Royale Energy, Inc. - Quarter Report: 2018 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)

Royale Energy Holdings, Inc.

(Former name, former address and former fiscal year, if changed since last report)

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post 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  ☒

At August 15, 2018, a total of 48,400,371 shares of registrant’s common stock were outstanding.

TABLE OF CONTENTS

PART I.   FINANCIAL INFORMATION

Item 1.  Financial Statements

ROYALE ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

See notes to unaudited consolidated financial statements.

ROYALE ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

See notes to unaudited consolidated financial statements.

ROYALE ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE PERIODS ENDED JUNE 30, 2018 AND 2017 (UNAUDITED)

See notes to unaudited financial statements.

ROYALE ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

FOR THE SIX MONTHS ENDED JUNE 30, 2018 AND 2017

See notes to unaudited consolidated financial statements.

ROYALE ENERGY, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – In the opinion of management, the accompanying unaudited financial statements include all adjustments, consisting only of normally recurring 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 consolidated financial statements and the notes thereto included in the Company’s latest annual report.

Merger with Matrix Oil Management Corporation

On March 7, 2018, Royale Energy, Inc. (“Royale Energy,” formerly known as  Royale Energy Holdings, Inc., a Delaware corporation), Royale Energy Funds, Inc. (“REF,” formerly known as Royale Energy, Inc., a California corporation), and Matrix Oil Management Corporation (“Matrix”) and its affiliates were notified by the California Secretary of State of the filing and acceptance of agreements of merger by the California Secretary of State, to complete the previously announced merger between the companies (the “Merger”).  In the Merger, REF was merged into a newly formed subsidiary of Royale Energy, and Matrix was merged into a second newly formed subsidiary of Royale Energy pursuant to the Amended and Restated Agreement and Plan of Merger among REF, Royale Energy, Royale Merger Sub, Inc., (“Royale Merger Sub”), Matrix Merger Sub, Inc., (“Matrix Merger Sub”) and Matrix (the “Merger Agreement”).  Additionally, in connection with the merger, all limited partnership interest of two limited partnership affiliates of Matrix (Matrix Permian Investments, LP, and Matrix Las Cienegas Limited Partnership), were exchanged for Royale Energy common stock using conversion ratios according to the relative values of each partnership.  All Class A limited partnership interests of another Matrix affiliate, Matrix Investments, LP (“Matrix Investments”) were exchanged for Royale Energy Common stock using conversion ratios according to the relative value of the Class A limited partnership interests, and $20,124,000 of Matrix Investments preferred limited partnership interests were converted into 2,012,400 shares of Series B Convertible Preferred Stock of Royale Energy.  Another Matrix affiliate, Matrix Oil Corporation (“Matrix Operator”), was acquired by Royale Energy by exchanging Royale Energy common stock for the outstanding common stock of Matrix Oil Corporation using a conversion ratio according to the relative value of the Matrix Oil Corporation common stock.  Matrix, Matrix Oil Corporation and the three limited partnership affiliates of Matrix called the “Matrix Entities.”

The Merger had been previously approved by the respective holders of all outstanding capital stock of REF, Matrix, Royale Energy, Matrix Merger Sub and Royale Merger Sub on November 16, 2017, as previously reported in our Current Report on Form 8-K dated November 16, 2017.  The Merger and related transactions are described in detail in our Current Report on Form 8-K dated March 7, 2018, and in Royale Energy’s Current Report on Form 8-K dated March 7, 2018 (SEC File No. 000-55912).

As a result of the Merger, REF became a wholly owned subsidiary of Royale Energy, and each outstanding share common stock of REF at the time of the Merger was converted into one share of common stock of Royale Energy.  The common stock of Royale Energy is traded on the Over-The-Counter QB (OTCQB) Market System (symbol ROYL).

Under FASB Topic ASC 805, Business Combinations, which among other things requires the assets acquired and liabilities assumed to be measured and recorded at their fair values as of the acquisition date, the Company was determined to be the acquirer and as such, the acquisition was accounted for as a business combination.

The preliminary allocation of the purchase price was determined in arms’ length negotiations between the parties.  Substantially all of the value of the transaction was related to the value of the oil and gas assets acquired with minimal value ascribed to the other assets. The Company considered two valuation methods in its determination of fair value for the oil and natural gas properties; the discounted cash flow analysis and comparable transaction analysis. Assumptions for the discounted cash flow analysis include commodity price, operating costs and capital outlay for future development of the acquired properties, pricing differentials, reserve risking, and discount rates. NYMEX strip pricing, less applicable pricing differentials, was utilized in the discounted cash flow analysis. Risking levels in the discounted cash flow analysis are determined based on a variety of factors, such as existing well performance, offset production and analogue wells. Discount rates used in the discounted cash flow analysis were determined by using the estimated cost of capital, discount rates, as well as industry knowledge and experience. The comparable transaction analysis was performed to establish a range of fair values for similarly situated oil and gas properties that were recently bought or sold in arms-length, observable market transactions. The range of value observed from the Company’s analysis of recent market transactions was then utilized as a basis for evaluating the fair value determined via the discounted cash flow method. The Company’s fair value conclusion indicated that the discounted cash flow method valuation is in line with the same range as the comparable transactions reviewed, when considering the comparable transactions. Other current liabilities assumed in the acquisition, were carried over at historical carrying values because the assets and liabilities are short term in nature and their carrying values are estimated to represent the best estimate of fair value. Any changes to the estimates used in preparing this preliminary purchase price allocation could result in a corresponding change in the final purchase price allocation.

The following table summarizes the consideration transferred, fair value of assets acquired and liabilities assumed:

In accordance with FASB Topic ASC 805, the following unaudited supplemental pro forma condensed results of operations present combined information as though the business combination had been completed as of January 1, 2018. The unaudited supplemental pro forma financial information was derived from the historical revenues and direct operating expenses of Royale Energy, Inc. and Matrix Oil Management Corporation and its affiliates. These unaudited supplemental pro forma results of operations for the consolidated companies as of March 31, 2017, are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the consolidated company for the periods presented or that may be achieved by the consolidated company in the future.

Formation of RMX and Asset Contribution

On April 13, 2018, Royale Energy, Inc., and two of Royale’s subsidiaries, Royale Energy Funds, Inc. and Matrix Oil Management Corporation (the “Royale Entities”) completed  the Subscription and Contribution Agreement (“Contribution Agreement”), in which the Royale Entities and CIC RMX LP (“CIC”) entered into the Contribution Agreement and certain other agreements providing that the Royale Entities would contribute certain assets to RMX Resources, LLC (“RMX”), a newly formed Texas limited liability company. In exchange for its contributed assets, Royale received a 20% equity interest in RMX, an equity performance incentive interest and up to $20.0 million to pay off Royale Entities senior lender, Arena Limited SPV, LLC., in full, and to pay Royale Entities trade payables and other outstanding obligations. CIC contributed an aggregate of $25.0 million in cash to RMX in exchange for (i) an 80% equity interest in RMX with preferred distributions until certain thresholds are met, (ii) a warrant (“Warrant”) to acquire up to 4,000,000 shares of Royale’s common stock at an exercise price of $.01 per share and registration rights pursuant to a Registration Rights Agreement.

The Contribution Agreement was completed in a two-step closing and funding, with the First Closing consummated on April 4, 2018 and the Second Closing consummated on April 13, 2018 with the Royale Entities. In connection with the Second Closing, the parties entered into a letter agreement related to the preliminary Settlement Statement process.  The parties agreed that, in lieu of the payment originally contemplated under Section 1.6(v) of the Contribution Agreement, the Royale Entities would receive the sum of $4,000,000, subject to adjustment. The $4,000,000 delivered at the Second Closing was an advance against amounts due the Royale Entities as Purchase Price, and the advance was subject to further adjustment in accordance with the Contribution Agreement.

RMX has two classes of stock and a six-member board of directors. Royale has two seats on the board giving it a third of the Board.  Royale has designated Michael McCaskey and Johnny Jordan as its members of the RMX board.  The return targets for CIC through its funding of RMX provide for a “waterfall” style return profile with the first distributions going to CIC until certain return thresholds are achieved.

As part of the formation of the joint venture, Royale contributed Matrix Oil Corporation (“MOC”) to RMX. MOC has the permits and licenses to operating oil and gas properties in California. It was the operating entity for the Matrix group of companies that were acquired on February 28, 2018, see NOTE 1 – Merger with Matrix Oil Management Corporation above. This allows the RMX joint venture to be the operator of record for the contributed assets.

Royale will account for its ownership interest in RMX following the equity method of accounting. By agreement, Royale has an initial equity value of $6.25 million or 20% of the total equity of the joint venture with CIC having an initial equity value of $25.0 million or 80% of the total equity of the joint venture.

The Royale Entities contributed 100% of the Sansinena Field, 100% of the Sempra Field, 50% of the Bellevue Field, 100% of the Whittier Main Field, and 50% of the Whittier Field. The result of the transfer of oil and gas properties and surface rights for cash as described above and a 20 percent working interest in RMX resulted in Royale recording a loss of approximately $16.2 million. The contribution by Royale of warrants to acquire 4,000,000 shares of Royale common stock caused Royale to record a loss of approximately $1.44 million. In addition, the Contribution Agreement called for an effective date of the property transfer of February 28, 2018 which required a purchase price adjustment of approximately $334,000 in the form of a cash contribution to RMX and an increase in the loss on the sale. The transfer of MOC to RMX as the operating company provided an amount due Royale of approximately $640,000, which was recorded as a due from affiliate during the period in 2018.

The RMX joint venture has a senior revolving loan facility with Legacy Bank Texas. RMX initially drew down on the line of credit in the amount of $12.5 million to complete the acquisition of the Royale Entities. The borrowing base of the facility is $17.5 million with $5.0 million remaining undrawn at June 30, 2018.

As part of the joint venture, RMX entered into a Master Service Agreement “MSA” calling for Royale Energy to provide land, engineering and support services for the joint venture.  For these services, Royale will receive $180,000 per month for the first year, renewable after one year at a reduced rate of $150,000 per month and subject to termination on 90 days notice.  These amounts are included in Supervisory Fees, Service Agreement and Other.

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

Consolidation

The accompanying consolidated financial statements include the accounts of Royale Energy, Inc. (sometimes called the “Company” “we,” “our,” “us,” or “Royale Energy”), 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.

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 Merger with Matrix and the Contribution Agreement with CIC, which created RMX, 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 $69,213,498, a working capital deficiency of $5,133,752 and a stockholders’ equity of $3,509,519. 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 completion of the second step of the merger with Matrix and additional financing through issuances of common stock and the reduction of overhead costs as more fully outlined below.  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.

Revenue Recognition

On January 1, 2018, we adopted the new ASC Topic 606, Revenue from Contracts with Customers and all the related amendments ("new revenue standard") using the modified retrospective method.

We evaluated the effect of transition by applying the provisions of the new revenue standard to contracts with remaining obligations as of January 1, 2018. No cumulative adjustment to retained earnings was necessary as a result of adopting this standard.

Results for reporting periods beginning after January 1, 2018 are presented under the new revenue standard, while prior period amounts are not adjusted and continue to be reported in accordance with our historic accounting policies.

We concluded that the adoption of the new revenue standard did not result in any changes to our consolidated balance sheet or statement of cash flow.

The majority of our revenues are derived from the sale of crude oil and condensate, natural gas liquids ("NGLs") and natural gas under spot and term agreements with our customers.

The pricing in our hydrocarbon sales agreements are variable, determined using various published benchmarks which are adjusted for negotiated quality and location differentials. As a result, revenue collected under our agreements with customers is highly dependent on the market conditions and may fluctuate considerably as the hydrocarbon market prices rise or fall. Typically, our customers pay us monthly, within a short period of time after we deliver the hydrocarbon products. As such, we do not have any financing element associated with our contracts. We do not have any issues related to returns or refunds, as product specifications are standardized for the industry and are typically measured when transferred to a common carrier or midstream entity, and other contractual mechanisms (e.g., price adjustments) are used when products do not meet those specifications.

In limited cases, we may also collect advance payments from customers as stipulated in our agreements; payments in excess of recognized revenue are recorded as contract liabilities on our consolidated balance sheet.

Under our hydrocarbon sales agreements, the entire consideration amount is variable either due to pricing and/or volumes. We recognize revenue in the amount of variable consideration allocated to distinct units of hydrocarbons transferred to a customer. Such allocation reflects the amount of total consideration we expect to collect for completed deliveries of hydrocarbons and the terms of variable payment relate specifically to our efforts to satisfy the performance obligations under these contracts. Our performance obligations under our hydrocarbon sales agreements are to deliver either the entire production from the dedicated wells or specified contractual volumes of hydrocarbons.

We often serve as the operator for jointly owned oil and gas properties. As part of this role, we perform activities to explore, develop and produce oil and gas properties in accordance with the joint operating arrangement and collective decisions of the joint parties. Other working interest owners reimburse us for costs incurred based on our agreements. We determined that these activities are not performed as part of customer relationships, in accordance with the new revenue standard, and such reimbursements will continue to not be recorded as revenues within the scope of the new revenue standard after the first quarter of 2018.  Prior to this, such cost reimbursements were included in revenue.

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

The Company frequently sells a portion of the working interest in each well it drills or participates in to third party investors and retains a portion of the prospect for its own account.  The Company typically guarantees a cost to drill to the third-party drilling participants and records a loss or gain on the difference between the guaranteed price and the actual cost to drill the well.  When monies are received from third parties for future drilling obligations, the Company records the liability as Turnkey Drilling Obligations.  Once the contracted depth for the drilling of the well is reached and a determination as to the commercial viability of the well (typically call “Casing Point Election” or “Logging Point”), the difference in the actual cost to drill and the guaranteed cost is recorded as income or expense depending on whether there was a gain or loss.

Crude oil and condensate

For the crude sales agreements, we satisfy our performance obligations and recognize revenue once customers take control of the crude at the designated delivery points, which include pipelines, trucks or vessels.

Natural gas and NGLs

When selling natural gas and NGLs, we engage midstream entities to process our production stream by separating natural gas from the NGLs. Frequently, these midstream entities also purchase our natural gas and NGLs under the same agreements. In these situations, we determined the performance obligation is complete and satisfied at the tailgate of the processing plant when the natural gas and NGLs become identifiable and measurable products. We determined the plant tailgate is the point in time where control, as defined in the new revenue standard, is transferred to midstream entities and they are entitled to significant risks and rewards of ownership of the natural gas and NGLs.

The amounts due to midstream entities for gathering and processing services are recognized as shipping and handling cost and included as lease operating expense in our consolidated statement of operations, since we make those payments in exchange for distinct services with the exception of natural gas sold to PG&E where transportation is netted directly against revenue. Under some of our natural gas processing agreements, we have an option to take the processed natural gas and NGLs in-kind and sell to customers other than the processing company. In those circumstances, our performance obligations are complete after delivering the processed hydrocarbons to the customer at the designated delivery points, which may be the tailgate of the processing plant or an alternative delivery point requested by the customer.

Turnkey Drilling Obligations

These Turnkey Agreements are managed by the Company for the participants of the well.  The collections of pre-drilling AFE amounts are segregated by the Company and the gains and losses on the Turnkey Agreements are recorded in income or expense at the time of the casing point election in accordance with ASC 932-323-25 and 932-360.  The Company manages the performance obligation for the well participants and only records revenue or expense at the time the performance obligation of the Turnkey Agreement has been satisfied.

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 the six months ended June 30, 2017, impairment losses of $136,837 were recorded on various capitalized lease and land costs that were no longer viable. During the same period in 2018, no impairment losses were recorded.

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 June 30, 2018 and December 31, 2017, Royale Energy had Deferred Drilling Obligations of $8,654,398 and $5,891,898, respectively.

If Royale Energy is unable to drill the wells, and a suitable replacement well is not found, Royale would retain the non-refundable portion of the contact and return the remaining funds to the participant.  Included in cash and cash equivalents are amounts for use in completion of turnkey drilling programs in progress.

Losses on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value.

Other Receivables

Our other receivables consist of 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, 2018 and December 31, 2017, the Company established an allowance for uncollectable accounts of $1,965,076 and $1,975,660, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue.

Revenue Receivables

Our revenue receivables consist of receivables related to the sale of our natural gas and oil.  Once a production month is completed we receive payment approximately 15 to 30 days later.

Receivable from Affiliate

Our receivable from affiliate consists of receivables related to the transactions between Royale Energy and RMX Resources, LLC and its subsidiary, MOC.

Other Assets

Our other assets consist of long term cash deposits or bank certificates of deposit required by county government agencies or other companies mainly due to Royale’s well operations.

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.

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 June 30, 2018 and December 31, 2017, 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” (“FASB ASC 410”). 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.

Accounts Payable and Accrued Expenses

At June 30, 2018, the components of accounts payable and accrued expenses consisted of $3,596,131 in trade accounts payable due to various vendors, $1,967,318 in payables and accruals related to direct working interest investors revenues and operating costs, $269,099 in accrued expenses related to current drilling efforts, $24,387 due to affiliates, $244,311 for accrued liabilities for amounts set aside mainly for the plugging and abandonment of certain wells, $117,676 for employee related taxes and accruals, $34,059 in deferred rent and $14,723 in federal and state income taxes payable.  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.

Secured Term Debt

Prior to the Merger, Matrix had an outstanding term loan agreement with Arena Limited SPV, LLC (Term Loan) for approximately $12.4 million. The original maturity date of the Term Loan was June 15, 2018, it was secured by the assets of Matrix, and contained financial covenants commencing June 30, 2016 and thereafter, as defined in the term loan agreement. The Term Loan was repaid in full in April 2018 in connection with the Contribution Agreement with CIC.  The Company recognized $164,401 in interest expense for the period ended June 30, 2018.

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 and interest of $47,500 was converted into 750,000 shares of Royale common stock valued at $347,500, and Royale agreed to a cash settlement with the holder of the $1,280,000 note for $1,900,000, which was paid in full on April 13, 2018.

Commodity Derivative Financial Instruments

From time to time, Matrix utilized derivative financial instruments, consisting of puts and swaps, in order to manage exposure to changes in oil commodity prices. These derivative contracts require financial settlements with counterparties based on comparison of various market prices for oil and either floor or swap benchmark prices. The notional amounts of these derivative contracts are economically based on a percentage of estimated production from proved reserves.

The Company accounts for derivative contracts in accordance with FASB ASC Topic 815, Accounting for Derivative Instruments and Hedging Activities, which establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives), and for hedging activities. Currently, the Company has elected not to designate any derivative contracts as accounting hedges under the provisions of FASB ASC Topic 815.

As such, all derivative contracts are carried at fair value on the balance sheet and are marked-to-market at the end of each period with a related adjustment to earnings. Unrealized gains or losses are recorded as gain (loss) on derivatives in unrealized gain (loss) on derivative instruments in the consolidated statements of operations. Realized gain or losses are recorded net in oil and gas sales in the consolidated statements of operations.

Fair Values – Recurring

The Company’s derivative contracts are carried at fair value under ASC Topic 820. The fair value is based upon independently sourced market parameters. The fair value is estimated using forward-looking price curves and discounted cash flows that are observable or that can be corroborated by observable market data and, therefore, are classified within Level 2 of the valuation hierarchy. At June 30, 2018, the Company did not have any derivative contracts.

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.

Recently Issued Accounting Pronouncements

The Company has reviewed the updates issued by the Financial Accounting Standards Board (FASB) during the six months ended June 30, 2018:

ASU 2018-05: Income Taxes (Topic 740) – In March 2018, the Financial Accounting Standards Board (“FASB”) issued ASU 2018-05, Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118, to add various SEC paragraphs pursuant to the issuance of SAB 118 to ASC 740. SAB 118 was issued by the SEC in December 2017 to provide immediate guidance for accounting implications of U.S. tax reform under the TCJA. The Company is currently evaluating the effects of adopting ASU 2016-02 on its consolidated financial statements, but the adoption is not expected to have a significant impact on the Company’s financial statements.

ASU 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 adoption of this guidance has no impact on our results of operations or cash flows.

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 adoption of this guidance has no impact on our results of operations or cash flows.

ASU No. 2016-02: Leases (Topic 842). In February 2016, FASB issued ASU 2016-02 which aims to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and requiring disclosure of key information about leasing agreements. Entities are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. The Company is currently evaluating the effects of adopting ASU 2016-02 on its consolidated financial statements, but the adoption is not expected to have a significant impact on the Company’s financial statements. 

ASU 2016-01: 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 adoption of this guidance has no impact on our results of operations or cash flows. 

NOTE 2 – LOSS PER SHARE

Basic and diluted loss per share are calculated as follows:

For the three and six month period ended June 30, 2018, Royale Energy had dilutive securities of 23,509,917 and 15,266,074, respectively.  These securities were not included in the dilutive loss per share due to their antidilutive nature.

NOTE 3 – OIL AND GAS PROPERTIES, 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 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 the periods in 2018 or 2017. 

NOTE 4 – 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 2018.

The calculation below does not consider the tax basis of the assets acquired through the merger with Matrix Oil Management Corporation as discussed in Note 1 above.  The calculation only considers the book basis of assets acquired.  Therefore, the Company cannot say with certainty that the projected tax losses shown below will be fully realized.  The Company has initiated steps to resolve this issue in the near future as further described in Item 4. – Controls and Procedures.  At this time, the Company cannot say whether it will be filing as a tax group or maintain a separate filing status.  Further, the Company has not fully identified the amount of tax carryforward balances, deferred taxes and tax basis of reported assets resulting from the merger with Matrix Oil Company.

A reconciliation of Royale Energy’s provision for income taxes and the amount computed by applying the statutory income tax rates at June 30, 2018 and 2017, respectively, to pretax income is as follows: 

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.

Merger with Matrix Oil Management Corporation

Effective March 7, 2018, Royale Energy merged with REF and Matrix as described in Note 1 to the Unaudited Financial Statements – Merger with Matrix Oil Management Corporation, and our Current Report on Form 8-K filed with the SEC on March 12, 2018, as amended on May 17, 2018.

Contribution Agreement with RMX Resources, LLC

In April 2018, Royale Energy consummated a Subscription and Contribution Agreement with RMX Resources, LLC, and CIC RMX LP, as described in Note 1 to the Unaudited Financial Statement, and our Current Reports on Form 8-K filed with the SEC on April 4, 2018, and April 13, 2018.

Going Concern

At June 30, 2018, the Company has an accumulated deficit of $69,213,498, a working capital deficiency of $5,133,752 and a stockholders’ equity of $3,509,519. As a result, our financial statements include a “going concern qualification” reflecting substantial doubt as to our ability to continue as a going concern.  We have merged with Matrix to increase efficiency and reduce costs to both companies, thereby allowing a return to positive cash flow.  We have also entered into a joint venture with RMX which provided additional liquidity as further described in Note 1.  We are exploring commitments to provide additional financing, but there is no guarantee that we will be able to secure additional financing on acceptable terms, or at all, if needed to fully fund our 2018 drilling budget and to support future operations.

Results of Operations

The merger between Royale Energy and Matrix Oil Management was completed during the first quarter of 2018.  For the period in 2018, the consolidated amounts represented here are for the six month period for Royale Energy, Inc. and the four month period for Matrix Oil Management and its subsidiaries.

For the six months ended June 30, 2018, we had a net loss of $20,774,316 compared to the net loss of $916,982 during the first six months of 2017.  Our net loss for the second quarter of 2018 was $19,140,603, of which our loss from operations in the second quarter of 2018 was $844,894, versus net income from operations of $110,162 in the second quarter of 2017.  The components of the remaining $18,295,709 net loss for the second quarter of 2018 were:

The loss on sale of assets of $16,217,673 was recorded upon the transfer of oil and gas properties to RMX and surface rights in exchange for cash and a 20 percent working interest in RMX under the Contribution Agreement. Under the Contribution Agreement, we also issued warrants to acquire 4,000,000 shares of Royale common stock and recorded a loss of $1,439,990.  The loss on investment in joint venture of $684,264 represents Royale’s share of RMX’s net loss from operations in the second quarter of 2018.    See Note 1 – Formation of RMX and Asset Contribution. 

Total revenues for the first half of 2018 were $1,517,531, an increase of $997,625 or 191.9% from the total revenues of $519,906 during the same period in 2017. 

During the first six months of 2018, revenues from oil and gas production increased $602,082 or 171.5% to $953,131 from the 2017 first half revenues of $351,049.  This increase was due to higher production volumes associated with the merger.  The net sales volume of oil and condensate for the six months ended June 30, 2018, was approximately 12,345 barrels with an average price of $64.75 per barrel, versus 90 barrels with an average price of $46.03 per barrel for the first half of 2017.  This represents an increase in net sales volume of 12,255 barrels. The net sales volume of natural gas for the six months ended June 30, 2018, was approximately 62,385 Mcf with an average price of $2.41 per Mcf, versus 117,475 Mcf with an average price of $2.95 per Mcf for the same period in 2017.  This represents a decrease in net sales volume of 55,090 Mcf or 46.9%.  The decrease in natural gas production volume was due to several of our operated wells being offline during the period in 2018 due to new pipeline equipment requirements by Pacific Gas & Electric and to the natural declines of our remaining wells. For the quarter ended June 30, 2018, revenues from oil and gas production increased $118,223 or 72.2% to $281,929 from the 2017 second quarter revenues of $163,706.  This increase was also due to higher production volumes associated with the merger.  The net sales volume of oil and condensate for the quarter ended June 30, 2018, was approximately 3,036 barrels with an average price of $70.89 per barrel, versus 45 barrels with an average price of $45.54 per barrel for the second quarter of 2017.  This represents an increase in net sales volume of 2,991 barrels for the quarter in 2018. The net sales volume of natural gas for the quarter ended June 30, 2018, was approximately 29,221 Mcf with an average price of $2.23 per Mcf, versus 58,287 Mcf with an average price of $2.77 per Mcf for the second quarter of 2017.  This represents a decrease in net sales volume of 29,066 Mcf or 49.9% for the quarter in 2018.

Oil and natural gas lease operating expenses increased by $536,365 or 232.7%, to $766,818 for the six months ended June 30, 2018, from $230,453 for the same period in 2017.  For the second quarter in 2018, lease operating expenses increased $375,338 or 303.1% from the same quarter in 2017. These were both higher due to the increase in the number of wells operated by the Company during the period in 2018, related to the merger.  

The aggregate of supervisory fees and other income was $564,400 for six months ended June 30, 2018, an increase of $395,543 or 234.3% from $168,857 during the same period in 2017.  During the second quarter 2018, supervisory fees and other income increased $430,628 or 526.4% when compared to the quarter in 2017.  These increases were mainly due to the receipt of service agreement fees through an arrangement with RMX Resources, LLC.

Depreciation, depletion and amortization expense increased to $275,946 from $90,304, an increase of $185,642 or 205.6% for the six months ended June 30, 2018, as compared to the same period in 2017. During the second quarter 2018, depreciation, depletion and amortization expenses increased $58,766 or 135.2%.  The depletion rate is calculated using production as a percentage of reserves.  This increase in depreciation expense was due to the increase in the number of wells and related equipment operated by the Company as a result of the merger consolidation.

General and administrative expenses increased by $452,602 or 44.6% from $1,015,028 for the six months ended June 30, 2017, to $1,467,630 for the same period in 2018. For the second quarter 2018, general and administrative expenses increased $158,231 or 35.2% when compared to the same period in 2017. These increases were primarily due mainly to merger related increases in employee costs and outside consulting.  Marketing expense for the six months ended June 30, 2018, decreased $38,539, or 23.8%, to $123,693, compared to $162,232 for the same period in 2017.  For the second quarter 2018, marketing expenses decreased $52,874 or 48.9% when compared to the second quarter in 2017. Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs.

Legal and accounting expense increased to $1,077,302 for the six month period in 2018, compared to $668,283 for the same period in 2017, a $409,019 or 61.2% increase.  For the second quarter 2018, legal and accounting expenses increased $175,591 or 92.9%, when compared to the second quarter in 2017.  This increase was primarily due to legal and accounting fees related to the Matrix merger.

During the six months ended June 30, 2018, we recorded a loss on investment in joint venture of $684,264 as our 20% share of RMX Resources, LLC’s period loss of $3,421,321, see discussion in Note 1.  During the six months ended June 30, 2018, we recorded a $105,130 loss on derivative instruments, reflecting the period end market-to market changes in the fair value positions.  During the six months ended June 30, 2018 and 2017, we recorded gains of $46,218 and $73,128, respectively on the settlement of accounts payable.  We periodically review our proved properties for impairment on a field-by-field basis and charge impairments of value to the expense. During the first six months of 2017, we recorded a lease impairment of $136,837 on various lease and land costs that were no longer viable.  There were no lease impairments recorded during the period in 2018.  During the six months ended June 30, 2018 and 2017, we recorded write downs of $9,790 and $6,000, respectively on certain well equipment that was no longer useable.

At June 30, 2018, Royale Energy had a Deferred Drilling Obligation of $8,654,398.  During the first half of 2018, we were unable to drill new wells due to wet weather conditions and other delays in our Northern California fields. At June 30, 2017, Royale Energy had a Deferred Drilling Obligation of $7,450,467.  During the first six months of 2017, we disposed of $1,868,534 of drilling obligations upon completing the drilling of one well, while incurring expenses of $990,001, resulting in a gain of $878,533.  

Interest expense increased to $169,829 for the six months ended June 30, 2018, from $79,412 for the same period in 2017, a $90,417 increase.  This increase resulted from interest accrued on the term loan agreement originated by Matrix.  Further details concerning this agreement can be found in Capital Resources and Liquidity, below.  

Capital Resources and Liquidity

At June 30, 2018, Royale Energy had current assets totaling $11,698,707 and current liabilities totaling $16,832,459 a $5,133,752 working capital deficit.  We had cash at June 30, 2018, of $6,673,603 compared to $3,338,693 at December 31, 2017.

Ordinarily, we fund our operations and cash needs from our available credit and cash flows generated from operations.  We believe that consummation of the Merger will enable the combined companies to meet their liquidity demands.  However, because the Merger results in different liquidity needs than Royale had before the Merger, there is doubt as to the ability to meet liquidity demands through cash flow or ongoing operations.  In that event, the Company will seek alternative capital sources through additional sales of equity or debt securities, or the sale of property.

At June 30, 2018, our other receivables, which consist of joint interest billing receivables from direct working interest investors and industry partners, totaled $2,786,227, compared to $764,015 at December 31, 2017, a $2,022,212 increase.  This increase was mainly due to receivables from Matrix industry partners for drilling and well operations.  At June 30, 2018, revenue receivable was $568,086, an increase of $462,079, compared to $106,007 at December 31, 2017, due to higher oil and gas production volumes on Matrix operated wells.  At June 30, 2018, our accounts payable and accrued expenses totaled $6,267,702, an increase of $1,628,823 from the accounts payable at December 31, 2017 of $4,638,879, mainly related to Matrix drilling and operations related trade accounts payable. 

In July 2016, we received a cash investment of $1,580,000 from two investors to purchase convertible promissory notes with principal amounts of $1,280,000 and $300,000, with a conversion price of $0.40 per share, with warrants to purchase one share of common stock for every three shares of common stock issuable upon conversion of the notes.  The notes 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 and accrued interest of $47,500 was converted into 750,000 shares of Royale common stock valued at $347,500, and Royale agreed to a cash settlement with the holder of the $1,280,000 note for $1,900,000, which was paid on April 13, 2018.

In conjunction with the Purchase and Sale Agreement on June 15, 2016, Matrix Oil Management Corp entered into a term loan agreement with Arena Limited SPV, LLC (Term Loan) for approximately $12.4 million. The uses of the term loan were used for the approximately 50% working interest purchase of the oil and gas properties noted above in the Purchase and Sale Agreement, the payoff of the existing Credit Facility, payment of legal and other loan costs, and other working capital needs of the Company as defined in the loan agreement. The original maturity date of the Term Loan was June 15, 2018, it was secured by the assets of Matrix, and contained financial covenants commencing June 30, 2016 and thereafter, as defined in the term loan agreement. The Term Loan contained preferential payment requirements in advance of the amounts outstanding under the subordinated notes payable to partners, as defined in the term loan agreement.  The Term Loan Agreement called for interest at the rate of nine percent (9%) plus the adjusted LIBOR Rate computed on a daily basis.  The loan balance as of March 31, 2018 was $11,140,749.  The Company recognized $164,401 in interest expense for the period ended March 31, 2018.  In April 2018 pursuant to the Contribution Agreement, this loan agreement was paid in full.

Operating Activities.  Net cash used by operating activities totaled $1,209,949 and $1,149,332 for the six month periods ended June 30, 2018 and 2017, respectively.  This $60,617 or 5.3% increase in cash used was mainly due to increases in due from affiliates during the period in 2018 related to the sale of oil and gas assets in the formation of RMX Resources, previously discussed in Note 1.

Investing Activities.  Net cash provided by investing activities totaled $6,719,779 and $371,558 for the six month periods ended June 30, 2018 and 2017, respectively.  The $6,348,221 increase in cash provided during the period in 2018 was mainly due to approximately $4 million received in the merger and for the oil and gas asset sale and contribution in the formation of RMX Resources, LLC as previously discussed in Note 1.  During the period on 2018, we also received $2,762,500 in direct working interest investor turnkey drilling investments, while during the same period in 2017 we received $1,425,000. 

Financing Activities.  Net cash used by financing activities totaled $2,174,920 in the first six months of 2018, mainly due to the $1.9 million settlement payment for the cash advances on pending transactions. During the period in 2018, we also paid $274,920 for principal and fee payments on the Matrix originated term loan agreement.  No net cash was provided or used in financing activities in the first half of 2017.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

Our major market risk exposure relates to pricing of oil and gas production.  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 we expect that volatility to continue.  Monthly average natural gas prices ranged from a low of $2.33 per Mcf to a high of $2.95 per Mcf for the first six months of 2018. 

Item 4.  Controls and Procedures

As of June 30, 2018, 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. 

Management identified an internal control deficiency that represents a material weakness in or internal control over financial reporting as of December 31, 2017, in that, certain legal documents, such as debt and equity financing transactions, during the fiscal year were not supported by fully executed agreements.

The control deficiency that gave rise to the material weakness did not result in a material misstatement of our financial statements for the fiscal year ended December 31, 2017.

Because of the material weakness 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. Management is seeking written acknowledgement of the note transactions from the note holders in order to remediate the material weakness described above and will require written acknowledgement from counterparties of all similar future transactions.

Management has also identified a significant deficiency that existed as of June 30, 2018, in that we did not have appropriate policies and procedures in place to properly evaluate the accuracy of certain of our financial accounts related to the determination of the tax basis of acquired assets associated with the merger of the Company with Matrix as further described in the financial Note 1 – Merger with Matrix Oil Management Corporation.  There have been no changes in our internal control over financial reporting that occurred during the three month period ended June 30, 2018, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Remedial Action

We have begun our remediation plan with respect to improving and implementing our control over financial reporting and more specifically associated with determining the tax basis of the properties acquired in the merger with Matrix Oil Management Corporation.  We will be engaging an outside consulting firm to assist us in the determination of the tax basis of these properties, determination of whether or not to file as a tax group or maintain separate filing status.  Additionally, we are in the process of implementing a more robust review and increasing the supervision and monitoring of the financial reporting processes related to our material weakness in the calculation and reporting of tax carryforward balances, deferred taxes and tax basis of reported assets.

Except for the actions described above that were taken to address the material weaknesses, there were no changes in our internal controls during the six months ended June 30, 2018, that 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 3. Defaults Upon Senior Securities

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 and accrued interest of $47,500 was converted into 750,000 shares of Royale common stock valued at $347,500, and Royale agreed to a cash settlement with the holder of the $1,280,000 note for $1,900,000, which was paid in full on April 13, 2018.

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.