Document And Entity Information
Document And Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Feb. 27, 2018 | Jun. 30, 2017 | |
Document and Entity Information [Abstract] | |||
Entity Registrant Name | ROYALE ENERGY FUNDS, INC. | ||
Document Type | 10-K | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Common Stock, Shares Outstanding | 21,850,185 | ||
Entity Public Float | $ 7,161,166 | ||
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, 2017 | ||
Document Fiscal Year Focus | 2,017 | ||
Document Fiscal Period Focus | FY |
BALANCE SHEETS
BALANCE SHEETS - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 |
Current Assets: | ||
Cash | $ 3,338,693 | $ 4,994,598 |
Other Receivables, net | 764,015 | 676,647 |
Revenue Receivables | 106,007 | 303,528 |
Prepaid Expenses | 149,367 | 63,308 |
Total Current Assets | 4,358,082 | 6,038,081 |
Other Assets | 511,120 | 610,779 |
Oil And Gas Properties (Successful Efforts Basis), Real Property and Equipment and Fixtures, net | 1,302,242 | 1,733,424 |
Total Assets | 6,171,444 | 8,382,284 |
Current Liabilities: | ||
Accounts Payable and Accrued Expenses | 4,638,879 | 2,469,245 |
Cash Advances on Pending Transactions | 1,580,000 | 1,580,000 |
Current Portion of Long-Term Debt | 0 | 0 |
Deferred Drilling Obligations | 5,891,898 | 7,894,001 |
Total Current Liabilities | 12,110,777 | 11,943,246 |
Noncurrent Liabilities: | ||
Asset Retirement Obligation | 1,000,908 | 952,110 |
Note Payable, less current portion | 0 | 0 |
Total Noncurrent Liabilities | 1,000,908 | 952,110 |
Total Liabilities | 13,111,685 | 12,895,356 |
Stockholders’ Deficit: | ||
Common Stock, No Par Value, 30,000,000 Shares Authorized; 21,850,185 and 21,836,033 Shares Issued and Outstanding, at December 31, 2017 and 2016, respectively | 41,265,449 | 41,265,449 |
Accumulated Deficit | (48,205,690) | (45,778,521) |
Total Stockholders’ Deficit | (6,940,241) | (4,513,072) |
Total Liabilities and Stockholders’ Deficit | $ 6,171,444 | $ 8,382,284 |
BALANCE SHEETS (Parentheticals)
BALANCE SHEETS (Parentheticals) - $ / shares | Dec. 31, 2017 | Dec. 31, 2016 |
Common stock, no par value (in Dollars per share) | ||
Common stock, shares authorized | 30,000,000 | 30,000,000 |
Common stock, shares issued | 21,850,185 | 21,836,033 |
Common Stock, shares outstanding | 21,850,185 | 21,836,033 |
STATEMENTS OF COMPREHENSIVE LOS
STATEMENTS OF COMPREHENSIVE LOSS - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Revenues: | ||
Sale of Oil and Gas | $ 554,235 | $ 538,631 |
Supervisory Fees and Other | 453,144 | 675,208 |
Total Revenues | 1,007,379 | 1,213,839 |
Costs and Expenses: | ||
Lease Operating | 435,637 | 594,241 |
Lease Impairment | 289,775 | 2,071,849 |
Well Equipment Write Down | 16,375 | 19,151 |
Bad Debt Expense | 164,145 | 0 |
General and Administrative | 2,005,630 | 2,614,502 |
Legal and Accounting | 1,540,190 | 627,577 |
Marketing | 268,660 | 294,522 |
Depreciation, Depletion and Amortization | 116,017 | 283,874 |
Total Costs and Expenses | 4,836,429 | 6,505,716 |
Gain on Turnkey Drilling Programs | 1,487,824 | 460,210 |
Loss from Operations | (2,341,226) | (4,831,667) |
Other Income (Expense): | ||
Interest Expense | (159,268) | (114,159) |
Gain on Sale of Assets | 0 | 483,394 |
Gain on Settlement of Accounts Payable | 73,325 | 341,751 |
Loss on Disposal of Assets | 0 | (23,781) |
Loss Before Income Tax Expense | (2,427,169) | (4,144,462) |
Provision for Income Taxes | 0 | 0 |
Net Loss | $ (2,427,169) | $ (4,144,462) |
Basic Loss Per Share (in Dollars per share) | $ (0.11) | $ (0.22) |
Diluted Loss Per Share (in Dollars per share) | $ (0.11) | $ (0.22) |
Other Comprehensive Income (Loss) | ||
Unrealized Loss on Equity Securities | $ 0 | $ 0 |
Less: Reclassification Adjustment for Losses Included in Net Income | 0 | 0 |
Other Comprehensive Gain (Loss) before tax | 0 | 0 |
Other Comprehensive Gain (Loss), net of tax | 0 | 0 |
Comprehensive Loss | $ (2,427,169) | $ (4,144,462) |
STATEMENTS OF STOCKHOLDERS' EQU
STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT) - USD ($) | Common Stock [Member] | Preferred Stock [Member]Series AA Preferred Stock [Member] | Retained Earnings [Member] | AOCI Attributable to Parent [Member] | Total |
Balance at Dec. 31, 2015 | $ 39,272,429 | $ 136,149 | $ (41,634,959) | $ (2,225,481) | |
Balance (in Shares) at Dec. 31, 2015 | 16,396,579 | 46,662 | |||
Common Stock Private Placement | $ 1,160,885 | 1,160,885 | |||
Common Stock Private Placement (in Shares) | 3,027,070 | ||||
Issuance of Common Stock in Settlement of AP | $ 50,000 | 50,000 | |||
Issuance of Common Stock in Settlement of AP (in Shares) | 76,923 | ||||
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 | ||||
Conversion of Convertible Securities | $ 136,149 | $ (136,149) | |||
Conversion of Convertible Securities (in Shares) | (46,662) | ||||
Net Loss | (4,144,462) | (4,144,462) | |||
Balance at Dec. 31, 2016 | $ 41,265,449 | $ 0 | (45,778,521) | $ 0 | (4,513,072) |
Balance (in Shares) at Dec. 31, 2016 | 21,836,033 | 0 | |||
Issuance of Common Stock in Settlement of AP | $ (25,000) | (25,000) | |||
Issuance of Common Stock in Settlement of AP (in Shares) | (38,461) | ||||
Common Stock Issued to Executives in lieu of Compensation | $ 25,000 | 25,000 | |||
Common Stock Issued to Executives in lieu of Compensation (in Shares) | 52,613 | ||||
Net Loss | (2,427,169) | (2,427,169) | |||
Balance at Dec. 31, 2017 | $ 41,265,449 | $ (48,205,690) | $ 0 | $ (6,940,241) | |
Balance (in Shares) at Dec. 31, 2017 | 21,850,185 |
STATEMENTS OF CASH FLOWS
STATEMENTS OF CASH FLOWS - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | ||
Net (Loss) | $ (2,427,169) | $ (4,144,462) |
Adjustments to Reconcile Net Loss to Net Cash Used by Operating Activities: | ||
Depreciation, Depletion, and Amortization | 116,017 | 283,874 |
Lease Impairment | 289,775 | 2,071,849 |
Gain on Sale of Assets | 0 | (483,394) |
Gain on Turnkey Drilling Programs | (1,487,824) | (460,210) |
Gain on Settlement of Accounts Payable | (73,325) | (341,751) |
Loss on Disposal of Assets | 0 | 23,781 |
Bad Debt Expense | 164,145 | 0 |
Stock-Based Compensation | 0 | 645,986 |
Realized Loss on Equity Securities | 0 | 0 |
Well Equipment and Other Assets Write Down | 16,375 | 19,151 |
(Increase) Decrease in: | ||
Other & Revenue Receivables | (53,992) | (451,047) |
Prepaid Expenses and Other Assets | 13,600 | 151,642 |
Increase (Decrease) in: | ||
Accounts Payable and Accrued Expenses | 2,242,959 | (587,050) |
Net Cash Used by Operating Activities | (1,199,439) | (3,271,631) |
CASH FLOWS FROM INVESTING ACTIVITIES: | ||
Expenditures for Oil And Gas Properties | (4,388,967) | (2,058,357) |
Proceeds from Turnkey Drilling Programs | 3,932,501 | 3,980,499 |
Proceeds from Sale of Assets | 0 | 1,286,236 |
Net Cash Provided by (Used In) Investing Activities | (456,466) | 3,208,378 |
CASH FLOWS FROM FINANCING ACTIVITIES: | ||
Cash Advances From Investors | 0 | 1,580,000 |
Principal Payments on Long-Term Debt | 0 | (1,446,853) |
Proceeds from Issuance of Common Stock | 0 | 1,160,885 |
Net Cash Provided by Financing Activities | 0 | 1,294,032 |
Net Increase (Decrease) in Cash | (1,655,905) | 1,230,779 |
Cash at Beginning of Year | 4,994,598 | 3,763,819 |
Cash at End of Year | 3,338,693 | 4,994,598 |
Cash Paid for Interest | 1,268 | 48,325 |
Cash Paid for Taxes | 1,539 | 2,100 |
Supplemental Schedule of Non-Cash Investing and Financing Transactions: | ||
Conversion of Series AA Stock to Common Stock | 0 | 136,149 |
Asset Retirement Obligation Addition | 65,461 | 0 |
Issuance of Common Stock for Accrued Compensation Expense | 25,000 | 0 |
Warrants Issued with Common Stock | $ 0 | $ 156,205 |
NOTE 1 - SUMMARY OF SIGNIFICANT
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Significant Accounting Policies [Text Block] | NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES This summary of significant accounting policies of Royale Energy Funds, Inc. (formerly known as Royale Energy, Inc., and in these notes sometimes called “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 and going concern 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 $48,205,690, a working capital deficiency of $7,752,695 and a stockholders’ deficit of $6,940,241. 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 2017 and 2016, impairment losses of $289,775 and $2,071,849, 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, 2017 and 2016, Royale Energy had Deferred Drilling Obligations of $5,891,898 and $7,894,001, 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, 2017 and 2016, the Company established an allowance for uncollectable accounts of $1,975,660 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, 2017 Loss (Numerator) Shares (Denominator) Per-Share Amount Basic Loss Per Share: Net loss available to common stock $ (2,427,169 ) 21,836,975 $ (0.11 ) Loss Per Share: Effect of dilutive securities and stock options - $ - Net loss available to common stock $ (2,427,169 ) 21,836,975 $ (0.11 ) For the Year Ended December 31, 2016 Loss (Numerator) Shares (Denominator) Per-Share Amount Basic Loss Per Share: Net income 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 ) 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, 2017 and 2016, 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, 2017, the components of accounts payable and accrued expenses consisted of $2,392,755 in trade accounts payable due to various vendors, $688,002 in payables and accruals related to direct working interest investors revenues and operating costs, $483,734 in accrued expenses related to current drilling efforts, $438,667 in legal settlement payables related to Cash Advances on Pending Transactions, $266,110 for accrued liabilities for amounts set aside mainly for the plugging and abandonment of certain wells, $93,619 for employee related taxes and accruals, $223,833 related to interest payable on cash advances on pending transactions, $35,036 in deferred rent and $17,123 in federal and state income taxes payable. 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 on pending transactions, $12,446 in deferred rent and $18,662 in federal and state income taxes payable. Cash Advances on Pending Transactions In July 2016, we received a cash investment of $1,580,000 from two investors to purchase convertible promissory notes of $1,280,000 and $300,000, with a conversion price of $0.40 per share, with warrants to purchase one share of common stock for every three shares of common stock issuable upon conversion of the notes. The funds from these transactions were used to continue drilling activities, fund expenses incurred in connection with the completion of Royale Energy’s merger with Matrix Oil Corporation and for general corporate purposes. The notes originally matured on August 2, 2017, one year from the date of issuance, and carried a 10% interest rate, with a default rate of 25%. Shortly before completion of the Merger, the $300,000 note was converted into 750,000 shares of Royale common stock, and Royale agreed to a cash settlement with the holder of the $1,280,000 note for $1,900,000. Recently Issued Accounting Pronouncements The Company has reviewed the updates issued by the Financial Accounting Standards Board (FASB) during the year ended December 31, 2017. ASU 2017-09: Compensation - Stock Compensation (Topic 718) – Scope of Modification Accounting - In May 2017, the FASB issued ASU 2017-09, which provides guidance about which changes to the terms or conditions of a share-based payment awarded require an entity to apply modification accounting. ASU 2017-09 is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted. The amendments in ASU 2017-09 are to be applied prospectively to an award modified on or after the adoption date, consequently the impact will be dependent on the modification of any share-based payment awards and the nature of such modifications. The Company is currently evaluating the impact of the adoption of ASU 2017-09 on the Company’s financial statements. ASU 2017-01: Business Combinations (Topic 805) – Clarifying the Definition of a Business - In January 2017, FASB issued ASU 2017-01. The objective of ASU 2017-01 is to clarify the definition of a business by adding guidance on how entities should evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. ASU 2017-01 will be effective for public business entities for fiscal years beginning after December 15, 2017, including interim periods in the year of adoption. Early adoption is permitted for any interim or annual period. The Company is in the process of determining the impact that the implementation of ASU 2017-01 will have 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. 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. |
NOTE 2 - OIL AND GAS PROPERTIES
NOTE 2 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES | 12 Months Ended |
Dec. 31, 2017 | |
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: 2017 2016 Oil and Gas Producing properties, including intangible drilling costs $ 3,755,705 $ 3,755,705 Undeveloped properties 1,435 307,158 Lease and well equipment 4,119,802 4,128,178 7,876,942 8,191,041 Accumulated depletion, depreciation and amortization (6,582,648 ) (6,468,279 ) $ 1,294,294 $ 1,722,762 Commercial and Other 2017 2016 Real estate, including furniture and fixtures $ - $ - Vehicles 40,061 40,061 Furniture and equipment 1,092,926 1,089,648 1,132,987 1,129,709 Accumulated depreciation (1,125,039 ) (1,119,047 ) 7,948 10,662 $ 1,302,242 $ 1,733,424 The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed: 2017 2016 Acquisition - Proved $ - - Acquisition- Unproved $ - - Development $ 4,525,452 1,210,261 Exploration $ - 2,603,209 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 2017 or 2016. 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, 2017 2016 Beginning balance at January 1 $ - $ - Additions to capitalized exploratory well costs pending the determination of proved reserves $ - $ - Reclassifications to wells, facilities, and equipment based on the determination of proved reserves $ - $ - Ending balance at December 31 $ - $ - Results of Operations from Oil and Gas Producing and Exploration Activities The results of operations from oil and gas producing and exploration activities (excluding corporate overhead and interest costs) for the two years ended December 31, are as follows: 2017 2016 Oil and gas sales $ 554,235 538,631 Production related costs (435,637 ) (594,241 ) Lease Impairment (289,775 ) (2,071,849 ) Depreciation, depletion and amortization (116,017 ) (283,874 ) Results of operations from producing and exploration activities $ (287,194 ) (2,411,333 ) Income Taxes (Benefit) - - Net Results $ (287,194 ) (2,411,333 ) |
NOTE 3 - ASSET RETIREMENT OBLIG
NOTE 3 - ASSET RETIREMENT OBLIGATION | 12 Months Ended |
Dec. 31, 2017 | |
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. 2017 2016 Asset retirement obligation, Beginning of the year $ 952,110 $ 1,096,179 Liabilities incurred during the period 53,142 90,000 Settlements - (10,498 ) Sales - (229,465 ) Accretion expense (4,344 ) 5,894 Asset retirement obligation, End of year $ 1,000,908 $ 952,110 |
NOTE 4 - TURNKEY DRILLING OBLIG
NOTE 4 - TURNKEY DRILLING OBLIGATION | 12 Months Ended |
Dec. 31, 2017 | |
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, 2017 and 2016, Royale Energy had recorded deferred turnkey drilling associated with undrilled wells of $5,891,898 and $7,894,001, respectively, as a current liability. |
NOTE 5 - LONG-TERM DEBT
NOTE 5 - LONG-TERM DEBT | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure Text Block [Abstract] | |
Long-term Debt [Text Block] | NOTE 5 - LONG-TERM DEBT 2017 2016 $ - $ - Total Long Term Debt $ - $ - Less Current Maturity - $ - Long Term Debt Less Current Portion $ - $ - |
NOTE 6 - INCOME TAXES
NOTE 6 - INCOME TAXES | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Tax Disclosure [Text Block] | NOTE 6 - INCOME TAXES Deferred tax assets and liabilities reflect the net tax effect of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and amounts used for income tax purposes. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. In 2016, the Company adopted Accounting Standards Update (ASU) 2015-17 and has classified all of its deferred tax assets and liabilities as noncurrent on its balance sheet. On December 22, 2017, the U.S. enacted significant changes to U.S. tax law following the passage and signing of H.R.1, “An Act to Provide for Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018 (the “Tax Act”). The Tax Act permanently reduces the U.S. federal corporate tax rate from a maximum 35% to 21%, eliminated corporate Alternative Minimum Tax, modified rules for expensing capital investment, and limits the deduction of interest expense for certain companies. Accounting Standard Codification (“ASC”) 740 requires filers to record the effect of tax law changes in the period enacted. However, the SEC issued Staff Accounting Bulletin No. 118 (“SAB 118”), that permits filers to record provisional amounts during a measurement period ending no later than one year from the date of enactment. For the period ending December 31, 2017, the Company re-measured the applicable deferred tax assets based on the rates at which they are expected to reverse. The gross deferred tax assets and liabilities have been adjusted and a corresponding offset has been recorded to the full valuation allowance against the Company’s net deferred tax assets, which resulted in no net effect to its provision for income taxes and effective tax rate. No other provisional adjustments have been made as a result of the Act. Significant components of the Company’s deferred assets and liabilities at December 31, 2017 and 2016, respectively, are as follows: 2017 2016 Deferred Tax Assets (Liabilities): Statutory Depletion Carry Forward $ 369,591 $ 474,250 Net Operating Loss 3,130,841 5,392,208 Other 1,013,329 1,255,372 Share-Based Compensation 69,609 104,388 Capital Loss / AMT Credit Carry Forward 18,915 18,915 Charitable Contributions Carry Forward 10,025 13,102 Allowance for Doubtful Accounts 514,067 886,056 Oil and Gas Properties and Fixed Assets 4,839,823 5,922,031 $ 9,966,200 $ 14,066,322 Valuation Allowance (9,966,200 ) (14,066,322 ) Net Deferred Tax Asset $ - $ - At the end of 2016, management reviewed the realizability of the Company’s net deferred tax assets. Due to the Company’s cumulative losses in recent years, Royale and its management concluded that it is not “more-likely-than-not” its deferred tax assets will be realized. As a result, the Company recorded a full valuation allowance against the net deferred tax assets in 2016. At the end of 2017, management reviewed the reliability of the Company’s net deferred tax assets, and due to the Company’s continued cumulative losses in recent years, Royale and its management concluded it is not “more-likely-than-not” its deferred tax assets will be realized. As a result, the Company will continue to record a full valuation allowance against the deferred tax assets in 2017. 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 $1.4 million at December 31, 2017. The depletion has no expiration date. The Company also has a net operating loss carry forward of approximately $12.0 million at December 31, 2017, 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, 2017 and 2016, respectively, to pretax income is as follows: 2017 2016 Tax (benefit) computed at statutory rate of 34% $ (825,237 ) $ (1,400,617 ) Increase (decrease) in taxes resulting from: State tax / percentage depletion / other 990 937 Other non-deductible expenses 403 624 Change in valuation allowance 823,844 1,399,056 Provision (benefit) $ - $ - The components of the Company’s tax provision are as follows: 2017 2016 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, 2017, 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 2012 through 2016 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, 2017 | |
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, 2017 | |
Stockholders' Equity Note [Abstract] | |
Stockholders' Equity Note Disclosure [Text Block] | NOTE 8 - COMMON STOCK In April 2016, Royale entered in a securities purchase agreement and related agreements with one investor. Under the terms of the agreement, the investor purchased 622,316 shares of Royale’s common stock at $0.3214 per share, and received warrants to purchase up to 311,158 shares (the “Warrants’) of stock at $0.5356 per share for three (3) years, for a total of $200,000 in gross proceeds. In July 2016, Royale entered in securities purchase agreements and related agreements with three investors. Under the terms of the agreement, the investors purchased 2,392,500 shares of Royale’s common stock at $0.40 per share, and received warrants to purchase up to 478,500 shares (the “Warrants’) of stock at $0.80 per share for two (2) years, for a total of $957,000 in gross proceeds. On 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, 2017 | |
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, 2017 and 2016 was $110,909 and $63,733 respectively. Year Ended December 31, 2018 $ 119,286 2019 $ 123,251 2020 $ 127,355 2021 $ 131,602 2022 $ 13,802 Total $ 515,296 |
NOTE 10 - RELATED PARTY TRANSAC
NOTE 10 - RELATED PARTY TRANSACTIONS | 12 Months Ended |
Dec. 31, 2017 | |
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 February 27, 2018, Donald H. Hosmer owned 6.75% 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 2017, Donald did not participate in fractional interests and in 2016 participated in fractional interests of one well in the amount of $1,556. At December 31, 2017, Royale had a payable balance of $340 due to Donald Hosmer for normal drilling and lease operating expenses. As of February 27, 2018, Stephen M. Hosmer owned 6.32% 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 2017, Stephen did not participate in fractional interests and in 2016 participated in fractional interests of one well in the amount of $1,556. At December 31, 2017, Royale had a receivable balance of $11,817 due from Stephen Hosmer for normal drilling and lease operating expenses. As of February 27, 2018, Harry E. Hosmer owned 7.09% of Royale Energy common stock (as calculated under SEC Rule 13d-3). During 2017, Harry Hosmer did not participate in fractional interests and in 2016 participated in fractional interests of one well in the amount of $1,556. At December 31, 2017, Royale had a receivable balance of $3,999 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, 2017 | |
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, 2017 and 2016, and changes during the years ending on those dates is presented below: 2017 2016 Weighted- Weighted- Average Average Exercise Exercise Shares Price Shares Price Options Outstanding and Exercisable at Beginning of Year 100,000 $ 5.00 100,000 $ 5.00 Granted or Vested - - - - Exercised - - - - Forfeited (100,000 ) - - - Options Outstanding and Exercisable at Year End - $ - 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 2017. A summary of the status of Royale Energy’s non-vested stock options as of December 31, 2017 and 2016, and changes during the years ending on those dates is presented below: 2017 2016 Weighted- Weighted- Average Average Grant-Date Grant-Date Shares Fair Value Shares Fair Value Non-vested Stock Options Non-vested at Beginning of Year - $ - - $ - Granted - - - - Reinstated - - - - Vested - - - - Expired or Forfeited - - - - Non-vested at End of Year - $ - - $ - During 2017 and 2016, we recognized $0 and $0, 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, 2017 | |
Retirement Benefits [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, 2017 and 2016, were $28,967 and $29,011 respectively. |
NOTE 13 - ENVIRONMENTAL MATTERS
NOTE 13 - ENVIRONMENTAL MATTERS | 12 Months Ended |
Dec. 31, 2017 | |
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 2017 or 2016. 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, 2017 | |
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 32% of its monthly natural gas production to one customer on a month to month basis. Since we are able to sell our natural gas to other readily available customers, the loss of any one customer would not have an adverse effect on our overall sales operations. The Company maintains cash in depository institutions that are guaranteed by the Federal Deposit Insurance Corporation (FDIC) up to $250,000 per institution for our interest bearing accounts in the years ended December 31, 2017, and 2016. At December 31, 2016, and 2015, the Company’s non-interest bearing accounts were fully insured by the FDIC. At December 31, 2017 and 2016, cash in banks exceeded the FDIC limits by approximately $2.8 million and $4.5 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, 2017 | |
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, 2017 | |
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, 2017 | |
Subsequent Events [Abstract] | |
Subsequent Events [Text Block] | NOTE 17 - SUBSEQUENT EVENTS On August 2, 2016, the Company issued two unsecured convertible promissory notes for a total principal amount of $1,580,000 to two investors. See Capital Resources and Liquidity, page 12. On August 2, 2017, the notes became due and payable and remained due and payable on December 31, 2017. On February 28, 2018, one of the notes, for $300,000, was converted to 750,000 shares of common stock immediately prior to the Merger (a conversion price of $0.40 per share). Also on February 28, 2018, Royale reached a settlement of a dispute with the second investor regarding his advance of $1.28 million. In the settlement, Royale has agreed to pay $1.9 million to the investor, who in turn did not receive shares of the Company’s common stock on conversion of this investment. At December 31, 2017, Legal and Accounting expense includes a $438,667 litigation settlement, the difference between the $1.9 million settlement and the original note of $1.28 million and accrued interest of $181,333. In the settlement, Royale also cancelled a two year warrant issued to the second investor to purchase 1,066,667 of Royale common stock at $0.80 per share. On March 7, 2018, New Royale, Royale, and Matrix and its affiliates were notified by the California Secretary of State of the filing and acceptance of agreements of merger by the California Secretary of State, to complete the previously announced merger between the companies (the “Merger”), as described in Item 1 – Description of Business – Merger with Matrix Oil Management Corporation. |
NOTE 18 - SUPPLEMENTAL INFORMAT
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) | 12 Months Ended |
Dec. 31, 2017 | |
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, 2017 and 2016, and changes in such quantities during each of the years then ended, were as follows: 2017 2016 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed and undeveloped reserves: Beginning of period 5,853 2,014,921 3,600 2,510,700 Revisions of previous estimates (5,549 ) 307,371 2,446 74,983 Production (102 ) (190,111 ) (193 ) (232,539 ) Extensions, discoveries and improved recovery - 40 - 112,265 Purchase of minerals in place - - - - Sales of minerals in place - - - (450,488 ) Proved reserves end of period 202 2,132,221 5,853 2,014,921 2017 2016 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed reserves: Beginning of period 5,823 1,699,997 - 2,174,100 End of period 202 1,798,697 5,823 1,699,997 2017 2016 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved undeveloped reserves: Beginning of period - 314,925 3,600 336,600 End of period - 333,524 - 314,925 For December 31, 2017, our previously estimated proved developed and undeveloped reserve quantities were revised upward by approximately 307,371 MCF of natural gas. This upward revision reflected higher than previously estimated proved producing and non-producing natural gas reserves at eight California wells and one Utah well. A location which had 63,350 MCF in proved developed reserves at December 31, 2016, was drilled and began in 2011, was revised upward 122,998 MCF at December 31, 2017. Two locations which had 128,165 MCF in proved developed reserves at December 31, 2016, were drilled and began producing prior to 2000, were revised upward 118,006 MCF at December 31, 2017. A location which was drilled and began producing in 2010, which had proved developed reserves of 618,709 was revised upward 15,227 MCF at December 31, 2017. A location in Utah which was drilled and began producing in 2006, was revised upward 14,688 MCF at December 31, 2017. A location which was drilled and began producing in 2012, had no proved developed reserves at December 31, 2016, was revised upward 10,994 MCF at December 31, 2017. A location which was drilled and began producing in 2008, had proved developed reserves of 13,878 at December 31, 2016, was revised upward 6,084 MCF at December 31, 2017. A location which had proved undeveloped reserves of 314,925 MCF at December 31, 2016, was revised upward 18,598 MCF at December 31, 2017. 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. 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, 2017. 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: 2018 $ 103,300 2019 342,700 2020 - Thereafter 134,800 Total $ 580,800 The resulting future net revenue streams are reduced to present value amounts by applying a ten percent discount. Disclosure of principal components of the standardized measure of discounted future net cash flows provides information concerning the factors involved in making the calculation. In addition, the disclosure of both undiscounted and discounted net cash flows provides a measure of comparing proved oil and gas reserves both with and without an estimate of production timing. The standardized measure of discounted future net cash flow relating to proved reserves reflects estimated income taxes. Changes in standardized measure of discounted future net cash flow from proved reserve quantities 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. 2017 2016 Future cash inflows $ 6,065,500 5,270,400 Future production costs (2,117,900 ) (1,744,200 ) Future development costs (580,800 ) (556,500 ) Future income tax expense (1,010,040 ) (890,910 ) Future net cash flows 2,356,760 2,078,790 10% annual discount for estimated timing of cash flows (712,072 ) (595,518 ) Standardized measure of discounted future net cash flows $ 1,644,688 1,483,272 Sales of oil and gas produced, net of production costs $ (161,139 ) (55,272 ) Revisions of previous quantity estimates 87,956 120,833 Net changes in prices and production costs 106,303 (253,313 ) Sales of minerals in place - (402,900 ) Purchases of minerals in place - - Extensions, discoveries and improved recovery 74 184,476 Accretion of discount 197,400 296,970 Net change in income tax (69,178 ) 32,762 Net increase (decrease) $ 161,416 (76,444 ) 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 2018 through 2020. Future development cost of: 2018 2019 2020 Proved developed reserves $ - $ - $ - Proved non-producing reserves 103,300 - - Proved undeveloped reserves - 342,700 - Total $ 103,300 $ 342,700 $ - 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: 2017 $ - 2016 $ 243,583 2015 $ - |
Accounting Policies, by Policy
Accounting Policies, by Policy (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
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 and going concern 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 $48,205,690, a working capital deficiency of $7,752,695 and a stockholders’ deficit of $6,940,241. 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 2017 and 2016, impairment losses of $289,775 and $2,071,849, 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, 2017 and 2016, Royale Energy had Deferred Drilling Obligations of $5,891,898 and $7,894,001, 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, 2017 and 2016, the Company established an allowance for uncollectable accounts of $1,975,660 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, 2017 Loss (Numerator) Shares (Denominator) Per-Share Amount Basic Loss Per Share: Net loss available to common stock $ (2,427,169 ) 21,836,975 $ (0.11 ) Loss Per Share: Effect of dilutive securities and stock options - $ - Net loss available to common stock $ (2,427,169 ) 21,836,975 $ (0.11 ) For the Year Ended December 31, 2016 Loss (Numerator) Shares (Denominator) Per-Share Amount Basic Loss Per Share: Net income 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 ) |
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, 2017 and 2016, 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, 2017, the components of accounts payable and accrued expenses consisted of $2,392,755 in trade accounts payable due to various vendors, $688,002 in payables and accruals related to direct working interest investors revenues and operating costs, $483,734 in accrued expenses related to current drilling efforts, $438,667 in legal settlement payables related to Cash Advances on Pending Transactions, $266,110 for accrued liabilities for amounts set aside mainly for the plugging and abandonment of certain wells, $93,619 for employee related taxes and accruals, $223,833 related to interest payable on cash advances on pending transactions, $35,036 in deferred rent and $17,123 in federal and state income taxes payable. 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 on pending transactions, $12,446 in deferred rent and $18,662 in federal and state income taxes payable. |
Other Current Liabilities [Policy Text Block] | Cash Advances on Pending TransactionsIn July 2016, we received a cash investment of $1,580,000 from two investors to purchase convertible promissory notes of $1,280,000 and $300,000, with a conversion price of $0.40 per share, with warrants to purchase one share of common stock for every three shares of common stock issuable upon conversion of the notes.  The funds from these transactions were used to continue drilling activities, fund expenses incurred in connection with the completion of Royale Energy’s merger with Matrix Oil Corporation and for general corporate purposes.  The notes originally matured on August 2, 2017, one year from the date of issuance, and carried a 10% interest rate, with a default rate of 25%.  Shortly before completion of the Merger, the $300,000 note was converted into 750,000 shares of Royale common stock, and Royale agreed to a cash settlement with the holder of the $1,280,000 note for $1,900,000. |
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, 2017. ASU 2017-09: Compensation - Stock Compensation (Topic 718) – Scope of Modification Accounting - In May 2017, the FASB issued ASU 2017-09, which provides guidance about which changes to the terms or conditions of a share-based payment awarded require an entity to apply modification accounting. ASU 2017-09 is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted. The amendments in ASU 2017-09 are to be applied prospectively to an award modified on or after the adoption date, consequently the impact will be dependent on the modification of any share-based payment awards and the nature of such modifications. The Company is currently evaluating the impact of the adoption of ASU 2017-09 on the Company’s financial statements. ASU 2017-01: Business Combinations (Topic 805) – Clarifying the Definition of a Business - In January 2017, FASB issued ASU 2017-01. The objective of ASU 2017-01 is to clarify the definition of a business by adding guidance on how entities should evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. ASU 2017-01 will be effective for public business entities for fiscal years beginning after December 15, 2017, including interim periods in the year of adoption. Early adoption is permitted for any interim or annual period. The Company is in the process of determining the impact that the implementation of ASU 2017-01 will have 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. 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. |
NOTE 1 - SUMMARY OF SIGNIFICA26
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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, 2017 Loss (Numerator) Shares (Denominator) Per-Share Amount Basic Loss Per Share: Net loss available to common stock $ (2,427,169 ) 21,836,975 $ (0.11 ) Loss Per Share: Effect of dilutive securities and stock options - $ - Net loss available to common stock $ (2,427,169 ) 21,836,975 $ (0.11 ) For the Year Ended December 31, 2016 Loss (Numerator) Shares (Denominator) Per-Share Amount Basic Loss Per Share: Net income 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 ) |
NOTE 2 - OIL AND GAS PROPERTI27
NOTE 2 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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: 2017 2016 Oil and Gas Producing properties, including intangible drilling costs $ 3,755,705 $ 3,755,705 Undeveloped properties 1,435 307,158 Lease and well equipment 4,119,802 4,128,178 7,876,942 8,191,041 Accumulated depletion, depreciation and amortization (6,582,648 ) (6,468,279 ) $ 1,294,294 $ 1,722,762 Commercial and Other 2017 2016 Real estate, including furniture and fixtures $ - $ - Vehicles 40,061 40,061 Furniture and equipment 1,092,926 1,089,648 1,132,987 1,129,709 Accumulated depreciation (1,125,039 ) (1,119,047 ) 7,948 10,662 $ 1,302,242 $ 1,733,424 |
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: 2017 2016 Acquisition - Proved $ - - Acquisition- Unproved $ - - Development $ 4,525,452 1,210,261 Exploration $ - 2,603,209 |
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 2017 or 2016. 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, 2017 2016 Beginning balance at January 1 $ - $ - Additions to capitalized exploratory well costs pending the determination of proved reserves $ - $ - Reclassifications to wells, facilities, and equipment based on the determination of proved reserves $ - $ - Ending balance at December 31 $ - $ - |
Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block] | The results of operations from oil and gas producing and exploration activities (excluding corporate overhead and interest costs) for the two years ended December 31, are as follows: 2017 2016 Oil and gas sales $ 554,235 538,631 Production related costs (435,637 ) (594,241 ) Lease Impairment (289,775 ) (2,071,849 ) Depreciation, depletion and amortization (116,017 ) (283,874 ) Results of operations from producing and exploration activities $ (287,194 ) (2,411,333 ) Income Taxes (Benefit) - - Net Results $ (287,194 ) (2,411,333 ) |
NOTE 3 - ASSET RETIREMENT OBL28
NOTE 3 - ASSET RETIREMENT OBLIGATION (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Change in Asset Retirement Obligation [Table Text Block] | The Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification requires that an asset retirement obligation (ARO) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset. The ARO is recorded at fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value. The fair value of the ARO is measured using expected future cash outflows discounted at the Company’s credit-adjusted risk-free interest rate. The provisions of this Topic apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, development, and operation of a long-lived asset. 2017 2016 Asset retirement obligation, Beginning of the year $ 952,110 $ 1,096,179 Liabilities incurred during the period 53,142 90,000 Settlements - (10,498 ) Sales - (229,465 ) Accretion expense (4,344 ) 5,894 Asset retirement obligation, End of year $ 1,000,908 $ 952,110 |
NOTE 5 - LONG-TERM DEBT (Tables
NOTE 5 - LONG-TERM DEBT (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure Text Block [Abstract] | |
Schedule of Long-term Debt Instruments [Table Text Block] | 2017 2016 $ - $ - Total Long Term Debt $ - $ - Less Current Maturity - $ - Long Term Debt Less Current Portion $ - $ - |
NOTE 6 - INCOME TAXES (Tables)
NOTE 6 - INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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, 2017 and 2016, respectively, are as follows: 2017 2016 Deferred Tax Assets (Liabilities): Statutory Depletion Carry Forward $ 369,591 $ 474,250 Net Operating Loss 3,130,841 5,392,208 Other 1,013,329 1,255,372 Share-Based Compensation 69,609 104,388 Capital Loss / AMT Credit Carry Forward 18,915 18,915 Charitable Contributions Carry Forward 10,025 13,102 Allowance for Doubtful Accounts 514,067 886,056 Oil and Gas Properties and Fixed Assets 4,839,823 5,922,031 $ 9,966,200 $ 14,066,322 Valuation Allowance (9,966,200 ) (14,066,322 ) 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, 2017 and 2016, respectively, to pretax income is as follows: 2017 2016 Tax (benefit) computed at statutory rate of 34% $ (825,237 ) $ (1,400,617 ) Increase (decrease) in taxes resulting from: State tax / percentage depletion / other 990 937 Other non-deductible expenses 403 624 Change in valuation allowance 823,844 1,399,056 Provision (benefit) $ - $ - |
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block] | The components of the Company’s tax provision are as follows: 2017 2016 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, 2017 | |
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, 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, 2017 and 2016 was $110,909 and $63,733 respectively. Year Ended December 31, 2018 $ 119,286 2019 $ 123,251 2020 $ 127,355 2021 $ 131,602 2022 $ 13,802 Total $ 515,296 |
NOTE 11 - STOCK COMPENSATION 32
NOTE 11 - STOCK COMPENSATION PLAN (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Share-based Compensation, Stock Options, Activity [Table Text Block] | A summary of the status of Royale Energy’s stock option plan as of December 31, 2017 and 2016, and changes during the years ending on those dates is presented below: 2017 2016 Weighted- Weighted- Average Average Exercise Exercise Shares Price Shares Price Options Outstanding and Exercisable at Beginning of Year 100,000 $ 5.00 100,000 $ 5.00 Granted or Vested - - - - Exercised - - - - Forfeited (100,000 ) - - - Options Outstanding and Exercisable at Year End - $ - 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, 2017 and 2016, and changes during the years ending on those dates is presented below: 2017 2016 Weighted- Weighted- Average Average Grant-Date Grant-Date Shares Fair Value Shares Fair Value Non-vested Stock Options Non-vested at Beginning of Year - $ - - $ - Granted - - - - Reinstated - - - - Vested - - - - Expired or Forfeited - - - - 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, 2017 | |
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables) [Line Items] | |
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block] | The net interest in estimated quantities of proved developed reserves of crude oil and natural gas at December 31, 2017 and 2016, and changes in such quantities during each of the years then ended, were as follows: 2017 2016 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed and undeveloped reserves: Beginning of period 5,853 2,014,921 3,600 2,510,700 Revisions of previous estimates (5,549 ) 307,371 2,446 74,983 Production (102 ) (190,111 ) (193 ) (232,539 ) Extensions, discoveries and improved recovery - 40 - 112,265 Purchase of minerals in place - - - - Sales of minerals in place - - - (450,488 ) Proved reserves end of period 202 2,132,221 5,853 2,014,921 2017 2016 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved developed reserves: Beginning of period 5,823 1,699,997 - 2,174,100 End of period 202 1,798,697 5,823 1,699,997 2017 2016 Oil (BBL) Gas (MCF) Oil (BBL) Gas (MCF) Proved undeveloped reserves: Beginning of period - 314,925 3,600 336,600 End of period - 333,524 - 314,925 |
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block] | 2017 2016 Future cash inflows $ 6,065,500 5,270,400 Future production costs (2,117,900 ) (1,744,200 ) Future development costs (580,800 ) (556,500 ) Future income tax expense (1,010,040 ) (890,910 ) Future net cash flows 2,356,760 2,078,790 10% annual discount for estimated timing of cash flows (712,072 ) (595,518 ) Standardized measure of discounted future net cash flows $ 1,644,688 1,483,272 Sales of oil and gas produced, net of production costs $ (161,139 ) (55,272 ) Revisions of previous quantity estimates 87,956 120,833 Net changes in prices and production costs 106,303 (253,313 ) Sales of minerals in place - (402,900 ) Purchases of minerals in place - - Extensions, discoveries and improved recovery 74 184,476 Accretion of discount 197,400 296,970 Net change in income tax (69,178 ) 32,762 Net increase (decrease) $ 161,416 (76,444 ) |
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: 2017 2016 Acquisition - Proved $ - - Acquisition- Unproved $ - - Development $ 4,525,452 1,210,261 Exploration $ - 2,603,209 |
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] | Estimated future development costs by year are as follows: 2018 $ 103,300 2019 342,700 2020 - Thereafter 134,800 Total $ 580,800 |
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: 2018 2019 2020 Proved developed reserves $ - $ - $ - Proved non-producing reserves 103,300 - - Proved undeveloped reserves - 342,700 - Total $ 103,300 $ 342,700 $ - |
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] | 2017 $ - 2016 $ 243,583 2015 $ - |
NOTE 1 - SUMMARY OF SIGNIFICA34
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) | 12 Months Ended | ||
Dec. 31, 2017USD ($)shares | Dec. 31, 2016USD ($)$ / shares | Dec. 31, 2015USD ($) | |
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items] | |||
Retained Earnings (Accumulated Deficit) | $ (48,205,690) | $ (45,778,521) | |
Working Capital (Deficit) | (7,752,695) | ||
Stockholders' Equity Attributable to Parent | $ (6,940,241) | (4,513,072) | $ (2,225,481) |
Joint Venture, Ownership Interest | 50.00% | ||
Impairment of Oil and Gas Properties | $ 289,775 | 2,071,849 | |
Customer Deposits, Current | 5,891,898 | 7,894,001 | |
Allowance for Doubtful Accounts Receivable | 1,975,660 | 2,270,773 | |
Accounts Payable and Accrued Liabilities, Current | $ 4,638,879 | 2,469,245 | |
Convertible Notes Payable [Member] | |||
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items] | |||
Debt Instrument, Face Amount | $ 1,580,000 | ||
Number of Investors | 2 | ||
Debt Instrument, Convertible, Conversion Price (in Dollars per share) | $ / shares | $ 0.40 | ||
Debt Instrument, Term | 1 year | ||
Debt Instrument, Interest Rate, Stated Percentage | 10.00% | ||
Debt Conversion, Converted Instrument, Shares Issued (in Shares) | shares | 750,000 | ||
Repayments of Debt | $ 1,900,000 | ||
Convertible Notes Payable [Member] | Note to First Investor [Member] | |||
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items] | |||
Debt Instrument, Face Amount | $ 1,280,000 | ||
Convertible Notes Payable [Member] | Note to Second Investor [Member] | |||
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items] | |||
Debt Instrument, Face Amount | $ 300,000 | ||
Convertible Notes Payable [Member] | Note #1 Entered into Negotiations [Member] | |||
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items] | |||
Debt Instrument, Face Amount | $ 1,280,000 | ||
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 | ||
Maximum [Member] | Convertible Notes Payable [Member] | |||
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items] | |||
Debt Instrument, Interest Rate, Stated Percentage | 25.00% | ||
Trading Liabilities [Member] | |||
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items] | |||
Accounts Payable and Accrued Liabilities, Current | $ 2,392,755 | $ 1,205,740 | |
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 | 688,002 | 699,068 | |
Accruals Related to Current Drilling Efforts [Member] | |||
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items] | |||
Accounts Payable and Accrued Liabilities, Current | 483,734 | 98,172 | |
Legal Settlement Payables [Member] | |||
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items] | |||
Accounts Payable and Accrued Liabilities, Current | 438,667 | ||
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 | 266,110 | |
Employee Related Taxes and Accruals [Member] | |||
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items] | |||
Accounts Payable and Accrued Liabilities, Current | 93,619 | 103,212 | |
Interest on Cash Advances [Member] | |||
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items] | |||
Accounts Payable and Accrued Liabilities, Current | 223,833 | 65,833 | |
Accruals Related to Deferred Rent [Member] | |||
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items] | |||
Accounts Payable and Accrued Liabilities, Current | 35,036 | 12,446 | |
Federal and State Income Taxes Payable [Member] | |||
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items] | |||
Accounts Payable and Accrued Liabilities, Current | $ 17,123 | $ 18,662 |
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, 2017 | Dec. 31, 2016 | |
Basic Loss Per Share: | ||
Net income (loss) available to common stock, Income | $ (2,427,169) | $ (4,144,462) |
Net income (loss) available to common stock, Shares | 21,836,975 | 19,185,896 |
Net income (loss) available to common stock, Per-Share Amount | $ (0.11) | $ (0.22) |
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 | $ (2,427,169) | $ (4,144,462) |
Net income (loss) available to common stock, Shares | 21,836,975 | 19,185,896 |
Net income (loss) available to common stock, Per-Share Amount | $ (0.11) | $ (0.22) |
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, 2017 | Dec. 31, 2016 |
Property, Plant and Equipment [Line Items] | ||
Producing properties, including intangible drilling costs | $ 3,755,705 | $ 3,755,705 |
Undeveloped properties | 1,435 | 307,158 |
Lease and well equipment | 4,119,802 | 4,128,178 |
Oil and gas, gross | 7,876,942 | 8,191,041 |
Accumulated depletion, depreciation and amortization | (6,582,648) | (6,468,279) |
Oil and gas, net | 1,294,294 | 1,722,762 |
Property, Plant and Equipment, Gross | 1,132,987 | 1,129,709 |
Accumulated depreciation | (1,125,039) | (1,119,047) |
Property, Plant and Equipment, Net | 7,948 | 10,662 |
Oil and gas properties, equipment and fixtures | 1,302,242 | 1,733,424 |
Land, Buildings and Improvements [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, Plant and Equipment, Gross | 0 | 0 |
Vehicles [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, Plant and Equipment, Gross | 40,061 | 40,061 |
Furniture and Fixtures [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, Plant and Equipment, Gross | $ 1,092,926 | $ 1,089,648 |
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, 2017 | Dec. 31, 2016 | |
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Abstract] | ||
Acquisition - Proved | $ 0 | $ 0 |
Acquisition- Unproved | 0 | 0 |
Development | 4,525,452 | 1,210,261 |
Exploration | $ 0 | $ 2,603,209 |
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, 2017 | Dec. 31, 2016 | |
Capitalized Exploratory Well Costs, Roll Forward [Abstract] | ||
Beginning balance at January 1 | $ 0 | $ 0 |
Additions to capitalized exploratory well costs pending the determination of proved reserves | 0 | 0 |
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves | 0 | 0 |
Ending balance at December 31 | $ 0 | $ 0 |
NOTE 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, 2017 | Dec. 31, 2016 | |
Results of Operations for Oil and Gas Producing Activities Disclosure [Abstract] | ||
Oil and gas sales | $ 554,235 | $ 538,631 |
Production related costs | (435,637) | (594,241) |
Lease Impairment | (289,775) | (2,071,849) |
Depreciation, depletion and amortization | (116,017) | (283,874) |
Results of operations from producing and exploration activities | (287,194) | (2,411,333) |
Income Taxes (Benefit) | 0 | 0 |
Net Results | $ (287,194) | $ (2,411,333) |
NOTE 3 - ASSET RETIREMENT OBL40
NOTE 3 - ASSET RETIREMENT OBLIGATION (Details) - Schedule of Change in Asset Retirement Obligation - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Schedule of Change in Asset Retirement Obligation [Abstract] | ||
Asset retirement obligation, Beginning of the year | $ 952,110 | $ 1,096,179 |
Liabilities incurred during the period | 53,142 | 90,000 |
Settlements | 0 | (10,498) |
Sales | 0 | (229,465) |
Accretion expense | (4,344) | 5,894 |
Asset retirement obligation, End of year | $ 1,000,908 | $ 952,110 |
NOTE 4 - TURNKEY DRILLING OBL41
NOTE 4 - TURNKEY DRILLING OBLIGATION (Details) - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 |
Deferred Revenue Disclosure [Abstract] | ||
Customer Deposits, Current | $ 5,891,898 | $ 7,894,001 |
NOTE 5 - LONG-TERM DEBT (Deta
NOTE 5 - LONG-TERM DEBT (Details) - Schedule of Long-term Debt - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 |
Debt Instrument [Line Items] | ||
Long Term Debt | $ 0 | $ 0 |
Less Current Maturity | 0 | 0 |
Long Term Debt Less Current Portion | 0 | 0 |
Secured Debt [Member] | ||
Debt Instrument [Line Items] | ||
Long Term Debt | $ 0 | $ 0 |
NOTE 6 - INCOME TAXES (Details)
NOTE 6 - INCOME TAXES (Details) - USD ($) $ in Millions | Dec. 22, 2017 | Dec. 21, 2017 | Dec. 31, 2017 | Dec. 31, 2016 |
Income Tax Disclosure [Abstract] | ||||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21.00% | 35.00% | 34.00% | 34.00% |
Deferred Tax Assets, Tax Credit Carryforwards | $ 1.4 | |||
Operating Loss Carryforwards | $ 12 | |||
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, 2017 | Dec. 31, 2016 |
Deferred Tax Assets (Liabilities): | ||
Statutory Depletion Carry Forward | $ 369,591 | $ 474,250 |
Net Operating Loss | 3,130,841 | 5,392,208 |
Other | 1,013,329 | 1,255,372 |
Share-Based Compensation | 69,609 | 104,388 |
Capital Loss / AMT Credit Carry Forward | 18,915 | 18,915 |
Charitable Contributions Carry Forward | 10,025 | 13,102 |
Allowance for Doubtful Accounts | 514,067 | 886,056 |
Oil and Gas Properties and Fixed Assets | 4,839,823 | 5,922,031 |
9,966,200 | 14,066,322 | |
Valuation Allowance | (9,966,200) | (14,066,322) |
Net Deferred Tax Asset | $ 0 | $ 0 |
NOTE 6 - INCOME TAXES (Detai45
NOTE 6 - INCOME TAXES (Details) - Schedule of Effective Income Tax Rate Reconciliation - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Schedule of Effective Income Tax Rate Reconciliation [Abstract] | ||
Tax (benefit) computed at statutory rate of 34% | $ (825,237) | $ (1,400,617) |
Increase (decrease) in taxes resulting from: | ||
State tax / percentage depletion / other | 990 | 937 |
Other non-deductible expenses | 403 | 624 |
Change in valuation allowance | 823,844 | 1,399,056 |
Provision (benefit) | $ 0 | $ 0 |
NOTE 6 - INCOME TAXES (Detai46
NOTE 6 - INCOME TAXES (Details) - Schedule of Effective Income Tax Rate Reconciliation (Parentheticals) | Dec. 22, 2017 | Dec. 21, 2017 | Dec. 31, 2017 | Dec. 31, 2016 |
Schedule of Effective Income Tax Rate Reconciliation [Abstract] | ||||
Statutory rate | 21.00% | 35.00% | 34.00% | 34.00% |
NOTE 6 - INCOME TAXES (Detai47
NOTE 6 - INCOME TAXES (Details) - Schedule of Components of Income Tax Expense (Benefit) - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
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 48
NOTE 7 - SERIES AA PREFERRED STOCK (Details) - USD ($) | 1 Months Ended | |||
Nov. 30, 2016 | Apr. 30, 1992 | Dec. 31, 2016 | Sep. 30, 2016 | |
NOTE 7 - SERIES AA PREFERRED STOCK (Details) [Line Items] | ||||
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 |
NOTE 8 - COMMON STOCK (Details) [Line Items] | |||
Warrants, Vesting Term | 1 year | ||
Securities Purchase Agreement [Member] | |||
NOTE 8 - COMMON STOCK (Details) [Line Items] | |||
Number of Investors | 3 | 1 | |
Stock Issued During Period, Shares, New Issues | shares | 497,948 | 2,392,500 | 622,316 |
Shares Issued, Price Per Share | $ / shares | $ 0.408 | $ 0.40 | $ 0.3214 |
Class of Warrant or Right, Number of Securities Called by Warrants or Rights | shares | 248,973 | 478,500 | 311,158 |
Class of Warrant or Right, Exercise Price of Warrants or Rights | $ / shares | $ 1 | $ 0.80 | $ 0.5356 |
Warrant Term | 3 years | 2 years | 3 years |
Proceeds from Issuance or Sale of Equity | $ | $ 203,165 | $ 957,000 | $ 200,000 |
Fair Value Assumptions, Expected Volatility Rate | 78.96% | ||
Fair Value Assumptions, Risk Free Interest Rate | 1.13% | ||
Fair Value Assumptions, Expected Term | 1460 days |
NOTE 9 - OPERATING LEASES (Deta
NOTE 9 - OPERATING LEASES (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
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 | $ 110,909 | $ 63,733 |
El Cajon, CA [Member] | ||
NOTE 9 - OPERATING LEASES (Details) [Line Items] | ||
Description of Lessee Leasing Arrangements, Operating Leases | yearly increase of 3.5% | |
Lessee, Operating Lease, Term of Contract | 62 months | |
San Diego, CA [Member] | Minimum [Member] | ||
NOTE 9 - OPERATING LEASES (Details) [Line Items] | ||
Operating Leases, Rent Expense, Minimum Rentals | $ 6,148 | |
San Diego, CA [Member] | Maximum [Member] | ||
NOTE 9 - OPERATING LEASES (Details) [Line Items] | ||
Operating Leases, Rent Expense, Minimum Rentals | $ 10,801 | |
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 |
NOTE 9 - OPERATING LEASES (Det
NOTE 9 - OPERATING LEASES (Details) - Schedule of Future Minimum Rental Payments for Operating Leases | Dec. 31, 2017USD ($) |
Schedule of Future Minimum Rental Payments for Operating Leases [Abstract] | |
2,018 | $ 119,286 |
2,019 | 123,251 |
2,020 | 127,355 |
2,021 | 131,602 |
2,022 | 13,802 |
Total | $ 515,296 |
NOTE 10 - RELATED PARTY TRANS52
NOTE 10 - RELATED PARTY TRANSACTIONS (Details) | Feb. 27, 2018 | Dec. 31, 2016USD ($) | Dec. 31, 2017USD ($) |
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 | ||
Wells, Fractional Interest, Value (in Dollars) | $ 1,556 | ||
Due to Related Parties (in Dollars) | $ 340 | ||
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 | ||
Wells, Fractional Interest, Value (in Dollars) | $ 1,556 | ||
Due from Related Parties (in Dollars) | 11,817 | ||
Harry E. Hosmer, former president and former chief executive officer [Member] | |||
NOTE 10 - RELATED PARTY TRANSACTIONS (Details) [Line Items] | |||
Wells, Fractional Interest, Value (in Dollars) | $ 1,556 | ||
Due from Related Parties (in Dollars) | $ 3,999 | ||
Subsequent Event [Member] | Donald H. Hosmer, co-president and co-chief executive officer [Member] | |||
NOTE 10 - RELATED PARTY TRANSACTIONS (Details) [Line Items] | |||
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners | 6.75% | ||
Number of Wells, Participated Individually | 179 | ||
Subsequent Event [Member] | Stephen M. Hosmer, co-president, co-chief executive officer and chief financial officer [Member] | |||
NOTE 10 - RELATED PARTY TRANSACTIONS (Details) [Line Items] | |||
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners | 6.32% | ||
Number of Wells, Participated Individually | 179 | ||
Subsequent Event [Member] | Harry E. Hosmer, former president and former chief executive officer [Member] | |||
NOTE 10 - RELATED PARTY TRANSACTIONS (Details) [Line Items] | |||
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners | 7.09% | ||
Number of Wells with Fractional Interest | 1 |
NOTE 11 - STOCK COMPENSATION 53
NOTE 11 - STOCK COMPENSATION PLAN (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
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 | 0 |
Allocated Share-based Compensation Expense | $ 0 | $ 0 |
2014 Stock Options [Member] | Employee Stock Option [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 54
NOTE 11 - STOCK COMPENSATION PLAN (Details) - Schedule of Share-based Compensation, Stock Options, Activity - $ / shares | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Options | ||
Outstanding and Exercisable at Beginning of Year (in Shares) | 100,000 | 100,000 |
Outstanding and Exercisable at Beginning of Year | $ 5 | $ 5 |
Granted or Vested (in Shares) | 0 | 0 |
Granted or Vested | $ 0 | $ 0 |
Exercised (in Shares) | 0 | 0 |
Exercised | $ 0 | $ 0 |
Forfeited (in Shares) | (100,000) | 0 |
Forfeited | $ 0 | $ 0 |
Options Outstanding and Exercisable at Year End (in Shares) | 0 | 100,000 |
Options Outstanding and Exercisable at Year End | $ 0 | $ 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 55
NOTE 11 - STOCK COMPENSATION PLAN (Details) - Schedule of Nonvested Restricted Stock Units Activity - $ / shares | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Non-vested Stock Options | ||
Non-vested at Beginning of Year | 0 | 0 |
Non-vested at Beginning of Year | $ 0 | $ 0 |
Granted | 0 | 0 |
Granted | $ 0 | $ 0 |
Reinstated | 0 | 0 |
Reinstated | $ 0 | $ 0 |
Vested | 0 | 0 |
Vested | $ 0 | $ 0 |
Expired or Forfeited | 0 | 0 |
Expired or Forfeited | $ 0 | $ 0 |
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, 2017 | Dec. 31, 2016 | |
NOTE 12 - SIMPLE IRA PLAN (Details) [Line Items] | ||
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent | 3.00% | |
Defined Contribution Plan, Cost | $ 28,967 | $ 29,011 |
NOTE 14 - CONCENTRATIONS OF C57
NOTE 14 - CONCENTRATIONS OF CREDIT RISK (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
NOTE 14 - CONCENTRATIONS OF CREDIT RISK (Details) [Line Items] | ||
Cash, FDIC Insured Amount | $ 250,000 | |
Cash, Uninsured Amount | $ 2,800,000 | $ 4,500,000 |
Sales Revenue, Net [Member] | Customer A [Member] | Customer Concentration Risk [Member] | ||
NOTE 14 - CONCENTRATIONS OF CREDIT RISK (Details) [Line Items] | ||
Concentration Risk, Percentage | 32.00% |
NOTE 17 - SUBSEQUENT EVENTS (De
NOTE 17 - SUBSEQUENT EVENTS (Details) - USD ($) | Feb. 28, 2018 | Nov. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 02, 2016 |
NOTE 17 - SUBSEQUENT EVENTS (Details) [Line Items] | |||||
Debt Conversion, Original Debt, Amount | $ 25,000 | ||||
Convertible Notes Payable [Member] | |||||
NOTE 17 - SUBSEQUENT EVENTS (Details) [Line Items] | |||||
Debt Instrument, Face Amount | $ 1,580,000 | ||||
Debt Conversion, Converted Instrument, Shares Issued (in Shares) | 750,000 | ||||
Debt Instrument, Convertible, Conversion Price (in Dollars per share) | $ 0.40 | ||||
Convertible Notes Payable [Member] | Note to Two Investors [Member] | |||||
NOTE 17 - SUBSEQUENT EVENTS (Details) [Line Items] | |||||
Debt Instrument, Face Amount | $ 1,580,000 | ||||
Convertible Notes Payable [Member] | Note #1 Entered into Negotiations [Member] | |||||
NOTE 17 - SUBSEQUENT EVENTS (Details) [Line Items] | |||||
Debt Instrument, Face Amount | $ 1,280,000 | ||||
Subsequent Event [Member] | Note #1 Entered into Negotiations [Member] | Warrant Cancelled [Member] | |||||
NOTE 17 - SUBSEQUENT EVENTS (Details) [Line Items] | |||||
Warrant Term | 2 years | ||||
Stock Issued During Period, Shares, Conversion of Convertible Securities (in Shares) | 1,066,667 | ||||
Class of Warrant or Right, Exercise Price of Warrants or Rights (in Dollars per share) | $ 0.80 | ||||
Subsequent Event [Member] | Convertible Notes Payable [Member] | Note #2 Entered into Negotiations [Member] | |||||
NOTE 17 - SUBSEQUENT EVENTS (Details) [Line Items] | |||||
Debt Conversion, Original Debt, Amount | $ 300,000 | ||||
Debt Conversion, Converted Instrument, Shares Issued (in Shares) | 750,000 | ||||
Debt Instrument, Convertible, Conversion Price (in Dollars per share) | $ 0.40 | ||||
Subsequent Event [Member] | Settled Litigation [Member] | |||||
NOTE 17 - SUBSEQUENT EVENTS (Details) [Line Items] | |||||
Litigation Settlement, Expense | $ 438,667 | ||||
Interest Expense, Other | 181,333 | ||||
Subsequent Event [Member] | Settled Litigation [Member] | Convertible Notes Payable [Member] | Note #1 Entered into Negotiations [Member] | |||||
NOTE 17 - SUBSEQUENT EVENTS (Details) [Line Items] | |||||
Debt Instrument, Face Amount | 1,280,000 | ||||
Loss Contingency, Damages Awarded, Value | $ 1,900,000 |
NOTE 18 - SUPPLEMENTAL INFORM59
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) | 12 Months Ended | |||||||||||||
Dec. 31, 2017USD ($) | Dec. 31, 2017USD ($)MMcf | Dec. 31, 2017USD ($)bbl | Dec. 31, 2016USD ($) | Dec. 31, 2016USD ($)$ / MMcf | Dec. 31, 2016USD ($)$ / bbl | Dec. 31, 2016USD ($)MMcf | Dec. 31, 2016USD ($)bbl | Dec. 31, 2017MMcf | Dec. 31, 2017bbl | Dec. 31, 2016MMcf | Dec. 31, 2016bbl | Dec. 31, 2015MMcf | Dec. 31, 2015bbl | |
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 | $ 3,755,705 | $ 3,755,705 | $ 3,755,705 | ||||||
Fair Value Inputs, Discount Rate | 10.00% | 10.00% | ||||||||||||
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | 307,371 | (5,549) | 74,983 | 2,446 | ||||||||||
Proved Developed Reserves (Volume) | 1,798,697 | 202 | 1,699,997 | 5,823 | 2,174,100 | 0 | ||||||||
Proved Undeveloped Reserve (Volume) | 333,524 | 0 | 314,925 | 0 | 336,600 | 3,600 | ||||||||
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions | 40 | 0 | 112,265 | 0 | ||||||||||
Exploratory Wells Drilled, Net Productive | 2 | |||||||||||||
Development Wells Drilled, Net Productive | 1 | |||||||||||||
Producing and Non-producing Natural Gas Reserves at California [Member] | ||||||||||||||
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items] | ||||||||||||||
Number of Wells | 8 | |||||||||||||
Producing and Non-producing Natural Gas Reserves at Utah [Member] | ||||||||||||||
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items] | ||||||||||||||
Number of Wells | 1 | |||||||||||||
Drilled and Began Producing in 2011 [Member] | ||||||||||||||
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items] | ||||||||||||||
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | 122,998 | |||||||||||||
Proved Developed Reserves (Volume) | 63,350 | |||||||||||||
Drilled and Began Producing Prior to 2000 [Member] | ||||||||||||||
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items] | ||||||||||||||
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | 118,006 | (150,609) | ||||||||||||
Proved Developed Reserves (Volume) | 128,165 | 187,500 | ||||||||||||
Drilled and Began Producing in 2010 [Member] | ||||||||||||||
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items] | ||||||||||||||
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | 15,227 | 31,843 | ||||||||||||
Proved Developed Reserves (Volume) | 618,709 | 592,700 | ||||||||||||
Drilled and Began Producing in 2006 [Member] | ||||||||||||||
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items] | ||||||||||||||
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | 14,688 | |||||||||||||
Drilled and Began Producing in 2012 [Member] | ||||||||||||||
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items] | ||||||||||||||
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | 10,994 | |||||||||||||
Proved Developed Reserves (Volume) | 0 | |||||||||||||
Drilled and Began Producing in 2008 [Member] | ||||||||||||||
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items] | ||||||||||||||
Proved Undeveloped Reserve (Volume) | 13,878 | |||||||||||||
Drilled and Began Producing Prior to 2015 [Member] | ||||||||||||||
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items] | ||||||||||||||
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | 6,084 | |||||||||||||
Proved Undeveloped Reserves [Member] | ||||||||||||||
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items] | ||||||||||||||
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | 18,598 | |||||||||||||
Proved Undeveloped Reserve (Volume) | 314,925 | |||||||||||||
New Exploratory Well [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 in 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 | 71,607 | |||||||||||||
Proved Developed Reserves (Volume) | 400,400 | |||||||||||||
Drilled and Began Producing in 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 in 2015, Undeveloped Reserves [Member] | ||||||||||||||
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items] | ||||||||||||||
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | 20,099 | |||||||||||||
Proved Undeveloped Reserve (Volume) | 16,900 | |||||||||||||
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 and Undeveloped Reserves, Revisions of Previous Estimates | 37,181 | |||||||||||||
Proved Developed Reserves (Volume) | 249,500 | |||||||||||||
Two Locations Drilled 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 | |||||||||||||
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 Million Cubic Feet) | $ / MMcf | 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 Million Cubic Feet) | $ / bbl | 39.25 | |||||||||||||
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 |
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 | 12 Months Ended | |||
Dec. 31, 2017MMcf | Dec. 31, 2017bbl | Dec. 31, 2016MMcf | Dec. 31, 2016bbl | |
Proved developed and undeveloped reserves: | ||||
Proved developed and undeveloped reserves | 2,014,921 | 5,853 | 2,510,700 | 3,600 |
Revisions of previous estimates | 307,371 | (5,549) | 74,983 | 2,446 |
Production | (190,111) | (102) | (232,539) | (193) |
Extensions, discoveries and improved recovery | 40 | 0 | 112,265 | 0 |
Purchase of minerals in place | 0 | 0 | 0 | 0 |
Sales of minerals in place | 0 | 0 | (450,488) | 0 |
Proved developed and undeveloped reserves | 2,132,221 | 202 | 2,014,921 | 5,853 |
Proved developed reserves: | ||||
Proved developed reserves | 1,699,997 | 5,823 | 2,174,100 | 0 |
Proved developed reserves | 1,798,697 | 202 | 1,699,997 | 5,823 |
Proved undeveloped reserves: | ||||
Proved undeveloped reserves | 314,925 | 0 | 336,600 | 3,600 |
Proved undeveloped reserves | 333,524 | 0 | 314,925 | 0 |
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, 2017 | Dec. 31, 2016 |
Schedule of Future Development Costs, Oil and Gas Production [Abstract] | ||
2,018 | $ 103,300 | |
2,019 | 342,700 | |
2,020 | 0 | |
Thereafter | 134,800 | |
Total | $ 580,800 | $ 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 - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Abstract] | ||
Future cash inflows | $ 6,065,500 | $ 5,270,400 |
Future production costs | (2,117,900) | (1,744,200) |
Future development costs | (580,800) | (556,500) |
Future income tax expense | (1,010,040) | (890,910) |
Future net cash flows | 2,356,760 | 2,078,790 |
10% annual discount for estimated timing of cash flows | (712,072) | (595,518) |
Standardized measure of discounted future net cash flows | 1,644,688 | 1,483,272 |
Sales of oil and gas produced, net of production costs | (161,139) | (55,272) |
Revisions of previous quantity estimates | 87,956 | 120,833 |
Net changes in prices and production costs | 106,303 | (253,313) |
Sales of minerals in place | 0 | (402,900) |
Purchases of minerals in place | 0 | 0 |
Extensions, discoveries and improved recovery | 74 | 184,476 |
Accretion of discount | 197,400 | 296,970 |
Net change in income tax | (69,178) | 32,762 |
Net increase (decrease) | $ 161,416 | $ (76,444) |
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 (Parentheticals) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [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, 2017USD ($) |
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 | $ 103,300 |
Estimated Future Costs, Year 2 | 342,700 |
Estimated Future Costs, Year 3 | 0 |
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 | 103,300 |
Estimated Future Costs, Year 2 | 0 |
Estimated Future Costs, Year 3 | 0 |
Proved Undeveloped Reserves [Member] | |
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Future Development Costs, Oil and Gas Production [Line Items] | |
Estimated Future Costs, Year 1 | 0 |
Estimated Future Costs, Year 2 | 342,700 |
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 | 103,300 |
Estimated Future Costs, Year 2 | 342,700 |
Estimated Future Costs, Year 3 | $ 0 |
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 ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Schedule of Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Abstract] | |||
Cost incurred for proved undeveloped reserves | $ 0 | $ 243,583 | $ 0 |