Royale Energy (ROYL) 10-K 30 Mar 20 2019 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2019	Mar. 06, 2020	Jun. 30, 2019
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		52,231,899
Entity Public Float			$ 8,024,089
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, 2019
Document Fiscal Year Focus	2019
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, 2019	Dec. 31, 2018
Current Assets:
Cash and Cash equivalents	$ 1,031,014	$ 1,853,742
Restricted Cash	2,845,515	4,501,300
Other Receivables, net	1,189,892	1,411,144
Revenue Receivables	589,151	316,974
Prepaid Expenses and Other Current Assets	376,587	174,852
Prepaid Drilling to RMX Resources, LLC	2,680,155	0
Total Current Assets	8,712,314	8,258,012
Investment in Joint Venture	6,185,995	6,583,931
Other Assets	708,554	509,955
Right of Use Asset - Operating Leases	392,774	0
Oil and Gas Properties (Successful Efforts Basis), Real Property and Equipment and Fixtures, net	4,590,990	6,407,490
Total Assets	20,590,627	21,759,388
Current Liabilities:
Accounts Payable and Accrued Expenses	6,031,034	4,895,533
Royalties Payable	623,405	1,676,865
Notes Payable	55,573	390,839
Due RMX Resources, LLC	32,367	552,645
Accrued Liabilities	0	1,254,204
Operating Leases - Current	162,272	0
Deferred Drilling Obligations	5,232,675	6,213,283
Total Current Liabilities	12,137,326	14,983,369
Noncurrent Liabilities:
Asset Retirement Obligation	3,632,423	2,366,455
Operating Leases - Non-current	231,071	0
Accrued Unpaid Guaranteed Payments	1,616,205	1,616,205
Accrued Liabilities - Non-current	1,306,605	1,306,605
Total Liabilities	18,923,630	20,272,634
Stockholders’ Equity:
Convertible Preferred Stock, Series B, $10 par value, 3,000,000 Shares Authorized, 2,145,332 and 2,012,400 shares issued / outstanding at December 31, 2019 and 2018, respectively	21,453,338	20,718,613
Common Stock	51,854	49,421
Additional Paid in Capital	53,549,543	53,023,350
Accumulated Deficit	(73,387,738)	(72,304,630)
Total Stockholder’s Equity	1,666,997	1,486,754
Total Liabilities and Stockholders’ Equity	$ 20,590,627	$ 21,759,388

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parentheticals) - $ / shares	Dec. 31, 2019	Dec. 31, 2018
Convertible Preferred Stock, Series B, par value (in Dollars per share)	$ 10	$ 10
Convertible Preferred Stock, Series B, Shares Authorized	3,000,000	3,000,000
Convertible Preferred Stock, Series B, shares issued	2,145,332	2,012,400
Convertible Preferred Stock, Series B, outstanding	2,145,332	2,012,400
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	51,854,136	49,421,387
Common Stock, shares outstanding	51,854,136	49,421,387

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenues:
Revenues	$ 2,967,183	$ 3,283,041
Costs and Expenses:
Lease Operating	1,764,538	1,613,368
Impairment	977,682	1,183,515
Geological and Geophysical Expense	264,219
Well Equipment Write Down	28,343	9,790
Depreciation, Depletion and Amortization	468,143	722,935
Bad Debt Expense	60,512	648,518
General and Administrative	1,991,819	3,136,009
Legal and Accounting	751,935	1,391,037
Marketing	414,971	340,641
Total Costs and Expenses	6,722,162	9,045,813
Gain on Turnkey Drilling Programs	2,909,908	2,558,716
Loss from Operations	(845,071)	(3,204,056)
Other Income (Expense):
Interest Expense	(20,559)	(177,171)
Gain (Loss) on Investment in Joint Venture	(397,936)	333,931
Gain on Settlement of Payables	897,708	287,134
Other Gain	172,523	0
Loss on Hedging Activities	0	(105,130)
Loss on Issuance of Stock Warrants	0	(1,439,990)
Loss on Sale of Assets	(155,048)	(19,199,045)
Loss Before Income Tax Expense	(348,383)	(23,504,327)
Provision for Income Taxes	0	0
Net Loss	$ (348,383)	$ (23,504,327)
Basic Loss Per Share (in Dollars per share)	$ (0.02)	$ (0.55)
Diluted Loss Per Share (in Dollars per share)	$ (0.02)	$ (0.55)
Oil and Gas [Member]
Revenues:
Revenues	$ 2,329,275	$ 1,599,362
Management Service [Member]
Revenues:
Revenues	$ 637,908	$ 1,683,679

CONSOLIDATED STATEMENTS OF STOC

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT) - USD ($)	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Preferred Stock [Member]	Total
Balance at Dec. 31, 2017	$ 40,561,882	$ 703,567	$ (48,205,690)		$ (6,940,241)
Balance (in Shares) at Dec. 31, 2017	21,850,185
Matrix Merger	$ (40,165,982)	50,407,050		$ 20,124,000	30,365,068
Matrix Merger (in Shares)	25,800,186			2,012,400
Stock issued for convsion of notes payable pursuant to merger agreement	$ (347,500)				(347,500)
Stock issued for convsion of notes payable pursuant to merger agreement (in Shares)	750,000
Stock issued in lieu of Compensation	$ 1,021	407,779			408,800
Stock issued in lieu of Compensation (in Shares)	1,021,016
Sale of Assets to RMX – Investment in J.V.		1,440,000			1,440,000
Executive’s Stock Option Grant		64,954			64,954
Preferred Series B 3.5% Dividend			(594,613)	$ 594,613	0
Preferred Series B 3.5% Dividend (in Shares)				59,461
Net Loss			(23,504,327)		(23,504,327)
Balance at Dec. 31, 2018	$ 49,421	53,023,350	(72,304,630)	$ 20,718,613	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	0
Preferred Series B 3.5% Dividend (in Shares)				73,473
Net Loss			(348,383)		(348,383)
Balance at Dec. 31, 2019	$ 51,854	$ 53,549,543	$ (73,387,738)	$ 21,453,338	$ 1,666,997
Balance (in Shares) at Dec. 31, 2019	51,854,136			2,145,334

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (Loss)	$ (348,383)	$ (23,504,327)
Adjustments to Reconcile Net Loss to Net Cash Used by Operating Activities:
Depreciation, Depletion, and Amortization	468,143	722,935
Impairment	977,682	1,183,515
Loss on Sale of Assets	155,048	19,199,045
Gain on Turnkey Drilling Programs	(2,909,908)	(2,558,716)
Gain on Settlement of Accounts Payable	(897,708)	(287,134)
Loss (Gain) on Investment in Joint Venture	397,936	(333,931)
Bad Debt Expense	60,512	648,518
Geological & Geophysical Costs	264,219	0
Gain on Other	(172,523)	0
Stock-Based Compensation	528,626	64,954
Loss on Issuance of Stock Warrants	0	1,439,990
Well Equipment and Other Assets Write Down	28,343	9,790
Loan Fee Amortization	0	144,186
Change in Fair Value of Derivative Investments	0	105,130
(Increase) Decrease in:
Other & Revenue Receivables	84,372	(858,096)
Prepaid Expenses and Other Assets	(2,535,103)	(26,464)
Increase (Decrease) in:
Accounts Payable and Accrued Expenses	960,638	286,109
Royalties Payable	(9,386)	301,222
Due to Affiliate	(302,628)	547,030
Other Long-Term Liabilities	0	50,415
Net Cash Used by Operating Activities	(3,250,120)	(2,865,829)
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for Oil and Gas Properties	(9,487,884)	(3,221,099)
Proceeds from Turnkey Drilling Programs	10,981,159	6,450,000
Proceeds from Sale of Assets	0	4,406,138
Cash Acquired in Merger	0	548,805
Net Cash Provided by (Used In) Investing Activities	1,493,275	8,183,844
CASH FLOWS FROM FINANCING ACTIVITIES:
Settlement of Liabilities from Cash Advances from Investors	0	(1,900,000)
Principal Payments on Long-Term Debt	(535,656)	(401,666)
Seismic Financing Agreement Payments	(186,012)	0
Net Cash Provided by Financing Activities	(721,668)	(2,301,666)
Net Increase (Decrease) in Cash	(2,478,513)	3,016,349
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year	6,355,042	3,338,693
Cash, Cash Equivalents, and Restricted Cash at End of Year	3,876,529	6,355,042
Cash Paid for Interest	20,559	172,171
Cash Paid for Taxes	19,374	4,800
Asset Retirement Obligation Addition	0	362,192
Issuance of Common Stock for Accrued Compensation Expense	0	408,800
Warrants Issued with Sale of Assets	0	1,440,000
Series B Paid-In-Kind Dividends	734,725	594,613
Conversion of Convertible Notes to Common Stock	0	347,500
Notes paid with proceeds from sale of Assets	0	11,616,885
Contributions to J.V.	$ 0	$ 6,250,000

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2019
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. See Note 2 – Merger With Matrix Oil Management Corporation And Formation Of RMX below. 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 property, plant and equipment, asset retirement obligations, valuation of derivative instruments 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 and operations. 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. The Company’s 2019 consolidated financial statements reflect a working capital deficiency of $3,425,012 and a net loss from operations of $845,071. 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. 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, 2019 2018 Cash and cash equivalents $ 1,031,014 $ 1,853,742 Restricted cash 2,845,515 4,501,300 Total cash, cash equivalents, and restricted cash shown in the statement of cash flows 3,876,529 6,355,042 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. 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. Revenue Recognition On January 1, 2018, we adopted the new ASC 606, Revenue from Contracts with Customers and all the related amendments (“new revenue standard”) using the modified retrospective method. We evaluated the effect of transition by applying the provisions of the new revenue standard to contracts with remaining obligations as of January 1, 2018. No cumulative adjustment to retained earnings was necessary as a result of adopting this standard. A significant portion of our revenues are derived from the sale of crude oil and condensate, natural gas liquids (“NGLs”) and natural gas under spot and term agreements with our customers. Year Ended December 31, 2019 2018 Oil & Condensate Sales $ 1,504,936 $ 1,211,818 Natural Gas Sales 824,339 385,803 NGL Sales - 1,741 $ 2,329,275 $ 1,599,362 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 regards 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. During 2018, we recognized $1,620,000 or 49.3% of our total revenues from these services. Royale had a single supervisory fee customer, that being RMX, which represented 100% of the Supervisory Fee income. 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 2019 and 2018, impairment losses of $977,682 and $1,183,515, respectively, were recorded 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. 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, 2019 and 2018, Royale Energy had Deferred Drilling Obligations of $5,232,675 and $6,213,283, 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. Losses on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value. 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, 2019 and 2018, the Company established an allowance for uncollectable accounts of $1,791,162 and $2,296,384, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue. During 2019, the Company closed a number of accounts as uncollectable, offsetting the allowance in the amount of $519,333. 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. 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, 2019 2018 Basic Diluted Basic Diluted Net Loss $ (348,383 ) $ (348,383 ) $ (23,504,327 ) $ (23,504,327 ) Less: Preferred Stock Dividend 734,725 734,725 594,613 594,613 Less: Preferred Stock Dividend in Arrears - - - - Net Loss Attributable to Common Shareholders (1,083,108 ) (1,083,108 ) (24,098,940 ) (24,098,940 ) Weighted average common shares outstanding 50,871,447 50,871,447 44,174,209 44,174,209 Effect of dilutive securities - - - - Weighted average common shares, including Dilutive effect 50,871,447 50,871,447 44,174,209 44,174,209 Per share: Net Loss $ (0.02 ) $ (0.02 ) $ (0.55 ) $ (0.55 ) For the years ended December 31, 2019 and 2018, Royale Energy had dilutive securities of 23,947,519 and 24,049,443, 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 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. Shares issued in connection with a business combination as part of the consideration transferred in exchange for the acquiree are treated within the scope of ASC 805. 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 ASC740. 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 Topic of the ASC, 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, 2019 and 2018, 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” Accounts Payable and Accrued Expenses At December 31, 2019 and 2018, the components of accounts payable and accrued expenses consisted of: 2019 2018 Trade Payables including accruals 3,107,012 2,589,518 Direct working interest investors related accruals 1,811,649 1,223,588 Current drilling efforts accrued expenses 508,246 413,701 Accrued Liabilities 393,245 391,641 Employee related accruals 195,998 232,010 Deferred rent 14,884 32,752 Federal and State income taxes payable - 12,323 6,031,034 4,895,533 Accrued– Non-current At December 31, 2019, 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. See NOTE 2 – Merger with Matrix Oil Management Corporation and Formation of RMX. Note Settlements On August 2, 2017, one year from the date of issuance, two notes totaling $1,580,000 matured, with a default rate of 25%. In the first quarter 2018, the $300,000 note was converted into 750,000 shares of Royale common stock, and Royale agreed to a cash settlement with the holder of th

MERGER WITH MATRIX OIL MANAGEME

MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
Business Combination Disclosure [Text Block]	NOTE 2 – MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX Merger On March 7, 2018, Royale Energy, Inc. (“Royale Energy,” formerly known as Royale Energy Holdings, Inc., a Delaware corporation), Royale Energy Funds, Inc. (“REF,” formerly known as Royale Energy, Inc., a California corporation), and Matrix Oil Management Corporation (“Matrix”) and its affiliates were notified by the California Secretary of State of the filing and acceptance of agreements of merger by the California Secretary of State, to complete the previously announced merger between the companies (the “Merger”). In the Merger, REF was merged into a newly formed subsidiary of Royale Energy, and Matrix was merged into a second newly formed subsidiary of Royale Energy pursuant to the Amended and Restated Agreement and Plan of Merger among REF, Royale Energy, Royale Merger Sub, Inc., (“Royale Merger Sub”), Matrix Merger Sub, Inc., (“Matrix Merger Sub”) and Matrix (the “Merger Agreement”). Additionally, in connection with the merger, all limited partnership interest of two limited partnership affiliates of Matrix (Matrix Permian Investments, LP, and Matrix Las Cienegas Limited Partnership), were exchanged for Royale Energy common stock using conversion ratios according to the relative values of each partnership. All Class A limited partnership interests of another Matrix affiliate, Matrix Investments, LP (“Matrix Investments”) were exchanged for Royale Energy 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 Energy. Another Matrix affiliate, Matrix Oil Corporation (“Matrix Operator”), was acquired by Royale Energy by exchanging Royale Energy common stock for the outstanding common stock of Matrix Oil Corporation using a conversion ratio according to the relative value of the Matrix Oil Corporation common stock. Matrix, Matrix Oil Corporation and the three limited partnership affiliates of Matrix called the “Matrix Entities.” The Merger had been previously approved by the respective holders of all outstanding capital stock of REF, Matrix, Royale Energy, Matrix Merger Sub and Royale Merger Sub on November 16, 2017, as previously reported in our Current Report on Form 8-K dated November 16, 2017. The Merger and related transactions are described in more detail in our Form 8-K dated March 7, 2018 (SEC File No. 000-55912). As a result of the Merger, REF became a wholly owned subsidiary of Royale Energy, and each outstanding share of common stock of REF at the time of the Merger was converted into one share of common stock of Royale Energy. The common stock of Royale Energy is traded on the Over-The-Counter QB (OTCQB) Market System (symbol ROYL). Under ASC 805, Business Combinations The preliminary allocation of the purchase price was determined in arms’ length negotiations between the parties. Substantially all of the value of the transaction was related to the value of the oil and gas assets acquired with minimal value ascribed to the other assets. The Company considered two valuation methods in its determination of fair value for the oil and natural gas properties; the discounted cash flow analysis and comparable transaction analysis. Assumptions for the discounted cash flow analysis include commodity price, operating costs and capital outlay for future development of the acquired properties, pricing differentials, reserve risking, and discount rates. NYMEX strip pricing, less applicable pricing differentials, was utilized in the discounted cash flow analysis. Risking levels in the discounted cash flow analysis are determined based on a variety of factors, such as existing well performance, offset production and analogue wells. Discount rates used in the discounted cash flow analysis were determined by using the estimated cost of capital, discount rates, as well as industry knowledge and experience. The comparable transaction analysis was performed to establish a range of fair values for similarly situated oil and gas properties that were recently bought or sold in arms-length, observable market transactions. The range of value observed from the Company’s analysis of recent market transactions was then utilized as a basis for evaluating the fair value determined via the discounted cash flow method. The Company’s fair value conclusion indicated that the discounted cash flow method valuation is in line with the same range as the comparable transactions reviewed, when considering the comparable transactions. Other current liabilities assumed in the acquisition, were carried over at historical carrying values because the assets and liabilities are short term in nature and their carrying values are estimated to represent the best estimate of fair value. The following table summarizes the consideration transferred, fair value of assets acquired and liabilities assumed: March 7, 2018 Consideration: Value of Royale Common Stock issued $ 9,546,068 Value of Series B Convertible Preferred Stock issued 20,124,000 Total consideration $ 29,670,068 Fair Value of Liabilities Assumed: Current liabilities 19,624,592 Other liabilities 3,125,394 Asset Retirement obligations 1,419,544 Total fair value of liabilities assumed 24,169,530 Total consideration plus liabilities assumed $ 53,839,598 Fair Value of Assets Acquired: Cash $ 548,805 Current assets 1,073,532 Proved and unproved crude oil and gas properties 51,214,512 Land 1,002,750 Total Fair Value of Assets Acquired $ 53,839,598 In accordance with ASC 805, the following unaudited supplemental pro forma condensed results of operations present combined information as though the business combination had been completed as of January 1, 2018. The unaudited supplemental pro forma financial information was derived from the historical revenues and direct operating expenses of Royale Energy, Inc. and Matrix Oil Management Corporation and its affiliates. These unaudited supplemental pro forma results of operations for the consolidated companies as of December 31, 2018, are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the consolidated company for the periods presented or that may be achieved by the consolidated company in the future. Year ended December 31, 2018 Royale Energy, Inc. Matrix Oil Management Corp Consolidated Revenue $ 723,172 $ 1,199,684 $ 1,922,856 Net Loss $ (1,633,713 ) $ (149,936 ) $ (1,783,649 ) Net Loss available to common shareholders $ (1,633,713 ) $ (149,936 ) $ (1,783,649 ) Pro forma Loss per common share Basic and diluted $ (0.04 ) $ (0.00 ) $ (0.04 ) Amounts previously estimated have changed during the measurement period. The changes in estimates included an increase of $2,581,641 million of oil and gas properties and a decrease of $2,581,641 million in accounts receivable and other current assets. We recorded measurement-period adjustments in the fourth quarter of 2018. Depletion expense increased by an immaterial amount as a result of these measurement-period adjustments and all amounts referenced below are inclusive of these measurement period adjustments. As of December 31, 2018, the purchase accounting for the Matrix acquisition was complete. Original Adjustment Revised Cash $ 548,805 $ - $ 548,805 Current Assets $ 3,655,173 $ (2,581,641 ) $ 1,073,532 Oil and gas properties $ 48,632,870 $ 2,581,641 $ 51,214,512 Formation of RMX and Asset Contribution 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. The Contribution Agreement was completed in a two-step closing and funding, with the First Closing consummated on April 4, 2018 and the Second Closing consummated on April 13, 2018 with the Royale Entities. In connection with the Second Closing, the parties entered into a letter agreement related to the preliminary Settlement Statement process. The parties agreed that, in lieu of the payment originally contemplated under Section 1.6(v) of the Contribution Agreement, the Royale Entities would receive the sum of $4,000,000, subject to adjustment. The $4,000,000 delivered at the Second Closing was an advance against amounts due the Royale Entities as Purchase Price, and the advance was subject to further adjustment in accordance with the Contribution 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. As part of the formation of the joint venture, Royale contributed Matrix Oil Corporation (“MOC”) to RMX. MOC has the permits and licenses to operating oil and gas properties in California. It was the operating entity for the Matrix group of companies that were acquired on February 28, 2018, discussed above. This allows the RMX joint venture to be the operator of record for the contributed assets. Royale accounts for its ownership interest in RMX following the equity method of accounting, in accordance with ASC 323. Pursuant to the Subscription and Contribution agreement, Royale has an initial equity value of $6.25 million or 20% of the total equity of the joint venture with CIC having an initial equity value of $25.0 million or 80% of the total equity of the joint venture. The Royale Entities contributed 100% of their interest in the Sansinena Field, 100% of the Sempra Field, 50% of the Bellevue Field, 100% of the Whittier Main Field, and 50% of the Whittier Field. The result of the transfer of oil and gas properties and surface rights for cash as described above and a 20% interest in RMX resulted in Royale recording a loss of approximately $17.9 million. The issuance by Royale of warrants to acquire 4,000,000 shares of Royale common stock, by CIC, caused Royale to record a loss of approximately $1.44 million. In addition, the Contribution Agreement called for an effective date of the property transfer of February 28, 2018 which required a purchase price adjustment of approximately $334,000 in the form of a cash contribution to RMX and an increase in the loss on the sale. The transfer of MOC to RMX as the operating company provided an amount due Royale of approximately $640,000, which was recorded as a due from affiliate during the period in 2018. 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. The RMX joint venture has a senior revolving loan facility with Washington Federal Bank. The borrowing base of the facility is $25.0 million with $19,403,800 drawn at December 31, 2019. RMX 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 first year. 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. 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 has 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 will continue to be responsible for the liability 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. 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. Listed below is summarized information the Company’s investment in RMX: Twelve Months Ended December 31, 2019 March 27, 2018 December 31, 2018 RMX Resources, LLC RMX Resources, LLC Balance Sheet: Total Assets $ 72,401,841 $ 71,758,262 Total Liabilities $ 41,573,426 $ 38,838,608 Members Equity $ 30,828,415 $ 32,919,654 Results of Operations: Net operating revenue $ 16,392,305 $ 8,773,661 Loss from operations $ 1,456,290 $ (181,464 ) Net income $ (2,091,239 ) $ 1,669,654

OIL AND GAS PROPERTIES, EQUIPME

OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES	12 Months Ended
	Dec. 31, 2018
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, 2019 2018 Oil and Gas Producing properties, including intangible drilling costs $ 7,792,156 $ 9,340,779 Undeveloped properties 46,990 25,582 Lease and well equipment 3,304,565 3,350,893 11,143,711 12,717,254 Accumulated depletion, depreciation and amortization (6,559,182 ) (6,402,657 ) Net capitalized costs Total $ 4,584,529 $ 6,314,597 Commercial and Other 2019 2018 Real estate, including furniture and fixtures $ - $ 83,405 Vehicles 40,061 40,061 Furniture and equipment 1,097,428 1,095,149 1,137,489 1,218,615 Accumulated depreciation (1,131,028 ) (1,125,722 ) 6,461 92,893 Net capitalized costs Total $ 4,590,990 $ 6,407,490 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, 2019 2018 Acquisition - Proved $ - $ - Acquisition - Unproved - - Development 9,680,298 3,838,998 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 2019 and 2018. 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, 2019 2018 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, 2019 2018 Oil and gas sales $ 2,329,275 $ 1,599,362 Production related costs (Lease Operating) (1,764,538 ) (1,613,368 ) Impairment (977,682 ) (1,183,515 ) Depreciation, depletion and amortization (468,143 ) (722,935 ) Results of operations from producing and exploration activities $ (881,088 ) $ (1,920,456 ) Income Taxes (Benefit) - - Net Results $ (881,088 ) $ (1,920,456 )

ASSET RETIREMENT OBLIGATION

ASSET RETIREMENT OBLIGATION	12 Months Ended
	Dec. 31, 2019
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 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 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. 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 has recorded them as impairment expense at year end 2019. 2019 2018 Asset retirement obligation Beginning of the year $ 2,366,456 $ 1,000,908 Liabilities incurred during the period 210,643 595,583 Settlements - (52,636 ) Merger Additions - 1,419,544 Sales (33,026 ) (486,585 ) Changes in estimates 922,698 - Accretion expense 165,651 (110,358 ) End of year $ 3,632,422 $ 2,366,456 The Company records accretion expense as part of Depreciation, Depletion and Amortization

NOTES PAYABLE

NOTES PAYABLE	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Debt Disclosure [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, 2019 and 2018, Royale Energy had Notes Payable of $55,573 and $390,839, respectively, as a current liability.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2019
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, 2019 and 2018, respectively, are as follows: 2019 2018 Deferred Tax Assets (Liabilities): Statutory Depletion Carry Forward $ 367,149 $ 367,149 Net Operating Loss 6,489,891 7,121,912 Other 595,990 708,057 Share-Based Compensation 86,510 86,510 Capital Loss / AMT Credit Carry Forward 9,458 9,458 Charitable Contributions Carry Forward 3,890 6,158 Allowance for Doubtful Accounts 466,060 597,519 Oil and Gas Properties and Fixed Assets 5,404,787 5,987,061 Investment in RMX Joint Venture (1,238,551 ) (1,247,847 ) Section 481(a) Adjustments (214,859 ) - $ 11,970,325 $ 13,635,977 Valuation Allowance (11,970,325 ) (13,635,977 ) 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 $22.9 million generated in tax years ended before January 1,2018, which if not utilized, begin to expire in the year 2024. 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, 2019 and 2018, respectively, to pretax income is as follows: 2019 2018 Tax (benefit) computed at statutory rate of 21% at December 31, 2019 and 2018, respectively $ (71,680 ) $ (4,935,909 ) Increase (decrease) in taxes resulting from: Meals & Entertainment 1,583 1,320 Investor Incentive Expense - 7 Transaction Costs - 160,927 Loss on Warrants Issued to RMX - 302,398 Prior-year true-up for Books 1,461,914 2,075,440 Deferred State Taxes, net of federal benefit 214,161 (1,009,601 ) Other non-deductible expenses 59,674 (264,359 ) Change in valuation allowance (1,665,652 ) 3,669,777 Provision (benefit) - - The components of the Company’s tax provision are as follows: 2019 2018 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, 2019
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% dividend, payable in cash or Paid-In-Kind 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. For 2019 and 2018, the board has authorized the payment of all dividends of Series B Convertible Preferred shares, as Paid-In-Kind shares. During 2019 the Company had issued 73,473 and 59,461 shares for the year ended 2019 and 2018 respectively, representing a value of $734,725 and $594,613 for the same periods. No cash was used to pay dividends on Series B preferred shares in 2019 or 2018.

COMMON STOCK

COMMON STOCK	12 Months Ended
	Dec. 31, 2019
Stockholders' Equity Note [Abstract]
Stockholders' Equity Note Disclosure [Text Block]	NOTE 8 - COMMON STOCK In April 2016, Royale entered in a securities purchase agreement and related agreements with one investor. Under the terms of the agreement, the investor purchased 622,316 shares of Royale’s common stock at $0.3214 per share, and received warrants to purchase up to 311,158 shares (the “Warrants’) of stock at $0.5356 per share for three (3) years, for a total of $200,000 in gross proceeds. In July 2016, Royale entered in securities purchase agreements and related agreements with three investors. Under the terms of the agreement, the investors purchased 2,392,500 shares of Royale’s common stock at $0.40 per share, and received warrants to purchase up to 478,500 shares (the “Warrants’) of stock at $0.80 per share for two (2) years, for a total of $957,000 in gross proceeds. 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. As part of the agreement a warrant (“Warrant”) was issued 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. As further described in NOTE 2 – Merger with Matrix Oil Management Corporation and Formation of RMX . During the year 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.

IMPLEMENTATION OF ASC 842 - LEA

IMPLEMENTATION OF ASC 842 - LEASE ACCOUNTING	12 Months Ended
	Dec. 31, 2019
Disclosure Text Block [Abstract]
Leases of Lessee Disclosure [Text Block]	NOTE 9 - OPERATING LEASES The Company has elected a modified retrospective transition approach for the implementation methodology of ASC 842, Leases The standard did not materially impact our consolidated results of operations, earnings per share, and had no impact on cash flows. The most significant effects relate to: (1) the recognition of new ROU assets in long-term assets on the balance sheet; (2) lease liabilities, both short-term and long-term, on our balance sheet; and, (3) providing significant new disclosures about our leasing activities. The interest rate used in each lease analysis was the risk-free rate for the period of the lease plus 400 basis points as the Company’s risk premium. 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 initial base rental payment was $5,086 with various adjustments to market and planned escalations. These two leases were initially recorded as operating leases at January 1, 2019 as listed below. Debit/Credit Operating Lease – ROU Asset 483,504 Operating Lease Liability – Current (140,831 ) Operating Lease Liability – Long-Term (342,673 ) In July 2019, we entered into a 60 month agreement with MRC for the leasing of two Xerox machines with monthly payments of $1,049. This lease was initially recorded as a financing lease on July 31, 2019 as listed below: Debit/Credit Financing Lease - ROU Asset 54,655 Financing Lease Liability - Current (9,725 ) Financing Lease Liability - Long-Term (44,930 ) The new standard provides practical expedients for an entity’s ongoing accounting. We have elected the short-term lease recognition exemption for all leases that qualify. This means, for those leases that qualify, we will not recognize ROU assets or lease liabilities, and this includes not recognizing ROU assets or lease liabilities for existing short-term leases of those assets in transition. We 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 Operating lease expense 184,374 Financing lease expense 10,757 Operating – short-term 7,886 Short Term - field 6,000 Total lease expense 209,017 The following tables summarized the operating and financing lease obligations. Lease Obligations Operating Financing Total 2020 173,809 12,588 186,397 2021 179,630 12,588 192,218 2022 24,408 12,588 36,996 Thereafter - 19,931 19,931 Total undiscounted lease payments $ 377,847 57,695 435,542 Less: Amount representing interest 35,174 7,025 42,199 Total Operating & Financing lease liabilities $ 342,673 50,670 393,343 Long-term lease liabilities as of December 31, 2019 $ 152,314 9,958 162,272 Long-term lease liabilities as of December 31, 2019 $ 190,359 40,712 231,071

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
Related Party Transactions Disclosure [Text Block]	NOTE 10 - RELATED PARTY TRANSACTIONS Significant Ownership Interests Our Chief Executive, Johnny Jordan, had been an employee of Matrix prior to the Merger. Pursuant to this employment, he had accrued certain unpaid salaries, which were assumed by the Company. At December 31, 2019 Mr. Jordan was owed $22,107 in accrued unpaid guaranteed payments. Our Chief Financial Officer, Stephen Hosmer has participated individually in 179 wells under the 1989 policy. During 2019 and 2018, Stephen did not participate in fractional interests. At December 31, 2019, the Company had a receivable balance of $15,524 due from Stephen Hosmer for normal drilling and lease operating expenses. Donald Hosmer has participated individually in 179 wells under the 1989 policy. During 2019 and 2018, Donald did not participate in fractional interests. At December 31, 2019, Royale had a receivable balance of $3,441 due from Donald Hosmer for normal drilling and lease operating expenses. At December 31, 2019, we had a total payable of $32,367 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 period, the Company also had prepaid expenses and other current assets of $2,680,155 primarily for the drilling of three wells, expected to commence in 2020. Royale had outstanding accrued unpaid guaranteed payments for unpaid salaries due to certain Matrix employees, for periods prior to the Merger. At December 31, 2019, 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, 2019
Share-based Payment Arrangement [Abstract]
Share-based Payment Arrangement [Text Block]	NOTE 11 - STOCK COMPENSATION PLAN On October 10, 2018, the Company entered into an Incentive Stock Option Award Agreement with Stephen M. Hosmer, Chief Financial Officer. Mr. Hosmer was granted 250,000 options to purchase common stock at an exercise price of $0.31 per share. These options were granted for a period of 10 years and will expire after October 10, 2028. These options become vested exercisable immediately. These options were valued using the Black-Scholes methodology. The Black-Scholes assumptions were as follows: Exercise price per share, $0.31; Current stock price (as of the close on October 10, 2018) $0.34; Risk-free interest rate of 3.22%; Time to maturity of 10 years; and, Stock volatility of 66.48%. The Black-Scholes model, using the values listed above, valued each option at $0.26 making the award of $250,000 options worth $64,954. There were no other stock options issued in 2019 and 2018. A summary of the status of Royale Energy’s stock option plan as of December 31, 2019 and 2018, and changes during the years ending on those dates is presented below: 2019 2018 Weighted- Weighted- Average Average Exercise Exercise Shares Price Shares Price Options Outstanding and Exercisable at Beginning of Year 250,000 $ 0.31 - Granted or Vested - 250,000 $ 0.31 Exercised - - Forfeited - - Options Outstanding and Exercisable at Year End 250,000 $ 0.31 250,000 $ 0.31 Weighted-average Fair Value of Options Granted During the Year $ - $ 64,954 At December 31, 2019, Royale Energy’s stock price, $0.11, was less than the weighted average exercise price, and as such the outstanding and exercisable stock options had no intrinsic value. All stock options were fully vested at December 31, 2019 and 2018. During 2019 and 2018, we recognized $0 and $64,954, respectively, in compensation costs for the vested stock options. The Company will incur no future expense related to these options.

SIMPLE IRA PLAN

SIMPLE IRA PLAN	12 Months Ended
	Dec. 31, 2019
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, 2019 and 2018, were $30,336 and $35,312 respectively.

ENVIRONMENTAL MATTERS

ENVIRONMENTAL MATTERS	12 Months Ended
	Dec. 31, 2019
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 assure 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 2019 or 2018. 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, 2019
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, 2019 and 2018. At December 31, 2019 and 2018, cash in banks exceeded the FDIC limits by approximately $3.4 million and $5.7 million, respectively. The Company has not experienced any losses on deposits.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2019
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.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2019
Subsequent Events [Abstract]
Subsequent Events [Text Block]	NOTE 16 - SUBSEQUENT EVENTS In late 2019 and continuing into 2020, there was a global outbreak of novel coronavirus (COVID-19) that has resulted in changes in global supply and demand of certain mineral and energy products. While the direct and indirect negative impacts that may affect the Company cannot be determined, they could have a prospective material impact to the Company's operations, cash flows and liquidity.

SUPPLEMENTAL INFORMATION ABOUT

SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)	12 Months Ended
	Dec. 31, 2019
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Oil and Gas Exploration and Production Industries Disclosures [Text Block]	NOTE 17 - SUPPLEMENTAL 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 $57.8 million at December 31, 2018, based on the average Henry Hub natural gas price spot price of $3.10 per MCF and for oil volumes, the average West Texas Intermediate price of $65.56 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 Financial Accounting Standards Board and the Securities and Exchange Commission (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, 2019 and 2018, and changes in such quantities during each of the years then ended, were as follows: Total Proved Reserves 2019 2018 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Beginning of period 1,146,400 2,986,200 202 2,132,221 Revisions of previous estimates 1,052,086 (890,032 ) (79,136 ) (401,498 ) Production (27,663 ) (292,472 ) (20,329 ) (135,396 ) Extensions, discoveries and improved recovery 22,042 2,516,046 - 25,014 Merger Acquisition - - 11,375,784 13,459,933 Purchase of minerals in place - - 29,300 116,110 Sales of minerals in place (21,865 ) (12,842 ) (10,159,421 ) (12,210,184 ) Proved reserves end of period 2,171,000 4,306,900 1,146,400 2,986,200 Proved Developed 2019 2018 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed reserves: Beginning of period 148,600 1,914,900 202 1,798,697 End of period 232,200 2,790,300 148,600 1,914,900 Proved Undeveloped 2019 2018 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved undeveloped reserves: Beginning of period 997,800 1,071,300 - 333,524 End of period 1,938,800 1,516,600 997,800 1,071,300 At December 31, 2019, our previously estimated proved developed and undeveloped natural gas reserve quantities were revised downward by approximately 890,032 MCF of natural gas. This downward revision was mainly the result of a decrease in proved undeveloped natural gas reserves from drilling locations which the Company had contracted. At December 31, 2019, our previously estimated proved developed and undeveloped oil reserve quantities were revised upward by approximately 1,052,086 BBL of oil. This upward revision was mainly the result an increase in the quantity and quality of undrilled wells, in which the Company has the right to participate. 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: 2020 $ 10,331,900 2021 4,500,000 2022 4,511,800 Thereafter 1,244,100 Total $ 20,587,800 The resulting future net revenue streams are reduced to present value amounts by applying a ten 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, 2019 and 2018. 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 ten 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. 2019 2018 Future cash inflows 143,045,000 87,467,200 Future production costs (28,967,400 ) (22,390,900 ) Future development costs (20,587,800 ) (7,256,900 ) Future income tax expense (28,046,940 ) (17,345,820 ) Future net cash flows 65,442,860 40,473,580 10% annual discount for estimated timing of cash flows (35,801,989 ) (9,827,666 ) Standardized measure of discounted future net cash flows 29,640,871 30,645,914 Sales of oil and gas produced, net of production costs (624,744 ) (40,557 ) Revisions of previous quantity estimates 14,035,099 (71,162 ) Net changes in prices and production costs (14,331,770 ) 11,683,159 Sales of minerals in place (272,507 ) (3,061,278 ) Purchases of minerals in place - 287,300 Merger Acquisition - 29,903,670 Extensions, discoveries and improved recovery 2,157,052 59,191 Accretion of discount 2,900,123 2,670,000 Net change in income tax (4,868,296 ) (12,429,097 ) Net increase (decrease) (1,005,043 ) 29,001,226 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 2020 through 2022. Future development cost of: 2020 2021 2022 Proved developed reserves (PDP) $ - $ - $ - Proved non-producing reserves (PDNP) 126,900 - 11,800 Proved undeveloped reserves (PUD) 10,205,000 4,500,000 4,500,000 Total $ 10,331,900 $ 4,500,000 $ 4,511,800 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. RMX Resources, LLC Royale has a 20% interest in RMX Resources, LLC, as described in The estimates listed below of proved oil and gas reserves and revenues, both developed and undeveloped represent the gross volume attributable to RMX as a whole and to the 20 percent interest of RMX held by Royale. The reserve values were prepared by independent petroleum engineering consultants Netherland, Sewell & Associates, Inc. These estimates do not include probable or possible reserves and revenue and are presented on the same bases as that of Royale. RMX is not subject to U.S. Federal or state income taxes related to crude oil and natural gas production. RMX has elected to be taxed as a partnership; therefore, the reserve information provided below does not consider Federal or state income taxes. Total Proved Reserves 2019 2018 Net to Royale (20%) Net to Royale (20%) Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed and undeveloped reserves: Beginning of period – 4,219,140 4,378,060 3,739,820 4,403,654 Revisions of previous estimates (188,726 ) (3,388,497 ) - - Production (49,894 ) (23,023 ) (41,240 ) (25,594 ) Extensions, discoveries and improved recovery - - - - Purchase of minerals in place - - 520,560 - Sales of minerals in place - - - - Proved reserves end of period 3,980,520 966,540 4,219,140 4,378,060 Proved Developed Net to Royale (20%) Net to Royale (20%) Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed reserves: Beginning of period – (2018 at formation of RMX) 993,080 635,180 791,073 660,774 End of period 1,186,080 653,920 993,080 635,180 Proved Undeveloped Net to Royale (20%) Net to Royale (20%) Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved undeveloped reserves: Beginning of period – (2018 at formation of RMX) 3,226,060 3,742,880 2,917,721 3,742,880 End of period 2,794,440 312,620 3,226,060 3,742,880 Changes in Standardized measure of discounted future net cash flow from proved reserve quantities 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 ten 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. Because RMX was formed in April of 2018, this analysis only provides the reserve information as of year-end without a comparison and reciliation to a beginning reserve report. 2019 2018 Net to Royale Net to Royale Future cash inflows 247,894,600 305,586,180 Future production costs (72,400,860 ) (84,222,980 ) Future development costs (22,142,340 ) (28,801,620 ) Future income tax expense (46,005,420 ) - Future net cash flows 107,345,980 192,561,580 10% annual discount for estimated timing of cash flows (61,882,856 ) (118,962,940 ) Standardized measure of discounted future net cash flows 45,463,124 73,598,640 Sales of oil and gas produced, net of production costs (1,308,378 ) (810,635 ) Formation of RMX Joint Venture - 60,282,536 Net changes in prices and production costs and revisions of previous quantity estimates (14,702,806 ) - Sales of minerals in place - - Purchases of minerals in place - 8,673,117 Extensions, discoveries and improved recovery - - Accretion of discount 7,359,864 5,453,622 Net change in income tax (19,484,196 ) - Net increase (decrease) (28,135,516 ) 73,598,640

Accounting Policies, by Policy

Accounting Policies, by Policy (Policies)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Consolidation, Policy [Policy Text Block]	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. See Note 2 – Merger With Matrix Oil Management Corporation And Formation Of RMX below. 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
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 property, plant and equipment, asset retirement obligations, valuation of derivative instruments 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 and operations. 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. The Company’s 2019 consolidated financial statements reflect a working capital deficiency of $3,425,012 and a net loss from operations of $845,071. 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.
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, 2019 2018 Cash and cash equivalents $ 1,031,014 $ 1,853,742 Restricted cash 2,845,515 4,501,300 Total cash, cash equivalents, and restricted cash shown in the statement of cash flows 3,876,529 6,355,042
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. 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.
Revenue [Policy Text Block]	Revenue Recognition On January 1, 2018, we adopted the new ASC 606, Revenue from Contracts with Customers and all the related amendments (“new revenue standard”) using the modified retrospective method. We evaluated the effect of transition by applying the provisions of the new revenue standard to contracts with remaining obligations as of January 1, 2018. No cumulative adjustment to retained earnings was necessary as a result of adopting this standard. A significant portion of our revenues are derived from the sale of crude oil and condensate, natural gas liquids (“NGLs”) and natural gas under spot and term agreements with our customers. Year Ended December 31, 2019 2018 Oil & Condensate Sales $ 1,504,936 $ 1,211,818 Natural Gas Sales 824,339 385,803 NGL Sales - 1,741 $ 2,329,275 $ 1,599,362 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 regards 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. During 2018, we recognized $1,620,000 or 49.3% of our total revenues from these services. Royale had a single supervisory fee customer, that being RMX, which represented 100% of the Supervisory Fee income. 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 2019 and 2018, impairment losses of $977,682 and $1,183,515, respectively, were recorded 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. 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, 2019 and 2018, Royale Energy had Deferred Drilling Obligations of $5,232,675 and $6,213,283, 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. Losses on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value.
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, 2019 and 2018, the Company established an allowance for uncollectable accounts of $1,791,162 and $2,296,384, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue. During 2019, the Company closed a number of accounts as uncollectable, offsetting the allowance in the amount of $519,333.
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.
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, 2019 2018 Basic Diluted Basic Diluted Net Loss $ (348,383 ) $ (348,383 ) $ (23,504,327 ) $ (23,504,327 ) Less: Preferred Stock Dividend 734,725 734,725 594,613 594,613 Less: Preferred Stock Dividend in Arrears - - - - Net Loss Attributable to Common Shareholders (1,083,108 ) (1,083,108 ) (24,098,940 ) (24,098,940 ) Weighted average common shares outstanding 50,871,447 50,871,447 44,174,209 44,174,209 Effect of dilutive securities - - - - Weighted average common shares, including Dilutive effect 50,871,447 50,871,447 44,174,209 44,174,209 Per share: Net Loss $ (0.02 ) $ (0.02 ) $ (0.55 ) $ (0.55 ) For the years ended December 31, 2019 and 2018, Royale Energy had dilutive securities of 23,947,519 and 24,049,443, 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 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. Shares issued in connection with a business combination as part of the consideration transferred in exchange for the acquiree are treated within the scope of ASC 805.
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 ASC740. 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 Topic of the ASC, 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, 2019 and 2018, 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”
Accounts Payable and Accrued Expenses [Policy Text Block]	Accounts Payable and Accrued Expenses At December 31, 2019 and 2018, the components of accounts payable and accrued expenses consisted of: 2019 2018 Trade Payables including accruals 3,107,012 2,589,518 Direct working interest investors related accruals 1,811,649 1,223,588 Current drilling efforts accrued expenses 508,246 413,701 Accrued Liabilities 393,245 391,641 Employee related accruals 195,998 232,010 Deferred rent 14,884 32,752 Federal and State income taxes payable - 12,323 6,031,034 4,895,533
Accrued Liabilitites Policy [Policy Text Block]	Accrued– Non-current At December 31, 2019, 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. See NOTE 2 – Merger with Matrix Oil Management Corporation and Formation of RMX
Debt, Policy [Policy Text Block]	Note Settlements On August 2, 2017, one year from the date of issuance, two notes totaling $1,580,000 matured, with a default rate of 25%. In the first quarter 2018, the $300,000 note was converted into 750,000 shares of Royale common stock, and Royale agreed to a cash settlement with the holder of the $1,280,000 note for $1,900,000.
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. Fair value considerations include the evaluation of the underlying documentation supporting receivables, property, other assets and liabilities. If the documentation and support for a receivable or other asset represented by the seller is not deemed acceptable by the Company’s auditors, the receivable or other asset is not considered in the purchase price until such time as the receivable or other asset can be proven to a level acceptable to the Company’s auditors. Any receipts by the Company of cash or other assets, subsequent to the transaction date for which the merger documentation was considered insufficient at the time of the merger, the Company recognizes as a current liability. At such time as the documentation is deemed acceptable, the liability is relieved with a credit to earnings in the period of determination.
New Accounting Pronouncements, Policy [Policy Text Block]	Accounting Standards Recently Adopted ASU 2017-12, Derivatives and hedging – Targeted Improvement to Accounting for Hedging Activities In August 2017, the FASB issued an ASU to amend the hedge accounting rules to simplify the application of hedge accounting guidance and better portray the economic results of risk management activities in the financial statements. The guidance expands the ability to hedge nonfinancial and financial risk components, reduces complexity in fair value hedges of interest rate risk, eliminates the requirements to separately measure and report hedge ineffectiveness and eases certain hedge effectiveness assessment requirements. The guidance was effective beginning in 2019. Adoption of this standard did not have a material impact on our consolidated financial statements. ASU 2016-02 and 2018-11, Leases In February 2016, the FASB established Topic 842, Leases, by issuing Accounting Standards Update (ASU) No. 2016-02, which requires lessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. Topic 842 was subsequently amended by ASU No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842; ASU No. 2018-10, Codification Improvements to Topic 842, Leases; and ASU No. 2018-11, Targeted Improvements. The new standard establishes a right-of-use model (“ROU”) that requires a lessee to recognize a ROU asset and lease liability on the balance sheet for all leases with a term longer than 12 months. As a public company, the new standard is effective for us on January 1, 2019. A modified retrospective transition approach is the implementation methodology we have selected; applying the new standard to all leases existing at the date of initial application, in this case January 1, 2019. Consequently, financial information has not been updated and the disclosures required under the new standard have not been provided for dates and periods before January 1, 2019. The new standard provides a number of optional practical expedients for the transition. We have elected the ‘package of practical expedients’, which permits us not to reassess under the new standard our prior conclusions about lease identification, lease classification and initial direct costs. We do not expect to elect the use-of hindsight or the practical expedient pertaining to land easements; the latter not being applicable to us. We have elected all of the new standard’s available transition practical expedients. The standard did not materially impact our consolidated results of operations, earnings per share, and had no impact on cash flows. The most significant effects relate to: (1) the recognition of new ROU assets in long-term assets on the balance sheet; (2) lease liabilities, both short-term and long-term, on our balance sheet; and, (3) providing significant new disclosures about our leasing activities. We do not expect a significant change in our leasing activities as a result of the adoption of this new pronouncement. See Note 9- Operating Leases

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 Cash and cash equivalents $ 1,031,014 $ 1,853,742 Restricted cash 2,845,515 4,501,300 Total cash, cash equivalents, and restricted cash shown in the statement of cash flows 3,876,529 6,355,042
Disaggregation of Revenue [Table Text Block]	A significant portion of our revenues are derived from the sale of crude oil and condensate, natural gas liquids (“NGLs”) and natural gas under spot and term agreements with our customers. Year Ended December 31, 2019 2018 Oil & Condensate Sales $ 1,504,936 $ 1,211,818 Natural Gas Sales 824,339 385,803 NGL Sales - 1,741 $ 2,329,275 $ 1,599,362
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, 2019 2018 Basic Diluted Basic Diluted Net Loss $ (348,383 ) $ (348,383 ) $ (23,504,327 ) $ (23,504,327 ) Less: Preferred Stock Dividend 734,725 734,725 594,613 594,613 Less: Preferred Stock Dividend in Arrears - - - - Net Loss Attributable to Common Shareholders (1,083,108 ) (1,083,108 ) (24,098,940 ) (24,098,940 ) Weighted average common shares outstanding 50,871,447 50,871,447 44,174,209 44,174,209 Effect of dilutive securities - - - - Weighted average common shares, including Dilutive effect 50,871,447 50,871,447 44,174,209 44,174,209 Per share: Net Loss $ (0.02 ) $ (0.02 ) $ (0.55 ) $ (0.55 )
Schedule of Accounts Payable and Accrued Liabilities [Table Text Block]	At December 31, 2019 and 2018, the components of accounts payable and accrued expenses consisted of: 2019 2018 Trade Payables including accruals 3,107,012 2,589,518 Direct working interest investors related accruals 1,811,649 1,223,588 Current drilling efforts accrued expenses 508,246 413,701 Accrued Liabilities 393,245 391,641 Employee related accruals 195,998 232,010 Deferred rent 14,884 32,752 Federal and State income taxes payable - 12,323 6,031,034 4,895,533

MERGER WITH MATRIX OIL MANAGE_2

MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Tables)	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]	The following table summarizes the consideration transferred, fair value of assets acquired and liabilities assumed: March 7, 2018 Consideration: Value of Royale Common Stock issued $ 9,546,068 Value of Series B Convertible Preferred Stock issued 20,124,000 Total consideration $ 29,670,068 Fair Value of Liabilities Assumed: Current liabilities 19,624,592 Other liabilities 3,125,394 Asset Retirement obligations 1,419,544 Total fair value of liabilities assumed 24,169,530 Total consideration plus liabilities assumed $ 53,839,598 Fair Value of Assets Acquired: Cash $ 548,805 Current assets 1,073,532 Proved and unproved crude oil and gas properties 51,214,512 Land 1,002,750 Total Fair Value of Assets Acquired $ 53,839,598
Business Acquisition, Pro Forma Information [Table Text Block]	In accordance with ASC 805, the following unaudited supplemental pro forma condensed results of operations present combined information as though the business combination had been completed as of January 1, 2018. The unaudited supplemental pro forma financial information was derived from the historical revenues and direct operating expenses of Royale Energy, Inc. and Matrix Oil Management Corporation and its affiliates. These unaudited supplemental pro forma results of operations for the consolidated companies as of December 31, 2018, are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the consolidated company for the periods presented or that may be achieved by the consolidated company in the future. Year ended December 31, 2018 Royale Energy, Inc. Matrix Oil Management Corp Consolidated Revenue $ 723,172 $ 1,199,684 $ 1,922,856 Net Loss $ (1,633,713 ) $ (149,936 ) $ (1,783,649 ) Net Loss available to common shareholders $ (1,633,713 ) $ (149,936 ) $ (1,783,649 ) Pro forma Loss per common share Basic and diluted $ (0.04 ) $ (0.00 ) $ (0.04 )
Business Combination, Separately Recognized Transactions [Table Text Block]	Amounts previously estimated have changed during the measurement period. The changes in estimates included an increase of $2,581,641 million of oil and gas properties and a decrease of $2,581,641 million in accounts receivable and other current assets. We recorded measurement-period adjustments in the fourth quarter of 2018. Depletion expense increased by an immaterial amount as a result of these measurement-period adjustments and all amounts referenced below are inclusive of these measurement period adjustments. As of December 31, 2018, the purchase accounting for the Matrix acquisition was complete. Original Adjustment Revised Cash $ 548,805 $ - $ 548,805 Current Assets $ 3,655,173 $ (2,581,641 ) $ 1,073,532 Oil and gas properties $ 48,632,870 $ 2,581,641 $ 51,214,512
Equity Method Investments [Table Text Block]	Listed below is summarized information the Company’s investment in RMX: Twelve Months Ended December 31, 2019 March 27, 2018 December 31, 2018 RMX Resources, LLC RMX Resources, LLC Balance Sheet: Total Assets $ 72,401,841 $ 71,758,262 Total Liabilities $ 41,573,426 $ 38,838,608 Members Equity $ 30,828,415 $ 32,919,654 Results of Operations: Net operating revenue $ 16,392,305 $ 8,773,661 Loss from operations $ 1,456,290 $ (181,464 ) Net income $ (2,091,239 ) $ 1,669,654

OIL AND GAS PROPERTIES, EQUIP_2

OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 Oil and Gas Producing properties, including intangible drilling costs $ 7,792,156 $ 9,340,779 Undeveloped properties 46,990 25,582 Lease and well equipment 3,304,565 3,350,893 11,143,711 12,717,254 Accumulated depletion, depreciation and amortization (6,559,182 ) (6,402,657 ) Net capitalized costs Total $ 4,584,529 $ 6,314,597 Commercial and Other 2019 2018 Real estate, including furniture and fixtures $ - $ 83,405 Vehicles 40,061 40,061 Furniture and equipment 1,097,428 1,095,149 1,137,489 1,218,615 Accumulated depreciation (1,131,028 ) (1,125,722 ) 6,461 92,893 Net capitalized costs Total $ 4,590,990 $ 6,407,490
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, 2019 2018 Acquisition - Proved $ - $ - Acquisition - Unproved - - Development 9,680,298 3,838,998 Exploration - -
Capitalized Exploratory Well Costs, Roll Forward [Table Text Block]	Undeveloped properties are not subject to depletion, depreciation or amortization. Year ended December 31, 2019 2018 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, 2019 2018 Oil and gas sales $ 2,329,275 $ 1,599,362 Production related costs (Lease Operating) (1,764,538 ) (1,613,368 ) Impairment (977,682 ) (1,183,515 ) Depreciation, depletion and amortization (468,143 ) (722,935 ) Results of operations from producing and exploration activities $ (881,088 ) $ (1,920,456 ) Income Taxes (Benefit) - - Net Results $ (881,088 ) $ (1,920,456 )

ASSET RETIREMENT OBLIGATION (Ta

ASSET RETIREMENT OBLIGATION (Tables)	12 Months Ended
	Dec. 31, 2019
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 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 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. 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 has recorded them as impairment expense at year end 2019. 2019 2018 Asset retirement obligation Beginning of the year $ 2,366,456 $ 1,000,908 Liabilities incurred during the period 210,643 595,583 Settlements - (52,636 ) Merger Additions - 1,419,544 Sales (33,026 ) (486,585 ) Changes in estimates 922,698 - Accretion expense 165,651 (110,358 ) End of year $ 3,632,422 $ 2,366,456

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 and 2018, respectively, are as follows: 2019 2018 Deferred Tax Assets (Liabilities): Statutory Depletion Carry Forward $ 367,149 $ 367,149 Net Operating Loss 6,489,891 7,121,912 Other 595,990 708,057 Share-Based Compensation 86,510 86,510 Capital Loss / AMT Credit Carry Forward 9,458 9,458 Charitable Contributions Carry Forward 3,890 6,158 Allowance for Doubtful Accounts 466,060 597,519 Oil and Gas Properties and Fixed Assets 5,404,787 5,987,061 Investment in RMX Joint Venture (1,238,551 ) (1,247,847 ) Section 481(a) Adjustments (214,859 ) - $ 11,970,325 $ 13,635,977 Valuation Allowance (11,970,325 ) (13,635,977 ) 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, 2019 and 2018, respectively, to pretax income is as follows: 2019 2018 Tax (benefit) computed at statutory rate of 21% at December 31, 2019 and 2018, respectively $ (71,680 ) $ (4,935,909 ) Increase (decrease) in taxes resulting from: Meals & Entertainment 1,583 1,320 Investor Incentive Expense - 7 Transaction Costs - 160,927 Loss on Warrants Issued to RMX - 302,398 Prior-year true-up for Books 1,461,914 2,075,440 Deferred State Taxes, net of federal benefit 214,161 (1,009,601 ) Other non-deductible expenses 59,674 (264,359 ) Change in valuation allowance (1,665,652 ) 3,669,777 Provision (benefit) - -
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	The components of the Company’s tax provision are as follows: 2019 2018 Current tax provision (benefit) - federal $ - $ - Current tax provision (benefit) - state - - Deferred tax provision (benefit) - federal - - Deferred tax provision (benefit) - state - - Total provision (benefit) $ - $ -

IMPLEMENTATION OF ASC 842 - L_2

IMPLEMENTATION OF ASC 842 - LEASE ACCOUNTING (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure Text Block [Abstract]
Lessee, Operating Lease, Disclosure [Table Text Block]	These two leases were initially recorded as operating leases at January 1, 2019 as listed below. Debit/Credit Operating Lease – ROU Asset 483,504 Operating Lease Liability – Current (140,831 ) Operating Lease Liability – Long-Term (342,673 )
Lessee, Financing Lease, Disclosure [Text Block]	In July 2019, we entered into a 60 month agreement with MRC for the leasing of two Xerox machines with monthly payments of $1,049. This lease was initially recorded as a financing lease on July 31, 2019 as listed below: Debit/Credit Financing Lease - ROU Asset 54,655 Financing Lease Liability - Current (9,725 ) Financing Lease Liability - Long-Term (44,930 )
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 Operating lease expense 184,374 Financing lease expense 10,757 Operating – short-term 7,886 Short Term - field 6,000 Total lease expense 209,017
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	The following tables summarized the operating and financing lease obligations. Lease Obligations Operating Financing Total 2020 173,809 12,588 186,397 2021 179,630 12,588 192,218 2022 24,408 12,588 36,996 Thereafter - 19,931 19,931 Total undiscounted lease payments $ 377,847 57,695 435,542 Less: Amount representing interest 35,174 7,025 42,199 Total Operating & Financing lease liabilities $ 342,673 50,670 393,343 Long-term lease liabilities as of December 31, 2019 $ 152,314 9,958 162,272 Long-term lease liabilities as of December 31, 2019 $ 190,359 40,712 231,071

STOCK COMPENSATION PLAN (Tables

STOCK COMPENSATION PLAN (Tables)	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Share-based Payment Arrangement, Option, Activity [Table Text Block]	A summary of the status of Royale Energy’s stock option plan as of December 31, 2019 and 2018, and changes during the years ending on those dates is presented below: 2019 2018 Weighted- Weighted- Average Average Exercise Exercise Shares Price Shares Price Options Outstanding and Exercisable at Beginning of Year 250,000 $ 0.31 - Granted or Vested - 250,000 $ 0.31 Exercised - - Forfeited - - Options Outstanding and Exercisable at Year End 250,000 $ 0.31 250,000 $ 0.31 Weighted-average Fair Value of Options Granted During the Year $ - $ 64,954

SUPPLEMENTAL INFORMATION ABOU_2

SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 and 2018, and changes in such quantities during each of the years then ended, were as follows: Total Proved Reserves 2019 2018 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Beginning of period 1,146,400 2,986,200 202 2,132,221 Revisions of previous estimates 1,052,086 (890,032 ) (79,136 ) (401,498 ) Production (27,663 ) (292,472 ) (20,329 ) (135,396 ) Extensions, discoveries and improved recovery 22,042 2,516,046 - 25,014 Merger Acquisition - - 11,375,784 13,459,933 Purchase of minerals in place - - 29,300 116,110 Sales of minerals in place (21,865 ) (12,842 ) (10,159,421 ) (12,210,184 ) Proved reserves end of period 2,171,000 4,306,900 1,146,400 2,986,200 Proved Developed 2019 2018 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed reserves: Beginning of period 148,600 1,914,900 202 1,798,697 End of period 232,200 2,790,300 148,600 1,914,900 Proved Undeveloped 2019 2018 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved undeveloped reserves: Beginning of period 997,800 1,071,300 - 333,524 End of period 1,938,800 1,516,600 997,800 1,071,300 Total Proved Reserves 2019 2018 Net to Royale (20%) Net to Royale (20%) Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed and undeveloped reserves: Beginning of period – 4,219,140 4,378,060 3,739,820 4,403,654 Revisions of previous estimates (188,726 ) (3,388,497 ) - - Production (49,894 ) (23,023 ) (41,240 ) (25,594 ) Extensions, discoveries and improved recovery - - - - Purchase of minerals in place - - 520,560 - Sales of minerals in place - - - - Proved reserves end of period 3,980,520 966,540 4,219,140 4,378,060 Proved Developed Net to Royale (20%) Net to Royale (20%) Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed reserves: Beginning of period – (2018 at formation of RMX) 993,080 635,180 791,073 660,774 End of period 1,186,080 653,920 993,080 635,180 Proved Undeveloped Net to Royale (20%) Net to Royale (20%) Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved undeveloped reserves: Beginning of period – (2018 at formation of RMX) 3,226,060 3,742,880 2,917,721 3,742,880 End of period 2,794,440 312,620 3,226,060 3,742,880
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, 2019 2018 Acquisition - Proved $ - $ - Acquisition - Unproved - - Development 9,680,298 3,838,998 Exploration - -
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block]	2019 2018 Future cash inflows 143,045,000 87,467,200 Future production costs (28,967,400 ) (22,390,900 ) Future development costs (20,587,800 ) (7,256,900 ) Future income tax expense (28,046,940 ) (17,345,820 ) Future net cash flows 65,442,860 40,473,580 10% annual discount for estimated timing of cash flows (35,801,989 ) (9,827,666 ) Standardized measure of discounted future net cash flows 29,640,871 30,645,914 Sales of oil and gas produced, net of production costs (624,744 ) (40,557 ) Revisions of previous quantity estimates 14,035,099 (71,162 ) Net changes in prices and production costs (14,331,770 ) 11,683,159 Sales of minerals in place (272,507 ) (3,061,278 ) Purchases of minerals in place - 287,300 Merger Acquisition - 29,903,670 Extensions, discoveries and improved recovery 2,157,052 59,191 Accretion of discount 2,900,123 2,670,000 Net change in income tax (4,868,296 ) (12,429,097 ) Net increase (decrease) (1,005,043 ) 29,001,226 2019 2018 Net to Royale Net to Royale Future cash inflows 247,894,600 305,586,180 Future production costs (72,400,860 ) (84,222,980 ) Future development costs (22,142,340 ) (28,801,620 ) Future income tax expense (46,005,420 ) - Future net cash flows 107,345,980 192,561,580 10% annual discount for estimated timing of cash flows (61,882,856 ) (118,962,940 ) Standardized measure of discounted future net cash flows 45,463,124 73,598,640 Sales of oil and gas produced, net of production costs (1,308,378 ) (810,635 ) Formation of RMX Joint Venture - 60,282,536 Net changes in prices and production costs and revisions of previous quantity estimates (14,702,806 ) - Sales of minerals in place - - Purchases of minerals in place - 8,673,117 Extensions, discoveries and improved recovery - - Accretion of discount 7,359,864 5,453,622 Net change in income tax (19,484,196 ) - Net increase (decrease) (28,135,516 ) 73,598,640
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: 2020 $ 10,331,900 2021 4,500,000 2022 4,511,800 Thereafter 1,244,100 Total $ 20,587,800
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]	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 ten 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. Future development cost of: 2020 2021 2022 Proved developed reserves (PDP) $ - $ - $ - Proved non-producing reserves (PDNP) 126,900 - 11,800 Proved undeveloped reserves (PUD) 10,205,000 4,500,000 4,500,000 Total $ 10,331,900 $ 4,500,000 $ 4,511,800

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - USD ($)	Aug. 02, 2017	Jan. 01, 2016	Dec. 31, 2019	Dec. 31, 2018
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Working Capital (Deficit)			$ (3,425,012)
Operating Income (Loss)			(845,071)	$ (3,204,056)
Revenues			2,967,183	3,283,041
Impairment of Oil and Gas Properties			977,682	1,183,515
Contract with Customer, Liability, Current			5,232,675	6,213,283
Accounts Receivable, Allowance for Credit Loss			1,791,162	$ 2,296,384
Accounts Receivable, Allowance for Credit Loss, Writeoff			$ 519,333
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount (in Shares)			23,947,519	24,049,443
Other Accrued Liabilities, Noncurrent			$ 1,306,605	$ 1,306,605
Other Liabilities, Noncurrent			1,616,205	1,616,205
Debt Instrument, Face Amount	$ 1,580,000
Debt Conversion, Original Debt, Amount			$ 0	408,800
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
Services related to Master Service Agreement with RMX [Member]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Revenues				1,620,000
Supervisory, Services [Member]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Revenues			$ 540,000
Convertible Notes Payable [Member]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Debt Instrument, Term	1 year
Convertible Notes Payable [Member] | Notes Entered into Negotiations [Member]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Debt Instrument, Debt Default, Rate	25.00%
Convertible Notes Payable [Member] | Note #2 Entered into Negotiations [Member]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Debt Conversion, Original Debt, Amount				$ 300,000
Debt Conversion, Converted Instrument, Shares Issued (in Shares)				750,000
Convertible Notes Payable [Member] | Note #1 Entered into Negotiations [Member]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Debt Instrument, Face Amount				$ 1,280,000
Repayments of Debt		$ 1,900,000
RMX Joint Venture [Member] | Customer Concentration Risk [Member] | Revenue Benchmark [Member]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Concentration Risk, Percentage				49.30%
RMX Joint Venture [Member] | Supervisory, Services [Member] | Customer Concentration Risk [Member] | Revenue Benchmark [Member]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Concentration Risk, Percentage				100.00%

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - Schedule of Cash and Cash Equivalents - USD ($)	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Schedule of Cash and Cash Equivalents [Abstract]
Cash and cash equivalents	$ 1,031,014	$ 1,853,742
Restricted cash	2,845,515	4,501,300
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows	$ 3,876,529	$ 6,355,042	$ 3,338,693

SUMMARY OF SIGNIFICANT ACCOUN_5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - Disaggregation of Revenue - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Oil [Member]
Disaggregation of Revenue [Line Items]
Revenues	$ 1,504,936	$ 1,211,818
Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenues	824,339	385,803
Natural Gas Liquids [Member]
Disaggregation of Revenue [Line Items]
Revenues	0	1,741
Natural Gas Liquids [Member] | Oil and Gas [Member]
Disaggregation of Revenue [Line Items]
Revenues	$ 2,329,275	$ 1,599,362

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, 2019	Dec. 31, 2018
Schedule of Earnings Per Share, Basic and Diluted [Abstract]
Net Loss	$ (348,383)	$ (23,504,327)
Less: Preferred Stock Dividend	734,725	594,613
Less: Preferred Stock Dividend in Arrears	0	0
Net Loss Attributable to Common Shareholders	$ (1,083,108)	$ (24,098,940)
Weighted average common shares outstanding (in Shares)	50,871,447	44,174,209
Weighted average common shares outstanding (in Shares)	50,871,447	44,174,209
Effect of dilutive securities	$ 0	$ 0
Effect of dilutive securities (in Shares)	0	0
Weighted average common shares, including Dilutive effect (in Shares)	50,871,447	44,174,209
Weighted average common shares, including Dilutive effect (in Shares)	50,871,447	44,174,209
Net Loss (in Dollars per share)	$ (0.02)	$ (0.55)
Net Loss (in Dollars per share)	$ (0.02)	$ (0.55)

SUMMARY OF SIGNIFICANT ACCOUN_7

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - Schedule of Accounts Payable and Accrued Liabilities - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Schedule of Accounts Payable and Accrued Liabilities [Abstract]
Trade Payables including accruals	$ 3,107,012	$ 2,589,518
Direct working interest investors related accruals	1,811,649	1,223,588
Current drilling efforts accrued expenses	508,246	413,701
Accrued Liabilities	393,245	391,641
Employee related taxes and accruals	195,998	232,010
Deferred rent	14,884	32,752
Federal and State income taxes payable	0	12,323
	$ 6,031,034	$ 4,895,533

MERGER WITH MATRIX OIL MANAGE_3

MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details)	Apr. 30, 2018USD ($)shares	Mar. 07, 2018USD ($)shares	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Mar. 11, 2019USD ($)Boe
MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) [Line Items]
Stock Issued During Period, Shares, New Issues (in Shares) | shares		2,012,400
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment		$ 51,214,512		$ 51,214,512
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets		1,073,532
Cash Acquired from Acquisition			$ 0	548,805
Business Combination, Consideration Transferred		29,670,068
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves			29,640,871	30,645,914
Gain (Loss) on Disposition of Assets			(155,048)	(19,199,045)
Gain (Loss) on Extinguishment of Debt			1,254,204
Bellevue Field [Member]
MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (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]
MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (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]
MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) [Line Items]
Equity Method Investment, Ownership Percentage	20.00%
Equity Method Investments	$ 6,250,000
Gain (Loss) on Investments	17,900,000
Gain (Loss) on Issuance of Warrants	(1,440,000)
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Consideration Transferred	334,000
Supervisory Fees, Service Agreements, and Other				180,000
Gain (Loss) on Disposition of Assets			$ 1,237,126
RMX Resources, LLC [Member] | Maximum [Member]
MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) [Line Items]
Cash Acquired from Acquisition	20,000,000
RMX Resources, LLC [Member] | Matrix Oil Corporation (“MOC”) [Member]
MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) [Line Items]
Due from Affiliates	$ 640,000
Scenario, Adjustment [Member]
MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment				2,581,641
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets				(2,581,641)
Matrix Investments [Member]
MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) [Line Items]
Limited Partners' Capital Account		$ 20,124,000
CIC RMX LP [Member] | Legacy Bank Texas [Member]
MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				25,000,000
Line of Credit Facility, Remaining Borrowing Capacity				$ 19,403,800
CIC RMX LP [Member] | RMX Resources, LLC [Member]
MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (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
Equity Method Investments	$ 25,000,000
The Royal Entities [Member] | RMX Resources, LLC [Member]
MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) [Line Items]
Business Combination, Consideration Transferred	$ 4,000,000
Working Interest	20.00%
The Royal Entities [Member] | RMX Resources, LLC [Member] | Sansinena Field [Member]
MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) [Line Items]
Contribution of Property Percentage	100.00%
The Royal Entities [Member] | RMX Resources, LLC [Member] | Sempra Field [Member]
MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) [Line Items]
Contribution of Property Percentage	100.00%
The Royal Entities [Member] | RMX Resources, LLC [Member] | Bellevue Field [Member]
MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) [Line Items]
Contribution of Property Percentage	50.00%
The Royal Entities [Member] | RMX Resources, LLC [Member] | Whittier Main Field [Member]
MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) [Line Items]
Contribution of Property Percentage	100.00%
The Royal Entities [Member] | RMX Resources, LLC [Member] | Whittier Field [Member]
MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) [Line Items]
Contribution of Property Percentage	50.00%

MERGER WITH MATRIX OIL MANAGE_4

MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) - Schedule of Recognized Identified Assets Acquired and Liabilities Assumed - USD ($)	Mar. 07, 2018	Dec. 31, 2018
Consideration:
Value of Stock issued	$ 9,546,068
Total consideration	29,670,068
Fair Value of Liabilities Assumed:
Current liabilities	19,624,592
Other liabilities	3,125,394
Asset Retirement obligations	1,419,544
Total fair value of liabilities assumed	24,169,530
Cash	548,805	$ 548,805
Current assets	1,073,532
Proved and unproved crude oil and gas properties	51,214,512	$ 51,214,512
Land	1,002,750
Total consideration plus liabilities assumed	53,839,598
Series B Preferred Stock [Member]
Consideration:
Value of Stock issued	$ 20,124,000

MERGER WITH MATRIX OIL MANAGE_5

MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) - Business Acquisition, Pro Forma Information	12 Months Ended
	Dec. 31, 2018USD ($)$ / shares
MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) - Business Acquisition, Pro Forma Information [Line Items]
Revenue	$ 1,922,856
Net Loss	(1,783,649)
Net Loss available to common shareholders	$ (1,783,649)
Pro forma Loss per common share Basic and diluted (in Dollars per share) | $ / shares	$ (0.04)
Parent [Member]
MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) - Business Acquisition, Pro Forma Information [Line Items]
Revenue	$ 723,172
Net Loss	(1,633,713)
Net Loss available to common shareholders	$ (1,633,713)
Pro forma Loss per common share Basic and diluted (in Dollars per share) | $ / shares	$ (0.04)
Matrix Oil Management Corp [Member]
MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) - Business Acquisition, Pro Forma Information [Line Items]
Revenue	$ 1,199,684
Net Loss	(149,936)
Net Loss available to common shareholders	$ (149,936)
Pro forma Loss per common share Basic and diluted (in Dollars per share) | $ / shares	$ 0

MERGER WITH MATRIX OIL MANAGE_6

MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) - Business Combination, Separately Recognized Transactions - USD ($)	Dec. 31, 2018	Mar. 07, 2018
Business Combination, Separately Recognized Transactions [Line Items]
Cash	$ 548,805	$ 548,805
Current assets	1,073,532
Oil and gas properties	51,214,512	$ 51,214,512
Previously Reported [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Cash	548,805
Current assets	3,655,173
Oil and gas properties	48,632,870
Scenario, Adjustment [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Current assets	(2,581,641)
Oil and gas properties	$ 2,581,641

MERGER WITH MATRIX OIL MANAGE_7

MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) - Equity Method Investments - USD ($)	9 Months Ended	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018
Schedule of Equity Method Investments [Line Items]
Total Assets	$ 21,759,388	$ 20,590,627	$ 21,759,388
Total Liabilities	20,272,634	18,923,630	20,272,634
Net Operating Revenue		2,967,183	3,283,041
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)
RMX Resources, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Total Assets	71,758,262		71,758,262
Total Liabilities	38,838,608		38,838,608
Members Equity	32,919,654		$ 32,919,654
Net Operating Revenue	8,773,661
Loss from Continuing Operations	(181,464)
Net Loss	$ 1,669,654

OIL AND GAS PROPERTIES, EQUIP_3

OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Details) - Schedule of Property, Plant and Equipment - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Oil and Gas
Producing properties, including intangible drilling costs	$ 7,792,156	$ 9,340,779
Undeveloped properties	46,990	25,582
Lease and well equipment	3,304,565	3,350,893
Oil and gas, gross	11,143,711	12,717,254
Accumulated depletion, depreciation and amortization	(6,559,182)	(6,402,657)
Oil and gas, net	4,584,529	6,314,597
Property, Plant and Equipment, Gross	1,137,489	1,218,615
Accumulated depreciation	(1,131,028)	(1,125,722)
Property, Plant and Equipment, Net	6,461	92,893
Oil and gas properties, equipment and fixtures	4,590,990	6,407,490
Land [Member]
Oil and Gas
Property, Plant and Equipment, Gross	0	83,405
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	$ 1,095,149

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, 2019	Dec. 31, 2018
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Abstract]
Acquisition - Proved	$ 0	$ 0
Acquisition - Unproved	0	0
Development	9,680,298	3,838,998
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, 2019	Dec. 31, 2018
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, 2019	Dec. 31, 2018
Results of Operations for Oil and Gas Producing Activities Disclosure [Abstract]
Oil and gas sales	$ 2,329,275	$ 1,599,362
Production related costs (Lease Operating)	(1,764,538)	(1,613,368)
Impairment	(977,682)	(1,183,515)
Depreciation, depletion and amortization	(468,143)	(722,935)
Results of operations from producing and exploration activities	(881,088)	(1,920,456)
Income Taxes (Benefit)	0	0
Net Results	$ (881,088)	$ (1,920,456)

ASSET RETIREMENT OBLIGATION (De

ASSET RETIREMENT OBLIGATION (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation, Revision of Estimate	$ 922,698	$ 0

ASSET RETIREMENT OBLIGATION (D

ASSET RETIREMENT OBLIGATION (Details) - Schedule of Change in Asset Retirement Obligation - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Asset retirement obligation
Beginning of the year	$ 2,366,456	$ 1,000,908
Liabilities incurred	210,643	595,583
Sales	(33,026)	(486,585)
Changes in estimates	922,698	0
Accretion expense	165,651	(110,358)
End of year	3,632,422	2,366,456
Settlements	0	(52,636)
RMX Resources, LLC [Member]
Asset retirement obligation
Liabilities incurred		$ 1,419,544

NOTES PAYABLE (Details)

NOTES PAYABLE (Details) - USD ($)	Oct. 03, 2018	Dec. 31, 2019	Dec. 31, 2018	Aug. 02, 2017
NOTES PAYABLE (Details) [Line Items]
Debt Instrument, Face Amount				$ 1,580,000
Notes Payable		$ 55,573	$ 390,839
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

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	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)	$ 22.9
Operating Loss Carryforwards, Expiration Date	2024
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, 2019	Dec. 31, 2018
Schedule of Deferred Tax Assets and Liabilities [Abstract]
Statutory Depletion Carry Forward	$ 367,149	$ 367,149
Net Operating Loss	6,489,891	7,121,912
Other	595,990	708,057
Share-Based Compensation	86,510	86,510
Capital Loss / AMT Credit Carry Forward	9,458	9,458
Charitable Contributions Carry Forward	3,890	6,158
Allowance for Doubtful Accounts	466,060	597,519
Oil and Gas Properties and Fixed Assets	5,404,787	5,987,061
Investment in RMX Joint Venture	(1,238,551)	(1,247,847)
Section 481(a) Adjustments	(214,859)	0
	11,970,325	13,635,977
Valuation Allowance	(11,970,325)	(13,635,977)
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, 2019	Dec. 31, 2018
Schedule of Effective Income Tax Rate Reconciliation [Abstract]
Tax (benefit) computed at statutory rate of 21% at December 31, 2019 and 2018, respectively	$ (71,680)	$ (4,935,909)
Meals & Entertainment	1,583	1,320
Investor Incentive Expense	0	7
Transaction Costs	0	160,927
Loss on Warrants Issued to RMX	0	302,398
Prior-year true-up for Books	1,461,914	2,075,440
Deferred State Taxes, net of federal benefit	214,161	(1,009,601)
Other non-deductible expenses	59,674	(264,359)
Change in valuation allowance	(1,665,652)	3,669,777
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, 2019	Dec. 31, 2018
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, 2019	Dec. 31, 2018
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, 2019	Dec. 31, 2018	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		73,473	59,461
Dividends, Preferred Stock, Paid-in-kind (in Dollars)		$ 734,725	$ 594,613

COMMON STOCK (Details)

COMMON STOCK (Details)	Apr. 13, 2018$ / sharesshares	Mar. 07, 2018shares	Jul. 31, 2016USD ($)$ / sharesshares	Apr. 30, 2016USD ($)$ / sharesshares
COMMON STOCK (Details) [Line Items]
Stock Issued During Period, Shares, New Issues		2,012,400
Number of Subsidiaries	2
Securities Purchase Agreement [Member]
COMMON STOCK (Details) [Line Items]
Number of Investors			3	1
Stock Issued During Period, Shares, New Issues			2,392,500	622,316
Shares Issued, Price Per Share | $ / shares			$ 0.40	$ 0.3214
Class of Warrant or Right, Number of Securities Called by Warrants or Rights			478,500	311,158
Class of Warrant or Right, Exercise Price of Warrants or Rights | $ / shares			$ 0.80	$ 0.5356
Warrant Term			2 years	3 years
Proceeds from Issuance or Sale of Equity | $			$ 957,000	$ 200,000
Class Of Warrant or Rights Granted	4,000,000
Securities Purchase Agreement [Member] | Measurement Input, Exercise Price [Member]
COMMON STOCK (Details) [Line Items]
Class of Warrant or Right, Exercise Price of Warrants or Rights | $ / shares	$ 0.01

IMPLEMENTATION OF ASC 842 - L_3

IMPLEMENTATION OF ASC 842 - LEASE ACCOUNTING (Details)	12 Months Ended
	Dec. 31, 2019USD ($)
IMPLEMENTATION OF ASC 842 - LEASE ACCOUNTING (Details) [Line Items]
Lessee, Operating Lease, Description	These two leases were initially recorded as operating leases at January 1, 2019 as listed below.
San Diego, CA [Member]
IMPLEMENTATION OF ASC 842 - LEASE ACCOUNTING (Details) [Line Items]
Operating Leases, Rent Expense, Minimum Rentals	$ 6,148
Santa Barbara [Member]
IMPLEMENTATION OF ASC 842 - LEASE ACCOUNTING (Details) [Line Items]
Operating Leases, Rent Expense, Minimum Rentals	$ 5,086
Office Equipment [Member]
IMPLEMENTATION OF ASC 842 - LEASE ACCOUNTING (Details) [Line Items]
Lessee, Finance Lease, Term of Contract	60 years
Finance Lease, Principal Payments	$ 1,049

IMPLEMENTATION OF ASC 842 - L_4

IMPLEMENTATION OF ASC 842 - LEASE ACCOUNTING (Details) - Lessee, Operating Lease, Disclosure - USD ($)	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Lessee, Operating Lease, Disclosure [Abstract]
Operating Lease – ROU Asset	$ 392,774	$ 483,504	$ 0
Operating Lease Liability – Current	(152,314)	(140,831)
Operating Lease Liability – Long-Term	$ (190,359)	$ (342,673)

IMPLEMENTATION OF ASC 842 - L_5

IMPLEMENTATION OF ASC 842 - LEASE ACCOUNTING (Details) - Lessee Financing Lease Disclosure - USD ($)	Dec. 31, 2019	Jul. 31, 2019
Lessee Financing Lease Disclosure [Abstract]
Financing Lease - ROU Asset		$ 54,655
Financing Lease Liability - Current	$ (9,958)	(9,725)
Financing Lease Liability - Long-Term	$ (40,712)	$ (44,930)

IMPLEMENTATION OF ASC 842 - L_6

IMPLEMENTATION OF ASC 842 - LEASE ACCOUNTING (Details) - Lease, Cost	12 Months Ended
	Dec. 31, 2019USD ($)
Lease, Cost [Abstract]
Operating lease expense	$ 184,374
Financing lease expense	10,757
Operating – short-term	7,886
Short Term - field	6,000
Total lease expense	$ 209,017

IMPLEMENTATION OF ASC 842 - L_7

IMPLEMENTATION OF ASC 842 - LEASE ACCOUNTING (Details) - Lessee, Operating Lease, Liability, Maturity - USD ($)	12 Months Ended
	Dec. 31, 2019	Jul. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Lessee, Operating Lease, Liability, Maturity [Abstract]
2020	$ 173,809
2020	12,588
2020	186,397
2021	179,630
2021	12,588
2021	192,218
2022	24,408
2022	12,588
2022	36,996
Thereafter	0
Thereafter	19,931
Thereafter	19,931
Total undiscounted lease payments	377,847
Total undiscounted lease payments	57,695
Total undiscounted lease payments	435,542
Less: Amount representing interest	35,174
Less: Amount representing interest	7,025
Less: Amount representing interest	42,199
Total Operating & Financing lease liabilities	342,673
Total Operating & Financing lease liabilities	50,670
Total Operating & Financing lease liabilities	393,343
Current portion of long-term liabilities as September 30, 2019	152,314		$ 140,831
Current portion of long-term liabilities as September 30, 2019	9,958	$ 9,725
Current portion of long-term liabilities as September 30, 2019	162,272			$ 0
Long-term lease liabilities as of September 30, 2019	190,359		$ 342,673
Long-term lease liabilities as of September 30, 2019	40,712	$ 44,930
Long-term lease liabilities as of September 30, 2019	$ 231,071			$ 0

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details)	12 Months Ended
	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	$ 15,524
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	$ 3,441
RMX Resources, LLC [Member]
RELATED PARTY TRANSACTIONS (Details) [Line Items]
Due to Related Parties	32,367
Prepaid Expense and Other Assets	2,680,155
Chief Executive Officer [Member]
RELATED PARTY TRANSACTIONS (Details) [Line Items]
Due to Related Parties	22,107
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

STOCK COMPENSATION PLAN (Detail

STOCK COMPENSATION PLAN (Details) - USD ($)	Oct. 10, 2018	Dec. 31, 2019	Dec. 31, 2018
STOCK COMPENSATION PLAN (Details) [Line Items]
Share-based Compensation Arrangements by Share-based Payment Award, Options, Grants in Period, Weighted Average Exercise Price	$ 0.31		$ 0.31
Share Price	$ 0.34	$ 0.11
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	3.22%
Share-based Goods and Nonemployee Services Transaction, Valuation Method, Expected Term	10 years
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate	66.48%
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 0.26		$ 64,954
Share-based Payment Arrangement, Expense (in Dollars)		$ 528,626	$ 64,954
Share-based Payment Arrangement, Option [Member]
STOCK COMPENSATION PLAN (Details) [Line Items]
Share-based Payment Arrangement, Expense (in Dollars)		$ 0	$ 64,954
Share-based Payment Arrangement, Option [Member] | Chief Financial Officer [Member]
STOCK COMPENSATION PLAN (Details) [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures (in Shares)	250,000
Share-based Compensation Arrangements by Share-based Payment Award, Options, Grants in Period, Weighted Average Exercise Price	$ 0.31
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period	10 years

STOCK COMPENSATION PLAN (Detai

STOCK COMPENSATION PLAN (Details) - Schedule of Share-based Compensation, Stock Options, Activity - $ / shares	Oct. 10, 2018	Dec. 31, 2019	Dec. 31, 2018
Schedule of Share-based Compensation, Stock Options, Activity [Abstract]
Outstanding and Exercisable, Shares		250,000	0
Outstanding and Exercisable, Weighted Average Exercise Price (in Dollars per share)		$ 0.31
Weighted-average Fair Value of Options Granted During the Year (in Dollars per share)	$ 0.26		$ 64,954
Granted or Vested, Shares		0	250,000
Granted or Vested, Weighted Average Exercise Price (in Dollars per share)	$ 0.31		$ 0.31
Exercised, Shares		0	0
Forfeited, Shares		0	0
Outstanding and Exercisable, Shares		250,000	250,000
Outstanding and Exercisable, Weighted Average Exercise Price (in Dollars per share)		$ 0.31	$ 0.31

SIMPLE IRA PLAN (Details)

SIMPLE IRA PLAN (Details) - Pension Plan [Member] - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
SIMPLE IRA PLAN (Details) [Line Items]
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	3.00%
Defined Contribution Plan, Cost	$ 30,336	$ 35,312

CONCENTRATIONS (Details)

CONCENTRATIONS (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
CONCENTRATIONS (Details) [Line Items]
Cash, FDIC Insured Amount	$ 250,000
Cash, Uninsured Amount	$ 3,400,000	$ 5,700,000
Customer Concentration Risk [Member] | Customer A [Member] | Revenue Benchmark [Member]
CONCENTRATIONS (Details) [Line Items]
Concentration Risk, Percentage	32.00%

SUPPLEMENTAL INFORMATION ABOU_3

SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details)	12 Months Ended
	Dec. 31, 2019USD ($)Mcfbbl	Dec. 31, 2018USD ($)$ / Mcf$ / bblMcfbbl
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Oil and Gas Property, Successful Effort Method	$ 7,792,156	$ 9,340,779
RMX Resources, LLC [Member]
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	20.00%
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	(890,032)	(401,498)
Oil [Member]
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | bbl	1,052,086	(79,136)
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		$ 57,800,000
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		3.10
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		65.56

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, 2019Mcfbbll	Dec. 31, 2018Mcfbbl
Oil [Member]
Reserve Quantities [Line Items]
Beginning of period	1,146,400	202
Revisions of previous estimates	1,052,086	(79,136)
Production	(27,663)	(20,329)
Extensions, discoveries and improved recovery	22,042
Merger Acquisition		11,375,784
Purchase of minerals in place		29,300
Sales of minerals in place	(21,865)	(10,159,421)
Proved reserves end of period	2,171,000	1,146,400
Beginning of period	148,600	202
End of period	232,200	148,600
Beginning of period	997,800
End of period	1,938,800	997,800
Oil [Member] | The 20% Interest in RMX [Member]
Reserve Quantities [Line Items]
Beginning of period	3,739,820
Production	(41,240)
Purchase of minerals in place	520,560
Proved reserves end of period	4,219,140	3,739,820
Beginning of period	791,073
End of period	993,080	791,073
Beginning of period	2,917,721
End of period	3,226,060	2,917,721
Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning of period | Mcf	2,986,200	2,132,221
Revisions of previous estimates | Mcf	(890,032)	(401,498)
Production | Mcf	(292,472)	(135,396)
Extensions, discoveries and improved recovery | Mcf	2,516,046	25,014
Merger Acquisition | Mcf		13,459,933
Purchase of minerals in place | Mcf		116,110
Sales of minerals in place | Mcf	(12,842)	(12,210,184)
Proved reserves end of period | Mcf	4,306,900	2,986,200
Beginning of period | Mcf	1,914,900	1,798,697
End of period | Mcf	2,790,300	1,914,900
Beginning of period | Mcf	1,071,300	333,524
End of period | Mcf	1,516,600	1,071,300
Natural Gas [Member] | The 20% Interest in RMX [Member]
Reserve Quantities [Line Items]
Beginning of period | Mcf	4,403,654
Production | Mcf	(25,594)
Proved reserves end of period | Mcf	4,378,060	4,403,654
Beginning of period | Mcf	660,774
End of period | Mcf	635,180	660,774
Beginning of period | Mcf	3,742,880
End of period | Mcf	3,742,880	3,742,880
RMX Resources, LLC [Member] | Oil [Member]
Reserve Quantities [Line Items]
Beginning of period	4,219,140
Revisions of previous estimates | l	(188,726)
Production	(49,894)
Proved reserves end of period	3,980,520	4,219,140
Beginning of period	993,080
End of period	1,186,080	993,080
Beginning of period	3,226,060
End of period	2,794,440	3,226,060
RMX Resources, LLC [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning of period | Mcf	4,378,060
Revisions of previous estimates | l	(3,388,497)
Production | Mcf	(23,023)
Proved reserves end of period | Mcf	966,540	4,378,060
Beginning of period | Mcf	635,180
End of period | Mcf	653,920	635,180
Beginning of period | Mcf	3,742,880
End of period | Mcf	312,620	3,742,880

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, 2019USD ($)
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
2020	$ 10,331,900
2021	4,500,000
2022	4,511,800
Thereafter	1,244,100
Total	$ 20,587,800

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, 2019	Dec. 31, 2018
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Line Items]
Future cash inflows	$ 143,045,000	$ 87,467,200
Future production costs	(28,967,400)	(22,390,900)
Future development costs	(20,587,800)	(7,256,900)
Future income tax expense	(28,046,940)	(17,345,820)
Future net cash flows	65,442,860	40,473,580
10% annual discount for estimated timing of cash flows	(35,801,989)	(9,827,666)
Standardized measure of discounted future net cash flows	29,640,871	30,645,914
Sales of oil and gas produced, net of production costs	(624,744)	(40,557)
Formation of RMX joint venture	0	6,250,000
Revisions of previous quantity estimates	14,035,099	(71,162)
Net changes in prices and production costs	(14,331,770)	11,683,159
Sales of minerals in place	(272,507)	(3,061,278)
Purchases of minerals in place	0	287,300
Merger Acquisition	0	29,903,670
Extensions, discoveries and improved recovery	2,157,052	59,191
Accretion of discount	2,900,123	2,670,000
Net change in income tax	(4,868,296)	(12,429,097)
Net increase (decrease)	(1,005,043)	29,001,226
The 20% Interest in RMX [Member]
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Line Items]
Future cash inflows		305,586,180
Future production costs		(84,222,980)
Future development costs		(28,801,620)
Future income tax expense		0
Future net cash flows		192,561,580
10% annual discount for estimated timing of cash flows		(118,962,940)
Standardized measure of discounted future net cash flows		73,598,640
Sales of oil and gas produced, net of production costs		(810,635)
Formation of RMX joint venture		60,282,536
Revisions of previous quantity estimates		0
Sales of minerals in place		0
Purchases of minerals in place		8,673,117
Extensions, discoveries and improved recovery		0
Accretion of discount		5,453,622
Net change in income tax		0
Net increase (decrease)		$ 73,598,640
RMX Resources, LLC [Member]
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Line Items]
Future cash inflows	247,894,600
Future production costs	(72,400,860)
Future development costs	(22,142,340)
Future income tax expense	(46,005,420)
Future net cash flows	107,345,980
10% annual discount for estimated timing of cash flows	(61,882,856)
Standardized measure of discounted future net cash flows	45,463,124
Sales of oil and gas produced, net of production costs	(1,308,378)
Formation of RMX joint venture	0
Revisions of previous quantity estimates	(14,702,806)
Sales of minerals in place	0
Purchases of minerals in place	0
Extensions, discoveries and improved recovery	0
Accretion of discount	7,359,864
Net change in income tax	(19,484,196)
Net increase (decrease)	$ (28,135,516)

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, 2019USD ($)
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	126,900
Estimated Future Costs, Year 2	0
Estimated Future Costs, Year 3	11,800
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	10,205,000
Estimated Future Costs, Year 2	4,500,000
Estimated Future Costs, Year 3	4,500,000
Proved Developed, Proved Non-Producing and Proved Undeveloped Reserves [Member]
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Future Development Costs, Oil and Gas Production [Line Items]
Estimated Future Costs, Year 1	10,331,900
Estimated Future Costs, Year 2	4,500,000
Estimated Future Costs, Year 3	$ 4,511,800