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
For the Fiscal Year Ended December 31, 2018 |
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Commission File No. 055912 |
ROYALE ENERGY, INC.
(Name of registrant in its charter)
Delaware |
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81-4596368 |
(State or other jurisdiction of incorporation or organization) |
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(I.R.S. Employer Identification No.) |
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:
Large accelerated filer ☐ |
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Accelerated filer ☐ |
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Non-accelerated filer ☐ |
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Smaller Reporting Company ☒ |
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Emerging growth company ☐ |
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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.
PART I |
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Item 1 |
4 |
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6 |
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7 |
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Item 2 |
8 |
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8 |
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8 |
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8 |
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9 |
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9 |
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10 |
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Item 3 |
10 |
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Item 4 |
10 |
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PART II |
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Item 3 |
11 |
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Item 5 |
11 |
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11 |
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11 |
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11 |
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Item 7 |
Management’s Discussion and Analysis of Financial Condition and Results of Operations |
11 |
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11 |
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12 |
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12 |
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17 |
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18 |
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Item 7A |
18 |
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Item 8 |
18 |
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Item 9 |
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
18 |
Item 9A |
18 |
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18 |
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Management Report on Internal Control over Financial Reporting |
19 |
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19 |
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19 |
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PART III |
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Item 10 |
21 |
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23 |
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23 |
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23 |
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Item 11 |
23 |
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Stock Options and Equity Compensation; Outstanding Equity Awards at Fiscal Year End |
24 |
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25 |
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25 |
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25 |
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Item 12 |
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
26 |
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26 |
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Item 13 |
27 |
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Item 14 |
28 |
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PART IV |
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Item 15 |
29 |
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32 |
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F-1 |
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.
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.
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.
Developed |
Undeveloped |
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Gross Acres |
Net Acres |
Gross Acres |
Net Acres |
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California |
5,092.76 | 3,890.17 | 11,431.00 | 3,308.42 | ||||||||||||
All Other States |
10,212.89 | 9,015.13 | 7,121.00 | 6,609.00 | ||||||||||||
Total |
15,305.65 | 12,905.30 | 18,552.00 | 9,917.42 |
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:
Gross Wells |
Net Wells |
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Natural Gas |
40.00 | 15.96 | ||||||
Oil |
56.00 | 21.07 | ||||||
Total |
96.00 | 37.03 |
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.
Year |
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Type of Well(a) |
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Gross Wells(b) |
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Net Wells(e) |
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Total |
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Producing(c) |
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Dry(d) |
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Producing(c) |
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Dry(d) |
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2017 |
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Exploratory |
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- |
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- |
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- |
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- |
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- |
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Developmental |
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4 |
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3 |
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1 |
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0.0028 |
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0.0000 |
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2018 |
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Exploratory |
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- |
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- |
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- |
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- |
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- |
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Developmental |
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4 |
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2 |
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2 |
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0.1464 |
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0.0000 |
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a) |
An exploratory well is one that is drilled in search of new oil and natural gas reservoirs, or to test the boundary limits of a previously discovered reservoir. A developmental well is one drilled on a previously known productive area of an oil and natural gas reservoir with the objective of completing that reservoir. |
b) |
Gross wells represent the number of actual wells in which Royale owns an interest. Royale’s interest in these wells may range from 1% to 100%. |
c) |
A producing well is one that produces oil and/or natural gas that is being purchased on the market. |
d) |
A dry well is a well that is not deemed capable of producing hydrocarbons in paying quantities. |
e) |
One “net well” is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as a whole number or a fraction. |
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.
2018 |
2017 |
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Net volume |
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Oil (BBL) |
18,570 | 102 | ||||||
Gas (MCF) |
135,396 | 190,111 | ||||||
MCFE |
246,816 | 190,723 | ||||||
Average sales price |
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Oil (BBL) |
$ | 64.10 | $ | 46.07 | ||||
Gas (MCF) |
$ | 2.85 | $ | 2.89 | ||||
Net production costs and taxes |
$ | 1,613,368 | $ | 435,637 | ||||
Lifting costs (per MCFE) |
$ | 6.54 | $ | 2.28 |
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.
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,
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1st Qtr |
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2nd Qtr |
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3rd Qtr |
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4th Qtr |
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High |
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Low |
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High |
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Low |
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High |
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Low |
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High |
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Low |
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2017 |
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0.65 |
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0.50 |
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0.50 |
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0.32 |
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0.44 |
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0.33 |
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0.45 |
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0.34 |
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2018 |
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0.49 |
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0.35 |
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0.45 |
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0.36 |
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0.47 |
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0.37 |
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0.36 |
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0.13 |
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The company has engaged the services of American Stock Transfer & Trust company as its transfer agent.
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.
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:
Gain on Settlement of Accounts Payable |
287,134 | |||
Loss on Sale of Assets, net |
(19,199,045 | ) | ||
Loss on Issuance of Warrants |
(1,439,990 | ) | ||
Interest Expense |
(177,171 | ) | ||
Gain on Investment in Joint Venture |
333,931 | |||
Other Loss – Major Components |
$ | (20,195,141 | ) |
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.
Total Obligations |
2019 |
2020 |
2021 |
2022 |
Beyond |
|||||||||||||||||||
Office Leases |
$ | 489,983 | $ | 217,224 | $ | 127,355 | $ | 131,602 | $ | 13,802 | $ | - |
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.
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 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:
Name |
|
Age |
|
|
First Became Director or Executive Officer |
|
Positions Held |
|
|
|
|
|
|
|
|
Mel G. Riggs |
|
64 |
|
|
2018 |
|
Chairman of the Board |
Jonathan Gregory |
|
54 |
|
|
2014 |
|
Vice-Chair of the Board of Directors |
Rod Eson |
|
68 |
|
|
2018 |
|
Director |
Johnny Jordan |
|
58 |
|
|
2018 |
|
Chief Executive and Operating officer and Director |
Thomas M. Gladney (1) (2) |
|
66 |
|
|
2018 |
|
Director |
Barry Lasker (1) (2) |
|
58 |
|
|
2018 |
|
Director |
Robert Vogel (1) (2) |
|
59 |
|
|
2018 |
|
Director |
Harry E. Hosmer |
|
88 |
|
|
1986 |
|
Chairman Emeritus |
(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.
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.
All Other |
||||||||||||||||||||||
Name and Principal Position |
Year |
Salary (4) |
Bonus |
Option Awards (1) |
Compensation (2) |
Total |
||||||||||||||||
Johnny Jordan, CEO (6) |
2018 |
$ | 213,141 | $ | - | $ | - | $ | 213,141 | |||||||||||||
2017 |
$ | - | $ | - | $ | - | $ | - | ||||||||||||||
2016 |
$ | - | $ | - | $ | - | $ | - | ||||||||||||||
Jonathan Gregory (3) (5) |
2018 |
$ | 72,909 | $ | - | $ | 9,583 | $ | 82,492 | |||||||||||||
2017 |
$ | 242,469 | $ | - | $ | - | $ | 242,469 | ||||||||||||||
2016 |
$ | 242,469 | $ | - | $ | - | $ | 242,469 | ||||||||||||||
Donald H. Hosmer |
2018 |
$ | 236,331 | $ | - | $ | 18,930 | $ | 255,261 | |||||||||||||
Business Development |
2017 |
$ | 236,331 | $ | - | $ | 19,090 | $ | 255,421 | |||||||||||||
2016 |
$ | 282,533 | $ | - | $ | 18,339 | $ | 300,872 | ||||||||||||||
Stephen M. Hosmer (4) |
2018 |
$ | 230,192 | $ | - | $ | 64,954 | $ | 18,750 | $ | 313,896 | |||||||||||
Chief Financial Officer |
2017 |
$ | 230,192 | $ | - | $ | 18,906 | $ | 249,098 | |||||||||||||
2016 |
$ | 207,693 | $ | - | $ | 18,231 | $ | 225,924 | ||||||||||||||
Rod Eson (7) |
2018 |
$ | 156,154 | $ | 6,250 | $ | 162,404 |
(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 $6,250 as Board compensation.
Stock Options and Equity Compensation; Outstanding Equity Awards at Fiscal Year End
The following table presents the number of unexercised options at the 2018 year end for each named executive officer. No unvested stock awards were outstanding at the end of 2018.
Options |
||||||||||
Name |
Number of securities underlying unexercised options (1) exercisable |
Number of securities underlying unexercised options (1) unexercisable |
Option exercise price ($) |
Option expiration date |
||||||
Stephen M. Hosmer |
250,000 | (1) | $ | 0.31 |
10/09/2028 |
(1) |
On October 10, 2018, the Board of Directors of Royale granted Mr. Stephen M. Hosmer 250,000 options to purchase common stock at an exercise price of $0.31 per share. These options expire on October 9, 2028. |
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.
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.
Fees paid in cash or Common Stock |
Stock awards |
Option awards |
All Other Compensation |
Total |
||||||||||||||||
Name |
($) | ($) | ($) | ($) | ($) | |||||||||||||||
Mel G. Riggs |
$ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Thomas M. Gladney |
$ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Barry Lasker |
$ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Robert Vogel |
$ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Harry E. Hosmer |
$ | 20,000 | $ | - | $ | - | $ | - | $ | 20,000 | ||||||||||
Former Board Members |
||||||||||||||||||||
Ronald Verdier |
$ | 29,167 | $ | - | $ | - | $ | 6,250 | $ | 35,417 | ||||||||||
Gary Grinsfelder |
$ | 29,167 | $ | - | $ | - | $ | 6,250 | $ | 35,417 | ||||||||||
Ronald Buck |
$ | 29,167 | $ | - | $ | - | $ | 6,250 | $ | 35,417 |
|
(1) |
Mr. Eson served as CEO of the Company during 2018. |
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
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.
Stockholder (1) |
Number |
Percent |
||||||
Stephen M. Hosmer (2) |
1,358,229 | 2.69 | % | |||||
Johnny Jordan (3) |
19,236,954 | 31.95 | % | |||||
Jonathan Gregory (4) |
440,267 | * | ||||||
Mel G. Riggs |
59,524 | * | ||||||
Rod Eson |
- | * | ||||||
Thomas M. Gladney |
59,524 | * | ||||||
Barry Lasker |
69,048 | * | ||||||
Robert Vogel |
69,048 | * | ||||||
All officers and directors as a group |
14,523,710 | 35.34 | % |
* 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.
Stockholder (1) |
Number |
Percent |
||||||
Johnny Jordan (2) |
19,236,954 | 31.95 | % | |||||
Jeff Kerns (3) |
17,290,318 | 29.10 | % | |||||
Michael McCaskey (4) |
4,703,125 | 9.26 | % |
(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:
Year |
# of fractional interests |
Amount |
|||||||
Donald Hosmer (1) |
2018 |
- | $ | - | |||||
2017 |
- | $ | - | ||||||
2016 |
1 | $ | 1,556 | ||||||
Stephen Hosmer (1) |
2018 |
- | $ | - | |||||
2017 |
- | $ | - | ||||||
2016 |
1 | $ | 1,556 | ||||||
Hosmer Trust |
2018 |
- | $ | - | |||||
2017 |
- | $ | - | ||||||
2016 |
1 | $ | 1,556 |
|
(1) |
Mr. Donald Hosmer and Mr. Stephen Hosmer did not participate in any wells under this policy during 2017 or 2018. |
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:
2018 |
2017 |
|||||||
Audit fees (1) |
$ | 180,824 | $ | 184,352 | ||||
Tax fees (2) |
$ | - | $ | - | ||||
All other fees (3) |
$ | 17,326 | $ | 113,387 | ||||
Total |
$ | 198,150 | $ | 297,739 |
(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.
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2.1 |
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2.2 |
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2.3 |
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2.4 |
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3.1 |
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3.2 |
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3.3 |
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4.1 |
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10.1 |
10.2 |
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10.3 |
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10.4 |
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10.5 |
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10.6 |
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10.7 |
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10.8 |
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10.9 |
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10.10 |
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10.11 |
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10.12 |
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10.13 |
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10.14 |
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10.15 |
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10.16 |
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10.17 |
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10.19 |
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10.20 |
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10.21 |
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10.22 |
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10.23 |
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10.24 |
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10.25 |
10.26 |
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10.27 |
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10.28 |
Participation Agreement between the Company and California Resources Petroleum Corporation October 17, 2018), filed as Exhibit 10.29 to the Company’s Form 8-K filed on November 19, 2018 |
21.1 |
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23.1 |
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23.2 |
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23.3 | Consent of Netherland, Sewell & Associates, Inc., filed herewith. |
31.1 |
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31.2 |
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32.1 |
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32.2 |
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99.1 |
Report of Netherland, Sewell & Associates, Inc., filed herewith. |
99.2 |
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101.INS* |
XBRL Instance Document |
101.SCH* |
XBRL Taxonomy Extension Schema |
101.CAL* |
XBRL Taxonomy Extension Calculation Linkbase |
101.DEF* |
XBRL Taxonomy Extension Definition Linkbase |
101.LAB* |
XBRL Taxonomy Extension Label Linkbase |
101.PRE* |
XBRL Taxonomy Extension Presentation Linkbase |
* 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.
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.
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Royale Energy, Inc. |
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Date: April 15, 2019 |
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/s/ Johnny Jordan |
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Johnny Jordan |
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Chief Executive Officer |
Date: April 15, 2019 |
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/s/ Stephen M. Hosmer |
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Stephen M. Hosmer |
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Chief Financial Officer, Secretary and Principle Accounting Officer
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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.
Date: April 15, 2019 |
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/s/ Mel G. Riggs |
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Mel G. Riggs |
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Chairman of the Board of Directors
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Date: April 15, 2019 |
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/s/ Jonathan Gregory |
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Jonathan Gregory |
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Vice-Chair of the Board of Directors
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Date: April 15, 2019 |
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/s/ Rod Eson |
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Rod Eson |
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Director
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Date: April 15, 2019 |
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/s/ Thomas M. Gladney |
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Thomas M. Gladney |
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Director
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Date: April 15, 2019 |
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/s/ Barry Lasker |
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Barry Lasker |
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Director
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Date: April 15, 2019 |
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/s/ Robert Vogel |
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Robert Vogel |
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Director
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ROYALE ENERGY, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA
REPORT OF SINGERLEWAK LLP, INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM |
F-2 |
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F-3 |
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F-5 |
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F-6 |
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F-7 |
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F-8 |
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SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (Unaudited) |
F-29 |
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.
DECEMBER 31,
2018 |
2017 |
|||||||
ASSETS |
||||||||
Current Assets: |
||||||||
Cash and Cash equivalents |
$ | 1,853,742 | $ | 278,227 | ||||
Restricted Cash |
4,501,300 | 3,060,466 | ||||||
Other Receivables, net |
1,411,144 | 764,015 | ||||||
Revenue Receivables |
316,974 | 106,007 | ||||||
Prepaid Expenses and Other Current Assets |
174,852 | 149,367 | ||||||
Total Current Assets |
8,258,012 | 4,358,082 | ||||||
Investment in Joint Venture |
6,583,931 | - | ||||||
Other Assets |
509,955 | 511,120 | ||||||
Oil and Gas Properties (Successful Efforts Basis), Real Property and Equipment and Fixtures, net |
6,407,490 | 1,302,242 | ||||||
Total Assets |
$ | 21,759,388 | $ | 6,171,444 |
The accompanying notes are an integral part of these financial statements.
ROYALE ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
2018 |
2017 |
|||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT) |
||||||||
Current Liabilities: |
||||||||
Accounts Payable and Accrued Expenses |
$ | 4,895,533 | $ | 4,638,879 | ||||
Cash Advances on Pending Transactions |
- | 1,580,000 | ||||||
Royalties Payable |
1,676,865 | - | ||||||
Notes Payable |
390,839 | - | ||||||
Due RMX Resources, LLC |
552,645 | - | ||||||
Accrued Liabilities |
1,254,204 | |||||||
Deferred Drilling Obligations |
6,213,283 | 5,891,898 | ||||||
Total Current Liabilities |
14,983,369 | 12,110,777 | ||||||
Noncurrent Liabilities: |
||||||||
Asset Retirement Obligation |
2,366,455 | 1,000,908 | ||||||
Accrued Unpaid Guaranteed Payments |
1,616,205 | - | ||||||
Accrued Liabilities |
1,306,605 | - | ||||||
Total Liabilities |
20,272,634 | 13,111,685 | ||||||
Stockholders’ Equity (Deficit): |
||||||||
Convertible Preferred Stock, Series B, $10 par value, 3,000,000 |
20,718,613 | - | ||||||
Common Stock, No Par Value, 30,000,000 Shared Authorized |
- | 40,561,882 | ||||||
Common Stock, .001 Par Value, 280,000,000 Shares Authorized |
49,421 | - | ||||||
Additional Paid in Capital |
53,023,350 | 703,567 | ||||||
Accumulated Deficit |
(72,304,630 | ) | (48,205,690 | ) | ||||
Total Stockholder’ Equity (Deficit) |
1,486,754 | (6,940,241 | ) | |||||
Total Liabilities and Stockholders’ Equity (Deficit) |
$ | 21,759,388 | $ | 6,171,444 |
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
2018 |
2017 |
|||||||
Revenues: |
||||||||
Sale of Oil and Gas |
$ | 1,599,362 | $ | 554,235 | ||||
Supervisory Fees and Other |
1,683,679 | 453,144 | ||||||
Total Revenues |
3,283,041 | 1,007,379 | ||||||
Costs and Expenses: |
||||||||
Lease Operating |
1,613,368 | 435,637 | ||||||
Lease Impairment |
1,183,515 | 289,775 | ||||||
Well Equipment Write Down |
9,790 | 16,375 | ||||||
Depreciation, Depletion and Amortization |
722,935 | 116,017 | ||||||
Bad Debt Expense |
648,518 | 164,145 | ||||||
General and Administrative |
3,136,009 | 2,005,630 | ||||||
Legal and Accounting |
1,391,037 | 1,540,190 | ||||||
Marketing |
340,641 | 268,660 | ||||||
Total Costs and Expenses |
9,045,813 | 4,836,429 | ||||||
Gain on Turnkey Drilling Programs |
2,558,716 | 1,487,824 | ||||||
Loss from Operations |
(3,204,056 | ) | (2,341,226 | ) | ||||
Other Income (Expense): |
||||||||
Interest Expense |
(177,171 | ) | (159,268 | ) | ||||
Gain on Investment in Joint Venture |
333,931 | - | ||||||
Gain on Settlement of Accounts Payable |
287,134 | 73,325 | ||||||
Loss on Hedging Activities |
(105,130 | ) | - | |||||
Loss on Issuance of Stock Warrants |
(1,439,990 | ) | - | |||||
Loss on Sale of Assets |
(19,199,045 | ) | - | |||||
Loss Before Income Tax Expense |
(23,504,327 | ) | (2,427,169 | ) | ||||
Provision for Income Taxes |
- | - | ||||||
Net Loss |
(23,504,327 | ) | (2,427,169 | ) | ||||
Basic Loss Per Share |
(0.55 | ) | (0.11 | ) | ||||
Diluted Loss Per Share |
(0.55 | ) | (0.11 | ) |
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
Common Stock |
Preferred Stock Series B |
|||||||||||||||||||||||||||
Number Shares Issued and Outstanding |
Amount |
Number Shares Issued and Outstanding |
Amount |
Additional Capital |
Accumulated |
Total |
||||||||||||||||||||||
Balance, December 31, 2016 |
21,836,033 | $ | 40,561,882 | - | $ | - | $ | 703,567 | $ | (45,778,521 | ) | $ | (4,513,072 | ) | ||||||||||||||
Stock issued in lieu of Compensation |
52,613 | 25,000 | - | - | - | - | 25,000 | |||||||||||||||||||||
Stock issued in Settlement of AP-Adjustment |
(38,461 | ) | (25,000 | ) | - | - | - | - | (25,000 | ) | ||||||||||||||||||
Net (Loss) |
- | - | - | - | - | (2,427,169 | ) | (2,427,169 | ) | |||||||||||||||||||
Balance, December 31, 2017 |
21,850,185 | $ | 40,561,882 | - | $ | - | $ | 703,567 | $ | (48,205,690 | ) | $ | (6,940,241 | ) | ||||||||||||||
Matrix Merger |
25,800,186 | (40,165,982 | ) | 2,012,400 | 20,124,000 | 50,407,050 | - | 30,365,068 | ||||||||||||||||||||
Stock issued for conversion of notes payable pursuant to merger agreement |
750,000 | (347,500 | ) | (347,500 | ) | |||||||||||||||||||||||
Stock issued in lieu of Compensation |
1,021,016 | 1,021 | - | - | 407,779 | - | 408,800 | |||||||||||||||||||||
Warrants Issued to CIC with Sale of Assets to RMX |
- | - | - | - | 1,440,000 | - | 1,440,000 | |||||||||||||||||||||
Executive’s Stock Option Grant |
- | - | - | - | 64,954 | - | 64,954 | |||||||||||||||||||||
Preferred Series B 3.5% Dividend |
- | - | 59,461 | 594,613 | - | (594,613 | ) | - | ||||||||||||||||||||
Net (Loss) |
- | - | - | - | - | (23,504,327 | ) | (23,504,327 | ) | |||||||||||||||||||
Balance, December 31, 2018 |
49,421,387 | $ | 49,421 | 2,071,861 | $ | 20,718,613 | $ | 53,023,350 | $ | (72,304,630 | ) | 1,486,754 |
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
2018 |
2017 |
|||||||
CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||
Net (Loss) |
$ | (23,504,327 | ) | $ | (2,427,169 | ) | ||
Adjustments to Reconcile Net Loss to Net Cash Used by Operating Activities: |
||||||||
Depreciation, Depletion, and Amortization |
722,935 | 116,017 | ||||||
Lease Impairment |
1,183,515 | 289,775 | ||||||
Loss on Sale of Assets |
19,199,045 | - | ||||||
Gain on Turnkey Drilling Programs |
(2,558,716 | ) | (1,487,824 | ) | ||||
Gain on Settlement of Accounts Payable |
(287,134 | ) | (73,325 | ) | ||||
Gain on Investment in Joint Venture |
(333,931 | ) | - | |||||
Bad Debt Expense |
648,518 | 164,145 | ||||||
Stock-Based Compensation |
64,954 | - | ||||||
Loss on Issuance of Stock Warrants |
1,439,990 | - | ||||||
Well Equipment and Other Assets Write Down |
9,790 | 16,375 | ||||||
Loan Fee Amortization |
144,186 | - | ||||||
Change in Fair Value of Derivative Investments |
105,130 | - | ||||||
(Increase) Decrease in: |
||||||||
Other & Revenue Receivables |
(858,096 | ) | (53,992 | ) | ||||
Prepaid Expenses and Other Assets |
(26,464 | ) | 13,600 | |||||
Increase (Decrease) in: |
||||||||
Accounts Payable and Accrued Expenses |
286,109 | 2,242,959 | ||||||
Royalties Payable |
301,222 | - | ||||||
Due to Affiliate |
547,030 | - | ||||||
Other Long-Term Liabilities |
50,415 | - | ||||||
Net Cash Used by Operating Activities |
(2,865,829 | ) | (1,199,439 | ) | ||||
CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||
Expenditures for Oil and Gas Properties |
(3,221,099 | ) | (4,388,967 | ) | ||||
Proceeds from Turnkey Drilling Programs |
6,450,000 | 3,932,501 | ||||||
Proceeds from Sale of Assets |
4,406,138 | - | ||||||
Cash Acquired in Merger |
548,805 | - | ||||||
Net Cash Provided by (Used In) Investing Activities |
8,183,844 | (456,466 | ) | |||||
CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||
Settlement of Liabilities from Cash Advances from Investors |
(1,900,000 | ) | - | |||||
Principal Payments on Long-Term Debt |
(401,666 | ) | - | |||||
Proceeds from Issuance of Common Stock |
- | - | ||||||
Net Cash Provided by Financing Activities |
(2,301,666 | ) | - | |||||
Net Increase (Decrease) in Cash |
3,016,349 | (1,655,905 | ) | |||||
Cash at Beginning of Year |
3,338,693 | 4,994,598 | ||||||
Cash at End of Year |
$ | 6,355,042 | $ | 3,338,693 | ||||
Cash Paid for Interest |
$ | 172,171 | $ | 1,268 | ||||
Cash Paid for Taxes |
$ | 4,800 | $ | 1,539 | ||||
Supplemental Schedule of Non-Cash Investing and Financing Transactions: |
||||||||
Asset Retirement Obligation Addition |
$ | 362,192 | $ | 65,461 | ||||
Issuance of Common Stock for Accrued Compensation Expense |
$ | 408,800 | $ | 25,000 | ||||
Series B Paid-In-Kind Dividends |
$ | 594,615 | $ | - | ||||
Conversion of Convertible Notes to Common Stock |
$ | 347,500 | $ | - | ||||
Notes paid with proceeds from sale of Assets |
$ | 11,616,885 | $ | - | ||||
Contributions to J.V. |
$ | 6,250,000 | $ | - |
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.
12/31/2018 |
12/31/2017 |
|||||||
Cash and cash equivalents |
$ | 1,853,742 | $ | 278,227 | ||||
Restricted cash |
$ | 4,501,300 | $ | 3,060,466 | ||||
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows |
$ | 6,355,042 | $ | 3,338,693 |
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.
Year Ended December 31, |
||||||||
2018 |
2017 |
|||||||
Oil & Condensate Sales |
$ | 1,211,818 | $ | 4,703 | ||||
Natural Gas Sales |
385,803 | 549,532 | ||||||
NGL Sales |
1,741 | - | ||||||
$ | 1,599,362 | $ | 554,235 |
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:
Year Ended December 31, |
||||||||||||||||
2018 |
2017 |
|||||||||||||||
Basic |
Diluted |
Basic |
Diluted |
|||||||||||||
Net Loss |
$ | (23,504,327 | ) | $ | (23,504,327 | ) | $ | (2,427,169 | ) | $ | (2,427,169 | ) | ||||
Less: Preferred Stock Dividend |
594,613 | 594,613 | - | - | ||||||||||||
Less: Preferred Stock Dividend in Arrears |
- | - | - | - | ||||||||||||
Net Loss Attributable to Common Shareholders |
(24,098,940 | ) | (24,098,940 | ) | (2,427,169 | ) | (2,427,169 | ) | ||||||||
Weighted average common shares outstanding |
44,174,209 | 44,174,209 | 21,836,975 | 21,836,975 | ||||||||||||
Effect of dilutive securities |
- | -- | - | - | ||||||||||||
Weighted average common shares, including Dilutive effect |
44,174,209 | 44,174,209 | 21,836,975 | 21,836,975 | ||||||||||||
Per share: |
||||||||||||||||
Net Loss |
$ | (0.55 | ) | $ | (0.55 | ) | $ | (0.11 | ) | $ | (0.11 | ) |
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:
2018 |
2017 |
|||||||
Trade Payables including accruals |
$ | 2,589,518 | $ | 2,392,755 | ||||
Direct working interest investors related accruals |
1,223,588 | 688,002 | ||||||
Current drilling efforts accrued expenses |
413,701 | 483,734 | ||||||
Legal Settlement Payable |
- | 438,667 | ||||||
Accrued Liabilities |
391,641 | 266,110 | ||||||
Employee related accruals |
232,010 | 93,619 | ||||||
Interest payable on cash advances |
- | 223,833 | ||||||
Deferred rent |
32,752 | 35,036 | ||||||
Federal and State income taxes payable |
12,323 | 17,123 | ||||||
$ | 4,895,533 | $ | 4,638,879 |
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.
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
ASU 2017-01: Business Combinations–Clarifying the Definition of a Business
In January 2017, the FASB issued a new accounting standards update that changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities constitutes a business. The guidance requires us to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities would not represent a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described in the new revenue guidance. This standard was effective for us in the first quarter of 2018, and was applied prospectively. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.
ASU 2016-18: Statement of Cash Flow-Restricted Cash (ASC-230-10-50-8)
In November 2016, the FASB issued a new accounting standards update that requires entities to show the changes in the total of cash, cash equivalents and restricted cash in the statement of cash flows. As a result, we no longer present transfers between cash and cash equivalents and restricted cash in the statement of cash flows. When cash, cash equivalents, and restricted cash are presented in more than one line item on the balance sheet, the standard requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. This reconciliation can be presented either on the face of the statement of cash flows or in the notes to the financial statements.
Royale has adopted this new ASU 2016-18 with the reporting of year-end financials. This standard requires Royale to show cash received specifically for drilling operations separately on the balance sheet as Restricted Cash. See note above.
We also adopted the following ASUs during 2018, none of which had a material impact to our financial statements or financial statement disclosures:
ASU |
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Effective Date |
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2017-09 Stock Compensation-Scope of Modification Accounting |
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January 1, 2018 |
2017-07 Retirement Benefits-Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post Retirement Cost |
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January 1, 2018 |
2017-05 Gains and Losses from the Depreciation of Nonfinancial Assets -Clarifying the Scope of Assets Derecognition Guidance |
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January 1, 2018 |
2014-16 Income Taxes-Intra-Entity Transfers of Assets other than Inventory |
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January 1, 2018 |
2016-15 Statement of Cash Flows-Classification of Certain Cash Receipts and Cash Payments |
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January 1, 2018 |
2016-01 Financial Instruments-Recognition and Measurement of Financial Assets and Liabilities |
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January 1, 2018 |
Not Yet Adopted
ASU 2018-02, Reporting Comprehensive Income – Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income
In February 2018, the FASB issued an ASU allowing an entity the choice to retained earnings the tax effects related to the TCJA that are stranded in accumulated other comprehensive income. We do not expect adoption of this standard to have a material impact on our financial statements. The amendment is effective beginning in 2019.
ASU 2017-12, Derivatives and hedging – Targeted Improvement to Accounting for Hedging Activities
In August 2017, the FASB issued an ASU to amend the hedge accounting rules to simplify the application of hedge accounting guidance and better portray the economic results of risk management activities in the financial statements. The guidance expands the ability to hedge nonfinancial and financial risk components, reduces complexity in fair value hedges of interest rate risk, eliminates the requirements to separately measure and report hedge ineffectiveness and eases certain hedge effectiveness assessment requirements. The guidance is effective beginning in 2019. We are currently evaluating the impact of this guidance, including transition elections and required disclosures, on our financial statements and the timing of adoption. However, since we have not historically used derivatives to hedge our commodity price risk, we do not expect adoption of this ASU to have a material impact on our consolidated financial statements.
ASU 2016-13, Credit Losses – Measurement of Credit Losses on Financial Instruments
In June 2016, the FASB issued an ASU related to the accounting for credit losses on certain financial instruments. The guidance requires that for most financial assets, losses be based on an expected loss approach which includes estimates of losses over the life of exposures that considers historical, current and forecasted information. Expanded disclosures related to the methods used to estimate the losses as well as a specific disaggregation of balances for financial assets are also required. The change is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. We do not expect application of this ASU to have a material impact on our consolidated financial statements.
ASU 2016-02 and 2018-11, Leases
In February 2016, the FASB issued an ASU requiring lessees to record virtually all leases on their balance sheet. The ASU also requires expanded disclosures to help financial statement users better understand the amount, timing and uncertainty of cash flow arising from leases. For Lessors, this amended guidance modifies the classification criteria and the accounting for sales-type and direct financing leasers. The guidance will be effective for fiscal years beginning after December 15, 2018, and interim periods within those years. We will transition to the new guidance by recording leases on our balance sheet as of January 1, 2019. We continue to evaluate the impact of this standard on our financial statements, disclosures, internal controls and accounting policies. This evaluation process includes reviewing all forms of leases, performing a completeness assessment over the lease population and analyzing the practical expedients in order to determine the best path of implementing changes to existing processes and controls. We believe the adoption of the standard will have a material impact on our consolidated financial statements as virtually all leases will be recognized as a right of use asset and lease obligation.
NOTE 2 – Merger with Matrix Oil Management Corporation and Formation of RMX
On March 7, 2018, Royale Energy, Inc. (“Royale Energy,” formerly known as Royale Energy Holdings, Inc., a Delaware corporation), Royale Energy Funds, Inc. (“REF,” formerly known as Royale Energy, Inc., a California corporation), and Matrix Oil Management Corporation (“Matrix”) and its affiliates were notified by the California Secretary of State of the filing and acceptance of agreements of merger by the California Secretary of State, to complete the previously announced merger between the companies (the “Merger”). In the Merger, REF was merged into a newly formed subsidiary of Royale Energy, and Matrix was merged into a second newly formed subsidiary of Royale Energy pursuant to the Amended and Restated Agreement and Plan of Merger among REF, Royale Energy, Royale Merger Sub, Inc., (“Royale Merger Sub”), Matrix Merger Sub, Inc., (“Matrix Merger Sub”) and Matrix (the “Merger Agreement”). Additionally, in connection with the merger, all limited partnership interest of two limited partnership affiliates of Matrix (Matrix Permian Investments, LP, and Matrix Las Cienegas Limited Partnership), were exchanged for Royale Energy common stock using conversion ratios according to the relative values of each partnership. All Class A limited partnership interests of another Matrix affiliate, Matrix Investments, LP (“Matrix Investments”) were exchanged for Royale Energy Common stock using conversion ratios according to the relative value of the Class A limited partnership interests, and $20,124,000 of Matrix Investments preferred limited partnership interests were converted into 2,012,400 shares of Series B Convertible Preferred Stock of Royale Energy. Another Matrix affiliate, Matrix Oil Corporation (“Matrix Operator”), was acquired by Royale Energy by exchanging Royale Energy common stock for the outstanding common stock of Matrix Oil Corporation using a conversion ratio according to the relative value of the Matrix Oil Corporation common stock. Matrix, Matrix Oil Corporation and the three limited partnership affiliates of Matrix called the “Matrix Entities.”
The Merger had been previously approved by the respective holders of all outstanding capital stock of REF, Matrix, Royale Energy, Matrix Merger Sub and Royale Merger Sub on November 16, 2017, as previously reported in our Current Report on Form 8-K dated November 16, 2017. The Merger and related transactions are described in detail in our Current Report on Form 8-K dated March 7, 2018, and in Royale Energy’s Current Report on Form 8-K dated March 7, 2018 (SEC File No. 000-55912).
As a result of the Merger, REF became a wholly owned subsidiary of Royale Energy, and each outstanding share of common stock of REF at the time of the Merger was converted into one share of common stock of Royale Energy. The common stock of Royale Energy is traded on the Over-The-Counter QB (OTCQB) Market System (symbol ROYL).
Under FASB Topic ASC 805, Business Combinations, which among other things requires the assets acquired and liabilities assumed to be measured and recorded at their fair values as of the acquisition date, the Company was determined to be the acquirer and as such, the acquisition was accounted for as a business combination.
The preliminary allocation of the purchase price was determined in arms’ length negotiations between the parties. Substantially all of the value of the transaction was related to the value of the oil and gas assets acquired with minimal value ascribed to the other assets. The Company considered two valuation methods in its determination of fair value for the oil and natural gas properties; the discounted cash flow analysis and comparable transaction analysis. Assumptions for the discounted cash flow analysis include commodity price, operating costs and capital outlay for future development of the acquired properties, pricing differentials, reserve risking, and discount rates. NYMEX strip pricing, less applicable pricing differentials, was utilized in the discounted cash flow analysis. Risking levels in the discounted cash flow analysis are determined based on a variety of factors, such as existing well performance, offset production and analogue wells. Discount rates used in the discounted cash flow analysis were determined by using the estimated cost of capital, discount rates, as well as industry knowledge and experience. The comparable transaction analysis was performed to establish a range of fair values for similarly situated oil and gas properties that were recently bought or sold in arms-length, observable market transactions. The range of value observed from the Company’s analysis of recent market transactions was then utilized as a basis for evaluating the fair value determined via the discounted cash flow method. The Company’s fair value conclusion indicated that the discounted cash flow method valuation is in line with the same range as the comparable transactions reviewed, when considering the comparable transactions. Other current liabilities assumed in the acquisition, were carried over at historical carrying values because the assets and liabilities are short term in nature and their carrying values are estimated to represent the best estimate of fair value.
The following table summarizes the consideration transferred, fair value of assets acquired and liabilities assumed:
March 7, 2018 |
||||
Consideration: |
||||
Value of Royale Common Stock issued |
$ | 9,546,068 | ||
Value of Series B Convertible Preferred Stock issued |
20,124,000 | |||
Total consideration |
$ | 29,670,068 | ||
Fair Value of Liabilities Assumed: |
||||
Current liabilities |
19,624,592 | |||
Other liabilities |
3,125,394 | |||
Asset Retirement obligations |
1,419,544 | |||
Total fair value of liabilities assumed |
24,169,530 | |||
Total consideration plus liabilities assumed |
$ | 53,839,598 | ||
Fair Value of Assets Acquired: |
||||
Cash |
$ | 548,805 | ||
Current assets |
1,073,532 | |||
Proved and unproved crude oil and gas properties |
51,214,512 | |||
Land |
1,002,750 | |||
Total Fair Value of Assets Acquired |
$ | 53,839,598 |
In accordance with FASB Topic ASC 805, the following unaudited supplemental pro forma condensed results of operations present combined information as though the business combination had been completed as of January 1, 2018. The unaudited supplemental pro forma financial information was derived from the historical revenues and direct operating expenses of Royale Energy, Inc. and Matrix Oil Management Corporation and its affiliates. These unaudited supplemental pro forma results of operations for the consolidated companies as of December 31, 2018, are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the consolidated company for the periods presented or that may be achieved by the consolidated company in the future.
Year ended December 31, 2018 |
Year ended December 31, 2017 |
|||||||||||||||||||||||
Royale Energy, Inc. |
Matrix Oil Management Corp |
Consolidated |
Royale Energy, Inc. |
Matrix Oil Management Corp |
Consolidated |
|||||||||||||||||||
(Unaudited) |
||||||||||||||||||||||||
Revenue |
$ | 723,172 | $ | 1,199,684 | $ | 1,922,856 | $ | 1,007,379 | $ | 4,896,861 | $ | 5,904,240 | ||||||||||||
Net Loss |
$ | (1,633,713 |
) |
$ | (149,936 |
) |
$ | (1,783,649 |
) |
$ | (2,427,169 |
) |
$ | (3,116,662 |
) |
$ | (5,543,831 |
) |
||||||
Net Loss available to common shareholders |
$ | (1,633,713 |
) |
$ | (149,936 |
) |
$ | (1,783,649 |
) |
$ | (2,427,169 |
) |
$ | (3,116,662 |
) |
$ | (5,543,831 |
) |
||||||
Pro forma Loss per common share Basic and diluted |
$ | (0.04 |
) |
$ | (0.00 |
) |
$ | (0.04 |
) |
$ | (0.11 |
) |
$ | (0.14 |
) |
$ | (0.25 |
) |
Amounts previously estimated have changed during the measurement period. The changes in estimates included an increase of $2,581,641 of oil and gas properties and a decrease of $2,581,641 in accounts receivable and other current assets. We recorded measurement-period adjustments in the fourth quarter of 2018. Depletion expense increased by an immaterial amount as a result of these measurement-period adjustments and all amounts referenced below are inclusive of these measurement period adjustments. As of December 31, 2018, the purchase accounting for the Matrix acquisition was complete.
Original |
Adjustment |
Revised |
||||||||||
Cash |
$ | 548,805 | $ | 548,805 | ||||||||
Current assets |
$ | 3,655,173 | $ | (2,581,641 | ) | $ | 1,073,532 | |||||
Oil and gas properties |
$ | 48,632,870 | $ | 2,581,641 | $ | 51,214,512 |
Formation of RMX and Asset Contribution
On April 13, 2018, Royale Energy, Inc., and two of Royale’s subsidiaries, Royale Energy Funds, Inc. and Matrix Oil Management Corporation (the “Royale Entities”) completed the Subscription and Contribution Agreement (“Contribution Agreement”), in which the Royale Entities and CIC RMX LP (“CIC”) entered into the Contribution Agreement and certain other agreements providing that the Royale Entities would contribute certain assets to RMX Resources, LLC (“RMX”), a newly formed Texas limited liability company formed to facilitate the investment from CIC. In exchange for its contributed assets, Royale received a 20% equity interest in RMX, an equity performance incentive interest and up to $20.0 million to pay off Royale Entities senior lender, Arena Limited SPV, LLC., in full, and to pay Royale Entities trade payables and other outstanding obligations. CIC contributed an aggregate of $25.0 million in cash to RMX in exchange for (i) an 80% equity interest in RMX with preferred distributions until certain thresholds are met, (ii) a warrant (“Warrant”) to acquire up to 4,000,000 shares of Royale’s common stock at an exercise price of $.01 per share and registration rights pursuant to a Registration Rights Agreement
The Contribution Agreement was completed in a two-step closing and funding, with the First Closing consummated on April 4, 2018 and the Second Closing consummated on April 13, 2018 with the Royale Entities. In connection with the Second Closing, the parties entered into a letter agreement related to the preliminary Settlement Statement process. The parties agreed that, in lieu of the payment originally contemplated under Section 1.6(v) of the Contribution Agreement, the Royale Entities would receive the sum of $4,000,000, subject to adjustment. The $4,000,000 delivered at the Second Closing was an advance against amounts due the Royale Entities as Purchase Price, and the advance was subject to further adjustment in accordance with the Contribution Agreement.
RMX has a six-member board of managers. Royale has two seats on the board giving it a third of the Board. Royale has designated Michael McCaskey and Johnny Jordan as its members of the RMX board. The return targets for CIC through its funding of RMX provide for a “waterfall” style return profile with the first distributions going to CIC until it has received all Unpaid Preferred Return and Unpaid Preferred Enhanced Return, as defined by the Company’s Agreement.
As part of the formation of the joint venture, Royale contributed Matrix Oil Corporation (“MOC”) to RMX. MOC has the permits and licenses to operating oil and gas properties in California. It was the operating entity for the Matrix group of companies that were acquired on February 28, 2018, discussed above. This allows the RMX joint venture to be the operator of record for the contributed assets.
Royale accounts for its ownership interest in RMX following the equity method of accounting, in accordance with ASC 323. Pursuant to the Subscription and Contribution agreement, Royale has an initial equity value of $6.25 million or 20% of the total equity of the joint venture with CIC having an initial equity value of $25.0 million or 80% of the total equity of the joint venture.
The Royale Entities contributed 100% of their interest in the Sansinena Field, 100% of the Sempra Field, 50% of the Bellevue Field, 100% of the Whittier Main Field, and 50% of the Whittier Field. The result of the transfer of oil and gas properties and surface rights for cash as described above and a 20% interest in RMX resulted in Royale recording a loss of approximately $17.9 million. The issuance by Royale of warrants to acquire 4,000,000 shares of Royale common stock, by CIC, caused Royale to record a loss of approximately $1.44 million. In addition, the Contribution Agreement called for an effective date of the property transfer of February 28, 2018 which required a purchase price adjustment of approximately $334,000 in the form of a cash contribution to RMX and an increase in the loss on the sale. The transfer of MOC to RMX as the operating company provided an amount due Royale of approximately $640,000, which was recorded as a due from affiliate during the period in 2018.
The RMX joint venture has a senior revolving loan facility with Washington Federal Bank. The borrowing base of the facility is $25.0 million with $22.9 million drawn at December 31, 2018.
As part of the joint venture, RMX entered into a Master Service Agreement (“MSA”) calling for Royale Energy to provide land, engineering and support services for the joint venture. For these services, Royale will receive $180,000 per month for the first year, renewable after one year at a reduced rate of $150,000 per month and subject to termination on 90 days’ notice. These amounts are included in Supervisory Fees, Service Agreement and Other as more fully described in Note 1.
Termination of RMX MSA
On December 31, 2018, Royale was formally notified of RMX’s intent to terminate the MSA as of March 31, 2019. The Termination Notice calls for Royale to continue to provide accounting and other services through March 31, 2019. Thereafter, per Article VII, Section 7.2 of the MSA, Royale shall provide all reasonable assistance requested by the RMX Board to transition the management of RMX for a period of 30 days.
RMX Special Tax Provisions
Under the provisions of the Amended and Restated Limited Liability Company Agreement of RMX Resources, LLC (“RMX Agreement”) dated March 27, 2018, the gains and losses of the partnership are distributed as if all of RMX’s assets were sold for cash at a price equal to their book basis and all RMX liabilities were satisfied at their book basis and all of the remaining assets of RMX were distributed in accordance with Section 5.4 of the RMX Agreement. Notwithstanding the above, for each fiscal year or other relevant period, deductions attributable to exploration costs, IDCs, and operating and maintenance costs shall be allocated 100% to the CIC members pro rata in accordance with their Class B percentage interests for each fiscal year.
Listed below is the summarized information required under Rule 3-09 of regulation S-X, Article 10 for Royale’s investment in RMX:
March 27 (inception) through December 31, 2018 |
||||||||
RMX Resources, LLC |
Royale Energy, Inc. Share |
|||||||
Balance Sheet: |
||||||||
Total Assets |
$ | 71,758,262 | $ | 14,351,652 | ||||
Total Liabilities |
38,838,608 | 7,767,722 | ||||||
Members Equity |
32,919,654 | 6,583,931 | ||||||
Results of Operations: |
||||||||
Net operating revenue |
$ | 8,773,661 | $ | 1,754,732 | ||||
Loss from operations |
(181,464 | ) | (36,293 | ) | ||||
Net income |
1,669,654 | 333,931 |
NOTE 3 – OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES
Oil and gas properties, equipment and fixtures consist of the following at December 31:
2018 |
2017 |
|||||||
Oil and Gas |
||||||||
Producing properties, including intangible drilling costs |
$ | 9,340,779 | $ | 3,755,705 | ||||
Undeveloped properties |
25,582 | 1,435 | ||||||
Lease and well equipment |
3,350,893 | 4,119,802 | ||||||
12,717,254 | 7,876,942 | |||||||
Accumulated depletion, depreciation and amortization |
(6,402,657 | ) | (6,582,648 | ) | ||||
Net capitalized costs Total |
$ | 6,314,597 | $ | 1,294,294 |
Commercial and Other |
2018 |
2017 |
||||||
Real estate, including furniture and fixtures |
$ | 83,405 | $ | - | ||||
Vehicles |
40,061 | 40,061 | ||||||
Furniture and equipment |
1,095,149 | 1,092,926 | ||||||
1,218,615 | 1,132,987 | |||||||
Accumulated depreciation |
(1,125,722 | ) | (1,125,039 | ) | ||||
92,893 | 7,948 | |||||||
Net capitalized costs Total |
$ | 6,407,490 | $ | 1,302,242 |
The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed at December 31:
2018 |
2017 |
|||||||
Acquisition – Proved |
$ | - | - | |||||
Acquisition- Unproved |
$ | - | - | |||||
Development |
$ | 3,838,998 | $ | 4,525,452 | ||||
Exploration |
$ | - | - |
The guidance set forth in the Continued Capitalization of Exploratory Well Costs paragraph of the Extractive Activities Topic of the FASB Accounting Standards Codification requires that we evaluate all existing capitalized exploratory well costs and disclose the extent to which any such capitalized costs have become impaired and are expensed or reclassified during a fiscal period. We did not make any additions to capitalized exploratory well costs pending a determination of proved reserves during 2018 or 2017. We did not charge any previously capitalized exploratory well costs to expense upon adoption of Topic. Undeveloped properties are not subject to depletion, depreciation or amortization.
Year Ended December 31, |
||||||||
2018 |
2017 |
|||||||
Beginning balance at January 1 |
$ | - | $ | - | ||||
Additions to capitalized exploratory well costs pending the determination of proved reserves |
$ | - | $ | - | ||||
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves |
$ | - | $ | - | ||||
Ending balance at December 31 |
$ | - | $ | - |
Results of Operations from Oil and Gas Producing and Exploration Activities
The results of operations from oil and gas producing and exploration activities (excluding corporate overhead and interest costs) are as follows:
Year Ended December 31, |
||||||||
2018 |
2017 |
|||||||
Oil and gas sales |
$ | 1,599,362 | $ | 554,235 | ||||
Production related costs |
(1,613,368 | ) | (435,637 | ) | ||||
Lease Impairment |
(1,183,515 | ) | (289,775 | ) | ||||
Depreciation, depletion and amortization |
(722,935 | ) | (116,017 | ) | ||||
Results of operations from producing and exploration activities |
$ | (1,920,456 | ) | $ | (287,194 | ) | ||
Income Taxes (Benefit) |
- | - | ||||||
Net Results |
$ | (1,920,456 | ) | $ | (287,194 | ) |
NOTE 4 – ASSET RETIREMENT OBLIGATION
The Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification requires that an asset retirement obligation (ARO) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset. The ARO is recorded at fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value. The fair value of the ARO is measured using expected future cash outflows discounted at the Company’s credit-adjusted risk-free interest rate. The provisions of this Topic apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, development, and operation of a long-lived asset.
2018 |
2017 |
|||||||
Asset retirement obligation, Beginning of the year |
$ | 1,000,908 | $ | 952,110 | ||||
Liabilities incurred during the period |
595,583 | 53,142 | ||||||
Settlements |
(52,636 | ) | - | |||||
Merger Additions |
1,419,544 | - | ||||||
Sales |
(486,585 | ) | - | |||||
Accretion expense |
(110,358 | ) | (4,344 | ) | ||||
Asset retirement obligation, End of year |
$ | 2,366,456 | $ | 1,000,908 |
NOTE 5 – TURNKEY DRILLING OBLIGATION
Royale Energy receives funds under turnkey drilling contracts, which require Royale Energy to drill oil and gas wells within a reasonable time period from the date of receipt of the funds. At December 31, 2018 and 2017, Royale Energy had recorded deferred turnkey drilling associated with undrilled wells of $6,213,283 and $5,891,898, respectively, as a current liability.
NOTE 6 – NOTES PAYABLE
On October 3, 2018, the Company issued a promissory note for a principal amount of $517,585 to Forza Operating, LLC. At an interest rate of 5.5%. Beginning October 3, 2018, principal and interest is due and payable in 12 monthly installments of $44,428. The note was the result of an agreement regarding the plugging and abandonment of the CL&F #1 and the CL&F #1 SWD wells. The Company agreed to include the current joint interest billing balance due to Forza Operating of $233,367 and Royale’s share of future plugging and abandonment costs of $284,218. Immediately following the merger with the Matrix entities, it acquired the Matrix loan with Arena which was subsequently paid off with the closing of the RMX joint venture. At December 31, 2018 and 2017, Royale Energy had Notes Payable of $390,839 and $0, respectively, as a current liability.
NOTE 7 – INCOME TAXES
Deferred tax assets and liabilities reflect the net tax effect of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and amounts used for income tax purposes. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. In 2016, the Company adopted Accounting Standards Update (ASU) 2015-17 and has classified all of its deferred tax assets and liabilities as noncurrent on its balance sheet.
On December 22, 2017, the U.S. enacted significant changes to U.S. tax law following the passage and signing of H.R.1, “An Act to Provide for Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018 (the “Tax Act”). The Tax Act permanently reduces the U.S. federal corporate tax rate from a maximum 35% to 21%, eliminated corporate Alternative Minimum Tax, modified rules for expensing capital investment, and limits the deduction of interest expense for certain companies. Accounting Standard Codification (“ASC”) 740 requires filers to record the effect of tax law changes in the period enacted. However, the SEC issued Staff Accounting Bulletin No. 118 (“SAB 118”), that permits filers to record provisional amounts during a measurement period ending no later than one year from the date of enactment. For the period ending December 31, 2018, the Company re-measured the applicable deferred tax assets based on the rates at which they are expected to reverse. The gross deferred tax assets and liabilities have been adjusted and a corresponding offset has been recorded to the full valuation allowance against the Company’s net deferred tax assets, which resulted in no net effect to its provision for income taxes and effective tax rate. No other provisional adjustments have been made as a result of the Act.
Significant components of the Company’s deferred assets and liabilities at December 31, 2018 and 2017, respectively, are as follows:
2018 |
2017 |
|||||||
Deferred Tax Assets (Liabilities): |
||||||||
Statutory Depletion Carry Forward |
$ | 367,149 | $ | 369,591 | ||||
Net Operating Loss |
7,121,912 | 3,130,841 | ||||||
Other |
708,057 | 1,013,329 | ||||||
Share-Based Compensation |
86,510 | 69,609 | ||||||
Capital Loss / AMT Credit Carry Forward |
9,458 | 18,915 | ||||||
Charitable Contributions Carry Forward |
6,158 | 10,025 | ||||||
Allowance for Doubtful Accounts |
597,519 | 514,067 | ||||||
Oil and Gas Properties and Fixed Assets |
5,987,061 | 4,839,823 | ||||||
Investment in RMX Joint Venture |
(1,247,847 | ) | - | |||||
$ | 13,635,977 | $ | 9,966,200 | |||||
Valuation Allowance |
(13,635,977 | ) | (9,966,200 | ) | ||||
Net Deferred Tax Asset |
$ | - | $ | - |
At the end of 2016, management reviewed the realizability of the Company’s net deferred tax assets. Due to the Company’s cumulative losses in recent years, Royale and its management concluded that it is not “more-likely-than-not” its deferred tax assets will be realized. As a result, the Company recorded a full valuation allowance against the net deferred tax assets in 2016. At the end of 2017, management reviewed the reliability of the Company’s net deferred tax assets, and due to the Company’s continued cumulative losses in recent years, Royale and its management concluded it is not “more-likely-than-not” its deferred tax assets will be realized. As a result, the Company will continue to record a full valuation allowance against the deferred tax assets in 2018. The Company will assess the realizability of the deferred tax assets at least yearly and make appropriate updates as needed. Royale Energy, Inc. have available net operating loss carryforwards of $19,151,810 generated in tax years ended before January 1,2018, which if not utilized, begin to expire in the year 2024. Royale Energy, Inc. has no net operating loss carryforwards generated after December 31, 2017, which can be carried forward indefinitely.
A reconciliation of Royale Energy’s provision for income taxes and the amount computed by applying the statutory income tax rates at December 31, 2018 and 2017, respectively, to pretax income is as follows:
2018 |
2017 |
|||||||
Tax (benefit) computed at statutory rate of 21% for 2018 and 34% for 2017 |
$ | (4,935,909 | ) | $ | (825,237 | ) | ||
Increase (decrease) in taxes resulting from: |
||||||||
Meals & Entertainment |
1,320 | - | ||||||
Investor Incentive Expense |
7 | - | ||||||
Transaction Costs |
160,927 | - | ||||||
Loss on Warrants Issued to RMX |
302,398 | - | ||||||
Prior-year true-up for Books |
2,075,440 | - | ||||||
Deferred State Taxes, net of federal benefit |
(1,009,601 | ) | - | |||||
Other non-deductible expenses |
(264,359 | ) | 1,393 | |||||
Change in valuation allowance |
3,669,777 | 823,844 | ||||||
Provision (benefit) |
$ | - | $ | - |
The components of the Company’s tax provision are as follows:
2018 |
2017 |
|||||||
Current tax provision (benefit) – federal |
$ | - | - | |||||
Current tax provision (benefit) – state |
- | - | ||||||
Deferred tax provision (benefit) – federal |
- | - | ||||||
Deferred tax provision (benefit) – state |
- | - | ||||||
Total provision (benefit) |
$ | - | - |
In January 2007, Royale adopted additional provisions from the Income Taxes Topic of the FASB Accounting Standards Codification, which clarified the accounting for uncertainty in income taxes recognized in an entity’s financial statements and prescribes a recognition threshold and measurement attribute for financial statement disclosure of tax positions taken or expected to be taken on a tax return. As a result of our implementation of the Topic at the time of adoption and at December 31, 2018, the Company did not recognize a liability for uncertain tax positions. Currently, the only differences between our financial statements and our income tax returns relate to normal timing differences such as depreciation, depletion and amortization, which are recorded as deferred taxes on our balance sheets. We do not expect our unrecognized tax benefits to change significantly over the next 12 months. The tax years 2013 through 2017 remain open to examination by the taxing jurisdictions in which we file income tax returns.
NOTE 8 - SERIES B PREFERRED STOCK
Pursuant to the terms of the Merger all Class A limited partnership interests of 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. The Board of Directors of Royale Energy, prior to the merger, authorized 3,000,000 shares of Series B Convertible Preferred, which carries a liquidation preference and a 3.5% dividend, payable in cash or Paid-In-Kind shares. The Series B Convertible Preferred Stock is convertible at the option of the security holder at the rate of ten shares of common stock for one share of Series B Convertible Preferred Stock. The Series B Preferred Stock has never been registered under the Securities Exchange Act of 1934, and no market exists for the shares. Additionally, the Series B Convertible Preferred shares will automatically convert to common at any time in which the Volume Weighted Average Price (VWAP) of the common stock exceeds $3.50 per share for 20 consecutive trading days, the shares are registered with the SEC and the volume of common shares trades exceeds 200,000 shares per day. The shareholders of the Series B Convertible Preferred may vote the number of shares into which they would be entitled to convert, beginning in 2020.
On December 17, 2018, the board authorized the issuance of 59,416 shares of Series B Convertible Preferred shares, valued at $594,613, for the outstanding dividends as Paid-In-Kind shares. At December 31, 2018, the shares were outstanding but not issued. No cash was used to pay dividends on Series B preferred shares in 2018.
NOTE 9 - COMMON STOCK
In November 2015, Royale entered in a securities purchase agreement and related agreements with ten investors. Under the terms of the agreement, the investors purchased 497,740 shares of Royale’s common stock at $0.408 per share and received warrants to purchase up to 248,873 shares (the “Warrants’) of stock at $1.00 per share for three (3) years, for a total of $203,080 in gross proceeds. In April 2016, Royale entered in a securities purchase agreement and related agreements with one investor. Under the terms of the agreement, the investor purchased 622,316 shares of Royale’s common stock at $0.3214 per share, and received warrants to purchase up to 311,158 shares (the “Warrants’) of stock at $0.5356 per share for three (3) years, for a total of $200,000 in gross proceeds. In July 2016, Royale entered in securities purchase agreements and related agreements with three investors. Under the terms of the agreement, the investors purchased 2,392,500 shares of Royale’s common stock at $0.40 per share, and received warrants to purchase up to 478,500 shares (the “Warrants’) of stock at $0.80 per share for two (2) years, for a total of $957,000 in gross proceeds. On April 13, 2018, Royale Energy, Inc., and two of Royale’s subsidiaries, Royale Energy Funds, Inc. and Matrix Oil Management Corporation (the “Royale Entities”) completed the Subscription and Contribution Agreement (“Contribution Agreement”), in which the Royale Entities and CIC RMX LP (“CIC”) entered into the Contribution Agreement and certain other agreements providing that the Royale Entities would contribute certain assets to RMX Resources, LLC (“RMX”), a newly formed Texas limited liability company formed to facilitate the investment from CIC. As part of the agreement a warrant (“Warrant”) was issued to acquire up to 4,000,000 shares of Royale’s common stock at an exercise price of $.01 per share and registration rights pursuant to a Registration Rights Agreement. See Note 2 for full discussion.
NOTE 10 - OPERATING LEASES
Royale Energy occupies office space through the use of certain leases, one for their office in El Cajon, CA and one for an office and yard in Woodland, CA. The El Cajon lease is under a 62 month lease contract, with a yearly increase of 3.5%, which expires in January 2020. The El Cajon lease calls for monthly payments ranging from $6,148 to $10,801, and the Woodland lease calls for monthly payments of $500. Royale rents an office and yard in Woodland, CA on a month-to-month basis that currently calls for monthly payments of $500. Additionally, Royale has assumed the use of and responsibility for the payments under a lease for an office space in Santa Barbara, CA. The Santa Barbara lease calls for monthly payments of $7,843, through expiration in September 2019. The Company is currently in discussion to extend the term in exchange for a reduction in rate and amendment name Royale as the contracting party. Rental expense for the years ended December 31, 2018 and 2017 was $210,280 and $110,909 respectively.
Year Ended |
||||
December 31, |
||||
2019 |
$ | 217,224 | ||
2020 |
127,355 | |||
2021 |
131,602 | |||
2022 |
13,802 | |||
2023 |
- | |||
Total |
$ | 489,983 |
NOTE 11 - RELATED PARTY TRANSACTIONS
Significant Ownership Interests
As of March 14, 2019, Mr. Donald H. Hosmer owned 2.69% of Royale Energy common stock (as calculated under SEC Rule 13d-3). Donald Hosmer has participated individually in 179 wells under the 1989 policy. During 2018 and 2017, Donald did not participate in fractional interests. At December 31, 2018, Royale had a payable balance of $2,994 due to Donald Hosmer for normal drilling and lease operating expenses.
As of March 14, 2019, Stephen M. Hosmer owned 2.93% of Royale Energy common stock (as calculated under SEC Rule 13d-3). Stephen Hosmer has participated individually in 179 wells under the 1989 policy. During 2018 and 2017, Stephen did not participate in fractional interests. At December 31, 2018, Royale had a receivable balance of $14,706 due from Stephen Hosmer for normal drilling and lease operating expenses.
At December 31, 2018, we had a total payable of $552,645 due to RMX Resources, LLC and its subsidiary, Matrix Oil Corporation, related to the ongoing transactions between the Royale Energy and RMX Resources, LLC. Of this balance, approximately $312,000 was received on behalf RMX Resources from various oil and gas customers. See related discussion in Note 17 – Subsequent Events.
Prior to the Merger, Matrix had outstanding accrued unpaid guaranteed payments for unpaid salaries due to certain Matrix employees. At December 31, 2018, the balance due these employees was $1,616,205. Prior to the Merger, Matrix had outstanding long term liabilities for interest on notes payable due to certain Matrix principals. The balance due these principals at December 31, 2018, was $1,306,605.
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.
NOTE 12 - STOCK COMPENSATION PLAN
On October 10, 2018, the Company entered into an Incentive Stock Option Award Agreement with Stephen M. Hosmer, Chief Financial Officer. Mr. Hosmer was granted 250,000 options to purchase common stock at an exercise price of $0.31 per share. These options were granted for a period of 10 years and will expire after October 10, 2028. These options become vested exercisable immediately. These options were valued using the Black-Scholes methodology. The Black-Scholes assumptions were as follows: Exercise price per share, $0.31; Current stock price (as of the close on October 10, 2018) $0.34; Risk-free interest rate of 3.22%; Time to maturity of 10 years; and, Stock volatility of 66.48%. The Black-Scholes model, using the values listed above, valued each option at $0.26 making the award of $250,000 options worth $64,954. There were no other stock options issued in 2018 or 2017.
A summary of the status of Royale Energy’s stock option plan as of December 31, 2018 and 2017, and changes during the years ending on those dates is presented below:
2018 |
2017 |
|||||||||||||||
Weighted- |
Weighted- |
|||||||||||||||
Average |
Average |
|||||||||||||||
Exercise |
Exercise |
|||||||||||||||
Shares |
Price |
Shares |
Price |
|||||||||||||
Options |
||||||||||||||||
Outstanding and Exercisable at Beginning of Year |
- | 100,000 | $ | 5.00 | ||||||||||||
Granted or Vested |
250,000 | $ | 0.31 | - | - | |||||||||||
Exercised |
- | - | - | |||||||||||||
Forfeited |
- | (100,000 | ) | - | ||||||||||||
Options Outstanding and Exercisable at Year End |
250,000 | $ | 0.31 | $ | - | |||||||||||
Weighted-average Fair Value of Options Granted During the Year |
$ | 64,954 | - |
At December 31, 2018, Royale Energy’s stock price, $0.13, was less than the weighted average exercise price, and as such the outstanding and exercisable stock options had no intrinsic value. The remaining outstanding stock options have a weighted-average remaining contractual term of one year as of December 31, 2018.
The Company had no non-vested stock option at December 31, 2018 or 2017.
During 2018 and 2017, we recognized $64,954 and $0, respectively, in compensation costs for the vested stock options. The company will incur no future expense related to these options.
NOTE 13 - SIMPLE IRA PLAN
In April 1998, the Company established a Simple IRA pension plan covering all employees. The Company will contribute a matching contribution to each eligible employee’s Simple IRA equal to the employee’s salary reduction contributions up to a limit of 3% of the employee’s compensation for the year. The employer contribution for the years ending December 31, 2018 and 2017, were $35,312 and $28,947 respectively.
NOTE 14 - ENVIRONMENTAL MATTERS
Royale Energy has established procedures for the continuing evaluation of its operations to identify potential environmental exposures and assure compliance with regulatory policies and procedures. Management monitors these laws and regulations and periodically assesses the propriety of its operational and accounting policies related to environmental issues. The nature of Royale Energy’s business requires routine day-to-day compliance with environmental laws and regulations. Royale Energy incurred no material environmental investigation, compliance and remediation costs in 2018 or 2017.
Royale Energy is unable to predict whether its future operations will be materially affected by these laws and regulations. It is believed that legislation and regulations relating to environmental protection will not materially affect the results of operations of Royale Energy.
NOTE 15 - CONCENTRATIONS
The Company bids its gas sales on a month to month basis and generally sells to a single customer without commitment to future gas sales to any particular customer. The Company normally sells approximately 32% of its monthly natural gas production to one customer on a month to month basis. Since we are able to sell our natural gas to other readily available customers, the loss of any one customer would not have an adverse effect on our overall sales operations.
The Company maintains cash in depository institutions that are guaranteed by the Federal Deposit Insurance Corporation (FDIC) up to $250,000 per institution for our interest bearing accounts in the years ended December 31, 2018, and 2017. At December 31, 2016, and 2015, the Company’s non-interest bearing accounts were fully insured by the FDIC. At December 31, 2018 and 2017, cash in banks exceeded the FDIC limits by approximately $5.7 million and $2.8 million, respectively. The Company has not experienced any losses on deposits.
NOTE 16 - COMMITMENTS AND CONTINGENCIES
The Company may become involved from time to time in litigation on various matters, which are routine to the conduct of its business. The Company believes that none of these actions, individually or in the aggregate, will have a material adverse effect on its financial position or results of operations, though any adverse decision in these cases or the costs of defending or settling such claims could have a material effect on its business.
The Company 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. The contracts require the participants pay Royale the full contract price upon execution of the agreement. Royale typically begins the drilling activities within 12 months of funding and reaches total depth between 10 and 30 days after drilling begins.
NOTE 17 - SUBSEQUENT EVENTS
Settlement Agreement and Well Participation Agreement with RMX
On March 11, 2019 Royale entered into a Settlement Agreement with RMX Resources to resolve differences resulting from the calculation of certain post-closing amounts as called for under Section 7.3 of the Subscription and Contribution Agreement. Under the terms of this provision, Royale estimates that it may owe RMX approximately $552,645 related to its calculation of this post-closing amount under this provision. In addition, there are other disputed amounts related to certain joint owner billing amounts remaining unpaid at year end. In settlement of these differences, Royale has agreed to assign its remaining interests in the Bellevue Field, located in Kern County and the W. Whittier Field located in Los Angeles County, California to RMX. At December 31,2018, the Bellevue and W. Whittier fields accounted for 5.145 and 140.647 Mboe in reserves and were valued at $67,671 and $2.4 million, respectively using SEC pricing and discounted at 10 percent. Royale will continue to be responsible for the liability for the payment of all royalties and suspended funds incurred prior to March 1, 2018. As part of this Settlement Agreement, RMX will offer Royale the right, but not the obligation to participate in a number of wells to be drilled in the Sansinena, Sempra, Whittier and/or East LA properties in Los Angeles County, California at an offered working interest up to 75% of RMX’s working interest in each of the offered wells. The minimum number of wells to be offered to Royale in each year is 2 net wells as determined by an agreed upon methodology. The Agreement also calls for certain credits toward future drilling costs of the offered wells.
Settlement with Sunny Frog
Matrix Oil Company (“MOC” or “Matrix”) operated the Sansinena Field and the East LA Fields. Sunny Frog Oil, LLC (“Sunny Frog”) was a non-operator working interest participant in these fields. During the merger negotiations with Matrix Oil, LLC held during 2017, Royale entered into a purchase and sales agreement with Sunny Frog for the purchase of their 50% interest in the Sansinena and East La Fields on November 27, 2017. After Matrix completed the merger with Royale during March of 2018, it then committed to sell or contributed the Sansinena Field to the RMX joint venture along with certain other properties in April of 2018. In addition, Royale contributed it right to purchase the Sunny Frog interests in the Sansinena and East LA Fields to the RMX joint venture. On April 4, 2018, RMX closed with Sunny Frog for all of their interests in the Sansinena and East LA Fields.
Subsequent to the closing by RMX of the properties with Sunny Frog, Sunny Frog commissioned an audit of the joint accounts during the period that MOC operated the properties. The audit report reflected a large balance due Sunny Frog from MOC. (MOC became part of RMX following the contribution of assets by Royale in early April.) Pursuant to Section 14.2 of the Purchase Agreement, RMX was to deliver any objections to the Preliminary Settlement Statement within 120 days following the closing Date. RMX did not tender its objections to the audit within the proscribed 120-day time limit.
In addition, subsequent to the audit, other matters of controversy arose between Sunny Frog and RMX.
On February 11, 2019, a settlement and release agreement was entered into by Sunny Frog and RMX whereby RMX agreed to pay $75,000 to settle any and all differences between MOC and Sunny Frog. This settlement includes any liabilities payable by Royale. Royale has reviewed its accounts and made any required adjustments.
Issuance of Common Stock
During the first quarter of 2019, in lieu of cash payments for salaries, fees or incentives, Royale issued 989,966 shares of its Common stock valued at approximately $240,008 to various employees, officers and board members.
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
The following estimates of proved oil and gas reserves, both developed and undeveloped, represent interests owned by Royale Energy which are located solely in the United States. Proved reserves represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate to be reasonably certain to be recoverable in the future from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells, with existing equipment and operating methods. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which relatively major expenditures are required for completion.
Disclosures of oil and gas reserves, which follow, are based on estimates prepared by independent petroleum engineering consultant Netherland, Sewell & Associates, Inc., the net reserve value of its proved developed and undeveloped reserves was approximately $57.8 million at December 31, 2018, based on the average Henry Hub natural gas price spot price of $3.10 per MCF and for oil volumes, the average West Texas Intermediate price of $65.56 per barrel as applied on a field-by-field basis. Netherland, Sewell & Associates, Inc. provided reserve value information for the Company’s California, Texas, Oklahoma, Utah and Louisiana properties. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. These estimates do not include probable or possible reserves.
The technical persons responsible for preparing the reserves estimates presented in the report of Netherland, Sewell & Associates, Inc., meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Netherland, Sewell & Associates, Inc. is a firm of independent petroleum engineers, geologists, geophysicists, and petrophysicists; and do not own an interest in our properties and are not employed on a contingent basis. All activities and reports performed and completed by Netherland, Sewell & Associates, Inc. with regards to our reserve valuation estimates are reviewed Royale’s management.
These estimates are furnished and calculated in accordance with requirements of the Financial Accounting Standards Board and the Securities and Exchange Commission (SEC). Because of unpredictable variances in expenses and capital forecasts, crude oil and natural gas price changes, largely influenced and controlled by U.S. and foreign government actions, and the fact that the bases for such estimates vary significantly, management believes the usefulness of these projections is limited. Estimates of future net cash flows presented do not represent management’s assessment of future profitability or future cash flows to Royale Energy. Management’s investment and operating decisions are based upon reserve estimates that include proved reserves prescribed by the SEC as well as probable reserves, and upon different price and cost assumptions from those used here.
It should be recognized that applying current costs and prices and a 10 percent standard discount rate does not convey absolute value. The discounted amounts arrived at are only one measure of the value of proved reserves.
Changes in Estimated Reserve Quantities
The net interest in estimated quantities of proved developed reserves of crude oil and natural gas at December 31, 2018 and 2017, and changes in such quantities during each of the years then ended, were as follows:
Total Proved Reserves |
||||||||||||||||
2018 |
2017 |
|||||||||||||||
Oil (BBL) |
Gas (MCF) |
Oil (BBL) |
Gas (MCF) |
|||||||||||||
Proved developed and |
||||||||||||||||
Beginning of period |
202 | 2,132,221 | 5,853 | 2,014,921 | ||||||||||||
Revisions of previous estimates |
(79,135 | ) | (401,498 | ) | (5,549 | ) | 307,371 | |||||||||
Production |
(20,329 | ) | (135,396 | ) | (102 | ) | (190,111 | ) | ||||||||
Extensions, discoveries and improved recovery |
- | 25,014 | - | 40 | ||||||||||||
Merger Acquisition |
11,375,784 | 13,459,933 | - | - | ||||||||||||
Purchase of minerals in place |
29,300 | 116,110 | - | - | ||||||||||||
Sales of minerals in place |
(10,159,421 | ) | (12,210,184 | ) | - | (450,488 | ) | |||||||||
Proved reserves end of period |
1,146,400 | 2,986,200 | 202 | 2,132,221 |
Proved Developed |
||||||||||||||||
2018 |
2017 |
|||||||||||||||
Oil (BBL) |
Gas (MCF) |
Oil (BBL) |
Gas (MCF) |
|||||||||||||
Proved developed reserves: |
||||||||||||||||
Beginning of period |
202 | 1,798,697 | 5,823 | 1,699,997 | ||||||||||||
End of period |
148,600 | 1,914,900 | 202 | 1,798,697 |
Proved Undeveloped |
||||||||||||||||
2018 |
2017 |
|||||||||||||||
Oil (BBL) |
Gas (MCF) |
Oil (BBL) |
Gas (MCF) |
|||||||||||||
Proved undeveloped reserves: |
||||||||||||||||
Beginning of period |
- | 333,524 | - | 314,925 | ||||||||||||
End of period |
997,800 | 1,071,300 | - | 333,524 |
At December 31, 2018, our previously estimated proved developed and undeveloped natural gas reserve quantities were revised downward by approximately 401,498 MCF of natural gas. This downward revision was mainly the result of one California location which had proved undeveloped reserves 333,524 MCF of natural gas at December 31, 2017, which the Company has decided not to drill. At December 31, 2018, our previously estimated proved developed and undeveloped oil reserve quantities were revised downward by approximately 79,135 BBL of oil. This downward revision was mainly the result of a Texas field acquired during the Matrix merger which had 81,054 BBL of oil lower proved developed producing reserves than originally estimated at the time of the merger.
For December 31, 2017, our previously estimated proved developed and undeveloped reserve quantities were revised upward by approximately 307,371 MCF of natural gas. This upward revision reflected higher than previously estimated proved producing and non-producing natural gas reserves at eight California wells and one Utah well. A location which had 63,350 MCF in proved developed reserves at December 31, 2016, was drilled and began in 2011, was revised upward 122,998 MCF at December 31, 2017. Two locations which had 128,165 MCF in proved developed reserves at December 31, 2016, were drilled and began producing prior to 2000, were revised upward 118,006 MCF at December 31, 2017. A location which was drilled and began producing in 2010, which had proved developed reserves of 618,709 was revised upward 15,227 MCF at December 31, 2017. A location in Utah which was drilled and began producing in 2006, was revised upward 14,688 MCF at December 31, 2017. A location which was drilled and began producing in 2012, had no proved developed reserves at December 31, 2016, was revised upward 10,994 MCF at December 31, 2017. A location which was drilled and began producing in 2008, had proved developed reserves of 13,878 at December 31, 2016, was revised upward 6,084 MCF at December 31, 2017. A location which had proved undeveloped reserves of 314,925 MCF at December 31, 2016, was revised upward 18,598 MCF at December 31, 2017.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The future net cash inflows are developed as follows:
• |
Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. |
• |
The estimated future production of proved reserves is priced on the basis of year-end prices. |
• |
The resulting future gross revenue streams are reduced by estimated future costs to develop and to produce proved reserves, based on year-end estimates. Estimated future development costs by year are as follows: |
2019 |
$ |
2,130,500 |
|
2020 |
|
1,881,500 |
|
2021 |
|
1,500,000 |
|
Thereafter |
|
1,744,900 |
|
|
|
|
|
Total |
$ |
7,256,900 |
|
The resulting future net revenue streams are reduced to present value amounts by applying a ten percent discount.
Disclosure of principal components of the standardized measure of discounted future net cash flows provides information concerning the factors involved in making the calculation. In addition, the disclosure of both undiscounted and discounted net cash flows provides a measure of comparing proved oil and gas reserves both with and without an estimate of production timing. The standardized measure of discounted future net cash flow relating to proved reserves reflects estimated income taxes.
Changes in standardized measure of discounted future net cash flow from proved reserve quantities
The standardized measure of discounted future net cash flows is presented below for the years ended December 31, 2018 and 2017.
This statement discloses the sources of changes in the standardized measure from year to year. The amount reported as “Net changes in prices and production costs” represents the present value of changes in prices and production costs multiplied by estimates of proved reserves as of the beginning of the year. The “accretion of discount” was computed by multiplying the ten percent discount factor by the standardized measure on a pretax basis as of the beginning of the year. The “Sales of oil and gas produced, net of production costs” are expressed in actual dollar amounts. “Revisions of previous quantity estimates” is expressed at year-end prices. The “Net change in income taxes” is computed as the change in present value of future income taxes.
2018 |
2017 |
|||||||
Future cash inflows |
$ | 87,467,200 | 6,065,500 | |||||
Future production costs |
(22,390,900 | ) | (2,117,900 | ) | ||||
Future development costs |
(7,256,900 | ) | (580,800 | ) | ||||
Future income tax expense |
(17,345,820 | ) | (1,010,040 | ) | ||||
Future net cash flows |
40,473,580 | 2,356,760 | ||||||
10% annual discount for estimated timing of cash flows |
(9,827,666 | ) | (712,072 | ) | ||||
Standardized measure of discounted future net cash flows |
$ | 30,645,914 | 1,644,688 | |||||
Sales of oil and gas produced, net of production costs |
$ | (40,557 | ) | (161,139 | ) | |||
Revisions of previous quantity estimates |
(71,162 | ) | 87,956 | |||||
Net changes in prices and production costs |
11,683,159 | 106,303 | ||||||
Sales of minerals in place |
(3,061,278 | ) | - | |||||
Purchases of minerals in place |
287,300 | - | ||||||
Merger Acquisition |
29,903,670 | - | ||||||
Extensions, discoveries and improved recovery |
59,191 | 74 | ||||||
Accretion of discount |
2,670,000 | 197,400 | ||||||
Net change in income tax |
(12,429,097 | ) | (69,178 | ) | ||||
Net increase (decrease) |
$ | 29,001,226 | 161,416 |
Future Development Costs
In order to realize future revenues from our proved reserves estimated in our reserve report, it will be necessary to incur future costs to develop and produce the proved reserves. The following table estimates the costs to develop and produce our proved reserves in the years 2019 through 2021.
Future development cost of: |
2019 |
2020 |
2021 |
|||||||||
Proved developed reserves (PDP) |
$ | - | $ | - | $ | - | ||||||
Proved non-producing reserves (PDNP) |
38,000 | 91,500 | - | |||||||||
Proved undeveloped reserves (PUD) |
2,092,500 | 1,790,000 | 1,500,000 | |||||||||
Total |
$ | 2,130,500 | $ | 1,881,500 | $ | 1,500,000 |
Common assumptions include such matters as the real extent and average thickness of a particular reservoir, the average porosity and permeability of the reservoir, the anticipated future production from existing and future wells, future development and production costs and the ultimate hydrocarbon recovery percentage. As a result, oil and gas reserve estimates and discounted present value estimates are frequently revised in subsequent periods to reflect production data obtained after the date of the original estimate. If the reserve estimates are inaccurate, production rates may decline more rapidly than anticipated, and future production revenues may be less than estimated.
Additional data relating to Royale Energy’s oil and natural gas properties is disclosed in Supplemental Information About Oil and Gas Producing Activities (Unaudited), attached to Royale Energy’s Financial Statements, beginning on page F-1.
Historic Development Costs for Proved Reserves
In each year we expend funds to drill and develop some of our proved undeveloped reserves. The following table summarizes our historic costs incurred in each of the past three fiscal years to drill and develop reserves that were classified as proved undeveloped reserves as of December 31 of the immediately preceding year:
2018 |
|
$ |
- |
2017 |
|
$ |
- |
2016 |
|
$ |
243,583 |
RMX Resources, LLC
Royale has a 20% interest in RMX Resources, LLC, as described in NOTE 2- Merger with Matrix Oil Management Corporation and Formation of RMX. The estimates listed below of proved oil and gas reserves and revenues, both developed and undeveloped represent the gross volume attributable to RMX as a whole and to the 20 percent interest of RMX held by Royale. The reserve values were prepared by independent petroleum engineering consultants Netherland, Sewell & Associates, Inc. These estimates do not include probable or possible reserves and revenue and are presented on the same bases as that of Royale. RMX is not subject to U.S. Federal or state income taxes related to crude oil and natural gas production. RMX has elected to be taxed as a partnership; therefore, the reserve information provided below does not consider Federal or state income taxes.
Total Proved Reserves | ||||||||||||||||
Net to RMX |
Net to Royale (20%) |
|||||||||||||||
Oil (BBL) |
Gas (MCF) |
Oil (BBL) |
Gas (MCF) |
|||||||||||||
Proved developed and undeveloped reserves: |
||||||||||||||||
Beginning of period – formation of RMX |
18,699,100 | 22,018,272 | 3,739,820 | 4,403,654 | ||||||||||||
Production |
(206,200 | ) | (127,972 | ) | (41,240 | ) | (25,594 | ) | ||||||||
Extensions, discoveries and improved recovery |
- | - | - | - | ||||||||||||
Purchase of minerals in place |
2,757,926 | - | 551,585 | - | ||||||||||||
Sales of minerals in place |
- | - | ||||||||||||||
Proved reserves end of period |
21,095,700 | 21,890,300 | 4,219,140 | 4,378,060 |
Proved Developed | ||||||||||||||||
Net to RMX |
Net to Royale (20%) |
|||||||||||||||
Oil (BBL) |
Gas (MCF) |
Oil (BBL) |
Gas (MCF) |
|||||||||||||
Proved developed reserves: |
||||||||||||||||
Beginning of period – formation of RMX |
3,955,367 | 3,303,772 | 791,073 | 660,754 | ||||||||||||
End of period |
4,965,400 | 3,175,700 | 993,080 | 635,140 |
Proved Undeveloped | ||||||||||||||||
Net to RMX |
Net to Royale (20%) |
|||||||||||||||
Oil (BBL) |
Gas (MCF) |
Oil (BBL) |
Gas (MCF) |
|||||||||||||
Proved undeveloped reserves: |
||||||||||||||||
Beginning of period – formation of RMX |
14,588,606 | 18,714,400 | 2,917,721 | 3,742,880 | ||||||||||||
End of period |
16,130,300 | 18,714,400 | 3,226,060 | 3,742,880 |
Changes in Standardized measure of discounted future net cash flow from proved reserve quantities
This statement discloses the sources of changes in the standardized measure from year to year. The amount reported as “Net changes in prices and production costs” represents the present value of changes in prices and production costs multiplied by estimates of proved reserves as of the beginning of the year. The “accretion of discount” was computed by multiplying the ten percent discount factor by the standardized measure on a pretax basis as of the beginning of the year. The “Sales of oil and gas produced, net of production costs” are expressed in actual dollar amounts. “Revisions of previous quantity estimates” is expressed at year-end prices. Because RMX was formed in April of 2018, this analysis only provides the reserve information as of year-end without a comparison and reciliation to a beginning reserve report.
Net to RMX |
Net to Royale (20%) |
|||||||
Future cash inflows |
1,527,930,900 | 305,586,180 | ||||||
Future production costs |
(421,114,900 | ) | (84,222,980 | ) | ||||
Future development costs |
(144,008,100 | ) | (28,801,620 | ) | ||||
Future income tax expense |
- | - | ||||||
Future net cash flows |
962,807,900 | 192,561,580 | ||||||
10% annual discount for estimated timing of |
(594,814,700 | ) | (118,962,940 | ) | ||||
Standardized measure of discounted future net cash flows |
367,993,200 | 73,598,640 | ||||||
Sales of oil and gas produced, |
(4,053,176 | ) | (810,635 | ) | ||||
Formation of RMX joint venture |
301,412,679 | 60,282,536 | ||||||
Revisions of previous quantity estimates |
- | - | ||||||
Net changes in prices and production costs |
- | - | ||||||
Sales of minerals in place |
- | - | ||||||
Purchases of minerals in place |
43,365,585 | 8,673,117 | ||||||
Extensions, discoveries and improved recovery |
||||||||
Accretion of discount |
27,268,112 | 5,453,622 | ||||||
Net change in income tax |
- | - | ||||||
Net increase (decrease) |
367,993,200 | 73,598,640 |
Exhibit 21.1
ROYALE ENERGY, INC.
SUBSIDIARIES
December 31, 2018
Royale Energy Funds, Inc
Matrix Permian Investment, L.P.
Matrix Las Cienegas L.P.
Matrix Investment, L.P.
Royale DWI Investors, LLC
Matrix Oil Management, Corp.
Matrix Pipeline, L.P. (Limited Partner only, General Partner is Matrix Oil Corp. part of the RMX Joint Venture)
Exhibit 23.1
Consent of Independent Registered Public Accounting Firm
We consent to the incorporation by reference in the Registration Statement (No. 333-228028) on Form S-8 of Royale Energy, Inc. of our report dated April 15, 2019 relating to the consolidated financial statements of Royale Energy, Inc., appearing in this Annual Report on Form 10-K of Royale Energy, Inc. for the year ended December 31, 2018.
/s/ SingerLewak LLP
Denver, Colorado
April 15, 2019
Exhibit 23.2
Consent of Independent Registered Public Accounting Firm
We consent to the incorporation by reference in the Registration Statement (Form S-8 No. 333-228028) of our report dated April 15, 2019, relating to the consolidated financial statements of RMX Resources, LLC, appearing in this Annual Report (Form 10-K) of Royale Energy Inc. for the year ended December 31, 2018.
/s/ Moss Adams LLP
Dallas, Texas
April 15, 2019
Exhibit 23.3
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
We hereby consent to the inclusion of our report of Royale Energy, Inc. (the “Company”) dated February 20, 2019, in the Annual Report on Form 10-K for the year ended December 31, 2018, of the Company and its subsidiaries, to be filed with the Securities and Exchange Commission.
NETHERLAND, SEWELL & ASSOCIATES, INC.
By: /s/ Danny D. Simmons
Danny D. Simmons, P.E.
President and Chief Operating Officer
Houston, Texas
April 15, 2019
Exhibit 31.1
I, Johnny Jordan, certify that:
1. I have reviewed this report on Form 10-K of Royale Energy, Inc.;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: April 15, 2019 |
/s/ Johnny Jordan |
|
|
Johnny Jordan, Chief Executive Officer |
Exhibit 31.2
I, Stephen M. Hosmer, certify that:
1. I have reviewed this report on Form 10-K of Royale Energy, Inc.;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions)
a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: April 15, 2019 |
/s/ Stephen M. Hosmer |
|
|
Stephen M. Hosmer, Chief Financial Officer |
Exhibit 32.1
Certification Pursuant to 18 U.S.C. § 1350
The undersigned, Johnny Jordan, Chief Executive Officer of Royale Energy, Inc., a Delaware corporation (the “Company”), pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes Oxley Act of 2002, hereby certifies that:
(1) the Company’s Annual Report on Form 10-K for the year ended December 31, 2018 (the “Report”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and
(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
Date: April 15, 2019 |
By: |
/s/ Johnny Jordan |
|
|
|
Johnny Jordan, Chief Executive Officer |
Exhibit 32.2
Certification Pursuant to 18 U.S.C. § 1350
The undersigned, Stephen M. Hosmer, Co-President, Co-Chief Executive Officer and Chief Financial Officer of Royale Energy, Inc., a Delaware corporation (the “Company”), pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes Oxley Act of 2002, hereby certifies that:
(1) the Company’s Annual Report on Form 10-K for the year ended December 31, 2018 (the “Report”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and
(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
Date: April 15, 2019 |
By: |
/s/ Stephen M. Hosmer |
|
|
|
Stephen M. Hosmer, Chief Financial Officer |
Exhibit 99.1
February 20, 2019
Mr. Stephen M. Hosmer
Royale Energy, Inc.
1870 Cordell Court, Suite 210
El Cajon, California 92020
Dear Mr. Hosmer:
In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2018, to the Royale Energy, Inc. (Royale) interest in certain oil and gas properties located in California, Louisiana, Oklahoma, Texas, and Utah. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Royale. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Royale's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.
We estimate the net reserves and future net revenue to the Royale interest in these properties, as of December 31, 2018, to be:
Net Reserves |
Future Net Revenue (M$) |
|||||||
Oil |
Gas |
Present Worth |
||||||
Category |
(MBBL) |
(MMCF) |
Total |
at 10% |
||||
Proved Developed Producing |
129.2 |
315.2 |
3,725.9 |
2,445.3 |
||||
Proved Developed Non-Producing |
19.4 |
1,599.7 |
3,937.6 |
2,184.7 |
||||
Proved Undeveloped |
997.8 |
1,071.3 |
50,155.9 |
22,070.0 |
||||
Total Proved |
1,146.4 |
2,986.2 |
57,819.4 |
26.700.0 |
The oil volumes shown include crude oil and condensate. Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.
Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. No study was made to determine whether probable or possible reserves might be established for these properties. The estimates of reserves and future revenue included herein have not been adjusted for risk. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.
Gross revenue is Royale's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Royale's share of production taxes, ad valorem taxes, capital costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue
presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.
Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2018. For oil volumes, the average West Texas Intermediate spot price of $65.56 per barrel is adjusted by field for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $3.100 per MMBTU is adjusted by field for energy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $68.41 per barrel of oil and $3.027 per MCF of gas.
Operating costs used in this report are based on operating expense records of Royale. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into field-level costs, per-well costs, and per-unit-of-production costs. Headquarters general and administrative overhead expenses of Royale are included to the extent that they are covered under joint operating agreements for the operated properties. Operating costs are not escalated for inflation.
Capital costs used in this report were provided by Royale and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Capital costs are not escalated for inflation. Our estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties. It is our understanding that Royale has fully prefunded accounts that meet or exceed its estimates of abandonment costs for the properties, net of any salvage value.
For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.
We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Royale interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Royale receiving its net revenue interest share of estimated future gross production. Additionally, we have made no specific investigation of any firm transportation contracts that may be in place for these properties; our estimates of future revenue include the effects of such contracts only to the extent that the associated fees are accounted for in the historical field- and lease-level accounting statements.
The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Royale, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.
For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for behind-pipe zones and undeveloped locations; such reserves are based on
estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.
The data used in our estimates were obtained from Royale, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Mr. C. Ashley Smith, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2006 and has over 5 years of prior industry experience. Mr. Shane M. Howell, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 2005 and has over 7 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.
Sincerely, | |||
|
NETHERLAND, SEWELL & ASSOCIATES, INC. |
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By: |
/s/ C.H. (Scott) Rees III |
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C.H. (Scott) Rees III, P.E. |
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Chairman and Chief Executive Officer |
|
By: /s/ C. Ashley Smith | By: | /s/ Shane M. Howell | |
C. Ashley Smith, P.E. 100560 | Shane M. Howell, P.G. 11276 | ||
Vice President | Vice President | ||
Date Signed: February 20, 2019 | Date Signed: February 20, 2019 |
CAS:RQH
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document. |
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.
(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.
(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:
(i) |
Same geological formation (but not necessarily in pressure communication with the reservoir of interest); |
(ii) |
Same environment of deposition; |
(iii) |
Similar geological structure; and |
(iv) |
Same drive mechanism. |
Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.
(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.
(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.
(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) |
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and |
(ii) |
Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. |
Supplemental definitions from the 2018 Petroleum Resources Management System:
Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. |
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
(i) |
Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves. |
(ii) |
Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly. |
(iii) |
Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems. |
(iv) |
Provide improved recovery systems. |
(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.
(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:
(i) |
Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs. |
(ii) |
Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records. |
(iii) |
Dry hole contributions and bottom hole contributions. |
(iv) |
Costs of drilling and equipping exploratory wells. |
(v) |
Costs of drilling exploratory-type stratigraphic test wells. |
(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.
(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.
(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(16) Oil and gas producing activities.
(i) |
Oil and gas producing activities include: |
(A) |
The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations; |
(B) |
The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties; |
(C) |
The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as: |
(1) |
Lifting the oil and gas to the surface; and |
(2) |
Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and |
(D) |
Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction. |
Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:
a. |
The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and |
b. |
In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas. |
Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.
(ii) |
Oil and gas producing activities do not include: |
(A) |
Transporting, refining, or marketing oil and gas; |
(B) |
Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production; |
(C) |
Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or |
(D) |
Production of geothermal steam. |
(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
(i) |
When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. |
(ii) |
Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. |
(iii) |
Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. |
(iv) |
The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. |
(v) |
Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be |
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(v) |
assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. |
(vi) |
Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations. |
(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
(i) |
When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. |
(ii) |
Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. |
(iii) |
Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. |
(iv) |
See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. |
(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.
(20) Production costs.
(i) |
Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are: |
(A) |
Costs of labor to operate the wells and related equipment and facilities. |
(B) |
Repairs and maintenance. |
(C) |
Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities. |
(D) |
Property taxes and insurance applicable to proved properties and wells and related equipment and facilities. |
(E) |
Severance taxes. |
(ii) |
Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above. |
(21) Proved area. The part of a property to which proved reserves have been specifically attributed.
(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) |
The area of the reservoir considered as proved includes: |
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(A) |
The area identified by drilling and limited by fluid contacts, if any, and |
(B) |
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. |
(ii) |
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. |
(iii) |
Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. |
(iv) |
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: |
(A) |
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and |
(B) |
The project has been approved for development by all necessary parties and entities, including governmental entities. |
(v) |
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. |
(23) Proved properties. Properties with proved reserves.
(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:
a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B) b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end. b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs. c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves. d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows. e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves. f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.
|
(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.
(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.
(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i) |
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. |
(ii) |
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. |
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:
● The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities); ● The company's historical record at completing development of comparable long-term projects; ● The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities; ● The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and ● The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).
|
(iii) |
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty. |
(32) Unproved properties. Properties with no proved reserves.
Exhibit 99.2
RMX Resources, LLC |
|
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS |
|
|
|
|
|
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM |
2 |
|
|
CONSOLIDATED BALANCE SHEET |
3 |
|
|
CONSOLIDATED STATEMENT OF OPERATIONS |
5 |
|
|
CONSOLIDATED STATEMENT OF MEMBERS' EQUITY |
6 |
|
|
CONSOLIDATED STATEMENT OF CASH FLOWS |
7 |
|
|
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS |
8 |
Report of Independent Registered Public Accounting Firm
To the Members and the Board of Managers of
RMX Resources, LLC
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheet of RMX Resources, LLC and subsidiaries (the “Company”) as of December 31, 2018, the related consolidated statements of operations, changes in members’ equity and cash flows for the period from March 27, 2018 (inception) through December 31, 2018, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2018, and the consolidated results of its operations and its cash flows for the period from March 27, 2018 (inception) through December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audit. 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 the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated 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 audit 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 audit included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audit provides a reasonable basis for our opinion.
/s/ Moss Adams LLP
Dallas, Texas
April 15, 2019
We have served as the Company’s auditor since 2018.
RMX Resources, LLC
Consolidated Balance Sheet
December 31, 2018
ASSETS |
||||
CURRENT ASSETS |
||||
Cash and cash equivalents |
$ | 1,735,555 | ||
Restricted cash |
800,000 | |||
Accounts receivable: |
||||
Oil and gas sales |
1,249,134 | |||
Joint interest billings |
65,649 | |||
Receivable from Royale Energy |
621,244 | |||
Other |
191,604 | |||
Prepaid expenses |
232,475 | |||
Commodity derivatives short-term |
1,546,614 | |||
Total current assets |
6,442,275 | |||
OIL AND GAS PROPERTIES, |
||||
(successful efforts method) |
||||
Work in progress, not subject to amortization |
698,996 | |||
Proved properties, subject to amortization |
64,351,145 | |||
Other fixed assets |
240,107 | |||
Accumulated, depreciation, depletion and amortization |
(704,548 | ) | ||
Net oil and gas properties |
64,585,700 | |||
OTHER ASSETS |
||||
Deposits |
30,000 | |||
Commodity derivatives, long-term |
700,287 | |||
Total other assets |
730,287 | |||
TOTAL ASSETS |
$ | 71,758,262 |
See accompanying notes to these financials statements
RMX Resources, LLC
Consolidated Balance Sheet - Continued
December 31, 2018
LIABILITIES AND MEMBERS' EQUITY |
||||
CURRENT LIABILITIES |
||||
Trade payables |
$ | 1,877,151 | ||
Royalties payable |
791,084 | |||
Asset retirement obligations |
954,157 | |||
Accrued liabilities |
608,362 | |||
Total current liabilities |
4,230,754 | |||
LONG-TERM LIABILITIES AND DEBT |
||||
Secured term debt, net of unamortized loan costs |
22,822,550 | |||
Asset retirement obligations |
11,785,304 | |||
Total long-term liabilities and debt |
34,607,854 | |||
Total Liabilities |
38,838,608 | |||
COMMITMENTS AND CONTINGENCIES (Note 11) |
||||
MEMBERS' EQUITY |
||||
Member's Equity |
32,919,654 | |||
Total members' equity |
32,919,654 | |||
TOTAL LIABILITIES AND MEMBERS' EQUITY |
$ | 71,758,262 |
See accompanying notes to these financials statements
RMX Resources LLC
Consolidated Statement of Operations
Period from |
||||
December 31, 2018 |
||||
OPERATING REVENUES |
||||
Oil and gas sales, net |
$ | 8,773,661 | ||
Net Operating Revenue |
8,773,661 | |||
OPERATING EXPENSES |
||||
Oil and gas production costs |
4,720,485 | |||
General and administrative expense |
2,368,248 | |||
Acquisition and start-up costs |
805,802 | |||
Depreciation, depletion and amortization |
704,548 | |||
Accretion of asset retirement obligations |
356,042 | |||
Total operating expense |
8,955,125 | |||
Loss from operations |
(181,464 | ) | ||
OTHER INCOME (EXPENSE) |
||||
Interest income |
- | |||
Interest expense |
(653,569 | ) | ||
Gain on commodity derivatives, net |
2,466,812 | |||
Other |
37,875 | |||
Total other income (expense), net |
1,851,118 | |||
NET INCOME |
$ | 1,669,654 |
See accompanying notes to these financials statements
RMX Resources LLC
Consolidated Statement of Changes in Members Equity
Period from March 27, 2018 (inception) through December 31, 2018
Series A |
Series B |
Series C |
Total |
|||||||||||||
BALANCES, March 27, 2018 |
$ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||
Contributions |
6,250,000 | 25,000,000 | 0 | 31,250,000 | ||||||||||||
Net Income |
333,931 | 1,335,723 | 0 | 1,669,654 | ||||||||||||
BALANCES, December 31, 2018 |
$ | 6,583,931 | $ | 26,335,723 | $ | 0 | $ | 32,919,654 |
See accompanying notes to these financials statements
RMX Resources LLC
Consolidated Statement of Cash Flows
Period from March 27, 2018 (inception) through December 31, 2018
OPERATING |
||||
Net income |
$ | 1,669,654 | ||
Reconciliation of net income to net cash provided by |
||||
Operating activities |
||||
Depreciation, depletion and amortization |
704,548 | |||
Accretion of discount on ARO |
356,042 | |||
Amortization of deferred loan costs |
90,104 | |||
Unrealized gain on commodity derivatives |
(3,346,189 | ) | ||
Changes in operating assets and liabilities |
||||
Accounts receivable |
(1,943,661 | ) | ||
Prepaid expenses |
(227,553 | ) | ||
Deposits |
(30,000 | ) | ||
Payables |
2,239,392 | |||
Accrued liabilities |
608,362 | |||
Net cash provided by operating activities |
120,699 | |||
INVESTING |
||||
Acquisitions of oil and gas properties, net of cash acquired |
(44,364,800 | ) | ||
Additions to oil and gas properties |
(952,790 | ) | ||
Net cash used in investing activities |
(45,317,590 | ) | ||
FINANCING |
||||
Payment of debt issuance costs |
(212,500 | ) | ||
Borrowings under revolving lines of credit |
35,444,946 | |||
Repayments under revolving lines of credit |
(12,500,000 | ) | ||
Contributions from members |
25,000,000 | |||
Net cash provided by financing activities |
47,732,446 | |||
Net change in cash, cash equivalents and restricted cash |
2,535,555 | |||
Cash, cash equivalents and restricted cash, beginning of period |
- | |||
Cash, cash equivalents and restricted cash, end of period |
$ | 2,535,555 | ||
SUPPLEMENTAL DISCLOSURES: |
||||
Cash paid for interest |
$ | 554,564 | ||
Issuance of Series A units in exchange for oil and gas properties |
$ | 6,250,000 |
See accompanying notes to these financials statements
RMX RESOURCES, LLC
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2018
NOTE 1 – Organization and Basis of Presentation
Organization
RMX Resources, LLC, is a Texas limited liability company (“RMX”, or the “Company”) formed on March 27, 2018 with CIC RMX LP (“CIC”) as the sole member to acquire and develop oil and gas reserves in certain fields in California. Pursuant to the Subscription and Contribution Agreement dated April 4, 2018, between RMX and Royale Energy, Inc. (‘Royale”), RMX acquired its initial oil and gas properties and its ownership of Matrix Oil Corporation (“MOC”), its wholly owned subsidiary. (See Note 2 – Asset Acquisition and Business Combination)
Basis of Presentation and Consolidation
The accompanying consolidated financial statements of RMX and its wholly owned subsidiary, MOC, have been prepared in conformity with the generally accepted accounting principles of the United States of America (“GAAP”). Significant intercompany balances and transactions have been eliminated upon consolidation.
The preparation of consolidated 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and gas reserve volumes and the future development costs. Actual results could differ from those estimates.
Cash, Restricted Cash and Cash Equivalents
RMX considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. At times, the amount of cash and cash equivalents on deposit in financial institutions exceeds federally insured limits. We monitor the soundness of the financial institutions and believe the Company’s risk is negligible.
Accounts Receivable
Accounts receivable, joint interest billings, consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date. Accounts receivable, oil and gas sales, consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. No such allowance was considered necessary at December 31, 2018.
Prepaid Expenses and Other Assets
Prepaid expenses represent expenditures that have not yet been recorded by the Company as an expense but have been paid for in advance. The cost is charged to expense each month for which the future benefit is recognized.
Deposits
RMX maintains a rolling deposit for use in ongoing negotiations with governmental entities whereby the Company has agreed to assist those entities with costs which they might incur during those negotiations. This deposit will be maintained until numerous negotiations are concluded, which will likely take more than twelve months.
Royalties Payable
The Company receives gross proceeds from oil and gas sales. The proceeds include amounts due to royalty owners and are recorded as royalties payable until such time they are paid.
RMX RESOURCES, LLC
Notes to Consolidated Financial Statements -- Continued
December 31, 2018
Revenue Recognition
Revenue is recognized when oil and gas is delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership. Revenue is measured based on a consideration specified in a contract with a customer, and excludes any sales incentives and amounts collected on behalf of third parties. The Company recognizes revenue when it satisfies a performance obligation by transferring control over a product or service to a customer.
Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction, that are collected by the Company from a customer, are excluded from revenue. The company bears no shipping and handling costs related to its sales of oil and gas.
The principal activity from which the Company generates its revenue is oil and gas sales by way of contracts with customers. Contracts with customers stipulate how the products are priced and payment terms. RMX generally sells crude oil and natural gas under short-term agreements at prevailing market prices. Prices are fixed or determinable and collectability is reasonably assured. Revenues from the production of oil and natural gas properties, in which RMX has an interest with other producers, are recognized on the basis of RMX’s net working interest. Differences between actual production and net working interest volumes are not significant. RMX’s consolidated financial statements reflect its pro rata ownership of wells.
All oil and gas sales of the Company are generated in California. The following table presents disaggregated revenue by major sources for the period ended December 31, 2018:
Revenues |
||||
Oil |
$ | 8,442,914 | ||
Gas |
330,747 | |||
Total Revenue from contracts with customers |
$ | 8,773,661 |
Dependence on Major Customers
For the period ended December 31, 2018, sales to ConocoPhillips accounted for approximately 95% of our total sales. Accounts receivable, oil and gas sales, from ConocoPhillips and one other customer, amounted to 83% of the amount outstanding at December 31, 2018. Although we are exposed to a concentration of credit risk, we believe that our primary purchasers are credit worthy.
Oil and Gas Property and Equipment
RMX uses the “successful efforts” method to account for its development, exploration and production activities. Under this method, RMX 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. Maintenance and repair costs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired.
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. The Company had no capitalized interest for any projects under this accounting policy during the reporting period.
RMX 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 RMX 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.
Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of gas to one barrel of oil equivalent (“Boe”), and one barrel of NGLs to one Boe. The ratios of six Mcf of natural gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe for natural gas may differ significantly from the price for a barrel of oil. Capitalized costs of proved mineral interests are depleted over total estimated proved reserves, and capitalized costs of wells and related equipment and facilities are depleted over estimated proved developed reserves.
RMX RESOURCES, LLC
Notes to Consolidated Financial Statements -- Continued
December 31, 2018
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 point when custody transfers to the buyer. Production costs are those incurred to operate and maintain RMX’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 RMX are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable.
RMX 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. No impairment was indicated at December 31, 2018.
Council of Petroleum Accounting Societies (“COPAS”) Overhead
The operations and accounting for oil and gas properties is governed by a Joint Operating Agreement. Most operating agreements call for the charging of an overhead rate to cover the cost of company personnel performing engineering, land and accounting functions to support the operations of the property. RMX charges this monthly overhead rate through the lease operating billings for all properties except for the Sansinena Field as a whole since RMX owns 100% of the working interest in all wells except the 9A4. RMX does record overhead for the 9A4 well, recently drilled, within the Sansinena Field as RMX does not own 100% of the working interest in this well. The amounts charged to properties as COPAS overhead are treated as a reduction to general and administrative expense.
Royalty Owner Transportation and Marketing Charges
Many lease agreements provide that oil and gas marketing and transportation expenses may be charged to the lease owner as a reduction to their royalty compensation. RMX regularly charges this amount to royalty owners and credits the amount through the joint owner billings to working interest participants.
Fair Value Measurements
According to Fair Value Measurements and Disclosures Topic of the FASB Accounting Standards Codification (“ASC”), assets and liabilities that are measured at fair value on a recurring and nonrecurring basis in period subsequent to initial recognition, the reporting entity shall disclose information that enable users of its financial statements to assess the inputs used to develop those measurements and for recurring fair value measurements using significant unobservable inputs, the effect of the measurements on earnings for the period.
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. In determining fair value, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible as well as considers counterparty credit risk in its assessment of fair value. Carrying amounts of the Company’s financial instruments, including cash equivalents, accounts receivable, accounts payable and accrued liabilities, approximate their fair values as of the balance sheet dates because of their generally short maturities.
RMX RESOURCES, LLC
Notes to Consolidated Financial Statements -- Continued
December 31, 2018
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 |
Fair Value of Financial Instruments (other than Commodity Derivative Instruments, see below) – The carrying values of financial instruments, excluding commodity derivative instruments, comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments.
Derivatives – The fair values of the Company’s commodity derivatives are considered Level 2 as their fair values are based on third-party pricing models which utilize inputs that are either readily available in the public market, such as natural gas and oil forward curves and discount rates, or can be corroborated from active markets or broker quotes. These values are then compared to the values given by the Company’s counterparties for reasonableness. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which results in the Company using market prices and implied volatility factors related to changes in the forward curves. Derivatives are also subject to the risk that counterparties will be unable to meet their obligations.
Debt -- The Company’s debt is recorded at the carrying amount on its Consolidated Balance Sheets. For further discussion of the Company’s debt, please see Note 4 – Debt and Interest Expense. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates.
ARO Amounts - 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 a non-recurring Level 3 fair value measurement. See Note 3 for further discussion of the Company's asset retirement obligations.
Financial assets are considered Level 3 when their fair values are determined using pricing models, discounted cash flow methodologies or similar techniques, and at least one significant model assumption or input is unobservable.
Fair value measurements at December 31, 2018
Quoted |
Significant |
|||||||||||||||
prices |
other |
Significant |
||||||||||||||
in active |
observable |
unobservable |
||||||||||||||
markets |
inputs |
inputs |
||||||||||||||
(Level 1) |
(Level 2) |
(Level 3) |
Total |
|||||||||||||
Assets: |
||||||||||||||||
Commodity derivatives – oil |
$ | 2,246,901 | $ | 2,246,901 |
RMX RESOURCES, LLC
Notes to Consolidated Financial Statements -- Continued
December 31, 2018
Derivative instruments listed above include swaps and two-way collars. For additional information on the Company’s derivative instruments and derivative liabilities, see Note 6 – Commodity Derivative Instruments.
Unit Based Compensation
We measure and record compensation expense for Series C Unit awards to employees and others based on estimated grant date fair values. We recognize compensation costs for awards granted over the requisite service period based on the grant date fair value in general and administrative expenses on our consolidated statements of operations. Additionally, we recognize forfeitures of share-based compensation as they occur.
Accounting Standards
Not Yet Adopted
Lease accounting standard -- In February 2016, the FASB issued a new lease accounting standard, which requires lessees to recognize most leases, including operating leases, on the balance sheet as a right of use asset and lease liability. Short-term leases can continue being accounted for off balance sheet based on a policy election. This standard does not apply to leases to explore for or use minerals, oil, natural gas and similar non-regenerative resources, including the intangible right to explore for those natural resources and rights to use the land in which those natural resources are contained. This standard is effective for us in the first quarter of 2019 and shall be applied using a modified retrospective approach at the beginning of the earliest period presented in the consolidated financial statements. Early adoption is permitted. RMX adopted the standard beginning January 1, 2019 with no significant impact to the consolidated financial statements.
Hedge accounting standard -- In August 2017, the FASB issued a new accounting standards update that amends the hedge accounting model to enable entities to hedge certain financial and nonfinancial risk attributes previously not allowed. The amendment also reduces the overall complexity of documenting, assessing and measuring hedge effectiveness. This standard is effective for us in the first quarter of 2019. Early adoption is permitted in any interim or annual period. The amendment mandates modified retrospective adoption when accounting for hedge relationships in effect as of the adoption date. None of our derivative instruments are currently designated as hedges; as a result we do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.
Recently Adopted
Revenue recognition standard -- On the formation of RMX, we adopted the new ASC Topic 606, Revenue from Contracts with Customers and all the related amendments. We determined that for oil and gas concerns, the transition to this new standard has little or no impact on our existing procedures.
Definition of a business -- In January 2017, the FASB issued a new accounting standards update that changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities constitutes a business. The guidance requires us to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities would not represent a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described in the new revenue guidance. RMX adopted this standard at inception.
Statement of Cash Flows -- In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows, which clarifies the classification of certain cash receipts and payments. The specific cash flow issues addressed by ASU 2016-15, with the objective of reducing the existing diversity in practice, are as follows: (1) Debt prepayment or debt extinguishment costs; (2) Settlement of zero-coupon debt instruments or other debt instruments with insignificant coupon interest rates; (3) Contingent consideration payments made after a business combination; (4) Proceeds from the settlement of insurance claims; (5) Proceeds from the settlement of corporate-owned life insurance policies; (6) Distributions received from equity method investees; (7) Beneficial interest in securitization transactions; and (8) Separately identifiable cash flows and application of the predominance in principle. The Company adopted this new standard at inception. The most significant impact on its consolidated financial statements is the presentation of restricted cash within the totals of cash, cash equivalents and restricted cash on the consolidated statement of cash flows.
RMX RESOURCES, LLC
Notes to Consolidated Financial Statements -- Continued
December 31, 2018
NOTE 2 – Asset Acquisitions and Business Combination
Royale Energy, Inc.
On April 4, 2018, RMX and Royale entered into a Subscription and Contribution Agreement (the “Contribution Agreement”) whereby RMX would acquire certain assets from Royale, principally comprised of oil and gas properties in Los Angeles and Kern Counties. In exchange for the contributed assets, Royale would receive a 20% equity interest in RMX, an equity performance incentive interest and $20.0 million in cash, subject to customary purchase price adjustments.
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, (ii), the right to acquire the 50% non-operated working interest in oil and gas leases in the Sansinena and East Los Angeles fields from Sunny Frog Oil LLC (“Sunny Frog”) which were operated by MOC, and (iii) all of the stock of MOC, the operating company.
The Contribution Agreement contemplated a two-step closing and funding, with the first closing being the Sunny Frog acquisition consummated on April 4, 2018 and the second closing occurring on 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 Purchase and Sales Agreement, as amended for approximately $15 million.
We considered various factors in our estimate of fair value of the acquired assets including (i) reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices, including price differentials, (v) future cash flows.
We consider the two transactions contemplated by the Contribution Agreement as more or less simultaneous. The assets acquired and the liabilities assumed by the Company in the transactions constitute a business combination.
The fair value of the assets was determined using the discounted cash flow approach using Level 3 inputs according to the ASC 820, Fair Value, hierarchy. The determination of the fair value of the oil and gas and other property, plant and equipment acquired required significant judgement, including estimates relating to the production assets and the other transaction costs. Below is the summary of fair value of considerations transferred, the assets acquired, and the liabilities assumed:
Fair value of consideration transferred |
|||||
Cash |
$ | 35,036,603 | |||
Purchase price adjustments payable |
75,000 | ||||
Series A membership units (1) |
6,250,000 | ||||
Total consideration transferred |
$ | 41,361,603 | |||
Assets acquired and liabilities assumed |
|||||
Cash |
$ | 555,518 | |||
Oil and gas properties |
50,818,079 | ||||
Commodity derivatives (2) |
(1,099,288 | ) | |||
Royalties payable |
(305,765 | ) | |||
Working Capital Items, net |
(4,990 | ) | |||
Asset retirement obligations |
(8,601,951 | ) | |||
Net assets acquired |
$ | 41,361,603 |
(1) The Series A Units issued to Royale represented a 20% equity interest in the LLC at closing.
(2) At closing RMX assumed commodity derivates liabilities, crude oil swaps, from Royale and Sunny Frog which had a combined negative mark to market of $1,099,288 based on forward commodity prices and other data (a level 2 fair value measurement)
Acquisition costs amounted to $805,802 and are included in acquisition and start-up costs.
RMX RESOURCES, LLC
Notes to Consolidated Financial Statements -- Continued
December 31, 2018
West Coast Energy Properties
In December 2018, RMX acquired additional interests in the Whittier Field and Bellevue Field. These interests were acquired pursuant to the Purchase and Sale Agreement between Royale Energy, Inc. and West Coast Energy Properties (“WCEP”) executed September 19, 2018. The Purchase and Sale Agreement was amended on October 18, 2018 to add RMX as a party to the agreement, with RMX being the purchaser of the Whittier and Bellevue interests. The purchase price was $12,000,000 with an effective date of March 31, 2018. The transaction was subject to customary and standard purchase price adjustments.
We considered various factors in our estimate of fair value of the acquired assets including (i) reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices, including price differentials, (v) future cash flows, and (vi) working conditions and expected lives of vehicles and equipment.
We determined that substantially all of the fair value of the assets acquired related to additional interests in proved oil and gas properties in which RMX had existing ownership and, as such, the WCEP acquisition does not meet the definition of a business. Therefore, we have accounted for the transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired.
The fair value of the assets was determined using the discounted cash flow approach using Level 3 inputs according to the ASC 820, Fair Value, hierarchy. The determination of the fair value of the oil and gas and other property, plant and equipment acquired, and accounts payable and liabilities assumed, required significant judgement, including estimates relating to the production assets and the other transaction costs. Below is the summary of the identifiable assets acquired:
Amount |
||||
Fair value of consideration transferred |
||||
Cash |
$ | 9,883,715 | ||
Total consideration transferred |
9,883,715 | |||
Assets acquired and liabilities assumed |
||||
Accounts receivable |
$ | 145,804 | ||
Oil and gas properties |
13,519,379 | |||
Asset retirement obligations |
(3,781,468 | ) | ||
Net assets acquired |
$ | 9,883,715 |
NOTE 3 - Asset Retirement Obligations
The Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset. The ARO is recorded at fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value. The fair value of the ARO is measured using expected future cash outflows discounted at the Company’s credit-adjusted risk-free interest rate. The provisions of this topic apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, development, and operation of a long-lived asset. The following table summarizes ARO for the period ended December 31, 2018.
Asset retirement obligation, beginning of period |
$ | - | ||
Liabilities incurred during the period |
12,383,419 | |||
Settlements |
- | |||
Sales |
- | |||
Accretion expense |
356,043 | |||
Asset retirement obligation, end of period |
$ | 12,739,462 |
RMX RESOURCES, LLC
Notes to Consolidated Financial Statements -- Continued
December 31, 2018
NOTE 4 - Debt and Interest Expense
Long-term debt consisted of the following:
Senior credit facility, balance outstanding |
$ | 22,944,946 | ||
Deferred loan costs, net of amortization |
(122,396 | ) | ||
Secured term debt, net of amortized loan cost |
$ | 22,822,550 |
The following table summarizes interest expense for the period ended December 31, 2018.
Credit agreement interest expense |
$ | 534,935 | ||
Credit agreement commitment fees |
18,963 | |||
Amortization of credit agreement loan costs |
90,104 | |||
Letter of Credit Fee |
9,567 | |||
Total interest expense |
$ | 653,569 |
Senior Credit Facility – Washington Federal Bank
On November 30, 2018, RMX entered into a Credit Agreement providing for a $50.0 million four-year senior secured revolving credit facility (the “Credit Agreement”) with Washington Federal Bank, as administrative agent, lead arranger and bookrunner.
As of December 31, 2018, the credit facility had a borrowing base of $25.0 million with $22.9 million outstanding. The amounts borrowed under the Credit Agreement bear annual interest rates at prime lending rate as published from time to time in the “Money Rates” section of The Wall Street Journal as the prime rate. Additional payments due under the Credit Agreement include paying a commitment fee to the Lender in respect of the unutilized commitments thereunder. The commitment rate is 0.50% per year of the unutilized portion of the borrowing base in effect from time to time. The Company is also required to pay customary letter of credit fees. The effective interest rate under the revolving line of credit was 5.50% as of December 31, 2018. The bank charges associated with the commitment rate are reflected on the Statement of Operations as part of interest expense. The note requires payment of interest monthly until maturity on December 1, 2022 at which time all outstanding principal and interest amounts are due.
The Credit Agreement requires the Company to maintain the following financial covenants: commencing with the quarter ended March 31, 2019, a current ratio of not less than 1.0 to 1.0 on the last day of each quarter and, a ratio of total debt to earnings (“Leverage Ratio”) before interest, taxes, depreciation, depletion, amortization and exploration expenses (“EBITDAX”) ratio of not greater than 3.5 to 1.0 for the four fiscal quarters ending on the last day immediately preceding such date of determination, and an interest coverage ratio of greater than or equal to 2.5. to 1.0 at the end of each quarter. The Credit Agreement contains customary affirmative covenants and defines events of default for credit facilities of this type, including failure to pay principal or interest, breach of covenants, breach of representations and warranties, insolvency, judgment default, and a change of control. Upon the occurrence and continuance of an event of default, the Lender has the right to accelerate repayment of the loans and exercise its remedies with respect to the collateral. The borrowing base under the Credit Agreement is subject to redetermination on February 1 and August 1 of each year, as well as special redeterminations described in the Credit Agreement.
Senior Credit Facility - LegacyTexas
On April 4, 2018, RMX entered into a Credit Agreement providing for a $100.0 million four-year senior secured revolving credit facility (the “Credit Agreement”) with LegacyTexas Bank, as administrative agent, lead arranger and bookrunner. This credit facility was paid in full and terminated in December 2018.
As part of the credit facility, there was a Letter of Credit outstanding in the amount of $800,000 for bonds. At the time of pay-off of the credit facility, the Letter of Credit became secured with $800,000 in cash, which is reflected as restricted cash on the consolidated balance sheet as of December 31, 2018.
NOTE 5 – Income Taxes
RMX has elected to be taxed as a partnership under Treasury Regulations § 301.7701-3 and provisions of subchapter K of chapter 1 of subtitle A of the Code. RMX is subject only to California Franchise Tax which is not material and no provisions for current or deferred taxes have been included in these consolidated financial statements. RMX has reviewed its income tax positions and concluded that no uncertain tax positions exist. Penalties and interest, if any, are included in income tax expense on the consolidated statement of operations. There were no such amounts recorded through December 31, 2018.
RMX RESOURCES, LLC
Notes to Consolidated Financial Statements -- Continued
December 31, 2018
MOC is a “C” Corporation for income tax purposes. Deferred tax assets and liabilities related to MOC were inconsequential as of December 31, 2018 and for the period then ended.
The MOC tax calculation has no impact on the consolidated financial statements at December 31, 2018 and is not reflected in them. The effective rate of 0% differs from the statutory rate of 21% due to adjustments to the valuation allowance against deferred taxes and the portion of RMX’s consolidated taxable income generated in RMX which is not subject to tax.
NOTE 6 – Commodity Derivative Instruments
Objective and Strategies for Using Commodity Derivative Instruments – In order to mitigate the effect of commodity price uncertainty and enhance the predictability of cash flows relating to the marketing of the Company’s crude oil the Company enters into crude oil price commodity derivative instruments with respect to a portion of the Company’s expected production. The commodity derivative instruments used include futures, swaps, and options to manage exposure to commodity price risk inherent in the Company’s crude oil operations.
Futures contracts and commodity price swap agreements are used to fix the price of expected future oil sales at major industry trading locations such as Cushing, Oklahoma for oil. Basis swaps are used to fix or float the price differential between product prices at one market location versus another. Options are used to establish a floor price, a ceiling price, or a floor and ceiling price (collar) for expected future oil sales. (RMX does not hold any basis swaps as of December 31, 2018.)
While these instruments mitigate the cash flow risk of future reductions in commodity prices, they may also curtail benefits from future increases in commodity prices.
The Company does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses associated with derivative instruments are recognized currently in earnings. The change in the mark-to-market value of all hedge instruments are included in other income and expense while the realized settlement amount each month is included in oil and gas revenue.
Counterparty Credit Risk – Commodity derivative instruments expose the Company to counterparty credit risk. The Company’s commodity derivative instruments are with Cargill. Cargill, Inc.’s long-term rating is “A” by Standard & Poor’s, “A2” by Moody’s Investor Service and “A” by Fitch Ratings. If the Company chooses to elect early termination, all asset and liability positions would be netted and settled at the time of election.
Commodity derivative instruments open as of December 31, 2018 are provided below.
Summary by year, as of December 31, 2018 |
||||||||
2019 |
2020 |
|||||||
CRUDE OIL (bbls) |
Settlement |
Settlement |
||||||
Volume Hedged - WTI |
144,000 | 96,000 | ||||||
Average Prices (WTI Hedges) |
||||||||
Swap |
$ | 59.65 | $ | 55.18 | ||||
Call |
$ | 55.70 | $ | 70.70 | ||||
Put |
$ | 47.00 | $ | 55.00 | ||||
2019 |
2020 |
|||||||
Settlement |
Settlement |
|||||||
Volume Hedged - Brent |
24,000 | 12,000 | ||||||
Average Prices (Brent Hedges) |
||||||||
Swap |
$ | 60.65 | $ | 61.20 |
RMX RESOURCES, LLC
Notes to Consolidated Financial Statements -- Continued
December 31, 2018
The following summarizes the fair value of our open commodity derivatives as of December 31, 2018:
Balance Sheet Location |
|||||
Derivatives not designated as hedging instruments |
|||||
Commodity derivatives |
Commodity hedges - short term |
$ | 1,546,614 | ||
Commodity derivatives |
Commodity hedges - long term |
$ | 700,287 |
The following summarizes the cash settlements and change in fair value of our commodity derivatives for the period ended December 31, 2018:
Derivatives not designated as hedging instruments |
||||
Net cash payment on derivative settlements |
$ | (879,377 | ) | |
Non-cash fair value gain on derivatives |
3,346,189 | |||
Commodity derivative gain |
$ | 2,466,812 |
NOTE 7 – General and Administrative
General and administrative expense for the period ending December 31, 2018 is summarized in the table below.
General and administrative expense |
$ | 1,171,216 | ||
Master Service Agreement (see Note 9 - Related Party Transactions) |
1,620,000 | |||
COPAS overhead reimbursement |
(422,968 | ) | ||
Total general and administrative for the period |
$ | 2,368,248 |
NOTE 8 – Equity
The RMX Company Agreement provides for three classes of ownership, which are issued as follows:
|
● |
A Units – These units are all held by Royale and are issued and outstanding for their contribution to RMX of oil and gas property interests and the stock of MOC. As of December 31, 2018, there were 20 A Units outstanding. |
|
● |
B Units – These units are held by CIC RMX LP and are issued and outstanding for their contribution of cash. All distributions are allocated to B Units until they exceed the amounts of contributed capital, plus a minimum return of 12.0% per annum. As of December 31, 2018, there were 80 B Units outstanding. |
|
● |
C Units – These units are available at the direction of the Company. They have a restricted participation under which all B units must first have all of their investment returned plus a minimum return of 12.0%. All 1,000 C-1 units are issued and outstanding to Royale. Of 1,000 available C-2 units, 66% are issued and outstanding to management, with the 34% balance unallocated. As of December 31, 2018, there were 1,610 class C Units outstanding. Subsequent to December 31, 2018, 50 class C Units were awarded to an employee. |
C-1 units vest on April 13, 2020 or upon the sale of all or substantially all of the Company's assets. C-2 units vest immediately upon the sale of all or substantially all of the Company's assets.
Compensation associated with C units has not been recognized due to performance conditions not being met. Compensation of $400,000 will be recognized upon the meeting of performance conditions.
Net income of RMX is allocated based on the pro-rata share of voting interests of the A and B units. As an LLC, each member is limited in liability to their investment in the Company.
RMX RESOURCES, LLC
Notes to Consolidated Financial Statements -- Continued
December 31, 2018
NOTE 9 – Related Party Transactions
At December 31, 2018, we had a receivable from Royale of $621,244 arising from Royale’s collection of revenues belonging to RMX, or related to joint interest billings to Royale related to the ongoing transactions between the Royale Energy and RMX Resources, LLC. This is recorded as accounts receivable from Royale on the consolidated balance sheet as of December 31, 2018.
A Master Service Agreement (“MSA”) was entered into on April 4, 2018 between the Company and Royale, whereby Royale would provide accounting, engineering and land back office services at $180,000 per month. As provided by the MSA, the contract was terminated on March 31, 2019 by the Company giving a thirty-day notice.
At December 31, 2018, the amount due Royale for 2018 services was $540,000, which was recorded in accounts payable. At December 31, 2018, the Company had a remaining obligation of $540,000 for the period January 1, 2019 through March 31, 2019.
NOTE 10 – Acquisition and Start Up Costs
With the formation of RMX and the transfer of oil and gas properties to the new joint venture, the venture incurred certain startup costs. Such costs were expensed as incurred. Because of the significant nature of these expenses, they were listed separately in the accompanying consolidated statement of operations. The costs incurred by CIC RMX LP were engineering, geo-technical and other due diligence costs incurred for the formation of RMX Resources LLC and were reimbursed concurrent with Royale closing.
Initial costs incurred by CIC RMX LP |
$ | 400,000 | ||
Legal expenses |
405,802 | |||
Total startup costs |
$ | 805,802 |
NOTE 11– Commitments and Contingencies
Sunny Frog Post Closing
On April 4, 2018, RMX purchased Sunny Frog’s interest in the Sansinena Field and the East LA Field. The Purchase and Sales Agreement called for the preparation of a post-closing statement by RMX within 120 days of closing. RMX prepared and forwarded to Sunny Frog a post-closing statement showing that Sunny Frog owed RMX approximately $885,000. Sunny Frog disputed the post-closing and contended that RMX owed approximately $2.4 million to Sunny Frog in disputed joint interest billing charges from MOC. This matter was settled in 2019. The effects of this settlement have been recorded as of December 31, 2018.
General Litigation
We are involved in various legal and regulatory proceedings arising in the normal course of business. While we cannot predict the outcome of these proceedings with certainty, we do not believe that an adverse result in any pending legal or regulatory proceeding, individually or in the aggregate, would be material to our consolidated financial condition or cash flow.
Environmental Remediation Contingencies
We are engaged in oil and gas exploration and production and may become subject to certain liabilities or damages as they relate to environmental cleanup of well sites or other environmental restoration or ground water contamination, in connection with drilling or operating oil and gas wells. In connection with our acquisition of existing or previously drilled well bores, we may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental clean up, restoration or contamination, we would be responsible for curing such a violation or paying damages. As of December 31, 2018, no claim has been made, nor are we aware of any liability that exists, as it relates to any environmental cleanup, restoration, contamination or the violation of any rules or regulations relating thereto.
RMX RESOURCES, LLC
Notes to Consolidated Financial Statements -- Continued
December 31, 2018
Employment Agreement with CEO
On April 4, 2018 RMX entered a two-year employment agreement with its chief executive officer. The agreement automatically extends on its anniversary for a period of one year, unless either party provides written notice of its intention not to extend the term of the agreement at least 60 days prior to the anniversary date. In the event of a termination by the company without cause, the executive shall be entitled to receive a lump sum in cash, equal to the executive’s then current base salary.
The base salary of the chief executive officer is presently $250,000 per year, which is the total future commitment of the Company under the employment agreement.
NOTE 12– Subsequent Events
Settlement with Sunny Frog
On February 11, RMX and Sunny Frog reached an agreement whereby Sunny Frog accepted a cash settlement of $75,000 in full resolution of the post-closing and joint interest billing dispute between the two companies. As a result of the settlement, RMX wrote off certain amounts due from Sunny Frog in the amount of $89,298. These costs were reported as of December 31, 2018.
Derivative Transactions
On January 15, 2019, RMX entered into a 9,000 barrel per month Brent crude Swap contract with an average price of $60.10. The contract is effective for calendar year 2021 with Cargill as the counterparty.
On March 28, 2019, the Company entered into a 2,000 barrel per month Brent crude Collar with a $60 floor and a $64.30 cap. The contract is effective for calendar year 2021 with Cargill as the counterparty.
Settlement and Well Participation Agreement with Royale
On March 11, 2019 RMX Resources entered into a Settlement Agreement with Royale to resolve differences resulting from the calculation of certain post-closing amounts as called for under Section 7.3 of the Subscription and Contribution Agreement. Under the terms of this provision, RMX estimated that Royale owed RMX approximately $3.4 million related to its calculation of the post-closing amount. This amount included amounts claimed by Sunny Frog related to its audit of joint owner billings by MOC prior to March 31, 2018. In settlement of these differences, Royale assigned to RMX its remaining interests in the Bellevue Field, located in Kern County and the W. Whittier Field located in Los Angeles County. Royale retained its liability for the payment of all royalties and suspended funds incurred by MOC prior to March 1, 2018. As part of this Settlement Agreement, RMX forgave a net $150,000 of past due joint interest billings owed by Royale to RMX, and agreed to offer Royale the right, but not the obligation to participate in a number of wells to be drilled in the Sansinena, and W Whittier at an offered working interest up to 75% of RMX’s working interest in each of the offered wells for two years. The minimum number of wells to be offered to Royale in each year is 2 net wells as determined by an agreed upon methodology. The Agreement also calls for certain credits toward future drilling costs of the offered wells.
Management has evaluated subsequent events through April 15, 2019, the date on which these consolidated financial statements were available for issuance.
/($.*'$FRI,F3*%.J7,FRI
Document And Entity Information - USD ($) |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Apr. 10, 2019 |
Jun. 30, 2018 |
|
Document and Entity Information [Abstract] | |||
Entity Registrant Name | Royale Energy, Inc. | ||
Document Type | 10-K | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Common Stock, Shares Outstanding | 50,411,353 | ||
Entity Public Float | $ 12,074,673 | ||
Amendment Flag | false | ||
Entity Central Index Key | 0001694617 | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Well-known Seasoned Issuer | No | ||
Document Period End Date | Dec. 31, 2018 | ||
Document Fiscal Year Focus | 2018 | ||
Document Fiscal Period Focus | FY | ||
Entity Small Business | true | ||
Entity Emerging Growth Company | false | ||
Entity Shell Company | false | ||
Entity Ex Transition Period | false |
CONSOLIDATED BALANCE SHEETS (Parentheticals) - $ / shares |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Convertible Preferred Stock, Series B, par value (in Dollars per share) | $ 10 | |
Convertible Preferred Stock, Series B, Shares Authorized | 3,000,000 | |
Convertible Preferred Stock, Series B, shares issued | 2,012,400 | |
Convertible Preferred Stock, Series B, outstanding | 2,012,400 | |
Common Stock, Par Value (in Dollars per share) | $ 0 | |
Common stock, shares authorized | 30,000,000 | |
Common Stock, shares issued | 21,850,185 | |
Common Stock, shares outstanding | 21,850,185 | |
Common Stock with Par Value [Member] | ||
Common Stock, Par Value (in Dollars per share) | $ 0.001 | |
Common stock, shares authorized | 280,000,000 | |
Common Stock, shares issued | 49,421,387 | |
Common Stock, shares outstanding | 49,421,387 |
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
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Accounting Policies [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Significant Accounting Policies [Text Block] | 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. 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 ASU 2017-01: Business Combinations–Clarifying the Definition of a Business In January 2017, the FASB issued a new accounting standards update that changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities constitutes a business. The guidance requires us to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities would not represent a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described in the new revenue guidance. This standard was effective for us in the first quarter of 2018, and was applied prospectively. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows. ASU 2016-18: Statement of Cash Flow-Restricted Cash (ASC-230-10-50-8) In November 2016, the FASB issued a new accounting standards update that requires entities to show the changes in the total of cash, cash equivalents and restricted cash in the statement of cash flows. As a result, we no longer present transfers between cash and cash equivalents and restricted cash in the statement of cash flows. When cash, cash equivalents, and restricted cash are presented in more than one line item on the balance sheet, the standard requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. This reconciliation can be presented either on the face of the statement of cash flows or in the notes to the financial statements. Royale has adopted this new ASU 2016-18 with the reporting of year-end financials. This standard requires Royale to show cash received specifically for drilling operations separately on the balance sheet as Restricted Cash. See note above. We also adopted the following ASUs during 2018, none of which had a material impact to our financial statements or financial statement disclosures:
Not Yet Adopted ASU 2018-02, Reporting Comprehensive Income – Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income In February 2018, the FASB issued an ASU allowing an entity the choice to retained earnings the tax effects related to the TCJA that are stranded in accumulated other comprehensive income. We do not expect adoption of this standard to have a material impact on our financial statements. The amendment is effective beginning in 2019. ASU 2017-12, Derivatives and hedging – Targeted Improvement to Accounting for Hedging Activities In August 2017, the FASB issued an ASU to amend the hedge accounting rules to simplify the application of hedge accounting guidance and better portray the economic results of risk management activities in the financial statements. The guidance expands the ability to hedge nonfinancial and financial risk components, reduces complexity in fair value hedges of interest rate risk, eliminates the requirements to separately measure and report hedge ineffectiveness and eases certain hedge effectiveness assessment requirements. The guidance is effective beginning in 2019. We are currently evaluating the impact of this guidance, including transition elections and required disclosures, on our financial statements and the timing of adoption. However, since we have not historically used derivatives to hedge our commodity price risk, we do not expect adoption of this ASU to have a material impact on our consolidated financial statements. ASU 2016-13, Credit Losses – Measurement of Credit Losses on Financial Instruments In June 2016, the FASB issued an ASU related to the accounting for credit losses on certain financial instruments. The guidance requires that for most financial assets, losses be based on an expected loss approach which includes estimates of losses over the life of exposures that considers historical, current and forecasted information. Expanded disclosures related to the methods used to estimate the losses as well as a specific disaggregation of balances for financial assets are also required. The change is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. We do not expect application of this ASU to have a material impact on our consolidated financial statements. ASU 2016-02 and 2018-11, Leases In February 2016, the FASB issued an ASU requiring lessees to record virtually all leases on their balance sheet. The ASU also requires expanded disclosures to help financial statement users better understand the amount, timing and uncertainty of cash flow arising from leases. For Lessors, this amended guidance modifies the classification criteria and the accounting for sales-type and direct financing leasers. The guidance will be effective for fiscal years beginning after December 15, 2018, and interim periods within those years. We will transition to the new guidance by recording leases on our balance sheet as of January 1, 2019. We continue to evaluate the impact of this standard on our financial statements, disclosures, internal controls and accounting policies. This evaluation process includes reviewing all forms of leases, performing a completeness assessment over the lease population and analyzing the practical expedients in order to determine the best path of implementing changes to existing processes and controls. We believe the adoption of the standard will have a material impact on our consolidated financial statements as virtually all leases will be recognized as a right of use asset and lease obligation. |
NOTE 2 - MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX |
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Business Combination Disclosure [Text Block] | NOTE 2 – Merger with Matrix Oil Management Corporation and Formation of RMX On March 7, 2018, Royale Energy, Inc. (“Royale Energy,” formerly known as Royale Energy Holdings, Inc., a Delaware corporation), Royale Energy Funds, Inc. (“REF,” formerly known as Royale Energy, Inc., a California corporation), and Matrix Oil Management Corporation (“Matrix”) and its affiliates were notified by the California Secretary of State of the filing and acceptance of agreements of merger by the California Secretary of State, to complete the previously announced merger between the companies (the “Merger”). In the Merger, REF was merged into a newly formed subsidiary of Royale Energy, and Matrix was merged into a second newly formed subsidiary of Royale Energy pursuant to the Amended and Restated Agreement and Plan of Merger among REF, Royale Energy, Royale Merger Sub, Inc., (“Royale Merger Sub”), Matrix Merger Sub, Inc., (“Matrix Merger Sub”) and Matrix (the “Merger Agreement”). Additionally, in connection with the merger, all limited partnership interest of two limited partnership affiliates of Matrix (Matrix Permian Investments, LP, and Matrix Las Cienegas Limited Partnership), were exchanged for Royale Energy common stock using conversion ratios according to the relative values of each partnership. All Class A limited partnership interests of another Matrix affiliate, Matrix Investments, LP (“Matrix Investments”) were exchanged for Royale Energy Common stock using conversion ratios according to the relative value of the Class A limited partnership interests, and $20,124,000 of Matrix Investments preferred limited partnership interests were converted into 2,012,400 shares of Series B Convertible Preferred Stock of Royale Energy. Another Matrix affiliate, Matrix Oil Corporation (“Matrix Operator”), was acquired by Royale Energy by exchanging Royale Energy common stock for the outstanding common stock of Matrix Oil Corporation using a conversion ratio according to the relative value of the Matrix Oil Corporation common stock. Matrix, Matrix Oil Corporation and the three limited partnership affiliates of Matrix called the “Matrix Entities.” The Merger had been previously approved by the respective holders of all outstanding capital stock of REF, Matrix, Royale Energy, Matrix Merger Sub and Royale Merger Sub on November 16, 2017, as previously reported in our Current Report on Form 8-K dated November 16, 2017. The Merger and related transactions are described in detail in our Current Report on Form 8-K dated March 7, 2018, and in Royale Energy’s Current Report on Form 8-K dated March 7, 2018 (SEC File No. 000-55912). As a result of the Merger, REF became a wholly owned subsidiary of Royale Energy, and each outstanding share of common stock of REF at the time of the Merger was converted into one share of common stock of Royale Energy. The common stock of Royale Energy is traded on the Over-The-Counter QB (OTCQB) Market System (symbol ROYL). Under FASB Topic ASC 805, Business Combinations, which among other things requires the assets acquired and liabilities assumed to be measured and recorded at their fair values as of the acquisition date, the Company was determined to be the acquirer and as such, the acquisition was accounted for as a business combination. The preliminary allocation of the purchase price was determined in arms’ length negotiations between the parties. Substantially all of the value of the transaction was related to the value of the oil and gas assets acquired with minimal value ascribed to the other assets. The Company considered two valuation methods in its determination of fair value for the oil and natural gas properties; the discounted cash flow analysis and comparable transaction analysis. Assumptions for the discounted cash flow analysis include commodity price, operating costs and capital outlay for future development of the acquired properties, pricing differentials, reserve risking, and discount rates. NYMEX strip pricing, less applicable pricing differentials, was utilized in the discounted cash flow analysis. Risking levels in the discounted cash flow analysis are determined based on a variety of factors, such as existing well performance, offset production and analogue wells. Discount rates used in the discounted cash flow analysis were determined by using the estimated cost of capital, discount rates, as well as industry knowledge and experience. The comparable transaction analysis was performed to establish a range of fair values for similarly situated oil and gas properties that were recently bought or sold in arms-length, observable market transactions. The range of value observed from the Company’s analysis of recent market transactions was then utilized as a basis for evaluating the fair value determined via the discounted cash flow method. The Company’s fair value conclusion indicated that the discounted cash flow method valuation is in line with the same range as the comparable transactions reviewed, when considering the comparable transactions. Other current liabilities assumed in the acquisition, were carried over at historical carrying values because the assets and liabilities are short term in nature and their carrying values are estimated to represent the best estimate of fair value. The following table summarizes the consideration transferred, fair value of assets acquired and liabilities assumed:
In accordance with FASB Topic ASC 805, the following unaudited supplemental pro forma condensed results of operations present combined information as though the business combination had been completed as of January 1, 2018. The unaudited supplemental pro forma financial information was derived from the historical revenues and direct operating expenses of Royale Energy, Inc. and Matrix Oil Management Corporation and its affiliates. These unaudited supplemental pro forma results of operations for the consolidated companies as of December 31, 2018, are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the consolidated company for the periods presented or that may be achieved by the consolidated company in the future.
Amounts previously estimated have changed during the measurement period. The changes in estimates included an increase of $2,581,641 of oil and gas properties and a decrease of $2,581,641 in accounts receivable and other current assets. We recorded measurement-period adjustments in the fourth quarter of 2018. Depletion expense increased by an immaterial amount as a result of these measurement-period adjustments and all amounts referenced below are inclusive of these measurement period adjustments. As of December 31, 2018, the purchase accounting for the Matrix acquisition was complete.
Formation of RMX and Asset Contribution On April 13, 2018, Royale Energy, Inc., and two of Royale’s subsidiaries, Royale Energy Funds, Inc. and Matrix Oil Management Corporation (the “Royale Entities”) completed the Subscription and Contribution Agreement (“Contribution Agreement”), in which the Royale Entities and CIC RMX LP (“CIC”) entered into the Contribution Agreement and certain other agreements providing that the Royale Entities would contribute certain assets to RMX Resources, LLC (“RMX”), a newly formed Texas limited liability company formed to facilitate the investment from CIC. In exchange for its contributed assets, Royale received a 20% equity interest in RMX, an equity performance incentive interest and up to $20.0 million to pay off Royale Entities senior lender, Arena Limited SPV, LLC., in full, and to pay Royale Entities trade payables and other outstanding obligations. CIC contributed an aggregate of $25.0 million in cash to RMX in exchange for (i) an 80% equity interest in RMX with preferred distributions until certain thresholds are met, (ii) a warrant (“Warrant”) to acquire up to 4,000,000 shares of Royale’s common stock at an exercise price of $.01 per share and registration rights pursuant to a Registration Rights Agreement The Contribution Agreement was completed in a two-step closing and funding, with the First Closing consummated on April 4, 2018 and the Second Closing consummated on April 13, 2018 with the Royale Entities. In connection with the Second Closing, the parties entered into a letter agreement related to the preliminary Settlement Statement process. The parties agreed that, in lieu of the payment originally contemplated under Section 1.6(v) of the Contribution Agreement, the Royale Entities would receive the sum of $4,000,000, subject to adjustment. The $4,000,000 delivered at the Second Closing was an advance against amounts due the Royale Entities as Purchase Price, and the advance was subject to further adjustment in accordance with the Contribution Agreement. RMX has a six-member board of managers. Royale has two seats on the board giving it a third of the Board. Royale has designated Michael McCaskey and Johnny Jordan as its members of the RMX board. The return targets for CIC through its funding of RMX provide for a “waterfall” style return profile with the first distributions going to CIC until it has received all Unpaid Preferred Return and Unpaid Preferred Enhanced Return, as defined by the Company’s Agreement. As part of the formation of the joint venture, Royale contributed Matrix Oil Corporation (“MOC”) to RMX. MOC has the permits and licenses to operating oil and gas properties in California. It was the operating entity for the Matrix group of companies that were acquired on February 28, 2018, discussed above. This allows the RMX joint venture to be the operator of record for the contributed assets. Royale accounts for its ownership interest in RMX following the equity method of accounting, in accordance with ASC 323. Pursuant to the Subscription and Contribution agreement, Royale has an initial equity value of $6.25 million or 20% of the total equity of the joint venture with CIC having an initial equity value of $25.0 million or 80% of the total equity of the joint venture. The Royale Entities contributed 100% of their interest in the Sansinena Field, 100% of the Sempra Field, 50% of the Bellevue Field, 100% of the Whittier Main Field, and 50% of the Whittier Field. The result of the transfer of oil and gas properties and surface rights for cash as described above and a 20% interest in RMX resulted in Royale recording a loss of approximately $17.9 million. The issuance by Royale of warrants to acquire 4,000,000 shares of Royale common stock, by CIC, caused Royale to record a loss of approximately $1.44 million. In addition, the Contribution Agreement called for an effective date of the property transfer of February 28, 2018 which required a purchase price adjustment of approximately $334,000 in the form of a cash contribution to RMX and an increase in the loss on the sale. The transfer of MOC to RMX as the operating company provided an amount due Royale of approximately $640,000, which was recorded as a due from affiliate during the period in 2018. The RMX joint venture has a senior revolving loan facility with Washington Federal Bank. The borrowing base of the facility is $25.0 million with $22.9 million drawn at December 31, 2018. As part of the joint venture, RMX entered into a Master Service Agreement (“MSA”) calling for Royale Energy to provide land, engineering and support services for the joint venture. For these services, Royale will receive $180,000 per month for the first year, renewable after one year at a reduced rate of $150,000 per month and subject to termination on 90 days’ notice. These amounts are included in Supervisory Fees, Service Agreement and Other as more fully described in Note 1. Termination of RMX MSA On December 31, 2018, Royale was formally notified of RMX’s intent to terminate the MSA as of March 31, 2019. The Termination Notice calls for Royale to continue to provide accounting and other services through March 31, 2019. Thereafter, per Article VII, Section 7.2 of the MSA, Royale shall provide all reasonable assistance requested by the RMX Board to transition the management of RMX for a period of 30 days. RMX Special Tax Provisions Under the provisions of the Amended and Restated Limited Liability Company Agreement of RMX Resources, LLC (“RMX Agreement”) dated March 27, 2018, the gains and losses of the partnership are distributed as if all of RMX’s assets were sold for cash at a price equal to their book basis and all RMX liabilities were satisfied at their book basis and all of the remaining assets of RMX were distributed in accordance with Section 5.4 of the RMX Agreement. Notwithstanding the above, for each fiscal year or other relevant period, deductions attributable to exploration costs, IDCs, and operating and maintenance costs shall be allocated 100% to the CIC members pro rata in accordance with their Class B percentage interests for each fiscal year. Listed below is the summarized information required under Rule 3-09 of regulation S-X, Article 10 for Royale’s investment in RMX:
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NOTE 3 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES |
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Oil and Gas Properties [Text Block] | NOTE 3 – OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES Oil and gas properties, equipment and fixtures consist of the following at December 31:
The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed at December 31:
The guidance set forth in the Continued Capitalization of Exploratory Well Costs paragraph of the Extractive Activities Topic of the FASB Accounting Standards Codification requires that we evaluate all existing capitalized exploratory well costs and disclose the extent to which any such capitalized costs have become impaired and are expensed or reclassified during a fiscal period. We did not make any additions to capitalized exploratory well costs pending a determination of proved reserves during 2018 or 2017. We did not charge any previously capitalized exploratory well costs to expense upon adoption of Topic. Undeveloped properties are not subject to depletion, depreciation or amortization.
Results of Operations from Oil and Gas Producing and Exploration Activities The results of operations from oil and gas producing and exploration activities (excluding corporate overhead and interest costs) are as follows:
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NOTE 4 - ASSET RETIREMENT OBLIGATION |
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Asset Retirement Obligation Disclosure [Text Block] | NOTE 4 – ASSET RETIREMENT OBLIGATION The Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification requires that an asset retirement obligation (ARO) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset. The ARO is recorded at fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value. The fair value of the ARO is measured using expected future cash outflows discounted at the Company’s credit-adjusted risk-free interest rate. The provisions of this Topic apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, development, and operation of a long-lived asset.
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NOTE 5 - TURNKEY DRILLING OBLIGATION |
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Revenue from Contract with Customer [Abstract] | |
Revenue from Contract with Customer [Text Block] | NOTE 5 – TURNKEY DRILLING OBLIGATION Royale Energy receives funds under turnkey drilling contracts, which require Royale Energy to drill oil and gas wells within a reasonable time period from the date of receipt of the funds. At December 31, 2018 and 2017, Royale Energy had recorded deferred turnkey drilling associated with undrilled wells of $6,213,283 and $5,891,898, respectively, as a current liability. |
NOTE 6 - NOTES PAYABLE |
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Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Debt Disclosure [Text Block] | NOTE 6 – NOTES PAYABLE On October 3, 2018, the Company issued a promissory note for a principal amount of $517,585 to Forza Operating, LLC. At an interest rate of 5.5%. Beginning October 3, 2018, principal and interest is due and payable in 12 monthly installments of $44,428. The note was the result of an agreement regarding the plugging and abandonment of the CL&F #1 and the CL&F #1 SWD wells. The Company agreed to include the current joint interest billing balance due to Forza Operating of $233,367 and Royale’s share of future plugging and abandonment costs of $284,218. Immediately following the merger with the Matrix entities, it acquired the Matrix loan with Arena which was subsequently paid off with the closing of the RMX joint venture. At December 31, 2018 and 2017, Royale Energy had Notes Payable of $390,839 and $0, respectively, as a current liability. |
NOTE 7 - INCOME TAXES |
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Income Tax Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Income Tax Disclosure [Text Block] | NOTE 7 – INCOME TAXES Deferred tax assets and liabilities reflect the net tax effect of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and amounts used for income tax purposes. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. In 2016, the Company adopted Accounting Standards Update (ASU) 2015-17 and has classified all of its deferred tax assets and liabilities as noncurrent on its balance sheet. On December 22, 2017, the U.S. enacted significant changes to U.S. tax law following the passage and signing of H.R.1, “An Act to Provide for Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018 (the “Tax Act”). The Tax Act permanently reduces the U.S. federal corporate tax rate from a maximum 35% to 21%, eliminated corporate Alternative Minimum Tax, modified rules for expensing capital investment, and limits the deduction of interest expense for certain companies. Accounting Standard Codification (“ASC”) 740 requires filers to record the effect of tax law changes in the period enacted. However, the SEC issued Staff Accounting Bulletin No. 118 (“SAB 118”), that permits filers to record provisional amounts during a measurement period ending no later than one year from the date of enactment. For the period ending December 31, 2018, the Company re-measured the applicable deferred tax assets based on the rates at which they are expected to reverse. The gross deferred tax assets and liabilities have been adjusted and a corresponding offset has been recorded to the full valuation allowance against the Company’s net deferred tax assets, which resulted in no net effect to its provision for income taxes and effective tax rate. No other provisional adjustments have been made as a result of the Act. Significant components of the Company’s deferred assets and liabilities at December 31, 2018 and 2017, respectively, are as follows:
At the end of 2016, management reviewed the realizability of the Company’s net deferred tax assets. Due to the Company’s cumulative losses in recent years, Royale and its management concluded that it is not “more-likely-than-not” its deferred tax assets will be realized. As a result, the Company recorded a full valuation allowance against the net deferred tax assets in 2016. At the end of 2017, management reviewed the reliability of the Company’s net deferred tax assets, and due to the Company’s continued cumulative losses in recent years, Royale and its management concluded it is not “more-likely-than-not” its deferred tax assets will be realized. As a result, the Company will continue to record a full valuation allowance against the deferred tax assets in 2018. The Company will assess the realizability of the deferred tax assets at least yearly and make appropriate updates as needed. Royale Energy, Inc. have available net operating loss carryforwards of $19,151,810 generated in tax years ended before January 1,2018, which if not utilized, begin to expire in the year 2024. Royale Energy, Inc. has no net operating loss carryforwards generated after December 31, 2017, which can be carried forward indefinitely. A reconciliation of Royale Energy’s provision for income taxes and the amount computed by applying the statutory income tax rates at December 31, 2018 and 2017, respectively, to pretax income is as follows:
The components of the Company’s tax provision are as follows:
In January 2007, Royale adopted additional provisions from the Income Taxes Topic of the FASB Accounting Standards Codification, which clarified the accounting for uncertainty in income taxes recognized in an entity’s financial statements and prescribes a recognition threshold and measurement attribute for financial statement disclosure of tax positions taken or expected to be taken on a tax return. As a result of our implementation of the Topic at the time of adoption and at December 31, 2018, the Company did not recognize a liability for uncertain tax positions. Currently, the only differences between our financial statements and our income tax returns relate to normal timing differences such as depreciation, depletion and amortization, which are recorded as deferred taxes on our balance sheets. We do not expect our unrecognized tax benefits to change significantly over the next 12 months. The tax years 2013 through 2017 remain open to examination by the taxing jurisdictions in which we file income tax returns. |
NOTE 8 - SERIES B PREFERRED STOCK |
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Dec. 31, 2018 | |
Disclosure Text Block Supplement [Abstract] | |
Preferred Stock [Text Block] | NOTE 8 - SERIES B PREFERRED STOCK Pursuant to the terms of the Merger all Class A limited partnership interests of 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. The Board of Directors of Royale Energy, prior to the merger, authorized 3,000,000 shares of Series B Convertible Preferred, which carries a liquidation preference and a 3.5% dividend, payable in cash or Paid-In-Kind shares. The Series B Convertible Preferred Stock is convertible at the option of the security holder at the rate of ten shares of common stock for one share of Series B Convertible Preferred Stock. The Series B Preferred Stock has never been registered under the Securities Exchange Act of 1934, and no market exists for the shares. Additionally, the Series B Convertible Preferred shares will automatically convert to common at any time in which the Volume Weighted Average Price (VWAP) of the common stock exceeds $3.50 per share for 20 consecutive trading days, the shares are registered with the SEC and the volume of common shares trades exceeds 200,000 shares per day. The shareholders of the Series B Convertible Preferred may vote the number of shares into which they would be entitled to convert, beginning in 2020. On December 17, 2018, the board authorized the issuance of 59,416 shares of Series B Convertible Preferred shares, valued at $594,613, for the outstanding dividends as Paid-In-Kind shares. At December 31, 2018, the shares were outstanding but not issued. No cash was used to pay dividends on Series B preferred shares in 2018. |
NOTE 9 - COMMON STOCK |
12 Months Ended |
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Dec. 31, 2018 | |
Stockholders' Equity Note [Abstract] | |
Stockholders' Equity Note Disclosure [Text Block] | NOTE 9 - COMMON STOCK In November 2015, Royale entered in a securities purchase agreement and related agreements with ten investors. Under the terms of the agreement, the investors purchased 497,740 shares of Royale’s common stock at $0.408 per share and received warrants to purchase up to 248,873 shares (the “Warrants’) of stock at $1.00 per share for three (3) years, for a total of $203,080 in gross proceeds. In April 2016, Royale entered in a securities purchase agreement and related agreements with one investor. Under the terms of the agreement, the investor purchased 622,316 shares of Royale’s common stock at $0.3214 per share, and received warrants to purchase up to 311,158 shares (the “Warrants’) of stock at $0.5356 per share for three (3) years, for a total of $200,000 in gross proceeds. In July 2016, Royale entered in securities purchase agreements and related agreements with three investors. Under the terms of the agreement, the investors purchased 2,392,500 shares of Royale’s common stock at $0.40 per share, and received warrants to purchase up to 478,500 shares (the “Warrants’) of stock at $0.80 per share for two (2) years, for a total of $957,000 in gross proceeds. On April 13, 2018, Royale Energy, Inc., and two of Royale’s subsidiaries, Royale Energy Funds, Inc. and Matrix Oil Management Corporation (the “Royale Entities”) completed the Subscription and Contribution Agreement (“Contribution Agreement”), in which the Royale Entities and CIC RMX LP (“CIC”) entered into the Contribution Agreement and certain other agreements providing that the Royale Entities would contribute certain assets to RMX Resources, LLC (“RMX”), a newly formed Texas limited liability company formed to facilitate the investment from CIC. As part of the agreement a warrant (“Warrant”) was issued to acquire up to 4,000,000 shares of Royale’s common stock at an exercise price of $.01 per share and registration rights pursuant to a Registration Rights Agreement. See Note 2 for full discussion. |
NOTE 10 - OPERATING LEASES |
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Commitments Disclosure [Text Block] | NOTE 10 - OPERATING LEASES Royale Energy occupies office space through the use of certain leases, one for their office in El Cajon, CA and one for an office and yard in Woodland, CA. The El Cajon lease is under a 62 month lease contract, with a yearly increase of 3.5%, which expires in January 2020. The El Cajon lease calls for monthly payments ranging from $6,148 to $10,801, and the Woodland lease calls for monthly payments of $500. Royale rents an office and yard in Woodland, CA on a month-to-month basis that currently calls for monthly payments of $500. Additionally, Royale has assumed the use of and responsibility for the payments under a lease for an office space in Santa Barbara, CA. The Santa Barbara lease calls for monthly payments of $7,843, through expiration in September 2019. The Company is currently in discussion to extend the term in exchange for a reduction in rate and amendment name Royale as the contracting party. Rental expense for the years ended December 31, 2018 and 2017 was $210,280 and $110,909 respectively.
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NOTE 11 - RELATED PARTY TRANSACTIONS |
12 Months Ended |
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Dec. 31, 2018 | |
Related Party Transactions [Abstract] | |
Related Party Transactions Disclosure [Text Block] | NOTE 11 - RELATED PARTY TRANSACTIONS Significant Ownership Interests As of March 14, 2019, Mr. Donald H. Hosmer owned 2.69% of Royale Energy common stock (as calculated under SEC Rule 13d-3). Donald Hosmer has participated individually in 179 wells under the 1989 policy. During 2018 and 2017, Donald did not participate in fractional interests. At December 31, 2018, Royale had a payable balance of $2,994 due to Donald Hosmer for normal drilling and lease operating expenses. As of March 14, 2019, Stephen M. Hosmer owned 2.93% of Royale Energy common stock (as calculated under SEC Rule 13d-3). Stephen Hosmer has participated individually in 179 wells under the 1989 policy. During 2018 and 2017, Stephen did not participate in fractional interests. At December 31, 2018, Royale had a receivable balance of $14,706 due from Stephen Hosmer for normal drilling and lease operating expenses. At December 31, 2018, we had a total payable of $552,645 due to RMX Resources, LLC and its subsidiary, Matrix Oil Corporation, related to the ongoing transactions between the Royale Energy and RMX Resources, LLC. Of this balance, approximately $312,000 was received on behalf RMX Resources from various oil and gas customers. See related discussion in Note 17 – Subsequent Events. Prior to the Merger, Matrix had outstanding accrued unpaid guaranteed payments for unpaid salaries due to certain Matrix employees. At December 31, 2018, the balance due these employees was $1,616,205. Prior to the Merger, Matrix had outstanding long term liabilities for interest on notes payable due to certain Matrix principals. The balance due these principals at December 31, 2018, was $1,306,605. 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. |
NOTE 12 - STOCK COMPENSATION PLAN |
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Disclosure of Compensation Related Costs, Share-based Payments [Text Block] | NOTE 12 - STOCK COMPENSATION PLAN On October 10, 2018, the Company entered into an Incentive Stock Option Award Agreement with Stephen M. Hosmer, Chief Financial Officer. Mr. Hosmer was granted 250,000 options to purchase common stock at an exercise price of $0.31 per share. These options were granted for a period of 10 years and will expire after October 10, 2028. These options become vested exercisable immediately. These options were valued using the Black-Scholes methodology. The Black-Scholes assumptions were as follows: Exercise price per share, $0.31; Current stock price (as of the close on October 10, 2018) $0.34; Risk-free interest rate of 3.22%; Time to maturity of 10 years; and, Stock volatility of 66.48%. The Black-Scholes model, using the values listed above, valued each option at $0.26 making the award of $250,000 options worth $64,954. There were no other stock options issued in 2018 or 2017. A summary of the status of Royale Energy’s stock option plan as of December 31, 2018 and 2017, and changes during the years ending on those dates is presented below:
At December 31, 2018, Royale Energy’s stock price, $0.13, was less than the weighted average exercise price, and as such the outstanding and exercisable stock options had no intrinsic value. The remaining outstanding stock options have a weighted-average remaining contractual term of one year as of December 31, 2018. The Company had no non-vested stock option at December 31, 2018 or 2017. During 2018 and 2017, we recognized $64,954 and $0, respectively, in compensation costs for the vested stock options. The company will incur no future expense related to these options. |
NOTE 13 - SIMPLE IRA PLAN |
12 Months Ended |
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Dec. 31, 2018 | |
Retirement Benefits [Abstract] | |
Pension and Other Postretirement Benefits Disclosure [Text Block] | NOTE 13 - SIMPLE IRA PLAN In April 1998, the Company established a Simple IRA pension plan covering all employees. The Company will contribute a matching contribution to each eligible employee’s Simple IRA equal to the employee’s salary reduction contributions up to a limit of 3% of the employee’s compensation for the year. The employer contribution for the years ending December 31, 2018 and 2017, were $35,312 and $28,947 respectively. |
NOTE 14 - ENVIRONMENTAL MATTERS |
12 Months Ended |
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Dec. 31, 2018 | |
Environmental Remediation Obligations [Abstract] | |
Environmental Loss Contingency Disclosure [Text Block] | NOTE 14 - ENVIRONMENTAL MATTERS Royale Energy has established procedures for the continuing evaluation of its operations to identify potential environmental exposures and assure compliance with regulatory policies and procedures. Management monitors these laws and regulations and periodically assesses the propriety of its operational and accounting policies related to environmental issues. The nature of Royale Energy’s business requires routine day-to-day compliance with environmental laws and regulations. Royale Energy incurred no material environmental investigation, compliance and remediation costs in 2018 or 2017. Royale Energy is unable to predict whether its future operations will be materially affected by these laws and regulations. It is believed that legislation and regulations relating to environmental protection will not materially affect the results of operations of Royale Energy. |
NOTE 15 - CONCENTRATIONS OF CREDIT RISK |
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Dec. 31, 2018 | |
Risks and Uncertainties [Abstract] | |
Concentration Risk Disclosure [Text Block] | NOTE 15 - CONCENTRATIONS The Company bids its gas sales on a month to month basis and generally sells to a single customer without commitment to future gas sales to any particular customer. The Company normally sells approximately 32% of its monthly natural gas production to one customer on a month to month basis. Since we are able to sell our natural gas to other readily available customers, the loss of any one customer would not have an adverse effect on our overall sales operations. The Company maintains cash in depository institutions that are guaranteed by the Federal Deposit Insurance Corporation (FDIC) up to $250,000 per institution for our interest bearing accounts in the years ended December 31, 2018, and 2017. At December 31, 2016, and 2015, the Company’s non-interest bearing accounts were fully insured by the FDIC. At December 31, 2018 and 2017, cash in banks exceeded the FDIC limits by approximately $5.7 million and $2.8 million, respectively. The Company has not experienced any losses on deposits. |
NOTE 16 - COMMITMENTS AND CONTINGENCIES |
12 Months Ended |
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Dec. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies Disclosure [Text Block] | NOTE 16 - COMMITMENTS AND CONTINGENCIES The Company may become involved from time to time in litigation on various matters, which are routine to the conduct of its business. The Company believes that none of these actions, individually or in the aggregate, will have a material adverse effect on its financial position or results of operations, though any adverse decision in these cases or the costs of defending or settling such claims could have a material effect on its business. The Company 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. The contracts require the participants pay Royale the full contract price upon execution of the agreement. Royale typically begins the drilling activities within 12 months of funding and reaches total depth between 10 and 30 days after drilling begins. |
NOTE 17 - SUBSEQUENT EVENTS |
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Dec. 31, 2018 | |
Subsequent Events [Abstract] | |
Subsequent Events [Text Block] | NOTE 17 - SUBSEQUENT EVENTS Settlement Agreement and Well Participation Agreement with RMX On March 11, 2019 Royale entered into a Settlement Agreement with RMX Resources to resolve differences resulting from the calculation of certain post-closing amounts as called for under Section 7.3 of the Subscription and Contribution Agreement. Under the terms of this provision, Royale estimates that it may owe RMX approximately $552,645 related to its calculation of this post-closing amount under this provision. In addition, there are other disputed amounts related to certain joint owner billing amounts remaining unpaid at year end. In settlement of these differences, Royale has agreed to assign its remaining interests in the Bellevue Field, located in Kern County and the W. Whittier Field located in Los Angeles County, California to RMX. At December 31,2018, the Bellevue and W. Whittier fields accounted for 5.145 and 140.647 Mboe in reserves and were valued at $67,671 and $2.4 million, respectively using SEC pricing and discounted at 10 percent. Royale will continue to be responsible for the liability for the payment of all royalties and suspended funds incurred prior to March 1, 2018. As part of this Settlement Agreement, RMX will offer Royale the right, but not the obligation to participate in a number of wells to be drilled in the Sansinena, Sempra, Whittier and/or East LA properties in Los Angeles County, California at an offered working interest up to 75% of RMX’s working interest in each of the offered wells. The minimum number of wells to be offered to Royale in each year is 2 net wells as determined by an agreed upon methodology. The Agreement also calls for certain credits toward future drilling costs of the offered wells. Settlement with Sunny Frog Matrix Oil Company (“MOC” or “Matrix”) operated the Sansinena Field and the East LA Fields. Sunny Frog Oil, LLC (“Sunny Frog”) was a non-operator working interest participant in these fields. During the merger negotiations with Matrix Oil, LLC held during 2017, Royale entered into a purchase and sales agreement with Sunny Frog for the purchase of their 50% interest in the Sansinena and East La Fields on November 27, 2017. After Matrix completed the merger with Royale during March of 2018, it then committed to sell or contributed the Sansinena Field to the RMX joint venture along with certain other properties in April of 2018. In addition, Royale contributed it right to purchase the Sunny Frog interests in the Sansinena and East LA Fields to the RMX joint venture. On April 4, 2018, RMX closed with Sunny Frog for all of their interests in the Sansinena and East LA Fields. Subsequent to the closing by RMX of the properties with Sunny Frog, Sunny Frog commissioned an audit of the joint accounts during the period that MOC operated the properties. The audit report reflected a large balance due Sunny Frog from MOC. (MOC became part of RMX following the contribution of assets by Royale in early April.) Pursuant to Section 14.2 of the Purchase Agreement, RMX was to deliver any objections to the Preliminary Settlement Statement within 120 days following the closing Date. RMX did not tender its objections to the audit within the proscribed 120-day time limit. In addition, subsequent to the audit, other matters of controversy arose between Sunny Frog and RMX. On February 11, 2019, a settlement and release agreement was entered into by Sunny Frog and RMX whereby RMX agreed to pay $75,000 to settle any and all differences between MOC and Sunny Frog. This settlement includes any liabilities payable by Royale. Royale has reviewed its accounts and made any required adjustments. Issuance of Common Stock During the first quarter of 2019, in lieu of cash payments for salaries, fees or incentives, Royale issued 989,966 shares of its Common stock valued at approximately $240,008 to various employees, officers and board members. |
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) |
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Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Oil and Gas Exploration and Production Industries Disclosures [Text Block] | NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) The following estimates of proved oil and gas reserves, both developed and undeveloped, represent interests owned by Royale Energy which are located solely in the United States. Proved reserves represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate to be reasonably certain to be recoverable in the future from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells, with existing equipment and operating methods. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which relatively major expenditures are required for completion. Disclosures of oil and gas reserves, which follow, are based on estimates prepared by independent petroleum engineering consultant Netherland, Sewell & Associates, Inc., the net reserve value of its proved developed and undeveloped reserves was approximately $57.8 million at December 31, 2018, based on the average Henry Hub natural gas price spot price of $3.10 per MCF and for oil volumes, the average West Texas Intermediate price of $65.56 per barrel as applied on a field-by-field basis. Netherland, Sewell & Associates, Inc. provided reserve value information for the Company’s California, Texas, Oklahoma, Utah and Louisiana properties. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. These estimates do not include probable or possible reserves. The technical persons responsible for preparing the reserves estimates presented in the report of Netherland, Sewell & Associates, Inc., meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Netherland, Sewell & Associates, Inc. is a firm of independent petroleum engineers, geologists, geophysicists, and petrophysicists; and do not own an interest in our properties and are not employed on a contingent basis. All activities and reports performed and completed by Netherland, Sewell & Associates, Inc. with regards to our reserve valuation estimates are reviewed Royale’s management. These estimates are furnished and calculated in accordance with requirements of the Financial Accounting Standards Board and the Securities and Exchange Commission (SEC). Because of unpredictable variances in expenses and capital forecasts, crude oil and natural gas price changes, largely influenced and controlled by U.S. and foreign government actions, and the fact that the bases for such estimates vary significantly, management believes the usefulness of these projections is limited. Estimates of future net cash flows presented do not represent management’s assessment of future profitability or future cash flows to Royale Energy. Management’s investment and operating decisions are based upon reserve estimates that include proved reserves prescribed by the SEC as well as probable reserves, and upon different price and cost assumptions from those used here. It should be recognized that applying current costs and prices and a 10 percent standard discount rate does not convey absolute value. The discounted amounts arrived at are only one measure of the value of proved reserves. Changes in Estimated Reserve Quantities The net interest in estimated quantities of proved developed reserves of crude oil and natural gas at December 31, 2018 and 2017, and changes in such quantities during each of the years then ended, were as follows:
At December 31, 2018, our previously estimated proved developed and undeveloped natural gas reserve quantities were revised downward by approximately 401,498 MCF of natural gas. This downward revision was mainly the result of one California location which had proved undeveloped reserves 333,524 MCF of natural gas at December 31, 2017, which the Company has decided not to drill. At December 31, 2018, our previously estimated proved developed and undeveloped oil reserve quantities were revised downward by approximately 79,135 BBL of oil. This downward revision was mainly the result of a Texas field acquired during the Matrix merger which had 81,054 BBL of oil lower proved developed producing reserves than originally estimated at the time of the merger. For December 31, 2017, our previously estimated proved developed and undeveloped reserve quantities were revised upward by approximately 307,371 MCF of natural gas. This upward revision reflected higher than previously estimated proved producing and non-producing natural gas reserves at eight California wells and one Utah well. A location which had 63,350 MCF in proved developed reserves at December 31, 2016, was drilled and began in 2011, was revised upward 122,998 MCF at December 31, 2017. Two locations which had 128,165 MCF in proved developed reserves at December 31, 2016, were drilled and began producing prior to 2000, were revised upward 118,006 MCF at December 31, 2017. A location which was drilled and began producing in 2010, which had proved developed reserves of 618,709 was revised upward 15,227 MCF at December 31, 2017. A location in Utah which was drilled and began producing in 2006, was revised upward 14,688 MCF at December 31, 2017. A location which was drilled and began producing in 2012, had no proved developed reserves at December 31, 2016, was revised upward 10,994 MCF at December 31, 2017. A location which was drilled and began producing in 2008, had proved developed reserves of 13,878 at December 31, 2016, was revised upward 6,084 MCF at December 31, 2017. A location which had proved undeveloped reserves of 314,925 MCF at December 31, 2016, was revised upward 18,598 MCF at December 31, 2017. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves The future net cash inflows are developed as follows:
The resulting future net revenue streams are reduced to present value amounts by applying a ten percent discount. Disclosure of principal components of the standardized measure of discounted future net cash flows provides information concerning the factors involved in making the calculation. In addition, the disclosure of both undiscounted and discounted net cash flows provides a measure of comparing proved oil and gas reserves both with and without an estimate of production timing. The standardized measure of discounted future net cash flow relating to proved reserves reflects estimated income taxes. Changes in standardized measure of discounted future net cash flow from proved reserve quantities The standardized measure of discounted future net cash flows is presented below for the years ended December 31, 2018 and 2017. This statement discloses the sources of changes in the standardized measure from year to year. The amount reported as “Net changes in prices and production costs” represents the present value of changes in prices and production costs multiplied by estimates of proved reserves as of the beginning of the year. The “accretion of discount” was computed by multiplying the ten percent discount factor by the standardized measure on a pretax basis as of the beginning of the year. The “Sales of oil and gas produced, net of production costs” are expressed in actual dollar amounts. “Revisions of previous quantity estimates” is expressed at year-end prices. The “Net change in income taxes” is computed as the change in present value of future income taxes.
Future Development Costs In order to realize future revenues from our proved reserves estimated in our reserve report, it will be necessary to incur future costs to develop and produce the proved reserves. The following table estimates the costs to develop and produce our proved reserves in the years 2019 through 2021.
Common assumptions include such matters as the real extent and average thickness of a particular reservoir, the average porosity and permeability of the reservoir, the anticipated future production from existing and future wells, future development and production costs and the ultimate hydrocarbon recovery percentage. As a result, oil and gas reserve estimates and discounted present value estimates are frequently revised in subsequent periods to reflect production data obtained after the date of the original estimate. If the reserve estimates are inaccurate, production rates may decline more rapidly than anticipated, and future production revenues may be less than estimated. Additional data relating to Royale Energy’s oil and natural gas properties is disclosed in Supplemental Information About Oil and Gas Producing Activities (Unaudited), attached to Royale Energy’s Financial Statements, beginning on page F-1. Historic Development Costs for Proved Reserves In each year we expend funds to drill and develop some of our proved undeveloped reserves. The following table summarizes our historic costs incurred in each of the past three fiscal years to drill and develop reserves that were classified as proved undeveloped reserves as of December 31 of the immediately preceding year:
RMX Resources, LLC Royale has a 20% interest in RMX Resources, LLC, as described in NOTE 2- Merger with Matrix Oil Management Corporation and Formation of RMX. The estimates listed below of proved oil and gas reserves and revenues, both developed and undeveloped represent the gross volume attributable to RMX as a whole and to the 20 percent interest of RMX held by Royale. The reserve values were prepared by independent petroleum engineering consultants Netherland, Sewell & Associates, Inc. These estimates do not include probable or possible reserves and revenue and are presented on the same bases as that of Royale. RMX is not subject to U.S. Federal or state income taxes related to crude oil and natural gas production. RMX has elected to be taxed as a partnership; therefore, the reserve information provided below does not consider Federal or state income taxes.
Changes in Standardized measure of discounted future net cash flow from proved reserve quantities This statement discloses the sources of changes in the standardized measure from year to year. The amount reported as “Net changes in prices and production costs” represents the present value of changes in prices and production costs multiplied by estimates of proved reserves as of the beginning of the year. The “accretion of discount” was computed by multiplying the ten percent discount factor by the standardized measure on a pretax basis as of the beginning of the year. The “Sales of oil and gas produced, net of production costs” are expressed in actual dollar amounts. “Revisions of previous quantity estimates” is expressed at year-end prices. Because RMX was formed in April of 2018, this analysis only provides the reserve information as of year-end without a comparison and reciliation to a beginning reserve report.
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Accounting Policies, by Policy (Policies) |
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Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Basis of Accounting, Policy [Policy Text Block] | 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. |
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Use of Estimates, Policy [Policy Text Block] | Use of Estimates The accompanying financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America and requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 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. |
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Liquidity and Going Concern [Policy Text Block] | Liquidity and Going ConcernThe 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. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block] | 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.
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Investment, Policy [Policy Text Block] | 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. |
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Revenue Recognition, Policy [Policy Text Block] | 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. |
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Oil and Gas Properties Policy [Policy Text Block] | 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. |
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Receivables, Policy [Policy Text Block] | 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. |
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Trade and Other Accounts Receivable, Policy [Policy Text Block] | 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. |
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Property, Plant and Equipment, Policy [Policy Text Block] | Equipment and Fixtures Equipment and fixtures are stated at cost and depreciated over the estimated useful lives of the assets, which range from three to seven years, using the straight-line method. Repairs and maintenance are charged to expense as incurred. When assets are sold or retired, the cost and related accumulated depreciation are removed from the accounts and any resulting gain or loss is included in income. Maintenance and repairs, which neither materially add to the value of the property nor appreciably prolong its life, are charged to expense as incurred. Gains or losses on dispositions of property and equipment, other than oil and gas, are reflected in operations. |
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Earnings Per Share, Policy [Policy Text Block] | Income (Loss) Per Share Basic and diluted losses per share are calculated as follows:
For the year ended December 31, 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. |
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Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block] | 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. |
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Income Tax, Policy [Policy Text Block] | Income Taxes Royale utilizes the asset and liability approach to measure deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates in accordance with the Income Taxes Topic of the 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. |
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Fair Value Measurement, Policy [Policy Text Block] | Fair Value Measurements According to Fair Value Measurements and Disclosures Topic of the FASB Accounting Standards Codification, assets and liabilities that are measured at fair value on a recurring and nonrecurring basis in period subsequent to initial recognition, the reporting entity shall disclose information that enable users of its financial statements to assess the inputs used to develop those measurements and for recurring fair value measurements using significant unobservable inputs, the effect of the measurements on earnings for the period. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. In determining fair value, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible as well as considers counterparty credit risk in its assessment of fair value. Carrying amounts of the Company’s financial instruments, including cash equivalents, accounts receivable, accounts payable and accrued liabilities, approximate their fair values as of the balance sheet dates because of their generally short maturities. The fair value hierarchy distinguishes between (1) market participant assumptions developed based on market data obtained from independent sources (observable inputs) and (2) an entity’s own assumptions about market participant assumptions developed based on the best information available in the circumstances (unobservable inputs). The fair value hierarchy consists of three broad levels, which gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy are described below: Level 1: Quoted prices (unadjusted) in active markets that are accessible at the measurement date for assets or liabilities. Level 2: Directly or indirectly observable inputs as of the reporting date through correlation with market data, including quoted prices for similar assets and liabilities in active markets and quoted prices in markets that are not active. Level 2 also includes assets and liabilities that are valued using models or other pricing methodologies that do not require significant judgment since the input assumptions used in the models, such as interest rates and volatility factors, are corroborated by readily observable data from actively quoted markets for substantially the full term of the financial instrument. Level 3: Unobservable inputs that are supported by little or no market activity and reflect the use of significant management judgment. These values are generally determined using pricing models for which the assumptions utilize management’s estimates of market participant assumptions At December 31, 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. |
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Accounts Payable and Accrued Expenses [Policy Text Block] | Accounts Payable and Accrued ExpensesAt December 31, 2018 and 2017, the components of accounts payable and accrued expenses consisted of: 2018 2017 Trade Payables including accruals $2,589,518 $2,392,755 Direct working interest investors related accruals 1,223,588 688,002 Current drilling efforts accrued expenses 413,701 483,734 Legal Settlement Payable - 438,667 Accrued Liabilities 391,641 266,110 Employee related accruals 232,010 93,619 Interest payable on cash advances - 223,833 Deferred rent 32,752 35,036 Federal and State income taxes payable 12,323 17,123 $4,895,533 $4,638,879 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accrued Liabilitites Policy [Policy Text Block] | Accrued Liabilities – Long TermPrior 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 Guaranteed Payments Policy [Policy Text Block] | Accrued Unpaid Guaranteed PaymentsPrior 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. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Current Liabilities [Policy Text Block] | Cash Advances on Pending TransactionsIn July 2016, we received a cash investment of $1,580,000 from two investors to purchase convertible promissory notes of $1,280,000 and $300,000, with a conversion price of $0.40 per share, with warrants to purchase one share of common stock for every three shares of common stock issuable upon conversion of the notes. The funds from these transactions were used to continue drilling activities, fund expenses incurred in connection with the completion of Royale Energy’s merger with Matrix Oil Corporation and for general corporate purposes. The notes originally matured on August 2, 2017, one year from the date of issuance, and carried a 10% interest rate, with a default rate of 25%. Shortly before completion of the Merger, the $300,000 note was converted into 750,000 shares of Royale common stock, and Royale agreed to a cash settlement with the holder of the $1,280,000 note for $1,900,000. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reclassification, Policy [Policy Text Block] | 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. |
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Business Combinations Policy [Policy Text Block] | 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. |
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Goodwill and Intangible Assets, Goodwill, Policy [Policy Text Block] | 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. |
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New Accounting Pronouncements, Policy [Policy Text Block] | 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. 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 ASU 2017-01: Business Combinations–Clarifying the Definition of a Business In January 2017, the FASB issued a new accounting standards update that changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities constitutes a business. The guidance requires us to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities would not represent a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described in the new revenue guidance. This standard was effective for us in the first quarter of 2018, and was applied prospectively. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows. ASU 2016-18: Statement of Cash Flow-Restricted Cash (ASC-230-10-50-8) In November 2016, the FASB issued a new accounting standards update that requires entities to show the changes in the total of cash, cash equivalents and restricted cash in the statement of cash flows. As a result, we no longer present transfers between cash and cash equivalents and restricted cash in the statement of cash flows. When cash, cash equivalents, and restricted cash are presented in more than one line item on the balance sheet, the standard requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. This reconciliation can be presented either on the face of the statement of cash flows or in the notes to the financial statements. Royale has adopted this new ASU 2016-18 with the reporting of year-end financials. This standard requires Royale to show cash received specifically for drilling operations separately on the balance sheet as Restricted Cash. See note above. We also adopted the following ASUs during 2018, none of which had a material impact to our financial statements or financial statement disclosures:
Not Yet Adopted ASU 2018-02, Reporting Comprehensive Income – Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income In February 2018, the FASB issued an ASU allowing an entity the choice to retained earnings the tax effects related to the TCJA that are stranded in accumulated other comprehensive income. We do not expect adoption of this standard to have a material impact on our financial statements. The amendment is effective beginning in 2019. ASU 2017-12, Derivatives and hedging – Targeted Improvement to Accounting for Hedging Activities In August 2017, the FASB issued an ASU to amend the hedge accounting rules to simplify the application of hedge accounting guidance and better portray the economic results of risk management activities in the financial statements. The guidance expands the ability to hedge nonfinancial and financial risk components, reduces complexity in fair value hedges of interest rate risk, eliminates the requirements to separately measure and report hedge ineffectiveness and eases certain hedge effectiveness assessment requirements. The guidance is effective beginning in 2019. We are currently evaluating the impact of this guidance, including transition elections and required disclosures, on our financial statements and the timing of adoption. However, since we have not historically used derivatives to hedge our commodity price risk, we do not expect adoption of this ASU to have a material impact on our consolidated financial statements. ASU 2016-13, Credit Losses – Measurement of Credit Losses on Financial Instruments In June 2016, the FASB issued an ASU related to the accounting for credit losses on certain financial instruments. The guidance requires that for most financial assets, losses be based on an expected loss approach which includes estimates of losses over the life of exposures that considers historical, current and forecasted information. Expanded disclosures related to the methods used to estimate the losses as well as a specific disaggregation of balances for financial assets are also required. The change is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. We do not expect application of this ASU to have a material impact on our consolidated financial statements. ASU 2016-02 and 2018-11, Leases In February 2016, the FASB issued an ASU requiring lessees to record virtually all leases on their balance sheet. The ASU also requires expanded disclosures to help financial statement users better understand the amount, timing and uncertainty of cash flow arising from leases. For Lessors, this amended guidance modifies the classification criteria and the accounting for sales-type and direct financing leasers. The guidance will be effective for fiscal years beginning after December 15, 2018, and interim periods within those years. We will transition to the new guidance by recording leases on our balance sheet as of January 1, 2019. We continue to evaluate the impact of this standard on our financial statements, disclosures, internal controls and accounting policies. This evaluation process includes reviewing all forms of leases, performing a completeness assessment over the lease population and analyzing the practical expedients in order to determine the best path of implementing changes to existing processes and controls. We believe the adoption of the standard will have a material impact on our consolidated financial statements as virtually all leases will be recognized as a right of use asset and lease obligation. |
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) |
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Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Cash and Cash Equivalents [Table Text Block] |
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.
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Disaggregation of Revenue [Table Text Block] |
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.
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Schedule of Earnings Per Share, Basic and Diluted [Table Text Block] |
Basic and diluted losses per share are calculated as follows:
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Schedule of Accounts Payable and Accrued Liabilities [Table Text Block] |
At December 31, 2018 and 2017, the components of accounts payable and accrued expenses consisted of:
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Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block] |
We also adopted the following ASUs during 2018, none of which had a material impact to our financial statements or financial statement disclosures:
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NOTE 2 - MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Tables) |
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Business Combinations [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block] |
The following table summarizes the consideration transferred, fair value of assets acquired and liabilities assumed:
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Business Acquisition, Pro Forma Information [Table Text Block] |
In accordance with FASB Topic ASC 805, the following unaudited supplemental pro forma condensed results of operations present combined information as though the business combination had been completed as of January 1, 2018. The unaudited supplemental pro forma financial information was derived from the historical revenues and direct operating expenses of Royale Energy, Inc. and Matrix Oil Management Corporation and its affiliates. These unaudited supplemental pro forma results of operations for the consolidated companies as of December 31, 2018, are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the consolidated company for the periods presented or that may be achieved by the consolidated company in the future.
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Business Combination, Separately Recognized Transactions [Table Text Block] |
Amounts previously estimated have changed during the measurement period. The changes in estimates included an increase of $2,581,641 of oil and gas properties and a decrease of $2,581,641 in accounts receivable and other current assets. We recorded measurement-period adjustments in the fourth quarter of 2018. Depletion expense increased by an immaterial amount as a result of these measurement-period adjustments and all amounts referenced below are inclusive of these measurement period adjustments. As of December 31, 2018, the purchase accounting for the Matrix acquisition was complete.
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Equity Method Investments [Table Text Block] |
Listed below is the summarized information required under Rule 3-09 of regulation S-X, Article 10 for Royale’s investment in RMX:
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NOTE 3 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Tables) |
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Oil and Gas Property [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Property, Plant and Equipment [Table Text Block] |
Oil and gas properties, equipment and fixtures consist of the following at December 31:
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Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block] |
The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed at December 31:
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Capitalized Exploratory Well Costs, Roll Forward [Table Text Block] |
Undeveloped properties are not subject to depletion, depreciation or amortization.
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Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block] |
The results of operations from oil and gas producing and exploration activities (excluding corporate overhead and interest costs) are as follows:
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NOTE 4 - ASSET RETIREMENT OBLIGATION (Tables) |
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Schedule of Change in Asset Retirement Obligation [Table Text Block] |
The Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification requires that an asset retirement obligation (ARO) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset. The ARO is recorded at fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value. The fair value of the ARO is measured using expected future cash outflows discounted at the Company’s credit-adjusted risk-free interest rate. The provisions of this Topic apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, development, and operation of a long-lived asset.
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NOTE 7 - INCOME TAXES (Tables) |
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Schedule of Deferred Tax Assets and Liabilities [Table Text Block] |
Significant components of the Company’s deferred assets and liabilities at December 31, 2018 and 2017, respectively, are as follows:
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Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] |
A reconciliation of Royale Energy’s provision for income taxes and the amount computed by applying the statutory income tax rates at December 31, 2018 and 2017, respectively, to pretax income is as follows:
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Schedule of Components of Income Tax Expense (Benefit) [Table Text Block] |
The components of the Company’s tax provision are as follows:
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NOTE 10 - OPERATING LEASES (Tables) |
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Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block] |
Royale Energy occupies office space through the use of certain leases, one for their office in El Cajon, CA and one for an office and yard in Woodland, CA. The El Cajon lease is under a 62 month lease contract, with a yearly increase of 3.5%, which expires in January 2020. The El Cajon lease calls for monthly payments ranging from $6,148 to $10,801, and the Woodland lease calls for monthly payments of $500. Royale rents an office and yard in Woodland, CA on a month-to-month basis that currently calls for monthly payments of $500. Additionally, Royale has assumed the use of and responsibility for the payments under a lease for an office space in Santa Barbara, CA. The Santa Barbara lease calls for monthly payments of $7,843, through expiration in September 2019. The company is currently in discussion to extend the term in exchange for a reduction in rate and amendment name Royale as the contracting party. Rental expense for the years ended December 31, 2018 and 2017 was $210,280 and $110,909 respectively.
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NOTE 12 - STOCK COMPENSATION PLAN (Tables) |
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Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Share-based Compensation, Stock Options, Activity [Table Text Block] |
A summary of the status of Royale Energy’s stock option plan as of December 31, 2018 and 2017, and changes during the years ending on those dates is presented below:
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NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables) |
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NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables) [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block] |
The net interest in estimated quantities of proved developed reserves of crude oil and natural gas at December 31, 2018 and 2017, and changes in such quantities during each of the years then ended, were as follows:
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Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block] |
The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed at December 31:
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Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block] |
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Proved Undeveloped Reserves [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables) [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block] |
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Proved Developed, Proved Non-Producing and Proved Undeveloped Reserves [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables) [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Future Development Costs, Oil and Gas Production [Table Text Block] |
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NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - Schedule of Cash and Cash Equivalents - USD ($) |
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
---|---|---|---|
Schedule of Cash and Cash Equivalents [Abstract] | |||
Cash and cash equivalents | $ 1,853,742 | $ 278,227 | |
Restricted cash | 4,501,300 | 3,060,466 | |
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows | $ 6,355,042 | $ 3,338,693 | $ 4,994,598 |
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - Disaggregation of Revenue - USD ($) |
12 Months Ended | |
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Dec. 31, 2018 |
Dec. 31, 2017 |
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Disaggregation of Revenue [Line Items] | ||
Revenues | $ 3,283,041 | $ 1,007,379 |
Oil [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenues | 1,211,818 | 4,703 |
Natural Gas [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenues | 385,803 | 549,532 |
Natural Gas Liquids [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenues | 1,741 | 0 |
Oil and Gas [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Revenues | $ 1,599,362 | $ 554,235 |
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - Schedule of Earnings Per Share, Basic and Diluted - USD ($) |
12 Months Ended | |
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Dec. 31, 2018 |
Dec. 31, 2017 |
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Schedule of Earnings Per Share, Basic and Diluted [Abstract] | ||
Net Loss | $ (23,504,327) | $ (2,427,169) |
Less: Preferred Stock Dividend | 594,613 | 0 |
Less: Preferred Stock Dividend in Arrears | 0 | 0 |
Net Loss Attributable to Common Shareholders | $ (24,098,940) | $ (2,427,169) |
Weighted average common shares outstanding (in Shares) | 44,174,209 | 21,836,975 |
Weighted average common shares outstanding (in Shares) | 44,174,209 | 21,836,975 |
Effect of dilutive securities | $ 0 | $ 0 |
Effect of dilutive securities (in Shares) | 0 | 0 |
Weighted average common shares, including Dilutive effect (in Shares) | 44,174,209 | 21,836,975 |
Weighted average common shares, including Dilutive effect (in Shares) | 44,174,209 | 21,836,975 |
Net Loss (in Dollars per share) | $ (0.55) | $ (0.11) |
Net Loss (in Dollars per share) | $ (0.55) | $ (0.11) |
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - Schedule of Accounts Payable and Accrued Liabilities - USD ($) |
Dec. 31, 2018 |
Dec. 31, 2017 |
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Schedule of Accounts Payable and Accrued Liabilities [Abstract] | ||
Trade Payables including accruals | $ 2,589,518 | $ 2,392,755 |
Direct working interest investors related accruals | 1,223,588 | 688,002 |
Current drilling efforts accrued expenses | 413,701 | 483,734 |
Legal Settlement Payable | 0 | 438,667 |
Accrued Liabilities | 391,641 | 266,110 |
Employee related taxes and accruals | 232,010 | 93,619 |
Interest payable on cash advances | 0 | 223,833 |
Deferred rent | 32,752 | 35,036 |
Federal and State income taxes payable | 12,323 | 17,123 |
$ 4,895,533 | $ 4,638,879 |
NOTE 2 - MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) - Schedule of Recognized Identified Assets Acquired and Liabilities Assumed - USD ($) |
Mar. 07, 2018 |
Dec. 31, 2018 |
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Consideration: | ||
Value of Stock issued | $ 9,546,068 | |
Total consideration | 29,670,068 | |
Fair Value of Liabilities Assumed: | ||
Current liabilities | 19,624,592 | |
Other liabilities | 3,125,394 | |
Asset Retirement obligations | 1,419,544 | |
Total fair value of liabilities assumed | 24,169,530 | |
Cash | 548,805 | $ 548,805 |
Current assets | 1,073,532 | |
Proved and unproved crude oil and gas properties | 51,214,512 | $ 51,214,512 |
Land | 1,002,750 | |
Total consideration plus liabilities assumed | 53,839,598 | |
Series B Preferred Stock [Member] | ||
Consideration: | ||
Value of Stock issued | $ 20,124,000 |
NOTE 2 - MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) - Business Combination, Separately Recognized Transactions - USD ($) |
Dec. 31, 2018 |
Mar. 07, 2018 |
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Business Combination, Separately Recognized Transactions [Line Items] | ||
Cash | $ 548,805 | $ 548,805 |
Current assets | 1,073,532 | |
Oil and gas properties | 51,214,512 | $ 51,214,512 |
Scenario, Adjustment [Member] | ||
Business Combination, Separately Recognized Transactions [Line Items] | ||
Current assets | (2,581,641) | |
Oil and gas properties | 2,581,641 | |
Previously Reported [Member] | ||
Business Combination, Separately Recognized Transactions [Line Items] | ||
Cash | 548,805 | |
Current assets | 3,655,173 | |
Oil and gas properties | $ 48,632,870 |
NOTE 2 - MERGER WITH MATRIX OIL MANAGEMENT CORPORATION AND FORMATION OF RMX (Details) - Equity Method Investments |
9 Months Ended |
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Dec. 31, 2018
USD ($)
| |
RMX Resources, LLC [Member] | |
Balance Sheet: | |
Total Assets | $ 14,351,652 |
Total Liabilities | 7,767,722 |
Members Equity | 6,583,931 |
Results of Operations: | |
Net Operating Revenue | 1,754,732 |
Loss from Continuing Operations | (36,293) |
Net Loss | 333,931 |
RMX Resources, LLC [Member] | |
Balance Sheet: | |
Total Assets | 71,758,262 |
Total Liabilities | 38,838,608 |
Members Equity | 32,919,654 |
Results of Operations: | |
Net Operating Revenue | 8,773,661 |
Loss from Continuing Operations | (181,464) |
Net Loss | $ 1,669,654 |
NOTE 3 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Details) - Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure - USD ($) |
12 Months Ended | |
---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
|
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Abstract] | ||
Acquisition – Proved | $ 0 | $ 0 |
Acquisition- Unproved | 0 | 0 |
Development | 3,838,998 | 4,525,452 |
Exploration | $ 0 | $ 0 |
NOTE 3 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Details) - Capitalized Exploratory Well Costs, Roll Forward - USD ($) |
12 Months Ended | |
---|---|---|
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Capitalized Exploratory Well Costs, Roll Forward [Abstract] | ||
Beginning balance at January 1 | $ 0 | $ 0 |
Additions to capitalized exploratory well costs pending the determination of proved reserves | 0 | 0 |
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves | 0 | 0 |
Ending balance at December 31 | $ 0 | $ 0 |
NOTE 3 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Details) - Results of Operations for Oil and Gas Producing Activities Disclosure - USD ($) |
12 Months Ended | |
---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
|
Results of Operations for Oil and Gas Producing Activities Disclosure [Abstract] | ||
Oil and gas sales | $ 1,599,362 | $ 554,235 |
Production related costs | (1,613,368) | (435,637) |
Lease Impairment | (1,183,515) | (289,775) |
Depreciation, depletion and amortization | (722,935) | (116,017) |
Results of operations from producing and exploration activities | (1,920,456) | (287,194) |
Income Taxes (Benefit) | 0 | 0 |
Net Results | $ (1,920,456) | $ (287,194) |
NOTE 4 - ASSET RETIREMENT OBLIGATION (Details) - Schedule of Change in Asset Retirement Obligation - USD ($) |
12 Months Ended | |
---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
|
NOTE 4 - ASSET RETIREMENT OBLIGATION (Details) - Schedule of Change in Asset Retirement Obligation [Line Items] | ||
Asset retirement obligation, Beginning of the year | $ 1,000,908 | $ 952,110 |
Liabilities incurred | 595,583 | 53,142 |
Sales | (486,585) | 0 |
Accretion expense | (110,358) | (4,344) |
Asset retirement obligation, End of year | 2,366,456 | 1,000,908 |
Settlements | (52,636) | 0 |
RMX Resources, LLC [Member] | ||
NOTE 4 - ASSET RETIREMENT OBLIGATION (Details) - Schedule of Change in Asset Retirement Obligation [Line Items] | ||
Liabilities incurred | $ 1,419,544 | $ 0 |
NOTE 5 - TURNKEY DRILLING OBLIGATION (Details) - USD ($) |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Revenue from Contract with Customer [Abstract] | ||
Contract with Customer, Liability, Current | $ 6,213,283 | $ 5,891,898 |
NOTE 6 - NOTES PAYABLE (Details) - USD ($) |
Oct. 03, 2018 |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|---|
NOTE 6 - NOTES PAYABLE (Details) [Line Items] | |||
Notes Payable | $ 390,839 | $ 0 | |
Debt, Forza Operating, LCC [Member] | |||
NOTE 6 - NOTES PAYABLE (Details) [Line Items] | |||
Debt Instrument, Face Amount | $ 517,585 | ||
Debt Instrument, Interest Rate, Stated Percentage | 5.50% | ||
Debt Instrument, Frequency of Periodic Payment | 12 monthly installments | ||
Debt Instrument, Periodic Payment | $ 44,428 | ||
Oil and Gas Joint Interest Billing Receivables | 233,367 | ||
Exploration Abandonment and Impairment Expense | $ 284,218 |
NOTE 7 - INCOME TAXES (Details) - USD ($) |
12 Months Ended | |
---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
|
NOTE 7 - INCOME TAXES (Details) [Line Items] | ||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21.00% | 34.00% |
Operating Loss Carryforwards (in Dollars) | $ 19,151,810 | |
Operating Loss Carryforwards, Expiration Date | 2024 | |
Domestic Tax Authority [Member] | ||
NOTE 7 - INCOME TAXES (Details) [Line Items] | ||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21.00% | 35.00% |
NOTE 7 - INCOME TAXES (Details) - Schedule of Deferred Tax Assets and Liabilities - USD ($) |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Deferred Tax Assets (Liabilities): | ||
Statutory Depletion Carry Forward | $ 367,149 | $ 369,591 |
Net Operating Loss | 7,121,912 | 3,130,841 |
Other | 708,057 | 1,013,329 |
Share-Based Compensation | 86,510 | 69,609 |
Capital Loss / AMT Credit Carry Forward | 9,458 | 18,915 |
Charitable Contributions Carry Forward | 6,158 | 10,025 |
Allowance for Doubtful Accounts | 597,519 | 514,067 |
Oil and Gas Properties and Fixed Assets | 5,987,061 | 4,839,823 |
Investment in RMX Joint Venture | (1,247,847) | 0 |
13,635,977 | 9,966,200 | |
Valuation Allowance | (13,635,977) | (9,966,200) |
Net Deferred Tax Asset | $ 0 | $ 0 |
NOTE 7 - INCOME TAXES (Details) - Schedule of Effective Income Tax Rate Reconciliation - USD ($) |
12 Months Ended | |
---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
|
Schedule of Effective Income Tax Rate Reconciliation [Abstract] | ||
Tax (benefit) computed at statutory rate of 21% for 2018 and 34% for 2017 | $ (4,935,909) | $ (825,237) |
Meals & Entertainment | 1,320 | 0 |
Investor Incentive Expense | 7 | 0 |
Transaction Costs | 160,927 | 0 |
Loss on Warrants Issued to RMX | 302,398 | 0 |
Prior-year true-up for Books | 2,075,440 | 0 |
Deferred State Taxes, net of federal benefit | (1,009,601) | 0 |
Other non-deductible expenses | (264,359) | 1,393 |
Change in valuation allowance | 3,669,777 | 823,844 |
Provision (benefit) | $ 0 | $ 0 |
NOTE 7 - INCOME TAXES (Details) - Schedule of Effective Income Tax Rate Reconciliation (Parentheticals) |
12 Months Ended | |
---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
|
Schedule of Effective Income Tax Rate Reconciliation [Abstract] | ||
Statutory rate | 21.00% | 34.00% |
NOTE 7 - INCOME TAXES (Details) - Schedule of Components of Income Tax Expense (Benefit) - USD ($) |
12 Months Ended | |
---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
|
Schedule of Components of Income Tax Expense (Benefit) [Abstract] | ||
Current tax provision (benefit) – federal | $ 0 | $ 0 |
Current tax provision (benefit) – state | 0 | 0 |
Deferred tax provision (benefit) – federal | 0 | 0 |
Deferred tax provision (benefit) – state | 0 | 0 |
Total provision (benefit) | $ 0 | $ 0 |
NOTE 8 - SERIES B PREFERRED STOCK (Details) - Series B Preferred Stock [Member] - USD ($) |
12 Months Ended | |||
---|---|---|---|---|
Dec. 17, 2018 |
Mar. 07, 2018 |
Dec. 31, 2018 |
Mar. 06, 2018 |
|
NOTE 8 - SERIES B PREFERRED STOCK (Details) [Line Items] | ||||
Preferred Stock, Value, Issued (in Dollars) | $ 20,124,000 | |||
Preferred Stock, Shares Issued | 2,012,400 | |||
Preferred Stock, Shares Authorized | 3,000,000 | |||
Preferred Stock, Dividend Rate, Percentage | 3.50% | |||
Convertible Preferred Stock, Terms of Conversion | The Series B Convertible Preferred Stock is convertible at the option of the security holder at the rate of ten shares of common stock for one share of Series B Convertible Preferred Stock. The Series B Preferred Stock has never been registered under the Securities Exchange Act of 1934, and no market exists for the shares. Additionally, the Series B Convertible Preferred shares will automatically convert to common at any time in which the Volume Weighted Average Price (VWAP) of the common stock exceeds $3.50 per share for 20 consecutive trading days, the shares are registered with the SEC and the volume of common shares trades exceeds 200,000 shares per day. | |||
Preferred Stock Dividends, Shares | 59,416 | |||
Dividends, Preferred Stock, Paid-in-kind (in Dollars) | $ 594,613 |
NOTE 10 - OPERATING LEASES (Details) - Schedule of Future Minimum Rental Payments for Operating Leases |
Dec. 31, 2018
USD ($)
|
---|---|
Schedule of Future Minimum Rental Payments for Operating Leases [Abstract] | |
2019 | $ 217,224 |
2020 | 127,355 |
2021 | 131,602 |
2022 | 13,802 |
2023 | 0 |
Total | $ 489,983 |
NOTE 12 - STOCK COMPENSATION PLAN (Details) - Schedule of Share-based Compensation, Stock Options, Activity - $ / shares |
12 Months Ended | ||
---|---|---|---|
Oct. 10, 2018 |
Dec. 31, 2018 |
Dec. 31, 2017 |
|
Options | |||
Outstanding and Exercisable, Shares (in Shares) | 0 | 100,000 | |
Outstanding and Exercisable, Weighted Average Exercise Price | $ 0 | $ 5.00 | |
Granted or Vested, Shares (in Shares) | 250,000 | 0 | |
Granted or Vested, Weighted Average Exercise Price | $ 0.31 | $ 0.31 | $ 0 |
Exercised, Shares (in Shares) | 0 | 0 | |
Exercised, Weighted Average Exercise Price | $ 0 | $ 0 | |
Forfeited, Shares (in Shares) | 0 | (100,000) | |
Forfeited, Weighted Average Exercise Price | $ 0 | $ 0 | |
Outstanding and Exercisable, Shares (in Shares) | 250,000 | 0 | |
Outstanding and Exercisable, Weighted Average Exercise Price | $ 0.31 | $ 0 | |
Weighted-average Fair Value of Options Granted During the Year | $ 0.26 | $ 64,954 | $ 0 |
NOTE 13 - SIMPLE IRA PLAN (Details) - Pension Plan [Member] - USD ($) |
12 Months Ended | |
---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
|
NOTE 13 - SIMPLE IRA PLAN (Details) [Line Items] | ||
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent | 3.00% | |
Defined Contribution Plan, Cost | $ 35,312 | $ 28,947 |
NOTE 15 - CONCENTRATIONS OF CREDIT RISK (Details) - USD ($) |
12 Months Ended | |
---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
|
NOTE 15 - CONCENTRATIONS OF CREDIT RISK (Details) [Line Items] | ||
Cash, FDIC Insured Amount | $ 250,000 | |
Cash, Uninsured Amount | $ 5,700,000 | $ 2,800,000 |
Customer A [Member] | Customer Concentration Risk [Member] | Sales Revenue, Net [Member] | ||
NOTE 15 - CONCENTRATIONS OF CREDIT RISK (Details) [Line Items] | ||
Concentration Risk, Percentage | 32.00% |
NOTE 18 - SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure - USD ($) |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||
Total | $ 7,256,900 | ||
Cost incurred for proved undeveloped reserves | 0 | $ 0 | $ 243,583 |
Proved Developed, Proved Non-Producing and Proved Undeveloped Reserves [Member] | |||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||
2019 | 2,130,500 | ||
2020 | 1,881,500 | ||
2021 | 1,500,000 | ||
Thereafter | $ 1,744,900 |
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