Royale Energy (ROYL) 10-K 16 Apr 19 2018 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Apr. 10, 2019	Jun. 30, 2018
Document and Entity Information [Abstract]
Entity Registrant Name	Royale Energy, Inc.
Document Type	10-K
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		50,411,353
Entity Public Float			$ 12,074,673
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, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Ex Transition Period	false

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Current Assets:
Cash and Cash equivalents	$ 1,853,742	$ 278,227
Restricted Cash	4,501,300	3,060,466
Other Receivables, net	1,411,144	764,015
Revenue Receivables	316,974	106,007
Prepaid Expenses and Other Current Assets	174,852	149,367
Total Current Assets	8,258,012	4,358,082
Investment in Joint Venture	6,583,931	0
Other Assets	509,955	511,120
Oil and Gas Properties (Successful Efforts Basis), Real Property and Equipment and Fixtures, net	6,407,490	1,302,242
Total Assets	21,759,388	6,171,444
Current Liabilities:
Accounts Payable and Accrued Expenses	4,895,533	4,638,879
Cash Advances on Pending Transactions	0	1,580,000
Royalties Payable	1,676,865	0
Notes Payable	390,839	0
Due RMX Resources, LLC	552,645	0
Accrued Liabilities	1,254,204	0
Deferred Drilling Obligations	6,213,283	5,891,898
Total Current Liabilities	14,983,369	12,110,777
Noncurrent Liabilities:
Asset Retirement Obligation	2,366,455	1,000,908
Accrued Unpaid Guaranteed Payments	1,616,205	0
Accrued Liabilities	1,306,605	0
Total Liabilities	20,272,634	13,111,685
Stockholders’ Equity (Deficit):
Convertible Preferred Stock, Series B, $10 par value, 3,000,000 Shares Authorized, 2,012,400 shares issued and outstanding 59,461 Authorized but unissued at December 31, 2018	20,718,613	0
Common Stock	0	40,561,882
Additional Paid in Capital	53,023,350	703,567
Accumulated Deficit	(72,304,630)	(48,205,690)
Total Stockholder’ Equity (Deficit)	1,486,754	(6,940,241)
Total Liabilities and Stockholders’ Equity (Deficit)	21,759,388	6,171,444
Common Stock with Par Value [Member]
Stockholders’ Equity (Deficit):
Common Stock	$ 49,421	$ 0

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parentheticals) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
Convertible Preferred Stock, Series B, par value (in Dollars per share)	$ 10
Convertible Preferred Stock, Series B, Shares Authorized	3,000,000
Convertible Preferred Stock, Series B, shares issued	2,012,400
Convertible Preferred Stock, Series B, outstanding	2,012,400
Common Stock, Par Value (in Dollars per share)		$ 0
Common stock, shares authorized		30,000,000
Common Stock, shares issued		21,850,185
Common Stock, shares outstanding		21,850,185
Common Stock with Par Value [Member]
Common Stock, Par Value (in Dollars per share)	$ 0.001
Common stock, shares authorized	280,000,000
Common Stock, shares issued	49,421,387
Common Stock, shares outstanding	49,421,387

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Revenues:
Revenues	$ 3,283,041	$ 1,007,379
Costs and Expenses:
Lease Operating	1,613,368	435,637
Lease Impairment	1,183,515	289,775
Well Equipment Write Down	9,790	16,375
Depreciation, Depletion and Amortization	722,935	116,017
Bad Debt Expense	648,518	164,145
General and Administrative	3,136,009	2,005,630
Legal and Accounting	1,391,037	1,540,190
Marketing	340,641	268,660
Total Costs and Expenses	9,045,813	4,836,429
Gain on Turnkey Drilling Programs	2,558,716	1,487,824
Loss from Operations	(3,204,056)	(2,341,226)
Other Income (Expense):
Interest Expense	(177,171)	(159,268)
Gain on Investment in Joint Venture	333,931	0
Gain on Settlement of Accounts Payable	287,134	73,325
Loss on Hedging Activities	(105,130)	0
Loss on Issuance of Stock Warrants	(1,439,990)	0
Loss on Sale of Assets	(19,199,045)	0
Loss Before Income Tax Expense	(23,504,327)	(2,427,169)
Provision for Income Taxes	0	0
Net Loss	$ (23,504,327)	$ (2,427,169)
Basic Loss Per Share (in Dollars per share)	$ (0.55)	$ (0.11)
Diluted Loss Per Share (in Dollars per share)	$ (0.55)	$ (0.11)
Oil and Gas [Member]
Revenues:
Revenues	$ 1,599,362	$ 554,235
Management Service [Member]
Revenues:
Revenues	$ 1,683,679	$ 453,144

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, 2016	$ 40,561,882	$ 703,567	$ (45,778,521)		$ (4,513,072)
Balance (in Shares) at Dec. 31, 2016	21,836,033
Stock issued in lieu of Compensation	$ 25,000				25,000
Stock issued in lieu of Compensation (in Shares)	52,613
Stock issued in Settlement of AP-Adjustment	$ (25,000)				(25,000)
Stock issued in Settlement of AP-Adjustment (in Shares)	(38,461)
Net (Loss)			(2,427,169)		(2,427,169)
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
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

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (Loss)	$ (23,504,327)	$ (2,427,169)
Adjustments to Reconcile Net Loss to Net Cash Used by Operating Activities:
Depreciation, Depletion, and Amortization	722,935	116,017
Lease Impairment	1,183,515	289,775
Loss on Sale of Assets	19,199,045	0
Gain on Turnkey Drilling Programs	(2,558,716)	(1,487,824)
Gain on Settlement of Accounts Payable	(287,134)	(73,325)
Gain on Investment in Joint Venture	(333,931)	0
Bad Debt Expense	648,518	164,145
Stock-Based Compensation	64,954	0
Loss on Issuance of Stock Warrants	1,439,990	0
Well Equipment and Other Assets Write Down	9,790	16,375
Loan Fee Amortization	144,186	0
Change in Fair Value of Derivative Investments	105,130	0
(Increase) Decrease in:
Other & Revenue Receivables	(858,096)	(53,992)
Prepaid Expenses and Other Assets	(26,464)	13,600
Increase (Decrease) in:
Accounts Payable and Accrued Expenses	286,109	2,242,959
Royalties Payable	301,222	0
Due to Affiliate	547,030	0
Other Long-Term Liabilities	50,415	0
Net Cash Used by Operating Activities	(2,865,829)	(1,199,439)
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for Oil and Gas Properties	(3,221,099)	(4,388,967)
Proceeds from Turnkey Drilling Programs	6,450,000	3,932,501
Proceeds from Sale of Assets	4,406,138	0
Cash Acquired in Merger	548,805	0
Net Cash Provided by (Used In) Investing Activities	8,183,844	(456,466)
CASH FLOWS FROM FINANCING ACTIVITIES:
Settlement of Liabilities from Cash Advances from Investors	(1,900,000)	0
Principal Payments on Long-Term Debt	(401,666)	0
Proceeds from Issuance of Common Stock	0	0
Net Cash Provided by Financing Activities	(2,301,666)	0
Net Increase (Decrease) in Cash	3,016,349	(1,655,905)
Cash at Beginning of Year	3,338,693	4,994,598
Cash at End of Year	6,355,042	3,338,693
Cash Paid for Interest	172,171	1,268
Cash Paid for Taxes	4,800	1,539
Supplemental Schedule of Non-Cash Investing and Financing Transactions:
Asset Retirement Obligation Addition	362,192	65,461
Issuance of Common Stock for Accrued Compensation Expense	408,800	25,000
Series B Paid-In-Kind Dividends	594,615	0
Conversion of Convertible Notes to Common Stock	347,500	0
Notes paid with proceeds from sale of Assets	11,616,885	0
Contributions to J.V.	$ 6,250,000	$ 0

NOTE 1 - SUMMARY OF SIGNIFICANT

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2018
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 below, Merger with Matrix Oil Management, Corporation and Formation of RMX.) 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 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 18 – Supplementary Information About Oil and Gas Producing Activities 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 consolidated financial statements reflect a working capital deficiency of $5,471,153 and a net loss from operations of $(3,204,056). 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 by 25% 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 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 drilling as restricted cash as called for under ASU 2016-15 and later codified as ASC 230-10-50-8. 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. 12/31/2018 12/31/2017 Cash and cash equivalents $ 1,853,742 $ 278,227 Restricted cash $ 4,501,300 $ 3,060,466 Total cash, cash equivalents, and restricted cash shown in the statement of cash flows $ 6,355,042 $ 3,338,693 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. Revenue Recognition On January 1, 2018, we adopted the new ASC Topic 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. Results for reporting periods beginning after January 1, 2018 are presented under the new revenue standard, while prior period amounts are not adjusted and continue to be reported in accordance with our historic accounting policies. We concluded that the adoption of the new revenue standard did not result in any changes to our consolidated balance sheet or statement of cash flow. 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, 2018 2017 Oil & Condensate Sales $ 1,211,818 $ 4,703 Natural Gas Sales 385,803 549,532 NGL Sales 1,741 - $ 1,599,362 $ 554,235 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, in accordance with the new revenue standard, and such reimbursements will continue to not be recorded as revenues within the scope of the new revenue standard after the first quarter of 2018. Prior to this, such cost reimbursements were included in revenue. We commonly market the share of production belonging to other working interest owners as the operator of jointly owned oil and gas properties. We concluded that 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 are recorded at the end of each month that services were performed in conformity with the Agreement with an offsetting receivable from the RMX joint venture. The service fee income is deemed earned at the end of each month that services are performed as prescribed by the contract. Payment is due on the thirteenth day following the end of the month following the performance of the services. Although payment is not necessarily received in accordance with the contract terms, it is eventually received. During 2018, we recognized $1,620,000 or 49.3% of our total revenues from these services. Royale has a single supervisory fee customer, that being RMX, which represents 100% of the Supervisory Fee income. On December 31, 2018, Royale received notice of cancelation of the MSA by RMX effective March 31, 2019. Also included are Pipeline and Compressor fees which are received and allocated based on production volumes. Oil and Gas Property and Equipment 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 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, 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 construction phase commences with the development of the detailed engineering design and ends when the constructed 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. 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 2018 and 2017, impairment losses of $1,183,515 and $289,775, 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. Royale Energy sponsors turnkey drilling agreement arrangements in 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, 2018 and 2017, Royale Energy had Deferred Drilling Obligations of $6,213,283 and $5,891,898, 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, 2018 and 2017, the Company established an allowance for uncollectable accounts of $2,296,384 and $1,975,660, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue. Revenue Receivables Our revenue receivables consist of receivables related to the sale of our natural gas and oil. Once a production month is completed, we receive payment approximately 15 to 30 days later. Historically, 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, 2018 2017 Basic Diluted Basic Diluted Net Loss $ (23,504,327 ) $ (23,504,327 ) $ (2,427,169 ) $ (2,427,169 ) Less: Preferred Stock Dividend 594,613 594,613 - - Less: Preferred Stock Dividend in Arrears - - - - Net Loss Attributable to Common Shareholders (24,098,940 ) (24,098,940 ) (2,427,169 ) (2,427,169 ) Weighted average common shares outstanding 44,174,209 44,174,209 21,836,975 21,836,975 Effect of dilutive securities - -- - - Weighted average common shares, including Dilutive effect 44,174,209 44,174,209 21,836,975 21,836,975 Per share: Net Loss $ (0.55 ) $ (0.55 ) $ (0.11 ) $ (0.11 ) For the year ended December 31, 2018, Royale Energy had dilutive securities of 24,049,443. 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 12. The Company has adopted ASC 718 as updated by ASU 2016-09 and ASU 2017-09 for share-based payments. The Company has not implemented the amendments described in ASU 2018-07 as they become effective for public companies in 2019. 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 Topic 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 Accounting Standards Codification 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 FASB Accounting Standards Codification, 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, 2018 and 2017, 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 FASB ASC Topic 410, “ Asset Retirement and Environmental Obligations” Accounts Payable and Accrued Expenses At December 31, 2018 and 2017, the components of accounts payable and accrued expenses consisted of: 2018 2017 Trade Payables including accruals $ 2,589,518 $ 2,392,755 Direct working interest investors related accruals 1,223,588 688,002 Current drilling efforts accrued expenses 413,701 483,734 Legal Settlement Payable - 438,667 Accrued Liabilities 391,641 266,110 Employee related accruals 232,010 93,619 Interest payable on cash advances - 223,833 Deferred rent 32,752 35,036 Federal and State income taxes payable 12,323 17,123 $ 4,895,533 $ 4,638,879 Accrued Liabilities – Long Term Prior to the Merger, Matrix had outstanding long term liabilities for interest on notes payable due to certain Matrix principals. The balance due at December 31, 2018, was $1,306,605. Accrued Unpaid Guaranteed Payments Prior to the Merger, Matrix had outstanding accrued unpaid guaranteed payments for unpaid s

NOTE 2 - MERGER WITH MATRIX OIL

NOTE 2 - MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX	12 Months Ended
	Dec. 31, 2018
Business Combinations [Abstract]
Business Combination Disclosure [Text Block]	NOTE 2 – Merger with Matrix Oil Management Corporation and Formation of RMX 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 detail in our Current Report on Form 8-K dated March 7, 2018, and in Royale Energy’s Current Report on 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 FASB Topic ASC 805, Business Combinations, which among other things requires the assets acquired and liabilities assumed to be measured and recorded at their fair values as of the acquisition date, the Company was determined to be the acquirer and as such, the acquisition was accounted for as a business combination. 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 FASB Topic 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 Year ended December 31, 2017 Royale Energy, Inc. Matrix Oil Management Corp Consolidated Royale Energy, Inc. Matrix Oil Management Corp Consolidated (Unaudited) Revenue $ 723,172 $ 1,199,684 $ 1,922,856 $ 1,007,379 $ 4,896,861 $ 5,904,240 Net Loss $ (1,633,713 ) $ (149,936 ) $ (1,783,649 ) $ (2,427,169 ) $ (3,116,662 ) $ (5,543,831 ) Net Loss available to common shareholders $ (1,633,713 ) $ (149,936 ) $ (1,783,649 ) $ (2,427,169 ) $ (3,116,662 ) $ (5,543,831 ) Pro forma Loss per common share Basic and diluted $ (0.04 ) $ (0.00 ) $ (0.04 ) $ (0.11 ) $ (0.14 ) $ (0.25 ) Amounts previously estimated have changed during the measurement period. The changes in estimates included an increase of $2,581,641 of oil and gas properties and a decrease of $2,581,641 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. 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 $22.9 million drawn at December 31, 2018. 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 will receive $180,000 per month for the first year, renewable after one year at a reduced rate of $150,000 per month and subject to termination on 90 days’ notice. These amounts are included in Supervisory Fees, Service Agreement and Other as more fully described in Note 1. Termination of RMX MSA On December 31, 2018, Royale was formally notified of RMX’s intent to terminate the MSA as of March 31, 2019. The Termination Notice calls for Royale to continue to provide accounting and other services through March 31, 2019. Thereafter, per Article VII, Section 7.2 of the MSA, Royale shall provide all reasonable assistance requested by the RMX Board to transition the management of RMX for a period of 30 days. RMX Special Tax Provisions 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. Listed below is the summarized information required under Rule 3-09 of regulation S-X, Article 10 for Royale’s investment in RMX: March 27 (inception) through December 31, 2018 RMX Resources, LLC Royale Energy, Inc. Share Balance Sheet: Total Assets $ 71,758,262 $ 14,351,652 Total Liabilities 38,838,608 7,767,722 Members Equity 32,919,654 6,583,931 Results of Operations: Net operating revenue $ 8,773,661 $ 1,754,732 Loss from operations (181,464 ) (36,293 ) Net income 1,669,654 333,931

NOTE 3 - OIL AND GAS PROPERTIES

NOTE 3 - 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 the following at December 31: 2018 2017 Oil and Gas Producing properties, including intangible drilling costs $ 9,340,779 $ 3,755,705 Undeveloped properties 25,582 1,435 Lease and well equipment 3,350,893 4,119,802 12,717,254 7,876,942 Accumulated depletion, depreciation and amortization (6,402,657 ) (6,582,648 ) Net capitalized costs Total $ 6,314,597 $ 1,294,294 Commercial and Other 2018 2017 Real estate, including furniture and fixtures $ 83,405 $ - Vehicles 40,061 40,061 Furniture and equipment 1,095,149 1,092,926 1,218,615 1,132,987 Accumulated depreciation (1,125,722 ) (1,125,039 ) 92,893 7,948 Net capitalized costs Total $ 6,407,490 $ 1,302,242 The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed at December 31: 2018 2017 Acquisition – Proved $ - - Acquisition- Unproved $ - - Development $ 3,838,998 $ 4,525,452 Exploration $ - - The guidance set forth in the Continued Capitalization of Exploratory Well Costs paragraph of the Extractive Activities Topic of the FASB Accounting Standards Codification 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 2018 or 2017. 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, 2018 2017 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, 2018 2017 Oil and gas sales $ 1,599,362 $ 554,235 Production related costs (1,613,368 ) (435,637 ) Lease Impairment (1,183,515 ) (289,775 ) Depreciation, depletion and amortization (722,935 ) (116,017 ) Results of operations from producing and exploration activities $ (1,920,456 ) $ (287,194 ) Income Taxes (Benefit) - - Net Results $ (1,920,456 ) $ (287,194 )

NOTE 4 - ASSET RETIREMENT OBLIG

NOTE 4 - ASSET RETIREMENT OBLIGATION	12 Months Ended
	Dec. 31, 2018
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 FASB Accounting Standards Codification 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 fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value. 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. 2018 2017 Asset retirement obligation, Beginning of the year $ 1,000,908 $ 952,110 Liabilities incurred during the period 595,583 53,142 Settlements (52,636 ) - Merger Additions 1,419,544 - Sales (486,585 ) - Accretion expense (110,358 ) (4,344 ) Asset retirement obligation, End of year $ 2,366,456 $ 1,000,908

NOTE 5 - TURNKEY DRILLING OBLIG

NOTE 5 - TURNKEY DRILLING OBLIGATION	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer [Text Block]	NOTE 5 – TURNKEY DRILLING OBLIGATION Royale Energy receives funds under turnkey drilling contracts, which require Royale Energy to drill oil and gas wells within a reasonable time period from the date of receipt of the funds. At December 31, 2018 and 2017, Royale Energy had recorded deferred turnkey drilling associated with undrilled wells of $6,213,283 and $5,891,898, respectively, as a current liability.

NOTE 6 - NOTES PAYABLE

NOTE 6 - NOTES PAYABLE	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Debt Disclosure [Text Block]	NOTE 6 – 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. Immediately following the merger with the Matrix entities, it acquired the Matrix loan with Arena which was subsequently paid off with the closing of the RMX joint venture. At December 31, 2018 and 2017, Royale Energy had Notes Payable of $390,839 and $0, respectively, as a current liability.

NOTE 7 - INCOME TAXES

NOTE 7 - INCOME TAXES	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income Tax Disclosure [Text Block]	NOTE 7 – 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. Accounting Standard Codification (“ASC”) 740 requires filers to record the effect of tax law changes in the period enacted. However, the SEC issued Staff Accounting Bulletin No. 118 (“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, 2018 and 2017, respectively, are as follows: 2018 2017 Deferred Tax Assets (Liabilities): Statutory Depletion Carry Forward $ 367,149 $ 369,591 Net Operating Loss 7,121,912 3,130,841 Other 708,057 1,013,329 Share-Based Compensation 86,510 69,609 Capital Loss / AMT Credit Carry Forward 9,458 18,915 Charitable Contributions Carry Forward 6,158 10,025 Allowance for Doubtful Accounts 597,519 514,067 Oil and Gas Properties and Fixed Assets 5,987,061 4,839,823 Investment in RMX Joint Venture (1,247,847 ) - $ 13,635,977 $ 9,966,200 Valuation Allowance (13,635,977 ) (9,966,200 ) Net Deferred Tax Asset $ - $ - At the end of 2016, management reviewed the realizability of the Company’s net deferred tax assets. Due to the Company’s cumulative losses in recent years, Royale and its management concluded that it is not “more-likely-than-not” its deferred tax assets will be realized. As a result, 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 2018. The Company will assess the realizability of the deferred tax assets at least yearly and make appropriate updates as needed. Royale Energy, Inc. have available net operating loss carryforwards of $19,151,810 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, 2018 and 2017, respectively, to pretax income is as follows: 2018 2017 Tax (benefit) computed at statutory rate of 21% for 2018 and 34% for 2017 $ (4,935,909 ) $ (825,237 ) Increase (decrease) in taxes resulting from: Meals & Entertainment 1,320 - Investor Incentive Expense 7 - Transaction Costs 160,927 - Loss on Warrants Issued to RMX 302,398 - Prior-year true-up for Books 2,075,440 - Deferred State Taxes, net of federal benefit (1,009,601 ) - Other non-deductible expenses (264,359 ) 1,393 Change in valuation allowance 3,669,777 823,844 Provision (benefit) $ - $ - The components of the Company’s tax provision are as follows: 2018 2017 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 FASB Accounting Standards Codification, 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 2017 remain open to examination by the taxing jurisdictions in which we file income tax returns.

NOTE 8 - SERIES B PREFERRED STO

NOTE 8 - SERIES B PREFERRED STOCK	12 Months Ended
	Dec. 31, 2018
Disclosure Text Block Supplement [Abstract]
Preferred Stock [Text Block]	NOTE 8 - 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. On December 17, 2018, the board authorized the issuance of 59,416 shares of Series B Convertible Preferred shares, valued at $594,613, for the outstanding dividends as Paid-In-Kind shares. At December 31, 2018, the shares were outstanding but not issued. No cash was used to pay dividends on Series B preferred shares in 2018.

NOTE 9 - COMMON STOCK

NOTE 9 - COMMON STOCK	12 Months Ended
	Dec. 31, 2018
Stockholders' Equity Note [Abstract]
Stockholders' Equity Note Disclosure [Text Block]	NOTE 9 - COMMON STOCK In November 2015, Royale entered in a securities purchase agreement and related agreements with ten investors. Under the terms of the agreement, the investors purchased 497,740 shares of Royale’s common stock at $0.408 per share and received warrants to purchase up to 248,873 shares (the “Warrants’) of stock at $1.00 per share for three (3) years, for a total of $203,080 in gross proceeds. 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. See Note 2 for full discussion.

NOTE 10 - OPERATING LEASES

NOTE 10 - OPERATING LEASES	12 Months Ended
	Dec. 31, 2018
Disclosure Text Block Supplement [Abstract]
Commitments Disclosure [Text Block]	NOTE 10 - OPERATING LEASES Royale Energy occupies office space through the use of certain leases, one for their office in El Cajon, CA and one for an office and yard in Woodland, CA. The El Cajon lease is under a 62 month lease contract, with a yearly increase of 3.5%, which expires in January 2020. The El Cajon lease calls for monthly payments ranging from $6,148 to $10,801, and the Woodland lease calls for monthly payments of $500. Royale rents an office and yard in Woodland, CA on a month-to-month basis that currently calls for monthly payments of $500. Additionally, Royale has assumed the use of and responsibility for the payments under a lease for an office space in Santa Barbara, CA. The Santa Barbara lease calls for monthly payments of $7,843, through expiration in September 2019. The Company is currently in discussion to extend the term in exchange for a reduction in rate and amendment name Royale as the contracting party. Rental expense for the years ended December 31, 2018 and 2017 was $210,280 and $110,909 respectively. Year Ended December 31, 2019 $ 217,224 2020 127,355 2021 131,602 2022 13,802 2023 - Total $ 489,983

NOTE 11 - RELATED PARTY TRANSAC

NOTE 11 - RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2018
Related Party Transactions [Abstract]
Related Party Transactions Disclosure [Text Block]	NOTE 11 - RELATED PARTY TRANSACTIONS Significant Ownership Interests As of March 14, 2019, Mr. Donald H. Hosmer owned 2.69% of Royale Energy common stock (as calculated under SEC Rule 13d-3). Donald Hosmer has participated individually in 179 wells under the 1989 policy. During 2018 and 2017, Donald did not participate in fractional interests. At December 31, 2018, Royale had a payable balance of $2,994 due to Donald Hosmer for normal drilling and lease operating expenses. As of March 14, 2019, Stephen M. Hosmer owned 2.93% of Royale Energy common stock (as calculated under SEC Rule 13d-3). Stephen Hosmer has participated individually in 179 wells under the 1989 policy. During 2018 and 2017, Stephen did not participate in fractional interests. At December 31, 2018, Royale had a receivable balance of $14,706 due from Stephen Hosmer for normal drilling and lease operating expenses. At December 31, 2018, we had a total payable of $552,645 due to RMX Resources, LLC and its subsidiary, Matrix Oil Corporation, related to the ongoing transactions between the Royale Energy and RMX Resources, LLC. Of this balance, approximately $312,000 was received on behalf RMX Resources from various oil and gas customers. See related discussion in Note 17 – Subsequent Events. Prior to the Merger, Matrix had outstanding accrued unpaid guaranteed payments for unpaid salaries due to certain Matrix employees. At December 31, 2018, the balance due these employees was $1,616,205. Prior to the Merger, Matrix had outstanding long term liabilities for interest on notes payable due to certain Matrix principals. The balance due these principals at December 31, 2018, 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.

NOTE 12 - STOCK COMPENSATION PL

NOTE 12 - STOCK COMPENSATION PLAN	12 Months Ended
	Dec. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Disclosure of Compensation Related Costs, Share-based Payments [Text Block]	NOTE 12 - 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 2018 or 2017. A summary of the status of Royale Energy’s stock option plan as of December 31, 2018 and 2017, and changes during the years ending on those dates is presented below: 2018 2017 Weighted- Weighted- Average Average Exercise Exercise Shares Price Shares Price Options Outstanding and Exercisable at Beginning of Year - 100,000 $ 5.00 Granted or Vested 250,000 $ 0.31 - - Exercised - - - Forfeited - (100,000 ) - Options Outstanding and Exercisable at Year End 250,000 $ 0.31 $ - Weighted-average Fair Value of Options Granted During the Year $ 64,954 - At December 31, 2018, Royale Energy’s stock price, $0.13, was less than the weighted average exercise price, and as such the outstanding and exercisable stock options had no intrinsic value. The remaining outstanding stock options have a weighted-average remaining contractual term of one year as of December 31, 2018. The Company had no non-vested stock option at December 31, 2018 or 2017. During 2018 and 2017, we recognized $64,954 and $0, respectively, in compensation costs for the vested stock options. The company will incur no future expense related to these options.

NOTE 13 - SIMPLE IRA PLAN

NOTE 13 - SIMPLE IRA PLAN	12 Months Ended
	Dec. 31, 2018
Retirement Benefits [Abstract]
Pension and Other Postretirement Benefits Disclosure [Text Block]	NOTE 13 - 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, 2018 and 2017, were $35,312 and $28,947 respectively.

NOTE 14 - ENVIRONMENTAL MATTERS

NOTE 14 - ENVIRONMENTAL MATTERS	12 Months Ended
	Dec. 31, 2018
Environmental Remediation Obligations [Abstract]
Environmental Loss Contingency Disclosure [Text Block]	NOTE 14 - 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 2018 or 2017. 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.

NOTE 15 - CONCENTRATIONS OF CRE

NOTE 15 - CONCENTRATIONS OF CREDIT RISK	12 Months Ended
	Dec. 31, 2018
Risks and Uncertainties [Abstract]
Concentration Risk Disclosure [Text Block]	NOTE 15 - 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, 2018, and 2017. At December 31, 2016, and 2015, the Company’s non-interest bearing accounts were fully insured by the FDIC. At December 31, 2018 and 2017, cash in banks exceeded the FDIC limits by approximately $5.7 million and $2.8 million, respectively. The Company has not experienced any losses on deposits.

NOTE 16 - COMMITMENTS AND CONTI

NOTE 16 - COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies Disclosure [Text Block]	NOTE 16 - 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 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.

NOTE 17 - SUBSEQUENT EVENTS

NOTE 17 - SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2018
Subsequent Events [Abstract]
Subsequent Events [Text Block]	NOTE 17 - SUBSEQUENT EVENTS Settlement Agreement and Well Participation Agreement with RMX 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. Under the terms of this provision, Royale estimates that it may owe RMX approximately $552,645 related to its calculation of this post-closing amount under this provision. In addition, there are other disputed amounts related to certain joint owner billing amounts remaining unpaid at year end. 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. At December 31,2018, the Bellevue and W. Whittier 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. Royale will continue to be responsible for the liability for the payment of all royalties and suspended funds incurred prior to March 1, 2018. As part of this Settlement Agreement, RMX will offer Royale the right, but not the obligation to participate in a number of wells to be drilled in the Sansinena, Sempra, Whittier and/or East LA properties in Los Angeles County, California at an offered working interest up to 75% of RMX’s working interest in each of the offered wells. 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. Settlement with Sunny Frog Matrix Oil Company (“MOC” or “Matrix”) operated the Sansinena Field and the East LA Fields. Sunny Frog Oil, LLC (“Sunny Frog”) was a non-operator working interest participant in these fields. During the merger negotiations with Matrix Oil, LLC held during 2017, Royale entered into a purchase and sales agreement with Sunny Frog for the purchase of their 50% interest in the Sansinena and East La Fields on November 27, 2017. After Matrix completed the merger with Royale during March of 2018, it then committed to sell or contributed the Sansinena Field to the RMX joint venture along with certain other properties in April of 2018. In addition, Royale contributed it right to purchase the Sunny Frog interests in the Sansinena and East LA Fields to the RMX joint venture. On April 4, 2018, RMX closed with Sunny Frog for all of their interests in the Sansinena and East LA Fields. Subsequent to the closing by RMX of the properties with Sunny Frog, Sunny Frog commissioned an audit of the joint accounts during the period that MOC operated the properties. The audit report reflected a large balance due Sunny Frog from MOC. (MOC became part of RMX following the contribution of assets by Royale in early April.) Pursuant to Section 14.2 of the Purchase Agreement, RMX was to deliver any objections to the Preliminary Settlement Statement within 120 days following the closing Date. RMX did not tender its objections to the audit within the proscribed 120-day time limit. In addition, subsequent to the audit, other matters of controversy arose between Sunny Frog and RMX. On February 11, 2019, a settlement and release agreement was entered into by Sunny Frog and RMX whereby RMX agreed to pay $75,000 to settle any and all differences between MOC and Sunny Frog. This settlement includes any liabilities payable by Royale. Royale has reviewed its accounts and made any required adjustments. Issuance of Common Stock During the first quarter of 2019, in lieu of cash payments for salaries, fees or incentives, Royale issued 989,966 shares of its Common stock valued at approximately $240,008 to various employees, officers and board members.

NOTE 18 - SUPPLEMENTAL INFORMAT

NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)	12 Months Ended
	Dec. 31, 2018
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Oil and Gas Exploration and Production Industries Disclosures [Text Block]	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, 2018 and 2017, and changes in such quantities during each of the years then ended, were as follows: Total Proved Reserves 2018 2017 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed and Beginning of period 202 2,132,221 5,853 2,014,921 Revisions of previous estimates (79,135 ) (401,498 ) (5,549 ) 307,371 Production (20,329 ) (135,396 ) (102 ) (190,111 ) Extensions, discoveries and improved recovery - 25,014 - 40 Merger Acquisition 11,375,784 13,459,933 - - Purchase of minerals in place 29,300 116,110 - - Sales of minerals in place (10,159,421 ) (12,210,184 ) - (450,488 ) Proved reserves end of period 1,146,400 2,986,200 202 2,132,221 Proved Developed 2018 2017 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed reserves: Beginning of period 202 1,798,697 5,823 1,699,997 End of period 148,600 1,914,900 202 1,798,697 Proved Undeveloped 2018 2017 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved undeveloped reserves: Beginning of period - 333,524 - 314,925 End of period 997,800 1,071,300 - 333,524 At December 31, 2018, our previously estimated proved developed and undeveloped natural gas reserve quantities were revised downward by approximately 401,498 MCF of natural gas. This downward revision was mainly the result of one California location which had proved undeveloped reserves 333,524 MCF of natural gas at December 31, 2017, which the Company has decided not to drill. At December 31, 2018, our previously estimated proved developed and undeveloped oil reserve quantities were revised downward by approximately 79,135 BBL of oil. This downward revision was mainly the result of a Texas field acquired during the Matrix merger which had 81,054 BBL of oil lower proved developed producing reserves than originally estimated at the time of the merger. For December 31, 2017, our previously estimated proved developed and undeveloped reserve quantities were revised upward by approximately 307,371 MCF of natural gas. This upward revision reflected higher than previously estimated proved producing and non-producing natural gas reserves at eight California wells and one Utah well. A location which had 63,350 MCF in proved developed reserves at December 31, 2016, was drilled and began in 2011, was revised upward 122,998 MCF at December 31, 2017. Two locations which had 128,165 MCF in proved developed reserves at December 31, 2016, were drilled and began producing prior to 2000, were revised upward 118,006 MCF at December 31, 2017. A location which was drilled and began producing in 2010, which had proved developed reserves of 618,709 was revised upward 15,227 MCF at December 31, 2017. A location in Utah which was drilled and began producing in 2006, was revised upward 14,688 MCF at December 31, 2017. A location which was drilled and began producing in 2012, had no proved developed reserves at December 31, 2016, was revised upward 10,994 MCF at December 31, 2017. A location which was drilled and began producing in 2008, had proved developed reserves of 13,878 at December 31, 2016, was revised upward 6,084 MCF at December 31, 2017. A location which had proved undeveloped reserves of 314,925 MCF at December 31, 2016, was revised upward 18,598 MCF at December 31, 2017. 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: 2019 $ 2,130,500 2020 1,881,500 2021 1,500,000 Thereafter 1,744,900 Total $ 7,256,900 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, 2018 and 2017. 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. 2018 2017 Future cash inflows $ 87,467,200 6,065,500 Future production costs (22,390,900 ) (2,117,900 ) Future development costs (7,256,900 ) (580,800 ) Future income tax expense (17,345,820 ) (1,010,040 ) Future net cash flows 40,473,580 2,356,760 10% annual discount for estimated timing of cash flows (9,827,666 ) (712,072 ) Standardized measure of discounted future net cash flows $ 30,645,914 1,644,688 Sales of oil and gas produced, net of production costs $ (40,557 ) (161,139 ) Revisions of previous quantity estimates (71,162 ) 87,956 Net changes in prices and production costs 11,683,159 106,303 Sales of minerals in place (3,061,278 ) - Purchases of minerals in place 287,300 - Merger Acquisition 29,903,670 - Extensions, discoveries and improved recovery 59,191 74 Accretion of discount 2,670,000 197,400 Net change in income tax (12,429,097 ) (69,178 ) Net increase (decrease) $ 29,001,226 161,416 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 2019 through 2021. Future development cost of: 2019 2020 2021 Proved developed reserves (PDP) $ - $ - $ - Proved non-producing reserves (PDNP) 38,000 91,500 - Proved undeveloped reserves (PUD) 2,092,500 1,790,000 1,500,000 Total $ 2,130,500 $ 1,881,500 $ 1,500,000 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. The following table summarizes our historic costs incurred in each 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: 2018 $ - 2017 $ - 2016 $ 243,583 RMX Resources, LLC Royale has a 20% interest in RMX Resources, LLC, as described in NOTE 2- Merger with Matrix Oil Management Corporation and Formation of RMX. 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 Net to RMX Net to Royale (20%) Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed and undeveloped reserves: Beginning of period – formation of RMX 18,699,100 22,018,272 3,739,820 4,403,654 Production (206,200 ) (127,972 ) (41,240 ) (25,594 ) Extensions, discoveries and improved recovery - - - - Purchase of minerals in place 2,757,926 - 551,585 - Sales of minerals in place - - Proved reserves end of period 21,095,700 21,890,300 4,219,140 4,378,060 Proved Developed Net to RMX Net to Royale (20%) Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed reserves: Beginning of period – formation of RMX 3,955,367 3,303,772 791,073 660,754 End of period 4,965,400 3,175,700 993,080 635,140 Proved Undeveloped Net to RMX Net to Royale (20%) Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved undeveloped reserves: Beginning of period – formation of RMX 14,588,606 18,714,400 2,917,721 3,742,880 End of period 16,130,300 18,714,400 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. Net to RMX Net to Royale (20%) Future cash inflows 1,527,930,900 305,586,180 Future production costs (421,114,900 ) (84,222,980 ) Future development costs (144,008,100 ) (28,801,620 ) Future income tax expense - - Future net cash flows 962,807,900 192,561,580 10% annual discount for estimated timing of (594,814,700 ) (118,962,940 ) Standardized measure of discounted future net cash flows 367,993,200 73,598,640 Sales of oil and gas produced, (4,053,176 ) (810,635 ) Formation of RMX joint venture 301,412,679 60,282,536 Revisions of previous quantity estimates - - Net changes in prices and production costs - - Sales of minerals in place - - Purchases of minerals in place 43,365,585 8,673,117 Extensions, discoveries and improved recovery Accretion of discount 27,268,112 5,453,622 Net change in income tax - - Net increase (decrease) 367,993,200 73,598,640

Accounting Policies, by Policy

Accounting Policies, by Policy (Policies)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Basis of Accounting, Policy [Policy Text Block]	Description of Business Royale Energy is an independent oil and gas producer which also has operations in the area of turnkey drilling. Royale Energy owns wells and leases in major geological basins located primarily in California, Texas, Oklahoma 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 18 – Supplementary Information About Oil and Gas Producing Activities 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 ConcernThe 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 consolidated financial statements reflect a working capital deficiency of $5,471,153 and a net loss from operations of $(3,204,056). 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 by 25% 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 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 drilling as restricted cash as called for under ASU 2016-15 and later codified as ASC 230-10-50-8. 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. 12/31/2018 12/31/2017 Cash and cash equivalents $ 1,853,742 $ 278,227 Restricted cash $ 4,501,300 $ 3,060,466 Total cash, cash equivalents, and restricted cash shown in the statement of cash flows $ 6,355,042 $ 3,338,693
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.
Revenue Recognition, Policy [Policy Text Block]	Revenue Recognition On January 1, 2018, we adopted the new ASC Topic 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. Results for reporting periods beginning after January 1, 2018 are presented under the new revenue standard, while prior period amounts are not adjusted and continue to be reported in accordance with our historic accounting policies. We concluded that the adoption of the new revenue standard did not result in any changes to our consolidated balance sheet or statement of cash flow. 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, 2018 2017 Oil & Condensate Sales $ 1,211,818 $ 4,703 Natural Gas Sales 385,803 549,532 NGL Sales 1,741 - $ 1,599,362 $ 554,235 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, in accordance with the new revenue standard, and such reimbursements will continue to not be recorded as revenues within the scope of the new revenue standard after the first quarter of 2018. Prior to this, such cost reimbursements were included in revenue. We commonly market the share of production belonging to other working interest owners as the operator of jointly owned oil and gas properties. We concluded that 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 are recorded at the end of each month that services were performed in conformity with the Agreement with an offsetting receivable from the RMX joint venture. The service fee income is deemed earned at the end of each month that services are performed as prescribed by the contract. Payment is due on the thirteenth day following the end of the month following the performance of the services. Although payment is not necessarily received in accordance with the contract terms, it is eventually received. During 2018, we recognized $1,620,000 or 49.3% of our total revenues from these services. Royale has a single supervisory fee customer, that being RMX, which represents 100% of the Supervisory Fee income. On December 31, 2018, Royale received notice of cancelation of the MSA by RMX effective March 31, 2019. Also included 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 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 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, 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 construction phase commences with the development of the detailed engineering design and ends when the constructed 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. 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 2018 and 2017, impairment losses of $1,183,515 and $289,775, 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. Royale Energy sponsors turnkey drilling agreement arrangements in 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, 2018 and 2017, Royale Energy had Deferred Drilling Obligations of $6,213,283 and $5,891,898, 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.
Receivables, Policy [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, 2018 and 2017, the Company established an allowance for uncollectable accounts of $2,296,384 and $1,975,660, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue.
Trade and Other Accounts Receivable, Policy [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, 2018 2017 Basic Diluted Basic Diluted Net Loss $ (23,504,327 ) $ (23,504,327 ) $ (2,427,169 ) $ (2,427,169 ) Less: Preferred Stock Dividend 594,613 594,613 - - Less: Preferred Stock Dividend in Arrears - - - - Net Loss Attributable to Common Shareholders (24,098,940 ) (24,098,940 ) (2,427,169 ) (2,427,169 ) Weighted average common shares outstanding 44,174,209 44,174,209 21,836,975 21,836,975 Effect of dilutive securities - -- - - Weighted average common shares, including Dilutive effect 44,174,209 44,174,209 21,836,975 21,836,975 Per share: Net Loss $ (0.55 ) $ (0.55 ) $ (0.11 ) $ (0.11 ) For the year ended December 31, 2018, Royale Energy had dilutive securities of 24,049,443. These securities were not included in the dilutive loss per share due to their antidilutive nature.
Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block]	Stock Based Compensation Royale has a stock-based employee compensation plan, which is more fully described in Note 12. The Company has adopted ASC 718 as updated by ASU 2016-09 and ASU 2017-09 for share-based payments. The Company has not implemented the amendments described in ASU 2018-07 as they become effective for public companies in 2019. 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 Topic 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 Accounting Standards Codification 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 FASB Accounting Standards Codification, 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, 2018 and 2017, 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 FASB ASC Topic 410, “ Asset Retirement and Environmental Obligations”
Accounts Payable and Accrued Expenses [Policy Text Block]	Accounts Payable and Accrued ExpensesAt December 31, 2018 and 2017, the components of accounts payable and accrued expenses consisted of:  2018  2017          Trade Payables including accruals $2,589,518  $2,392,755 Direct working interest investors related accruals  1,223,588   688,002 Current drilling efforts accrued expenses  413,701   483,734 Legal Settlement Payable  -   438,667 Accrued Liabilities  391,641   266,110 Employee related accruals  232,010   93,619 Interest payable on cash advances  -   223,833 Deferred rent  32,752   35,036 Federal and State income taxes payable  12,323   17,123   $4,895,533  $4,638,879 
Accrued Liabilitites Policy [Policy Text Block]	Accrued Liabilities – Long TermPrior to the Merger, Matrix had outstanding long term liabilities for interest on notes payable due to certain Matrix principals.  The balance due at December 31, 2018, was $1,306,605.
Accrued Guaranteed Payments Policy [Policy Text Block]	Accrued Unpaid Guaranteed PaymentsPrior to the Merger, Matrix had outstanding accrued unpaid guaranteed payments for unpaid salaries due to certain Matrix employees.  At December 31, 2018, the $1,616,205 balance remains the same as the time of merger.
Other Current Liabilities [Policy Text Block]	Cash Advances on Pending TransactionsIn July 2016, we received a cash investment of $1,580,000 from two investors to purchase convertible promissory notes of $1,280,000 and $300,000, with a conversion price of $0.40 per share, with warrants to purchase one share of common stock for every three shares of common stock issuable upon conversion of the notes.  The funds from these transactions were used to continue drilling activities, fund expenses incurred in connection with the completion of Royale Energy’s merger with Matrix Oil Corporation and for general corporate purposes.  The notes originally matured on August 2, 2017, one year from the date of issuance, and carried a 10% interest rate, with a default rate of 25%.  Shortly before completion of the Merger, 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.
Reclassification, Policy [Policy Text Block]	Reclassifications The Company has reclassified certain prior year amounts between operating cash flow categories to present it on a basis comparable with the current year’s presentation with no impact on net cash provided by operating activities. During 2017, Royale treated reimbursement of overhead expenses through joint operations (“COPAS Overhead”) as part of revenue. In 2018, the Company changed its accounting policy and treats COPAS Overhead as a reduction to the Company’s General and Administrative expenses. Certain prior year amounts have been reclassified for consistency with the current year presentation. These reclassifications had no effect on the reported results of operations.
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. When the Company pays more than fair market value for an asset, it records the overage as an intangible asset (“goodwill”). In the event that the Company pays less than fair market value for an asset(s) this results in “negative goodwill” or a so called “bargain purchase”. In the event of a bargain purchase, the Company will reevaluate the fair market value of the asset(s) being acquired until such time as there is no negative goodwill.
Goodwill and Intangible Assets, Goodwill, Policy [Policy Text Block]	Goodwill and Impairments We evaluate goodwill for impairment annually as of December 31st, or when an indicator of impairment exists. We compare the fair value of our reporting units with the carrying value, including goodwill. We recognize an impairment charge for the amount by which the carrying value exceeds a reporting unit’s fair value, not to exceed the total amount of recorded goodwill, as applicable. Significant estimates used in our fair value calculation using discounted future cash flows include: (1) estimates of future revenue and expense growth by field, (2) future estimated effective tax rates, which vary by geological region and state; (3) future estimated capital expenditures and future required investments in working capital; (4) estimated discount rates, (5) reserve life and decline rates as estimated by an industry recognized reservoir engineer, (6) future commodity pricing expectations as developed by Company management, (7) risking factors established by management by asset class and (8) future development opportunities as evaluated by the Company’s engineering staff. Significant estimates include; oil and gas future well recoveries, future commodity price forecasts, future potential growth estimates, discount values and risk factors. In addition, we evaluate an acquisition for impairment if events or circumstances change between annual tests, indicating a possible impairment. Examples of such events or circumstances include: (1) a significant adverse change in legal factors or in the business climate; (2) an adverse change in commodity prices, (3) assessment by a regulator; (3) a determination by management that some or all of the acquisition will be sold; (4) continued or sustained losses by the acquisition; (5) a significant decline in production as compared to our book value; or (6) we conclude that we may not recover a significant asset class within the acquisition.
New Accounting Pronouncements, Policy [Policy Text Block]	Accounting Standards Recently Adopted ASU 2017-09, Revenue from Contracts with Customers (ASC 606) On January 1, 2018, we adopted the new ASC Topic 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 obligation as of January 1, 2018. No cumulative adjustment to retained earnings was necessary as a result of adopting this standard. Results for reporting periods beginning after January 1, 2018 are presented under the new revenue standard, while prior period amounts are not adjusted and continue to be reported in accordance with our historic accounting policies. We concluded that the adoption of the new revenue standard did not result in any changes to our consolidated balance sheet or statement of cash flow ASU 2017-01: Business Combinations–Clarifying the Definition of a Business In January 2017, the FASB issued a new accounting standards update that changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities constitutes a business. The guidance requires us to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities would not represent a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described in the new revenue guidance. This standard was effective for us in the first quarter of 2018, and was applied prospectively. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows. ASU 2016-18: Statement of Cash Flow-Restricted Cash (ASC-230-10-50-8) In November 2016, the FASB issued a new accounting standards update that requires entities to show the changes in the total of cash, cash equivalents and restricted cash in the statement of cash flows. As a result, we no longer present transfers between cash and cash equivalents and restricted cash in the statement of cash flows. When cash, cash equivalents, and restricted cash are presented in more than one line item on the balance sheet, the standard requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. This reconciliation can be presented either on the face of the statement of cash flows or in the notes to the financial statements. Royale has adopted this new ASU 2016-18 with the reporting of year-end financials. This standard requires Royale to show cash received specifically for drilling operations separately on the balance sheet as Restricted Cash. See note above. We also adopted the following ASUs during 2018, none of which had a material impact to our financial statements or financial statement disclosures: ASU Effective Date 2017-09 Stock Compensation-Scope of Modification Accounting January 1, 2018 2017-07 Retirement Benefits-Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post Retirement Cost January 1, 2018 2017-05 Gains and Losses from the Depreciation of Nonfinancial Assets -Clarifying the Scope of Assets Derecognition Guidance January 1, 2018 2014-16 Income Taxes-Intra-Entity Transfers of Assets other than Inventory January 1, 2018 2016-15 Statement of Cash Flows-Classification of Certain Cash Receipts and Cash Payments January 1, 2018 2016-01 Financial Instruments-Recognition and Measurement of Financial Assets and Liabilities January 1, 2018 Not Yet Adopted ASU 2018-02, Reporting Comprehensive Income – Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income In February 2018, the FASB issued an ASU allowing an entity the choice to retained earnings the tax effects related to the TCJA that are stranded in accumulated other comprehensive income. We do not expect adoption of this standard to have a material impact on our financial statements. The amendment is effective beginning in 2019. 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 is effective beginning in 2019. We are currently evaluating the impact of this guidance, including transition elections and required disclosures, on our financial statements and the timing of adoption. However, since we have not historically used derivatives to hedge our commodity price risk, we do not expect adoption of this ASU to have a material impact on our consolidated financial statements. ASU 2016-13, Credit Losses – Measurement of Credit Losses on Financial Instruments In June 2016, the FASB issued an ASU related to the accounting for credit losses on certain financial instruments. The guidance requires that for most financial assets, losses be based on an expected loss approach which includes estimates of losses over the life of exposures that considers historical, current and forecasted information. Expanded disclosures related to the methods used to estimate the losses as well as a specific disaggregation of balances for financial assets are also required. The change is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. We do not expect application of this ASU to have a material impact on our consolidated financial statements. ASU 2016-02 and 2018-11, Leases In February 2016, the FASB issued an ASU requiring lessees to record virtually all leases on their balance sheet. The ASU also requires expanded disclosures to help financial statement users better understand the amount, timing and uncertainty of cash flow arising from leases. For Lessors, this amended guidance modifies the classification criteria and the accounting for sales-type and direct financing leasers. The guidance will be effective for fiscal years beginning after December 15, 2018, and interim periods within those years. We will transition to the new guidance by recording leases on our balance sheet as of January 1, 2019. We continue to evaluate the impact of this standard on our financial statements, disclosures, internal controls and accounting policies. This evaluation process includes reviewing all forms of leases, performing a completeness assessment over the lease population and analyzing the practical expedients in order to determine the best path of implementing changes to existing processes and controls. We believe the adoption of the standard will have a material impact on our consolidated financial statements as virtually all leases will be recognized as a right of use asset and lease obligation.

NOTE 1 - SUMMARY OF SIGNIFICA_2

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2018
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. 12/31/2018 12/31/2017 Cash and cash equivalents $ 1,853,742 $ 278,227 Restricted cash $ 4,501,300 $ 3,060,466 Total cash, cash equivalents, and restricted cash shown in the statement of cash flows $ 6,355,042 $ 3,338,693
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, 2018 2017 Oil & Condensate Sales $ 1,211,818 $ 4,703 Natural Gas Sales 385,803 549,532 NGL Sales 1,741 - $ 1,599,362 $ 554,235
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, 2018 2017 Basic Diluted Basic Diluted Net Loss $ (23,504,327 ) $ (23,504,327 ) $ (2,427,169 ) $ (2,427,169 ) Less: Preferred Stock Dividend 594,613 594,613 - - Less: Preferred Stock Dividend in Arrears - - - - Net Loss Attributable to Common Shareholders (24,098,940 ) (24,098,940 ) (2,427,169 ) (2,427,169 ) Weighted average common shares outstanding 44,174,209 44,174,209 21,836,975 21,836,975 Effect of dilutive securities - -- - - Weighted average common shares, including Dilutive effect 44,174,209 44,174,209 21,836,975 21,836,975 Per share: Net Loss $ (0.55 ) $ (0.55 ) $ (0.11 ) $ (0.11 )
Schedule of Accounts Payable and Accrued Liabilities [Table Text Block]	At December 31, 2018 and 2017, the components of accounts payable and accrued expenses consisted of: 2018 2017 Trade Payables including accruals $ 2,589,518 $ 2,392,755 Direct working interest investors related accruals 1,223,588 688,002 Current drilling efforts accrued expenses 413,701 483,734 Legal Settlement Payable - 438,667 Accrued Liabilities 391,641 266,110 Employee related accruals 232,010 93,619 Interest payable on cash advances - 223,833 Deferred rent 32,752 35,036 Federal and State income taxes payable 12,323 17,123 $ 4,895,533 $ 4,638,879
Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block]	We also adopted the following ASUs during 2018, none of which had a material impact to our financial statements or financial statement disclosures: ASU Effective Date 2017-09 Stock Compensation-Scope of Modification Accounting January 1, 2018 2017-07 Retirement Benefits-Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post Retirement Cost January 1, 2018 2017-05 Gains and Losses from the Depreciation of Nonfinancial Assets -Clarifying the Scope of Assets Derecognition Guidance January 1, 2018 2014-16 Income Taxes-Intra-Entity Transfers of Assets other than Inventory January 1, 2018 2016-15 Statement of Cash Flows-Classification of Certain Cash Receipts and Cash Payments January 1, 2018 2016-01 Financial Instruments-Recognition and Measurement of Financial Assets and Liabilities January 1, 2018

NOTE 2 - MERGER WITH MATRIX O_2

NOTE 2 - MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Tables)	12 Months Ended
	Dec. 31, 2018
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 FASB Topic 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 Year ended December 31, 2017 Royale Energy, Inc. Matrix Oil Management Corp Consolidated Royale Energy, Inc. Matrix Oil Management Corp Consolidated (Unaudited) Revenue $ 723,172 $ 1,199,684 $ 1,922,856 $ 1,007,379 $ 4,896,861 $ 5,904,240 Net Loss $ (1,633,713 ) $ (149,936 ) $ (1,783,649 ) $ (2,427,169 ) $ (3,116,662 ) $ (5,543,831 ) Net Loss available to common shareholders $ (1,633,713 ) $ (149,936 ) $ (1,783,649 ) $ (2,427,169 ) $ (3,116,662 ) $ (5,543,831 ) Pro forma Loss per common share Basic and diluted $ (0.04 ) $ (0.00 ) $ (0.04 ) $ (0.11 ) $ (0.14 ) $ (0.25 )
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 of oil and gas properties and a decrease of $2,581,641 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 the summarized information required under Rule 3-09 of regulation S-X, Article 10 for Royale’s investment in RMX: March 27 (inception) through December 31, 2018 RMX Resources, LLC Royale Energy, Inc. Share Balance Sheet: Total Assets $ 71,758,262 $ 14,351,652 Total Liabilities 38,838,608 7,767,722 Members Equity 32,919,654 6,583,931 Results of Operations: Net operating revenue $ 8,773,661 $ 1,754,732 Loss from operations (181,464 ) (36,293 ) Net income 1,669,654 333,931

NOTE 3 - OIL AND GAS PROPERTI_2

NOTE 3 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Tables)	12 Months Ended
	Dec. 31, 2018
Oil and Gas Property [Abstract]
Property, Plant and Equipment [Table Text Block]	Oil and gas properties, equipment and fixtures consist of the following at December 31: 2018 2017 Oil and Gas Producing properties, including intangible drilling costs $ 9,340,779 $ 3,755,705 Undeveloped properties 25,582 1,435 Lease and well equipment 3,350,893 4,119,802 12,717,254 7,876,942 Accumulated depletion, depreciation and amortization (6,402,657 ) (6,582,648 ) Net capitalized costs Total $ 6,314,597 $ 1,294,294 Commercial and Other 2018 2017 Real estate, including furniture and fixtures $ 83,405 $ - Vehicles 40,061 40,061 Furniture and equipment 1,095,149 1,092,926 1,218,615 1,132,987 Accumulated depreciation (1,125,722 ) (1,125,039 ) 92,893 7,948 Net capitalized costs Total $ 6,407,490 $ 1,302,242
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: 2018 2017 Acquisition – Proved $ - - Acquisition- Unproved $ - - Development $ 3,838,998 $ 4,525,452 Exploration $ - -
Capitalized Exploratory Well Costs, Roll Forward [Table Text Block]	Undeveloped properties are not subject to depletion, depreciation or amortization. Year Ended December 31, 2018 2017 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, 2018 2017 Oil and gas sales $ 1,599,362 $ 554,235 Production related costs (1,613,368 ) (435,637 ) Lease Impairment (1,183,515 ) (289,775 ) Depreciation, depletion and amortization (722,935 ) (116,017 ) Results of operations from producing and exploration activities $ (1,920,456 ) $ (287,194 ) Income Taxes (Benefit) - - Net Results $ (1,920,456 ) $ (287,194 )

NOTE 4 - ASSET RETIREMENT OBL_2

NOTE 4 - ASSET RETIREMENT OBLIGATION (Tables)	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligation [Table Text Block]	The Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification 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 fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value. 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. 2018 2017 Asset retirement obligation, Beginning of the year $ 1,000,908 $ 952,110 Liabilities incurred during the period 595,583 53,142 Settlements (52,636 ) - Merger Additions 1,419,544 - Sales (486,585 ) - Accretion expense (110,358 ) (4,344 ) Asset retirement obligation, End of year $ 2,366,456 $ 1,000,908

NOTE 7 - INCOME TAXES (Tables)

NOTE 7 - INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 and 2017, respectively, are as follows: 2018 2017 Deferred Tax Assets (Liabilities): Statutory Depletion Carry Forward $ 367,149 $ 369,591 Net Operating Loss 7,121,912 3,130,841 Other 708,057 1,013,329 Share-Based Compensation 86,510 69,609 Capital Loss / AMT Credit Carry Forward 9,458 18,915 Charitable Contributions Carry Forward 6,158 10,025 Allowance for Doubtful Accounts 597,519 514,067 Oil and Gas Properties and Fixed Assets 5,987,061 4,839,823 Investment in RMX Joint Venture (1,247,847 ) - $ 13,635,977 $ 9,966,200 Valuation Allowance (13,635,977 ) (9,966,200 ) 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, 2018 and 2017, respectively, to pretax income is as follows: 2018 2017 Tax (benefit) computed at statutory rate of 21% for 2018 and 34% for 2017 $ (4,935,909 ) $ (825,237 ) Increase (decrease) in taxes resulting from: Meals & Entertainment 1,320 - Investor Incentive Expense 7 - Transaction Costs 160,927 - Loss on Warrants Issued to RMX 302,398 - Prior-year true-up for Books 2,075,440 - Deferred State Taxes, net of federal benefit (1,009,601 ) - Other non-deductible expenses (264,359 ) 1,393 Change in valuation allowance 3,669,777 823,844 Provision (benefit) $ - $ -
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	The components of the Company’s tax provision are as follows: 2018 2017 Current tax provision (benefit) – federal $ - - Current tax provision (benefit) – state - - Deferred tax provision (benefit) – federal - - Deferred tax provision (benefit) – state - - Total provision (benefit) $ - -

NOTE 10 - OPERATING LEASES (Tab

NOTE 10 - OPERATING LEASES (Tables)	12 Months Ended
	Dec. 31, 2018
Disclosure Text Block Supplement [Abstract]
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]	Royale Energy occupies office space through the use of certain leases, one for their office in El Cajon, CA and one for an office and yard in Woodland, CA. The El Cajon lease is under a 62 month lease contract, with a yearly increase of 3.5%, which expires in January 2020. The El Cajon lease calls for monthly payments ranging from $6,148 to $10,801, and the Woodland lease calls for monthly payments of $500. Royale rents an office and yard in Woodland, CA on a month-to-month basis that currently calls for monthly payments of $500. Additionally, Royale has assumed the use of and responsibility for the payments under a lease for an office space in Santa Barbara, CA. The Santa Barbara lease calls for monthly payments of $7,843, through expiration in September 2019. The company is currently in discussion to extend the term in exchange for a reduction in rate and amendment name Royale as the contracting party. Rental expense for the years ended December 31, 2018 and 2017 was $210,280 and $110,909 respectively. Year Ended December 31, 2019 $ 217,224 2020 127,355 2021 131,602 2022 13,802 2023 - Total $ 489,983

NOTE 12 - STOCK COMPENSATION _2

NOTE 12 - STOCK COMPENSATION PLAN (Tables)	12 Months Ended
	Dec. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share-based Compensation, Stock Options, Activity [Table Text Block]	A summary of the status of Royale Energy’s stock option plan as of December 31, 2018 and 2017, and changes during the years ending on those dates is presented below: 2018 2017 Weighted- Weighted- Average Average Exercise Exercise Shares Price Shares Price Options Outstanding and Exercisable at Beginning of Year - 100,000 $ 5.00 Granted or Vested 250,000 $ 0.31 - - Exercised - - - Forfeited - (100,000 ) - Options Outstanding and Exercisable at Year End 250,000 $ 0.31 $ - Weighted-average Fair Value of Options Granted During the Year $ 64,954 -

NOTE 18 - SUPPLEMENTAL INFORM_2

NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2018
NOTE 18 - 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, 2018 and 2017, and changes in such quantities during each of the years then ended, were as follows: Total Proved Reserves 2018 2017 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed and Beginning of period 202 2,132,221 5,853 2,014,921 Revisions of previous estimates (79,135 ) (401,498 ) (5,549 ) 307,371 Production (20,329 ) (135,396 ) (102 ) (190,111 ) Extensions, discoveries and improved recovery - 25,014 - 40 Merger Acquisition 11,375,784 13,459,933 - - Purchase of minerals in place 29,300 116,110 - - Sales of minerals in place (10,159,421 ) (12,210,184 ) - (450,488 ) Proved reserves end of period 1,146,400 2,986,200 202 2,132,221 Proved Developed 2018 2017 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed reserves: Beginning of period 202 1,798,697 5,823 1,699,997 End of period 148,600 1,914,900 202 1,798,697 Proved Undeveloped 2018 2017 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved undeveloped reserves: Beginning of period - 333,524 - 314,925 End of period 997,800 1,071,300 - 333,524 Total Proved Reserves Net to RMX Net to Royale (20%) Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed and undeveloped reserves: Beginning of period – formation of RMX 18,699,100 22,018,272 3,739,820 4,403,654 Production (206,200 ) (127,972 ) (41,240 ) (25,594 ) Extensions, discoveries and improved recovery - - - - Purchase of minerals in place 2,757,926 - 551,585 - Sales of minerals in place - - Proved reserves end of period 21,095,700 21,890,300 4,219,140 4,378,060 Proved Developed Net to RMX Net to Royale (20%) Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed reserves: Beginning of period – formation of RMX 3,955,367 3,303,772 791,073 660,754 End of period 4,965,400 3,175,700 993,080 635,140 Proved Undeveloped Net to RMX Net to Royale (20%) Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved undeveloped reserves: Beginning of period – formation of RMX 14,588,606 18,714,400 2,917,721 3,742,880 End of period 16,130,300 18,714,400 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: 2018 2017 Acquisition – Proved $ - - Acquisition- Unproved $ - - Development $ 3,838,998 $ 4,525,452 Exploration $ - -
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block]	2018 2017 Future cash inflows $ 87,467,200 6,065,500 Future production costs (22,390,900 ) (2,117,900 ) Future development costs (7,256,900 ) (580,800 ) Future income tax expense (17,345,820 ) (1,010,040 ) Future net cash flows 40,473,580 2,356,760 10% annual discount for estimated timing of cash flows (9,827,666 ) (712,072 ) Standardized measure of discounted future net cash flows $ 30,645,914 1,644,688 Sales of oil and gas produced, net of production costs $ (40,557 ) (161,139 ) Revisions of previous quantity estimates (71,162 ) 87,956 Net changes in prices and production costs 11,683,159 106,303 Sales of minerals in place (3,061,278 ) - Purchases of minerals in place 287,300 - Merger Acquisition 29,903,670 - Extensions, discoveries and improved recovery 59,191 74 Accretion of discount 2,670,000 197,400 Net change in income tax (12,429,097 ) (69,178 ) Net increase (decrease) $ 29,001,226 161,416 Net to RMX Net to Royale (20%) Future cash inflows 1,527,930,900 305,586,180 Future production costs (421,114,900 ) (84,222,980 ) Future development costs (144,008,100 ) (28,801,620 ) Future income tax expense - - Future net cash flows 962,807,900 192,561,580 10% annual discount for estimated timing of (594,814,700 ) (118,962,940 ) Standardized measure of discounted future net cash flows 367,993,200 73,598,640 Sales of oil and gas produced, (4,053,176 ) (810,635 ) Formation of RMX joint venture 301,412,679 60,282,536 Revisions of previous quantity estimates - - Net changes in prices and production costs - - Sales of minerals in place - - Purchases of minerals in place 43,365,585 8,673,117 Extensions, discoveries and improved recovery Accretion of discount 27,268,112 5,453,622 Net change in income tax - - Net increase (decrease) 367,993,200 73,598,640
Proved Undeveloped Reserves [Member]
NOTE 18 - 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]	2019 $ 2,130,500 2020 1,881,500 2021 1,500,000 Thereafter 1,744,900 Total $ 7,256,900 2018 $ - 2017 $ - 2016 $ 243,583
Proved Developed, Proved Non-Producing and Proved Undeveloped Reserves [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables) [Line Items]
Schedule of Future Development Costs, Oil and Gas Production [Table Text Block]	Future development cost of: 2019 2020 2021 Proved developed reserves (PDP) $ - $ - $ - Proved non-producing reserves (PDNP) 38,000 91,500 - Proved undeveloped reserves (PUD) 2,092,500 1,790,000 1,500,000 Total $ 2,130,500 $ 1,881,500 $ 1,500,000

NOTE 1 - SUMMARY OF SIGNIFICA_3

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - USD ($)	Jan. 01, 2016	Dec. 31, 2018	Dec. 31, 2017
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Working Capital (Deficit)		$ (5,471,153)
Operating Income (Loss)		$ (3,204,056)	$ (2,341,226)
Overhead Cost Increase (Decrease), Percentage		25.00%
Revenues		$ 3,283,041	1,007,379
Impairment of Oil and Gas Properties		1,183,515	289,775
Contract with Customer, Liability, Current		6,213,283	5,891,898
Allowance for Doubtful Accounts Receivable		$ 2,296,384	1,975,660
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount (in Shares)		24,049,443
Other Accrued Liabilities, Noncurrent		$ 1,306,605	0
Other Liabilities, Noncurrent		1,616,205	0
Debt Conversion, Original Debt, Amount		$ 347,500	$ 0
Minimum [Member]
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Property, Plant and Equipment, Estimated Useful Lives		three
Maximum [Member]
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Property, Plant and Equipment, Estimated Useful Lives		seven
Notes Entered into Negotiations [Member] | Convertible Notes Payable [Member]
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Debt Instrument, Face Amount	$ 1,580,000
Debt Conversion, Description	with a conversion price of $0.40 per share, with warrants to purchase one share of common stock for every three shares of common stock issuable upon conversion of the notes
Debt Instrument, Convertible, Conversion Price (in Dollars per share)	$ 0.40
Debt Instrument, Term	1 year
Debt Instrument, Interest Rate, Stated Percentage	10.00%
Debt Instrument, Debt Default, Rate	25.00%
Note #1 Entered into Negotiations [Member] | Convertible Notes Payable [Member]
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Debt Instrument, Face Amount	$ 1,280,000
Repayments of Debt	1,900,000
Note #2 Entered into Negotiations [Member] | Convertible Notes Payable [Member]
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Debt Instrument, Face Amount	300,000
Debt Conversion, Original Debt, Amount	$ 300,000
Debt Conversion, Converted Instrument, Shares Issued (in Shares)	750,000
RMX Joint Venture [Member] | Customer Concentration Risk [Member] | Sales Revenue, Net [Member]
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Concentration Risk, Percentage		49.30%
Services related to Master Service Agreement with RMX [Member]
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Revenues		$ 1,620,000
Supervisory, Services [Member] | RMX Joint Venture [Member] | Customer Concentration Risk [Member] | Sales Revenue, Net [Member]
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Concentration Risk, Percentage		100.00%

NOTE 1 - SUMMARY OF SIGNIFICA_4

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - Schedule of Cash and Cash Equivalents - USD ($)	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Schedule of Cash and Cash Equivalents [Abstract]
Cash and cash equivalents	$ 1,853,742	$ 278,227
Restricted cash	4,501,300	3,060,466
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows	$ 6,355,042	$ 3,338,693	$ 4,994,598

NOTE 1 - SUMMARY OF SIGNIFICA_5

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - Disaggregation of Revenue - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Revenues	$ 3,283,041	$ 1,007,379
Oil [Member]
Disaggregation of Revenue [Line Items]
Revenues	1,211,818	4,703
Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenues	385,803	549,532
Natural Gas Liquids [Member]
Disaggregation of Revenue [Line Items]
Revenues	1,741	0
Oil and Gas [Member]
Disaggregation of Revenue [Line Items]
Revenues	$ 1,599,362	$ 554,235

NOTE 1 - SUMMARY OF SIGNIFICA_6

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - Schedule of Earnings Per Share, Basic and Diluted - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Schedule of Earnings Per Share, Basic and Diluted [Abstract]
Net Loss	$ (23,504,327)	$ (2,427,169)
Less: Preferred Stock Dividend	594,613	0
Less: Preferred Stock Dividend in Arrears	0	0
Net Loss Attributable to Common Shareholders	$ (24,098,940)	$ (2,427,169)
Weighted average common shares outstanding (in Shares)	44,174,209	21,836,975
Weighted average common shares outstanding (in Shares)	44,174,209	21,836,975
Effect of dilutive securities	$ 0	$ 0
Effect of dilutive securities (in Shares)	0	0
Weighted average common shares, including Dilutive effect (in Shares)	44,174,209	21,836,975
Weighted average common shares, including Dilutive effect (in Shares)	44,174,209	21,836,975
Net Loss (in Dollars per share)	$ (0.55)	$ (0.11)
Net Loss (in Dollars per share)	$ (0.55)	$ (0.11)

NOTE 1 - SUMMARY OF SIGNIFICA_7

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - Schedule of Accounts Payable and Accrued Liabilities - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Schedule of Accounts Payable and Accrued Liabilities [Abstract]
Trade Payables including accruals	$ 2,589,518	$ 2,392,755
Direct working interest investors related accruals	1,223,588	688,002
Current drilling efforts accrued expenses	413,701	483,734
Legal Settlement Payable	0	438,667
Accrued Liabilities	391,641	266,110
Employee related taxes and accruals	232,010	93,619
Interest payable on cash advances	0	223,833
Deferred rent	32,752	35,036
Federal and State income taxes payable	12,323	17,123
	$ 4,895,533	$ 4,638,879

NOTE 1 - SUMMARY OF SIGNIFICA_8

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - Schedule of New Accounting Pronouncements and Changes in Accounting Principles	12 Months Ended
	Dec. 31, 2018
Accounting Standards Update 2017-09 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement, Description	Jan. 1, 2018
Accounting Standards Update 2017-07 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement, Description	Jan. 1, 2018
Accounting Standards Update 2017-05 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement, Description	Jan. 1, 2018
Accounting Standards Update 2014-16 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement, Description	Jan. 1, 2018
Accounting Standards Update 2016-15 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement, Description	Jan. 1, 2018
Accounting Standards Update 2016-01 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement, Description	Jan. 1, 2018

NOTE 2 - MERGER WITH MATRIX O_3

NOTE 2 - MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) - USD ($)	Apr. 30, 2018	Mar. 07, 2018	Nov. 30, 2015	Dec. 31, 2018	Dec. 31, 2017
NOTE 2 - MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) [Line Items]
Stock Issued During Period, Shares, New Issues (in Shares)		2,012,400	497,740
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				548,805	$ 0
Class Of Warrant or Rights Granted (in Shares)			248,873
Business Combination, Consideration Transferred		29,670,068
Scenario, Adjustment [Member]
NOTE 2 - 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]
NOTE 2 - 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]
NOTE 2 - 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				22,900,000
RMX Resources, LLC [Member]
NOTE 2 - 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
Supervisory Fees, Service Agreements, and Other, Renewal Reduced Rate				$ 150,000
RMX Resources, LLC [Member] | Matrix Oil Corporation (“MOC”) [Member]
NOTE 2 - MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) [Line Items]
Due from Affiliates	640,000
RMX Resources, LLC [Member] | Maximum [Member]
NOTE 2 - MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) [Line Items]
Cash Acquired from Acquisition	$ 20,000,000
RMX Resources, LLC [Member] | CIC RMX LP [Member]
NOTE 2 - 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)	4,000,000
Equity Method Investments	$ 25,000,000
RMX Resources, LLC [Member] | The Royal Entities [Member]
NOTE 2 - MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) [Line Items]
Business Combination, Consideration Transferred	$ 4,000,000
Working Interest	20.00%
RMX Resources, LLC [Member] | The Royal Entities [Member] | Sansinena Field [Member]
NOTE 2 - MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) [Line Items]
Contribution of Property Percentage	100.00%
RMX Resources, LLC [Member] | The Royal Entities [Member] | Sempra Field [Member]
NOTE 2 - MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) [Line Items]
Contribution of Property Percentage	100.00%
RMX Resources, LLC [Member] | The Royal Entities [Member] | Bellevue Field [Member]
NOTE 2 - MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) [Line Items]
Contribution of Property Percentage	50.00%
RMX Resources, LLC [Member] | The Royal Entities [Member] | Whittier Main Field [Member]
NOTE 2 - MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) [Line Items]
Contribution of Property Percentage	100.00%
RMX Resources, LLC [Member] | The Royal Entities [Member] | Whittier Field [Member]
NOTE 2 - MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) [Line Items]
Contribution of Property Percentage	50.00%

NOTE 2 - MERGER WITH MATRIX OI

NOTE 2 - 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

NOTE 2 - MERGER WITH MATRIX _2

NOTE 2 - MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) - Business Acquisition, Pro Forma Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
NOTE 2 - MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) - Business Acquisition, Pro Forma Information [Line Items]
Revenue	$ 1,922,856	$ 5,904,240
Net Loss	(1,783,649)	(5,543,831)
Net Loss available to common shareholders	$ (1,783,649)	$ (5,543,831)
Pro forma Loss per common share Basic and diluted (in Dollars per share)	$ (0.04)	$ (0.25)
Matrix Oil Management Corp [Member]
NOTE 2 - MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) - Business Acquisition, Pro Forma Information [Line Items]
Revenue	$ 1,199,684	$ 4,896,861
Net Loss	(149,936)	(3,116,662)
Net Loss available to common shareholders	$ (149,936)	$ (3,116,662)
Pro forma Loss per common share Basic and diluted (in Dollars per share)	$ 0	$ (0.14)
Parent [Member]
NOTE 2 - MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) - Business Acquisition, Pro Forma Information [Line Items]
Revenue	$ 723,172	$ 1,007,379
Net Loss	(1,633,713)	(2,427,169)
Net Loss available to common shareholders	$ (1,633,713)	$ (2,427,169)
Pro forma Loss per common share Basic and diluted (in Dollars per share)	$ (0.04)	$ (0.11)

NOTE 2 - MERGER WITH MATRIX _3

NOTE 2 - 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
Scenario, Adjustment [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Current assets	(2,581,641)
Oil and gas properties	2,581,641
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

NOTE 2 - MERGER WITH MATRIX _4

NOTE 2 - MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) - Equity Method Investments	9 Months Ended
	Dec. 31, 2018USD ($)
RMX Resources, LLC [Member]
Balance Sheet:
Total Assets	$ 14,351,652
Total Liabilities	7,767,722
Members Equity	6,583,931
Results of Operations:
Net Operating Revenue	1,754,732
Loss from Continuing Operations	(36,293)
Net Loss	333,931
RMX Resources, LLC [Member]
Balance Sheet:
Total Assets	71,758,262
Total Liabilities	38,838,608
Members Equity	32,919,654
Results of Operations:
Net Operating Revenue	8,773,661
Loss from Continuing Operations	(181,464)
Net Loss	$ 1,669,654

NOTE 3 - OIL AND GAS PROPERTI_3

NOTE 3 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Details) - Schedule of Property, Plant and Equipment - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Producing properties, including intangible drilling costs	$ 9,340,779	$ 3,755,705
Undeveloped properties	25,582	1,435
Lease and well equipment	3,350,893	4,119,802
Oil and gas, gross	12,717,254	7,876,942
Accumulated depletion, depreciation and amortization	(6,402,657)	(6,582,648)
Oil and gas, net	6,314,597	1,294,294
Property, Plant and Equipment, Gross	1,218,615	1,132,987
Accumulated depreciation	(1,125,722)	(1,125,039)
Property, Plant and Equipment, Net	92,893	7,948
Oil and gas properties, equipment and fixtures	6,407,490	1,302,242
Land [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	83,405	0
Vehicles [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	40,061	40,061
Furniture and Fixtures [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 1,095,149	$ 1,092,926

NOTE 3 - OIL AND GAS PROPERTI_4

NOTE 3 - 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, 2018	Dec. 31, 2017
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Abstract]
Acquisition – Proved	$ 0	$ 0
Acquisition- Unproved	0	0
Development	3,838,998	4,525,452
Exploration	$ 0	$ 0

NOTE 3 - OIL AND GAS PROPERTI_5

NOTE 3 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Details) - Capitalized Exploratory Well Costs, Roll Forward - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
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

NOTE 3 - OIL AND GAS PROPERTI_6

NOTE 3 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Details) - Results of Operations for Oil and Gas Producing Activities Disclosure - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Results of Operations for Oil and Gas Producing Activities Disclosure [Abstract]
Oil and gas sales	$ 1,599,362	$ 554,235
Production related costs	(1,613,368)	(435,637)
Lease Impairment	(1,183,515)	(289,775)
Depreciation, depletion and amortization	(722,935)	(116,017)
Results of operations from producing and exploration activities	(1,920,456)	(287,194)
Income Taxes (Benefit)	0	0
Net Results	$ (1,920,456)	$ (287,194)

NOTE 4 - ASSET RETIREMENT OBL_3

NOTE 4 - ASSET RETIREMENT OBLIGATION (Details) - Schedule of Change in Asset Retirement Obligation - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
NOTE 4 - ASSET RETIREMENT OBLIGATION (Details) - Schedule of Change in Asset Retirement Obligation [Line Items]
Asset retirement obligation, Beginning of the year	$ 1,000,908	$ 952,110
Liabilities incurred	595,583	53,142
Sales	(486,585)	0
Accretion expense	(110,358)	(4,344)
Asset retirement obligation, End of year	2,366,456	1,000,908
Settlements	(52,636)	0
RMX Resources, LLC [Member]
NOTE 4 - ASSET RETIREMENT OBLIGATION (Details) - Schedule of Change in Asset Retirement Obligation [Line Items]
Liabilities incurred	$ 1,419,544	$ 0

NOTE 5 - TURNKEY DRILLING OBL_2

NOTE 5 - TURNKEY DRILLING OBLIGATION (Details) - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Revenue from Contract with Customer [Abstract]
Contract with Customer, Liability, Current	$ 6,213,283	$ 5,891,898

NOTE 6 - NOTES PAYABLE (Details

NOTE 6 - NOTES PAYABLE (Details) - USD ($)	Oct. 03, 2018	Dec. 31, 2018	Dec. 31, 2017
NOTE 6 - NOTES PAYABLE (Details) [Line Items]
Notes Payable		$ 390,839	$ 0
Debt, Forza Operating, LCC [Member]
NOTE 6 - 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

NOTE 7 - INCOME TAXES (Details)

NOTE 7 - INCOME TAXES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
NOTE 7 - INCOME TAXES (Details) [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	34.00%
Operating Loss Carryforwards (in Dollars)	$ 19,151,810
Operating Loss Carryforwards, Expiration Date	2024
Domestic Tax Authority [Member]
NOTE 7 - INCOME TAXES (Details) [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	35.00%

NOTE 7 - INCOME TAXES (Details

NOTE 7 - INCOME TAXES (Details) - Schedule of Deferred Tax Assets and Liabilities - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Deferred Tax Assets (Liabilities):
Statutory Depletion Carry Forward	$ 367,149	$ 369,591
Net Operating Loss	7,121,912	3,130,841
Other	708,057	1,013,329
Share-Based Compensation	86,510	69,609
Capital Loss / AMT Credit Carry Forward	9,458	18,915
Charitable Contributions Carry Forward	6,158	10,025
Allowance for Doubtful Accounts	597,519	514,067
Oil and Gas Properties and Fixed Assets	5,987,061	4,839,823
Investment in RMX Joint Venture	(1,247,847)	0
	13,635,977	9,966,200
Valuation Allowance	(13,635,977)	(9,966,200)
Net Deferred Tax Asset	$ 0	$ 0

NOTE 7 - INCOME TAXES (Detai_2

NOTE 7 - INCOME TAXES (Details) - Schedule of Effective Income Tax Rate Reconciliation - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Schedule of Effective Income Tax Rate Reconciliation [Abstract]
Tax (benefit) computed at statutory rate of 21% for 2018 and 34% for 2017	$ (4,935,909)	$ (825,237)
Meals & Entertainment	1,320	0
Investor Incentive Expense	7	0
Transaction Costs	160,927	0
Loss on Warrants Issued to RMX	302,398	0
Prior-year true-up for Books	2,075,440	0
Deferred State Taxes, net of federal benefit	(1,009,601)	0
Other non-deductible expenses	(264,359)	1,393
Change in valuation allowance	3,669,777	823,844
Provision (benefit)	$ 0	$ 0

NOTE 7 - INCOME TAXES (Detai_3

NOTE 7 - INCOME TAXES (Details) - Schedule of Effective Income Tax Rate Reconciliation (Parentheticals)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Schedule of Effective Income Tax Rate Reconciliation [Abstract]
Statutory rate	21.00%	34.00%

NOTE 7 - INCOME TAXES (Detai_4

NOTE 7 - INCOME TAXES (Details) - Schedule of Components of Income Tax Expense (Benefit) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
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

NOTE 8 - SERIES B PREFERRED S_2

NOTE 8 - SERIES B PREFERRED STOCK (Details) - Series B Preferred Stock [Member] - USD ($)	Dec. 17, 2018	Mar. 07, 2018	Dec. 31, 2018	Mar. 06, 2018
NOTE 8 - 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	59,416
Dividends, Preferred Stock, Paid-in-kind (in Dollars)	$ 594,613

NOTE 9 - COMMON STOCK (Details)

NOTE 9 - COMMON STOCK (Details)	Apr. 13, 2018$ / sharesshares	Mar. 07, 2018shares	Jul. 31, 2016USD ($)$ / sharesshares	Apr. 30, 2016USD ($)$ / sharesshares	Nov. 30, 2015USD ($)$ / sharesshares
NOTE 9 - COMMON STOCK (Details) [Line Items]
Number of Investors					10
Stock Issued During Period, Shares, New Issues | shares		2,012,400			497,740
Shares Issued, Price Per Share | $ / shares					$ 0.408
Class Of Warrant or Rights Granted | shares					248,873
Class of Warrant or Right, Exercise Price of Warrants or Rights | $ / shares					$ 1
Warrants and Rights Outstanding, Term					3 years
Proceeds from Issuance or Sale of Equity | $					$ 203,080
Number of Subsidiaries	2
Securities Purchase Agreement [Member]
NOTE 9 - COMMON STOCK (Details) [Line Items]
Number of Investors			3	1
Stock Issued During Period, Shares, New Issues | shares			2,392,500	622,316
Shares Issued, Price Per Share | $ / shares			$ 0.40	$ 0.3214
Class Of Warrant or Rights Granted | shares	4,000,000
Class of Warrant or Right, Exercise Price of Warrants or Rights | $ / shares			$ 0.80	$ 0.5356
Proceeds from Issuance or Sale of Equity | $			$ 957,000	$ 200,000
Class of Warrant or Right, Number of Securities Called by Warrants or Rights | shares			478,500	311,158
Warrant Term			2 years	3 years
Measurement Input, Exercise Price [Member] | Securities Purchase Agreement [Member]
NOTE 9 - COMMON STOCK (Details) [Line Items]
Class of Warrant or Right, Exercise Price of Warrants or Rights | $ / shares	$ 1

NOTE 10 - OPERATING LEASES (Det

NOTE 10 - OPERATING LEASES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
NOTE 10 - OPERATING LEASES (Details) [Line Items]
Description of Lessee Leasing Arrangements, Operating Leases	Royale Energy occupies office space through the use of certain leases, one for their office in El Cajon, CA and one for an office and yard in Woodland, CA.
Operating Leases, Rent Expense	$ 210,280	$ 110,909
El Cajon, CA [Member]
NOTE 10 - OPERATING LEASES (Details) [Line Items]
Description of Lessee Leasing Arrangements, Operating Leases	yearly increase of 3.5%
Lessee, Operating Lease, Term of Contract	62 months
San Diego, CA [Member] | Minimum [Member]
NOTE 10 - OPERATING LEASES (Details) [Line Items]
Operating Leases, Rent Expense, Minimum Rentals	$ 6,148
San Diego, CA [Member] | Maximum [Member]
NOTE 10 - OPERATING LEASES (Details) [Line Items]
Operating Leases, Rent Expense, Minimum Rentals	$ 10,801
Woodland, CA [Member]
NOTE 10 - OPERATING LEASES (Details) [Line Items]
Description of Lessee Leasing Arrangements, Operating Leases	month-to-month basis
Operating Leases, Rent Expense, Minimum Rentals	$ 500
Santa Barbara [Member]
NOTE 10 - OPERATING LEASES (Details) [Line Items]
Operating Leases, Rent Expense, Minimum Rentals	$ 7,843

NOTE 10 - OPERATING LEASES (De

NOTE 10 - OPERATING LEASES (Details) - Schedule of Future Minimum Rental Payments for Operating Leases	Dec. 31, 2018USD ($)
Schedule of Future Minimum Rental Payments for Operating Leases [Abstract]
2019	$ 217,224
2020	127,355
2021	131,602
2022	13,802
2023	0
Total	$ 489,983

NOTE 11 - RELATED PARTY TRANS_2

NOTE 11 - RELATED PARTY TRANSACTIONS (Details)	Mar. 14, 2019	Dec. 31, 2018USD ($)
Donald H. Hosmer, co-president and co-chief executive officer [Member]
NOTE 11 - RELATED PARTY TRANSACTIONS (Details) [Line Items]
Due to Related Parties		$ 2,994
Stephen M. Hosmer, co-president, co-chief executive officer and chief financial officer [Member]
NOTE 11 - RELATED PARTY TRANSACTIONS (Details) [Line Items]
Due from Related Parties		14,706
RMX Resources, LLC [Member]
NOTE 11 - RELATED PARTY TRANSACTIONS (Details) [Line Items]
Due to Related Parties		552,645
RMX Resources, LLC [Member] | Various Oil and Gas Customers [Member]
NOTE 11 - RELATED PARTY TRANSACTIONS (Details) [Line Items]
Due to Related Parties		312,000
Subsequent Event [Member] | Donald H. Hosmer, co-president and co-chief executive officer [Member]
NOTE 11 - RELATED PARTY TRANSACTIONS (Details) [Line Items]
Number of Wells, Participated Individually	179
Subsequent Event [Member] | Stephen M. Hosmer, co-president, co-chief executive officer and chief financial officer [Member]
NOTE 11 - RELATED PARTY TRANSACTIONS (Details) [Line Items]
Number of Wells, Participated Individually	179
Royale Energy [Member] | Subsequent Event [Member] | Donald H. Hosmer, co-president and co-chief executive officer [Member]
NOTE 11 - RELATED PARTY TRANSACTIONS (Details) [Line Items]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	2.69%
Royale Energy [Member] | Subsequent Event [Member] | Stephen M. Hosmer, co-president, co-chief executive officer and chief financial officer [Member]
NOTE 11 - RELATED PARTY TRANSACTIONS (Details) [Line Items]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	2.93%
Matrix Oil Corporation (“MOC”) [Member] | Certain Matrix Employees [Member] | Unpaid Salaries [Member]
NOTE 11 - RELATED PARTY TRANSACTIONS (Details) [Line Items]
Due to Related Parties		1,616,205
Matrix Oil Corporation (“MOC”) [Member] | Certain Matrix Principals [Member] | Interest on Notes Payable [Member]
NOTE 11 - RELATED PARTY TRANSACTIONS (Details) [Line Items]
Due to Related Parties		$ 1,306,605

NOTE 12 - STOCK COMPENSATION _3

NOTE 12 - STOCK COMPENSATION PLAN (Details) - USD ($)	Oct. 10, 2018	Dec. 31, 2018	Dec. 31, 2017
NOTE 12 - 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	$ 0
Share Price	$ 0.34	0.13
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	$ 0
Allocated Share-based Compensation Expense (in Dollars)		$ 64,954	$ 0
Employee Stock Option [Member] | Chief Financial Officer [Member]
NOTE 12 - 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
2014 Stock Options [Member] | Employee Stock Option [Member]
NOTE 12 - STOCK COMPENSATION PLAN (Details) [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term		1 year

NOTE 12 - STOCK COMPENSATION _4

NOTE 12 - STOCK COMPENSATION PLAN (Details) - Schedule of Share-based Compensation, Stock Options, Activity - $ / shares	Oct. 10, 2018	Dec. 31, 2018	Dec. 31, 2017
Options
Outstanding and Exercisable, Shares (in Shares)		0	100,000
Outstanding and Exercisable, Weighted Average Exercise Price		$ 0	$ 5
Granted or Vested, Shares (in Shares)		250,000	0
Granted or Vested, Weighted Average Exercise Price	$ 0.31	$ 0.31	$ 0
Exercised, Shares (in Shares)		0	0
Exercised, Weighted Average Exercise Price		$ 0	$ 0
Forfeited, Shares (in Shares)		0	(100,000)
Forfeited, Weighted Average Exercise Price		$ 0	$ 0
Outstanding and Exercisable, Shares (in Shares)		250,000	0
Outstanding and Exercisable, Weighted Average Exercise Price		$ 0.31	$ 0
Weighted-average Fair Value of Options Granted During the Year	$ 0.26	$ 64,954	$ 0

NOTE 13 - SIMPLE IRA PLAN (Deta

NOTE 13 - SIMPLE IRA PLAN (Details) - Pension Plan [Member] - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
NOTE 13 - SIMPLE IRA PLAN (Details) [Line Items]
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	3.00%
Defined Contribution Plan, Cost	$ 35,312	$ 28,947

NOTE 15 - CONCENTRATIONS OF C_2

NOTE 15 - CONCENTRATIONS OF CREDIT RISK (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
NOTE 15 - CONCENTRATIONS OF CREDIT RISK (Details) [Line Items]
Cash, FDIC Insured Amount	$ 250,000
Cash, Uninsured Amount	$ 5,700,000	$ 2,800,000
Customer A [Member] | Customer Concentration Risk [Member] | Sales Revenue, Net [Member]
NOTE 15 - CONCENTRATIONS OF CREDIT RISK (Details) [Line Items]
Concentration Risk, Percentage	32.00%

NOTE 17 - SUBSEQUENT EVENTS (De

NOTE 17 - SUBSEQUENT EVENTS (Details) - Subsequent Event [Member]	Mar. 11, 2019USD ($)MBoemJ	Mar. 31, 2019USD ($)shares
NOTE 17 - SUBSEQUENT EVENTS (Details) [Line Items]
SEC pricing and discounted, Oil and Gas Property, Percentage	10.00%
Minimum Number Of Wells To Be Offered	2
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures (in Shares) | shares		989,966
Stock Issued During Period, Value, Share-based Compensation, Net of Forfeitures		$ 240,008
RMX Resources, LLC [Member]
NOTE 17 - SUBSEQUENT EVENTS (Details) [Line Items]
Estimated Liability	$ 552,645
Bellevue Field [Member]
NOTE 17 - SUBSEQUENT EVENTS (Details) [Line Items]
Production, Barrels of Oil Equivalents | MBoe	5.145
Bellevue Field [Member] | Oil and Gas Properties [Member]
NOTE 17 - SUBSEQUENT EVENTS (Details) [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure	$ 67,671
Whittier Field [Member]
NOTE 17 - SUBSEQUENT EVENTS (Details) [Line Items]
Production, Barrels of Oil Equivalents | mJ	140.647
Whittier Field [Member] | Oil and Gas Properties [Member]
NOTE 17 - SUBSEQUENT EVENTS (Details) [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure	$ 2,400,000
RMX Resources, LLC [Member]
NOTE 17 - SUBSEQUENT EVENTS (Details) [Line Items]
Working Interest, Percentage	75.00%
RMX Resources, LLC [Member] | Sunny Frog Oil, LLC [Member]
NOTE 17 - SUBSEQUENT EVENTS (Details) [Line Items]
Payments for Legal Settlements	$ 75,000
Sunny Frog Oil, LLC [Member]
NOTE 17 - SUBSEQUENT EVENTS (Details) [Line Items]
Working Interest, Percentage	50.00%

NOTE 18 - SUPPLEMENTAL INFORM_3

NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details)	12 Months Ended
	Dec. 31, 2018USD ($)$ / Mcf$ / bblMcfbbl	Dec. 31, 2017USD ($)Mcfbbl	Dec. 31, 2016Mcfbbl
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Oil and Gas Property, Successful Effort Method (in Dollars) | $	$ 9,340,779	$ 3,755,705
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates		307,371
Oil and Gas Properties [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Oil and Gas Property, Successful Effort Method (in Dollars) | $	$ 57,800,000
Proved Undeveloped Reserves [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates		18,598
Proved Undeveloped Reserve (Volume)			314,925
Producing and Non-producing Natural Gas Reserves at California [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Number of Wells		8
Producing and Non-producing Natural Gas Reserves at Utah [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Number of Wells		1
Drilled and Began Producing in 2011 [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates		122,998
Proved Developed Reserves (Volume)			63,350
Drilled and Began Producing Prior to 2000 [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates		118,006
Proved Developed Reserves (Volume)			128,165
Drilled and Began Producing in 2010 [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates		15,227
Proved Developed Reserves (Volume)		618,709
Drilled and Began Producing in 2006 [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates		14,688
Drilled and Began Producing in 2012 [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates		10,994
Proved Developed Reserves (Volume)			0
Drilled and Began Producing in 2008 [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Undeveloped Reserve (Volume)			13,878
Drilled and Began Producing Prior to 2015 [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates		6,084
Natural Gas [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	(401,498)	307,371
Proved Developed Reserves (Volume)	1,914,900	1,798,697	1,699,997
Proved Undeveloped Reserve (Volume)	1,071,300	333,524	314,925
Natural Gas [Member] | Proved Undeveloped Reserves [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	(333,524)
Number of Wells	1
Oil [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | bbl	(79,135)	(5,549)
Proved Developed Reserves (Volume) | bbl	148,600	202	5,823
Proved Undeveloped Reserve (Volume) | bbl	997,800
Oil [Member] | Proved Developed Reserves [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | bbl	(81,054)
RMX Resources, LLC [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	20.00%
PG&E Citygate [Member] | Natural Gas [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Average Sales Prices (in Dollars per Thousand Cubic Feet) | $ / Mcf	3.10
West Texas Intermediate [Member] | Oil [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Average Sales Prices (in Dollars per Thousand Cubic Feet) | $ / bbl	65.56
Measurement Input, Discount Rate [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Oil and Gas Property, Measurement Input	10

NOTE 18 - SUPPLEMENTAL INFORM_4

NOTE 18 - 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, 2018Mcfbbl	Dec. 31, 2017Mcfbbl	Dec. 20, 2017Mcfbbl
Oil [Member]
Reserve Quantities [Line Items]
Beginning of period | bbl	202	5,853
Revisions of previous estimates | bbl	(79,135)	(5,549)
Production | bbl	(20,329)	(102)
Merger Acquisition | bbl	11,375,784
Purchase of minerals in place | bbl	29,300
Sales of minerals in place | bbl	(10,159,421)
Proved reserves end of period | bbl	1,146,400	202
Beginning of period | bbl	202	5,823
End of period | bbl	148,600	202
End of period | bbl	997,800
Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning of period | Mcf	2,132,221	2,014,921
Revisions of previous estimates | Mcf	(401,498)	307,371
Production | Mcf	(135,396)	(190,111)
Extensions, discoveries and improved recovery | Mcf	25,014	40
Merger Acquisition | Mcf	13,459,933
Purchase of minerals in place | Mcf	116,110
Sales of minerals in place | Mcf	(12,210,184)	(450,488)
Proved reserves end of period | Mcf	2,986,200	2,132,221
Beginning of period | Mcf	1,798,697	1,699,997
End of period | Mcf	1,914,900	1,798,697
Beginning of period | Mcf	333,524	314,925
End of period | Mcf	1,071,300	333,524
The 20% Interest in RMX [Member] | Oil [Member]
Reserve Quantities [Line Items]
Beginning of period | bbl			3,739,820
Production | bbl			(41,240)
Purchase of minerals in place | bbl			551,585
Proved reserves end of period | bbl			4,219,140
Beginning of period | bbl			791,073
End of period | bbl			993,080
Beginning of period | bbl			2,917,721
End of period | bbl			3,226,060
The 20% Interest in RMX [Member] | Natural Gas [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
Beginning of period | Mcf			660,754
End of period | Mcf			635,140
Beginning of period | Mcf			3,742,880
End of period | Mcf			3,742,880
RMX Resources, LLC [Member] | Oil [Member]
Reserve Quantities [Line Items]
Beginning of period | bbl	21,095,700	18,699,100
Production | bbl		(206,200)
Purchase of minerals in place | bbl		2,757,926
Proved reserves end of period | bbl		21,095,700
Beginning of period | bbl	4,965,400	3,955,367
End of period | bbl		4,965,400
Beginning of period | bbl	16,130,300	14,588,606
End of period | bbl		16,130,300
RMX Resources, LLC [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning of period | Mcf	21,890,300	22,018,272
Production | Mcf		(127,972)
Proved reserves end of period | Mcf		21,890,300
Beginning of period | Mcf	3,175,700	3,303,772
End of period | Mcf		3,175,700
Beginning of period | Mcf	18,714,400	18,714,400
End of period | Mcf		18,714,400

NOTE 18 - SUPPLEMENTAL INFORM_5

NOTE 18 - 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 - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Total	$ 7,256,900
Cost incurred for proved undeveloped reserves	0	$ 0	$ 243,583
Proved Developed, Proved Non-Producing and Proved Undeveloped Reserves [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
2019	2,130,500
2020	1,881,500
2021	1,500,000
Thereafter	$ 1,744,900

NOTE 18 - SUPPLEMENTAL INFORM_6

NOTE 18 - 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, 2018	Dec. 31, 2017
NOTE 18 - 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	$ 87,467,200	$ 6,065,500
Future production costs	(22,390,900)	(2,117,900)
Future development costs	(7,256,900)	(580,800)
Future income tax expense	(17,345,820)	(1,010,040)
Future net cash flows	40,473,580	2,356,760
10% annual discount for estimated timing of cash flows	(9,827,666)	(712,072)
Standardized measure of discounted future net cash flows	30,645,914	1,644,688
Sales of oil and gas produced, net of production costs	(40,557)	(161,139)
Revisions of previous quantity estimates	(71,162)	87,956
Net changes in prices and production costs	11,683,159	106,303
Sales of minerals in place	(3,061,278)
Purchases of minerals in place	287,300
Merger Acquisition	29,903,670
Extensions, discoveries and improved recovery	59,191	74
Accretion of discount	2,670,000	197,400
Net change in income tax	(12,429,097)	(69,178)
Net increase (decrease)	29,001,226	$ 161,416
The 20% Interest in RMX [Member]
NOTE 18 - 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 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
Purchases of minerals in place	8,673,117
Accretion of discount	5,453,622
Net increase (decrease)	73,598,640
RMX Resources, LLC [Member]
NOTE 18 - 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	1,527,930,900
Future production costs	(421,114,900)
Future development costs	(144,008,100)
Future net cash flows	962,807,900
10% annual discount for estimated timing of cash flows	(594,814,700)
Standardized measure of discounted future net cash flows	367,993,200
Sales of oil and gas produced, net of production costs	(4,053,176)
Formation of RMX joint venture	301,412,679
Purchases of minerals in place	43,365,585
Accretion of discount	27,268,112
Net increase (decrease)	$ 367,993,200

NOTE 18 - SUPPLEMENTAL INFORM_7

NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Future Development Costs, Oil and Gas Production	Dec. 31, 2018USD ($)
Proved Developed Reserves [Member]
NOTE 18 - 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]
NOTE 18 - 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	38,000
Estimated Future Costs, Year 2	91,500
Estimated Future Costs, Year 3	0
Proved Undeveloped Reserves [Member]
NOTE 18 - 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	2,092,500
Estimated Future Costs, Year 2	1,790,000
Estimated Future Costs, Year 3	1,500,000
Proved Developed, Proved Non-Producing and Proved Undeveloped Reserves [Member]
NOTE 18 - 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	2,130,500
Estimated Future Costs, Year 2	1,881,500
Estimated Future Costs, Year 3	$ 1,500,000