Royale Energy, Inc. - Annual Report: 2018 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549  

FORM 10-K 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

ROYALE ENERGY, INC.

(Name of registrant in its charter)

1870 Cordell Court

El Cajon, CA 92020

(Address of principal executive offices)

Issuer’s telephone number:     619-383-6600

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

None

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

Common Stock, 0.001 par value per share

(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.   Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.   Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities 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 on its corporate Web site, if any, 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-B is not contained herein, and will not be contained, to the best or registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ☐

Indicate by check mark whether the registrant is large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See definition of “large accelerated filer,” accelerated filer” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:

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 ☒

At June 30, 2018, the end of the registrant’s most recently completed second fiscal quarter; the aggregate market value of common equity held by non-affiliates was $12,074,673.

At April 10, 2019, 50,411,353 shares of registrant’s Common Stock were outstanding.

TABLE OF CONTENTS

ROYALE ENERGY, INC.

PART I

Item 1     Description of Business

Royale Energy, Inc. (“Royale” or the “Company”) is an independent oil and natural gas producer incorporated under the laws of Delaware.  Royale’s principal lines of business are the production and sale of oil and natural gas, acquisition of oil and gas lease interests and proved reserves, drilling of both exploratory and development wells, and sales of fractional working interests in wells to be drilled by Royale.  Royale was incorporated in Delaware in 2017.   On December 31, 2018, Royale and its consolidated subsidiaries had 11 full time employees.

Merger with Matrix Oil Management Corporation

On March 7, 2018, Royale Energy, Inc. (“Royale”), Royale Energy Funds, Inc. (“REF”), 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, and Matrix was merged into a second newly formed subsidiary of Royale pursuant to the Amended and Restated Agreement and Plan of Merger among REF, Royale, 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 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 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.  Another Matrix affiliate, Matrix Oil Corporation (“Matrix Operator”), was acquired by Royale by exchanging Royale 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, 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’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, and each outstanding share common stock of REF at the time of the Merger was converted into one share of common stock of Royale.  The common stock of Royale is traded on the Over-The-Counter QB (OTCQB) Market System (symbol ROYL).

Joint Venture with RMX Resources, LLC

On April 4, 2018, RMX Resources, LLC (“RMX”), CIC RMX LP (“CIC”), and Royale, REF, and Matrix, entered into a Subscription and Contribution Agreement (the “Contribution Agreement”) and certain other agreements contemplated therein (the “Transaction”).  The Contribution Agreement provided that Royale, REF and Matrix 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 $20.0 million to satisfy Matrix’s current senior lender, Arena Limited SPV, LLC, in full, and to pay REF, Matrix and Royale’s 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 $0.01 per share and registration rights pursuant to a Registration Rights Agreement (“Registration Rights Agreement”).

The assets contributed by Royale and its subsidiaries included (i) all of their respective oil and gas properties located in the State of California other than certain excluded assets (the “Excluded Assets”),   (ii), the right to acquire the 50% non-operated working interest in oil and gas leases in the Sansinena and East Los Angeles fields (“Sunny Frog Acquisition Agreement”) operated by Matrix   Oil Corporation (“Matrix Operator”) and (iii) all of the stock of Matrix Operator.  The Excluded Assets include (i) 50% of Matrix’s working interest ownership in a) the City of Whittier, b) Bellevue and (ii) 100% of Matrix’s working interest in the East LA Field, the oil and gas leasehold interest, equipment and properties owned by Royale prior to February 1, 2018, and business equipment and other personal property held by Matrix Operator.

The Contribution Agreement contemplated a two-step closing and funding, with the First Closing consummated on April 4, 2018 and the Second Closing to occur by April 13, 2018.

Immediately upon execution of the Contribution Agreement and consummation of the First Closing, RMX purchased the 50% non-operated working interest in oil and gas leases in the Sansinena and East Los Angeles fields pursuant to the Sunny Frog Acquisition Agreement for approximately $15 million, pursuant to the Sunny Frog Acquisition Agreement, as amended.

As a requirement of the Contribution Agreement, Jonathan Gregory, the Chief Executive Officer of Royale, also became CEO of RMX.  Mr. Gregory entered into an employment agreement (the “Gregory Employment Agreement”) with Royale and separately with RMX.  RMX acquired Matrix Operator and its employees in order to continue the current development efforts on the property being acquired by RMX. Under the terms of a management services agreement (the “Management Services Agreement”), required by the Contribution Agreement, Royale provided RMX with its required accounting, financial reporting and analysis and regulatory support services for a payment of $180,000 per month for the first twelve months, and a fee of $150,000 per month thereafter.

On April 13, 2018, the parties consummated the second part of the Contribution Agreement and Transaction.  In connection with this 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 Parties 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 Parties as Purchase Price, and the advance was subject to further adjustment in accordance with the Contribution Agreement.  In addition, the Royale Parties acknowledged that RMX and CIC retained all rights to pursue any claims for indemnification that may arise from breaches with respect to the matters described therein.

In this Annual Report, “Royale” and the “Company” refer to Royale Energy, Inc., the Delaware corporation. Financial information for 2018 is reported for Royale on a consolidated basis including the following subsidiaries:

      ◦ Royale Energy Funds, Inc

      ◦ Matrix Permian Investment, L.P.

      ◦ Matrix Las Cienegas L.P.

      ◦ Matrix Investment, L.P.

      ◦ Royale DWI Investors, LLC¹

      ◦ Matrix Oil Management, Corp.

      ◦ Matrix Pipeline, L.P. (Limited Partner only, General Partner is Matrix Oil Corp. part of the RMX Joint Venture)

Financial information, including the financial statements as of December 31, 2017, is reported for REF unless reference is specifically made to financial information for one or more of the Matrix Entities prior to the merger. Prior to 2018, REF was registered with the SEC under the Securities Exchange Act of 1934 and filed reports under Royale Energy Funds, Inc., SEC File No. 0-22750.

Royale Energy, Inc.

Royale and its subsidiaries own wells and leases located mainly in the Sacramento Basin and San Joaquin Basin in California as well as in Utah, Texas, Oklahoma, and Louisiana.  Royale usually 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.  Selling part of the working interest to others allows Royale to reduce its drilling risk by owning a diversified inventory of properties with less of its own funds invested in each drilling prospect, than if Royale owned all the working interest and paid all drilling and development costs of each prospect itself.  Royale generally sells working interests in its prospects to accredited investors in exempt securities offerings.  The prospects are bundled into multi-well investments, which permit the third party investors to diversify their investments by investing in several wells at once instead of investing in single well prospects.

¹Royale DWI Investors, LLC, is a California limited liability company formed in 2017 to hold legal title to certain oil and gas working interests which Royale owns for the benefit of its working interest investors.

During its fiscal year ended December 31, 2018, Royale continued to explore and develop natural gas properties with a concentration in California.  Additionally, we own proved developed producing and non-producing reserves of oil and natural gas in Utah, Texas, Oklahoma and Louisiana, as well as holding an overriding royalty interest in a discovery in Alaska.  In 2018, Royale drilled four natural gas wells in northern California, two of which were commercially productive.  Royale’s estimated total reserves were approximately 9.9 and 2.1 BCFE (billion cubic feet equivalent) at December 31, 2018 and 2017, respectively.  According to the reserve reports furnished by Netherland, Sewell & Associates, Inc., Royale’s independent petroleum engineers, the undiscounted net reserve value of its proved developed and undeveloped reserves was approximately $57.8 million at December 31, 2018, based on the average West Texas intermediate spot price of $65.56 per barrel and the natural gas average Henry Hub spot price of $3.10 per MCF.  Netherland, Sewell & Associates, Inc. supplied reserve value estimates for the Company’s California, Texas, Oklahoma, Utah and Louisiana properties.  

Of course, net reserve value does not represent the fair market value of our reserves on that date, and we cannot be sure what return we will eventually receive on our reserves.  Net reserve value of proved developed and undeveloped reserves was calculated by subtracting estimated future development costs, future production costs and other operating expenses from estimated net future cash flows from our developed and undeveloped reserves.

Our standardized measure of discounted future net cash flows at December 31, 2018, was estimated to be $30,645,914.  This figure was calculated by subtracting our estimated future income tax expense from the net reserve value of proved developed and undeveloped reserves, and by further applying a 10% annual discount for estimated timing of cash flows.  A detailed calculation of our standardized measure of discounted future net cash flow is contained in Supplemental Information about Oil and Gas Producing Activities – Changes in Standardized Measure of Discounted Future Net Cash Flow from Proved Reserve Quantities, page F- 32.

Royale reported a gain on turnkey drilling in connection with the drilling of wells on a “turnkey contract” basis in the amount of $2,558,716 and $1,487,824 for the years ended December 31, 2018 and 2017, respectively.

In addition to Royale’s own staff, Royale hires independent contractors to drill, test, complete and equip the wells that it drills.  Approximately 48.7% of Royale’s total revenue for the year ended December 31, 2018, came from sales of oil and natural gas from production of its wells in the amount of $1,599,362.  In 2017, this amount was $554,235, which represented 55.0% of Royale’s total revenues.

Plan of Business

Royale acquires interests in oil and natural gas reserves and sponsors private joint ventures.  Royale believes that its stockholders are better served by diversification of its investments among individual drilling prospects.  Through its sale of joint ventures, Royale can acquire interests and develop oil and natural gas properties with greater diversification of risk and still receive an interest in the revenues and reserves produced from these properties.  By selling some of its working interest in most projects, Royale decreases the amount of its investment in the projects and diversifies its oil and gas property holdings, to reduce the risk of concentrating a large amount of its capital in a few projects that may not be successful.

After acquiring the leases or lease participation, Royale drills or participates in the drilling of development and exploratory oil and natural gas wells on its property.  Royale pays its proportionate share of the actual cost of drilling, testing, and completing the project to the extent that it retains all or any portion of the working interest.

Royale also may sell fractional working interests in undeveloped wells to finance part of the drilling cost. A drilling contract that calls for a company to drill a well, for a fixed price, to a specified depth or geological formation is called a “turnkey contract.” When Royale sells fractional working interests in unproved property to raise capital to drill oil and natural gas wells, generally it agrees to drill these wells on a turnkey contract basis, so that the holders of the fractional interests prepay a fixed amount for the drilling and completion of a specified number of wells.  Under a turnkey contract, Royale may record a gain if total funds received to drill a well were more than the actual cost to drill those wells including costs incurred on behalf of the participants and costs incurred for its own account.

Although Royale’s operating agreements do not usually address whether investors have a right to participate in subsequent wells in the same area of interest as a proposed well, it is the Company’s policy to offer to investors in a successful well the right to participate in subsequent wells at the same percentage level as their working interest investment in the prior successful well.

Our policy for turnkey drilling agreements is to recognize a gain on turnkey drilling programs after our obligations have been fulfilled, and a gain is only recorded when funds received from participants are 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.  See Note 1 to our Financial Statements, at page F-9.

Once drilling has commenced, it is generally completed within 10-30 days.  See Note 1 to Royale’s Financial Statements, at page F-9.  Royale maintains internal records of the expenditure of each investor’s funds for drilling projects.

Royale generally operates the wells it completes.  As operator, it receives fees set by industry standards from the owners of fractional interests in the wells and from expense reimbursements.  For the year ended December 31, 2018, Royale charged overhead from operation of the wells in the amount of $299,646 for the year, which were an offset to general and administrative expenses.  In 2017, the amount was $197,020.  At December 31, 2018, Royale operated 24 natural gas wells in California. Royale also has non-operating interests in seven oil and gas wells in California, three natural gas wells in Utah, four oil and gas wells in Texas, two in Oklahoma and one in Louisiana.

Royale currently sells most of its California natural gas production through PG&E pipelines to independent customers on a monthly contract basis, while some gas is delivered through privately owned pipelines to independent customers. Since many users are willing to make such purchase arrangements, the loss of any one customer would not affect our overall sales operations.

All oil and natural gas properties are depleting assets in which production naturally decreases over time as the finite amount of existing reserves are produced and sold.  It is Royale’s business as an oil and natural gas exploration and production company to continually search for new development properties.  The Company’s success will ultimately depend on its ability to continue locating and developing new oil and natural gas resources.  Natural gas demand and the prices paid for gas are seasonal. In recent years, natural gas demand and prices in Northern California have fluctuated unpredictably throughout the year.

Competition, Markets and Regulation

Competition

The exploration and production of oil and natural gas is an intensely competitive industry.  The sale of interests in oil and gas projects, like those Royale sells, is also very competitive.  Royale encounters competition from other oil and natural gas producers, as well as from other entities that invest in oil and gas for their own account or for others, and many of these companies are substantially larger than Royale.

Markets

Market factors affect the quantities of oil and natural gas production and the price Royale can obtain for the production from its oil and natural gas properties.  Such factors include: the extent of domestic production; the level of imports of foreign oil and natural gas; the general level of market demand on a regional, national and worldwide basis; domestic and foreign economic conditions that determine levels of industrial production; political events in foreign oil-producing regions; and variations in governmental regulations including environmental, energy conservation, and tax laws or the imposition of new regulatory requirements upon the oil and natural gas industry.

Regulation

Federal and state laws and regulations affect, to some degree, the production, transportation, and sale of oil and natural gas from Royale’s operations.  States in which Royale operates have statutory provisions regulating the production and sale of oil and natural gas, including provisions regarding deliverability.  These statutes, along with the regulations interpreting the statutes, generally are intended to prevent waste of oil and natural gas, and to protect correlative rights to produce oil and natural gas by assigning allowable rates of production to each well or proration unit.

The exploration, development, production and processing of oil and natural gas are subject to various federal and state laws and regulations to protect the environment.  Various federal and state agencies are considering, and some have adopted, other laws and regulations regarding environmental controls that could increase the cost of doing business.  These laws and regulations may require: the acquisition of permits by operators before drilling commences; the prohibition of drilling activities on certain lands lying within wilderness areas or where pollution arises; and the imposition of substantial liabilities for pollution resulting from drilling operations, particularly operations in offshore waters or on submerged lands.  The cost of oil and natural gas development and production also may increase because of the cost of compliance with such legislation and regulations, together with any penalties resulting from failing to comply with the legislation and regulations.  Ultimately, Royale may bear some of these costs.

Presently, Royale does not anticipate that compliance with federal, state and local environmental regulations will have a material adverse effect on capital expenditures, earnings, or its competitive position in the oil and natural gas industry; however, changes in the laws, rules or regulations, or the interpretation thereof, could have a materially adverse effect on Royale’s financial condition or results of operation.

REF has filed quarterly, yearly and other reports with the Securities Exchange Commission, and Royale will continue filing these reports as REF’s successor in interest.  You may obtain a copy of any materials filed by Royale with the SEC at 100 F Street, N.W., Washington, D.C. 20549, by calling 1-800-SEC-0300.  The SEC also maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov.  Royale also provides access to its SEC reports and other public announcements on its website, http://www.royl.com.

Item 2     Description of Property

Since 1993, Royale has concentrated on development of properties in the Sacramento Basin and the San Joaquin Basin of Northern and Central California.  In 2018, Royale drilled four developmental natural gas wells in northern California.   

Following industry standards, Royale generally acquires oil and natural gas acreage without warranty of title except as to claims made by, though, or under the transferor.  In these cases, Royale attempts to conduct due diligence as to title before the acquisition, but it cannot assure that there will be no losses resulting from title defects or from defects in the assignment of leasehold rights.  Title to property most often carries encumbrances, such as royalties, overriding royalties, carried and other similar interests, and contractual obligations, all of which are customary within the oil and natural gas industry.

Following is a discussion of Royale’s significant oil and natural gas properties.  Reserves at December 31, 2018, for each property discussed below, have been determined by Netherland, Sewell & Associates, Inc., registered professional petroleum engineers, in accordance with reports submitted to Royale on February 20, 2019.

California

Royale owns lease interests in nine gas fields with locations ranging from Glenn County in the north to Madera County in the south, in the Sacramento Basin in California.  At December 31, 2018, Royale operated 24 wells and owns interests in 10 non-operated wells in Northern California and 28 non-operated wells in Southern and Central California. Our California estimated total proven, developed, and undeveloped net reserves are approximately 9.9 BCFE, according to Royale’s independently prepared reserve report as of December 31, 2018

Developed and Undeveloped Leasehold Acreage

As of December 31, 2018, Royale owned leasehold interests in the following developed and undeveloped properties in both gross and net acreage.

Gross and Net Productive Wells

As of December 31, 2018, Royale owned interests in the following oil and gas wells in both gross and net acreage:

Drilling Activities

The following table sets forth Royale’s drilling activities during the years ended December 31, 2018 and 2017.  All wells are located in the Continental U.S., in California, Texas, Louisiana and Utah.

Production

The following table summarizes, for the periods indicated, Royale’s net share of oil and natural gas production, average sales price per barrel (BBL), per thousand cubic feet (MCF) of natural gas, and the MCF equivalent (MCFE) for the barrels of oil based on a 6 to 1 ratio of the price per barrel of oil to the price per MCF of natural gas.  “Net” production is production that Royale owns either directly or indirectly through partnership or joint venture interests produced to its interest after deducting royalty, limited partner or other similar interests.  Royale generally sells its oil and natural gas at prices then prevailing on the “spot market” and does not have any material long term contracts for the sale of natural gas at a fixed price.

Net Proved Oil and Natural Gas Reserves

As of December 31, 2018, Royale had proved developed reserves of 1,915 MMCF and total proved reserves of 2,986 MMCF of natural gas on all of the properties Royale leases.  For the same period, Royale also had proved developed oil and natural gas liquid combined reserves of 149 MBBL and total proved oil and natural gas liquid combined reserves of 1,146 MBBL.

Oil and gas reserve estimates and the discounted present value estimates associated with the reserve estimates are based on numerous engineering, geological and operational assumptions that generally are derived from limited data.

Item 3     Legal Proceedings

None.

Item 4     Mine Safety Disclosures

Not Applicable 

PART II

Item 3     Defaults Upon Senior Securities

On August 2, 2016, the Company issued two unsecured convertible promissory notes for a total principal amount of $1,580,000 to two investors.  See Capital Resources and Liquidity, page 17.  On August 2, 2017, the notes became due and payable and remained due and payable on December 31, 2017.  On February 28, 2018, one of the notes, for $300,000, was converted to 750,000 shares of common stock immediately prior to the Merger (a conversion price of $0.40 per share).  Also, on February 28, 2018, Royale reached a settlement of a dispute with the second investor regarding his advance of $1.28 million.  In the settlement, Royale has agreed to pay $1.9 million to the investor, who in turn did not receive shares of the Company’s common stock on conversion of this investment.  In the settlement, Royale also cancelled a two year warrant issued to the second investor to purchase 1,066,667 of Royale common stock at $0.80 per share.

Item 5     Market for Common Equity and Related Stockholder Matters

Royale’s Common Stock is traded on the OTC QB Market. Prior to March 7, 2018, REF’s Common Stock was traded under the symbol “ROYL”, and since March 8, 2018, Royale’s Common Stock has traded under the symbol “ROYL”.   As of December 31, 2018, 49,421,387 shares of Royale’s Common Stock were held by approximately 5,018 stockholders.  As of December 31, 2017, 21,850,387 shares of REF’s Common Stock were held by approximately 4,928 stockholders. The following table reflects the high and low quarterly closing sales prices on the Nasdaq Stock Market and OTC QB Market from January 2017 through March 7, 2018, and of Royale from March 8, 2018, through December,

Transfer Agent

The company has engaged the services of American Stock Transfer & Trust company as its transfer agent.

Dividends

The Board of Directors did not issue cash dividends in either 2018 or 2017. The Board of Directors did declare dividends during 2018 on the preferred stock to be Paid In Kind (“PIK”) of 59,461 shares par value $594,613. At year-end, these shares have not been issued.

Recent Sales of Unregistered Securities

On October 29, 2018 the company filed Form S-8 to register up to 3,235,824 shares of common stock for compensation.

Item 7     Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read in conjunction with Royale’s Financial Statements and Notes thereto and other financial information relating to Royale included elsewhere in this document.

Since 1993, Royale has primarily acquired and developed producing and non-producing natural gas properties in California.   In 2004, Royale began developing leases in Utah and in 2012 began acquiring leases in Alaska.  The most significant factors affecting the results of operations are (i) the merger with Matrix in March 2018, (ii) the sale of certain oil and gas assets to RMX Resources, LLC, (iii) changes in oil and natural gas production levels and reserves, and (iv) turnkey drilling activities.

Merger with Matrix Oil Management Corporation

On March 7, 2018, Royale, REF, and Matrix and its affiliates were notified by the California Secretary of State of the filing and acceptance of agreements of merger by the California Secretary of State, to complete the previously announced merger between the companies described in Item 1 – Description of Business – Merger with Matrix Oil Management Corporation.

Joint Venture with RMX Resources, LLC

On April 4 and April 13, 2018, Royale contributed certain assets to RMX Resources, LLC pursuant to a Contribution Agreement described in Item 1 – Description of Business – Joint Venture with RMX Resources, LLC.

Critical Accounting Policies

Revenue Recognition

Royale’s primary business is oil and gas production.  Natural gas flows from the wells into gathering line systems, which are equipped occasionally with compressor systems, which in turn flow into metered transportation and customer pipelines.  Monthly, price data and daily production are used to invoice customers for amounts due to Royale and other working interest owners.  Royale operates most of its own wells and receives industry standard operator fees. These Supervisory fees are recognized as a reduction to the company’s General and Administrative expenses.

Royale generally sells crude oil and natural gas under short-term agreements at prevailing market prices. Revenues are recognized when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured.

Revenues from the production of oil and natural gas properties in which the Royale has an interest with other producers are recognized on the basis of Royale’s net working interest. Differences between actual production and net working interest volumes are not significant.

Royale’s financial statements include its pro rata ownership of wells.  Royale usually 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.   All results, successful or not, are included at its pro rata ownership amounts: revenue, expenses, assets, and liabilities as defined in FASB ASC 932-323-25 and 932-360.

The Company records amounts received from the Master Service Agreement (“MSA”) with RMX for providing land, engineering, accounting and back-office support as part of revenues. Revenues earned under the MSA are recorded at the end of each month that services were performed in conformity with the Agreement with an offsetting receivable from the RMX joint venture. The service fee income is treated as earned at the end of each month that services are performed as provided by contract.

Equity Method Investments

Investments in entities over which the Company has significant influence, but not control, are accounted for using the equity method of accounting. Income from equity method investments represents Royale’s proportionate share of net income generated by the equity method. Equity method investments are included as noncurrent assets on the consolidated balance sheet.

Business Combinations

From time-to-time, the Company acquires businesses in the oil and gas industry. Businesses are included in the consolidated financial statements from the date of acquisition. We recognize, separately from goodwill, the identifiable assets acquired and liabilities assumed at their estimated acquisition-date fair values. We measure and recognize goodwill as of the acquisition date as the excess of: (1) the aggregate of the fair value of consideration transferred, the fair value of any noncontrolling interest in the acquiree (if any) and the acquisition date fair value of our previously held equity interest in the acquiree (if any), over (2) the fair value of assets acquired and liabilities assumed. If information about facts and circumstances existing as of the acquisition date is incomplete by the end of the reporting period in which a business combination occurs, we report provisional amounts for the items for which the accounting is incomplete. The measurement or allocation period ends once we receive the information we are seeking; however, this period will generally not exceed one year from the acquisition date. Any material adjustments recognized during the measurement period will be reflected retrospectively in the consolidated financial statements of the subsequent period. We recognize third-party transaction related costs as expense currently in the period in which they are incurred.

Fair value considerations include the evaluation of the underlying documentation supporting receivables, property, other assets and liabilities. If the documentation and support for a receivable or other asset represented by the seller is not deemed acceptable by the Company’s auditors, the receivable or other asset is not considered in the purchase price until such time as the receivable or other asset can be proven to a level acceptable to the Company’s auditors.

Any receipts by the company of cash or other assets, subsequent to the transaction date for which the merger documentation was considered insufficient at the time of the merger, the company recognizes as a current liability. At such time as the documentation is deemed acceptable, the liability is relieved with a credit to earnings in the period of determination.

When the Company pays more than fair market value for an asset, it records the overage as an intangible asset (“goodwill”). In the event that the Company pays less than fair market value for an asset(s) this results in “negative goodwill” or a so called “bargain purchase”. In the event of a bargain purchase, the Company will reevaluate the fair market value of the asset(s) being acquired until such time as there is no negative goodwill. We evaluate goodwill for impairment annually as of December 31st, or when an indicator of impairment exists. We compare the fair value of our reporting units with the carrying value, including goodwill. We recognize an impairment charge for the amount by which the carrying value exceeds a reporting unit’s fair value, not to exceed the total amount of recorded goodwill, as applicable.

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 uses the “successful efforts” method to account for its exploration and production activities.  Under this method, Royale 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 amortizes the costs of productive wells under the unit-of-production method.

Royale 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 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’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 are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable.

Royale 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 2018 and 2017, impairment losses of $1,183,515 and $289,775, respectively, were recorded on various capitalized lease and land costs where the carrying value exceeded the fair value or where the leases were no longer viable.

Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that Royale 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 eliminates the cost from its books, and the resultant gain or loss is recorded to Royale’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’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’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 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 the full contract price upon execution of the agreement.   Royale 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 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.

Since the participant’s interest in the prospect is limited to the well, and not the lease, the investor does not have a legal right to participate in additional wells drilled within the same lease.  However, it is the Company’s policy to offer to participants in a successful well the right to participate in subsequent wells at the same percentage level as their working interest investment in the prior successful well with similar turnkey drilling agreement terms.

A certain portion of the turnkey drilling participant’s funds received are non-refundable.    The company records a liability for all funds invested as deferred drilling obligations until each individual well is complete.  Occasionally, drilling is delayed for various reasons such as weather, permitting, drilling rig availability and/or contractual obligations.  At December 31, 2018 and 2017, Royale had deferred drilling obligations of $6,213,283 and $5,891,898 respectively.

If Royale 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 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.

Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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.  The most significant estimates pertain to proved oil, plant products and gas reserve volumes and the future development costs.  Actual results could differ from those estimates.

Deferred Income Taxes

Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts attributable to events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax credit carry forwards.  All available evidence, both positive and negative, must be considered to determine whether, based on the weight of that evidence, a valuation allowance for deferred tax assets is needed.  The Company uses information about the Company’s financial position and its results of operations for the current and preceding years.

The Company must use its judgment in considering the relative impact of negative and positive evidence. The weight given to the potential effect of negative and positive evidence is commensurate with the extent to which it can be objectively verified. The more negative evidence that exists, the more positive evidence is necessary and the more difficult it is to support a conclusion that a valuation allowance is not needed for some portion or all of the deferred tax asset. A cumulative loss in recent years is a significant piece of negative evidence that is difficult to overcome.

Future realization of a tax benefit sometimes will be expected for a portion, but not all, of a deferred tax asset, and the dividing line between the two portions may be unclear. In those circumstances, application of judgment based on a careful assessment of all available evidence is required to determine the portion of a deferred tax asset for which it is more likely than not a tax benefit will not be realized.

Going Concern

At December 31, 2018, the Company has an accumulated deficit of $71,050,426, a working capital deficiency of $5,471,153 and a stockholders’ equity of $2,740,958. As a result, our financial statements include a “going concern qualification” reflecting substantial doubt as to our ability to continue as a going concern. See Note 1 to our audited financial statements.  We have merged with Matrix to increase efficiency and reduce costs to both companies, thereby allowing a return to positive cash flow.  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 2019 drilling budget and to support future operations.

Results of Operations for the Twelve Months Ended December 31, 2018, as Compared to the Twelve Months Ended December 31, 2017

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

For the year ended December 31, 2018, we had a net loss of $23,504,327 compared to the net loss of $2,427,169 during the year in 2017. For the year in 2018, we had a loss from operations of $3,204,056, the major components of the remaining $20,300,271 net loss during the year were:

The majority of the loss on sale of assets of $20,092,402 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, along with subsequent purchase price adjustments. This loss was offset by a $550,000 gain on the sale of seismic data and a $334,661 gain on the sale of previously owned Matrix leases. 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 gain on investment in joint venture of $333,931 represents Royale’s share of RMX’s net income from operations through the year ended December 31, 2018.    See Note 2 – Formation of RMX and Asset Contribution. 

During the year in 2018, revenues from oil and gas production increased $1,045,127 or 188.6% to $1,599,362 from the 2017 revenues of $554,235.  This increase was due to higher production volumes associated with the merger.  The net sales volume of oil for the year ended December 31, 2018, was approximately 18,570 barrels with an average price of $64.10 per barrel, versus 102 barrels with an average price of $46.07 per barrel for the same period in 2017.  This represents an increase in net sales volume of 18,468 barrels. The net sales volume of natural gas for the year ended December 31, 2018, was approximately 135,396 Mcf with an average price of $2.85 per Mcf, versus 190,111 Mcf with an average price of $2.89 per Mcf for the same period in 2017.  This represents a decrease in net sales volume of 54,715 Mcf or 28.8%.  The decrease in natural gas production volume was due to several of our operated wells being offline during the year in 2018 due to new pipeline equipment requirements by Pacific Gas & Electric and to the natural declines of our remaining wells.

Oil and natural gas lease operating expenses increased by $1,177,731 or 270.4%, to $1,613,368 for the year ended December 31, 2018, from $435,637 for the year in 2017.  This was higher due to the increase in the number of wells operated by the Company during the period in 2018, related to the merger.  When measuring lease operating costs on a production or lifting cost basis, in 2018, the $1,613,368 equates to a $6.54 per MCFE lifting cost versus a $2.28 per MCFE lifting cost in 2017, a 160.2% increase, due to higher operating costs related to non-operated wells in 2018.

The aggregate of supervisory fees and other income was $1,683,679 for year ended December 31, 2018, an increase of $1,230,535 or 271.6% from $453,144 during the year in 2017. This increase was mainly due to the receipt of service agreement fees through an arrangement with RMX Resources, LLC.

Depreciation, depletion and amortization expense increased to $722,935 from $116,017, an increase of $606,918 or 523.1% for the year ended December 31, 2018, as compared to the year in 2017. 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 $1,130,379 or 56.4% from $2,005,630 for the year ended December 31, 2018, to $3,136,009 for the year in 2018. This increase was primarily due to merger related increases in employee associated costs of $631,896 and outside consulting of $563,452 when compared to 2017.  Legal and accounting expense decreased to $1,391,037 for the year in 2018, compared to $1,540,190 for the year in 2017, a $149,153 or 9.7% decrease.  This decrease was primarily due to lower legal and accounting fees related to the Matrix merger, which concluded during the first quarter. Marketing expense for the year ended December 31, 2018, increased $71,981, or 26.8%, to $340,641, compared to $268,660 for the year in 2017.  Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs.

At December 31, 2018, Royale Energy had a Deferred Drilling Obligation of $6,213,283.  During 2018, we disposed of $6,128,615 of drilling obligations upon completing the drilling of four natural gas wells in Northern California, while incurring expenses of $3,569,899, resulting in a gain of $2,558,716. At December 31, 2017, Royale had a deferred drilling obligation of $5,891,898.  During 2017, we disposed of $5,934,604 of obligations relating to 2016, upon completing the drilling of three developmental natural gas wells and participating in the drilling of an additional developmental oil well, while incurring expenses of $4,446,780.  This resulted in a gain of $1,487,824.   

During 2018, we recorded a gain on investment in joint venture of $333,931 as our 20% share of RMX Resources, LLC’s period net income of $1,669,654, see discussion in Note 2.  During 2018, we also recorded a $105,130 loss on derivative instruments, reflecting the period end market-to market changes in the fair value positions, related to Matrix operations prior to the conclusion of the merger.  During the year ended December 31, 2018 and 2017, we recorded gains of $287,134 and $73,325, respectively, on the settlement of accounts payable.  Impairment losses of $1,183,515 and $289,775 were recorded in 2018 and 2017, respectively.  We periodically review our proved properties for impairment on a field-by-field basis and charge impairments of value to the expense.  In 2017, the impairments were on various capitalized leases that were no longer viable.  During the years in 2018 and 2017, we recorded write downs of $9,790 and $16,375, respectively on certain well equipment that was no longer useable.

Bad debt expense for 2018 and 2017 were $648,518 and $164,145, respectively.  The expenses in 2018 and 2017 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 year-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 increased to $177,171 for the year ended December 31, 2018, from $159,268 in 2017, a $17,903 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.  

In 2018 and 2017, we did not have an income tax expense due to the use of a percentage depletion carryover valuation allowance created from the current and past operations resulting in an effective tax rate less than the new federal rate of 21% plus the relevant state rates (mostly California, 8.8%).  

Capital Resources and Liquidity

At December 31, 2018, Royale had current assets totaling $8,258,012 and current liabilities totaling $14,983,369, a $6,725,357 working capital deficit.  We had cash and cash equivalents at December 31, 2018 of $1,853,742 and restricted cash of $4,501,300 compared to cash and cash equivalents of $278,227 and restricted cash of $3,060,466 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 December 31, 2018, our other receivables, which consist of joint interest billing receivables from direct working interest investors and industry partners, totaled $1,411,144, compared to $764,015 at December 31, 2017, a $647,129 increase.  This increase was mainly due to receivables from an affiliate for contracted services and an industry partner for drilling operations.  At December 31, 2018, revenue receivable was $316,974, an increase of $210,967, compared to $106,007 at December 31, 2017, due to higher oil and gas production volumes on wells that were drilled or came back on production in 2018.  At December 31, 2018, our accounts payable and accrued expenses totaled $4,895,533, an increase of $256,654 from the accounts payable at December 31, 2017 of $4,638,879, mainly related to drilling of one well at year end 2018 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 proceeds 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.

We have not engaged in hedging activities or use derivative instruments to manage market risks.

The following schedule summarizes our known contractual cash obligations at December 31, 2018, and the effect such obligations are expected to have on our liquidity and cash flow in future periods.

Operating Activities.  For the years ended December 31, 2018 and 2017, cash used by operating activities totaled $2,865,829 and $1,199,439, respectively.  This $1,666,390 or 138.9% increase in cash used was due to higher receivables from an affiliate for contracted services, an industry drilling partner accounts and revenue receivables due to higher production volumes. It was also higher in 2018 due to higher merger related royalty and affiliate payables.   

Investing Activities.   Net cash provided by investing activities totaled $8,183,844 for the year ended December 31, 2018.  Net cash used by investing activities totaled $456,466 for the year ended December 31, 2017. The difference in cash during the year in 2018 was due to approximately $4 million in cash received in the merger and for the oil and gas asset sale and contribution in the formation of RMX Resources, LLC, discussed previously. In 2018, we also received $550,000 on the sale of a seismic license and approximately $412,000 for the sale of various lease interests previously owned by Matrix. During the year in 2018, we also received approximately $6.5 million in direct working interest investor turnkey drilling investments, while in 2017 we received approximately $3.9 million. Additionally, our turnkey drilling expenditures were higher in 2017, where we drilled three natural gas wells and participated in the drilling of an oil well, while in 2018 we drilled four natural gas wells and completed two, due to formation difficulties in one well and the other was dry. 

Financing Activities.  Net cash used by financing activities totaled $2,301,666 in 2018, mainly due to the $1.9 million settlement payment for the cash advances on pending transactions. In 2018, we also paid $274,920 for principal and fee payments on the Matrix originated term loan agreement.  In 2018, we paid $126,746 on a note payable to an industry partner for lease operating and plugging and abandonment costs. No net cash was provided or used in financing activities during 2017.

Changes in Reserve Estimates

During 2018, our overall proved developed and undeveloped natural gas reserves increased by 40.1% and our previously estimated proved developed and undeveloped natural gas reserve quantities were revised downward by approximately .40 million cubic feet of natural gas.  This downward revision was mainly the result of one location with previously estimated proved undeveloped natural gas reserves which the Company had decided not to drill.  See Supplemental Information about Oil and Gas Producing Activities (Unaudited), page F-29. 

During 2017, our overall proved developed and undeveloped reserves increased by 4% and our previously estimated proved developed and undeveloped reserve quantities were revised upward by approximately .31 million cubic feet of natural gas.  This upward revision reflected higher than previously estimated proved producing and non-producing natural gas reserves at eight California wells and one Utah well.  See Supplemental Information about Oil and Gas Producing Activities (Unaudited), page F-29. 

Item 7A     Qualitative and Quantitative Disclosures About Market Risk

Royale is exposed to market risk from changes in commodity prices and in interest rates.  In 2018, we sold a majority of our natural gas at the daily market rate through the Pacific Gas & Electric pipeline.  In 2018, our natural gas revenues were approximately $385,800 with an average price of $2.85 per MCF.  At current production levels, a 10% per MCF increase or decrease in our average price received could potentially increase or decrease our natural gas revenues by approximately $38,580.  We currently do not sell any of our natural gas or oil through hedging contracts. 

Item 8     Financial Statements and Supplementary Data

See pages F-1, et seq., included herein.

Item 9     Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None

Item 9A     Controls and Procedures

Disclosure Controls

Disclosure controls are controls and other procedures that are designed to ensure that information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.  Our disclosure controls and procedures are designed to insure that the information required to be filed is accumulated and communicated to our management in a manner designed to enable them to make timely decisions regarding required disclosure.

Our executive officers, Johnny Jordan, Chief Executive Officer, and Stephen M. Hosmer, Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of the end of the 2018 fiscal year. Based on their evaluation, they concluded that our disclosure controls are effective as of December 31, 2018.

Management Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company, (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.  Management assessed our internal control over financial reporting as of December 31, 2018, which was the end of our fiscal year. Management based its assessment on criteria established in the SEC Commission Guidance Regarding Management’s Report on Internal Control Over Financial Reporting Under Section 13(a) or 15(d) of the Securities Exchange Act of 1934. The guidance sets forth an approach by which management can conduct a top-down, risk-based evaluation of internal control over financial reporting. Management’s assessment included an evaluation of risks to reliable financial reporting, whether controls exist to address those risks and evaluated evidence about the operation of the controls included in the evaluation based on its assessment of risk.

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. There were no changes in our internal controls during the fiscal year ended December 31, 2018 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.  We reviewed the results of management’s assessment with the Audit Committee of our Board of Directors.

This annual report does not include an attestation report of the company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this annual report.

Changes in Internal Control over Financial Reporting

No changes in our internal control over financial reporting occurred during the last fiscal quarter of 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Limitations on Effectiveness of Controls

Our management, including our CEO and CFO, does not expect that our disclosure controls or internal controls over financial reporting will prevent all error or fraud.  A control system, no matter how well conceived and operated, can provide only reasonable, but not absolute, assurance that the objectives of a control system are met.  Any control system contains limitations imposed by resources and relevant cost considerations.  Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues have been addressed.  These inherent limitations include the realities that judgments can be faulty and that breakdowns can occur because of simple error or mistake.  In addition, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of a control.  Our control system design is also based on assumptions about the likelihood of future events, and we cannot be sure that we have considered all possible future circumstances and events.

Material Weakness

Certain legal documents, such as debt and equity financing transactions, during the fiscal year were not supported by fully executed agreements. Because of this material weakness, 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.

We did not maintain effective controls over our financial close and reporting process. The financial close and reporting process needs additional formal procedures.

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 has determined that the notes are fully satisfied and will fully document future financial instruments if and when entered into.

Management has also identified a material weakness that existed, 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 nine month period year ended September 30December 31, 2018, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.  Management has engaged a nationally recognized tax preparer, and believes that this engagement will remediate the stated weakness.

Based on their most recent evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2018, our Company’s disclosure controls and procedures were not effective as a result of the material weaknesses in our internal control over financial reporting described.

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

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 have engaged outside consulting firms and tax counsel to assist us in the determination of the tax basis of these properties, application of IRS regulation 382, determination of whether or not to file as a tax group or maintain separate filing status and the ultimate calculation of the proper tax accounting for the contribution of assets to the RMX joint venture. 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 twelve months ended December 31, 2018, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART III

Item 10     Directors and Executive Officers of the Registrant

All of our directors serve one-year terms from the time of their election to the time their successor is elected and qualified.  The following information is furnished with respect to each director and executive officer who served as such during the fiscal year ended December 31, 2018:

(1)     Member of the audit committee.

(2)     Member of the compensation committee.

Member of the nominations committee (company has not assigned Board members to the nominations committee).

The board has determined that directors Mel G. Riggs, Thomas M. Gladney, Barry Lasker and Robert Vogel qualify as independent directors.

The following summarizes the business experience of each director and executive officer for the past six years.

Mel G. Riggs – Chairman of the Board

Mel G. Riggs presently is affiliated with the Clayton Williams family office. Mr. Riggs previously served as President of Clayton Williams Energy, Inc. (NYSE: CWEI) from March 2015 until April 2017 when CWEI was acquired for $2.7 billion by Noble Energy, Inc. (NYSE: NBL). Mr. Riggs is a certified public accountant and received a BBA with a degree in accounting from Texas Tech University in 1977.

Jonathan Gregory – Vice Chair of the Board of Directors

Mr. Gregory became director of Royale in March 2014 and served as Royale's chief executive officer from September 10, 2015, until June 1, 2018. Prior to becoming Royale's CEO, Mr. Gregory, from March 2014 to July 2015, served as Chief Financial Officer and Chief Business Development Strategist for Americo Energy Resources, a private exploration and production company located in Houston, Texas, Prior to serving as CFO of Americo Energy, Mr, Gregory was CFO of J&S Oil & Gas, LLC, from April 2012 to February 2014. From December 2004 to April 2012, Mr. Gregory was head of the energy lending group in Houston, Texas for Texas Capital Bank, N.A. Mr. Gregory is presently CEO of RMX Resources, LLC, a private Texas based oil and gas company with oil and gas properties primarily located in California. Mr. Gregory is also a Credit Committee Advisor to Anvil Capital Partners, a private debt capital provider to upstream energy companies. Mr. Gregory graduated from Lamar

University in 1986 with a Bachelor's degree in Finance.

Johnny Jordan – Chief Executive Officer, President, Chief Operating Officer and Director

Mr. Jordan is a petroleum engineer with expertise in acquisitions, field economics and reserves analysis, bank negotiations, reservoir and field operations, and multi-team interaction. Mr. Jordan served on the Board of Directors of Matrix. Mr. Jordan has been active in the oil and gas industry since 1980 beginning as a floor hand on a well service rig. He has held various staff and supervisory positions for Exxon, Mack Energy, Enron Oil and Gas and Venoco Corporation. He was the team leader of a multi-discipline team from 1992 to 1996 that added 455 BCF and 79 MMCFD through acquisitions (71 BCF) and field development (365 wells) in the Val Verde Basin in West Texas. Mr. Jordan has managed acquisition evaluations in many of the oil and gas producing basins in the US. He has coordinated field development for various recovery mechanisms that include waterflood, tertiary flood, water drive oil and gas reservoirs, and pressure depletion fields with gas cap expansion or gravity drainage. Mr. Jordan received a B.S. in Chemical Engineering from the University of Oklahoma in 1983 and is currently a member of the Society of Petroleum Engineers and the American Petroleum Institute.

Rod Eson – Director

Mr. Eson is the chief executive officer of Foothill Energy, LLC, a position he has held since he founded Foothill Energy in 2004.  Foothill owns and operates oil and gas properties in the central and northern valleys of California.  Mr. Eson has owned and operated oil and gas production companies as well as oilfield service companies since 1979.  From 2006 to 2014, he was chairman of the board of Enhanced Oil Resources, Inc. Prior to forming Foothill Energy in June 2004, Mr. Eson was president and chief executive officer of Venoco, Inc., a California based independent oil and gas company he cofounded in 1992.  At the time of Mr. Eson’s sale of his interest in Venoco, it held assets in excess of $400 million in California, Texas, Mississippi, Colorado and Argentina.

Mr. Eson is the former chairman of the board of the California Independent Petroleum Association and has been a member of the Society of Petroleum Engineers and American Petroleum Institute for more than three decades.  He is also a member of the Texas Independent Producers and Royalty Owners Association and a member of the board of directors of the Independent Petroleum Association of America.  He received a B.S. in Mechanical Engineering from California State Polytechnic University in Pomona, California. 

Thomas M. Gladney - Director

Thomas M. Gladney, since 2006, has served as president of privately held Bodog Resources, LLC, as a wholly owned private entity which invests in oil and gas, water treatment oil field services, and real estate. Mr. Gladney previously served as executive vice president of Plains Exploration and Production Company (PXP) where he helped increase proved reserves from 239 MMEB to more than 400 MMEB while directing various projects to include integration of the merger of two large public companies, work on development and exploration projects in the Gulf of Mexico and on several key engineering projects. Mr. Gladney has a BS in Petroleum Engineering from Mississippi State University.

Barry Lasker - Director

Barry Lasker has served as founder and managing partner of Baja Oil and Gas LLC, which is focused on exploration projects using geology and geophysics in South Texas since 2017. From January 2005 to January 2015, Mr. Lasker served as president and CEO of Enhanced Oil Resources, Inc. (TSX Venture Exchange). Mr. Lasker has 34 years of oil and gas experience with majors and small public and private companies.

Robert Vogel – Director 

Robert Vogel is a Principal at Lucas Capital Management, a registered investment advisor providing a full suite of financial services to individuals and institutional clients. He is a seasoned executive with extensive background in the energy industry. Mr. Vogel previously was Vice President and Treasurer of Hess Corporation. He serves as the Chairman of BlinkNow Foundation, an organization that supports women and children in Nepal. Mr. Vogel holds a BS in Chemical Engineering from the University of Colorado and an MBA from New York University.

Harry E. Hosmer – Chairman Emeritus 

Harry E. Hosmer has served as chairman of Royale since he founded the company in 1986. From inception until June 1995, he also served as president and chief executive officer. Mr. Hosmer will serve as chairman of Holdings until the first annual shareholders meeting, at which time he will retire as chairman and assume the title of chairman emeritus.

Audit Committee

The board has appointed an audit committee to assist the board of directors in carrying out its responsibility as to the independence and competence of the Company’s independent public accountants. All members of the audit committee are independent members of the board of directors.  The audit committee operates pursuant to an audit committee charger, which has been adopted by the board of directors to define the committee’s responsibilities.  A copy of the audit committee charter is posted on our website, www.royl.com The board has determined that Robert Vogel qualifies as an “audit committee financial expert” as defined in Item 407(d)(5) of the Securities and Exchange Commission.

At the end of 2018, the members of the audit committee were Robert Vogel (Chair), Barry Lasker, Jonathan Gregory and Thomas M. Gladney.

Code of Business Conduct and Ethics

We have adopted a code of business conduct and ethics for our directors and executive officers.  The code is posted on our website, www.royl.com.

Compliance with Section 16(a) of the Exchange Act

Section 16(a) of the Securities Exchange Act of 1934 and Securities and Exchange Commission regulations require that Royale’s directors, certain officers, and greater than 10 percent shareholders file reports of ownership and changes in ownership with the SEC and the NASD and furnish Royale with copies of all such reports they file.  Based solely upon a review of the copies of the forms furnished to Royale, or representations from certain reporting persons that no reports were required, Royale believes that no persons failed to file required reports on a timely basis for 2017.

Item 11     Executive Compensation

The following table summarizes the compensation of the chief executive officer, chief financial officer and the one other most highly non-executive employees (the “named executives and employees”) of Royale and its subsidiaries during the past three years.

(1)     Certain options granted in October 2014 expired on December 31, 2017 unexercised.  At December 29, 2017, Royale’s stock price, $0.36, was less than the weighted average exercise price, and as such the outstanding and exercisable stock options had no intrinsic value. On October 10, 2018, the company entered into an agreement to issue Mr. Hosmer 250,000 options to purchase common stock previously approved by the Board of Directors with an exercise price of $0.31. These options were granted for a period of ten years with a maturity date of October 9, 2028.

(2)     All other compensation consists of matching contributions to the Company’s simple IRA plan, except for Donald H. Hosmer and Stephen M. Hosmer, who also received a $12,000 car allowance. This category also includes Board fees for Mr. Gregory and Mr. Eson.

(3)     During 2016, Jonathan Gregory, Donald and Stephen Hosmer received a portion of their compensation in shares of common stock, valued at the closing market price on the date of grant, instead of cash.  In 2016, of the $242,469 paid to Jonathan Gregory, $141,814 was paid in cash and 386,178 shares of common stock were issued, valued at $100,655.  Of the $282,533 paid to Donald Hosmer, $190,595 was paid in cash and 609,702 shares of common stock were issued, valued at $91,938.  Of the $207,693 paid to Stephen Hosmer, $165,742 was paid in cash and 101,630 shares of common stock were issued, valued at $41,951. During 2017 the $230,192 paid to Stephen Hosmer, $173,945 was paid in cash and 200,564 shares of common stock were issued, valued at $56,247.

(4)     Salary represents either direct payroll or common stock paid in lieu of taking a cash salary.

(5)     Mr. Gregory served as CEO of the Company during 2016, 2017 and part of 2018. Mr. Gregory resigned from the CEO position with the execution of the RMX joint venture.

(6)     Mr. Jordan became CEO of the Company in January 2019. Mr. Jordan joined the Company upon the merger with the Matrix entities on March 7, 2018

(7)     Mr. Eson served as CEO of the Company during 2018. Mr. Eson received $144,609 in compensation as CEO of which $69,179 was paid in cash and $75,429 was paid in common stock. Mr. Eson serves on the Board of Directors and received $6,250 as Board compensation.

Stock Options and Equity Compensation; Outstanding Equity Awards at Fiscal Year End

The following table presents the number of unexercised options at the 2018 year end for each named executive officer.  No unvested stock awards were outstanding at the end of 2018.

Compensation Committee Report

Our executive compensation committee has reviewed and discussed the following Compensation Discussion and Analysis with management and, based on its discussion and review, has recommended that the Compensation Discussion and Analysis be included in this proxy statement.

Members of the Compensation Committee:

Thomas M. Gladney, Barry Lasker (Chair), and Robert Vogel

All members of the compensation committee are independent members of the Board of Directors.

Compensation Discussion and Analysis

Our executive compensation policy is designed to motivate, reward and retain the key executive talent necessary to achieve our business objectives and contribute to our long-term success. Our compensation policy for our executive officers focuses primarily on determining appropriate salary levels and performance-based cash bonuses.

The elements of executive compensation at Royale consist mainly of cash salary and, if appropriate, a cash bonus at year end.  The compensation committee makes recommendations to the board of directors annually on the compensation of the three top executives:  Johnny Jordan, Chief Executive Officer, Donald H. Hosmer, Business Development and Stephen M. Hosmer, Chief Financial Officer.  

Royale also does not provide extensive personal benefits to its executives beyond those benefits, such as health insurance, that are provided to all employees.  Donald Hosmer and Stephen Hosmer each receive an annual car allowance.

Policy

The compensation committee’s primary responsibility is making recommendations to the board of directors relating to compensation of our officers.  The committee also makes recommendations to the board of directors regarding employee benefits, our defined benefit plans, defined contribution plans, and stock based plans.

Determination

To determine executive compensation, the committee, in December each year, meets with our officers to review our compensation programs, discuss the performance of the company, the duties and responsibilities of each of the officers pay levels and business results compared to others similarly situated within the industry.  The committee then makes recommendations to the board of directors for any adjustment to the officers’ compensation levels.  The committee does not employ compensation consultants to make recommendations on executive compensation.

Compensation Elements

Base.  Base salaries for our executive officers are established based on the scope of their responsibilities, taking into account competitive market compensation paid by our peers. Base salaries are reviewed annually. The salaries we paid to our most highly paid executive officers for the last three years are set forth in the Summary Compensation Table included under Executive Compensation.

Bonus.  The compensation committee meets annually to determine the quantity, if any, of the cash bonuses of executive officers.  The amount granted is based, subjectively, upon the company’s stock price performance, earnings, revenue, reserves and production.  The committee does not use quantifiable metrics for these criteria; but rather uses each in balance to assess the strength of the company’s performance.  The committee believes that formulaic approaches to cash incentives can foster an unhealthy balance between short-term and long-term goals.  No cash bonuses were paid to executive officers in 2018 or 2017.

Compensation of Directors

In 2018, board members or committee member accrued or received fees for attendance at board meetings or committee meetings during the year.  In addition to cash payments, common stock was issued in lieu of compensation or reimbursements.  Royale also reimbursed directors for the expenses incurred for their services.

The following table describes the compensation paid to our directors who are not also named executives for their services in 2018.

Item 12     Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Common Stock

On April 10, 2019, 50,411,353 shares of Royale’s common stock were outstanding.

The following table contains information regarding the ownership of Royale’s common stock as March 14, 2019, by each director and executive officer of Royale, and all directors and officers of Royale as a group.  

Except pursuant to applicable community property laws and except as otherwise indicated, each shareholder identified in the table possesses sole voting and investment power with respect to its or his shares.  The holdings reported are based on reports filed with the Securities and Exchange Commission and the Company by the officers and directors.

*  Less than 1%.

(1)  The mailing address of each listed stockholder is 1870 Cordell Court, Suite 210, El Cajon, California 92020.

(2)  Includes 12,000 shares owned by Stephen M. Hosmer’s minor children.

(3)  Includes 9,795,290 shares issuable upon conversion of Series B Convertible Preferred Stock.

(4)  Includes 35,000 shares owned by Mr. Gregory’s son.

The following table contains information regarding the ownership of Royale’s common stock as March 14, 2019, by each person who is known by Royale to own beneficially more than 5% of the outstanding shares of each class of equity securities. Except pursuant to applicable community property laws and except as otherwise indicated, each shareholder identified in the table possesses sole voting and investment power with respect to its or his shares.  The holdings reported are based on reports filed with the Securities and Exchange Commission and the Company by the 5% shareholders.

(1)  The mailing address of each listed stockholder is 1870 Cordell Court, Suite 210, El Cajon, California 92020.

(2)  Includes 9,795,290 shares issuable upon conversion of Series B Convertible Preferred Stock.

(3)  Includes 8,995,560 shares issuable upon conversion of Series B Convertible Preferred Stock.

(4)  Includes 395,970 shares issuable upon conversion of Series B Convertible Preferred Stock.

Item 13     Certain Relationships and Related Transactions

In 1989, the board of directors adopted a policy (the “1989 policy”) that permits each director and officer of Royale to purchase from Royale, at its cost, up to one percent (1%) fractional interest in any well to be drilled by Royale.  When an officer or director elects to make such a purchase, the amount charged per each percentage working interest is equal to Royale’s actual pro rata cost of drilling and completion, rather than the higher amount that Royale charges to working interest holders for the purchase of a percentage working interest in a well.  Of the current officers and directors, Donald Hosmer, Stephen Hosmer and Harry E. Hosmer at various times have elected under the 1989 policy to purchase interests in certain wells Royale has drilled.

Under the 1989 policy, officers and directors may elect to participate in wells at any time up until drilling of the prospect begins.  Participants are required to pay all direct costs and expenses through completion of a well, whether or not the well drilling and completion expenses exceed Royale’s cost estimates, instead of paying a set, turnkey price (as do outside investors who purchase undivided working interests from Royale).  Thus, they participate on terms similar to other oil and gas industry participants or joint venturers.  Participants are invoiced in advance for their share of estimated direct costs of drilling and completion and later actual costs are reconciled, as Royale incurs expenses and participants make further payments as necessary.

Officer and director participants under this program do not pay some expenses paid by outside, retail investors in working interests, such as sales commissions, if any, or marketing expenses.  The outside, turnkey drilling agreement investors, on the other hand, are not obligated to pay additional costs if a drilling project experiences cost overruns or unanticipated expenses in the drilling and completion stage.  Accordingly, Royale’s management believes that its officers and directors who participate in wells under the board of directors’ policy do so on terms the same as could be obtained by unaffiliated oil and gas industry participants in arms-length transactions, albeit those terms are different than the turnkey agreement under which outside investors purchase fractional undivided working interests from Royale.

Donald and Stephen Hosmer each have participated individually in 179 wells each under the 1989 policy.  The Hosmer Trust, a trust for the benefit of family members of Harry E. Hosmer, has participated in 178 wells.

Investments in wells under the 1989 policy for the three years ended December 31, 2018, 2017, and 2016 are as follows:

Michael McCaskey and Jeffery Kerns, each former directors of Royale, have consulting agreements to provide services as directed and at the discretion of the company.

Item 14     Principal Accountant Fees and Services

SingerLewak LLP served as the independent auditors to audit the Company’s financial statements for the fiscal year ended December 31, 2018 and 2017.  This is the fifth annual audit performed by SingerLewak LLP.  The aggregate fees billed by SingerLewak LLP for the years ended December 31, 2018 and 2017 are as follows, respectively:

(1)  Audit fees are fees for professional services rendered for the audit of Royale Energy’s annual financial statements, reviews of financial statements included in the company’s Forms 10-Q, and reviews of documents filed with the U.S. Securities and Exchange Commission.

(2)  Tax fees consist of tax planning, consulting and tax return reviews.

(3)  Other fees consist of work on registration statements under the Securities Act of 1933.

The audit committee of Royale Energy has adopted policies for the pre-approval of all audit and non-audit services provided by the company’s independent auditor.  The policy requires pre-approval by the audit committee of specifically defined audit and non-audit services.  Unless the specific service has been previously pre-approved with respect to that year, the audit committee must approve the permitted service before the independent auditor is engaged to perform it.

No representatives of SingerLewak LLP are expected to be present at the annual meeting.  Although the audit committee has the sole responsibility to appoint the auditors as required under the Securities Exchange Act of 1934, the committee welcomes any comments from shareholders on auditor selection or performance.  Comments may be sent to the audit committee chair, Robert Vogel, care of Royale Energy’s executive office, 1870 Cordell Court, Suite 210, El Cajon, California 92020.

PART IV

Item 15     Exhibits and Financial Statement Schedules

The agreements included as exhibits to this report are included to provide information about their terms and not to provide any other factual or disclosure information about Royale or the other parties to the agreements.  The agreements contain representations and warranties by each of the parties to the applicable agreement that were made solely for the benefit of the other agreement parties and:

●     should not be treated as categorical statements of fact, but rather as a way of allocating the risk among the parties if those statements prove to be inaccurate;

●     have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;

●     may apply standards of materiality in a way that is different from the way investors may view materiality; and

●     were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.

1.       Financial Statements.  See Index to Financial Statements, page F-1

2.       Schedules.  None.

3.       Exhibits.  Certain of the exhibits listed in the following index are incorporated by reference.

* Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability. 

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.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

ROYALE ENERGY, INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Stockholders and Board of Directors of Royale Energy, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Royale Energy, Inc. (the “Company”) as of December 31, 2018 and 2017, the related consolidated statements of operations, stockholders' deficit, and cash flows for the years then ended, and the related notes to the consolidated financial statements (collectively, the “financial statements”). In our opinion, based on our audit and the report of the other auditor, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

We did not audit the financial statements of RMX Resources, LLC, an equity method investment, which statements reflect total assets and revenue constituting 30 percent and 10 percent, respectively, in 2018, of the related consolidated totals. Those statements were audited by other auditors, whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for RMX Resources, LLC, is based solely on the report of the other auditors.

Going Concern

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company has suffered recurring losses from operations, and its total liabilities exceed its total assets. This raises substantial doubt about the Company's ability to continue as a going concern. Management's plans in regard to these matters also are described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements, based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB), and are required to be independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements.

Our audits also included evaluating the accounting principles used, and significant estimates made, by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

SingerLewak LLP

We have served as the Company's auditor since 2014.

Denver, Colorado

April 15, 2019

ROYALE ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

DECEMBER 31,

The accompanying notes are an integral part of these financial statements.

ROYALE ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

DECEMBER 31, 

The accompanying notes are an integral part of these financial statements.

ROYALE ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2018, AND 2017

 The accompanying notes are an integral part of these financial statements.

ROYALE ENERGY, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)

FOR THE YEARS ENDED DECEMBER 31, 2018 AND 2017

The accompanying notes are an integral part of these financial statements.

ROYALE ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2018 AND 2017

The accompanying notes are an integral part of these financial statements.

ROYALE ENERGY, INC.

CONSOLIDATED NOTES TO FINANCIAL STATEMENTS

NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

This summary of significant accounting policies of Royale Energy, Inc. (in these notes sometimes called “Royale Energy,” “Royale,” or the “Company”) is presented to assist in understanding Royale Energy’s financial statements.  (See Note 2 below, Merger with Matrix Oil Management, Corporation and Formation of RMX.) These consolidated financial statements include the accounts of our controlled subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis. The financial statements and notes are representations of Royale Energy’s management, which is responsible for their integrity and objectivity.  These accounting policies conform to accounting principles generally accepted in the United States of America and have been consistently applied in the preparation of the financial statements.

Description of Business

Royale Energy is an independent oil and gas producer which also has operations in the area of turnkey drilling.  Royale Energy owns wells and leases in major geological basins located primarily in California, Texas, Oklahoma and Utah. Royale Energy offers fractional working interests and seeks to minimize the risks of oil and gas drilling by selling multiple well drilling projects which do not include the use of debt financing.

Use of Estimates

The accompanying financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America and requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.   

Estimated quantities of crude oil and condensate, NGLs and natural gas reserves is a significant estimate that requires judgment. All of the reserve data included in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and condensate, NGLs and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and condensate, NGLs and natural gas reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil and condensate, NGLs and natural gas that are ultimately recovered. See Note 18 – Supplementary Information About Oil and Gas Producing Activities for further detail.

Other items subject to estimates and assumptions include the carrying amounts of property, plant and equipment, asset retirement obligations, valuation of derivative instruments and valuation allowances for deferred tax assets, among others. Although we believe these estimates, actual results could differ from these estimates. 

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 consolidated financial statements reflect a working capital deficiency of $5,471,153 and a net loss from operations of $(3,204,056). 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 by cost control measures that include the reduction of overhead costs by 25% 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. 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.

Restricted Cash

Royale sponsors turnkey drilling arrangements in 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 drilling as restricted cash as called for under ASU 2016-15 and later codified as ASC 230-10-50-8.

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the statement of financial position 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 consolidated statements of income. Equity method investments are included as noncurrent assets on the consolidated balance sheet.

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

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.

A significant portion 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.

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 are recorded at the end of each month that services were performed in conformity with the Agreement with an offsetting receivable from the RMX joint venture. The service fee income is deemed earned at the end of each month that services are performed as prescribed by the contract. Payment is due on the thirteenth day following the end of the month following the performance of the services. Although payment is not necessarily received in accordance with the contract terms, it is eventually received. During 2018, we recognized $1,620,000 or 49.3% of our total revenues from these services. Royale has a single supervisory fee customer, that being RMX, which represents 100% of the Supervisory Fee income. On December 31, 2018, Royale received notice of cancelation of the MSA by RMX effective March 31, 2019. Also included are Pipeline and Compressor fees which are received and allocated based on production volumes.

Oil and Gas Property and Equipment

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.

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.

We evaluate our oil and gas producing properties, including capitalized costs of exploratory wells and development costs, for impairment of value whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. Oil and gas producing properties are reviewed for impairment on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure or contractual terms that cause economic interdependency amongst separate, discrete fields. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows or, if available, comparable market value. We evaluate our unproved property investment and record impairment based on time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved property investments are deemed to be impaired, this amount is reported in exploration expenses in our consolidated statements of income. During 2018 and 2017, impairment losses of $1,183,515 and $289,775, respectively, were recorded on various capitalized base and land costs as well as certain fields acquired through the merger with the matrix entities.

Upon the sale or retirement of a complete field of a proved property, Royale Energy eliminates the cost from its books, and the resultant gain or loss is recorded to Royale Energy’s Statement of Operations.  Upon the sale of an entire interest in an unproved property where the property has been assessed for impairment individually, a gain or loss is recognized in Royale Energy’s Statement of Operations.  If a partial interest in an unproved property is sold, any funds received are accounted for as a recovery of the cost in the interest retained with any excess funds recognized as a gain. Should Royale Energy’s turnkey drilling agreements include unproved property, total drilling costs incurred to satisfy its obligations are recovered by the total funds received under the agreements.  Any excess funds are recorded as a Gain on Turnkey Drilling Programs, and any costs not recovered are capitalized and accounted for under the “successful efforts” method. 

Royale Energy sponsors turnkey drilling agreement arrangements in unproved properties as a pooling of assets in a joint undertaking, whereby proceeds from participants are reported as Deferred Drilling Obligations, and then reduced as costs to complete its obligations are incurred with any excess booked against its property account to reduce any basis in its own interest.  Gains on Turnkey Drilling Programs represent funds received from turnkey drilling participants in excess of all costs Royale incurs during the drilling programs (e.g., lease acquisition, exploration and development costs), including costs incurred on behalf of participants and costs incurred for its own account; and are recognized only upon making this determination after Royale’s obligations have been fulfilled.

The contracts require the participants pay Royale Energy the full contract price upon execution of the agreement.   Royale Energy completes the drilling activities typically between 10 and 30 days after drilling begins.  The participant retains an undivided or proportional beneficial interest in the property, and is also responsible for its proportionate share of operating costs.  Royale Energy retains legal title to the lease.  The participants purchase a working interest directly in the well bore.

In these working interest arrangements, the participants are responsible for sharing in the risk of development, but also sharing in a proportional interest in rights to revenues and proportional liability for the cost of operations after drilling is completed and the interest is conveyed to the participant.

A certain portion of the turnkey drilling participant’s funds received are non-refundable.  The company holds all funds invested as Deferred Drilling Obligations until drilling is complete.  Occasionally, drilling is delayed for various reasons such as weather, permitting, drilling rig availability and/or contractual obligations.  At December 31, 2018 and 2017, Royale Energy had Deferred Drilling Obligations of $6,213,283 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 receivables from direct working interest investors and industry partners. We provide for uncollectible accounts receivable using the allowance method of accounting for bad debts.  Under this method of accounting, a provision for uncollectible accounts is charged directly to bad debt expense when it becomes probable the receivable will not be collected.  The allowance account is increased or decreased based on past collection history and management’s evaluation of accounts receivable.  All amounts considered uncollectible are charged against the allowance account and recoveries of previously charged off accounts are added to the allowance.  At December 31, 2018 and 2017, the Company established an allowance for uncollectable accounts of $2,296,384 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. Historically, Royale has not had issues related to the collection of revenue receivables, and as such has determined that an allowance for revenue receivables is not currently necessary.

Equipment and Fixtures

Equipment and fixtures are stated at cost and depreciated over the estimated useful lives of the assets, which range from three to seven years, using the straight-line method. Repairs and maintenance are charged to expense as incurred. When assets are sold or retired, the cost and related accumulated depreciation are removed from the accounts and any resulting gain or loss is included in income. Maintenance and repairs, which neither materially add to the value of the property nor appreciably prolong its life, are charged to expense as incurred. Gains or losses on dispositions of property and equipment, other than oil and gas, are reflected in operations.

Income (Loss) Per Share

Basic and diluted losses per share are calculated as follows:

For the year ended December 31, 2018, Royale Energy had dilutive securities of 24,049,443.  These securities were not included in the dilutive loss per share due to their antidilutive nature.

Stock Based Compensation

Royale has a stock-based employee compensation plan, which is more fully described in Note 12. The Company has adopted ASC 718 as updated by ASU 2016-09 and ASU 2017-09 for share-based payments. The Company has not implemented the amendments described in ASU 2018-07 as they become effective for public companies in 2019. This topic requires that the cost resulting from all share-based payment transactions be recognized in the financial statements. It further establishes fair value as the measurement objective in accounting for share-based payment arrangements and requires all entities to apply a fair-value based measurement method in accounting for share-based payment transactions with employees except for equity instruments held by employee stock ownership plans. Shares issued in connection with a business combination as part of the consideration transferred in exchange for the acquiree are treated within the scope of Topic 805.

Income Taxes

Royale utilizes the asset and liability approach to measure deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates in accordance with the Income Taxes Topic of the Accounting Standards Codification ASC740. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. Under the Topic, deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

The provision for income taxes is based on pretax financial accounting income. Deferred tax assets and liabilities are recognized for the expected tax consequences of temporary differences between the tax basis of assets and liabilities and their reported net amounts.

Fair Value Measurements

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

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

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

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

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

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

At December 31, 2018 and 2017, Royale Energy does not have any financial assets measured and recognized at fair value on a recurring basis.  The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic 410, “Asset Retirement and Environmental Obligations” (“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. See Note 3 for further discussion of the Company’s asset retirement obligations.

Accounts Payable and Accrued Expenses

At December 31, 2018 and 2017, the components of accounts payable and accrued expenses consisted of:

Accrued Liabilities – Long Term

Prior to the Merger, Matrix had outstanding long term liabilities for interest on notes payable due to certain Matrix principals.  The balance due at December 31, 2018, was $1,306,605.

Accrued Unpaid Guaranteed Payments

Prior to the Merger, Matrix had outstanding accrued unpaid guaranteed payments for unpaid salaries due to certain Matrix employees.  At December 31, 2018, the $1,616,205 balance remains the same as the time of merger.

Cash Advances on Pending Transactions

In July 2016, we received a cash investment of $1,580,000 from two investors to purchase convertible promissory notes of $1,280,000 and $300,000, with a conversion price of $0.40 per share, with warrants to purchase one share of common stock for every three shares of common stock issuable upon conversion of the notes.  The funds from these transactions were used to continue drilling activities, fund expenses incurred in connection with the completion of Royale Energy’s merger with Matrix Oil Corporation and for general corporate purposes.  The notes originally matured on August 2, 2017, one year from the date of issuance, and carried a 10% interest rate, with a default rate of 25%.  Shortly before completion of the Merger, the $300,000 note was converted into 750,000 shares of Royale common stock, and Royale agreed to a cash settlement with the holder of the $1,280,000 note for $1,900,000.

Reclassifications

The Company has reclassified certain prior year amounts between operating cash flow categories to present it on a basis comparable with the current year’s presentation with no impact on net cash provided by operating activities. During 2017, Royale treated reimbursement of overhead expenses through joint operations (“COPAS Overhead”) as part of revenue. In 2018, the Company changed its accounting policy and treats COPAS Overhead as a reduction to the Company’s General and Administrative expenses. Certain prior year amounts have been reclassified for consistency with the current year presentation. These reclassifications had no effect on the reported results of operations.

Business Combinations

From time-to-time, the Company acquires businesses in the oil and gas industry. Royale primarily targets businesses in geological basins that the Company considers to be in a focus area. Businesses are included in the consolidated financial statements from the date of acquisition.

We recognize, separately from goodwill, the identifiable assets acquired and liabilities assumed at their estimated acquisition-date fair values. We measure and recognize goodwill as of the acquisition date as the excess of: (1) the aggregate of the fair value of consideration transferred, the fair value of any noncontrolling interest in the acquiree (if any) and the acquisition date fair value of our previously held equity interest in the acquiree (if any), over (2) the fair value of assets acquired and liabilities assumed. If information about facts and circumstances existing as of the acquisition date is incomplete by the end of the reporting period in which a business combination occurs, we report provisional amounts for the items for which the accounting is incomplete. The measurement or allocation period ends once we receive the information we are seeking; however, this period will generally not exceed one year from the acquisition date. Any material adjustments recognized during the measurement period will be reflected retrospectively in the consolidated financial statements of the subsequent period. We recognize third-party transaction related costs as expense currently in the period in which they are incurred.

Fair value considerations include the evaluation of the underlying documentation supporting receivables, property, other assets and liabilities. If the documentation and support for a receivable or other asset represented by the seller is not deemed acceptable by the Company’s auditors, the receivable or other asset is not considered in the purchase price until such time as the receivable or other asset can be proven to a level acceptable to the Company’s auditors.

Any receipts by the company of cash or other assets, subsequent to the transaction date for which the merger documentation was considered insufficient at the time of the merger, the company recognizes as a current liability. At such time as the documentation is deemed acceptable, the liability is relieved with a credit to earnings in the period of determination.

When the Company pays more than fair market value for an asset, it records the overage as an intangible asset (“goodwill”). In the event that the Company pays less than fair market value for an asset(s) this results in “negative goodwill” or a so called “bargain purchase”. In the event of a bargain purchase, the Company will reevaluate the fair market value of the asset(s) being acquired until such time as there is no negative goodwill.

Goodwill and Impairments

We evaluate goodwill for impairment annually as of December 31st, or when an indicator of impairment exists. We compare the fair value of our reporting units with the carrying value, including goodwill. We recognize an impairment charge for the amount by which the carrying value exceeds a reporting unit’s fair value, not to exceed the total amount of recorded goodwill, as applicable.

Significant estimates used in our fair value calculation using discounted future cash flows include: (1) estimates of future revenue and expense growth by field, (2) future estimated effective tax rates, which vary by geological region and state; (3) future estimated capital expenditures and future required investments in working capital; (4) estimated discount rates, (5) reserve life and decline rates as estimated by an industry recognized reservoir engineer, (6) future commodity pricing expectations as developed by Company management, (7) risking factors established by management by asset class and (8) future development opportunities as evaluated by the Company’s engineering staff. Significant estimates include; oil and gas future well recoveries, future commodity price forecasts, future potential growth estimates, discount values and risk factors.

In addition, we evaluate an acquisition for impairment if events or circumstances change between annual tests, indicating a possible impairment. Examples of such events or circumstances include: (1) a significant adverse change in legal factors or in the business climate; (2) an adverse change in commodity prices, (3) assessment by a regulator; (3) a determination by management that some or all of the acquisition will be sold; (4) continued or sustained losses by the acquisition; (5) a significant decline in production as compared to our book value; or (6) we conclude that we may not recover a significant asset class within the acquisition.

Accounting Standards

Recently Adopted

ASU 2017-09, Revenue from Contracts with Customers (ASC 606) 

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 obligation 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.