Royale Energy Funds 10-K 31 Mar 17 2016 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Mar. 24, 2017	Jun. 30, 2016
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		21,836,033
Entity Public Float			$ 5,395,938
Amendment Flag	false
Entity Central Index Key	864,839
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Smaller Reporting Company
Entity Well-known Seasoned Issuer	No
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY

BALANCE SHEETS

BALANCE SHEETS - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Current Assets:
Cash	$ 4,994,598	$ 3,763,819
Other Receivables, net	676,647	381,192
Revenue Receivables	303,528	147,936
Prepaid Expenses	63,308	114,036
Total Current Assets	6,038,081	4,406,983
Other Assets	610,779	730,844
Oil And Gas Properties (Successful Efforts Basis), Real Property and Equipment and Fixtures, net	1,733,424	6,532,478
Total Assets	8,382,284	11,670,305
Current Liabilities:
Accounts Payable and Accrued Expenses	2,469,245	2,937,226
Cash Advances on Pending Transactions	1,580,000	0
Current Portion of Long-Term Debt	0	30,528
Deferred Drilling Obligations	7,894,001	8,415,528
Total Current Liabilities	11,943,246	11,383,282
Asset Retirement Obligation	952,110	1,096,179
Note Payable, less current portion	0	1,416,325
Total Noncurrent Liabilities	952,110	2,512,504
Total Liabilities	12,895,356	13,895,786
Stockholders' Deficit:
Convertible Preferred Stock, Series AA, No Par Value, 147,500 Shares Authorized; 0 and 46,662 Shares Issued and Outstanding, at December 31, 2016 and 2015, Respectively	0	136,149
Common Stock, No Par Value, 30,000,000 Shares Authorized; 21,836,033 and 16,396,579 Shares Issued and Outstanding, at December 31, 2016 and 2015, respectively	41,265,449	39,272,429
Accumulated Deficit	(45,778,521)	(41,634,059)
Total Stockholders' Deficit	(4,513,072)	(2,225,481)
Total Liabilities and Stockholders' Deficit	$ 8,382,284	$ 11,670,305

BALANCE SHEETS (Parentheticals)

BALANCE SHEETS (Parentheticals) - $ / shares	Dec. 31, 2016	Dec. 31, 2015
Convertible Preferred Stock, Series AA, no par value (in Dollars per share)
Convertible Preferred Stock, Series AA, shares authorized	147,500	147,500
Convertible Preferred Stock, Series AA, shares issued	0	46,662
Convertible preferred stock, Series AA, shares outstanding	0	46,662
Common stock, no par value (in Dollars per share)
Common stock, shares authorized	30,000,000	30,000,000
Common stock, shares issued	21,836,033	16,396,579
Common Stock, shares outstanding	21,836,033	16,396,579

STATEMENTS OF COMPREHENSIVE INC

STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Sale of Oil and Gas	$ 538,631	$ 1,018,928
Supervisory Fees and Other	675,208	694,160
Total Revenues	1,213,839	1,713,088
Costs and Expenses:
General and Administrative	2,614,502	3,181,571
Lease Operating	594,241	1,000,769
Delay Rentals	0	448,313
Lease Impairment	2,071,849	424,163
Well Equipment Write Down	19,151	60,960
Bad Debt Expense	0	536,538
Legal and Accounting	627,577	558,471
Marketing	294,522	326,143
Depreciation, Depletion and Amortization	283,874	400,813
Total Costs and Expenses	6,505,716	6,937,741
Gain on Turnkey Drilling Programs	460,210	2,330,969
Loss from Operations	(4,831,667)	(2,893,684)
Other Income (Expense):
Interest Expense	(114,159)	(86,088)
Gain on Sale of Assets	483,394	968,956
Gain on Settlement of Accounts Payable	341,751	0
Loss on Disposal of Assets	(23,781)	0
Loss Before Income Tax Expense	(4,144,462)	(2,010,816)
Provision for Income Taxes	0	0
Net Loss	$ (4,144,462)	$ (2,010,816)
Basic Loss Per Share (in Dollars per share)	$ (0.22)	$ (0.13)
Diluted Loss Per Share (in Dollars per share)	$ (0.22)	$ (0.13)
Other Comprehensive Income (Loss)
Unrealized Loss on Equity Securities	$ 0	$ 0
Less: Reclassification Adjustment for Losses Included in Net Income	0	(6,503)
Other Comprehensive Gain (Loss) before tax	0	6,503
Other Comprehensive Gain (Loss), net of tax	0	6,503
Comprehensive Loss	$ (4,144,462)	$ (2,004,313)

STATEMENTS OF STOCKHOLDERS' EQU

STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($)	Series AA Preferred Stock [Member]Preferred Stock [Member]	RDO Private Placement [Member]Common Stock [Member]	RDO Private Placement [Member]AOCI Attributable to Parent [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	AOCI Attributable to Parent [Member]	Total
Balance at Dec. 31, 2014	$ 136,149			$ 38,352,370	$ (39,623,243)	$ (6,503)	$ (1,141,227)
Balance (in Shares) at Dec. 31, 2014	46,662			14,945,789
Common Stock Private Placement		$ 199,195	$ 199,195	$ 490,116			490,116
Common Stock Private Placement (in Shares)		485,486		701,397
Common Stock Issued to Executives in lieu of Compensation				$ 143,871			143,871
Common Stock Issued to Executives in lieu of Compensation (in Shares)				263,907
Available for Sale Securities – Unrealized Gain (Loss), net of tax						6,503	6,503	$ 6,503
Net Income (Loss)					(2,010,816)		(2,010,816)	(2,010,816)
Director’s Stock Option Grant				$ 86,877			86,877
Balance at Dec. 31, 2015	$ 136,149			$ 39,272,429	(41,634,059)	0	(2,225,481)	(2,225,481)
Balance (in Shares) at Dec. 31, 2015	46,662			16,396,579
Common Stock Private Placement				$ 1,160,885			1,160,885
Common Stock Private Placement (in Shares)				3,027,070
Common Stock Issued to Executives in lieu of Compensation				$ 645,986			645,986
Common Stock Issued to Executives in lieu of Compensation (in Shares)				2,335,461
Issuance of Common Stock in Settlement of AP				$ 50,000			50,000
Issuance of Common Stock in Settlement of AP (in Shares)				76,923
Conversion of Convertible Securities	$ (136,149)			$ 136,149
Conversion of Convertible Securities (in Shares)	(46,662)			23,331
Available for Sale Securities – Unrealized Gain (Loss), net of tax								0
Net Income (Loss)					(4,144,462)		(4,144,462)	(4,144,462)
Balance at Dec. 31, 2016	$ 0			$ 41,265,449	$ (45,778,521)	$ 0	$ (4,513,072)	$ (4,513,072)
Balance (in Shares) at Dec. 31, 2016	0			21,859,364

STATEMENTS OF CASH FLOWS

STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (Loss)	$ (4,144,462)	$ (2,010,816)
Adjustments to Reconcile Net Loss to Net Cash Used by Operating Activities:
Depreciation, Depletion, and Amortization	283,874	400,813
Lease Impairment	2,071,849	424,163
Gain on Sale of Assets	(483,394)	(968,956)
Gain on Turnkey Drilling Programs	(460,210)	(2,330,969)
Gain on Settlement of Accounts Payable	(341,751)	0
Loss on Disposal of Assets	23,781	0
Bad Debt Expense	0	536,538
Stock-Based Compensation	645,986	230,749
Realized Loss on Equity Securities	0	6,503
Well Equipment and Other Assets Write Down	19,151	60,960
(Increase) Decrease in:
Other & Revenue Receivables	(451,047)	1,187,810
Prepaid Expenses and Other Assets	151,642	(236,615)
Accounts Payable and Accrued Expenses	(587,050)	(1,273,360)
Net Cash Used by Operating Activities	(3,271,631)	(3,973,180)
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for Oil And Gas Properties	(2,058,357)	(3,753,134)
Proceeds from Turnkey Drilling Programs	3,980,499	5,433,476
Proceeds from Sale of Assets	1,286,236	2,334,537
Net Cash Provided by Investing Activities	3,208,378	4,014,879
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash Advances From Investors	1,580,000	0
Principal Payments on Long-Term Debt	(1,446,853)	(29,031)
Proceeds from Issuance of Common Stock	1,160,885	689,310
Net Cash Provided by Financing Activities	1,294,032	660,279
Net Increase in Cash	1,230,779	701,978
Cash at Beginning of Year	3,763,819	3,061,841
Cash at End of Year	4,994,598	3,763,819
Cash Paid for Interest	48,325	86,088
Cash Paid for Taxes	2,100	1,000
Supplemental Schedule of Non-Cash Investing and Financing Transactions:
Conversion of Series AA Stock to Common Stock	136,149	0
Reclassification Adjustment for Losses Included in Net Income	0	(6,503)
Warrants Issued with Common Stock	$ 156,205	$ 0

NOTE 1 - SUMMARY OF SIGNIFICANT

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2016
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. (“Royale Energy,” “Royale,” or the “Company”) is presented to assist in understanding Royale Energy's financial statements. 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. As reflected in the accompanying financial statements, the Company has negative working capital, losses from operations and negative cash flows from operations. Material estimates that are particularly susceptible to significant change relate to the estimate of Company oil and gas reserves prepared by an independent engineering consultant. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proven reserves. Estimated reserves are used in the calculation of depletion, depreciation and amortization, unevaluated property costs, impairment of oil and natural gas properties, estimated future net cash flows, taxes, and contingencies. Liquidity The primary sources of liquidity have historically been issuances of common stock and operations. We believe that the completion of the contemplated merger with will enable us to return to positive cash flow. There is some 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, and the sale of oil and natural gas property participation interest. The Company’s consolidated financial statements reflect an accumulated deficit of $45,778,521, a working capital deficiency of $5,905,165 and a stockholders’ deficit of $4,513,072. 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 include the proposed merger with Matrix and additional financing through issuances of common stock and the reduction of overhead costs. 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. Revenue Recognition Royale’s primary business is oil and gas production. Natural gas flows from the wells into gathering line systems, which are equipped occasionally with compressor systems, which in turn flow into metered transportation and customer pipelines. Monthly, price data and daily production are used to invoice customers for amounts due to Royale Energy and other working interest owners. Royale Energy operates virtually all of its own wells and receives industry standard operator fees. Royale Energy generally sells crude oil and natural gas under short-term agreements at prevailing market prices. Revenues are recognized when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured. Revenues from the production of oil and natural gas properties in which the Royale Energy has an interest with other producers are recognized on the basis of Royale Energy’s net working interest. Differences between actual production and net working interest volumes are not significant. Royale Energy’s financial statements include its pro rata Oil and Gas Property and Equipment 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. 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. Proved oil and gas properties held and used by Royale Energy are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Royale Energy estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated evaluation assumptions for crude oil commodity prices. Annual volumes are based on field production profiles, which are also updated annually. Prices for natural gas and other products are based on assumptions developed annually for evaluation purposes. Impairment analyses are generally based on proved reserves. An asset group would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount the carrying value exceeds fair value. During 2016 and 2015, impairment losses of $2,071,849 and $424,163, respectively, were recorded on various capitalized lease and land costs that were no longer viable. Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that Royale Energy expects to hold the properties. The valuation allowances are reviewed at least annually. 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, 2016 and 2015, Royale Energy had Deferred Drilling Obligations of $7,894,001 and $8,415,528, 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 consists 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, 2016 and 2015, the Company established an allowance for uncollectable accounts of $2,270,773 and $2,270,773, 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 consists 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. 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: For the Year Ended December 31, 2016 Loss (Numerator) Shares (Denominator) Per-Share Amount Basic Loss Per Share: Net loss available to common stock $ (4,144,462 ) 19,185,896 $ (0.22 ) Loss Per Share: Effect of dilutive securities and stock options - $ - Net loss available to common stock $ (4,144,462 ) 19,185,896 $ (0.22 ) For the Year Ended December 31, 2015 Loss (Numerator) Shares (Denominator) Per-Share Amount Basic Loss Per Share: Net income available to common stock $ (2,010,816 ) 15,194,534 $ (0.13 ) Loss Per Share: Effect of dilutive securities and stock options - $ - Net loss available to common stock $ (2,010,816 ) 15,194,534 $ (0.13 ) For the years ended December 31, 2016 and 2015, Royale Energy had dilutive securities of 0 and 23,331, respectively. These securities were not included in the dilutive loss per share due to their antidilutive nature. Stock Based Compensation Royale Energy has a stock-based employee compensation plan, which is more fully described in Note 11. Effective January 1, 2006, the Company adopted the Compensation – Stock Compensation Topic of the FASB Accounting Standards Codification, which addresses the accounting for stock-based payment transactions in which an enterprise receives employee services in exchange for (a) equity instruments of the enterprise or (b) liabilities that are based on the fair value of the enterprise’s equity instruments or that may be settled by the issuance of such equity instruments. The Company uses the Black-Scholes option-pricing model to determine the fair value of stock-based awards. 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 FASB Accounting Standards Codification. 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, 2016 and 2015, 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, 2016, the components of accounts payable and accrued expenses consisted of $1,205,740 in trade accounts payable due to various vendors, $699,068 in payables and accruals related to direct working interest investors revenues and operating costs, $98,172 in accrued expenses related to current drilling efforts, $266,110 for accrued liabilities for amounts set aside mainly for the plugging and abandonment of certain wells, $103,212 for employee related taxes and accruals, $65,833 related to interest payable on cash advances from investors and $18,662 in federal and state income taxes payable. At December 31, 2015, the components of accounts payable and accrued expenses consisted of $2,167,809 in trade accounts payable due to various vendors, $238,320 in payables and accruals related to direct working interest investors operating costs, $369,837 for accrued liabilities for amounts set aside mainly for the plugging and abandonment of certain wells, $140,798 for employee related taxes and accruals and $20,462 in federal and state income taxes payable. Cash Advances on Pending Transactions In July 2016, Royale entered into negotiations for certain equity and debt financing transactions, described below. The funds from these transactions is to be used to continue drilling activities, fund expenses to be incurred in connection with completion of Royale Energy’s proposed merger with Matrix Oil Corporation and for general corporate purposes. At December 31, 2016, the paperwork for these transactions had not been finalized and as such have been included as Cash Advances from Investors: The Company entered in negotiations with two separate investors for 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 notes mature one year from the date of issuance and carry a 10% interest rate, which is due at maturity. The conversion of the notes to shares is subject to shareholder approval. Reclassifications Certain items in the financial statements have been reclassified to maintain consistency and comparability for all periods presented herein. Recently Issued Accounting Pronouncements The Company has reviewed the updates issued by the Financial Accounting Standards Board (FASB) during the year ended December 31, 2016. ASU 2015-17: Income Taxes (Topic740) Balance Sheet Classification of Deferred Taxes – In November 2015, FASB issued ASU 2015-17 which eliminates the requirement to present deferred tax assets and liabilities as current and noncurrent amounts in a classified balance sheet. The new standard requires deferred tax assets and liabilities to be classified as noncurrent. The amendments in this update are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Earlier application is permitted for all entities as of the beginning of an interim or annual reporting period and may be applied either prospectively or retrospectively to all periods presented. 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. The adoption of this guidance has no impact on our results of operations or cash flows. ASU 2016-01: Financial Instruments – Overall – Recognition and Measurement of Financial Assets and Financial Liabilities (Subtopic 825-10) In January 2016, FASB issued ASU 2016-01 which requires an entity to: (i) measure equity investments at fair value through net income, with certain exceptions; (ii) present in Other Comprehensive Income the changes in instrument-specific credit risk for financial liabilities measured using the fair value option; (iii) present financial assets and financial liabilities by measurement category and form of financial asset; (iv) calculate the fair value of financial instruments for disclosure purposes based on an exit price and; (v) assess a valuation allowance on deferred tax assets related to unrealized losses of AFS debt securities in combination with other deferred tax assets. The Update provides an election to subsequently measure certain nonmarketable equity investments at cost less any impairment and adjusted for certain observable price changes. The Update also requires a qualitative impairment assessment of such equity investments and amends certain fair value disclosure requirements. The new standard becomes effective for fiscal years beginning after December 15, 2017. Early adoption is only permitted for the provision related to instrument-specific credit risk and the fair value disclosure exemption provided to nonpublic entities. The Company is currently evaluating the effects of adopting ASU 2016-01 on its consolidated financial statements but the adoption is not expected to have a significant impact on the Company’s consolidated financial statements. ASU No. 2016-02: Leases (Topic 842). In February 2016, FASB issued ASU 2016-02 which aims to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and requiring disclosure of key information about leasing agreements. Entities are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. The Company is currently evaluating the effects of adopting ASU 2016-02 on its consolidated financial statements but the adoption is not expected to have a significant impact on the Company’s financial statements. ASU 2016-09: Compensation—Stock Compensation (Topic 718): Improvements to Employee Share- Based Payment Accounting. In March 2016, FASB issued ASU 2016-09 which amends several aspects of the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Early adoption is permitted. If early adopted, an entity must adopt all of the amendments in the same period. The Company is currently evaluating the impact of the adoption of ASU 2016-09 on the Company’s financial statements. ASU 2016-13: Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. In June 2016, FASB issued ASU 2016-13 which was issued to provide more decision-useful information about the expected credit losses on financial instruments and changes the loss impairment methodology. To achieve this objective, the amendments in ASU 2016-13 replace the incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. The amendments affect entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance-sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. This pronouncement is effective for reporting periods beginning after December 15, 2019 using a modified retrospective adoption method. A prospective transition approach is required for debt securities for which an other-than-temporary impairment had been recognized before the effective date. The Company is currently evaluating the impact of the adoption of ASU 2016-13 on the Company’s financial statements. ASU 2016-15: Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. In August 2016, FASB issued ASU 2016-15 which addresses several specific cash flow issues. ASU 2016-15 is effective for annual and interim periods beginning January 1, 2018, with early adoption permitted, and requires full retrospective application on adoption. The Company is currently evaluating the effects of adopting ASU 2016-15 on its financial statements but the adoption is not expected to have a significant impact on the Company’s financial statements. ASU 2014-15: Presentation of Financial Statements - Going Concern (Subtopic 205-40) - Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. The Company adopted ASU 2014-15 as of December 31, 2016. This ASU requires management to assess a company's ability to continue as a going concern and to provide related disclosures in certain circumstances.

NOTE 2 - OIL AND GAS PROPERTIES

NOTE 2 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES	12 Months Ended
	Dec. 31, 2016
Oil and Gas Property [Abstract]
Oil and Gas Properties [Text Block]	NOTE 2 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES Oil and gas properties, equipment and fixtures consist of the following at December 31: 2016 2015 Oil and Gas Producing properties, including intangible drilling costs $ 3,755,705 $ 5,217,637 Undeveloped properties 307,158 2,381,564 Lease and well equipment 4,128,178 4,339,122 8,191,041 11,938,323 Accumulated depletion, depreciation and amortization (6,468,279 ) (7,656,731 ) $ 1,722,762 $ 4,281,592 Commercial and Other 2016 2015 Real estate, including furniture and fixtures $ - $ 2,266,050 Vehicles 40,061 118,061 Furniture and equipment 1,089,648 1,120,760 1,129,709 3,504,871 Accumulated depreciation (1,119,047 ) (1,253,985 ) 10,662 2,250,886 $ 1,733,424 $ 6,532,478 The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed: 2016 2015 Acquisition - Proved $ - 69,446 Acquisition- Unproved $ - 113,749 Development $ 1,210,261 672,651 Exploration $ 2,603,209 1,845,585 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 2016 or 2015. 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. 12 Months Ended December 31, 2016 2015 Beginning balance at January 1 $ - $ - Additions to capitalized exploratory well costs pending the determination of proved reserves $ - $ 85,640 Reclassifications to wells, facilities, and equipment based on the determination of proved reserves $ - $ (85,640 ) 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) for the two years ended December 31, are as follows: 2016 2015 Oil and gas sales $ 538,631 1,018,928 Production related costs (594,241 ) (1,449,082 ) Lease Impairment (2,071,849 ) (424,163 ) Depreciation, depletion and amortization (283,874 ) (400,813 ) Results of operations from producing and exploration activities $ (2,411,333 ) (1,255,130 ) Income Taxes (Benefit) - - Net Results $ (2,411,333 ) (1,255,130 )

NOTE 3 - ASSET RETIREMENT OBLIG

NOTE 3 - ASSET RETIREMENT OBLIGATION	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation Disclosure [Text Block]	NOTE 3 - 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. 2016 2015 Asset retirement obligation, Beginning of the year $ 1,096,179 $ 804,206 Liabilities incurred during the period 90,000 321,560 Settlements (10,498 ) (68,360 ) Sales (229,465 ) - Accretion expense 5,894 38,773 Asset retirement obligation, End of year $ 952,110 $ 1,096,179

NOTE 4 - TURNKEY DRILLING OBLIG

NOTE 4 - TURNKEY DRILLING OBLIGATION	12 Months Ended
	Dec. 31, 2016
Deferred Revenue Disclosure [Abstract]
Deferred Revenue Disclosure [Text Block]	NOTE 4 - 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. As of December 31, 2016 and 2015, Royale Energy had recorded deferred turnkey drilling associated with undrilled wells of $7,894,001 and $8,415,528, respectively, as a current liability.

NOTE 5 - LONG-TERM DEBT

NOTE 5 - LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2016
Disclosure Text Block [Abstract]
Long-term Debt [Text Block]	NOTE 5 - LONG-TERM DEBT 2016 2015 On December 24, 2013, Royale Energy, Inc. entered into an agreement between the Company, as buyer, and North Island Financial Credit Union as seller, for the purchase of commercial property in San Diego, California, for a purchase price of $2,000,000, of which $500,000 was paid in cash on the date of purchase, and $1,500,000 was borrowed from AmericanWest Bank, NA, with a note secured by the property being purchased. The note carries an interest rate of 5.75% until paid in full. Royale will pay this loan in 119 regular payments of $9,525 each and one balloon payment estimated at $1,150,435. Royale’s first payment was due February 1, 2014, and all subsequent payments are due on the same day of each month after that. Royale’s final payment will be due on January 1, 2024, and will be for all principal and all accrued interest not yet paid. Payments include principal and interest. Stephen M Hosmer, President, CFO is named as a personal guarantor of the loan. The loan agreement contains certain covenants that, among other things, Royale must maintain a ratio of EBITDA-Debt Service Coverage in excess of 1.50 to 1.00. At December 31, 2015, Royale was not in compliance with this covenant, but obtained a forbearance from the bank from terms of that covenant to May 26, 2016. In June 2016, the sale of the building was completed and the related principal and interest payments were paid in full. $ - $ 1,446,853 Total Long Term Debt $ - $ 1,446,853 Less Current Maturity - $ 30,528 Long Term Debt Less Current Portion $ - $ 1,416,325

NOTE 6 - INCOME TAXES

NOTE 6 - INCOME TAXES	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Tax Disclosure [Text Block]	NOTE 6 - INCOME TAXES Deferred tax assets and liabilities reflect the net tax effect of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and amounts used for income tax purposes. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. In 2016, the Company adopted Accounting Standards Update (ASU) 2015-17 and has classified all of its deferred tax assets and liabilities as noncurrent on its balance sheet. Significant components of the Company’s deferred assets and liabilities at December 31, 2016 and 2015, respectively, are as follows: 2016 2015 Deferred Tax Assets (Liabilities): Statutory Depletion Carry Forward $ 474,250 $ 555,093 Net Operating Loss 5,392,208 4,651,428 Other 1,255,372 1,247,829 Share-Based Compensation 104,388 96,536 Capital Loss / AMT Credit Carry Forward 18,915 18,915 Charitable Contributions Carry Forward 13,102 21,644 Allowance for Doubtful Accounts 886,056 887,418 Oil and Gas Properties and Fixed Assets 5,922,031 4,980,324 $ 14,066,322 $ 12,459,187 Valuation Allowance (14,066,322 ) (12,459,187 ) Net Deferred Tax Asset $ - $ - At the end of 2015, 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 2015. At the end of 2016, 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 2016. The Company will assess the realizability of the deferred tax assets at least yearly and make appropriate updates as needed. The Company had statutory percentage depletion carry forwards of approximately $1.2 million at December 31, 2016. The depletion has no expiration date. The Company also has a net operating loss carry forward of approximately $13.5 million at December 31, 2016, which will begin to expire in 2027. A reconciliation of Royale Energy's provision for income taxes and the amount computed by applying the statutory income tax rates at December 31, 2016 and 2015, respectively, to pretax income is as follows: 2016 2015 Tax (benefit) computed at statutory rate of 34% $ (1,400,617 ) $ (683,678 ) Increase (decrease) in taxes resulting from: State tax / percentage depletion / other 937 957 Other non-deductible expenses 624 1,478 Change in valuation allowance 1,399,056 681,243 Provision (benefit) $ - $ - The components of the Company’s tax provision are as follows: 2016 2015 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, 2016, 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 2011 through 2015 remain open to examination by the taxing jurisdictions in which we file income tax returns.

NOTE 7 - SERIES AA PREFERRED ST

NOTE 7 - SERIES AA PREFERRED STOCK	12 Months Ended
	Dec. 31, 2016
Disclosure Text Block Supplement [Abstract]
Preferred Stock [Text Block]	NOTE 7 - SERIES AA PREFERRED STOCK In April 1992, Royale Energy's Board of Directors authorized the sale of 147,500 shares of Series AA Convertible Preferred Stock. The resolution authorizing the Series AA Convertible Preferred Stock provided for a stated value of $4 per share. The Series AA Convertible Preferred Stock is convertible at the option of the security holder at the rate of one share of common stock for two shares of Series AA Convertible Preferred Stock. The Series AA Preferred Stock has never been registered under the Securities Exchange Act of 1934, and no market exists for the shares. No shares of Series AA Preferred Stock have been issued since the original shares were issued in 1992. As of September 30, 2016, Royale Energy’s transfer records reflected that certificates representing 46,662 shares of Series AA Preferred stock remained outstanding, but Royale Energy has lost contact with the registered holders of the Series AA Preferred Stock and does not have a means to communicate with them concerning the status of their shares. In November 2016, Royale entered into a securities purchase agreement with one vendor for the settlement an outstanding accounts payable of $25,000. Under the terms of the agreement, Royale issued 76,923 shares of its Series AA convertible preferred stock at $0.325 per share. On the basis of a resolution by the Board of Directors’, these Series AA shares were immediately converted to common stock on a one to one basis. In late 2016, Royale Energy learned that the records of the Secretary of State of California do not reflect that a certificate of determination, amendment to the company’s articles of incorporation, or any other document had ever been filed with the Secretary of State authorizing the issuance of the Series AA Preferred Stock. Royale Energy has reserved 23,331 shares of its common stock (the amount of common stock into which the Series AA Preferred shares would be convertible) for issuance to holders of the outstanding certificates for Series AA Preferred Stock at such time as Royale Energy is able to make contact with the Series AA Preferred shareholders.

NOTE 8 - COMMON STOCK

NOTE 8 - COMMON STOCK	12 Months Ended
	Dec. 31, 2016
Stockholders' Equity Note [Abstract]
Stockholders' Equity Note Disclosure [Text Block]	NOTE 8 - COMMON STOCK In April 2016, Royale entered in a securities purchase agreement and related agreements with one investor. Under the terms of the agreement, the investor purchased 622,316 shares of Royale’s common stock at $0.3214 per share, and received warrants to purchase up to 311,158 shares (the “Warrants’) of stock at $0.5356 per share for three (3) years, for a total of $200,000 in gross proceeds. In July 2016, Royale entered in securities purchase agreements and related agreements with three investors. Under the terms of the agreement, the investors purchased 2,392,500 shares of Royale’s common stock at $0.40 per share, and received warrants to purchase up to 478,500 shares (the “Warrants’) of stock at $0.80 per share for two (2) years, for a total of $957,000 in gross proceeds. In May 2015 and April 2014, Royale Energy entered into Sales Agreements with Roth Capital Partners, LLC (Roth), under which the Company had the ability to issue and sell shares of its common stock from time to time in an at the market equity offering program with Roth acting as the Company’s sales agent. Royale Energy sold 701,397 shares of common stock for total consideration of $556,123 under the 2015 Sales Agreement and no shares of common stock under the 2014 Sales Agreement. Both agreements have been terminated as of December 31, 2015. On November 25, 2015, Royale Energy entered into a securities purchase agreement and related agreements with a group of individual investors pursuant to a registered direct offering. Under the terms of the agreements, the investors purchased 497,948 shares of Royale’s common stock at $0.408 per share, and received warrants to purchase up to 248,973 shares (the “Warrants’) of stock at $1.00 per share for three (3) years, for a total of $203,165 in gross proceeds,. Each Warrant becomes exercisable one year from the date of issuance. Each Warrant contains customary adjustments for corporate events such as reorganizations, splits, and dividends. The fair value of each warrant was estimated on the grant date using the Black-Scholes option-pricing model. This model incorporates certain assumptions for inputs including a risk-free market interest rate, expected dividend yield of the underlying common stock, expected warrant life and expected volatility in the market value of the underlying common stock. For these warrants, the value was calculated with the following assumptions: expected volatility of 78.96%, risk-free market interest rate of 1.13%, an expected term of 1,460 days, and an exercise price of $1.00.

NOTE 9 - OPERATING LEASES

NOTE 9 - OPERATING LEASES	12 Months Ended
	Dec. 31, 2016
Disclosure Text Block Supplement [Abstract]
Commitments Disclosure [Text Block]	NOTE 9 - OPERATING LEASES Royale Energy occupies office space through the use of two 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. Rental expense for the years ended December 31, 2016 and 2015 was $63,733 and $10,400 respectively. Year Ended December 31, 2017 $ 97,266 2018 $ 119,286 2019 $ 123,251 2020 $ 127,355 2021 $ 131,602 Thereafter $ 13,802 Total $ 612,562

NOTE 10 - RELATED PARTY TRANSAC

NOTE 10 - RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Related Party Transactions Disclosure [Text Block]	NOTE 10 - RELATED PARTY TRANSACTIONS Significant Ownership Interests Harry E. Hosmer, Royale Energy’s chairman of the board of directors, is the father of Royale Energy executives Donald H. Hosmer, president of business development and director; and Stephen M. Hosmer, chief financial officer and director. As of March 20, 2017, Donald H. Hosmer owned 6.84% 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 2016, Donald participated in fractional interests of one well in the amount of $1,556 and in 2015 participated in fractional interests of two wells in the amount of $3,143. At December 31, 2016, Royale had a receivable balance of $2,318 due from Donald Hosmer for normal drilling and lease operating expenses. As of March 20, 2017, Stephen M. Hosmer owned 6.31% 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 2016, Stephen participated in fractional interests of one well in the amount of $1,556 and in 2015 participated in fractional interests of four wells in the amount of $4,389. At December 31, 2016, Royale had a receivable balance of $12,912 due from Stephen Hosmer for normal drilling and lease operating expenses. As of March 20, 2017, Harry E. Hosmer owned 7.18% of Royale Energy common stock (as calculated under SEC Rule 13d-3). During 2016, Harry Hosmer participated in fractional interests of one well in the amount of $1,556 and in 2015 participated in fractional interests of four wells in the amount of $5,633. At December 31, 2016, Royale had a receivable balance of $6,459 due from Harry Hosmer for normal drilling and lease operating expenses.

NOTE 11 - STOCK COMPENSATION PL

NOTE 11 - STOCK COMPENSATION PLAN	12 Months Ended
	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Disclosure of Compensation Related Costs, Share-based Payments [Text Block]	NOTE 11 - STOCK COMPENSATION PLAN A summary of the status of Royale Energy's stock option plan as of December 31, 2016 and 2015, and changes during the years ending on those dates is presented below: 2016 2015 Weighted- Weighted- Average Average Exercise Exercise Shares Price Shares Price Options Outstanding and Exercisable at Beginning of Year 100,000 $ 5.00 281,308 $ 3.25 Granted or Vested - - 100,000 5.00 Exercised - - - - Forfeited - - (281,308 ) - Options Outstanding and Exercisable at Year End 100,000 $ 5.00 100,000 $ 5.00 Weighted-average Fair Value of Options Granted During the Year $ - $ - At December 31, 2016, Royale Energy’s stock price, $0.62, 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, 2016. There were no stock options granted during 2016. A summary of the status of Royale Energy's non-vested stock options as of December 31, 2016 and 2015, and changes during the years ending on those dates is presented below: 2016 2015 Weighted- Weighted- Average Average Grant-Date Grant-Date Shares Fair Value Shares Fair Value Non-vested Stock Options Non-vested at Beginning of Year - $ - 105,000 $ 0.97 Granted - - - - Reinstated - - - - Vested - - 90,000 0.97 Expired or Forfeited - - 15,000 0.97 Non-vested at End of Year - $ - - $ - During 2016 and 2015, we recognized $0 and $86,877, respectively, in compensation costs for the vested stock options. The company will incur no future expense related to these options.

NOTE 12 - SIMPLE IRA PLAN

NOTE 12 - SIMPLE IRA PLAN	12 Months Ended
	Dec. 31, 2016
Compensation and Retirement Disclosure [Abstract]
Pension and Other Postretirement Benefits Disclosure [Text Block]	NOTE 12 - SIMPLE IRA PLAN In April 1998, the Company established a Simple IRA pension plan covering all employees. The Company will contribute a matching contribution to each eligible employee’s Simple IRA equal to the employee’s salary reduction contributions up to a limit of 3% of the employee’s compensation for the year. The employer contribution for the years ending December 31, 2016 and 2015, were $29,011, and $43,001 respectively.

NOTE 13 - ENVIRONMENTAL MATTERS

NOTE 13 - ENVIRONMENTAL MATTERS	12 Months Ended
	Dec. 31, 2016
Environmental Remediation Obligations [Abstract]
Environmental Loss Contingency Disclosure [Text Block]	NOTE 13 - ENVIRONMENTAL MATTERS Royale Energy has established procedures for the continuing evaluation of its operations to identify potential environmental exposures and assure compliance with regulatory policies and procedures. Management monitors these laws and regulations and periodically assesses the propriety of its operational and accounting policies related to environmental issues. The nature of Royale Energy's business requires routine day-to-day compliance with environmental laws and regulations. Royale Energy incurred no material environmental investigation, compliance and remediation costs in 2016 or 2015. 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 14 - CONCENTRATIONS OF CRE

NOTE 14 - CONCENTRATIONS OF CREDIT RISK	12 Months Ended
	Dec. 31, 2016
Risks and Uncertainties [Abstract]
Concentration Risk Disclosure [Text Block]	NOTE 14 - CONCENTRATIONS OF CREDIT RISK 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 69% 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, 2016, and 2015. At December 31, 2016, and 2015, the Company’s non-interest bearing accounts were fully insured by the FDIC. At December 31, 2016 and 2015, cash in banks exceeded the FDIC limits by approximately $4.5 million and $3.4 million, respectively. The Company has not experienced any losses on deposits.

NOTE 15 - COMMITMENTS AND CONTI

NOTE 15 - COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies Disclosure [Text Block]	NOTE 15 - COMMITMENTS AND CONTINGENCIES The Company may become involved from time to time in litigation on various matters, which are routine to the conduct of its business. The Company believes that none of these actions, individually or in the aggregate, will have a material adverse effect on its financial position or results of operations, though any adverse decision in these cases or the costs of defending or settling such claims could have a material effect on its business.

NOTE 16 - CHANGE IN ESTIMATE

NOTE 16 - CHANGE IN ESTIMATE	12 Months Ended
	Dec. 31, 2016
Disclosure Text Block Supplement [Abstract]
Accounting Changes [Text Block]	NOTE 16 - CHANGE IN ESTIMATE During the year 2016, the Company changed the process by which it analyzed the collectability of its other receivables, mainly from direct working interest investors. S ee Note 1, Other Receivables

NOTE 17 - SUBSEQUENT EVENTS

NOTE 17 - SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2016
Subsequent Events [Abstract]
Subsequent Events [Text Block]	NOTE 17 - SUBSEQUENT EVENTS On November 30, 2016, the Company entered into an Agreement and Plan of Merger and Reorganization (the “Merger Agreement”) among the Company, Royale Energy Holdings, Inc., Royale Merger Sub, Inc., and Matrix Merger Sub, Inc., and Matrix Oil Management Corporation The Merger Agreement was subsequently amended and restated as of December 31, 2016. The amended and restated Merger Agreement provided that it may be terminated by the Company or Matrix Oil Management Corporation if not consummated on or before an outside termination date of March 31, 2017. On March 30, 2017, the parties agreed to extend the outside termination date of the Merger Agreement until June 30, 2017.

NOTE 18 - SUPPLEMENTAL INFORMAT

NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)	12 Months Ended
	Dec. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Oil and Gas Exploration and Production Industries Disclosures [Text Block]	NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) The following estimates of proved oil and gas reserves, both developed and undeveloped, represent interests owned by Royale Energy which are located solely in the United States. Proved reserves represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate to be reasonably certain to be recoverable in the future from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells, with existing equipment and operating methods. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which relatively major expenditures are required for completion. Disclosures of oil and gas reserves, which follow, are based on estimates prepared by independent petroleum engineering consultant Netherland, Sewell & Associates, Inc., the net reserve value of its proved developed and undeveloped reserves was approximately $3.0 million at December 31, 2016, based on the average PG&E city-gate natural gas price spot price of $2.76 per MCF and for oil volumes, the average West Texas Intermediate price of $39.25 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, 2016 and 2015, and changes in such quantities during each of the years then ended, were as follows: 2016 2015 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed and undeveloped reserves: Beginning of period 3,600 2,510,700 1,781 4,131,806 Revisions of previous estimates 2,446 74,983 (178 ) (1,323,750 ) Production (193 ) (232,539 ) (403 ) (363,168 ) Extensions, discoveries and improved recovery - 112,265 - 48,912 Purchase of minerals in place - - 2,400 16,900 Sales of minerals in place - (450,488 ) - - Proved reserves end of period 5,853 2,014,921 3,600 2,510,700 2016 2015 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed reserves: Beginning of period - 2,174,100 587 3,786,785 End of period 5,823 1,699,997 - 2,174,100 2016 2015 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved undeveloped reserves: Beginning of period 3,600 336,600 1,194 345,021 End of period - 314,925 3,600 336,600 For December 31, 2016, natural gas extensions, discoveries and improved recovery were 112,265 MCF which was added due to the drilling of two new exploratory wells and one new developmental well during 2016. The three new wells consisted of 99,762 MCF of proved developed producing reserves at year end. A location which had 187,500 MCF in proved developed reserves at December 31, 2015, was drilled and began producing prior to 2000, was revised downward 150,609 MCF at December 31, 2016. A location which was drilled and began producing in 2009, which had proved developed reserves of 400,400 was revised upward 71,607 MCF at December 31, 2016. A location which was drilled and began producing in 2015, was revised downward 44,600 MCF at December 31, 2016. A location which was drilled and began producing in 2010, had proved developed reserves of 592,700 at December 31, 2015, was revised upward 31,843 MCF at December 31, 2016. A location which was drilled and began producing in 2015, which had proved undeveloped reserves of 16,900, was revised upward 20,099 MCF at December 31, 2016. Four locations which were drilled prior to 2015, had a total of 249,500 MCF of proved developed reserves at December 31, 2015, were revised upward 37,181 MCF at December 31, 2016. Additionally in 2016, two locations which were drilled prior to 2009, were revised upward 44,175 MCF at December 31, 2016. For December 31, 2015, natural gas extensions, discoveries and improved recovery were 48,912 MCF which was added due to the drilling one new exploratory well during 2015. This new well consisted of 4,312 MCF of proved developed producing reserves and 44,600 proved developed non-producing reserves. A location which had 658,894 MCF in proved developed reserves at December 31, 2014, was drilled and began producing in 2014, was revised downward 566,405 MCF at December 31, 2015. A location which was drilled in 2011 and began producing in 2013, was revised downward 135,729 MCF at December 31, 2015. A location which was drilled and began producing in 2012, had proved developed producing reserves of 229,287 at December 31, 2014, was revised downward 184,436 MCF at December 31, 2015. A location which was drilled and began producing in 2013, had proved developed producing reserves of 111,445 at December 31, 2014, was revised downward 80,486 MCF at December 31, 2015. Additionally in 2015, four locations which were drilled prior to 2011, had a total of 905,646 MCF of proved developed reserves at December 31, 2014, were revised downward 306,366 MCF at December 31, 2015. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves The standardized measure of discounted future net cash flows is presented below for the two years ended December 31, 2016. 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: 2017 $ 467,400 2018 - 2019 34,000 Thereafter 55,100 Total $ 556,500 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 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. 2016 2015 Future cash inflows $ 5,270,400 6,962,900 Future production costs (1,744,200 ) (3,066,200 ) Future development costs (556,500 ) (662,800 ) Future income tax expense (890,910 ) (970,170 ) Future net cash flows 2,078,790 2,263,730 10% annual discount for estimated timing of cash flows (595,518 ) (704,014 ) Standardized measure of discounted future net cash flows $ 1,483,272 1,559,716 Sales of oil and gas produced, net of production costs $ (55,272 ) (155,847 ) Revisions of previous quantity estimates 120,833 (5,089,087 ) Net changes in prices and production costs (253,313 ) (2,238,956 ) Sales of minerals in place (402,900 ) - Purchases of minerals in place - 6,000 Extensions, discoveries and improved recovery 184,476 36,000 Accretion of discount 296,970 220,000 Net change in income tax 32,762 2,166,567 Net increase (decrease) $ (76,444 ) (5,055,323 ) 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 2017 through 2019. Future development cost of: 2017 2018 2019 Proved developed reserves $ - $ - $ - Proved non-producing reserves 124,700 - 34,000 Proved undeveloped reserves 342,700 - - Total $ 467,400 $ - $ 34,000 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: 2016 $ 243,583 2015 $ - 2014 $ 549,236

Accounting Policies, by Policy

Accounting Policies, by Policy (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
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. As reflected in the accompanying financial statements, the Company has negative working capital, losses from operations and negative cash flows from operations. Material estimates that are particularly susceptible to significant change relate to the estimate of Company oil and gas reserves prepared by an independent engineering consultant. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proven reserves. Estimated reserves are used in the calculation of depletion, depreciation and amortization, unevaluated property costs, impairment of oil and natural gas properties, estimated future net cash flows, taxes, and contingencies.
Liquidity Policy [Policy Text Block]	Liquidity The primary sources of liquidity have historically been issuances of common stock and operations. We believe that the completion of the contemplated merger with will enable us to return to positive cash flow. There is some 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, and the sale of oil and natural gas property participation interest. The Company’s consolidated financial statements reflect an accumulated deficit of $45,778,521, a working capital deficiency of $5,905,165 and a stockholders’ deficit of $4,513,072. 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 include the proposed merger with Matrix and additional financing through issuances of common stock and the reduction of overhead costs. 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.
Revenue Recognition, Policy [Policy Text Block]	Revenue Recognition Royale’s primary business is oil and gas production. Natural gas flows from the wells into gathering line systems, which are equipped occasionally with compressor systems, which in turn flow into metered transportation and customer pipelines. Monthly, price data and daily production are used to invoice customers for amounts due to Royale Energy and other working interest owners. Royale Energy operates virtually all of its own wells and receives industry standard operator fees. Royale Energy generally sells crude oil and natural gas under short-term agreements at prevailing market prices. Revenues are recognized when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured. Revenues from the production of oil and natural gas properties in which the Royale Energy has an interest with other producers are recognized on the basis of Royale Energy’s net working interest. Differences between actual production and net working interest volumes are not significant. Royale Energy’s financial statements include its pro rata
Oil and Gas Properties Policy [Policy Text Block]	Oil and Gas Property and Equipment 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. 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. Proved oil and gas properties held and used by Royale Energy are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Royale Energy estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated evaluation assumptions for crude oil commodity prices. Annual volumes are based on field production profiles, which are also updated annually. Prices for natural gas and other products are based on assumptions developed annually for evaluation purposes. Impairment analyses are generally based on proved reserves. An asset group would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount the carrying value exceeds fair value. During 2016 and 2015, impairment losses of $2,071,849 and $424,163, respectively, were recorded on various capitalized lease and land costs that were no longer viable. Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that Royale Energy expects to hold the properties. The valuation allowances are reviewed at least annually. 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, 2016 and 2015, Royale Energy had Deferred Drilling Obligations of $7,894,001 and $8,415,528, 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 consists 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, 2016 and 2015, the Company established an allowance for uncollectable accounts of $2,270,773 and $2,270,773, 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 consists 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.
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: For the Year Ended December 31, 2016 Loss (Numerator) Shares (Denominator) Per-Share Amount Basic Loss Per Share: Net loss available to common stock $ (4,144,462 ) 19,185,896 $ (0.22 ) Loss Per Share: Effect of dilutive securities and stock options - $ - Net loss available to common stock $ (4,144,462 ) 19,185,896 $ (0.22 ) For the Year Ended December 31, 2015 Loss (Numerator) Shares (Denominator) Per-Share Amount Basic Loss Per Share: Net income available to common stock $ (2,010,816 ) 15,194,534 $ (0.13 ) Loss Per Share: Effect of dilutive securities and stock options - $ - Net loss available to common stock $ (2,010,816 ) 15,194,534 $ (0.13 ) For the years ended December 31, 2016 and 2015, Royale Energy had dilutive securities of 0 and 23,331, respectively. 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 Energy has a stock-based employee compensation plan, which is more fully described in Note 11. Effective January 1, 2006, the Company adopted the Compensation – Stock Compensation Topic of the FASB Accounting Standards Codification, which addresses the accounting for stock-based payment transactions in which an enterprise receives employee services in exchange for (a) equity instruments of the enterprise or (b) liabilities that are based on the fair value of the enterprise’s equity instruments or that may be settled by the issuance of such equity instruments. The Company uses the Black-Scholes option-pricing model to determine the fair value of stock-based awards.
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 FASB Accounting Standards Codification. 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, 2016 and 2015, 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 Liabilities [Policy Text Block]	Accounts Payable and Accrued Expenses At December 31, 2016, the components of accounts payable and accrued expenses consisted of $1,205,740 in trade accounts payable due to various vendors, $699,068 in payables and accruals related to direct working interest investors revenues and operating costs, $98,172 in accrued expenses related to current drilling efforts, $266,110 for accrued liabilities for amounts set aside mainly for the plugging and abandonment of certain wells, $103,212 for employee related taxes and accruals, $65,833 related to interest payable on cash advances from investors and $18,662 in federal and state income taxes payable. At December 31, 2015, the components of accounts payable and accrued expenses consisted of $2,167,809 in trade accounts payable due to various vendors, $238,320 in payables and accruals related to direct working interest investors operating costs, $369,837 for accrued liabilities for amounts set aside mainly for the plugging and abandonment of certain wells, $140,798 for employee related taxes and accruals and $20,462 in federal and state income taxes payable.
Debt, Policy [Policy Text Block]	Cash Advances on Pending Transactions In July 2016, Royale entered into negotiations for certain equity and debt financing transactions, described below. The funds from these transactions is to be used to continue drilling activities, fund expenses to be incurred in connection with completion of Royale Energy’s proposed merger with Matrix Oil Corporation and for general corporate purposes. At December 31, 2016, the paperwork for these transactions had not been finalized and as such have been included as Cash Advances from Investors: The Company entered in negotiations with two separate investors for 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 notes mature one year from the date of issuance and carry a 10% interest rate, which is due at maturity. The conversion of the notes to shares is subject to shareholder approval.
Reclassification, Policy [Policy Text Block]	Reclassifications Certain items in the financial statements have been reclassified to maintain consistency and comparability for all periods presented herein.
New Accounting Pronouncements, Policy [Policy Text Block]	Recently Issued Accounting Pronouncements The Company has reviewed the updates issued by the Financial Accounting Standards Board (FASB) during the year ended December 31, 2016. ASU 2015-17: Income Taxes (Topic740) Balance Sheet Classification of Deferred Taxes – In November 2015, FASB issued ASU 2015-17 which eliminates the requirement to present deferred tax assets and liabilities as current and noncurrent amounts in a classified balance sheet. The new standard requires deferred tax assets and liabilities to be classified as noncurrent. The amendments in this update are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Earlier application is permitted for all entities as of the beginning of an interim or annual reporting period and may be applied either prospectively or retrospectively to all periods presented. 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. The adoption of this guidance has no impact on our results of operations or cash flows. ASU 2016-01: Financial Instruments – Overall – Recognition and Measurement of Financial Assets and Financial Liabilities (Subtopic 825-10) In January 2016, FASB issued ASU 2016-01 which requires an entity to: (i) measure equity investments at fair value through net income, with certain exceptions; (ii) present in Other Comprehensive Income the changes in instrument-specific credit risk for financial liabilities measured using the fair value option; (iii) present financial assets and financial liabilities by measurement category and form of financial asset; (iv) calculate the fair value of financial instruments for disclosure purposes based on an exit price and; (v) assess a valuation allowance on deferred tax assets related to unrealized losses of AFS debt securities in combination with other deferred tax assets. The Update provides an election to subsequently measure certain nonmarketable equity investments at cost less any impairment and adjusted for certain observable price changes. The Update also requires a qualitative impairment assessment of such equity investments and amends certain fair value disclosure requirements. The new standard becomes effective for fiscal years beginning after December 15, 2017. Early adoption is only permitted for the provision related to instrument-specific credit risk and the fair value disclosure exemption provided to nonpublic entities. The Company is currently evaluating the effects of adopting ASU 2016-01 on its consolidated financial statements but the adoption is not expected to have a significant impact on the Company’s consolidated financial statements. ASU No. 2016-02: Leases (Topic 842). In February 2016, FASB issued ASU 2016-02 which aims to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and requiring disclosure of key information about leasing agreements. Entities are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. The Company is currently evaluating the effects of adopting ASU 2016-02 on its consolidated financial statements but the adoption is not expected to have a significant impact on the Company’s financial statements. ASU 2016-09: Compensation—Stock Compensation (Topic 718): Improvements to Employee Share- Based Payment Accounting. In March 2016, FASB issued ASU 2016-09 which amends several aspects of the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Early adoption is permitted. If early adopted, an entity must adopt all of the amendments in the same period. The Company is currently evaluating the impact of the adoption of ASU 2016-09 on the Company’s financial statements. ASU 2016-13: Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. In June 2016, FASB issued ASU 2016-13 which was issued to provide more decision-useful information about the expected credit losses on financial instruments and changes the loss impairment methodology. To achieve this objective, the amendments in ASU 2016-13 replace the incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. The amendments affect entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance-sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. This pronouncement is effective for reporting periods beginning after December 15, 2019 using a modified retrospective adoption method. A prospective transition approach is required for debt securities for which an other-than-temporary impairment had been recognized before the effective date. The Company is currently evaluating the impact of the adoption of ASU 2016-13 on the Company’s financial statements. ASU 2016-15: Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. In August 2016, FASB issued ASU 2016-15 which addresses several specific cash flow issues. ASU 2016-15 is effective for annual and interim periods beginning January 1, 2018, with early adoption permitted, and requires full retrospective application on adoption. The Company is currently evaluating the effects of adopting ASU 2016-15 on its financial statements but the adoption is not expected to have a significant impact on the Company’s financial statements. ASU 2014-15: Presentation of Financial Statements - Going Concern (Subtopic 205-40) - Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. The Company adopted ASU 2014-15 as of December 31, 2016. This ASU requires management to assess a company's ability to continue as a going concern and to provide related disclosures in certain circumstances.

NOTE 1 - SUMMARY OF SIGNIFICA26

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	Basic and diluted losses per share are calculated as follows: For the Year Ended December 31, 2016 Loss (Numerator) Shares (Denominator) Per-Share Amount Basic Loss Per Share: Net loss available to common stock $ (4,144,462 ) 19,185,896 $ (0.22 ) Loss Per Share: Effect of dilutive securities and stock options - $ - Net loss available to common stock $ (4,144,462 ) 19,185,896 $ (0.22 ) For the Year Ended December 31, 2015 Loss (Numerator) Shares (Denominator) Per-Share Amount Basic Loss Per Share: Net income available to common stock $ (2,010,816 ) 15,194,534 $ (0.13 ) Loss Per Share: Effect of dilutive securities and stock options - $ - Net loss available to common stock $ (2,010,816 ) 15,194,534 $ (0.13 )

NOTE 2 - OIL AND GAS PROPERTI27

NOTE 2 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Tables)	12 Months Ended
	Dec. 31, 2016
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: 2016 2015 Oil and Gas Producing properties, including intangible drilling costs $ 3,755,705 $ 5,217,637 Undeveloped properties 307,158 2,381,564 Lease and well equipment 4,128,178 4,339,122 8,191,041 11,938,323 Accumulated depletion, depreciation and amortization (6,468,279 ) (7,656,731 ) $ 1,722,762 $ 4,281,592 Commercial and Other 2016 2015 Real estate, including furniture and fixtures $ - $ 2,266,050 Vehicles 40,061 118,061 Furniture and equipment 1,089,648 1,120,760 1,129,709 3,504,871 Accumulated depreciation (1,119,047 ) (1,253,985 ) 10,662 2,250,886 $ 1,733,424 $ 6,532,478
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: 2016 2015 Acquisition - Proved $ - 69,446 Acquisition- Unproved $ - 113,749 Development $ 1,210,261 672,651 Exploration $ 2,603,209 1,845,585
Capitalized Exploratory Well Costs, Roll Forward [Table Text Block]	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 2016 or 2015. 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. 12 Months Ended December 31, 2016 2015 Beginning balance at January 1 $ - $ - Additions to capitalized exploratory well costs pending the determination of proved reserves $ - $ 85,640 Reclassifications to wells, facilities, and equipment based on the determination of proved reserves $ - $ (85,640 ) 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) for the two years ended December 31, are as follows: 2016 2015 Oil and gas sales $ 538,631 1,018,928 Production related costs (594,241 ) (1,449,082 ) Lease Impairment (2,071,849 ) (424,163 ) Depreciation, depletion and amortization (283,874 ) (400,813 ) Results of operations from producing and exploration activities $ (2,411,333 ) (1,255,130 ) Income Taxes (Benefit) - - Net Results $ (2,411,333 ) (1,255,130 )

NOTE 3 - ASSET RETIREMENT OBL28

NOTE 3 - ASSET RETIREMENT OBLIGATION (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligation [Table Text Block]	2016 2015 Asset retirement obligation, Beginning of the year $ 1,096,179 $ 804,206 Liabilities incurred during the period 90,000 321,560 Settlements (10,498 ) (68,360 ) Sales (229,465 ) - Accretion expense 5,894 38,773 Asset retirement obligation, End of year $ 952,110 $ 1,096,179

NOTE 5 - LONG-TERM DEBT (Tables

NOTE 5 - LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2016
Disclosure Text Block [Abstract]
Schedule of Long-term Debt Instruments [Table Text Block]	2016 2015 On December 24, 2013, Royale Energy, Inc. entered into an agreement between the Company, as buyer, and North Island Financial Credit Union as seller, for the purchase of commercial property in San Diego, California, for a purchase price of $2,000,000, of which $500,000 was paid in cash on the date of purchase, and $1,500,000 was borrowed from AmericanWest Bank, NA, with a note secured by the property being purchased. The note carries an interest rate of 5.75% until paid in full. Royale will pay this loan in 119 regular payments of $9,525 each and one balloon payment estimated at $1,150,435. Royale’s first payment was due February 1, 2014, and all subsequent payments are due on the same day of each month after that. Royale’s final payment will be due on January 1, 2024, and will be for all principal and all accrued interest not yet paid. Payments include principal and interest. Stephen M Hosmer, President, CFO is named as a personal guarantor of the loan. The loan agreement contains certain covenants that, among other things, Royale must maintain a ratio of EBITDA-Debt Service Coverage in excess of 1.50 to 1.00. At December 31, 2015, Royale was not in compliance with this covenant, but obtained a forbearance from the bank from terms of that covenant to May 26, 2016. In June 2016, the sale of the building was completed and the related principal and interest payments were paid in full. $ - $ 1,446,853 Total Long Term Debt $ - $ 1,446,853 Less Current Maturity - $ 30,528 Long Term Debt Less Current Portion $ - $ 1,416,325

NOTE 6 - INCOME TAXES (Tables)

NOTE 6 - INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015, respectively, are as follows: 2016 2015 Deferred Tax Assets (Liabilities): Statutory Depletion Carry Forward $ 474,250 $ 555,093 Net Operating Loss 5,392,208 4,651,428 Other 1,255,372 1,247,829 Share-Based Compensation 104,388 96,536 Capital Loss / AMT Credit Carry Forward 18,915 18,915 Charitable Contributions Carry Forward 13,102 21,644 Allowance for Doubtful Accounts 886,056 887,418 Oil and Gas Properties and Fixed Assets 5,922,031 4,980,324 $ 14,066,322 $ 12,459,187 Valuation Allowance (14,066,322 ) (12,459,187 ) 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, 2016 and 2015, respectively, to pretax income is as follows: 2016 2015 Tax (benefit) computed at statutory rate of 34% $ (1,400,617 ) $ (683,678 ) Increase (decrease) in taxes resulting from: State tax / percentage depletion / other 937 957 Other non-deductible expenses 624 1,478 Change in valuation allowance 1,399,056 681,243 Provision (benefit) $ - $ -
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	The components of the Company’s tax provision are as follows: 2016 2015 Current tax provision (benefit) – federal $ - - Current tax provision (benefit) – state - - Deferred tax provision (benefit) – federal - - Deferred tax provision (benefit) – state - - Total provision (benefit) $ - -

NOTE 9 - OPERATING LEASES (Tabl

NOTE 9 - OPERATING LEASES (Tables)	12 Months Ended
	Dec. 31, 2016
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 two leases, one for their office in El Cajon, Year Ended December 31, 2017 $ 97,266 2018 $ 119,286 2019 $ 123,251 2020 $ 127,355 2021 $ 131,602 Thereafter $ 13,802 Total $ 612,562

NOTE 11 - STOCK COMPENSATION 32

NOTE 11 - STOCK COMPENSATION PLAN (Tables)	12 Months Ended
	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of 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, 2016 and 2015, and changes during the years ending on those dates is presented below: 2016 2015 Weighted- Weighted- Average Average Exercise Exercise Shares Price Shares Price Options Outstanding and Exercisable at Beginning of Year 100,000 $ 5.00 281,308 $ 3.25 Granted or Vested - - 100,000 5.00 Exercised - - - - Forfeited - - (281,308 ) - Options Outstanding and Exercisable at Year End 100,000 $ 5.00 100,000 $ 5.00 Weighted-average Fair Value of Options Granted During the Year $ - $ -
Schedule of Nonvested Restricted Stock Units Activity [Table Text Block]	A summary of the status of Royale Energy's non-vested stock options as of December 31, 2016 and 2015, and changes during the years ending on those dates is presented below: 2016 2015 Weighted- Weighted- Average Average Grant-Date Grant-Date Shares Fair Value Shares Fair Value Non-vested Stock Options Non-vested at Beginning of Year - $ - 105,000 $ 0.97 Granted - - - - Reinstated - - - - Vested - - 90,000 0.97 Expired or Forfeited - - 15,000 0.97 Non-vested at End of Year - $ - - $ -

NOTE 18 - SUPPLEMENTAL INFORM33

NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2016
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]	2016 2015 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed and undeveloped reserves: Beginning of period 3,600 2,510,700 1,781 4,131,806 Revisions of previous estimates 2,446 74,983 (178 ) (1,323,750 ) Production (193 ) (232,539 ) (403 ) (363,168 ) Extensions, discoveries and improved recovery - 112,265 - 48,912 Purchase of minerals in place - - 2,400 16,900 Sales of minerals in place - (450,488 ) - - Proved reserves end of period 5,853 2,014,921 3,600 2,510,700 2016 2015 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed reserves: Beginning of period - 2,174,100 587 3,786,785 End of period 5,823 1,699,997 - 2,174,100 2016 2015 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved undeveloped reserves: Beginning of period 3,600 336,600 1,194 345,021 End of period - 314,925 3,600 336,600
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block]	2016 2015 Future cash inflows $ 5,270,400 6,962,900 Future production costs (1,744,200 ) (3,066,200 ) Future development costs (556,500 ) (662,800 ) Future income tax expense (890,910 ) (970,170 ) Future net cash flows 2,078,790 2,263,730 10% annual discount for estimated timing of cash flows (595,518 ) (704,014 ) Standardized measure of discounted future net cash flows $ 1,483,272 1,559,716 Sales of oil and gas produced, net of production costs $ (55,272 ) (155,847 ) Revisions of previous quantity estimates 120,833 (5,089,087 ) Net changes in prices and production costs (253,313 ) (2,238,956 ) Sales of minerals in place (402,900 ) - Purchases of minerals in place - 6,000 Extensions, discoveries and improved recovery 184,476 36,000 Accretion of discount 296,970 220,000 Net change in income tax 32,762 2,166,567 Net increase (decrease) $ (76,444 ) (5,055,323 )
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: 2016 2015 Acquisition - Proved $ - 69,446 Acquisition- Unproved $ - 113,749 Development $ 1,210,261 672,651 Exploration $ 2,603,209 1,845,585
Proved Developed 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]	2017 $ 467,400 2018 - 2019 34,000 Thereafter 55,100 Total $ 556,500
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: 2017 2018 2019 Proved developed reserves $ - $ - $ - Proved non-producing reserves 124,700 - 34,000 Proved undeveloped reserves 342,700 - - Total $ 467,400 $ - $ 34,000
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]	2016 $ 243,583 2015 $ - 2014 $ 549,236

NOTE 1 - SUMMARY OF SIGNIFICA34

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details)	12 Months Ended
	Dec. 31, 2016USD ($)$ / sharesshares	Dec. 31, 2015USD ($)shares
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Retained Earnings (Accumulated Deficit)	$ (45,778,521)	$ (41,634,059)
Working Capital (Deficit)	(5,905,165)
Stockholders' Equity Attributable to Parent	$ (4,513,072)	(2,225,481)
Joint Venture, Ownership Interest	50.00%
Impairment of Oil and Gas Properties	$ 2,071,849	424,163
Customer Deposits, Current	7,894,001	8,415,528
Allowance for Doubtful Accounts Receivable	$ 2,270,773	$ 2,270,773
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount (in Shares) | shares	0	23,331
Accounts Payable and Accrued Liabilities, Current	$ 2,469,245	$ 2,937,226
Trading Liabilities [Member]
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Accounts Payable and Accrued Liabilities, Current	1,205,740	2,167,809
Accruals Related to Direct Working Interest Investors Revenues and Operating Costs [Member]
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Accounts Payable and Accrued Liabilities, Current	699,068	238,320
Accruals Related to Current Drilling Efforts [Member]
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Accounts Payable and Accrued Liabilities, Current	98,172
Accruals Mainly for Plugging and Abandonment of Certain Wells [Member]
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Accounts Payable and Accrued Liabilities, Current	266,110	369,837
Employee Related Taxes and Accruals [Member]
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Accounts Payable and Accrued Liabilities, Current	103,212	140,798
Interest on Cash Advances [Member]
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Accounts Payable and Accrued Liabilities, Current	65,833
Federal and State Income Taxes Payable [Member]
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Accounts Payable and Accrued Liabilities, Current	$ 18,662	$ 20,462
Minimum [Member]
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Property, Plant and Equipment, Useful Life	3 years
Maximum [Member]
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Property, Plant and Equipment, Useful Life	7 years
Convertible Notes Payable [Member]
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Number of Investors	2
Debt Instrument, Convertible, Conversion Price (in Dollars per share) | $ / shares	$ 0.40
Debt Instrument, Convertible, Terms of Conversion Feature	with warrants to purchase one share of common stock for every three shares of common stock issuable upon conversion of the notes
Debt Instrument, Term	1 year
Debt Instrument, Interest Rate, Stated Percentage	10.00%
Note to First Investor [Member] | Convertible Notes Payable [Member]
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Debt Instrument, Face Amount	$ 1,280,000
Note to Second Investor [Member] | Convertible Notes Payable [Member]
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Debt Instrument, Face Amount	$ 300,000

NOTE 1 - SUMMARY OF SIGNIFICA35

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - Schedule of Earnings Per Share, Basic and Diluted - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Basic Loss Per Share:
Net income (loss) available to common stock, Income	$ (4,144,462)	$ (2,010,816)
Net income (loss) available to common stock, Shares	19,185,896	15,194,534
Net income (loss) available to common stock, Per-Share Amount	$ (0.22)	$ (0.13)
Loss Per Share:
Effect of dilutive securities and stock options, Income	$ 0	$ 0
Effect of dilutive securities and stock options, Shares	0	0
Effect of dilutive securities and stock options, Per-Share Amount	$ 0	$ 0
Net income (loss) available to common stock, Income	$ (4,144,462)	$ (2,010,816)
Net income (loss) available to common stock, Shares	19,185,896	15,194,534
Net income (loss) available to common stock, Per-Share Amount	$ (0.22)	$ (0.13)

NOTE 2 - OIL AND GAS PROPERTI36

NOTE 2 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Details) - Schedule of Property, Plant and Equipment - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Producing properties, including intangible drilling costs	$ 3,755,705	$ 5,217,637
Undeveloped properties	307,158	2,381,564
Lease and well equipment	4,128,178	4,339,122
Oil and gas, gross	8,191,041	11,938,323
Accumulated depletion, depreciation and amortization	(6,468,279)	(7,656,731)
Oil and gas, net	1,722,762	4,281,592
Property, Plant and Equipment, Gross	1,129,709	3,504,871
Accumulated depreciation	(1,119,047)	(1,253,985)
Property, Plant and Equipment, Net	10,662	2,250,886
Oil and gas properties, equipment and fixtures	1,733,424	6,532,478
Land, Buildings and Improvements [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	0	2,266,050
Vehicles [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	40,061	118,061
Furniture and Fixtures [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 1,089,648	$ 1,120,760

NOTE 2 - OIL AND GAS PROPERTI37

NOTE 2 - 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, 2016	Dec. 31, 2015
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Abstract]
Acquisition - Proved	$ 0	$ 69,446
Acquisition- Unproved	0	113,749
Development	1,210,261	672,651
Exploration	$ 2,603,209	$ 1,845,585

NOTE 2 - OIL AND GAS PROPERTI38

NOTE 2 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Details) - Capitalized Exploratory Well Costs, Roll Forward - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
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	85,640
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves	0	(85,640)
Ending balance at December 31	$ 0	$ 0

NOTE 2 - OIL AND GAS PROPERTI39

NOTE 2 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Details) - Results of Operations for Oil and Gas Producing Activities Disclosure - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Results of Operations for Oil and Gas Producing Activities Disclosure [Abstract]
Oil and gas sales	$ 538,631	$ 1,018,928
Production related costs	(594,241)	(1,449,082)
Lease Impairment	(2,071,849)	(424,163)
Depreciation, depletion and amortization	(283,874)	(400,813)
Results of operations from producing and exploration activities	(2,411,333)	(1,255,130)
Income Taxes (Benefit)	0	0
Net Results	$ (2,411,333)	$ (1,255,130)

NOTE 3 - ASSET RETIREMENT OBL40

NOTE 3 - ASSET RETIREMENT OBLIGATION (Details) - Schedule of Change in Asset Retirement Obligation - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Schedule of Change in Asset Retirement Obligation [Abstract]
Asset retirement obligation, Beginning of the year	$ 1,096,179	$ 804,206
Liabilities incurred during the period	90,000	321,560
Settlements	(10,498)	(68,360)
Sales	(229,465)	0
Accretion expense	5,894	38,773
Asset retirement obligation, End of year	$ 952,110	$ 1,096,179

NOTE 4 - TURNKEY DRILLING OBL41

NOTE 4 - TURNKEY DRILLING OBLIGATION (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Deferred Revenue Disclosure [Abstract]
Customer Deposits, Current	$ 7,894,001	$ 8,415,528

NOTE 5 - LONG-TERM DEBT (Deta

NOTE 5 - LONG-TERM DEBT (Details) - Schedule of Long-term Debt - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Long Term Debt	$ 0	$ 1,446,853
Less Current Maturity	0	30,528
Long Term Debt Less Current Portion	0	1,416,325
Secured Debt [Member]
Debt Instrument [Line Items]
Long Term Debt	$ 0	$ 1,446,853

NOTE 5 - LONG-TERM DEBT (De43

NOTE 5 - LONG-TERM DEBT (Details) - Schedule of Long-term Debt (Parentheticals) - Secured Debt [Member] - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Purchase Agreement, Purchase Price	$ 2,000,000	$ 2,000,000
Purchase Price, Cash Paid	500,000	500,000
Note	$ 1,500,000	$ 1,500,000
Note, Interest Rate	5.75%	5.75%
Note, Payment	119 regular payments of $9,525 each and one balloon payment estimated at $1,150,435	119 regular payments of $9,525 each and one balloon payment estimated at $1,150,435
Note, First Payment	Feb. 1, 2014	Feb. 1, 2014
Note, due on	Jan. 1, 2024	Jan. 1, 2024
Entered into Agreement	Dec. 24, 2013	Dec. 24, 2013
Loan Covenants	Royale must maintain a ratio of EBITDA-Debt Service Coverage in excess of 1.50 to 1.00.	Royale must maintain a ratio of EBITDA-Debt Service Coverage in excess of 1.50 to 1.00.

NOTE 6 - INCOME TAXES (Details)

NOTE 6 - INCOME TAXES (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Income Tax Disclosure [Abstract]
Deferred Tax Assets, Tax Credit Carryforwards	$ 1.2
Operating Loss Carryforwards	$ 13.5
Operating Loss Carryforwards, Expiration Date	2,027

NOTE 6 - INCOME TAXES (Details

NOTE 6 - INCOME TAXES (Details) - Schedule of Deferred Tax Assets and Liabilities - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Deferred Tax Assets (Liabilities):
Statutory Depletion Carry Forward	$ 474,250	$ 555,093
Net Operating Loss	5,392,208	4,651,428
Other	1,255,372	1,247,829
Share-Based Compensation	104,388	96,536
Capital Loss / AMT Credit Carry Forward	18,915	18,915
Charitable Contributions Carry Forward	13,102	21,644
Allowance for Doubtful Accounts	886,056	887,418
Oil and Gas Properties and Fixed Assets	5,922,031	4,980,324
	14,066,322	12,459,187
Valuation Allowance	(14,066,322)	(12,459,187)
Net Deferred Tax Asset	$ 0	$ 0

NOTE 6 - INCOME TAXES (Detai46

NOTE 6 - INCOME TAXES (Details) - Schedule of Effective Income Tax Rate Reconciliation - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Schedule of Effective Income Tax Rate Reconciliation [Abstract]
Tax (benefit) computed at statutory rate of 34%	$ (1,400,617)	$ (683,678)
Increase (decrease) in taxes resulting from:
State tax / percentage depletion / other	937	957
Other non-deductible expenses	624	1,478
Change in valuation allowance	1,399,056	681,243
Provision (benefit)	$ 0	$ 0

NOTE 6 - INCOME TAXES (Detai47

NOTE 6 - INCOME TAXES (Details) - Schedule of Effective Income Tax Rate Reconciliation (Parentheticals)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Schedule of Effective Income Tax Rate Reconciliation [Abstract]
Statutory rate	34.00%	34.00%

NOTE 6 - INCOME TAXES (Detai48

NOTE 6 - INCOME TAXES (Details) - Schedule of Components of Income Tax Expense (Benefit) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
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 7 - SERIES AA PREFERRED 49

NOTE 7 - SERIES AA PREFERRED STOCK (Details) - USD ($)	1 Months Ended
	Nov. 30, 2016	Apr. 30, 1992	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015	Dec. 31, 2014
NOTE 7 - SERIES AA PREFERRED STOCK (Details) [Line Items]
Preferred Stock, Shares Authorized			147,500		147,500
Preferred Stock, Shares Outstanding			0		46,662
Preferred Stock, Shares Issued			0		46,662
Debt Conversion, Original Debt, Amount (in Dollars)	$ 25,000
Series AA Preferred Stock [Member]
NOTE 7 - SERIES AA PREFERRED STOCK (Details) [Line Items]
Preferred Stock, Shares Authorized		147,500
Preferred Stock, Par or Stated Value Per Share (in Dollars per share)		$ 4
Convertible Preferred Stock, Terms of Conversion		The Series AA Convertible Preferred Stock is convertible at the option of the security holder at the rate of one share of common stock for two shares of Series AA Convertible Preferred Stock. The Series AA Preferred Stock has never been registered under the Securities Exchange Act of 1934, and no market exists for the shares. No shares of Series AA Preferred Stock have been issued since the original shares were issued in 1992.
Preferred Stock, Shares Outstanding				46,662
Preferred Stock, Shares Issued						46,662
Stock Issued During Period, Shares, Other	76,923
Shares Issued, Price Per Share (in Dollars per share)	$ 0.325
Conversion of Stock, Description	these Series AA shares were immediately converted to common stock on a one to one basis
Preferred Stock, Capital Shares Reserved for Future Issuance			23,331

NOTE 8 - COMMON STOCK (Details)

NOTE 8 - COMMON STOCK (Details)	Nov. 25, 2015USD ($)$ / sharesshares	Jul. 31, 2016USD ($)$ / sharesshares	Apr. 30, 2016USD ($)$ / sharesshares	Dec. 31, 2015USD ($)shares	Dec. 31, 2014shares
Securities Purchase Agreement [Member]
NOTE 8 - COMMON STOCK (Details) [Line Items]
Number of Investors		3	1
Stock Issued During Period, Shares, New Issues	497,948	2,392,500	622,316
Shares Issued, Price Per Share (in Dollars per share) | $ / shares	$ 0.408	$ 0.40	$ 0.3214
Class of Warrant or Right, Number of Securities Called by Warrants or Rights		478,500	311,158
Class of Warrant or Right, Exercise Price of Warrants or Rights (in Dollars per share) | $ / shares	$ 1	$ 0.80	$ 0.5356
Warrant Term	3 years	2 years	3 years
Proceeds from Issuance or Sale of Equity (in Dollars) | $	$ 203,165	$ 957,000	$ 200,000
Class of Warrant or Rights, Granted	248,973
Warrants, Vesting Term	1 year
Fair Value Assumptions, Expected Volatility Rate	78.96%
Fair Value Assumptions, Risk Free Interest Rate	1.13%
Fair Value Assumptions, Expected Term	1460 days
Sales Agreements [Member]
NOTE 8 - COMMON STOCK (Details) [Line Items]
Stock Issued During Period, Shares, New Issues				701,397	0
Stock Issued During Period, Value, New Issues (in Dollars) | $				$ 556,123

NOTE 9 - OPERATING LEASES (Deta

NOTE 9 - OPERATING LEASES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
NOTE 9 - OPERATING LEASES (Details) [Line Items]
Description of Lessee Leasing Arrangements, Operating Leases	Royale Energy occupies office space through the use of two leases, one for their office in El Cajon, CA and one for an office and yard in Woodland, CA.
Operating Leases, Rent Expense	$ 63,733	$ 10,400
El Cajon, CA [Member]
NOTE 9 - OPERATING LEASES (Details) [Line Items]
Description of Lessee Leasing Arrangements, Operating Leases	yearly increase of 3.5%
Lessee Leasing Arrangements, Operating Leases, Term of Contract	62 months
Woodland, CA [Member]
NOTE 9 - OPERATING LEASES (Details) [Line Items]
Description of Lessee Leasing Arrangements, Operating Leases	month-to-month basis
Operating Leases, Rent Expense, Minimum Rentals	$ 500
Minimum [Member] | San Diego, CA [Member]
NOTE 9 - OPERATING LEASES (Details) [Line Items]
Operating Leases, Rent Expense, Minimum Rentals	6,148
Maximum [Member] | San Diego, CA [Member]
NOTE 9 - OPERATING LEASES (Details) [Line Items]
Operating Leases, Rent Expense, Minimum Rentals	$ 10,801

NOTE 9 - OPERATING LEASES (Det

NOTE 9 - OPERATING LEASES (Details) - Schedule of Future Minimum Rental Payments for Operating Leases	Dec. 31, 2016USD ($)
Schedule of Future Minimum Rental Payments for Operating Leases [Abstract]
2,017	$ 97,266
2,018	119,286
2,019	123,251
2,020	127,355
2,021	131,602
Thereafter	13,802
Total	$ 612,562

NOTE 10 - RELATED PARTY TRANS53

NOTE 10 - RELATED PARTY TRANSACTIONS (Details)	Mar. 20, 2017	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Donald H. Hosmer, co-president and co-chief executive officer [Member]
NOTE 10 - RELATED PARTY TRANSACTIONS (Details) [Line Items]
Number of Wells with Fractional Interest		1	2
Wells, Fractional Interest, Value (in Dollars)		$ 1,556	$ 3,143
Due from Related Parties (in Dollars)		$ 2,318
Donald H. Hosmer, co-president and co-chief executive officer [Member] | Subsequent Event [Member]
NOTE 10 - RELATED PARTY TRANSACTIONS (Details) [Line Items]
Equity Method Investment, Ownership Percentage	6.84%
Number of Wells, Participated Individually	179
Stephen M. Hosmer, co-president, co-chief executive officer and chief financial officer [Member]
NOTE 10 - RELATED PARTY TRANSACTIONS (Details) [Line Items]
Number of Wells with Fractional Interest		1	4
Wells, Fractional Interest, Value (in Dollars)		$ 1,556	$ 4,389
Due from Related Parties (in Dollars)			12,912
Stephen M. Hosmer, co-president, co-chief executive officer and chief financial officer [Member] | Subsequent Event [Member]
NOTE 10 - RELATED PARTY TRANSACTIONS (Details) [Line Items]
Equity Method Investment, Ownership Percentage	6.31%
Number of Wells, Participated Individually	179
Harry E. Hosmer, former president and former chief executive officer [Member]
NOTE 10 - RELATED PARTY TRANSACTIONS (Details) [Line Items]
Number of Wells with Fractional Interest		4
Wells, Fractional Interest, Value (in Dollars)		$ 1,556	5,633
Due from Related Parties (in Dollars)			$ 6,459
Harry E. Hosmer, former president and former chief executive officer [Member] | Subsequent Event [Member]
NOTE 10 - RELATED PARTY TRANSACTIONS (Details) [Line Items]
Equity Method Investment, Ownership Percentage	7.18%
Number of Wells with Fractional Interest	1

NOTE 11 - STOCK COMPENSATION 54

NOTE 11 - STOCK COMPENSATION PLAN (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
NOTE 11 - STOCK COMPENSATION PLAN (Details) [Line Items]
Share Price (in Dollars per share)	$ 0.62
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross (in Shares)	0	100,000
Allocated Share-based Compensation Expense	$ 0	$ 86,877
Employee Stock Option [Member] | 2014 Stock Options [Member]
NOTE 11 - 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 11 - STOCK COMPENSATION 55

NOTE 11 - STOCK COMPENSATION PLAN (Details) - Schedule of Share-based Compensation, Stock Options, Activity - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Options
Outstanding and Exercisable at Beginning of Year (in Shares)	100,000	281,308
Outstanding and Exercisable at Beginning of Year	$ 5	$ 3.25
Granted or Vested (in Shares)	0	100,000
Granted or Vested	$ 0	$ 5
Exercised (in Shares)	0	0
Exercised	$ 0	$ 0
Forfeited (in Shares)	0	(281,308)
Forfeited	$ 0	$ 0
Options Outstanding and Exercisable at Year End (in Shares)	100,000	100,000
Options Outstanding and Exercisable at Year End	$ 5	$ 5
Outstanding and Exercisable at Beginning of Year (in Shares)		100,000
Outstanding and Exercisable at Beginning of Year		$ 5
Weighted-average Fair Value of Options Granted During the Year	$ 0	$ 0

NOTE 11 - STOCK COMPENSATION 56

NOTE 11 - STOCK COMPENSATION PLAN (Details) - Schedule of Nonvested Restricted Stock Units Activity - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Non-vested Stock Options
Non-vested at Beginning of Year	0	105,000
Non-vested at Beginning of Year	$ 0	$ 0.97
Granted	0	0
Granted	$ 0	$ 0
Reinstated	0	0
Reinstated	$ 0	$ 0
Vested	0	90,000
Vested	$ 0	$ 0.97
Expired or Forfeited	0	15,000
Expired or Forfeited	$ 0	$ 0.97
Non-vested at End of Year	0	0
Non-vested at End of Year	$ 0	$ 0

NOTE 12 - SIMPLE IRA PLAN (Deta

NOTE 12 - SIMPLE IRA PLAN (Details) - Pension Plan [Member] - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
NOTE 12 - SIMPLE IRA PLAN (Details) [Line Items]
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	3.00%	3.00%
Defined Contribution Plan, Cost Recognized	$ 29,011	$ 43,001

NOTE 14 - CONCENTRATIONS OF C58

NOTE 14 - CONCENTRATIONS OF CREDIT RISK (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
NOTE 14 - CONCENTRATIONS OF CREDIT RISK (Details) [Line Items]
Cash, FDIC Insured Amount	$ 250,000	$ 250,000
Cash, Uninsured Amount	$ 4,500,000	$ 3,400,000
Customer A [Member] | Sales Revenue, Net [Member] | Customer Concentration Risk [Member]
NOTE 14 - CONCENTRATIONS OF CREDIT RISK (Details) [Line Items]
Concentration Risk, Percentage	69.00%

NOTE 18 - SUPPLEMENTAL INFORM59

NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details)	12 Months Ended
	Dec. 31, 2016USD ($)	Dec. 31, 2016USD ($)$ / Mcf	Dec. 31, 2016USD ($)$ / bbl	Dec. 31, 2016USD ($)Mcf	Dec. 31, 2016USD ($)bbl	Dec. 31, 2015USD ($)	Dec. 31, 2015USD ($)Mcf	Dec. 31, 2015USD ($)bbl	Dec. 31, 2016Mcf	Dec. 31, 2016bbl	Dec. 31, 2015Mcf	Dec. 31, 2015bbl	Dec. 31, 2014Mcf	Dec. 31, 2014bbl
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Oil and Gas Property, Successful Effort Method (in Dollars) | $	$ 3,755,705	$ 3,755,705	$ 3,755,705	$ 3,755,705	$ 3,755,705	$ 5,217,637	$ 5,217,637	$ 5,217,637
Fair Value Inputs, Discount Rate	10.00%					10.00%
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions				112,265	0		48,912	0
Exploratory Wells Drilled, Net Productive	2					1
Development Wells Drilled, Net Productive	1
Proved Developed Reserves (Volume)									1,699,997	5,823	2,174,100	0	3,786,785	587
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates				74,983	2,446		(1,323,750)	(178)
Proved Undeveloped Reserve (Volume)									314,925	0	336,600	3,600	345,021	1,194
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) | $	$ 3,000,000	$ 3,000,000	$ 3,000,000	$ 3,000,000	$ 3,000,000
Natural Gas [Member] | PG&E Citygate [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		2.76
Oil [Member] | West Texas Intermediate [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			39.25
New Exploratory and Developmental Wells [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed Reserves (Volume)									99,762
Drilled and Began Producing Prior to 2000 [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed Reserves (Volume)											187,500
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates							150,609
Drilled and Began Producing Prior to 2009 [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed Reserves (Volume)									400,400
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates				71,607
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				44,600
Drilled and Began Producing Prior to 2010 [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed Reserves (Volume)									592,700
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates				31,843
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				20,099
Proved Undeveloped Reserve (Volume)									16,900
Four Locations Drilled and Began Producing Prior to 2015 [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed Reserves (Volume)											249,500
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates				37,181
Two Locations Drilled and Began Producing Prior to 2009 [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates				44,175
New Exploratory Well [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed Reserves (Volume)											4,312
Proved Developed Non-Producting Reserve Volume											44,600
Drilled and Began Producing in 2014 [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed Reserves (Volume)													658,894
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates							566,405
Drilled in 2011 and Began Producing in 2013 [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates							135,729
Drilled and Began Producing in 2012 [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed Reserves (Volume)													229,287
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates							184,436
Drilled and Began Producing in 2013 [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed Reserves (Volume)													111,445
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates							80,486
Four Locatoins Drilled and Began Producing in 2011 [Member]
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed Reserves (Volume)													905,646
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates							306,366

NOTE 18 - SUPPLEMENTAL INFORM60

NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]	12 Months Ended
	Dec. 31, 2016Mcf	Dec. 31, 2016bbl	Dec. 31, 2015Mcf	Dec. 31, 2015bbl
Proved developed and undeveloped reserves:
Proved developed and undeveloped reserves	2,510,700	3,600	4,131,806	1,781
Revisions of previous estimates	74,983	2,446	(1,323,750)	(178)
Production	(232,539)	(193)	(363,168)	(403)
Extensions, discoveries and improved recovery	112,265	0	48,912	0
Purchase of minerals in place	0	0	16,900	2,400
Sales of minerals in place	(450,488)	0	0	0
Proved developed and undeveloped reserves	2,014,921	5,853	2,510,700	3,600
Proved developed reserves:
Proved developed reserves	2,174,100	0	3,786,785	587
Proved developed reserves	1,699,997	5,823	2,174,100	0
Proved undeveloped reserves:
Proved undeveloped reserves	336,600	3,600	345,021	1,194
Proved undeveloped reserves	314,925	0	336,600	3,600

NOTE 18 - SUPPLEMENTAL INFORM61

NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Future Development Costs, Oil and Gas Production - USD ($)	Dec. 31, 2016	Dec. 31, 2015
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Future Development Costs, Oil and Gas Production [Line Items]
Total	$ 556,500	$ 662,800
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]
2,017	467,400
2,018	0
2,019	34,000
Thereafter	55,100
Total	$ 556,500

NOTE 18 - SUPPLEMENTAL INFORM62

NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block] - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block] [Abstract]
Future cash inflows	$ 5,270,400	$ 6,962,900
Future production costs	(1,744,200)	(3,066,200)
Future development costs	(556,500)	(662,800)
Future income tax expense	(890,910)	(970,170)
Future net cash flows	2,078,790	2,263,730
10% annual discount for estimated timing of cash flows	(595,518)	(704,014)
Standardized measure of discounted future net cash flows	1,483,272	1,559,716
Sales of oil and gas produced, net of production costs	(55,272)	(155,847)
Revisions of previous quantity estimates	120,833	(5,089,087)
Net changes in prices and production costs	(253,313)	(2,238,956)
Sales of minerals in place	(402,900)	0
Purchases of minerals in place	0	6,000
Extensions, discoveries and improved recovery	184,476	36,000
Accretion of discount	296,970	220,000
Net change in income tax	32,762	2,166,567
Net increase (decrease)	$ (76,444)	$ (5,055,323)

NOTE 18 - SUPPLEMENTAL INFORM63

NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block] (Parentheticals)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block] [Abstract]
Annual discount for estimated timing of cash flows	10.00%	10.00%

NOTE 18 - SUPPLEMENTAL INFORM64

NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Future Development Costs, Oil and Gas Production	Dec. 31, 2016USD ($)
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	124,700
Estimated Future Costs, Year 2	0
Estimated Future Costs, Year 3	34,000
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	342,700
Estimated Future Costs, Year 2	0
Estimated Future Costs, Year 3	0
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	467,400
Estimated Future Costs, Year 2	0
Estimated Future Costs, Year 3	$ 34,000

NOTE 18 - SUPPLEMENTAL INFORM65

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 ($)	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Schedule of Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Abstract]
Cost incurred for proved undeveloped reserves	$ 243,583	$ 0	$ 549,236