

Continued increases in interest rates could adversely affect HighPeak Energy’s business.

 

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

 

Risks Related to Ownership of our Securities

 

 

We are evaluating strategic alternatives, including a possible sale of our business, and there can be no assurance that we will be successful in identifying or completing any strategic alternative transactions, that any such strategic alternative transactions will result in additional value for our shareholders or that the process will not have an adverse impact on our business and shareholders.

 

HighPeak Energy is a “controlled company” within the meaning of Nasdaq rules and qualifies for exemptions from certain corporate governance requirements. As a result, you do not have the same protections afforded to stockholders of companies that are not exempt from such corporate governance requirements.

 

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

 

HighPeak Energy is an emerging growth company within the meaning of the Securities Act, and if HighPeak Energy takes advantage of certain exemptions from disclosure requirements available to emerging growth companies, which could make HighPeak Energy’s common stock less attractive to investors and may make it more difficult to compare its performance with other public companies.

 

Risks Related to Our Business

 

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

 

The prices HighPeak Energy receives for its crude oil, NGL and natural gas production heavily influence its revenue, profitability, access to capital, future rate of growth and the carrying value of its properties. The markets for crude oil and natural gas have been volatile historically and are likely to remain volatile in the future. For example, during the period from January 1, 2020 through December 31, 2023, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $16.70 to a high of $114.34, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.50 to a high of $9.35. For the month of April 2020, the calendar month average NYMEX WTI crude oil price was $16.70 per Bbl and the last trading day NYMEX natural gas price was $1.63 per MMBtu. One of the factors which caused the fall in prices was OPEC+ being unable to reach an agreement on production levels for crude oil, which resulted in Saudi Arabia and Russia initiating efforts to increase production. The convergence of these events, along with the significantly reduced demand because of the COVID-19 pandemic, created an unprecedented global crude oil and natural gas supply and demand imbalance, reduced global crude oil and natural gas storage capacity, caused crude oil and natural gas prices to decline significantly and resulted in continued volatility in crude oil, NGL and natural gas prices into the second quarter of 2020. Prices have recovered to pre-pandemic levels, with the calendar month average NYMEX WTI crude oil price of $72.12 per Bbl and the last trading day NYMEX natural gas price of $2.71 per MMBtu for the month of December 2023. However, there can be no certainty that commodity prices will sustain at these levels or continue to increase.

 

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

 

 

worldwide and regional economic conditions, including elevated interest rates and associated policies of the Federal Reserve, impacting the global supply and demand for crude oil, NGL and natural gas;

 

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

 

domestic and global political and economic conditions, such as the upcoming U.S. presidential election, the ongoing conflict in Ukraine, the Israel-Hamas conflict, socio-political unrest and instability, terrorism or hostilities in or affecting other producing regions or countries, including the Middle East, Africa, South America and Russia;
 

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

 

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

 

the level of global exploration, development and production;

 

the level of global inventories;

 

prevailing prices, and expectations regarding future prices, on local price indexes in the areas in which HighPeak Energy operates;

 

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

 

localized and global supply and demand fundamentals and transportation availability;

 

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

 

weather conditions and natural disasters;

 

technological advances affecting energy consumption;

 

the price and availability of alternative fuels, including the potential acceleration of the development of alternative fuels as a result of the IRA 2022 or otherwise;

 

expectations about future commodity prices; and

 

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

 

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

 

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of reserves.

 

Numerous uncertainties are inherent in estimating quantities of crude oil and natural gas reserves. Our estimates of our SEC reserves are based upon average commodity prices over the prior 12 months, which may not reflect actual prices received for our production. For example, our reserve volumes and PV-10 as disclosed in this Annual Report are based on assumed commodity prices of $78.22 per Bbl of crude oil and NGL and $2.637 per MMBtu of natural gas as of December 31, 2023, which are somewhat higher than the December 31, 2023 front-month forward pricing of $71.65 per Bbl of crude oil and $2.514 per Mcf of natural gas. Accordingly, you are cautioned not to place undue weight on our reserve volumes or PV-10 based on such pricing when evaluating our financial condition or an investment in our securities. The process of estimating crude oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves. To prepare the reserve estimates included in this Annual Report, CG&A analyzed available geological, geophysical, production and engineering data and projected the production rates and timing of development expenditures. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as crude oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

 

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

 

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HighPeak Energys development projects and acquisitions will require substantial capital expenditures. HighPeak Energy may be unable to obtain required capital or financing on satisfactory terms, including as a result of recent increases in the cost of capital resulting from Federal Reserve policies or otherwise, which could reduce its ability to access or increase production and reserves.

 

The crude oil and natural gas industry is capital-intensive. HighPeak Energy has evaluated multiple development scenarios under multiple potential commodity price assumptions. Under its current 2024 development program, HighPeak Energy would expect to incur approximately $450 to $525 million of capital expenditures for drilling, completion, facilities and equipping costs and $50 - $60 million for field infrastructure, land and other costs. The ability to make these capital expenditures will be highly dependent on the price of crude oil and available funding of HighPeak Energy. Commodity prices have recovered from their April 2020 lows, with the calendar month average NYMEX WTI price of $72.12 per Bbl and last trading day NYMEX natural gas price of $2.71 per MMBtu for the month of December 2023. HighPeak Energy began the year with six rigs, then ran a five-rig program from February to mid-April of 2023 and subsequently decreased to a three-rig program beginning in May 2023 and a two-rig program from June 2023 to the end of October 2023 when it increased to a three-rig program through yearend. HighPeak Energy expects to average two (2) drilling rigs and one (1) frac crew during 2024. However, HighPeak Energy recognizes that commodity prices remain highly volatile and that its liquidity is limited, and as a result, there is no certainty that HighPeak Energy will operate a two (2) rig development program in the future.

 

HighPeak Energy expects to fund its forecasted capital expenditures with cash on its balance sheet, cash generated by operations, through borrowings under the Senior Credit Facility Agreement if needed and, depending on market circumstances, potential future debt or equity offerings. For terms of the Term Loan Credit Agreement and Senior Credit Facility Agreement, see Note 7 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

 

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

 

HighPeak Energy’s financing needs may require it to alter or increase its capitalization substantially through the issuance of debt or equity securities or the sale of assets. The availability and cost of these capital sources is cyclical, and these capital sources may not remain available, or we may not be able to obtain financing at a reasonable cost in the future. For example, due to the high levels of inflation in the U.S., the Federal Reserve and other central banks increased interest rates multiple times in 2022 and 2023, and although the Federal Reserve has indicated that such increases have ceased going into 2024, uncertainty remains as to when or if such elevated rates may be decreased. Such increased interest rates have increased the cost of capital and may prevent us from being able to obtain debt financing at favorable rates, or at all, which would materially impact our operations. In addition, conditions in the global capital markets have been volatile due to the conflict in Ukraine, the Israel-Hamas conflict or otherwise, making terms for certain types of financing difficult to predict, and in certain cases, resulting in certain types of financing being unavailable. Further, the issuance of additional indebtedness would require that an additional portion of cash flow from operations be used for the payment of interest and principal on its indebtedness, thereby further reducing its ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities would be dilutive to existing stockholders. The actual amount and timing of future capital expenditures may differ materially from estimates as a result of, among other things: commodity prices; actual drilling results; the availability of drilling rigs and other services and equipment; and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in actual capital expenditures, which would negatively impact HighPeak Energy’s ability to increase production.

 

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

 

 

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

 

proved reserves;

 

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

 

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

 

the amount of HighPeak Energy’s operating expenses;

 

cash settlements from HighPeak Energy’s derivative activities;

 

restrictions on capital expenditures in certain circumstances under the Term Loan Credit Agreement or the Senior Credit Facility Agreement;

 

HighPeak Energy’s ability to obtain additional debt financing, including increases to the Term Loan Credit Agreement or the Senior Credit Facility Agreement;

 

the duration and scope of the ongoing war between Russia and Ukraine and conflict in the Middle East, including between Israel and Hamas;

 

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

 

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

 

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

 

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

 

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Restrictions in the Term Loan Credit Agreement, the Senior Credit Facility Agreement and any future debt agreements could limit HighPeak Energys growth and ability to engage in certain activities.

 

The terms and conditions governing the Term Loan Credit Agreement, the Senior Credit Facility Agreement and any future additional indebtedness are expected to:

 

 

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

 

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

 

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

 

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

 

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

 

Our debt instruments also contain provisions that could have the effect of making it more difficult for a third party to acquire control of us. The Term Loan Credit Agreement and the Senior Credit Facility Agreement provide that a change of control constitutes an event of default and would permit the lenders to declare the indebtedness thereunder to be immediately due and payable. Our future credit facilities may contain similar provisions. The need to repay all such indebtedness may deter potential third parties from acquiring us.

 

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

 

The Company had an aggregate maximum commitment amount of $100.0 million and commitment amount of $75.0 million with respect to the Senior Credit Facility Agreement as of December 31, 2023. The Term Loan Credit Agreement also limits the amounts HighPeak Energy can borrow under the Senior Credit Facility Agreement to $100.0 million.

 

Our ability to repurchase shares under our recently announced share repurchase program is subject to certain considerations, and any share repurchases thereunder could increase the volatility of our stock prices and could diminish our cash reserves.

 

We recently adopted a share repurchase program that authorizes us to repurchase up to an aggregate $75.0 million of shares of our common stock. Our repurchase program expires December 31, 2024 and does not obligate HighPeak to repurchase any specific dollar amount or to acquire any specific number of shares and will depend upon, among other things, our earnings, liquidity, capital requirements, financial condition and other factors deemed relevant by our board of directors. Additionally, our Term Loan Credit Agreement limits our ability to repurchase shares of our common stock. Further, our share repurchases could affect our share trading prices, increase their volatility, reduce our cash reserves and may be suspended or terminated at any time, which may result in a decrease in the trading prices of our stock. Our Board of Directors may amend or suspend the share repurchase program at any time in its discretion. We can provide no assurances that we will repurchase shares of our common stock within the authorized amount or at all.

 

Our existing and future indebtedness may adversely affect our cash flows and ability to operate our business, remain in compliance and repay our debt.

 

In September 2023, in connection with the entry into the Term Loan Credit Agreement, the Prior Credit Agreement was terminated.  As of December 31, 2023, we had $1.2 billion of total indebtedness, including $1.2 billion outstanding of our Term Loan Credit Agreement and no indebtedness outstanding under our Senior Credit Facility Agreement, and available capacity under our Senior Credit Facility Agreement of approximately $68.9 million. The entirety of our $1.2 billion of total indebtedness is maturing in 2026.

 

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Among other events of default, an event of default will occur under the Term Loan Credit Agreement and the Senior Credit Facility Agreement if HighPeak Energy should fail to make any payment (whether of principal or interest and regardless of amount) in respect of any material debt, when and as the same shall become due and payable and such failure to pay continues beyond any applicable grace period, or any event or condition occurs that results in any material debt becoming due prior to its scheduled maturity or that enables or permits (with or without the giving of notice, the lapse of time or both) the holder or holders of any material debt or any trustee or agent on its or their behalf to cause any material debt to become due, or to require the redemption thereof or any offer to redeem to be made in respect thereof, prior to its scheduled maturity or require HighPeak Energy to make an offer in respect thereof and such event or condition continues beyond any applicable grace period. In the event of a default under these circumstances, lenders could terminate their commitments to lend or accelerate the loans and declare all amounts borrowed due and payable.

 

We may be unable to repay amounts due when they become due, and our ability to refinance our indebtedness on reasonable terms may be limited. Although our debt agreements contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to several significant qualifications and exceptions, and any indebtedness incurred in compliance with these restrictions could be substantial, and some of which may be secured by our assets. Our current level of indebtedness could have important consequences, such as:

 

 

making it difficult for us to satisfy our obligations under our indebtedness and contractual and commercial commitments;

 

increasing our vulnerability to adverse economic and industry conditions;

 

requiring us to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures and other general corporate purposes;

 

limiting our flexibility to plan for, or react to, changes in our business and the industry in which we operate;

 

restricting us from making strategic acquisitions or exploiting business opportunities;

 

placing us at a competitive disadvantage compared to our competitors that have less debt;

 

limiting our ability to borrow additional funds; and

 

decreasing our ability to compete effectively or operate successfully under adverse economic and industry conditions.

 

Our results of operations and cash flows vary significantly from year to year due to the cyclical nature of the crude oil and natural gas industry.

 

We expect our results of operations and cash flows to vary significantly from year to year due to the cyclical nature of the crude oil and natural gas industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. In addition, our future cash flows may be insufficient to meet our debt obligations and commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and as a result, our ability to generate cash flows from operations and to pay our debt. Many of these factors, such as crude oil, NGL and natural gas prices, regulatory factors, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control. If we do not generate sufficient cash flows from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

 

 

refinancing or restructuring our debt;

 

selling assets;

 

reducing or delaying capital investments; or

 

seeking to raise additional capital.

 

However, any alternative financing plans that we undertake, if necessary, may not allow us to meet our debt obligations. We cannot assure you that any refinancing or debt restructuring would be possible, that any assets could be sold or that, if sold, the timing of the sales and the amount of proceeds realized from those sales would be favorable to us or that additional financing could be obtained on acceptable terms. Our inability to generate sufficient cash flows to satisfy our debt obligations, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.

 

Our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our indebtedness could be at higher interest rates and could require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments, may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest or principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. 

 

In addition, if we fail to comply with the covenants or other terms of our Credit Agreements, our lenders will have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. Realization of any of these factors could adversely affect our financial condition.

 

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HighPeak Energy experiences periods of higher costs when commodity prices rise and inflation may adversely affect our operating results, which could negatively impact our profitability, cash flow and ability to complete development activities as planned. Continuing or worsening inflationary issues and associated changes in monetary policy have resulted in and may result in additional increases to the cost of our goods, services and personnel, which in turn could cause our capital expenditures and operating costs to rise.

 

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

 

Elevated inflation rates throughout 2023 and inflationary pressures have resulted in and may result in additional increases to the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise. Due to the high levels of inflation in the U.S., the Federal Reserve and other central banks increased interest rates multiple times in 2022 and 2023, and although the Federal Reserve has indicated that such increases have ceased going into 2024, uncertainty remains as to when or if such elevated rates may be decreased.  To the extent rates remain high, this could have the effects of raising the cost of capital and depressing economic growth, either of which—or the combination thereof—could hurt the financial and operating results of our business. To the extent elevated inflation remains, we may experience further cost increases for our operations, including oilfield services, labor costs and equipment if our drilling activity increases.

 

Higher crude oil and natural gas prices, continued inflation and supply chain issues as well as an increase in demand for services may cause the costs of materials and services to continue to rise. We cannot predict any future trends in the rate of inflation, and a significant increase in inflation, to the extent we are unable to recover higher costs through higher crude oil and natural gas prices and revenues, would negatively impact our business, financial condition and results of operations.

 

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Volatility in the political, legal and regulatory environments ahead of the upcoming U.S. presidential election and 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 OPEC+ policy decisions could have a material adverse impact on our business, financial condition or future results.

 

Our business, financial condition and future results are subject to political and economic risks and uncertainties, including volatility in the political, legal and regulatory environments ahead of the upcoming U.S. presidential election and instability resulting from civil unrest, political demonstrations, mass strikes or armed conflict or other crises in crude oil or natural gas producing areas such as the ongoing war between Russia and Ukraine and the Israel-Hamas conflict.

 

The United States and other countries and certain international organizations have imposed broad-ranging and severe economic sanctions on Russia and certain Russian individuals, banking entities and corporations as a response, and additional sanctions may be imposed in the future. This conflict and the resulting sanctions and concerns regarding global energy security have contributed to increases and volatility in the prices for crude oil and natural gas. The length, impact, and outcome of the ongoing war between Russia and Ukraine is highly unpredictable, and such events or any further hostilities in Ukraine or elsewhere could severely impact the world economy and may adversely affect our financial condition. Furthermore, escalations of the Israel-Hamas conflict may result in heightened geopolitical risks for crude oil and natural gas markets, given the significant share of global oil supply in the Middle East. While the Company does not have operations overseas, these conflicts elevate the likelihood of supply chain disruptions, heightened volatility in crude oil and natural gas prices and negative effects on our ability to raise additional capital when required and could have a material adverse impact on our business, financial condition or future results.

 

Currently, global crude oil inventories are low relative to historical levels and supply from OPEC+ and other crude oil producing nations are not expected to be sufficient to meet forecasted crude oil demand growth for the next few years. It is believed that many OPEC+ countries will be unable to increase their production levels or even produce at expected levels due to their lack of capital investments in developing incremental crude oil supplies over the past few years. In November 2023, OPEC+ determined to reduce production beginning in early 2024 by 2.2 million Bopd, due to the uncertainty surrounding the global economic and crude oil market outlooks. Furthermore, sanctions and import bans on Russian crude oil have been implemented by various countries in response to the war in Ukraine, further impacting global crude oil supply. Still, crude oil and natural gas prices have declined from the highs experienced in second quarter of 2022 and could decrease or increase with any changes in demand due to, among other things, uncertainty and volatility from global supply chain disruptions attributable to the pandemic, the ongoing conflict in Ukraine, the Israel-Hamas conflict, international sanctions, speculation as to future actions by OPEC+, increasing inflation and government efforts to reduce inflation, and possible changes in the overall health of the global economy, including a prolonged recession. Further, the volatility in crude oil and natural gas prices could accelerate a transition away from fossil fuels, resulting in reduced demand over the longer term. To what extent these and other external factors (such as government action with respect to climate change regulation) ultimately impact our future business, liquidity, financial condition, and results of operations is highly uncertain and dependent on numerous factors, including future developments, which are not within our control and cannot be accurately predicted.

 

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

 

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

 

Production may be interrupted, or shut-in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline, gathering, processing or transportation system access or capacity, various contaminants, field labor issues or strikes, or we might voluntarily curtail production in response to market or other conditions. Some of these risks may be exacerbated by other risks that we face. For instance, the potential exists for some of our wells to produce high levels of hydrogen sulfide, a highly toxic, naturally-occurring gas frequently associated with crude oil and natural gas production. Safe handling of hydrogen sulfide gas requires highly skilled operations and field personnel as well as specialized infrastructure, treating facilities, disposal facilities, and/or third-party sour gas takeaway. If we are unable to successfully secure adequate treatment and/or sour gas takeaway capacity from third parties when and if necessary, our production may be adversely impacted. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flows and results of operations.

 

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

 

During 2020, the reduction in global demand caused by COVID-19, coupled with the actions of foreign crude oil producers such as Saudi Arabia and Russia, materially decreased global crude oil prices and generated a surplus of crude oil. This significant surplus created a saturation of storage and caused imminent crude storage constraints, which led to, and in the future may further lead to the shut-in of production of our wells due to the lack of sufficient markets or the lack of availability and capacity of processing, gathering, storing and transportation systems. Additionally, several state crude oil and natural gas authorities, including the TRRC, implemented or considered implementing crude oil and natural gas production limits in an effort to stabilize declining commodity prices. To the extent adopted, such production limits could not only reduce our revenue, but also, if wells are required to be shut-in for extended periods of time due to such production limits, result in expenditures related to well plugging and abandonment. Cost increases necessary to bring wells back online may be significant enough that such wells would become uneconomic at low commodity price levels, which may lead to decreases in HighPeak Energy’s proved reserve estimates and potential impairments and associated charges to its earnings. HighPeak Energy curtailed the majority of its production in April 2020. However, prices increased, and HighPeak Energy management began returning its wells to production in mid-July 2020. As of December 31, 2023, HighPeak Energy was running a three-rig program and expects to average two (2) drilling rigs and one (1) frac crew during 2024 under our current development plan. HighPeak Energy will continue to monitor the extent by which prices continue to increase and/or stabilize as we execute our capital expenditure program. Any shut-in or curtailment of the crude oil, NGL and natural gas produced from HighPeak Energy’s fields could adversely affect its financial condition and results of operations.

 

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

 

As of December 31, 2023, approximately 64% of HighPeak Energy’s acreage was held by production. Generally, the leases for net acreage not held by production will expire at the end of their primary term unless production is established in paying quantities under the units containing these leases or the leases are extended or renewed. From 2024 through 2026, approximately 21%, 14% and 1%, respectively, of the net acreage associated with the leases are set to expire. If the leases expire and HighPeak Energy is unable to renew the leases, HighPeak Energy will lose its right to develop the related properties. Although HighPeak Energy intends to hold substantially all these leases through its development drilling program or extend substantially all the net acreage associated with identified drilling locations through a combination of exploratory and development drilling, a portion of such leases may be extended or renewed. Additionally, any payments related to such extensions or renewals may be more than anticipated. Please see “Items 1 and 2: Business and Properties—Reserve Data—Undeveloped Acreage Expirations” for more information regarding acreage expirations and our plans for extending our acreage. HighPeak Energy’s ability to drill and develop its acreage and establish production to maintain its leases depends on a number of uncertainties, including crude oil, NGL and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing, frac sand and distribution systems, regulatory approvals and other factors.

 

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

 

Accounting rules require that HighPeak Energy periodically review the carrying value of its properties for possible impairment, whenever changes in events or circumstances indicate that the carrying value of its properties 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. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, HighPeak Energy may be required to write-down the carrying value of its properties. A write-down constitutes a non-cash impairment charge to earnings. Historically, crude oil, NGL and natural gas prices have been volatile. For example, during the period from January 1, 2020 through December 31, 2023, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $16.70 to a high of $114.34, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.50 to a high of $9.35.

 

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

 

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

 

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

 

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

 

 

landing its wellbore in the desired drilling zone;

 

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

 

Running and cementing casing throughout the wellbore; and
 

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

 

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

 

 

the ability to fracture stimulate the planned number of stages;

 

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

 

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

 

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

 

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

 

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

 

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

 

HighPeak Energy’s decisions to develop or purchase prospects or properties will depend, in part, on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of reserves.” In addition, the cost of drilling, completing and operating wells will often be uncertain.

 

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

 

 

delays imposed by, or resulting from, compliance with regulatory requirements, including the IRA 2022, limitations on wastewater disposal, emission of GHGs and hydraulic fracturing;

 

pressure or irregularities in geological formations;

 

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

 

equipment failures, accidents or other unexpected operational events;

 

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

 

lack of available capacity on interconnecting transmission pipelines;

 

lack of availability of water and electricity;

 

adverse weather conditions;

 

issues related to compliance with environmental regulations;

 

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

 

declines in crude oil and natural gas prices;

 

limited availability of financing on acceptable terms;

 

title issues; and

 

other market limitations in HighPeak Energy’s industry.

 

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

 

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

 

In May 2021, the Company entered into a crude oil marketing contract with Delek as the purchaser and DKL Permian Gathering, LLC (“DKL”) as the gatherer and transporter. The contract includes the Company’s current and future crude oil production from the majority of its horizontal wells in Flat Top where DKL is constructing a crude oil gathering system and custody transfer meters to most of the Company’s central tank batteries. The contract contains a minimum volume commitment commencing October 2021 based on the gross barrels delivered at the Company’s central tank battery facilities and is 5,000 Bopd for the first year, 7,500 Bopd for the second year and 10,000 Bopd for the remaining eight years of the contract. However, the Company has the ability under the contract to cumulatively bank excess volumes delivered to offset future minimum volume commitments. For the period from October 1, 2021 to December 31, 2023, the Company has delivered approximately 29,600 Bopd under the contract. The remaining monetary commitment as of December 31, 2023, if the Company never delivers any additional volumes under the agreement, is approximately $7.8 million.

 

The Company is party to an amended agreement whereby it has agreed to purchase at least 1.6 million tons of frac sand over a two-year period beginning July 1, 2022. There are stipulations in the agreement that reduce this commitment should we experience a downturn in crude oil prices. As of December 31, 2023, the Company has purchased approximately 1.2 million tons of frac sand under the contract.  However, generally if the Company never takes delivery of any additional frac sand under the agreement, the monetary commitment that remains as of December 31, 2023 is approximately $9.5 million.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

Standardized measure is a reporting convention that provides a common basis for comparing crude oil and natural gas companies subject to the rules and regulations of the SEC. Standardized measure requires historical twelve-month pricing as required by the SEC as well as operating and development costs prevailing as of the date of computation. For example, our reserve volumes and PV-10 as disclosed in this Annual Report are based on assumed commodity prices of $78.22 per Bbl of crude oil and NGL and $2.637 per MMBtu of natural gas as of December 31, 2023, which are substantially higher than December 31, 2023 front-month forward pricing of $71.65 per Bbl of crude oil and $2.514 per Mcf of natural gas. Consequently, it may not reflect the prices ordinarily received or that will be received for crude oil and natural gas production because of varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the crude oil and natural gas properties. As a result, estimates included in this Annual Report of future net cash flow may be materially different from the future net cash flows that are ultimately received. Therefore, the standardized measure of estimated reserves included in this Annual Report should not be construed as an accurate estimate of the current fair value of such proved reserves. Accordingly, you are cautioned not to place undue weight on our reserve volumes or PV-10 based on such pricing when evaluating our financial condition or an investment in our securities.

 

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

 

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

 

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

 

HighPeak Energy is not the operator on all its acreage or drilling locations, and, therefore, HighPeak Energy is not able to control the timing of exploration or development efforts, associated costs or the rate of production of any non-operated assets, and could be liable for certain financial obligations of the operators or any of its contractors, to the extent such operator or contractor is unable to satisfy such obligations.

 

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

 

 

the timing and amount of capital expenditures;

 

the operator’s expertise and financial resources;

 

the approval of other participants in drilling wells;

 

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the selection of technology; and

 

the rate of production of reserves, if any.

 

This limited ability to exercise control over the operations and associated costs of some of HighPeak Energy’s drilling locations could prevent the realization of targeted returns on capital in drilling or acquisition activities. Further, HighPeak Energy may be liable for certain financial obligations of the operator of a well in which it owns a working interest to the extent such operator becomes insolvent and cannot satisfy such obligations. Similarly, HighPeak Energy may be liable for certain obligations of contractors to the extent such contractor becomes insolvent and cannot satisfy their obligations. The satisfaction of such obligations could have a material adverse effect on HighPeak Energy’s financial condition. For more information about certain of HighPeak Energy’s assets, see the sections entitled “Items 1 and 2. Business and Properties” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

The development of estimated PUDs may take longer and may require higher levels of capital expenditures than anticipated. Therefore, estimated PUDs may not be ultimately developed or produced.

 

As of December 31, 2023, the Company’s assets contained 74,569 MBoe of proved undeveloped reserves, or PUDs, consisting of 60,923 MBbls of crude oil, 7,913 MBbls of NGL and 34,400 MMcf of natural gas. Development of these proved undeveloped reserves may take longer and require higher levels of capital expenditures than anticipated. Estimated future development costs relating to the development of such PUDs at December 31, 2023 are approximately $1.5 billion over the next five (5) years. HighPeak Energy’s ability to fund these expenditures is subject to several risks. See “—HighPeak Energy’s development projects and acquisitions will require substantial capital expenditures. HighPeak Energy may be unable to obtain required capital or financing on satisfactory terms, which could reduce its ability to access or increase production and reserves.” Delays in the development of reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the value of the estimated PUDs and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause HighPeak Energy to have to reclassify PUDs as unproved reserves. Furthermore, there is no certainty that HighPeak Energy will be able to convert PUDs to developed reserves or that undeveloped reserves will be economically viable or technically feasible to produce.

 

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

 

Unless HighPeak Energy replaces its reserves with new reserves and develops those new reserves, its reserves and production will decline, which would adversely affect future cash flows and results of operations.

 

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

 

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

 

HighPeak Energy expects to sell its production to a relatively small number of customers, as is customary in the crude oil and natural gas business. For the year ended December 31, 2023, there were two purchasers that accounted for approximately 96% of our revenue (one at approximately 82% and one at approximately 14%) and for the years ended December 31, 2022 and 2021, there was one purchaser that accounted for approximately 88% and 94% of our revenue, respectively. No other purchaser accounted for 10% or more of such revenues during such period. The loss of any such greater than 10% purchaser could adversely affect HighPeak Energy’s revenues in the short term. See the section entitled “Items 1 and 2: Business and Properties—Operations—Marketing and Customers” for additional information. HighPeak Energy expects to depend upon these or other significant purchasers for the sale of most of its crude oil and natural gas production. HighPeak Energy cannot ensure that it will continue to have ready access to suitable markets for its future crude oil and natural gas production.

 

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HighPeak Energys operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to its business activities.

 

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

 

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

 

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

 

 

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

 

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

 

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

 

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the SDWA, which ensures the quality of the nations’ public drinking water through adoption of drinking water standards and control over the subsurface injection of fluids into belowground formations;

 

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

 

CERCLA, which imposes liability on generators, transporters and those who arrange for transportation or disposal of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur, as well as imposes liability on present and certain past owners and operations of sites where hazardous substance releases have occurred or are threatening to occur;

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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HighPeak Energy may incur substantial losses and be subject to substantial liability claims as a result of operations. Additionally, HighPeak Energy may not be insured for, or insurance may be inadequate to protect HighPeak Energy against, these risks.

 

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

 

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

 

 

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

 

abnormally pressured formations;

 

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

 

fires, explosions and ruptures of pipelines;

 

personal injuries and death;

 

natural disasters; and

 

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

 

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

 

 

injury or loss of life;

 

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

 

pollution and other environmental or natural resource damage;

 

regulatory investigations and penalties; and

 

repair and remediation costs.

 

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

 

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

 

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

 

 

unexpected drilling conditions;

 

title issues;

 

pressure or lost circulation in formations;

 

equipment failures or accidents;

 

adverse weather conditions;

 

compliance with, or changes in, environmental and other governmental or contractual requirements, including the IRA 2022; and

 

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

 

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HighPeak Energy may be unable to make additional attractive acquisitions or successfully integrate acquired businesses with its current assets, and any inability to do so may disrupt its business and hinder its ability to grow.

 

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

 

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

 

In addition, the Term Loan Credit Agreement and Senior Credit Facility Agreement impose certain limitations on HighPeak Energy’s ability to enter into mergers or combination transactions and on HighPeak Energy’s and its restricted subsidiaries’ ability to incur certain indebtedness, which could indirectly limit its ability to acquire assets and businesses.

 

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

 

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

 

The unavailability or high cost of drilling rigs, equipment, supplies, personnel, frac crews and oilfield services due to commodity price volatility or supply constraints as a result of the conflict in Ukraine, the Israel-Hamas conflict, elevated interest rates and associated policies of the Federal Reserve could adversely affect HighPeak Energys ability to execute its development plans within its budget and on a timely basis and consequently could materially and adversely affect our cash flows and results of operations.

 

The demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the crude oil and natural gas industry, can fluctuate significantly, often in correlation with crude oil, NGL and natural gas prices, causing periodic shortages of equipment, supplies and needed personnel. Additionally, supply constraints due to the conflict in Ukraine, the Israel-Hamas conflict, elevated interest rates and associated policies of the Federal Reserve has increased the cost of oilfield services. HighPeak Energy’s operations are concentrated in areas in which oilfield activity levels have previously increased rapidly. If that were to happen again, demand for drilling rigs, equipment, supplies and personnel may increase the costs for these services. Access to transportation, processing and refining facilities in these areas may become constrained resulting in higher costs and reduced access for those items. Historically, crude oil, NGL and natural gas prices have been volatile. For example, during the period from January 1, 2020 through December 31, 2023, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $16.70 to a high of $114.34, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.50 to a high of $9.35. For the month of April 2020, the calendar month average NYMEX WTI crude oil price was $16.70 and last trading day NYMEX natural gas price was $1.63 per MMBtu. However, prices have since increased. To the extent commodity prices improve in the future, the demand for and prices of these goods and services are likely to increase and HighPeak Energy could encounter delays in or an inability to secure the personnel, equipment, power, services, resources and facilities access necessary for it to resume or increase HighPeak Energy’s development activities, which could result in production volumes being below its forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on cash flow and profitability. Furthermore, if it is unable to secure a sufficient number of drilling rigs at reasonable costs, HighPeak Energy may not be able to drill all its acreage before its leases expire.

 

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

 

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

 

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The IRA 2022 could accelerate the transition to a low carbon economy and could impose new costs on our operations.

 

In August 2022, President Biden signed the IRA 2022 into law. The IRA 2022 contains hundreds of billions in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, amongst other provisions. In addition, the IRA 2022 imposes the first ever federal fee on the emission of greenhouse gases through a methane emissions charge. The IRA 2022 amends the federal Clean Air Act to impose a fee on the emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the onshore petroleum and natural gas production categories. The methane emissions charge would start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA 2022. In addition, the multiple incentives offered for various clean energy industries referenced above could further accelerate the transition of the economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives. This could decrease demand for crude oil and natural gas, increase our compliance and operating costs and consequently adversely affect our business.

 

In addition, fuel conservation measures, alternative fuel requirements and increasing consumer demand for alternatives to crude oil, NGL and natural gas could reduce demand for crude oil, NGL and natural gas. The IRA 2022 incentives discussed above could further accelerate the transition of our economy to alternatives to crude oil, NGL and natural gas. The impact of the changing demand for crude oil, NGL and natural gas may have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

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

 

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

 

Should our operators fail to comply with all applicable regulatory agency administered statutes, rules, regulations and orders, our operators could be subject to substantial penalties and fines.

 

Under the Energy Policy Act of 2005, FERC has civil penalty authority under the Natural Gas Act of 1938 to impose penalties for current violations of up to $1,544,521 per day for each violation (annually adjusted for inflation) and disgorgement of profits associated with any violation. While our operators’ operations have not been regulated by the FERC as a natural gas company under this law, the FERC has adopted regulations that may subject certain of our operators’ otherwise non-FERC jurisdictional facilities to the FERC annual reporting requirements. Our operators also must comply with the anti-market manipulation rules enforced by the FERC. Additional rules and legislation pertaining to those and other matters may be considered or adopted by the FERC from time to time. Additionally, the FTC has regulations intended to prohibit market manipulation in the petroleum industry with authority to fine violators of the regulations civil penalties of up to $1,472,546 per day (annually adjusted for inflation) and the CFTC prohibits market manipulation in the markets regulated by the CFTC, including similar anti-manipulation authority with respect to crude oil swaps and futures contracts as that granted to the CFTC with respect to crude oil purchases and sales. The CFTC rules subject violators to a civil penalty of up to the greater of $1,450,040 per day (annually adjusted for inflation) or triple the monetary gain to the person for each violation. Failure to comply with those regulations in the future could subject our operators to civil penalty liability, as described in “Items 1 and 2: Business and Properties—Regulation of the Crude Oil and Natural Gas Industry.”

 

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

 

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

 

In the United States, no comprehensive climate change legislation has been implemented at the federal level, though federal law such as the IRA 2022 advances numerous climate-related objectives. However, with the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted rules that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. The regulation of methane from crude oil and natural gas facilities has been subject to uncertainty in recent years. Although, in September 2020, the Trump Administration revised prior promulgated regulations to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations, the U.S. Congress approved, and President Biden signed into law, a resolution under the Congressional Review Act to repeal the September 2020 revisions, effectively reinstating the prior standards. Additionally, in December 2023, the EPA finalized a rule that established OOOOb as new source and OOOOc as first-time existing source standards of performance for methane and VOC emissions for the crude oil and natural gas source category. Under the final rule, owners or operators of affected emission units or processes will have two years to prepare and submit their plans to impose methane emission controls on existing sources. The presumptive standards under the final rule are generally the same for both new and existing sources, including enhanced leak detection using optical gas imaging and subsequent repair requirements, reduction of regulated emissions through capture and control systems, zero-emission requirements for certain equipment or processes, operations and maintenance requirements and requirements for “green well” completions. The rule also establishes a “super-emitter” response program to timely mitigate emissions events as detected by governmental agencies or qualified third parties, triggering certain investigation and repair requirements. Separately, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, the United Nations-sponsored “Paris Agreement” requires member states to submit non-binding, individually-determined reduction goals every five years after 2020. President Biden has recommitted the United States to the Paris Agreement and in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. In November 2021, the international community gathered again in Glasgow at COP26, during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-CO2 GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. These goals were reaffirmed at COP27, and countries were called upon to accelerate their efforts, though no firm commitments were made. At COP28, the parties entered into an agreement to transition away from fossil fuels in energy systems and increase renewable energy capacity, though no timeline for doing so was set. The impacts of these actions cannot be predicted at this time. For more information, see the section entitled “Items 1 and 2. Business and Properties—Regulation of Environmental and Occupational Safety and Health Matters— Regulation of Greenhouse Gas Emissions.”

 

Governmental, scientific and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by certain candidates in public office. On January 27, 2021, President Biden signed an executive order calling for substantial action on climate change, including, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry and increased emphasis on climate-related risks across agencies and economic sectors. Additional actions that could be pursued by the Biden Administration may include more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities. For example, on January 26, 2024, President Biden announced a temporary pause on pending decisions on new exports of LNG to countries that the U.S. does not have free trade agreements with, pending Department of Energy review. Litigation risks are also increasing, as a number of entities have sought to bring suit against crude oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to climate change or that such companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.

 

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There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all their investments into other sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. For example, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing and/or underwriting activities to net zero by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. In late 2020, the Federal Reserve announced it has joined the NGFS and, in November 2021, issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. In September 2022, the Federal Reserve announced that six of the U.S.’ largest banks will participate in a pilot climate scenario analysis exercise, which took place throughout 2023, to enhance the ability of firms and supervisors to measure and manage climate-related financial risk. Limitation of investments in and financing for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities. In addition, the SEC proposed a rule requiring registrants to make certain climate-related disclosures, including emissions data. The final rule remains pending, and we cannot predict its final form or substance. To the extent the rules impose additional reporting obligations, we could face increased costs. Some states have also enacted or are considering climate-related disclosure requirements. Additionally, we cannot predict how financial institutions and investors might consider any information disclosed under a final rule when making investment decisions, and as a result it is possible that we could face increases with respect to the costs of, or restrictions imposed on, our access to capital. For more information, see the section entitled “Items 1 and 2. Business and Properties—Regulation of Environmental and Occupational Safety and Health Matters— Regulation of Greenhouse Gas Emissions.”

 

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

 

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

 

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

 

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

 

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

 

Moreover, some states and local governments have adopted, and other governmental entities are considering adopting, regulations that could impose more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations, including states in which our properties are located. For example, Texas, among others, has adopted regulations that impose new or more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. States could also elect to prohibit high volume hydraulic fracturing altogether. In addition to state laws, local land use restrictions, such as city ordinances may restrict drilling in general and/or hydraulic fracturing in particular. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where HighPeak Energy will operate, it could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells. For more information, see the section entitled “Items 1 and 2. Business and Properties—Regulation of Environmental and Occupational Safety and Health Matters— Hydraulic Fracturing Activities.”

 

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

 

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

 

In addition, a number of lawsuits have been filed in some states, including Texas, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. For example, Texas has imposed certain limits on the permitting or operation of disposal wells in areas with increased instances of induced seismic events. In some instances, regulators may also order that disposal wells be shut-in. In September 2021, the TRRC issued a notice to operators in the city of Midland area to reduce daily injection volumes following multiple earthquakes above a 3.5 magnitude over an 18-month period. The notice also required disposal well operators to provide injection data to TRRC staff to further analyze seismicity in the area. Subsequently, the TRRC ordered the indefinite suspension of all deep crude oil and natural gas produced water injection wells in the area, effective December 31, 2021. The response area was expanded to cover an additional 17 wells following another earthquake in December 2022. Additional response areas have been established, most recently the Northern Culberson-Reeves Seismic Response Area, where 23 deep disposal well permits were suspended in December 2023.

 

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

 

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

 

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

 

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

 

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

 

Increases in interest rates could adversely affect HighPeak Energys business.

 

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

 

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

 

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

 

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

 

Crude oil and natural gas operations in HighPeak Energy’s operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Such restrictions may limit HighPeak Energy’s ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay HighPeak Energy’s operations or materially increase its operating and capital costs. Permanent restrictions imposed to protect threatened or endangered species, other protected species (such as migratory birds), or their habitat could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where HighPeak Energy operates as threatened or endangered could cause it to incur increased costs arising from species protection measures or could result in limitations on its activities that could have a material and adverse impact on its ability to develop and produce reserves. For example, a review is currently pending to determine whether the dunes sagebrush lizard should be listed and, in November 2022, the FWS listed two distinct population segments of the lesser prairie-chicken under the ESA. If these species or others are listed, the FWS and similar state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of or access to federal, state and private lands. To the extent species are listed under the ESA or similar state laws, or previously unprotected species are designated as threatened or endangered in areas where our properties are located, operations on those properties could incur increased costs arising from species protection measures and face delays or limitations with respect to production activities thereon. For more information, see the section entitled “Items 1 and 2. Business and Properties—Regulation of Environmental and Occupational Safety and Health Matters— Endangered Species Act and Migratory Birds.”

 

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

 

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

 

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

 

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

 

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HighPeak Energys business could be adversely affected by security threats, including cyber-security threats, and relate