Document And Entity Information
Document And Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2020 | Feb. 17, 2021 | Jun. 30, 2020 | |
Document Information Line Items | |||
Entity Registrant Name | Royale Energy, Inc. | ||
Document Type | 10-K | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Common Stock, Shares Outstanding | 55,192,846 | ||
Entity Public Float | $ 3,376,913 | ||
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, 2020 | ||
Document Fiscal Year Focus | 2020 | ||
Document Fiscal Period Focus | FY | ||
Entity Small Business | true | ||
Entity Emerging Growth Company | false | ||
Entity Shell Company | false | ||
Entity Interactive Data Current | Yes |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) | Dec. 31, 2020 | Dec. 31, 2019 |
Current Assets: | ||
Cash and Cash equivalents | $ 255,112 | $ 1,031,014 |
Restricted Cash | 2,146,571 | 2,845,515 |
Other Receivables, net | 462,777 | 1,189,892 |
Revenue Receivables | 204,149 | 589,151 |
Assets Held For Sale | 1,529,141 | 0 |
Prepaid Expenses and Other Current Assets | 233,769 | 376,587 |
Prepaid Drilling to RMX Resources, LLC | 239,036 | 2,680,155 |
Total Current Assets | 5,070,555 | 8,712,314 |
Investment in Joint Venture | 0 | 6,185,995 |
Other Assets | 583,554 | 708,554 |
Right of Use Asset - Operating Leases | 229,516 | 392,774 |
Oil and Gas Properties (Successful Efforts Basis), Real Property and Equipment and Fixtures, net | 2,541,001 | 4,590,990 |
Total Assets | 8,424,626 | 20,590,627 |
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT) | ||
Accounts Payable and Accrued Expenses | 4,161,109 | 6,031,034 |
Royalties Payable | 623,405 | 623,405 |
Notes Payable | 132,624 | 55,573 |
Due RMX Resources, LLC | 23,087 | 32,367 |
Operating Leases - Current | 178,120 | 162,272 |
Asset Retirement Obligation - Current | 869,147 | 0 |
Deferred Drilling Obligations | 3,127,500 | 5,232,675 |
Total Current Liabilities | 9,114,992 | 12,137,326 |
Asset Retirement Obligation | 2,478,350 | 3,632,423 |
Operating Leases - Non-current | 52,937 | 231,071 |
Accrued Unpaid Guaranteed Payments | 1,616,205 | 1,616,205 |
Accrued Liabilities - Non-current | 1,306,605 | 1,306,605 |
Total Liabilities | 14,569,089 | 18,923,630 |
Mezzanine Equity: | ||
Convertible Preferred Stock, Series B, $10 par value, 3.5% annual dividend, 2,221,622 shares issued as of December 31, 2020 | 22,216,238 | 0 |
Convertible Preferred Stock, Series B, $10 par value, 3,000,000 Shares Authorized, 2,145,332 shares issued / outstanding at December 31, 2019 | 0 | 21,453,338 |
Common Stock | 54,605 | 51,854 |
Additional Paid in Capital | 53,883,479 | 53,549,543 |
Accumulated Deficit | (82,298,785) | (73,387,738) |
Total Stockholder’s Equity (Deficit) | (28,360,701) | 1,666,997 |
Total Liabilities and Stockholders’ Equity | $ 8,424,626 | $ 20,590,627 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parentheticals) - $ / shares | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Statement of Financial Position [Abstract] | ||
Convertible Preferred, shares issued | 2,221,622 | |
Convertible Preferred Stock, Series B, annual dividend | 3.50% | |
Convertible Preferred Stock, Series B, par value (in Dollars per share) | $ 10 | |
Convertible Preferred Stock, Series B, par value (in Dollars per share) | 10 | $ 10 |
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 | 54,605,488 | 51,854,136 |
Common Stock, shares outstanding | 54,605,488 | 51,854,136 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Revenues: | ||
Revenues | $ 1,587,855 | $ 2,967,183 |
Costs and Expenses: | ||
Lease Operating | 1,397,673 | 1,764,538 |
Impairment | 0 | 977,682 |
Geological and Geophysical Expense | 14,392 | 264,219 |
Well Equipment Write Down | 0 | 28,343 |
Depreciation, Depletion and Amortization | 473,647 | 468,143 |
Bad Debt Expense | 1,008,003 | 60,512 |
General and Administrative | 2,109,232 | 1,991,819 |
Legal and Accounting | 279,227 | 751,935 |
Marketing | 113,614 | 414,971 |
Loss on Assets Held For Sale | 566,858 | 0 |
Total Costs and Expenses | 5,962,646 | 6,722,162 |
Gain on Turnkey Drilling | 1,700,462 | 2,909,908 |
Loss from Operations | (2,674,329) | (845,071) |
Interest Expense | (12,949) | (20,559) |
Loss on Investment in Joint Venture | (6,185,995) | (397,936) |
Gain on Settlement of Payables | 166,300 | 897,708 |
Other Gain | 551,906 | 172,523 |
Gain (Loss) on Sale of Assets | 6,920 | (155,048) |
Loss Before Income Tax Expense | (8,148,147) | (348,383) |
Net Loss | $ (8,148,147) | $ (348,383) |
Basic Loss Per Share (in Dollars per share) | $ (0.17) | $ (0.02) |
Diluted Loss Per Share (in Dollars per share) | $ (0.17) | $ (0.02) |
Oil and Gas [Member] | ||
Revenues: | ||
Revenues | $ 1,542,803 | $ 2,329,275 |
Management Service [Member] | ||
Revenues: | ||
Revenues | $ 45,052 | $ 637,908 |
CONSOLIDATED STATEMENTS OF STOC
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT) - USD ($) | Common Stock [Member] | Preferred Stock [Member] | Additional Paid-in Capital [Member] | Retained Earnings [Member] | Total |
Balance at Dec. 31, 2018 | $ 49,421 | $ 20,718,613 | $ 53,023,350 | $ (72,304,630) | $ 1,486,754 |
Balance (in Shares) at Dec. 31, 2018 | 49,421,387 | 2,071,861 | |||
Stock issued in lieu of Compensation | $ 2,433 | 526,193 | 528,626 | ||
Stock issued in lieu of Compensation (in Shares) | 2,432,749 | ||||
Preferred Series B 3.5% Dividend | $ 734,725 | (734,725) | |||
Preferred Series B 3.5% Dividend (in Shares) | 73,473 | ||||
Net Loss | (348,383) | (348,383) | |||
Balance at Dec. 31, 2019 | $ 51,854 | $ 21,453,338 | 53,549,543 | (73,387,738) | 1,666,997 |
Balance (in Shares) at Dec. 31, 2019 | 51,854,136 | 2,145,334 | |||
Stock issued in lieu of Compensation | $ 2,751 | 333,936 | 336,687 | ||
Stock issued in lieu of Compensation (in Shares) | 2,751,352 | ||||
Reclassify Preferred B to Mezzanine | $ (21,640,538) | (21,640,538) | |||
Reclassify Preferred B to Mezzanine (in Shares) | (2,164,054) | ||||
Preferred Series B 3.5% Dividend | $ 187,200 | (762,900) | (575,700) | ||
Preferred Series B 3.5% Dividend (in Shares) | 18,720 | ||||
Net Loss | (8,148,147) | (8,148,147) | |||
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 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | ||
Net (Loss) | $ (8,148,147) | $ (348,383) |
Adjustments to Reconcile Net Loss to Net Cash Used by Operating Activities: | ||
Depreciation, Depletion, and Amortization | 473,647 | 468,143 |
Impairment | 0 | 977,682 |
(Gain) Loss on Sale of Assets | (6,920) | 155,048 |
Gain on Turnkey Drilling | (1,700,462) | (2,909,908) |
(Gain) Loss on Settlement of Accounts Payable | (166,300) | (897,708) |
Loss on Investment in Joint Venture | 6,185,995 | 397,936 |
Bad Debt Expense | 1,008,003 | 60,512 |
Loss on Assets Held For Sale | 566,858 | 0 |
Geological & Geophysical Costs | 14,392 | 264,219 |
Gain on Other | (271,310) | (172,523) |
Stock-Based Compensation | 336,687 | 528,626 |
Well Equipment and Other Assets Write Down | 0 | 28,343 |
Right of Use Asset Depreciation | 10,945 | 0 |
(Increase) Decrease in: | ||
Other & Revenue Receivables | 46,210 | 84,372 |
Prepaid Expenses and Other Assets | 2,583,937 | (2,679,919) |
Increase (Decrease) in: | ||
Accounts Payable and Accrued Expenses | (1,305,371) | 866,092 |
Royalties Payable | 0 | (9,386) |
Due to Affiliate | (9,280) | (302,628) |
Net Cash Used in Operating Activities | (381,116) | (3,489,482) |
CASH FLOWS FROM INVESTING ACTIVITIES: | ||
Expenditures for Oil and Gas Properties | (5,562,985) | (9,393,338) |
Proceeds from Turnkey Drilling | 4,327,500 | 10,981,159 |
Net Cash (Used In) Provided by Investing Activities | (1,235,485) | 1,587,821 |
CASH FLOWS FROM FINANCING ACTIVITIES: | ||
Principal Payments on Long-Term Debt | (66,045) | (390,840) |
Proceeds from Long-Term Debt | 207,800 | 0 |
Seismic Financing Agreement Payments | 0 | (186,012) |
Net Cash Provided by (Used In) Financing Activities | 141,755 | (576,852) |
Net Increase (Decrease) in Cash | (1,474,846) | (2,478,513) |
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year | 3,876,529 | 6,355,042 |
Cash, Cash Equivalents, and Restricted Cash at End of Year | 2,401,683 | 3,876,529 |
Cash Paid for Interest | 12,949 | 20,559 |
Cash Paid for Taxes | 5,559 | 19,374 |
Increase (Decrease) in Capital Accrued Balance | (487,323) | (94,546) |
Series B Paid-In-Kind Dividends | $ 762,900 | $ 734,725 |
SUMMARY OF SIGNIFICANT ACCOUNTI
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2020 | |
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 “Royale Energy,” “Royale,” or the “Company”) is presented to assist in understanding Royale Energy’s financial statements. These consolidated financial statements include the accounts of 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 Royale Energy’s 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 Royale Energy is an independent oil and gas producer which also has operations in the area of turnkey drilling. Royale Energy owns wells and leases in major geological basins located primarily in California, Texas, Oklahoma, Colorado, and Utah. Royale Energy offers fractional working interests and seeks 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 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 17 – Supplemental Information About Oil and Gas Producing Activities (Unaudited) 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, 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 the Company’s 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. At December 31, 2020, the Company has $1.529 million in Long Lived Assets Held for Sale. The Company’s 2020 consolidated financial statements reflect a working capital deficiency of $4,044,437 and a net loss from operations of $2,674,329. 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 the Company is unable to continue as a going concern. Management’s plans to alleviate the going concern by cost control measures that include the reduction of overhead costs and 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 the Company and whether the Company will become profitable and generate positive operating cash flow. If the Company is unable to raise sufficient additional funds, it will have to develop and implement a plan to further extend payables, attempt to extend note repayments, 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. Correction of Immaterial Errors in Previously Issued Financial Statements Subsequent to the issuance of the consolidated financial statements for the year ended December 31, 2019, the Company concluded that the Statement of Cash Flows for the year ending December 31, 2019, contained immaterial errors related to the classification of payments arising from operating leases and to the quantification of the amount of capital expenditures that had been accrued for but not yet paid. These immaterial errors have been corrected for the comparative period, resulting in an increase in cash flows used in operating activities of $239,362; an increase in cash flows provided by investing activities of $94,546; and a decrease in cash flows used in financing activities of $144,816 for the period ending December 31, 2019. These immaterial errors did not have any impact on our financial position, net loss or total cash flow for the period ending December 31, 2019. Restricted Cash Royale sponsors turnkey drilling arrangements in proved and unproved properties. The contracts require that participants pay Royale 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, the Company 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. Royale classifies 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 statement of financial position that sum to the total of the same amounts shown in the statement of cash flows. Year Ended December 31, 2020 2019 Cash and cash equivalents $ 255,112 $ 1,031,014 Restricted cash 2,146,571 2,845,515 Total cash, cash equivalents, and restricted cash shown in the statement of cash flows 2,401,683 3,876,529 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 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, 2020 and 2019, the Company established an allowance for uncollectable accounts of $2,582,093 and $1,791,162, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue. During 2020 and 2019, the Company closed a number of accounts as uncollectable, offsetting the allowance in the amount of $2,553 and $519,333 respectively. 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, Royale has not had issues related to the collection of revenue receivables, and as such has 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 sheet. 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. The earnings from RMX reflected in these financial statements as Investment in JV, reflect our share of net earnings or losses directly attributable to this equity method investment. We evaluated our investment in RMX as of December 31, 2019, and determined that any losses were not other than temporary. At December 31, 2020, we evaluated our investment in RMX and determined that our investment was impaired as further described in Note 2 – RMX Joint Venture. 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. Year Ended December 31, 2020 2019 Oil & Condensate Sales $ 1,184,680 $ 1,504,936 Natural Gas Sales 357,587 824,339 NGL Sales 536 - $ 1,542,803 $ 2,329,275 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 sheet. Under our hydrocarbon sales agreements, the entire consideration amount is variable either due to pricing and/or volumes. We recognize revenue 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. The Company frequently sells a portion of the working interest in each well it drills or participates in to third-party investors and retains a portion of the prospect for its own account. The Company typically guarantees a cost to drill to the third-party drilling participants and records 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, the Company records 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, as defined in the new revenue standard, 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 is netted directly against revenue. 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 These Turnkey Agreements are managed by the Company for the participants of the well. The collections of pre-drilling AFE amounts are segregated by the Company 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. The Company manages the performance obligation for the well participants and only records revenue or expense at the time the performance obligation of the Turnkey Agreement has been satisfied. Supervisory Fees and Other These amounts include proceeds from the Master Service Agreement (“MSA”) with RMX for the providing of land, engineering, accounting and support services for the RMX joint venture. Revenues earned under the MSA were recorded at the end of each month that services were performed, in conformity with the Agreement. The service fee income was deemed earned at the end of each month that services were performed as prescribed by the contract. On December 31, 2018, Royale received notice of cancelation of the MSA by RMX effective March 31, 2019. For the year ended 2019, the Company recognized $540,000 in supervisory fees from RMX. Also included in the caption are Pipeline and Compressor fees which are received and allocated based on production volumes. Oil and Gas Property and Equipment Successful Efforts Royale Energy uses the “successful efforts” method to account for its exploration and production activities. Under this method, Royale Energy accumulates its proportionate share of costs on a well-by-well basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred, and capitalizes expenditures for productive wells. Royale Energy amortizes the costs of productive wells under the unit-of-production method. Royale Energy carries, 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 Royale Energy is 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 Royale Energy’s 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 income. During 2020 there were no impairment losses, while 2019 the Company recorded impairment losses of $977,682, on various capitalized base and land costs as well as certain fields acquired through the merger with the matrix entities. Upon the sale or retirement of a complete field of a proved property, Royale Energy eliminates the cost from its books, and the resultant gain or loss is recorded to Royale Energy’s Statement 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 Royale Energy’s Statement 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 Royale Energy’s turnkey drilling agreements include unproved property, total drilling costs incurred to satisfy its 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 Royale classifies 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 the Company retains the responsibility for the P&A, equipment removal or site restoration, the associated anticipated expense is carried as current ARO. The Company has two property groups that are being Held for Sale as further described in Note 17 – Long-Lived Assets Held for Sale. Turnkey Drilling Royale Energy sponsors 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 its obligations are incurred with any excess booked against its property account to reduce any basis in its own interest. Gains on Turnkey Drilling Programs represent funds received from turnkey drilling participants in excess of all costs Royale incurs during the drilling programs (e.g., lease acquisition, exploration and development costs), including costs incurred on behalf of participants and costs incurred for its own account; and are recognized only upon making this determination after Royale’s obligations have been fulfilled. The contracts require the participants pay Royale Energy the full contract price upon execution of the agreement. Royale Energy completes 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 its proportionate share of operating costs. Royale Energy retains 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. The Company holds 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, 2020 and 2019, Royale Energy had Deferred Drilling Obligations of $ 3,127,500 and $5,232,675, respectively. If Royale Energy is unable to drill the wells, and a suitable replacement well is not found, Royale would retain the non-refundable portion of the contact and return the remaining funds to the participant. Included in cash and cash equivalents 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. Gains or losses on dispositions of property and equipment, other than oil and gas, are reflected in operations. Income (Loss) Per Share Basic and diluted losses per share are calculated as follows: Year Ended December 31, 2020 2019 Basic Diluted Basic Diluted Net Loss $ (8,148,147 ) $ (8,148,147 ) $ (348,383 ) $ (348,383 ) Less: Preferred Stock Dividend 762,900 762,900 734,725 734,725 Less: Preferred Stock Dividend in Arrears - - - - Net Loss Attributable to Common Shareholders (8,911,047 ) (8,911,047 ) (1,083,108 ) (1,083,108 ) Weighted average common shares outstanding 53,292,647 53,292,647 50,871,447 50,871,447 Effect of dilutive securities - - - - Weighted average common shares, including Dilutive effect 53,292,647 53,292,647 50,871,447 50,871,447 Per share: Net Loss $ (0.17 ) $ (0.17 ) $ (0.02 ) $ (0.02 ) For the years ended December 31, 2020 and 2019, Royale Energy had dilutive securities of 25,137,267 and 23,947,519 respectively. These securities were not included in the dilutive loss per share due to their antidilutive nature. Stock Based Compensation Royale has a stock-based employee compensation plan, which is more fully described in Note 11 – Stock Compensation Plan. The Company has 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 Royale utilizes 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 period subsequent to initial recognition, the reporting entity shall disclose information that enable users of its 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, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible as well as considers counterparty credit risk in its assessment of fair value. Carrying amounts of the Company’s 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 p |
RMX JOINT VENTURE
RMX JOINT VENTURE | 12 Months Ended |
Dec. 31, 2020 | |
Business Combinations [Abstract] | |
Business Combination Disclosure [Text Block] | NOTE 2 RMX JOINT VENTURE RMX Joint Venture On April 13, 2018, Royale Energy, Inc., and two of Royale’s 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 Resources, LLC (“RMX”), a newly formed Texas limited liability company formed to facilitate the investment from CIC. In exchange for its contributed assets, Royale received a 20% equity interest in RMX, an equity performance incentive interest and up to $20.0 million to pay off Royale Entities senior lender, Arena Limited SPV, LLC., in full, and to pay 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 Royale’s 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. Royale has two seats on the board giving it a third of the Board. Royale has designated Michael McCaskey and Johnny Jordan as its 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 it has received all Unpaid Preferred Return and Unpaid Preferred Enhanced Return, as defined by the Company’s Agreement. Royale accounts for its 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 Resources, LLC (“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 MSA As part of the joint venture, RMX entered into a Master Service Agreement (“MSA”) calling for Royale Energy to provide land, engineering and support services for the joint venture. For these services, Royale received $180,000 per month for the period April 2018 through March 2019. These amounts are included in Supervisory Fees, Service Agreement and Other as more fully described in Note 1. On December 31, 2018, Royale was formally notified of RMX’s intent to terminate the MSA as of March 31, 2019. The Termination Notice called for Royale to continue to provide accounting and other services through March 31, 2019. RMX Joint Venture Post-Closing On March 11, 2019, Royale 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. In settlement of these differences, Royale agreed to assign its remaining interests in the Bellevue Field, located in Kern County and the W. Whittier Field located in Los Angeles County, California to RMX. These fields accounted for 5.145 and 140.647 Mboe in reserves and were valued at $67,671 and $2.4 million, respectively using SEC pricing and discounted at 10 percent at December 31, 2018. Royale continues to be liable for the payment of all royalties and suspended funds incurred prior to March 1, 2018. Also, as part of this Settlement Agreement, RMX will offer Royale 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 Royale in each year is 2 net wells as determined by an agreed upon methodology. The Agreement also calls for certain credits toward future drilling costs of the offered wells. The Company recorded a loss of $1,237,126 on the settlement, recorded in Loss on Sale of Assets in the Statement of Operations during 2019. In conjunction with the merger between the Matrix entities and Royale, there were $1,254,204 of assets included on the books of Matrix for which documentary support could not be identified. At December 31, 2018, the Company concluded that these amounts were a contingent liability and recorded them in Current - Accrued Liabilities. On October 11, 2019, the Company received documentary support enabling management to conclude that the liability was no longer probable and should be derecognized. The Company recorded a gain of $1,254,204 on extinguishment, recorded in Loss on Sale of Assets in the Statement of Operations during 2019. 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, Royale received the RMX engineering reserve report prepared by an independent outside engineering firm. The report reflected reserve values for RMX that were below the Company’s expectations. As a result, of this and on-going market conditions along with the contractual terms of Royale’s investment in RMX, management performed an impairment test. Royale considered the waterfall formula as called for under its agreements with RMX as well as the preferred return owed to other partners. As part of this computation, Royale 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, Royale does not expect to realize the entire carrying amount of the RMX investment. Therefore, the entire amount of $6,185,995 is impaired and was taken to the Statement of Operations. Additional reasons that Royale considers this impairment to be permanent is that these assets are located in California close to urban dwellings and subject to increasing regulatory scrutiny. Further, the current state administration has indicated a strong desire to impose increasing regulations on oil and gas producing properties thereby reducing their economic value. Because the Company does not expect the value of the RMX Joint Venture to improve to a level where the water-fall profit sharing formula will provide value to Royale, the Company is no longer providing summarized financial information on the RMX investment in its financial statements or its reserve disclosures. Listed below is summarized information the Company’s investment in RMX: Twelve Months Ended December 31, 2020 Twelve Months Ended December 31, 2019 RMX Resources, LLC RMX Resources, LLC Balance Sheet: Total Assets $ 77,168,147 $ 72,401,841 Total Liabilities $ 46,213,651 $ 41,573,426 Members Equity $ 30,954,496 $ 30,828,415 Results of Operations: Net operating revenue $ 9,376,395 $ 16,392,305 Income (Loss) from operations $ (3,352,584 ) $ 1,456,290 Net income $ 126,081 $ (2,091,239 ) |
OIL AND GAS PROPERTIES, EQUIPME
OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES | 12 Months Ended |
Dec. 31, 2020 | |
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, 2020 2019 Oil and Gas Producing properties, including intangible drilling costs $ 5,672,457 $ 7,792,156 Undeveloped properties 13,993 46,990 Lease and well equipment 3,317,718 3,304,565 $ 9,004,168 $ 11,143,711 Accumulated depletion, depreciation and amortization (6,467,626 ) (6,559,182 ) Net capitalized costs Total 2,536,542 4,584,529 Commercial and Other 2020 2019 Real estate, including furniture and fixtures $ - $ - Vehicles 40,061 40,061 Furniture and equipment 1,097,428 1,097,428 1,137,489 1,137,489 Accumulated depreciation (1,133,030 ) (1,131,028 ) 4,459 6,461 Net capitalized costs Total $ 2,541,001 $ 4,590,990 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, 2020 2019 Acquisition - Proved - - Acquisition - Unproved - - Development 5,306,639 9,680,298 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 2020 and 2019. 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. Year Ended December 31, 2020 2019 Beginning balance at January 1 - - Additions to capitalized exploratory well costs pending the determination of proved reserves - - Reclassifications to wells, facilities, and equipment based on the determination of proved reserves - - Ending balance at December 31 - - 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, 2020 2019 Oil and gas sales $ 1,542,803 $ 2,329,275 Production-related costs (Lease Operating) (1,397,673 ) (1,764,538 ) Impairment - (977,682 ) Depreciation, depletion and amortization (473,647 ) (468,143 ) Results of operations from producing and exploration activities $ (328,517 ) $ (881,088 ) Income Taxes (Benefit) - - Net Results $ (328,517 ) $ (881,088 ) |
ASSET RETIREMENT OBLIGATION
ASSET RETIREMENT OBLIGATION | 12 Months Ended |
Dec. 31, 2020 | |
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 the Company’s 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 year ended December 31, 2020. During the year ended December 31, 2019, the Company recorded $922,698 in increased costs related to estimates for abandonment of its’ share of certain California oil properties. These estimates relate to properties likely to be abandoned in the current period. As a result, the Company recorded them as impairment expense at year end 2019. 2020 2019 Asset retirement obligation Beginning of the year $ 3,632,422 $ 2,366,456 Liabilities incurred during the period 29,323 210,643 Settlements (508,538 ) - Merger Additions - - Sales - (33,026 ) Changes in estimates - 922,698 Accretion expense 194,290 165,651 Reclassification to ARO - current (869,147 ) - End of year $ 2,478,350 $ 3,632,422 The Company records accretion expense as part of Depreciation, Depletion and Amortization |
NOTES PAYABLE
NOTES PAYABLE | 12 Months Ended |
Dec. 31, 2020 | |
Debt Disclosure [Abstract] | |
Short-term Debt [Text Block] | NOTE 5 NOTES PAYABLE On October 3, 2018, the Company issued a promissory note for a principal amount of $517,585 to Forza Operating, LLC. At an interest rate of 5.5%. Beginning October 3, 2018, principal and interest is due and payable in 12 monthly installments of $44,428. The note was the result of an agreement regarding the plugging and abandonment of the CL&F #1 and the CL&F #1 SWD wells. The Company agreed to include the current joint interest billing balance due to Forza Operating of $233,367 and Royale’s share of future plugging and abandonment costs of $284,218. At December 31, 2020 and 2019, Royale Energy had Notes Payable of $132,624 and $55,573, respectively, as a current liability. On November 2, 2020, in conjunction with the PPP loan forgiveness described in Note 16 – Coronavirus Aid, Relief, And Economic Security Act (“CARES Act”), Royale’s 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. The loan is being amortized over 18 months at an annual interest rate of 1.00 percent with the last payment being a balloon payment to complete the loan repayment. |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2020 | |
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. In 2016, the Company adopted Accounting Standards Update (ASU) 2015-17 and has classified all of its deferred tax assets and liabilities as noncurrent on its balance sheet. On December 22, 2017, the U.S. enacted significant changes to U.S. tax law following the passage and signing of H.R.1, An Act to Provide for Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018 (the “Tax Act”). The Tax Act permanently reduces the U.S. federal corporate tax rate from a maximum 35% to 21%, eliminated corporate Alternative Minimum Tax, modified rules for expensing capital investment, and limits the deduction of interest expense for certain companies. ASC 740 requires filers to record the effect of tax law changes in the period enacted. However, the SEC issued Staff Accounting Bulletin (“SAB”) 118 that permits filers to record provisional amounts during a measurement period ending no later than one year from the date of enactment. For the period ending December 31, 2018, the Company re-measured the applicable deferred tax assets based on the rates at which they are expected to reverse. The gross deferred tax assets and liabilities have been adjusted and a corresponding offset has been recorded to the full valuation allowance against the Company’s net deferred tax assets, which resulted in no net effect to its provision for income taxes and effective tax rate. No other provisional adjustments have been made as a result of the Act. Significant components of the Company’s deferred assets and liabilities at December 31, 2020 and 2019, respectively, are as follows: 2020 2019 Deferred Tax Assets (Liabilities): Statutory Depletion Carry Forward $ 361,444 $ 367,149 Net Operating Loss 7,361,230 6,489,891 Other 583,281 595,990 Share-Based Compensation 86,510 86,510 Capital Loss / AMT Credit Carry Forward 9,458 9,458 Charitable Contributions Carry Forward 3,396 3,890 Allowance for Doubtful Accounts 671,861 466,060 Oil and Gas Properties and Fixed Assets 4,860,069 5,404,787 Investment in RMX Joint Venture 342,569 (1,238,551 ) Section 481(a) Adjustments (107,432 ) (214,859 ) $ 14,172,386 $ 11,970,325 Valuation Allowance (14,172,386 ) (11,970,325 ) Net Deferred Tax Asset $ - $ - The Company recorded a full valuation allowance against the net deferred tax assets in 2016. At the end of 2017, management reviewed the reliability of the Company’s net deferred tax assets, and due to the Company’s continued cumulative losses in recent years, Royale and its management concluded it is not “more-likely-than-not” its deferred tax assets will be realized. As a result, the Company will continue to record a full valuation allowance against the deferred tax assets in 2019. The Company will assess the realizability of the deferred tax assets at least yearly and make appropriate updates as needed. Royale Energy, Inc. and its subsidiaries have available net operating loss carryforwards of $27.5 million generated in tax years ended before January 1, 2018, which if not utilized, begin to expire in the year 2027. Royale Energy, Inc. has no net operating loss carryforwards generated after December 31, 2017, which can be carried forward indefinitely. A reconciliation of Royale Energy’s provision for income taxes and the amount computed by applying the statutory income tax rates at December 31, 2020 and 2019, respectively, to pretax income is as follows: 2020 2019 Tax (benefit) computed at statutory rate of 21% at December 31, 2020 and 2019, respectively $ (1,708,463 ) $ (71,680 ) Increase (decrease) in taxes resulting from: Meals & Entertainment 740 1,583 PPP Loan Forgiveness (41,538 ) - Prior-year true-up for Books (126,541 ) 1,461,914 Deferred State Taxes, net of federal benefit (330,367 ) 214,161 Other non-deductible expenses 4,108 59,674 Change in valuation allowance 2,202,061 (1,665,652 ) Provision (benefit) - - The components of the Company’s tax provision are as follows: 2020 2019 Current tax provision (benefit) - federal $ - $ - Current tax provision (benefit) - state - - Deferred tax provision (benefit) - federal - - Deferred tax provision (benefit) - state - - Total provision (benefit) $ - $ - In January 2007, Royale 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, the Company 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 2013 through 2018 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, 2020 | |
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 Royale 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 Series B Convertible Preferred Stock of Royale. The Board of Directors of Royale Energy, 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 common 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 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, the Company has determined that the conversion or redemption of these shares are outside the sole control of the Company 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 2020 and 2019, 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, 2020, the Company issued 76,290 shares with a value of $762,900. During 2020 and 2019, no cash was used to pay dividends on Series B preferred shares. |
COMMON STOCK
COMMON STOCK | 12 Months Ended |
Dec. 31, 2020 | |
Stockholders' Equity Note [Abstract] | |
Stockholders' Equity Note Disclosure [Text Block] | NOTE 8 COMMON STOCK During the year 2020 and 2019, the Company issued shares of its Common Stock in lieu of cash payments for salaries, fees or incentives to various officers and board members, including our CEO. |
OPERATING LEASES
OPERATING LEASES | 12 Months Ended |
Dec. 31, 2020 | |
Disclosure Text Block [Abstract] | |
Leases of Lessee Disclosure [Text Block] | NOTE 9 OPERATING LEASES The Company has two office leases. One at 1870 Cordell Court, El Cajon, California, the location of its corporate offices and one at 104 W. Anapamu, Santa Barbara, California, the location of the Company’s CEO and engineering team. The corporate office lease was entered into on August 31, 2016 and expires on October 31, 2021, with initial monthly payments of $6,148 with escalations. The lease in Santa Barbara was initiated in December of 2006 and, through several extensions and renewals, will expire in March of 2022. The Company has 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 also currently expect to elect 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, 2020 2019 Operating lease expense 200,836 184,374 Financing lease expense 19,137 10,757 Operating - short-term - 7,886 Short Term - field 6,000 6,000 Total lease expense 225,973 209,017 The following tables summarized the operating and financing lease obligations. Lease Obligations Operating Lease Obligations Financing Lease Obligations Total Lease Obligations 2021 $ 179,630 12,588 192,218 2022 24,408 12,588 36,996 2023 - 12,588 12,588 Thereafter - 7,343 7,343 Total undiscounted lease payments $ 204,038 45,107 249,145 Less: Amount representing interest 13,679 4,409 18,088 Total Operating & Financing lease liabilities $ 190,359 40,698 231,057 Current lease liabilities as of December 31, 2020 $ 167,578 10,542 178,120 Long-term lease liabilities as of December 31, 2020 $ 22,781 30,156 52,937 |
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS | 12 Months Ended |
Dec. 31, 2020 | |
Related Party Transactions [Abstract] | |
Related Party Transactions Disclosure [Text Block] | NOTE 10 RELATED-PARTY TRANSACTIONS Significant Ownership Interests Our Chief Executive, Johnny Jordan, has accrued certain unpaid salaries, which were assumed by the Company. At December 31, 2020, Mr. Jordan was owed $14,648, in accrued unpaid guaranteed payments. Our Chief Financial Officer, Stephen Hosmer, has participated individually in 179 wells under the 1989 policy. During 2020 and 2019, Stephen did not participate in fractional interests. At December 31, 2020, the Company had a receivable balance of $17,101 due from Stephen Hosmer for normal drilling and lease operating expenses. Donald Hosmer has participated individually in 179 wells under the 1989 policy. During 2020 and 2019, Donald did not participate in fractional interests. At December 31, 2020, Royale had a receivable balance of $5,385 due from Donald Hosmer for normal drilling and lease operating expenses. At December 31, 2020 and 2019, we had a total payable of $23,087 and $32,367, respectively, due to RMX Resources, LLC and its subsidiary, Matrix Oil Corporation, related to certain lease operating expenses for wells operated by RMX Resources, LLC. For the same periods, the Company also had prepaid expenses and other current assets of $239,036 and $2,680,155, respectively. The prepaid amount where primarily for the drilling of wells. Royale had outstanding accrued unpaid guaranteed payments for unpaid salaries for periods predating their joining the Company due to certain former Matrix employees. At December 31, 2020, the balance due was $1,306,605. Michael McCaskey and Jeffery Kerns, each former directors of Royale, have consulting agreements to provide services as directed and at the discretion of the Company. Mr. Kerns wife is a director. |
STOCK COMPENSATION PLAN
STOCK COMPENSATION PLAN | 12 Months Ended |
Dec. 31, 2020 | |
Share-based Payment Arrangement [Abstract] | |
Share-based Payment Arrangement [Text Block] | NOTE 11 STOCK COMPENSATION PLAN There were no stock options issued during 2020 and 2019. |
SIMPLE IRA PLAN
SIMPLE IRA PLAN | 12 Months Ended |
Dec. 31, 2020 | |
Retirement Benefits [Abstract] | |
Retirement Benefits [Text Block] | NOTE 12 SIMPLE IRA PLAN In April 1998, the Company established a Simple IRA pension plan covering all employees. The Company 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, 2020 and 2019, were $41,921 and $30,336 respectively. |
ENVIRONMENTAL MATTERS
ENVIRONMENTAL MATTERS | 12 Months Ended |
Dec. 31, 2020 | |
Environmental Remediation Obligations [Abstract] | |
Environmental Loss Contingency Disclosure [Text Block] | NOTE 13 ENVIRONMENTAL MATTERS Royale Energy has established procedures for the continuing evaluation of its 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 its operational and accounting policies related to environmental issues. The nature of Royale Energy’s business requires routine day-to-day compliance with environmental laws and regulations. Royale Energy incurred no material environmental investigation, compliance and remediation costs in 2020 or 2019. Royale Energy is unable to predict whether its 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 the results of operations of Royale Energy. |
CONCENTRATIONS
CONCENTRATIONS | 12 Months Ended |
Dec. 31, 2020 | |
Risks and Uncertainties [Abstract] | |
Concentration Risk Disclosure [Text Block] | NOTE 14 CONCENTRATIONS The Company bids its gas sales on a month-to-month basis and generally sells to a single customer without commitment to future gas sales to any particular customer. The Company normally sells approximately 32% of its monthly 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. The Company maintains 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, 2020 and 2019. At December 31, 2020 and 2019, cash in banks exceeded the FDIC limits by approximately $1.9 million and $3.4 million, respectively. The Company has not experienced any losses on deposits. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended |
Dec. 31, 2020 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies Disclosure [Text Block] | NOTE 15 COMMITMENTS AND CONTINGENCIES The Company may become involved from time to time in litigation on various matters, which are routine to the conduct of its business. The Company believes that none of these actions, individually or in the aggregate, will have a material adverse effect on its 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 its business. The Company sponsors 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 Royale the full contract price upon execution of the agreement. Royale typically begins the drilling activities within 12 months of funding and reaches 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, 2020 | |
Debt Disclosure [Abstract] | |
Debt Disclosure [Text Block] | NOTE 16 CORONAVIRUS AID, RELIEF, AND ECONOMIC SECURITY ACT ( CARES ACT ) In December 2019, a novel strain of coronavirus (which triggers a respiratory disease called COVID-19) was reported in Wuhan, China. The World health Organization has declared the outbreak to constitute a “Public Health Emergency of International Concern.” The COVID-19 outbreak has caused a major reduction in the consumption of hydrocarbon-based transportation fuels as airlines have grounded flights worldwide and countries around the world have asked residents to suspend automobile travel. In addition to a substantial loss of demand for crude oil, In March, Saudi Arabia entered into a price war with Russia and added additional supplies of crude oil to an already over supplied market. The result has been a precipitous decline in the price of crude oil received by the Company. As a result, the Company has seen a reduction in its oil and gas revenues and resulting cash flows for the year 2020. The CARES Act provided tax benefits and potential loans/grants for businesses and non-profits. On April 13, 2020, the Company 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, Royale’s 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 will be repaid through monthly interest and principal payments of $560 beginning December 1, 2020, with the final payment of $614 scheduled for April 23, 2022. The loan is being amortized over 18 months at an annual interest rate of 1.00 percent with the last payment being a balloon payment to complete the loan repayment. On the Statement of Cash Flows, the Company has shown this PPP loan as a cash inflow from financing activities, principal repayments as cash outflows from financing activities, and interest payments as outflows from operating activities. The amounts of principal and interest forgiven are shown as reconciling items to net loss in determining net cash used in operating activities. Under the updated regulations, the forgiveness of PPP loan in 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. |
LONG-LIVED ASSETS HELD FOR SALE
LONG-LIVED ASSETS HELD FOR SALE | 12 Months Ended |
Dec. 31, 2020 | |
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 the Company has defined as long-lived assets held for sale in accordance with ASC 360-10-45. East Los Angeles The Company and its joint venture partner, RMX, have entered into a purchase and sales agreement as well as a second amendment to that certain purchase and sales agreement extending the closing date to the second quarter of 2021. The Company carries these assets on the books for $1.9 million with an ARO amount of approximately $1.1 million for the existing wells and facilities located on the properties providing a net book value of approximately $0.846 million. The sale would require the Company to plug and abandon the wells on the property and remove and restore the surface land with an estimated cost of $0.721 million. The sale price is approximately $1.0 million to the Company. Therefore, the Company will record a loss on the pending sale of these properties of $0.567 million and reflect Assets Held for Sale of $1.0 million reflected in current assets with an ARO balance of $0.721 million in current liabilities. Texas Properties The Company and its partners in these producing properties have exchanged document drafts of a purchase and sales agreement during 2021. The Company has a net book value for the properties of $0.381 million including an ARO liability of $0.149 million and expects to receive approximately $0.700 million at the consummation of the sale. Negotiations are ongoing with the sale expected to close during the second quarter of 2021. The Company is reflecting these properties at $0.529 million in Assets Held for Sale in current assets. |
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS | 12 Months Ended |
Dec. 31, 2020 | |
Subsequent Events [Abstract] | |
Subsequent Events [Text Block] | NOTE 18 SUBSEQUENT EVENTS The Company has evaluated subsequent events through March 30, 2021, the date these financial statements were available to be issued. The Company is not aware of any subsequent events which would require recognition or disclosure in the financial statements, except as noted below or already recognized or disclosed. Texas Properties The Purchase and Sales Agreement for the Texas properties was executed between all the parties on February 18, 2021, with closing anticipated in the 2nd quarter of 2021. |
SUPPLEMENTAL INFORMATION ABOUT
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) | 12 Months Ended |
Dec. 31, 2020 | |
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 interests owned by Royale Energy 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 its proved developed and undeveloped reserves was approximately $20.8 million at December 31, 2020, based on the average Henry Hub natural gas price spot price of $1.985 per MCF and for oil volumes, the average West Texas Intermediate price of $39.54 per barrel as applied on a field-by-field basis. Netherland, Sewell & Associates, Inc. provided reserve value information for the Company’s 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 Royale’s 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 Management’s assessment of future profitability or future cash flows to Royale Energy. 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, 2020 and 2019, and changes in such quantities during each of the years then ended, were as follows: Total Proved Reserves 2020 2019 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Beginning of period 2,171,000 4,306,900 1,146,400 2,986,200 Revisions of previous estimates (646,080 ) (1,515,637 ) 1,052,086 (890,032 ) Production (31,210 ) (160,406 ) (27,663 ) (292,472 ) Extensions, discoveries and improved recovery 47,290 29,643 22,042 2,516,046 Merger Acquisition - - Purchase of minerals in place - - Sales of minerals in place (21,865 ) (12,842 ) Proved reserves end of period 1,541,000 2,660,500 2,171,000 4,306,900 Proved Developed 2020 2019 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed reserves: Beginning of period 232,200 2,790,300 148,600 1,914,900 End of period 224,900 691,900 232,200 2,790,300 Proved Undeveloped 2020 2019 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved undeveloped reserves: Beginning of period 1,938,800 1,516,600 997,800 1,071,300 End of period 1,316,100 1,968,600 1,938,800 1,516,600 At December 31, 2020, our previously estimated proved developed and undeveloped natural gas reserve quantities were revised downward by approximately 1,515,637 MCF of natural gas. This downward revision was mainly the result of a decrease in proved developed natural gas reserves from drilling locations which the Company had contracted. At December 31, 2020, our previously estimated proved developed and undeveloped oil reserve quantities were revised downward by approximately 646,080 BBL of oil. This downward revision was mainly the result a decrease in the price of oil, which resulted in a decrease in the economic life. 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: 2021 8,954,000 2022 6,750,000 2023 1,404,500 Thereafter - 17,108,500 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, 2020 and 2019. 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. 2020 2019 Future cash inflows 65,939,300 143,045,000 Future production costs (28,008,100 ) (28,967,400 ) Future development costs (17,108,400 ) (20,587,800 ) Future income tax expense (6,246,840 ) (28,046,940 ) Future net cash flows 14,575,960 65,442,860 10% annual discount for estimated timing of cash flows (7,134,925 ) (35,801,989 ) Standardized measure of discounted future net cash flows 7,441,035 29,640,871 Sales of oil and gas produced, net of production costs (351,478 ) (624,744 ) Revisions of previous quantity estimates (31,231,533 ) 14,035,099 Net changes in prices and production costs (617,847 ) (14,331,770 ) Sales of minerals in place - (272,507 ) Purchases of minerals in place - Merger Acquisition - Extensions, discoveries and improved recovery 587,311 2,157,052 Accretion of discount (100,504 ) 2,900,123 Net change in income tax 9,514,215 (4,868,296 ) Net increase (decrease) (22,199,836 ) (1,005,043 ) 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 years 2021 through 2023. 2021 2022 2023 Future development cost of: Proved developed reserves (PDP) - - - Proved non-producing reserves (PDNP) 54,000 - - Proved undeveloped reserves (PUD) 8,900,000 6,750,000 1,404,500 Total 8,954,000 6,750,000 1,404,500 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 Royale Energy’s oil and natural gas properties is disclosed in Supplemental Information About Oil and Gas Producing Activities (Unaudited), attached to Royale Energy’s Financial Statements, beginning on page F-1. 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, 2020 | |
Accounting Policies [Abstract] | |
Basis of Accounting, Policy [Policy Text Block] | Description of Business Royale Energy is an independent oil and gas producer which also has operations in the area of turnkey drilling. Royale Energy owns wells and leases in major geological basins located primarily in California, Texas, Oklahoma, Colorado, and Utah. Royale Energy offers fractional working interests and seeks 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 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 17 – Supplemental Information About Oil and Gas Producing Activities (Unaudited) 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, 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 the Company’s 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. At December 31, 2020, the Company has $1.529 million in Long Lived Assets Held for Sale. The Company’s 2020 consolidated financial statements reflect a working capital deficiency of $4,044,437 and a net loss from operations of $2,674,329. 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 the Company is unable to continue as a going concern. Management’s plans to alleviate the going concern by cost control measures that include the reduction of overhead costs and 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 the Company and whether the Company will become profitable and generate positive operating cash flow. If the Company is unable to raise sufficient additional funds, it will have to develop and implement a plan to further extend payables, attempt to extend note repayments, 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. |
Reclassification, Comparability Adjustment [Policy Text Block] | Correction of Immaterial Errors in Previously Issued Financial Statements Subsequent to the issuance of the consolidated financial statements for the year ended December 31, 2019, the Company concluded that the Statement of Cash Flows for the year ending December 31, 2019, contained immaterial errors related to the classification of payments arising from operating leases and to the quantification of the amount of capital expenditures that had been accrued for but not yet paid. These immaterial errors have been corrected for the comparative period, resulting in an increase in cash flows used in operating activities of $239,362; an increase in cash flows provided by investing activities of $94,546; and a decrease in cash flows used in financing activities of $144,816 for the period ending December 31, 2019. These immaterial errors did not have any impact on our financial position, net loss or total cash flow for the period ending December 31, 2019. |
Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block] | Restricted Cash Royale sponsors turnkey drilling arrangements in proved and unproved properties. The contracts require that participants pay Royale 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, the Company 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. Royale classifies 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 statement of financial position that sum to the total of the same amounts shown in the statement of cash flows. Year Ended December 31, 2020 2019 Cash and cash equivalents $ 255,112 $ 1,031,014 Restricted cash 2,146,571 2,845,515 Total cash, cash equivalents, and restricted cash shown in the statement of cash flows 2,401,683 3,876,529 |
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 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, 2020 and 2019, the Company established an allowance for uncollectable accounts of $2,582,093 and $1,791,162, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue. During 2020 and 2019, the Company closed a number of accounts as uncollectable, offsetting the allowance in the amount of $2,553 and $519,333 respectively. |
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, Royale has not had issues related to the collection of revenue receivables, and as such has 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 sheet. 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. The earnings from RMX reflected in these financial statements as Investment in JV, reflect our share of net earnings or losses directly attributable to this equity method investment. We evaluated our investment in RMX as of December 31, 2019, and determined that any losses were not other than temporary. At December 31, 2020, we evaluated our investment in RMX and determined that our investment was impaired as further described in Note 2 – RMX Joint Venture |
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. Year Ended December 31, 2020 2019 Oil & Condensate Sales $ 1,184,680 $ 1,504,936 Natural Gas Sales 357,587 824,339 NGL Sales 536 - $ 1,542,803 $ 2,329,275 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 sheet. Under our hydrocarbon sales agreements, the entire consideration amount is variable either due to pricing and/or volumes. We recognize revenue 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. The Company frequently sells a portion of the working interest in each well it drills or participates in to third-party investors and retains a portion of the prospect for its own account. The Company typically guarantees a cost to drill to the third-party drilling participants and records 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, the Company records 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, as defined in the new revenue standard, 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 is netted directly against revenue. 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 These Turnkey Agreements are managed by the Company for the participants of the well. The collections of pre-drilling AFE amounts are segregated by the Company 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. The Company manages the performance obligation for the well participants and only records revenue or expense at the time the performance obligation of the Turnkey Agreement has been satisfied. Supervisory Fees and Other These amounts include proceeds from the Master Service Agreement (“MSA”) with RMX for the providing of land, engineering, accounting and support services for the RMX joint venture. Revenues earned under the MSA were recorded at the end of each month that services were performed, in conformity with the Agreement. The service fee income was deemed earned at the end of each month that services were performed as prescribed by the contract. On December 31, 2018, Royale received notice of cancelation of the MSA by RMX effective March 31, 2019. For the year ended 2019, the Company recognized $540,000 in supervisory fees from RMX. Also included in the caption are Pipeline and Compressor fees which are received and allocated based on production volumes. |
Oil and Gas Properties Policy [Policy Text Block] | Oil and Gas Property and Equipment Successful Efforts Royale Energy uses the “successful efforts” method to account for its exploration and production activities. Under this method, Royale Energy accumulates its proportionate share of costs on a well-by-well basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred, and capitalizes expenditures for productive wells. Royale Energy amortizes the costs of productive wells under the unit-of-production method. Royale Energy carries, 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 Royale Energy is 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 Royale Energy’s 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 income. During 2020 there were no impairment losses, while 2019 the Company recorded impairment losses of $977,682, on various capitalized base and land costs as well as certain fields acquired through the merger with the matrix entities. Upon the sale or retirement of a complete field of a proved property, Royale Energy eliminates the cost from its books, and the resultant gain or loss is recorded to Royale Energy’s Statement 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 Royale Energy’s Statement 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 Royale Energy’s turnkey drilling agreements include unproved property, total drilling costs incurred to satisfy its 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 Royale classifies 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 the Company retains the responsibility for the P&A, equipment removal or site restoration, the associated anticipated expense is carried as current ARO. The Company has two property groups that are being Held for Sale as further described in Note 17 – Long-Lived Assets Held for Sale |
Industry Specific Policies, Oil and Gas [Policy Text Block] | Turnkey Drilling Royale Energy sponsors 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 its obligations are incurred with any excess booked against its property account to reduce any basis in its own interest. Gains on Turnkey Drilling Programs represent funds received from turnkey drilling participants in excess of all costs Royale incurs during the drilling programs (e.g., lease acquisition, exploration and development costs), including costs incurred on behalf of participants and costs incurred for its own account; and are recognized only upon making this determination after Royale’s obligations have been fulfilled. The contracts require the participants pay Royale Energy the full contract price upon execution of the agreement. Royale Energy completes 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 its proportionate share of operating costs. Royale Energy retains 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. The Company holds 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, 2020 and 2019, Royale Energy had Deferred Drilling Obligations of $ 3,127,500 and $5,232,675, respectively. If Royale Energy is unable to drill the wells, and a suitable replacement well is not found, Royale would retain the non-refundable portion of the contact and return the remaining funds to the participant. Included in cash and cash equivalents 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. Gains or losses on dispositions of property and equipment, other than oil and gas, are reflected in operations. |
Earnings Per Share, Policy [Policy Text Block] | Income (Loss) Per Share Basic and diluted losses per share are calculated as follows: Year Ended December 31, 2020 2019 Basic Diluted Basic Diluted Net Loss $ (8,148,147 ) $ (8,148,147 ) $ (348,383 ) $ (348,383 ) Less: Preferred Stock Dividend 762,900 762,900 734,725 734,725 Less: Preferred Stock Dividend in Arrears - - - - Net Loss Attributable to Common Shareholders (8,911,047 ) (8,911,047 ) (1,083,108 ) (1,083,108 ) Weighted average common shares outstanding 53,292,647 53,292,647 50,871,447 50,871,447 Effect of dilutive securities - - - - Weighted average common shares, including Dilutive effect 53,292,647 53,292,647 50,871,447 50,871,447 Per share: Net Loss $ (0.17 ) $ (0.17 ) $ (0.02 ) $ (0.02 ) For the years ended December 31, 2020 and 2019, Royale Energy had dilutive securities of 25,137,267 and 23,947,519 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 Royale has a stock-based employee compensation plan, which is more fully described in Note 11 – Stock Compensation Plan. The Company has 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 Royale utilizes 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 period subsequent to initial recognition, the reporting entity shall disclose information that enable users of its 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, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible as well as considers counterparty credit risk in its assessment of fair value. Carrying amounts of the Company’s 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, 2020 and 2019, Royale Energy does not have any financial assets measured and recognized at fair value on a recurring basis. The Company estimates 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, 2020 and 2019, the components of accounts payable and accrued expenses consisted of: 2020 2019 Trade Payables including accruals 2,264,562 3,107,012 Direct working interest investors related accruals 1,277,428 1,811,649 Current drilling efforts accrued expenses 20,924 508,246 Accrued Liabilities 391,434 393,245 Employee related accruals 196,014 195,998 Deferred rent 10,747 14,884 Federal and State income taxes payable - - 4,161,109 6,031,034 |
Accrued Liabilitites Policy [Policy Text Block] | Accrued – Non-current At December 31, 2020, the Company had non-current accrued liabilities of $1,306,605 and accrued unpaid guaranteed payment of $1,616,205, due to certain Matrix principals, from periods prior to the merger with the Matrix entities during March of |
Business Combinations Policy [Policy Text Block] | Business Combinations From time-to-time, the Company acquires businesses in the oil and gas industry. Royale primarily targets businesses in geological basins that the Company considers 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 2017-04, Simplifying the test for goodwill impairment In January 2017, FASB issued Accounting Standards Update (ASU) 2017-04, Intangibles—Goodwill and Other (Topic 350), Simplifying the Test for Goodwill Impairment, which eliminated the calculation of implied goodwill fair value. This guidance simplifies the accounting as compared to prior Generally Accepted Accounting Principles “GAAP.” This ASU was effective for SEC filers beginning after December 15, 2019. Adoption of this standard did not have a material impact on our consolidated financial statements. ASU 2018-13, Changes to the fair value disclosure requirements In August 2018, FASB issued ASU 2018-13, Fair Value Measurement (Topic 820), Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement. This pronouncement modifies, eliminates and adds disclosure requirements for fair value measurements. This ASU was effective for SEC filers beginning after December 15, 2019. Adoption of this standard did not have a material impact on our consolidated financial statements. 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. The Company 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 currently taking place in the financial markets will not have any impact on the Company or its existing financial instruments or agreements. ASU 2018-18, Clarifying the interaction between ASC 808 and ASC 606 In November 2018, FASB issued ASU 2018-18, Collaborative Arrangements (Topic 808). This pronouncement clarifies that certain transactions between collaborative partners should be accounted for as revenue under Topic 606 (Revenue Recognition) when one is a customer of the other. Adoption of this standard did not have a material impact on our consolidated financial statements. Not Adopted 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) such as Royale, 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, 2020 | |
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 statement of financial position that sum to the total of the same amounts shown in the statement of cash flows. Year Ended December 31, 2020 2019 Cash and cash equivalents $ 255,112 $ 1,031,014 Restricted cash 2,146,571 2,845,515 Total cash, cash equivalents, and restricted cash shown in the statement of cash flows 2,401,683 3,876,529 |
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. Year Ended December 31, 2020 2019 Oil & Condensate Sales $ 1,184,680 $ 1,504,936 Natural Gas Sales 357,587 824,339 NGL Sales 536 - $ 1,542,803 $ 2,329,275 |
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, 2020 2019 Basic Diluted Basic Diluted Net Loss $ (8,148,147 ) $ (8,148,147 ) $ (348,383 ) $ (348,383 ) Less: Preferred Stock Dividend 762,900 762,900 734,725 734,725 Less: Preferred Stock Dividend in Arrears - - - - Net Loss Attributable to Common Shareholders (8,911,047 ) (8,911,047 ) (1,083,108 ) (1,083,108 ) Weighted average common shares outstanding 53,292,647 53,292,647 50,871,447 50,871,447 Effect of dilutive securities - - - - Weighted average common shares, including Dilutive effect 53,292,647 53,292,647 50,871,447 50,871,447 Per share: Net Loss $ (0.17 ) $ (0.17 ) $ (0.02 ) $ (0.02 ) |
Schedule of Accounts Payable and Accrued Liabilities [Table Text Block] | At December 31, 2020 and 2019, the components of accounts payable and accrued expenses consisted of: 2020 2019 Trade Payables including accruals 2,264,562 3,107,012 Direct working interest investors related accruals 1,277,428 1,811,649 Current drilling efforts accrued expenses 20,924 508,246 Accrued Liabilities 391,434 393,245 Employee related accruals 196,014 195,998 Deferred rent 10,747 14,884 Federal and State income taxes payable - - 4,161,109 6,031,034 |
RMX JOINT VENTURE (Tables)
RMX JOINT VENTURE (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Business Combinations [Abstract] | |
Equity Method Investments [Table Text Block] | Listed below is summarized information the Company’s investment in RMX: Twelve Months Ended December 31, 2020 Twelve Months Ended December 31, 2019 RMX Resources, LLC RMX Resources, LLC Balance Sheet: Total Assets $ 77,168,147 $ 72,401,841 Total Liabilities $ 46,213,651 $ 41,573,426 Members Equity $ 30,954,496 $ 30,828,415 Results of Operations: Net operating revenue $ 9,376,395 $ 16,392,305 Income (Loss) from operations $ (3,352,584 ) $ 1,456,290 Net income $ 126,081 $ (2,091,239 ) |
OIL AND GAS PROPERTIES, EQUIP_2
OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
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, 2020 2019 Oil and Gas Producing properties, including intangible drilling costs $ 5,672,457 $ 7,792,156 Undeveloped properties 13,993 46,990 Lease and well equipment 3,317,718 3,304,565 $ 9,004,168 $ 11,143,711 Accumulated depletion, depreciation and amortization (6,467,626 ) (6,559,182 ) Net capitalized costs Total 2,536,542 4,584,529 Commercial and Other 2020 2019 Real estate, including furniture and fixtures $ - $ - Vehicles 40,061 40,061 Furniture and equipment 1,097,428 1,097,428 1,137,489 1,137,489 Accumulated depreciation (1,133,030 ) (1,131,028 ) 4,459 6,461 Net capitalized costs Total $ 2,541,001 $ 4,590,990 |
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, 2020 2019 Acquisition - Proved - - Acquisition - Unproved - - Development 5,306,639 9,680,298 Exploration - - |
Capitalized Exploratory Well Costs, Roll Forward [Table Text Block] | Undeveloped properties are not subject to depletion, depreciation or amortization. Year Ended December 31, 2020 2019 Beginning balance at January 1 - - Additions to capitalized exploratory well costs pending the determination of proved reserves - - Reclassifications to wells, facilities, and equipment based on the determination of proved reserves - - Ending balance at December 31 - - |
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, 2020 2019 Oil and gas sales $ 1,542,803 $ 2,329,275 Production-related costs (Lease Operating) (1,397,673 ) (1,764,538 ) Impairment - (977,682 ) Depreciation, depletion and amortization (473,647 ) (468,143 ) Results of operations from producing and exploration activities $ (328,517 ) $ (881,088 ) Income Taxes (Benefit) - - Net Results $ (328,517 ) $ (881,088 ) |
ASSET RETIREMENT OBLIGATION (Ta
ASSET RETIREMENT OBLIGATION (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
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 the Company’s 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 year ended December 31, 2020. During the year ended December 31, 2019, the Company recorded $922,698 in increased costs related to estimates for abandonment of its’ share of certain California oil properties. These estimates relate to properties likely to be abandoned in the current period. As a result, the Company recorded them as impairment expense at year end 2019. 2020 2019 Asset retirement obligation Beginning of the year $ 3,632,422 $ 2,366,456 Liabilities incurred during the period 29,323 210,643 Settlements (508,538 ) - Merger Additions - - Sales - (33,026 ) Changes in estimates - 922,698 Accretion expense 194,290 165,651 Reclassification to ARO - current (869,147 ) - End of year $ 2,478,350 $ 3,632,422 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Income Tax Disclosure [Abstract] | |
Schedule of Deferred Tax Assets and Liabilities [Table Text Block] | Significant components of the Company’s deferred assets and liabilities at December 31, 2020 and 2019, respectively, are as follows: 2020 2019 Deferred Tax Assets (Liabilities): Statutory Depletion Carry Forward $ 361,444 $ 367,149 Net Operating Loss 7,361,230 6,489,891 Other 583,281 595,990 Share-Based Compensation 86,510 86,510 Capital Loss / AMT Credit Carry Forward 9,458 9,458 Charitable Contributions Carry Forward 3,396 3,890 Allowance for Doubtful Accounts 671,861 466,060 Oil and Gas Properties and Fixed Assets 4,860,069 5,404,787 Investment in RMX Joint Venture 342,569 (1,238,551 ) Section 481(a) Adjustments (107,432 ) (214,859 ) $ 14,172,386 $ 11,970,325 Valuation Allowance (14,172,386 ) (11,970,325 ) Net Deferred Tax Asset $ - $ - |
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | A reconciliation of Royale Energy’s provision for income taxes and the amount computed by applying the statutory income tax rates at December 31, 2020 and 2019, respectively, to pretax income is as follows: 2020 2019 Tax (benefit) computed at statutory rate of 21% at December 31, 2020 and 2019, respectively $ (1,708,463 ) $ (71,680 ) Increase (decrease) in taxes resulting from: Meals & Entertainment 740 1,583 PPP Loan Forgiveness (41,538 ) - Prior-year true-up for Books (126,541 ) 1,461,914 Deferred State Taxes, net of federal benefit (330,367 ) 214,161 Other non-deductible expenses 4,108 59,674 Change in valuation allowance 2,202,061 (1,665,652 ) Provision (benefit) - - |
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block] | The components of the Company’s tax provision are as follows: 2020 2019 Current tax provision (benefit) - federal $ - $ - Current tax provision (benefit) - state - - Deferred tax provision (benefit) - federal - - Deferred tax provision (benefit) - state - - Total provision (benefit) $ - $ - |
OPERATING LEASES (Tables)
OPERATING LEASES (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
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, 2020 2019 Operating lease expense 200,836 184,374 Financing lease expense 19,137 10,757 Operating - short-term - 7,886 Short Term - field 6,000 6,000 Total lease expense 225,973 209,017 |
Lessee, Operating Lease, Liability, 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 2021 $ 179,630 12,588 192,218 2022 24,408 12,588 36,996 2023 - 12,588 12,588 Thereafter - 7,343 7,343 Total undiscounted lease payments $ 204,038 45,107 249,145 Less: Amount representing interest 13,679 4,409 18,088 Total Operating & Financing lease liabilities $ 190,359 40,698 231,057 Current lease liabilities as of December 31, 2020 $ 167,578 10,542 178,120 Long-term lease liabilities as of December 31, 2020 $ 22,781 30,156 52,937 |
SUPPLEMENTAL INFORMATION ABOU_2
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
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, 2020 and 2019, and changes in such quantities during each of the years then ended, were as follows: Total Proved Reserves 2020 2019 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Beginning of period 2,171,000 4,306,900 1,146,400 2,986,200 Revisions of previous estimates (646,080 ) (1,515,637 ) 1,052,086 (890,032 ) Production (31,210 ) (160,406 ) (27,663 ) (292,472 ) Extensions, discoveries and improved recovery 47,290 29,643 22,042 2,516,046 Merger Acquisition - - Purchase of minerals in place - - Sales of minerals in place (21,865 ) (12,842 ) Proved reserves end of period 1,541,000 2,660,500 2,171,000 4,306,900 Proved Developed 2020 2019 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed reserves: Beginning of period 232,200 2,790,300 148,600 1,914,900 End of period 224,900 691,900 232,200 2,790,300 Proved Undeveloped 2020 2019 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved undeveloped reserves: Beginning of period 1,938,800 1,516,600 997,800 1,071,300 End of period 1,316,100 1,968,600 1,938,800 1,516,600 |
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, 2020 2019 Acquisition - Proved - - Acquisition - Unproved - - Development 5,306,639 9,680,298 Exploration - - |
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block] | 2020 2019 Future cash inflows 65,939,300 143,045,000 Future production costs (28,008,100 ) (28,967,400 ) Future development costs (17,108,400 ) (20,587,800 ) Future income tax expense (6,246,840 ) (28,046,940 ) Future net cash flows 14,575,960 65,442,860 10% annual discount for estimated timing of cash flows (7,134,925 ) (35,801,989 ) Standardized measure of discounted future net cash flows 7,441,035 29,640,871 Sales of oil and gas produced, net of production costs (351,478 ) (624,744 ) Revisions of previous quantity estimates (31,231,533 ) 14,035,099 Net changes in prices and production costs (617,847 ) (14,331,770 ) Sales of minerals in place - (272,507 ) Purchases of minerals in place - Merger Acquisition - Extensions, discoveries and improved recovery 587,311 2,157,052 Accretion of discount (100,504 ) 2,900,123 Net change in income tax 9,514,215 (4,868,296 ) Net increase (decrease) (22,199,836 ) (1,005,043 ) |
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: 2021 8,954,000 2022 6,750,000 2023 1,404,500 Thereafter - 17,108,500 |
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 years 2021 through 2023. 2021 2022 2023 Future development cost of: Proved developed reserves (PDP) - - - Proved non-producing reserves (PDNP) 54,000 - - Proved undeveloped reserves (PUD) 8,900,000 6,750,000 1,404,500 Total 8,954,000 6,750,000 1,404,500 |
SUMMARY OF SIGNIFICANT ACCOUN_3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items] | ||
Assets Held-for-sale, Long Lived, Fair Value Disclosure | $ 1,529,000 | |
Working Capital (Deficit) | (4,044,437) | |
Operating Income (Loss) | (2,674,329) | $ (845,071) |
Immaterial Error Correction | These immaterial errors have been corrected for the comparative period, resulting in an increase in cash flows used in operating activities of $239,362; an increase in cash flows provided by investing activities of $94,546; and a decrease in cash flows used in financing activities of $144,816 for the period ending December 31, 2019. | |
Accounts Receivable, Allowance for Credit Loss | 2,582,093 | $ 1,791,162 |
Accounts Receivable, Allowance for Credit Loss, Writeoff | 2,553 | 519,333 |
Revenues | 1,587,855 | 2,967,183 |
Impairment of Oil and Gas Properties | 977,682 | |
Contract with Customer, Liability, Current | $ 3,127,500 | $ 5,232,675 |
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount (in Shares) | 25,137,267 | 23,947,519 |
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 | $ 540,000 | |
Minimum [Member] | ||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items] | ||
Property, Plant and Equipment, Estimated Useful Lives | three | |
Maximum [Member] | ||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items] | ||
Property, Plant and Equipment, Estimated Useful Lives | seven |
SUMMARY OF SIGNIFICANT ACCOUN_4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - Schedule of Cash and Cash Equivalents - USD ($) | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Schedule of Cash and Cash Equivalents [Abstract] | |||
Cash and cash equivalents | $ 255,112 | $ 1,031,014 | |
Restricted cash | 2,146,571 | 2,845,515 | |
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows | $ 2,401,683 | $ 3,876,529 | $ 6,355,042 |
SUMMARY OF SIGNIFICANT ACCOUN_5
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - Disaggregation of Revenue - USD ($) | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Oil [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenues | $ 1,184,680 | $ 1,504,936 |
Natural Gas [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenues | 357,587 | 824,339 |
Natural Gas Liquids [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenues | 536 | 0 |
Natural Gas Liquids [Member] | Oil and Gas [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenues | $ 1,542,803 | $ 2,329,275 |
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, 2020 | Dec. 31, 2019 | |
Schedule of Earnings Per Share, Basic and Diluted [Abstract] | ||
Net Loss | $ (8,148,147) | $ (348,383) |
Less: Preferred Stock Dividend | 762,900 | 734,725 |
Less: Preferred Stock Dividend in Arrears | 0 | 0 |
Less: Preferred Stock Dividend in Arrears | 0 | 0 |
Net Loss Attributable to Common Shareholders | $ (8,911,047) | $ (1,083,108) |
Weighted average common shares outstanding (in Shares) | 53,292,647 | 50,871,447 |
Weighted average common shares outstanding (in Shares) | 53,292,647 | 50,871,447 |
Effect of dilutive securities | $ 0 | $ 0 |
Effect of dilutive securities (in Shares) | 0 | 0 |
Weighted average common shares, including Dilutive effect (in Shares) | 53,292,647 | 50,871,447 |
Weighted average common shares, including Dilutive effect (in Shares) | 53,292,647 | 50,871,447 |
Net Loss (in Dollars per share) | $ (0.17) | $ (0.02) |
Net Loss (in Dollars per share) | $ (0.17) | $ (0.02) |
SUMMARY OF SIGNIFICANT ACCOUN_7
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - Schedule of Accounts Payable and Accrued Liabilities - USD ($) | Dec. 31, 2020 | Dec. 31, 2019 |
Schedule of Accounts Payable and Accrued Liabilities [Abstract] | ||
Trade Payables including accruals | $ 2,264,562 | $ 3,107,012 |
Direct working interest investors related accruals | 1,277,428 | 1,811,649 |
Current drilling efforts accrued expenses | 20,924 | 508,246 |
Accrued Liabilities | 391,434 | 393,245 |
Employee related taxes and accruals | 196,014 | 195,998 |
Deferred rent | 10,747 | 14,884 |
Federal and State income taxes payable | 0 | 0 |
$ 4,161,109 | $ 6,031,034 |
RMX JOINT VENTURE (Details)
RMX JOINT VENTURE (Details) | Apr. 30, 2018USD ($)shares | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Mar. 11, 2019USD ($)Boe |
RMX JOINT VENTURE (Details) [Line Items] | |||||
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves | $ 7,441,035 | $ 29,640,871 | |||
Gain (Loss) on Disposition of Assets | 6,920 | (155,048) | |||
Gain (Loss) on Extinguishment of Debt | 1,254,204 | ||||
Equity Method Investment, Other than Temporary Impairment | $ 6,185,995 | ||||
Bellevue Field [Member] | |||||
RMX JOINT VENTURE (Details) [Line Items] | |||||
Proved Developed Reserves (Energy) (in Barrels of Oil Equivalent) | Boe | 5.145 | ||||
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves | $ 67,671 | ||||
Whittier Field [Member] | |||||
RMX JOINT VENTURE (Details) [Line Items] | |||||
Proved Developed Reserves (Energy) (in Barrels of Oil Equivalent) | Boe | 140.647 | ||||
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves | $ 2,400,000 | ||||
RMX Resources, LLC [Member] | |||||
RMX JOINT VENTURE (Details) [Line Items] | |||||
Equity Method Investment, Ownership Percentage | 20.00% | ||||
Supervisory Fees, Service Agreements, and Other | $ 180,000 | ||||
Gain (Loss) on Disposition of Assets | $ 1,237,126 | ||||
RMX Resources, LLC [Member] | Maximum [Member] | |||||
RMX JOINT VENTURE (Details) [Line Items] | |||||
Cash Acquired from Acquisition | $ 20,000,000 | ||||
CIC RMX LP [Member] | RMX Resources, LLC [Member] | |||||
RMX JOINT VENTURE (Details) [Line Items] | |||||
Equity Method Investment, Ownership Percentage | 80.00% | ||||
Payments to Acquire Businesses, Gross | $ 25,000,000 | ||||
Class Of Warrant or Rights Granted (in Shares) | shares | 4,000,000 |
RMX JOINT VENTURE (Details) - E
RMX JOINT VENTURE (Details) - Equity Method Investments - USD ($) | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Schedule of Equity Method Investments [Line Items] | ||
Total Assets | $ 8,424,626 | $ 20,590,627 |
Total Liabilities | 14,569,089 | 18,923,630 |
Net Operating Revenue | 1,587,855 | 2,967,183 |
Net Loss | (8,148,147) | (348,383) |
RMX Resources, LLC [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Total Assets | 77,168,147 | |
Total Liabilities | 46,213,651 | |
Members Equity | 30,954,496 | |
Net Operating Revenue | 9,376,395 | |
Loss from Continuing Operations | (3,352,584) | |
Net Loss | $ 126,081 | |
RMX Resources, LLC [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Total Assets | 72,401,841 | |
Total Liabilities | 41,573,426 | |
Members Equity | 30,828,415 | |
Net Operating Revenue | 16,392,305 | |
Loss from Continuing Operations | 1,456,290 | |
Net Loss | $ (2,091,239) |
OIL AND GAS PROPERTIES, EQUIP_3
OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Details) - Schedule of Property, Plant and Equipment - USD ($) | Dec. 31, 2020 | Dec. 31, 2019 |
Oil and Gas | ||
Producing properties, including intangible drilling costs | $ 5,672,457 | $ 7,792,156 |
Undeveloped properties | 13,993 | 46,990 |
Lease and well equipment | 3,317,718 | 3,304,565 |
Oil and gas, gross | 9,004,168 | 11,143,711 |
Accumulated depletion, depreciation and amortization | (6,467,626) | (6,559,182) |
Oil and gas, net | 2,536,542 | 4,584,529 |
Property, Plant and Equipment, Gross | 1,137,489 | 1,137,489 |
Accumulated depreciation | (1,133,030) | (1,131,028) |
Property, Plant and Equipment, Net | 4,459 | 6,461 |
Oil and gas properties, equipment and fixtures | 2,541,001 | 4,590,990 |
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, 2020 | Dec. 31, 2019 | |
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Abstract] | ||
Acquisition - Proved | $ 0 | $ 0 |
Acquisition - Unproved | 0 | 0 |
Development | 5,306,639 | 9,680,298 |
Exploration | $ 0 | $ 0 |
OIL AND GAS PROPERTIES, EQUIP_5
OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Details) - Capitalized Exploratory Well Costs, Roll Forward - USD ($) | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Capitalized Exploratory Well Costs, Roll Forward [Abstract] | ||
Beginning balance at January 1 | $ 0 | $ 0 |
Additions to capitalized exploratory well costs pending the determination of proved reserves | 0 | 0 |
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves | 0 | 0 |
Ending balance at December 31 | $ 0 | $ 0 |
OIL AND GAS PROPERTIES, EQUIP_6
OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Details) - Results of Operations for Oil and Gas Producing Activities Disclosure - USD ($) | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Results of Operations for Oil and Gas Producing Activities Disclosure [Abstract] | ||
Oil and gas sales | $ 1,542,803 | $ 2,329,275 |
Production-related costs (Lease Operating) | (1,397,673) | (1,764,538) |
Impairment | 0 | (977,682) |
Depreciation, depletion and amortization | (473,647) | (468,143) |
Results of operations from producing and exploration activities | (328,517) | (881,088) |
Income Taxes (Benefit) | 0 | 0 |
Net Results | $ (328,517) | $ (881,088) |
ASSET RETIREMENT OBLIGATION (De
ASSET RETIREMENT OBLIGATION (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Asset Retirement Obligation Disclosure [Abstract] | ||
Asset Retirement Obligation, Revision of Estimate | $ 0 | $ 922,698 |
ASSET RETIREMENT OBLIGATION (D
ASSET RETIREMENT OBLIGATION (Details) - Schedule of Change in Asset Retirement Obligation - USD ($) | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Asset retirement obligation | ||
Beginning of the year | $ 3,632,422 | $ 2,366,456 |
Liabilities incurred | 29,323 | 210,643 |
Sales | 0 | (33,026) |
Changes in estimates | 0 | 922,698 |
Accretion expense | 194,290 | 165,651 |
Reclassification to ARO - current | (869,147) | 0 |
End of year | 2,478,350 | 3,632,422 |
Settlements | (508,538) | 0 |
RMX Resources, LLC [Member] | ||
Asset retirement obligation | ||
Liabilities incurred | $ 0 | $ 0 |
NOTES PAYABLE (Details)
NOTES PAYABLE (Details) - USD ($) | Nov. 10, 2020 | Nov. 02, 2020 | Oct. 03, 2018 | Dec. 31, 2020 | Apr. 22, 2020 | Dec. 31, 2019 |
NOTES PAYABLE (Details) [Line Items] | ||||||
Notes Payable | $ 132,624 | $ 55,573 | ||||
Debt, Forza Operating, LCC [Member] | ||||||
NOTES PAYABLE (Details) [Line Items] | ||||||
Debt Instrument, Face Amount | $ 517,585 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 5.50% | |||||
Debt Instrument, Frequency of Periodic Payment | 12 monthly installments | |||||
Debt Instrument, Periodic Payment | $ 44,428 | |||||
Oil and Gas Joint Interest Billing Receivables | 233,367 | |||||
Exploration Abandonment and Impairment Expense | $ 284,218 | |||||
PPP Loan [Member] | ||||||
NOTES PAYABLE (Details) [Line Items] | ||||||
Debt Instrument, Face Amount | $ 10,054 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 1.00% | 1.00% | ||||
Debt Instrument, Periodic Payment | $ 560 | $ 560 | ||||
Debt Instrument, Term | 18 months | 18 months | ||||
PPP Loan [Member] | Final Payment [Member] | ||||||
NOTES PAYABLE (Details) [Line Items] | ||||||
Debt Instrument, Periodic Payment | $ 614 | $ 613 |
INCOME TAXES (Details)
INCOME TAXES (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2017 | |
INCOME TAXES (Details) [Line Items] | |||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21.00% | 21.00% | |
Operating Loss Carryforwards (in Dollars) | $ 27.5 | ||
Operating Loss Carryforwards, Expiration Date | 2027 | ||
Domestic Tax Authority [Member] | |||
INCOME TAXES (Details) [Line Items] | |||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21.00% | 35.00% |
INCOME TAXES (Details) - Sched
INCOME TAXES (Details) - Schedule of Deferred Tax Assets and Liabilities - USD ($) | Dec. 31, 2020 | Dec. 31, 2019 |
Schedule of Deferred Tax Assets and Liabilities [Abstract] | ||
Statutory Depletion Carry Forward | $ 361,444 | $ 367,149 |
Net Operating Loss | 7,361,230 | 6,489,891 |
Other | 583,281 | 595,990 |
Share-Based Compensation | 86,510 | 86,510 |
Capital Loss / AMT Credit Carry Forward | 9,458 | 9,458 |
Charitable Contributions Carry Forward | 3,396 | 3,890 |
Allowance for Doubtful Accounts | 671,861 | 466,060 |
Oil and Gas Properties and Fixed Assets | 4,860,069 | 5,404,787 |
Investment in RMX Joint Venture | 342,569 | (1,238,551) |
Section 481(a) Adjustments | (107,432) | (214,859) |
14,172,386 | 11,970,325 | |
Valuation Allowance | (14,172,386) | (11,970,325) |
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, 2020 | Dec. 31, 2019 | |
Schedule of Effective Income Tax Rate Reconciliation [Abstract] | ||
Tax (benefit) computed at statutory rate of 21% at December 31, 2020 and 2019, respectively | $ (1,708,463) | $ (71,680) |
Meals & Entertainment | 740 | 1,583 |
PPP Loan Forgiveness | (41,538) | 0 |
Prior-year true-up for Books | (126,541) | 1,461,914 |
Deferred State Taxes, net of federal benefit | (330,367) | 214,161 |
Other non-deductible expenses | 4,108 | 59,674 |
Change in valuation allowance | 2,202,061 | (1,665,652) |
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, 2020 | Dec. 31, 2019 | |
Schedule of Effective Income Tax Rate Reconciliation [Abstract] | ||
Statutory rate | 21.00% | 21.00% |
INCOME TAXES (Details) - Sch_4
INCOME TAXES (Details) - Schedule of Components of Income Tax Expense (Benefit) - USD ($) | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Schedule of Components of Income Tax Expense (Benefit) [Abstract] | ||
Current tax provision (benefit) - federal | $ 0 | $ 0 |
Current tax provision (benefit) - state | 0 | 0 |
Deferred tax provision (benefit) - federal | 0 | 0 |
Deferred tax provision (benefit) - state | 0 | 0 |
Total provision (benefit) | $ 0 | $ 0 |
SERIES B PREFERRED STOCK (Detai
SERIES B PREFERRED STOCK (Details) - Series B Preferred Stock [Member] - USD ($) | Mar. 07, 2018 | Dec. 31, 2020 | 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% | ||
Convertible Preferred Stock, Terms of Conversion | 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 common 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 are registered with the SEC and the volume of common shares trades exceeds 200,000 shares per day. | ||
Preferred Stock Dividends, Shares | 76,290 | ||
Dividends, Preferred Stock, Paid-in-kind (in Dollars) | $ 762,900 |
OPERATING LEASES (Details)
OPERATING LEASES (Details) | 12 Months Ended |
Dec. 31, 2020USD ($) | |
San Diego, CA [Member] | |
OPERATING LEASES (Details) [Line Items] | |
Operating Leases, Rent Expense, Minimum Rentals | $ 6,148 |
OPERATING LEASES (Details) - Le
OPERATING LEASES (Details) - Lease, Cost - USD ($) | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Lease, Cost [Abstract] | ||
Operating lease expense | $ 200,836 | $ 184,374 |
Financing lease expense | 19,137 | 10,757 |
Operating – short-term | 0 | 7,886 |
Short Term - field | 6,000 | 6,000 |
Total lease expense | $ 225,973 | $ 209,017 |
OPERATING LEASES (Details) - _2
OPERATING LEASES (Details) - Lessee, Operating Lease, Liability, Maturity - USD ($) | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Lessee, Operating Lease, Liability, Maturity [Abstract] | ||
2020 | $ 179,630 | |
2020 | 12,588 | |
2020 | 192,218 | |
2021 | 24,408 | |
2021 | 12,588 | |
2021 | 36,996 | |
2022 | 0 | |
2022 | 12,588 | |
2022 | 12,588 | |
Thereafter | 0 | |
Thereafter | 7,343 | |
Thereafter | 7,343 | |
Total undiscounted lease payments | 204,038 | |
Total undiscounted lease payments | 45,107 | |
Total undiscounted lease payments | 249,145 | |
Less: Amount representing interest | 13,679 | |
Less: Amount representing interest | 4,409 | |
Less: Amount representing interest | 18,088 | |
Total Operating & Financing lease liabilities | 190,359 | |
Total Operating & Financing lease liabilities | 40,698 | |
Total Operating & Financing lease liabilities | 231,057 | |
Current portion of long-term liabilities as September 30, 2019 | 167,578 | |
Current portion of long-term liabilities as September 30, 2019 | 10,542 | |
Current portion of long-term liabilities as September 30, 2019 | 178,120 | $ 162,272 |
Long-term lease liabilities as of September 30, 2019 | 22,781 | |
Long-term lease liabilities as of September 30, 2019 | 30,156 | |
Long-term lease liabilities as of September 30, 2019 | $ 52,937 | $ 231,071 |
RELATED PARTY TRANSACTIONS (Det
RELATED PARTY TRANSACTIONS (Details) | 12 Months Ended | |
Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | |
Stephen M. Hosmer, co-president, co-chief executive officer and chief financial officer [Member] | ||
RELATED PARTY TRANSACTIONS (Details) [Line Items] | ||
Due to Related Parties | $ 17,101 | |
Number of Wells, Participated Individually | 179 | |
Donald H. Hosmer, co-president and co-chief executive officer [Member] | ||
RELATED PARTY TRANSACTIONS (Details) [Line Items] | ||
Number of Wells, Participated Individually | 179 | |
Due from Related Parties | $ 5,385 | |
RMX Resources, LLC [Member] | ||
RELATED PARTY TRANSACTIONS (Details) [Line Items] | ||
Due to Related Parties | 23,087 | $ 32,367 |
Prepaid Expense and Other Assets | 239,036 | $ 2,680,155 |
Chief Executive Officer [Member] | ||
RELATED PARTY TRANSACTIONS (Details) [Line Items] | ||
Due to Related Parties | 14,648 | |
Matrix Oil Corporation (“MOC”) [Member] | Unpaid Salaries [Member] | Certain Matrix Employees [Member] | ||
RELATED PARTY TRANSACTIONS (Details) [Line Items] | ||
Due to Related Parties | $ 1,306,605 |
SIMPLE IRA PLAN (Details)
SIMPLE IRA PLAN (Details) - Pension Plan [Member] - USD ($) | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
SIMPLE IRA PLAN (Details) [Line Items] | ||
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent | 3.00% | |
Defined Contribution Plan, Cost | $ 41,921 | $ 30,336 |
CONCENTRATIONS (Details)
CONCENTRATIONS (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
CONCENTRATIONS (Details) [Line Items] | ||
Cash, FDIC Insured Amount | $ 250,000 | |
Cash, Uninsured Amount | $ 1,900,000 | $ 3,400,000 |
Customer Concentration Risk [Member] | Customer A [Member] | Revenue Benchmark [Member] | ||
CONCENTRATIONS (Details) [Line Items] | ||
Concentration Risk, Percentage | 32.00% |
CORONAVIRUS AID, RELIEF, AND _2
CORONAVIRUS AID, RELIEF, AND ECONOMIC SECURITY ACT (“CARES ACT”) (Details) - PPP Loan [Member] - USD ($) | Nov. 10, 2020 | Nov. 02, 2020 | Apr. 22, 2020 |
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 | 1.00% | 1.00% | |
Debt Instrument, Decrease, Forgiveness | 198,846 | ||
Debt Instrument, Periodic Payment | $ 560 | $ 560 | |
Debt Instrument, Term | 18 months | 18 months | |
Final Payment [Member] | |||
CORONAVIRUS AID, RELIEF, AND ECONOMIC SECURITY ACT (“CARES ACT”) (Details) [Line Items] | |||
Debt Instrument, Periodic Payment | $ 614 | $ 613 | |
Principal Forgiveness [Member] | |||
CORONAVIRUS AID, RELIEF, AND ECONOMIC SECURITY ACT (“CARES ACT”) (Details) [Line Items] | |||
Debt Instrument, Decrease, Forgiveness | 197,800 | ||
Interest Forgiveness [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) $ in Thousands | 12 Months Ended |
Dec. 31, 2020USD ($) | |
East Los Angeles [Member] | |
LONG-LIVED ASSETS HELD FOR SALE (Details) [Line Items] | |
Assets Held-for-sale, Not Part of Disposal Group | $ 1,900 |
Asset Retirement Obligation | 1,100 |
Property, Plant and Equipment, Net | 846 |
Oil and Gas Reclamation Liability, Noncurrent | 721 |
Proceeds from Sale of Property, Plant, and Equipment | 1,000 |
Gain (Loss) on Disposition of Property Plant Equipment | (567) |
Assets Held-for-sale, Not Part of Disposal Group, Current | 1,000 |
Asset Retirement Obligation, Current | 721 |
Texas Properties [Member] | |
LONG-LIVED ASSETS HELD FOR SALE (Details) [Line Items] | |
Asset Retirement Obligation | 149 |
Property, Plant and Equipment, Net | 381 |
Proceeds from Sale of Property, Plant, and Equipment | 700 |
Assets Held-for-sale, Not Part of Disposal Group, Current | $ 529 |
SUPPLEMENTAL INFORMATION ABOU_3
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) | 12 Months Ended | |
Dec. 31, 2020USD ($)$ / Mcf$ / bblMcfbbl | Dec. 31, 2019USD ($)Mcfbbl | |
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items] | ||
Proved Oil and Gas Property, Successful Effort Method (in Dollars) | $ 5,672,457 | $ 7,792,156 |
Natural Gas [Member] | ||
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items] | ||
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | Mcf | (1,515,637) | (890,032) |
Oil [Member] | ||
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items] | ||
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | bbl | (646,080) | 1,052,086 |
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) | $ 20,800,000 | |
Measurement Input, Discount Rate [Member] | ||
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items] | ||
Oil and Gas Property, Measurement Input | 10 | |
PG&E Citygate [Member] | Natural Gas [Member] | ||
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items] | ||
Oil and Gas, Average Sale Price | $ / Mcf | 1.985 | |
West Texas Intermediate [Member] | Oil [Member] | ||
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items] | ||
Oil and Gas, Average Sale Price | $ / bbl | 39.54 |
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, 2020Mcfbbl | Dec. 31, 2019Mcfbbl | |
Oil [Member] | ||
Reserve Quantities [Line Items] | ||
Beginning of period | bbl | 2,171,000 | 1,146,400 |
Proved reserves end of period | bbl | 1,541,000 | 2,171,000 |
Beginning of period | bbl | 232,200 | 148,600 |
End of period | bbl | 224,900 | 232,200 |
Beginning of period | bbl | 1,938,800 | 997,800 |
End of period | bbl | 1,316,100 | 1,938,800 |
Revisions of previous estimates | bbl | (646,080) | 1,052,086 |
Production | bbl | (31,210) | (27,663) |
Extensions, discoveries and improved recovery | bbl | 47,290 | 22,042 |
Sales of minerals in place | bbl | (21,865) | |
Natural Gas [Member] | ||
Reserve Quantities [Line Items] | ||
Beginning of period | Mcf | 4,306,900 | 2,986,200 |
Proved reserves end of period | Mcf | 2,660,500 | 4,306,900 |
Beginning of period | Mcf | 2,790,300 | 1,914,900 |
End of period | Mcf | 691,900 | 2,790,300 |
Beginning of period | Mcf | 1,516,600 | 1,071,300 |
End of period | Mcf | 1,968,600 | 1,516,600 |
Revisions of previous estimates | Mcf | (1,515,637) | (890,032) |
Production | Mcf | (160,406) | (292,472) |
Extensions, discoveries and improved recovery | Mcf | 29,643 | 2,516,046 |
Sales of minerals in place | Mcf | (12,842) |
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, 2020USD ($) |
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |
2021 | $ 8,954,000 |
2022 | 6,750,000 |
2023 | 1,404,500 |
Thereafter | 0 |
$ 17,108,500 |
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, 2020 | Dec. 31, 2019 | |
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Abstract] | ||
Future cash inflows | $ 65,939,300 | $ 143,045,000 |
Future production costs | (28,008,100) | (28,967,400) |
Future development costs | (17,108,400) | (20,587,800) |
Future income tax expense | (6,246,840) | (28,046,940) |
Future net cash flows | 14,575,960 | 65,442,860 |
10% annual discount for estimated timing of cash flows | (7,134,925) | (35,801,989) |
Standardized measure of discounted future net cash flows | 7,441,035 | 29,640,871 |
Sales of oil and gas produced, net of production costs | (351,478) | (624,744) |
Revisions of previous quantity estimates | (31,231,533) | 14,035,099 |
Net changes in prices and production costs | (617,847) | (14,331,770) |
Sales of minerals in place | 0 | (272,507) |
Extensions, discoveries and improved recovery | 587,311 | 2,157,052 |
Accretion of discount | (100,504) | 2,900,123 |
Net change in income tax | 9,514,215 | (4,868,296) |
Net increase (decrease) | $ (22,199,836) | $ (1,005,043) |
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, 2020USD ($) |
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 |
Estimated Future Costs, Year 2 | 0 |
Estimated Future Costs, Year 3 | 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 | 54,000 |
Estimated Future Costs, Year 2 | 0 |
Estimated Future Costs, Year 3 | 0 |
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 | 8,900,000 |
Estimated Future Costs, Year 2 | 6,750,000 |
Estimated Future Costs, Year 3 | 1,404,500 |
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 | 8,954,000 |
Estimated Future Costs, Year 2 | 6,750,000 |
Estimated Future Costs, Year 3 | $ 1,404,500 |