ROYL 10-Q
Royale Energy, Inc. (ROYL)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
For the Quarterly Period Ended
Commission File No.
(Exact name of registrant as specified in its charter)
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| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
(Address of principal executive offices) (Zip Code)
(
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
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 of 1934 during the preceding 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.
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Check one:
| Large accelerated filer ☐ | Accelerated filer ☐ |
| | Smaller reporting company |
| 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 ☐
At August 3, 2023, a total of
TABLE OF CONTENTS
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PART I. FINANCIAL INFORMATION |
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations |
17 |
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Item 3. Quantitative and Qualitative Disclosures About Market Risk |
20 |
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20 |
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PART II. OTHER INFORMATION |
21 |
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21 |
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21 |
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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds |
21 |
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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
ROYALE ENERGY, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
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June 30, 2023 |
December 31, 2022 |
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ASSETS |
(unaudited) |
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Current Assets |
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Cash and Cash Equivalents |
$ | $ | ||||||
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Restricted Cash |
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Other Receivables, net |
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Revenue Receivables |
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Prepaid Expenses |
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Deferred Drilling Costs |
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Prepaid Drilling to RMX Resources, LLC |
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Total Current Assets |
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Right of Use Assets - Leases |
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Other Assets |
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Oil and Gas Properties, (Successful Efforts Basis), Equipment and Fixtures, net |
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Total Assets |
$ | $ | ||||||
See notes to unaudited condensed consolidated financial statements.
ROYALE ENERGY, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
| June 30, 2023 | December 31, 2022 | |||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT) | ||||||||
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Current Liabilities: |
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Accounts Payable and Accrued Expenses |
$ | $ | ||||||
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Royalties Payable |
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Due to RMX Resources, LLC |
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Accrued Liabilities |
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Asset Retirement Obligation - Current |
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Deferred Drilling Obligation |
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Operating Leases - Current |
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Total Current Liabilities |
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Noncurrent Liabilities: |
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Accrued Liabilities - Long Term |
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Accrued Unpaid Guaranteed Payments |
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Operating Leases - Long-Term |
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Asset Retirement Obligation |
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Total Liabilities |
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Mezzanine Equity: |
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| Convertible Preferred Stock, Series B, $ |
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Stockholders' Equity (Deficit): |
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| Common Stock, |
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Additional Paid in Capital |
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Accumulated Deficit |
( |
) | ( |
) | ||||
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Total Stockholders' Equity (Deficit) |
( |
) | ( |
) | ||||
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Total Liabilities and Stockholders' Equity (Deficit) |
$ | $ | ||||||
See notes to unaudited condensed consolidated financial statements.
ROYALE ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
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For the three months ended |
For the six months ended |
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| June 30, 2023 | June 30, 2022 | June 30, 2023 | June 30, 2022 | |||||||||||||
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Revenues: |
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Oil, NGL and Gas Sales |
$ | $ | $ | $ | ||||||||||||
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Supervisory Fees and Other |
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Total Revenues |
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Costs and Expenses: |
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Oil and Gas Lease Operating |
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Depreciation, Depletion and Amortization |
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Well Equipment Write Down |
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Legal and Accounting |
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Marketing |
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General and Administrative |
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Total Costs and Expenses |
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Gain (Loss) on Turnkey Drilling |
( |
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Loss From Operations |
( |
) | ( |
) | ( |
) | ( |
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Other Income (Expense): |
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Interest Expense |
( |
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) | ( |
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Gain on Settlement of Accounts Payable |
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Other Gain |
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Loss Before Income Tax Expense |
( |
) | ( |
) | ( |
) | ( |
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Income Tax Provision |
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Net Loss |
( |
) | ( |
) | ( |
) | ( |
) | ||||||||
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Less: Preferred Stock Dividend |
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Net Loss available to common stock |
( |
) | ( |
) | ( |
) | ( |
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Shares used in computing Basic Net Loss per share |
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Basic and Diluted (Loss) Per Share |
$ | ( |
) | $ | ( |
) | $ | ( |
) | $ | ( |
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Shares used in computing Diluted Net Loss per share |
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Diluted Net Income (Loss) per Share |
$ | ( |
) | $ | ( |
) | $ | ( |
) | $ | ( |
) | ||||
See notes to unaudited condensed consolidated financial statements.
ROYALE ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
FOR THE SIX MONTHS ENDED JUNE 30, 2023 AND 2022
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For the Six Months Ended |
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| June 30, 2023 | June 30, 2022 | |||||||
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CASH FLOWS FROM OPERATING ACTIVITIES |
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Net Loss |
$ | ( |
) | $ | ( |
) | ||
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Adjustments to Reconcile Net Loss to Net Cash Used in Operating Activities: |
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Depreciation, Depletion and Amortization |
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Gain on Turnkey Drilling Programs |
( |
) | ( |
) | ||||
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Gain on Settlement of Accounts Payable |
( |
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Well Equipment Write Down |
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Stock Based Compensation |
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Gain on Other |
( |
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Right of use asset depreciation |
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(Increase) Decrease in: |
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Other & Revenue Receivables |
( |
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Prepaid Expenses and Other Assets |
( |
) | ( |
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Increase (Decrease) in: |
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Accounts Payable and Accrued Expenses |
( |
) | ||||||
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Net Cash Used in Operating Activities |
( |
) | ( |
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CASH FLOWS FROM INVESTING ACTIVITIES |
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Expenditures for Oil and Gas Properties and Other Capital Expenditures |
( |
) | ( |
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Proceeds from Turnkey Drilling Programs |
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Net Cash Provided (Used) by Investing Activities |
( |
) | ||||||
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CASH FLOWS FROM FINANCING ACTIVITIES |
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Principal Payments on Long-Term Debt |
( |
) | ( |
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Net Cash Used by Financing Activities |
( |
) | ( |
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Net Decrease in Cash and Cash Equivalents |
( |
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Cash, Cash Equivalents, and Restricted Cash at Beginning of Period |
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Cash, Cash Equivalents, and Restricted Cash at End of Period |
$ | $ | ||||||
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SUPPLEMENTAL DISCLOSURES OF CASH FLOWS INFORMATION: |
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Cash Paid for Interest |
$ | $ | ||||||
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Cash Paid for Taxes |
$ | $ | ||||||
See notes to unaudited condensed consolidated financial statements.
ROYALE ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)
FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2023 AND 2022
(UNAUDITED)
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Number of Shares Issued and Outstanding |
Amount |
Additional Paid in Capital |
Accumulated Deficit |
Total |
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| ($) | ($) | ($) | ($) | |||||||||||||||||||||||||
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Common Shares |
Common Amount |
Preferred Shares |
Preferred Amount |
APIC |
ACD |
Total |
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December 31, 2021 Balance |
- | - | ( |
) | $ | ( |
) | |||||||||||||||||||||
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Stock Issued in lieu of Compensation |
- | |||||||||||||||||||||||||||
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Preferred Series B 3.5% Dividend |
- | - | - | - | ( |
) | ( |
) | ||||||||||||||||||||
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Net Loss |
- | - | - | - | - | ( |
) | ( |
) | |||||||||||||||||||
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June 30, 2022 Balance |
- | - | ( |
) | $ | ( |
) | |||||||||||||||||||||
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Common Shares |
Common Amount |
Preferred Shares |
Preferred Amount |
APIC |
ACD |
Total |
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December 31, 2022 Balance |
- | - | ( |
) | $ | ( |
) | |||||||||||||||||||||
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Cashless Warrant Exercise Issuance |
- | - | ( |
) | - | - | ||||||||||||||||||||||
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Stock Issued in lieu of Compensation |
- | - | - | |||||||||||||||||||||||||
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Preferred Series B 3.5% Dividend |
( |
) | ( |
) | ||||||||||||||||||||||||
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Net Loss |
- | - | - | - | - | ( |
) | ( |
) | |||||||||||||||||||
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June 30, 2023 Balance |
- | - | ( |
) | $ | ( |
) | |||||||||||||||||||||
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Common Shares |
Common Amount |
Preferred Shares |
Preferred Amount |
APIC |
ACD |
Total |
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March 31, 2022 Balance |
- | - | ( |
) | $ | ( |
) | |||||||||||||||||||||
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Stock Issued in lieu of Compensation |
- | - | - | |||||||||||||||||||||||||
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Preferred Series B 3.5% Dividend |
- | - | - | - | - | ( |
) | ( |
) | |||||||||||||||||||
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Net Loss |
- | - | - | - | - | ( |
) | ( |
) | |||||||||||||||||||
|
June 30, 2022 Balance |
- | - | ( |
) | $ | ( |
) | |||||||||||||||||||||
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Common Shares |
Common Amount |
Preferred Shares |
Preferred Amount |
APIC |
ACD |
Total |
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March 31, 2023 Balance |
- | - | ( |
) | ( |
) | ||||||||||||||||||||||
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Cashless Warrant Exercise Issuance |
- | - | ( |
) | - | - | ||||||||||||||||||||||
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Stock Issued in lieu of Compensation |
- | - | - | |||||||||||||||||||||||||
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Preferred Series B 3.5% Dividend |
- | - | - | - | - | ( |
) | ( |
) | |||||||||||||||||||
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Net Loss |
- | - | - | - | - | ( |
) | ( |
) | |||||||||||||||||||
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June 30, 2023 Balance |
- | - | ( |
) | ( |
) | ||||||||||||||||||||||
See notes to unaudited condensed consolidated financial statements.
ROYALE ENERGY, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 – BASIS OF PRESENTATION: ACCOUNTING STANDARDS
Consolidation
In the opinion of management, the accompanying unaudited condensed consolidated Financial Statements (“statements”) include all adjustments necessary to present fairly the Company’s financial position and the results of its operations and cash flows for the periods presented.
The accompanying unaudited consolidated financial statements, which include the accounts of Royale Energy, Inc. (sometimes referred to as the “Company” “we,” “our,” “us,” “Royale Energy,” or “Royale”), Royale Energy Funds, Inc. (“REF”), and Matrix Oil Management Corporation and its subsidiaries, have been prepared in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”) for interim consolidated financial information pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) under Article 10 of Regulation S-X and the instructions to Form 10-Q. Accordingly, certain information and footnote disclosures normally included in our audited financial statements have been condensed or omitted pursuant to the SEC’s rules and regulations. Significant intercompany transactions have been eliminated in the consolidation. In our opinion, all adjustments considered necessary for a fair presentation have been included, disclosures are adequate, and the presented information is not misleading.
Liquidity and Going Concern
The primary sources of liquidity have historically been issuances of common stock, oil and gas sales through ongoing operations and the sale of oil and gas properties. There are factors that give rise to substantial doubt about our 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.
At June 30, 2023, our consolidated financial statements reflect a working capital deficiency of $
Use of Estimates
The accompanying financial statements have been prepared in conformity GAAP and requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Material estimates that are particularly susceptible to significant change relate to the estimate of Company oil and gas reserves prepared by an independent engineering consultant. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proven reserves. Estimated reserves are used in the calculation of depletion, depreciation and amortization, unevaluated property costs, impairment of oil and natural gas properties, estimated future net cash flows, taxes, and contingencies.
Revenue Recognition
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For the three months ended June 30, |
For the six months ended June 30, |
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2023 |
2022 |
2023 |
2022 |
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Oil & Condensate Sales |
$ | $ | ||||||||||||||
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Natural Gas Sales |
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NGL Sales |
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Total |
$ | $ | ||||||||||||||
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 sheets.
Under our hydrocarbon sales agreements, the entire consideration amount is variable either due to pricing and/or volumes. We recognize revenues 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, and such reimbursements are recorded as cost reimbursements.
We commonly market the share of production belonging to other working interest owners as the operator of jointly owned oil and gas properties. Those marketing activities are carried out as part of the collaborative arrangement, and we do not purchase or otherwise obtain control of other working interest owners’ share of production. Therefore, we act as a principal only with respect to the sale of our share of production and recognize revenue for the volumes associated with our net production.
We frequently sell a portion of the working interest in each well we drill or participate in to third-party investors and retain a portion of the prospect for our own account. We typically guarantee a cost to drill to the third-party drilling participants and record 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, we record 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 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 except for natural gas sold to Pacific Gas & Electric (PG&E) where transportation is netted directly against revenue. Under some of our natural gas processing agreements, we have an option to take the processed natural gas and NGLs in-kind and sell to customers other than the processing company. In those circumstances, our performance obligations are complete after delivering the processed hydrocarbons to the customer at the designated delivery points, which may be the tailgate of the processing plant, or an alternative delivery point requested by the customer.
Turnkey Drilling
We sponsor turnkey drilling arrangements in proved and unproved properties. The contracts require that participants pay us 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 (“Drilling Funds”). If something changes, we may designate the Drilling Funds a substitute well. Under certain conditions, a portion of the Drilling Funds may be required to be returned to a participant. Once the well is drilled, the Drilling Funds are used to satisfy the drilling cost.
We manage these Turnkey Agreements for the participants of the well. We segregate the collections of pre-drilling AFE amounts 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 the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 932-323-25 and 932-360. We manage 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.
Restricted Cash
Prior to commencement of drilling, we classify Drilling Funds as restricted cash based on guidance codified as under ASC 230-10-50-8. In the event that progress payments are made from these funds; they are recorded as Prepaid Expenses and Other Current Assets.
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June 30, 2023 |
December 31, 2022 |
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Cash and Cash Equivalents |
$ | $ | ||||||
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Restricted Cash |
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Total cash, cash equivalents, and restricted cash shown in the statement of cash flows |
$ | $ | ||||||
Equity Method Investments
Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting. Income from equity method investments represents our proportionate share of net income generated by the equity method investees and is reflected in revenue and other income in our condensed consolidated statements of operations. Equity method investments are included as noncurrent assets on the consolidated balance sheet.
Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value may have occurred as called for under ASC 323. When a loss is deemed to have occurred and is other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income.
Other Receivables, net
Other receivables, net consist of joint interest billing receivables from direct working interest investors and industry partners. We provide for uncollectible accounts receivable using the allowance method of accounting for bad debts. Under this method of accounting, a provision for uncollectible accounts is charged directly to bad debt expense when it becomes probable the receivable will not be collected. The allowance account is increased or decreased based on past collection history and management’s evaluation of accounts receivable. All amounts considered uncollectible are charged against the allowance account and recoveries of previously charged off accounts are added to the allowance. At June 30, 2023, and December 31, 2022, we maintained an allowance for uncollectable accounts of $
Fair Value Measurements
According to Fair Value Measurements and Disclosures Topic of the FASB ASC, assets and liabilities that are measured at fair value on a recurring and nonrecurring basis in periods 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, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible as well as considering counterparty credit risk in our assessment of fair value. Carrying amounts of our financial instruments, including cash equivalents, accounts receivable, accounts payable and accrued liabilities, approximate their fair values as of the balance sheet dates because of their generally short maturities.
The fair value hierarchy distinguishes between (1) market participant assumptions developed based on market data obtained from independent sources (observable inputs) and (2) an entity’s own assumptions about market participant assumptions developed based on the best information available in the circumstances (unobservable inputs). The fair value hierarchy consists of three broad levels, which gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy are described below:
Level 1: Quoted prices (unadjusted) in active markets that are accessible at the measurement date for assets or liabilities.
Level 2: Directly or indirectly observable inputs as of the reporting date through correlation with market data, including quoted prices for similar assets and liabilities in active markets and quoted prices in markets that are not active. Level 2 also includes assets and liabilities that are valued using models or other pricing methodologies that do not require significant judgment since the input assumptions used in the models, such as interest rates and volatility factors, are corroborated by readily observable data from actively quoted markets for substantially the full term of the financial instrument.
Level 3: Unobservable inputs that are supported by little or no market activity and reflect the use of significant management judgment. These values are generally determined using pricing models for which the assumptions utilize management’s estimates of market participant assumptions.
At June 30, 2023 and December 31, 2022, we do not have any financial assets measured and recognized at fair value on a recurring basis. We estimate asset retirement obligations (AROs) pursuant to the provisions of ASC 410, “Asset Retirement and Environmental Obligations”. The estimates of the fair value the AROs are based on discounted cash flow projections using numerous estimates, assumptions, and judgements regarding such factors as the existence of a legal obligation for an ARO, amounts and timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates.
The initial measurement of AROs 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.
Other receivables will be reflected as Level 3. The fair value of our other receivables is based on credit factors, oil and gas well reserve profiles and commodity prices both current and forecast specific to these financial instruments.
Fair Values - Non-recurring
We applied the provisions of the fair value measurement standard to our non-recurring, non-financial measurements including oil and natural gas property impairments and other long-lived asset impairments. These items are not measured at fair value on a recurring basis but are subject to fair value adjustments only in certain circumstances.
Dividends on Series B Convertible Preferred Stock
The Series B Convertible Preferred Stock, (“Preferred Stock”) has an obligation to pay a
ACCOUNTING STANDARDS
Recently Adopted
ASU 2016-13, Credit Impairment
NOTE 2 – OIL AND GAS PROPERTY AND EQUIPMENT AND FIXTURES
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June 30, |
December 31, |
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|
2023 |
2022 |
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|
(Unaudited) |
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|
Oil and Gas |
||||||||
|
Producing properties, including drilling costs |
$ | $ | ||||||
|
Undeveloped properties |
||||||||
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Lease and well equipment |
||||||||
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Accumulated depletion, depreciation & amortization |
( |
) | ( |
) | ||||
|
Net capitalized costs Total |
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Commercial and Other |
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Vehicles |
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Accumulated depreciation |
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The guidance set forth in the Continued Capitalization of Exploratory Well Costs paragraph of the Extractive Activities Topic of the FASB ASC requires that we evaluate all existing capitalized exploratory well costs and disclose the extent to which any such capitalized costs have become impaired and are expensed or reclassified during a fiscal period.
Depreciation, depletion, and amortization, based on cost less estimated salvage value of the asset, are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. Maintenance and repairs are expensed as incurred. Major renewals and improvements are capitalized, and the assets replaced are retired.
The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use. Interest costs, to the extent they are incurred to finance expenditures during the construction phase, are included in property, plant and equipment and are depreciated over the service life of the related assets.
We use the “successful efforts” method to account for our exploration and production activities. Under this method, we accumulate our proportionate share of costs on a well-by-well basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred and capitalize expenditures for productive wells. We amortize the costs of productive wells under the unit-of-production method.
We carry, 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 we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred.
Acquisition costs of proved oil and gas properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves.
Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using unit-of-production rates based on the amount of proved developed reserves of oil and gas that are estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production method, oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank.
Production costs are expensed as incurred. Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain our 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, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable.
We estimate the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts and whether carrying amounts should be impaired. We perform the evaluation of carrying amounts at least annually or when economic events or commodity prices indicate that a substantial and measurable change in future cash flows has occurred. Cash flows used in impairment evaluations are developed using updated evaluation assumptions for crude oil and natural gas commodity prices. Annual volumes are based on field production profiles, which are also updated annually.
Impairment analyses are generally based on proved reserves. An asset group would be further assessed if the undiscounted cash flows were less than its’ carrying value. Impairments are measured by the amount the carrying value exceeds fair value. During the six months ended June 30, 2023, and 2022, no impairment losses were incurred.
Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that Royale Energy expects to hold the properties. The valuation allowances are reviewed at least annually.
Upon the sale or retirement of a complete field of a proven property, we eliminate the cost from our books, and the resulting gain or loss is recorded to the 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 the 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 our turnkey drilling agreements include unproved property, total drilling costs incurred to satisfy our 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.
We sponsor 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 our obligations are incurred with any excess booked against our property account to reduce any basis in our own interest. Gains on Turnkey Drilling Programs represent funds received from turnkey drilling participants in excess of all costs we incur during the drilling programs (e.g., lease acquisition, exploration and development costs), including costs incurred on behalf of participants and costs incurred for our own account; and are recognized only upon making this determination after our obligations have been fulfilled.
The contracts require the participants to pay the full contract price upon execution of the agreement. We complete 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 their proportionate share of operating costs. We retain 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. We hold all funds invested as Deferred Drilling Obligations until drilling is complete. Occasionally, drilling is delayed for various reasons such as weather, permitting, drilling rig availability and/or contractual obligations. At June 30, 2023, and December 31, 2022, we had Deferred Drilling Obligations of $
If we are unable to drill the wells, and a suitable replacement well is not found, we would retain the non-refundable portion of the contract and return the remaining funds to the participant. Included in Restricted Cash are amounts for use in completion of turnkey drilling programs in progress.
Losses on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value.
NOTE 3 – SERIES B PREFERRED STOCK
In accordance with ASC 480-10-S99-1.02, we have determined that the conversion or redemption of the Preferred Stock are outside the sole control of the Company and that they should be classified in mezzanine or temporary equity as redeemable noncontrolling interest beginning at the reporting period ended June 30, 2020.
For 2023 and 2022, the board authorized the payment of each quarterly dividend on shares of Preferred Stock, as Paid-In-Kind shares to be paid immediately following the end of the quarter. For the quarter ending June 30, 2023, we accrued
NOTE 4 – LOSS PER SHARE
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For the six months ended June 30, 2023 and 2022, we had dilutive securities of
NOTE 5 – INCOME TAXES
Deferred tax assets and liabilities reflect the net tax effect of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and amounts used for income tax purposes. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more-likely-than-not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. At the end of 2015, management reviewed the reliability of our net deferred tax assets, and due to our continued cumulative losses in recent years, the we concluded it is not “more-likely-than-not” our deferred tax assets will be realized. As a result, we will continue to record a full valuation allowance against the deferred tax assets in 2023.
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NOTE 6 – ISSUANCE OF COMMON STOCK
In April 2023, CIC RMX LP (“CIC”) exercised in full its warrant to purchase shares of our common stock. CIC elected to make a cashless exercise of the warrant and as a result we issued
NOTE 7 – ALLOWANCE FOR CREDIT LOSSES
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Balance at December 31, 2022 |
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Balance at June 30, 2023 |
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
FORWARD-LOOKING STATEMENTS
In addition to historical information contained herein, certain information contained in this Quarterly Report on Form 10-Q, as well as other written and oral statements made or incorporated by reference from time to time by the Company and its representatives in other reports, filings with the SEC, press releases, conferences or otherwise, may be deemed to be “forward-looking statements” within the meaning of Section 21E of the Exchange Act. This information includes, without limitation, statements concerning the Company’s future financial position and results of operations, planned capital expenditures, sources and availability of financing, business strategy and other plans for future operations, the future mix of revenues and business, customer retention, project reversals, commitments and contingent liabilities, future demand, and industry conditions. While we believe our forward-looking statements are based upon reasonable assumptions, we can give no assurance that such expectations will prove to have been correct. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Generally, the words “anticipate,” “believe,” “estimate,” “expect,” “may” and similar expressions, identify forward-looking statements, which generally are not historical in nature. Actual results could differ materially from the results described in the forward-looking statements due to the risks and uncertainties set forth under “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” elsewhere in this Quarterly Report on Form 10-Q, in the Company’s Annual Report on Form 10-K for the year ended December 31, 2022, and those described from time to time in our future reports filed with the SEC.
The following discussion is qualified in its entirety by, and should be read in conjunction with, the Company’s financial statements, including the notes thereto, included in this Quarterly Report on Form 10-Q and the Company’s Annual Report on Form 10-K for the year ended December 31, 2022.
OVERVIEW
Royale is an independent oil and natural gas producer. 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. Since 1993, Royale has primarily acquired and developed producing and non-producing natural gas properties in California. In December 2018, Royale became the operator of a newly acquired oil and gas property in Texas. The most significant factors affecting our results of operations are (i) changes in oil and natural gas prices, production levels and reserves, (ii) turnkey drilling activities, and (iii) the increase in future cost associated with abandonment of wells.
RESULTS OF OPERATIONS
For the six months ended June 30, 2023 and 2022, we had net losses of $33,031 and $312,853, respectively. The decrease in net losses were primarily due to the completion of one oil well in Texas and participating in the drilling and completion of an oil well in the Texas Permian basin where we recognized a gain on turnkey drilling of $1,339,382. During the three months ended June 30, 2023 and 2022, we had net losses of $1,035,375 and $260,502, respectively. The difference was due to higher turnkey drilling costs incurred in the second quarter of 2023 in the Texas well in which we participated and lower oil and gas revenues due to lower oil and gas commodity prices during the second quarter 2023.
During the first six months of 2023, revenues from oil and gas production decreased $197,875 or 16.7%, to $988,744 in 2023 from revenues of $1,186,619 during the first six months of 2022. This decrease was mainly due to lower oil and natural gas commodity prices. The net sales volume of oil and condensate for the six months ended June 30, 2023, was approximately 9,864 barrels with an average price of $71.69 per barrel, versus 8,186 barrels with an average price of $99.58 per barrel for the six months of 2022. This represents an increase in net sales volume of 1,678 barrels or 20.5%, which was due to wells completed and put online during the latter half of 2022 and first half of 2023. The net sales volume of natural gas for the six months ended June 30, 2023, was approximately 68,081 Mcf with an average price of $4.10 per Mcf, versus 65,308 Mcf with an average price of $5.61 per Mcf for the same period in 2022. This represents an increase in net sales volume of 2,773 Mcf or 4.2%. The increase in natural gas production volume was also due to new wells being brought online. For the quarter ended June 30, 2023, revenues from oil and gas production decreased $249,112 or 36.7% to $430,293 from the 2022 second quarter revenues of $679,405. This decrease was also due to lower oil and natural gas commodity prices. The net sales volume of oil and condensate for the quarter ended June 30, 2022, was approximately 5,104 barrels with an average price of $70.45 per barrel, versus 4,297 barrels with an average price of $106.05 per barrel for the second quarter of 2022. This represents an increase in net sales volume of 807 barrels or 18.8% for the quarter in 2023. The net sales volume of natural gas for the quarter ended June 30, 2023, was approximately 37,962 Mcf with an average price of $1.84 per Mcf, versus 31,781 Mcf with an average price of $6.92 per Mcf for the second quarter of 2022. This represents an increase in net sales volume of 6,181 Mcf or 19.4% for the quarter in 2023.
Oil and natural gas lease operating expenses increased by $289,117 or 35.6%, to $1,102,095 for the six months ended June 30, 2023, from $812,978 for the same period in 2022. This increase was mainly due to well equipment and supplies primarily on our Texas Jameson wells to increase production. For the second quarter in 2023, lease operating expenses increased $127,788 or 32.1% from the same quarter in 2022, mainly due to increases in workovers and water disposal fees in our Texas Jameson field during the quarter in 2023.
The aggregate of supervisory fees and other income was $111,966 for the six months ended June 30, 2023, an increase of $94,925 from $17,041 during the same period in 2022. During the second quarter 2023, supervisory fees and other income increased $90,842 when compared to the quarter in 2022. These increases were mainly due to increases in water disposal recovery income as we converted an existing non-producing oil well into a water injection well in order to reduce water disposal hauling costs paid to outside vendors.
Depreciation, depletion and amortization expense decreased to $173,907 from $244,208, a decrease of $70,301 or 28.8% for the six months ended June 30, 2023, as compared to the same period in 2022. During the second quarter 2023, depreciation, depletion and amortization expenses also decreased $5,057 or 4.2%. The depletion rate is calculated using production as a percentage of reserves. This decrease in depletion expense was due to an increase in expected recoverable reserves which decreased the depletion rate.
At June 30, 2023, Royale Energy had a Deferred Drilling Obligation of $8,190,855. During the first six months of 2023, we removed $2,561,610 of drilling obligations as we completed one oil well in our Texas Jameson field and participated in the drilling and completion of an oil well in the Texas Permian basin, while incurring expenses of $1,222,228, resulting in a gain of $1,339,382. At June 30, 2022, Royale Energy had a Deferred Drilling Obligation of $8,359,011. During the first six months of 2022, we disposed of $3,185,928 of drilling obligations upon completing one oil well in Texas and participated in the drilling and completion of two oil wells in southern California, while incurring expenses of $2,558,792, resulting in a gain of $627,136.
General and administrative expenses decreased by $145,648 or 14.2% from $1,023,817 for the six months ended June 30, 2022 to $878,169 for the same period in 2023. For the second quarter 2023, general and administrative expenses decreased $64,662 or 13.3% when compared to the same period in 2022. These decreases were mainly due to lower employee related expenses due to cost reduction measures during the periods in 2023. For the first six months of 2023, marketing expenses increased $12,572 or 9.4% to $146,891, compared to $134,319 for the first six months of 2022. For the second quarter 2023, marketing expenses decreased $20,301 or 25.9% when compared to the second quarter in 2022. Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs.
Legal and accounting expense decreased to $273,143 for the six-month period in 2023, compared to $346,410 for the same period in 2022, a $73,267 or 21.2%. This decrease during the period in 2023 was primarily due to higher fees related to the conversion of our accounting software during the period in 2022. For the second quarter 2023, legal and accounting expenses increased $87,112 or 55.1%, when compared to the second quarter in 2022, primarily due to the delay in our 2022 audit and its related fees, which occurred during the second quarter 2023.
During the six months ended June 30, 2023, we recorded a gain on other of $54,975 as we reconciled employee related items previously recorded as liabilities. We also recorded a gain on other of approximately $57,000 on our share of prior years property tax refunds received by RMX Resources, LLC during the period in 2023. During the six months ended June 30, 2022, we recorded a gain of $422,614 on settlement of accounts payable for a reduced amount.
CAPITAL RESOURCES AND LIQUIDITY
At June 30, 2023, we had current assets totaling $8,155,268 and current liabilities totaling $15,139,599, a $6,984,331 working capital deficit. We had $974,496 in cash and $1,236,665 in restricted cash at June 30, 2023, compared to $1,650,507 in cash and $2,249,627 in restricted cash at December 31, 2022.
In accordance with ASC 480-10-S99, we reclassified the Series B Convertible Preferred Stock from Permanent Equity to Mezzanine capital as a result of the change in voting rights provided at the time of issuance. For more information, see Note 3 – Series B Convertible Preferred Stock.
At June 30, 2023, our other receivables, which consist of joint interest billing receivables from direct working interest investors and industry partners, totaled $999,030 compared to $943,633 at December 31, 2022, a $55,397 increase. This increase was mainly due to accounts receivables from direct working interest owners for lease operating expenses on our Texas Jameson wells to increase production volumes. At June 30, 2023, revenue receivable was $381,821, a decrease of $320,116, compared to $701,937 at December 31, 2022, due to lower commodity prices during the second quarter in 2023. At June 30, 2023, our accounts payable and accrued expenses totaled $5,342,800 a decrease of $186,029 from the accounts payable at December 31, 2022 of $5,528,829, which was mainly due to lower revenue payables due to the lower commodity prices during the period in 2023.
We have had recurring operating and net losses and cash used in operations and the financial statements reflect a working capital deficiency of $6,984,331 and an accumulated deficit of $88,094,633. These factors raise substantial doubt about our ability to continue as a going concern. We anticipate that our primary sources of liquidity will be from the sale of oil and gas in the course of normal operations, the sale of oil and gas property, sales of participation interest and possible issuance of debt and/or equity. If we are unable to generate sufficient cash from operations or financing sources, it may become necessary to curtail, suspend or cease operations, sell property, or enter into financing transaction(s) on less favorable terms; any such outcomes could have a material adverse effect on our business, results of operations, financial position and liquidity. Management has plans to continue to increase revenues by making commitments to participate with industry partners in drilling wells in the Permian basin and will also continue to drill and workover wells in our Texas Jameson field. We are also looking for possible ways to increase production on some of our California natural gas wells.
Operating Activities. Net cash used in operating activities totaled $1,658,304 and $1,078,217 for the six months ended June 30, 2023 and 2022, respectively. This difference in cash used was mainly due to lower accounts payable during the period in 2023 when compared to the period in 2022 where we increased our accounts payable.
Investing Activities. Net cash provided by investing activities totaled $24,774 and $1,100,610 for the six months ended June 30, 2023, and 2022, respectively. During the six-month period in 2023, we received approximately $2.6 million in direct working interest investor turnkey drilling investments while our drilling expenditures were approximately $2.6 million as we drilled and completed one Texas well and participated in the drilling and completing of another Texas well in the Permian basin. During the six month period in 2022, we received approximately $3.7 million in direct working interest investor turnkey drilling investments while our drilling expenditures were approximately $2.6 million as we drilled and completed one Texas well and participated in the drilling and completing of two southern California oil wells.
Financing Activities. Net cash used in financing activities totaled $5,895 and $76,333 for the six months ended June 30, 2023, and 2022, respectively. During the periods in 2023 and 2022, the totals were used for principal payments on our notes payable and financing lease payments.
Critical Accounting Estimates
Our critical accounting policies are further disclosed in Note 1 to the consolidated financial statements included in our 2022 Annual Report on Form 10-K.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Not applicable.
Item 4. Controls and Procedures
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
Disclosure controls and procedures are controls and other procedures of a registrant designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Exchange Act is properly recorded, processed, summarized and reported, within the time periods specified in the SEC rules and forms. Disclosure controls and procedures include processes to accumulate and evaluate relevant information and communicate such information to a registrant’s management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.
As of December 31, 2022, our management, including our Chief Executive and Chief Financial Officers evaluated the effectiveness of the design and operation of our disclosure controls and procedures, as required by Rule 13a-15 of the Exchange Act. Based on the evaluation described above, the company concluded that there was a material weakness in our disclosure controls and procedures. These controls and procedures are based on the definition of disclosure controls and procedures in Rule 13a-15(e) and Rule 15d-15(e) promulgated under the Securities Exchange Act of 1934. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.
As a result of the review by the CFO and CEO, the material weakness was identified as listed below.
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In connection with the audit of our 2022 and 2021 consolidated financial statements, management has identified a material weakness that exists because we did not maintain effective controls over our financial close and reporting process, and has concluded that the financial close and reporting process needs additional formal procedures to ensure that appropriate reviews occur on all financial reporting analysis. Management has designed and implemented updated control procedures that we believe will mitigate this material weakness and is monitoring these procedures for effectiveness. |
Because of the material weaknesses described above, our management was unable to conclude that our internal control over financial reporting was effective as of the end of period to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with generally accepted accounting principles.
Notwithstanding the material weaknesses described above, our management, including our Chief Executive Officer and Chief Financial Officer, believes that the consolidated financial statements contained in this Report on Form 10-Q fairly present, in all material respects, our financial condition, results of operations and cash flows for the fiscal periods presented in conformity with U.S. generally accepted accounting principles. In addition, the material weakness described did not result in the restatements of any of our audited or unaudited consolidated financial statements or disclosures for any previously reported periods.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
Except for the actions described above, that were taken to address the material weaknesses, there were no changes in our internal controls during the period ended June 30, 2023, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
From time to time, the Company may be involved in various legal proceedings or may be subject to claims that arise in the ordinary course of business. The outcome of any such claims or proceedings cannot be predicted with certainty. As of the date of this filing, management is not aware of any such claims against the Company.
Item 1A. Risk Factors
Not applicable to smaller reporting companies.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
During the period covered by this report, we have not issued any unregistered shares.
Item 3. Defaults Upon Senior Securities
None
Item 4. Mine Safety Disclosures
Not applicable
Item 5. Other Information
None
Item 6. Exhibits
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31.1 |
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31.2 |
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32.1 |
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32.2 |
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101.INS |
Inline XBRL Instance Document |
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101.SCH |
Inline XBRL Taxonomy Extension Schema |
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101.CAL |
Inline XBRL Taxonomy Extension Calculation Linkbase |
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101.DEF |
Inline XBRL Taxonomy Extension Definition Linkbase |
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101.LAB |
Inline XBRL Taxonomy Extension Label Linkbase |
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101.PRE |
Inline XBRL Taxonomy Extension Presentation Linkbase |
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104 |
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |
Signatures
Pursuant to the requirements 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: August 14, 2023 |
/s/ Johnny Jordan |
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Johnny Jordan, Chief Executive Officer |
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Date: August 14, 2023 |
/s/ Ronald Lipnick |
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Ronald Lipnick, Interim Chief Financial Officer |
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