| Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block] | NOTE 1 – The Company has a substantial investment in RMX Resources, LLC (“RMX”), a joint venture with CIC RMX LP. Royale entered into the RMX joint venture on April 13, 2018 and records its interest in RMX under the equity method as further described below. Liquidity and Going Concern The Company has had recurring operating and net losses and cash used in operations and the consolidated financial statements reflect a working capital deficiency of $5,662,446 and an accumulated deficit of $73,652,310. These factors raise substantial doubt about our ability to continue as a going concern. We anticipate that our primary sources of liquidity will be from the sale of oil & gas in the course of normal operations, the sale of oil and gas property, sales of participation interest and possible issuance of debt and/or equity. If the Company is unable to generate sufficient cash from operations or financing sources, it may become necessary to curtail, suspend or cease operations, sell property, or enter into financing transaction(s) on less favorable terms; any such outcomes could have a material adverse effect on the Company’s business, results of operations, financial position and liquidity. Additionally, management has, and plans to continue, to increase revenue and reduce overhead and Lease Operating Expense (LOE) costs. 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. Consolidation The accompanying consolidated financial statements include the accounts of Royale Energy, Inc. (sometimes called the “Company” “we,” “our,” “us,” “Royale Energy,” or “Royale”), Royale Energy Funds, Inc. (“REF”), and Matrix Oil Management Corporation and its subsidiaries. All entities comprising the consolidated financial statements of Royale Energy have fiscal years ending December 31. All material intercompany accounts and transactions have been eliminated in the consolidated financial statements. 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. Termination of RMX MSA On December 31, 2018, Royale was formally notified of RMX Resources, LLC’s intent to terminate the Master Service Agreement (“MSA”) as of March 31, 2019. The Termination Notice calls for Royale to continue to provide accounting and other services through March 31, 2019. Thereafter, per Article VII, Section 7.2 of the MSA, Royale has provided all reasonable assistance requested, by the RMX Board of Directors, to transition the management of RMX through April 30, 2019 at which point all services under the MSA terminated. Settlement Agreement and Well Participation Agreement with RMX On March 11, 2019 Royale entered into a Settlement Agreement with RMX to resolve differences resulting from the calculation of certain post-closing amounts as called for under Section 7.3 of the Subscription and Contribution Agreement. Under the terms of this provision, Royale estimated that it may owe RMX approximately $552,645 related to its calculation of this post-closing amount under this provision. In addition, there are other disputed amounts related to certain joint owner billing amounts remaining unpaid at year end. In settlement of these differences, Royale has agreed to assign its remaining interests in the Bellevue Field, located in Kern County and the W. Whittier Field located in Los Angeles County, California to RMX. At December 31, 2018, the Bellevue and W. Whittier fields accounted for 5.145 and 140.647 Mboe in reserves and were valued at $67,671 and $2.4 million, respectively, using SEC pricing and discounted at 10 percent. Royale will continue to be responsible for the liability for the payment of all royalties and suspended funds incurred prior to March 1, 2018. As part of this Settlement Agreement, RMX will offer Royale the right, but not the obligation, to participate in a number of wells to be drilled in the Sansinena, Sempra, Whittier and/or East LA properties in Los Angeles County, California at an offered working interest up to 75% of RMX’s working interest in each of the offered wells. The minimum number of wells to be offered to Royale in each year is 2 net wells as determined by an agreed upon methodology. The Agreement also calls for certain credits toward future drilling costs of the offered wells. The Company recorded a loss of $1,237,126 on the settlement during 1 st West Coast Settlement On December 5, 2018, Royale entered into a Purchase and Sales Agreement (“West Coast Agreement”) for properties located in the Jameson North Field Area in Mitchell and Nolan Counties, Texas and the Big Mineral Creek Field Area in Grayson County, Texas. The seller was West Coast Energy Properties, LP. The West Coast Agreement called for a post-closing settlement. On July 11, 2019, Royale entered into a post-closing settlement as called for under the terms of the West Coast Agreement calling for payment due seller of $156,975 to be made in equal monthly payments of $26,163 commencing July 31, 2019 with the final payment on December 31, 2019. As part of the post-closing settlement, we capitalized approximately $165,000 to the North Jameson field and increased short term liabilities for approximately $165,000, approximately $157,000 for the total settlement payments and $8,000 for royalties payable assumed in the settlement. Vanco Agreement On September 10, 2019, Royale granted to Vanco Oil and Gas Corporation, the right to purchase all of Matrix’s right, title and interest in certain non-operated oil and gas properties in west Texas. While the purchase has not been consummated, the company is engaged in an ongoing effort to complete this, or a similar transaction in the near future. Revenue Recognition The majority of our ongoing revenues are derived from the sale of crude oil and condensate, natural gas liquids ("NGLs") and natural gas under spot and term agreements with our customers.
For the Three Months
For the Nine Months
2019
2018
2019
2018
Oil & Condensate Sales $ 471,201 $ 221,330 $ 832,108 $ 1,020,703
Natural Gas Sales 139,226 93,267 587,713 243,513
NGL Sales - (1,770 ) - 1,742
Oil, NGL and Gas Sales $ 610,427 $ 312,827 $ 1,419,821 $ 1,265,958 The pricing in our hydrocarbon sales agreements are variable, determined using various published benchmarks which are adjusted for negotiated quality and location differentials. As a result, revenue collected under our agreements with customers is highly dependent on the market conditions and may fluctuate considerably as the hydrocarbon market prices rise or fall. Typically, our customers pay us monthly, within a short period of time after we deliver the hydrocarbon products. As such, we do not have any financing element associated with our contracts. We do not have any issues related to returns or refunds, as product specifications are standardized for the industry and are typically measured when transferred to a common carrier or midstream entity, and other contractual mechanisms (e.g., price adjustments) are used when products do not meet those specifications. When we serve as the operator for jointly owned oil and gas properties, we perform activities to explore, develop and produce oil and gas properties in accordance with the joint operating arrangement and collective decisions of the joint parties. Other working interest owners reimburse us for costs incurred based on our agreements. We determined that these activities are not performed as part of customer relationships, and, accordingly, these reimbursements are not reported as revenue. When we serve as operator, we commonly market the share of production belonging to other working interest owners as the operator of jointly owned oil and gas properties. We concluded that those marketing activities are carried out as part of the collaborative arrangement, and we do not purchase or otherwise obtain control of other working interest owners’ share of production. Therefore, we act as a principal only in regards to the sale of our share of production and recognize revenue for the volumes associated with our net production. The Company frequently sells a portion of the working interest in each well it drills or participates in to third-party investors and retains a portion of the prospect for its own account. The Company typically guarantees a cost to drill to the third-party drilling participants and records a loss or gain on the difference between the guaranteed price and the actual cost to drill the well. When monies are received from third parties for future drilling obligations, the Company records the liability as Deferred Drilling Obligations. Once the contracted depth for the drilling of the well is reached and a determination as to the commercial viability of the well (typically call “Casing Point Election” or “Logging Point”), the difference in the actual cost to drill and the guaranteed cost is recorded as income or expense depending on whether there was a gain or loss. Crude oil and condensate For the crude sales agreements, we satisfy our performance obligations and recognize revenue once customers take control of the crude at the designated delivery points, which include pipelines, trucks or vessels. Natural gas and NGLs When selling natural gas and NGLs, we engage midstream entities to process our production stream by separating natural gas from the NGLs. Frequently, these midstream entities also purchase our natural gas and NGLs under the same agreements. In these situations, we determined the performance obligation is complete and satisfied at the tailgate of the processing plant when the natural gas and NGLs become identifiable and measurable products. We determined the plant tailgate is the point in time where control is transferred to midstream entities and they are entitled to significant risks and rewards of ownership of the natural gas and NGLs. The amounts due to midstream entities for gathering and processing services are recognized as shipping and handling cost and included as lease operating expense in our consolidated statement of operations, since we make those payments in exchange for distinct services with the exception of natural gas sold to PG&E where transportation is netted directly against revenue. Under some of our natural gas processing agreements, we have an option to take the processed natural gas and NGLs in-kind and sell to customers other than the processing company. In those circumstances, our performance obligations are complete after delivering the processed hydrocarbons to the customer at the designated delivery points, which may be the tailgate of the processing plant or an alternative delivery point requested by the customer. Turnkey Drilling Obligations Turnkey Agreements are managed by the Company for the participants of the well. The collections of pre-drilling AFE amounts are segregated by the Company and the gains and losses on the Turnkey Agreements are recorded in income or expense at the time of the casing point election in accordance with ASC 932-323-25 (Extractive Activities - Investments - Equity Method and Joint Ventures) and 932-360 (Extractive Activities - Oil and Gas Property, Plant, and Equipment). The Company manages the performance obligation for the well participants and only records revenue or expense at the time the performance obligation of the Turnkey Agreement has been satisfied. At September 30, 2019 we had Deferred Drilling Obligations of $6,077,583, during the first nine months of 2019 we disposed of $9,382,519 of drilling obligations upon completing the drilling of eight wells, six natural gas wells in Northern California and two oil wells in Southern California, while incurring expenses of $7,484,260 resulting in a gain of $1,898,259. At September 30, 2018, Royale Energy had a Deferred Drilling Obligation of $5,406,678. During the first nine months of 2018, we disposed of $4,797,720 of drilling obligations upon completing the drilling of three natural gas wells in Northern California while incurring expenses of $2,603,261, resulting in a gain of $2,194,459. Supervisory Fees and Other These amounts include proceeds from the MSA with RMX for the providing of land, engineering, accounting and support services for the RMX joint venture. Revenues earned under the MSA are recorded at the end of each month that services were performed in conformity with the Agreement with an offsetting receivable from the RMX joint venture. The service fee income is deemed earned at the end of each month that services are performed as prescribed by the contract. During the first half of 2019, we recognized $540,000 or 39% of our total revenues from these services. Royale has a single supervisory fee customer, that being RMX, which represents 100% of the Supervisory Fee income. On December 31, 2018, Royale received notice of cancelation of the MSA by RMX effective March 31, 2019. Also included are Pipeline and Compressor fees which are received and allocated based on production volumes. Restricted Cash Royale sponsors turnkey drilling arrangements in both proved and exploratory properties. The contracts require that participants pay Royale the full contract price upon execution of the drilling agreement. Each participant earns an undivided interest in the well bore at the completion of the well. A portion of the funds received in advance of the drilling of a well from a working interest participant are held for the expressed purpose of drilling a well. If something changes, the Company may designate these funds for a substitute well. Under certain conditions, a portion of these funds may be required to be returned to a participant. Once the well is drilled, the funds are used to satisfy the drilling cost. Royale classifies these funds prior to drilling as restricted cash. The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheet that sum to the total of the same amounts shown in the statement of cash flows.
September 30, 2019
December 31, 2018
Cash and cash equivalents $ 724,994 $ 1,853,742
Restricted cash 5,622,772 4,501,300
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows $ 6,347,766 $ 6,355,042 Equity Method Investments Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting. Income from equity method investments represents our proportionate share of net income generated by the equity method investees and is reflected in revenue and other income in our consolidated statements of income. Equity method investments are included as noncurrent assets on the consolidated balance sheet. Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value may have occurred as called for under ASC 323. When a loss is deemed to have occurred and is other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income. Listed below is the summarized information required under Rule 3-09 of regulation S-X, Article 10 for Royale’s investment in RMX:
RMX Resources
Royale Energy, Inc.
September 30,
December 31, 2018
September 30,
December 31, 2018
Balance Sheet
Total Assets $ 71,406,655 $ 71,758,262 $ 14,281,331 $ 14,351,653
Total Liabilities 39,110,581 38,838,608 7,822,116 7,767,722
Member Equity 32,296,074 32,919,654 6,459,215 6,583,931
RMX Resources
Royale Energy, Inc.
For the three months ended September 30, 2019
For the nine months ended September 30, 2019
For the three months ended September 30, 2019
For the nine months ended September 30, 2019
Results of Operations:
Net Operating revenue $ 4,195,522 $ 11,975,338 $ 839,104 $ 2,395,068
Income (Loss) from operations 478,946 930,072 95,789 186,014
Net Income (Loss) 1,787,844 (623,579 ) 357,569 (124,716 ) Other Receivables Our other receivables consist of joint interest billing 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 September 30, 2019 and December 31, 2018, the Company maintained an allowance for uncollectable accounts of $2,260,077 and $2,296,384, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue. Revenue Receivables Our revenue receivables consist of receivables related to the sale of our natural gas and oil. Once a production month is completed, we receive payment approximately 15 to 30 days later for Company operated properties. For outside operated properties, we generally receive payment approximately 45 to 60 days later. Fair Value Measurements According to Fair Value Measurements and Disclosures Topic of the Financial Accounting Standards Board (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. The Company estimates the fair value of asset retirement obligations (ARO’s) based on discounted cash flow projections using numerous estimates, assumptions and judgements regarding such factors as the existence of a legal obligation for an ARO, amounts and timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates. At September 30, 2019 and December 31, 2018, Royale Energy did 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” Fair Values - Non-recurring The Company applies the provisions of the fair value measurement standard to its non-recurring, non-financial measurements including oil and natural gas property impairments and other long-lived asset impairments. These items are not measured at fair value on a recurring basis but are subject to fair value adjustments only in certain circumstances. Dividends on Convertible Preferred Stock, Series B The Convertible Preferred Stock, Series B (“Preferred”), has an obligation to pay a 3.5% cumulative dividend, in kind or cash, on a quarterly basis. In the first quarter of 2019, the Board of Directors authorized the issuance of Preferred shares, for the settlement of dividends accumulated through March 31, 2019. As a result, the Company issued 59,461 Preferred shares for dividends accumulated through December 31, 2018 and 17,879 additional shares for dividends accumulated for the quarter ended March 31, 2019. On September 20, 2019, the Board authorized the settlement, via the issuance of Preferred shares, of each quarterly dividend that will accrue in 2019. Each quarter, the Company charges retained earnings for the accumulating dividend as the amounts add to the liquidation preference of the Preferred. Through September 30, 2019, the total number of shares issued was 77,340. Accounting Standards Recently Adopted ASU 842, Lease Accounting Standard In February 2016, the FASB issued a new leasing accounting standard, which modified the definition of a lease and established comprehensive accounting and financial reporting requirements for leasing arrangements. It requires lessees to recognize a lease liability and a right-of-use ("ROU") asset for all leases, including operating leases, with a term of greater than 12 months on the balance sheet. On January 1, 2019, we adopted the new lease accounting standard as further described in Note 5 using the modified retrospective method and applied to all leases that existed as of that date. It does not apply to oil & gas mineral leases and contracts to explore for or use minerals, oil, natural gas and similar non-regenerative resources, including the intangible right to explore for those natural resources and rights to use the land in which those natural resources are contained. We also adopted the following ASUs during 2018, none of which had a material impact to our financial statements or financial statement disclosures: ASU 2018-02, Reporting Comprehensive Income – Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income In February 2018, the FASB issued an ASU allowing an entity the choice to retained earnings the tax effects related to the TCJA that are stranded in accumulated other comprehensive income. We adopted this standard during the first quarter of 2019. It did not have a material impact to our financial statements or financial statement disclosures. ASU 2017-12, Derivatives and Hedging – Targeted Improvement to Accounting for Hedging Activities In August 2017, the FASB issued an ASU to amend the hedge accounting rules to simplify the application of hedge accounting guidance and better portray the economic results of risk management activities in the financial statements. The guidance expands the ability to hedge nonfinancial and financial risk components, reduces complexity in fair value hedges of interest rate risk, eliminates the requirements to separately measure and report hedge ineffectiveness and eases certain hedge effectiveness assessment requirements. The guidance is effective beginning in 2019. We have not historically used derivatives to hedge our commodity price risk; this ASU did not have a material impact on our consolidated financial statements. NOT YET ADOPTED ASU 2018-18, Collaborative Arrangements (Topic 808) Clarifying the Interaction between Topic 808 and Topic 606 This is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Application of this ASU is not expected to have a material impact on our consolidated financial statements. ASU 2018-17, Consolidation (Topic 810), Targeted Improvements to Related Party Guidance for Variable Interest Entities Effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Application of this ASU is not expected to have a material impact on our consolidated financial statements. ASU 2018-15, Intangibles – Goodwill and Other – Internal Use Software (Subtopic 350-400), Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract Effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2019. Application of this ASU is not expected to have a material impact on our consolidated financial statements. ASU 2018-14, Compensation – Retirement Benefits – Defined Benefit Plans – General (Subtopic 715-720), Disclosure Framework – Changes to the Disclosure Requirements for Defined Benefit Plans Effective for financial statements issued for fiscal years ending after December 15, 2020. Application of this ASU is not expected to have a material impact on our consolidated financial statements. ASU 2018-13, Fair Value Measurement (Topic 820), Disclosure Framework – Changes to the Disclosure Requirements for fair value measurement Effective for fiscal years, and interim periods within those years, beginning after December 15, 2019. Application of this ASU is not expected to have a material impact on our consolidated financial statements. ASU 2017-04, Intangible – Goodwill and Other (Topic 350), Simplifying the Test for Goodwill Impairment In January 2017, the FASB issued a new ASU that eliminates the requirement to calculate the implied fair value of the goodwill (Step 2 of goodwill impairment test under the current guidance) to measure a goodwill impairment charge. We anticipate the standard to require entities to record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value (measure the charge based on Step 1 under the current guidance). This standard is effective for us in the first quarter of 2020 and shall be applied on a prospective basis. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We plan to adopt the standard on a prospective basis, and do not expect a material impact on our consolidated results of operations, financial position or cash flows for prior periods. ASU 2016-13, Financial Instruments – Credit Losses (Topic 326), Measurement of Credit Losses on Financial Instruments Effective for fiscal years beginning after December 15, 2020 including interim periods within those fiscal years. Earlier application is permitted only for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Application of this ASU is not expected to have a material impact on our consolidated financial statements. ASU 2016-13, Credit Losses - CECL – Current Expected Credit Losses Methodology The Financial Accounting Standards Board (FASB) issued a new expected credit loss accounting standard in June 2016. The new accounting standard introduces the current expected credit losses methodology (CECL) for estimating allowances for credit losses. The guidance requires that for most financial assets, losses be based on an expected loss approach which includes estimates of losses over the life of exposures that considers historical, current and forecasted information. Expanded disclosures related to the methods used to estimate the losses as well as a specific disaggregation of balances for financial assets are also required. The standard is effective for SEC filers in fiscal years and interim periods beginning after December 15, 2019. For public business entities that are not SEC filers, the standard takes effect in fiscal years and interim periods beginning after December 15, 2020. For an entity that is not a public business entity, it takes effect in fiscal years beginning after December 15, 2020. |
