HIGHPEAK ENERGY, INC.

TABLE OF CONTENTS

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:

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

Cautionary Statement Concerning Forward-Looking Statements

This 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:

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.

HIGHPEAK ENERGY, INC.

PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

Overview

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

HighPeak Energy focuses on the Midland Basin and specifically the Howard 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 has recently experienced significant redevelopment activity in the Lower Spraberry and Wolfcamp A formations utilizing modern horizontal drilling technology, with some operators having additional success developing the Middle Spraberry, Jo Mill, Wolfcamp B and Wolfcamp D formations, through the use of modern, high-intensity hydraulic fracturing techniques, decreased frac spacing, increased proppant usage and increased lateral lengths. Our interpretation of available IHS Markit data as well as our own drilling and completion results show that Howard and Borden Counties have 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, 2022, the Company’s assets consisted of two generally contiguous leasehold positions of approximately 125,730 gross (107,704 net) acres covering various subsurface depths, approximately 56% of which were held by production, with an average working interest of approximately 86%. 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, Lower Spraberry and Wolfcamp D formations with additional wells planned in the Wolfcamp B and Wolfcamp C 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, 2022, HighPeak Energy had forty-seven 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 crude oil and natural gas and is estimated by the United States Geologic Survey to contain significant remaining hydrocarbon potential.

HighPeak Energy developed its properties using up to six (6) drilling rigs and three (3) frac crews during the year ended December 31, 2022.  The Company expects to average four to five (4-5) drilling rigs and two to three (2-3) frac crews during 2023 under our current development plan. HighPeak Energy expects to fund its forecasted capital expenditures with cash on its balance sheet, cash generated by operations, through borrowings under the Credit Agreement, and, depending on market circumstances, potential future debt or equity offerings.

HighPeak Energy has discretion to modify its capital program. Because HighPeak Energy operates a high percentage of its acreage, capital expenditure amounts and timing are largely discretionary and within its control. HighPeak Energy determines its capital expenditures depending on a variety of factors, including, but not limited to, the success of its drilling activities, prevailing and anticipated prices for crude oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, drilling and acquisition costs and the level of participation by other working interest owners. A deferral of planned capital expenditures, particularly with respect to drilling and completing new wells, could result in a reduction in anticipated production and cash flows. Additionally, if HighPeak Energy curtails or reallocates priorities in its drilling program, HighPeak Energy may lose a portion of its acreage through lease expirations. However, in the event of any such curtailment or reallocation of priorities, HighPeak Energy would expect to prioritize lease retention to minimize any expirations.  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, 2022, 2021 and 2020 were prepared by Cawley, Gillespie and Associates, Inc. (“CG&A”). As of December 31, 2022, 2021 and 2020, the Company’s assets contained 122,958, 64,213 and 22,515 MBoe, respectively, of estimated proved reserves. In addition, as of December 31, 2022, 2021 and 2020, the estimated proved reserves of the Company’s assets were estimated by CG&A to be 92%, 92% and 94% crude oil and NGL, respectively, and 8%, 8% and 6% natural gas, respectively. The following table provides summary information regarding the estimated proved reserves data of the Company’s assets based on the 2022 Reserve Report, 2021 Reserve Report and 2020 Reserve Report (each defined below) as of December 31, 2022, 2021 and 2020, respectively:

Reserve Data

Preparation of Reserve Estimates

The reserve estimates as of December 31, 2022, 2021 and 2020 included in this Annual Report are based on evaluations prepared by CG&A in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC (individually, the “2022 Reserve Report,” the “2021 Reserve Report” and the “2020 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, 2022, 2021 and 2020, respectively, of HighPeak Energy, prepared by CG&A, were led by W. Todd Brooker. Mr. Brooker is a Licensed Professional Engineer in the State of Texas and has been practicing at CG&A for 30 years and, including such 30 years, has over 32 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, 2022, 2021 and 2020, respectively, were prepared by geologists and reservoir engineers who integrate geological, geophysical, engineering and economic data to produce high quality reserve estimates and economic forecasts. The process was supervised by Christopher Mundy, Vice President, Reserves and Evaluations, for HighPeak Energy, who has approximately 26 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, 2022, 2021 and 2020, respectively, were reviewed and approved by our technical staff, other members of senior management and our Chief Executive Officer. The Reserve Reports prepared by CG&A contain further discussion of the reserve estimates and the procedures used in connection with its preparation.

The reserve estimates as of December 31, 2022, 2021 and 2020, included in this Annual Report are based on evaluations prepared by the independent petroleum engineering firm CG&A representing 100% of the Company’s assets’ total net proved reserves in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. The Independent Reserve Engineers were selected for their historical experience and geographic expertise in engineering similar resources.

Estimated Proved Reserves

The following tables present the estimated net proved crude oil and natural gas reserves as of December 31, 2022, 2021 and 2020, based on the Reserve Reports of the Company’s assets as of such date.

Development of Proved Undeveloped Reserves

The following table summarizes the changes in HighPeak Energy’s proved undeveloped reserves for the period from August 22, 2020 through December 31, 2020 and the years ended December 31, 2021 and 2022 (the “Successor Period”):

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

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

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

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

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

Proved undeveloped reserves changed during the Predecessor Period from January 1, 2020 to August 21, 2020 primarily as a result of the following significant factors:

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 year ended December 31, 2022, $391.3 million 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, 2022, all our proved undeveloped reserves are scheduled to be developed within five years from the date they were initially recorded.

PV-10

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

Unlike PV-10, the standardized measure deducts future U.S. federal income taxes and Texas margin taxes and abandonment obligations on wells with no proved reserves as of December 31, 2022, 2021 and 2020, respectively. Neither PV-10 nor standardized measure represents an estimate of the fair market value of the applicable crude oil and natural gas properties. It is industry standard to use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

The following tables present the undiscounted estimated future net cash flows, PV-10 and standardized measure of the proved reserves of the Company at December 31, 2022, 2021 and 2020 (in thousands):

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, 2022, 2021 and 2020, and assuming commodity prices as set forth below. For the purpose of determining prices used in our reserve reports, in accordance with SEC guidelines, CG&A uses the unweighted arithmetic average of the prices on the first day of each month in the 12-month period ended December 31, 2022, 2021 and 2020. These prices were $93.67, $66.56 and $39.57 per Bbl for crude oil and $6.358, $3.598 and $1.985 per MMBtu for natural gas, respectively, before adjustment for energy content, gathering, transportation and processing fees and basis differential adjustments. The average adjusted prices realized over the remaining lives of the Company’s assets by CG&A were $94.59, $66.10 and $38.08 per barrel of crude oil, $36.69, $29.76 and $12.27 per barrel of NGL and $4.871, $0.786 and -$1.304 per Mcf of natural gas as of December 31, 2022, 2021 and 2020, respectively. These prices should not be interpreted as a prediction of future prices. The amounts shown do not give effect to non-property-related expenses, such as corporate general and administrative expenses and debt service, or to DD&A.

Production, Revenue and Price History

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

The following tables summarize the average net sales volumes, average unhedged sales prices by product and lease operating expenses of the Company for the years ended December 31, 2022, 2021 and 2020:

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, 2022.

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, 2022. Approximately 56% of the net acreage of HighPeak Energy was held by production as of December 31, 2022.

Undeveloped Acreage Expirations

The following table sets forth the number of total net undeveloped acres as of December 31, 2022 across HighPeak Energy’s properties that will expire in 2023, 2024, 2025, 2026, 2027 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.

With respect to the 19,391 net acres expiring in 2023 across our properties, HighPeak Energy intends to retain substantially all 19,391 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, 2022 and 2021 and the period from August 22, 2020 through December 31, 2020 (Successor), and the period from January 1, 2020 through August 22, 2020 (Predecessor). The information should not be indicative of future performance, nor should it be assumed there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. As of December 31, 2022 and not included in the following table, were 11 gross (10.7 net) wells in the process of being drilled and 54 gross (46.8 net) wells either waiting on completion or in various stages of completion operations. As of December 31, 2022, HighPeak Energy was running a six-rig program. The Company expects to average four to five (4-5) drilling rigs and two to three (2-3) frac crews during 2023 under our current development plan. Our development program may change based on capital availability and other factors.

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, 2022, the Company had delivered approximately 22,800 Bopd under the contract, banking excess volumes at the outset. There are no material commitments to deliver a fixed and determinable quantity of natural gas production from the Company’s assets to customers under existing contracts. Given the current production levels coupled with the wells planned to come on production in 2023 and beyond, the Company expects to meet the volume commitments under this agreement well in advance of the requirement.

Operations

General

As of December 31, 2022, HighPeak Energy’s properties consisted of 125,730 gross (107,704 net) acres with an average working interest of approximately 86%.

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, 2022, 2021 and 2020.

* 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, 2022, 2021 or 2020. 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, 2022, the Company has delivered approximately 22,800 Bopd under the contract. The remaining monetary commitment as of December 31, 2022, if the Company never delivers any additional volumes under the agreement, is approximately $18.3 million. In addition, HighPeak Energy sells its natural gas production from the Company’s assets to multiple third-party purchasers pursuant to the terms of natural gas processing and purchase contracts at varying rates. The natural gas production is gathered and processed under agreements with a primary term and generally an evergreen extension option.

Competition

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

There is also competition between crude oil and natural gas producers and other industries producing energy and fuel. For example, HighPeak Energy also faces indirect competition from alternative energy sources, including wind and solar. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which HighPeak Energy operates, 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.

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 its jurisdiction. The failure to comply with these rules and regulations can result in substantial penalties.

Regulation Affecting Sales and Transportation of Commodities

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

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

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

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

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

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

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

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

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

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

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

Regulation of Environmental and Occupational Safety and Health Matters

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

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

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

Hazardous Substances and Waste Handling

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

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

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

Water Discharges, Fluid Disposal and NORM

The Water Pollution Control Act, also known as the Clean Water Act (“CWA”) and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other crude oil and natural gas wastes, into or near navigable waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”). The scope of jurisdiction under the CWA has been subject to several rulemakings by the EPA in recent years and is subject to ongoing litigation; additionally, in January 2023, the EPA and Corps published a final rule establishing a definition of “waters of the United States” based on the broader pre-2015 definition and related regulatory guidance and case law. However, this rule is subject to multiple legal challenges, which could have an impact on the definition or its implementation. Additionally, the Supreme Court heard arguments on Sackett v. EPA in October 2022, and is expected to issue its decision in 2023. 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. Obtaining permits has the potential to delay the development of crude oil and natural gas projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of crude oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.

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

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

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