UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
| ☒ | Annual report pursuant to section 13 or 15(d) of the SECURITIES EXCHANGE ACT OF 1934 |
| For the Fiscal Year Ended December 31, 2021 | |
| ☐ | Transition report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from ________________ to _______________ |
Commission File Number 000-06814
US ENERGY CORP.
(Exact Name of Company as Specified in its Charter)
| Wyoming | 83-0205516 | |
(State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) | |
| 675 Bering, Suite 390, Houston, Texas | 77057 | |
| (Address of principal executive offices) | (Zip Code) | |
| Registrant’s telephone number, including area code: | (303) 993-3200 |
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol(s) | Name of exchange on which registered | ||
| Common Stock, $0.01 par value | USEG | NASDAQ Capital Market LLC (Nasdaq Capital Market) |
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 ☐ ☒
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 ☐ ☒
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. ☒ 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). ☒ NO ☐
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 ☒ 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 ☒
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, 2021, was $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 shares of its $0.01 par value common stock outstanding as of March 25, 2022.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive proxy statement relating 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 U.S. Securities and Exchange Commission within 120 days after the end of the fiscal year to which this report relates.
TABLE OF CONTENTS
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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, Section 21E of the Securities Exchange Act of 1934, as amended, 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:
| ● | planned capital expenditures for oil and natural gas exploration and environmental compliance; | |
| ● | potential drilling locations and available spacing units, and possible changes in spacing rules; | |
| ● | cash expected to be available for capital expenditures and to satisfy other obligations; | |
| ● | recovered volumes and values of oil and natural gas approximating third-party estimates; | |
| ● | anticipated changes in oil and natural gas production; | |
| ● | drilling and completion activities and opportunities; | |
| ● | timing of drilling additional wells and performing other exploration and development projects; | |
| ● | expected spacing and the number of wells to be drilled with our oil and natural gas industry partners; | |
| ● | when payout-based milestones or similar thresholds will be reached for the purposes of our agreements with our partners; | |
| ● | expected working and net revenue interests, and costs of wells, relating to the drilling programs with our partners; | |
| ● | actual decline rates for producing wells; | |
| ● | future cash flows, expenses and borrowings; | |
| ● | pursuit of potential acquisition opportunities; | |
| ● | economic downturns (including as a result of COVID-19), wars and increases in inflation, and possible recessions caused thereby; | |
| ● | the effects of global pandemics, such as COVID-19 on our operations, properties, the market for oil and gas, and the demand for oil and gas; | |
| ● | our expected financial position; | |
| ● | our expected future overhead reductions; | |
| ● | our ability to become an operator of oil and natural gas properties; | |
| ● | our ability to raise additional financing and acquire attractive oil and natural gas properties; and | |
| ● | other plans and objectives for future operations. |
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 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 undertake any obligation to update or revise publicly any forward-looking statements except as required by law, including the securities laws of the United States and the rules and regulations of the SEC.
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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.
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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 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.
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PART I
Item 1. Business.
General 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:
| ● | “Exchange Act” refers to the Securities Exchange Act of 1934, as amended; | |
| ● | “SEC” or the “Commission” refers to the United States Securities and Exchange Commission; and | |
| ● | “Securities Act” refers to the Securities Act of 1933, as amended. |
Overview
U.S. 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.
We have historically explored for and produced oil and natural gas through a non-operator business model, however, during 2020 we acquired operated properties in North Dakota, New Mexico, Wyoming and the Texas Gulf Coast, and on January 5, 2022, we closed the acquisitions of certain oil and gas properties from three separate sellers, representing a diversified 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 to enhance the value of our acquired operated assets through evaluation of certain properties with the goal of increasing production and reserves. We plan to deploy our capital in a conservative and strategic manner and pursue value-enhancing transactions and expect to continuously evaluate strategic alternative opportunities that we believe will enhance shareholder value.
Office Location
Our principal executive office is located at 675 Bering, Suite 390, Houston, Texas 77057. Our telephone number is (303) 993-3200.
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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 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 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:
| ● | Estimated proved reserves of 1,344,626 barrel of oil equivalent (BOE) (76% oil and 24% natural gas) as of December 31, 2021, with a standardized measure value of $19.2 million. | |
| ● | As of December 31, 2021, our oil and natural gas leases covered 89,846 gross acres and 5,757 net acres. | |
| ● | 146 gross (35.3 net) producing wells as of December 31, 2021. | |
| ● | 337 BOE per day average net production for 2021. |
Recent 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 cash and 6,568,828 shares of our 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 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:
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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:
| ● | To use our commercially reasonable efforts to prepare and file an initial shelf registration statement under the Securities Act covering the resale of all of the shares of common stock issuable to the Sellers, on or before the 30th day after the date the RRA was entered into and use commercially reasonable efforts to cause such initial shelf registration statement to become effective no later than 60 days following the filing date (or, in the event of a “full review” by the Commission, the 90th day following the filing date), provided that the filing of the required registration statement may be delayed pending the finalization of required financial statements associated with the acquisition which are required to be included in the registration statement; and | |
| ● | To provide the Sellers certain piggy-back registration and participation rights associated with future registration statements and/or future registered offerings we may undertake in the future, subject to certain exclusions and exceptions. |
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 Disqualified 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 unfit 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.
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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.
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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 1st and October 1st 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 reserves in accordance with the lenders’ customary procedures and practices.
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 promissory 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 (b) the Federal Funds rate in effect on such day (as determined in the Credit Agreement) plus 0.50%, and an applicable margin that ranges 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 0.75% regardless of utilization. If the Company fails to deliver a report setting forth its proved oil and natural gas reserves 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 arrears 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 payable 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 administrative agent accruing interest at the Applicable Margin as loans under the Credit Agreement, based on the average daily amount of the letter of credits issued by such Lender, as calculated under the 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.
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We are also 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 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 Company’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.
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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 as Exhibit I to the Master Agreement.
The Company’s entry into and the obligations of the Company under the Master Agreement and Schedule were required conditions to the Closing of 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 West 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.
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Williston Basin, North Dakota (Bakken and Three Forks Formations)
Zavanna, LLC. We have an interest in 18 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 comprised approximately 37.5% of the PV-10 related to our oil and natural gas 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)
Contango Resources Inc. We have an interest in multiple wells with Contango 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 22.4% net revenue interest. All of the leases are currently held by production and comprised approximately 6.9% of the PV-10 related to our oil and natural gas reserves at December 31, 2021.
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:
| ● | Require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities; | |
| ● | Limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and | |
| ● | Impose substantial liabilities for pollution resulting from operations. |
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.
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Waste Handling. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Under 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 their own, more stringent requirements. Drilling fluids, produced water, and most of the other wastes associated with the exploration, development, and production of oil or gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.
Endangered Species. The federal Endangered Species Act and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species. Some of our operations are conducted in areas 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 as 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 certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where we perform drilling, completion, and production activities could impair our ability to timely complete well drilling and development and could adversely affect our 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 pounds 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.
Water discharges. The federal Water Pollution Control Act (“Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States and states. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, or analogous state agencies. This includes the discharge of certain storm water without a permit which requires periodic monitoring and sampling. In addition, the Clean Water Act regulates wastewater generated by unconventional oil and gas operations during the hydraulic fracturing process and discharged to publicly-owned wastewater treatment facilities. The Clean Water Act also prohibits discharge of dredged or fill material into waters of the United States, including wetlands, except in accordance with the terms of a permit issued by the United States Army Corps of Engineers, or a state, if the state has assumed authority to issue such permits. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.
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Oil Pollution Act of 1990 (“OPA”). OPA 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 other consequences of oil spills into jurisdictional waters. Any unpermitted release of petroleum or other pollutants from our operations could result in governmental penalties and civil 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 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 used to stimulate production of hydrocarbons from tight shale formations. We routinely utilize hydraulic fracturing techniques in most of our drilling and completion programs. The process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, even on private lands, the EPA has asserted federal regulatory authority over hydraulic fracturing involving 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 sources.
Increased regulation and scrutiny on oil and gas activities involving hydraulic fracturing techniques could potentially lead to a 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 levels, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting requirements, which could result in additional permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and gas that we are ultimately able to produce from our reserves.
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We believe the trend in local, state, and federal 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 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 our 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.
Research and Development
No research and development expenditures have been incurred 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.
Human Capital
As of March 22, 2022, we had 23 full-time employees and 2 part-time employees, none of whom were subject to a collective bargaining agreement. In addition, we utilize several consultants on an as-needed 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:
| ● | integrity and ethical behavior in the conduct of our business; | |
| ● | environmental, health and safety priorities: | |
| ● | prioritizing the success of others and the team; | |
| ● | communicating why we do what we do and how every employee contributes to achieving success; and | |
| ● | support for team members’ professional and personal development. |
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.
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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 2022 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:
| ● | Deploy our Capital in a Conservative and Strategic Manner and Review Opportunities to Bolster our Liquidity. In the current industry environment, maintaining liquidity is critical. Therefore, we will be highly selective in the projects we evaluate and will review opportunities to bolster our liquidity and financial position through various means. | |
| ● | Evaluate and Pursue Value-Enhancing Transactions. We will continuously evaluate strategic alternative opportunities that we believe will enhance shareholder value. |
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. 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.
In 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 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.
Additionally, 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.
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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 engaged 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. 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.
Seasonality
Winter weather conditions and lease stipulations can limit or temporarily halt our drilling and producing activities and other oil and natural gas 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.
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.
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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 re-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-service filing. Every five years, the FERC reviews the appropriateness of the index level in relation to changes in industry costs.
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.
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Marketing, Major Customers and Delivery Commitments
Markets for oil and natural 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 pricing 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 the 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 operating 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 properties than we can. Ultimately, our future success will depend on our ability to develop or acquire additional reserves at costs that allow us to remain 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 amendments to reports filed pursuant to Sections 13(a) and 15(d) of the Exchange Act, are filed with the U.S. Securities and Exchange Commission. Such reports and other information filed by 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 website 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 Secretary, who can be contacted at the address and telephone number set forth on the cover page of this Report. You may also find information related to our corporate governance, board committees and code of ethics on our website.
Item 1A. Risk Factors.
An investment in our common stock involves a high degree of risk. You should carefully consider the risks described below as well as the other information in this filing before deciding to invest in our company. Any of the risk factors described below could significantly and adversely affect our business, prospects, financial condition and results of operations. Additional risks and uncertainties 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 operations. As a result, the trading price or value of our common stock could be materially adversely affected and you may lose all or part of your investment.
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Summary Risk 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:
| ● | our ability to obtain sufficient cash flow from operations, borrowing, and/or other sources to fully develop our undeveloped acreage positions; | |
| ● | volatility in oil and natural gas prices, including further declines in oil prices and/or natural gas prices, which would have a negative impact on operating cash flow and could require further ceiling test write-downs on our oil and natural gas assets; | |
| ● | the possibility that the oil and natural gas industry may be subject to new adverse regulatory or legislative actions (including changes to existing tax rules and regulations and changes in environmental regulation); | |
| ● | the general risks of exploration and development activities, including the failure to find oil and natural gas in sufficient commercial quantities to provide a reasonable return on investment; | |
| ● | future oil and natural gas production rates, and/or the ultimate recoverability of reserves, falling below estimates; | |
| ● | the ability to replace oil and natural gas reserves as they deplete from production; | |
| ● | environmental risks; | |
| ● | risks associated with our plan to develop additional operating capabilities, including the potential inability to recruit and retain personnel with the requisite skills and experience and liabilities we could assume or incur as an operator or to acquire operated properties or obtain operatorship of existing properties; | |
| ● | availability of pipeline capacity and other means of transporting crude oil and natural gas production, and related midstream infrastructure and services; | |
| ● | competition in leasing new acreage and for drilling programs with operating companies, resulting in less favorable terms or fewer opportunities being available; | |
| ● | higher drilling and completion costs related to competition for drilling and completion services and shortages of labor and materials; | |
| ● | disruptions resulting from unanticipated weather events, natural disasters, and public health crises and pandemics, such as the coronavirus, resulting in possible delays of drilling and completions and the interruption of anticipated production streams of hydrocarbons, which could impact expenses and revenues; | |
| ● | our lack of effective disclosure controls and procedures and internal control over financial reporting; | |
| ● | our ability to maintain the listing of our common stock on The Nasdaq Capital Market; | |
| ● | dilution caused by new equity or debt offerings; | |
| ● | our need for additional capital to complete future acquisitions, conduct our operations and fund our business, and our ability to obtain such necessary funding on favorable terms, if at all; | |
| ● | the speculative nature of our oil and gas operations, and general risks associated with the exploration for, and production of oil and gas; including accidents, equipment failures or mechanical problems which may occur while drilling or completing wells or in production activities; operational hazards and unforeseen interruptions for which we may not be adequately insured; the threat and impact of terrorist attacks, cyber-attacks or similar hostilities; declining reserves and production; and losses or costs we may incur as a result of title deficiencies or environmental issues in the properties in which we invest, any one of which may adversely impact our operations; | |
| ● | changes in the legal and regulatory environment governing the oil and natural gas industry, including new or amended environmental legislation or regulatory initiatives which could result in increased costs, additional operating restrictions, or delays, or have other adverse effects on us; | |
| ● | improvements in or new discoveries of alternative energy technologies that could have a material adverse effect on our financial condition and results of operations; | |
| ● | the fact that our officers and directors beneficially own a majority of our common stock and that their interests may be different from other shareholders; | |
| ● | our dependence on the continued involvement of our present management; |
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| ● | economic downturns and possible recessions caused thereby (including as a result of COVID-19, increases in inflation or global conflicts, such as the current conflict in Ukraine); | |
| ● | the effects of global pandemics, such as COVID-19 on our operations, properties, the market for oil and gas, and the demand for oil and gas; | |
| ● | the need to write-down assets and/or shut-in wells, or our non-operated wells being shut-in by their operators; | |
| ● | future litigation or governmental proceedings which could result in material adverse consequences, including judgments or settlements; | |
| ● | unanticipated down-hole mechanical problems, which could result in higher-than-expected drilling and completion expenses and/or the loss of the wellbore or a portion thereof; and | |
| ● | Other risks disclosed below under “Risk Factors”. |
Risk Factors
The following risk factors should be carefully considered in evaluating the information in this annual report on Form 10-K.
Risks Related 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.
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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 price 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 have been volatile. These markets will likely continue to be volatile in the future. Further, oil prices and natural gas prices do not necessarily fluctuate in direct 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, or further declines in the market prices for oil and natural gas, will likely result in capital expenditures being further curtailed and will adversely affect our business, financial condition and liquidity. Additionally, lower oil and natural gas prices 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 $63.27 per Bbl to a low of ($36.98) per Bbl and the 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 spot price ranged from a high of 85.64 per Bbl to a low of 47.47 per Bbl and 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.
As described above, oil, NGLs, and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the commodities 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 prices received from operators of our non-operated production, and the levels of such production, will continue to depend on numerous factors, including the following:
| ● | the domestic and foreign supply of oil, NGLs, and natural gas; | |
| ● | the domestic and foreign demand for oil, NGLs, and natural gas; | |
| ● | the prices and availability of competitors’ supplies of oil, NGLs, and natural gas; | |
| ● | the actions of the Organization of Petroleum Exporting Countries, or OPEC, and state-controlled oil companies relating to oil price and production controls; | |
| ● | the price and quantity of foreign imports of oil, NGLs, and natural gas; | |
| ● | the impact of U.S. dollar exchange rates on oil, NGLs, and natural gas prices and inflation; | |
| ● | domestic and foreign governmental regulations and taxes; | |
| ● | speculative trading of oil, NGLs, and natural gas futures contracts; | |
| ● | localized supply and demand fundamentals, including the availability, proximity, and capacity of gathering and transportation systems for natural gas; | |
| ● | the availability of refining capacity; | |
| ● | the prices and availability of alternative fuel sources; | |
| ● | the threat, or perceived threat, or results, of viral pandemics, for example, as currently being experienced with the COVID-19 pandemic; |
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| ● | weather conditions and natural disasters; | |
| ● | political conditions in or affecting oil, NGLs, and natural gas producing regions, including the Middle East and South America and the recent conflict in Ukraine; | |
| ● | the continued threat of terrorism and the impact of military action and civil unrest; | |
| ● | public pressure on, and legislative and regulatory interest within, federal, state, and local governments to stop, significantly limit, or regulate hydraulic fracturing activities; | |
| ● | the level of global oil, NGL, and natural gas inventories and exploration and production activity; | |
| ● | authorization of exports from the United States of liquefied natural gas; | |
| ● | the impact of energy conservation efforts; | |
| ● | technological advances affecting energy consumption; and | |
| ● | overall worldwide economic conditions. |
Declines in oil, NGL, 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 operator’s expertise and financial resources; | |
| ● | the rate of production of reserves, if any; | |
| ● | approval of other participants in drilling wells; and | |
| ● | selection of technology. |
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, liquidity, 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.
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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, declining business and consumer confidence, and increased unemployment, have precipitated an economic slowdown and a recession, which could expand to a 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 liquids, affect the ability of our vendors, suppliers and customers to continue operations, and ultimately adversely impact our results of operations, liquidity and financial condition to a greater extent than it has already. In addition, a decline in consumer confidence or changing patterns in the availability and use of disposable income by consumers can negatively affect the demand for oil and gas and as a result our results of operations.
The development of oil and natural gas properties involves substantial risks that may result in a total loss of investment.
The business of exploring for, working over 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, 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:
| ● | unexpected drilling conditions; | |
| ● | inability to obtain required permits from governmental authorities; | |
| ● | inability to obtain, or limitations on, easements from landowners; |
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| ● | uncertainty regarding our operating partners’ drilling schedules; | |
| ● | high pressure or irregularities in geologic formations; | |
| ● | equipment failures; | |
| ● | title problems; | |
| ● | fires, explosions, blowouts, cratering, pollution, spills and other environmental risks or accidents; | |
| ● | changes in government regulations and issuance of local drilling restrictions or moratoria; | |
| ● | adverse weather; | |
| ● | reductions in commodity prices; | |
| ● | pipeline ruptures; and | |
| ● | unavailability or high cost of equipment, field services and labor. |
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 higher 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 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 2021, our weighted average realized oil price in the Williston Basin was $61.74, which due to transportation costs was approximately $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.
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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.
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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.
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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 nature and timing of the operator’s drilling and other activities; | |
| ● | the timing and amount of required capital expenditures; | |
| ● | the operator’s geological and engineering expertise and financial resources; | |
| ● | the approval of other participants in drilling wells; and | |
| ● | the operator’s selection of suitable technology. |
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.
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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.
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Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:
| ● | the counter-party to the derivative instrument defaults on its contract obligations; | |
| ● | there is an increase in the differential between the underlying price in the derivative instrument and actual prices received (as existed in 2021, and has occurred in the first part of 2022); or | |
| ● | the steps we take to monitor our derivative financial instruments do not detect and prevent transactions that are inconsistent with our risk management strategies. |
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.
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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.
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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.
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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 quality and quantity of available data; |
| ● | the interpretation of that data; |
| ● | the judgment of the persons preparing the estimate; and |
| ● | the accuracy of the assumptions. |
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.
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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.
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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 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, 2021 due to the material weaknesses described below.
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As of December 31, 2021, we have identified the following material weaknesses:
| ● | We had inadequate segregation of duties as a result of limited accounting staff and resources, which may impact our ability to prevent or detect material errors in our consolidated financial statements. | |
| ● | We had inadequate segregation of duties related to logical access to our accounting systems, which may affect our ability to prevent or detect material errors in the recorded transactions. |
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 as of December 31, 2021, 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.
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 the Company’s annual or interim financial statements will not be 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, or the development of new material weaknesses in our internal control over financial reporting, 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 trading 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 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 not be detected.
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Our ability to use net operating loss carryforwards and realize 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.
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.
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:
| ● | requiring the installation of pollution-control equipment or otherwise restricting the handling or disposal of wastes and other substances associated with operations; | |
| ● | limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species and/or species of special statewide concern or their habitats; | |
| ● | requiring investigatory and remedial actions to address pollution caused by our operations or attributable to former operations; | |
| ● | requiring noise, lighting, visual impact, odor and/or dust mitigation, setbacks, landscaping, fencing, and other measures; | |
| ● | restricting access to certain equipment or areas to a limited set of employees or contractors who have proper certification or permits to conduct work (e.g., confined space entry and process safety maintenance requirements); and | |
| ● | restricting or even prohibiting water use based upon availability, impacts or other factors. |
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.
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Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations, and cash flows.
From time to time, legislative proposals are made that would, if enacted, result in the elimination of the immediate deduction for intangible drilling and development costs, the elimination of the 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
Our 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 financial condition and liquidity.
In connection with the Credit Agreement, we agreed to comply 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 borrowing base.
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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 breach of any of the covenants of the Credit Agreement or any future agreements, if uncured or unwaived, could lead to an event of default under any such document, which in some circumstances could give our creditors the right to demand that we accelerate repayment of amounts 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 documents governing our indebtedness. Therefore, in the event 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 we 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 our ability to obtain additional financing on acceptable terms. The occurrence of any of these events could have a material adverse effect on our financial condition and liquidity and/or cause our lenders to enforce their security interests which could ultimately result in the foreclosure of our assets, which would have a material adverse effect on our operations and the value of our securities.
The covenants in our credit and loan agreements restrict our ability to operate our business and 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 these 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 that difficulty.
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Risks Related to Our Stock
We currently have an unlimited number of shares of common 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 executive 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. Additionally, we are not restricted from issuing additional shares of common 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 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). 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 which can be designated by the Board of Directors without shareholder approval.
We have 100,000 shares of preferred stock authorized, which includes 50,000 shares of Series A Convertible Preferred Stock (none of which are outstanding) and 50,000 shares of Series P preferred stock (none of which are outstanding). Shares of preferred stock may be designated and issued by our Board of Directors without shareholder approval with voting 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 shares of common stock currently 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 the preferred stock the right to convert the shares of preferred stock they hold into shares of our common stock, which may cause substantial dilution to our then common stock stockholders and/or have other rights and preferences (including, but not limited to voting rights) greater than those of our common stock stockholders. 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 existing stockholders or result in a change of control. Because our Board of Directors is entitled to designate the powers and preferences of the preferred stock without a vote of our stockholders, subject to NASDAQ rules and regulations, our stockholders will have no control over what designations and preferences our future preferred stock, if any, will have.
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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 a 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 your interests; and as a result of such ownership, we are a “controlled company” under applicable Nasdaq Capital Market Rules.
John A. Weinzierl, Duane H. King and Joshua Batchelor, our Chairman, director and director, respectively, beneficially own an aggregate of 20,185,736 shares of our common stock, representing approximately 78.9% of our outstanding common 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 such, Messrs. Weinzierl, King and Batchelor can control the outcome of all matters requiring a shareholder vote, including the election of directors, the adoption of amendments to our certificate of incorporation or bylaws and the approval of mergers and other significant corporate transactions. Subject to any fiduciary duties owed to the stockholders generally, while Messrs. Weinzierl’s, King’s and Batchelor’s interests may generally 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. Because 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 necessary to nominate and elect (and, if applicable, maintain in office) 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 earlier of (a) the date mutually agreed by all the parties; and (b) the date that no seller party 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 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 Voting Agreement, even if such seller party’s ownership increases above 5% of the Company’s common stock in the future. 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 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 certain corporate governance requirements, including requirements that:
| ● | a majority of the Board of Directors consist of independent directors; | |
| ● | the board maintain a nominations committee with prescribed duties and a written charter; and | |
| ● | the board maintain a compensation committee with prescribed duties and a written charter and comprised solely of independent directors. |
As a “controlled company,” we may elect to rely on some or all of these exemptions, provided that we have to date not taken advantage of any of these exemptions and do not currently intend to take 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 avail ourselves of these exemptions, our status as a controlled company could make our common stock less attractive to some investors or otherwise harm our stock price.
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Our governing documents and Wyoming law includes various take-over defense provisions that could discourage some advantageous transactions.
We 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 to continue to be, volatile.
Our stock is traded on The NASDAQ Capital Market under the symbol “USEG”. During the last 52 weeks, our common stock has traded as high as $13.92 per share and as low as $2.91 per 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:
| ● | price volatility in the oil and natural gas commodities markets; | |
| ● | variations in our drilling, recompletion and operating activity; | |
| ● | relatively small amounts of our common stock trading on any given day; | |
| ● | additions or departures of key personnel; | |
| ● | legislative and regulatory changes; and | |
| ● | changes in the national and global economic outlook, including, but not limited to, as a result of global pandemics (including COVID-19, inflation and global conflicts, including the current ongoing conflict between Ukraine and Russia). |
The stock market has previously experienced significant price and volume fluctuations, and oil and natural gas prices declined 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.
Our 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 majority of independent directors, and to maintain a stock price 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 affect the acceptance of our common stock as 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 any sales of our securities. These requirements could severely limit the market liquidity of our common stock and the ability 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 be able to list our common stock on another national securities exchange or obtain quotation on an over-the counter quotation system.
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If we are delisted from The Nasdaq Capital Market, your ability to sell your shares of our common stock could also be limited by the penny stock restrictions, which could further limit the marketability of your shares.
If our common stock is 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:
| ● | establish and maintain a system of internal control over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board; | |
| ● | comply with rules and regulations promulgated by NASDAQ; | |
| ● | prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws; | |
| ● | maintain various internal compliance and disclosures policies, such as those relating to disclosure controls and procedures and insider trading in our common stock; | |
| ● | involve and retain to a greater degree outside counsel and accountants in the above activities; | |
| ● | maintain a comprehensive internal audit function; and | |
| ● | maintain an investor relations function. |
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.
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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 security threats subjects our operations to increased 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 increased capital and 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 extent 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 timely fashion.
Because of our small size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As we expand our activities, including 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.
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If we complete acquisitions or enter into business combinations in the future, 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:
| ● | the difficulty of integrating acquired companies, concepts and operations; | |
| ● | the potential disruption of the ongoing businesses and distraction of our management and the management of acquired companies; | |
| ● | change in our business focus and/or management; | |
| ● | difficulties in maintaining uniform standards, controls, procedures and policies; | |
| ● | the potential impairment of relationships with employees and partners as a result of any integration of new management personnel; | |
| ● | the potential inability to manage an increased number of locations and employees; | |
| ● | our ability to successfully manage the companies and/or concepts acquired; | |
| ● | the failure to realize efficiencies, synergies and cost savings; or | |
| ● | the effect of any government regulations which relate to the business acquired. |
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 sometimes sell short knowing they can, in effect, cover through the exercise of 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 market price of a security. Further sales of common stock issued upon exercise of future warrants or other convertible securities could cause even greater declines in the price of our common stock due to the number 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, preferred stock, or warrants to purchase shares of our common stock. Our Board of Directors has authority, without action or vote of the stockholders, subject to the requirements of The NASDAQ Capital Market (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 attempt to raise capital by selling shares of our common stock, possibly at a discount to market in the future. 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.
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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 affect 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 borrowing capacity to meet short-term obligations that would arise from such an event or series of 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.
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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
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, 2021, 2020 and 2019 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:
| Average Price During | ||||||||||||
| 2021 | 2020 | 2019 | ||||||||||
| Oil (per Bbl) | $ | 66.56 | $ | 39.57 | $ | 55.69 | ||||||
| Gas (per Mcfe) | $ | 3.60 | $ | 1.99 | $ | 2.58 | ||||||
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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:
| As of December 31, | ||||||||||||||||||||||||||||||||||||
| 2021 (1) | 2020 (1) | 2019 (1) | ||||||||||||||||||||||||||||||||||
| Oil | Natural Gas | Total | Oil | Natural Gas | Total | Oil | Natural Gas | Total | ||||||||||||||||||||||||||||
| (Bbl) | (Mcf) | (BOE) | (Bbl) | (Mcf) | (BOE) | (Bbl) | (Mcf) | (BOE) | ||||||||||||||||||||||||||||
| Proved developed | 1,021,620 | 1,938,048 | 1,344,626 | 870,877 | 1,676,948 | 1,150,368 | 807,510 | 1,129,260 | 995,720 | |||||||||||||||||||||||||||
| Proved non-producing | - | - | - | 104,868 | - | 104,868 | - | - | - | |||||||||||||||||||||||||||
| Proved undeveloped | - | - | - | - | - | - | - | - | - | |||||||||||||||||||||||||||
| Total proved reserves | 1,021,620 | 1,938,048 | 1,344,626 | 975,745 | 1,676,948 | 1,255,236 | 807,510 | 1,129,260 | 995,720 | |||||||||||||||||||||||||||
| (1) | Our reserve estimates as of December 31, 2021, 2020 and 2019 are based on reserve reports prepared by Don Jacks, PE. A copy of Mr. Jacks’ report is filed as an exhibit to this annual report on Form 10-K. |
Internal Controls Over Proved Reserve Estimates
Our internal controls over the recording of proved reserves are structured to objectively and accurately estimate our reserve quantities and values in compliance with the SEC’s regulations. Our process for managing and monitoring our proved reserves is delegated to Don Jacks, a third-party independent petroleum engineer. Oversight is provided by management and the Audit Committee of our Board of Directors, as discussed below.
Mr. Jacks has worked in the energy industry since 1981 and has been contracted by the Company to perform our proved reserve estimates since 2019. He holds a Bachelor of Science Degree and a Master of Science Degree in Petroleum Engineering from The University of Texas at Austin and is a Registered Professional Petroleum Engineer in the states of Texas since 1992. He is also a member of the Society of Petroleum Evaluation Engineers (SPEE) and has been a chapter officer since 2005. Technical and engineering reviews of our assets are performed quarterly by Mr. Jacks and reported to our management. Data obtained from these reviews, in conjunction with economic data and our ownership information, is used in making a determination of estimated proved reserve quantities.
Our reserves are reviewed by our management quarterly and by the Audit Committee of our Board of Directors at least annually. Our management, which includes our Chief Executive Officer, Chief Operating Officer, and Chief Accounting Officer, are responsible for reviewing and verifying that the estimate of proved reserves is reasonable, complete, and accurate. The Audit Committee reviews a summary of the final reserves estimate and meets independently with Mr. Jacks separate from our management to discuss processes and findings in the reserve report. The Audit Committee can and does request reports and information from Mr. Jacks to independently verify values reported by the management team.
As of December 31, 2021, our proved reserves totaled 1,344,626 BOE, of which 100% were classified as proved developed. On a BOE basis, approximately 76% of the total proved reserves are derived from 1,021,620 Bbls of oil and 24% is derived from 1,938,048 Mcfe of natural gas and NGLs. See the “Glossary of Oil and Natural Gas Terms” above for an explanation of these and other terms.
You should not place undue reliance on estimates of proved reserves. See “Risk Factors - 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.” A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetrics, material balance, advance production type curve matching, petrophysics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.
The primary inputs to the reserve estimation process are comprised of technical information, financial data, ownership interests and production data. All field and reservoir technical information is assessed for validity when meetings are held with management, land personnel and third-party operators to discuss field performance and to validate future development plans. Current revenue and expense information is obtained from our accounting records, which are subject to their own set of internal controls over financial reporting. All current financial data such as commodity prices, lease operating expenses, production taxes and field commodity price differentials are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete. Our current ownership in mineral interests and well production data are also subject to the aforementioned internal controls over financial reporting, and they are incorporated into the reserve database as well and verified to ensure their accuracy and completeness. Our reserve database is currently maintained by Don Jacks, PE. Mr. Jacks works with our personnel to review field performance, future development plans, current revenues and expense information. Following these reviews, the reserve database and supporting data is updated so that Mr. Jacks can prepare his independent reserve estimates and final report.
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Proved Undeveloped Reserves. As of December 31, 2021, 2020 and 2019, we did not have any and did not book any proved undeveloped (“PUD”) reserves due to the lack of an approved development plan for development of PUD reserves and uncertainty regarding the availability of capital that would be required to develop any PUD reserves.
Oil and Natural Gas Production, Production Prices, and Production Costs. The following table sets forth certain information regarding our net production volumes, average sales prices realized and certain expenses associated with sales of oil and natural gas for the years ended December 31, 2021, 2020 and 2019.
| 2021 | 2020 | 2019 | ||||||||||
| Production Volume | ||||||||||||
| Oil (Bbls) | 93,722 | 60,469 | 110,090 | |||||||||
| Natural gas (Mcfe) | 176,657 | 116,085 | 209,518 | |||||||||
| BOE | 123,165 | 79,816 | 145,010 | |||||||||
| Daily Average Production Volume | ||||||||||||
| Oil (Bbls per day) | 257 | 165 | 302 | |||||||||
| Natural gas (Mcfe per day) | 484 | 317 | 574 | |||||||||
| BOE per day | 337 | 218 | 397 | |||||||||
| Net prices realized | ||||||||||||
| Oil per Bbl | $ | 63.55 | $ | 35.18 | $ | 55.85 | ||||||
| Natural gas per Mcfe | 3.97 | 1.75 | 2.03 | |||||||||
| Oil and natural gas per BOE | 54.05 | 29.19 | 45.33 | |||||||||
| Operating Expenses per BOE | ||||||||||||
| Lease operating expenses and production taxes | $ | 22.38 | $ | 21.34 | $ | 15.70 | ||||||
| Depletion, depreciation and amortization | 4.61 | 5.09 | 4.78 | |||||||||
We encourage you to read this information in conjunction with the information contained in our financial statements and related notes included in Item 8 of this annual report on Form 10-K under “Financial Statements and Supplemental Data”.
The following table provides a regional summary of our production for the years ended December 31, 2021, 2020 and 2019
| 2021 | 2020 | 2019 | ||||||||||||||||||||||||||||||||||
| Oil | Natural Gas | Total | Oil | Natural Gas | Total | Oil | Natural Gas | Total | ||||||||||||||||||||||||||||
| (Bbl) | (Mcfe) | (BOE) | (Bbl) | (Mcfe) | (BOE) | (Bbl) | (Mcfe) | (BOE) | ||||||||||||||||||||||||||||
| North Dakota | 41,111 | 96,730 | 57,233 | 38,021 | 65,059 | 48,864 | 47,170 | 82,620 | 60,940 | |||||||||||||||||||||||||||
| South Texas | 14,321 | 23,273 | 18,200 | 18,687 | 30,080 | 23,700 | 62,920 | 126,898 | 84,070 | |||||||||||||||||||||||||||
| West Texas (1) | 15,441 | 59,193 | 25,307 | 2,472 | 12,766 | 4,600 | - | - | - | |||||||||||||||||||||||||||
| Gulf Coast (2) | 17,971 | - | 17,971 | 991 | - | 991 | - | - | - | |||||||||||||||||||||||||||
| Other | 4,878 | (2,539 | ) | 4,454 | 298 | 8,174 | 1,661 | - | - | - | ||||||||||||||||||||||||||
| Total | 93,722 | 176,657 | 123,165 | 60,649 | 116,085 | 79,816 | 110,090 | 209,518 | 145,010 | |||||||||||||||||||||||||||
| (1) | Includes properties in West Texas and Southeastern New Mexico acquired from FieldPoint Petroleum on September 25, 2020. | |
| (2) | Includes production from Liberty County, Texas properties acquired in December 2020. |
Drilling and Other Exploratory and Development Activities. The following table sets forth information with respect to development and exploratory activity on wells in which we own an interest during the periods ended December 31, 2021, 2020 and 2019.
| 2021 | 2020 | 2019 | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
| Development wells: | ||||||||||||||||||||||||
| Productive | - | - | - | - | - | - | ||||||||||||||||||
| Non-productive | - | - | - | - | - | - | ||||||||||||||||||
| Sub-total | - | - | - | - | - | - | ||||||||||||||||||
| Exploratory wells: | ||||||||||||||||||||||||
| Productive | - | - | - | - | 4 | 0.16 | ||||||||||||||||||
| Non-productive | - | - | - | - | - | - | ||||||||||||||||||
| Sub-total | - | - | - | - | 4 | 0.16 | ||||||||||||||||||
| Total | - | - | - | - | 4 | 0.16 | ||||||||||||||||||
The number of gross wells is the total number of wells we participated in, regardless of our ownership interest in the wells. The information above should not be considered indicative of future drilling performance, nor should it be assumed that there is any correlation between the number of productive wells drilled and the amount of oil and natural gas that may ultimately be recovered. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in this annual report on Form 10-K.
Present Activities. As of March 22, 2022, we are participating in the drilling of one gross well, 0.21 net wells. We are also in the process of returning idle wells we acquired in January 2022 back to production.
Oil and Natural Gas Properties, Wells, Operations and Acreage. The following table summarizes information about our gross and net productive wells as of December 31, 2021.
| Gross Producing Wells | Net Producing Wells | Average Working Interest | ||||||||||||||||||||||||||||||||||
| Oil | Gas | Total | Oil | Gas | Total | Oil | Gas | Total | ||||||||||||||||||||||||||||
| North Dakota | 93 | - | 93 | 7.0 | - | 7.0 | 7.5 | % | - | % | 7.5 | % | ||||||||||||||||||||||||
| South Texas | 20 | - | 20 | 4.6 | - | 4.6 | 22.8 | % | - | % | 22.8 | % | ||||||||||||||||||||||||
| Gulf Coast | 17 | - | 17 | 16.7 | - | 16.7 | 98.1 | % | - | % | 98.1 | % | ||||||||||||||||||||||||
| West Texas | 9 | - | 9 | 3.7 | - | 3.7 | 40.9 | % | - | % | 40.9 | % | ||||||||||||||||||||||||
| Other | 7 | - | 7 | 3.3 | - | 3.3 | 48.4 | % | - | % | 48.4 | % | ||||||||||||||||||||||||
| Total | 146 | - | 146 | 35.3 | - | 35.3 | 24.2 | % | - | % | 24.2 | % | ||||||||||||||||||||||||
Wells are classified as oil or natural gas wells according to the predominant production stream.
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Acreage. The following table summarizes our estimated developed and undeveloped leasehold acreage as of December 31, 2021.
| Developed | Undeveloped | Total | ||||||||||||||||||||||
| Area | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||
| North Dakota | 73,113 | 2,035 | - | - | 73,113 | 2,035 | ||||||||||||||||||
| South Texas | 8,809 | 1,769 | 4,065 | 449 | 12,874 | 2,218 | ||||||||||||||||||
| Gulf Coast | 2,534 | 994 | - | - | 2,534 | 994 | ||||||||||||||||||
| New Mexico | 1,325 | 510 | - | - | 1,325 | 510 | ||||||||||||||||||
| Total | 85,781 | 5,308 | 4,065 | 449 | 89,846 | 5,757 | ||||||||||||||||||
As a non-operator, we are subject to lease expiration if the operator does not commence the development of operations within the agreed terms of our leases. In addition, our leases typically provide that the lease does not expire at the end of the primary term if drilling operations have commenced. As of December 31, 2021, all of our acreage in North Dakota, South Texas, Gulf Coast and New Mexico is held by production.
Real Estate
In August 2021, we sold our 30,400 square-foot office building and 14- acre tract we owned in Riverton, Wyoming. The office building once served as our corporate headquarters but is rented to non-affiliates and government agencies. We received net proceeds of $440 thousand on the sale of the building and land and recorded a loss of $151 thousand in 2021. In addition, we own three city lots covering 13.84 acres adjacent to the office building, which we expect to sell in 2022. However, there can be no assurance that sales of any of this property will be completed on the terms, or in the time frame, we expect or at all.
Office Space
As of December 31, 2021, we leased office space as summarized in the table below:
| Approximate Square Footage Leased | ||||
| Houston- corporate office (1) | 2,006 | |||
| Denver- former corporate office (2) | 2,817 | |||
| (1) | In February 2022, we signed an operating lease for an additional 7,099 square feet of office space in Houston, Texas. The lease has a term of 67 months and will commence once the tenant improvements are substantially complete, which we expect will be in May 2022. |
| (2) | The Denver office operating lease is subleased until its expiration on January 31, 2023. |
Item 3. Legal Proceedings.
From time to time, we may become party to litigation or other legal proceedings that we consider to be a part of the ordinary course of our business. We are not currently involved in any legal proceedings that we believe could reasonably be expected to have a material adverse effect on our business, prospects, financial condition or results of operations. We may become involved in material legal proceedings in the future.
Prior litigation and other legal proceedings which have been settled to date, are described in, and incorporated by reference in, this “Item 3. Legal Proceedings” of this Annual Report on Form 10-K from, “Item 8. Financial Statements and Supplementary Data” in the Notes to Consolidated Financial Statements in “Note 9. Commitments, Contingencies, and Related Party Transactions”, under the heading “Litigation”.
Item 4. Mine Safety Disclosures.
Not applicable.
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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities.
Market Information
Our common stock is traded on the NASDAQ Capital Market under the symbol “USEG”.
Holders
As of March 25, 2022, we had 24,873,812 shares of common stock issued and outstanding held by 408 shareholders of record.
Dividends
We did not declare or pay any cash dividends on common stock during fiscal years 2021 and 2020. The determination to pay dividends on our common stock will be at the discretion of our Board of Directors and will depend on, among other factors, our results of operations, financial condition, capital requirements and contractual restrictions.
Recent Sales of Unregistered Securities
There were no sales of unregistered securities during the year ended December 31, 2021, and from the period from January 1, 2022, to the filing date of this report, which have not previously been included in a Quarterly Report on Form 10-Q or in a Current Report on Form 8-K except as set forth below:
On March 11, 2022, a holder of warrants exercised warrants to purchase 50,000 shares of common stock with an exercise price of $3.92 per share, we received proceeds of $195 thousand and issued 50,000 shares of common stock.
We claim an exemption from registration pursuant to Section 4(a)(2) of the Securities Act, for the above issuance in connection with the exercise.
Purchases of Equity Securities by The Issuer and Affiliated Purchasers
During the year ended December 31, 2021, the Company did not repurchase any shares of its common stock.
Item 6. Selected Financial Data
This Item is not required for smaller reporting companies.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
This discussion includes forward-looking statements. Please refer to “Cautionary Statement Regarding Forward-Looking Statements” of this annual report on Form 10-K for important information about these types of statements and “Risk Factors”, above. Additionally, please refer to the “Glossary of Oil and Natural Gas Terms” of this annual report on Form 10-K for oil and natural gas industry terminology used herein.
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Summary of The Information Contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations
Our Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is provided in addition to the accompanying consolidated financial statements and notes to assist readers in understanding our results of operations, financial condition, and cash flows. MD&A is organized as follows:
| ● | Recent Developments. Discussion of recent developments affecting the Company and our operations. | |
| ● | Plan of Operations and Strategy. Discussion of our strategy moving forward and how we plan to seek to increase stockholder value. | |
| ● | Critical Accounting Policies and Estimates. Accounting estimates that we believe are important to understanding the assumptions and judgments incorporated in our reported financial results and forecasts. | |
| ● | Results of Operations. An analysis of our financial results comparing the years ended December 31, 2021 and 2020. | |
| ● | Liquidity and Capital Resources. A discussion of our financial condition, including descriptions of balance sheet information and cash flows. |
Recent Developments
On January 5, 2022, we closed the acquisitions of assets from three separate Purchase and Sale Agreements entered into by the Company on October 4, 2021, with (i) Lubbock Energy Partners LLC, (ii) Banner Oil & Gas, LLC, Woodford Petroleum, LLC and Llano Energy LLC (collectively, “Banner”), and (iii) Synergy Offshore LLC for approximately $87.3 million. The acquisition has an effective date of January 1, 2022. The purchase price includes payment of $1.3 million in cash and issuance of 19,904,736 shares of our common stock, valued at $64.7 million. In addition, we assumed Banner’s debt of approximately $3.3 million and derivative positions, which were in a loss position of $3.1 million. The assets acquired include certain oil and gas properties 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.
Plan of Operations and Strategy
In 2022 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 and natural gas producing assets. In addition, we plan to grow production by performing workovers on operated idle wells acquired in January 2022 to return them back to production.
Key elements of our business strategy include:
| ● | Deploy our Capital in a Conservative and Strategic Manner and Review Opportunities to Bolster our Liquidity. In the current industry environment, maintaining liquidity is critical. Therefore, we will be highly selective in the projects we evaluate and will review opportunities to bolster our liquidity and financial position through various means. | |
| ● | Evaluate and Pursue Value-Enhancing Transactions. We will continuously evaluate strategic alternative opportunities that we believe will enhance shareholder value. |
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Critical Accounting Policies and Estimates
The preparation of our consolidated financial statements in conformity with GAAP requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates under different assumptions or conditions. A summary of our significant accounting policies is detailed in Note 1 – Organization, Operations and Significant Accounting Policies in Item 8 of this annual report on Form 10-K under “Financial Statements and Supplementary Data”. We have outlined below those policies identified as being critical to the understanding of our business and results of operations and that require the application of significant management judgment.
Oil and Natural Gas Reserve Estimates. Our estimates of proved reserves are based on quantities of oil and natural gas reserves which current engineering data indicates are recoverable from known reservoirs under existing economic and operating conditions. Estimates of proved reserves are critical estimates in determining our depreciation, depletion and amortization expense (“DD&A”) and our full cost ceiling limitation (“Full Cost Ceiling”). Future cash inflows are determined by applying oil and natural gas prices, as adjusted for transportation, quality and basis differentials to the estimated quantities of proved reserves remaining to be produced as of the end of that period. Future production and development costs are based on costs existing at the effective date of the report. Expected cash flows are discounted to present value using a prescribed discount rate of 10% per annum.
Estimates of proved reserves are inherently imprecise because of uncertainties in projecting rates of production and timing of developmental expenditures, interpretations of geological, geophysical, engineering and production data and the quality and quantity of available data. Changing economic conditions also may affect our estimates of proved reserves due to changes in developmental costs and changes in commodity prices that may impact reservoir economics. We utilize independent reserve engineers to estimate our proved reserves at the end of each fiscal quarter during the year.
Oil and Natural Gas Properties. We follow the full cost method in accounting for our oil and natural gas properties. 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 property 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 are amortized using the equivalent unit-of-production method, based on proved oil and natural gas reserves. The capitalized costs are amortized over the life of the reserves associated with the assets, with the DD&A recognized in the period that the reserves are produced. DD&A is calculated by dividing the period’s production volumes by the estimated volume of reserves associated with the investment and multiplying the calculated percentage by the sum of the capitalized investment and estimated future development costs associated with the investment. Changes in our reserve estimates will therefore result in changes in our DD&A per unit. Costs associated with production and general corporate activities are expensed in the period incurred.
Exploratory wells in progress are excluded from the DD&A calculation until the outcome of the well is determined. Similarly, unproved property costs are initially excluded from the DD&A calculation. Unproved property costs not subject to the DD&A calculation consist primarily of leasehold and seismic costs related to unproved areas. Unproved property costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Unproved oil and natural gas properties are assessed quarterly for impairment to determine whether we are still actively pursuing the project and whether the project has been proven either to have economic quantities of reserves or that economic quantities of reserves do not exist.
Under the full cost method of accounting, capitalized oil and natural gas property costs less accumulated DD&A and net of deferred income taxes may not exceed the Full Cost Ceiling. The Full Cost Ceiling is equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves plus the unimpaired cost of unproved properties not subject to amortization, plus the lower of cost or fair value of unproved properties that are subject to amortization. When net capitalized costs exceed the Full Cost Ceiling, an impairment is recognized.
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Joint Interest Operations. Until the January 2022 acquisition, the majority of our properties were operated by other companies. Therefore, we relied to a large extent on the operator of the property to provide us with timely and accurate information about the operations of the properties. Revenue statements and joint interest billings from the operators serve as our primary source of information to record revenue, operating expenses and capital expenditures for our properties on a monthly basis. Many of our properties are subject to complex participation and operating agreements where our working interests and net revenue interests are subject to change upon the occurrence of certain events, such as the achievement of “payout.” These calculations may be subject to error and differences of interpretation which can cause uncertainties about the proper amount that should be recorded in our accounting records. When these issues arise, we make every effort to work with the operators to resolve the issues promptly.
Acquisitions. The Company accounts for acquisitions as business combinations if the acquired assets meet the definition of a business. If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar assets, the acquisition is not considered a business and is accounted for as an asset acquisition. This determination of whether the gross assets acquired are concentrated in a group of similar assets is based on whether the risks associated with managing and creating outputs from the assets are similar.
Revenue Recognition. We recognize revenue in accordance with FASB ASC Topic 606-Revenue from Contracts with Customers. See Note 4- Revenue Recognition to our consolidated financial statements included in Item 8 of this report on Form 10-K under “Financial Statements and Supplementary Data”.
Stock-Based Compensation. We measure the cost of employee services received in exchange for all equity awards granted, including stock options, based on the fair market value of the award as of the grant date. We recognize the cost of the equity awards over the period during which an employee is required to provide service in exchange for the award, usually the vesting period.
Preferred Stock. On December 31, 2020, we redeemed all outstanding shares of our Series A Convertible Preferred Stock, as discussed above. In previous periods, we have excluded our Series A Convertible Preferred Stock from stockholders’ equity due to a redemption feature whereby the holders of the preferred stock had the option to redeem their shares in the event of a change of control, which is outside of our control. See Note 10- Preferred Stock to our consolidated financial statements included in Item 8 of this report on Form 10-K under “Financial Statements and Supplementary Data” for more information related to the Series A Convertible Preferred Stock.
Recently Issued Accounting Standards
Please refer to the section entitled Recent Accounting Pronouncements under Note 1 – Organization, Operations and Significant Accounting Policies in Item 8 of this annual report on Form 10-K under “Financial Statements and Supplementary Data” for additional information on recently issued accounting standards and our plans for adoption of those standards.
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Results of Operations
Comparison of our Statements of Operations for the Years Ended December 31, 2021 and 2020
During the year ended December 31, 2021, we recorded a net loss of $1.8 million as compared to a net loss of $6.4 million for the year ended December 31, 2020. In the following sections we discuss our revenue, operating expenses, and non-operating income (expense) for the year ended December 31, 2021, compared to the year ended December 31, 2020.
Revenue. Presented below is a comparison of our oil and natural gas sales, production quantities and average sales prices for the years ended December 31, 2021 and 2020 (dollars in thousands, except average sales prices):
| Change | ||||||||||||||||
| 2021 | 2020 | Amount | Percent | |||||||||||||
| Revenue: | ||||||||||||||||
| Oil | $ | 5,956 | $ | 2,127 | $ | 3,829 | 180 | % | ||||||||
| Gas | 702 | 203 | 499 | 246 | % | |||||||||||
| Total | $ | 6,658 | 2,330 | $ | 4,328 | 186 | % | |||||||||
| Production quantities: | ||||||||||||||||
| Oil (Bbls) | 93,722 | 60,469 | 33,253 | 55 | % | |||||||||||
| Gas (Mcfe) | 176,657 | 116,085 | 60,576 | 52 | % | |||||||||||
| BOE | 123,165 | 79,816 | 43,349 | 54 | % | |||||||||||
| Average sales prices: | ||||||||||||||||
| Oil (Bbls) | $ | 63.55 | $ | 35.18 | $ | 28.37 | 81 | % | ||||||||
| Gas (Mcfe) | 3.97 | 1.75 | 2.22 | 127 | % | |||||||||||
| BOE | 54.05 | 29.19 | 24.87 | 85 | % | |||||||||||
The increase in our oil sales of $3.8 million for the year ended December 31, 2021, compared to the prior year’s period resulted from a 55% increase in production quantities and an 81% increase in the average sales price received during 2021, compared to 2020. The increase in oil prices is primarily due to increased demand for crude oil on a global basis as restrictions that were in place as a result of the COVID-19 pandemic in 2020 were relaxed or repealed. The increase in oil production quantities is the result of an increase in production from our operated properties, which added 26,990 Bbls during 2021, specifically, the operated Gulf Coast Texas wells, which were acquired in December 2020 added 16,980 Bbls and the New Mexico and Wyoming operated wells added 9,805 Bbls. Most of our capital expenditures during 2021 were focused on returning idle wells in these areas to production. In addition, we realized production increases in our non-operated properties as operators in North Dakota and West Texas increased production by 10,708 Bbls during 2021 as compared to 2020, in response to higher prices. These increases were partially offset by a decrease in production from our South Texas properties of 4,366 Bbls due to natural production declines from wells drilled prior to 2020.
For the year ended December 31, 2021, we produced 123,165 BOE, or an average of 337 BOE per day, as compared to 79,816 BOE or 218 BOE per day in 2020. The increase in production is the result of the previously mentioned capital expenditures we performed in 2021 to return idle wells to production, primarily in our Gulf Coast Texas, Wyoming and New Mexico properties. These efforts increased BOE by 26,785. In addition, non-operated production in North Dakota and West Texas increased production by 23,515 BOE. These increases were partially offset by a decrease of 7,156 BOE in our non-operated South Texas and other regions.
Oil and Natural Gas Production Costs. Presented below is a comparison of our oil and natural gas production costs for the years ended December 31, 2021 and 2020 (in thousands):
| Change | ||||||||||||||||
| 2021 | 2020 | Amount | Percent | |||||||||||||
| Lease operating expenses | $ | 2,421 | $ | 1,535 | $ | 886 | 58 | % | ||||||||
| Production taxes | 471 | 168 | 303 | 180 | % | |||||||||||
| Total | $ | 2,892 | $ | 1,703 | $ | 1,189 | 70 | % | ||||||||
For the year ended December 31, 2021, lease operating expense increased by $866 thousand or 58% due to operating expenses of $695 thousand for wells acquired near the end of 2020 in the Gulf Coast Texas region. In addition, the operators of our non-operated properties in North Dakota performed workovers to increase production. During 2020, we, as well as operators of our non-operated properties, enacted cost cutting measures due to low commodity prices. Production taxes increased by $303 thousand or 180% compared to 2020. The increase in production taxes is the result of an increase in oil and natural gas revenues of 186%.
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Depreciation, Depletion and Amortization. Our DD&A rate for the year ended December 31, 2021 was $4.60 per BOE, compared to $5.09 per BOE for the year ended December 31, 2020. During 2021, our depletion rate was impacted by upward pricing revisions to our estimated proved reserves of 201,192 BOE due to an increase in the economic lives of certain wells. During 2020, our depletion rate was impacted by a reclassification of $2.1 million of our unevaluated properties and ceiling test write downs of $2.9 million. Our DD&A rate can fluctuate as a result of changes in drilling and completion costs, impairments, divestitures, changes in the mix of our production, the underlying proved reserve volumes and estimated costs to drill and complete proved undeveloped reserves.
Impairment of Oil and Natural Gas Properties. For the year ended December 31, 2021, we did not record a full cost ceiling limitation. For the year ended December 31, 2020, we recorded an impairment of $2.9 million due to the net capitalized cost of our oil and natural gas properties exceeding the full cost ceiling limitation.
General and Administrative Expenses. Presented below is a comparison of our general and administrative expenses for the years ended December 31, 2021 and 2020 (in thousands):
| Change | ||||||||||||||||
| 2021 | 2020 | Amount | Percent | |||||||||||||
| Compensation and benefits, including directors | $ | 2,622 | $ | 1,141 | $ | 1,481 | 130 | % | ||||||||
| Professional fees, insurance and other | 2,013 | 1,506 | 507 | 33 | % | |||||||||||
| Total | $ | 4,635 | $ | 2,647 | $ | 1,988 | 75 | % | ||||||||
General and administrative expenses increased by $1,988 thousand for the year ended December 31, 2021, as compared to the year ended December 31, 2020, primarily due to an increase in compensation and benefits. The increase was due to adding three employees, including our Vice President of Operations (who subsequently became our Chief Operating Officer in January 2022). In addition, amortization of stock-based compensation increased in 2021 by $338 thousand due to restricted stock grants to employees and directors in January 2021. In addition, the accrued performance bonuses increased $755 thousand in 2021 when compared to 2020. Professional fees increased by $507 thousand, primarily due to the settlement of litigation between us and our former Chief Executive Officer. Total amounts paid by us related to the litigation and settlement costs incurred in 2021 were $427 thousand, net of amounts received from our insurance carrier. See Litigation with Former Chief Executive Officer in Note 9—Commitments, Contingencies and Related-Party Transactions in the Notes to the Financial Statements included in Item 8 of this annual report on Form 10-K under “Financial Statements and Supplementary Data”. We expect an increase in General and administrative expenses in 2022 as we add employees and integrate properties acquired in January 2022. See Note 16-Subsequent Events.
Non-Operating Income (Expense). Presented below is a comparison of our non-operating income (expense) for the years ended December 31, 2021 and 2020 (in thousands):
| Change | ||||||||||||||||
| 2021 | 2020 | Amount | Percent | |||||||||||||
| Loss on real estate assets held for sale | (151 | ) | (1,054 | ) | 903 | 85 | % | |||||||||
| Commodity derivative loss, net | (260 | ) | - | (260 | ) | -100 | % | |||||||||
| Loss on marketable equity securities | 10 | (81 | ) | 91 | 112 | % | ||||||||||
| Warrant revaluation (loss) gain | 76 | (23 | ) | 99 | 430 | % | ||||||||||
| Rental property loss | 8 | (27 | ) | 35 | 130 | % | ||||||||||
| Other income | 39 | 88 | (49 | ) | -56 | % | ||||||||||
| Interest expense, net | (57 | ) | (14 | ) | (43 | ) | -307 | % | ||||||||
| Total non-operating expense | $ | (335 | ) | $ | (1,111 | ) | $ | 776 | 70 | % | ||||||
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During the year ended December 31, 2021, we sold our Riverton, Wyoming office building and land for net proceeds of $440 thousand and recorded a loss on real estate held for sale of $151 thousand. During the year ended December 2020, we reclassified the building and land to real estate held for sale. Concurrent with the reclassification we recognized a $651 thousand loss to adjust the carrying amount of the land and building to its estimated fair value of $725 thousand. We also recognized an additional $403 thousand loss to adjust the carrying amount of three land parcels adjacent to our building, to their estimated fair value of $250 thousand. We continue to hold the three land parcels and have classified them as held for sale. See Note 3—Real Estate Held for Sale in the Notes to the Financial Statements included in Item 8 of this annual report on Form 10-K under “Financial Statements and Supplementary Data.
During the year ended December 31, 2021, we realized a loss on our fixed-price swap commodity derivative contract of $260 thousand. In March 2021, we entered into the swap contract to fix the price of 100 barrels of crude oil at $61.90 per barrel from March 1, 2021 through December 31, 2021. The fixed-price swap contract represented approximately 32% of our 2021 oil production. The loss is related to the increase in the price of crude oil during the period.
During the year ended December 31, 2021, we recognized an unrealized gain on marketable equity securities of $10 thousand as compared to an unrealized loss of $81 thousand for the comparable period of 2020. The unrealized gain represents the increase in value of our investment in Anfield Energy, Inc. In July 2020, we sold 1,210,455 shares, representing one-third of our total investment for proceeds of $45 thousand.
During the year ended December 31, 2021, we recognized a warrant revaluation gain of $76 thousand as compared to a loss of $23 thousand during the year ended December 31, 2020. The current year gain was attributable to a decrease in the warrant liability, primarily as a result of the decrease in the value of our common stock. During the year ended December 31, 2020, 50,000 warrants were exercised. In March 2022, we received proceed of $196 thousand for the exercise of the remaining 50,000 warrants.
During the year ended December 31, 2021, we recognized a gain in other income of $25 thousand from the partial recovery of a deposit written off in 2018. For the year ended December 31, 2020, we recognized a $75 thousand gain related to the recovery of the same deposit.
Interest, net increased by $43 thousand during the year ended December 31, 2021, compared to the comparable period in 2020. On March 4, 2021, we entered into a Debt Conversion Agreement with APEG Energy II, L.P. (“APEG II”), which entity Patrick E. Duke, a former director of the Company, has shared voting power and shared investment power over APEG II. Pursuant to the agreement we repaid a note owed to APEG II and accrued interest to the maturity date by issuing 97,962 shares of common stock. See Note 7-Debt in the Notes to the consolidated financial statements included in this report.
Liquidity and Capital Resources
Based on the current commodity price environment and the derivative contracts that we have entered into we believe we have sufficient liquidity and capital resources to execute our business plan while continuing to meet our current financial obligations.
On January 5, 2022, we closed on an acquisition of certain oil and gas properties, representing a diversified, portfolio of primarily operated, producing, oil-weighted assets located across the Rockies, West Texas, Eagle Ford, and Mid-Continent. The acquisition is expected to generate significant cash flow. In connection with the acquisition, we entered into a five-year credit agreement with Firstbank Southwest as administrative agent for one or more lenders, which provides for a reserve-based, revolving line of credit with an initial borrowing base of $15 million. As of March 28, 2022, we have $3.5 million drawn on the facility, which was used to pay off debt we assumed in the acquisition, leaving us with available borrowing capacity of $11.5 million.
Also on January 5, 2022, we acquired derivative contracts, which were in a mark-to-market liability position of $3.2 million at the time of acquisition. The derivative contacts will be settled monthly in 2022 and 2023.
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The following table sets forth certain measures about our liquidity as of December 31, 2021 and 2020, in thousands:
| 2021 | 2020 | Change | ||||||||||
| Cash and equivalents | $ | 4,422 | $ | 2,854 | $ | 1,568 | ||||||
| Working capital surplus (1) | 3,233 | 2,499 | 734 | |||||||||
| Total assets | 17,663 | 12,363 | 5,300 | |||||||||
| Outstanding debt | - | 375 | (375 | ) | ||||||||
| Total shareholders’ equity | 13,435 | 8,567 | 4,868 | |||||||||
| Select Ratios: | ||||||||||||
| Current ratio (2) | 2.18 to 1.00 | 2.17 to 1.00 | ||||||||||
| Debt-to-equity ratio (3) | Not applicable | 0.04 to 1.00 | ||||||||||
| (1) | Working capital is computed by subtracting total current liabilities from total current assets. | |
| (2) | The current ratio is computed by dividing total current assets by total current liabilities. | |
| (3) | The debt-to-equity ratio is computed by dividing total debt by total shareholders’ equity. |
As of December 31, 2021, we had a working capital surplus of $3.2 million compared to a working capital surplus of $2.5 million as of December 31, 2020, an increase of $0.7 million. This increase was primarily attributable to the sale of 1,131,600 shares of our common stock in an underwritten offering at a public offering price of $5.10 per share on February 17, 2021. The net proceeds to us after deducting the underwriting discounts, commissions and offering expenses were approximately $5.3 million. Partially offsetting this amount were advance deposits of $1.5 million and transaction costs of $1.3 million paid in connection with the acquisition, which we completed on January 5, 2022.
As of December 31, 2021, we had cash and cash equivalents of $4.4 million and accounts payable and accrued liabilities of $1.4 million. As of March 25, 2022, we had cash and cash equivalents of $3.5 million and accounts payable and accrued liabilities of approximately $1.6 million.
Subsequent to December 31, 2021, we entered into the Credit Agreement and International Swap Dealers Association, Inc. Master Agreement and schedule thereto, which are described in greater detail above under “Item 1. Business —Recent Events— Credit Agreement; Hedging Agreement and Related Transactions”.
If we have needs for financing in 2022, alternatives that we will consider would potentially include, borrowing amounts on our credit facility, selling all or a partial interest in certain of our oil and natural gas assets, selling our marketable equity securities, issuing additional shares of our common stock for cash or as consideration for acquisitions in public or private offerings, and other alternatives, as we determine how to best fund our capital programs and meet our financial obligations.
Cash Flows
The following table summarizes our cash flows for the years ended December 31, 2021 and 2020 (in thousands):
| 2021 | 2020 | Change | ||||||||||
| Net cash provided by (used in): | ||||||||||||
| Operating activities | $ | (153 | ) | $ | (717 | ) | $ | 564 | ||||
| Investing activities | (3,325 | ) | (1,109 | ) | (2,216 | ) | ||||||
| Financing activities | 5,046 | 3,148 | 1,898 | |||||||||
Operating Activities. Cash used in operating activities for the year ended December 31, 2021, was $153 thousand as compared to cash used in operating activities of $0.7 million for 2020, a decrease of $0.6 million. The decrease in cash used in operating activities is mainly attributable to increases in cash receipts for revenues due to the acquisition of our Gulf Coast Texas properties in December 2020, which were partially offset by an increase in payments for operating and general and administrative expenses.
Investing Activities. Cash used in investing activities for the year ended December 31, 2021, was $3.3 million compared to cash used in investing activities of $1.1 million for 2020, an increase of $2.2 million. The primary use of cash in our investing activities for the year ended December 31, 2021, was attributable to $1.5 million in deposits to the sellers of the assets acquired in January 2022. We also paid $0.8 million in transaction costs related to the acquisition. In addition, we incurred capital expenditures for workovers related to returning idle wells to production in our Gulf Coast Texas field. The comparable number in 2020 mainly represents the amount paid for the acquisition of New Horizon and FieldPoint properties for net cash of $651 thousand and capitalized workovers to return idle wells to production in our Gulf Coast Texas field.
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Financing Activities. Cash provided by financing activities for the year ended December 31, 2021, was $5.0 million as compared to cash provided by financing activities of $3.1 million for the comparable period in 2020. The cash provided by financing activities during the year ended December 31, 2021, was primarily attributable to cash received of $5.3 million from the sale of 1.1 million shares of common stock in an underwritten offering which closed in February 2021, which was partially offset by payments on our premium finance note of $0.2 million. The comparable number in 2020 represents net proceeds of $4.5 million from the issuance of common stock, $0.6 million in proceeds from the exercise of stock purchase warrants, and $0.4 million from the related party note payable. These increases were partially offset by a cash payment of $2.0 million for the redemption of our Series A preferred stock and $0.2 million in payments on our note payable to finance insurance premiums.
Item 8. Financial Statements and Supplementary Data.
Financial statements meeting the requirements of Regulation S-X are included below.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures.
We are required to maintain disclosure controls and procedures (as defined by Rules 13a-15(e) and 15d-15(e) under the Exchange Act) that are designed to ensure that required information is recorded, processed, summarized and reported within the required timeframe, as specified in the rules of the SEC. Our disclosure controls and procedures are also designed to ensure that information required to be disclosed is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures.
Based on an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of our fiscal year ended December 31, 2021, our Chief Executive Officer and Chief Financial Officer determined that our disclosure controls and procedures were not effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.
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Management’s Report on Internal Control Over Financial Reporting.
Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act). We maintain a system of internal controls that is designed to provide reasonable assurance in a cost-effective manner as to the fair and reliable preparation and presentation of the consolidated financial statements in accordance with GAAP. Internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on our financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer (Principal Accounting/Financial Officer), our management conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2021. In making its assessment, our management used the criteria set forth in the “Internal Control – Integrated Framework” (2013 framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on the evaluation conducted under this framework, our management concluded that our internal control over financial reporting was not effective as of December 31, 2021, for the reasons described below.
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 the Company’s annual or interim financial statements will not be prevented or detected on a timely basis. In connection with our management’s assessment of our internal control over financial reporting as of December 31, 2021:
| ● | We had inadequate segregation of duties as a result of limited accounting staff and resources, which may impact our ability to prevent or detect material errors in our consolidated financial statements. | |
| ● | We had inadequate segregation of duties related to logical access to our accounting systems, which may affect our ability to prevent or detect material errors in the recorded transactions. | |
| ● | We did not have adequate controls to ensure the accuracy of the disclosures related to the accounting for and valuation of the acquisition completed subsequent to year end. |
Changes in Internal Control Over Financial Reporting.
There have been no changes to our system of internal control over financial reporting during the fiscal quarter ended December 31, 2021. Beginning in January 2022 and continuing through March 2022, we have added three additional experienced accounting personnel, including a controller and have implemented a new accounting system. We are also working towards segregation of duties controls, which may help remediate the material weakness related to inadequate segregation of duties as discussed above.
Limitations on the Effectiveness of Controls
The Company’s disclosure controls and procedures are designed to provide the Company’s Chief Executive Officer and Chief Financial Officer with reasonable assurances that the Company’s disclosure controls and procedures will achieve their objectives. However, the Company’s management does not expect that the Company’s disclosure controls and procedures or the Company’s internal control over financial reporting can or will prevent all human error. A control system, no matter how well designed and implemented, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Furthermore, the design of a control system must reflect the fact that there are internal resource constraints, and the benefit of controls must be weighed relative to their corresponding costs. Because of the limitations in all control systems, no evaluation of controls can provide complete assurance that all control issues and instances of error, if any, within the Company are detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur due to human error or mistake. Additionally, controls, no matter how well designed, could be circumvented by the individual acts of specific persons within the organization. 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 its stated objectives under all potential future conditions.
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Attestation Report of the Registered Public Accounting Firm
This report does not include an attestation report of our registered public accounting firm regarding our internal controls over financial reporting. Under SEC rules, such attestation is not required for smaller reporting companies such as the Company.
Item 9B – Other Information.
Because this Annual Report on Form 10-K is being filed within four business days from the date of the reportable events described below, we have elected to make the following disclosures in this Annual Report on Form 10-K instead of in a Current Report on Form 8-K under Item 1.01 Item 5.02 and Item 8.01:
Item 1.01 Entry into a Material Definitive Agreement.
On or around March 25, 2022, the Company entered into indemnification agreements, in substantially the form attached as Exhibit 10.35 to this Annual Report on Form 10-K (the “Indemnification Agreements”), with each director serving on the Company’s board of directors (the “Board”), and each current executive officer of the Company (each, an “Indemnitee”). Each Indemnification Agreement replaces and supersedes any prior indemnification agreement entered into between the Company and such Indemnitee to the extent such Indemnitee was a party to the Company’s prior form of indemnification agreement.
Each Indemnification Agreement provides that the Company shall indemnify to the fullest extent permitted by law if Indemnitee was or is or becomes a party to or witness or other participant in, or is threatened to be made a party to or witness or other participant in, any threatened, pending or completed action, suit, proceeding or alternative dispute resolution mechanism, or any hearing, inquiry or investigation that Indemnitee in good faith believes might lead to the institution of any such action, suit, proceeding or alternative dispute resolution mechanism, whether civil, criminal, administrative, investigative or other (a “Claim”) by reason of (or arising in part out of) any event or occurrence related to the fact that Indemnitee is or was a director, officer, employee, agent or fiduciary of the Company, or any subsidiary of the Company, or is or was serving at the request of the Company as a director, officer, employee, agent or fiduciary of another corporation, partnership, joint venture, trust or other enterprise, or by reason of any action or inaction on the part of Indemnitee while serving in such capacity (an “Indemnifiable Event”) against any and all expenses (including attorneys’ fees and all other costs, expenses and obligations incurred in connection with investigating, defending, being a witness in or participating in (including on appeal), or preparing to defend, be a witness in or participate in, any such action, suit, proceeding, alternative dispute resolution mechanism, hearing, inquiry or investigation), judgments, fines, penalties and amounts paid in settlement (if such settlement is approved in advance by the Company, which approval shall not be unreasonably withheld) of such Claim and any federal, state, local or foreign taxes imposed on Indemnitee as a result of the actual or deemed receipt of any payments under the Indemnification Agreement (collectively, “Expenses”), including all interest, assessments and other charges paid or payable in connection with or in respect of such Expenses, subject to certain requirements and determinations relating to an Indemnitee’s right to receive indemnification and advancement of Expenses as described in the Indemnification Agreement.
The foregoing description of the Indemnification Agreements is qualified in its entirety by reference to the full text of the Indemnification Agreement filed herewith as Exhibit 10.35 hereto.
Item 5.02 Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers.
The information included in Item 1.01 is incorporated by reference into this Item 5.02 by reference.
Item 8.01 Other Events.
On March 24, 2022, the Board of Directors of the Company adopted an amended and restated charter of the Nominating and Governance Committee, a copy of which is attached as Exhibit 99.2 hereto.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.
Not applicable.
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PART III
Information required by Items 10, 11, 12, 13 and 14 of Part III is omitted from this Annual Report and will be filed in a definitive proxy statement or by an amendment to this Annual Report not later than 120 days after the end of the fiscal year covered by this Annual Report.
Item 10. Directors, Executive Officers and Corporate Governance
The information required by this Item will be included in the Company’s 2022 Proxy Statement to be filed with the SEC within 120 days after December 31, 2021 in connection with the solicitation of proxies for the Company’s 2023 annual meeting of shareholders, including under the headings “Requirements and Deadlines for Shareholders to Submit Proposals”, “Election of Directors”, “Executive Officers”, “Corporate Governance”, “Code of Conduct”, “Committees of the Board”, and “Delinquent Section 16(a) Reports” (to the extent applicable and warranted) and is incorporated herein by reference.
Item 11. Executive Compensation.
The information required by this Item will be included in the Company’s 2022 Proxy Statement to be filed with the SEC within 120 days after December 31, 2021 in connection with the solicitation of proxies for the Company’s 2023 annual meeting of shareholders, including under the headings “Executive and Director Compensation”, “Executive Compensation”, “Directors Compensation”, “Outstanding Equity Awards at Fiscal Year-End”, “Compensation Committee Interlocks and Insider Participation” and “Compensation Committee Report” (to the extent required), and is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required by this Item will be included in the Company’s 2022 Proxy Statement to be filed with the SEC within 120 days after December 31, 2021 in connection with the solicitation of proxies for the Company’s 2023 annual meeting of shareholders, including under the heading “Principal Holders of Voting Securities and Ownership by Officers and Directors” and “Equity Compensation Plan Information” and is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
The information required by this Item will be included in the Company’s 2022 Proxy Statement to be filed with the SEC within 120 days after December 31, 2021 in connection with the solicitation of proxies for the Company’s 2023 annual meeting of shareholders, including under the headings “Certain Relationships and Related Transactions” and “Director Independence” and is incorporated herein by reference.
Item 14. Principal Accounting Fees and Services.
Our independent public accounting firm is Plante & Moran, PLLC, Denver, Colorado, PCAOB ID 166
The information required by this Item will be set forth under the heading “Ratification of Appointment of Independent Auditors”-“Principal Accounting Fees and Services” in the Company’s 2022 Proxy Statement to be filed with the SEC within 120 days after December 31, 2021 and is incorporated herein by reference.
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Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors of U.S. Energy Corp.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of U.S. Energy Corp. and Subsidiaries (the “Company”) as of December 31, 2021 and 2020, the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the years in the two-year period ended December 31, 2021, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
The Company’s management is responsible for these financial statements. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Emphasis of a Matter - Significant Subsequent Event
As discussed in Note 16 to the financial statements, on January 5, 2022, the Company acquired certain oil and gas properties, as well as assumed certain liabilities from (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”) for consideration including cash, the issuance of 19,905,736 shares of common stock and assumption of certain liabilities. Our opinion is not modified with respect to this matter.
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Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Impact of Proved Oil and Natural Gas Reserves on Oil and Natural Gas Properties - Refer to Notes 1 and 6 of the financial statements.
Critical Audit Matter Description
The Company’s net oil and natural gas properties balance was $8.5 million as of December 31, 2021, depreciation, depletion, and amortization expense was $0.5 million for the year ended December 31, 2021. The Company follows the full cost method of accounting for its oil and natural gas properties. The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center are subject to depreciation, depletion, and amortization using the equivalent unit-of-production method, based on total proved oil and natural gas reserves. Under the full cost method, net capitalized costs are limited to the lower of unamortized cost reduced by the related net deferred tax liability, or the cost center ceiling, as defined in Note 1. As disclosed by management, the proved oil and natural gas reserves used in the calculation of depreciation, depletion, amortization and the cost center ceiling test is a significant estimate and are inherently imprecise and subject to inherent uncertainties, including the future prices of oil and natural gas, which are expected to change as future information becomes available and such changes could be material. Management utilizes a specialist to estimate proved oil and natural gas reserves.
We identified the assessment of the impact of proved oil and natural gas reserves on depreciation, depletion, and amortization expense related to oil and natural gas properties as a critical audit matter. There are significant judgments by management, including the use and oversight of management’s specialist when developing the estimate of proved oil and natural gas reserves. In turn, performing audit procedures and evaluating audit evidence obtained related to these significant estimates and judgments required a high degree of judgment and effort.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures performed to address this critical audit matter included the following, among others:
| ● | We obtained an understanding of management’s process to develop estimates of proved oil and natural gas reserves. |
| ● | We tested the completeness and accuracy of the underlying information used by management in determining the estimate of proved oil and natural gas reserves and assessed the methodology used in estimating proved oil and natural gas reserves by management and its specialist. |
| ● | We evaluated the significant assumptions utilized by management in determining its estimate including commodity prices and price differentials, forecasted production, and estimated future operating costs. We also compared these assumptions to historical and actual results as well as publicly available prices and relevant historical differentials. |
| ● | We evaluated the work of management’s specialist by analyzing their objectivity, experience, and qualifications. |
/s/ Plante & Moran, PLLC
We have served as the Company’s auditor since 2018.
Denver, Colorado
March 28, 2022
| 65 |
U.S. ENERGY CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2021 AND 2020
(in thousands, except share and per share amounts)
| 2021 | 2020 | |||||||
| ASSETS | ||||||||
| Current assets: | ||||||||
| Cash and equivalents | $ | 4,422 | $ | 2,854 | ||||
| Oil and natural gas sales receivable | 933 | 514 | ||||||
| Marketable equity securities | 191 | 181 | ||||||
| Prepaid and other current assets | 179 | 184 | ||||||
| Real estate assets held for sale, net of selling costs | 250 | 975 | ||||||
| Total current assets | 5,975 | 4,708 | ||||||
| Oil and natural gas properties under full cost method: | ||||||||
| Unevaluated properties | 1,588 | 1,597 | ||||||
| Evaluated properties | 95,088 | 93,549 | ||||||
| Less accumulated depreciation, depletion, amortization and impairment | (88,195 | ) | (87,708 | ) | ||||
| Net oil and natural gas properties | 8,481 | 7,438 | ||||||
| Other assets: | ||||||||
| Pending acquisition | 2,767 | - | ||||||
| Property and equipment, net | 188 | 25 | ||||||
| Right of use asset | 120 | 127 | ||||||
| Other assets | 132 | 65 | ||||||
| Total other assets | 3,207 | 217 | ||||||
| Total assets | $ | 17,663 | $ | 12,363 | ||||
| LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||
| Current liabilities: | ||||||||
| Accounts payable and accrued liabilities | $ | 1,447 | $ | 1,457 | ||||
| Accrued compensation and benefits | 1,162 | 312 | ||||||
| Related party secured note payable | - | 375 | ||||||
| Warrant liability | 19 | - | ||||||
| Current lease obligation | 114 | 65 | ||||||
| Total current liabilities | 2,742 | 2,209 | ||||||
| Noncurrent liabilities: | ||||||||
| Asset retirement obligations | 1,461 | 1,408 | ||||||
| Warrant liability | - | 95 | ||||||
| Long-term lease obligation, net of current portion | 19 | 78 | ||||||
| Other noncurrent liabilities | 6 | 6 | ||||||
| Total noncurrent liabilities | 1,486 | 1,587 | ||||||
| Total liabilities | 4,228 | 3,796 | ||||||
| Commitments and contingencies (Note 9) | ||||||||
| Shareholders’ equity: | ||||||||
| Common stock, $ par value; shares authorized; and shares issued and outstanding as of December 31, 2021 and 2020, respectively | 47 | 33 | ||||||
| Additional paid-in capital | 149,276 | 142,652 | ||||||
| Accumulated deficit | (135,888 | ) | (134,118 | ) | ||||
| Total shareholders’ equity | 13,435 | 8,567 | ||||||
| Total liabilities and shareholders’ equity | $ | 17,663 | $ | 12,363 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
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U.S. ENERGY CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2021 and 2020
(in thousands, except share and per share amounts)
| 2021 | 2020 | |||||||
| Revenue: | ||||||||
| Oil | $ | 5,956 | $ | 2,127 | ||||
| Natural gas and liquids | 702 | 203 | ||||||
| Total revenue | 6,658 | 2,330 | ||||||
| Operating expenses: | ||||||||
| Oil and natural gas operations: | ||||||||
| Lease operating expense | 2,421 | 1,535 | ||||||
| Production taxes | 471 | 168 | ||||||
| Depreciation, depletion, accretion and amortization | 566 | 407 | ||||||
| Impairment of oil and natural gas properties | - | 2,943 | ||||||
| General and administrative: | ||||||||
| Compensation and benefits | 2,622 | 1,141 | ||||||
| Professional fees, insurance and other | 2,013 | 1,506 | ||||||
| Total operating expenses | 8,093 | 7,700 | ||||||
| Operating Loss | (1,435 | ) | (5,370 | ) | ||||
| Other income (expense): | ||||||||
| Loss on real estate held for sale | (151 | ) | (1,054 | ) | ||||
| Commodity derivative loss | (260 | ) | - | |||||
| Gain (loss) on marketable equity securities | 10 | (81 | ) | |||||
| Warrant revaluation gain (loss) | 76 | (23 | ) | |||||
| Rental and other income (loss) | 8 | (27 | ) | |||||
| Recovery of deposit | - | 75 | ||||||
| Other income | 39 | 13 | ||||||
| Interest expense, net | (57 | ) | (14 | ) | ||||
| Total other expense | (335 | ) | (1,111 | ) | ||||
| Loss before income taxes | $ | (1,770 | ) | (6,481 | ) | |||
| Income tax benefit | - | 42 | ||||||
| Net loss | $ | (1,770 | ) | $ | (6,439 | ) | ||
| Preferred stock dividends | $ | $ | 20 | |||||
| Net loss applicable to common shareholders | $ | (1,770 | ) | $ | (6,419 | ) | ||
| Basic and diluted weighted average shares outstanding | 4,491,984 | 1,627,517 | ||||||
| Basic and diluted net loss per share | $ | (0.39 | ) | $ | (3.94 | ) | ||
The accompanying notes are an integral part of these consolidated financial statements.
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U.S. ENERGY CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2021 and 2020
(in thousands, except share amounts)
| Additional | ||||||||||||||||||||
| Common Stock | Paid-in | Accumulated | ||||||||||||||||||
| Shares | Amount | Capital | Deficit | Total | ||||||||||||||||
| Balances, December 31, 2019 | 1,340,583 | $ | 13 | $ | 136,876 | $ | (127,679 | ) | $ | 9,210 | ||||||||||
| Settlement of fractional shares in cash | (327 | ) | - | (1 | ) | - | (1 | ) | ||||||||||||
| Shares issued for acquisition of New Horizon Resources | 59,498 | 1 | 239 | - | 240 | |||||||||||||||
| Shares issued for acquisition of Liberty County properties | 67,254 | 1 | 284 | 285 | ||||||||||||||||
| Shares issued for transaction costs in FieldPoint acquisition | 7,075 | - | 29 | 29 | ||||||||||||||||
| Issuance of shares in registered direct offering, net of offering costs of $158 | 315,810 | 3 | 1,496 | 1,499 | ||||||||||||||||
| Issuance of shares in underwritten offering, net of offering costs of $482 | 1,150,000 | 11 | 2,957 | 2,968 | ||||||||||||||||
| Exercise of stock warrants | 50,000 | 1 | 564 | 565 | ||||||||||||||||
| Adjustment of Series A Preferred Stock to redemption value (Note 10) | - | - | (1,207 | ) | (1,207 | ) | ||||||||||||||
| Issuance of shares for redemption of Series A Preferred Stock | 328,000 | 3 | 1,204 | - | 1,207 | |||||||||||||||
| Share-based compensation | - | - | 211 | - | 211 | |||||||||||||||
| Net loss | - | - | - | (6,439 | ) | (6,439 | ) | |||||||||||||
| Balances, December 31, 2020 | 3,317,893 | $ | 33 | $ | 142,652 | $ | (134,118 | ) | $ | 8,567 | ||||||||||
| Issuance of shares in underwritten offering, net of offering costs of $488 | 1,131,600 | 11 | 5,272 | - | 5,283 | |||||||||||||||
| Issuance of shares for related party secured note payable conversion | 97,962 | 1 | 437 | - | 438 | |||||||||||||||
| Issuance of shares for settlement of related party legal costs | 90,846 | 1 | 405 | 406 | ||||||||||||||||
| Issuance of shares upon vesting of restricted stock awards | 47,000 | 1 | (1 | ) | - | |||||||||||||||
| Shares withheld to settle tax withholding obligations for restricted stock awards | (9,000 | ) | - | (38 | ) | (38 | ) | |||||||||||||
| Stock-based compensation | - | - | 549 | 549 | ||||||||||||||||
| Net loss | - | - | - | (1,770 | ) | (1,770 | ) | |||||||||||||
| Balances, December 31, 2021 | 4,676,301 | $ | 47 | $ | 149,276 | $ | (135,888 | ) | $ | 13,435 | ||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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U.S. ENERGY CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2021 AND 2020
(in thousands)
| 2021 | 2020 | |||||||
| Cash flows from operating activities: | ||||||||
| Net loss | $ | (1,770 | ) | $ | (6,439 | ) | ||
| Adjustments to reconcile net loss to net cash provided by (used in) operating activities: | ||||||||
| Depreciation, depletion, accretion, and amortization | 589 | 467 | ||||||
| Impairment of oil and gas properties | - | 2,943 | ||||||
| Loss on real estate assets held for sale | 151 | 1,054 | ||||||
| Change in fair value of warrants | (76 | ) | 23 | |||||
| (Gain) loss on marketable equity securities | (10 | ) | 81 | |||||
| Loss on related party debt conversion and settlement of legal costs | 76 | - | ||||||
| Stock-based compensation | 549 | 211 | ||||||
| Right of use asset amortization | 90 | 53 | ||||||
| Changes in operating assets and liabilities: | ||||||||
| Decrease (increase) in: | ||||||||
| Oil and natural gas sales receivable | (419 | ) | 214 | |||||
| Other assets | 141 | 153 | ||||||
| Increase (decrease) in: | ||||||||
| Accounts payable accrued liabilities | (125 | ) | 461 | |||||
| Accrued compensation and benefits | 850 | 120 | ||||||
| Payments on operating lease liability | (92 | ) | (58 | ) | ||||
| Payments of asset retirement obligations | (107 | ) | - | |||||
| Net cash used in operating activities | (153 | ) | (717 | ) | ||||
| Cash flows from investing activities: | ||||||||
| Acquisition of oil and natural gas properties, net of cash acquired | - | (699 | ) | |||||
| Expenditures for pending acquisition | (2,221 | ) | - | |||||
| Oil and gas properties capital expenditures | (1,408 | ) | (475 | ) | ||||
| Property and equipment additions | (196 | ) | - | |||||
| Proceeds from sale of marketable equity securities | - | 45 | ||||||
| Proceeds from sale of oil and natural gas properties | 40 | - | ||||||
| Proceeds from sale of real estate | 440 | - | ||||||
| Payment received on notes receivable | 20 | 20 | ||||||
| Net cash used in investing activities: | (3,325 | ) | (1,109 | ) | ||||
| Cash flows from financing activities: | ||||||||
| Issuance of common stock, net of fees | 5,283 | 4,468 | ||||||
| Proceeds from warrant exercise | - | 565 | ||||||
| Proceeds from related party secured note payable | - | 375 | ||||||
| Redemption of Series A Preferred Stock | - | (2,000 | ) | |||||
| Payments on insurance premium finance note | (199 | ) | (198 | ) | ||||
| Payments on credit facility | - | (61 | ) | |||||
| Payment for fractional shares in reverse stock split | - | (1 | ) | |||||
| Shares withheld to settle tax withholding obligations for restricted stock awards | (38 | ) | - | |||||
| Net cash provided by financing activities | 5,046 | 3,148 | ||||||
| Net increase in cash and equivalents | 1,568 | 1,322 | ||||||
| Cash and equivalents, beginning of year | 2,854 | 1,532 | ||||||
| Cash and equivalents, end of year | $ | 4,422 | $ | 2,854 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
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U.S. ENERGY CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS, Continued
FOR THE YEARS ENDED DECEMBER 31, 2021 AND 2020
(in thousands)
| 2021 | 2020 | |||||||
| Supplemental disclosures of cash flow information and non-cash activities: | ||||||||
| Cash payments for interest | $ | 5 | $ | 5 | ||||
| Investing activities: | ||||||||
| Change in capital expenditure accruals | 626 | (21 | ) | |||||
| Issuance of stock for acquisitions | - | 554 | ||||||
| Prepaid rent liability netted with proceeds on sale of real estate | 143 | - | ||||||
| Asset retirement obligations | (45 | ) | 558 | |||||
| Asset retirement obligations sold /plugged | 70 | 12 | ||||||
| Operating lease liability and right of use asset | 82 | - | ||||||
| Financing activities: | ||||||||
| Shares issued in redemption of Series A preferred stock | - | 1,207 | ||||||
| Issuance of stock for conversion of related party secured note payable | 438 | - | ||||||
| Issuance of stock for settlement of related party legal costs | 406 | - | ||||||
| Financing of insurance premiums with accrued payable | 223 | 198 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
| 70 |
U.S. ENERGY CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION, OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES
Organization and Operations
U.S. Energy Corp. (collectively with its wholly owned subsidiaries, Energy One LLC and New Horizon Resources, LLC, referred to as the “Company” in these Notes to Consolidated Financial Statements) was incorporated in the State of Wyoming on January 26, 1966. The Company’s principal business activities are focused on the acquisition, exploration and development of oil and natural gas properties in the United States. On January 5, 2022, the Company closed the acquisitions of certain oil and gas properties from three separate sellers, representing a diversified portfolio of primarily operated, producing, oil-weighted assets located across the Rockies, West Texas, Eagle Ford, and Mid-Continent see Note 16-Subsequent Events.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles in the United States (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates include oil and natural gas reserves that are used in the calculation of depreciation, depletion, amortization and impairment of the carrying value of evaluated oil and natural gas properties; realizability of unevaluated properties; production and commodity price estimates used to record accrued oil and natural gas sales receivables; valuation of real estate assets held for sale; and the cost of future asset retirement obligations. The Company evaluates its estimates on an on-going basis and bases its estimates on historical experience and on various other assumptions the Company believes to be reasonable. Due to inherent uncertainties, including the future prices of oil and natural gas, these estimates could change in the near term and such changes could be material.
Principles of Consolidation
The accompanying financial statements include the accounts of U.S. Energy Corp. and its wholly owned subsidiaries Energy One LLC (“Energy One”) and New Horizon Resources LLC (“New Horizon”). All inter-company balances and transactions have been eliminated in consolidation.
Industry Segment and Geographic Information
The Company operates in the exploration and production segment of the oil and gas industry, onshore in the United States. The Company reports as a single industry segment.
Cash and Equivalents
The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents.
Oil and Natural Gas Sales Receivable
The Company’s oil and natural gas sales receivable consist of receivables from joint interest operators for the Company’s share of oil, natural gas, and natural gas liquids (“NGLs”) sales and purchasers of the Company’s operated production, Generally, the Company’s oil and natural gas sales receivables from joint interest operators is collected within three months. The Company’s operated production is collected the month following production. The Company has had minimal bad debts related to oil and natural gas sales. Although diversified among several joint interest operators and first purchasers, collectability is dependent upon the financial wherewithal of each joint interest operator or first purchaser and is influenced by the general economic conditions of the industry. Receivables are not collateralized. As of December 31, 2021, and 2020, the Company had not provided an allowance for doubtful accounts on its oil and natural gas sales receivable.
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Concentration of Credit Risk
The Company has exposure to credit risk in the event of nonpayment of oil and natural gas receivables by purchasers of the Company’s share of oil and natural gas production and its operated production. The following table presents the purchasers that accounted for 10% or more of the Company’s total oil and natural gas revenue for at least one of the periods presented:
| Operator | 2021 | 2020 | ||||||
| Zavanna, LLC | 34 | % | 41 | % | ||||
| Infinity Hydrocarbons | 30 | % | 6 | % | ||||
| CML Exploration, LLC | 10 | % | 25 | % | ||||
Marketable Equity Securities
Marketable equity securities are reported at fair value based on end of period quoted prices. Changes in fair value are recorded in the consolidated statements of operations at the end of each reporting period. Gains or losses from sales of marketable equity securities are recorded in the consolidated statements of operations when realized.
Oil and Natural Gas Properties
The Company follows the full cost method of accounting for its oil and natural gas properties. 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 property 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 are subject to depreciation, depletion and amortization (“DD&A”) using the equivalent unit-of-production method, based on total proved oil and natural gas reserves. For financial statement presentation, DD&A includes accretion expense related to asset retirement obligations. Excluded from amounts subject to DD&A are costs associated with unevaluated properties.
Under the full cost method, net capitalized costs are limited to the lower of unamortized cost reduced by the related net deferred tax liability, or the cost center ceiling (the “Ceiling Test”). 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 average prices per barrel of oil and per Mcf of natural gas at the first day of each month in the 12-month period prior to the end of the reporting period; and costs, adjusted for contract provisions and financial derivatives qualifying as accounting hedges and asset retirement obligations, (ii) the cost of unevaluated properties not being amortized, and (iii) the lower of cost or market value of unproved properties included in the cost being amortized, reduced by (iv) the income tax effects related to differences between the book and tax basis of the crude oil and natural gas properties. If the net book value reduced by the related net deferred income tax liability (if any) exceeds the cost center ceiling limitation, a non-cash impairment charge is required in the period in which the impairment occurs. Since all of the Company’s oil and natural gas properties are located within the United States, the Company only has one cost center for which a quarterly Ceiling Test is performed.
Acquisitions
The Company accounts for acquisitions as business combinations if the acquired assets meet the definition of a business. If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar assets, the acquisition is not considered a business and is accounted for as an asset acquisition. This determination of whether the gross assets acquired are concentrated in a group of similar assets is based on whether the risks associated with managing and creating outputs from the assets are similar.
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Property and Equipment
Land, buildings, and building improvements are classified as held for sale and are carried at the estimated realizable value, less costs to sell. Long-lived assets are classified as held for sale when the Company commits to a plan to sell the assets. Such assets are classified within current assets if there is reasonable certainty that the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to determine if there is any excess of carrying value over fair value less costs to sell. Subsequent changes to estimated fair value less the cost to sell will impact the measurement of assets held for sale if the fair value is determined to be less than the carrying value of the assets.
Administrative assets are carried at cost. Depreciation of administrative assets is provided principally by the straight-line method over estimated useful lives as follows:
| Years | |||
| Administrative assets: | |||
| Computers and software | 3 | ||
| Office furniture and equipment | 5 | ||
| Autos and trucks | 5 | ||
| Other equipment | 10 |
Impairment of Long-Lived Assets
The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the related carrying amount may not be recoverable. If estimated future cash flows, on an undiscounted basis, are less than the carrying amount of the related asset, an asset impairment charge is recognized, and measured as the amount by which the carrying value exceeds the estimated fair value. Changes in significant assumptions underlying future cash flow estimates may have a material effect on the Company’s financial position and results of operations.
Derivative Financial Instruments
The Company periodically enters into commodity derivative instruments to mitigate a portion of its exposure to oil price volatility for its expected future oil production. The Company does not designate commodity derivative contracts as cash flow hedges, and therefore the contracts do not qualify for hedge accounting. Changes in fair value of derivative contracts are recorded in the consolidated statement of operations. The fair value of derivative contracts is recorded as either an asset or a liability on the consolidated balance sheet.
Warrant Liability
The Company has classified the warrants as liabilities due to provisions in the warrant agreement that precluded equity classification, including an option of the holder to receive the calculated fair value of the warrant from the Company in cash in the event of a “Fundamental Transaction,” as defined in the warrant agreement. Changes in fair value are reported each period in the consolidated statements of operations.
Asset Retirement Obligations
The Company records the estimated fair value of restoration and reclamation liabilities related to its oil and natural gas properties as of the date that the liability is incurred. The Company reviews the liability each quarter and determines if a change in estimate is required, and accretion of the discounted liability is recorded based on the passage of time. Final determinations are made during the fourth quarter of each year. The Company deducts any actual funds expended for restoration and reclamation during the quarter in which it occurs.
Stock-Based Compensation
The Company measures the cost of employee and director services received in exchange for all equity awards granted, including stock options, based on the fair value of the award as of the grant date. The Company computes the fair values of its options granted to employees using the Black-Scholes option pricing model. The Company recognizes the cost of the equity awards over the period during which an employee is required to provide services in exchange for the award, usually the vesting period.
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Income Taxes
The Company recognizes deferred income tax assets and liabilities for the expected future income tax consequences, based on enacted tax laws, of temporary differences between the financial reporting and tax bases of assets, liabilities and carry forwards.
Additionally, the Company recognizes deferred tax assets for the expected future effects of all deductible temporary differences, loss carry forwards and tax credit carry forwards. Deferred tax assets are reduced, if deemed necessary, by a valuation allowance for any tax benefits that, based on current circumstances, are not expected to be realized. At December 31, 2021 and 2020, management believed it was more likely than not that such tax benefits would not be realized and a valuation allowance has been provided. In assessing the need for a valuation allowance for the Company’s deferred tax assets, a significant item of negative evidence considered was the cumulative book loss over the three-year period ended December 31, 2021.
The Company assesses its uncertain tax positions annually. The Company recognizes the tax benefit from an uncertain tax position only if it is probable that the tax position will be sustained on examination by taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that is probable of being realized upon ultimate settlement. The amount of unrecognized tax benefits is adjusted as appropriate for changes in facts and circumstances, such as significant amendments to existing tax law, new regulations or interpretations by the taxing authorities, new information obtained during a tax examination, or resolution of an examination.
Basic net income (loss) per share is computed based on the weighted average number of common shares outstanding. Diluted net income (loss) per share is calculated by dividing net income or loss by the diluted weighted average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of in-the-money outstanding stock options, warrants and restricted stock, and prior to the redemption of such preferred stock on December 31, 2020, the Series A Convertible Preferred Stock. When there is a loss from continuing operations, all potentially dilutive shares are anti-dilutive and are excluded from the calculation of net income (loss) per share. The treasury stock method is used to measure the dilutive impact of in-the-money stock options.
Recent Accounting Pronouncements
There were no significant new accounting standards adopted or new accounting pronouncements issued that would have a potential effect on the Company of December 31, 2021.
2. ACQUISITIONS
Pending Acquisition
At December 31, 2021, the Company was in the process of closing acquisitions of assets contemplated by the October 4, 2021, purchase and sale agreements (as amended) with (a) Lubbock Energy Partners LLC, (b) Banner Oil & Gas, LLC, Woodford Petroleum, LLC and Llano Energy, LLC (collectively Banner) and (c) Synergy Offshore LLC. The acquisition closed on January 5, 2022. See Note 16- Subsequent Events. At December 31, 2021, amounts incurred for the pending acquisition relate to payment of deposits totaling $1.5 million and transaction costs of $1.3 million. The amounts are included in other assets in the accompanying consolidated balance sheet.
New Horizon Resources
On March 1, 2020, the Company acquired all the issued and outstanding equity interests of New Horizon. Its assets include acreage and operated producing properties in North Dakota (the “New Horizon Properties”). The Company accounted for the acquisition of the New Horizon Properties as a business combination. The consideration paid at closing consisted of shares of the Company’s common stock, $150,000 in cash and the assumption of certain liabilities (the “New Horizon Acquisition”). The New Horizon Acquisition gives the Company operated properties in its core area of operations. The New Horizon Properties consist of nine gross wells (five net wells), and approximately 1,300 net acres located primarily in McKenzie and Divide Counties, North Dakota, which are 100% held by production and average a 63% working interest.
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| Amount | ||||
| (in thousands) | ||||
| Fair value of net assets: | ||||
| Proved oil and natural gas properties | $ | 564 | ||
| Other current assets | 14 | |||
| Other long-term assets | 58 | |||
| Total assets acquired | 636 | |||
| Asset retirement obligations | (163 | ) | ||
| Current payables | (50 | ) | ||
| Credit facility | (61 | ) | ||
| Net assets acquired | $ | 362 | ||
| Fair value of consideration paid for net assets: | ||||
| Cash consideration | $ | 150 | ||
| Issuance of common stock ( shares at $ per share) | 240 | |||
| Cash acquired | (28 | ) | ||
| Total fair value of consideration transferred | $ | 362 | ||
For the years ended December 31, 2021 and 2020, the Company recorded revenues of approximately $204 thousand and $101 thousand, respectively, and lease operating and workover expenses of approximately $88 thousand and $231 thousand, respectively, related to the New Horizon Properties. Assuming that the acquisition of the New Horizon properties had occurred on January 1, 2020, the Company would have recorded revenues of $132 thousand and expenses of $252 thousand for the year ended December 31, 2020. These results are not necessarily indicative of the results that would have occurred had the Company completed the acquisition on the date indicated, or that will be attained in the future. Subsequent to the closing of the New Horizon Acquisition, the Company repaid the outstanding liabilities assumed at closing.
Acquisition of FieldPoint Properties
On September 25, 2020, the Company acquired certain oil and gas properties primarily located in Lea County, New Mexico and Converse County, Wyoming. The properties were acquired from FieldPoint Petroleum Corporation (“FieldPoint”) pursuant to FieldPoint’s Chapter 7 bankruptcy process (the “FieldPoint Properties”). The Company accounted for the acquisition of the FieldPoint Properties as an asset acquisition. The total amount paid for the FieldPoint Properties as of December 31, 2020, was $597 thousand, which includes the purchase price of $500 thousand and transaction costs of $97 thousand of which $29 thousand were paid via the issuance of shares of the Company’s common stock. The Company also recorded purchase price adjustments of $31 thousand for net revenues received, less operating expense related to periods prior to the closing of the transaction. In addition, the Company recorded asset retirement obligations of $203 thousand for the assets acquired. Substantially all of the value of the acquired FieldPoint Properties consists of mature proved developed producing reserves. Following is a summary of the amounts recorded for the assets acquired:
| Amount | ||||
| (in thousands) | ||||
| Amounts incurred: | ||||
| Cash consideration | $ | 500 | ||
| Transaction costs | 97 | |||
| Purchase price adjustments | (31 | ) | ||
| Total consideration paid | 566 | |||
| Asset retirement obligations assumed | 203 | |||
| Total amount incurred | $ | 769 | ||
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Acquisition of Liberty County Properties
On November 9, 2020, the Company entered into a Purchase and Sale Agreement (the “PSA”) to acquire certain assets from Newbridge Resources LLC (“Newbridge”). The transaction closed on December 1, 2020 with an effective date of November 1, 2020. The assets include operated producing properties in Liberty County, Texas (the “Liberty County Properties”). The Liberty County Properties include 41 wells which have a 100% working interest and an average 86% net revenue interest and approximately 680 net acres located primarily in Liberty County, Texas which are 100% held by production. The Company issued shares of its common stock, which at the closing price of $ on the date of the closing of the PSA were valued at $285 thousand, in consideration for the acquisition. The Company accounted for the acquisition of the Liberty County Properties as an asset acquisition. The total amount paid as of December 31, 2020, was $326 thousand including transaction costs of $41 thousand. In addition, the Company recorded asset retirement obligations of $192 thousand for the assets acquired. Substantially all of the value of the Liberty County Properties acquired consists of mature proved developed producing reserves and proved developed non-producing reserves. Following is a summary of the amounts recorded for the assets acquired:
| Amount | ||||
| (in thousands) | ||||
| Amounts incurred: | ||||
| Value of shares issued | $ | 285 | ||
| Transaction costs | 41 | |||
| Total consideration paid | 326 | |||
| Asset retirement obligations assumed | 192 | |||
| Total amount incurred | $ | 518 | ||
3. REAL ESTATE HELD FOR SALE
During the year ended December 31, 2021, the Company completed the sale of its 30,400 square foot office building and the related 14-acre tract in Riverton, Wyoming, which was classified as held for sale. The Company received net proceeds of $440 thousand and recorded a loss on the sale of the property of $151 thousand. For the year ended December 31, 2020, the Company recorded an impairment of $651 thousand related to the property.
The Company continues to hold approximately 13 acres of land in Riverton, Wyoming with an estimated fair value, net of selling costs of $250 thousand, which is classified as held for sale at December 31, 2021. During the year ended December 31, 2020, the Company recorded impairment of $403 thousand related to the land.
4. REVENUE RECOGNITION
The Company’s revenues are primarily derived from its non-operated interest in the sales of oil and natural gas production. The sales of oil and natural gas are made under contracts that operators of the wells have negotiated with third-party customers. The Company receives payment from the sale of oil and natural gas production between one to three months after delivery. At the end of each period when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in oil and natural gas sales receivable in the consolidated balance sheets. Variances between the Company’s estimated revenue and actual payments are recorded in the month the payment is received. Accordingly, the variable consideration is not constrained. For the properties in which the Company holds non-operated interest, the Company records its share of the revenues and expenses based upon the information provided by the operators within the revenue statements.
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The Company’s oil and natural gas production is typically sold at delivery points to various purchasers under contract terms that are common in the oil and natural gas industry. Regardless of the contract type, the terms of these contracts compensate the well operators for the value of the oil and natural gas at specified prices, and then the well operators remit payment to the Company for its share in the value of the oil and natural gas sold.
During 2020, the Company acquired operated oil and gas producing properties (see Note 2- Acquisitions, above). The Company sells its oil production at the delivery point specified in the contract and collects an agreed-upon index price, net of pricing differentials. The purchaser takes custody, title, and risk of loss of the oil at the delivery point; therefore, control passes at the delivery point. The Company recognizes revenue at the net price received when control transfers to the purchaser. Natural gas and natural gas liquids (“NGL”) are sold at the lease location, which is generally when control of the natural gas and NGL transfers to the purchaser, and revenue is recognized as the amount received from the purchaser.
The Company does not disclose the values of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption in accordance with Accounting Standards Codification (ASC) 606. The exemption applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to the remaining performance obligations is not required.
The Company reports revenue as the gross amount received from the well operators before taking into account production taxes and transportation costs. Production taxes are reported separately and transportation costs are included in lease operating expense in the accompanying consolidated statements of operations. The revenue and costs in the consolidated statements of operations were reported gross for the years ended December 31, 2021 and 2020, as the gross amounts were known.
The Company disaggregates revenues from its share of revenue from the sale of oil and natural gas and liquids by state. The Company’s revenues in its North Dakota, Texas, New Mexico and other states for the years ended December 31, 2021 and 2020, are presented in the following table:
| Year
Ended December 31, | ||||||||
| 2021 | 2020 | |||||||
| (in thousands) | ||||||||
| Revenue: | ||||||||
| North Dakota | ||||||||
| Oil | $ | 2,538 | $ | 1,240 | ||||
| Natural gas and liquids | 391 | 102 | ||||||
| Total | 2,929 | 1,342 | ||||||
| Texas | ||||||||
| Oil | 2,729 | 875 | ||||||
| Natural gas and liquids | 312 | 82 | ||||||
| Total | 3,041 | 957 | ||||||
| New Mexico | ||||||||
| Oil | 348 | - | ||||||
| Natural gas and liquids | - | - | ||||||
| Total | 348 | - | ||||||
| Other | ||||||||
| Oil | 341 | 12 | ||||||
| Natural gas and liquids | (1 | ) | 19 | |||||
| Total | 340 | 31 | ||||||
| Combined Total | $ | 6,658 | $ | 2,330 | ||||
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5. LEASES
During the year ended December 31, 2021, the Company acquired right-of-use assets and operating lease liability of $82 thousand associated with entering into a non-cancellable, long-term lease agreement for office space in Houston, Texas. The Company’s right-of-use assets and lease liabilities are recognized at their discounted present value under the following captions in the consolidated balance sheets at December 31, 2021 and 2020:
| December 31, | ||||||||
| 2021 | 2020 | |||||||
| (in thousands) | ||||||||
| Right of use asset balance | ||||||||
| Operating lease | $ | 120 | $ | 127 | ||||
| Lease liability | ||||||||
| Short-term operating lease | 114 | 65 | ||||||
| Long-term operating lease | 19 | 78 | ||||||
| $ | 133 | $ | 143 | |||||
The Company recognizes lease expense on a straight-line basis excluding short-term and variable lease payments, which are recognized as incurred. Short-term lease costs represent payments for our Houston, Texas office lease, prior to February 2021, when the Company entered into a new 25-month lease for its Houston office. Beginning in March 2020, the Company subleased its Denver, Colorado office and recognizes sublease income as a reduction of rent expense. Following are the amounts recognized as components of rental expense for the years ended December 31, 2021 and 2020:
| December 31, | ||||||||
| 2021 | 2020 | |||||||
| (in thousands) | ||||||||
| Operating lease cost | $ | 125 | 74 | |||||
| Short-term lease cost | 9 | 22 | ||||||
| Sublease income | (64 | ) | (41 | ) | ||||
| Total lease costs | $ | 70 | $ | 55 | ||||
The Company’s Denver and Houston office operating leases do not contain implicit interest rates that can be readily determined; therefore, the Company used the incremental borrowing rates in effect at the time the Company entered into the leases.
| As of December 31, | ||||||||
| 2021 | 2020 | |||||||
| Weighted average lease term (years) | 1.1 | 2.1 | ||||||
| Weighted average discount rate | 9.26 | % | 8.75 | % | ||||
| December 31, 2021 | ||||
| (in thousands) | ||||
| 2022 | 122 | |||
| 2023 | 18 | |||
| Total lease payments | $ | 140 | ||
| Less: imputed interest | (7 | ) | ||
| Total lease liability | $ | 133 | ||
As discussed in Note 3- Real Estate Held for Sale, the Company owned a 14-acre tract in Riverton, Wyoming with a two-story, 30,400 square foot office building, which was sold in August 2021. During the year ended December 31, 2021, the Company recognized a $151 thousand loss on the sale of the building and land. The Company recognized a loss during the year ended December 31, 2020 of $651 thousand related to the building and land subject to the operating leases. The building was not depreciated while held for sale.
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The Company recognized, as a component of rental property income (loss), the following operating lease income and expenses related to its Riverton, Wyoming office building for the years ended December 31, 2021 and 2020:
| Year
Ended December 31, | ||||||||
| 2021 | 2020 | |||||||
| (in thousands) | ||||||||
| Operating lease income | $ | 131 | $ | 213 | ||||
| Operating lease expense | (123 | ) | (181 | ) | ||||
| Depreciation | - | (59 | ) | |||||
| Rental property income (loss), net | $ | 8 | $ | (27 | ) | |||
6. OIL AND NATURAL GAS PRODUCING ACTIVITIES
Divestitures
During the year ended December 31, 2021, the Company divested an operated well in North Dakota for proceeds of $10 thousand and assumption of asset retirement obligations of $53 thousand. In addition, the Company sold approximately 12 acres of undeveloped acreage in Midland County, Texas for total proceeds of approximately $30 thousand. The proceeds from divestitures of $40 thousand were recorded as a reduction in full cost pool. There were no divestures of oil and natural gas producing properties during the year ended December 31, 2020.
Ceiling Test and Impairment
The reserves used in the ceiling test incorporate assumptions regarding pricing and discount rates over which management has no influence in the determination of present value. In the calculation of the ceiling test as of December 31, 2021, the Company used $66.56 per barrel for oil and $3.60 per one million British Thermal Units (MMbtu) for natural gas (as further adjusted for property, specific gravity, quality, local markets and distance from markets) to compute the future cash flows of the Company’s producing properties. The discount factor used was 10%.
For the year ended December 31, 2021, the Company did not have a ceiling test write down of its oil and natural gas properties. During the year ended December 31, 2020, the Company recorded ceiling test write-downs of its oil and natural gas properties of $2.9 million due to a reduction in the value of proved oil and natural gas reserves, primarily as a result of a decrease in crude oil prices and the performance of a South Texas well drilled in the prior year. In addition, during the year ended December 31, 2020, the Company recorded a reclassification to the depletable base of the full cost pool of $2.1 million related to a reduction in value of certain acreage.
7. DEBT
On March 4, 2021, the Company closed a Debt Conversion Agreement (the “Conversion Agreement”) with APEG Energy II, L.P. (“APEG II”), which entity Patrick E. Duke, a former director of the Company, has shared voting power and shared investment power. The Conversion Agreement was related to a $375,000 related party secured note payable the Company borrowed from APEG II on September 24, 2020 (the “Note”). The Note accrued interest at 10% per annum and had a maturity date of September 24, 2021. The Note was secured by the Company’s wholly-owned subsidiary, Energy One LLC’s oil and natural gas producing properties. Under the terms of the Note, the Company could repay the Note prior to maturity, however, in the event of a prepayment of the Note, the Company was required to pay APEG II the amount of interest which would have accrued through maturity (at 10% per annum). Pursuant to the Conversion Agreement, the Company converted the related party secured note payable of $375,000 and accrued interest to the date of the Note’s September 24, 2021 maturity of $37,500 into shares of unregistered common stock with a value on the date of the Conversion Agreement of $438,000. The difference of $25,500 between the value of the shares issued and the $412,500 amount of the Note and accrued interest through the date of maturity is recorded as interest expense, net, in the condensed consolidated statements of operations.
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8. ASSET RETIREMENT OBLIGATIONS
The Company has asset retirement obligations (“ARO”) associated with the future plugging and abandonment of developed oil and gas properties. Initially, the fair value of a liability for an ARO is recorded in the period in which the ARO is incurred with a corresponding increase in the carrying amount of the related asset. The liability is accreted to its present value each period and the capitalized cost is depleted over the life of the related asset. If the liability is settled for an amount other than the recorded amount, an adjustment to the full-cost pool is recognized. The Company had no assets that are restricted for the purpose of settling AROs.
In the fair value calculation for the ARO there are numerous assumptions and judgments including the ultimate retirement cost, inflation factors, credit-adjusted risk-free discount rates, market risk premiums, timing of retirement and changes in legal, regulatory, environmental and political environments. To the extent future revisions to assumptions and judgments impact the present value of the existing ARO, a corresponding adjustment is made to the oil and natural gas property balance.
The following is a reconciliation of the changes in the Company’s liabilities for asset retirement obligations for the years ended December 31, 2021 and 2020:
| Year Ended December 31, | ||||||||
| 2021 | 2020 | |||||||
| (in thousands) | ||||||||
| Balance, beginning of year | $ | 1,408 | $ | 819 | ||||
| Accretion | 78 | 43 | ||||||
| Sold/Plugged | (70 | ) | (12 | ) | ||||
| Acquired | 45 | 558 | ||||||
| Balance, end of year | $ | 1,461 | $ | 1,408 | ||||
9. COMMITMENTS, CONTINGENCIES, AND RELATED PARTY TRANSACTIONS
Litigation
In July 2020, the Company received a request for arbitration from its former Chief Executive Officer, David Veltri claiming that it breached his employment agreement. The Company settled the litigation in December 2021 by paying Mr. Veltri and his attorneys $750 thousand, of which $375 thousand was reimbursed by the Company’s insurance carrier. For the year ended December 31, 2021, total amounts incurred by the Company related to the litigation was $427 thousand.
APEG II Litigation
From February 2019 until August 2020, the Company was involved in litigation with its former Chief Executive Officer, David Veltri, and at the time its largest shareholder, APEG II and APEG II’s general partner, APEG Energy II, GP (together with APEG II, “APEG”). In addition, Patrick E. Duke, a former director of the Company, had shared voting and shared investment power over APEG. The litigation arose as a result of a vote at the February 25, 2019 board of directors meeting to terminate Mr. Veltri for using Company funds outside of his authority and for other reasons (the “Texas Litigation”). In a separate lawsuit, APEG initiated a shareholder derivative action in Colorado against Mr. Veltri due to his refusal to recognize the Board’s decision to terminate him (the “Colorado Litigation”). The Company was named as a nominal defendant in the Colorado Litigation. The Colorado litigation was dismissed in May 2020 and the Texas Litigation was dismissed in August 2020. On March 4, 2021, the Company issued shares of unregistered common stock, which had a value on the date of issuance of $406 thousand, to APEG in reimbursement of APEG’s legal costs in the Colorado and Texas Litigation.
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10. PREFERRED STOCK
The Company’s articles of incorporation authorize the issuance of up to shares of preferred stock, $ par value. Shares of preferred stock may be issued with such dividend, liquidation, voting and conversion features as may be determined by the Board of Directors without shareholder approval. The Company is authorized to issue shares of Series P preferred stock in connection with a shareholder rights plan that expired in 2011.
On December 31, 2020, the Company redeemed all then outstanding of Series A Convertible Preferred Stock (the “Preferred Stock”) by making a cash payment of $2.0 million and issuing shares of its common stock, which at the date of the redemption had a value of $ per share for a total redemption price of $3.2 million. The liquidation preference on the date of redemption was $3.6 million. The difference between the redemption price and the liquidation preference of the preferred stock was included as a reduction of the net loss available to common shareholders in the calculation of loss per share.
11. SHAREHOLDERS’ EQUITY
Common Stock
At December 31, 2021, the Company had shares of common stock outstanding. On February 17, 2021, the Company sold shares of common stock for net proceeds of $5.3 million.
Warrants
In December 2016, the Company completed a registered direct offering of shares of common stock at a net gross price of $ per share. Concurrently, the investors received warrants to purchase 100,000 shares of common stock of the Company at an exercise price of $20.05 per share, for a period of five years from the final closing date of June 21, 2017. The warrants include anti-dilution rights. The total net proceeds received by the Company were approximately $1.3 million. The fair value of the warrants upon issuance were $1.2 million, with the remaining $0.1 million being attributed to common stock. On September 29, 2020, the Company received proceeds of $565 thousand related to the exercise of warrants to purchase 50,000 shares of common stock. The warrants have been classified as liabilities due to features in the warrant agreement that give the warrant holder an option to require the Company to redeem the warrant at a calculated fair value in the event of a “Fundamental Transaction,” as defined in the warrant agreement. The fair value of the remaining warrants to purchase 50,000 shares of common stock was $19 thousand and $95 thousand at December 31, 2021 and 2020, respectively.
Pursuant to the original warrant agreement, as a result of common stock issuances at various prices, the warrant exercise price has been reduced from its original $20.50 exercise price to the floor price of $3.92, which is the exercise price of the warrants at December 31, 2021.
Stock Option Plans
From time to time, the Company may grant stock options under its incentive plan covering shares of common stock to employees of the Company. Stock options, when exercised, are settled through the payment of the exercise price in exchange for new shares of stock underlying the option. These awards typically expire ten years from the grant date.
For the years ended December 31, 2021 and 2020, there was compensation expense related to stock options. As of December 31, 2021, all stock options had vested. stock options were granted or exercised, during the years ended December 31, 2021 or 2020. During the years ended December 31, 2021 and 2020, options to purchase shares and shares, respectively, expired. Presented below is information about stock options outstanding and exercisable as of December 31, 2021 and 2020:
| December 31, 2021 | December 31, 2020 | |||||||||||||||
| Shares | Price (1) | Shares | Price (1) | |||||||||||||
| Stock options outstanding and exercisable | 31,035 | $ | 31,367 | $ | ||||||||||||
| (1) | Represents the weighted average price. |
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| Options Outstanding | Options Exercisable | |||||||||||||||||||||||||
| Exercise Price | Remaining | Weighted Average | ||||||||||||||||||||||||
| Number of | Range | Weighted | Contractual | Number of | Exercise | |||||||||||||||||||||
| Shares | Low | High | Average | Term (years) | Shares | Price | ||||||||||||||||||||
| 16,500 | $ | $ | $ | 16,500 | $ | |||||||||||||||||||||
| 10,622 | 90.00 | 124.80 | 10,622 | 106.20 | ||||||||||||||||||||||
| 2,913 | 139.20 | 171.00 | 2,913 | 147.39 | ||||||||||||||||||||||
| 1,000 | 226.20 | 226.20 | 1,000 | 226.20 | ||||||||||||||||||||||
| 31,035 | $ | 7.20 | $ | 226.20 | $ | 31,035 | $ | 62.79 | ||||||||||||||||||
Restricted Stock
The Company grants restricted stock under its incentive plan covering shares of common stock to employees and directors of the Company. The restricted stock awards are time-based awards and are amortized ratably over the requisite service period. Restricted stock vests ratably on each anniversary following the grant date provided the grantee is employed on the vesting date. Restricted stock granted to employees, when vested, are net settled through the issuance of shares, net of the number of shares required to pay withholding taxes.
The following table presents the changes in non-vested, time-based restricted stock awards to all employees and directors for the year ended December 31, 2021:
| Shares | Weighted-Avg. Grant Date Fair Value per Share | |||||||
| Non-vested restricted stock at December 31, 2020 | 71,000 | $ | 4.89 | |||||
| Granted | 150,000 | $ | 4.72 | |||||
| Vested | (47,000 | ) | $ | 4.89 | ||||
| Non-vested restricted stock at December 31, 2021 | 174,000 | $ | 4.75 | |||||
The following table presents the stock compensation expense related to restricted stock grants for the years ended December 31, 2021 and 2020:
Year Ended December 31, | ||||||||
| 2021 | 2020 | |||||||
| (in thousands) | ||||||||
| Stock compensation expense | $ | 549 | 211 | |||||
Total compensation cost related to non-vested time-based awards not yet recognized in the Company’s condensed consolidated statements of operations as of December 31, 2021 is $thousand. This cost is expected to be recognized over a weighted average period of years. At December 31, 2021, the Company had shares available for issuance under its 2021 Sock Incentive Plan.
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12. INCOME TAXES
The components of the income tax provision for the years ended December 31, 2021 and 2020 include the following:
| 2021 | 2020 | |||||||
| (in thousands) | ||||||||
| Current income tax expense (benefit) | $ | $ | (42 | ) | ||||
| Deferred income taxes | - | - | ||||||
| $ | $ | (42 | ) | |||||
The current income tax benefit for the year ended December 31, 2020 represents a refund of alternative minimum tax credit carryovers received in 2020.
The Company incurred net losses for each of the years ended December 31, 2021 and 2020, and the Company has recorded valuation allowances for its net deferred tax assets for each of those years. Accordingly, the Company has not recognized a benefit for income taxes in the accompanying financial statements. Income tax benefit using the Company’s effective income tax rate differs from the U.S. federal statutory income tax rate due to the following:
| 2021 | 2020 | |||||||
| (in thousands) | ||||||||
| Income tax benefit at federal statutory rate | $ | (372 | ) | $ | (1,361 | ) | ||
| State income tax benefit, net of federal impact | (25 | ) | (35 | ) | ||||
| Change in state tax rate, net of federal benefit | (1 | ) | (32 | ) | ||||
| Change in value of warrant | (16 | ) | 5 | |||||
| Percentage depletion carryover | (50 | ) | (3 | ) | ||||
| Prior year true up | (14 | ) | 154 | |||||
| Other | 2 | (53 | ) | |||||
| Increase in valuation allowance | 476 | 1,283 | ||||||
| Income tax expense (benefit) | $ | $ | (42 | ) | ||||
The components of deferred tax assets and liabilities as of December 31, 2021 and 2020 are as follows:
| 2021 | 2020 | |||||||
| (in thousands) | ||||||||
| Deferred tax assets: | ||||||||
| Net operating loss carryover (1) | $ | 6,295 | $ | 5,154 | ||||
| Property and equipment | 3,115 | 3,939 | ||||||
| Percentage depletion and contribution carryovers (1) | 1,947 | 1,855 | ||||||
| Alternative minimum tax credit carryover (1) | - | - | ||||||
| Equity method investment and other | 225 | 246 | ||||||
| Deferred compensation liability | 9 | 7 | ||||||
| Asset retirement obligations | 327 | 315 | ||||||
| Stock-based compensation | 190 | 115 | ||||||
| Lease obligations | 30 | 32 | ||||||
| Total deferred tax assets | 12,138 | 11,663 | ||||||
| Deferred tax liabilities: | ||||||||
| Lease assets | (27 | ) | (28 | ) | ||||
| Total deferred tax liabilities | (27 | ) | (28 | ) | ||||
| Net deferred tax assets | 12,111 | 11,635 | ||||||
| Less valuation allowance | (12,111 | ) | (11,635 | ) | ||||
| Net deferred tax asset | $ | $ | ||||||
| (1) | In December 2017, the Company paid down debt through the issuance of common stock. This issuance represented a 49.3% ownership change in the Company. This change in ownership, combined with other equity events, triggered loss limitations under Internal Revenue Code (“I.R.C.”) Section 382. As a result, the Company wrote off $29.8 million of gross deferred tax assets in 2017, and an additional $2.4 million in gross deferred tax assets in 2018. Since the Company has maintained a valuation allowance against these tax assets there is no impact to the consolidated statement of operations in either year. |
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As of December 31, 2021, the Company has approximately $12.5 million in net operating loss carryovers (after limitations) for federal income tax purposes. The losses will be subject to an Internal Revenue Code (IRC) Section 382 limitation as a result the acquisition that closed on January 5, 2022 see Note 16-Subsequent Events.
I.R.C. Section 382 of the Internal Revenue Code limits the Company’s ability to utilize the tax deductions associated with its oil and gas properties to offset taxable income in future years, due to the existence of a Net Unrealizable Built-In Loss (“NUBIL”) at the time of the change in control. Such a limitation will be effective for a five-year period subsequent to the change in control. In the event the Company has Recognized Built-In Losses (“RBIL”) during the five-year period, those losses will be limited; losses exceeding the annual limitation are carried forward as RBIL carryovers. As of December 31, 2021, the Company has approximately $10.8 million of RBIL carryovers, which carry forward indefinitely subject to the annual limitation.
The Company recognizes, measures, and discloses uncertain tax positions whereby tax positions must meet a “more-likely-than-not” threshold to be recognized. During the years ended December 31, 2021 and 2020, no adjustments were recognized for uncertain tax positions.
The Company files income tax returns in U.S. federal and multiple state jurisdictions. The Company is subject to tax audits in these jurisdictions until the applicable statute of limitations expires. The Company is no longer subject to U.S. federal tax examinations for tax years prior to 2017. The Company is open for various state tax examinations for tax years 2016 and later. The Company’s policy is to recognize potential interest and penalties accrued related to uncertain tax positions within income tax expense. For the years ended December 31, 2021 and 2020, the Company did not recognize any interest or penalties in its statement of operations, nor did it have any interest or penalties accrued in its balance sheet at December 31, 2021 and 2020 related to uncertain tax positions.
Basic net loss per common share is calculated by dividing net loss attributable to common shareholders by the weighted-average number of common shares outstanding for the respective period. Diluted net loss per common share is calculated by dividing adjusted net loss by the diluted weighted average number of common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of stock options and warrants, which are measured using the treasury stock method, the conversion feature of the Series A Preferred Stock prior to redemption, and unvested shares of restricted common stock. When the Company recognizes a net loss, as was the case for the years ended December 31, 2021 and 2020, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of dilutive net loss per common share.
| 2021 | 2020 | |||||||
| (in thousands except per share data) | ||||||||
| Net loss | $ | (1,770 | ) | $ | (6,439 | ) | ||
| Dividend on series A preferred stock | - | (421 | ) | |||||
| Gain on redemption of series A preferred stock | - | 441 | ||||||
| Net loss applicable to common shareholders | $ | (1,770 | ) | $ | (6,419 | ) | ||
| Basic weighted-average common shares outstanding | 4,492 | 1,628 | ||||||
| Dilutive effect of potentially dilutive securities | - | - | ||||||
| Diluted weighted-average common shares outstanding | 4,492 | 1,628 | ||||||
| Basic net loss per share | $ | (0.39 | ) | $ | (3.94 | ) | ||
| Diluted net loss per share | $ | (0.39 | ) | $ | (3.94 | ) | ||
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| 2021 | 2020 | |||||||
| (in thousands) | ||||||||
| Stock options | 31 | 31 | ||||||
| Unvested shares of restricted stock | 174 | 71 | ||||||
| Warrants | 50 | 50 | ||||||
| Total | 255 | 152 | ||||||
14. FAIR VALUE MEASUREMENTS
The Company’s fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the hierarchy level. The three levels of inputs that may be used to measure fair value are defined as:
Level 1 - Quoted prices for identical assets and liabilities traded in active exchange markets.
Level 2 - Observable inputs other than Level 1 that are directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities inactive markets, or other observable inputs that can be corroborated by observable market data.
Level 3 - Unobservable inputs supported by little or no market activity for financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation.
The Company has processes and controls in place to attempt to ensure that fair value is reasonably estimated. The Company performs due diligence procedures over third-party pricing service providers in order to support their use in the valuation process. Where market information is not available to support internal valuations, independent reviews of the valuations are performed, and any material exposures are evaluated through a management review process.
While the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. The following is a description of the valuation methodologies used for complex financial instruments measured at fair value:
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Warrant Valuation Methodologies
The warrants contain a dilutive issuance and other liability provisions that cause the warrants to be accounted for as a liability. Such warrant instruments are initially recorded and valued as a Level 3 liability and are accounted for at fair value with changes in fair value reported in earnings. There were no changes in the methodology to value the warrants during 2021. The Company estimated the value of the warrants at December 31, 2021 and 2020, with the following assumptions:
| 2021 | 2020 | |||||||
| Number of warrants outstanding | 50,000 | 50,000 | ||||||
| Expiration date | June 21, 2022 | June 21, 2022 | ||||||
| Exercise price | $ | 3.92 | $ | 3.92 | ||||
| Stock price | $ | 3.27 | $ | 3.68 | ||||
| Dividend yield | 0 | % | 0 | % | ||||
| Average volatility rate (1) | 66 | % | 120 | % | ||||
| Probability of down-round event (2) | 0 | % | 0 | % | ||||
| Risk free interest rate | 0.11 | % | 0.11 | % | ||||
| (1) | The average volatility represents the Company’s volatility measurement, the observed volatility of our peer group over a similar period, and the stock market volatility as of the valuation date. |
| (2) | Represents the estimated probability of a future down-round event during the remaining term of the warrants. |
At December 31, 2021 and 2020, the Company used the average value calculated by the Black-Scholes model as opposed to a Monte Carlo model, because the strike price is set at the floor of $3.92 and therefore cannot be rounded down further. An increase in any of the inputs would cause an increase in the fair value of the warrants. Likewise, a decrease in any input would cause a decrease in the fair value of the warrants.
Marketable Equity Securities Valuation Methodologies
The fair value of marketable equity securities is based on quoted market prices obtained from independent pricing services. The Company has an investment in the marketable equity securities of Anfield Energy (“Anfield”), which it acquired as consideration for sales of certain mining operations. Anfield is traded in an active market under the trading symbol AEC:TSXV and has been classified as Level 1.
| December 31, | ||||||||
| 2021 | 2020 | |||||||
| Number of shares owned | 2,421,180 | 2,421,180 | ||||||
| Quoted market price | $ | 0.07874 | $ | 0.07455 | ||||
| Fair value | $ | 190,641 | $ | 180,500 | ||||
Asset Retirement Obligations
The Company measures the fair value of asset retirement obligations as of the date a well is acquired or the date a well begins drilling using a discounted cash flow method based on unobservable inputs in the market and therefore are designated as Level 3 within the valuation hierarchy. See Note 8-Asset Retirement Obligations.
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Other Assets and Liabilities
The Company evaluates the fair value on a non-recurring basis of properties acquired in business combinations. The fair value of the oil and gas properties is determined based upon estimated future discounted cash flow, a Level 3 input, using estimated production which we reasonably expect, and estimated prices adjusted for differentials. Unobservable inputs include estimated future oil and natural gas production, prices, operating and development costs, and a discount rate of 10%, all Level 3 inputs within the fair value hierarchy.
The Company evaluates the fair value on a non-recurring basis of its Riverton, Wyoming real estate assets when circumstances indicate that the value has been impaired. At December 31, 2021, the Company estimated the fair value of its real estate assets based on a market approach with comparison to recent comparable sales, all Level 3 inputs within the fair value hierarchy.
The carrying value of financial instruments included in current assets and current liabilities approximate fair value due to the short-term nature of those instruments.
Recurring Fair Value Measurements
Recurring measurements of the fair value of assets and liabilities as of December 31, 2021 and 2020 are as follows:
| December 31, 2021 | December 31, 2020 | |||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||
| (in thousands) | ||||||||||||||||||||||||||||||||
| Current Assets: | ||||||||||||||||||||||||||||||||
| Marketable Equity Securities | $ | 191 | $ | $ | $ | 191 | $ | 181 | $ | $ | $ | 181 | ||||||||||||||||||||
| Current Liabilities: | ||||||||||||||||||||||||||||||||
| Warrants | $ | $ | $ | 19 | $ | 19 | $ | $ | $ | $ | ||||||||||||||||||||||
| Non-current Liabilities: | ||||||||||||||||||||||||||||||||
| Warrants | $ | $ | $ | $ | $ | $ | $ | 95 | $ | 95 | ||||||||||||||||||||||
The following table presents a reconciliation of our Level 3 warrants measured at fair value:
| Year Ended December 31, | ||||||||
| 2021 | 2020 | |||||||
| (in thousands) | ||||||||
| Fair value of Level 3 instruments liabilities at beginning of period | $ | 95 | $ | 73 | ||||
| Net unrealized (gain) loss on warrant valuation | (76 | ) | 22 | |||||
| Fair value of Level 3 instruments liabilities at end of period | $ | 19 | $ | 95 | ||||
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15. SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED)
Capitalized Costs incurred
The capitalized costs incurred in crude oil and natural gas acquisitions, exploration and development activities for the years ended December 31, 2021 and 2020 are provided in the table below:
| 2021 | 2020 | |||||||
| (in thousands) | ||||||||
| Proved property acquisition | $ | 46 | $ | 1,851 | ||||
| Unproved property acquisition | 5 | - | ||||||
| Development | 1,519 | 441 | ||||||
| Exploration | - | - | ||||||
| Total | $ | 1,570 | $ | 2,292 | ||||
Capitalized Costs
The following table presents the Company’s capitalized costs associated with oil and natural gas producing activities as of December 31, 2021 and 2020:
| 2021 | 2020 | |||||||
| (in thousands) | ||||||||
| Oil and Natural Gas Properties: | ||||||||
| Unevaluated properties: | ||||||||
| Unproved leasehold costs | $ | 1,588 | $ | 1,597 | ||||
| Evaluated properties in full cost pool | 95,088 | 93,549 | ||||||
| Less accumulated depletion and ceiling test impairment | (88,195 | ) | (87,708 | ) | ||||
| Net capitalized costs | $ | 8,481 | $ | 7,438 | ||||
The Company did t incur a ceiling test write-down for the year ended December 31, 2021. During the year ended December 31, 2020, the Company incurred ceiling test write-downs of its oil and natural gas properties of $2.9 million due to a reduction in the value of its proved oil and natural gas reserves primarily as the result of a decrease in crude prices and the performance of a South Texas well drilled in the prior year. Depletion and amortization was $490 thousand ($3.98 per BOE) and $363 thousand ($4.55 per BOE) for the years ended December 31, 2021 and 2020, respectively.
Unevaluated oil and natural gas properties consist of leasehold costs that are excluded from the depletion, depreciation and amortization calculation and the ceiling test until a determination about the existence of proved reserves can be completed. Unevaluated oil and natural gas properties consisted of unproved lease acquisition costs and costs paid to evaluate potential acquisition prospects of $1.6 million at December 31, 2021 and 2020, respectively.
On a quarterly basis, management reviews market conditions and other changes in circumstances related to the Company’s unevaluated properties and transfers the costs to evaluated properties within the full cost pool as warranted. During the year ended December 31, 2020, the Company evaluated its unevaluated property and recorded a reclassification to the depletable base of the full cost pool of $2.1 million related to a reduction in value of certain of its acreage.
Results of Operations from oil and natural gas producing activities
Presented below are the results of operations from oil and natural gas producing activities for the years ended December 31, 2021 and 2020:
| 2021 | 2020 | |||||||
| (in thousands) | ||||||||
| Oil and natural gas sales | $ | 6,658 | $ | 2,330 | ||||
| Lease operating expense | (2,421 | ) | (1,535 | ) | ||||
| Production taxes | (471 | ) | (168 | ) | ||||
| Depletion and amortization | (487 | ) | (356 | ) | ||||
| Impairment of oil and natural gas properties | - | (2,943 | ) | |||||
| Results of operations from oil and natural gas producing activities | $ | 3,279 | $ | (2,672 | ) | |||
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Oil and Natural Gas Reserves (Unaudited)
Proved reserves are estimated quantities of oil, NGLs and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Oil and natural gas prices used are the average price during the 12-month period prior to the effective date of the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements. Proved developed reserves are reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.
Proved oil and natural gas reserve quantities at December 31, 2021 and 2020 and the related discounted future net cash flows before income taxes are based on the estimates prepared by Don Jacks, PE. The estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission. All of the Company’s estimated proved reserves are located in the United States.
As of December 31, 2021, and 2020, the Company had no proved undeveloped reserves. All proved reserves were proved developed producing and proved developed non-producing.
The Company’s estimated quantities of proved oil and natural gas reserves and changes in net proved reserves are summarized below for the years ended December 31, 2021 and 2020:
| 2021 | 2020 | |||||||||||||||
| Oil | Gas | Oil | Gas | |||||||||||||
| (bbls) | (mcfe) (1) | (bbls) | (mcfe) (1) | |||||||||||||
| Total proved reserves: | ||||||||||||||||
| Reserve quantities, beginning of year | 975,745 | 1,676,948 | 807,505 | 1,129,258 | ||||||||||||
| Revisions of previous estimates | 128,232 | 437,757 | (248,770 | ) | (22,895 | ) | ||||||||||
| Discoveries and extensions | - | - | - | - | ||||||||||||
| Purchases of minerals in place | 11,365 | - | 477,479 | 686,670 | ||||||||||||
| Sale of minerals in place | - | - | - | - | ||||||||||||
| Production | (93,722 | ) | (176,657 | ) | (60,469 | ) | (116,085 | ) | ||||||||
| Reserve quantities, end of year | 1,021,620 | 1,938,048 | 975,745 | 1,676,948 | ||||||||||||
| (1) | Mcf equivalents (Mcfe) consist of natural gas reserves in mcf plus NGLs converted to mcf using a factor of 6 mcf for each barrel of NGL. |
Notable changes in proved reserves for the year ended December 31, 2021 included the following:
| ● | The upward revisions of previous estimates of 201,192 BOE were primarily attributable to revisions due to higher pricing used in the estimate of proved reserves at December 31, 2021. | |
| ● | Purchases of minerals in place in 2021 represent reserves added as a result of the acquisition of one well in our Liberty County properties. Purchases of reserves in place in 2020 represent the reserves added as a result of the acquisitions of New Horizon Resources LLC, certain properties from FieldPoint Production Company, and certain properties from Newbridge Resources completed during the year. |
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Standardized Measure (Unaudited)
The Company computes a standardized measure of future net cash flows and changes therein relating to estimated proved reserves in accordance with authoritative accounting guidance. The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value amount. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process.
Future cash inflows and production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year-end estimated future reserve quantities. The following prices as adjusted for transportation, quality, and basis differentials were used in the calculation of the standardized measure:
| 2021 | 2020 | |||||||
| Oil per Bbl | $ | 66.56 | $ | 39.57 | ||||
| Gas per Mcfe (1) | $ | 3.60 | $ | 1.99 | ||||
| (1) | Consists of the weighted average price for natural gas in mcf plus NGLs converted to mcf using a factor of 6 mcf for each barrel of NGL. |
Future operating costs are determined based on estimates of expenditures to be incurred in developing and producing the proved reserves in place at the end of the period using year-end costs and assuming continuation of existing economic conditions. Estimated future income taxes are computed using the current statutory income tax rates, including consideration for estimated future statutory depletion. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.
The standardized measure of discounted future net cash flows relating to the Company’s proved oil and natural gas reserves is as follows as of December 31, 2021 and 2020:
| 2021 | 2020 | |||||||
| (in thousands) | ||||||||
| Future cash inflows | $ | 76,041 | $ | 39,090 | ||||
| Future cash outflows: | ||||||||
| Production costs | (40,350 | ) | (24,189 | ) | ||||
| Development costs | - | (302 | ) | |||||
| Income taxes | (2,818 | ) | (142 | ) | ||||
| Future net cash flows | 32,873 | 14,457 | ||||||
| 10% annual discount factor | (13,706 | ) | (5,871 | ) | ||||
| Standardized measure of discounted future net cash flows | $ | 19,167 | $ | 8,586 | ||||
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Changes in Standardized Measure (Unaudited)
The changes in the standardized measure of future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2021 and 2020 are as follows:
| 2021 | 2020 | |||||||
| (in thousands) | ||||||||
| Standardized measure, beginning of year | $ | 8,586 | $ | 10,348 | ||||
| Sales of oil and natural gas, net of production costs | (3,766 | ) | (627 | ) | ||||
| Net changes in prices and production costs | 11,675 | (8,487 | ) | |||||
| Changes in estimated future development costs | 302 | (302 | ) | |||||
| Extensions and discoveries | - | - | ||||||
| Purchases of minerals in place | 216 | 5,841 | ||||||
| Sale of minerals in place | - | - | ||||||
| Revisions in previous quantity estimates | 3,080 | (1,148 | ) | |||||
| Previously estimated development costs incurred | (302 | ) | - | |||||
| Net changes in income taxes | (1,389 | ) | 1,649 | |||||
| Accretion of discount | 674 | 855 | ||||||
| Changes in timing and other | 91 | 457 | ||||||
| Standardized measure, end of year | $ | 19,167 | $ | 8,586 | ||||
16. SUBSEQUENT EVENTS
On January 5, 2022 (the “Closing Date”), the Company closed the acquisitions contemplated by three separate Purchase and Sale Agreements (the “Purchase Agreements”), 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, the Company 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 cash and shares of our common stock, as to Lubbock; (b) $1,000,000 in cash, the assumption of $3.3 million of debt, and 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; and (c) $125,000 in cash and shares of common stock, as to Synergy. The aggregate purchase price under all the Purchase Agreements was $67.4 million, representing $1.25 million in cash, the value of shares of our common stock on the Closing Date of $64.7 million and purchase price adjustments on the Closing Date of $1.4 million. In addition, we assumed various liabilities, including the repayment of $3.3 million in debt, as well as a derivative liability from the novation of the hedges discussed above of $3.1 million, suspense accounts and asset retirement obligations. The initial base purchase price remains subject to final post-closing settlement including customary working capital and other adjustments between the Company and the Sellers 120 days following the Closing Date.
Each Purchase Agreement required the Company to place a $500,000 deposit into escrow ($1.5 million in aggregate) (the “Deposits”). The Deposits, included in other assets in the consolidated balance sheet at December 31, 2021, were released on the Closing Date to pay a portion of the purchase price and closing adjustments for the Acquired Assets. The Company is currently evaluating certain accounting and valuation considerations for the Acquired Assets.
Board of Directors
On January 4, 2022, and effective as of the Closing on January 5, 2022, the Board of Directors (the “Board”) (i) increased the size of the Company’s Board of Directors from five members to seven members (with Javier F. Pico resigning from the Board effective immediately prior to Closing), and appointed (a) Mr. John A. Weinzierl, the Chief Executive Officer of Lubbock, who was designated by Lubbock, as a director and Chairman of the Company; (b) Mr. Joshua Batchelor, the Managing Partner of Sage Road Capital, LP, the owner of Banner, who was designated by Banner, as a director of the Company; and (c) Mr. Duane H. King, the Chief Executive Officer of Synergy, who was designated by Synergy, as a director of the Company.
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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, and a maximum credit amount of $100 million. Under the Credit Agreement, revolving loans may be borrowed, repaid and re-borrowed until January 5, 2026, when all outstanding amounts must be repaid. 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 (b) the Federal Funds rate in effect on such day (as determined in the Credit Agreement) plus 0.50%, and an applicable margin that ranges 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 0.75% regardless of utilization. Accrued interest on each revolving loan is payable in arrears on the last day of each March, June, September and December. A commitment fee of 0.50% accrues on the average daily amount of the unused portion of the borrowing base (as of March 22, $11,500,000) is payable in arrears on the last business day of March, June, September and December of each year and on the maturity date.
The Company is also 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 Company and its subsidiaries (the “Loan Parties”). 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 the Company to hedge certain oil and gas volumes, based on utilization of the borrowing base, which hedging will be accomplished pursuant to the ISDA Master Agreement, discussed below.
If any event of default occurs as defined in the Credit Agreement 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.
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.
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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.
The Company’s entry into and the obligations of the Company under the Master Agreement and Schedule were required conditions to the Closing of 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. In addition, on January 12, 2022, the Company entered into additional Nymex WTI crude oil commodity derivative contracts with NextEra for 2022 and 2023 production. The Company’s commodity derivative positions for years 2022 and 2023 are shown in the following table below:
| Collars | Fixed Price Swaps | ||||||||||||||||||||
| Commodity/ | Quantity | Quantity | Weighted | ||||||||||||||||||
| Index/ | Crude oil-(Bbks) | Weighted Average Prices | Crude oil-(Bbks) | Average | |||||||||||||||||
| Maturity Period | Natura lGas-(Mmbtu) | Floors | Ceilings | Natural Gas (mmbtu) | Price | ||||||||||||||||
| Crude Oil | |||||||||||||||||||||
| Nymex | |||||||||||||||||||||
| 2022 | 270,500 | $ | 59.54 | $ | 79.78 | 35,700 | $ | 49.99 | |||||||||||||
| 2023 | 223,500 | $ | 59.33 | $ | 79.55 | 12,000 | $ | 59.20 | |||||||||||||
| Natural Gas | |||||||||||||||||||||
| Nymex | |||||||||||||||||||||
| 2022 | 40,000 | $ | 2.95 | $ | 3.33 | 180,000 | $ | 2.96 | |||||||||||||
| 2023 | 60,000 | $ | 2.96 | ||||||||||||||||||
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 land and lease administration services; accounting services tax services; and 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.
Exercise of Warrants
On March 11, 2022, a holder of warrants exercised warrants to purchase shares of common stock with an exercise price of $3.92 and we received proceeds of $195 thousand and issued shares of common stock.
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PART IV
Item 15 – Exhibits and Financial Statement Schedules
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules:
The following financial statements are included in Item 8 of this report under “Financial Statements and Supplementary Data”:
All schedules are omitted because the required information is not applicable or is not present in amounts sufficient to require submission of the schedule or because the information required is included in the Consolidated Financial Statement and Notes thereto.
(b) Exhibits. The following exhibits are filed or furnished with or incorporated by reference into this report on Form 10-K:
| Incorporated by Reference | ||||||||||||
| Exhibit No. |
Description | Form | File No. | Exhibit | Filing Date |
Filed Herewith | ||||||
| 1.2 | Placement Agency Agreement, dated September 29, 2020, between the Company and Kingswood Capital Markets, division of Benchmark Investments, Inc. | 8-K | 000-06814 | 1.1 | 10/2/2020 | |||||||
| 1.2 | Underwriting Agreement, dated February 11, 2021, by and between U.S. Energy Corp. and Kingswood Capital Markets, division of Benchmark Investments, Inc. | 8-K | 000-06814 | 1.1 | 2/16/2021 | |||||||
| 2.1 | Purchase and Sale Agreement between among Lubbock Energy Partners, LLC, as seller, and U.S. Energy Corp., as purchaser, dated as of October 4, 2021 | 8-K | 000-06814 | 2.1 | 10/6/2021 | |||||||
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| 95 |
| 96 |
| 97 |
| 98 |
| 99 |
| 14.1† | Code of Ethics and Conduct | 8-K | 000-06814 | 14.1 | 8/5/2019 | |||||||
| 21.1* | Subsidiaries of the Registrant | X | ||||||||||
| 23.1* | Consent of Independent Registered Public Accounting Firm (Plante & Moran, PLLC) | X | ||||||||||
| 23.2* | Consent of Reserve Engineer (Don Jacks, PE) | X | ||||||||||
| 31.1* | Certification of Chief Executive Officer and principal financial officer pursuant to Section 302 of the Sarbanes – Oxley Act of 2002 | X | ||||||||||
| 32.1** | Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | X | ||||||||||
| 99.1* | Reserve Report Summary (Don Jacks, PE) | X | ||||||||||
| 99.2* | Amended and Restated Charter of the Nominating and Governance Committee | X | ||||||||||
| 101.INS* | Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document | X | ||||||||||
| 101.SCH* | XBRL Schema Document | X | ||||||||||
| 101.CAL* | XBRL Calculation Linkbase Document | X | ||||||||||
| 101.DEF* | XBRL Definition Linkbase Document | X | ||||||||||
| 101.LAB* | XBRL Label Linkbase Document | X | ||||||||||
| 101.PRE* | XBRL Presentation Linkbase Document | X | ||||||||||
| 104* | Inline XBRL for the cover page of this Annual Report on Form 10-K, included in the Exhibit 101 Inline XBRL Document Set | X |
| * | Filed herewith. |
| ** | Furnished herewith. |
| † | Exhibit constitutes a management contract or compensatory plan or agreement. |
| # | Certain schedules, annexes, and similar attachments have been omitted pursuant to Item 601(a)(5) of Regulation S-K. A copy of any omitted schedule or exhibit will be furnished supplementally to the Securities and Exchange Commission upon request; provided, however, that U.S. Energy Corp. may request confidential treatment pursuant to Rule 24b-2 of the Securities Exchange Act of 1934, as amended, for any schedule or exhibit so furnished. |
Item 16. Form 10-K Summary
None
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| U.S. ENERGY CORP. | ||
| Date: March 28, 2022 | By: | /s/ Ryan L. Smith |
RYAN L. SMITH, President, Chief Executive Officer, Chief Financial Officer and Director (Principal Executive Officer and Principal Financial and Accounting Officer) | ||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
| Date: March 28, 2022 | By: | /s/ Ryan L. Smith |
RYAN L. SMITH, President, Chief Executive Officer, Chief Financial Officer and Director (Principal Executive Officer and Principal Financial and Accounting Officer) | ||
Date: March 28, 2022 |
By: |
/s/ John A. Weinzierl |
| John Weinzierl, Director | ||
| Date: March 28, 2022 | By: | /s/ Joshua L. Batchelor |
| Joshua L. Batchelor | ||
| Date: March 28, 2022 | By: | /s/ James W. Denny III |
| James W. Denny III, Director | ||
| Date: March 28, 2022 | By: | /s/ Randall D. Keys |
| Randall D. Keys, Director | ||
| Date: March 28, 2022 | By: | /s/ Duane H. King |
| Duane H. King, Director | ||
| Date: March 28, 2022 | By: | /s/ D. Stephen Slack |
| D. Stephen Slack, Director |
| 101 |
