Document And Entity Information
Document And Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2022 | May 19, 2023 | Jun. 30, 2022 | |
Document Information Line Items | |||
Entity Registrant Name | ROYALE ENERGY, INC. | ||
Trading Symbol | ROYL | ||
Document Type | 10-K | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Common Stock, Shares Outstanding | 65,143,012 | ||
Entity Public Float | $ 2,702,007 | ||
Amendment Flag | false | ||
Entity Central Index Key | 0001694617 | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Well-known Seasoned Issuer | No | ||
Document Period End Date | Dec. 31, 2022 | ||
Document Fiscal Year Focus | 2022 | ||
Document Fiscal Period Focus | FY | ||
Entity Small Business | true | ||
Entity Emerging Growth Company | false | ||
Entity Shell Company | false | ||
ICFR Auditor Attestation Flag | false | ||
Document Annual Report | true | ||
Entity File Number | 000-55912 | ||
Entity Incorporation, State or Country Code | DE | ||
Entity Tax Identification Number | 81-4596368 | ||
Entity Address, Address Line One | 1530 Hilton Head Road #205 | ||
Entity Address, City or Town | El Cajon | ||
Entity Address, State or Province | CA | ||
Entity Address, Postal Zip Code | 92019 | ||
City Area Code | 619-383-6600 | ||
Local Phone Number | 619-383-6600 | ||
Title of 12(g) Security | Common Stock, 0.001 par value per share | ||
Entity Interactive Data Current | Yes | ||
Document Financial Statement Error Correction [Flag] | false | ||
Auditor Firm ID | 171 | ||
Auditor Name | HORNE LLP | ||
Auditor Location | Ridgeland, Mississippi | ||
Document Transition Report | false | ||
Security Exchange Name | NONE |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) | Dec. 31, 2022 | Dec. 31, 2021 |
Current Assets: | ||
Cash and Cash Equivalents | $ 1,650,507 | $ 220,304 |
Restricted Cash | 2,249,627 | 4,002,500 |
Other Receivables, net | 943,633 | 413,133 |
Revenue Receivables | 701,937 | 365,150 |
Prepaid Expenses and Other Current Assets | 1,935,346 | 150,837 |
Deferred Drilling Costs | 1,219,177 | 2,256,461 |
Prepaid Drilling to RMX Resources, LLC | 114,563 | 276,423 |
Total Current Assets | 8,814,790 | 7,684,808 |
Other Assets | 589,865 | 598,873 |
Right of Use Asset - Operating Leases | 335,213 | 423,299 |
Oil and Gas Properties (Successful Efforts Basis), Real Property and Equipment and Fixtures, net | 2,040,320 | 2,079,800 |
Total Assets | 11,780,188 | 10,786,780 |
Current Liabilities: | ||
Accounts Payable and Accrued Expenses | 5,528,829 | 5,160,484 |
Royalties Payable | 612,925 | 623,405 |
Notes Payable | 0 | 113,915 |
Due RMX Resources, LLC | 23,087 | 23,087 |
Accrued Liabilities | 208,307 | 201,172 |
Operating Leases - Current | 81,995 | 88,257 |
Asset Retirement Obligation - Current | 675,000 | 648,536 |
Deferred Drilling Obligations | 8,129,965 | 7,824,939 |
Total Current Liabilities | 15,260,108 | 14,683,795 |
Noncurrent Liabilities: | ||
Asset Retirement Obligation | 2,867,479 | 2,610,560 |
Operating Leases - Non-current | 254,858 | 336,959 |
Accrued Unpaid Guaranteed Payments | 1,616,205 | 1,616,205 |
Accrued Liabilities - Non-current | 1,306,605 | 1,306,605 |
Total Liabilities | 21,305,255 | 20,554,124 |
Mezzanine Equity: | ||
Convertible Preferred Stock, Series B, $10 par value, 3,000,000 Shares Authorized, 2,361,154 and 2,280,289 shares issued and outstanding at December 31, 2022 and 2021, respectively | 23,611,536 | 22,802,899 |
Stockholders’ Deficit: | ||
Common Stock | 61,876 | 56,239 |
Additional Paid in Capital | 54,447,923 | 54,058,554 |
Accumulated Deficit | (87,646,402) | (86,685,036) |
Total Stockholder’s Deficit | (33,136,603) | (32,570,243) |
Total Liabilities, Mezzanine Equity and Stockholders’ Deficit | $ 11,780,188 | $ 10,786,780 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parentheticals) - $ / shares | Dec. 31, 2022 | Dec. 31, 2021 |
Statement of Financial Position [Abstract] | ||
Convertible Preferred, shares issued | 2,361,154 | 2,280,289 |
Convertible Preferred Stock, Series B, par value (in Dollars per share) | $ 10 | $ 10 |
Convertible Preferred Stock, shares outstanding | 2,361,154 | 2,280,289 |
Convertible Preferred Stock, Shares Authorized | 3,000,000 | 3,000,000 |
Common Stock, Par Value (in Dollars per share) | $ 0.001 | $ 0.001 |
Common stock, shares authorized | 280,000,000 | 280,000,000 |
Common Stock, shares issued | 61,876,957 | 56,239,715 |
Common Stock, shares outstanding | 61,876,957 | 56,239,715 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Revenues: | ||
Revenues | $ 2,642,537 | $ 1,718,664 |
Costs and Expenses: | ||
Lease Operating | 1,928,521 | 1,814,643 |
Impairment | 0 | 177,011 |
Depreciation, Depletion and Amortization | 575,909 | 537,273 |
Bad Debt Expense | 0 | 190,414 |
General and Administrative | 1,808,197 | 1,951,083 |
Legal and Accounting | 526,550 | 419,587 |
Marketing | 259,101 | 230,346 |
Total Costs and Expenses | 5,098,278 | 5,320,357 |
Gain (Loss) on Turnkey Drilling Programs | 1,726,414 | (64,468) |
Loss from Operations | (729,327) | (3,666,161) |
Other Income (Expense): | ||
Interest Expense | (2,452) | (9,206) |
Gain on Settlement of Payables | 422,614 | 12,071 |
Other Gain | 163,571 | 0 |
Gain on Sale of Assets | 0 | 64,878 |
Loss Before Income Tax Expense | (145,594) | (3,598,418) |
Provision for Income Taxes | 0 | 0 |
Net Loss | $ (145,594) | $ (3,598,418) |
Basic and Diluted Loss Per Share (in Dollars per share) | $ (0.02) | $ (0.06) |
Weighted average number of common shares outstanding, basic and diluted (in Shares) | 58,472,340 | 55,887,319 |
Oil and Gas [Member] | ||
Revenues: | ||
Revenues | $ 2,611,222 | $ 1,686,424 |
Management Service [Member] | ||
Revenues: | ||
Revenues | $ 31,315 | $ 32,240 |
CONSOLIDATED STATEMENTS OF STOC
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT) - USD ($) | Common Stock [Member] | Additional Paid-in Capital [Member] | Retained Earnings [Member] | Total |
Balance at Dec. 31, 2020 | $ 54,605 | $ 53,883,479 | $ (82,298,785) | $ (28,360,701) |
Balance (in Shares) at Dec. 31, 2020 | 54,605,488 | |||
Stock issued in lieu of Compensation | $ 1,634 | 175,075 | 176,709 | |
Stock issued in lieu of Compensation (in Shares) | 1,634,227 | |||
Preferred Series B 3.5% Dividend | (787,833) | (787,833) | ||
Net Loss | (3,598,418) | (3,598,418) | ||
Balance at Dec. 31, 2021 | $ 56,239 | 54,058,554 | (86,685,036) | (32,570,243) |
Balance (in Shares) at Dec. 31, 2021 | 56,239,715 | |||
Stock issued in lieu of Compensation | $ 5,637 | 389,369 | 395,006 | |
Stock issued in lieu of Compensation (in Shares) | 5,637,242 | |||
Preferred Series B 3.5% Dividend | (815,772) | (815,772) | ||
Net Loss | (145,594) | (145,594) | ||
Balance at Dec. 31, 2022 | $ 61,876 | $ 54,447,923 | $ (87,646,402) | $ (33,136,603) |
Balance (in Shares) at Dec. 31, 2022 | 61,876,957 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | ||
Net Loss | $ (145,594) | $ (3,598,418) |
Adjustments to Reconcile Net Loss to Net Cash Used by Operating Activities: | ||
Depreciation, Depletion, and Amortization | 575,909 | 537,273 |
Impairment | 0 | 177,011 |
Gain on Sale of Assets | 0 | (64,878) |
(Gain) Loss on Turnkey Drilling Programs | (1,726,414) | 64,468 |
Gain on Settlement of Accounts Payable | (422,614) | (12,071) |
Bad Debt Expense | 0 | 190,414 |
Other Gain | (163,571) | 0 |
Stock-Based Compensation | 395,006 | 176,709 |
Right of Use Asset Depreciation | 10,989 | 10,972 |
(Increase) Decrease in: | ||
Other & Revenue Receivables | (867,287) | (301,771) |
Prepaid Expenses and Other Assets | (1,613,641) | 30,226 |
Increase (Decrease) in: | ||
Accounts Payable and Accrued Expenses | 1,157,909 | 1,165,966 |
Royalties Payable | (10,480) | 0 |
Net Cash Used in Operating Activities | (2,809,788) | (1,624,099) |
CASH FLOWS FROM INVESTING ACTIVITIES: | ||
Expenditures for Oil and Gas Properties | (4,723,629) | (4,146,131) |
Proceeds from Turnkey Drilling Programs | 7,332,500 | 6,538,500 |
Proceeds from Sale of Assets | 0 | 1,072,655 |
Net Cash Provided by Investing Activities | 2,608,871 | 3,465,024 |
CASH FLOWS FROM FINANCING ACTIVITIES: | ||
Principal Payments on Long-Term Debt | (121,753) | (58,294) |
Office Rent Financing Agreement | 0 | 38,490 |
Net Used by Financing Activities | (121,753) | (19,804) |
Net (Decrease) Increase in Cash | (322,670) | 1,821,121 |
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year | 4,222,804 | 2,401,683 |
Cash, Cash Equivalents, and Restricted Cash at End of Year | 3,900,134 | 4,222,804 |
Cash Paid for Interest | 2,452 | 2,942 |
Cash Paid for Taxes | 6,850 | 10,394 |
Supplemental Schedule of Non-Cash Investing and Financing Transactions: | ||
Asset Retirement Obligation Addition | 29,338 | 0 |
(Decrease) Increase in Capital Accrued Balance | (206,806) | 208,792 |
Series B Paid-In-Kind Dividends | $ 815,772 | $ 787,833 |
SUMMARY OF SIGNIFICANT ACCOUNTI
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
Significant Accounting Policies [Text Block] | NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES This summary of significant accounting policies of Royale Energy, Inc. (in these notes sometimes called “we”, “us”, “our”) is presented to assist in understanding our financial statements. These consolidated financial statements include the accounts of Royale Energy Inc and our controlled subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis. The financial statements and notes are representations of our management, which is responsible for their integrity and objectivity. These accounting policies conform to accounting principles generally accepted in the United States of America and have been consistently applied in the preparation of the financial statements. Description of Business We are an independent oil and gas producer and we also perform turnkey drilling operations. We own wells and leases in major geological basins located primarily in California, Texas, Oklahoma, and Utah, and offer fractional working interests and seek to minimize the risks of oil and gas drilling by selling multiple well drilling projects which do not include the use of debt financing. Use of Estimates The accompanying consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America and requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and 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. Actual results could differ from those estimates. Estimated quantities of crude oil and condensate, NGLs and natural gas reserves is a significant estimate that requires judgment. All of the reserve data included in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and condensate, NGLs and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and condensate, NGLs and natural gas reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil and condensate, NGLs and natural gas that are ultimately recovered. See Note 19 – Supplemental Information About Oil and Gas Producing Activities (Unaudited) to our Consolidated Financial Statements for further detail. Other items subject to estimates and assumptions include the carrying amounts of accounts receivable, property, plant and equipment, equity method investments, asset retirement obligations, and valuation allowances for deferred tax assets, among others. Although we believe these estimates are accurate, actual results could differ from these estimates. Liquidity and Going Concern The primary sources of liquidity have historically been issuances of common stock, oil and gas sales through ongoing operations and the sale of oil and gas properties. There are factors that give rise to substantial doubt about our ability to meet liquidity demands, and we anticipate that our primary sources of liquidity will be from the issuance of debt and/or equity, the sale of oil and natural gas property participation interests through our normal course of business and the sale of non-strategic assets. Our 2022 consolidated financial statements reflect a working capital deficiency of $6,445,318 and a net loss from operations of $145,594. These factors raise substantial doubt about our ability to continue as a going concern. The accompanying consolidated financial statements do not include any adjustments that might be necessary if we are unable to continue as a going concern. Management’s plans to alleviate the going concern by implementing cost control measures that include the reduction of overhead costs and through the sale of non-strategic assets. There is no assurance that additional financing will be available when needed or that management will be able to obtain financing on terms acceptable to us and whether we will become profitable and generate positive operating cash flow. If we are unable to raise sufficient additional funds, we will have to develop and implement a plan to further extend payables and reduce overhead until sufficient additional capital is raised to support further operations. There can be no assurance that such a plan will be successful. Restricted Cash We sponsor turnkey drilling arrangements in proved and unproved properties. The contracts require that participants pay us the full contract price upon execution of the drilling agreement. Each participant earns an undivided interest in the well bore at the completion of the well. A portion of the funds received in advance of the drilling of a well from a working interest participant are held for the expressed purpose of drilling a well. If something changes, we may designate these funds for a substitute well. Under certain conditions, a portion of these funds may be required to be returned to a participant. Once the well is drilled, the funds are used to satisfy the drilling cost. We classify these funds prior to commencement of drilling as restricted cash based on guidance codified as under the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 230-10-50-8. In the event that progress payments are made from these funds; they are recorded as Prepaid Expenses and Other Current Assets. The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheets that sum to the total of the same amounts shown in the statement of cash flows. Year Ended December 31, 2022 2021 Cash and cash equivalents $ 1,650,507 $ 220,304 Restricted cash 2,249,627 4,002,500 Total cash, cash equivalents, and restricted cash shown in the Statement of Cash Flows $ 3,900,134 $ 4,222,804 Other Receivables Our other receivables consist of receivables from direct working interest investors and industry partners. We provide for uncollectible accounts receivable using the allowance method of accounting for bad debts. Under this method of accounting, a provision for uncollectible accounts is charged directly to bad debt expense when it becomes probable the receivable will not be fully collected. The allowance account is increased or decreased based on past collection history and management’s evaluation of accounts receivable. All amounts considered uncollectible are charged against the allowance account and recoveries of previously charged off accounts are added to the allowance. At December 31, 2022 and 2021, we established an allowance for uncollectable accounts of $2,757,549 and $2,761,398, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue. Revenue Receivables Our revenue receivables consist of receivables related to the sale of our natural gas and oil. Once a production month is completed, we receive payment approximately 15 to 30 days later. Historically, we have not had issues related to the collection of revenue receivables, and as such have determined that an allowance for revenue receivables is not currently necessary. Equity Method Investments Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting. Income from equity method investments represents our proportionate share of net income generated by the equity method investees and is reflected in revenue and other income in our consolidated statements of income. Equity method investments are included as noncurrent assets on the consolidated balance sheets. Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value may have occurred as called for under ASC 323, Investments—Equity Method and Joint Ventures. When a loss is deemed to have occurred and is other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income. Revenue Recognition A significant portion of our revenues are derived from the sale of crude oil, condensate, natural gas liquids (“NGLs”) and natural gas under spot and term agreements with our customers as follows: Year Ended December 31, 2022 2021 Oil & Condensate Sales $ 1,654,840 $ 1,238,014 Natural Gas Sales 947,407 445,080 NGL Sales 8,975 3,330 $ 2,611,222 $ 1,686,424 The pricing in our hydrocarbon sales agreements are variable, determined using various published benchmarks which are adjusted for negotiated quality and location differentials. As a result, revenue collected under our agreements with customers is highly dependent on the market conditions and may fluctuate considerably as the hydrocarbon market prices rise or fall. Typically, our customers pay us monthly, within a short period of time after we deliver the hydrocarbon products. As such, we do not have any financing element associated with our contracts. We do not have any issues related to returns or refunds, as product specifications are standardized for the industry and are typically measured when transferred to a common carrier or midstream entity, and other contractual mechanisms (e.g., price adjustments) are used when products do not meet those specifications. In limited cases, we may also collect advance payments from customers as stipulated in our agreements; payments in excess of recognized revenue are recorded as contract liabilities on our consolidated balance sheets. Under our hydrocarbon sales agreements, the entire consideration amount is variable either due to pricing and/or volumes. We recognize revenues in the amount of variable consideration allocated to distinct units of hydrocarbons transferred to a customer. Such allocation reflects the amount of total consideration we expect to collect for completed deliveries of hydrocarbons and the terms of variable payment relate specifically to our efforts to satisfy the performance obligations under these contracts. Our performance obligations under our hydrocarbon sales agreements are to deliver either the entire production from the dedicated wells or specified contractual volumes of hydrocarbons. We often serve as the operator for jointly owned oil and gas properties. As part of this role, we perform activities to explore, develop and produce oil and gas properties in accordance with the joint operating arrangement and collective decisions of the joint parties. Other working interest owners reimburse us for costs incurred based on our agreements. We determined that these activities are not performed as part of customer relationships, and such reimbursements are recorded as cost reimbursements. We commonly market the share of production belonging to other working interest owners as the operator of jointly owned oil and gas properties. Those marketing activities are carried out as part of the collaborative arrangement, and we do not purchase or otherwise obtain control of other working interest owners’ share of production. Therefore, we act as a principal only in regard to the sale of our share of production and recognize revenue for the volumes associated with our net production. We frequently sells a portion of the working interest in each well we drill or participate in to third-party investors and retains a portion of the prospect for our own account. We typically guarantee a cost to drill to the third-party drilling participants and record a loss or gain on the difference between the guaranteed price and the actual cost to drill the well. When monies are received from third parties for future drilling obligations, we record the liability as Turnkey Drilling Obligations. Once the contracted depth for the drilling of the well is reached and a determination as to the commercial viability of the well (typically call “Casing Point Election” or “Logging Point”), the difference in the actual cost to drill and the guaranteed cost is recorded as income or expense depending on whether there was a gain or loss. Crude oil and condensate For the crude sales agreements, we satisfy our performance obligations and recognize revenue once customers take control of the crude at the designated delivery points, which include pipelines, trucks or vessels. Natural Gas and NGLs When selling natural gas and NGLs, we engage midstream entities to process our production stream by separating natural gas from the NGLs. Frequently, these midstream entities also purchase our natural gas and NGLs under the same agreements. In these situations, we determined the performance obligation is complete and satisfied at the tailgate of the processing plant when the natural gas and NGLs become identifiable and measurable products. We determined the plant tailgate is the point in time where control, is transferred to midstream entities and they are entitled to significant risks and rewards of ownership of the natural gas and NGLs. The amounts due to midstream entities for gathering and processing services are recognized as shipping and handling cost and included as lease operating expense in our consolidated Statement of Operations, since we make those payments in exchange for distinct services with the exception of natural gas sold to PG&E where transportation cost is netted directly against revenues. Under some of our natural gas processing agreements, we have an option to take the processed natural gas and NGLs in-kind and sell to customers other than the processing company. In those circumstances, our performance obligations are complete after delivering the processed hydrocarbons to the customer at the designated delivery points, which may be the tailgate of the processing plant or an alternative delivery point requested by the customer. Turnkey Drilling Obligations We manage these Turnkey Agreements for the participants of the well. The collections of pre-drilling Authorization for Expenditure (“AFE”) amounts are segregated and the gains and losses on the Turnkey Agreements are recorded in income or expense at the time of the casing point election in accordance with ASC 932-323-25 and 932-360. We manage the performance obligation for the well participants and only record revenue or expense at the time the performance obligation of the Turnkey Agreement has been satisfied. Supervisory Fees and Other For the years ended December 31, 2022 and 2021, we recognized $31,315 and $32,240, respectively in supervisory fees in Pipeline and Compressor fees which were received and allocated based on production volumes. Oil and Gas Property and Equipment Successful Efforts We use the “successful efforts” method to account for our exploration and production activities. Under this method, we accumulate our proportionate share of costs on a well-by-well basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred, and capitalize expenditures for productive wells. We amortize the costs of productive wells under the unit-of-production method. We carry, as an asset, exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred. Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves. Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using unit-of-production rates based on the amount of proved developed reserves of oil and gas that are estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production method, oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank. Production Cost Production costs are expensed as incurred. Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain our wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labor costs to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity. Depreciation, Depletion and Amortization Depreciation, depletion and amortization, based on cost less estimated salvage value of the asset, are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized, and the assets replaced are retired. The project drilling phase commences with the development of the detailed engineering design and ends when the assets are ready for their intended use. Interest costs, to the extent they are incurred to finance expenditures during the construction phase, are included in property, plant and equipment and are depreciated over the service life of the related assets. Impairment We evaluate our oil and gas producing properties, including capitalized costs of exploratory wells and development costs, for impairment of value whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. Oil and gas producing properties are reviewed for impairment on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure or contractual terms that cause economic interdependency amongst separate, discrete fields. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows or, if available, comparable market value. We evaluate our unproved property investment and record impairment based on time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved property investments are deemed to be impaired, this amount is reported in exploration expenses in our consolidated statements of operations. During 2021 we recorded impairment losses of $177,011, on various capitalized lease and land costs where the carrying value exceeded the fair value. In 2022 there were no impairment losses. Upon the sale or retirement of a complete field of a proved property, we eliminate the cost from our books, and the resultant gain or loss is recorded to our consolidated statements of operations. Upon the sale of an entire interest in an unproved property where the property has been assessed for impairment individually, a gain or loss is recognized in our consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a recovery of the cost in the interest retained with any excess funds recognized as a gain. Should our turnkey drilling agreements include unproved property, total drilling costs incurred to satisfy our obligations are recovered by the total funds received under the agreements. Any excess funds are recorded as a Gain on Turnkey Drilling Programs, and any costs not recovered are capitalized and accounted for under the “successful efforts” method. Long-Lived Assets Classified as Held for Sale We classify long-lived assets as Held-for-Sale when the criteria of ASC 360-10-45-9 through 45-11, Impairment and Disposal of Long-Lived Assets, have been met. This criterion is listed below: ● Management has committed to a plan to sell the asset; ● The asset group is available for immediate sale in its present condition; ● An active program is underway to locate potential buyers; ● The sale is probable within one year; ● The asset group is being marketed at a price that is reasonable relative to its current fair value; and ● Actions required to complete the plan indicate that it is unlikely that significant changes to the plan will be made or the plan will be withdrawn. Assets held for sale are carried at the lower of cost or fair market value less cost of disposal in current assets. If we retain the responsibility for the P&A, equipment removal or site restoration, the associated anticipated expense is carried as current an asset retirement obligation (“ARO”) (See Note 4, below). We have two property groups that are being Held for Sale as further described in Note 17 – Long-Lived Assets Held for Sale. Turnkey Drilling We sponsor turnkey drilling agreement arrangements in proved and unproved properties as a pooling of assets in a joint undertaking, whereby proceeds from participants are reported as Deferred Drilling Obligations, and then reduced as costs to complete our obligations and are incurred with any excess booked against our property account to reduce any basis in our own interest. Gains on Turnkey Drilling Programs represent funds received from turnkey drilling participants in excess of all costs we incur during the drilling programs (e.g., lease acquisition, exploration and development costs), including costs incurred on behalf of participants and costs incurred for our own account; and are recognized only upon making this determination after our obligations have been fulfilled. The contracts require the participants pay us the full contract price upon execution of the agreement. We complete the drilling activities typically between 10 and 30 days after drilling begins. The participant retains an undivided or proportional beneficial interest in the property, and is also responsible for their proportionate share of operating costs. We retain legal title to the lease. The participants purchase a working interest directly in the well bore. In these working interest arrangements, the participants are responsible for sharing in the risk of development, but also sharing in a proportional interest in rights to revenues and proportional liability for the cost of operations after drilling is completed and the interest is conveyed to the participant. A certain portion of the turnkey drilling participant’s funds received are non-refundable. We hold all funds invested as Deferred Drilling Obligations until drilling is complete. Occasionally, drilling is delayed for various reasons such as weather, permitting, drilling rig availability and/or contractual obligations. At December 31, 2022 and 2021, We had Deferred Drilling Obligations of $8,129,965 and $7,824,939, respectively. During 2022, we disposed of $7,027,474 of drilling obligations as we completed five oil wells in Texas and participated in completing the drilling of two oil wells in southern California, while incurring expenses of $5,301,060, resulting in a gain of $1,726,414. During 2021, we disposed of $1,841,061 of drilling obligations upon completing the drilling of two oil wells in Texas, while incurring expenses of $1,905,529, resulting in a loss of $64,468. If we are unable to drill the wells, and a suitable replacement well is not found, we would retain the non-refundable portion of the contract and return the remaining funds to the participant. Included in restricted cash are amounts for use in completion of turnkey drilling programs in progress. Equipment and Fixtures Equipment and fixtures are stated at cost and depreciated over the estimated useful lives of the assets, which range from three to seven years, using the straight-line method. Repairs and maintenance are charged to expense as incurred. When assets are sold or retired, the cost and related accumulated depreciation are removed from the accounts and any resulting gain or loss is included in income. Maintenance and repairs, which neither materially add to the value of the property nor appreciably prolong its life, are charged to expense as incurred. Loss Per Share Basic and diluted losses per share are calculated as follows: Year Ended December 31, 2022 2021 Basic Diluted Basic Diluted Net Loss $ (145,594 ) $ (145,594 ) $ (3,598,418 ) $ (3,598,418 ) Less: Preferred Stock Dividend 815,772 815,772 787,833 787,833 Less: Preferred Stock Dividend in Arrears - - - - Net Loss Attributable to Common Shareholders (961,366 ) (961,366 ) (4,386,251 ) (4,386,251 ) Weighted average common shares outstanding 58,472,340 58,472,340 55,887,319 55,887,319 Effect of dilutive securities - - - - Weighted average common shares, including Dilutive effect 58,472,340 58,472,340 55,887,319 55,887,319 Per share: Net Loss $ (0.02 ) $ (0.02 ) $ (0.06 ) $ (0.06 ) For the years ended December 31, 2022 and 2021, Royale Energy had dilutive securities of 27,058,677 and 26,582,388 respectively. These securities were not included in the dilutive loss per share due to their antidilutive nature. Stock Based Compensation We have a stock-based employee compensation plan, which is more fully described in Note 11 – Stock Compensation Plan. We have adopted ASC 718, Compensation – Stock Compensation, for share-based payments. This topic requires that the cost resulting from all share-based payment transactions be recognized in the financial statements. It further establishes fair value as the measurement objective in accounting for share-based payment arrangements and requires all entities to apply a fair-value based measurement method in accounting for share-based payment transactions with employees except for equity instruments held by employee stock ownership plans. Income Taxes We utilize the asset and liability approach to measure deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates in accordance with the Income Taxes Topic of the ASC 740. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. Under the Topic, deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more-likely-than-not that some portion or all of the deferred tax assets will not be realized. The provision for income taxes is based on pretax financial accounting income. Deferred tax assets and liabilities are recognized for the expected tax consequences of temporary differences between the tax basis of assets and liabilities and their reported net amounts. Fair Value Measurements According to Fair Value Measurements and Disclosures guidance as provided by ASC 820 and 825, assets and liabilities that are measured at fair value on a recurring and nonrecurring basis in periods subsequent to initial recognition, the reporting entity shall disclose information that enable users of our financial statements to assess the inputs used to develop those measurements and for recurring fair value measurements using significant unobservable inputs, the effect of the measurements on earnings for the period. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. In determining fair value, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible as well as consider counterparty credit risk in our assessment of fair value. Carrying amounts of our financial instruments, including cash equivalents, accounts receivable, accounts payable and accrued liabilities, approximate their fair values as of the balance sheet dates because of their generally short maturities. The fair value hierarchy distinguishes between (1) market participant assumptions developed based on market data obtained from independent sources (observable inputs) and (2) an entity’s own assumptions about market participant assumptions developed based on the best information available in the circumstances (unobservable inputs). The fair value hierarchy consists of three broad levels, which gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy are described below: Level 1: Quoted prices (unadjusted) in active markets that are accessible at the measurement date for assets or liabilities. Level 2: Directly or indirectly observable inputs as of the reporting date through correlation with market data, including quoted prices for similar assets and liabilities in active markets and quoted prices in markets that are not active. Level 2 also includes assets and liabilities that are valued using models or other pricing methodologies that do not require significant judgment since the input assumptions used in the models, such as interest rates and volatility factors, are corroborated by readily observable data from actively quoted markets for substantially the full term of the financial instrument. Level 3: Unobservable inputs that are supported by little or no market activity and reflect the use of significant management judgment. These values are generally determined using pricing models for which the assumptions utilize management’s estimates of market participant assumptions. At December 31, 2022 and 2021, we do not have any financial assets measured and recognized at fair value on a recurring basis. We estimate asset retirement obligations pursuant to the provisions of ASC 410, Asset Retirement and Environmental Obligations. The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 3 – Accounts Payable and Accrued Expenses At December 31, 2022 and 2021, the components of accounts payable and accrued expenses consisted of: 2022 2021 Trade Payables including accruals $ 3,108,931 $ 2,845,395 Direct working interest investors related accruals 1,801,818 1,409,148 Current drilling efforts accrued expenses 22,910 229,716 Accrued Liabilities 400,296 410,308 Employee related accruals 189,736 266,531 Deferred rent 5,138 (614 ) $ 5,528,829 $ 5,160,484 Accrued Non-current At December 31, 2022 and 2021, we had non-current accrued liabilities of $1,306,605 and accrued unpaid guaranteed payment of $1,616,205, due to certain Matrix Oil Corp (“Matrix”) principals, from periods prior to the merger with the Matrix entities during March of 2018. Business Combinations From time-to-time, we acquire businesses in the oil and gas industry. We primarily target businesses in geological basins that we consider to be in a focus area. Businesses are included in the consolidated financial statements from the date of acquisition. We recognize, separately from goodwill, the identifiable assets acquired and liabilities assumed at their estimated acquisition-date fair values. We measure and recognize goodwill as of the acquisition date as the excess of: (1) the aggregate of the fair value of consideration transferred, the fair value of any noncontrolling interest in the acquiree (if any) and the acquisition date fair value of our previously held equity interest in the acquiree (if any), |
RMX JOINT VENTURE
RMX JOINT VENTURE | 12 Months Ended |
Dec. 31, 2022 | |
Business Combinations [Abstract] | |
Business Combination Disclosure [Text Block] | NOTE 2 RMX JOINT VENTURE RMX Joint Venture On April 13, 2018, we and two of our subsidiaries, Royale Energy Funds, Inc. and Matrix Oil Management Corporation (the “Royale Entities”) completed the Subscription and Contribution Agreement (“Contribution Agreement”), in which the Royale Entities and CIC RMX LP (“CIC”) entered into the Contribution Agreement and certain other agreements providing that the Royale Entities would contribute certain assets to RMX (“RMX”), a newly formed Texas limited liability company formed to facilitate the investment from CIC. In exchange for our contributed assets, we received a 20% equity interest in RMX, an equity performance incentive interest and up to $20.0 million to pay off the Royale Entities senior lender, Arena Limited SPV, LLC., in full, and to pay the Royale Entities trade payables and other outstanding obligations. CIC contributed an aggregate of $25.0 million in cash to RMX in exchange for (i) an 80% equity interest in RMX with preferred distributions until certain thresholds are met, (ii) a warrant (“Warrant”) to acquire up to 4,000,000 shares of our common stock at an exercise price of $.01 per share and registration rights pursuant to a Registration Rights Agreement. RMX has a six-member board of managers. We have two seats on the board giving us a third of the available seats on the Board. We have designated Michael McCaskey and Johnny Jordan as our members of the RMX board. The return targets for CIC through its funding of RMX provide for a “waterfall” style return profile with the first distributions going to CIC until they have received all Unpaid Preferred Return and Unpaid Preferred Enhanced Return, as defined by the Contribution Agreement. We account for our ownership interest in RMX following the equity method of accounting, in accordance with ASC 323, Investments—Equity Method and Joint Ventures. Under the provisions of the Amended and Restated Limited Liability Company Agreement of RMX (“RMX Agreement”) dated March 27, 2018, the gains and losses of the partnership are distributed as if all of RMX’s assets were sold for cash at a price equal to their book basis and all RMX liabilities were satisfied at their book basis and all of the remaining assets of RMX were distributed in accordance with Section 5.4 of the RMX Agreement. Notwithstanding the above, for each fiscal year or other relevant period, deductions attributable to exploration costs, IDCs, and operating and maintenance costs shall be allocated 100% to the CIC members pro rata in accordance with their Class B percentage interests for each fiscal year. RMX Joint Venture Post-Closing On March 11, 2019, we entered into a Settlement Agreement with RMX Resources to resolve differences resulting from the calculation of certain post-closing amounts as called for under Section 7.3 of the Subscription and Contribution Agreement. Pursuant to the Settlement Agreement, we continue to be liable for the payment of all royalties and suspended funds incurred prior to March 1, 2018. It also, required RMX to offer us the right, but not the obligation to participate in a portion of the working interest, in a number of wells to be drilled in the Sansinena, Sempra, Whittier and/or East LA properties in Los Angeles County, California. The minimum number of wells to be offered to us each year is two net wells as determined by an agreed upon methodology. The Settlement Agreement also calls for certain credits toward future drilling costs of the offered wells. The RMX Joint Venture, like any Joint Venture investment following the equity method, is subject to ASC 323-10-35-31 and 32, impairment testing. During the 4th quarter of 2020, we received the RMX engineering reserve report prepared by an independent outside engineering firm. The report reflected reserve values for RMX that were below our expectations. As a result of this and on-going market conditions along with the contractual terms of our investment in RMX, management performed an impairment test. We considered the waterfall formula as called for under the Contribution Agreement and certain other agreements with RMX as well as the preferred return owed to other partners. As part of this computation, we applied a discounted cash flow test as called for under ASC 820-10-55-5(c) and 5(d) incorporating the time value of money and risk premium. In our test, we considered factors including, most significantly, the estimated market value of the reserves of RMX and the amount of preferred return owed to other partners. As a result of this analysis and the fact that management does not believe the values reflected in this most recent reserve report are temporary, we do not expect to realize the entire carrying amount of the RMX investment. Therefore, we recognized an impairment of our investment of $6,185,995 in our Statement of Operations in the year ended December 31, 2020. Because we do not expect the value of the RMX Joint Venture to improve to a level where the water-fall profit sharing formula will provide us value, and we are no longer providing summarized financial information on the RMX investment in our financial statements or our reserve disclosures. Further the investment in RMX Joint Venture was $0 as of December 31, 2021, due to recording the full impairment in 2020. |
OIL AND GAS PROPERTIES, EQUIPME
OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES | 12 Months Ended |
Dec. 31, 2022 | |
Oil and Gas Property [Abstract] | |
Oil and Gas Properties [Text Block] | NOTE 3 OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES Oil and gas properties, equipment and fixtures consist of: Year ended December 31, 2022 2021 Oil and Gas Producing properties, including intangible drilling costs $ 5,712,436 $ 5,509,568 Undeveloped properties 148,989 128,362 Lease and well equipment 3,317,718 3,317,718 9,179,143 8,955,648 Accumulated depletion, depreciation and amortization (7,142,506 ) (6,879,531 ) Net capitalized costs Total $ 2,036,637 $ 2,076,117 Commercial and Other 2022 2021 Vehicles $ 40,061 $ 40,061 Furniture and equipment 1,097,428 1,097,428 1,137,489 1,137,489 Accumulated depreciation (1,133,806 ) (1,133,806 ) 3,683 3,683 Net capitalized costs Total $ 2,040,320 $ 2,079,800 The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed at December 31: Year Ended December 31, 2022 2021 Acquisition - Proved - - Acquisition - Unproved - - Development $ 5,301,061 $ 1,905,529 Exploration - - The guidance set forth in the Continued Capitalization of Exploratory Well Costs paragraph of the Extractive Activities Topic of the FASB ASC requires that we evaluate all existing capitalized exploratory well costs and disclose the extent to which any such capitalized costs have become impaired and are expensed or reclassified during a fiscal period. We did not make any additions to capitalized exploratory well costs pending a determination of proved reserves during 2022 and 2021. We did not charge any previously capitalized exploratory well costs to expense upon adoption of Topic. Undeveloped properties are not subject to depletion, depreciation or amortization. Results of Operations from Oil and Gas Producing and Exploration Activities The results of operations from oil and gas producing and exploration activities (excluding corporate overhead and interest costs) are as follows: Year Ended December 31, 2022 2021 Oil and gas sales $ 2,611,222 $ 1,686,424 Production-related costs (Lease Operating) (1,928,521 ) (1,814,643 ) Impairment - (177,011 ) Depreciation, depletion and amortization (575,909 ) (537,273 ) Results of operations from producing and exploration activities 106,792 (842,503 ) Income Taxes (Benefit) - - Net Results $ 106,792 $ (842,503 ) |
ASSET RETIREMENT OBLIGATION
ASSET RETIREMENT OBLIGATION | 12 Months Ended |
Dec. 31, 2022 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligation Disclosure [Text Block] | NOTE 4 ASSET RETIREMENT OBLIGATION The Asset Retirement and Environmental Obligations Topic of the ASC 410-20 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset. The ARO is recorded at the estimated fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value. Accretion expense is included as part of Depreciation, Depletion and Amortization in the Consolidated Statement of Operations. The fair value (as provided in ASC 820 guidance) of the ARO is measured using expected future cash outflows discounted at our credit-adjusted risk-free interest rate. The provisions of this Topic apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, development, and operation of a long-lived asset. There were no changes in estimates for the years ended December 31, 2022 and 2021. 2022 2021 Asset retirement obligation Beginning of the year $ 2,610,560 $ 2,478,350 Liabilities incurred during the period 29,338 14,122 Settlements (58,889 ) - Sales - - Changes in estimates - - Accretion expense 286,470 118,088 Reclassification to ARO - current - - End of year $ 2,867,479 $ 2,610,560 We record accretion expense as part of Depreciation, Depletion and Amortization. Accretion expense was $286,470 and $118,088 for the years ended December 31, 2022 and 2021, respectively. |
NOTES PAYABLE
NOTES PAYABLE | 12 Months Ended |
Dec. 31, 2022 | |
Debt Disclosure [Abstract] | |
Short-Term Debt [Text Block] | NOTE 5 NOTES PAYABLE On November 1, 2021, we issued a promissory note for a principal amount of $38,490 to Pacific Gillespie Partners IV, LP. Five principal payments of $7,698 are due the first of the month beginning December 1, 2021. On October 3, 2018, we issued a promissory note for a principal amount of $517,585 to Forza Operating, LLC (“Forza”) at an interest rate of 5.5%. Beginning October 3, 2018, principal and interest was due and payable in 12 monthly installments of $44,428. The note was the result of an agreement regarding the P&A of the CL&F #1 and the CL&F #1 SWD wells. We agreed to include the current joint interest billing balance due to Forza of $233,367 and our share of future P&A costs of $284,218. Forza agreed to accept the principal balance, less a portion of the accrued interest. As a result, we recorded a gain of $13,440 as Other Gain. This note was fully satisfied in October 2022. At December 31, 2022 and 2021, we had Notes Payable of $0 and $113,915, respectively. On November 2, 2020, in conjunction with the PPP loan forgiveness described in Note 16 – Coronavirus Aid, Relief, And Economic Security Act (“CARES Act”), we entered into a loan for $10,054 to be repaid through monthly interest and principal payments of $560 beginning December 1, 2020, with the final payment of $613 scheduled for April 23, 2022. In February 2021, the balance of the loan and interest of $10,081 was paid by the SBA resulting in a gain on settlement of $10,061 in 2021. |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2022 | |
Income Tax Disclosure [Abstract] | |
Income Tax Disclosure [Text Block] | NOTE 6 INCOME TAXES Deferred tax assets and liabilities reflect the net tax effect of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and amounts used for income tax purposes. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more-likely-than-not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. Significant components of our deferred assets and liabilities at December 31, 2022 and 2021, respectively, are as follows: 2022 2021 Deferred Tax Assets (Liabilities): Statutory Depletion Carry Forward $ 310,903 $ 277,521 Net Operating Loss 8,542,098 8,697,243 Other 688,377 605,684 Share-Based Compensation 86,510 86,510 Capital Loss / AMT Credit Carry Forward 9,458 9,458 Charitable Contributions Carry Forward 100 - Allowance for Doubtful Accounts 717,514 718,516 Oil and Gas Properties and Fixed Assets 4,976,399 3,945,568 Investment in RMX Joint Venture (285,626 ) 486,092 15,045,733 $ 14,826,592 Valuation Allowance (15,045,733 ) (14,826,592 ) Net Deferred Tax Asset $ - $ - We recorded a full valuation allowance against the net deferred tax assets in 2016. At the end of 2017, management reviewed the reliability of our net deferred tax assets, and due to our continued cumulative losses in recent years, we and our management concluded it is not “more-likely-than-not” our deferred tax assets will be realized. As a result, we will continue to record a full valuation allowance against the deferred tax assets. We will assess the realizability of the deferred tax assets at least yearly and make appropriate updates as needed. We and our subsidiaries have available net operating loss carryforwards of $20.5 million generated in tax years ended before January 1, 2018, which if not utilized, begin to expire in the year 2026. We have $12.0 million net operating loss carryforwards generated after December 31, 2017, which can be carried forward indefinitely. A reconciliation of our provision for income taxes and the amount computed by applying the statutory income tax rates at December 31, 2022 and 2021, respectively, to pretax income is as follows: 2022 2021 Tax (benefit) computed at statutory rate of 21% at December 31, 2022 and 2021, respectively $ (30,575 ) $ (755,668 ) Increase (decrease) in taxes resulting from: PPP Loan Forgiveness - (2,113 ) Employer Retention Credits (31,527 ) - Prior-year true-up for Books (221,621 ) 241,652 Deferred State Taxes, net of federal benefit 62,558 (131,991 ) Other non-deductible expenses 2,024 (6,086 ) Change in valuation allowance 219,141 654,206 Provision (benefit) $ - $ - In January 2007, we adopted additional provisions from the Income Taxes Topic of the ASC, which clarified the accounting for uncertainty in income taxes recognized in an entity’s financial statements and prescribes a recognition threshold and measurement attribute for financial statement disclosure of tax positions taken or expected to be taken on a tax return. As a result of our implementation of the Topic at the time of adoption and at December 31, 2018, we did not recognize a liability for uncertain tax positions. Currently, the only differences between our financial statements and our income tax returns relate to normal timing differences such as depreciation, depletion and amortization, which are recorded as deferred taxes on our balance sheets. We do not expect our unrecognized tax benefits to change significantly over the next 12 months. The tax years 2018 through 2021 remain open to examination by the taxing jurisdictions in which we file income tax returns. |
SERIES B PREFERRED STOCK
SERIES B PREFERRED STOCK | 12 Months Ended |
Dec. 31, 2022 | |
Disclosure Text Block Supplement [Abstract] | |
Preferred Stock [Text Block] | NOTE 7 SERIES B PREFERRED STOCK Pursuant to the terms of the Merger all Class A limited partnership interests of Matrix Investments, LP (“Matrix Investments”) were exchanged for our Common stock using conversion ratios according to the relative value of the Class A limited partnership interests, and $20,124,000 of Matrix Investments preferred limited partnership interests were converted into 2,012,400 shares of our Series B Convertible Preferred Stock. Our Board of Directors, prior to the merger, authorized 3,000,000 shares of Series B Convertible Preferred, which carries a liquidation preference and a 3.5% annual dividend, payable quarterly in cash or Paid-In-Kind (“PIK”) shares. The Series B Convertible Preferred Stock is convertible at the option of the security holder at the rate of ten shares of common stock for one share of Series B Convertible Preferred Stock. The Series B Preferred Stock has never been registered under the Securities Exchange Act of 1934, and no market exists for the shares. Additionally, the Series B Convertible Preferred shares will automatically convert to shares of common stock at any time in which the Volume Weighted Average Price (“VWAP”) of the common stock exceeds $3.50 per share for 20 consecutive trading days, the shares of common stock are registered with the SEC and the volume of common shares trades exceeds 200,000 shares per day. The shareholders of the Series B Convertible Preferred may vote the number of shares into which they would be entitled to convert, beginning in 2020. In accordance with ASC 480-10-S99-1.02, we have determined that the conversion or redemption of these shares are outside our sole control and that they should be classified in mezzanine or temporary equity as redeemable noncontrolling interest beginning at the reporting period, ended March 31, 2020. For 2022 and 2021, the board authorized the payment of each quarterly dividend of Series B Convertible Preferred shares, as Paid-In-Kind shares (“PIK”) to be paid immediately following the end of the quarter. For the 12 months ending December 31, 2022, we issued 60,748 shares with a value of $607,465, with 20,832 shares with a value of $208,307 accrued for but not yet issued at 12/31/22. For the 12 months ending December 31, 2021, we issued 58,667 shares with a value of $586,661, with 20,117 shares with a value of $201,172 accrued for but not yet issued at December 31, 2021. During 2022 and 2021, no cash was used to pay dividends on Series B preferred shares. |
COMMON STOCK
COMMON STOCK | 12 Months Ended |
Dec. 31, 2022 | |
Stockholders' Equity Note [Abstract] | |
Equity [Text Block] | NOTE 8 COMMON STOCK During the years 2022 and 2021, we issued shares of our Common Stock in lieu of cash payments for salaries, fees or incentives to various officers and board members, including our CEO, as noted in the Statement of Stockholders’ Equity (Deficit). |
OPERATING LEASES
OPERATING LEASES | 12 Months Ended |
Dec. 31, 2022 | |
Disclosure Text Block [Abstract] | |
Leases of Lessee Disclosure [Text Block] | NOTE 9 LEASES During 2022 we had two office leases. One at 1530 Hilton Head Road, El Cajon, California the location of our corporate offices and one at 104 W. Anapamu, Santa Barbara, California, the location of our CEO and engineering team. The corporate office lease was entered into on August 12, 2021, began on January 1, 2022 and expires on December 31, 2026, with initial monthly payments of $6,922 with escalations. The lease in Santa Barbara was initiated in December of 2006 and, through several extensions and renewals, expired in March of 2022. We have elected the short-term lease recognition exemption for all leases that qualify. This means, for those leases that qualify, we will not recognize ROU assets or lease liabilities, and this includes not recognizing ROU assets or lease liabilities for existing short-term leases of those assets in transition. We elected the practical expedient to not separate lease and non-lease components for all of our finance leases. For our real estate operating leases, we have only considered the fixed portion of our lease payment commitment and have excluded the variable components from the capitalized ROU and lease liability. Lease expense for operating as well as finance leases are included in General and Administrative expense and Interest Expense on the Consolidated Statement of Operations, while the lease expense for those leases that are short-term are included in Oil and Gas Lease Operating Expenses. The amounts are as follows: Year Ended December 31, 2022 2021 Operating lease expense $ 174,975 $ 163,025 Financing lease expense 19,076 18,635 Short Term - field 6,000 6,000 Total lease expense $ 200,051 $ 187,660 The following tables summarized the operating and financing lease obligations. Lease Obligations Operating Lease Obligations Financing Lease Obligations Total Lease Obligations 2023 $ 85,560 $ 12,588 $ 98,148 2024 88,128 7,343 95,471 2025 90,768 - 90,768 Thereafter 93,492 - 93,492 Total undiscounted lease payments 357,948 19,931 377,879 Less: Amount representing interest 39,929 1,097 41,026 Total Operating & Financing lease liabilities 318,019 18,834 336,853 Current lease liabilities as of December 31, 2022 70,200 11,795 81,995 Long-term lease liabilities as of December 31, 2022 $ 247,819 $ 7,039 $ 254,858 |
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS | 12 Months Ended |
Dec. 31, 2022 | |
Related Party Transactions [Abstract] | |
Related Party Transactions Disclosure [Text Block] | NOTE 10 RELATED-PARTY TRANSACTIONS Our Chief Executive Officer, Johnny Jordan, has accrued certain unpaid salaries. At December 31, 2022, Mr. Jordan was owed $15,694, in accrued unpaid guaranteed payments. Stephen Hosmer, former CFO, current director, and corporate secretary, has participated individually in 179. During 2022 and 2021, Stephen did not participate in fractional interests. At December 31, 2022, we had a receivable balance of $18,251 due from Stephen Hosmer for normal drilling and lease operating expenses. At December 31, 2022 and 2021, we had a total payable of $23,087 and $23,087, respectively, due to RMX and its subsidiary, Matrix Oil Corporation, related to certain lease operating expenses for wells operated by RMX. For the same periods, we also had prepaid expenses and other current assets, and deferred drilling costs of $290,871 and $1,327,763, respectively. In 2022, the prepaid amount was for drilling and future plugging costs. In 2021, the prepaid amount was primarily for the drilling of wells. During 2022, RMX Resources LLC operated various oil wells we have interests in, from which we received revenues of approximately $491,000 and incurred lease operating costs of approximately $189,000. At December 31, 2022 and 2021, we had a total revenue receivables of $127,360 and $98,274, respectively, due from RMX and its subsidiary, Matrix Oil Corporation. We had outstanding accrued unpaid guaranteed payments for unpaid salaries for periods predating their joining our company due to certain former Matrix employees. At December 31, 2022, the balance due was $1,616,205. At December 31, 2022, Royale also had accrued unpaid liabilities of $1,306,605 due to certain former Matrix employees for periods predating their employment. Michael McCaskey, a former director, and Jeffery Kerns, a current director, each have consulting agreements to provide services as directed and at our discretion. Mr. Kerns’ wife was a director during 2020 and 2021. At December 31, 2022 and 2021, we had total payables of $185,049 and $233,872, a respectively, owed to current and former board members for directors fees. |
STOCK COMPENSATION PLAN
STOCK COMPENSATION PLAN | 12 Months Ended |
Dec. 31, 2022 | |
Share-Based Payment Arrangement [Abstract] | |
Share-Based Payment Arrangement [Text Block] | NOTE 11 STOCK COMPENSATION PLAN There were no stock options issued during 2022 and 2021. |
SIMPLE IRA PLAN
SIMPLE IRA PLAN | 12 Months Ended |
Dec. 31, 2022 | |
Retirement Benefits [Abstract] | |
Retirement Benefits [Text Block] | NOTE 12 SIMPLE IRA PLAN In April 1998, we established a Simple IRA pension plan covering all employees. We will contribute a matching contribution to each eligible employee’s Simple IRA equal to the employee’s salary reduction contributions up to a limit of 3% of the employee’s compensation for the year. The employer contribution for the years ending December 31, 2022 and 2021, were $27,770 and $31,509 respectively. |
ENVIRONMENTAL MATTERS
ENVIRONMENTAL MATTERS | 12 Months Ended |
Dec. 31, 2022 | |
Environmental Remediation Obligations [Abstract] | |
Environmental Loss Contingency Disclosure [Text Block] | NOTE 13 ENVIRONMENTAL MATTERS We have established procedures for the continuing evaluation of our operations to identify potential environmental exposures and ensure compliance with regulatory policies and procedures. Management monitors these laws and regulations and periodically assesses the propriety of our operational and accounting policies related to environmental issues. The nature of our business requires routine day-to-day compliance with environmental laws and regulations. We incurred no material environmental investigation, compliance and remediation costs in 2022 or 2021. We are unable to predict whether our future operations will be materially affected by these laws and regulations. It is believed that legislation and regulations relating to environmental protection will not materially affect our results of operations. |
CONCENTRATIONS
CONCENTRATIONS | 12 Months Ended |
Dec. 31, 2022 | |
Risks and Uncertainties [Abstract] | |
Concentration Risk Disclosure [Text Block] | NOTE 14 CONCENTRATIONS We bid our gas sales on a month-to-month basis and generally sell to a single customer without commitment to future gas sales to any particular customer. We normally sell approximately 44% of our yearly natural gas production to one customer on a month-to-month basis. Since we are able to sell our natural gas to other readily available customers, the loss of any one customer would not have an adverse effect on our overall sales operations. We maintain cash in depository institutions that are guaranteed by the Federal Deposit Insurance Corporation (FDIC) up to $250,000 per institution for our interest-bearing accounts in the years ended December 31, 2022, and 2021. At December 31, 2022 and 2021, cash in banks exceeded the FDIC limits by approximately $3.6 million and $3.9 million, respectively. We have not experienced any losses on deposits. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended |
Dec. 31, 2022 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies Disclosure [Text Block] | NOTE 15 COMMITMENTS AND CONTINGENCIES We may become involved from time to time in litigation on various matters, which are routine to the conduct of our business. We believe that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial position or results of operations, though any adverse decision in these cases or the costs of defending or settling such claims could have a material effect on our business. We sponsor turnkey drilling agreement arrangements in proved and unproved properties as a pooling of assets in a joint undertaking, whereby proceeds from participants are reported as Deferred Drilling Obligations. The contracts require the participants pay us the full contract price upon execution of the agreement. We typically begin the drilling activities within 12 months of funding and reach total depth between 10 and 30 days after drilling begins. |
CORONAVIRUS AID, RELIEF, AND EC
CORONAVIRUS AID, RELIEF, AND ECONOMIC SECURITY ACT ("CARES ACT") | 12 Months Ended |
Dec. 31, 2022 | |
Debt Disclosure [Abstract] | |
Debt Disclosure [Text Block] | NOTE 16 CORONAVIRUS AID, RELIEF, AND ECONOMIC SECURITY ACT ( CARES ACT ) During 2020, the CARES Act provided tax benefits and potential loans/grants for businesses and non-profits. On April 13, 2020, we successfully completed the process to obtain a $207,800 PPP Loan through the SBA with Bank of Southern California (“BSC”) under the CARES Act. The interest rate was 1.00 percent per year fixed with a two-year term and all payments deferred for six months subject to loan forgiveness as provided for under the CARES Act. On November 2, 2020, our loan with BSC was paid down by $198,846 ($197,800 in principal and $1,046 in interest) as a result of completing the process of loan forgiveness under the terms of the CARES Act. The loan balance of $10,054 was forgiven and paid by the SBA in February 2021. Under the updated regulations, the forgiveness of PPP Loan is not taxable income. Additionally, expenses submitted in support of the PPP Loan forgiveness remain deductible for the purpose of tax reporting. Prior IRS positions in Notice 2020-32 and Rev Ruling 2020-27 no longer apply. We had also applied for approximately $152,000 in relief under the Employee Retention Credit program of the CARES act, for payroll expenses incurred for 2020 and 2021. We received these funds in December 2022, and recorded them as Other Income. |
LONG-LIVED ASSETS HELD FOR SALE
LONG-LIVED ASSETS HELD FOR SALE | 12 Months Ended |
Dec. 31, 2022 | |
Disclosure Text Block Supplement [Abstract] | |
Other Assets Disclosure [Text Block] | NOTE 17 LONG-LIVED ASSETS HELD FOR SALE Assets held for sale are carried at lower of cost or fair value less cost to sell. Listed below are the two current groups of properties that we defined as long-lived assets held for sale in accordance with ASC 360-10-45. East Los Angeles Sale In September 2021, we and our joint venture partner, RMX, sold certain assets in our East Los Angeles property. During 2021, we carried these assets on the books for $1.0 million booked as Held for Sale with a current ARO amount of approximately $721,000 for the existing wells and facilities located on the properties. The sale required us and RMX to plug and abandon the wells on the property and remove and restore the surface land. The sale price of $1.0 million to us resulted in recording a loss on sale of these properties of approximately $254,000. Non-operated West Texas Property Sale During 2021, we recorded a gain of approximately $319,000 on the sale of asset on the sale of certain non-operated Texas properties. These non-operated properties were originally acquired during the 2018 merger with Matrix Oil Management Corporation and booked as Held for Sale at year-end 2020. |
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS | 12 Months Ended |
Dec. 31, 2022 | |
Subsequent Events [Abstract] | |
Subsequent Events [Text Block] | NOTE 18 SUBSEQUENT EVENTS We have evaluated subsequent events through May 19, 2023, the date these financial statements were available to be issued. At March 1, 2023, we issued 20,832 shares of our Series B Preferred stock with a value of $208,307 for our fourth quarter 2022 dividend that had been accrued for but not yet issued at December 31, 2022.We are not aware of events which would require recognition or disclosure in the financial statements, except as noted here or already recognized or disclosed. |
SUPPLEMENTAL INFORMATION ABOUT
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) | 12 Months Ended |
Dec. 31, 2022 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Oil and Gas Exploration and Production Industries Disclosures [Text Block] | NOTE 19 SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) The following estimates of proved oil and gas reserves, both developed and undeveloped, represent interest we owned, which are located solely in the United States. Proved reserves represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate to be reasonably certain to be recoverable in the future from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells, with existing equipment and operating methods. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which relatively major expenditures are required for completion. Disclosures of oil and gas reserves, which follow, are based on estimates prepared by independent petroleum engineering consultant Netherland, Sewell & Associates, Inc., the net reserve value of our proved developed and undeveloped reserves was approximately $23.3 million at December 31, 2022, based on the average Henry Hub natural gas price spot price of $6.357 per MCF and for oil volumes, the average West Texas Intermediate price of $94.14 per barrel as applied on a field-by-field basis. Netherland, Sewell & Associates, Inc. provided reserve value information for our California, Texas, Oklahoma, Utah and Louisiana properties. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. These estimates do not include probable or possible reserves. The technical persons responsible for preparing the reserves estimates presented in the report of Netherland, Sewell & Associates, Inc., meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Netherland, Sewell & Associates, Inc. is a firm of independent petroleum engineers, geologists, geophysicists, and petrophysicists; and do not own an interest in our properties and are not employed on a contingent basis. All activities and reports performed and completed by Netherland, Sewell & Associates, Inc. with regards to our reserve valuation estimates are reviewed by our management. These estimates are furnished and calculated in accordance with requirements of the FASB and the SEC. Because of unpredictable variances in expenses and capital forecasts, crude oil and natural gas price changes, largely influenced and controlled by U.S. and foreign government actions, and the fact that the bases for such estimates vary significantly, management believes the usefulness of these projections is limited. Estimates of future net cash flows presented do not represent our management’s assessment of future profitability or future cash flows. Management’s investment and operating decisions are based upon reserve estimates that include proved reserves prescribed by the SEC as well as probable reserves, and upon different price and cost assumptions from those used here. It should be recognized that applying current costs and prices and a 10 percent standard discount rate does not convey absolute value. The discounted amounts arrived at are only one measure of the value of proved reserves. Changes in Estimated Reserve Quantities The net interest in estimated quantities of proved developed reserves of crude oil and natural gas at December 31, 2022 and 2021, and changes in such quantities during each of the years then ended, were as follows: Total Proved Reserves 2022 2021 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Beginning of period 1,579,100 1,354,300 1,541,000 2,660,500 Revisions of previous estimates (1,283,285 ) (85,864 ) (1,737 ) (1,916,677 ) Production (18,015 ) (135,136 ) (18,963 ) (122,151 ) Extensions, discoveries and improved recovery 94,500 - 146,052 782,300 Sales of minerals in place - - (87,252 ) (49,672 ) Proved reserves end of period 372,300 1,133,300 1,579,100 1,354,300 Proved Developed 2022 2021 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed reserves: Beginning of period 193,600 939,100 224,900 691,900 End of period 182,000 942,000 193,600 939,100 Proved Undeveloped 2022 2021 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved undeveloped reserves: Beginning of period 1,385,500 415,200 1,316,100 1,968,600 End of period 190,300 191,300 1,385,500 415,200 During 2022, our overall proved developed and undeveloped oil reserves decreased by 76.4% and our previously estimated proved developed and undeveloped oil reserve quantities were revised downward by approximately 1.3 million barrels. This downward revision was mainly the result of a decrease in proved undeveloped oil reserves from drilling locations which the Company had previously estimated. Our overall proved developed and undeveloped natural gas reserves decreased by 16.3% and our previously estimated proved developed and undeveloped natural gas reserve quantities were revised downward by approximately 86 thousand cubic feet of natural gas. This downward revision was mainly the result of a decrease in proved undeveloped natural gas reserves from drilling locations which we had previously estimated. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves The future net cash inflows are developed as follows: • Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. • The estimated future production of proved reserves is priced on the basis of year-end prices. • The resulting future gross revenue streams are reduced by estimated future costs to develop and to produce proved reserves, based on year-end estimates. Estimated future development costs by year are as follows: 2023 $ 1,374,500 2024 - 2025 - Thereafter 4,000 $ 1,378,500 The resulting future net revenue streams are reduced to present value amounts by applying a 10 percent discount. Disclosure of principal components of the standardized measure of discounted future net cash flows provides information concerning the factors involved in making the calculation. In addition, the disclosure of both undiscounted and discounted net cash flows provides a measure of comparing proved oil and gas reserves both with and without an estimate of production timing. The standardized measure of discounted future net cash flow relating to proved reserves reflects estimated income taxes. Changes in standardized measure of discounted future net cash flow from proved reserve quantities The standardized measure of discounted future net cash flows is presented below for the years ended December 31, 2022 and 2021. This statement discloses the sources of changes in the standardized measure from year to year. The amount reported as “Net changes in prices and production costs” represents the present value of changes in prices and production costs multiplied by estimates of proved reserves as of the beginning of the year. The “accretion of discount” was computed by multiplying the 10 percent discount factor by the standardized measure on a pretax basis as of the beginning of the year. The “Sales of oil and gas produced, net of production costs” are expressed in actual dollar amounts. “Revisions of previous quantity estimates” is expressed at year-end prices. The “Net change in income taxes” is computed as the change in present value of future income taxes. 2022 2021 Future cash inflows $ 38,766,900 $ 109,213,000 Future production costs (14,094,900 ) (51,448,200 ) Future development costs (1,378,500 ) (15,622,600 ) Future income tax expense (6,988,050 ) (12,642,660 ) Future net cash flows 16,305,450 29,499,540 10% annual discount for estimated timing of cash flows (6,044,467 ) (13,217,621 ) Standardized measure of discounted future net cash flows 10,260,983 16,281,919 Sales of oil and gas produced, net of production costs (608,735 ) (261,473 ) Revisions of previous quantity estimates (12,855,765 ) 9,511,179 Net changes in prices and production costs (287,425 ) 1,532,518 Sales of minerals in place - (1,236,927 ) Extensions, discoveries and improved recovery 4,266,500 5,304,521 Accretion of discount 884,088 (2,219,984 ) Net change in income tax 2,580,401 (3,788,950 ) Net increase (decrease) $ (6,020,936 ) $ 8,840,884 Future Development Costs In order to realize future revenues from our proved reserves estimated in our reserve report, it will be necessary to incur future costs to develop and produce the proved reserves. The following table estimates the costs to develop and produce our proved reserves in the year 2023. 2023 Future development cost of: Proved developed reserves (PDP) - Proved non-producing reserves (PDNP) $ 74,500 Proved undeveloped reserves (PUD) 1,300,000 Total $ 1,374,500 Common assumptions include such matters as the real extent and average thickness of a particular reservoir, the average porosity and permeability of the reservoir, the anticipated future production from existing and future wells, future development and production costs and the ultimate hydrocarbon recovery percentage. As a result, oil and gas reserve estimates and discounted present value estimates are frequently revised in subsequent periods to reflect production data obtained after the date of the original estimate. If the reserve estimates are inaccurate, production rates may decline more rapidly than anticipated, and future production revenues may be less than estimated. Additional data relating to our oil and natural gas properties is disclosed in Supplemental Information About Oil and Gas Producing Activities (Unaudited), attached to our Financial Statements, in Note 19. Historic Development Costs for Proved Reserves In each year we expend funds to drill and develop some of our proved undeveloped reserves. We have incurred no cost in any of the past three fiscal years to drill and develop reserves that were classified as proved undeveloped reserves as of December 31 of the immediately preceding year. |
Accounting Policies, by Policy
Accounting Policies, by Policy (Policies) | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
Basis of Accounting, Policy [Policy Text Block] | Description of Business We are an independent oil and gas producer and we also perform turnkey drilling operations. We own wells and leases in major geological basins located primarily in California, Texas, Oklahoma, and Utah, and offer fractional working interests and seek to minimize the risks of oil and gas drilling by selling multiple well drilling projects which do not include the use of debt financing. |
Use of Estimates, Policy [Policy Text Block] | Use of Estimates The accompanying consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America and requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and 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. Actual results could differ from those estimates. Estimated quantities of crude oil and condensate, NGLs and natural gas reserves is a significant estimate that requires judgment. All of the reserve data included in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and condensate, NGLs and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and condensate, NGLs and natural gas reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil and condensate, NGLs and natural gas that are ultimately recovered. See Note 19 – Supplemental Information About Oil and Gas Producing Activities (Unaudited) to our Consolidated Financial Statements for further detail. Other items subject to estimates and assumptions include the carrying amounts of accounts receivable, property, plant and equipment, equity method investments, asset retirement obligations, and valuation allowances for deferred tax assets, among others. Although we believe these estimates are accurate, actual results could differ from these estimates. |
Liquidity and Going Concern [Policy Text Block] | Liquidity and Going Concern The primary sources of liquidity have historically been issuances of common stock, oil and gas sales through ongoing operations and the sale of oil and gas properties. There are factors that give rise to substantial doubt about our ability to meet liquidity demands, and we anticipate that our primary sources of liquidity will be from the issuance of debt and/or equity, the sale of oil and natural gas property participation interests through our normal course of business and the sale of non-strategic assets. Our 2022 consolidated financial statements reflect a working capital deficiency of $6,445,318 and a net loss from operations of $145,594. These factors raise substantial doubt about our ability to continue as a going concern. The accompanying consolidated financial statements do not include any adjustments that might be necessary if we are unable to continue as a going concern. Management’s plans to alleviate the going concern by implementing cost control measures that include the reduction of overhead costs and through the sale of non-strategic assets. There is no assurance that additional financing will be available when needed or that management will be able to obtain financing on terms acceptable to us and whether we will become profitable and generate positive operating cash flow. If we are unable to raise sufficient additional funds, we will have to develop and implement a plan to further extend payables and reduce overhead until sufficient additional capital is raised to support further operations. There can be no assurance that such a plan will be successful. |
Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block] | Restricted Cash We sponsor turnkey drilling arrangements in proved and unproved properties. The contracts require that participants pay us the full contract price upon execution of the drilling agreement. Each participant earns an undivided interest in the well bore at the completion of the well. A portion of the funds received in advance of the drilling of a well from a working interest participant are held for the expressed purpose of drilling a well. If something changes, we may designate these funds for a substitute well. Under certain conditions, a portion of these funds may be required to be returned to a participant. Once the well is drilled, the funds are used to satisfy the drilling cost. We classify these funds prior to commencement of drilling as restricted cash based on guidance codified as under the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 230-10-50-8. In the event that progress payments are made from these funds; they are recorded as Prepaid Expenses and Other Current Assets. The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheets that sum to the total of the same amounts shown in the statement of cash flows. Year Ended December 31, 2022 2021 Cash and cash equivalents $ 1,650,507 $ 220,304 Restricted cash 2,249,627 4,002,500 Total cash, cash equivalents, and restricted cash shown in the Statement of Cash Flows $ 3,900,134 $ 4,222,804 |
Receivable [Policy Text Block] | Other Receivables Our other receivables consist of receivables from direct working interest investors and industry partners. We provide for uncollectible accounts receivable using the allowance method of accounting for bad debts. Under this method of accounting, a provision for uncollectible accounts is charged directly to bad debt expense when it becomes probable the receivable will not be fully collected. The allowance account is increased or decreased based on past collection history and management’s evaluation of accounts receivable. All amounts considered uncollectible are charged against the allowance account and recoveries of previously charged off accounts are added to the allowance. At December 31, 2022 and 2021, we established an allowance for uncollectable accounts of $2,757,549 and $2,761,398, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue. |
Accounts Receivable [Policy Text Block] | Revenue Receivables Our revenue receivables consist of receivables related to the sale of our natural gas and oil. Once a production month is completed, we receive payment approximately 15 to 30 days later. Historically, we have not had issues related to the collection of revenue receivables, and as such have determined that an allowance for revenue receivables is not currently necessary. |
Investment, Policy [Policy Text Block] | Equity Method Investments Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting. Income from equity method investments represents our proportionate share of net income generated by the equity method investees and is reflected in revenue and other income in our consolidated statements of income. Equity method investments are included as noncurrent assets on the consolidated balance sheets. Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value may have occurred as called for under ASC 323, Investments—Equity Method and Joint Ventures. When a loss is deemed to have occurred and is other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income. |
Revenue [Policy Text Block] | Revenue Recognition A significant portion of our revenues are derived from the sale of crude oil, condensate, natural gas liquids (“NGLs”) and natural gas under spot and term agreements with our customers as follows: Year Ended December 31, 2022 2021 Oil & Condensate Sales $ 1,654,840 $ 1,238,014 Natural Gas Sales 947,407 445,080 NGL Sales 8,975 3,330 $ 2,611,222 $ 1,686,424 The pricing in our hydrocarbon sales agreements are variable, determined using various published benchmarks which are adjusted for negotiated quality and location differentials. As a result, revenue collected under our agreements with customers is highly dependent on the market conditions and may fluctuate considerably as the hydrocarbon market prices rise or fall. Typically, our customers pay us monthly, within a short period of time after we deliver the hydrocarbon products. As such, we do not have any financing element associated with our contracts. We do not have any issues related to returns or refunds, as product specifications are standardized for the industry and are typically measured when transferred to a common carrier or midstream entity, and other contractual mechanisms (e.g., price adjustments) are used when products do not meet those specifications. In limited cases, we may also collect advance payments from customers as stipulated in our agreements; payments in excess of recognized revenue are recorded as contract liabilities on our consolidated balance sheets. Under our hydrocarbon sales agreements, the entire consideration amount is variable either due to pricing and/or volumes. We recognize revenues in the amount of variable consideration allocated to distinct units of hydrocarbons transferred to a customer. Such allocation reflects the amount of total consideration we expect to collect for completed deliveries of hydrocarbons and the terms of variable payment relate specifically to our efforts to satisfy the performance obligations under these contracts. Our performance obligations under our hydrocarbon sales agreements are to deliver either the entire production from the dedicated wells or specified contractual volumes of hydrocarbons. We often serve as the operator for jointly owned oil and gas properties. As part of this role, we perform activities to explore, develop and produce oil and gas properties in accordance with the joint operating arrangement and collective decisions of the joint parties. Other working interest owners reimburse us for costs incurred based on our agreements. We determined that these activities are not performed as part of customer relationships, and such reimbursements are recorded as cost reimbursements. We commonly market the share of production belonging to other working interest owners as the operator of jointly owned oil and gas properties. Those marketing activities are carried out as part of the collaborative arrangement, and we do not purchase or otherwise obtain control of other working interest owners’ share of production. Therefore, we act as a principal only in regard to the sale of our share of production and recognize revenue for the volumes associated with our net production. We frequently sells a portion of the working interest in each well we drill or participate in to third-party investors and retains a portion of the prospect for our own account. We typically guarantee a cost to drill to the third-party drilling participants and record a loss or gain on the difference between the guaranteed price and the actual cost to drill the well. When monies are received from third parties for future drilling obligations, we record the liability as Turnkey Drilling Obligations. Once the contracted depth for the drilling of the well is reached and a determination as to the commercial viability of the well (typically call “Casing Point Election” or “Logging Point”), the difference in the actual cost to drill and the guaranteed cost is recorded as income or expense depending on whether there was a gain or loss. Crude oil and condensate For the crude sales agreements, we satisfy our performance obligations and recognize revenue once customers take control of the crude at the designated delivery points, which include pipelines, trucks or vessels. Natural Gas and NGLs When selling natural gas and NGLs, we engage midstream entities to process our production stream by separating natural gas from the NGLs. Frequently, these midstream entities also purchase our natural gas and NGLs under the same agreements. In these situations, we determined the performance obligation is complete and satisfied at the tailgate of the processing plant when the natural gas and NGLs become identifiable and measurable products. We determined the plant tailgate is the point in time where control, is transferred to midstream entities and they are entitled to significant risks and rewards of ownership of the natural gas and NGLs. The amounts due to midstream entities for gathering and processing services are recognized as shipping and handling cost and included as lease operating expense in our consolidated Statement of Operations, since we make those payments in exchange for distinct services with the exception of natural gas sold to PG&E where transportation cost is netted directly against revenues. Under some of our natural gas processing agreements, we have an option to take the processed natural gas and NGLs in-kind and sell to customers other than the processing company. In those circumstances, our performance obligations are complete after delivering the processed hydrocarbons to the customer at the designated delivery points, which may be the tailgate of the processing plant or an alternative delivery point requested by the customer. Turnkey Drilling Obligations We manage these Turnkey Agreements for the participants of the well. The collections of pre-drilling Authorization for Expenditure (“AFE”) amounts are segregated and the gains and losses on the Turnkey Agreements are recorded in income or expense at the time of the casing point election in accordance with ASC 932-323-25 and 932-360. We manage the performance obligation for the well participants and only record revenue or expense at the time the performance obligation of the Turnkey Agreement has been satisfied. Supervisory Fees and Other For the years ended December 31, 2022 and 2021, we recognized $31,315 and $32,240, respectively in supervisory fees in Pipeline and Compressor fees which were received and allocated based on production volumes. |
Oil and Gas Properties Policy [Policy Text Block] | Oil and Gas Property and Equipment Successful Efforts We use the “successful efforts” method to account for our exploration and production activities. Under this method, we accumulate our proportionate share of costs on a well-by-well basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred, and capitalize expenditures for productive wells. We amortize the costs of productive wells under the unit-of-production method. We carry, as an asset, exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred. Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves. Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using unit-of-production rates based on the amount of proved developed reserves of oil and gas that are estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production method, oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank. Production Cost Production costs are expensed as incurred. Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain our wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labor costs to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity. Depreciation, Depletion and Amortization Depreciation, depletion and amortization, based on cost less estimated salvage value of the asset, are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized, and the assets replaced are retired. The project drilling phase commences with the development of the detailed engineering design and ends when the assets are ready for their intended use. Interest costs, to the extent they are incurred to finance expenditures during the construction phase, are included in property, plant and equipment and are depreciated over the service life of the related assets. Impairment We evaluate our oil and gas producing properties, including capitalized costs of exploratory wells and development costs, for impairment of value whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. Oil and gas producing properties are reviewed for impairment on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure or contractual terms that cause economic interdependency amongst separate, discrete fields. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows or, if available, comparable market value. We evaluate our unproved property investment and record impairment based on time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved property investments are deemed to be impaired, this amount is reported in exploration expenses in our consolidated statements of operations. During 2021 we recorded impairment losses of $177,011, on various capitalized lease and land costs where the carrying value exceeded the fair value. In 2022 there were no impairment losses. Upon the sale or retirement of a complete field of a proved property, we eliminate the cost from our books, and the resultant gain or loss is recorded to our consolidated statements of operations. Upon the sale of an entire interest in an unproved property where the property has been assessed for impairment individually, a gain or loss is recognized in our consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a recovery of the cost in the interest retained with any excess funds recognized as a gain. Should our turnkey drilling agreements include unproved property, total drilling costs incurred to satisfy our obligations are recovered by the total funds received under the agreements. Any excess funds are recorded as a Gain on Turnkey Drilling Programs, and any costs not recovered are capitalized and accounted for under the “successful efforts” method. |
Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block] | Long-Lived Assets Classified as Held for Sale We classify long-lived assets as Held-for-Sale when the criteria of ASC 360-10-45-9 through 45-11, Impairment and Disposal of Long-Lived Assets, have been met. This criterion is listed below: ● Management has committed to a plan to sell the asset; ● The asset group is available for immediate sale in its present condition; ● An active program is underway to locate potential buyers; ● The sale is probable within one year; ● The asset group is being marketed at a price that is reasonable relative to its current fair value; and ● Actions required to complete the plan indicate that it is unlikely that significant changes to the plan will be made or the plan will be withdrawn. |
Industry-Specific Policies, Oil and Gas [Policy Text Block] | Turnkey Drilling We sponsor turnkey drilling agreement arrangements in proved and unproved properties as a pooling of assets in a joint undertaking, whereby proceeds from participants are reported as Deferred Drilling Obligations, and then reduced as costs to complete our obligations and are incurred with any excess booked against our property account to reduce any basis in our own interest. Gains on Turnkey Drilling Programs represent funds received from turnkey drilling participants in excess of all costs we incur during the drilling programs (e.g., lease acquisition, exploration and development costs), including costs incurred on behalf of participants and costs incurred for our own account; and are recognized only upon making this determination after our obligations have been fulfilled. The contracts require the participants pay us the full contract price upon execution of the agreement. We complete the drilling activities typically between 10 and 30 days after drilling begins. The participant retains an undivided or proportional beneficial interest in the property, and is also responsible for their proportionate share of operating costs. We retain legal title to the lease. The participants purchase a working interest directly in the well bore. In these working interest arrangements, the participants are responsible for sharing in the risk of development, but also sharing in a proportional interest in rights to revenues and proportional liability for the cost of operations after drilling is completed and the interest is conveyed to the participant. A certain portion of the turnkey drilling participant’s funds received are non-refundable. We hold all funds invested as Deferred Drilling Obligations until drilling is complete. Occasionally, drilling is delayed for various reasons such as weather, permitting, drilling rig availability and/or contractual obligations. At December 31, 2022 and 2021, We had Deferred Drilling Obligations of $8,129,965 and $7,824,939, respectively. During 2022, we disposed of $7,027,474 of drilling obligations as we completed five oil wells in Texas and participated in completing the drilling of two oil wells in southern California, while incurring expenses of $5,301,060, resulting in a gain of $1,726,414. During 2021, we disposed of $1,841,061 of drilling obligations upon completing the drilling of two oil wells in Texas, while incurring expenses of $1,905,529, resulting in a loss of $64,468. If we are unable to drill the wells, and a suitable replacement well is not found, we would retain the non-refundable portion of the contract and return the remaining funds to the participant. Included in restricted cash are amounts for use in completion of turnkey drilling programs in progress. |
Property, Plant and Equipment, Policy [Policy Text Block] | Equipment and Fixtures Equipment and fixtures are stated at cost and depreciated over the estimated useful lives of the assets, which range from three to seven years, using the straight-line method. Repairs and maintenance are charged to expense as incurred. When assets are sold or retired, the cost and related accumulated depreciation are removed from the accounts and any resulting gain or loss is included in income. Maintenance and repairs, which neither materially add to the value of the property nor appreciably prolong its life, are charged to expense as incurred. |
Earnings Per Share, Policy [Policy Text Block] | Loss Per Share Basic and diluted losses per share are calculated as follows: Year Ended December 31, 2022 2021 Basic Diluted Basic Diluted Net Loss $ (145,594 ) $ (145,594 ) $ (3,598,418 ) $ (3,598,418 ) Less: Preferred Stock Dividend 815,772 815,772 787,833 787,833 Less: Preferred Stock Dividend in Arrears - - - - Net Loss Attributable to Common Shareholders (961,366 ) (961,366 ) (4,386,251 ) (4,386,251 ) Weighted average common shares outstanding 58,472,340 58,472,340 55,887,319 55,887,319 Effect of dilutive securities - - - - Weighted average common shares, including Dilutive effect 58,472,340 58,472,340 55,887,319 55,887,319 Per share: Net Loss $ (0.02 ) $ (0.02 ) $ (0.06 ) $ (0.06 ) For the years ended December 31, 2022 and 2021, Royale Energy had dilutive securities of 27,058,677 and 26,582,388 respectively. These securities were not included in the dilutive loss per share due to their antidilutive nature. |
Share-Based Payment Arrangement [Policy Text Block] | Stock Based Compensation We have a stock-based employee compensation plan, which is more fully described in Note 11 – Stock Compensation Plan. We have adopted ASC 718, Compensation – Stock Compensation, for share-based payments. This topic requires that the cost resulting from all share-based payment transactions be recognized in the financial statements. It further establishes fair value as the measurement objective in accounting for share-based payment arrangements and requires all entities to apply a fair-value based measurement method in accounting for share-based payment transactions with employees except for equity instruments held by employee stock ownership plans. |
Income Tax, Policy [Policy Text Block] | Income Taxes We utilize the asset and liability approach to measure deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates in accordance with the Income Taxes Topic of the ASC 740. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. Under the Topic, deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more-likely-than-not that some portion or all of the deferred tax assets will not be realized. The provision for income taxes is based on pretax financial accounting income. Deferred tax assets and liabilities are recognized for the expected tax consequences of temporary differences between the tax basis of assets and liabilities and their reported net amounts. |
Fair Value Measurement, Policy [Policy Text Block] | Fair Value Measurements According to Fair Value Measurements and Disclosures guidance as provided by ASC 820 and 825, assets and liabilities that are measured at fair value on a recurring and nonrecurring basis in periods subsequent to initial recognition, the reporting entity shall disclose information that enable users of our financial statements to assess the inputs used to develop those measurements and for recurring fair value measurements using significant unobservable inputs, the effect of the measurements on earnings for the period. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. In determining fair value, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible as well as consider counterparty credit risk in our assessment of fair value. Carrying amounts of our financial instruments, including cash equivalents, accounts receivable, accounts payable and accrued liabilities, approximate their fair values as of the balance sheet dates because of their generally short maturities. The fair value hierarchy distinguishes between (1) market participant assumptions developed based on market data obtained from independent sources (observable inputs) and (2) an entity’s own assumptions about market participant assumptions developed based on the best information available in the circumstances (unobservable inputs). The fair value hierarchy consists of three broad levels, which gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy are described below: Level 1: Quoted prices (unadjusted) in active markets that are accessible at the measurement date for assets or liabilities. Level 2: Directly or indirectly observable inputs as of the reporting date through correlation with market data, including quoted prices for similar assets and liabilities in active markets and quoted prices in markets that are not active. Level 2 also includes assets and liabilities that are valued using models or other pricing methodologies that do not require significant judgment since the input assumptions used in the models, such as interest rates and volatility factors, are corroborated by readily observable data from actively quoted markets for substantially the full term of the financial instrument. Level 3: Unobservable inputs that are supported by little or no market activity and reflect the use of significant management judgment. These values are generally determined using pricing models for which the assumptions utilize management’s estimates of market participant assumptions. At December 31, 2022 and 2021, we do not have any financial assets measured and recognized at fair value on a recurring basis. We estimate asset retirement obligations pursuant to the provisions of ASC 410, Asset Retirement and Environmental Obligations. The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 3 – |
Accounts Payable and Accrued Expenses [Policy Text Block] | Accounts Payable and Accrued Expenses At December 31, 2022 and 2021, the components of accounts payable and accrued expenses consisted of: 2022 2021 Trade Payables including accruals $ 3,108,931 $ 2,845,395 Direct working interest investors related accruals 1,801,818 1,409,148 Current drilling efforts accrued expenses 22,910 229,716 Accrued Liabilities 400,296 410,308 Employee related accruals 189,736 266,531 Deferred rent 5,138 (614 ) $ 5,528,829 $ 5,160,484 |
Accrued Liabilitites Policy [Policy Text Block] | Accrued – Non-current At December 31, 2022 and 2021, we had non-current accrued liabilities of $1,306,605 and accrued unpaid guaranteed payment of $1,616,205, due to certain Matrix Oil Corp (“Matrix”) principals, from periods prior to the merger with the Matrix entities during March of 2018. |
Business Combinations Policy [Policy Text Block] | Business Combinations From time-to-time, we acquire businesses in the oil and gas industry. We primarily target businesses in geological basins that we consider to be in a focus area. Businesses are included in the consolidated financial statements from the date of acquisition. We recognize, separately from goodwill, the identifiable assets acquired and liabilities assumed at their estimated acquisition-date fair values. We measure and recognize goodwill as of the acquisition date as the excess of: (1) the aggregate of the fair value of consideration transferred, the fair value of any noncontrolling interest in the acquiree (if any) and the acquisition date fair value of our previously held equity interest in the acquiree (if any), over (2) the fair value of assets acquired and liabilities assumed. If information about facts and circumstances existing as of the acquisition date is incomplete by the end of the reporting period in which a business combination occurs, we report provisional amounts for the items for which the accounting is incomplete. The measurement or allocation period ends once we receive the information we are seeking; however, this period will generally not exceed one year from the acquisition date. Any material adjustments recognized during the measurement period will be reflected retrospectively in the consolidated financial statements of the subsequent period. We recognize third-party transaction-related costs as expense currently in the period in which they are incurred. |
New Accounting Pronouncements, Policy [Policy Text Block] | Changes in Accounting Standards Recently Adopted ASU 2020-04, Changes to the fair value disclosure requirements In March 2020, FASB issued ASU 2020-04, Reference Rate Reform (Topic 848), Facilitation of the effects of Reference Rate Reform on Financial Reporting. This pronouncement provides optional expedients and exceptions for applying GAAP to contract modifications, hedging relationships, and other transactions affected by the anticipated transition away from LIBOR. This new ASU is eligible to be applied upon release and has various transition requirements. We acquired certain hedge contracts with the merger with the Matrix Companies in 2018. Those hedge contracts were transferred to RMX with the formation of the RMX Joint Venture as more fully described in Note 2 – RMX Joint Venture. The transition from LIBOR will not have any impact on us or our existing financial instruments or agreements. ASU 2016-13, Credit Impairment In June of 2016, the FASB issued ASC Topic 326, Financial Instruments – Credit Losses. This new guidance replaces the current incurred loss impairment model with a requirement to recognize lifetime expected credit losses immediately when a financial asset is originated or purchased. This new Current Expected Credit Losses (“CECL”) model applies to (1) loans, accounts receivable, trade receivables, and other financial assets measured at amortized cost, (2) loan commitments and certain other off-balance sheet credit exposures, (3) debt securities and financial assets measured at fair value, and (4) beneficial interests in securitized financial assets. This ASU was effective for SEC filers beginning after December 15, 2019; however, on November 15, 2019, the FASB issued ASU 2019-10, which delayed the effective date for “smaller reporting companies.” Therefore, ASU 2016-13 is effective for "smaller reporting companies" (as defined by the Securities and Exchange Commission) like us, for fiscal years beginning after December 15, 2022, including interim periods within those years, and must be adopted under the modified retrospective method. Entities may adopt ASU 2016-13 earlier as of the fiscal years beginning after December 15, 2018, including interim periods within those years. Adoption of this standard is not expected to have a material impact on our consolidated financial statements and cash flows. |
SUMMARY OF SIGNIFICANT ACCOUN_2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
Schedule of Cash and Cash Equivalents [Table Text Block] | The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheets that sum to the total of the same amounts shown in the statement of cash flows. Year Ended December 31, 2022 2021 Cash and cash equivalents $ 1,650,507 $ 220,304 Restricted cash 2,249,627 4,002,500 Total cash, cash equivalents, and restricted cash shown in the Statement of Cash Flows $ 3,900,134 $ 4,222,804 |
Disaggregation of Revenue [Table Text Block] | A significant portion of our revenues are derived from the sale of crude oil, condensate, natural gas liquids (“NGLs”) and natural gas under spot and term agreements with our customers as follows: Year Ended December 31, 2022 2021 Oil & Condensate Sales $ 1,654,840 $ 1,238,014 Natural Gas Sales 947,407 445,080 NGL Sales 8,975 3,330 $ 2,611,222 $ 1,686,424 |
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block] | Basic and diluted losses per share are calculated as follows: Year Ended December 31, 2022 2021 Basic Diluted Basic Diluted Net Loss $ (145,594 ) $ (145,594 ) $ (3,598,418 ) $ (3,598,418 ) Less: Preferred Stock Dividend 815,772 815,772 787,833 787,833 Less: Preferred Stock Dividend in Arrears - - - - Net Loss Attributable to Common Shareholders (961,366 ) (961,366 ) (4,386,251 ) (4,386,251 ) Weighted average common shares outstanding 58,472,340 58,472,340 55,887,319 55,887,319 Effect of dilutive securities - - - - Weighted average common shares, including Dilutive effect 58,472,340 58,472,340 55,887,319 55,887,319 Per share: Net Loss $ (0.02 ) $ (0.02 ) $ (0.06 ) $ (0.06 ) |
Schedule of Accounts Payable and Accrued Liabilities [Table Text Block] | At December 31, 2022 and 2021, the components of accounts payable and accrued expenses consisted of: 2022 2021 Trade Payables including accruals $ 3,108,931 $ 2,845,395 Direct working interest investors related accruals 1,801,818 1,409,148 Current drilling efforts accrued expenses 22,910 229,716 Accrued Liabilities 400,296 410,308 Employee related accruals 189,736 266,531 Deferred rent 5,138 (614 ) $ 5,528,829 $ 5,160,484 |
OIL AND GAS PROPERTIES, EQUIP_2
OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Oil and Gas Property [Abstract] | |
Property, Plant and Equipment [Table Text Block] | Oil and gas properties, equipment and fixtures consist of: Year ended December 31, 2022 2021 Oil and Gas Producing properties, including intangible drilling costs $ 5,712,436 $ 5,509,568 Undeveloped properties 148,989 128,362 Lease and well equipment 3,317,718 3,317,718 9,179,143 8,955,648 Accumulated depletion, depreciation and amortization (7,142,506 ) (6,879,531 ) Net capitalized costs Total $ 2,036,637 $ 2,076,117 Commercial and Other 2022 2021 Vehicles $ 40,061 $ 40,061 Furniture and equipment 1,097,428 1,097,428 1,137,489 1,137,489 Accumulated depreciation (1,133,806 ) (1,133,806 ) 3,683 3,683 Net capitalized costs Total $ 2,040,320 $ 2,079,800 |
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block] | The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed at December 31: Year Ended December 31, 2022 2021 Acquisition - Proved - - Acquisition - Unproved - - Development $ 5,301,061 $ 1,905,529 Exploration - - |
Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block] | The results of operations from oil and gas producing and exploration activities (excluding corporate overhead and interest costs) are as follows: Year Ended December 31, 2022 2021 Oil and gas sales $ 2,611,222 $ 1,686,424 Production-related costs (Lease Operating) (1,928,521 ) (1,814,643 ) Impairment - (177,011 ) Depreciation, depletion and amortization (575,909 ) (537,273 ) Results of operations from producing and exploration activities 106,792 (842,503 ) Income Taxes (Benefit) - - Net Results $ 106,792 $ (842,503 ) |
ASSET RETIREMENT OBLIGATION (Ta
ASSET RETIREMENT OBLIGATION (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Change in Asset Retirement Obligation [Table Text Block] | The Asset Retirement and Environmental Obligations Topic of the ASC 410-20 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset. The ARO is recorded at the estimated fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value. Accretion expense is included as part of Depreciation, Depletion and Amortization in the Consolidated Statement of Operations. The fair value (as provided in ASC 820 guidance) of the ARO is measured using expected future cash outflows discounted at our credit-adjusted risk-free interest rate. The provisions of this Topic apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, development, and operation of a long-lived asset. There were no changes in estimates for the years ended December 31, 2022 and 2021. 2022 2021 Asset retirement obligation Beginning of the year $ 2,610,560 $ 2,478,350 Liabilities incurred during the period 29,338 14,122 Settlements (58,889 ) - Sales - - Changes in estimates - - Accretion expense 286,470 118,088 Reclassification to ARO - current - - End of year $ 2,867,479 $ 2,610,560 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Income Tax Disclosure [Abstract] | |
Schedule of Deferred Tax Assets and Liabilities [Table Text Block] | Significant components of our deferred assets and liabilities at December 31, 2022 and 2021, respectively, are as follows: 2022 2021 Deferred Tax Assets (Liabilities): Statutory Depletion Carry Forward $ 310,903 $ 277,521 Net Operating Loss 8,542,098 8,697,243 Other 688,377 605,684 Share-Based Compensation 86,510 86,510 Capital Loss / AMT Credit Carry Forward 9,458 9,458 Charitable Contributions Carry Forward 100 - Allowance for Doubtful Accounts 717,514 718,516 Oil and Gas Properties and Fixed Assets 4,976,399 3,945,568 Investment in RMX Joint Venture (285,626 ) 486,092 15,045,733 $ 14,826,592 Valuation Allowance (15,045,733 ) (14,826,592 ) Net Deferred Tax Asset $ - $ - |
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | A reconciliation of our provision for income taxes and the amount computed by applying the statutory income tax rates at December 31, 2022 and 2021, respectively, to pretax income is as follows: 2022 2021 Tax (benefit) computed at statutory rate of 21% at December 31, 2022 and 2021, respectively $ (30,575 ) $ (755,668 ) Increase (decrease) in taxes resulting from: PPP Loan Forgiveness - (2,113 ) Employer Retention Credits (31,527 ) - Prior-year true-up for Books (221,621 ) 241,652 Deferred State Taxes, net of federal benefit 62,558 (131,991 ) Other non-deductible expenses 2,024 (6,086 ) Change in valuation allowance 219,141 654,206 Provision (benefit) $ - $ - |
OPERATING LEASES (Tables)
OPERATING LEASES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Disclosure Text Block [Abstract] | |
Lease, Cost [Table Text Block] | Lease expense for operating as well as finance leases are included in General and Administrative expense and Interest Expense on the Consolidated Statement of Operations, while the lease expense for those leases that are short-term are included in Oil and Gas Lease Operating Expenses. The amounts are as follows: Year Ended December 31, 2022 2021 Operating lease expense $ 174,975 $ 163,025 Financing lease expense 19,076 18,635 Short Term - field 6,000 6,000 Total lease expense $ 200,051 $ 187,660 |
Lessee, Operating Lease, Liability, to be Paid, Maturity [Table Text Block] | The following tables summarized the operating and financing lease obligations. Lease Obligations Operating Lease Obligations Financing Lease Obligations Total Lease Obligations 2023 $ 85,560 $ 12,588 $ 98,148 2024 88,128 7,343 95,471 2025 90,768 - 90,768 Thereafter 93,492 - 93,492 Total undiscounted lease payments 357,948 19,931 377,879 Less: Amount representing interest 39,929 1,097 41,026 Total Operating & Financing lease liabilities 318,019 18,834 336,853 Current lease liabilities as of December 31, 2022 70,200 11,795 81,995 Long-term lease liabilities as of December 31, 2022 $ 247,819 $ 7,039 $ 254,858 |
SUPPLEMENTAL INFORMATION ABOU_2
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables) [Line Items] | |
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block] | The net interest in estimated quantities of proved developed reserves of crude oil and natural gas at December 31, 2022 and 2021, and changes in such quantities during each of the years then ended, were as follows: Total Proved Reserves 2022 2021 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Beginning of period 1,579,100 1,354,300 1,541,000 2,660,500 Revisions of previous estimates (1,283,285 ) (85,864 ) (1,737 ) (1,916,677 ) Production (18,015 ) (135,136 ) (18,963 ) (122,151 ) Extensions, discoveries and improved recovery 94,500 - 146,052 782,300 Sales of minerals in place - - (87,252 ) (49,672 ) Proved reserves end of period 372,300 1,133,300 1,579,100 1,354,300 Proved Developed 2022 2021 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed reserves: Beginning of period 193,600 939,100 224,900 691,900 End of period 182,000 942,000 193,600 939,100 Proved Undeveloped 2022 2021 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved undeveloped reserves: Beginning of period 1,385,500 415,200 1,316,100 1,968,600 End of period 190,300 191,300 1,385,500 415,200 |
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block] | The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed at December 31: Year Ended December 31, 2022 2021 Acquisition - Proved - - Acquisition - Unproved - - Development $ 5,301,061 $ 1,905,529 Exploration - - |
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block] | This statement discloses the sources of changes in the standardized measure from year to year. The amount reported as “Net changes in prices and production costs” represents the present value of changes in prices and production costs multiplied by estimates of proved reserves as of the beginning of the year. The “accretion of discount” was computed by multiplying the 10 percent discount factor by the standardized measure on a pretax basis as of the beginning of the year. The “Sales of oil and gas produced, net of production costs” are expressed in actual dollar amounts. “Revisions of previous quantity estimates” is expressed at year-end prices. The “Net change in income taxes” is computed as the change in present value of future income taxes. 2022 2021 Future cash inflows $ 38,766,900 $ 109,213,000 Future production costs (14,094,900 ) (51,448,200 ) Future development costs (1,378,500 ) (15,622,600 ) Future income tax expense (6,988,050 ) (12,642,660 ) Future net cash flows 16,305,450 29,499,540 10% annual discount for estimated timing of cash flows (6,044,467 ) (13,217,621 ) Standardized measure of discounted future net cash flows 10,260,983 16,281,919 Sales of oil and gas produced, net of production costs (608,735 ) (261,473 ) Revisions of previous quantity estimates (12,855,765 ) 9,511,179 Net changes in prices and production costs (287,425 ) 1,532,518 Sales of minerals in place - (1,236,927 ) Extensions, discoveries and improved recovery 4,266,500 5,304,521 Accretion of discount 884,088 (2,219,984 ) Net change in income tax 2,580,401 (3,788,950 ) Net increase (decrease) $ (6,020,936 ) $ 8,840,884 |
Proved Undeveloped Reserves [Member] | |
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables) [Line Items] | |
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block] | The resulting future gross revenue streams are reduced by estimated future costs to develop and to produce proved reserves, based on year-end estimates. Estimated future development costs by year are as follows: 2023 $ 1,374,500 2024 - 2025 - Thereafter 4,000 $ 1,378,500 |
Proved Developed, Proved Non-Producing and Proved Undeveloped Reserves [Member] | |
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables) [Line Items] | |
Schedule of Future Development Costs, Oil and Gas Production [Table Text Block] | In order to realize future revenues from our proved reserves estimated in our reserve report, it will be necessary to incur future costs to develop and produce the proved reserves. The following table estimates the costs to develop and produce our proved reserves in the year 2023. 2023 Future development cost of: Proved developed reserves (PDP) - Proved non-producing reserves (PDNP) $ 74,500 Proved undeveloped reserves (PUD) 1,300,000 Total $ 1,374,500 |
SUMMARY OF SIGNIFICANT ACCOUN_3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items] | ||
Working Capital (Deficit) | $ (6,445,318) | |
Net Income (Loss) Attributable to Parent | (145,594) | $ (3,598,418) |
Accounts Receivable, Allowance for Credit Loss | 2,757,549 | 2,761,398 |
Revenues | 2,642,537 | 1,718,664 |
Contract with Customer, Liability, Current | 8,129,965 | 7,824,939 |
Oil and Gas Property, Successful Effort Method, Gross | 9,179,143 | 8,955,648 |
Increase (Decrease) in Asset Retirement Obligations | $ 0 | $ 0 |
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount (in Shares) | 27,058,677 | 26,582,388 |
Other Accrued Liabilities, Noncurrent | $ 1,306,605 | $ 1,306,605 |
Other Liabilities, Noncurrent | 1,616,205 | 1,616,205 |
Supervisory, Services [Member] | ||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items] | ||
Revenues | $ 31,315 | 32,240 |
Minimum [Member] | ||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items] | ||
Property, Plant and Equipment, Useful Life | 3 years | |
Maximum [Member] | ||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items] | ||
Property, Plant and Equipment, Useful Life | 7 years | |
Properties in California and Texas [Member] | ||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items] | ||
Oil and Gas Property, Successful Effort Method, Gross | $ 7,027,474 | |
Increase (Decrease) in Asset Retirement Obligations | $ 1,726,414 | |
Texas Properties [Member] | ||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items] | ||
Oil and Gas Property, Successful Effort Method, Gross | 1,841,061 | |
Increase (Decrease) in Asset Retirement Obligations | 1,905,529 | |
Gain (Loss) on Disposition of Oil and Gas Property | $ (64,468) |
SUMMARY OF SIGNIFICANT ACCOUN_4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - Schedule of Cash and Cash Equivalents - USD ($) | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Schedule Of Cash And Cash Equivalents Abstract | |||
Cash and cash equivalents | $ 1,650,507 | $ 220,304 | |
Restricted cash | 2,249,627 | 4,002,500 | |
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows | $ 3,900,134 | $ 4,222,804 | $ 2,401,683 |
SUMMARY OF SIGNIFICANT ACCOUN_5
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - Disaggregation of Revenue - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Oil [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenues | $ 1,654,840 | $ 1,238,014 |
Natural Gas [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenues | 947,407 | 445,080 |
Natural Gas Liquids [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenues | 8,975 | 3,330 |
Natural Gas Liquids [Member] | Oil and Gas [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenues | $ 2,611,222 | $ 1,686,424 |
SUMMARY OF SIGNIFICANT ACCOUN_6
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - Schedule of Earnings Per Share, Basic and Diluted - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Schedule Of Earnings Per Share Basic And Diluted Abstract | ||
Net Loss | $ (145,594) | $ (3,598,418) |
Less: Preferred Stock Dividend | 815,772 | 787,833 |
Less: Preferred Stock Dividend in Arrears | 0 | 0 |
Less: Preferred Stock Dividend in Arrears | 0 | 0 |
Net Loss Attributable to Common Shareholders | $ (961,366) | $ (4,386,251) |
Weighted average common shares outstanding (in Shares) | 58,472,340 | 55,887,319 |
Weighted average common shares outstanding (in Shares) | 58,472,340 | 55,887,319 |
Effect of dilutive securities | $ 0 | $ 0 |
Effect of dilutive securities (in Shares) | 0 | 0 |
Weighted average common shares, including Dilutive effect (in Shares) | 58,472,340 | 55,887,319 |
Weighted average common shares, including Dilutive effect (in Shares) | 58,472,340 | 55,887,319 |
Net Loss (in Dollars per share) | $ (0.02) | $ (0.06) |
Net Loss (in Dollars per share) | $ (0.02) | $ (0.06) |
SUMMARY OF SIGNIFICANT ACCOUN_7
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - Schedule of Accounts Payable and Accrued Liabilities - USD ($) | Dec. 31, 2022 | Dec. 31, 2021 |
Schedule Of Accounts Payable And Accrued Liabilities Abstract | ||
Trade Payables including accruals | $ 3,108,931 | $ 2,845,395 |
Direct working interest investors related accruals | 1,801,818 | 1,409,148 |
Current drilling efforts accrued expenses | 22,910 | 229,716 |
Accrued Liabilities | 400,296 | 410,308 |
Employee related accruals | 189,736 | 266,531 |
Deferred rent | 5,138 | (614) |
$ 5,528,829 | $ 5,160,484 |
RMX JOINT VENTURE (Details)
RMX JOINT VENTURE (Details) - USD ($) | 12 Months Ended | ||
Apr. 30, 2018 | Dec. 31, 2021 | Dec. 31, 2020 | |
RMX JOINT VENTURE (Details) [Line Items] | |||
Equity Method Investment, Other than Temporary Impairment | $ 6,185,995 | ||
Payments to Acquire Interest in Joint Venture | $ 0 | ||
RMX Resources, LLC [Member] | |||
RMX JOINT VENTURE (Details) [Line Items] | |||
Equity Method Investment, Ownership Percentage | 20% | ||
RMX Resources, LLC [Member] | CIC RMX LP [Member] | |||
RMX JOINT VENTURE (Details) [Line Items] | |||
Equity Method Investment, Ownership Percentage | 80% | ||
Payments to Acquire Businesses, Gross | $ 25,000,000 | ||
Class Of Warrant or Rights Granted (in Shares) | 4,000,000 | ||
RMX Resources, LLC [Member] | Maximum [Member] | |||
RMX JOINT VENTURE (Details) [Line Items] | |||
Cash Acquired from Acquisition | $ 20,000,000 |
OIL AND GAS PROPERTIES, EQUIP_3
OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Details) - Schedule of Property, Plant and Equipment - USD ($) | Dec. 31, 2022 | Dec. 31, 2021 |
Oil and Gas | ||
Producing properties, including intangible drilling costs | $ 5,712,436 | $ 5,509,568 |
Undeveloped properties | 148,989 | 128,362 |
Lease and well equipment | 3,317,718 | 3,317,718 |
Oil and gas, gross | 9,179,143 | 8,955,648 |
Accumulated depletion, depreciation and amortization | (7,142,506) | (6,879,531) |
Oil and gas, net | 2,036,637 | 2,076,117 |
Property, Plant and Equipment, Gross | 1,137,489 | 1,137,489 |
Accumulated depreciation | (1,133,806) | (1,133,806) |
Property, Plant and Equipment, Net | 3,683 | 3,683 |
Oil and gas properties, equipment and fixtures | 2,040,320 | 2,079,800 |
Vehicles [Member] | ||
Oil and Gas | ||
Property, Plant and Equipment, Gross | 40,061 | 40,061 |
Furniture and Fixtures [Member] | ||
Oil and Gas | ||
Property, Plant and Equipment, Gross | $ 1,097,428 | $ 1,097,428 |
OIL AND GAS PROPERTIES, EQUIP_4
OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Details) - Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Cost Incurred In Oil And Gas Property Acquisition Exploration And Development Activities Disclosure Abstract | ||
Acquisition - Proved | $ 0 | $ 0 |
Acquisition - Unproved | 0 | 0 |
Development | 5,301,061 | 1,905,529 |
Exploration | $ 0 | $ 0 |
OIL AND GAS PROPERTIES, EQUIP_5
OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Details) - Results of Operations for Oil and Gas Producing Activities Disclosure - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Results Of Operations For Oil And Gas Producing Activities Disclosure Abstract | ||
Oil and gas sales | $ 2,611,222 | $ 1,686,424 |
Production-related costs (Lease Operating) | (1,928,521) | (1,814,643) |
Impairment | 0 | (177,011) |
Depreciation, depletion and amortization | (575,909) | (537,273) |
Results of operations from producing and exploration activities | 106,792 | (842,503) |
Income Taxes (Benefit) | 0 | 0 |
Net Results | $ 106,792 | $ (842,503) |
ASSET RETIREMENT OBLIGATION (De
ASSET RETIREMENT OBLIGATION (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Asset Retirement Obligation Disclosure [Abstract] | ||
Asset Retirement Obligation, Accretion Expense | $ 286,470 | $ 118,088 |
ASSET RETIREMENT OBLIGATION (D
ASSET RETIREMENT OBLIGATION (Details) - Schedule of Change in Asset Retirement Obligation - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Asset retirement obligation | ||
Beginning of the year | $ 2,610,560 | $ 2,478,350 |
Liabilities incurred | 29,338 | 14,122 |
Settlements | (58,889) | 0 |
Sales | 0 | 0 |
Changes in estimates | 0 | 0 |
Accretion expense | 286,470 | 118,088 |
Reclassification to ARO - current | 0 | 0 |
End of year | $ 2,867,479 | $ 2,610,560 |
NOTES PAYABLE (Details)
NOTES PAYABLE (Details) - USD ($) | 1 Months Ended | 12 Months Ended | |||||
Nov. 01, 2021 | Nov. 02, 2020 | Oct. 03, 2018 | Feb. 28, 2021 | Dec. 31, 2022 | Dec. 31, 2021 | Apr. 22, 2020 | |
NOTES PAYABLE (Details) [Line Items] | |||||||
Debt Instrument, Face Amount | $ 38,490 | ||||||
Debt Instrument, Periodic Payment | $ 7,698 | ||||||
Other Nonrecurring Gain | $ 163,571 | $ 0 | |||||
Notes Payable | 0 | $ 113,915 | |||||
Debt, Forza Operating, LCC [Member] | |||||||
NOTES PAYABLE (Details) [Line Items] | |||||||
Debt Instrument, Face Amount | $ 517,585 | ||||||
Debt Instrument, Periodic Payment | $ 44,428 | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.50% | ||||||
Debt Instrument, Frequency of Periodic Payment | 12 monthly installments | ||||||
Oil and Gas Joint Interest Billing Receivables | $ 233,367 | ||||||
Exploration Abandonment and Impairment Expense | $ 284,218 | ||||||
Other Nonrecurring Gain | $ 13,440 | ||||||
PPP Loan [Member] | |||||||
NOTES PAYABLE (Details) [Line Items] | |||||||
Debt Instrument, Face Amount | $ 10,054 | ||||||
Debt Instrument, Periodic Payment | 560 | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 1% | ||||||
Repayments of Debt | $ 10,081 | ||||||
Gain (Loss) on Extinguishment of Debt | $ 10,061 | ||||||
PPP Loan [Member] | Final Payment [Member] | |||||||
NOTES PAYABLE (Details) [Line Items] | |||||||
Debt Instrument, Periodic Payment | $ 613 |
INCOME TAXES (Details)
INCOME TAXES (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2018 |
Income Tax Disclosure [Abstract] | ||
Operating Loss Carryforwards | $ 12 | $ 20.5 |
INCOME TAXES (Details) - Sched
INCOME TAXES (Details) - Schedule of Deferred Tax Assets and Liabilities - USD ($) | Dec. 31, 2022 | Dec. 31, 2021 |
Schedule Of Deferred Tax Assets And Liabilities Abstract | ||
Statutory Depletion Carry Forward | $ 310,903 | $ 277,521 |
Net Operating Loss | 8,542,098 | 8,697,243 |
Other | 688,377 | 605,684 |
Share-Based Compensation | 86,510 | 86,510 |
Capital Loss / AMT Credit Carry Forward | 9,458 | 9,458 |
Charitable Contributions Carry Forward | 100 | 0 |
Allowance for Doubtful Accounts | 717,514 | 718,516 |
Oil and Gas Properties and Fixed Assets | 4,976,399 | 3,945,568 |
Investment in RMX Joint Venture | (285,626) | 486,092 |
15,045,733 | 14,826,592 | |
Valuation Allowance | (15,045,733) | (14,826,592) |
Net Deferred Tax Asset | $ 0 | $ 0 |
INCOME TAXES (Details) - Sch_2
INCOME TAXES (Details) - Schedule of Effective Income Tax Rate Reconciliation - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Schedule Of Effective Income Tax Rate Reconciliation Abstract | ||
Tax (benefit) computed at statutory rate of 21% at December 31, 2022 and 2021, respectively | $ (30,575) | $ (755,668) |
PPP Loan Forgiveness | 0 | (2,113) |
Employer Retention Credits | (31,527) | 0 |
Prior-year true-up for Books | (221,621) | 241,652 |
Deferred State Taxes, net of federal benefit | 62,558 | (131,991) |
Other non-deductible expenses | 2,024 | (6,086) |
Change in valuation allowance | 219,141 | 654,206 |
Provision (benefit) | $ 0 | $ 0 |
INCOME TAXES (Details) - Sch_3
INCOME TAXES (Details) - Schedule of Effective Income Tax Rate Reconciliation (Parentheticals) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Schedule Of Effective Income Tax Rate Reconciliation Abstract | ||
Statutory rate | 21% | 21% |
SERIES B PREFERRED STOCK (Detai
SERIES B PREFERRED STOCK (Details) - Series B Preferred Stock [Member] - USD ($) | 12 Months Ended | |||
Mar. 07, 2018 | Dec. 31, 2022 | Dec. 31, 2021 | Mar. 06, 2018 | |
SERIES B PREFERRED STOCK (Details) [Line Items] | ||||
Preferred Stock, Value, Issued (in Dollars) | $ 20,124,000 | |||
Preferred Stock, Shares Issued | 2,012,400 | |||
Preferred Stock, Shares Authorized | 3,000,000 | |||
Preferred Stock, Dividend Rate, Percentage | 3.50% | |||
Preferred Stock, Convertible, Terms | The Series B Convertible Preferred Stock is convertible at the option of the security holder at the rate of ten shares of common stock for one share of Series B Convertible Preferred Stock. The Series B Preferred Stock has never been registered under the Securities Exchange Act of 1934, and no market exists for the shares. Additionally, the Series B Convertible Preferred shares will automatically convert to shares of common stock at any time in which the Volume Weighted Average Price (“VWAP”) of the common stock exceeds $3.50 per share for 20 consecutive trading days, the shares of common stock are registered with the SEC and the volume of common shares trades exceeds 200,000 shares per day. | |||
Preferred Stock Dividends, Shares | 60,748 | 58,667 | ||
Dividends, Preferred Stock, Paid-in-kind (in Dollars) | $ 607,465 | $ 586,661 | ||
Not Yet Issued [Member] | ||||
SERIES B PREFERRED STOCK (Details) [Line Items] | ||||
Preferred Stock Dividends, Shares | 20,832 | 20,117 | ||
Dividends, Preferred Stock, Paid-in-kind (in Dollars) | $ 208,307 | $ 201,172 |
OPERATING LEASES (Details)
OPERATING LEASES (Details) | 12 Months Ended |
Dec. 31, 2022 USD ($) | |
San Diego, CA [Member] | |
OPERATING LEASES (Details) [Line Items] | |
Operating Leases, Rent Expense, Minimum Rentals | $ 6,922 |
OPERATING LEASES (Details) - Le
OPERATING LEASES (Details) - Lease, Cost - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Lease, Cost [Abstract] | ||
Operating lease expense | $ 174,975 | $ 163,025 |
Financing lease expense | 19,076 | 18,635 |
Short Term - field | 6,000 | 6,000 |
Total lease expense | $ 200,051 | $ 187,660 |
OPERATING LEASES (Details) - _2
OPERATING LEASES (Details) - Lessee, Operating Lease, Liability, Maturity - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Lessee Operating Lease Liability Maturity Abstract | ||
2023 | $ 85,560 | |
2023 | 12,588 | |
2023 | 98,148 | |
2024 | 88,128 | |
2024 | 7,343 | |
2024 | 95,471 | |
2025 | 90,768 | |
2025 | 0 | |
2025 | 90,768 | |
Thereafter | 93,492 | |
Thereafter | 0 | |
Thereafter | 93,492 | |
Total undiscounted lease payments | 357,948 | |
Total undiscounted lease payments | 19,931 | |
Total undiscounted lease payments | 377,879 | |
Less: Amount representing interest | 39,929 | |
Less: Amount representing interest | 1,097 | |
Less: Amount representing interest | 41,026 | |
Total Operating & Financing lease liabilities | 318,019 | |
Total Operating & Financing lease liabilities | 18,834 | |
Total Operating & Financing lease liabilities | 336,853 | |
Current lease liabilities as of December 31, 2022 | 70,200 | |
Current lease liabilities as of December 31, 2022 | 11,795 | |
Current lease liabilities as of December 31, 2022 | 81,995 | $ 88,257 |
Long-term lease liabilities as of December 31, 2022 | 247,819 | |
Long-term lease liabilities as of December 31, 2022 | 7,039 | |
Long-term lease liabilities as of December 31, 2022 | $ 254,858 | $ 336,959 |
RELATED PARTY TRANSACTIONS (Det
RELATED PARTY TRANSACTIONS (Details) | 12 Months Ended | |
Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | |
RELATED PARTY TRANSACTIONS (Details) [Line Items] | ||
Notes Payable | $ 0 | $ 113,915 |
Revenues | 2,642,537 | 1,718,664 |
Results of Operations, Production or Lifting Costs | 1,928,521 | 1,814,643 |
Financing Receivable, after Allowance for Credit Loss | 127,360 | 98,274 |
Stephen M. Hosmer, co-president, co-chief executive officer and chief financial officer [Member] | ||
RELATED PARTY TRANSACTIONS (Details) [Line Items] | ||
Notes Payable | $ 18,251 | |
Number of Wells, Participated Individually | 179 | |
RMX Resources, LLC [Member] | ||
RELATED PARTY TRANSACTIONS (Details) [Line Items] | ||
Notes Payable | $ 23,087 | 23,087 |
Prepaid Expense and Other Assets | 290,871 | 1,327,763 |
Revenues | 491,000 | |
Results of Operations, Production or Lifting Costs | 189,000 | |
Director [Member] | ||
RELATED PARTY TRANSACTIONS (Details) [Line Items] | ||
Notes Payable | 185,049 | $ 233,872 |
Chief Executive Officer [Member] | ||
RELATED PARTY TRANSACTIONS (Details) [Line Items] | ||
Notes Payable | 15,694 | |
Unpaid Salaries [Member] | Certain Matrix Employees [Member] | Matrix Oil Corporation (“MOC”) [Member] | ||
RELATED PARTY TRANSACTIONS (Details) [Line Items] | ||
Notes Payable | 1,616,205 | |
Accrued Liabilities [Member] | Certain Matrix Employees [Member] | Matrix Oil Corporation (“MOC”) [Member] | ||
RELATED PARTY TRANSACTIONS (Details) [Line Items] | ||
Notes Payable | $ 1,306,605 |
SIMPLE IRA PLAN (Details)
SIMPLE IRA PLAN (Details) - Pension Plan [Member] - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
SIMPLE IRA PLAN (Details) [Line Items] | ||
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent | 3% | |
Defined Contribution Plan, Cost | $ 27,770 | $ 31,509 |
CONCENTRATIONS (Details)
CONCENTRATIONS (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
CONCENTRATIONS (Details) [Line Items] | ||
Cash, FDIC Insured Amount | $ 250,000 | |
Cash, Uninsured Amount | $ 3,600,000 | $ 3,900,000 |
Revenue Benchmark [Member] | Customer Concentration Risk [Member] | Customer A [Member] | ||
CONCENTRATIONS (Details) [Line Items] | ||
Concentration Risk, Percentage | 44% |
CORONAVIRUS AID, RELIEF, AND _2
CORONAVIRUS AID, RELIEF, AND ECONOMIC SECURITY ACT ("CARES ACT") (Details) - USD ($) | 12 Months Ended | ||
Nov. 10, 2020 | Dec. 31, 2022 | Apr. 22, 2020 | |
CORONAVIRUS AID, RELIEF, AND ECONOMIC SECURITY ACT ("CARES ACT") (Details) [Line Items] | |||
Proceeds from Loans | $ 152,000 | ||
PPP Loan [Member] | |||
CORONAVIRUS AID, RELIEF, AND ECONOMIC SECURITY ACT ("CARES ACT") (Details) [Line Items] | |||
Notes Payable to Bank | $ 10,054 | $ 207,800 | |
Debt Instrument, Interest Rate, Stated Percentage | 1% | ||
Debt Instrument, Decrease, Forgiveness | 198,846 | ||
Principal Forgiveness [Member] | PPP Loan [Member] | |||
CORONAVIRUS AID, RELIEF, AND ECONOMIC SECURITY ACT ("CARES ACT") (Details) [Line Items] | |||
Debt Instrument, Decrease, Forgiveness | 197,800 | ||
Interest Forgiveness [Member] | PPP Loan [Member] | |||
CORONAVIRUS AID, RELIEF, AND ECONOMIC SECURITY ACT ("CARES ACT") (Details) [Line Items] | |||
Debt Instrument, Decrease, Forgiveness | $ 1,046 |
LONG-LIVED ASSETS HELD FOR SA_2
LONG-LIVED ASSETS HELD FOR SALE (Details) | 12 Months Ended |
Dec. 31, 2021 USD ($) | |
East Los Angeles [Member] | |
LONG-LIVED ASSETS HELD FOR SALE (Details) [Line Items] | |
Asset, Held-for-Sale, Not Part of Disposal Group | $ 1,000,000 |
Asset Retirement Obligation | 721,000 |
Oil and Gas Reclamation Liability, Noncurrent | 1,000,000 |
Gain (Loss) on Disposition of Property Plant Equipment | 254,000 |
Texas Properties [Member] | |
LONG-LIVED ASSETS HELD FOR SALE (Details) [Line Items] | |
Gain (Loss) on Disposition of Property Plant Equipment | $ (319,000) |
SUBSEQUENT EVENTS (Details)
SUBSEQUENT EVENTS (Details) - Subsequent Event [Member] | 3 Months Ended |
Mar. 31, 2023 USD ($) | |
SUBSEQUENT EVENTS (Details) [Line Items] | |
Payments for Legal Settlements | $ 20,832 |
Debt Conversion, Original Debt, Amount | $ 208,307 |
SUPPLEMENTAL INFORMATION ABOU_3
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) | 12 Months Ended | |
Dec. 31, 2022 USD ($) $ / Mcf $ / bbl bbl Mcf | Dec. 31, 2021 USD ($) bbl Mcf | |
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items] | ||
Proved Oil and Gas Property, Successful Effort Method (in Dollars) | $ 5,712,436 | $ 5,509,568 |
Measurement Input, Discount Rate [Member] | ||
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items] | ||
Oil and Gas Property, Measurement Input | 10 | |
Natural Gas [Member] | ||
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items] | ||
Proved Developed and Undeveloped Reserves, Percentage change | (16.30%) | |
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | Mcf | (85,864) | (1,916,677) |
Natural Gas [Member] | PG&E Citygate [Member] | ||
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items] | ||
Oil and Gas, Average Sale Price (in Dollars per Thousand Cubic Feet) | $ / Mcf | 6.357 | |
Oil [Member] | ||
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items] | ||
Proved Developed and Undeveloped Reserves, Percentage change | (76.40%) | |
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | bbl | (1,283,285) | (1,737) |
Oil [Member] | West Texas Intermediate [Member] | ||
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items] | ||
Oil and Gas, Average Sale Price (in Dollars per Thousand Cubic Feet) | $ / bbl | 94.14 | |
Oil and Gas Properties [Member] | ||
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items] | ||
Proved Oil and Gas Property, Successful Effort Method (in Dollars) | $ 23,300,000 |
SUPPLEMENTAL INFORMATION ABOU_4
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities | 12 Months Ended | |
Dec. 31, 2022 bbl Mcf | Dec. 31, 2021 bbl Mcf | |
Oil [Member] | ||
Reserve Quantities [Line Items] | ||
Beginning of period | bbl | 1,579,100 | 1,541,000 |
Proved reserves end of period | bbl | 372,300 | 1,579,100 |
Beginning of period | bbl | 193,600 | 224,900 |
End of period | bbl | 182,000 | 193,600 |
Beginning of period | bbl | 1,385,500 | 1,316,100 |
End of period | bbl | 190,300 | 1,385,500 |
Revisions of previous estimates | bbl | (1,283,285) | (1,737) |
Production | bbl | (18,015) | (18,963) |
Extensions, discoveries and improved recovery | bbl | 94,500 | 146,052 |
Sales of minerals in place | bbl | 0 | (87,252) |
Natural Gas [Member] | ||
Reserve Quantities [Line Items] | ||
Beginning of period | Mcf | 1,354,300 | 2,660,500 |
Proved reserves end of period | Mcf | 1,133,300 | 1,354,300 |
Beginning of period | Mcf | 939,100 | 691,900 |
End of period | Mcf | 942,000 | 939,100 |
Beginning of period | Mcf | 415,200 | 1,968,600 |
End of period | Mcf | 191,300 | 415,200 |
Revisions of previous estimates | Mcf | (85,864) | (1,916,677) |
Production | Mcf | (135,136) | (122,151) |
Extensions, discoveries and improved recovery | Mcf | 0 | 782,300 |
Sales of minerals in place | Mcf | 0 | (49,672) |
SUPPLEMENTAL INFORMATION ABOU_5
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure - Proved Developed, Proved Non-Producing and Proved Undeveloped Reserves [Member] | Dec. 31, 2022 USD ($) |
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |
2023 | $ 1,374,500 |
2024 | 0 |
2025 | 0 |
Thereafter | 4,000 |
$ 1,378,500 |
SUPPLEMENTAL INFORMATION ABOU_6
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows Abstract | ||
Future cash inflows | $ 38,766,900 | $ 109,213,000 |
Future production costs | (14,094,900) | (51,448,200) |
Future development costs | (1,378,500) | (15,622,600) |
Future income tax expense | (6,988,050) | (12,642,660) |
Future net cash flows | 16,305,450 | 29,499,540 |
10% annual discount for estimated timing of cash flows | (6,044,467) | (13,217,621) |
Standardized measure of discounted future net cash flows | 10,260,983 | 16,281,919 |
Sales of oil and gas produced, net of production costs | (608,735) | (261,473) |
Revisions of previous quantity estimates | (12,855,765) | 9,511,179 |
Net changes in prices and production costs | (287,425) | 1,532,518 |
Sales of minerals in place | 0 | (1,236,927) |
Extensions, discoveries and improved recovery | 4,266,500 | 5,304,521 |
Accretion of discount | 884,088 | (2,219,984) |
Net change in income tax | 2,580,401 | (3,788,950) |
Net increase (decrease) | $ (6,020,936) | $ 8,840,884 |
SUPPLEMENTAL INFORMATION ABOU_7
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Future Development Costs, Oil and Gas Production | Dec. 31, 2022 USD ($) |
Proved Developed Reserves [Member] | |
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Future Development Costs, Oil and Gas Production [Line Items] | |
Estimated Future Costs, Year 1 | $ 0 |
Proved Non-Producing Reserves [Member] | |
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Future Development Costs, Oil and Gas Production [Line Items] | |
Estimated Future Costs, Year 1 | 74,500 |
Proved Undeveloped Reserves [Member] | |
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Future Development Costs, Oil and Gas Production [Line Items] | |
Estimated Future Costs, Year 1 | 1,300,000 |
Proved Developed, Proved Non-Producing and Proved Undeveloped Reserves [Member] | |
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Future Development Costs, Oil and Gas Production [Line Items] | |
Estimated Future Costs, Year 1 | $ 1,374,500 |