UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 2021
|
Commission File No. 000-55912
|
ROYALE ENERGY,
INC.
(Exact name of registrant as specified in its charter)
Delaware
|
81-4596368
|
(State or other jurisdiction of
incorporation or organization)
|
(I.R.S. Employer
Identification No.)
|
1870 Cordell Court, Suite 210
El Cajon, CA
92020
(Address of principal executive offices) (Zip Code)
619-383-6600
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Exchange
Act during the past 12 months (or for such shorter period that the
registrant was required to file such reports), and (2)
has been subject to such filing requirements for the past 90 days.
Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted
electronically every Interactive Data File required to be submitted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter)
during the preceding 12 months (or for such shorter period that the
registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated filer, a
smaller reporting company, or 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 ☐
|
Non-accelerated filer ☒
|
Smaller reporting company ☒
|
Emerging growth company ☐
|
|
If an emerging growth company, indicate by check mark if the
registrant has elected not to use the extended transition period
for complying with any new or revised financial accounting
standards provided pursuant to Section 13(a) of the Exchange
Act ☐
Indicate by check mark whether the registrant is a shell company
(as defined in Rule 12b-2 of the Act). Yes ☐ No ☒
Indicate by check mark whether the registrant is a blank check
company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No
☒
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
|
Trading Symbol(s)
|
Name of each exchange on which registered
|
Common stock, par value .001 per share
|
ROYL
|
OTC: QB
|
At August 5, 2021, a total of 56,239,715 shares of registrant’s
common stock were outstanding.
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
ROYALE ENERGY, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
|
|
June 30, 2021
|
|
|
December 31, 2020
|
|
ASSETS
|
|
(unaudited)
|
|
|
|
|
|
Current Assets
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents
|
|
|
603,075 |
|
|
|
255,112 |
|
Restricted Cash
|
|
|
2,271,556 |
|
|
|
2,146,571 |
|
Other Receivables, net
|
|
|
274,884 |
|
|
|
462,777 |
|
Revenue Receivables
|
|
|
355,990 |
|
|
|
204,149 |
|
Assets Held for Sale
|
|
|
1,000,000 |
|
|
|
1,529,141 |
|
Prepaid Expenses
|
|
|
70,680 |
|
|
|
233,769 |
|
Deferred Drilling Costs
|
|
|
133,361 |
|
|
|
- |
|
Prepaid Drilling to RMX Resources, LLC
|
|
|
275,006 |
|
|
|
239,036 |
|
Total Current Assets
|
|
|
4,984,552 |
|
|
|
5,070,555 |
|
|
|
|
|
|
|
|
|
|
Right of Use Assets - Leases
|
|
|
140,246 |
|
|
|
229,516 |
|
Other Assets
|
|
|
583,554 |
|
|
|
583,554 |
|
Oil and Gas Properties, (Successful Efforts Basis),
Equipment and Fixtures, net
|
|
|
2,309,711 |
|
|
|
2,541,001 |
|
Total Assets
|
|
|
8,018,063 |
|
|
|
8,424,626 |
|
See notes to unaudited condensed consolidated financial
statements.
ROYALE ENERGY, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
|
|
June 30, 2021 |
|
|
December 31, 2020
|
|
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities:
|
|
|
|
|
|
|
|
|
Accounts Payable and Accrued Expenses
|
|
|
4,481,815 |
|
|
|
4,161,109 |
|
Royalties Payable
|
|
|
623,405 |
|
|
|
623,405 |
|
Notes Payable
|
|
|
103,123 |
|
|
|
132,624 |
|
Due to RMX Resources, LLC
|
|
|
23,087 |
|
|
|
23,087 |
|
Asset Retirement Obligation - Current
|
|
|
720,596 |
|
|
|
869,147 |
|
Deferred Drilling Obligation
|
|
|
4,047,439 |
|
|
|
3,127,500 |
|
Operating Leases - Current
|
|
|
106,026 |
|
|
|
178,120 |
|
Total Current Liabilities
|
|
|
10,105,491 |
|
|
|
9,114,992 |
|
|
|
|
|
|
|
|
|
|
Noncurrent Liabilities:
|
|
|
|
|
|
|
|
|
Accrued Liabilities - Long Term
|
|
|
1,306,605 |
|
|
|
1,306,605 |
|
Accrued Unpaid Guaranteed Payments
|
|
|
1,616,205 |
|
|
|
1,616,205 |
|
Operating Leases - Long-Term
|
|
|
36,027 |
|
|
|
52,937 |
|
Asset Retirement Obligation
|
|
|
2,531,648 |
|
|
|
2,478,350 |
|
Total Liabilities
|
|
|
15,595,976 |
|
|
|
14,569,089 |
|
|
|
|
|
|
|
|
|
|
Mezzanine Equity:
|
|
|
|
|
|
|
|
|
Convertible Preferred Stock, Series B, $10 par value,
3,000,000 Shares Authorized
|
|
|
22,603,486 |
|
|
|
22,216,238 |
|
|
|
|
|
|
|
|
|
|
Stockholders' Equity (Deficit):
|
|
|
|
|
|
|
|
|
Common Stock, .001 Par Value, 280,000,000 Shares Authorized
|
|
|
56,074 |
|
|
|
54,605 |
|
Additional Paid in Capital
|
|
|
54,044,231 |
|
|
|
53,883,479 |
|
Accumulated Deficit
|
|
|
(84,281,704 |
) |
|
|
(82,298,785 |
) |
Total Stockholders' Equity (Deficit)
|
|
|
(30,181,399 |
) |
|
|
(28,360,701 |
) |
|
|
|
|
|
|
|
|
|
Total Liabilities and Stockholders' Equity
(Deficit)
|
|
|
8,018,063 |
|
|
|
8,424,626 |
|
See notes to unaudited condensed consolidated financial
statements.
ROYALE ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF
OPERATIONS (UNAUDITED)
|
|
For the three
months ended
|
|
|
For the three
months ended
|
|
|
For the six
months ended
|
|
|
For the six
months ended
|
|
|
|
June 30, 2021 |
|
|
June 30, 2020 |
|
|
June 30, 2021 |
|
|
June 30, 2020 |
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, NGL and Gas Sales
|
|
|
377,939 |
|
|
|
211,514 |
|
|
|
776,876 |
|
|
|
585,999 |
|
Supervisory Fees and Other
|
|
|
15,776 |
|
|
|
11,627 |
|
|
|
18,102 |
|
|
|
20,956 |
|
Total Revenues
|
|
|
393,715 |
|
|
|
223,141 |
|
|
|
794,978 |
|
|
|
606,955 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Natural Gas Operating
|
|
|
413,209 |
|
|
|
375,305 |
|
|
|
713,371 |
|
|
|
778,758 |
|
Depreciation, Depletion and Amortization
|
|
|
169,956 |
|
|
|
75,690 |
|
|
|
294,361 |
|
|
|
155,625 |
|
Bad Debt Expense
|
|
|
187,274 |
|
|
|
- |
|
|
|
187,348 |
|
|
|
186,168 |
|
Geological and Geophysical Expense
|
|
|
- |
|
|
|
14,392 |
|
|
|
- |
|
|
|
14,392 |
|
Legal and Accounting
|
|
|
57,237 |
|
|
|
88,125 |
|
|
|
276,000 |
|
|
|
174,660 |
|
Marketing
|
|
|
43,446 |
|
|
|
20,670 |
|
|
|
82,495 |
|
|
|
55,064 |
|
General and Administrative
|
|
|
511,682 |
|
|
|
554,277 |
|
|
|
1,076,665 |
|
|
|
1,075,340 |
|
Total Costs and Expenses
|
|
|
1,382,804 |
|
|
|
1,128,459 |
|
|
|
2,630,240 |
|
|
|
2,440,007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss) on Turnkey Drilling
|
|
|
(323,918 |
) |
|
|
872,673 |
|
|
|
(59,138 |
) |
|
|
910,448 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss From Operations
|
|
|
(1,313,007 |
) |
|
|
(32,645 |
) |
|
|
(1,894,400 |
) |
|
|
(922,604 |
) |
Other Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense
|
|
|
(3,756 |
) |
|
|
(3,414 |
) |
|
|
(4,591 |
) |
|
|
(7,444 |
) |
Gain (Loss) on Settlement of Accounts Payable
|
|
|
2,010 |
|
|
|
- |
|
|
|
12,071 |
|
|
|
(31,500 |
) |
Other Gain
|
|
|
- |
|
|
|
200,001 |
|
|
|
- |
|
|
|
200,001 |
|
Gain on Sale of Assets
|
|
|
291,249 |
|
|
|
- |
|
|
|
291,249 |
|
|
|
- |
|
Gain (Loss) on Investment in Joint Venture
|
|
|
- |
|
|
|
(476,326 |
) |
|
|
- |
|
|
|
833,525 |
|
Income (Loss) Before Income Tax Expense
|
|
|
(1,023,504 |
) |
|
|
(312,384 |
) |
|
|
(1,595,671 |
) |
|
|
71,978 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
|
|
|
(1,023,504 |
) |
|
|
(312,384 |
) |
|
|
(1,595,671 |
) |
|
|
71,978 |
|
Less: Preferred Stock Dividend
|
|
|
195,530 |
|
|
|
188,834 |
|
|
|
387,248 |
|
|
|
376,034 |
|
Net Loss available to common stock
|
|
|
(1,219,034 |
) |
|
|
(501,218 |
) |
|
|
(1,982,919 |
) |
|
|
(304,056 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares used in computing Basic and Diluted Net Loss per common
share
|
|
|
55,909,271 |
|
|
|
52,987,786 |
|
|
|
55,529,082 |
|
|
|
52,550,857 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and Diluted Net (Loss) Per Common Share
|
|
|
(0.02 |
) |
|
|
(0.01 |
) |
|
|
(0.04 |
) |
|
|
(0.01 |
) |
Shares used in computing Diluted Net Loss per share
|
|
|
55,909,271 |
|
|
|
52,987,786 |
|
|
|
55,529,082 |
|
|
|
52,550,857 |
|
Diluted Net Income (Loss) per Share
|
|
|
(0.02 |
) |
|
|
(0.01 |
) |
|
|
(0.04 |
) |
|
|
(0.01 |
) |
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, 2021 AND 2020
|
|
June 30, 2021 |
|
|
June 30, 2020 |
|
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
Net Income (Loss)
|
|
|
(1,595,671 |
) |
|
|
71,978 |
|
Adjustments to Reconcile Net Income (Loss) to Net Cash (Used In)
Provided By Operating Activities:
|
|
|
|
|
|
|
|
|
Depreciation, Depletion and Amortization
|
|
|
294,361 |
|
|
|
155,625 |
|
Gain on Sale of Assets
|
|
|
(291,249 |
) |
|
|
- |
|
(Gain) Loss on Turnkey Drilling Programs
|
|
|
59,138 |
|
|
|
(910,448 |
) |
(Gain) Loss on Settlement of Accounts Payable
|
|
|
(12,071 |
) |
|
|
31,500 |
|
Gain on Investment in Joint Venture
|
|
|
- |
|
|
|
(833,525 |
) |
Bad Debt Expense
|
|
|
187,348 |
|
|
|
186,168 |
|
Stock Based Compensation
|
|
|
162,221 |
|
|
|
169,550 |
|
Geological & Geophysical Costs
|
|
|
- |
|
|
|
14,392 |
|
Right of use asset depreciation
|
|
|
5,480 |
|
|
|
5,466 |
|
Increase (Decrease) in:
|
|
|
|
|
|
|
|
|
Other & Revenue Receivables
|
|
|
(151,296 |
) |
|
|
73,058 |
|
Prepaid Expenses and Other Assets
|
|
|
127,119 |
|
|
|
2,082,185 |
|
Accounts Payable and Accrued Expenses
|
|
|
332,200 |
|
|
|
(702,131 |
) |
Due to Affiliate
|
|
|
- |
|
|
|
(9,280 |
) |
Net Cash (Used in) Provided by Operating Activities
|
|
|
(882,420 |
) |
|
|
334,538 |
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
Expenditures for Oil and Gas Properties and Turnkey Drilling
Costs
|
|
|
(2,052,257 |
) |
|
|
(3,967,301 |
) |
Proceeds from Turnkey Drilling Programs
|
|
|
2,761,000 |
|
|
|
1,200,000 |
|
Proceeds from Sale of Assets, net
|
|
|
671,839 |
|
|
|
- |
|
Net Cash Provided by (Used in) Investing Activities
|
|
|
1,380,582 |
|
|
|
(2,767,301 |
) |
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Proceeds from Long-Term Debt
|
|
|
- |
|
|
|
207,800 |
|
Principal Payments on Long-Term Debt
|
|
|
(25,214 |
) |
|
|
(60,481 |
) |
Net Cash (Used in) Provided by Financing Activities
|
|
|
(25,214 |
) |
|
|
147,319 |
|
|
|
|
|
|
|
|
|
|
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted
Cash
|
|
|
472,948 |
|
|
|
(2,285,444 |
) |
|
|
|
|
|
|
|
|
|
Cash, Cash Equivalents, and Restricted Cash at Beginning of
Period
|
|
|
2,401,683 |
|
|
|
3,876,529 |
|
|
|
|
|
|
|
|
|
|
Cash, Cash Equivalents, and Restricted Cash at End of
Period
|
|
|
2,874,631 |
|
|
|
1,591,085 |
|
SUPPLEMENTAL DISCLOSURES OF CASH FLOWS INFORMATION:
|
|
|
|
|
|
|
|
|
Cash Paid for Interest
|
|
|
1,571 |
|
|
|
7,444 |
|
Cash Paid for Taxes
|
|
|
9,194 |
|
|
|
2,900 |
|
See notes to unaudited condensed consolidated financial
statements.
ROYALE ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(DEFICIT)
(UNAUDITED)
|
|
Common Stock
|
|
|
Preferred Stock Series B
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
Shares Issued
and Outstanding
|
|
|
Amount
|
|
|
Number of
Shares Issued
and Outstanding
|
|
|
Amount
|
|
|
Additional
Paid in
Capital
|
|
|
Accumulated
Comprehensive Deficit
|
|
|
Total
|
|
December 31, 2019 Balance
|
|
|
51,854,136 |
|
|
|
51,854 |
|
|
|
2,145,334 |
|
|
|
21,453,338 |
|
|
|
53,549,543 |
|
|
|
(73,387,738 |
) |
|
|
1,666,997 |
|
Stock Issued in lieu of Compensation
|
|
|
1,390,787 |
|
|
|
1,390 |
|
|
|
- |
|
|
|
- |
|
|
|
168,160 |
|
|
|
- |
|
|
|
169,550 |
|
Preferred Series B 3.5% Dividend
|
|
|
- |
|
|
|
- |
|
|
|
18,720 |
|
|
|
187,200 |
|
|
|
- |
|
|
|
(376,034 |
) |
|
|
(188,834 |
) |
Net Loss
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
71,978 |
|
|
|
71,978 |
|
Reclassify Preferred B to Mezzanine
|
|
|
- |
|
|
|
- |
|
|
|
(2,164,054 |
) |
|
|
(21,640,538 |
) |
|
|
- |
|
|
|
- |
|
|
|
(21,640,538 |
) |
June 30, 2020 Balance
|
|
|
53,244,923 |
|
|
|
53,244 |
|
|
|
- |
|
|
|
- |
|
|
|
53,717,703 |
|
|
|
(73,691,794 |
) |
|
|
(19,920,847 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020 Balance
|
|
|
54,605,488 |
|
|
|
54,605 |
|
|
|
- |
|
|
|
- |
|
|
|
53,883,479 |
|
|
|
(82,298,785 |
) |
|
|
(28,360,701 |
) |
Stock Issued in lieu of Compensation
|
|
|
1,468,642 |
|
|
|
1,469 |
|
|
|
- |
|
|
|
- |
|
|
|
160,752 |
|
|
|
- |
|
|
|
162,221 |
|
Preferred Series B 3.5% Dividend
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(387,248 |
) |
|
|
(387,248 |
) |
Net Loss
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(1,595,671 |
) |
|
|
(1,595,671 |
) |
June 30, 2021 Balance
|
|
|
56,074,130 |
|
|
|
56,074 |
|
|
|
- |
|
|
|
- |
|
|
|
54,044,231 |
|
|
|
(84,281,704 |
) |
|
|
(30,181,399 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2020 Balance
|
|
|
52,231,899 |
|
|
|
52,231 |
|
|
|
- |
|
|
|
- |
|
|
|
53,602,502 |
|
|
|
(73,190,576 |
) |
|
|
(19,535,843 |
) |
Stock Issued in lieu of Compensation
|
|
|
1,013,024 |
|
|
|
1,013 |
|
|
|
- |
|
|
|
- |
|
|
|
115,201 |
|
|
|
- |
|
|
|
116,214 |
|
Preferred Series B 3.5% Dividend
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(188,834 |
) |
|
|
(188,834 |
) |
Net Loss
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(312,384 |
) |
|
|
(312,384 |
) |
June 30, 2020 Balance
|
|
|
53,244,923 |
|
|
|
53,244 |
|
|
|
- |
|
|
|
- |
|
|
|
53,717,703 |
|
|
|
(73,691,794 |
) |
|
|
(19,920,847 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2021 Balance
|
|
|
55,628,901 |
|
|
|
55,628 |
|
|
|
- |
|
|
|
- |
|
|
|
54,001,192 |
|
|
|
(83,062,670 |
) |
|
|
(29,005,850 |
) |
Stock Issued in lieu of Compensation
|
|
|
445,229 |
|
|
|
446 |
|
|
|
- |
|
|
|
- |
|
|
|
43,039 |
|
|
|
- |
|
|
|
43,485 |
|
Preferred Series B 3.5% Dividend
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(195,530 |
) |
|
|
(195,530 |
) |
Net Loss
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(1,023,504 |
) |
|
|
(1,023,504 |
) |
June 30, 2021 Balance
|
|
|
56,074,130 |
|
|
|
56,074 |
|
|
|
- |
|
|
|
- |
|
|
|
54,044,231 |
|
|
|
(84,281,704 |
) |
|
|
(30,181,399 |
) |
See notes to unaudited condensed consolidated financial
statements.
ROYALE ENERGY, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
NOTE 1 – In
the opinion of management, the accompanying unaudited condensed
consolidated financial statements (“statements”) include all
adjustments necessary to present fairly the Company’s financial
position and the results of its operations and cash flows for the
periods presented. The results of operations for the
six-month period are not, in management’s opinion, indicative of
the results to be expected for a full year of
operations. It is suggested that these financial
statements be read in conjunction with the financial statements and
the notes thereto included in the Company’s latest annual report as
filed on Form 10-K.
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 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. At
June 30, 2021, the Company has $1.0 million in Long Lived Assets
Held for Sale (see Prospective East LA Sale below).
At June 30, 2021, the Company’s consolidated financial statements
reflect a working capital deficiency of $5,120,939 and a net loss
from of $1,023,504 and $1,595,671 for three months and six months
ended June 30 2021. 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 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.
Prospective East LA
Sale
The Company and its joint venture partner, RMX, have entered into a
purchase and sales agreement as well as a second amendment to that
certain purchase and sales agreement extending the closing date to
the third quarter of 2021. The property is surface real estate
located in the city of Commerce, California, The Company
carries these assets on the books for $1.9 million with an ARO
amount of approximately $1.1 million for the existing wells and
facilities located on the properties providing a net book value of
approximately $0.846 million. The sale would require the Company to
plug and abandon the wells on the property and remove and restore
the surface land with an estimated cost of $0.721 million. The sale
price is approximately $1.0 million to the Company. Therefore, the
Company recorded a loss on the pending sale of these properties of
$0.567 million and reflect Assets Held for Sale of $1.0 million
reflected in current assets with an ARO balance of $0.721 million
in current liabilities at December 31, 2020.
Non-operated West Texas
Property Sale
During the six months ended June 30, 2021, we recorded a gain of
$291,249 on the sale of asset on the sale of certain non-operated
Texas properties. These non-operated properties were originally
acquired during the 2018 merger with Matrix Oil Management
Corporation and booked as Held for Sale at the end of 2020.
Consolidation
The accompanying financial statements include the accounts of
Royale Energy, Inc. (sometimes called the “Company” “we,” “our,”
“us,” “Royale Energy,” or “Royale”), Royale Energy Funds, Inc.
(“REF”), and Matrix Oil Management Corporation and its
subsidiaries. All entities comprising the financial
statements of Royale Energy have fiscal years ending December
31. All material intercompany accounts and transactions have
been eliminated in the financial statements.
Use of Estimates
The accompanying financial statements have been prepared in
conformity with accounting principles generally accepted in the
United States of America and requires management to make estimates
and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results
could differ from those estimates.
Material estimates that are particularly susceptible to significant
change relate to the estimate of Company oil and gas reserves
prepared by an independent engineering consultant. Such
estimates are subject to numerous uncertainties inherent in the
estimation of quantities of proven reserves. Estimated reserves are
used in the calculation of depletion, depreciation and
amortization, unevaluated property costs, impairment of oil and
natural gas properties, estimated future net cash flows, taxes, and
contingencies.
Revenue
Recognition
The majority of our ongoing revenues are derived from the sale of
crude oil and condensate, natural gas liquids ("NGLs") and natural
gas under spot and term agreements with our customers.
|
|
For the three months ended June 30
|
|
|
For the six months ended June 30
|
|
|
|
2021
|
|
|
2020
|
|
|
2021
|
|
|
2020
|
|
Oil & Condensate Sales
|
|
$ |
290,739 |
|
|
|
156,371 |
|
|
$ |
603,308 |
|
|
|
397,212 |
|
Natural Gas Sales
|
|
|
87,200 |
|
|
|
55,010 |
|
|
|
173,567 |
|
|
|
188,654 |
|
NGL Sales
|
|
|
- |
|
|
|
133 |
|
|
|
- |
|
|
|
133 |
|
Total
|
|
$ |
377,939 |
|
|
|
211,514 |
|
|
$ |
776,876 |
|
|
|
585,999 |
|
The pricing in our hydrocarbon sales agreements are variable,
determined using various published benchmarks which are adjusted
for negotiated quality and location differentials. As a result,
revenue collected under our agreements with customers is highly
dependent on the market conditions and may fluctuate considerably
as the hydrocarbon market prices rise or fall. Typically, our
customers pay us monthly, within a short period of time after we
deliver the hydrocarbon products. As such, we do not have any
financing element associated with our contracts. We do not have any
issues related to returns or refunds, as product specifications are
standardized for the industry and are typically measured when
transferred to a common carrier or midstream entity, and other
contractual mechanisms (e.g., price adjustments) are used when
products do not meet those specifications.
We often serve as the operator for jointly owned oil and gas
properties. As part of this role, we perform activities to explore,
develop and produce oil and gas properties in accordance with the
joint operating arrangement and collective decisions of the joint
parties. Other working interest owners reimburse us for costs
incurred based on our agreements. We determined that these
activities are not performed as part of customer relationships, and
such reimbursements are recorded as cost reimbursements.
We commonly market the share of production belonging to other
working interest owners as the operator of jointly owned oil and
gas properties. Those marketing activities are carried out as part
of the collaborative arrangement, and we do not purchase or
otherwise obtain control of other working interest owners’ share of
production. Therefore, we act as a principal only in regards to the
sale of our share of production and recognize revenue for the
volumes associated with our net production.
The Company frequently sells a portion of the working interest in
each well it drills or participates in, to third-party investors
and retains a portion of the prospect for its own account.
The Company typically guarantees a cost to drill to the third-party
drilling participants and records a loss or gain on the difference
between the guaranteed price and the actual cost to drill the
well. When monies are received from third parties for future
drilling obligations, the Company records the liability as Deferred
Drilling Obligations. Once the contracted depth for the
drilling of the well is reached and a determination as to the
commercial viability of the well (typically call “Casing Point
Election” or “Logging Point”), the difference in the actual cost to
drill and the guaranteed cost is recorded as income or expense
depending on whether there was a gain or loss.
Crude oil and
condensate
For the crude sales agreements, we satisfy our performance
obligations and recognize revenue once customers take control of
the crude at the designated delivery points, which include
pipelines, trucks or vessels.
Natural gas and
NGLs
When selling natural gas and NGLs, we engage midstream entities to
process our production stream by separating natural gas from the
NGLs. Frequently, these midstream entities also purchase our
natural gas and NGLs under the same agreements. In these
situations, we determined the performance obligation is complete
and satisfied at the tailgate of the processing plant when the
natural gas and NGLs become identifiable and measurable products.
We determined the plant tailgate is the point in time where
control, as defined in the new revenue standard, is transferred to
midstream entities and they are entitled to significant risks and
rewards of ownership of the natural gas and NGLs.
The amounts due to midstream entities for gathering and processing
services are recognized as shipping and handling cost and included
as lease operating expense in our consolidated statement of
operations, since we make those payments in exchange for distinct
services with the exception of natural gas sold to Pacific Gas
& Electric (PG&E) where transportation is netted directly
against revenue. Under some of our natural gas processing
agreements, we have an option to take the processed natural gas and
NGLs in-kind and sell to customers other than the processing
company. In those circumstances, our performance obligations are
complete after delivering the processed hydrocarbons to the
customer at the designated delivery points, which may be the
tailgate of the processing plant or an alternative delivery point
requested by the customer.
Turnkey Drilling
Royale sponsors turnkey drilling arrangements in proved and
unproved properties. The contracts require that participants pay
Royale the full contract price upon execution of the drilling
agreement. Each participant earns an undivided interest in the well
bore at the completion of the well. A portion of the funds received
in advance of the drilling of a well from a working interest
participant are held for the expressed purpose of drilling a well.
If something changes, the Company may designate these funds for a
substitute well. Under certain conditions, a portion of these funds
may be required to be returned to a participant. Once the well is
drilled, the funds are used to satisfy the drilling cost.
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.
Restricted Cash
Royale sponsors turnkey drilling arrangements in proved and
unproved properties. The contracts require that participants pay
Royale the full contract price upon execution of the drilling
agreement. Each participant earns an undivided interest in the well
bore at the completion of the well. A portion of the funds received
in advance of the drilling of a well from a working interest
participant are held for the expressed purpose of drilling a well.
If something changes, the Company may designate these funds for a
substitute well. Under certain conditions, a portion of these funds
may be required to be returned to a participant. Once the well is
drilled, the funds are used to satisfy the drilling cost. Royale
classifies these funds prior to commencement of drilling as
restricted cash based on guidance codified as under the Financial
Accounting Standards Board (“FASB”) Accounting Standards
Codification (“ASC”) 230-10-50-8. In the event that progress
payments are made from these funds, they are recorded as Prepaid
Expenses and Other Current Assets.
The following table provides a reconciliation of cash, cash
equivalents, and restricted cash reported within the consolidated
balance sheet that sum to the total of the same amounts shown in
the statement of cash flows.
|
|
June 30,
2021
|
|
|
December 31, 2020
|
|
Cash and Cash Equivalents
|
|
$ |
603,075 |
|
|
$ |
255,112 |
|
Restricted Cash
|
|
|
2,271,556 |
|
|
|
2,146,571 |
|
Total cash, cash equivalents, and restricted cash shown in the
statement of cash flows
|
|
$ |
2,874,631 |
|
|
$ |
2,401,683 |
|
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.
At year-end 2020, we evaluated our investment in RMX and determined
that the investment was fully impaired at December 31, 2020. As a
result of the valuation allowance, the Company has not included any
gain or loss on its Investment in Joint Venture for the period
ended June 30, 2021. During the period ended June 30, 2020, the
Company recorded a gain of $833,525 reflecting our share of net
earnings or losses directly attributable to this equity method
investment. For the period ending June 30, 2021, no gain or loss
was recorded as a result of full impairment of the investment
balance at December 31, 2020.
Other
Receivables
Other receivables consist of joint interest billing receivables
from direct working interest investors and industry partners. We
provide for uncollectible accounts receivable using the allowance
method of accounting for bad debts. Under this method of
accounting, a provision for uncollectible accounts is charged
directly to bad debt expense when it becomes probable the
receivable will not be collected. The allowance account
is increased or decreased based on past collection history and
management’s evaluation of accounts receivable. All
amounts considered uncollectible are charged against the allowance
account and recoveries of previously charged off accounts are added
to the allowance. At June 30, 2021 and December 31,
2020, the Company maintained an allowance for uncollectable
accounts of $2,761,398 and $2,582,093, for receivables from direct
working interest investors whose expenses on non-producing wells
were unlikely to be collected from revenue.
Fair Value
Measurements
According to Fair Value Measurements and Disclosures Topic of the
FASB ASC, assets and liabilities that are measured at fair value on
a recurring and nonrecurring basis in period subsequent to initial
recognition, the reporting entity shall disclose information that
enable users of its financial statements to assess the inputs used
to develop those measurements and for recurring fair value
measurements using significant unobservable inputs, the effect of
the measurements on earnings for the period.
Fair value is defined as the price that would be received to sell
an asset or paid to transfer a liability in an orderly transaction
between market participants at the measurement date. In determining
fair value, the Company utilizes valuation techniques that maximize
the use of observable inputs and minimize the use of unobservable
inputs to the extent possible as well as considers counterparty
credit risk in its assessment of fair value. Carrying amounts of
the Company’s financial instruments, including cash equivalents,
accounts receivable, accounts payable and accrued liabilities,
approximate their fair values as of the balance sheet dates because
of their generally short maturities.
The fair value hierarchy distinguishes between (1) market
participant assumptions developed based on market data obtained
from independent sources (observable inputs) and (2) an entity’s
own assumptions about market participant assumptions developed
based on the best information available in the circumstances
(unobservable inputs). The fair value hierarchy consists of three
broad levels, which gives the highest priority to unadjusted quoted
prices in active markets for identical assets or liabilities (Level
1) and the lowest priority to unobservable inputs (Level 3). The
three levels of the fair value hierarchy are described below:
Level 1: Quoted prices (unadjusted) in active markets that are
accessible at the measurement date for assets or liabilities.
Level 2: Directly or indirectly observable inputs as of the
reporting date through correlation with market data, including
quoted prices for similar assets and liabilities in active markets
and quoted prices in markets that are not active. Level 2 also
includes assets and liabilities that are valued using models or
other pricing methodologies that do not require significant
judgment since the input assumptions used in the models, such as
interest rates and volatility factors, are corroborated by readily
observable data from actively quoted markets for substantially the
full term of the financial instrument.
Level 3: Unobservable inputs that are supported by little or no
market activity and reflect the use of significant management
judgment. These values are generally determined using pricing
models for which the assumptions utilize management’s estimates of
market participant assumptions.
At June 30, 2021 and December 31, 2020, Royale Energy does not have
any financial assets measured and recognized at fair value on a
recurring basis. The Company estimates asset retirement
obligations (ARO’s) pursuant to the provisions of ASC 410,
“Asset Retirement and Environmental Obligations”. The
estimates of the fair value the ARO’s are based on discounted cash
flow projections using numerous estimates, assumptions and
judgements regarding such factors as the existence of a legal
obligation for an ARO, amounts and timing of settlements, the
credit-adjusted risk-free rate to be used and inflation rates.
The initial measurement of asset retirement obligations at fair
value is calculated using discounted cash flow techniques and based
on internal estimates of future retirement costs associated with
oil and gas properties. Given the unobservable nature of the
inputs, including plugging costs and reserve lives, the initial
measurement of the asset retirement obligation liability is deemed
to use Level 3 inputs.
Fair Values -
Non-recurring
The Company applies the provisions of the fair value measurement
standard to its non-recurring, non-financial measurements including
oil and natural gas property impairments and other long-lived asset
impairments. These items are not measured at fair value on a
recurring basis but are subject to fair value adjustments only in
certain circumstances.
Dividends on Series B
Convertible Preferred Stock
The Series B Convertible Preferred Stock, (“Preferred”), has an
obligation to pay a 3.5% cumulative dividend, in kind or cash, on a
quarterly basis. In the third quarter of 2020, the Board of
Directors authorized the issuance of Preferred shares, for the
settlement of dividends accumulated through December 31,
2021. The Company accrued $195,530 and $188,834 for dividends
related to the Preferred shares during the second quarters of 2021
and 2020, respectively. Each quarter, the Company charges retained
earnings for the accumulating dividend as the amounts add to the
liquidation preference of the Preferred. For further information
regarding the Preferred Stock see Note 3, below.
Risks and
Uncertainties
In December 2019, a novel strain of coronavirus (which triggers a
respiratory disease called COVID-19) was reported in Wuhan, China.
The World health Organization has declared the outbreak to
constitute a “Public Health Emergency of International
Concern.” The COVID-19 outbreak has caused a major reduction
in the consumption of hydrocarbon-based transportation fuels as
airlines have grounded flights worldwide and countries around the
world have asked residents to suspend automobile travel. In
addition to a substantial loss of demand for crude oil, In March,
Saudi Arabia entered into a price war with Russia and added
additional supplies of crude oil to an already over supplied
market. The result was a precipitous decline in the price of crude
oil received by the Company in 2020. At June 30, 2021 the price of
West Texas Intermediate crude oil had reached $71.30 per
barrel.
ACCOUNTING STANDARDS
Not Yet Adopted
ASU 2016-13, Credit Impairment
In June of 2016, the FASB issued ASC Topic 326, Financial
Instruments – Credit Losses. This new guidance replaces the
current incurred loss impairment model with a requirement to
recognize lifetime expected credit losses immediately when a
financial asset is originated or purchased. This new Current
Expected Credit Losses (“CECL”) model applies to (1) loans,
accounts receivable, trade receivables, and other financial assets
measured at amortized cost, (2) loan commitments and certain other
off-balance sheet credit exposures, (3) debt securities and
financial assets measured at fair value, and (4) beneficial
interests in securitized financial assets. This ASU was effective
for SEC filers beginning after December 15, 2019; however, on
November 15, 2019, the FASB issued ASU 2019-10, which delayed the
effective date for “smaller reporting companies.” Therefore, ASU
2016-13 is effective for "smaller reporting companies" (as defined
by the Securities and Exchange Commission) such as Royale, for
fiscal years beginning after December 15, 2022, including interim
periods within those years, and must be adopted under the modified
retrospective method. Entities may adopt ASU 2016-13 earlier as of
the fiscal years beginning after December 15, 2018, including
interim periods within those years. Adoption of this standard is
not expected to have a material impact on our consolidated
financial statements and cash flows.
NOTE 2
– OIL AND GAS
PROPERTY AND EQUIPMENT AND FIXTURES
Oil and gas properties, equipment and fixtures consist of the
following:
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2021
|
|
|
2020
|
|
|
|
(Unaudited)
|
|
|
|
|
|
Oil and Gas
|
|
|
|
|
|
|
|
|
Producing properties, including drilling costs
|
|
$ |
5,672,457 |
|
|
$ |
5,672,457 |
|
Undeveloped properties
|
|
|
23,766 |
|
|
|
13,993 |
|
Lease and well equipment
|
|
|
3,317,718 |
|
|
|
3,317,718 |
|
|
|
|
9,013,941 |
|
|
|
9,004,168 |
|
|
|
|
|
|
|
|
|
|
Accumulated depletion, depreciation & amortization
|
|
|
(6,707,976 |
) |
|
|
(6,467,626 |
) |
Net capitalized costs Total
|
|
|
2,305,965 |
|
|
|
2,536,542 |
|
|
|
|
|
|
|
|
|
|
Commercial and Other
|
|
|
|
|
|
|
|
|
Vehicles
|
|
|
40,061 |
|
|
|
40,061 |
|
Furniture and equipment
|
|
|
1,097,428 |
|
|
|
1,097,428 |
|
|
|
|
1,137,489 |
|
|
|
1,137,489 |
|
Accumulated depreciation
|
|
|
(1,133,743 |
) |
|
|
(1,133,030 |
) |
|
|
|
3,746 |
|
|
|
4,459 |
|
Net capitalized costs Total
|
|
$ |
2,309,711 |
|
|
$ |
2,541,001 |
|
The guidance set forth in the Continued Capitalization of
Exploratory Well Costs paragraph of the Extractive Activities Topic
of the FASB ASC requires that we evaluate all existing capitalized
exploratory well costs and disclose the extent to which any such
capitalized costs have become impaired and are expensed or
reclassified during a fiscal period.
Depreciation, depletion and amortization, based on cost less
estimated salvage value of the asset, are primarily determined
under either the unit-of-production method or the straight-line
method, which is based on estimated asset service life taking
obsolescence into consideration. Maintenance and repairs
are expensed as incurred. Major renewals and
improvements are capitalized and the assets replaced are
retired.
The project construction phase commences with the development of
the detailed engineering design and ends when the constructed
assets are ready for their intended use. Interest costs,
to the extent they are incurred to finance expenditures during the
construction phase, are included in property, plant and equipment
and are depreciated over the service life of the related
assets.
Royale Energy uses the “successful efforts” method to account for
its exploration and production activities. Under this
method, Royale Energy accumulates its proportionate share of costs
on a well-by-well basis with certain exploratory expenditures and
exploratory dry holes being expensed as incurred and
capitalizes expenditures for productive wells. Royale
Energy amortizes the costs of productive wells under the
unit-of-production method.
Royale Energy carries, as an asset, exploratory well costs when the
well has found a sufficient quantity of reserves to justify its
completion as a producing well and where Royale Energy is making
sufficient progress assessing the reserves and the economic and
operating viability of the project. Exploratory well
costs not meeting these criteria are charged to expense. Other
exploratory expenditures, including geophysical costs and annual
lease rentals, are expensed as incurred.
Acquisition costs of proved oil and gas properties are amortized
using a unit-of-production method, computed on the basis of total
proved oil and gas reserves.
Capitalized exploratory drilling and development costs associated
with productive depletable extractive properties are amortized
using unit-of-production rates based on the amount of proved
developed reserves of oil and gas that are estimated to be
recoverable from existing facilities using current operating
methods. Under the unit-of-production method, oil and
gas volumes are considered produced once they have been measured
through meters at custody transfer or sales transaction points at
the outlet valve on the lease or field storage tank.
Production costs are expensed as incurred. Production involves
lifting the oil and gas to the surface and gathering, treating,
field processing and field storage of the oil and gas. The
production function normally terminates at the outlet valve on the
lease or field production storage tank. Production costs are those
incurred to operate and maintain Royale Energy’s wells and related
equipment and facilities. They become part of the cost of oil and
gas produced. These costs, sometimes referred to as lifting costs,
include such items as labor costs to operate the wells and related
equipment; repair and maintenance costs on the wells and equipment;
materials, supplies and energy costs required to operate the wells
and related equipment; and administrative expenses related to the
production activity. Proved oil and gas properties held and used by
Royale Energy are reviewed for impairment whenever events or
changes in circumstances indicate that the carrying amounts may not
be recoverable.
Royale Energy estimates the future undiscounted cash flows of the
affected properties to judge the recoverability of carrying amounts
and whether carrying amounts should be impaired. The Company
performs the evaluation of carrying amounts at least annually or
when economic events or commodity prices indicate that a
substantial and measurable change in future cash flows has
occurred. Cash flows used in impairment evaluations are developed
using updated evaluation assumptions for crude oil and natural gas
commodity prices. Annual volumes are based on field
production profiles, which are also updated annually.
Impairment analyses are generally based on proved reserves. An
asset group would be further assessed if the undiscounted cash
flows were less than its’ carrying value. Impairments
are measured by the amount the carrying value exceeds fair value.
During the six months ended June 30, 2021 and 2020, no impairment
losses were incurred.
Significant unproved properties are assessed for impairment
individually, and valuation allowances against the capitalized
costs are recorded based on the estimated economic chance of
success and the length of time that Royale Energy expects to hold
the properties. The valuation allowances are reviewed at
least annually.
Upon the sale or retirement of a complete field of a proved
property, Royale Energy eliminates the cost from its books, and the
resultant gain or loss is recorded to Royale Energy’s Statement of
Operations. Upon the sale of an entire interest in an
unproved property where the property has been assessed for
impairment individually, a gain or loss is recognized in Royale
Energy’s Statement of Operations. If a partial interest
in an unproved property is sold, any funds received are accounted
for as a recovery of the cost in the interest retained with any
excess funds recognized as a gain. Should Royale Energy’s turnkey
drilling agreements include unproved property, total drilling costs
incurred to satisfy its obligations are recovered by the total
funds received under the agreements. Any excess funds
are recorded as a Gain on Turnkey Drilling Programs, and any costs
not recovered are capitalized and accounted for under the
“successful efforts” method.
Royale Energy sponsors turnkey drilling agreement arrangements
in unproved properties as a pooling of assets in a joint
undertaking, whereby proceeds from participants are reported as
Deferred Drilling Obligations, and then reduced as costs to
complete its obligations are incurred with any excess booked
against its property account to reduce any basis in its own
interest. Gains on Turnkey Drilling Programs represent
funds received from turnkey drilling participants in excess of all
costs Royale incurs during the drilling programs (e.g., lease
acquisition, exploration and development costs), including costs
incurred on behalf of participants and costs incurred for its own
account; and are recognized only upon making this determination
after Royale’s obligations have been fulfilled.
The contracts require the participants pay Royale Energy the full
contract price upon execution of the agreement. Royale
Energy completes the drilling activities typically between 10 and
30 days after drilling begins. The participant retains
an undivided or proportional beneficial interest in the property
and is also responsible for its proportionate share of operating
costs. Royale Energy retains legal title to the
lease. The participants purchase a working interest
directly in the well bore.
In these working interest arrangements, the participants are
responsible for sharing in the risk of development, but also
sharing in a proportional interest in rights to revenues and
proportional liability for the cost of operations after drilling is
completed and the interest is conveyed to the participant.
A certain portion of the turnkey drilling participant’s funds
received are non-refundable. The Company holds all funds
invested as Deferred Drilling Obligations until drilling is
complete. Occasionally, drilling is delayed for various
reasons such as weather, permitting, drilling rig availability
and/or contractual obligations. At June 30, 2021 and
December 31, 2020, Royale Energy had Deferred Drilling Obligations
of $4,047,439 and $3,127,500, respectively.
If Royale Energy is unable to drill the wells, and a suitable
replacement well is not found, Royale would retain the
non-refundable portion of the contract and return the remaining
funds to the participant. Included in Restricted Cash
are amounts for use in completion of turnkey drilling programs in
progress.
Losses on properties sold are recognized when incurred or when the
properties are held for sale and the fair value of the properties
is less than the carrying value.
During the six months ended June 30, 2021, we recorded a gain of
$291,249 on the sale of asset on the sale of certain non-operated
Texas properties. These non-operated properties were originally
acquired during the 2018 merger with Matrix Oil Management
Corporation and booked as Held for Sale at the end of 2020.
NOTE 3
– 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% annual dividend, payable quarterly in cash or
Paid-In-Kind (“PIK”) 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.
In accordance with ASC 480-10-S99-1.02, the Company has determined
that the conversion or redemption of these shares are outside the
sole control of the Company and that they should be classified in
mezzanine or temporary equity as redeemable noncontrolling interest
beginning at the reporting period, ended March 31, 2020.
For 2021 and 2020, the board authorized the payment of each
quarterly dividend of Series B Convertible Preferred shares, as
Paid-In-Kind shares (“PIK”) to be paid immediately following the
end of the quarter. For the quarter ending June 30, 2021, the
Company accrued 19,553 shares with a value of $195,530. During 2021
and 2020 no cash was used to pay dividends on Series B preferred
shares.
NOTE 4
– LOSS PER
SHARE
Basic and diluted loss per share are calculated as follows:
|
|
Three Months Ended June 30,
|
|
|
|
2021
|
|
|
2020
|
|
|
|
Basic
|
|
|
Diluted
|
|
|
Basic
|
|
|
Diluted
|
|
Net (Loss)
|
|
$ |
(1,023,504 |
) |
|
$ |
(1,023,504 |
) |
|
$ |
(312,384 |
) |
|
$ |
(312,384 |
) |
Less: Preferred Stock Dividend
|
|
|
195,530 |
|
|
|
195,530 |
|
|
|
188,834 |
|
|
|
188,834 |
|
Net (Loss) Attributable to Common Shareholders
|
|
|
(1,219,034 |
) |
|
|
(1,219,034 |
) |
|
|
(501,218 |
) |
|
|
(501,218 |
) |
Weighted average common shares outstanding
|
|
|
55,909,271 |
|
|
|
55,909,271 |
|
|
|
52,987,786 |
|
|
|
52,987,786 |
|
Effect of dilutive securities
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Weighted average common shares, including Dilutive effect
|
|
|
55,909,271 |
|
|
|
55,909,271 |
|
|
|
52,987,786 |
|
|
|
52,987,786 |
|
Per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (Loss)
|
|
$ |
(0.02 |
) |
|
$ |
(0.02 |
) |
|
$ |
(0.01 |
) |
|
$ |
(0.01 |
) |
|
|
Six Months Ended June 30,
|
|
|
|
2021
|
|
|
2020
|
|
|
|
Basic
|
|
|
Diluted
|
|
|
Basic
|
|
|
Diluted
|
|
Net Income (Loss)
|
|
$ |
(1,595,671 |
) |
|
$ |
(1,595,671 |
) |
|
$ |
71,978 |
|
|
$ |
71,978 |
|
Less: Preferred Stock Dividend
|
|
|
387,248 |
|
|
|
387,248 |
|
|
|
376,034 |
|
|
|
376,034 |
|
Net Income (Loss) Attributable to Common Shareholders
|
|
|
(1,982,919 |
) |
|
|
(1,982,919 |
) |
|
|
(304,056 |
) |
|
|
(304,056 |
) |
Weighted average common shares outstanding
|
|
|
55,529,082 |
|
|
|
55,529,082 |
|
|
|
52,550,857 |
|
|
|
52,550,857 |
|
Effect of dilutive securities
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Weighted average common shares, including Dilutive effect
|
|
|
55,529,082 |
|
|
|
55,529,082 |
|
|
|
52,550,857 |
|
|
|
52,550,857 |
|
Per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (Loss)
|
|
$ |
(0.04 |
) |
|
$ |
(0.04 |
) |
|
$ |
(0.01 |
) |
|
$ |
(0.01 |
) |
For the six months ended June 30, 2021 and 2020, Royale Energy had
dilutive securities of 26,063,735 and 25,157,462, respectively. For
the three months ended June 30, 2021 and 2020, Royale Energy had
dilutive securities of 25,985,121 and 25,165,320, respectively. In
both periods, these securities were not included in the dilutive
loss per share, due to their antidilutive nature.
NOTE 5 –
INCOME
TAXES
Deferred tax assets and liabilities reflect the net tax effect of
temporary differences between the carrying amount of assets and
liabilities for financial reporting purposes and amounts used for
income tax purposes. Deferred tax assets are reduced by
a valuation allowance when, in the opinion of management, it is
more-likely-than-not that some portion or all of the deferred tax
assets will not be realized. Deferred tax assets and liabilities
are adjusted for the effects of changes in tax laws and rates on
the date of enactment. At the end of 2015, management
reviewed the reliability of the Company’s net deferred tax assets,
and due to the Company’s continued cumulative losses in recent
years, the Company concluded it is not “more-likely-than-not” its
deferred tax assets will be realized. As a result, the
Company will continue to record a full valuation allowance against
the deferred tax assets in 2021.
A reconciliation of Royale Energy’s provision for income taxes and
the amount computed by applying the statutory income tax rates at
June 30, 2021 and 2020, respectively, to pretax income is as
follows:
|
|
For the six months ended
|
|
|
|
June 30, 2021
|
|
|
June 30, 2020
|
|
|
|
|
|
|
|
|
|
|
Tax provision (benefit) computed at statutory rate of 21% at
June 30, 2021 and 2020, respectively
|
|
$ |
(335,091 |
) |
|
$ |
17,205 |
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in taxes resulting from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State tax / percentage depletion / other
|
|
|
4,411 |
|
|
|
|
|
Other non-deductible expenses
|
|
|
(1,485 |
) |
|
|
346 |
|
Change in valuation allowance
|
|
|
332,165 |
|
|
|
(17,551 |
) |
Provision (benefit)
|
|
$ |
- |
|
|
$ |
- |
|
NOTE 6 –
ISSUANCE OF COMMON
STOCK
During the six months ended June 30, 2021, in lieu of cash payments
for salaries and board fees, Royale issued 1,468,642 shares of its
Common stock valued at approximately $162,221 to an executive
officer and board members, compared to the issuance of 1,390,787
shares issued with an approximate value of $169,550 in the same
period of 2020.
Item 2. Management’s Discussion and Analysis of Financial
Condition and Results of Operations
FORWARD-LOOKING STATEMENTS
In addition to historical information contained herein, this
discussion contains “forward-looking statements” within the meaning
of the Private Securities Litigation Reform Act of 1995, subject to
various risks and uncertainties that could cause our actual results
to differ materially from those in the “forward-looking
statements”. While we believe our forward-looking statements are
based upon reasonable assumptions, there are factors that are
difficult to predict and that are influenced by economic and other
conditions beyond our control. Investors are directed to consider
such risks and other uncertainties discussed in documents filed by
the Company with the Securities and Exchange Commission.
RESULTS OF OPERATIONS
In late 2019 and continuing into 2021, there was a global outbreak
of novel coronavirus (COVID-19) that has resulted in changes in
global supply and demand of certain mineral and energy products.
While the direct and indirect negative impacts that may affect the
Company cannot be determined, they could have a prospective
material impact. For more information, see Item 3 below.
For the six months ended June 30, 2021, we had a net loss of
$1,595,671 compared to the net income of $71,978, during the six
months ended June 30, 2020. The difference was primarily the result
of a gain of $833,525 relating to our equity method investment in
RMX recorded during the six months ended June 30, 2020. During the
fourth quarter in 2020, it was determined that a full impairment of
the equity method investment was warranted, so there was no
comparative gain or loss in the current year period. During the
three months ended June 30, 2021 and 2020, we had net losses of
$1,023,504 and $312,384, respectively mainly due to higher turnkey
drilling costs during the second quarter in 2021 as additional work
on wells drilled during the first quarter was performed to improve
production.
During the first six months of 2021, revenues from oil and gas
production increased $190,877 or 32.6% to $776,876 from the 2020
first six months revenues of $585,999. This increase was mainly due
to higher oil and natural gas commodity prices. The net sales
volume of oil and condensate for the six months ended June 30,
2021, was approximately 10,171 barrels with an average price of
$59.32 per barrel, versus 11,499 barrels with an average price of
$34.54 per barrel for the first half of 2020. This represents a
decrease in net sales volume of 1,328 barrels or 11.5%. The net
sales volume of natural gas for the six months ended June 30, 2021,
was approximately 61,290 Mcf with an average price of $2.83 per
Mcf, versus 83,040 Mcf with an average price of $2.27 per Mcf for
the same period in 2020. This represents a decrease in net sales
volume of 21,750 Mcf or 26.2%. The decrease in natural gas
production volume was due to certain wells that were offline and
waiting on workovers and to lower volumes on existing wells due to
natural declines. For the quarter ended June 30, 2021, revenues
from oil and gas production increased $166,425 or 78.7% to $377,939
from the 2020 second quarter revenues of $211,514. This increase
was also due to higher oil and natural gas commodity prices. The
net sales volume of oil and condensate for the quarter ended June
30, 2021, was approximately 4,597 barrels with an average price of
$63.25 per barrel, versus 6,468 barrels with an average price of
$24.18 per barrel for the second quarter of 2020. This represents a
decrease in net sales volume of 1,871 barrels or 28.9% for the
quarter in 2020. The net sales volume of natural gas for the
quarter ended June 30, 2021, was approximately 31,631 Mcf with an
average price of $2.76 per Mcf, versus 30,587 Mcf with an average
price of $1.80 per Mcf for the second quarter of 2020. This
represents an increase in net sales volume of 1,044 Mcf or 3.4% for
the quarter in 2021.
Oil and natural gas lease operating expenses decreased by $65,387
or 8.4%, to $713,371 for the six months ended June 30, 2021, from
$778,758 for the same period in 2020. This was due mainly to lower
outside operated lease costs due to the sale of certain
non-operated Texas wells during the period in 2021. For the second
quarter in 2021, lease operating expenses increased $37,904 or
10.1% from the same quarter in 2020, mainly due to work on existing
wells in our operated Texas field to increase production.
The aggregate of supervisory fees and other income was $18,102 for
six months ended June 30, 2021, a decrease of $2,854 from $20,956
during the same period in 2020. During the second quarter 2021,
supervisory fees and other income increased $4,149 or 35.7% when
compared to the quarter in 2020, due mainly to higher rental
income.
Depreciation, depletion and amortization expense increased to
$294,361 from $155,625, an increase of $138,736 or 89.1% for the
six months ended June 30, 2021, as compared to the same period in
2020. During the second quarter 2021, depreciation, depletion and
amortization expenses also increased $94,266 or 124.5%. The
depletion rate is calculated using production as a percentage of
reserves. This increase in depreciation expense was due to a
decrease in expected recoverable reserves which increased the
depletion rate.
At June 30, 2021, Royale Energy had a Deferred Drilling Obligation
of $4,047,439. During the first six months of 2021, we disposed of
$1,841,061 of drilling obligations upon completing the drilling of
two oil wells in Texas, while incurring expenses of $1,900,199,
resulting in a loss of $59,138. Although these two wells were
originally drilled during the first quarter of 2021, we continued
additional work during second quarter 2021 to increase production.
At June 30, 2020, Royale Energy had a Deferred Drilling Obligation
of $2,531,094. During the first six months of 2020, we disposed of
$3,901,582 of drilling obligations upon completing the drilling of
three oil wells, one in California and two wells in Texas, while
incurring expenses of $2,991,134, resulting in a gain of
$910,448.
General and administrative expenses increased by $1,325 or 0.1%
from $1,075,340 for the six months ended June 30, 2020, to
$1,076,665 for the same period in 2021. For the second quarter
2021, general and administrative expenses decreased $42,595 or 7.7%
when compared to the same period in 2020. Marketing expense for the
six months ended June 30, 2021, increased $27,431, or 49.8%, to
$82,495, compared to $55,064 for the same period in 2020. For the
second quarter 2021, marketing expenses increased $22,776 or 110.2%
when compared to the second quarter in 2020. Marketing expense
varies from period to period according to the number of marketing
events attended by personnel and their associated costs.
Legal and accounting expense increased to $276,000 for the
six-month period in 2021, compared to $174,660 for the same period
in 2020, a $101,340 or 58.0% increase. This increase was primarily
due to higher audit related expenses during the period in 2021. For
the second quarter 2021, legal and accounting expenses decreased
$30,888 or 35.1%, when compared to the second quarter in 2020,
mainly due to lower legal fees.
During the six months ended June 30, 2021, we recorded a gain of
$291,249 on the sale of asset on the sale of certain non-operated
Texas properties. These non-operated properties were originally
acquired during the merger with Matrix and booked as Held for Sale
at the end of 2020. During the first quarter of 2021, we recorded a
gain on settlement of $10,061 due to the payment by the SBA of the
remaining balance on our PPP loan obtained in 2020. During the six
months ended June 30, 2020, we recorded a gain of $833,525, on
investment in joint venture as our 20% share of RMX Resources,
LLC’s. As a result of recognizing an impairment for the full value
of the investment, the company did not recognize any gain or loss
in subsequent periods. See note Equity Method Investment in Note 1
above. During the second quarter in 2020 we recorded a gain of
$200,001 on the receipt of a pre-Matrix merger prepayment refund.
During the first quarter in 2020, we recorded a loss on settlement
of $31,500 related to a 2018 seismic sales agreement. During the
six-month period in 2020, we recorded $14,392 in geological and
geophysical expenses.
Bad debt expense for the six months ended June 30, 2021, and 2020
were $187,348 and $186,168, respectively. Approximately
$180,000 of the expenses in 2021 and $80,000 of the expenses in
2020 arose from identified uncollectable receivables relating to
our oil and natural gas properties either plugged and abandoned or
scheduled for plugging and abandonment and our period end oil and
natural gas reserve values. We periodically review our
accounts receivable from working interest owners to determine
whether collection of any of these charges appears
doubtful. By contract, the Company may not collect some
charges from its Direct Working Interest owners for certain wells
that ceased production or had been sold during the year, to the
extent that these charges exceed production revenue. During the
period in 2020 approximately $106,000 was related to revenue
receivable from an industry partner whose collectability was in
doubt.
Interest expense decreased to $4,591 for the six months ended June
30, 2021, from $7,444 for the same period in 2020, a $2,853
decrease. This decrease was mainly due to lower
principal balances on notes payable during the six-month period in
2021.
CAPITAL RESOURCES AND LIQUIDITY
At June 30, 2021, we had current assets totaling $4,984,552 and
current liabilities totaling $10,105,491, a $5,120,939 working
capital deficit. We had $603,075 in cash and $2,271,556
in restricted cash at June 30, 2021, compared to $255,112 in cash
and $2,146,571 in restricted cash at December 31, 2020.
In accordance with ASC 480-10-S99 the Company reclassified the
Series B Convertible Preferred Stock from Permanent Equity to
Mezzanine capital as a result of the change in voting rights
provided at the time it of issuance. For more information, see Note
3 – Series B Convertible Preferred Stock.
At June 30, 2021, our other receivables, which consist of joint
interest billing receivables from direct working interest investors
and industry partners, totaled $274,884 compared to $462,777 at
December 31, 2020, a $187,893 decrease. This decrease
was mainly due to the increase in the accounts receivable allowance
from direct working interest owners. At June 30, 2021, revenue
receivable was $355,990, an increase of $151,841, compared to
$204,149 at December 31, 2020, due to higher commodity prices
during the quarter in 2021. At June 30, 2021, our
accounts payable and accrued expenses totaled $4,481,815, an
increase of $320,706 from the accounts payable at December 31, 2020
of $4,161,109, which was mainly due to drilling costs and lease
operating costs during the first six months in 2021.
The Company has had recurring operating and net losses and cash
used in operations and the financial statements reflect a working
capital deficiency of $5,120,939 and an accumulated deficit of
$84,281,704. These factors raise substantial doubt about our
ability to continue as a going concern. We anticipate that our
primary sources of liquidity will be from the sale of oil and gas
in the course of normal operations, the sale of oil and gas
property, sales of participation interest and possible issuance of
debt and/or equity. If the Company is unable to generate sufficient
cash from operations or financing sources, it may become necessary
to curtail, suspend or cease operations, sell property, or enter
into financing transaction(s) on less favorable terms; any such
outcomes could have a material adverse effect on the Company’s
business, results of operations, financial position and liquidity.
Additionally, management has, and plans to continue, to increase
revenue and reduce overhead and Lease Operating Expense (LOE)
costs.
Operating Activities. Net cash used in operating
activities totaled $882,420 for the six months ended June 30, 2021.
Net cash provided by operating activities was $334,538 for the six
months ended June 30, 2020. This difference in cash was
due to accounts payable and accrued expenses and prepaid assets
during the periods related mainly to the wells drilled during the
periods, as we used more prepaid drilling funds during the period
in 2020.
Investing Activities. Net cash provided by
investing activities totaled $1,380,582 and net cash used in
investing activities totaled $2,767,301 for the six months ended
June 30, 2021, and 2020, respectively. During the six month period
in 2021, we received approximately $2.8 million in direct working
interest investor turnkey drilling investments while our drilling
expenditures were approximately $2.0 million in the drilling and
completing of two Texas oil wells. During the period in 2021, we
also received approximately $672,000 for the sale of non-operated
properties in Texas. During the period in 2020, we received
approximately $1.2 million in direct working interest investor
turnkey drilling investments while our drilling expenditures were
approximately $4.0 million in the drilling and completing of one
Southern California oil well and two Texas oil wells.
Financing Activities. Net cash used in financing
activities totaled $25,214 and net cash provided by financing
activities was $147,319 for the six months ended June 30, 2021, and
2020, respectively. During the period in 2021, the total used was
for note and financing lease payments while during the period in
2020, we received $207,800 in SBA-PPP loan and made principal
payments of approximately $56,000 on existing notes payable.
Item 3. Quantitative and Qualitative Disclosures About Market
Risk
In late 2019 and continuing into 2021, there was a global outbreak
of COVID-19 that has resulted in changes in global supply and
demand of certain mineral and energy products. While the direct and
indirect negative impacts that may affect the Company cannot be
determined, they could have a prospective material impact to the
Company's operations, cash flows and liquidity, primarily related
to the decline in product price, in part, as a result of a decline
in demand related to “shelter-in-place” orders by various
governmental bodies.
Our major market risk exposure relates to pricing of oil and gas
production, which during the period in 2020 resulted in
historically low prices due to stay at home orders. The
prices we receive for oil and gas are closely related to worldwide
market prices for crude oil and local spot prices paid for natural
gas production. Prices have been volatile for the last
several years and have become even more unpredictable in the
current period. We expect that volatility to
continue. Our monthly average oil and condensate prices
ranged from a high of $63.92 per barrel to a low of $55.56 per
barrel and our monthly average natural gas prices ranged from a
high of $3.64 per Mcf to a low of $2.50 per Mcf for the first six
months of 2021.
Item 4. Controls and Procedures
As of June 30, 2021, an evaluation was performed under the
supervision and with the participation of our management, including
our CEO and CFO, of the effectiveness of the design and operation
of our disclosure controls and procedures. These
controls and procedures are based on the definition of disclosure
controls and procedures in Rule 13a-15(e) and Rule 15d-15(e)
promulgated under the Securities Exchange Act of 1934. A
material weakness is a deficiency, or a combination of
deficiencies, in internal control over financial reporting, such
that there is a reasonable possibility that a material misstatement
of our annual or interim financial statements will not be prevented
or detected on a timely basis.
As a result of the review by the CFO and CEO, the material weakness
was identified as listed below.
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●
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In connection with the audit of our 2020 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 there are appropriate reviews occur on all
financial reporting analysis. Management is in the process of
designing and implementing updated control procedures that it
believes will mitigate this material weakness.
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Because of the material weaknesses described above, our management
was unable to conclude that our internal control over financial
reporting was effective as of the end of period to provide
reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
reporting purposes in accordance with generally accepted accounting
principles.
Except for the actions described above that were taken to address
the material weaknesses, there were no changes in our internal
controls during the period ended June 30, 2021, that materially
affected, or are reasonably likely to materially affect, our
internal control over financial reporting.
Notwithstanding the material weaknesses described above, our
management, including our Chief Executive Officer and Chief
Financial Officer, believes that the consolidated financial
statements contained in this Report on Form 10-Q fairly present, in
all material respects, our financial condition, results of
operations and cash flows for the fiscal periods presented in
conformity with U.S. generally accepted accounting principles. In
addition, the material 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.
INTERNAL CONTROL OVER FINANCIAL REPORTING AND CHANGES IN
INTERNAL CONTROL OVER FINANCIAL REPORTING
During the six months ended June 30, 2021, there were no changes in
our internal control over financial reporting that have materially
affected, or are reasonably likely to materially affect, our
internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
None
Item 1A. Risk Factors
Not applicable to smaller reporting companies.
Item 2. Unregistered Sales of Equity Securities and Use of
Proceeds
During the period covered by this report, we have not issued any
unregistered shares.
Item 4. Mine Safety Disclosures
Not applicable
Item 5. Other Information
None
Item 6. Exhibits
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
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ROYALE ENERGY, INC.
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Date: August 16, 2021
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/s/ Johnny Jordan
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Johnny Jordan, Chief Executive Officer
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Date: August 16, 2021
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/s/ Stephen M. Hosmer
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Stephen M. Hosmer, Chief Financial Officer
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