Royale Energy, Inc. - Quarter Report: 2020 June (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549 

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D)

OF THE SECURITIES EXCHANGE ACT OF 1934

ROYALE ENERGY, INC.

(Exact name of registrant as specified in its charter)

1870 Cordell Court, Suite 210

El Cajon, CA 92020

(Address of principal executive offices) (Zip Code)

619-383-6600

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and  (2) has been subject to such filing requirements for the past 90 days. Yes  ☒  No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company (as defined in Rule 12b-2 of the Exchange Act).  Check one:

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒

Indicate by check mark whether the registrant is a blank check company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

Securities registered pursuant to Section 12(b) of the Act:

At August 3, 2020, a total of 53,700,191 shares of registrant’s common stock were outstanding. 

TABLE OF CONTENTS 

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

See notes to unaudited condensed consolidated financial statements.

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

See notes to unaudited condensed consolidated financial statements.

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

See notes to unaudited condensed consolidated financial statements.

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

FOR THE six MONTHS ENDED AND 2019

See notes to unaudited condensed consolidated financial statements.

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)

(UNAUDITED)

 See notes to unaudited condensed consolidated financial statements.

ROYALE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1– In the opinion of management, the accompanying unaudited condensed consolidated financial statements (“statements”) include all adjustments necessary to present fairly the Company’s financial position and the results of its operations and cash flows for the periods presented.  The results of operations for the six-month period are not, in management’s opinion, indicative of the results to be expected for a full year of operations.  It is suggested that these financial statements be read in conjunction with the financial statements and the notes thereto included in the Company’s latest annual report as filed on Form 10-K.

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 primary sources of liquidity have historically been issuances of common stock and operations.  There are factors that give rise to substantial doubt about the Company’s ability to meet liquidity demands, and we anticipate that our primary sources of liquidity will be from the issuance of debt and/or equity, the sale of oil and natural gas property participation interests through our normal course of business and the sale of non-strategic assets.

The Company’s 2020 financial statements reflect a working capital deficiency of $4,866,333 and a net loss of $312,384 for the three months ended June 30, 2020. These factors raise substantial doubt about our ability to continue as a going concern. The accompanying financial statements do not include any adjustments that might be necessary if the Company is unable to continue as a going concern.

Management’s plans to alleviate the going concern by cost control measures that include the reduction of overhead costs and the sale of non-strategic assets.  There is no assurance that additional financing will be available when needed or that management will be able to obtain financing on terms acceptable to the Company and whether the Company will become profitable and generate positive operating cash flow, which may be more difficult in light of the volatility created during the COVID-19 pandemic. 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.

Consolidation

The accompanying 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 financial statements of Royale Energy have fiscal years ending December 31.  All material intercompany accounts and transactions have been eliminated in the financial statements.

Correction of an Immaterial Error in Previously Issued Financial Statements

Subsequent to the issuance of the consolidated financial statements for the year ended December 31, 2019, the Company concluded that the Statement of Cash Flows for the year ending December 31, 2019 contained an immaterial error related to the classification of payments arising from operating leases as net cash used in financing activities rather than net cash used in operating activities. This immaterial error has been corrected for the comparative period shown by reclassifying $70,415 from cash flows from financing activities to cash flows used in operating activities for the period ending June 30, 2019.  This immaterial error did not have any impact on our financial position, net loss or total cash flow for the period ending June 30, 2019.

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.  

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 called 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 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 which resulted 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 have owed RMX approximately $552,645 related to its calculation of this post-closing amount under this provision. In addition, there were other disputed amounts related to certain joint owner billing amounts which remained unpaid at year end. In settlement of these differences, Royale 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%.

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 the three months ended March 31, 2019.

West Coast Settlement

On December 5, 2018, Royale entered into a Purchase and Sale 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 for payment due seller of $156,975 which were made in equal monthly payments of $26,163 commencing July 31, 2019 with the final payment on December 31, 2019.

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.

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.

We often serve as the operator for jointly owned oil and gas properties. As part of this role, we perform activities to explore, develop and produce oil and gas properties in accordance with the joint operating arrangement and collective decisions of the joint parties. Other working interest owners reimburse us for costs incurred based on our agreements. We determined that these activities are not performed as part of customer relationships, and such reimbursements are recorded as cost reimbursements.

We commonly market the share of production belonging to other working interest owners as the operator of jointly owned oil and gas properties. Those marketing activities are carried out as part of the collaborative arrangement, and we do not purchase or otherwise obtain control of other working interest owners’ share of production. Therefore, we act as a principal only in regards to the sale of our share of production and recognize revenue for the volumes associated with our net production.

The Company frequently sells a portion of the working interest in each well it drills or participates in, to third-party investors and retains a portion of the prospect for its own account.  The Company typically guarantees a cost to drill to the third-party drilling participants and records a loss or gain on the difference between the guaranteed price and the actual cost to drill the well.  When monies are received from third parties for future drilling obligations, the Company records the liability as 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, as defined in the new revenue standard, is transferred to midstream entities and they are entitled to significant risks and rewards of ownership of the natural gas and NGLs.

The amounts due to midstream entities for gathering and processing services are recognized as shipping and handling cost and included as lease operating expense in our consolidated statement of operations, since we make those payments in exchange for distinct services with the exception of natural gas sold to Pacific Gas & Electric (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

These Turnkey Drilling 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 Drilling Agreements are recorded in income or expense at the time of the casing point election in accordance with ASC 932-323-25 and 932-360. The Company manages the performance obligation for the well participants and only records revenue or expense at the time the performance obligation of the Turnkey Drilling Agreement has been satisfied.

Supervisory Fees and Other

These amounts include proceeds from the Master Service Agreement (“MSA”) with RMX for the providing of land, engineering, accounting and support services for the RMX joint venture. Revenues earned under the MSA were recorded at the end of each month that services were performed, in conformity with the Agreement. The service fee income was deemed earned at the end of each month that services were performed as prescribed by the contract. On December 31, 2018, Royale received notice of cancelation of the MSA by RMX effective March 31, 2019. For the six months ended June 30, 2019, the Company recognized $540,000 in supervisory fees from RMX. Also included in the caption are Pipeline and Compressor fees which are received and allocated based on production volumes.

Restricted Cash

Royale sponsors turnkey drilling arrangements in proved and unproved properties. The contracts require that participants pay Royale the full contract price upon execution of the drilling agreement. Each participant earns an undivided interest in the well bore at the completion of the well. A portion of the funds received in advance of the drilling of a well from a working interest participant are held for the expressed purpose of drilling a well. If something changes, the Company may designate these funds for a substitute well. Under certain conditions, a portion of these funds may be required to be returned to a participant. Once the well is drilled, the funds are used to satisfy the drilling cost. Royale classifies these funds prior to commencement of drilling as restricted cash based on guidance codified as under the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 230-10-50-8. In the event that progress payments are made from these funds, they are recorded as Prepaid Expenses and Other Current Assets.

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheet that sum to the total of the same amounts shown in the statement of cash flows.

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 condensed consolidated statements of operations. Equity method investments are included as noncurrent assets on the consolidated balance sheet.

Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value may have occurred as called for under ASC 323. When a loss is deemed to have occurred and is other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income.

The earnings from RMX reflected in these financial statements as Investment in Joint Venture (“JV”), reflect our share of net earnings or losses directly attributable to this equity method investment. As of June 30, 2020, we evaluated our investment in RMX and determined that any losses were not other than temporary.

Listed below is the summarized information required under Rule 3-09 of regulation S-X, Article 10 for Royale’s investment in RMX:

Other Receivables

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 June 30, 2020 and December 31, 2019, the Company maintained an allowance for uncollectable accounts of $1,868,508 and $1,791,162, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue.

Fair Value Measurements

According to Fair Value Measurements and Disclosures Topic of the FASB ASC, assets and liabilities that are measured at fair value on a recurring and nonrecurring basis in period subsequent to initial recognition, the reporting entity shall disclose information that enable users of its financial statements to assess the inputs used to develop those measurements and for recurring fair value measurements using significant unobservable inputs, the effect of the measurements on earnings for the period.

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. In determining fair value, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible as well as considers counterparty credit risk in its assessment of fair value. Carrying amounts of the Company’s financial instruments, including cash equivalents, accounts receivable, accounts payable and accrued liabilities, approximate their fair values as of the balance sheet dates because of their generally short maturities.

The fair value hierarchy distinguishes between (1) market participant assumptions developed based on market data obtained from independent sources (observable inputs) and (2) an entity’s own assumptions about market participant assumptions developed based on the best information available in the circumstances (unobservable inputs). The fair value hierarchy consists of three broad levels, which gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy are described below:

Level 1: Quoted prices (unadjusted) in active markets that are accessible at the measurement date for assets or liabilities.

Level 2: Directly or indirectly observable inputs as of the reporting date through correlation with market data, including quoted prices for similar assets and liabilities in active markets and quoted prices in markets that are not active. Level 2 also includes assets and liabilities that are valued using models or other pricing methodologies that do not require significant judgment since the input assumptions used in the models, such as interest rates and volatility factors, are corroborated by readily observable data from actively quoted markets for substantially the full term of the financial instrument.

Level 3: Unobservable inputs that are supported by little or no market activity and reflect the use of significant management judgment. These values are generally determined using pricing models for which the assumptions utilize management’s estimates of market participant assumptions.

At June 30, 2020 and December 31, 2019, Royale Energy does not have any financial assets measured and recognized at fair value on a recurring basis. The Company estimates asset retirement obligations (ARO’s) pursuant to the provisions of ASC 410, “Asset Retirement and Environmental Obligations”. The estimates of the fair value the ARO’s are 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.

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs.

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 Series B Convertible Preferred Stock

The Series B Convertible Preferred Stock, (“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 December 31, 2020.  The Company accrued $188,834 and $178,794 for dividends related to the Preferred shares during the second quarters of 2020 and 2019, respectively. Each quarter, the Company charges retained earnings for the accumulating dividend as the amounts add to the liquidation preference of the Preferred. For further information regarding the Preferred Stock see Note 3, below.

Accounting Standards

Recently Adopted

We adopted the following ASUs during 2020, none of which had a material impact to our financial statements or financial statement disclosures:

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 did not 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 has not had 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 has not had 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 has not had a material impact on our consolidated financial statements.

NOT YET ADOPTED

ASU 2016-13, Financial Instruments – Credit Losses (Topic 326), Measurement of Credit Losses on Financial Instruments

In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326) Measurement of Credit Losses on Financial Instruments ("ASU 2016-13"). The main objective of ASU 2016-13 is to provide financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. To achieve this objective, the amendments in ASU 2016-13 replace the incurred loss impairment methodology in current U.S. GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. ASU 2016-13 is effective for the Company for fiscal years beginning after December 15, 2022, including interim periods within those years, and must be adopted under a modified retrospective method approach. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company's consolidated financial statements.

NOTE 2 – OIL AND GAS PROPERTY AND EQUIPMENT AND FIXTURES

Oil and gas properties, equipment and fixtures consist of the following:

The guidance set forth in the Continued Capitalization of Exploratory Well Costs paragraph of the Extractive Activities Topic of the FASB ASC requires that we evaluate all existing capitalized exploratory well costs and disclose the extent to which any such capitalized costs have become impaired and are expensed or reclassified during a fiscal period.

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 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 oil and gas 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 and whether carrying amounts should be impaired. The Company performs the evaluation of carrying amounts at least annually or when economic events or commodity prices indicate that a substantial and measurable change in future cash flows has occurred. Cash flows used in impairment evaluations are developed using updated evaluation assumptions for crude oil and natural gas commodity prices.  Annual volumes are based on field production profiles, which are also updated annually.

Impairment analyses are generally based on proved reserves. An asset group would be further assessed if the undiscounted cash flows were less than its’ carrying value.  Impairments are measured by the amount the carrying value exceeds fair value. During the six months ended June 30, 2020 and 2019 no impairment losses were incurred.

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.

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 June 30, 2020 and December 31, 2019, Royale Energy had Deferred Drilling Obligations of $2,531,094 and $5,232,675, 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 contract and return the remaining funds to the participant.  Included in Restricted Cash 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.

NOTE 3 - SERIES B PREFERRED STOCK

Pursuant to the merger in 2018, Royale issued 2,012,400 shares of Series B Convertible Preferred Stock. The Board of Directors of Royale Energy, prior to the merger, authorized 3,000,000 shares of Series B Convertible Preferred, which carries a liquidation preference and a 3.5% dividend, payable in cash or Paid-In-Kind shares. The Series B Convertible Preferred Stock is convertible at the option of the security holder at the rate of ten shares of common stock for one share of Series B Convertible Preferred Stock. The Series B Preferred Stock has never been registered under the Securities Exchange Act of 1934, and no market exists for the shares. Additionally, the Series B Convertible Preferred shares will automatically convert to common stock at any time in which the Volume Weighted Average Price (VWAP) of the common stock exceeds $3.50 per share for 20 consecutive trading days, the shares are registered with the SEC and the volume of common shares trades exceeds 200,000 shares per day.

The shareholders of the Series B Convertible Preferred became entitled to vote the number of shares into which they would be entitled to convert, beginning in 2020. In accordance with ASC 480-10-S99-1.02, the Company has determined that the conversion or redemption of these shares are outside the sole control of the Company and that they should be classified in mezzanine or temporary equity as redeemable noncontrolling interest beginning at the reporting period ended June 30, 2020.

NOTE 4 – LOSS PER SHARE

Basic and diluted loss per share are calculated as follows:

For the six months ended June 30, 2020 and 2019, Royale Energy had dilutive securities of 25,157,462 and 23,978,631, respectively.  For the three months ended June 30, 2020 and 2019, Royale Energy had dilutive securities of 25,165,320 and 23,976,804, respectively.  In both periods, these securities were not included in the dilutive loss per share, due to their antidilutive nature.

NOTE 5 – 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.  At the end of 2015, management reviewed the reliability of the Company’s net deferred tax assets, and due to the Company’s continued cumulative losses in recent years, the Company 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 2020.

A reconciliation of Royale Energy’s provision for income taxes and the amount computed by applying the statutory income tax rates at June 30, 2020 and 2019, respectively, to pretax income is as follows: 

NOTE 6 – ISSUANCE OF COMMON STOCK

During the six months ended June 30, 2020, in lieu of cash payments for salaries and board fees, Royale issued 1,390,787 shares of its Common stock valued at approximately $169,550 to an executive officer and board members, compared to the issuance of 1,383,221 shares issued with an approximate value of $348,923 in the same period of 2019.

NOTE 7 – Cares act – ppp loan

On April 22, 2020, the Company entered into a loan (the "PPP Loan") evidenced by a promissory note (the "Promissory Note"), under the Paycheck Protection Program sponsored by the U.S. Small Business Administration ("SBA") through the Bank of Southern California N.A. providing for $207,800 in proceeds, which amount was funded to the Company on April 23, 2020. The PPP Loan was made pursuant to the Coronavirus Aid, Relief, and Economic Security Act (the "CARES Act") and is administered by the SBA.

The Promissory Note matures April 22, 2022 and provides for 18 monthly payments of principal and interest commencing on November 21, 2020. The interest rate on the PPP Loan is 1.00%. The Promissory Note is unsecured and contains customary events of default relating to, among other things, payment defaults, making materially false and misleading representations to the SBA or Bank of Southern California N.A., or breaching the terms of the PPP Loan. The occurrence of an event of default may result in the repayment of all amounts outstanding, collection of all amounts owing from the Company, or filing suit and obtaining judgment against the Company. The Promissory Note principal may be forgiven subject to the terms of the Paycheck Protection Program.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements

In addition to historical information contained herein, this discussion contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, subject to various risks and uncertainties that could cause our actual results to differ materially from those in the “forward-looking statements”. While we believe our forward-looking statements are based upon reasonable assumptions, there are factors that are difficult to predict and that are influenced by economic and other conditions beyond our control. Investors are directed to consider such risks and other uncertainties discussed in documents filed by the Company with the Securities and Exchange Commission.

Results of Operations

In late 2019 and continuing into 2020, there was a global outbreak of novel coronavirus (COVID-19) that has resulted in changes in global supply and demand of certain mineral and energy products. While the direct and indirect negative impacts that may affect the Company cannot be determined, they could have a prospective material impact.  For more information, see Item 3 below.

For the six months ended June 30, 2020, we had a net income of $71,978, when compared to the net loss of $3,104,674, during the six months ended June 30, 2019. This difference was primarily the result of a gain of $910,448 on our Turnkey drilling as we drilled three wells during the six month period in 2020. We also had an $833,525 gain relating to our equity method investment in RMX recorded during the six months ended June 30, 2020, compared to a loss of $458,269 recorded during the six months ended June 30, 2019. The gain in RMX during the current period was primarily due to their hedging activities. In addition, a loss of $1.2M on sale of assets was recorded during the first quarter of 2019 and there was no comparative loss in the current year period. Our net loss for the second quarter of 2020 was $312,384, while in the second quarter of 2019 the net loss was $467,491, mainly due to a gain on turnkey drilling in 2020. Total revenues for the first six months of 2020 and 2019 were $606,955 and $1,395,404, respectively.

During the first six months of 2020, revenues from oil and gas production decreased $223,395 or 27.6% to $585,999 from the 2019 first six months revenues of $809,394. This decrease was mainly due to lower oil and natural gas commodity prices as demand decreased due to federal and state government stay-at-home orders. The net sales volume of oil and condensate for the six months ended June 30, 2020, was approximately 11,499 barrels with an average price of $34.54 per barrel, versus 6,629 barrels with an average price of $54.44 per barrel for the first half of 2019. This represents an increase in net sales volume of 4,869 barrels. The net sales volume of natural gas for the six months ended June 30, 2020, was approximately 83,040 Mcf with an average price of $2.27 per Mcf, versus 135,887 Mcf with an average price of $3.30 per Mcf for the same period in 2019. This represents a decrease in net sales volume of 52,847 Mcf or 38.9%. The decrease in natural gas production volume was due to certain wells that were offline and waiting on workovers and to lower volumes on existing wells due to natural declines. For the quarter ended June 30, 2020, revenues from oil and gas production decreased $194,711 or 47.9% to $211,514 from the 2019 second quarter revenues of $406,225. This decrease was also due to wells that were offline and waiting on workovers. The net sales volume of oil and condensate for the quarter ended June 30, 2020, was approximately 6,468 barrels with an average price of $24.18 per barrel, versus 3,584 barrels with an average price of $59.89 per barrel for the second quarter of 2019. This represents an increase in net sales volume of 2,884 barrels or 80.5% for the quarter in 2020. The net sales volume of natural gas for the quarter ended June 30, 2020, was approximately 30,587 Mcf with an average price of $1.80 per Mcf, versus 73,420 Mcf with an average price of $2.61 per Mcf for the second quarter of 2019. This represents a decrease in net sales volume of 42,833 Mcf or 58.3% for the quarter in 2020.

Oil and natural gas lease operating expenses increased by $58,600 or 8.1%, to $778,758 for the six months ended June 30, 2020, from $720,158 for the same period in 2019. For the second quarter in 2020, lease operating expenses increased $10,757 or 3.0% from the same quarter in 2019. These were both higher due to the increase in the number of wells operated due mainly to 2019 and 2020 drilling.

The aggregate of supervisory fees and other income was $20,956 for six months ended June 30, 2020, a decrease of $565,054 from $586,010 during the same period in 2019. The decrease was mainly due to the cancellation of the service agreement with RMX Resources as of March 31, 2019. During the second quarter 2020, supervisory fees and other income decreased $4,276 or 26.9% when compared to the quarter in 2019, due mainly to lower interest income received on cash deposits.

Depreciation, depletion and amortization expense increased to $155,625 from $124,857, an increase of $30,768 or 24.6% for the six months ended June 30, 2020, as compared to the same period in 2019. During the second quarter 2019, depreciation, depletion and amortization expenses also increased $2,916 or 4.0%. The depletion rate is calculated using production as a percentage of reserves. This increase in depreciation expense was due to the increase in production and wells and related equipment due to drilling activity in 2019 and the first six months of 2020.

At June 30, 2020, Royale Energy had a Deferred Drilling Obligation of $2,531,094. During the first six months of 2020, we disposed of $3,901,582 of drilling obligations upon completing the drilling of three oil wells, one in California and two wells in Texas, while incurring expenses of $2,991,134, resulting in a gain of $910,448. At June 30, 2019, Royale Energy had a Deferred Drilling Obligation of $8,746,276. During the first six months of 2019, we disposed of $4,420,662 of drilling obligations upon completing two natural gas wells in Northern California and two oil wells in Southern California, while incurring expenses of $4,310,263, resulting in a gain of $110,399.

General and administrative expenses decreased by $227,562 or 17.5% from $1,302,902 for the six months ended June 30, 2019, to $1,075,340 for the same period in 2020. For the second quarter 2020, general and administrative expenses decreased $50,462 or 8.3% when compared to the same period in 2019. These decreases were mainly due to reductions in employee related costs and outside consulting services, in an effort by the Company to reduce costs. Marketing expense for the six months ended June 30, 2020, decreased $105,476, or 65.7%, to $55,064, compared to $160,540 for the same period in 2019. For the second quarter 2020, marketing expenses decreased $72,739 or 77.9% when compared to the second quarter in 2019. Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs. During the period in 2020 fewer marketing events were attended as the governmental mandate against large gatherings was implemented.

Legal and accounting expense decreased to $174,660 for the six month period in 2020, compared to $388,804 for the same period in 2019, a $214,144 or 55.1% decrease. For the second quarter 2020, legal and accounting expenses decreased $22,907 or 20.6%, when compared to the second quarter in 2019. These decreases were primarily due to higher accounting fees related to the Matrix post-merger reporting incurred during the period in 2019.

During the six months ended June 30, 2020, we recorded a gain of $833,525, on investment in joint venture as our 20% share of RMX Resources, LLC’s, compared to a loss of $458,269 in 2019. During the second quarter in 2020 we recorded a gain of $200,001 on the receipt of a pre-Matrix merger prepayment refund. During the first quarter in 2020, we recorded a loss on settlement of $31,500 related to a 2018 seismic sales agreement. During the six months ended June 30, 2019, we recorded a gain of $62,972, on the settlement of accounts payable. During the six-month period in 2019, we recorded geological and geophysical expense of $262,586 related mainly to the acquisition of a seismic survey of a Northern California field, during the same period in 2020, we recorded $14,392 in geological and geophysical expenses.

Bad debt expense for the periods ended June 30, 2020, and 2019 were $186,168 and $5,863, respectively.  During the period in 2020 approximately $106,000 was related to revenue receivable from an industry partner whose collectability was in doubt. Approximately $80,000 of the expenses in 2020 arose from identified uncollectable receivables relating to our oil and natural gas properties either plugged and abandoned or scheduled for plugging and abandonment and our period end oil and natural gas reserve values.  We periodically review our accounts receivable from working interest owners to determine whether collection of any of these charges appears doubtful.  By contract, the Company may not collect some charges from its Direct Working Interest owners for certain wells that ceased production or had been sold during the year, to the extent that these charges exceed production revenue.

Interest expense decreased to $7,444 for the six months ended June 30, 2020, from $12,344 for the same period in 2019, a $4,900 decrease.  This decrease was mainly due to lower principal balances on notes payable during the six month period in 2020.  

Capital Resources and Liquidity

At June 30, 2020, we had current assets totaling $4,085,459 and current liabilities totaling $8,951,792, a $4,866,333 working capital deficit.  We had $309,835 in cash and $1,281,250 in restricted cash at June 30, 2020, compared to $1,031,014 in cash and $2,845,515 in restricted cash at December 31, 2019.

In accordance with ASC 480-10-S99 the Company reclassified the Series B Convertible Preferred Stock from Permanent Equity to Mezzanine capital as a result of the change in voting rights provided at the time it of issuance. For more information, see Note 3 – Series B Convertible Preferred Stock.

At June 30, 2020, our other receivables, which consist of joint interest billing receivables from direct working interest investors and industry partners, totaled $1,215,706, compared to $1,189,892 at December 31, 2019, a $25,814 increase.  This increase was mainly due to an increase in receivable from an industry partner for drilling costs incurred during the period in 2020.  At June 30, 2020, revenue receivable was $304,111, an decrease of $285,040, compared to $589,151 at December 31, 2019, due to lower commodity prices and lower natural gas production volumes on existing wells.  At June 30, 2020, our accounts payable and accrued expenses totaled $5,273,092, a decrease of $757,942 from the accounts payable at December 31, 2019 of $6,031,034, which was related to payments made on account during the period in 2020. 

The Company has had recurring operating and net losses and cash used in operations and the financial statements reflect a working capital deficiency of $4,866,333 and an accumulated deficit of $73,691,794. 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 and 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.

Operating Activities.  Net cash provided by operating activities totaled $355,958 and compared to $281,352 used for the six months ended June 30, 2020, and 2019, respectively.  This difference in cash used was mainly due to a loss on the sale of assets during the first quarter in 2019 and the decrease in prepaid drilling in 2020 as they were applied to actual costs.

Investing Activities.  Net cash used by investing activities totaled $2,788,721 compared to $2,564,895 provided for the six months ended June 30, 2020, and 2019, respectively. During the period in 2020, we received approximately $1.2 million in direct working interest investor turnkey drilling investments while our drilling expenditures were approximately $3.9 million in the drilling and completing of one Southern California oil well and two Texas oil wells. During the 2019 period, we received approximately $7 million in direct working interest investor turnkey drilling investments while our drilling expenditures were approximately $4.2 million in the drilling and completing of two Northern California natural gas wells and two Southern California oil wells.

Financing Activities.  Net cash provided by financing activities totaled $147,319 compared to net cash of $94,780 used for the six months ended June 30, 2020, and 2019, respectively. During the period in 2020, we received $207,800 in SBA-PPP loan as discussed in Note 7. There were principal payments of approximately $56,000 on our notes payable. During the six month period in 2019, a financing agreement for a seismic survey was recognized when the terms were finalized, on which there were principal payments of approximately $53,000.  Additionally, in 2019, there were principal payments of approximately $259,000 on our note with Forza Operating.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

In late 2019 and continuing into 2020, there was a global outbreak of COVID-19 that has resulted in changes in global supply and demand of certain mineral and energy products. While the direct and indirect negative impacts that may affect the Company cannot be determined, they could have a prospective material impact to the Company's operations, cash flows and liquidity, primarily related to the decline in product price, in part, as a result of a decline in demand related to “shelter-in-place” orders by various governmental bodies.

Our major market risk exposure relates to pricing of oil and gas production, which during the period in 2020 resulted in historically low prices due to stay at home orders.  The prices we receive for oil and gas are closely related to worldwide market prices for crude oil and local spot prices paid for natural gas production.  Prices have been volatile for the last several years and have become even more unpredictable in the current period. We expect that volatility to continue.  Our monthly average oil and condensate prices ranged from a high of $60.99 per barrel to a low of $18.79 per barrel and our monthly average natural gas prices ranged from a high of $2.91 per Mcf to a low of $1.69 per Mcf for the first six months of 2020.  

Item 4. Controls and Procedures

As of June 30, 2020, an evaluation was performed under the supervision and with the participation of our management, including our CEO and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures.  These controls and procedures are based on the definition of disclosure controls and procedures in Rule 13a-15(e) and Rule 15d-15(e) promulgated under the Securities Exchange Act of 1934.  A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. 

As a result of the review by the CFO and CEO, the material weakness was identified as listed below.

Because of the material weaknesses described above, our management was unable to conclude that our internal control over financial reporting was effective as of the end of period to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with generally accepted accounting principles.

Except for the actions described above that were taken to address the material weaknesses, there were no changes in our internal controls during the period ended June 30, 2020, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Notwithstanding the material weaknesses described above, our management, including our Chief Executive Officer and Chief Financial Officer, believes that the consolidated financial statements contained in this Report on Form 10-Q fairly present, in all material respects, our financial condition, results of operations and cash flows for the fiscal periods presented in conformity with U.S. generally accepted accounting principles. In addition, the material weaknesses described did not result in the restatements of any of our audited or unaudited consolidated financial statements or disclosures for any previously reported periods.

Internal Control over Financial Reporting and Changes in Internal Control over Financial Reporting

During the six months ended June 30, 2020, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

None

Item 1A. Risk Factors

Not applicable to smaller reporting companies.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

During the period covered by this report, we have not issued any unregistered shares.

Item 4. Mine Safety Disclosures

Not applicable

Item 5.  Other Information

None

Item 6.  Exhibits

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.