這些前瞻性陳述通常以“可能”、“預期”、“估計”、“計劃”、“相信”、“意圖”、“可實現”、“預期”、“將”、“持續”、“潛在”、“應該”、“可能”、“高達”等具有類似意涵的詞語和詞組來辨識。儘管我們認為這些陳述所反映的期望是合理的，但其中涉及一定的假設、風險和不確定性。可能導致或對此出現差異的因素包括但不限於本季度報告表格10-Q中討論的事項，特別是所列入“風險因素”中的風險，2013年12月31日終了的財政年度年報表格10-k中 Part I，項目1A“風險因素”中討論的風險，以及在其他提交給證券交易委員會（股票交易所或委員會）的文件中所討論的風險。鑒於這些風險和不確定性，讀者應該謹慎對待此類前瞻性陳述。
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE nine months ended September 30, 2024 and 2023
(in thousands)
2024
2023
Cash flows from operating activities:
Net income (loss)
$
(13,758
)
$
(12,550
)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion, accretion, and amortization
6,392
8,181
Impairment of oil and natural gas properties
6,843
6,495
Deferred income taxes
(14
)
(452
)
Total commodity derivatives (gains) losses, net
(537
)
(704
)
Commodity derivative settlements received (paid)
2,381
(642
)
(Gains) losses on marketable equity securities
57
(54
)
Impairment and loss on real estate held for sale
11
-
Amortization of debt issuance costs
37
37
Stock-based compensation
950
1,951
Right of use asset amortization
123
135
Changes in operating assets and liabilities:
Oil and natural gas sales receivable
920
(292
)
Other assets
(174
)
395
Accounts payable and accrued liabilities
80
120
Accrued compensation and benefits
(91
)
(294
)
Revenue and royalties payable
(88
)
927
Payments on operating lease liability
(136
)
(145
)
Payments of asset retirement obligations
(105
)
(131
)
Net cash provided by operating activities
2,891
2,977
Cash flows from investing activities:
Acquisition of helium properties
(2,368
)
-
Helium capital expenditures
(1,599
)
-
Oil and natural gas capital expenditures
(1,158
)
(2,878
)
Property and equipment expenditures
(189
)
(487
)
Proceeds from sale of oil and natural gas properties, net
5,866
-
Proceeds from sale of real estate assets
139
-
Net cash provided by (used in) investing activities
691
(3,365
)
Cash flows from financing activities:
Borrowings on credit facility
2,000
500
Payments on credit facility
(7,000
)
(500
)
Payments on insurance premium finance note
(62
)
(465
)
Shares withheld to settle tax withholding obligations for restricted stock awards
(132
)
(151
)
Dividends paid
-
(1,192
)
Repurchases of common stock
(584
)
(241
)
Net cash provided by (used in) financing activities
(5,778
)
(2,049
)
Net (decrease) increase in cash and equivalents
(2,196
)
(2,437
)
Cash and equivalents, beginning of period
3,351
4,411
Cash and equivalents, end of period
$
1,155
$
1,974
The accompanying notes are an integral part of these unaudited Condensed Consolidated Financial Statements. Please see Note-15- Supplemental Disclosures of Cash Flow Information.
NOTES TO UNAUDITED CONDENSED 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 (“Energy One”), New Horizon Resources LLC (“New Horizon Resources”) and Coyote Resources LLC ("Coyote Resources"), which was formed on August 6, 2024, are referred to as the “Company” in these notes to unaudited Condensed Consolidated Financial Statements) is incorporated in the State of Delaware. The Company’s principal business activities are focused on the acquisition, exploration, and development of onshore helium, oil and natural gas properties (collectively referred to as "commodities" or "helium, oil and natural gas") in the United States, which the Company considers a single operating segment. Our principal properties and operations are in the Rockies region (Montana, Wyoming and North Dakota), the Mid-Continent (Oklahoma, Kansas and North and East Texas) region, and the West Texas, South Texas, and Gulf Coast region.
Basis of Presentation
The accompanying unaudited Condensed Consolidated Financial Statements are presented in accordance with U.S. generally accepted accounting principles (“GAAP”) and have been prepared by the Company pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”) regarding interim financial reporting. Accordingly, certain information and footnote disclosures required by GAAP for complete financial statements have been condensed or omitted in accordance with such rules and regulations. In the opinion of management, all adjustments (consisting of normal recurring adjustments) considered necessary for a fair presentation of the Condensed Consolidated Financial Statements have been included.
For further information, refer to the consolidated financial statements and footnotes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2023, as filed with the SEC on March 26, 2024. Our financial condition as of September 30, 2024, and operating results for the three and nine months ended September 30, 2024, are not necessarily indicative of the financial condition and results of operations that may be expected for any future interim period or for the year ending December 31, 2024.
Use of Estimates
The preparation of financial statements in conformity with 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 the fair value of helium, oil and gas properties acquired, oil and natural gas reserves that are used in the calculation of depreciation, depletion, amortization, and impairment of the carrying value of proved and unproved property; production and commodity price estimates used to record accrued sales receivables; future prices of commodities used in the valuation of commodity derivative contracts; and the cost and timing 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 commodity prices, these estimates could change in the near term and such changes could be material.
Principles of Consolidation
The accompanying Condensed Consolidated Financial Statements have been prepared in conformity with GAAP and include the accounts of U.S. Energy Corp. and its wholly-owned subsidiaries Energy One, New Horizon Resources and Coyote Resources. U.S. Energy Corp. accounts for its share of helium, oil and gas exploration and production activities, in which it has a direct working interest, by reporting its proportionate share of assets, liabilities, revenues, costs, and cash flows within the relevant lines on the Condensed Consolidated Balance Sheets, Statements of Operations, and Statements of Cash Flows. All inter-company balances and transactions have been eliminated in consolidation.
Segments
Based on the Company’s organization structure, the Company has one operating segment, which is the development, exploration and production of oil, natural gas and helium. In addition, the Company has a single company-wide management team that allocates capital resources to maximize profitability and measures financial performance as a single enterprise.
Reclassifications
Certain prior year amounts are reclassified to conform to the current year presentation.
Historically, the Company included gathering, transportation, and treating costs within lease operating expense on the Condensed Consolidated Statements of Operations. Effective July 1,2023, the Company began classifying gathering, treating, and transportation costs in a separate line item, titled Gathering, transportation, and treating, on the Condensed Consolidated Statements of Operations and recast prior period results for this reclassification. This reclassification had no impact on the Company's net income, earnings per share, cash flows, or financial position. The Company revised historical periods to reflect this change in presentation.
The Company has historically included revenue and royalties payable within accounts payables and accrued liabilities on the Condensed Consolidated Balance Sheets. Effective December 31,2023, the Company began classifying revenue and royalties payable as a separate line item on the Condensed Consolidated Balance Sheet. The Condensed Consolidated Statements of Cash Flows has been updated to separate changes in operating assets and liabilities from revenue and royalties payable and accounts payable and accrued liabilities. This reclassification had no impact on the Company's net income (loss), income (loss) per share, cash flows, or financial position. The Company revised historical periods to reflect this change in presentation.
2. ACQUISITIONS AND DIVESTITURES
Acquisition of helium acreage
On June 26, 2024, the Company entered into and closed the transactions contemplated by, a purchase and sale agreement with Wavetech Helium ("Wavetech" and the "Purchase Agreement"). Pursuant to the Purchase Agreement, effective June 1, 2024, the Company acquired 82.5% of Wavetech's rights under a farmout agreement for approximately 144 thousand net acres located across the Kevin Dome Structure in Toole County, Montana ("the Assigned Rights"). The Assigned Rights vest upon the drilling of two wells on the property. In consideration for the Assigned Rights, the Company paid Wavetech $2.0 million in cash and 2.6 million shares of restricted common stock, which were valued at $2.7 million on June 26, 2024. In addition, prior to the closing of the Purchase Agreement, the Company incurred $0.4 million of transaction costs related to the acquisition of the Assigned Rights. Additionally, the Company agreed to be responsible for 100% of capital costs, including costs related to project exploration, appraisal, development drilling and completion until $20 million has been incurred related to Wavetech's 17.5% interest. The Company accounted for the acquisition of the Assigned Rights as an asset acquisition.
Acquisition, exploration and development costs related to our helium acreage are accounted for under the full cost method of accounting in a separate cost center from our domestic oil and gas activities. Details about our application of full cost accounting can be found in our Annual Report on Form 10-K for the year ended December 31, 2023, as filed with the SEC on March 26, 2024.
On June 25, 2024, the Company entered into a related party non-binding letter of intent with Synergy Offshore LLC ("Synergy") relating to the proposed acquisition by the Company of 24 thousand net operated acres located across the Kevin Dome structure in Toole County, Montana, which are highly contiguous to the property acquired from Wavetech. Synergy is controlled by Mr. Duane H. King, a member of the Board of Directors of the Company, who serves as the Chief Executive Officer and Manager of Synergy, and John A. Weinzierl, the Company’s Chairman, who was then an approximate thirty percent beneficial owner of Synergy.
In September 2024, the related party non-binding letter of intent expired with the Company and Synergy unable to reach agreement on the definitive terms of a purchase and sale agreement. Through September 30, 2024 the Company incurred $547 thousand of transaction costs related to the related-party non-binding letter of intent of which $368 thousand were written-off during the period and reflected as acquisition transaction costs on the Condensed Consolidated Statement of Operations. The remaining $179 thousand, which is recorded in other assets on the Condensed Consolidated Balance Sheet, relates to land and helium reserve evaluation. The Company is continuing negotiations with Synergy for a potential joint venture for the development of their helium acreage.
Divestitures
During the nine months ended September 30, 2024, the Company closed several divestment transactions of its oil and gas properties for net proceeds totaling $5.9 million. The divestitures included a total of 245 wells in Karnes County and Archer County, Texas and Lea County, New Mexico. These divestitures did not have a significant impact to reserves volumes or the full cost pool depletion rate. As such, the Company recorded the proceeds, net of transaction costs and purchase price adjustments, to the full cost pool, with no gain or loss recognized in the Condensed Consolidated Statement of Operations. Relief of associated asset retirement obligations of $1.4 million were also recorded to the full cost pool.
During the year ended December 31, 2023, the Company closed on a series of individual divestitures for a total of $7.0 million in net proceeds before transaction costs of $0.4 million. The divestitures included the Company’s non-operated interests in 152 wells across North Dakota, New Mexico, and Texas, and overriding royalty interests in seven wells in Karnes County, Texas. These divestitures did not have a significant impact to reserves volumes or the full cost pool depletion rate. As such, the Company recorded the proceeds, net of transaction costs and purchase price adjustments, to the full cost pool, with no gain or loss recognized. Relief of associated asset retirement obligations of $0.5 million were also recorded to the full cost pool.
The Company disaggregates revenues from its share of revenue from the sale of oil and natural gas and liquids by region. The Company’s revenues in the Rockies region, West Texas, South Texas, and Gulf Coast region, and Mid-Continent region for the three and nine months ended September 30, 2024 and 2023, are presented in the following table:
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(in thousands)
Revenue:
Rockies
Oil
$
1,851
$
3,106
$
5,614
$
7,915
Natural gas and liquids
45
44
127
260
Total
$
1,896
$
3,150
$
5,741
$
8,175
West Texas, South Texas, and Gulf Coast
Oil
$
1,107
$
3,138
$
4,513
$
9,115
Natural gas and liquids
-
103
114
424
Total
$
1,107
$
3,241
$
4,627
$
9,539
Mid-Continent
Oil
$
1,417
$
1,567
$
4,447
$
4,905
Natural gas and liquids
537
783
1,579
2,373
Total
$
1,954
$
2,350
$
6,026
$
7,278
Combined Total
$
4,957
$
8,741
$
16,394
$
24,992
Significant concentrations of credit risk
The Company has exposure to credit risk in the event of non-payment of oil and natural gas receivables by purchasers of its operated oil and natural gas properties. 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:
Nine Months Ended
September 30,
2024
2023
Purchaser A
26
%
23
%
Purchaser B
26
%
19
%
Purchaser C
12
%
9
%
4. LEASES
The Company’s operating lease right-of-use asset and lease liability are recognized at their discounted present value under the following captions in the Condensed Consolidated Balance Sheets on September 30, 2024 and December 31, 2023:
September 30, 2024
December 31, 2023
(in thousands)
Right-of-use asset
$
570
$
693
Lease liability
Current lease obligation
$
193
$
182
Long-term lease obligation
466
611
Total lease liabilities
$
659
$
793
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 cost represents payments for oilfield equipment with original lease terms less than one year. Following are the amounts recognized as components of lease cost for the three and nine months ended September 30, 2024 and 2023:
The Company’s Houston office operating lease does 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 September 30,
2024
2023
(in thousands)
Weighted average lease term (years)
3.2
4.2
Weighted average discount rate
4.25
%
4.25
%
Maturity of operating lease liabilities with terms of one year or more as of September 30, 2024 are presented in the following table:
September 30, 2024
(in thousands)
2024
$
54
2025
218
2026
224
2027
210
Total lease payments
$
706
Less: imputed interest
(47
)
Total lease liability
$
659
5. OIL AND NATURAL GAS PRODUCING ACTIVITIES
Full Cost Method 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 September 30, 2024, the Company used $78.64 per barrel for oil and $2.21 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%.
During the three and nine months ended September 30, 2024, the Company recorded ceiling test write-downs of its oil and gas properties of $1.4 million and $6.8 million, respectively due to a reduction in the value of proved oil and natural gas reserves primarily as a result of a decrease in crude oil and natural gas prices, the divestment of properties, reserves revisions related to wells shut-in during the first quarter of 2024 and updates to the decline curves for certain wells.
6. DEBT
On January 5, 2022, the Company entered into a four-year credit agreement (“Credit Agreement”) with FirstBank Southwest (“FirstBank”) as administrative agent for one or more lenders (the “Lenders”), which provided for a revolving line of credit with an initial borrowing base of $15 million, and a maximum credit amount of $100 million. Borrowings under the Credit Agreement are collateralized by a first priority, perfected lien and security interests on substantially all assets of the Company (subject to permitted liens and other customary exceptions). On July 26, 2022, the Company entered into a letter agreement with FirstBank whereby it increased the borrowing base under the Credit Agreement from $15 million to $20 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 the greater of (i) the prime rate in effect on such day, and (ii) 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”). Interest expense recognized on the Credit Agreement and the weighted average interest rates for the three and nine months ended September 30, 2024 and 2023 are presented in the following table:
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(in thousands)
Interest expense
$
77
$
288
$
307
$
807
Weighted average interest rate
9.3
%
9.1
%
9.2
%
8.8
%
The Credit Agreement contains various restrictive covenants and compliance requirements, which include: (i) maintenance of certain financial ratios, as defined in the Credit Agreement 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; (ii) restrictions on making restricted payments as defined in the Credit Agreement, including the payment of cash dividends and repurchases of equity interests (subject to certain limited rights to make restricted payments as long as no event of default has occurred, or would result from the restricted payment, certain financial ratios are met and the borrowing availability after giving pro forma effect to any borrowing to be made on the date of the restricted payment is greater than, or equal to, 20% of the then existing borrowing base); (iii) limits on the incurrence of additional indebtedness; (iv) a prohibition on the entry into commodity swap contracts exceeding a specified percentage of our expected production; and (v) restrictions on the disposition of assets. As of September 30, 2024, the borrowing base was $20 million, and the Company was in compliance with all financial covenants related to the Credit Agreement.
On September 10, 2024, with the proceeds of $1.8 million from the settlement of the unwinding of its derivative contracts and cash on hand, the Company repaid the remaining balance of $2.0 million borrowed under the Credit Agreement. Therefore, the amount outstanding on the Credit Agreement as of September 30, 2024 and December 31, 2023, was $0.0 million and $5.0 million respectively.
The Company’s results of operations and cash flows are affected by changes in market prices for crude oil and natural gas. To manage a portion of its exposure to price volatility from producing crude oil and natural gas, the Company may enter into commodity derivative contracts to protect against price declines in future periods. The Company does not enter into derivative contracts for speculative purposes. The Company does not apply hedge accounting. Accordingly, changes in the fair value of the derivative contracts are recorded in the Condensed Consolidated Statements of Operations and are included as a non-cash adjustment to net loss in the operating activities section in the Condensed Consolidated Statements of Cash Flows.
On September 10, 2024, the Company settled all of its then outstanding commodity derivative contracts for 2024 and 2025 production receiving $1.8 million. As of September 30, 2024, the Company no longer has any commodity derivative contracts outstanding.
September 30, 2024
December 31, 2023
(in thousands)
Derivative assets:
Current assets
$
-
$
1,844
Total derivative assets
$
-
$
1,844
The following table summarizes the components of the commodity derivative settlement gain (loss) as well as the components of the net commodity derivative (gain) loss line-item presentation in the accompanying Condensed Consolidated Statements of Operations:
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(in thousands)
Commodity derivative settlement gain (loss):
Oil contracts
$
1,856
$
(148
)
$
2,381
$
(614
)
Gas contracts
-
-
-
(28
)
Total commodity derivative settlement gain (loss)
$
1,856
$
(148
)
$
2,381
$
(642
)
Total net commodity derivative gain (loss):
Oil contracts
$
2,030
$
(504
)
$
537
$
644
Gas contracts
-
-
-
60
Total net commodity derivative gain (loss)
$
2,030
$
(504
)
$
537
$
704
8. COMMITMENTS AND CONTINGENCIES
Contingencies
The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the anticipated results of any pending litigation and claims are not expected to have a material effect on the results of operations, the financial position, or the cash flows of the Company.
On January 5, 2022, the Company acquired certain oil and gas producing properties from Synergy Offshore LLC and contemporaneously entered into a farmout agreement concerning certain leases located in Glacier and Toole Counties, Montana. The farmout agreement gives Synergy Offshore LLC the right, subject to certain conditions, to purchase from the Company, any unit or field on the farmout properties once they have commenced enhanced recovery operations on the properties. The price of said purchase is to be based on the greater of present value of said unit or field discounted at 10 percent, based on its current production rate at either the prevailing commodity price at the time of purchase or flat pricing of $65.00 per barrel of oil and $3.25 per thousand cubic feet of natural gas (“Repurchase Price”). If a proposed purchase price for the sale to Synergy of the applicable farmout properties is less than the Repurchase Price, the sale will be subject to the affirmative approval by the disinterested members of the Board of Directors of the Company. The farmout agreement has a term of 10 years, expiring January 5, 2032.
9. SHAREHOLDERS’ EQUITY
At September 30, 2024and December 31, 2023 the Company had 28,035,613 and 25,333,870 shares of common stock outstanding, respectively and 245,000,000 authorized shares. In addition, as of September 30, 2024, and December 31, 2023 the Company had 5,000,000 authorized but unissued shares of preferred stock.
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 three and nine months ended September 30, 2024 and 2023, there was no compensation expense related to stock options. As of September 30, 2024 and September 30, 2023, all stock options had vested. No stock options were granted or exercised during the three and nine months ended September 30, 2024 and 2023. Stock options for 1,000 shares expired during the three months ended September 30, 2024. The stock options had de minimis intrinsic values for the periods reported. Presented below is information for stock options outstanding and exercisable as of September 30, 2024, and December 31, 2023:
September 30, 2024
December 31, 2023
Weighted
Weighted
Average
Average
Number of
Exercise
Number of
Exercise
Shares
Price
Shares
Price
Stock options outstanding and exercisable
22,176
$
30.48
23,176
$
38.92
The following table summarizes information for stock options outstanding and for stock options exercisable at September 30, 2024 by the remaining contractual term:
Options Outstanding and Exercisable
Exercise
Weighted
Remaining
Price
Average
Contractual
Number of
Range
Exercise
Term
Shares
Low
High
Price
(years)
16,500
$
7.20
$
11.60
$
10.00
3.0
5,676
90.00
90.00
90.00
0.3
22,176
$
7.20
$
90.00
$
30.48
2.3
Restricted Stock
The Company grants restricted stock under its incentive plans covering shares of common stock to employees and directors of the Company. Significantly all of the restricted stock awards are time-based awards and are amortized ratably over a requisite service period. Time-based awards vest ratably following the grant date, provided the grantee is employed on the vesting dates. The Company has one restricted stock award that vests if the Company's share price is equal to or greater than $2.00 for 20 consecutive trading days within the period beginning March 19, 2025 and ending March 18, 2027. The grant date fair value of this award is amortized over a derived requisite service period from the fair value model. Forfeitures of restricted stock awards are recognized as they occur. Restricted stock granted to employees, when vested, may be settled through the net issuance of shares, reduced by the number of shares required to pay withholding taxes. Non-vested shares of restricted stock are not included in common shares outstanding until vesting has occurred.
The following table presents the changes in non-vested restricted stock awards to all employees and directors for the nine months ended September 30, 2024:
Weighted-Avg.
Grant Date
Fair Value
Shares
Per Share
Non-vested restricted stock as of December 31, 2023
855,236
$
2.63
Granted
1,303,000
$
0.96
Vested
(673,041
)
$
2.12
Modifications (accelerated vesting)
(20,000
)
$
1.64
Forfeited
(117,500
)
$
1.18
Non-vested restricted stock as of September 30, 2024
1,347,695
$
1.41
For the nine months ended September 30, 2024 and 2023, the Company recognized $0.9 million and $2.0 million, respectively, of stock compensation expense related to restricted stock grants. Total compensation cost related to non-vested awards not yet recognized in the Company’s Condensed Consolidated Statements of Operations as of September 30, 2024 was $0.7 million. This cost is expected to be recognized over a weighted average period of 1.5 years.
Dividends
On August 9, 2023, the Board of Directors suspended the Company’s dividend payment program. As a result, no dividends were paid for the nine months ended September 30, 2024. During the three-month periods ended March 31, 2023, and June 30, 2023, the Company declared and paid dividends of $0.0225 per share of common stock. Dividends paid for the three and six months ended June 30, 2023, were $0.6 million and $1.2 million, respectively.
On April 26, 2023, the Board of Directors of the Company authorized and approved a share repurchase program for up to $5.0 million of the outstanding shares of the Company’s common stock. On March 19, 2024, the Board of Directors authorized and approved an extension of the ongoing share repurchase program. Subject to any future extensions, the repurchase program is scheduled to expire on the earlier of June 30, 2025, when a maximum of $5.0 million of the Company’s common stock has been repurchased, or when the program is discontinued by the Board of Directors.
Under the stock repurchase program, shares are repurchased from time to time in the open market or through negotiated transactions at prevailing market prices, or by other means in accordance with federal securities laws. Repurchases are made at management’s discretion at prices management considers to be attractive and in the best interests of both the Company and its stockholders, subject to the availability of stock, general market conditions, the trading price of the stock, alternative uses for capital, and the Company’s financial performance. The repurchase program is funded using the Company’s working capital. The repurchased shares are cancelled and therefore will not be held in treasury or reissued.
The following table presents the activity in the share repurchase program for the three and nine months ended September 30, 2024 and 2023:
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(in thousands)
Shares repurchased
19,000
-
482,500
163,300
Weighted average price per share
$
1.050
$
-
$
1.090
$
1.480
Value of shares repurchased
$
19,950
$
-
$
525,925
$
240,793
10. ASSET RETIREMENT OBLIGATIONS
The Company has asset retirement obligations (“ARO”) associated with the future plugging and abandonment of proved 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 ARO.
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, 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 as of September 30, 2024 and December 31, 2023:
September 30, 2024
December 31, 2023
(in thousands)
Balance, beginning of year
$
18,490
$
15,442
Acquired or incurred
-
11
Cost and life revisions
(150
)
2,494
Plugged
(105
)
(215
)
Sold
(1,425
)
(458
)
Accretion
1,181
1,216
Balance, end of period
$
17,991
$
18,490
Asset retirement obligations - current
$
1,000
$
1,273
Asset retirement obligations - noncurrent
16,991
17,217
Balance, end of period
$
17,991
$
18,490
11. INCOME TAXES
The Company’s tax provision or benefit from income taxes for interim periods is determined using an estimate of its annual effective tax rate, adjusted for discrete items, if any. Each quarter the Company updates its estimate of the annual effective tax rate and makes a year-to-date adjustment to the provision. The Company’s effective tax rate was approximately 0% and 3% for the nine months ended September 30, 2024 and 2023, respectively. The primary difference in the Company’s effective tax rate and the statutory rate for both periods is related to the movement in the valuation allowance against the Company’s net deferred tax assets.
Deferred taxes are recognized for the expected future tax consequences of temporary differences between the financial statement and tax basis of assets, liabilities, net operating losses and tax credit carry-forwards. We review our deferred tax assets (“DTAs”) and valuation allowance on a quarterly basis. As part of our review, we consider positive and negative evidence, including cumulative results in recent years. The Company has limitations on net operating losses (“NOLs”) generated prior to 2022 and other tax attributes as a result of an Internal Revenue Code ("IRC") Section 382 ownership change from a January 5, 2022 acquisition. As such, the Company is projecting that as of September 30, 2024, it will not have sufficient DTAs available to fully offset the expected future taxable income that will be generated by the realization of the Company’s deferred tax liabilities and thus has recorded a net deferred tax liability.
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 nine months ended September 30, 2024 and 2023, the Company had no uncertain tax positions.
12. INCOME (LOSS) PER SHARE
Basic net income (loss) per common share is calculated by dividing net income (loss) attributable to common shareholders by the weighted-average number of common shares outstanding for the respective period. Diluted net income per common share is calculated by dividing adjusted net income 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 unvested shares of restricted common stock, which are measured using the treasury stock method. When the Company recognizes a net loss, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of dilutive net loss per common share. Unvested shares of restricted stock participate in dividend distributions; however, they do not participate in losses. Therefore, dividends attributable to participating securities are not included as a reduction in the calculation of loss attributable to common shareholders.
The following table sets forth the calculation of basic and diluted net income (loss) per share for the three and nine months ended September 30, 2024 and 2023:
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(in thousands except per share data)
Net income (loss) attributable to common shareholders
$
(2,247
)
$
(8,788
)
$
(13,758
)
$
(12,550
)
Basic weighted average common shares outstanding
28,052
25,429
26,304
25,266
Dilutive effect of potentially dilutive securities
-
-
-
-
Diluted weighted average common shares outstanding
28,052
25,429
26,304
25,266
Basic net income (loss) per share
$
(0.08
)
$
(0.35
)
$
(0.52
)
$
(0.50
)
Diluted net income (loss) per share
$
(0.08
)
$
(0.35
)
$
(0.52
)
$
(0.50
)
For the three and nine months ended September 30, 2024 and 2023, potentially dilutive securities excluded from the calculation of weighted average shares because they were anti-dilutive were as follows:
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(in thousands)
Stock options
22
23
22
23
Unvested shares of restricted stock
1,348
855
1,348
855
Total
1,370
878
1,370
878
13. 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 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 in active 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.
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:
Recurring Fair Value Measurements
Commodity Derivative Instruments
On September 10, 2024, the Company received $1.8 million on the settlement of all outstanding commodity derivative contracts. The Company measures the fair value of commodity derivative contracts using an income valuation technique based on the contract price of the underlying positions, crude oil and natural gas forward curves, discount rates, and Company or counterparty non-performance risk. The fixed-price swaps and collar derivative contracts are included in Level 2. The fair value of commodity derivative contracts and their presentation in our unaudited Condensed Consolidated Balance Sheet as of December 31, 2023 is presented below:
We measure the fair value of marketable equity securities 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.
September 30, 2024
December 31, 2023
Current assets:
Marketable equity securities
Number of shares owned
2,421,180
2,421,180
Quoted market price
$
0.04439
$
0.06789
Fair value of marketable equity securities
$
107,474
$
164,375
Credit Facility
The Company’s credit facility approximates fair value because the interest rate is variable and reflective of market rates.
Other Financial Instruments
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.
Nonrecurring Fair Value Measurements
Unproved Properties
Unproved property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. The estimate of what could not be recoverable is based on the Company's intent to develop the properties or renew leases. To measure the fair value the Company uses a market approach which takes into account the following significant assumptions: remaining lease terms, future development plans, potential resource recovery, estimated reserve value and estimated acreage values based on prices received for similar recent acreage transactions by the Company or other market participants. If there is an indication that the value of unproved property has been impaired, the value being impaired is transferred to the full cost pool subject to depletion and the ceiling test limitation.
Asset Retirement Obligations
The Company measures the fair value of asset retirement obligations as of the date a well is acquired, the date a well begins drilling, or the date the Company revises its ARO assumptions. The Company’s estimated asset retirement obligations are based on historical experience in plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment costs and federal and state regulatory requirements, all unobservable inputs, and therefore, are designated as Level 3 within the valuation hierarchy. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised upwards. The credit adjusted risk-free rate used to discount the Company’s plugging and abandonment liabilities range from 7.30% to 19.00%. See Note 10-Asset Retirement Obligations.
14. OTHER CURRENT ASSETS AND ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
Other Current Assets
The following table presents the components of other current assets as of the dates indicated:
The following table presents the components of accounts payable and accrued liabilities as of the dates indicated:
September 30, 2024
December 31, 2023
(in thousands)
Accounts payable
$
2,168
$
1,944
Operating expense and oil and gas property accruals
1,576
1,335
Interest Payable
79
247
Production taxes payable
462
454
Insurance premium financing
-
62
Other
27
22
Total accounts payable and accrued expenses
$
4,312
$
4,064
15. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Nine Months Ended September 30,
2024
2023
(in thousands)
Cash paid for interest
$
(511
)
$
(832
)
Cash received for income taxes
(70
)
(74
)
Investing activities:
Change in capital expenditure accruals
(287
)
(240
)
Common stock issued for acquisition of properties
(2,678
)
-
Asset retirement obligations
(1,680
)
2,504
Financing activities:
Accrual for repurchase of common stock
58
Financing of insurance premiums with note payable
-
654
16. SUBSEQUENT EVENTS
Divestiture
On October 31, 2024, the Company closed on the divestment of oil and gas properties in Pratt County and Sumner County, Kansas and Kay County, Oklahoma for net proceeds of $1.2 million.
Expected Write-Down of Oil and Gas Properties
Under the full-cost method of accounting, the net book value of proved oil and gas properties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is the estimated after-tax future net cash flows from proved oil and gas reserves. Estimated future net cash flows are calculated using the unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, adjusted for location and quality differentials, held flat for the life of the production (except where prices are defined by contractual arrangements), less estimated operating costs, production taxes and future development costs, all discounted at 10 percent per annum. Future cash outflows associated with settling accrued asset retirement obligations are excluded from the calculation.
For the three and nine months ended September 30, 2024, we recorded ceiling test write-downs of our oil and natural gas properties of $1.4 million and $6.8 million, respectively. We expect to record a further write-down of our oil and gas properties in the fourth quarter of 2024 due to the sale of oil and natural gas properties in Pratt County and Sumner County, Kansas and Kay County, Oklahoma, which closed on October 31, 2024 and lower commodity prices used in the calculation of the ceiling test as higher fourth quarter 2023 commodity prices will be removed from the ceiling test calculation and replaced with what we expect to be lower fourth quarter 2024 commodity prices. Depending on actual commodity prices, estimated price differentials, lease operating costs, revisions to reserve estimates, and the amount and timing of capital expenditures, the write-down could be approximately $3.0 million to $4.0 million in the fourth quarter of 2024.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Introduction
This information should be read in conjunction with the interim unaudited financial statements and the notes thereto included in this Quarterly Report on Form 10-Q, and the audited financial statements and notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2023, filed with the Securities and Exchange Commission on March 26, 2024 (the “Annual Report”).
Certain abbreviations and oil and gas industry terms used throughout this Report are described and defined in greater detail under “Glossary of Oil and Natural Gas Terms” on page 4 of our Annual Report.
Certain capitalized terms used below and otherwise defined below, have the meanings given to such terms in the footnotes to our unaudited Condensed Consolidated Financial Statements included above under “Part I - Financial Information” – “Item 1. Financial Statements”.
In this Quarterly Report on Form 10-Q, we may rely on and refer to information regarding the industries in which we operate 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, we have not independently verified any of it, and we have not commissioned any such information.
See also “Cautionary Statement About “Forward-Looking Statements” above.
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:
●
“Bbl” refers to one stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons;
●
“BOE” refers to barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids, to six Mcf of natural gas;
●
“Bopd” refers to barrels of oil per day;
●
“Mcf” refers to a thousand cubic feet of natural gas;
●
“Mcfe” means 1,000 cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids;
●
“NGL” refers to natural gas liquids;
●
“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;
●
“Securities Act” refers to the Securities Act of 1933, as amended; and
●
“WTI” means West Texas Intermediate.
Where You Can Find Other Information
We file annual, quarterly, and current reports, proxy statements and other information with the SEC. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC like us at https://www.sec.gov (our filings can be found at https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0000101594) and on the “Investors – SEC Filings” page of our website at https://usnrg.com. 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.
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 unaudited Condensed 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:
●
General Overview. A general overview of the Company and our operations.
●
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 three and nine months ended September 30, 2024 and 2023.
●
Liquidity and Capital Resources. A discussion of our financial condition, including descriptions of balance sheet information and cash flows.
General Overview
U.S. Energy Corp. was incorporated in the State of Wyoming on January 26, 1966, and reincorporated to Delaware effective on August 3, 2022. We are an independent energy company focused on the acquisition and development of oil and natural gas producing properties in the continental United States. Our principal properties and operations are in the Rockies region (Montana, Wyoming and North Dakota), the Mid-Continent region (Oklahoma, Kansas, and North and East Texas), and the West Texas, South Texas, and Gulf Coast region.
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, South Texas, and Mid-Continent regions. During the fourth quarter of 2023, we sold virtually all of our non-operated properties and as of September 30, 2024, operated 99% of our reserves.
Our business strategy going forward is to enhance the value of our acquired operated assets through evaluation of selected 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. We also continue to evaluate strategic alternative opportunities that we believe will enhance stockholder value.
With our June 2024, acquisition of unproved properties from Wavetech Helium (as discussed below), we have significantly increased our acreage position in Montana with the focus to explore and produce helium and industrial gases in non-hydrocarbon-based reservoirs. During October 2024, we drilled our first helium well on the acreage. For the remainder of 2024, our capital budget will be substantially allocated to the completion of the well. The results of the well and the additional 3-5 wells we expect to drill in 2025 are expected to allow us to assess our next steps in the development of helium acreage and are further expected to allow us to vest the Assigned Rights.
Material Developments
Acquisition of helium properties
On June 26, 2024, the Company entered into and closed the transactions contemplated by a purchase and sale agreement with Wavetech Helium ("Wavetech" and the "Purchase Agreement"). Pursuant to the Purchase Agreement, effective June 1, 2024, the Company acquired 82.5%of Wavetech's rights under a farmout agreement for approximately 144 thousand net acres located across the Kevin Dome Structure in Toole County, Montana (the "Assigned Rights"). The Assigned Rights vest upon the drilling of two wells on the property. In consideration for the Assigned Rights, the Company paid Wavetech $2.0 million in cash and 2.6 million shares of restricted common stock, which were valued at $2.7 million on June 26, 2024. In addition, during the three months ended June 30, 2024, the Company incurred $0.4 million of transaction costs related to the acquisition of the Assigned Rights. Additionally, the Company agreed to be responsible for 100% of capital costs, including costs related to project exploration, appraisal, development drilling and completion until $20 million has been incurred related to Wavetech's 17.5% interest.
On June 25, 2024, the Company entered into a related party, non-binding letter of intent with Synergy Offshore LLC ("Synergy") relating to the proposed acquisition by the Company of 24,000 net operated acres located across the Kevin Dome structure in Toole County, Montana, which are highly contiguous to the property acquired from Wavetech. Synergy is controlled by Mr. Duane H. King, a member of the Board of Directors of the Company, who serves as the Chief Executive Officer and Manager of Synergy, and John A. Weinzierl, the Company’s Chairman, was then an approximate thirty percent beneficial owner of Synergy.
In September 2024, the related party non-binding letter of intent expired with the Company and Synergy unable to reach agreement on the definitive terms of a purchase and sale agreement. Through September 30, 2024 the Company incurred $547 thousand of transaction costs related to the related-party non-binding letter of intent of which $368 thousand were written-off during the period and reflected as acquisition transaction costs on the Condensed Consolidated Statement of Operations. The remaining $179 thousand relates to land and helium reserve evaluation. The Company is continuing negotiations with Synergy for a potential joint venture for the development of their helium acreage.
Divestment of Properties
In the fourth quarter of 2023, the Company closed on a series of individual divestitures for a total of $7.0 million in net proceeds before transaction costs of $0.4 million. The divestitures included the Company’s non-operated interests in 152 wells across North Dakota, New Mexico, and Texas, and overriding royalty interests in seven wells in Karnes County, Texas. These divestitures did not have a significant impact to reserves volumes or the full cost pool depletion rate. As such, the Company recorded the proceeds, net of transaction costs and purchase price adjustments, to the full cost pool with no gain or loss recognized. Relief of associated asset retirement obligations of $0.5 million were also recorded to the full cost pool. The net proceeds from these divestitures were used to repay a portion of the outstanding balance on our credit facility.
During the nine months ended September 30, 2024, the Company closed several divestment transactions of its oil and gas properties for net proceeds totaling $5.9 million. The divestitures included a total of 245 wells in Karnes County and Archer County, Texas and Lea County, New Mexico. These divestitures did not have a significant impact to reserves volumes or the full cost pool depletion rate. As such, the Company recorded the proceeds, net of transaction costs and purchase price adjustments, to the full cost pool, with no gain or loss recognized in the Condensed Consolidated Statement of Operations. Relief of associated asset retirement obligations of $1.4 million were also recorded to the full cost pool.
On October 31, 2024, the Company closed on the divestment of oil and gas properties in Pratt County and Sumner County, Kansas and Kay County, Oklahoma for net proceeds of $1.2 million.
Derivative Activities
On September 10, 2024, the Company received $1.8 million on the settlement of all of its then outstanding commodity derivative contracts.
Stock Repurchase Program
On March 19, 2024, the Board of Directors authorized and approved an extension of the ongoing share repurchase program for up to $5.0 million of the currently outstanding shares of the Company’s common stock originally approved by the Board of Directors on April 26, 2023, and set to expire on June 30, 2024. Subject to any future extension in the discretion of the Board of Directors of the Company, the repurchase program is now scheduled to expire on June 30, 2025, or when a maximum of $5.0 million of the Company’s common stock has been repurchased, or when such program is discontinued by the Board of Directors.
Under the stock repurchase program, shares may be repurchased from time to time in the open market or through negotiated transactions at prevailing market prices, or by other means in accordance with federal securities laws. Repurchases will be made at management’s discretion at prices management considers to be attractive and in the best interests of both the Company and its stockholders, subject to the availability of stock, general market conditions, the trading price of the stock, alternative uses for capital, and the Company’s financial performance. The repurchase program will be funded using the Company’s working capital.
During the nine months ended September 30, 2024, the Company repurchased 482,500 shares for $525 thousand, at a weighted average price of $1.09 per share. During the nine months ended September 30, 2023 the Company repurchased 163,300 shares for $240 thousand at a weighted average price of $1.48 per share. As of September 30, 2024, a total of $4.0 million remained available under the repurchase program for future repurchases.
Full Cost Method Ceiling Test
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 September 30, 2024, the Company used $78.64 per barrel for oil and $2.21 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%.
The Company recorded ceiling test write-downs of its oil and gas properties during the three and nine months ended September 30, 2024 of $1.4 million and $6.8 million respectively due to a reduction in the value of proved oil and natural gas reserves primarily as a result of a decrease in crude oil and natural gas prices, and reduction in oil and natural gas reserves from divestitures, as well as reserves revisions related to wells shut-in during the first quarter of 2024 and updates to the decline curves for certain wells.
We expect to record a further write-down of our oil and gas properties in the fourth quarter of 2024 due to the sale of oil and natural gas properties in Pratt County and Sumner County, Kansas and Kay County, Oklahoma, which closed on October 31, 2024 and lower commodity prices used in the calculation of the ceiling test as higher fourth quarter 2023 commodity prices will be removed from the ceiling test calculation and replaced with what we expect to be lower fourth quarter 2024 commodity prices. Depending on actual commodity prices, estimated price differentials, lease operating costs, revisions to reserve estimates, and the amount and timing of capital expenditures, the write-down could be approximately $3.0 million to $4.0 million in the fourth quarter of 2024.
Plan of Operations and Strategy
Continuing through the end of 2024 and beyond, we intend to develop the recently acquired helium acreage by drilling exploratory wells along with the related helium development activities. The first well was drilled in October. We have plans to drill 3-5 wells over the next twelve months. The costs to drill these wells is estimated to cost an aggregate of between $4.0 million and $6.5 million depending primarily on the number of wells drilled. The results from the completion and testing of these wells will allow us to assess our next steps in the development of our helium acreage. We also plan to actively manage our portfolio of oil and gas assets to maximize their value.
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 plan to be highly selective in the projects we evaluate and plan to review opportunities to bolster our liquidity and financial position through various means.
●
Evaluate and Pursue Value-Enhancing Transactions. We plan to continue to evaluate strategic alternative opportunities with the goal of enhancing shareholder value.
Critical Accounting Policies and Estimates
The preparation of our unaudited Condensed Consolidated Financial Statements in conformity with generally accepted accounting principles in the United States (“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 Part II, Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations of our 2023 Annual Report on Form 10-K filed with the SEC on March 26, 2024.
Results of Operations
Comparison of our Statements of Operations for the Three Months Ended September 30, 2024 and 2023
For the Three Months Ended September 30, 2024, we recorded a net loss of $2.3 million, which was primarily due to lower production resulting in reduced revenue for the period as a result of property sales. In the following sections we discuss our revenue, operating expenses, and other income (expense) for the three months ended September 30, 2024compared to the three months ended September 30, 2023.
Revenue. Presented below is a comparison of our oil and gas sales, production quantities and average sales prices for the three months ended September 30, 2024 and 2023:
Three months ended September 30,
Change
2024
2023
Amount
Percent
(in thousands except average prices and production quantities)
Revenue:
Oil
$
4,375
$
7,811
$
(3,436
)
(44
)%
Natural gas and liquids
582
930
(348
)
(37
)%
Total revenue
$
4,957
$
8,741
$
(3,784
)
(43
)%
Production quantities:
Oil (Bbls)
61,185
100,071
(38,886
)
(39
)%
Natural gas and liquids (Mcfe)
267,089
311,654
(44,565
)
(14
)%
BOE
105,699
152,013
(46,314
)
(30
)%
BOE/Day
1,149
1,652
(503
)
(30
)%
Average sales prices:
Oil (Bbls)
$
71.50
$
78.05
$
(6.55
)
(8
)%
Natural gas and liquids (Mcfe)
$
2.18
$
2.98
$
(0.81
)
(27
)%
BOE
$
46.90
$
57.50
$
(10.60
)
(18
)%
The decrease in our oil and gas revenue of $3.8 million for the three months ended September 30, 2024, as compared to the three months ended September 30, 2023, was primarily due to a decrease of 30% in production quantities and a decrease in realized commodity pricing of 18% on a per barrel of oil equivalent (BOE) basis. For the three months ended September 30, 2024, we produced 105,699 BOE, or an average of 1,149 BOE per day, as compared to 152,013 BOE or an average of 1,652 BOE per day during the comparable period in 2023. The decrease in our production quantities relates to the divestiture of substantially all of our non-operated properties in the fourth quarter of 2023, and the divestiture of additional operated properties during 2024 as wells as temporary weather-related events, such as severe storms and flooding and natural production declines. During the three months ended September 30, 2024, our production was 58% oil and 42% natural gas and liquids compared to 66% oil and 34% natural gas and liquids produced during the three months ended September 30, 2023.
Oil and Gas Production Costs. Presented below is a comparison of our oil and gas production costs for the three months ended September 30, 2024 and 2023:
Three months ended September 30,
Change
2024
2023
Amount
Percent
(in thousands)
Lease operating expenses
$
3,060
$
3,999
$
(939
)
(23
)%
Gathering, transportation and treating
43
167
$
(124
)
(74
)%
Production taxes
298
596
$
(298
)
(50
)%
Total
$
3,401
$
4,762
$
(1,361
)
(29
)%
Lease operating expense per BOE
$
28.95
$
26.31
$
2.64
10
%
Gathering, transportation and treating per BOE
$
0.41
$
1.10
$
(0.69
)
(63
)%
For the three months ended September 30, 2024, lease operating expenses were $3.1 million or $28.95 per BOE, a decrease of $0.9 million when compared to the $4.0 million or $26.31 per BOE for the three months ended September 30, 2023. The decrease in lease operating expense was due to the divestment of substantially all of our non-operated properties and a reduction in well workover activity in 2024 when compared to 2023. The increase on a per BOE basis is the result of lower production volumes being compared to relatively fixed recurring lease operated expenses.
For the three months ended September 30, 2024, gathering, transportation, and treating costs were $43 thousand, a decrease of $124 thousand, or 74%, compared to the comparable period of 2023. This decrease was attributable to the divestiture of substantially all of our non-operated activities in the fourth quarter of 2023.
For the three months ended September 30, 2024, production taxes were $298 thousand, a decrease of $298 thousand, or 50%, compared to the comparable period of 2023. This decrease was attributable to the decrease in revenue of 43% discussed above, as production taxes remained flat at 6% of revenue.
Depreciation, Depletion and Amortization. Our depreciation, depletion and amortization (“DD&A”) was $2.0 million and $2.9 million for the three months ended September 30, 2024 and 2023, respectively. Depletion expense on our oil and gas properties is the primary driver of DD&A expense. Our depletion rate was $14.94 per BOE and $16.39 per BOE for the three months ended September 30, 2024 and 2023, respectively. Our depletion rate can fluctuate because of acquisitions, changes in drilling and completion costs, impairments, revisions in asset retirement obligation cost estimates or timing, divestitures, changes in the mix of our production, the underlying proved reserve volumes and estimated future development costs.
Impairment of oil and natural gas properties. Impairment of $1.4 million for the three months ended September 30, 2024 was driven by a reduction in value of oil and gas reserves. The reduction was primarily due to lower commodity prices used in the full cost pool ceiling test, as well as divestitures of oil and gas properties during the third quarter of 2024.
General and Administrative Expenses. Presented below is a comparison of our general and administrative expenses for the three months ended September 30, 2024 and 2023:
Three months ended September 30,
Change
2024
2023
Amount
Percent
(in thousands)
Compensation and benefits
$
816
$
1,410
$
(594
)
(42
)%
Stock-based compensation
274
617
(343
)
(56
)%
Professional fees, insurance and other
794
797
(3
)
-
Total general and administrative expenses
$
1,884
$
2,824
$
(940
)
(33
)%
General and administrative expenses decreased by $0.9 million for the three months ended September 30, 2024, as compared to the prior year period. The decrease was primarily attributable both to a decrease in both professional fees, insurance, and other due to lower accounting, consulting, and recruitment fees and a decrease in compensation and benefits due to a reduction in headcount. Stock-based compensation was lower due to the value of the restricted stock awards being amortized for the three months ended September 30, 2024 being lower than those being amortized during the three months ended September 30, 2023 due to a decrease in our stock price.
Other Income (Expense). Presented below is a comparison of our other income (expense) for the three months ended September 30, 2024 and 2023:
Three months ended September 30,
Change
2024
2023
Amount
Percent
(in thousands)
Commodity derivative gain (loss), net
$
2,030
$
(504
)
$
2,534
503
%
Interest (expense), net
(93
)
(306
)
213
70
%
Other income (expense), net
(52
)
68
(120
)
(176
)%
Total other income (expense)
$
1,885
$
(742
)
$
2,627
354
%
Commodity derivative gain (loss), net, is the result of changes in derivative fair values associated with fluctuations in forward price curves for the commodities underlying our outstanding derivative contracts and the monthly cash settlements of our derivative positions during the period. For the three months ended September 30, 2024, we recognized gains on commodity derivative contracts of $2.0 million, primarily as the result of the settlement in September 2024, of all of our remaining commodity derivative contracts for $1.8 million. See Note 7 Commodity Derivatives in the notes to the unaudited Condensed Consolidated Financial Statements.
Interest expense primarily represents the interest on our credit facility with FirstBank Southwest. The increase in interest expense is primarily driven by the decrease in the balance outstanding period-over-period. As of September 30, 2024, we had fully repaid all outstanding amounts borrowed on the credit facility, as compared to $12.0 million borrowed as of September 30, 2023. The average interest rate increased to 9.3% per annum for the three months ended September 30, 2024, as compared to 9.1% per annum for the three months ended September 30, 2023. See Note 6 Debt in the notes to the unaudited Condensed Consolidated Financial Statements.
Comparison of our Statements of Operations for the Nine Months Ended September 30, 2024 and 2023
For the nine months ended September 30, 2024, we recorded a net loss of $13.8 million which was primarily due to lower production resulting in reduced revenue for the period. In addition, the Company recorded impairment of its oil and natural gas properties of $6.8 million from reduced commodity prices used in the full cost pool ceiling test and lower production resulting in reduced revenue for the period. In the following sections we discuss our revenue, operating expenses, and other income (expense) for the nine months ended September 30, 2024, compared to the nine months ended September 30, 2023.
Revenue. Presented below is a comparison of our oil and gas sales, production quantities and average sales prices for the nine months ended September 30, 2024 and 2023:
Nine months ended September 30,
Change
2024
2023
Amount
Percent
(in thousands except average prices and production quantities)
Revenue:
Oil
$
14,574
$
21,935
$
(7,361
)
(34
)%
Natural gas and liquids
1,820
3,057
(1,237
)
(40
)%
Total revenue
$
16,394
$
24,992
$
(8,598
)
(34
)%
Production quantities:
Oil (Bbls)
201,417
306,282
(104,865
)
(34
)%
Natural gas and liquids (Mcfe)
751,036
1,076,104
(325,068
)
(30
)%
BOE
326,589
485,633
(159,043
)
(33
)%
BOE/Day
1,192
1,779
(587
)
(33
)%
Average sales prices:
Oil (Bbls)
$
72.36
$
71.62
$
0.74
1
%
Natural gas and liquids (Mcfe)
$
2.42
$
2.84
$
(0.42
)
(15
)%
BOE
$
50.20
$
51.46
$
(1.27
)
(2
)%
The decrease in our oil and gas revenue of $8.6 million for the nine months ended September 30, 2024, as compared to the nine months ended September 30, 2023, was primarily due to a decrease of 33% in production quantities and a decrease in realized commodity pricing of 2% on a per BOE basis. For the nine months ended September 30, 2024, we produced 326,589 BOE, or an average of 1,192 BOE per day, as compared to 485,633 BOE or an average of 1,779 BOE per day during the comparable period in 2023. The decrease in our production quantities relates to the divestiture of substantially all of our non-operated properties in the fourth quarter of 2023, and the divestiture of additional operated properties during 2024as well as temporary weather-related events, such as severe storms, flooding and winter weather, and natural production declines. During the nine months ended September 30, 2024, our production was 62% oil and 38% natural gas and liquids compared to 63% oil and 37% natural gas and liquids produced during the nine months ended September 30, 2023.
Oil and Gas Production Costs. Presented below is a comparison of our oil and gas production costs for the nine months ended September 30, 2024 and 2023:
Nine months ended September 30,
Change
2024
2023
Amount
Percent
(in thousands)
Lease operating expenses
$
9,322
$
12,147
$
(2,825
)
(23
)%
Gathering, transportation and treating
$
170
$
419
$
(249
)
(59
)%
Production taxes
$
1,008
$
1,654
$
(646
)
(39
)%
Total
$
10,500
$
14,220
$
(3,720
)
(26
)%
Lease operating expense per BOE
$
28.54
$
25.01
$
3.53
14
%
Gathering, transportation and treating per BOE
$
0.52
$
0.86
$
(0.34
)
(40
)%
For the nine months ended September 30, 2024, lease operating expenses were $9.3 million or $28.54 per BOE, a decrease of $2.8 million when compared to the $12.1 million or $25.01 per BOE for the nine months ended September 30, 2023. The decrease in lease operating expense was due almost entirely to a reduction in well workover activity in 2024, when compared to 2023. The increase in lease operating expense on a per BOE basis is the result of lower production volumes being compared to relatively fixed recurring lease operated expenses.
For the nine months ended September 30, 2024, gathering, transportation, and treating costs were $170 thousand, a decrease of $249 thousand, or 59%, compared to the comparable period of 2023. This decrease was attributable to the divestiture of substantially all of our non-operated activities in the fourth quarter of 2023.
For the nine months ended September 30, 2024, production taxes were $1.0 million, a decrease of $0.6 million, or 39%, compared to the comparable period of 2023. This decrease was attributable to the decrease in revenue of (34)% discussed above, as production taxes remained flat at 6% of revenue.
Depreciation, Depletion and Amortization. Our depreciation, depletion and amortization (“DD&A”) was $6.4 million and $8.2 million for the nine months ended September 30, 2024 and 2023, respectively. Depletion expense on our oil and gas properties is the primary driver of DD&A expense. Our depletion rate was $15.39 per BOE and $14.74 per BOE for the nine months ended September 30, 2024 and 2023, respectively. Our depletion rate can fluctuate because of acquisitions, changes in drilling and completion costs, impairments, revisions in asset retirement obligation cost estimates or timing, divestitures, changes in the mix of our production, the underlying proved reserve volumes and estimated future development costs.
Impairment of oil and natural gas properties. Impairment of $6.8 million for the nine months ended September 30, 2024 was driven by a reduction in value of oil and gas reserves. The reduction was primarily due to lower commodity prices used in the full cost pool ceiling test, divestitures of oil and natural gas properties, as well as reserves revisions related to wells shut-in during the first quarter of 2024 and updates to the decline curves for certain wells.
General and Administrative Expenses. Presented below is a comparison of our general and administrative expenses for the nine months ended September 30, 2024 and 2023:
Nine months ended September 30,
Change
2024
2023
Amount
Percent
(in thousands)
Compensation and benefits
$
2,888
$
3,927
$
(1,039
)
(26
)%
Stock-based compensation
950
1,951
(1,001
)
(51
)%
Professional fees, insurance and other
2,343
3,086
(743
)
(24
)%
Total general and administrative expenses
$
6,181
$
8,964
$
(2,783
)
(31
)%
General and administrative expenses decreased by $2.8 million for the nine months ended September 30, 2024, as compared to the prior year period. The decrease was primarily attributable to a decrease in both professional fees, insurance, and other due to lower accounting, consulting, and recruitment fees and compensation and benefits, due to lower headcount. Stock-based compensation was lower due to the value of the restricted stock awards being amortized for the nine months ended September 30, 2024 being lower than those being amortized during the nine months ended September 30, 2023, due to the decline in our stock price.
Other Income (Expense). Presented below is a comparison of our other income (expense) for the nine months ended September 30, 2024 and 2023:
Nine months ended September 30,
Change
2024
2023
Amount
Percent
(in thousands)
Commodity derivative gain (loss), net
$
537
$
704
$
(167
)
(24
)%
Interest (expense), net
(344
)
(864
)
520
60
%
Other income (expense), net
(67
)
46
(113
)
(246
)%
Total other income (expense)
$
126
$
(114
)
$
240
211
%
Commodity derivative gain (loss), net, is the result of changes in derivative fair values associated with fluctuations in forward price curves for the commodities underlying our outstanding derivative contracts and the monthly cash settlements of our derivative positions during the period. For the nine months ended September 30, 2024, we recognized gains on commodity derivative contracts of $0.5 million, primarily as the result of the settlement in September 2024 of all our remaining commodity derivative contracts for $1.8 million. See Note 7 Commodity Derivatives in the notes to the unaudited Condensed Consolidated Financial Statements.
Interest expense primarily represents the interest on our credit facility with FirstBank Southwest. The increase in interest expense is primarily driven by the decrease in the balance outstanding period over period. As of September 30, 2024, we had fully repaid all outstanding amounts borrowed on the credit facility as compared to $12.0 million borrowed as of September 30, 2023. The average interest rate increased to 9.2% per annum for the nine months ended September 30, 2024, as compared to 8.8% per annum for the nine months ended September 30, 2023. See Note 6 Debt in the notes to the unaudited Condensed Consolidated Financial Statements.
Liquidity and Capital Resources
Based on the current commodity price environment, we believe we have sufficient liquidity and capital resources to execute our business plan while continuing to meet our current financial obligations. We continue to manage our commitments in order to maintain flexibility with regard to our activity level and capital expenditures.
For the remainder of 2024 and into 2025, our capital budget will be substantially allocated to the completion of our recent helium discovery. Over the next year, we anticipate drilling 3 – 5 wells along with related helium development activities with costs ranging between $4.0 and $6.5 million depending primarily on the number of wells drilled. In addition, depending on timing, regulatory requirements and weather, we plan to incur costs for plugging and abandonment of approximately $1.0 million, We view much of these capital activities as discretionary for which we can control both the timing and amount of the expenditures. Other activities, such as some repairs and maintenance may be required from time to time by regulatory bodies. We anticipate our expenditures will be funded primarily by operating cash flows, borrowings under our credit facility and proceeds from divestitures of oil and gas properties. In the event that readily available sources of cash flow are insufficient to fund our capital needs, we may utilize equity and credit markets as a funding mechanism.
Sources of Cash
For the nine months ended September 30, 2024, we funded our capital expenditures with cash on hand, cash flows from operating activities, proceeds from the divestiture of oil and gas producing properties and borrowings under our credit facility. In future quarters, if cash flows are not sufficient to fund our capital expenditures and operations, we may also raise funds through new equity offerings or from other sources of financing and re-evaluate our capital spend program as economic conditions warrant. Additionally, we may enter into carrying cost and sharing arrangements with third parties for certain development programs. All of our sources of liquidity can be affected by the changes in economic conditions, rising interest rates, changes in debt and equity markets, force majeure events, fluctuations in commodity prices, operating costs, tax law changes, and volumes produced, all of which would affect us and our industry.
On January 5, 2022, we entered into a four-year credit agreement with FirstBank Southwest as administrative agent, which provides for a revolving line of credit with a borrowing base of $20 million, and a maximum credit amount of $100 million (the “Credit Agreement”). Under the Credit Agreement, revolving loans may be borrowed, repaid and re-borrowed until January 5, 2026, when all outstanding amounts must be repaid. The Credit Agreement contains customary indemnification requirements, representations and warranties and customary affirmative and negative covenants applicable to the Company and its subsidiaries. In addition, the Credit Agreement contains financial covenants, tested quarterly, that limit our ratio of total debt to EBITDAX (as defined in the Credit Agreement) to 3:1 and require our ratio of consolidated current assets to consolidated current liabilities (as each is described in the Credit Agreement) to remain at 1:1 or higher. We were in compliance with all financial covenants as of September 30, 2024. Please refer to Note 6 - Debt in Part I, Item 1 of this report for additional discussion.
The borrowing base is subject to being redetermined semi-annually, commencing on or about April 1 and October 1 of each year during the four-year term of the Credit agreement. Our borrowing base can be adjusted as a result of changes in commodity prices, acquisitions or divestitures of proved properties, or financing activities, all as provided for in the Credit Agreement.
Cash flows provided by our operating activities, proceeds received from divestitures of properties, capital markets activities, and our capital expenditures, including acquisitions, all impact the amount we borrow under our revolving Credit Agreement. The amount outstanding on the Credit Agreement as of September 30, 2024, was $0.0 million. With the proceeds from the sale of our Karnes County, Texas properties, we repaid $5.0 million on the Credit Agreement, reducing the amount outstanding to $2.0 million as of July 31, 2024. In addition, in September 2024, with the proceeds from the settlement of our outstanding commodity derivative contracts of $1.8 million and cash on hand, we repaid the remaining $2.0 million outstanding on the credit facility.
Uses of Cash
We use cash for the acquisition and development of helium and oil and gas properties, workovers and capital expenditures, operating and general and administrative costs, settlements of commodity derivative contracts, debt obligations including interest, and share repurchases. During the nine months ended September 30, 2024, we spent approximately $3.7 million on the acquisition of helium properties and capital expenditures.
The amount and allocation of our future capital expenditures will depend upon a number of factors, including our cash flows from operating, investing, and financing activities, our ability to execute our development program, and the number and size of acquisitions that we complete. In addition, the impact of helium, oil and gas prices on investment opportunities, the availability of capital, tax law changes, and the timing and results of our development activities may lead to changes in funding requirements for future development. We periodically review our capital expenditure budget to assess if changes are necessary based on current and projected cash flows, acquisition and divestiture activities, and other factors. We will continue to monitor the economic environment through the remainder of the year and adjust our activity level as warranted.
Cash Flows
The following table summarizes our cash flows for the nine months ended September 30, 2024 and 2023:
Nine months ended September 30,
2024
2023
Change
(in thousands)
Net cash provided by (used in):
Operating activities
$
2,891
$
2,977
$
(86
)
Investing activities
691
(3,365
)
4,056
Financing activities
(5,778
)
(2,049
)
(3,729
)
Operating Activities. Cash provided by operating activities of $2.9 million for the nine months ended September 30, 2024 remained consistent with cash provided by operating activities of $3.0 million for the comparable period in 2023.
Investing Activities. Cash provided by investing activities for the nine months ended September 30, 2024 was $0.7 million as compared to cash used in investing activities of $3.4 million for the comparable period in 2023. The primary use of cash in our investing activities for the nine months ended September 30, 2024 was the acquisition of helium properties and capital expenditures, which were offset by proceeds received from the divesture of oil and gas properties. For the nine months ended September 30, 2023, the primary use of cash in our investing activities was capital expenditures related to returning idle wells to production and improvements to our gathering system in East Texas.
Financing Activities. Cash used in financing activities for the nine months ended September 30, 2024 was $5.8 million as compared cash used in financing activities of $2.1 million for the comparable period in 2023. Cash used in financing activities during the nine months ended September 30, 2024 was primarily attributable to repayments of $7.0 million on our credit facility, which were partially offset by borrowings under the credit facility of $2.0 million to fund the acquisition of our recently acquired helium properties. In addition, we spent $0.6 million on share repurchases. Cash used in financing activities during the nine months ended September 30, 2023 primarily related to cash dividends paid of $1.2 million, payments on the insurance premium finance note of $0.5 million and share repurchases of $0.2 million
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Pursuant to Item 305(e) of Regulation S-K (§ 229.305(e)), the Company is not required to provide the information required by this Item as it is a “smaller reporting company,” as defined by Rule 229.10(f)(1).
Item 4. 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 information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms and (ii) accumulated and communicated to the Company’s management, including its principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.
As of September 30, 2024, our management, including our Chief Executive Officer and Chief Financial Officer, carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Based on the results of the evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls were not effective as of September 30, 2024 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. Such determination was made due to a material weakness in our internal control over financial reporting as of December 31, 2023, as discussed 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. As previously reported in our Annual Report on Form 10-K for the year ended December 31, 2023, filed with the SEC on March 26, 2024, in connection with our assessment of the effectiveness of our internal control over financial reporting at the end of our last fiscal year, management identified a material weakness in our internal control over financial reporting as of December 31, 2023. Specifically, our accounting system was not designed appropriately, and reliance could not be placed on some of the control elements of the accounting system. These control elements include a lack of certain functionality related to system-based account reconciliations, missing systematic controls in areas such as segregation of duties enforcement and data input validation, and an absence of independent evaluation of third-party information technology controls ("ITGCs"). The Company's manual review controls partially compensate for the system design limitations, but this material weakness cannot be remediated without the implementation of a system-based solution.
Limitations on Effectiveness of Controls and Procedures
In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply its judgment in evaluating the benefits of possible controls and procedures relative to their costs.
Changes in Internal Control over Financial Reporting
Except as disclosed below there were no changes in our internal control over financial reporting during thethree months ended September 30, 2024, that have materially affected or are reasonably likely to materially affect, our internal control over financial reporting.
As of September 30, 2024, we have evaluated our options and anticipate a new accounting system solution to be operational by mid-2025.
PART II – OTHER INFORMATION
Item 1. 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.
Item 1A. Risk Factors.
There have been no material changes from the risk factors previously disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2023, as filed with the SEC on March 26, 2024, under the heading “Item 1A. Risk Factors”, except as discussed below, and investors should review the risks provided in the Annual Report, prior to making an investment in the Company. The business, financial condition and operating results of the Company can be affected by a number of factors, whether currently known or unknown, including but not limited to those described in the Annual Report, under “Item 1A. Risk Factors”, and below, any one or more of which could, directly or indirectly, cause the Company’s actual financial condition and operating results to vary materially from past, or from anticipated future, financial condition and operating results. Any of these factors, in whole or in part, could materially and adversely affect the Company’s business, financial condition, operating results and stock price.
Our stock repurchases are discretionary and even if effected, they may not achieve the desired objectives.
On March 19, 2024, the Board of Directors authorized and approved an extension of the ongoing share repurchase program for up to $5.0 million of the currently outstanding shares of the Company’s common stock originally approved by the Board of Directors on April 26, 2023, and set to expire on June 30, 2024. Subject to any future extension in the discretion of the Board of Directors of the Company, the repurchase program is now scheduled to expire on June 30, 2025, or when a maximum of $5.0 million of the Company’s common stock has been repurchased, or when such program is discontinued by the Board of Directors. Under the stock repurchase program, shares may be repurchased from time to time in the open market or through negotiated transactions at prevailing market rates, or by other means in accordance with federal securities laws. Repurchases are made at management’s discretion at prices management considers to be attractive and in the best interests of both the Company and its stockholders, subject to the availability of stock, general market conditions, the trading price of the stock, alternative uses for capital, and the Company’s financial performance. During the nine months ended September 30, 2024, the Company repurchased 482,500 shares for $525 thousand, at a weighted average price of $1.09 per share, in open market transactions. As of September 30, 2024 a total of $4.0 million remains available under the shares repurchase program. The program does not obligate the Company to acquire a minimum amount of shares.
There can be no assurance that any repurchases pursuant to our stock repurchase program will enhance stockholder value because the market price of our common stock may decline below the levels at which we repurchase such shares. The amounts and timing of the repurchases may also be influenced by general market conditions, regulatory developments (including recent legislative actions which, subject to certain conditions, may impose an excise tax of 1% on our stock repurchases) and the prevailing price and trading volumes of our common stock. If our financial condition deteriorates or we decide to use our cash for other purposes, we may suspend repurchase activity at any time.
We may enter into strategic transactions in the future which may result in a material change in our operations and/or a change of control.
In the future, we or our majority stockholders, may enter into transactions with, or undertake transactions with, parties seeking to merge and/or acquire us and/or our operations. While neither we, nor our majority stockholders have entered into any such agreements or understandings to date, in the event that we or our majority stockholders do enter into such a transaction or transactions in the future, it could result in a change in our business focus, the acquisition of significant amounts of our outstanding common stock, or a change in our majority stockholders. We and our majority stockholders have not entered into any agreements relating to any strategic transaction involving the Company as of the date of this filing and may never enter into such agreement(s) in the future. Any future strategic transaction involving the Company or its operations may have a material effect on our operations, cash flows, results of operations, prospects, plan of operations, the listing of our common stock on the Nasdaq Capital Market, our officers, directors and majority stockholders, and the value of our securities.
We have written down, and may in the future be forced to further write-down, material portions of our assets due to low oil and natural gas prices.
The full cost method of accounting is used for oil and gas acquisition, exploration, development and production activities. 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 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 2023 we recorded ceiling test write-downs of $26.7 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, 2023, we used an average price applicable to our properties of $78.22 per barrel for oil and $2.64 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.
In the calculation of the ceiling test as of September 30, 2024, the Company used $78.64 per barrel for oil and $2.21 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%. The Company recorded a $6.8 million ceiling test write-down of its oil and gas properties during the nine months ended September 30, 2024, due to a reduction in the value of proved oil and natural gas reserves primarily as a result of a decrease in crude oil and natural gas prices, divestitures of oil and natural gas properties, as well as reserves revisions related to wells shut-in during the first quarter of 2024 and decline curve updates.
Material write-downs or impairments of our oil and gas properties have in the past and may in the future have a material adverse effect on our assets and/or our financial condition, either of which may cause the value of our securities to decline in value.
The Company’s operations have in the past been, and could in the future be, disrupted by natural or human causes beyond its control.
The Company’s operations are subject to disruption from natural or human causes beyond its control, including risks from hurricanes, severe storms, floods, lightning strikes, heat waves, other forms of severe weather, wildfires, ambient temperature increases, sea level rise, war, accidents, civil unrest, political events, fires, earthquakes, system failures, cyber threats, terrorist acts and epidemic or pandemic diseases such as the COVID-19 pandemic, some of which may be impacted by climate change and any of which could result in suspension of operations or harm to people or the natural environment. Any of the above events could have a future material adverse effect on the Company’s results of operations or financial condition.
The future value and reserves associated with our helium development are unknown and the Company may never realize the value of any reserves.
No reserves have been assigned in connection with helium property interests to date, given their early stage of development. The future value of the Company is therefore dependent on the success or otherwise of drilling and development activities, which are principally directed toward the further exploration, appraisal and development of its assets in Montana, and construction of a helium gas processing facility. Exploration, appraisal and development of helium reserves are speculative and involve a significant degree of risk. There is no guarantee that exploration or appraisal of the helium property will lead to a commercial discovery or, if there is a commercial discovery, that the Company will be able to realize the value of such reserves as intended. If at any stage the Company is precluded from pursuing its exploration and development programs, or construction of a processing facility, or such programs are otherwise not continued, the Company’s business, financial condition and/or results of operations and, accordingly, the price of the Company’s shares, is likely to be materially adversely affected. Helium exploration involves a high degree of risk and there is no assurance that expenditures made for future exploration or development activities will result in discoveries reserves that are commercially or economically viable.
The Company’s helium properties are in the exploration stage; such properties may never yield commercial quantities of helium; and the Company may not be able to commercially extract any helium, if present.
The Company’s helium properties are in the exploration stage only. The Company has never had any material interest in helium producing properties. There is no assurance that commercial quantities of helium will be discovered at any of the properties or any future properties, nor is there any assurance that the exploration or development programs of will yield any positive results. Even if commercial quantities of helium are discovered, there can be no assurance that any development will result in profitable helium production. Factors which may limit the Company’s ability to produce helium include, but are not limited to, commodity prices, availability of additional capital and financing and the nature of any helium deposits.
Our helium, 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 helium, 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.
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. It is also possible that such regulations, or our requirement to comply with such regulations, could have a material adverse effect on our operations, negatively affect our margins, and/or force us to curtail certain business operations.
Our helium operations will require us to obtain licenses and permits which may not be obtained, may be delayed, or may limit our ability to undertake exploration and production activities.
The helium operations of the Company will require us to obtain licenses for operating, permits, and in some cases, renewals of existing licenses and permits from government agencies. There can be no assurances that the Company will attain all permits and licenses necessary to achieve profitable production of helium in the future. Further, the ability of the Company to obtain, sustain or renew any such licenses and permits on acceptable terms is subject to changes in regulations and policies and to the discretion of the applicable authorities or other governmental agencies.
Our helium operations are subject to risks and hazards which may not be covered by insurance.
The Company’s helium operations are subject to a number of risks and hazards generally, including adverse environmental conditions, accidents, mechanical failures, labor shortages, unusual or unexpected geological conditions, ground or slope failures, cave-ins, changes in the regulatory environment and natural phenomena such as inclement weather conditions, floods and earthquakes. Such occurrences could result in damage to our helium properties and/or facilities, personal injury or death, environmental damage to the properties, or delays in exploration, development and production activities, monetary losses and possible legal liability. Although the Company maintains insurance to protect against certain risks in such amounts as it considers reasonable, its insurance will not cover all the potential risks associated with helium operations. The Company may also be unable to maintain insurance to cover these risks at reasonable costs. Insurance coverage may not continue to be available or may not be adequate to cover any resulting liability. These events and limits to insurability may result in significant costs that could have a material adverse effect upon our financial performance and results of operations.
We face risks associated with our ability to locate and commercially extract helium.
The future value of the Company will depend in part on our ability to find and develop helium resources that are economically recoverable within the Kevin Dome Structure in Toole County, Montana. The circumstances in which a discovered helium accumulation becomes or remains commercially viable depends on a number of factors. These include the particular attributes of the deposit, such as size, depth concentration, development cost and proximity to infrastructure as well as key external factors such as helium supply and demand. This, along with other factors such as maintaining title to licenses, leases and permits, successful design, construction, commissioning and operating of wells and processing facilities may result in projects not being developed, or operations becoming unprofitable. Helium exploration involves exploration activities and drilling operations which may not generate a positive return on investment. This may arise from dry wells, but also from wells that are productive but do not produce sufficient revenues to return a profit after accounting for drilling, operating and other associated costs. The outcome of any drilling program may be dependent on matters which include the reservoir’s composition, the flow rate and the rate of any decrease in pressure as the gas flows to the surface. These matters cannot be known until the Company undertakes initial drilling programs. The production from successful wells may also be impacted by various operating conditions, including insufficient storage or transportation capacity, or other geological and mechanical conditions. In addition, managing drilling hazards or environmental damage and pollution caused by exploration and development operations could greatly increase the associated cost and profitability of individual wells. The future exploration activities of the Company may be affected by a range of factors including geological conditions, limitations on activities due to seasonal weather patterns, unanticipated operational and technical difficulties, industrial and environmental accidents, landholder disputes, changing government regulations and many other factors beyond the control of the Company.
The success of the Company will also depend upon the Company having access to sufficient development capital, being able to maintain title to its projects and obtain all required approvals for its activities. In the event that exploration programs prove to be unsuccessful this could lead to a diminution in the value of the Company’s projects, a reduction in the cash reserves of the Company and possible relinquishment of the Company’s projects.
The exploration costs of the Company are based on certain assumptions with respect to the method and timing of exploration. By their nature, these estimates and assumptions are subject to significant uncertainties and, accordingly, the actual costs may materially differ from these estimates and assumptions. Accordingly, no assurance can be given that the cost estimates and the underlying assumptions will be realized in practice, which may materially and adversely affect the Company’s results of operations. Helium exploration involves significant risk since few properties that are explored contain reserves that would be commercially economic to develop into producing wells. As such, there can be no assurance that existing or future exploration programs will result in discovery of commercially viable reserves. If there are resources located, there is no guarantee they can be commercially produced.
The Company has never had any helium producing properties and such properties may not result in profitable helium production.
The Company’s helium interests are exploration stage only. The Company has never had any material interest in helium producing properties. Even with application of best science, there is no assurance that commercial quantities of helium will be discovered at any of the properties of the Company or any future properties, nor is there any assurance that the exploration or development programs of the Company thereon will yield any positive results. The future development of any properties found to be economically feasible will require the construction and operation of wells and related infrastructure. Even if commercial quantities of helium are discovered, there can be no assurance that any property of the Company will ever be brought to a stage where helium can profitably be produced thereon. Factors which may limit the ability of the Company to produce helium from its properties include, but are not limited to, commodity prices, availability of additional capital and financing and the nature of any helium deposits. It is common in helium operations to experience unexpected costs, problems and delays during construction and development. In addition, delays in the early stages of helium production often occur. Accordingly, there cannot be any assurance that activities will result in profitable helium operations at our operations.
The Company faces helium drilling risks.
The Company’s helium exploration and development activities are dependent on the availability of drilling rigs and related equipment in the Kevin Dome Structure in Toole County, Montana. Increases in oil and gas exploration activities could result in higher demand and limited availability for some types of drilling rigs and equipment in certain areas, which may result in delays to the Company’s planned exploration and development activities.
The Company may encounter hazards inherent in drilling activities. Examples of such hazards include unusual or unexpected formations, abnormal pressures or rock properties, adverse weather conditions, mechanical difficulties, conditions which could result in damage to plant or equipment or shortages or delays in the delivery of rigs and/or other equipment. Drilling may result in wells that, or which encounter resources, that may not achieve economically viable results.
While the Company intends to take adequate precautions to minimize risks associated with drilling activities, there can be no guarantee that the Company will not experience one or more material incidents during drilling activities that may have an adverse impact on the operating and financial performances of the Company, including costs associated with control of well operation, recovery of plant and equipment, environmental rectification and compensation along with delays and other impacts on anticipated results.
The Company may be unable or unwilling to develop commercially viable helium operations.
On a long-term basis, in order for the Company’s helium operations to be successful, the Company must explore, develop and produce, or acquire interests in producing helium properties. The success depends on the ability to locate, identify, and acquire prospective helium exploration lands and productive helium property interests, find markets for any helium developed on such properties, and effectively distribute the helium into those markets. The helium development activities may not be economically viable because of unproductive helium properties, as well as helium properties that are productive but do not generate sufficient revenue to return a profit. Investing in a property does not ensure that the investment will be profitable since profitability depends on the cost of drilling and operating any wells on the property may exceed the amount of helium extracted from such wells. In addition, drilling hazards or environmental damage could increase the cost of operating any property. If the developmental costs exceed the Company’s estimate or if the development efforts of the Company do not produce results which meet our expectations, such efforts may not be commercially viable.
There are numerous risk associated with estimating helium reserves.
No reserves have been assigned in connection with the Company’s helium property interests to date, given their early stage of development. The future value of the Company’s helium reserves, if any, is therefore dependent on the success or otherwise of its activities, which are principally directed toward the future exploration, appraisal and development of its helium assets, and potential acquisition of property interests in the future. Estimating helium volumes is subject to significant uncertainties associated with technical data and the interpretation of that data, future commodity prices, and development and operating costs. There can be no guarantee that the Company will successfully convert any helium located on its properties to reserves and produce such estimated volume, if any. Estimates may alter significantly or become more uncertain when new information becomes available due to for example, additional drilling or production tests over the life of the field. As estimates change, development and production plans may also vary. Downward revision of helium volume estimates may adversely affect the Company’s operational or financial performance.
Helium volume estimates are expressions of judgment based on knowledge, experience and industry practice. These estimates are imprecise and depend to some extent on interpretations, which may ultimately prove to be inaccurate and require adjustment or, even if valid when originally calculated, may alter significantly when new information or techniques become available. As further information becomes available through additional drilling and analysis the estimates are likely to change. Any adjustments to volume could affect the Company’s exploration and development plans which may, in turn, affect the Company’s performance. The process of estimating helium resources is complex and requires significant decisions and assumptions to be made in evaluating the reliability of available geological, geophysical, engineering, and economic data for each property. Different engineers may make different estimates of resources, cash flows, or other variables based on the same available data.
Estimates include numerous assumptions relating to operating conditions and economic factors, including price at which recovered helium can be sold, future operating costs, costs associated with operations on producing wells to restore or increase production, and prevailing environment conditions associated with drilling.
The Company faces risks associated with its current lack of distribution agreements.
While the Company intends to partner with or sell to major industrial gas companies, the Company’s strategy is to become a fully integrated helium developer and processor and to sell directly to a limited number of major distributors and end-users in order to capture higher margins on its products. The Company currently does not have any formal agreements in place for accomplishing these strategic objectives, and the associated costs of and estimated timeline for the completion of these strategic objectives will not be able to be determined until such time that appraisal wells have been drilled and feasibility studies have been completed. Although the Company intends to enter into such formal agreements in the future, they may never be entered into. The absence of formal agreements could adversely affect the oversight and operations of any arrangement with these major industrial gas companies, major distributors and end-users, and the lack of clarity and specifically defined roles could lead to a strain on, or breakdown of, the working relationships between the Company and any of these major industrial gas companies, major distributors or end-users. Furthermore, in the event of a dispute prior to entry into formal agreements, it will not be immediately clear what recourse each party has against the other, if any.
The Company’s helium production and margins thereon, if any, will be subject to changing helium prices.
The Company’s possible future helium operation revenues may be derived from helium or from royalties gained from potential joint ventures or other arrangements. Consequently, the Company’s potential future earnings will likely be closely related to the price of helium. Helium prices fluctuate and are affected by numerous industry factors including demand for the resource, forward selling by producers, production cost levels in major producing regions and macroeconomic factors, such as inflation, interest rates, currency exchange rates and global and regional demand for, and supply of, helium. If the Company is producing helium and the market price of helium were to fall below the costs of production and remain at such a level for any sustained period, the Company would experience losses and could have to curtail or suspend some or all of its proposed activities. In such circumstances, the Company would also have to assess the economic impact of any sustained lower commodity prices on recoverability.
The Company’s helium operations will be subject to transportation costs and risks.
Disruption in or increased costs of transportation services could make helium a less competitive product or could make the Company’s future helium production, if any, less competitive than other sources. The industry depends on trucking, ocean-going vessels, pipeline facilities, and barge transportation to deliver shipment, and transportation costs are a significant component of the total cost of supplying helium. Disruptions of these transportation services due to weather problems, strikes, delays, lockouts, or other events could temporarily impair the ability to supply helium to customers and may result in lost sales. In addition, increases in transportation costs could adversely affect profitability.
The Company’s helium exploration and production activities will be subject to technological risks.
The helium industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technology. Other companies may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in future allow them to implement new technologies before the Company does. There can be no assurance that the Company will be able to respond to such competitive pressures and implement such technologies on a timely basis or at an acceptable cost. If the Company is unable to use the most advanced commercially available technology its business, financial condition and results of operations could be materially adversely affected.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
Sales of Unregistered Securities
There have been no sales of unregistered securities during the quarter ended September 30, 2024, and from the period from October 1, 2024, to the filing date of this Report.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table sets forth share repurchase activity for the respective periods:
Total Number
Approximate
of Shares
Dollar Value of
Purchased as
Shares that
Part of
May Yet Be
Publicly
Purchased
Total Number
Average
Announced
Under the
of Shares
Price Paid Per
Plans or
Plans or
Period
Purchased
Share
Programs(1)
Programs(1)
July 1- July 31, 2024
—
$
—
—
$
4,058,047
August 1 - August 31, 2024
—
$
—
—
$
4,058,047
September 1 - September 30, 2024
19,000
$
1.05
19,000
$
4,037,713
Total
19,000
$
1.05
19,000
$
4,037,713
(1) On March 19, 2024, the Board of Directors authorized and approved an extension of the ongoing share repurchase program for up to $5.0 million of the currently outstanding shares of the Company’s common stock originally approved by the Board of Directors on April 26, 2023, and set to expire on June 30, 2024. Subject to any future extension in the discretion of the Board of Directors of the Company, the repurchase program is now scheduled to expire on June 30, 2025, or when a maximum of $5.0 million of the Company’s common stock has been repurchased, or when such program is discontinued by the Board of Directors. Under the stock repurchase program, shares may be repurchased from time to time in the open market or through negotiated transactions at prevailing market rates, or by other means in accordance with federal securities laws. Repurchases are made at management’s discretion at prices management considers to be attractive and in the best interests of both the Company and its stockholders, subject to the availability of stock, general market conditions, the trading price of the stock, alternative uses for capital, and the Company’s financial performance. The repurchase program is funded using the Company’s working capital. The program does not obligate the Company to acquire a minimum amount of shares.
Item 3. Defaults Upon Senior Securities.
Not applicable.
Item 4. Mine Safety Disclosures.
Not applicable.
Item 5. Other Information.
Rule 10b5-1(c) Trading Plans. Our directors and executive officers may from time to time enter into plans or other arrangements for the purchase or sale of our shares that are intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or may represent a non-Rule 10b5-1 trading arrangement under the Exchange Act. During the quarter ended September 30, 2024, none of the Company’s directors or officers (as defined in Rule 16a-1(f)) adopted or terminated any contract, instruction or written plan for the purchase or sale of Company securities that was intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or any “non-Rule 10b5-1 trading arrangement.”
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*
Inline XBRL Schema Document
X
101.CAL*
Inline XBRL Calculation Linkbase Document
X
101.DEF*
Inline XBRL Definition Linkbase Document
X
101.LAB*
Inline XBRL Label Linkbase Document
X
101.PRE*
Inline XBRL Presentation Linkbase Document
X
104*
Inline XBRL for the cover page of this Quarterly Report on Form 10-Q, included in the Exhibit 101 Inline XBRL Document Set
X
*
Filed herewith.
†
Certain schedules and exhibits have been omitted pursuant to Item 601(b)(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.
♦
Furnished herewith.
#
Indicates management contract or compensatory plan or arrangement.
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.
