UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

Commission File Number 000-06814

U.S.US ENERGY CORP.CORP.

(Exact Name of Company as Specified in its Charter)

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

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 [X] ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. YES [  ] ☐ NO [X] ☒

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 Company was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [X] ☒ 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 [X] ☒ NO [  ]☐

Indicate by check mark if disclosure of delinquent filers, pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K [  ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a 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 [X]☒ 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. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES [  ] ☐ NO [X] ☒

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the Registrant, based upon the closing price of the shares of common stock on the NASDAQ Capital Market as of the last business day of the most recently completed second fiscal quarter, June 30, 2019,2021, was $6,166,682.$21,163,394. For purposes of calculating the aggregate market value of shares held by non-affiliates, we have assumed that all outstanding shares are held by non-affiliates, except for shares held by each of our executive officers, directors and 5% or greater shareholders. In the case of 5% or greater shareholders, we have not deemed such shareholders to be affiliates unless there are facts and circumstances which would indicate that such shareholders exercise any control over our company, or unless they hold 10% or more of our outstanding common stock. These assumptions should not be deemed to constitute an admission that all executive officers, directors and 5% or greater shareholders are, in fact, affiliates of our company, or that there are not other persons who may be deemed to be affiliates of our company. Further information concerning shareholdings of our officers, directors and principal shareholders is included or incorporated by reference in Part III, Item 12 of this Annual Report on Form 10-K.

The Registrant had 1,404,817 24,873,812shares of its $0.01 par value common stock outstanding as of March 20, 2020.25, 2022.

Part III incorporates information by reference fromDOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement forrelating to its 2022 annual meeting of shareholders (the “2022 Proxy Statement”) are incorporated by reference into Part III of this Annual Report on Form 10-K where indicated. The 2022 Proxy Statement will be filed with the registrant’s 2020 Annual MeetingU.S. Securities and Exchange Commission within 120 days after the end of Shareholders.the fiscal year to which this report relates.

TABLE OF CONTENTS

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information discussed in this Annual Report includes “forward-looking statements” within the meaning of the federal securities laws, including 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”).and the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical facts are forward-looking statements.

Examples of forward-looking statements in this Annual Report include:

These forward-looking statements are identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could,” “up to,” and similar terms and phrases. Though we believe that the expectations reflected in these statements are reasonable, they involve certain assumptions, risks and uncertainties. Results could differ materially from those anticipated in these statements as a result of numerous factors including, among others:discussed below under “Summary of Risk Factors”, and under “Risk Factors”, below.

Finally, our future results will depend upon various other risks and uncertainties, including, but not limited to, those detailed in Item 1A “Risk Factors” in this Annual Report on Form 10-K. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements made above and elsewhere in this Annual Report on Form 10-K.

All forward-looking statements speak only at the date of the filing of this Annual Report. We do not assume a dutyundertake any obligation to update theseor revise publicly any forward-looking statements whetherexcept as a resultrequired by law, including the securities laws of new information, subsequent events or circumstances, changes in expectations, or otherwise.the United States and the rules and regulations of the SEC.

Glossary of Oil and Natural Gas Terms

The following are abbreviations and definitions of certain terms commonly used in the oil and natural gas industry and in this report. The definitions of proved developed reserves, proved reserves and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a) of Regulation S-X.

API. The American Petroleum Institute gravity, or API gravity, is a measure of how heavy or light a petroleum liquid is compared to water: if its API gravity is greater than 10, it is lighter and floats on water; if less than 10, it is heavier and sinks.

Bbl.One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcfe.One billion cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio of 6 Mcf of natural gas to 1 Bbl of oil, condensate or natural gas liquids.

BOE.A barrel of oil equivalent is determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil, condensate or natural gas liquid.

Boed. Barrels of oil equivalent per day.

Bopd. Barrels of per oil day.

Completion.The installation of permanent equipment for the production of oil or natural gas, or, in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned. Completion of the well does not necessarily mean the well will be profitable.

Developed Acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.

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

Dry Well. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or gas well.

Exploratory Well. A well drilled to find a new field or a new reservoir in a field previously found to be productive of oil or gas in another reservoir.

Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which we have a working interest.

Lease Operating Expenses. The expenses, usually recurring, which pay for operating the wells and equipment on a producing lease.

Mcf.One thousand cubic feet of natural gas.

Mcfe.One thousand cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio of 6 Mcf of natural gas to 1 Bbl of oil, condensate or natural gas liquids.

MMBtu.One million Btu, or British Thermal Units. One British Thermal Unit is the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Net Acres or Net Wells. Gross acres or wells multiplied, in each case, by the percentage working interest we own.

Net Production. Production that we own less royalties and production due to others.

NGL. Natural gas liquids.

Oil.Crude oil, condensate or other liquid hydrocarbons.

Operator.The individual or company responsible for the exploration, development, and production of an oil or gas well or lease.

Pay.The vertical thickness of an oil and natural gas producing zone. Pay can be measured as either gross pay, including non-productive zones or net pay, including only zones that appear to be productive based upon logs and test data.

Ppb. Means pounds per barrel.

PV-10.The pre-tax present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with Securities and Exchange Commission (“SEC”)SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.

Proved Developed Reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved Reserves. The estimated quantities of crude oil, natural gas and natural gas liquids, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved Undeveloped Reserves. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Royalty.An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells 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.

Standardized Measure. The after-tax present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.

Working Interest. An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

WTI. West Texas Intermediate.

PART I

Item 1. Business.

OverviewGeneral Information

In this Annual Report on Form 10-K (this “Report”), we may rely on and refer to information regarding the oil and gas industry in general from market research reports, analyst reports and other publicly available information. Although we believe that this information is reliable, we cannot guarantee the accuracy and completeness of this information, and we have not independently verified any of it.

Please see the “Glossary” above for a list of abbreviations and definitions used throughout this Report.

Our fiscal year ends on December 31st. Interim results are presented on a quarterly basis for the quarters ended March 31, June 30, and September 30th, the first quarter, second quarter and third quarter, respectively, with the quarter ending December 31st being referenced herein as our fourth quarter. Fiscal 2021 means the year ended December 31, 2021, whereas fiscal 2020 means the year ended December 31, 2020.

Effective January 6, 2020, we completed a reverse stock split of our outstanding common stock at a ratio of one-for-ten shares (the “Reverse Stock Split”), which has been retroactively reflected throughout this Report.

Unless the context requires otherwise, references to the “Company,” “we,” “us,” “our,” “U.S. Energy,” and “U.S. Energy Corp.” refer specifically to U.S. Energy Corp. (“and its consolidated subsidiaries.

In addition, unless the context otherwise requires and for the purposes of this Report only:

Overview

U.S. Energy”, the “Company”, “we” or “us”)Energy Corp. is a Wyoming corporation organized in 1966. We are an independent energy company focused on the acquisition and development of oil and natural gas producing properties in the continental United States. Our business activities are currently focused in South Texas and the Williston Basin in North Dakota.

We have historically explored for and produced oil and natural gas through a non-operator business model. As a non-operator,model, however, during 2020 we relyacquired operated properties in North Dakota, New Mexico, Wyoming and the Texas Gulf Coast, and on our operating partners to propose, permit, drill, complete and produceJanuary 5, 2022, we closed the acquisitions of certain oil and natural gas wells. Beforeproperties from three separate sellers, representing a welldiversified portfolio of primarily operated, producing, oil-weighted assets located across the Rockies, West Texas, Eagle Ford, and Mid-Continent.

Our business strategy going forward is drilled,to enhance the operator provides all oilvalue of our acquired operated assets through evaluation of certain properties with the goal of increasing production and natural gas interest ownersreserves. We plan to deploy our capital in the designated well the opportunitya conservative and strategic manner and pursue value-enhancing transactions and expect to participate in the drilling and completion costs and revenues of the well on a pro-rata basis. Our operating partners also produce, transport, market and account for all oil and natural gas production.continuously evaluate strategic alternative opportunities that we believe will enhance shareholder value. 

Office Location and Website

Our principal executive office is located at 675 Bering, Suite 100,390, Houston, Texas 77057. Our telephone number is (303) 993-3200.

Our website is www.usnrg.com. We make available on this website, through a direct link to the Securities and Exchange Commission’s (the “SEC”) website at http://www.sec.gov, free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and Forms 3, 4 and 5 relating to stock ownership of our directors, executive officers and significant shareholders. You may also find information related to our corporate governance, board committees and code of ethics on our website. Our website and the information contained on or connected to our website are not incorporated by reference herein and should not be considered part of this document. In addition, you may read and copy any materials we file with the SEC at the SEC’s Public Reference Room, which is located at 100 F Street, NE, Room 1580, Washington, D.C. 20549. Information regarding the Public Reference Room may be obtained by calling the SEC at (800) 732-0330.

Oil and Natural Gas Operations

During 2021 we actively pursued acquisitions of exploration, development and production-stage oil and natural gas properties or companies. This resulted in the acquisition of certain oil and gas properties described below, which closed on January 5, 2022. We currently participate in oil and natural gas projects as both a non-operating working interest owner through exploration and development agreements with various oil and natural gas exploration and production companies.companies and as an operator. Our working interest varies by project and may change over time based on the terms of our leases and operating agreements. These projects may result in numerous wells being drilled over the next three to five years depending on, among other things, commodity prices and the availability of capital resources required to fund the expenditures. We are also actively pursuing potential acquisitions of exploration, development and production-stage oil and natural gas properties or companies. Key attributes of our oil and natural gas properties include the following:

PV-10 (definedRecent Events

Acquisition of Properties

On January 5, 2022 (the “Closing Date”), we closed the acquisitions (the “Closing”) contemplated by those certain three separate Purchase and Sale Agreements (as amended to date, the “Purchase Agreements”), previously entered into by the Company on October 4, 2021, with each of (a) Lubbock Energy Partners LLC (“Lubbock”); (b) Banner Oil & Gas, LLC, Woodford Petroleum, LLC and Llano Energy LLC (collectively, “Banner”), and (c) Synergy Offshore LLC (“Synergy”, and collectively with Lubbock and Banner, (the “Sellers”).

Pursuant to the Purchase Agreements, we acquired certain oil and gas properties from the Sellers, representing a diversified, portfolio of primarily operated, producing, oil-weighted assets located across the Rockies, West Texas, Eagle Ford, and Mid-Continent. The acquisition also included certain wells, contracts, technical data, records, personal property and hydrocarbons associated with the acquired assets (collectively with the oil and gas properties acquired, the “Acquired Assets”).

The purchase price for the Acquired Assets was (a) $125,000 in “Glossarycash and 6,568,828 shares of Oilour common stock, as to Lubbock; (b) $1,000,000 in cash, the repayment of $3.3 million in liabilities (which were repaid with funds borrowed under the Credit Agreement discussed and Natural Gas Terms”defined below), and 6,790,524 shares of common stock, as well as the novation of certain hedges which had a mark to market loss of approximately $3.1 million as of the Closing Date, as to Banner (which were evidenced by the Master Agreement and Schedule, discussed and defined below); and (c) $125,000 in cash and 6,546,384 shares of common stock, as to Synergy. The aggregate purchase price under all the Purchase Agreements was $1.25 million in cash, 19,905,736 shares of common stock (the “PSA Shares”), the repayment of $3.3 million in debt, as well as the novation of the hedges discussed above. The initial base purchase price remains subject to customary working capital and other adjustments following the Closing.

Each Purchase Agreement required the Company to place a $500,000 deposit into escrow ($1.5 million in aggregate)(the “Deposits”). The Deposits were released at the closing to pay a portion of the purchase price and closing adjustments for the Acquired Assets.

In connection with the Closing of the acquisition of the Acquired Assets, and on January 5, 2022, we entered into various related agreements with the Sellers as discussed below:

Registration Rights Agreement

Immediately prior to the Closing, on January 5, 2022, each Seller and the Company entered into a Registration Rights Agreement (the “RRA”). Pursuant to the RRA, we agreed:

We agreed to bear the full costs of such registration statements and to keep them effective indefinitely, as long as any Seller holds any shares of common stock included thereunder.

Nominating and Voting Agreement

Separately, at Closing, we and each of the Sellers entered into a Nominating and Voting Agreement. Pursuant to the Nominating and Voting Agreement, we were required to (a) increase the number of directors on the Board of Directors (the “Board”) from five to seven, (b) cause the resignation or removal of a member from the Board, and (c) cause to be appointed to the Board one person designated by each of Lubbock, Synergy and Banner (each a “Nominating Party”), with the result that, as of the Closing Date, the Board was required to be comprised of: (i) one person designated by each Nominating Party (each a “Seller Nominated Person”) and (ii) four current members of the Board, all of which such required actions under the Nominating and Voting Agreement were taken prior to or contemporaneously with the Closing.

The Nominating and Voting Agreement also provides that each Nominating Party will have the right to designate for nomination to the Board two nominees (for so long as such Nominating Party holds at least 15% of the Company’s outstanding common stock) and one nominee (for so long as such Nominating Party holds at least 5% of the Company’s common stock), for appointment at any stockholder meeting or via any consent to action without meeting of the stockholders of the Company. The Nominating and Voting Agreement also requires the Board to include such nominees in the slate of directors up for appointment at each meeting of stockholders where directors will be appointed, and take other actions to ensure that such persons are elected to the Board by the stockholders of the Company.

If any Nominating Party’s Seller Nominated Party ceases for any reason to serve on the Board, such Seller Nominated Party will be provided the right to appoint another person to the Board, who shall be appointed to the Board pursuant to the power to fill vacancies given to the Board without a stockholder vote, by the Bylaws of the Company.

Notwithstanding the above, no person is required to be included as a nominee for election or appointment to the Board in the event such person is a non-GAAP measureDisqualified Person. A “Disqualified Person” is a person for whom the Board reasonably determines that the nomination, election or appointment of, or retention of such person on the Board, as applicable, would (a) violate the listing rules of Nasdaq or the rules and regulations of the SEC, (b) due to such person’s past, affiliations or otherwise, negatively affect the reputation of the Company, negatively affect the Company’s ability to complete future transactions, or disqualify the Company from undertaking any offering under applicable securities laws, or (c) violate the fiduciary duties that the Board owes to the Company or its stockholders; provided, however, that if the Board reasonably determines that any person is widely usedunfit for service on the Board for the reasons set forth above, then the applicable Nominating Party is entitled to designate an alternative or replacement person.

Further notwithstanding the above, the non-Nominating Party directors and Nominating Party directors are required to be apportioned between ‘independent’ and non-’independent’ directors as required by the rules of Nasdaq such that the Company continues in compliance with applicable Nasdaq rules.

At all times when Lubbock holds at least 5% of the Company’s outstanding common stock and its appointee is John A. Weinzierl, each Seller is required to instruct its appointee on the Board to vote in favor of appointing Mr. Weinzierl as Chairman of the Board.

During the term of the Nominating and Voting Agreement, each Seller agreed to vote all securities of the Company which they hold in any manner as may be necessary to nominate and elect (and, if applicable, maintain in office) as a member of the Company’s Board, each of the Seller Nominated Persons and further to not remove any Seller Nominated Persons, unless such person is a Disqualified Person.

The agreement continues in effect from the Closing Date until the earlier of (a) the date mutually agreed by all the parties (the Company and each of the Sellers); and (b) the date that no Seller owns at least 5% of the outstanding shares of common stock of the Company; subject to certain rights and obligations which survive termination. Once a Seller’s ownership drops below 5% of the Company’s outstanding common stock, it no longer has any right to nominate any person under the Nominating and Voting Agreement, even if such Seller’s ownership increases above 5% of the Company’s common stock in the future.

Transition Services Agreement

On the Closing Date, the Company entered into a Transition Services Agreement (“TSA”) with Banner, for Banner to provide services in connection with the assets acquired from Banner (“Services”), including (i) land and lease administration services; (ii) revenue and expense accounting services, accounts payable payment services, accounts receivable collection services, division order services, marketing services, and related records services; (iii) information technology services, including all supervisory control and data acquisition (SCADA) and other field data capture, collection and reporting systems, and computer networks and other technology systems related to, or necessary in the operation of, the assets; (iv) tax services; and (v) other transition services and cooperation sufficient to enable the Company to set up its operations and assume the operation of the assets acquired from Banner.

The transition services are to be provided to the Company on an independent contractor basis. The TSA will remain in place for six months (through June 30, 2022), extendable on a month-to-month basis thereafter at the Company’s request, subject to the terms of the agreement, and the Company will pay Banner $90,000 per month during the duration of the TSA, and reimburse Banner for reasonable and documented expenses incurred by Banner, including the cost to maintain insurance. The TSA includes mutual confidentiality and indemnification obligations with the Company agreeing to indemnify Banner in respect to certain third-party claims arising from the Services and Banner agreeing to indemnify the Company against third party claims arising from the willful misconduct or gross negligence of Banner or its related parties.

Credit Agreement; Hedging Agreement and Related Transactions

Credit Agreement

Separate from the Closing, but also effective on January 5, 2022, the Company entered into a five-year credit agreement (“Credit Agreement”) with Firstbank Southwest (“Firstbank”) as administrative agent for one or more lenders (the “Lenders”), which provides for a revolving line of credit with an initial borrowing base of $15 million, subject to adjustment as discussed in the Credit Agreement, and redetermination on a semi-annual basis on April 1^st and October 1^st of each year, or in the interim as provided in the Credit Agreement, and a maximum credit amount of $100,000,000. The borrowing base is subject to semi-annual redeterminations in April and October of each year until maturity, based on the value of the Company’s proved oil and natural gas industryreserves in accordance with the lenders’ customary procedures and is consideredpractices.

Under the Credit Agreement, revolving loans may be borrowed, repaid and re-borrowed until January 5, 2026, when all outstanding amounts must be repaid.

Under the Credit Agreement, the Company may request letters of credit for its own account or the account of its subsidiaries (which are guarantors of the debt), in an amount equal to no more than 10% of the total borrowing base then in effect.

Amounts borrowed under the Credit Agreement are to be evidenced by institutional investorspromissory notes entered into with the Lenders subject to the terms of the Credit Agreement (the “Notes”).

Interest on the outstanding amounts under the Credit Agreement will accrue at an interest rate equal to (a) the greatest of (i) the prime rate in effect on such day, and professional analysts when comparing companies. We believe(b) the Federal Funds rate in effect on such day (as determined in the Credit Agreement) plus 0.50%, and an applicable margin that PV-10 is an important measure that canranges between 0.25% to 1.25% depending on utilization of the amount of the borrowing base (the “Applicable Margin”). During the first six months of the term, the applicable margin will be used0.75% regardless of utilization. If the Company fails to evaluate the relative significance of ourdeliver a report setting forth its proved oil and natural gas propertiesreserves as and when required under the Credit Agreement, the applicable margin will be 1.25% regardless of utilization.

In the event that certain event of defaults (as described under the Credit Agreement) occur, the outstanding amounts will bear an additional 2.00% interest per annum. Accrued interest on each revolving loan is payable in comparison with other companies. However, PV-10 dataarrears on the last day of each March, June, September and December.

The Company generally has the right to make prepayments of the borrowings at any time without penalty or premium under the Credit Agreement. A commitment fee of 0.50% accrues on the average daily amount of the unused portion of the borrowing base (currently $11,500,000) is not an alternativepayable in arrears on the last business day of March, June, September and December of each year and on the maturity date. Letter of credit fees will include a participation fee to the standardized measureadministrative agent accruing interest at the Applicable Margin as loans under the Credit Agreement, based on the average daily amount of discounted future net cash flows, which isthe letter of credits issued by such Lender, as calculated under generally accepted accounting principlesthe terms of the Credit Agreement, and a fronting fee accruing interest at 0.125% will be paid to each bank issuing letters of credit under the Credit Agreement, as well as certain other standard fees of issuing banks. Participation fees and fronting fees accrued through and including the last business day of March, June, September and December of each year are payable on such last business day. We also agreed to pay certain fees to the agent, including an upfront fee of 0.75% of the initial borrowing base.

We are also required to make certain mandatory repayments under the Credit Agreement, in the United States (“GAAP”) and includesevent the effectsborrowing base decreases below the aggregate amount of income taxes. The following table reconcilesloans made by the standardized measure of discounted future net cash flows to PV-10Lenders and/or if as of December 31, 2019, 2018 and 2017:

Additional information about our standardized measurethe last business day of any calendar month, certain required debt ratios required under the Credit Agreement are not met, there are outstanding amounts owed to the Lenders, and the changes duringCompany has consolidated cash on hand in excess of $5 million, and in some cases we are also required to pay cash to the agent to be held as collateral.

The Credit Agreement contains customary indemnification requirements, representations and warranties and customary affirmative and negative covenants applicable to the Loan Parties and their subsidiaries, including, among other things, restrictions on indebtedness, liens, investments, mergers, dispositions, prepayment of other indebtedness, transactions with affiliates, and dividends and other distributions. In addition, the Credit Agreement contains financial covenants, tested quarterly, that limit the Company’s ratio of total debt to EBITDAX (as defined in the Credit Agreement) to 3:1 and require its ratio of consolidated current assets to consolidated current liabilities (as each is described in the Credit Agreement) to remain at 1:1 or higher.

The proceeds of the borrowings under the Credit Agreement must be used to provide funds for working capital, to finance capital expenditures, for the acquisition and development by the Company and its subsidiaries of certain oil and natural gas producing properties, to refinance existing debt, and for general corporate purposes of the Company and its subsidiaries.

The Credit Agreement also requires us to hedge certain oil and gas volumes, based on our utilization of the borrowing base, which hedging will be accomplished pursuant to the ISDA Master Agreement, discussed below.

Events of default under the Credit Agreement include: the failure by the Company to timely make payments due under the Credit Agreement; material misrepresentations or misstatements in any representation or warranty of any of the Loan Parties; failure by the Company or any of its subsidiaries to comply with their covenants under the Credit Agreement and other related agreements, subject in certain cases to rights to cure; certain defaults under other indebtedness of the Loan Parties; insolvency or bankruptcy-related events with respect to the Company or any of its subsidiaries; certain unsatisfied judgments against the Company or any of its subsidiaries in an amount in excess of $500,000; if the Credit Agreement or certain related agreements or security interests created by them cease to be in full force and effect; certain ERISA-related events reasonably expected to have a material adverse effect on the Company and its subsidiaries; and the occurrence of a change in control, each as discussed in greater detail in the Credit Agreement, and subject to certain cure rights. If any event of default occurs and is continuing under the Credit Agreement, the Lenders may terminate their commitments, and may require the Company and its subsidiaries to repay outstanding debt and/or to provide a cash deposit as additional security for outstanding letters of credit.

A total of $3.5 million was borrowed under the Credit Agreement, immediately upon the entry into such Credit Agreement, which was evidenced by a Note dated January 5, 2022. Such $3.5 million was immediately used to repay $3.3 million of debt owed by Banner which the Company agreed to assume as part of the Closing.

Guaranty and Security Agreement

The Company’s obligations under the Credit Agreement and any secured swap agreement or secured cash management agreement are jointly and severally guaranteed by each of the last two yearsCompany’s existing and subsequently acquired or organized subsidiaries, including the Company’s current subsidiaries, Energy One LLC, New Horizon Resources LLC and BOG – OSAGE, LLC (together with the Company, the “Loan Parties”) pursuant to an Unconditional Guaranty dated February 5, 2022 (the “Guaranty”) and are secured, subject to customary permitted liens and other agreed upon exceptions, by (i) all of the equity interests of each Loan Party and (ii) a perfected security interest in and mortgages on all tangible and intangible assets of each Loan Party (i.e., are secured by substantially all of the assets of the Company). The security interests are set forth in a series of deeds of trust covering each of the Company’s oil and natural gas producing properties and in a Security Agreement dated February 5, 2022, covering the equity interests and other tangible and intangible assets of each Loan Party (the “Security Agreement”).

The Guaranty and Security Agreement requires the Company and its subsidiaries to comply with various affirmative and negative covenants, including, without limitation, covenants relating to maintaining perfected security interests, providing information and documentation to Firstbank, complying with contractual obligations relating to the collateral, restricting the sale and issuance of securities by their respective subsidiaries and providing Firstbank with access to the collateral.

Intercreditor Agreement

In connection with the Credit Agreement, Firstbank, as administrative agent for the Lenders and as collateral agent on behalf of all creditors, and Nextera Energy Marketing, LLC (“NextEra”), together with one or more future swap counterparties (“Swap Counterparties”) entered into an intercreditor agreement (“Intercreditor Agreement”), dated February 5, 2022, which was acknowledged by the Company. Under the Intercreditor Agreement, the parties agreed that the Loan Parties’ obligations under the Credit Agreement and their obligations to the Swap Counterparties in connection with certain acceptable swap agreements (as defined in the Intercreditor Agreement), and discussed below under “ISDA Master Agreement”, would be pari passu and ratably secured by the deeds of trust securing the Company’s obligations under the Credit Agreement, and permitted such swap agreements under the terms of the Credit Agreement, subject to certain requirements. The Intercreditor Agreement terminates upon payment in full of all amounts owed under the Credit Agreement and the Master Agreement Schedule, discussed below.

ISDA Master Agreement

Separate from the Closing, but also effective on January 5, 2022, the Company and NextEra entered into an International Swap Dealers Association, Inc. Master Agreement (“Master Agreement”), facilitating the Company to enter into derivative and/or hedging transactions (“Transactions”) to manage the risk associated with its business relating to commodity prices. The derivative and hedging transactions will be governed by the Master Agreement, including the related Schedule to the ISDA Master Agreement (“Schedule”). The Company’s obligations to NextEra under the Master Agreement are secured by the collateral which secures the loans under the Credit Agreement on a pari passu and pro rata basis with the principal of such loans. The structure of the Transactions may include swaps, caps, floors, collars, locks, forwards and options.

Certain events of default will apply to the Transactions under the ISDA Master Agreement and Schedule, including, but not limited to, failure to pay or deliver, breach of the agreement, credit support default, cross-defaults and misrepresentation.

NextEra’s obligations under the Master Agreement and Schedule were guaranteed by NextEra Energy Capital Holdings, Inc. pursuant to a Guaranty, which is included inNote 17-Unaudited Supplemental Oilas Exhibit I to the Master Agreement.

The Company’s entry into and Natural Gas Informationthe obligations of the Company under the Master Agreement and Schedule were required conditions to our consolidated financial statements included in Item 8the Closing of this report on Form 10-K.the Banner Purchase Agreement, pursuant to which the Company was required to assume and novate certain hedges of Banner which had a mark to market loss of approximately $3.1 million as of the Closing Date.

Activities with Operating Partners

We own working interests in a geographically and geologically diverse portfolio of oil-weighted prospects in varying stages of exploration and development. Prospect stages range from prospect origination, including geologic and geophysical mapping, to leasing, exploratory drilling and development. The Company participates in the prospect stages either for its own account or with prospective partners to enlarge its oil and natural gas lease ownership base.

Each of the operators of our principal prospects has a substantial technical staff. We believe that these arrangements currently allow us to deliver value to our shareholders without having to build the full staff of geologists, engineers and land personnel required to work on diverse projects involving horizontal drilling in North Dakota, New Mexico, South Texas and SouthWest Texas. However, consistent with industry practice with smaller independent oil and natural gas companies, we also utilize specialized consultants with local expertise, as needed.

Presented below is a description of significant oil and natural gas projects with our key operating partners, which constitute the majority of our production and reserves. In addition to the below descriptions, the Company holds interests in non-operated wells with several operators, which constitute the remainder of our PV-10.

Williston Basin, North Dakota (Bakken and Three Forks Formations)

Zavanna, LLC. We have an interest in multiple18 wells with Zavanna, LLC (“Zavanna”) with an average working interest of approximately 16% and net revenue interests ranging from 2% to 31%. These properties operated by Zavanna currently comprisecomprised approximately 50%37.5% of the PV-10 related to our oil and natural gas reserves.reserves at December 31, 2021.

Permian Basin, New Mexico

Cimarex Energy Company. We have an interest in three wells Cimarex Energy Company operates in Lea County, New Mexico. We currently hold a 43.8% working interest and a 36.3% net revenue interest in these wells. All of the leases are currently held by production and comprised approximately 8.0% of the PV-10 related to our oil and natural gas reserves at December 31, 2021.

Texas (Gulf Coast)

Crimson Exploration OperatingContango Resources Inc. We have an interest in multiple wells with Crimson Exploration OperatingContango Resources Inc., which is the operator of the Leona River and Booth Tortuga prospects in which we currently hold a 29% working interest and a 22.2%22.4% net revenue interest. All of the leases are currently held by production and comprisecomprised approximately 9%6.9% of the PV-10 related to our oil and natural gas reserves.reserves at December 31, 2021.

Texas (South Texas)

CML Exploration, LLC. We have an interest in multiple producing wells with CML Exploration, LLC (“CML”) in Dimmit and Zavala Counties, Texas with an average working interest of approximately 9% and an average net revenue interest of approximately 9%. These properties operated by CML currently comprise approximately 33% of the PV-10 related to our oil and natural gas reserves.

Environmental Laws and Regulations

Environmental Matters

Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may:

The permits required for our operations may be subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce their regulations, and violations are subject to fines or injunctions, or both. In the opinion of management, we are in substantial compliance with current applicable environmental laws and regulations and have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on our company, as well as the oil and natural gas industry in general.

Comprehensive Environmental, Response, Compensation, and Liability Act (“CERCLA”).CERCLA and comparable state statutes impose strict, joint and several liabilities on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. These persons include the owner or operator of the site where the release occurred, persons who disposed or arranged for the disposal of hazardous substances at the site, and any person who accepted hazardous substances for transportation to the site. CERCLA authorizes the Environmental Protection Agency (“EPA”), state environmental agencies, and in some cases third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for the 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. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum related products.

Waste Handling. The Resource Conservation and Recovery Act (“RCRA”). RCRA isand comparable state statutes regulate the principal federal statute governing thegeneration, transportation, treatment, storage, disposal, and disposalcleanup of hazardous and non-hazardous solid wastes. Analogous state laws also impose requirements associatedUnder the auspices of the United States Environmental Protection Agency (“EPA”), individual states administer some or all of the provisions of RCRA, sometimes in conjunction with the management of such wastes. In the course of our operations, we and others generate petroleum hydrocarbon wastes,their own, more stringent requirements. Drilling fluids, produced water, and ordinary industrial wastes. RCRA currently exempts drilling fluids, produced waters, and other wastes associated with the exploration development, or production of crude oil, natural gas, or geothermal resources from regulation as hazardous wastes, allowing us to manage these wastes under RCRA’s less stringent non-hazardous waste requirements. A similar exemption is contained in manymost of the state counterparts to RCRA.

Recently, following the filing of a lawsuit by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its non-hazardous waste (RCRA Subtitle D) criteria regulation for oil and natural gas wastes, the EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the U.S. District Court for the District of Columbia in December 2016. Under the decree, the EPA was required to propose no later than March 15, 2019 a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes or sign a determination that revision of the regulations is not necessary. The EPA missed the March 15, 2019 deadline, but in April 2019, the EPA determined that revisions to the federal regulations for the management ofother wastes associated with the exploration, development, and production of crude oil naturalor gas and geothermal energyare currently regulated under Subtitle D of RCRA were not necessary. This determination fulfilled EPA’s obligations under the referenced 2016 Consent Decree.

The imposition of new federal requirements under RCRA Subtitle D can result in an increase of our operating expenses. Moreover, repeal or modifications of the exemption forRCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes tonow classified as non-hazardous could be classified and regulated as non-hazardous by administrative, legislative or judicial process, or through changeshazardous wastes in applicable state statutes, wouldthe future. Any such change could result in an increase the volume of hazardous waste we are requiredin our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and would cause us, as well as our competitors, to incur significantly increased operating expenses.financial position.

Federal, state and local laws may also require us to remove or remediate wastes or hazardous substances that have been previously disposed or released into the environment. This can include removing or remediating wastes or hazardous substances disposed or released by us (or prior owners or operators) in accordance with then current laws, suspending or ceasing operations at contaminated areas, or performing remedial well plugging operations or response actions to reduce the risk of future contamination.

Endangered Species.The federal Endangered Species Act (“ESA”). The ESA seeks to ensureand analogous state laws regulate activities that activities do not jeopardizecould have an adverse effect on threatened or endangered or threatened animal, fish and plant species, nor destroy or modify the critical habitatspecies. Some of such species. Under ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species or its habitat. The ESA provides for criminal penalties for willful violations of ESA. Other statutes that provide protection to animal and plant species and that may apply to our operations include, but are not necessarily limited to, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. Although we believe that our operations are conducted in substantial compliance withareas where protected species are known to exist. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts on protected species, and we may be prohibited from conducting operations in certain locations or during certain seasons, such statutes, any changeas breeding and nesting seasons, when our operations could have an adverse effect on these species. It is also possible that a federal or state agency could order a complete halt to activities in these statutes or any reclassificationcertain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a species as endangered could subject our company (directly or indirectly through our operating partners) to significant expenses to modify our operations or could force discontinuation of certain operations altogether. Further, the ESA prohibits the taking of endangered or threatened species or their habitats. While some of our assets and lease acreage may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in material compliance with the ESA. However, the designation of previously unidentified endangered or threatenedprotected species in areas where we intendperform drilling, completion, and production activities could impair our ability to operatetimely complete well drilling and development and could materially limit or delayadversely affect our plans.future production from those areas.

Air Emissions. The federal Clean Air Act (the “CAA”) and state air pollution laws and regulations provide a framework for national, state and local efforts to protect air quality. Applicable to our business and operations, the CAA regulates emissions, discharges and controls with respect to oil and natural gas production and natural gas processing operations. The CAA includes New Source Performance Standards (“NSPS”) for the oil and natural gas source category to address emissions of sulfur dioxide, methane and volatile organic compounds (“VOCs”) from new and modified oil and natural gas production, processing and transmission sources as well as a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. Further, the CAA regulates the emissions from compressors, dehydrators, storage tanks and other production equipment as well as leak detection for natural gas processing plants. These rules have required a number of modifications to the operations of our third-party operating partners, including the installation of new equipment to control emissions from compressors.

In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions at specified sources. For example, under the EPA’s NSPS and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) regulations, since January 1, 2015, owners and operators of hydraulically fractured natural gas wells (wells drilled principally for the production of natural gas) have been required to use so-called “green completion” technology to recover natural gas that formerly would have been flared or vented. In 2016, the EPA issued additional rules for the oil and natural gas industry to reduce emissions of methane, VOCs and other compounds. These rules apply to certain sources of air emissions that were constructed, reconstructed, or modified after September 18, 2015. Among other things, the new rules impose green completion requirements on new hydraulically fractured or re-fractured oil wells and leak detection and repair requirements at well sites. We do not expect that the currently applicable NSPS or NESHAP requirements will have a material adverse effect on our business, financial condition or results of operations. However, any future laws and their implementing regulations may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permitting requirements or require us to use specific equipment or technologies to control emissions.

On December 17, 2014, the EPA proposed to revise and lower the existing 75 ppbpounds per barrel (ppb) National Ambient Air Quality Standard (“NAAQS”) for ozone under the CAA to a range within 65-70 ppb. On October 1, 2015, the EPA finalized a rule that lowered the standard to 70 ppb. This lowered ozone NAAQS could result in an expansion of ozone nonattainment areas across the United States, including areas in which we operate. Oil and natural gas operations in ozone nonattainment areas likely would be subject to more stringent emission controls, emission offset requirements for new sources, and increased permitting delays and costs. This could require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells.

Permit and related compliance obligations under the CAA, each state’s development and promulgation of regulatory programs to comport with federal requirements, as well as changes to state implementation plans for controlling air emissions in regional non-attainment or near-non-attainment areas, may require oil and natural gas exploration and production operators to incur future capital and operating expenditures in connection with the addition or modification of existing air emission control equipment and strategies.

Climate change. In December 2009, the EPA determined that emissions of carbon dioxide, methane, and other GHGs endanger public health and welfare, and as a result, began adopting and implementing a comprehensive suite of regulations to restrict emissions of GHGs under existing provisions of the CAA. While President Trump’s administration had taken steps to rescind or review many of these regulations, President Biden’s administration has actively been reviewing those actions and taking steps to strengthen and expand the regulations, specifically targeting, among other things, the regulation of methane emissions from the oil and gas sector. Legislative and regulatory initiatives related to climate change could have an adverse effect on our operations and the demand for oil and gas. Please refer to Risk Factors - Risks Related to Governmental Regulations- Oil and natural gas operations are subject to environmental, legislative and regulatory initiatives that can materially adversely affect the timing and cost of operations and the demand for crude oil, natural gas, and NGLs. In Part I, Item 1A of this Report. In addition to the effects of regulation, the meteorological and physical effects of global climate change could pose additional risks to our operations, including physical damage risks associated with more frequent, more intensive storms, flooding, and wildfires, and could adversely affect the demand for our products.

Clean Water Act.discharges. The federal Water Pollution Control Act of 1972, or the (“Clean Water Act (the “CWA”Act”), and analogous state laws impose restrictions and strict controls onwith respect to the discharge of produced waterspollutants, including spills and leaks of oil and other substances, into waters of the United States and states. The discharge of pollutants into navigable waters. The CWA and certain state regulations prohibit the discharge of produced water, sand, drilling fluids, drill cuttings, sediment and certain other substances related to the oil and natural gas industry into certain regulated waters without an individual or general dischargeis prohibited, except in accordance with the terms of a permit issued by the EPA, or an analogous state agency.agencies. This includes the discharge of certain storm water without a permit which requires periodic monitoring and sampling. In addition, the CWAClean Water Act regulates wastewater generated by unconventional oil and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types ofgas operations during the hydraulic fracturing process and discharged to publicly-owned wastewater treatment facilities. Some statesThe Clean Water Act also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Costs may be associated with the treatment of wastewater and/or developing and implementing storm water pollution prevention plans. The CWA and regulations implemented thereunder also prohibit dischargesprohibits discharge of dredged andor fill material in wetlands and otherinto waters of the United States, unless authorizedincluding wetlands, except in accordance with the terms of a permit issued by an appropriately issued permit. Spill prevention, control and countermeasure requirements of the CWA require appropriate containment berms and similar structures to help prevent the contamination of waters of the United States in the event of a petroleum hydrocarbon tank spill, rupture or leak.

The reach and scope of the CWA, and the determination of what water bodies and land areas are regulated as waters of the U.S., is the subject of various rules adopted by EPA and the U.S. Army Corps of Engineers, (which we referor a state, if the state has assumed authority to as the WOTUS Rules),issue such permits. Federal and on-going federal court litigation arising outstate regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with discharge permits or other requirements of the rulesClean Water Act and recent amendments. The WOTUS Rules, litigation over the rules,analogous state laws and the associated regulatory uncertainty, could impact our operations by subjecting new land and waters to regulation and increase our cost of operations. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges of oil and other pollutants and impose liability on parties responsible for those discharges, for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release.regulations.

Oil Pollution Act of 1990 (“OPA”).Federal regulations also requireOPA addresses prevention, containment and cleanup, and liability associated with oil pollution. OPA applies to vessels, offshore platforms, and onshore facilities. OPA subjects owners of such facilities to strict liability for containment and removal costs, natural resource damages, and certain owners and operatorsother consequences of facilities that store or otherwise handle oil to prepare and implement spill response plans relating to the potential discharge of oil into surface waters. The OPA, and analogous state laws, contain numerous requirements relating to prevention of, reporting of, and response to oil spills into watersjurisdictional waters. Any unpermitted release of the United States. A failure to comply with OPA’s requirementspetroleum or inadequate cooperation during a spill response action may subject a responsible party toother pollutants from our operations could result in governmental penalties and civil or criminal enforcement actions. The OPA establishes strict liability for owners and operators of facilities that release oil into waters of the United States. The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A ‘‘responsible party’’ under the OPA includes owners and operators of certain onshore facilities from which a release may affect waters of the United States.liability.

Safe Drinking Water Act (“SDWA”). The disposal of oil and natural gas wastes into underground injection wells are subject to the federal Safe Drinking Water Act, as amended, and analogous state laws. The SDWA’s Underground Injection Control (“UIC”) Program establishes requirements for permitting, testing, monitoring, recordkeeping and reporting of injection well activities as well as a prohibition against the migration of fluid containing any contaminants into underground sources of drinking water. State programs may have analogous permitting and operational requirements. In response to concerns related to increased seismic activity in the vicinity of injection wells, regulators in some states are considering additional requirements related to seismic safety. For example, the Texas Railroad Commission (“RRC”) adopted new oil and natural gas permit rules in October 2014 for wells used to dispose of saltwater and other fluids resulting from the production of oil and natural gas in order to address these seismic activity concerns within the state. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells, and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. If new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in our operations, our costs to operate may significantly increase and our ability to continue production may be delayed or limited, which could have a material adverse effect on our results of operations and financial position. In addition, any leakage from the subsurface portions of the injection wells may cause degradation of freshwater, potentially resulting in cancellation of operations of a well, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource, and imposition of liability by third parties for property damages and personal injury.

The Occupational Safety and Health Act (“OSHA”). OSHA and comparable state laws regulate the protection of the health and safety of employees. The federal Occupational Safety and Health Administration has established workplace safety standards that provide guidelines for maintaining a safe workplace in light of potential hazards, such as employee exposure to hazardous substances. OSHA also requires employee training and maintenance of records, and the OSHA hazard communication standard and EPA community right-to-know regulations under the Emergency Planning and Community Right-to-Know Act of 1986 require that we organize and/orand disclose information about hazardous materials used or produced in our operations.

Hydraulic Fracturing.Substantially all of the oil and natural gas production in which we have interests is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gashydrocarbons from tight shale formations. We routinely utilize hydraulic fracturing techniques in most of our drilling and oil from dense subsurface rock formations. Hydraulic fracturingcompletion programs. The process involves the injection of water, sand, or alternative proppant and chemicals under pressure into target geological formationsthe formation to fracture the surrounding rock and stimulate production. OverThe process is typically regulated by state oil and gas commissions. However, even on private lands, the years, thereEPA has been increased public concern regarding an alleged potential forasserted federal regulatory authority over hydraulic fracturing toinvolving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program. The federal Safe Drinking Water Act protects the quality of the nation’s public drinking water through the adoption of drinking water standards and controlling the injection of waste fluids, including saltwater disposal fluids, into below-ground formations that may adversely affect drinking water supplies,sources.

Increased regulation and proposals have been madescrutiny on oil and gas activities involving hydraulic fracturing techniques could potentially lead to enact separatea decrease in the completion of new oil and gas wells, an increase in compliance costs, delays, and changes in federal income tax laws, all of which could adversely affect our financial position, results of operations, and cash flows. As new laws or regulations that significantly restrict hydraulic fracturing are adopted at the state and local legislation that would increase the regulatory burden imposed on hydraulic fracturing. Hydrauliclevels, such laws could make it more difficult or costly for us to perform fracturing operations have historically been overseen by state regulators as part of their oil and natural gas regulatory programs, but where these operations occur on federal or tribal lands they are subject to regulation by the U.S. Department of the Interior, Bureau of Land Management (“BLM”). The EPA has taken the following actions and issued: guidance under the SDWA forstimulate production from tight formations. In addition, if hydraulic fracturing activities involving the use of diesel fuel; final regulations under the federal CAA governing performance standards, including standards for the capture of volatile organic compounds and methane emissions released during hydraulic fracturing; and finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

In addition, the BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. However, the BLM finalized a rule in December 2017 repealing its March 2015 hydraulic fracturing regulations. The repeal has been challenged in court and the final outcome is uncertain at this time.

In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under some circumstances, noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. The EPA has not proposed to take any action in response to the report’s findings, and additional regulation of hydraulic fracturingbecomes regulated at the federal level appears unlikely at this time.

While Congress has from time to time considered legislation to provide for federal regulationas a result of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process, the prospect of additional federal legislation relatedor regulatory initiatives by the EPA or other federal agencies, our fracturing activities could become subject to hydraulic fracturing appears remote at this time. In addition to federal legislativeadditional permitting requirements, which could result in additional permitting delays and regulatory actions, some states and local governments have considered imposing, or have adopted, various conditions and restrictionspotential increases in costs. Restrictions on hydraulic fracturing operations. This includes states where we have interests. Louisiana and Texas, for example, have adopted legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Moreover, some states and local governments have enacted laws or regulations limiting hydraulic fracturing within their borders or prohibitingalso reduce the activity altogether. In the event that new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuitamount of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of drilling in general and/or hydraulic fracturing in particular. Recently, several municipalities have passed or proposed zoning ordinances that ban or strictly regulate hydraulic fracturing within city boundaries, setting the stage for challenges by state regulators and third parties. Similar events and processes are playing out in several cities, counties, and townships across the United States. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct, operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and could even be prohibited from drilling and/or completing certain wells.

In May 2014, the EPA issued an advance notice of proposed rulemaking under the Toxic Substances Control Act to initiate a stakeholder process to request input on various aspects of obtaining information on chemical substances and mixtures used in hydraulic fracturing for oil and gas explorationthat we are ultimately able to produce from our reserves.

We believe the trend in local, state, and production. To date, no further action has been takenfederal environmental legislation and regulation will continue toward stricter standards, particularly under President Biden’s administration. While we believe we are in substantial compliance with existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations, we cannot give any assurance that we will not be adversely affected in the proposal.future.

National Environmental Policy Act (“NEPA”). Oil and natural gas exploration, development and production activities on federal lands, including tribal lands and lands administered by the BLM, are subject to NEPA. NEPA requires federal agencies, including the BLM, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. If we were to conduct any exploration and production activities on federal lands in the future, those activities may need to obtain governmental permits that are subject to the requirements of NEPA. This process has the potential to delay, limit or increase the cost of developing oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects. Many of theour activities and those of our third-party operating partners are covered under categorical exclusions which results in a shorter NEPA review process, however, the impact of the NEPA review process on our activities and those of our third-party operating partners is uncertain at this time and could lead to delays and increased costs that could materially adversely affect our revenues and results of operations.

Climate Change

The EPA has determined that greenhouse gases present an endangerment to public health and the environment and has issued regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. These regulations include limits on tailpipe emissions from motor vehicles and preconstruction and operating permit requirements for certain large stationary sources of greenhouse gas emissions (“GHG”). The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from a variety of sources in the United States, including certain onshore oil and natural gas production facilities, on an annual basis, including GHG emissions from completions and workovers from hydraulically fractured oil wells. In June 2016, the EPA published NSPS Subpart OOOOa standards that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. However, in April 2017, the EPA announced that it would review this methane rule for new, modified and reconstructed sources and initiated reconsideration proceedings to potentially revise or rescind portions of the rule. In June 2017, the EPA also proposed a two-year stay of certain requirements of the methane rule pending the reconsideration proceedings. The stay, however, was vacated by the D.C. Circuit Court of Appeals in July 2019. Accordingly, the June 2016 rule remains in effect, however, in September 2019, the EPA proposed amendments to the 2012 and 2016 NSPS for the oil and gas industry. The rule’s primary proposal would redefine the types of sources covered under the oil and gas industry to remove all sources in the transmission and storage segment of the oil and natural gas industry from regulation under the NSPS, both for ozone-forming VOCs and GHGs. In addition, the primary proposal would rescind emission limits for methane from the remaining segments in the oil and gas industry – production and processing. As a secondary proposal, EPA would not redefine the types of sources covered under the oil and gas NSPS, but would still rescind the methane emission limits for the oil and gas industry. The rule would retain VOC standards for the production, processing, and transmission and storage segments of the industry. The comment period for this rulemaking ended on November 25, 2019 and EPA has not taken further action at this time.

Similarly, in November 2016, the BLM issued a final rule to reduce methane emissions by regulating venting, flaring, and leaks from oil and natural gas operations on federal and American Indian lands. California and New Mexico have challenged the rule in ongoing litigation. In addition, in April 2018, a coalition of states filed a lawsuit aiming to force the EPA to establish guidelines for limiting methane emissions from existing sources in the oil and natural gas section; that lawsuit is currently pending. These rules, should they remain in effect, or any other new methane emission standards imposed on the oil and natural gas sector, could result in increased costs to our operations as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect our business. The potential increase in operating costs could include new or increased costs to (i) obtain permits, (ii) operate and maintain our equipment and facilities, (iii) install new emission controls on equipment and facilities, (iv) acquire allowances authorizing greenhouse gas emissions, (v) pay taxes related to greenhouse gas emissions and (vi) administer and manage a greenhouse gas emissions program. In addition to these federal actions, various state governments and/or regional agencies may consider enacting new legislation and/or promulgating new regulations governing or restricting the emission of greenhouse gases from stationary sources.

Currently, federal legislation related to the reduction of greenhouse gas emissions appears unlikely; however, many states have established greenhouse gas cap and trade programs, and others are considering carbon taxes or initiatives that promote the use of alternative fuels and renewable sources of energy. The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce, which could in turn have the effect of lowering the value of our reserves. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production or midstream activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and natural gas will continue to represent a substantial percentage of global energy use over that time. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other extreme weather events. Such events could disrupt our operations or result in damage to our assets and have an adverse effect on our financial condition and results of operations.

Our third-party operating partners are required to report their GHG under these rules. Although we cannot predict the cost to comply with current and future rules and regulations at this point, compliance with applicable rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

In addition, the United States was actively involved in the United Nations Conference on Climate Change in Paris, which led to the creation of the Paris Agreement. The Paris Agreement requires countries to review and “represent a progression” in their nationally determined contributions, which set emissions reduction goals, every five years. The Paris Agreement, which went into effect in November 2016, could further drive regulation in the United States. However, in June 2017, the United States announced its withdrawal from the Paris Agreement, although the earliest possible effective date of withdrawal is November 2020. Despite the planned withdrawal, certain U.S. city and state governments have announced their intention to satisfy their proportionate obligations under the Paris Agreement. The United States’ adherence to the exit process is uncertain and the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time. Restrictions on emissions of methane or carbon dioxide that have been or may be imposed in various states, or at the federal level could adversely affect the oil and natural gas industry. Moreover, incentives to conserve energy or use alternative energy sources as a means of addressing climate change could reduce demand for oil and natural gas.

Research and Development

No research and development expenditures have been incurred either on the Company’s account or sponsored by a customer of the Company, during the past three fiscal years.

Insurance

We have general liability and property insurance coverage in amounts we deem sufficient for our business operations, consisting of property loss insurance on all major assets equal to the approximate replacement value of the assets and additional liability and operator’s and control of well insurance for our oil and natural gas operations and drilling programs. We do not have insurance coverage for the lost revenues associated with a business interruption, nor do we have coverage for the loss of our oil and natural gas reserves. There is no guarantee that any insurance coverage would be sufficient to protect the value of our assets or to fully cover any losses sustained. Payment of substantial liabilities in excess of coverage could require diversion of internal capital away from regular business, which could result in curtailment of projected future operations.

Employees

Human Capital

As of December 31, 2019,March 22, 2022, we had 2 total and23 full-time employees and 2 part-time employees, none of whom were subject to a collective bargaining agreement. In addition, we utilizedutilize several consultants on an as-needed basis during 2019.basis. As a result of the acquisition completed on January 5, 2022, we added 13 employees. In addition, in 2022, we increased our corporate accounting, engineering and administrative staff. We recognize that our employees are our most valuable assets and drive the way we pursue our short-term and long-term goals. To attract and retain talent we promote:

The core values of integrity and ethical behavior are the pillars of our culture, and as a result, the health and safety of our employees and contractors is our highest priority. All employees are responsible for upholding Company-wide standards and values. We have policies designed to promote ethical conduct and integrity, that employees are required to read and acknowledge.

We strive to provide competitive, performance-based compensation and benefits to our employees, including market-competitive pay, and various healthcare, retirement, and other benefit packages The Compensation Committee of our Board of Directors oversees our compensation programs and designs programs to incentivize achievement of our corporate strategy and the matters of importance to our stakeholders.

Forward Plan

In 20202022 and beyond, we intend to seek additional opportunities in the oil and natural gas sector, including but not limited to further acquisition of assets, participation with current and new industry partners in their exploration and development projects, acquisition of existing companies, and the purchase of oil producing assets. In addition, we plan to grow production by performing workovers on operated idle wells acquired in 2022 to return them back to production.

Business Strategy

Key elements of our business strategy include:

Industry Operating Environment

The oil and natural gas industry is affected by many factors that we generally cannot control. Government regulations, particularly in the areas of taxation, energy, climate change and the environment, can have a significant impact on operations and profitability. Significant factors that will impact oil prices in the current fiscal year and future periods include the Russian war with Ukraine, inflation, political and social developments in the Middle East, demand in Asian and European markets, and the extent to which members of the Organization of the Petroleum Exporting Countries (“OPEC”) and other oil exporting nations manage oil supply through export quotas. Additionally, natural gas prices continue to be under pressure due to concerns about excess supply of natural gas due to the high productivity of emerging shale plays in the United States. Natural gas prices are generally determined by North American supply and demand and are also affected by imports and exports of liquefied natural gas. Weather also has a significant impact on demand for natural gas since natural gas is a primary heating source.

CommodityIn early March 2020, there was an outbreak of a novel strain of coronavirus, which causes the infectious disease known as COVID-19, which resulted in a drastic decline in global demand of certain mineral and energy products including crude oil. As a result of the lower demand caused by the COVID-19 pandemic and the oversupply of crude oil, spot and future prices of crude oil fell to historic lows during the second quarter of 2020, which remained depressed for the majority of 2020. Operators in North Dakota’s Williston Basin responded by significantly decreasing drilling and completion activity and shutting in or curtailing production from a significant number of producing wells, all of which have remained volatile over the past three years. While commodity prices generally improved in 2018 from 2017, commodity prices were generally lower in 2019, and oil prices have dropped significantly in March 2020. Currently, we do not have any commodity derivative contracts in place to mitigate the effect of lower commodity prices on our revenues.since come back online. Lower oil and natural gas prices not only decrease our revenues, but an extended decline in oil or gas prices may materially and adversely affect our future business, financial position, cash flows, results of operations, liquidity, ability to finance planned capital expenditures and the oil and natural gas reserves that we can economically produce.

DevelopmentAdditionally, the outbreak of COVID-19 and decreases in commodity prices, resulting from oversupply, government-imposed travel restrictions, and other constraints on economic activity created disruptions and volatility in the global marketplace for oil and gas. While demand and commodity prices recovered and are back to, or greater than pre-pandemic levels, our financial results may continue to be depressed in future quarters. These factors may adversely impact the supply and demand for oil and gas and our ability to produce and transport oil and gas and perform operations at and on our properties. This uncertainty also affects management’s accounting estimates and assumptions, which could result in greater variability in a variety of areas that depend on these estimates and assumptions, including investments, receivables, and forward-looking guidance.

We

Development

During 2022, our development activities will be focused on returning idle wells acquired in the January 2022 acquisition to production and participating in drilling projects with our joint interest operators.

Until acquiring operated properties during 2020, we primarily engageengaged in oil and natural gas exploration and production by participating, on a proportionate basis, alongside third-party interests in wells drilled and completed in spacing units that include our acreage. In addition, from time-to-time, we acquire working interests in wells in which we do not hold the underlying leasehold interests from third parties unable or unwilling to participate in well proposals. We typically depend on drilling partners to propose, permit and initiate the drilling of wells. Prior to commencing drilling, our partners are required to provide all owners of oil, natural gas and mineral interests within the designated spacing unit the opportunity to participate in the drilling costs and revenues of the well to the extent of their pro-rata share of such interest within the spacing unit. We assess each drilling opportunity on a case-by-case basis and participate in wells that we expect to meet our return thresholds based upon our estimates of ultimate recoverable oil and natural gas, expected oil and natural gas prices, expertise of the operator, and completed well cost from each project, as well as other factors. Historically, we have participated pursuant to our working interest in a vast majority of the wells proposed to us.

CompetitionSeasonality

The oil and natural gas industry is extremely competitive, and we compete with numerous other oil and natural gas exploration and production companies. Some of these companies have substantially greater resources than we have. Not only do other companies explore for and produce oil and natural gas, many also engage in midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. The operations of other companies may be able to pay more for exploratory prospects and productive oil and natural gas properties. Our competitors may also have more resources to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit.

Larger or integrated competitors may be better able to absorb the burden of existing and future federal, state, and local laws and regulations than we can, which would adversely affect our competitive position. Our ability to discover reserves and acquire additional properties in the future will be dependent upon our ability and resources to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, we may be at a disadvantage in producing oil and natural gas properties and bidding for exploratory prospects because we have fewer financial and human resources than other companies in our industry. Should a larger and better financed company decide to directly compete with us, and be successful in its efforts, our business could be adversely affected.

Marketing and Customers

The market for oil and natural gas produced from our properties depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

Our oil production is expected to be sold at prices tied to the spot oil markets. Our natural gas production is expected to be sold under short-term contracts and priced based on first-of-the-month index prices or on daily spot market prices. We rely on our operating partners to market and sell our production. Our operating partners include a concentrated list of exploration and production companies, from large publicly traded companies to small, privately held companies.

Seasonality

Winter weather conditions and lease stipulations can limit or temporarily halt theour drilling and producing activities of our operating partners and other oil and natural gas operations.operations and those of our operating partners. These constraints and the resulting shortages or high costs could delay or temporarily halt the operations of our operating partners and materially increase our operating and capital costs. Such seasonal anomalies can also pose challenges for meeting well drilling objectives and may increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay or temporarily halt our operations and those of our operating partners’ operations.partners.

Governmental Regulation

Our operations are subject to various rules, regulations and limitations impacting the oil and natural gas exploration and production industry as a whole.

Regulation of Oil and Natural Gas Production

Our oil and natural gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies. For example, North Dakota requires permits for drilling operations, drilling bonds and reports concerning operations and imposes other requirements relating to the exploration and production of oil and natural gas. Many states may also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the sourcing and disposal of water used in the process of drilling, the flaring of natural gas, completion and abandonment, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of such wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill. Moreover, many states impose a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within their jurisdictions. Failure to comply with any such rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry will most likely increase our cost of doing business and may affect our profitability. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on our financial condition and results of operations. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”) and the courts. We cannot predict when or whether any such proposals may become effective.

Regulation of Transportation of Oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenactre-enact price controls in the future. Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil by common carrier pipelines is also subject to rate and access regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil pipelines that allows a pipeline to increase its rates annually up to a prescribed ceiling, without making a cost of servicecost-of-service filing. Every five years, the FERC reviews the appropriateness of the index level in relation to changes in industry costs. On December 17, 2015, the FERC established a new price index for the five-year period that commenced on July 1, 2016.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors that are similarly situated.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is generally governed by pro-rationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

Regulation of Transportation and Sales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the FERC under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future.

Onshore gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states. 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.

Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Litigation

Marketing, Major Customers and LiquidityDelivery Commitments

APEG Energy II, L.P. (“APEG II”)Markets for oil and its general partner, APEG Energy II, GP (togethernatural gas are volatile and are subject to wide fluctuations depending on numerous factors beyond our control, including seasonality, economic conditions, foreign imports, political conditions in other energy producing countries, OPEC market actions, and domestic government regulations and policies. All of our production is marketed by our industry partners for our benefit and is sold to competing buyers, including large oil refining companies and independent marketers. Substantially all of our production is sold pursuant to agreements with APEG II, “APEG”) are involvedpricing based on prevailing commodity prices, subject to adjustment for regional differentials and similar factors. We had no material delivery commitments as of December 31, 2021.

Competition

The oil and natural gas business is highly competitive in litigation with usthe search for and acquisition of additional reserves and in the sale of oil and natural gas. Our competitors principally consist of major and intermediate-sized integrated oil and natural gas companies, independent oil and natural gas companies and individual producers and operators. Specifically, we compete for property acquisitions and our former Chief Executive Officer, David Veltri, as described below. Asoperating partners compete for the equipment and labor required to operate and develop our properties. Our competitors may be able to pay more for properties and may be able to define, evaluate, bid for and purchase a greater number of March 20, APEG II holds approximately 41% ofproperties than we can. Ultimately, our outstanding common stock and was our secured lender prior to the maturity of our credit facility on July 30, 2019. The costs associated with the pending litigation were a significant use of our existing cash during 2019, but we believe that the expenditures are significantly behind us.

APEG II Litigation

On February 14, 2019, our Board of Directors (only one member of which remainsfuture success will depend on our Board following our 2019 Annual Meeting of Shareholders held on December 10, 2019) received a letter from APEG II urgingability to develop or acquire additional reserves at costs that allow us to establish a seven-person, independent board of directors, establish a corporate business planremain competitive.

Available Information

The Company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and reduce our corporate generalamendments to reports filed pursuant to Sections 13(a) and administrative expenses. APEG II is our largest shareholder, owning approximately 41% of our outstanding common stock as of March 20, 2020 and was the secured lender under our credit facility, which we have repaid in full as discussed below.

On February 25, 2019, APEG II provided an access termination notice to our bank under its collateral documents, which resulted in all15(d) of the funds held in the collateral accounts, which totaled approximately $1.8 million, being wired to APEG II on March 1, 2019. On March 1, 2019, David Veltri, our former Chief Executive Officer and President,Exchange Act, are filed a lawsuit against APEG II in the Company’s name (the “Texas Litigation”). The Texas State Court granted the motion for a temporary restraining order (“TRO”) and ordered APEG to return immediately the approximate $1.8 million in cash previously wired to APEG II.

On March 4, 2019, APEG II filed an emergency motion with the U.S. District Court for the Southern District of Texas in order to remove the Texas Litigation from the State Court to the Federal District CourtSecurities and to stay or modify the TRO. Following a hearing on March 4, 2019, the Texas Federal Court vacated the TRO and the Court ordered APEG to return our funds, less the outstanding balance due to APEG II under the credit facility of approximately $937 thousand, and we received back approximately $850 thousand.

On February 25, 2019, our Board held a meeting at which it voted to terminate Mr. Veltri for cause as Chief Executive Officer and President as a result of using Company funds outside of his authorityExchange Commission. Such reports and other reasons. Mr. Veltri, along with John Hoffman, a former Board member, called into question whether or not such action was properly taken at the Board meeting. On March 8, 2019, our Audit Committee intervened in the Texas Litigationinformation filed by filing an emergency motion (the “AC Motion”). The AC Motion requested that the Texas Federal Court order that all of our funds and matters be placed under the control of our Chief Financial Officer and that control of these functions be removed from our former Chief Executive Officer.

On March 12, 2019, the Texas Federal Court granted the AC Motion, ordering that any disbursement made by us must be approved in writing by the Audit Committee in advance. Additionally, the Texas Federal Court ordered that our Chief Financial Officer must be appointed as the sole signatory on all of our bank accounts.

Litigation with Former Chief Executive Officer

In connection with the above described litigation with APEG II, APEG II then initiated a second lawsuit on March 18, 2019 as a shareholder derivative action in Colorado against Mr. Veltri, as a result of his refusal to recognize our Board’s decision to terminate him for cause (the “Colorado Litigation”). We were named as a nominal defendant in the Colorado Litigation. The APEG II complaint in the Colorado Litigation alleged that Mr. Veltri’s employment was terminated by our Board of Directors and sought an injunction and temporary restraining order against Mr. Veltri to prevent him from continuing to act as our Chief Executive Officer, President and Chairman.

On April 30, 2019, the Audit Committee took over the control of the defense of the Company, prosecution of its claims against APEG II, and filed third-party claims on behalf of the Company against Mr. Veltri and Mr. Hoffman, at the time a director of the Company, asserting that Mr. Veltri was responsible for any damages that APEG II claims, including attorneys’ fees, and that Mr. Veltri and Mr. Hoffman should be removed from our Board of Directors. On May 22, 2019, we and APEG II entered into a settlement agreement with Mr. Hoffman, pursuant to which Mr. Hoffman agreed to resign from the Board of Directors and committees thereof, and we agreed to pay up to $50,000 of his legal fees incurred. Further, we released Mr. Hoffman from any claims related to the Texas Litigation, APEG II released us from any claims that may have been caused by Mr. Hoffman, and Mr. Hoffman released us from any and all claims he may have had against the Company and its Board.

In the Colorado Litigation, the Colorado Federal Court granted interim preliminary injunctive relief to APEG II against Mr. Veltri, holding that Mr. Veltri, without authorization, continued to hold himself out to be, and continued to act as, as our President and Chief Executive Officer. Pursuant to the Order, Mr. Veltri was preliminarily enjoined from acting as, or holding himself out to be, our President and/or Chief Executive Officer, pending a trial on the merits. Ryan Smith, our Chief Financial Officer, was appointed temporary custodian of the Company with the SEC are available free of charge at https://investors.usnrg.com/investors/sec-filings when such reports are available on the SEC’s website. The Company periodically provides other information for investors on its corporate website, https://usnrg.com. The information contained on the websites referenced in this Form 10-K is not incorporated by reference into this filing. Further, the Company’s references to act aswebsite URLs are intended to be inactive textual references only. Copies of documents filed by us with the SEC are also available from us without charge, upon oral or written request to our Interim Chief Executive Officer.

On May 30, 2019,Secretary, who can be contacted at the Colorado Federal Court issued a subsequent order (the “Second Order”), appointing C. Randel Lewis as custodianaddress and telephone number set forth on the cover page of the Company pursuantthis Report. You may also find information related to the Wyoming Business Corporation Actour corporate governance, board committees and to take over for Mr. Smith in acting as our Interim Chief Executive Officer and to servecode of ethics on our Boardwebsite.

Item 1A. Risk Factors.

An investment in our common stock involves a high degree of Directors as Chairman. The Second Order noted thatrisk. You should carefully consider the primary purpose of having Mr. Lewis serve as custodian was to resolve the Board deadlock regarding Mr. Veltri’s termination. Pursuant to the Second Order, Mr. Lewis, as custodian, was ordered to act in place of the Board to appoint one independent director to replace Mr. Hoffman. On June 13, 2019, Mr. Lewis appointed Catherine J. Boggs to serve as an independent director until the 2019 annual meeting of our shareholders, which was held on December 10, 2019. Following such annual meeting, our directors appointed Ryan Smith as our Chief Executive Officer to replace Mr. Lewis in that role. Following our annual meeting, the Colorado Federal Court also discharged Mr. Lewis from serving as our custodian, Interim Chief Executive Officer and as a member of our Board.

Both the Texas Litigation and the Colorado Litigation currently remain pending.

Audit Committee Investigation

Following the termination of Mr. Veltri on February 25, 2019, our independent auditors, Plante & Moran PLLC, informed the Audit Committee that the auditors had found irregularities in the submission and payment of expense reports with respect to our former Chief Executive Officer. Our Audit Committee engaged independent legal counsel, which subsequently engaged an independent accounting firm to conduct a forensic accounting investigation of our expense reporting system in relation to issues raised by our auditors regarding potential financial improprieties related to expense reports, including examining expense reports and third-party expenditures made by or through our former Chief Executive Officer or his staff. The investigation was expanded into a forensic investigation of the integrity of our computer-based record keeping after Mr. Veltri and Mr. Hoffman managed to reset the security codes to give them complete control of our books and records temporarily and exclude our other employees’, members of management’s, other officer’s and director’s ability to access those records during that period. The scope of the forensic accounting investigation covered the period from January 1, 2017 through March 31, 2019. Our Audit Committee took certain steps in response to the forensic accounting investigation. See “Item 9A. Controls and Procedures—Changes in Internal Control Over Financial Reporting—Management’s Remediation Plan.”

The forensic accounting investigation and our internal investigation also identified numerous expense items on Mr. Veltri’s expense reports that appeared to be personal in nature or lacked adequate documentation showing that such expense was for legitimate business purposes. These expense items totaled at least $81,014, of which $32,194 was incurred during the year ended December 31, 2017, $34,203 was incurred during the year ended December 31, 2018 and $14,617 was incurred during 2019 prior to Mr. Veltri’s termination. We reclassified the entire $81,014 reimbursed to Mr. Veltri as additional compensation and taxable income. In addition, we have accrued payroll taxes payable on the additional compensation.

The report also indicated that Mr. Veltri used the Company’s vendors for his own personal benefit. Mr. Veltri bypassed our accounts payable process by paying third-party vendors personally through expense reports and then approved his own expense reports, which limited the visibility of the payments and review by our accounting personnel.

Mr. Veltri also incurred $47,156 in third-party professional fees in connection with a potential transaction with a company controlled by a former Board member, which transaction and related expenses in evaluating the potential transaction were not approved by the Board. At December 31, 2018, the total amount of the fees was impaired and transferred to the full cost pool.

Mr. Veltri also entered into an agreement to acquire some oil and natural gas properties for which the Board authorized $250,000, which amount was fully refundable, subject to the funds being held in escrow pending the closing of the acquisition. Mr. Veltri wired the funds directly into the seller’s account, rather than escrowing such funds, and also paid the seller an additional $124,328, which amount was not authorized by the Board,risks described below as well as $40,578 for professional services. The transaction never closed, and the Company has received $200,000 refund of such funds from the seller.

Recent Developments

On March 1, 2020, we acquired allother information in this filing before deciding to invest in our company. Any of the issuedrisk factors described below could significantly and outstanding equity interestsadversely affect our business, prospects, financial condition and results of New Horizon Resources LLC (“New Horizon”), whose assets include acreageoperations. Additional risks and operated producing properties in North Dakota (the “Properties”). The consideration paid at closing consisteduncertainties not currently known or that are currently considered to be immaterial may also materially and adversely affect our business, prospects, financial condition and results of 59,498 sharesoperations. As a result, the trading price or value of our common stock could be materially adversely affected and $150,000 in cash (the “Acquisition”). The New Horizon Properties consistyou may lose all or part of approximately 1,300 net acres located primarily in McKenzie and Divide Counties, North Dakota, which are 100% held by production, average a 63% working interest and produced approximately 30 net Boepd (88% oil) for the six-month period ended December 31, 2019.your investment.

Item 1A.Summary Risk Factors.Factors

An investment in our securities involves a high degree of risk. You should carefully consider the risks summarized below. These risks include, but are not limited to, the following:

Risk Factors

The following risk factors should be carefully considered in evaluating the information in this annual report on Form 10-K.

Risks InvolvingRelated to the Oil and Natural Gas Industry and Our Business

We may need additional capital to complete future acquisitions, conduct our operations, and fund our business, and our ability to obtain the necessary funding is uncertain.

We may need to raise additional funding to complete future potential acquisitions and will be required to raise additional funds through public or private debt or equity financing or other various means to fund our operations and complete workovers and acquire assets. In such a case, adequate funds may not be available when needed or may not be available on favorable terms. If we need to raise additional funds in the future by issuing equity securities, dilution to existing stockholders will result, and such securities may have rights, preferences, and privileges senior to those of our common stock. If funding is insufficient at any time in the future and we are unable to generate sufficient revenue from new business arrangements, to complete future acquisitions or operations, our results of operations and the value of our securities could be adversely affected.

Additionally, due to the nature of oil and gas interests, i.e., that rates of production generally decline over time as oil and gas reserves are depleted, if we are unable to acquire additional properties and/or develop our reserves, either because we are unable to raise sufficient funding for such development activities, or otherwise, or in the event we are unable to acquire additional operated or non-operated properties, we believe that our revenues will continue to decline over time. Furthermore, in the event we are unable to raise additional required funding in the future, we will not be able to participate in the drilling of additional wells, will not be able to complete other drilling and/or workover activities.

If this were to happen, we may be forced to scale back our business plan which could result in the value of our outstanding securities declining in value.

Oil, natural gas liquids (NGL) and natural gas prices, are volatile and declines in the prices of such commodities have in the past, and will continue in the future to, adversely affect our business, financial condition or results of operations, and our ability to meet our capital expenditure obligations or targets and financial commitments.

The developmentprice of oil and, to a lesser extent, natural gas and NGLs, heavily influences our revenue, profitability, cash flows, liquidity, access to capital, present value and quality of our reserves, the nature and scale of our operations, and our future rate of growth. Oil, NGL, and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. In recent years, the markets for oil and natural gas properties involves substantial risks that may resulthave been volatile. These markets will likely continue to be volatile in a total loss of investment.

The business of exploring forthe future. Further, oil prices and developing natural gas and oil properties involves a high degree of business and financial risk, and thus a significant risk of loss of initial investment that even a combination of experience, knowledge and careful evaluation may not be able to overcome. The cost and timing of drilling, completing and operating wells is often uncertain. Factors which can delay or prevent drilling or production, or otherwise impact expected results, include but are not limited to:

A productive well may become uneconomic in the event unusual quantities of water or other non-commercial substances are encountered in the well bore that impair or prevent production. We may participate in wells that are or become unproductive or, though productive,prices do not producenecessarily fluctuate in economic quantities. In addition, even commercial wells can produce less, or have higher costs, than we projected.

In addition, initial 24-hour or other limited-duration production rates announced regarding ourdirect relation to each other. The price of crude oil has experienced significant volatility over the last five years, with the price of a barrel of oil dropping below $20 during the early part of 2020, due in part to reduced global demand stemming from the recent global COVID-19 outbreak, and most recently surging over $125 a barrel in early March 2022 following Russia’s invasion of Ukraine, before more recently trading around $90-$100 a barrel. A prolonged period of low market prices for oil and natural gas, properties are not necessarily indicative of future production rates.

Dry holes and other unsuccessful or uneconomic exploration, exploitation and development activities can adversely affect our cash flow, profitability and financial condition, and can adversely affect our reserves. We do not currently operate any of our properties, and therefore have limited ability to control the manner in which drilling and other exploration and development activities on our properties are conducted, which may increase these risks.

Our business has been and may continue to be impacted by adverse commodity prices.

For the three years ended December 31, 2019, oil prices have ranged from highs over $77 per barrel in 2018 to lows below $43 per barrel in 2017. Global markets, in reaction to general economic conditions and perceived impacts of future global supply, have caused large fluctuations in price, and we believe significant future price swings are likely. Natural gas prices and NGL prices have experienced volatility of comparable magnitude over the same time period. Volatilityfurther declines in the market prices we receive for our oil and natural gas, production havewill likely result in capital expenditures being further curtailed and may continue towill adversely affect many aspects of our business, including our financial condition revenues, results of operations, cash flows, liquidity, reserves, rate of growth and the carrying value of ourliquidity. Additionally, lower oil and natural gas properties, allprices have, and may in the future, cause, a decline in our stock price. During the year ended December 31, 2020, the daily WTI oil spot price ranged from a high of which depend primarily or in part upon those prices. The reduction in drilling activity will likely result in lower production$63.27 per Bbl to a low of ($36.98) per Bbl and together with lower realizedthe NYMEX natural gas Henry Hub spot price ranged from a high of $3.14 per MMBtu to a low of $1.33 per MMBtu. During the year ended December 31, 2021, the daily WTI oil prices, lower revenuespot price ranged from a high of 85.64 per Bbl to a low of 47.47 per Bbl and adjusted EBITDAX. the NYMEX natural gas Henry Hub spot price ranged from a high of $23.86 per MMBtu to a low of $2.43 per MMBtu.

Declines in the prices we receive for our oil and natural gas can also adversely affect our ability to finance capital expenditures, make acquisitions, raise capital and satisfy our financial obligations. In addition, declines in prices can reduce the amount of oil and natural gas that we can produce economically and the estimated future cash flow from that production and, as a result, adversely affect the quantity and present value of our proved reserves. Among other things, a reduction in the amount or present value of our reserves can limit the capital available to us, and the availability of other sources of capital likely will be based to a significant degree on the estimated quantity and value of the reserves.

Declines inAs described above, oil, and natural gas prices have and will materially adversely affect our revenues.

Our financial condition and results of operations depend in large part upon the prices obtainable for our oil and natural gas production and the costs of finding, acquiring, developing and producing reserves. As seen in recent years, prices for oilNGLs, and natural gas are commodities and, therefore, their prices are subject to extremewide fluctuations in response to relatively minor changes in supply market uncertainty and a variety of additional factors that are beyond tour control. These factors include worldwide political instability (especially in the Middle East and other oil producing regions), the foreign supply of oil and natural gas, the price of foreign imports, the level of drilling activity, the level of consumer product demand, government regulations and taxes, the price and availability of alternative fuels, speculating activities indemand. Historically, the commodities markets,market has been volatile. An extended period of continued lower oil prices, or additional price declines, will have further adverse effects on us. The prices we receive for any future production and the overall economic environment. Our operations are substantially adversely impacted as oil prices decline. Lower prices dramatically affect our revenues. Further, drilling of new wells, developmentreceived from operators of our leasesnon-operated production, and acquisitionsthe levels of new properties are also adversely affected and limited. As a result, our potential revenues as well as our proved reserves may substantially decrease from levels achieved duringsuch production, will continue to depend on numerous factors, including the period whenfollowing:

Declines in oil, prices were much higher. There can be no assurances as to the future prices of oil or natural gas. A substantial or extended decline in oilNGL, or natural gas prices will reduce not only our revenue but also the amount of oil, NGL, and natural gas that we, and the operators of our properties, can produce economically. Should natural gas, NGL or oil prices decline in the future, our non-operated wells and/or any of our own wells, may be forced to be shut-in, and exploration and development plans for prospects and exploration or development activities may need to be postponed or abandoned. As a result, we may have to make substantial downward adjustments to our estimated proved reserves, each of which would have a material adverse effect on our business, financial condition, and results of operations.

We have limited control over activities on properties we do not operate.

We are not the operator on some of our properties, and, as a result, our ability to exercise influence over the operations of these properties or their associated costs is limited. Our dependence on the operators and other working interest owners of these projects and our limited ability to influence operations and associated costs or control the risks could materially and adversely affect the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including:

The operators of our Williston Basin wells previously temporarily shut-in such wells to preserve oil and gas reserves for production during a more favorable oil price environment, and while such wells have resumed production, our wells may again be shut-in, should market conditions significantly deteriorate.

In early March 2020, there was a global outbreak of COVID-19 that resulted in a drastic decline in global demand of certain mineral and energy products including crude oil. As a result of the lower demand caused by the COVID-19 pandemic and the oversupply of crude oil, spot and future prices of crude oil fell to historic lows during the second quarter of 2020. Operators in North Dakota’s Williston Basin (including the operators of our wells) responded by significantly decreasing drilling and completion activity and shutting in or curtailing production from a significant number of producing wells. Operators’ decisions on these matters are changing rapidly and it is difficult to predict the future effects on the Company’s business. Lower oil and natural gas prices not only decrease our revenues, but an extended decline in oil or gas prices may materially and adversely affect our future business, financial position, cash flows, results of operations, quantitiesliquidity, and ability to finance planned capital expenditures. While our producing wells are shut-in, we do not generate revenues from such wells, and would need to use our cash on hand and funds we receive from borrowings and the sale of equity in order to pay our operating expenses. A continued period of low-priced oil may make it non-economical for our wells to operate, which would have a material adverse effect on our operating results and the value of our assets. We cannot estimate the future price of oil, and as such cannot estimate, when our wells may again be shut-in by their operators.

Our business and operations have been adversely affected by the COVID-19 pandemic, and may be adversely affected by other similar outbreaks.

As a result of the COVID-19 pandemic or other adverse public health developments, including voluntary and mandatory quarantines, travel restrictions, and other restrictions, our operations, and those of our subcontractors, customers, and suppliers, have and experienced delays or disruptions and temporary suspensions of operations. In addition, our financial condition and results of operations have been adversely affected by the COVID-19 pandemic.

The timeline and potential magnitude of the COVID-19 outbreak are currently unknown. The continuation or amplification of this virus could continue to more broadly affect the United States and global economy, including our business and operations, and the demand for oil and gas. Other contagious diseases in the human population could have similar adverse effects. As the potential impact from COVID-19 is difficult to predict, the extent to which it will negatively affect our operating results, or the duration of any potential business disruption is uncertain. The magnitude and duration of any impact will depend on future developments and new information that may emerge regarding the severity and duration of COVID-19 and the actions taken by authorities to contain it or treat its impact, all of which are beyond our control.

Declining general economic, business or industry conditions have, and will continue to have, a material adverse effect on our results of operations, liquidity, and financial condition, and are expected to continue having a material adverse effect for the foreseeable future.

Concerns over global economic conditions, the threat of pandemic diseases and the results thereof, energy costs, geopolitical issues, inflation, the availability and cost of credit have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil and natural gas, that may be economically produced,declining business and accessconsumer confidence, and increased unemployment, have precipitated an economic slowdown and a recession, which could expand to capital. Oila global depression. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices and are expected to continue having a material adverse effect for the foreseeable future. If the economic climate in the United States or abroad continues to deteriorate, demand for petroleum products could diminish, which could further impact the price at which our operators can sell oil, natural gas, and natural gas prices have historically beenliquids, affect the ability of our vendors, suppliers and are likelycustomers to continue operations, and ultimately adversely impact our results of operations, liquidity and financial condition to be volatile.

This volatility makesa greater extent than it difficult to estimate with precisionhas already. In addition, a decline in consumer confidence or changing patterns in the valueavailability and use of producing properties in acquisitions and to budget and projectdisposable income by consumers can negatively affect the return on exploration and development projects involving ourdemand for oil and gas properties. In addition, unusually volatile prices often disrupt the market forand as a result our results of operations.

The development of oil and natural gas properties as buyersinvolves substantial risks that may result in a total loss of investment.

The business of exploring for, working over and sellersdeveloping natural gas and oil properties involves a high degree of business and financial risk, and thus a significant risk of loss of initial investment that even a combination of experience, knowledge and careful evaluation may not be able to overcome. The cost and timing of drilling, workover completing and operating wells is often uncertain. Factors which can delay or prevent drilling or production, or otherwise impact expected results, include but are not limited to:

A productive well may become uneconomic in the event unusual quantities of water or other non-commercial substances are encountered in the well bore that impair or prevent production. We may participate in wells that are or become unproductive or, though productive, do not produce in economic quantities. In addition, even commercial wells can produce less, or have more difficulty agreeing on the purchase pricehigher costs, than we projected.

In addition, initial 24-hour or other limited-duration production rates announced regarding our oil and natural gas properties are not necessarily indicative of properties.future production rates.

Dry holes and other unsuccessful or uneconomic exploration, exploitation and development activities can adversely affect our cash flow, profitability and financial condition, and can adversely affect our reserves.

The Williston Basin (Bakken and Three Forks shales) oil price differential and oil price differentials in recently acquired properties in Wyoming and Montana could have adverse impacts on our revenue.

Generally, crude oil produced from the Bakken formation in North Dakota is high quality (36 to 44 degrees API, which is comparable to West Texas Intermediate Crude (“WTI”)). During 2019,2021, our weighted average realized oil price in the Williston Basin was $51.92,$61.74, which due to transportation costs was approximately $5.06$6.25 per barrel less than the average WTI spot price for crude oil. This discount, or differential, may widen in the future, which would reduce the price we receive for our production. We may also be adversely affected by widening differentials in other areas of operation.

Drilling and completion costs for the wells we drill in the Williston Basin are comparable to or higher than other areas where there is no price differential. This makes it more likely that a downturn in oil prices will result in a ceiling limitation write-down of our oil and natural gas properties. A widening of the differential would reduce the cash flow from our Williston Basin properties and adversely impact our ability to participate fully in drilling. Our production in other areas could also be affected by adverse changes in differentials. In addition, changes in differentials could make it more difficult for us to effectively hedge our exposure to changes in commodity prices.

Our former Chief Executive Officer, President and Chairman of the Board of Directors, received expense reimbursements without adequate backup, and we paid certain vehicle expenses on behalf of an entity affiliated with John Hoffman, a former director, both of which may be deemed violations of Section 402 of the Sarbanes-Oxley Act of 2002 and/or other federal securities laws.

Our internal control testing identified inadequate supporting documentation and lack of adequate review for certain travel advances and expense reimbursements.

Following the termination of David Veltri, our former Chief Executive Officer, President and Chairman, our Audit Committee conducted a review of Company procedures, policies and practices, including travel expense advancements and reimbursements. Our Audit Committee retained independent counsel and an advisory firm with forensic accounting expertise to assist the Audit Committee in conducting the investigation. As part of the investigation, the Audit Committee reviewed our financial policies and procedures, including management expenses. The Audit Committee concluded that Mr. Veltri did not produce receipts with adequate detail for a portion of his reimbursed business expenses he received from 2017 to 2019.

In 2018 and 2019, we paid approximately $2,350 for vehicle expenses on behalf of an entity affiliated with Mr. Hoffman. While we were reimbursed for these expenses, it is possible that these payments by the Company on behalf of Mr. Hoffman could be deemed to be in violation of Section 402 of the Sarbanes-Oxley Act of 2002.

Section 402 of the Sarbanes Oxley Act of 2002 prohibits personal loans to a director or executive officer of a public company. If the SEC were to commence an investigation or institute proceedings to enforce a violation of this statute or other federal securities laws as a result of the reimbursement of expenses to Mr. Veltri or the payment of the vehicle expenses associated with an entity owned by an affiliated entity of Mr. Hoffman, we may become a party to litigation or proceedings over these matters, and the outcome of such litigation or proceedings (including criminal, civil or administrative sanctions or penalties by the SEC), alone or in addition to the costs of litigation, may materially and adversely affect our business. We are unable to predict the extent of our ultimate liability with respect to these payments.

Non-consent provisions could result in penalties and loss of revenues from wells.

Our industry partners may elect to engage in drilling activities that we are unwilling or unable to participate in during 2022 and thereafter. Our exploration and development agreements contain customary industry non-consent provisions. Pursuant to these provisions, if a well is proposed to be drilled or completed but if a working interest owner elects not to participate, the resulting revenues (which otherwise would go to the non-participant) flow to the participants until the participating parties receive from 150% to 300% of the capital they provided to cover the non-participant’s share. In order to be in position to avoid non-consent penalties and to make opportunistic investments in new assets, we will continue to evaluate various options to obtain additional capital, including debt financing, sales of one or more producing or non-producing oil and natural gas assets and the issuance of shares of our common stock.

Unanticipated costs could require new capital that may not be available.

The oil and natural gas business holds the opportunity for significant returns on investment, but achievement of such returns is subject to high risk. For example, initial results from one or more of the oil and natural gas programs could be marginal but warrant investing in more wells. Dry holes, over-budget exploration costs, low commodity prices, or any combination of these or other adverse factors, could result in production revenues falling below projections, thus adversely impacting cash expected to be available for a continued work program, and a reduction in cash available for investment in other programs. These types of events could require a reassessment of priorities and therefore potential re-allocations of existing capital and could also mandate obtaining new capital. There can be no assurance that we will be able to complete any financing transaction on acceptable terms.

Competition may limit our opportunities in the oil and natural gas business.

The oil and natural gas business is very competitive. We compete with many public and private exploration and development companies in finding investment opportunities. We also compete with oil and natural gas operators in acquiring acreage positions. Our principal competitors are small to mid-size companies with in-house petroleum exploration and drilling expertise. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. They also may be willing and able to pay more for oil and natural gas properties than our financial resources permit, and may be able to define, evaluate, bid for and purchase a greater number of properties. In addition, there is substantial competition in the oil and natural gas industry for investment capital, and we may not be able to compete successfully in raising additional capital if needed.

Successful exploitation of shale formations is subject to risks related to horizontal drilling and completion techniques.

Operations in shale formations in many cases involve utilizing the latest drilling and completion techniques in an effort to generate the highest possible cumulative recoveries and therefore generate the highest possible returns. Risks that are encountered while drilling include, but are not limited to, landing the well bore in the desired drilling zone, staying in the zone while drilling horizontally through the shale formation, running casing the entire length of the well bore (as applicable to the formation) and being able to run tools and other equipment consistently through the horizontal well bore.

For wells that are hydraulically fractured, completion risks include, but are not limited to, being able to fracture stimulate the planned number of fracture stimulation stages, and successfully cleaning out the well bore after completion of the final fracture stimulation stage. Ultimately, the success of these latest drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficient period of time.

Costs for any individual well will vary due to a variety of factors. These wells are significantly more expensive than a typical onshore shallow conventional well. Accordingly, unsuccessful exploration or development activity affecting even a small number of wells could have a significant impact on our results of operations. Costs other than drilling and completion costs can also be significant for shale wells.

If our access to oil and natural gas markets is restricted, it could negatively impact our production and revenues. Securing access to takeaway capacity may be particularly difficult in less developed areas of the Williston Basin and the recently acquired properties in Montana and Wyoming.

Market conditions or limited availability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and other midstream facilities. The ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, rail transportation and processing facilities owned and operated by third parties. In particular, access to adequate gathering systems or pipeline or rail takeaway capacity is limited in the Williston Basin and the recently acquired properties in Montana and Wyoming. In order to secure takeaway capacity and related services, we or our operating partners may be forced to enter into arrangements that are not as favorable to operators as those in other areas.

If we are unable to replace reserves, we will not be able to sustain production.

Our future operations depend on our ability to find, develop, and acquire crude oil, natural gas, and NGL reserves that are economically producible. Our properties produce crude oil, natural gas, and NGLs at a declining rate over time. In order to maintain current production rates, we must locate and develop or acquire new crude oil, natural gas, and NGL reserves to replace those being depleted by production. Without successful drilling or acquisition activities, our reserves and production will decline over time. In addition, competition for crude oil and natural gas properties is intense, and many of our competitors have financial, technical, human, and other resources necessary to evaluate and integrate acquisitions that are substantially greater than those available to us.

As part of our growth strategy, we intend to make acquisitions. However, suitable acquisition candidates may not be available on terms and conditions we find acceptable, and acquisitions pose substantial risks to our business, financial condition and results of operations. In pursuing acquisitions, we compete with other companies, many of which have greater financial and other resources than we do. In the event we do complete an acquisition, its successful impact on our business will depend on a number of factors, many of which are beyond our control. These factors include the purchase price for the acquisition, future crude oil, natural gas, and NGL prices, the ability to reasonably estimate or assess the recoverable volumes of reserves, rates of future production and future net revenues attainable from reserves, future operating and capital costs, results of future exploration, exploitation, and development activities on the acquired properties, and future abandonment and possible future environmental or other liabilities. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves, actual future production rates, and associated costs and potential liabilities with respect to prospective acquisition targets. Actual results may vary substantially from those assumed in the estimates. A customary review of subject properties will not necessarily reveal all existing or potential problems.

Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties if they have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such transactions may be limited. If we are unable to integrate acquisitions successfully and realize anticipated economic, operational and other benefits in a timely manner, substantial costs and delays or other operational, technical or financial problems could result.

Integrating acquired businesses and properties involves a number of special risks. These risks include the possibility that management may be distracted from regular business concerns by the need to integrate operations and systems and that unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results and may cause us to not be able to realize any or all of the anticipated benefits of the acquisitions.

Many of our joint operating agreements contain provisions that may be subject to legal interpretation, including allocation of non-consent interests, complex payout calculations that impact the timing of reversionary interests, and the impact of joint interest audits.

Substantially all of our oil and natural gas interests are subject to joint operating and similar agreements. Some of these agreements include payment provisions that are complex and subject to different interpretations and/or can be erroneously applied in particular situations.

Joint interest audits are a normal process in our business to ensure that operators adhere to standard industry practices in the billing of costs and expenses related to our oil and natural gas properties. However, the ultimate resolution of joint interest audits can extend over a long period of time in which we attempt to recover excessive amounts charged by the operator. Joint interest audits result in incremental costs for the audit services and we can incur substantial amounts of legal fees to resolve disputes with the operators of our properties.

We have many non-operated drilling locations. Therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of these non-operated assets.

We do not currently operate the drilling prospects in South Texas we hold with industry partners. As a non-operator, our ability to exercise influence over the operations of the drilling programs is limited. In the usual case in the oil and natural gas industry, new work is proposed by the operator and often is approved by most of the non-operating parties. If the work is approved by the holders of a majority of the working interests, but we disagree with the proposal and do not (or are unable to) participate, we will forfeit our share of revenues from the well until the participants receive 150% to 300% of their investment. In some cases, we could lose all of our interest in the well. We would avoid a penalty of this kind only if a majority of the working interest owners agree with us and the proposal does not proceed.

The success and timing of our drilling and development activities on properties operated by others depend upon a number of factors outside of our control, including:

The fact that our industry partners serve as operator makes it more difficult for us to predict future production, cash flows and liquidity needs. Our ability to grow our production and reserves depends on decisions by our partners to drill wells in which we have an interest, and they may elect to reduce or suspend the drilling of those wells.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or the relevant underlying assumptions will materially affect the quantity and present value of our reserves.

Oil and natural gas reserve reports are prepared by independent consultants to provide estimates of the quantities of hydrocarbons that can be economically recovered from proved properties, utilizing commodity prices for a trailing 12-month period and taking into account expected capital, operating and other expenditures. These reports also provide estimates of the future net present value of the reserves, which we use for internal planning purposes and for testing the carrying value of the properties on our balance sheet.

The reserve data included in this report represents estimates only. Estimating quantities of, and future cash flows from, proved oil and natural gas reserves is a complex process and not an exact science. It requires interpretations of available technical data and various estimates, including estimates based upon assumptions relating to economic factors, such as future production costs; ad valorem, severance and excise taxes; availability of capital; estimates of required capital expenditures, workover and remedial costs; and the assumed effect of governmental regulation. The assumptions underlying our estimates of our proved reserves could prove to be inaccurate, and any significant inaccuracy could materially affect, among other things, future estimates of the reserves, the economically recoverable quantities of oil and natural gas attributable to the properties, the classifications of reserves based on risk of recovery, and estimates of our future net cash flows.

At December 31, 2021, 100% of our estimated proved reserves were developed producing. Estimation of proved undeveloped reserves and proved developed non-producing reserves is almost always based on analogy to existing wells, volumetric analysis or probabilistic methods, in contrast to the performance data used to estimate producing reserves. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations.

You should not assume that the present values referred to in this report represent the current market value of our estimated oil and natural gas reserves. The timing and success of the production and the expenses related to the development of oil and natural gas properties, each of which is subject to numerous risks and uncertainties, will affect the timing and amount of actual future net cash flows from our proved reserves and their present value. In addition, our PV-10 and standardized measure estimates are based on costs as of the date of the estimates and assume fixed commodity prices. Actual future prices and costs may be materially higher or lower than the prices and costs used in the estimate.

Further, the use of a 10% discount factor to calculate PV-10 and standardized measure values may not necessarily represent the most appropriate discount factor given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

The use of derivative arrangements in oil and natural gas production have in the past and could in the future result in financial losses or reduce income.

From time to time, we use derivative instruments, typically fixed-rate swaps and costless collars, to manage price risk underlying our oil and natural gas production. For example, on March 9, 2021, we entered into a commodity derivative contract to fix the price of 100 barrels of crude oil per day from March 1 to December 31, 2021 at $61.90, based on the calendar month average of WTI Crude Oil. During the year ended December 31, 2021, we realized a loss on this fixed-price swap commodity derivative contract of $260 thousand. In addition, on January 12, 2022, the Company entered into additional NYMEX WTI crude oil commodity derivative contracts for 2022 and 2023 production. The Company entered into commodity derivative collar contracts for a total of 210,500 Bbls of crude oil from February 1, 2022 to December 31, 2022 with a floor of $65.00 and a ceiling of $89.40 and 211,500 Bbls of crude oil from January 1, 2023 to December 31, 2023 with a floor of $60.00 and a ceiling of $81.04. The price of oil has already exceeded the ceiling set forth in the February 1, 2022 to December 31, 2022 contract and we may not benefit from future increases in the price of oil due to such current or future commodity derivative contracts. The fair value of our derivative instruments is marked to market at the end of each quarter and the resulting unrealized gains or losses due to changes in the fair value of our derivative instruments is recognized in current earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for the relevant period. If the actual amount of production is higher than we estimated, we will have greater commodity price exposure than we intended. If the actual amount of production is lower than the notional amount that is subject to our derivative instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows.

Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

In addition, depending on the type of derivative arrangements we enter into, the agreements could limit the benefit we would receive from increases in oil prices. It cannot be assumed that the hedging transactions we have entered into, or will enter into, will adequately protect us from fluctuations in commodity prices.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) provides for statutory and regulatory requirements for derivative transactions, including crude oil and natural gas derivative transactions. Among other things, the Dodd-Frank Act provides for the creation of position limits for certain derivatives transactions, as well as requiring certain transactions to be cleared on exchanges for which cash collateral will be required. The Dodd-Frank Act requires the Commodities Futures and Trading Commission (the “CFTC”), the SEC and other regulators to promulgate rules and regulations implementing the Dodd-Frank Act.

The CFTC has finalized other regulations implementing the Dodd-Frank Act’s provisions regarding trade reporting, margin, clearing and trade execution; however, some regulations remain to be finalized and it is not possible at this time to predict when the CFTC will adopt final rules. For example, the CFTC has re-proposed regulations setting position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions are expected to be made exempt from these limits. Also, it is possible that under recently adopted margin rules, some registered swap dealers may require us to post initial and variation margins in connection with certain swaps not subject to central clearing.

The Dodd-Frank Act and any additional implementing regulations could significantly increase the cost of some commodity derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of some commodity derivative contracts, limit our ability to trade some derivatives to hedge risks, reduce the availability of some derivatives to protect against risks we encounter and reduce our ability to monetize or restructure our existing commodity derivative contracts. If we reduce our use of derivatives as a consequence, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. If the implementing regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could adversely affect our business, financial condition and results of operations.

Increases in the differential between the ceiling value for oil and natural gas prices set forth in our commodity derivative contracts and commodity derivative collar contracts has in the past adversely affected, and is anticipated to continue to adversely affect our business, financial condition and results of operations.

Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In the highly competitive market for acreage, failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, the loss of our lease and prospective drilling opportunities.

Unless production is established within the spacing units covering the undeveloped acres on which some of our potential drilling locations are identified, the leases for such acreage will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. The risk that our leases may expire will generally increase when commodity prices fall, as lower prices may cause our operating partners to reduce the number of wells they drill. In addition, on certain portions of our acreage, third-party leases could become immediately effective if our leases expire. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business.

Our producing properties are primarily located in the Williston Basin, Montana, Wyoming, New Mexico, Texas Oklahoma and Kansas, making us vulnerable to risks associated with having operations concentrated in these geographic areas.

Because our operations are geographically concentrated in the Williston Basin, Montana, Wyoming, New Mexico, Texas, Oklahoma and Kansas the success and profitability of our operations may be disproportionally exposed to the effect of regional events. These include, among others, regulatory issues, natural disasters and fluctuations in the prices of crude oil and natural gas produced from wells in the region and other regional supply and demand factors, including gathering, pipeline and other transportation capacity constraints, available rigs, equipment, oil field services, supplies, labor and infrastructure capacity. Any of these events has the potential to cause producing wells to be shut-in, delay operations and growth plans, decrease cash flows, increase operating and capital costs and prevent development of lease inventory before expiration. In addition, our operations in the Williston Basin, Montana and Wyoming may be adversely affected by seasonal weather and lease stipulations designed to protect wildlife, which can intensify competition for services, infrastructure and equipment during months when drilling is possible and may result in periodic shortages. Any of these risks could have a material adverse effect on our financial condition and results of operations.

Insurance may be insufficient to cover future liabilities.

Our business is currently focused on oil and natural gas exploration and development, and we also have potential exposure to general liability and property damage associated with the ownership of other corporate assets. We have obtained insurance policies for our oil and natural gas operations covering both operated and non-operated properties, as well as, policies covering corporate liabilities and damage to corporate assets.

We would be liable for claims in excess of coverage and for any deductible provided for in the relevant policy. If uncovered liabilities are substantial, payment could adversely impact the Company’s cash on hand, resulting in possible curtailment of operations. Moreover, some liabilities are not insurable at a reasonable cost or at all.

Potential conflicts of interest could arise for certain members of our Board of Directors that hold management positions with other entities and also represent our majority shareholders.

John A. Weinzierl, Duane H. King and Joshua Batchelor, each a member of the Board of Directors of the Company, hold various other management positions with privately-held companies, some of which are involved in the oil and gas industry, and together such persons control or have joint control, over a majority of our common stock. We believe these positions will not conflict with their roles or responsibilities with our company. Certain of these entities are party to agreements with the Company and if any of these companies enter into any additional transactions or agreements with our company, or other related party transactions or matters exist, potential conflicts of interests could arise from the directors performing services for us and these other entities.

We are dependent upon information technology systems, which are subject to disruption, damage, failure and risks associated with implementation and integration.

We are dependent upon information technology systems in the conduct of our operations. Our information technology systems are subject to disruption, damage or failure from a variety of sources, including, without limitation, computer viruses, security breaches, cyberattacks, natural disasters and defects in design. Cybersecurity incidents, in particular, are evolving and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and other electronic security breaches that could lead to disruptions in systems, unauthorized release of confidential or otherwise protected information and the corruption of data. Various measures have been implemented to manage our risks related to information technology systems and network disruptions. However, given the unpredictability of the timing, nature and scope of information technology disruptions, we could potentially be subject to operational delays, the compromising of confidential or otherwise protected information, destruction or corruption of data, security breaches, other manipulation or improper use of our systems and networks or financial losses from remedial actions, any of which could have a material adverse effect on our cash flows, competitive position, financial condition or results of operations.

Improvements in or new discoveries of alternative energy technologies could have a material adverse effect on our financial condition and results of operations.

Because our operations depend on the demand for oil and used oil, any improvement in or new discoveries of alternative energy technologies (such as wind, solar, geothermal, fuel cells and biofuels) that increase the use of alternative forms of energy and reduce the demand for oil, gas and oil and gas related products could have a material adverse impact on our business, financial condition and results of operations.

Competition due to advances in renewable fuels may lessen the demand for our products and negatively impact our profitability.

Alternatives to petroleum-based products and production methods are continually under development. For example, a number of automotive, industrial and power generation manufacturers are developing alternative clean power systems using fuel cells or clean-burning gaseous fuels that may address increasing worldwide energy costs, the long-term availability of petroleum reserves and environmental concerns, which if successful could lower the demand for oil and gas. If these non-petroleum-based products and oil alternatives continue to expand and gain broad acceptance such that the overall demand for oil and gas is decreased it could have an adverse effect on our operations and the value of our assets.

Permitting requirements could delay our ability to start or continue our operations.

Oil and natural gas projects are subject to extensive permitting requirements. Failure to timely obtain required permits to start operations at a project could cause delay and/or the failure of the project resulting in a potential write-off of the investments made.

Negative public perception regarding us and/or our industry could have an adverse effect on our operations.

Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, waste disposal, oil spills, seismic activity, climate change, explosions of natural gas transmission lines and the development and operation of pipelines and other midstream facilities may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. Additionally, environmental groups, landowners, local groups and other advocates may oppose our operations through organized protests, attempts to block or sabotage our operations or those of our midstream transportation providers, intervene in regulatory or administrative proceedings involving our assets or those of our midstream transportation providers, or file lawsuits or other actions designed to prevent, disrupt or delay the development or operation of our assets and business or those of our midstream transportation providers. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we require to conduct our operations to be withheld, delayed or burdened by requirements that restrict our ability to profitably conduct our business.

Recently, activists concerned about the potential effects of climate change have directed their attention towards sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in energy-related activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities.

Seasonal weather conditions adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in the Williston Basin, Montana, Wyoming and the Texas Gulf Coast can be adversely affected by seasonal weather conditions. In the Williston Basin, Montana and Wyoming, drilling and other oil and natural gas activities sometimes cannot be conducted as effectively during the winter months, and this can materially increase our operating and capital costs. Texas Gulf Coast operations are also subject to the risk of adverse weather events, including hurricanes.

Shortages of equipment, services and qualified personnel could reduce our cash flow and adversely affect results of operations.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices and activity levels in new regions, causing periodic shortages. These problems can be particularly severe in certain regions such as the Williston Basin and Texas. During periods of high oil and natural gas prices, the demand for drilling rigs and equipment tends to increase along with increased activity levels, and this may result in shortages of equipment. Higher oil and natural gas prices generally stimulate increased demand for equipment and services and subsequently often result in increased prices for drilling rigs, crews and associated supplies, oilfield equipment and services, and personnel in exploration, production and midstream operations. These types of shortages and subsequent price increases could significantly decrease our profit margin, cash flow and operating results and/or restrict or delay our ability to drill those wells and conduct those activities that we currently have planned and budgeted, causing us to miss our forecasts and projections.

We depend significantly upon the continued involvement of our present management.

We depend to a significant degree upon the involvement of our management, specifically, our Chief Executive Officer and Chief Financial Officer, Ryan L. Smith. Our performance and success are dependent to a large extent on the efforts and continued employment of Mr. Smith. We do not believe that Mr. Smith could be quickly replaced with personnel of equal experience and capabilities, and his successor(s) may not be as effective. If Mr. Smith or any of our other key personnel resign or become unable to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected. The Company entered into an agreement with Mr. Smith on March 5, 2020. The term of Mr. Smith’s Employment Agreement commenced on March 5, 2020, and was to continue until January 1, 2021, provided that on January 1, 2021, the Employment Agreement automatically renewed for a successive term of one year,. The Employment Agreement has since expired pursuant to its terms on January 1, 2022.

We have an active Board of Directors that meets several times throughout the year and is intimately involved in our business and the determination of our operational strategies. Members of our Board of Directors work closely with management to identify potential prospects, acquisitions, and areas for further development. If any of our directors resign or become unable to continue in their present role, it may be difficult to find replacements with the same knowledge and experience and as a result, our operations may be adversely affected.

Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil and natural gas we will receive, and significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating accumulations of oil and natural gas is complex and is not exact, due to numerous inherent uncertainties. The process relies on interpretations of available geological, geophysical, engineering, and production data. The extent, quality, and reliability of this technical data can vary. The process also requires certain economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes, and availability of funds. The accuracy of a reserves estimate is a function of:

The accuracy of any estimates of proved reserves generally increases with the length of the production history. Due to the limited production history of our properties, the estimates of future production associated with these properties may be subject to greater variance to actual production than would be the case with properties having a longer production history. As our wells produce over time and more data is available, the estimated proved reserves will be re-determined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other factors.

Actual future production, oil, and natural gas prices, revenues, taxes, development expenditures, operating expenses, and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that future production declines in our wells may be greater than we have estimated. Any significant variance to our estimates could materially affect the quantities and present value of our reserves.

We may purchase oil and natural gas properties with liabilities or risks that we did not know about or that we did not assess correctly, and, as a result, we could be subject to liabilities that could adversely affect our results of operations.

Before acquiring oil and natural gas properties, we estimate the reserves, future oil and natural gas prices, operating costs, potential environmental liabilities, and other factors relating to the properties. However, our review involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not discover all existing or potential problems associated with the properties we buy. We may not become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We generally do not perform inspections on every well or property, and we may not be able to observe mechanical and environmental problems even when we conduct an inspection. The seller may not be willing or financially able to give us contractual protection against any identified problems, and we may decide to assume environmental and other liabilities in connection with the properties we acquire. If we acquire properties with risks or liabilities we did not know about or that we did not assess correctly, our business, financial condition, and results of operations could be adversely affected as we settle claims and incur cleanup costs related to these liabilities.

The properties we acquired in January 2022 may be subject to liabilities or risks that we did not know about or that we did not assess correctly, and, as a result, we could be subject to liabilities that could adversely affect our results of operations as a result of such acquisitions.

We may fail to realize the anticipated benefits of the recent January 2022 acquisition and may assume unanticipated liabilities.

The success of our January 2022 acquisition will depend on, among other things, our ability to combine our assets and the acquired assets in a manner that realizes the various benefits, growth opportunities and synergies identified by combining our assets with the acquired assets. Achieving the anticipated benefits of the acquisition is subject to a number of risks and uncertainties. Completing the integration process may be more expensive than anticipated, and we cannot assure you that we will be able to affect the integration of these operations smoothly or efficiently or that the anticipated benefits of the purchase will be achieved.

Risks Related to Our Financial Statements

We have written down, and may in the future be forced to further write-down, material portions of our assets due to low oil prices.

The successful efforts method of accounting is used for oil and gas exploration and production activities. Under this method, all costs for development wells, support equipment and facilities, and proved mineral interests in oil and gas properties are capitalized. We review the carrying value of our long-lived assets annually or whenever events or changes in circumstances indicate that the historical cost-carrying value of an asset may no longer be appropriate. We assess the recoverability of the carrying value of the asset by estimating the future net undiscounted cash flows expected to result from the asset, including eventual disposition. If the future net undiscounted cash flows are less than the carrying value of the asset, an impairment loss is recorded equal to the difference between the asset’s carrying value and estimated fair value. This impairment does not impact cash flows from operating activities but does reduce earnings and our shareholders’ equity.

Under the full cost method of accounting, we capitalize the cost to acquire, explore for and develop our oil and natural gas investments. Under full cost accounting rules, the net capitalized cost of oil and natural gas properties may not exceed a “ceiling limit” that is based upon the present value of estimated future net revenues from proved reserves, discounted at 10%, plus the lower of the cost or fair market value of unproved properties. If net capitalized costs exceed the ceiling limit, we must charge the amount of the excess to earnings (a charge referred to as a “ceiling test write-down”). The risk of a ceiling test write-down increases when oil and natural gas prices are depressed, if we have substantial downward revisions in estimated proved reserves or if we drill unproductive wells.

Under the full cost method, all costs associated with the acquisition, exploration and development of oil and natural gas properties are capitalized and accumulated in a country-wide cost center. This includes any internal costs that are directly related to development and exploration activities, but does not include any costs related to production, general corporate overhead or similar activities. Proceeds received from disposals are credited against accumulated cost, except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized. The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production method, based on proved oil and natural gas reserves. Excluded from amounts subject to depreciation, depletion and amortization are costs associated with unevaluated properties.

Under the full cost method, net capitalized costs are limited to the lower of (a) unamortized cost reduced by the related net deferred tax liability and asset retirement obligations, and (b) the cost center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenue, discounted at 10% per annum, from proved reserves, based on unescalated costs, adjusted for contract provisions, any financial derivatives qualifying as accounting hedges and asset retirement obligations, and unescalated oil and natural gas prices during the period, (ii) the cost of properties not being amortized, and (iii) the lower of cost or market value of unproved properties included in the cost being amortized, less (iv) income tax effects related to tax assets directly attributable to the natural gas and crude oil properties. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds the cost center ceiling limitation, a non-cash impairment charge is required in the period in which the impairment occurs.

We perform a quarterly ceiling test for our only oil and natural gas cost center, which is the United States. During 2021, we did not record a ceiling test write-down, however, during 2020, our capitalized costs for oil and natural gas properties exceeded the ceiling and, therefore, we recorded an aggregate ceiling test write-down of $2.9 million. The ceiling test incorporates assumptions regarding pricing and discount rates over which we have no influence in the determination of present value In arriving at the ceiling test for the year ended December 31, 2021, we used an average price applicable to our properties of $66.56 per barrel for oil and $3.60 per Mcfe for natural gas, based on average prices per barrel of oil and per Mcfe of natural gas at the first day of each month of the 12-month period prior to the end of the reporting period, to compute the future cash flows of each of the producing properties at that date.

Capitalized costs associated with unevaluated properties include exploratory wells in progress, costs for seismic analysis of exploratory drilling locations, and leasehold costs related to unproved properties. During 2020, the COVID-19 pandemic has led to an economic downturn resulting in lower oil prices which required us to incur material write-downs. Unevaluated properties not subject to depreciation, depletion and amortization amounted to an aggregate of approximately $1.6 million as of December 31, 2021. These costs will be transferred to evaluated properties to the extent that we subsequently determine the properties are impaired or if proved reserves are established. During 2020, we impaired $2.1 million of unevaluated properties and reclassified these amounts to the full cost pool.

We have identified material weaknesses in our internal control over financial reporting, and our management has concluded that our disclosure controls and procedures were not effective during 2017, 2018, 2019, 2020 and 2019.2021. We cannot assure you that additional material weaknesses or significant deficiencies do not exist or that they will not occur in the future. If our internal control over financial reporting or our disclosure controls and procedures are not effective, we may not be able to accurately report our financial results or prevent fraud, which may cause investors to lose confidence in our reported financial information and may lead to a decline in our stock price.

Effective internal controls are necessary for us to provide reliable financial reports and effectively prevent fraud. We maintain a system of internal control over financial reporting, which is defined as a process designed by, or under the supervision of, our principal executive officer and principal financial officer, or persons performing similar functions, and effected by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. A “material weakness” is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our financial statements will not be prevented or detected on a timely basis. Based on the results of management’s assessment and evaluation of our internal controls, our principal executive officer and principal financial officer concluded that our internal control over financial reporting was not effective as of December 31, 20192021 due to the material weaknessweaknesses described below.

As of December 31, 2019,2021, we have identified the following material weaknesses:

Such internal control over financial reporting has not been effective since approximately December 31, 2016.

As a result, our management also concluded that our disclosure controls and procedures were not effective.aseffective as of December 31, 20192021, such that the information relating to us required to be disclosed in the reports we file with the SEC (a) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (b) is accumulated and communicated to our management to allow timely decisions regarding required disclosures and such disclosure controls and procedures have not been deemed effective since approximately December 31, 2016.

If we doA material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not successfullybe prevented or detected on a timely basis. A control deficiency exists when the design or operation of a control does not allow management or employees, in the normal course of performing their assigned functions, to prevent or detect misstatements on a timely basis.

Maintaining effective disclosure controls and procedures and effective internal control over financial reporting are necessary for us to produce reliable financial statements and the Company is committed to remediating its material weaknesses in such controls as promptly as possible. However, there can be no assurance as to when these material weaknesses will be remediated or that additional material weaknesses will not arise in the future. Any failure to remediate the material weaknesses, described above, or if otherthe development of new material weaknesses or other deficiencies arise in the future, we may be unable to accurately report our internal control over financial results on a timely basis or prevent fraud, which could cause our reported financial results to be materially misstated and require restatement whichreporting, could result in material misstatements in our financial statements and cause us to fail to meet our reporting and financial obligations, which in turn could have a material adverse effect on our financial condition and the loss of investor confidence, delisting or cause the markettrading price of our common stock, and/or result in litigation against us or our management. In addition, even if we are successful in strengthening our controls and procedures, those controls and procedures may not be adequate to decline.prevent or identify irregularities or facilitate the fair presentation of our financial statements or our periodic reports filed with the SEC.

There are inherent limitations in all control systems and misstatements due to error or fraud that may occur and not be detected.

The ongoing internal control provisions of Section 404 of the Sarbanes-Oxley Act of 2002 require us to identify material weaknesses in internal control over financial reporting, which is a process to provide reasonable assurance regarding the reliability of financial reporting for external purposes in accordance with GAAP. Our management does not expect that our internal controls and disclosure controls, even once all material weaknesses and control deficiencies are remediated, will prevent all errors 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, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud in our company 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 errors or mistakes. Further, controls can be circumvented by individual acts of some persons, by collusion of two or more persons, or by management override of the controls. The design of any system of controls is also 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 our stated goals under all potential future conditions. Over time, a control may be inadequate because of changes in conditions, such as growth of the Company or increased transaction volume, or the degree of compliance with the policies or procedures may deteriorate. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may and not be detected.

Pending litigation and other actions that may be threatened or taken against us could severely limit our liquidity.

We are currently involved in litigation with APEG II against us and our former Chief Executive Officer, as described inItem 1. Business—Litigation and Liquidity—APEG II Litigation. As of March 20, 2020, APEG II holds approximately 41% of our outstanding common stock and was our secured lender prior to the maturity on July 30, 2019 of our credit facility with APEG II. The costs associated with the pending litigation and other claims pending or threatened against us have been a significant use of our existing cash, and we have expended over $1.3 million in legal fees to date with respect to the pending actions. While we have historically funded all litigation costs out of operating cash flow, continued excessive legal fees associated with litigation could impair our liquidity profile and ability to fund significant drilling operations and participate in potential acquisitions in the future.

Non-consent provisions could result in penalties and loss of revenues from wells.

Our industry partners may elect to engage in drilling activities that we are unwilling or unable to participate in during 2020 and thereafter. Our exploration and development agreements contain customary industry non-consent provisions. Pursuant to these provisions, if a well is proposed to be drilled or completed but a working interest owner elects not to participate, the resulting revenues (which otherwise would go to the non-participant) flow to the participants until the participating parties receive from 150% to 300% of the capital they provided to cover the non-participant’s share. In order to be in position to avoid non-consent penalties and to make opportunistic investments in new assets, we will continue to evaluate various options to obtain additional capital, including debt financing, sales of one or more producing or non-producing oil and natural gas assets and the issuance of shares of our common stock.

Unanticipated costs could require new capital that may not be available.

The oil and natural gas business holds the opportunity for significant returns on investment, but achievement of such returns is subject to high risk. For example, initial results from one or more of the oil and natural gas programs could be marginal but warrant investing in more wells. Dry holes, over-budget exploration costs, low commodity prices, or any combination of these or other adverse factors, could result in production revenues falling below projections, thus adversely impacting cash expected to be available for a continued work program, and a reduction in cash available for investment in other programs. These types of events could require a reassessment of priorities and therefore potential re-allocations of existing capital and could also mandate obtaining new capital. There can be no assurance that we will be able to complete any financing transaction on acceptable terms.

Our ability to use net operating loss carryforwards and realizedrealize built in losses to offset future taxable income for U.S. federal income tax purposes is subject to limitation.

In general, under Section 382 of the Internal Revenue Code of 1986, as amended, a corporation that undergoes an “ownership change” is subject to limitations on its ability to utilize its pre-change net operating losses (“NOLs”) and realized built in losses (“RBILS”) to offset future taxable income. In general, an ownership change occurs if the aggregate stock ownership of certain stockholders (generally 5% stockholders, applying certain look-through rules) increases by more than 50 percentage points over such stockholders’ lowest percentage ownership during the testing period (generally three years).

On December 27, 2017, we paid down debt under our credit facility with APEG II with shares of our common stock, which represented a 49.3% ownership change in the Company. In addition, on January 5, 2022, we issued 19,905,736 shares of our common stock for the acquisition of assets, representing an 81.0% ownership change in the Company. As a result of these transactions, our ability to use these NOLs and RBILS were significantly reduced in 2018 and 2019.reduced.

Competition may limit our opportunities in the oil and natural gas business.

Risks Related to Governmental Regulations

The oil and natural gas business is very competitive. We compete with many public and private exploration and development companies in finding investment opportunities. We also compete with oil and natural gas operators in acquiring acreage positions. Our principal competitors are small to mid-size companies with in-house petroleum exploration and drilling expertise. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. They also may be willing and able to pay more for oil and natural gas properties than our financial resources permit, and may be able to define, evaluate, bid for and purchase a greater number of properties. In addition, there is substantial competition in the oil and natural gas industry for investment capital, and we may not be able to compete successfully in raising additional capital if needed.

Successful exploitation of the Buda formation, the Williston Basin (Bakken and Three Forks shales) and the Eagle Ford shale is subject to risks related to horizontal drilling and completion techniques.

Operations in the Buda formation and the Bakken, Three Forks and Eagle Ford shales in many cases involve utilizing the latest drilling and completion techniques in an effort to generate the highest possible cumulative recoveries and therefore generate the highest possible returns. Risks that are encountered while drilling include, but are not limited to, landing the well bore in the desired drilling zone, staying in the zone while drilling horizontally through the shale formation, running casing the entire length of the well bore (as applicable to the formation) and being able to run tools and other equipment consistently through the horizontal well bore.

For wells that are hydraulically fractured, completion risks include, but are not limited to, being able to fracture stimulate the planned number of fracture stimulation stages, and successfully cleaning out the well bore after completion of the final fracture stimulation stage. Ultimately, the success of these latest drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficient period of time.

Costs for any individual well will vary due to a variety of factors. These wells are significantly more expensive than a typical onshore shallow conventional well. Accordingly, unsuccessful exploration or development activity affecting even a small number of wells could have a significant impact on our results of operations. Costs other than drilling and completion costs can also be significant for Williston Basin, Eagle Ford and other wells.

If our access to oil and natural gas markets is restricted, it could negatively impact our production and revenues. Securing access to takeaway capacity may be particularly difficult in less developed areas of the Williston Basin.

Market conditions or limited availability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and other midstream facilities. The ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, rail transportation and processing facilities owned and operated by third parties. In particular, access to adequate gathering systems or pipeline or rail takeaway capacity is limited in the Williston Basin. In order to secure takeaway capacity and related services, we or our operating partners may be forced to enter into arrangements that are not as favorable to operators as those in other areas.

If we are unable to replace reserves, we will not be able to sustain production.

Our future operations depend on our ability to find, develop, and acquire crude oil, natural gas, and NGL reserves that are economically producible. Our properties produce crude oil, natural gas, and NGLs at a declining rate over time. In order to maintain current production rates, we must locate and develop or acquire new crude oil, natural gas, and NGL reserves to replace those being depleted by production. Without successful drilling or acquisition activities, our reserves and production will decline over time. In addition, competition for crude oil and natural gas properties is intense, and many of our competitors have financial, technical, human, and other resources necessary to evaluate and integrate acquisitions that are substantially greater than those available to us.

As part of our growth strategy, we intend to make acquisitions. However, suitable acquisition candidates may not be available on terms and conditions we find acceptable, and acquisitions pose substantial risks to our business, financial condition and results of operations. In pursuing acquisitions, we compete with other companies, many of which have greater financial and other resources than we do. In the event we do complete an acquisition, its successful impact on our business will depend on a number of factors, many of which are beyond our control. These factors include the purchase price for the acquisition, future crude oil, natural gas, and NGL prices, the ability to reasonably estimate or assess the recoverable volumes of reserves, rates of future production and future net revenues attainable from reserves, future operating and capital costs, results of future exploration, exploitation, and development activities on the acquired properties, and future abandonment and possible future environmental or other liabilities. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves, actual future production rates, and associated costs and potential liabilities with respect to prospective acquisition targets. Actual results may vary substantially from those assumed in the estimates. A customary review of subject properties will not necessarily reveal all existing or potential problems.

Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties if they have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such transactions may be limited. If we are unable to integrate acquisitions successfully and realize anticipated economic, operational and other benefits in a timely manner, substantial costs and delays or other operational, technical or financial problems could result.

Integrating acquired businesses and properties involves a number of special risks. These risks include the possibility that management may be distracted from regular business concerns by the need to integrate operations and systems and that unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results and may cause us to not be able to realize any or all of the anticipated benefits of the acquisitions.

Lower oil and natural gas prices may cause us to record ceiling test write-downs.

We use the full cost method of accounting to account for our oil and natural gas investments. Accordingly, we capitalize the cost to acquire, explore for and develop these properties. Under full cost accounting rules, the net capitalized cost of oil and natural gas properties may not exceed a “ceiling limit” that is based upon the present value of estimated future net revenues from proved reserves, discounted at 10%, plus the lower of the cost or fair market value of unproved properties. If net capitalized costs exceed the ceiling limit, we must charge the amount of the excess to earnings (a charge referred to as a “ceiling test write-down”). The risk of a ceiling test write-down increases when oil and natural gas prices are depressed, if we have substantial downward revisions in estimated proved reserves or if we drill unproductive wells.

Under the full cost method, all costs associated with the acquisition, exploration and development of oil and natural gas properties are capitalized and accumulated in a country-wide cost center. This includes any internal costs that are directly related to development and exploration activities, but does not include any costs related to production, general corporate overhead or similar activities. Proceeds received from disposals are credited against accumulated cost, except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized. The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production method, based on proved oil and natural gas reserves. Excluded from amounts subject to depreciation, depletion and amortization are costs associated with unevaluated properties.

Under the full cost method, net capitalized costs are limited to the lower of (a) unamortized cost reduced by the related net deferred tax liability and asset retirement obligations, and (b) the cost center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenue, discounted at 10% per annum, from proved reserves, based on unescalated costs, adjusted for contract provisions, any financial derivatives qualifying as accounting hedges and asset retirement obligations, and unescalated oil and natural gas prices during the period, (ii) the cost of properties not being amortized, and (iii) the lower of cost or market value of unproved properties included in the cost being amortized, less (iv) income tax effects related to tax assets directly attributable to the natural gas and crude oil properties. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds the cost center ceiling limitation, a non-cash impairment charge is required in the period in which the impairment occurs.

We perform a quarterly ceiling test for our only oil and natural gas cost center, which is the United States. During 2019 and 2018, our capitalized costs for oil and natural gas properties did not exceed the ceiling and, therefore, we did not record an aggregate ceiling test write-down. The ceiling test incorporates assumptions regarding pricing and discount rates over which we have no influence in the determination of present value. In arriving at the ceiling test for the year ended December 31, 2019, we used an average price applicable to our properties of $55.69 per barrel for oil and $2.58 per Mcfe for natural gas, based on average prices per barrel of oil and per Mcfe of natural gas at the first day of each month of the 12-month period prior to the end of the reporting period, to compute the future cash flows of each of the producing properties at that date.

As of March 20, 2020, the WTI spot price for crude oil was $23.64 and the 12-month strip price was $28.44. To determine the extent of these price reductions on the realizability of the Company’s oil and gas properties, the Company reran the year end reserves using 50% of the average crude price used in the original ceiling test calculation, or $27.85, as further adjusted for differentials, and determined that by using that price the Company would have incurred a ceiling test write-down of approximately $1.7 million.

Capitalized costs associated with unevaluated properties include exploratory wells in progress, costs for seismic analysis of exploratory drilling locations, and leasehold costs related to unproved properties. Unevaluated properties not subject to depreciation, depletion and amortization amounted to an aggregate of approximately $3.7 million as of December 31, 2019. These costs will be transferred to evaluated properties to the extent that we subsequently determine the properties are impaired or if proved reserves are established.

We do not serve as the operator for most of our oil and natural gas properties. Many of our joint operating agreements contain provisions that may be subject to legal interpretation, including allocation of non-consent interests, complex payout calculations that impact the timing of reversionary interests, and the impact of joint interest audits.

Substantially all of our oil and natural gas interests are subject to joint operating and similar agreements. Some of these agreements include payment provisions that are complex and subject to different interpretations and/or can be erroneously applied in particular situations.

Joint interest audits are a normal process in our business to ensure that operators adhere to standard industry practices in the billing of costs and expenses related to our oil and natural gas properties. However, the ultimate resolution of joint interest audits can extend over a long period of time in which we attempt to recover excessive amounts charged by the operator. Joint interest audits result in incremental costs for the audit services and we can incur substantial amounts of legal fees to resolve disputes with the operators of our properties.

We do not operate most of our drilling locations. Therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of these non-operated assets.

We do not currently operate any of the prospects we hold with industry partners. As a non-operator, our ability to exercise influence over the operations of the drilling programs is limited. In the usual case in the oil and natural gas industry, new work is proposed by the operator and often is approved by most of the non-operating parties. If the work is approved by the holders of a majority of the working interests, but we disagree with the proposal and do not (or are unable to) participate, we will forfeit our share of revenues from the well until the participants receive 150% to 300% of their investment. In some cases, we could lose all of our interest in the well. We would avoid a penalty of this kind only if a majority of the working interest owners agree with us and the proposal does not proceed.

The success and timing of our drilling and development activities on properties operated by others depend upon a number of factors outside of our control, including:

The fact that our industry partners serve as operator makes it more difficult for us to predict future production, cash flows and liquidity needs. Our ability to grow our production and reserves depends on decisions by our partners to drill wells in which we have an interest, and they may elect to reduce or suspend the drilling of those wells.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or the relevant underlying assumptions will materially affect the quantity and present value of our reserves.

Oil and natural gas reserve reports are prepared by independent consultants to provide estimates of the quantities of hydrocarbons that can be economically recovered from proved properties, utilizing commodity prices for a trailing 12-month period and taking into account expected capital, operating and other expenditures. These reports also provide estimates of the future net present value of the reserves, which we use for internal planning purposes and for testing the carrying value of the properties on our balance sheet.

The reserve data included in this report represent estimates only. Estimating quantities of, and future cash flows from, proved oil and natural gas reserves is a complex process and not an exact science. It requires interpretations of available technical data and various estimates, including estimates based upon assumptions relating to economic factors, such as future production costs; ad valorem, severance and excise taxes; availability of capital; estimates of required capital expenditures, workover and remedial costs; and the assumed effect of governmental regulation. The assumptions underlying our estimates of our proved reserves could prove to be inaccurate, and any significant inaccuracy could materially affect, among other things, future estimates of the reserves, the economically recoverable quantities of oil and natural gas attributable to the properties, the classifications of reserves based on risk of recovery, and estimates of our future net cash flows.

At December 31, 2019, all of our estimated proved reserves were producing. Estimation of proved undeveloped reserves and proved developed non-producing reserves is almost always based on analogy to existing wells, volumetric analysis or probabilistic methods, in contrast to the performance data used to estimate producing reserves. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations.

You should not assume that the present values referred to in this report represent the current market value of our estimated oil and natural gas reserves. The timing and success of the production and the expenses related to the development of oil and natural gas properties, each of which is subject to numerous risks and uncertainties, will affect the timing and amount of actual future net cash flows from our proved reserves and their present value. In addition, our PV-10 and standardized measure estimates are based on costs as of the date of the estimates and assume fixed commodity prices. Actual future prices and costs may be materially higher or lower than the prices and costs used in the estimate.

Further, the use of a 10% discount factor to calculate PV-10 and standardized measure values may not necessarily represent the most appropriate discount factor given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

The use of derivative arrangements in oil and natural gas production could result in financial losses or reduce income.

From time to time, we use derivative instruments, typically fixed-rate swaps and costless collars, to manage price risk underlying our oil and natural gas production. The fair value of our derivative instruments is marked to market at the end of each quarter and the resulting unrealized gains or losses due to changes in the fair value of our derivative instruments is recognized in current earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for the relevant period. If the actual amount of production is higher than we estimated, we will have greater commodity price exposure than we intended. If the actual amount of production is lower than the notional amount that is subject to our derivative instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows.

Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

In addition, depending on the type of derivative arrangements we enter into, the agreements could limit the benefit we would receive from increases in oil prices. It cannot be assumed that the hedging transactions we have entered into, or will enter into, will adequately protect us from fluctuations in commodity prices.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) provides for statutory and regulatory requirements for derivative transactions, including crude oil and natural gas derivative transactions. Among other things, the Dodd-Frank Act provides for the creation of position limits for certain derivatives transaction, as well as requiring certain transactions to be cleared on exchanges for which cash collateral will be required. The Dodd-Frank Act requires the Commodities Futures and Trading Commission (the “CFTC”), the SEC and other regulators to promulgate rules and regulations implementing the Dodd-Frank Act.

The CFTC has finalized other regulations implementing the Dodd-Frank Act’s provisions regarding trade reporting, margin, clearing and trade execution; however, some regulations remain to be finalized and it is not possible at this time to predict when the CFTC will adopt final rules. For example, the CFTC has re-proposed regulations setting position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions are expected to be made exempt from these limits. Also, it is possible that under recently adopted margin rules, some registered swap dealers may require us to post initial and variation margins in connection with certain swaps not subject to central clearing.

The Dodd-Frank Act and any additional implementing regulations could significantly increase the cost of some commodity derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of some commodity derivative contracts, limit our ability to trade some derivatives to hedge risks, reduce the availability of some derivatives to protect against risks we encounter and reduce our ability to monetize or restructure our existing commodity derivative contracts. If we reduce our use of derivatives as a consequence, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. If the implementing regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could adversely affect our business, financial condition and results of operations.

Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In the highly competitive market for acreage, failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, the loss of our lease and prospective drilling opportunities.

Unless production is established within the spacing units covering the undeveloped acres on which some of our potential drilling locations are identified, the leases for such acreage will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. The risk that our leases may expire will generally increase when commodity prices fall, as lower prices may cause our operating partners to reduce the number of wells they drill. In addition, on certain portions of our acreage, third-party leases could become immediately effective if our leases expire. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business.

Our producing properties are primarily located in the Williston Basin and South Texas, making us vulnerable to risks associated with having operations concentrated in these geographic areas.

Because our operations are geographically concentrated in the Williston Basin and South Texas, the success and profitability of our operations may be disproportionally exposed to the effect of regional events. These include, among others, regulatory issues, natural disasters and fluctuations in the prices of crude oil and natural gas produced from wells in the region and other regional supply and demand factors, including gathering, pipeline and other transportation capacity constraints, available rigs, equipment, oil field services, supplies, labor and infrastructure capacity. Any of these events has the potential to cause producing wells to be shut-in, delay operations and growth plans, decrease cash flows, increase operating and capital costs and prevent development of lease inventory before expiration. In addition, our operations in the Williston Basin may be adversely affected by seasonal weather and lease stipulations designed to protect wildlife, which can intensify competition for services, infrastructure and equipment during months when drilling is possible and may result in periodic shortages. Any of these risks could have a material adverse effect on our financial condition and results of operations.

Insurance may be insufficient to cover future liabilities.

Our business is currently focused on oil and natural gas exploration and development and we also have potential exposure to general liability and property damage associated with the ownership of other corporate assets. In the past, we relied primarily on the operators of our oil and natural gas properties to obtain and maintain liability insurance for our working interest in our oil and natural gas properties. In some cases, we may continue to rely on those operators’ insurance coverage policies depending on the coverage. Since 2011 we have obtained our own insurance policies for our oil and natural gas operations that are broader in scope and coverage and are in our control. We also maintain insurance policies for liabilities associated with and damage to general corporate assets.

We also have separate policies for environmental exposures related to our prior ownership of the water treatment plant operations related to our discontinued mining operations. These policies provide coverage for remediation events adversely impacting the environment. See“Insurance” in“Item 1 – Business”.

We would be liable for claims in excess of coverage and for any deductible provided for in the relevant policy. If uncovered liabilities are substantial, payment could adversely impact the Company’s cash on hand, resulting in possible curtailment of operations. Moreover, some liabilities are not insurable at a reasonable cost or at all.

Oil and natural gas operations are subject to environmental, legislative and regulatory initiatives that can materially adversely affect the timing and cost of operations and the demand for crude oil, natural gas, and NGLs.

Our operations are subject to stringent and complex federal, state and local laws and regulations relating to the protection of human health and safety, the environment and natural resources. These laws and regulations can restrict or impact our business activities in many ways including, but not limited to the following:

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial or restoration obligations, and the issuance of orders enjoining future operations or imposing additional compliance requirements. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, local restrictions, such as state or local moratoria, city ordinances, zoning laws and traffic regulations, may restrict or prohibit the execution of operational plans. In addition, third parties, such as neighboring landowners, may file claims alleging property damage, nuisance or personal injury arising from our operations or from the release of hazardous substances, hydrocarbons or other waste products into the environment.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. We monitor developments at the federal, state and local levels to keep informed of actions pertaining to future regulatory requirements that might be imposed in order to mitigate the costs of compliance with any such requirements. We also monitor industry groups that help formulate recommendations for addressing existing or future regulations and that share best practices and lessons learned in relation to pollution prevention and incident investigations.

See “Environmental Laws and Regulations” in Item 1 – Business in this Form 10-K for a discussion of the major environmental, health and safety laws and regulations that relate to our business. We believe, but cannot be certain, that we are in material compliance with these laws and regulations. We cannot reasonably predict what applicable laws, regulations or guidance may eventually be adopted with respect to our operations or the ultimate cost to comply with such requirements.

We are dependent upon information technology systems, which are subjectProposed changes to disruption, damage, failure and risks associated with implementation and integration.

We are dependent upon information technology systems in the conduct of our operations. Our information technology systems are subject to disruption, damage or failure from a variety of sources, including, without limitation, computer viruses, security breaches, cyberattacks, natural disasters and defects in design. Cybersecurity incidents, in particular, are evolving and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and other electronic security breaches that could lead to disruptions in systems, unauthorized release of confidential or otherwise protected information and the corruption of data. Various measures have been implemented to manage our risks related to information technology systems and network disruptions. However, given the unpredictability of the timing, nature and scope of information technology disruptions, we could potentially be subject to operational delays, the compromising of confidential or otherwise protected information, destruction or corruption of data, security breaches, other manipulation or improper use of our systems and networks or financial losses from remedial actions, any of whichU.S. tax laws, if adopted, could have a materialan adverse effect on our cash flows, competitive position,business, financial condition, or results of operations.operations, and cash flows.

Permitting requirements could delay our abilityFrom time to start or continue our operations.

Oil and natural gas projectstime, legislative proposals are subject to extensive permitting requirements. Failure to timely obtain required permits to start operations at a project could cause delay and/ormade that would, if enacted, result in the failureelimination of the project resulting in a potential write-offimmediate deduction for intangible drilling and development costs, the elimination of the investments made.deduction from income for domestic production activities relating to oil and gas exploration and development, the repeal of the percentage depletion allowance for oil and gas properties, and an extension of the amortization period for certain geological and geophysical expenditures. Such changes, if adopted, or other similar changes that reduce or eliminate deductions currently available with respect to oil and gas exploration and development, could adversely affect our business, financial condition, results of operations, and cash flows.

Our ability to produce crude oil, natural gas, and associated liquids economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations and/or completions or are unable to dispose of or recycle the water we use at a reasonable cost and in accordance with applicable environmental rules.

The hydraulic fracturing process on which we and others in our industry depend to complete wells that will produce commercial quantities of crude oil, natural gas, and NGLs requires the use and disposal or recycling of significant quantities of water. Our inability to secure sufficient amounts of water, or to dispose of, or recycle the water used in our operations, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of wastes, including, but not limited to, produced water, drilling fluids, and other wastes associated with the exploration, development, or production of crude oil, natural gas, and NGLs.

Compliance with environmental regulations and permit requirements governing the withdrawal, storage, and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions, or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial condition.

Risks Related to Our Credit Agreement

Seasonal weather conditionsOur obligations under the Credit Agreement are secured by a first priority security interest in substantially all of our assets.

Our obligations under the Credit Agreement are secured by a first priority security interest in substantially all of our assets. Additionally, substantially all of our subsidiaries agreed to guarantee our obligations under the Credit Agreement. As such, our creditor may enforce its security interests over our assets and/or our subsidiaries which secure the repayment of such obligations, take control of our assets and operations, force us to seek bankruptcy protection, or force us to curtail or abandon our current business plans and operations. If that were to happen, any investment in the Company could become worthless.

Our failure to comply with the covenants in the documents governing our existing and future indebtedness could materially adversely affect our abilityfinancial condition and liquidity.

In connection with the Credit Agreement, we agreed to conduct drilling activitiescomply with certain affirmative and negative covenants and agreed to meet certain financial covenants. We are required to make certain mandatory repayments under the Credit Agreement, in the event the borrowing base decreases below the aggregate amount of loans made by the lenders and/or if as of the last business day of any calendar month, certain required debt ratios required under the Credit Agreement are not met, there are outstanding amounts owed to the lenders, and the Company has consolidated cash on hand in excess of $5 million, and in some cases we are also required to pay cash to the agent to be held as collateral. The Credit Agreement contains customary indemnification requirements, representations and warranties and customary affirmative and negative covenants applicable to the Loan Parties and their subsidiaries, including, among other things, restrictions on indebtedness, liens, investments, mergers, dispositions, prepayment of other indebtedness, transactions with affiliates, and dividends and other distributions. In addition, the Credit Agreement contains financial covenants, tested quarterly, that limit the Company’s ratio of total debt to EBITDAX (as defined in the Credit Agreement) to 3:1 and require its ratio of consolidated current assets to consolidated current liabilities (as each is described in the Credit Agreement) to remain at 1:1 or higher. The Credit Agreement also requires us to hedge certain oil and gas volumes, based on our utilization of the areas where we operate.borrowing base.

Oil

Events of default under the Credit Agreement include: the failure by the Company to timely make payments due under the Credit Agreement; material misrepresentations or misstatements in any representation or warranty of any of the Loan Parties; failure by the Company or any of its subsidiaries to comply with their covenants under the Credit Agreement and natural gas operationsother related agreements, subject in certain cases to rights to cure; certain defaults under other indebtedness of the Loan Parties; insolvency or bankruptcy-related events with respect to the Company or any of its subsidiaries; certain unsatisfied judgments against the Company or any of its subsidiaries in an amount in excess of $500,000; if the Credit Agreement or certain related agreements or security interests created by them cease to be in full force and effect; certain ERISA-related events reasonably expected to have a material adverse effect on the Company and its subsidiaries; and the occurrence of a change in control, each as discussed in greater detail in the Williston BasinCredit Agreement, and the Gulf Coast can be adversely affected by seasonal weather conditions. In the Williston Basin, drilling and other oil and natural gas activities sometimes cannot be conducted as effectively during the winter months, and this can materially increase our operating and capital costs. Gulf Coast operations are also subject to certain cure rights. If any event of default occurs and is continuing under the riskCredit Agreement, the lenders may terminate their commitments, and may require the Company and its subsidiaries to repay outstanding debt and/or to provide a cash deposit as additional security for outstanding letters of adverse weather events, including hurricanes.credit.

ShortagesA breach of equipment, services and qualified personnelany of the covenants of the Credit Agreement or any future agreements, if uncured or unwaived, could reducelead to an event of default under any such document, which in some circumstances could give our cash flow and adversely affect resultscreditors the right to demand that we accelerate repayment of operations.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers andamounts due and/or enforce their security interests over substantially all of our assets. This would likely in turn trigger cross-acceleration or cross-default rights in other professionalsdocuments governing our indebtedness. Therefore, in the oilevent of any such breach, we may need to seek covenant waivers or amendments from our creditors or seek alternative or additional sources of financing, and natural gas industry can fluctuate significantly, often in correlation with oilwe may not be able to obtain any such waivers or amendments or alternative or additional financing on acceptable terms, if at all. In addition, any covenant breach or event of default could harm our credit rating and natural gas prices and activity levels in new regions, causing periodic shortages. These problems can be particularly severe in certain regions such as the Williston Basin and Texas. During periods of high oil and natural gas prices, the demand for drilling rigs and equipment tends to increase along with increased activity levels, and this may result in shortages of equipment. Higher oil and natural gas prices generally stimulate increased demand for equipment and services and subsequently often result in increased prices for drilling rigs, crews and associated supplies, oilfield equipment and services, and personnel in exploration, production and midstream operations. These types of shortages and subsequent price increases could significantly decrease our profit margin, cash flow and operating results and/or restrict or delay our ability to drill those wellsobtain additional financing on acceptable terms. The occurrence of any of these events could have a material adverse effect on our financial condition and conduct those activities that we currentlyliquidity and/or cause our lenders to enforce their security interests which could ultimately result in the foreclosure of our assets, which would have planneda material adverse effect on our operations and budgeted, causing usthe value of our securities.

The covenants in our credit and loan agreements restrict our ability to miss our forecasts and projections.

We depend on key personnel.

Our management team has experience in dealing with the acquisition and financing of oil and natural gas properties. We rely extensively on third-party consultants for legal, engineering, geophysical and geological advice in oil and natural gas matters. The loss of key personnel could adversely impactoperate our business as finding replacements could be difficult asand might lead to a default under our Credit Agreement.

The Credit Agreement contains customary indemnification requirements, representations and warranties and customary affirmative and negative covenants applicable to the Loan Parties and their subsidiaries, including, among other things, restrictions on indebtedness, liens, investments, mergers, dispositions, prepayment of other indebtedness, transactions with affiliates, and dividends and other distributions. In addition, the Credit Agreement contains financial covenants, tested quarterly, that limit the Company’s ratio of total debt to EBITDAX (as defined in the Credit Agreement) to 3:1 and require its ratio of consolidated current assets to consolidated current liabilities (as each is described in the Credit Agreement) to remain at 1:1 or higher.

As a result of competitionthese covenants and limitations, we may not be able to respond to changes in business and economic conditions and to obtain additional financing, if needed, and we may be prevented from engaging in transactions that might otherwise be beneficial to us. Our Credit Agreement requires, and our future credit facilities and loan agreements may require, us to maintain certain financial ratios and satisfy certain other financial condition tests. Our ability to meet these financial ratios and tests can be affected by events beyond our control, and we may not be able to meet those tests. The breach of any of these covenants could result in a default under our Credit Agreement or future credit facilities. Upon the occurrence of an event of default, the lenders could elect to declare all amounts outstanding under such Credit Agreement, including accrued interest or other obligations, to be immediately due and payable. If amounts outstanding under such Credit Agreement were to be accelerated, our assets might not be sufficient to repay in full that indebtedness and our other indebtedness.

A prolonged period of weak, or a significant decrease in, industry activity and overall markets, due to COVID-19 or otherwise, may make it difficult to comply with our covenants and the other restrictions in the agreements governing our debt and current global and market conditions have increased the potential for experienced personnel.that difficulty.

Risks Related to Our Stock

We currently have issuedan unlimited number of shares of Series A Preferred Stock with rights superiorcommon stock authorized and there may be future issuances of sales of our common stock, which could adversely affect the market price of our common stock and dilute a shareholder’s ownership of common stock.

The exercise of any options granted to thoseexecutive officers and other employees under our equity compensation plans could have an adverse effect on the market price of the shares of our common stock.

Our articles Additionally, we are not restricted from issuing additional shares of incorporation authorizecommon stock, including any securities that are convertible into or exchangeable for, or that represent the right to receive shares of common stock, and currently have an unlimited number of authorized shares of common stock, provided that we are subject to the requirements of The NASDAQ Capital Market (“NASDAQ”)(which generally requires shareholder approval for any transactions which would result in the issuance of up to 100,000more than 20% of our then outstanding shares of common stock or voting rights representing over 20% of our then outstanding shares of stock, subject to certain exceptions, including sales in a public offering and/or sales which are undertaken at or above the lower of the closing price immediately preceding the signing of the binding agreement or the average closing price for the five trading days preceding the signing of the binding agreement). Issuances of a substantial number of shares of our common stock and/or sales of a substantial number of shares of our common stock in the public market or the perception that such issuances or sales might occur could materially adversely affect the market price of the shares of our common stock. Because our decision to issue securities in the future, including in connection with any future offering, will depend on market conditions and other factors beyond our control, we cannot predict or estimate the amount, timing, or nature of our future issuances or offerings. Accordingly, our stockholders bear the risk that our future issuances and/or offerings will reduce the market price of our common stock and dilute their stock holdings in us.

We have established preferred stock $0.01 par value. Shares of preferred stock maywhich can be issued with such dividend, liquidation, voting and conversion features as may be determineddesignated by the Board of Directors without shareholder approval. Pursuant to this authority, in February 2016 we approved the designation

We have 100,000 shares of preferred stock authorized, which includes 50,000 shares of Series A Convertible Preferred Stock (“Series A Preferred”) in connection with the disposition(none of our mining segment.

The Series A Preferred accrues dividends at a rate of 12.25% per annum of the Adjusted Liquidation Preference. Such dividendswhich are not payable in cash but are accruedoutstanding) and compounded quarterly in arrears. The “Adjusted Liquidation Preference” is initially $40 per share50,000 shares of Series A Preferred for an aggregateP preferred stock (none of $2.0 million,which are outstanding). Shares of preferred stock may be designated and issued by our Board of Directors without shareholder approval with increases each quartervoting powers, and such preferences and relative, participating, optional, or other special rights and powers as determined by our Board of Directors, which may be greater than the accrued quarterly dividend. The Series A Preferred is senior to other classes or series of shares of the Company with respect to dividend rights and rights upon liquidation. No dividend or distribution will be declared or paid on our common stock (i) unless approvedcurrently outstanding. As a result, shares of preferred stock may be issued by our Board of Directors which cause the holders to have voting power over our shares or provide the holders of Series A Preferred and (ii) unless and until a like dividend has been declared and paid on the Series A Preferred on an as-converted basis.

Atpreferred stock the optionright to convert the shares of the holder, each share of Series A Preferred may initially be convertedpreferred stock they hold into 1.33 shares of our common stock, (the “Conversion Rate”) for an aggregate of 66,667 shares. This Conversion Rate reflects the effect of the reverse stock split described in this“Item 1A. Risk Factors” (the “Reverse Stock Split”). The Conversion Rate is subjectwhich may cause substantial dilution to anti-dilution adjustments for stock splits, stock dividends and certain reorganization events and to price-based anti-dilution protections. Each share of Series A Preferred will be convertible into a number of shares ofour then common stock equalstockholders and/or have other rights and preferences (including, but not limited to the ratio of the initial conversion value to the conversion value as adjusted for accumulated dividends multiplied by the Conversion Rate. In no event will the aggregate number of shares of common stock issued upon conversion bevoting rights) greater than 79,334 shares after taking into account the effectthose of the Reverse Stock Split. The Series A Preferred will generally not vote with our common stock on an as-converted basis on matters put beforestockholders. Investors should keep in mind that the Board of Directors has the authority to issue additional shares of preferred stock, which could cause substantial dilution to our shareholders. The holders of the Series A Preferred have the right to require us to repurchase the Series A Preferredexisting stockholders or result in connection with a change of control. The dividend, liquidationBecause our Board of Directors is entitled to designate the powers and other rights provided to holderspreferences of the Series A Preferredpreferred stock without a vote of our stockholders, subject to NASDAQ rules and regulations, our stockholders will make it more difficult for holdershave no control over what designations and preferences our future preferred stock, if any, will have.

Certain of our directors beneficially own approximately 78.9% of our outstanding common stock, which gives them majority voting control over shareholder matters, and each are also party to realize valuea Nominating and Voting Agreement, which allows them to control who is appointed to the Board of Directors of the Company and their interests may be different from their investment.your interests; and as a result of such ownership, we are a “controlled company” under applicable Nasdaq Capital Market Rules.

OneJohn A. Weinzierl, Duane H. King and Joshua Batchelor, our Chairman, director and director, respectively, beneficially own an aggregate of our existing shareholders beneficially owns a significant portion20,185,736 shares of our common stock, and its interests may conflict with those of our other shareholders.

As of March 20, 2020, APEG II beneficially owns 581,927 shares (as adjusted for the Reverse Stock Split), orrepresenting approximately 41%,78.9% of our outstanding common stock.stock, including approximately 26.5%, 25.7% and 26.7% of our common stock beneficially owned by each of John A. Weinzierl, Duane H. King and Joshua Batchelor. As a result, APEG II is able to exercise significant influence oversuch, Messrs. Weinzierl, King and Batchelor can control the outcome of all matters requiring a shareholder approval,vote, including the election of directors, the adoption of amendments to our certificate of incorporation or amendment of provisions in our charterbylaws and bylaws, the approval of mergers and other significant corporate transactions. TheSubject to any fiduciary duties owed to the stockholders generally, while Messrs. Weinzierl’s, King’s and Batchelor’s interests of APEG II with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities, may conflictgenerally be aligned with the interests of our shareholders, in some instances Messrs. Weinzierl, King and Batchelor may have interests different than the rest of our shareholders. Messrs. Weinzierl’s, King’s and Batchelor’s influence or control of our company as shareholders may have the effect of delaying or preventing a change of control of our company and may adversely affect the voting and other rights of other shareholders. See “Pending litigationBecause Messrs. Weinzierl, King and Batchelor control the shareholder vote, investors may find it difficult to replace Messrs. Weinzierl, King and Batchelor (and such persons as they may appoint from time to time) as members of our management and board of directors if they disagree with the way our business is being operated. Additionally, the interests of Messrs. Weinzierl, King and Batchelor may differ from the interests of the other shareholders and thus result in corporate decisions that are adverse to other shareholders.

Separately, each of the entities controlled by Messrs. Weinzierl, King and Batchelor entered into a Nominating and Voting Agreement with us in January 2022. Pursuant to the Nominating and Voting Agreement, each of the three entities party to the January 2022 purchase agreements (seller parties), which entities are controlled by Messrs. Weinzierl, King and Batchelor have the right to designate for nomination to the Board of Directors two nominees (for so long as such party holds at least 15% of the Company’s outstanding common stock) and one nominee (for so long as such party holds at least 5% of the Company’s common stock), for appointment at any shareholder meeting or via any consent to action without meeting of the stockholders of the Company. The Nominating and Voting Agreement also requires the Board of Directors to include such nominees in the slate of directors up for appointment at each meeting of stockholders where directors will be appointed, and take other actions to ensure that such persons are elected to the Board of Directors by the stockholders of the Company. If any party’s nominated person ceases for any reason to serve on the Board of Directors, such party is provided the right to appoint another person to the Board of Directors. At all times when the entity controlled by Mr. Weinzierl holds at least 5% of the Company’s outstanding common stock and its appointee is Mr. Weinzierl, each party is required to instruct its appointee on the Board of Directors to vote in favor of appointing Mr. Weinzierl as Chairman of the Board of Directors. During the term of the Nominating and Voting Agreement, each seller party agreed to vote all securities of the Company which they hold in any manner as may be threatened or taken against us could severely limited our liquidity”necessary to nominate and elect (and, if applicable, maintain in thisItem1A. Risk Factorsoffice) as a member of the Company’s Board of Directors, each of the seller nominated persons and further to not remove any seller nominated persons, subject to certain exceptions. The agreement continues in effect until the discussionearlier of this litigation inItem 1. Business—Litigation(a) the date mutually agreed by all the parties; and Liquidity—APEG II Litigation.

Future equity transactions and exercises(b) the date that no seller party owns at least 5% of the outstanding options or warrants could result in dilution.

From time to time, we have soldshares of common stock warrants, convertible preferredof the Company; subject to certain rights and obligations which survive termination. Once a seller party’s ownership drops below 5% of the Company’s outstanding common stock, it no longer has any right to nominate any person under the Nominating and convertible debt to investors in private placements and public offerings. Recently, we privately issued 59,498 sharesVoting Agreement, even if such seller party’s ownership increases above 5% of ourthe Company’s common stock in the New Horizon Acquisition. These transactions caused dilutionfuture. As a result of the above, each of Messrs. Weinzierl, King and Batchelor will control who serves on our Board of Directors and have the ability to existing shareholders. Also,appoint a majority of the persons on our Board of Directors.

Because of Messrs. Weinzierl’s, King’s and Batchelor’s ownership of the Company, as discussed above, we are a “controlled company” under the rules of the Nasdaq Capital Market. Under these rules, a company of which more than 50% of the voting power is held by an individual, a group or another company is a “controlled company” and, as such, can elect to be exempt from timecertain corporate governance requirements, including requirements that:

As a “controlled company,” we may elect to time,rely on some or all of these exemptions, provided that we issue optionshave to date not taken advantage of any of these exemptions and warrants to employees, directors and third parties as incentives, with exercise prices equal to the market price at the date of issuance. Vesting of restricted common stock and exercise of options and warrants would result in dilution to existing shareholders. Future issuances of equity securities, or securities convertible into equity securities, would also have a dilutive effect on existing shareholders. In addition, the perception that such issuances may occur could adversely affect the market price of our common stock.

We do not currently intend to declare dividends on our common stock.

Wetake advantage of any of these exemptions moving forward. Notwithstanding that, should the interests of Messrs. Weinzierl, King and Batchelor differ from those of other shareholders, the other shareholders may not have the same protections afforded to shareholders of companies that are subject to all of the Nasdaq Capital Market corporate governance standards. Even if we do not intend to declare dividends onavail ourselves of these exemptions, our status as a controlled company could make our common stock in the foreseeable future. Under the terms ofless attractive to some investors or otherwise harm our Series A Preferred, we are prohibited from paying dividends on our common stock without the approval of the holders of the Series A Preferred. Accordingly, our common shareholders must look solely to increases in the price of our common stock to realize a gain on their investment,price.

Our governing documents and this may not occur.

We could implementWyoming law includes various take-over defense mechanismsprovisions that could discourage some advantageous transactions.transactions.

Although our shareholder rights plan expired in 2011, certain provisions of our governing documents and applicable law could have anti-takeover effects. For example, weWe are subject to a number of provisions of the Wyoming Management Stability Act, an anti-takeover statute, and have a classified or “staggered” board. We could implement additional anti-takeover defenses in the future. These existing or future defenses could prevent or discourage a potential transaction in which shareholders would receive a takeover price in excess of then-current market values, even if a majority of the shareholders support such a transaction.

Our stock price has historically been and is likely willto continue to be, volatile.

Our stock is traded on The NASDAQ Capital Market under the Nasdaq Capital Market.symbol “USEG”. During the two years ended December 31, 2019,last 52 weeks, our common stock has traded as high as $17.60$13.92 per share and as low as $3.00$2.91 per share, as adjusted for the Reverse Stock Split.share. We expect our common stock will continue to be subject to wide fluctuations as a result of a variety of factors, including factors beyond our control. These factors include:

The stock market has recentlypreviously experienced significant price and volume fluctuations, and oil and natural gas prices have declined significantly.significantly in 2020, before more recent rebounding above pre-pandemic levels. These fluctuations have particularly affected the market prices of securities of oil and natural gas companies like ours.

We effectedOur Common Stock may be delisted from The Nasdaq Capital Market if we cannot satisfy Nasdaq’s continued listing requirements.

Among the conditions required for continued listing on The Nasdaq Capital Market, Nasdaq requires us to maintain at least $2.5 million in stockholders’ equity or $500,000 in net income over the prior two years or two of the prior three years, to have a reversemajority of independent directors, and to maintain a stock split whichprice over $1.00 per share. Our stockholders’ equity may not remain above Nasdaq’s $2.5 million minimum, we may not generate over $500,000 of yearly net income moving forward, we may not be able to maintain independent directors, and we may not be able to maintain a stock price over $1.00 per share. Delisting from The Nasdaq Capital Market could make trading our common stock more difficult for investors, potentially leading to declines in our share price and liquidity. Without a Nasdaq Capital Market listing, stockholders may have a difficult time getting a quote for the sale or purchase of our stock, the sale or purchase of our stock would likely be made more difficult and the trading volume and liquidity of our stock could decline. Delisting from The Nasdaq Capital Market could also result in negative publicity and could also make it more difficult for us to raise additional capital. The absence of such a listing may adversely impactaffect the market price of our common stock.

Effective January 6, 2020, we completed a reverse stock split of our outstanding common stock at a ratio of one-for-ten shares (the “Reverse Stock Split”). The effect of the Reverse Stock Split upon the future market priceacceptance of our common stock cannot be predictedas currency or the value accorded by other parties. Further, if we are delisted, we would also incur additional costs under state blue sky laws in connection with certainty. Accordingly, it is possible thatany sales of our securities. These requirements could severely limit the market price of our common stock could decline more than would occur in the absence of the Reverse Stock Split.

The Reverse Stock Split may decrease the liquidity of the shares of our common stock and the resulting market priceability of our stockholders to sell our common stock in the secondary market. If our common stock is delisted by Nasdaq, our common stock may be eligible to trade on an over-the-counter quotation system, such as the OTCQB market, where an investor may find it more difficult to sell our stock or obtain accurate quotations as to the market value of our common stock. In the event our common stock is delisted from The Nasdaq Capital Market, we may not attractbe able to list our common stock on another national securities exchange or satisfy the investing requirements of new investors, including institutional investors.obtain quotation on an over-the counter quotation system.

If we are delisted from The liquidity of theNasdaq Capital Market, your ability to sell your shares of our common stock maycould also be affected adverselylimited by the Reverse Stock Split givenpenny stock restrictions, which could further limit the reduced numbermarketability of shares outstanding following the Reverse Stock Split. Additionally, the Reverse Stock Split may increase the number of shareholders who own odd lots (less than 100 shares) ofyour shares.

If our common stock creatingis delisted, it could come within the definition of “penny stock” as defined in the Exchange Act and would then be covered by Rule 15g-9 of the Exchange Act. That Rule imposes additional sales practice requirements on broker-dealers who sell securities to persons other than established customers and accredited investors. For transactions covered by Rule 15g-9, the broker-dealer must make a special suitability determination for the purchaser and receive the purchaser’s written agreement to the transaction prior to the sale. Consequently, Rule 15g-9, if it were to become applicable, would affect the ability or willingness of broker-dealers to sell our securities, and accordingly would affect the ability of stockholders to sell their securities in the public market. These additional procedures could also limit our ability to raise additional capital in the future.

General Risk Factors

Because we are a small company, the requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes-Oxley Act and the Dodd-Frank Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company with listed equity securities, we must comply with the federal securities laws, rules and regulations, including certain corporate governance provisions of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”) and the Dodd-Frank Act, related rules and regulations of the SEC and NASDAQ, with which a private company is not required to comply. Complying with these laws, rules and regulations will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses, which we cannot estimate accurately at this time. Among other things, we must:

In addition, being a public company subject to these rules and regulations may require us to accept less director and officer liability insurance coverage than we desire or to incur substantial costs to obtain coverage. These factors could also make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our audit committee, and qualified executive officers.

Our business could be adversely affected by security threats, including cybersecurity threats.

We face various security threats, including cybersecurity threats to gain unauthorized access to our sensitive information or to render our information or systems unusable, and threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as gathering and processing facilities, refineries, rail facilities and pipelines. The potential for such shareholderssecurity threats subjects our operations to experience anincreased risks that could have a material adverse effect on our business, financial condition and results of operations. For example, unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruptions, or other disruptions to our operations.

Our implementation of various procedures and controls to monitor and mitigate such security threats and to increase security for our information, systems, facilities and infrastructure may result in the cost of selling their sharesincreased capital and greater difficulty effecting such sales.operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of, or damage to, sensitive information or facilities, infrastructure and systems essential to our business and operations, as well as data corruption, reputational damage, communication interruptions or other disruptions to our operations, which, in turn, could have a material adverse effect on our business, financial position and results of operations.

The threat and impact of terrorist attacks, cyber-attacks or similar hostilities may adversely impact our operations.

We cannot assess the Reverse stock Split will resultextent of either the threat or the potential impact of future terrorist attacks on the energy industry in general, and on us in particular, either in the short-term or in the long-term. Uncertainty surrounding such hostilities may affect our operations in unpredictable ways, including the possibility that infrastructure facilities, including pipelines and gathering systems, production facilities, processing plants and refineries, could be targets of, or indirect casualties of, an act of terror, a cyber-attack or electronic security breach, or an act of war.

We may have difficulty managing growth in our business, which could have a material adverse effect on our business, financial condition and results of operations and our ability to execute our business plan in a share price thattimely fashion.

Because of our small size, growth in accordance with our business plans, if achieved, will attract new investors,place a significant strain on our financial, technical, operational and management resources. As we expand our activities, including institutional investors,our planned increase in oil exploration, development and production, and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the inability to recruit and retain experienced managers, geoscientists, petroleum engineers and landmen could have a material adverse effect on our business, financial condition and results of operations and our ability to execute our business plan in a timely fashion.

Failure to adequately protect critical data and technology systems could materially affect our operations.

Information technology solution failures, network disruptions and breaches of data security could disrupt our operations by causing delays or cancellation of customer orders, impeding processing of transactions and reporting financial results, resulting in the unintentional disclosure of customer, employee or our information, or damage to our reputation. There can be no assurance that a system failure or data security breach will not have a material adverse effect on our financial condition, results of operations or cash flows.

If we complete acquisitions or enter into business combinations in the marketfuture, they may disrupt or have a negative impact on our business.

If we complete acquisitions or enter into business combinations in the future, funding permitting, we could have difficulty integrating the acquired companies’ assets, personnel and operations with our own. Additionally, acquisitions, mergers or business combinations we may enter into in the future could result in a change of control of the Company, and a change in the board of directors or officers of the Company. In addition, the key personnel of the acquired business may not be willing to work for us. We cannot predict the effect expansion may have on our core business. Regardless of whether we are successful in making an acquisition or completing a business combination, the negotiations could disrupt our ongoing business, distract our management and employees and increase our expenses. In addition to the risks described above, acquisitions and business combinations are accompanied by a number of inherent risks, including, without limitation, the following:

Our business could be severely impaired if and to the extent that we are unable to succeed in addressing any of these risks or other problems encountered in connection with an acquisition or business combination, many of which cannot be presently identified. These risks and problems could disrupt our ongoing business, distract our management and employees, increase our expenses and adversely affect our results of operations.

Any acquisition or business combination transaction we enter into in the future could cause substantial dilution to existing stockholders, result in one party having majority or significant control over the Company or result in a change in business focus of the Company.

If persons engage in short sales of our common stock, the price of our common stock may decline.

Selling short is a technique used by a stockholder to take advantage of an anticipated decline in the price of a security. In addition, holders of options and warrants will satisfysometimes sell short knowing they can, in effect, cover through the investing requirementsexercise of these investors. Consequently,an option or warrant, thus locking in a profit. A significant number of short sales or a large volume of other sales within a relatively short period of time can create downward pressure on the trading liquiditymarket price of our common stock may not necessarily improve as a result of the Reverse Stock Split.

If our common stock is delisted from the NASDAQ Capital Market, its liquidity and value could be reduced.

In order for us to maintain the listing of our sharessecurity. Further sales of common stock onissued upon exercise of future warrants or other convertible securities could cause even greater declines in the NASDAQ Capital Market, our common stock must maintain a minimum bid price of $1.00 as set forth in NASDAQ Marketplace Rule 5550(a)(2) (the “Minimum Price Requirement”). If the closing bid price of our common stock is below $1.00 for 30 consecutive trading days, thendue to the closing bid pricenumber of additional shares available in the market upon such exercise, which could encourage short sales that could further undermine the value of our common stock. Stockholders could, therefore, experience a decline in the values of their investment as a result of short sales of our common stock.

Stockholders may be diluted significantly through our efforts to obtain financing and satisfy obligations through the issuance of securities.

Wherever possible, our Board of Directors will attempt to use non-cash consideration to satisfy obligations. In many instances, we believe that the non-cash consideration will consist of shares of our common stock, must be $1.00preferred stock, or more for 10 consecutive trading days during a 180-day grace periodwarrants to regain compliance with the rule. Previously, we were not in compliance with the Minimum Price Requirement but regained compliance following the Reverse Stock Split. We cannot guarantee that we will be able to remain in compliance with the Minimum Price Requirement in the future or satisfy other continued listing requirements. Ifpurchase shares of our common stock is delisted from trading onstock. Our Board of Directors has authority, without action or vote of the stockholders,subject to the requirements of The NASDAQ Capital Market it(which generally require shareholder approval for any transactions which would result in the issuance of more than 20% of our then outstanding shares of common stock or voting rights representing over 20% of our then outstanding shares of stock, subject to certain exceptions, including sales in a public offering and/or sales which are undertaken at or above the lower of the closing price immediately preceding the signing of the binding agreement or the average closing price for the five trading days preceding the signing of the binding agreement), to issue all or part of the authorized but unissued shares of common stock, preferred stock or warrants to purchase such shares of common stock. In addition, we may be eligible for trading over-the-counter, but the delistingattempt to raise capital by selling shares of our common stock, frompossibly at a discount to market in the NASDAQ Capital Marketfuture. These actions will result in dilution of the ownership interests of existing stockholders and may further dilute common stock book value, and that dilution may be material. Such issuances may also serve to enhance existing management’s ability to maintain control of us, because the shares may be issued to parties or entities committed to supporting existing management.

Future litigation or governmental proceedings could result in material adverse consequences, including judgments or settlements.

From time to time, we are involved in lawsuits, regulatory inquiries and may be involved in governmental and other legal proceedings arising out of the ordinary course of our business. Many of these matters raise difficult and complicated factual and legal issues and are subject to uncertainties and complexities. The timing of the final resolutions to these types of matters is often uncertain. Additionally, the possible outcomes or resolutions to these matters could include adverse judgments or settlements, either of which could require substantial payments, adversely affecting our results of operations and liquidity.

We may become involved in securities class action litigation that could divert management’s attention and harm the combined company’s business, and insurance coverage may not be sufficient to cover all costs and damages.

In the past, securities class action or stockholder derivative litigation often follows certain significant business transactions, such as a material acquisition such as the one completed in January 2022. The combined company may become involved in this type of litigation in the future. Litigation often is expensive and diverts management’s attention and resources, which could adversely impactaffect the combined company’s business.

The physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. An economy-wide transition to lower GHG energy sources could have a variety of adverse effects on our operations and financial results.

Many scientists have shown that increasing concentrations of carbon dioxide, methane and other GHGs in the Earth’s atmosphere are changing global climate patterns. One consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such events were to occur, or become more frequent, our operations could be adversely affected in various ways, including through damage to our facilities or from increased costs for insurance.

Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. As a result, if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.

Efforts by governments, international bodies, businesses and consumers to reduce GHGs and otherwise mitigate the effects of climate change are ongoing. The nature of these efforts and their effects on our business are inherently unpredictable and subject to change. However, actions taken by private parties in anticipation of, or to facilitate, a transition to a lower-GHG economy will affect us as well. For example, our cost of capital may increase if lenders or other market participants decline to invest in fossil fuel-related companies for regulatory or reputational reasons. Similarly, increased demand for low-carbon or renewable energy sources from consumers could reduce the demand for, and the price of, the products we produce. Technological changes, such as developments in renewable energy and low-carbon transportation, could also adversely affect demand for our products.

The Company does not insure against all potential losses, which could result in significant financial exposure.

The Company does not have commercial insurance or third-party indemnities to fully cover all operational risks or potential liability in the event of a significant incident or series of incidents causing catastrophic loss. As a result, the Company is, to a substantial extent, self-insured for such events. The Company relies on existing liquidity, financial resources and valueborrowing capacity to meet short-term obligations that would arise from such an event or series of our common stock.events. The occurrence of a significant incident, series of events, or unforeseen liability for which the Company is self-insured, not fully insured or for which insurance recovery is significantly delayed could have a material adverse effect on the Company’s results of operations or financial condition.

Increasing attention to environmental, social, and governance (ESG) matters may impact our business.

Increasing attention to ESG matters, including those related to climate change and sustainability, increasing societal, investor and legislative pressure on companies to address ESG matters, may result in increased costs, reduced profits, increased investigations and litigation or threats thereof, negative impacts on our stock price and access to capital markets, and damage to our reputation. Increasing attention to climate change, for example, may result in demand shifts for hydrocarbon and additional governmental investigations and private litigation, or threats thereof, against the Company. In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters, including climate change and climate-related risks. Such ratings are used by some investors to inform their investment and voting decisions. Also, some stakeholders, including but not limited to sovereign wealth, pension, and endowment funds, have been divesting and promoting divestment of or screening out of fossil fuel equities and urging lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Unfavorable ESG ratings and investment community divestment initiatives, among other actions, may lead to negative investor sentiment toward the Company and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital. Additionally, evolving expectations on various ESG matters, including biodiversity, waste and water, may increase costs, require changes in how we operate and lead to negative stakeholder sentiment.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

The description of the Company’s properties below as of December 31, 2021, does not include any of the Acquired Assets acquired in January 2022.

Oil and Natural Gas Interests

We do not have in-house geophysical or reserve engineering expertise. We therefore primarily rely on the operators of our producing wells to provide production data to our independent reserve engineers. Reserve estimates are based on average prices per barrel of oil and per Mcfe of natural gas at the first day of each month of the 12-month period prior to the end of the reporting period. Reserve estimates as of December 31, 2019, 20182021, 2020 and 20172019 are based on the following average prices, in each case as adjusted for transportation, quality, and basis differentials applicable to our properties on a weighted average basis:

Presented below is a summary of our proved oil and natural gas reserve quantities, all of which are located in the United States, as of the end of each of our last three fiscal years: