Securities registered pursuant to Section 12(b) of the Act: None.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically 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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐
Indicate by check mark whether the registrant is large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See definition of “large accelerated filer,” “accelerated filer” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to § 240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒
At June 30, 2022, the end of the registrant’s most recently completed second fiscal quarter; the aggregate market value of Common Stock held by non-affiliates was $2,702,007.
At May 19, 2023, 65,143,012 shares of the registrant’s Common Stock were outstanding.
PART III
Item 10 Directors, Executive Officers and Corporate Governance
All of our directors serve one-year terms from the time of their election to the time their successor is elected and qualified. The following information is furnished with respect to each director and executive officer who served as such during the fiscal year ended December 31, 2022:
Name
|
|
Age
|
|
First Became Director or Executive Officer
|
|
Positions Held
|
John Sullivan (1)(2)(3)(4)
|
|
65
|
|
2021
|
|
Chairman of the Board
|
Jonathan Gregory (1)(2)(3)(4)
|
|
58
|
|
2014
|
|
Vice-Chair of the Board of Directors
|
Johnny Jordan
|
|
63
|
|
2018
|
|
Chief Executive and Operating Officer
and Director
|
Chris Parada (1) (2)(3)(4)
|
|
52
|
|
2021
|
|
Director
|
Jeff Kerns (1) (2)(3)(4)
|
|
66
|
|
2021
|
|
Director
|
Stephen Hosmer
|
|
56
|
|
1995
|
|
Director
|
(1) Members of the Audit Committee
|
(2) Members of the compensation committee
|
(3) Members of the nominations committee
|
(4) Members identified as independent
|
The board has determined that directors John Sullivan, Chris Parada, Jonathan Gregory and Jeff Kerns qualify as independent directors.
The following summarizes the business experience of each director and executive officer for the past six years.
John Sullivan – Chairman of the Board
Mr. Sullivan first became a director and began serving as the Chairman of the Board in 2021. Mr. Sullivan is the President of LTD Consulting Services LLC, which provides consulting and management services to private and public companies in the US and SE Asia, a position he has held since 2017. Previously, he held the position of Sr. Director at MMI International, a privately held, global supplier to the Data Storage, Aerospace and Oil and Gas industries from 2011-2017. In this role, he oversaw the sales and global operations for the Precision Forming Group, a division of MMI, with $250 million in annual sales.
Prior to this, as Director of Operations, COO and President, he spent eleven years, from 1999 until 2011, with Intri-Plex Technologies Inc., a leading design, engineering and manufacturing company to the Data Storage, Semi-conductor and Medical industries. In his various roles, he led the development and implementation of strategic sales and operating initiatives that resulted in significant top and bottom line growth. Overseeing the expansion of the business from a domestic manufacturing company to an international supplier of precision components with manufacturing facilities located in the US and SE Asia.
Previously, as COO and President of KR Precision Public Co. Ltd., a publicly held, global supplier of precision mechanical components, John was instrumental in transforming a small privately held company from a niche supplier to a publicly held industry leader listed on the SET 50.
John began his career in 1980 as an entrepreneur, spending ten years as a small business owner in the security and life safety industry. He grew his company organically and through acquisition, diversified its offerings and expanded its geographic footprint prior to it being acquired by ADT International in, a global leader in security and life safety industry, in 1990.
Chris Parada – Director
Mr. Parada became a director in 2021. Mr. Parada currently serves as Vice President of Business Development for Finergy Capital/EnRes Resources, an alternative investment fund providing structured capital solutions to upstream oil and gas companies. Additionally, Mr. Parada serves as President of CounterPoint Consulting, LLC, which he founded in 2019. Counterpoint provides a variety of consulting and contract CFO/VP Finance services to upstream and midstream clients. Prior to joining Finergy/EnRes, Mr. Parada served as Managing Director at TenOaks Energy Advisors from April 2020 to February 2021. Prior to 2019, Mr. Parada was an energy banker for over 25 years, most recently, as Managing Director – Head of Energy Finance for LegacyTexas Bank (2013-2019) where he started and built the Energy Finance team for LegacyTexas. While at LegacyTexas, Mr. Parada and the team successfully closed over $1.5 billion in transactions while he managed a team of seven professionals. Over the course of his career in banking, Mr. Parada has originated, led and syndicated several direct and multibank credit facilities of $10-$500 million. Mr. Parada graduated in 1993 from Texas A&M University with a B.B.A. in Finance.
Jonathan Gregory – Vice-Chair of the Board of Directors
Mr. Gregory became a director of Royale in March 2014 and served as Royale’s chief executive officer from September 10, 2015, until June 1, 2018. Prior to becoming Royale’s CEO, Mr. Gregory, from March 2014 to July 2015, served as Chief Financial Officer and Chief Business Development Strategist for Americo Energy Resources, a private exploration and production company located in Houston, Texas. Prior to serving as CFO of Americo Energy, Mr. Gregory was CFO of J&S Oil & Gas, LLC, from April 2012 to February 2014. From December 2004 to April 2012, Mr. Gregory was head of the energy lending group in Houston, Texas for Texas Capital Bank, N.A. Mr. Gregory is presently CEO of RMX, a private Texas based oil and gas company with oil and gas properties primarily located in California, in which, Royale holds an equity interest. Mr. Gregory is also a Credit Advisor to Anvil Capital Partners, a private debt capital provider to upstream energy companies and serves on the advisory board of the Center for Compassionate Leadership. Mr. Gregory graduated from Lamar University in 1986 with a Bachelor’s degree in Finance.
Johnny Jordan – Chief Executive Officer, President, Chief Operating Officer and Director
Mr. Jordan is a petroleum engineer with expertise in acquisitions, field economics and reserves analysis, bank negotiations, reservoir and field operations, and multi-team interaction. Mr. Jordan has been Royale Energy’s Chief Executive Officer since 2019. Mr. Jordan served on the Board of Directors of Matrix and currently serves on the Board of Directors of both RMX Resources and CIPA. Mr. Jordan has been active in the oil and gas industry since 1980 beginning as a floor hand on a well service rig. He has held various staff and supervisory positions for Exxon, Mack Energy, Enron Oil and Gas and Venoco Corporation. He co-founded Matrix Oil Corporation in 1999 and served as its president until its merger with Royale in 2018. Mr. Jordan is a member of the Society of Petroleum Engineers, American Petroleum Institute and the Texas Independent Producers and Royalty Owners Association. Mr. Jordan has managed acquisition evaluations in many of the oil and gas producing basins in the US. Mr. Jordan received a B.S. in Chemical Engineering from the University of Oklahoma in 1983.
Jeff Kerns – Director
Mr. Kerns was a founding partner of Matrix Oil Corp in 1999, which merged with Royale Energy, Inc. nearly 20 years later in 2018. As a director and officer of Matrix, Mr. Kerns participated in growing the Company from zero production to owning and operating nearly 500 bbls of oil per day. Mr. Kerns was involved in all aspects of the Company’s growth, but his primary focus was day to day operations.
Mr. Kerns has served as a consulting engineer to Royale Energy and Matrix Oil Company from 2018 to present.
Mr. Kerns started in the oil and gas business over 40 years ago as a roughneck in North Dakota working on rigs that drilled through the now famous Bakken Shale heading for deeper targets. Prior to Matrix Oil Corp, Mr. Kerns has held various staff and supervisory positions with Mobil Oil Corp (now ExxonMobil) and Venoco Inc, a small independent company headquartered in Santa Barbara, CA. He also gained broad skills working for many years as a consultant in the oil and gas business.
Mr. Kerns is a registered Professional Engineer in the state of CA. He received a BS degree from Stanford University in 1979. He served as an elected public official for 10 years on the local sanitary district board of directors as well as serving as a past president of a local Rotary International club and president of the San Joaquin Chapter of the American Petroleum Institute and has maintained a long term affiliation with SPE.
Stephen Hosmer – Director, Corporate Secretary
Mr. Hosmer first became a director in 1998, and served through 2018. He was then reappointed in January 2022, following his departure as the company’s Chief Financial Officer, where he served since 1995. Mr. Hosmer also served as the company’s Co-Chief Executive Officer from 2008 until September 2015.
During his tenure as CFO, Mr. Hosmer managed the development of over 178 wells, raised capital through a combination of debt and equity sources, and led the acquisition of more than 200 square miles of 3D seismic data. Mr. Hosmer holds a Bachelor of Science degree in Business Administration from Oral Roberts University in Tulsa, Oklahoma and an MBA degree from the President/Key Executive program at Pepperdine University.
Mr. Hosmer currently serves as the CFO for San Diego Rock Church, Managing Partner of Provident Ventures, and has also served on the board and/or consults for a number of not-for-profit organizations, including Venture Expeditions and Exile International, and Wycliffe Bible Translators.
Audit Committee
The board has appointed an audit committee to assist the board of directors in carrying out its responsibility as to the independence and competence of the Company’s independent public accountants. All members of the audit committee are independent members of the board of directors. The audit committee operates pursuant to an audit committee charter, which has been adopted by the board of directors to define the committee’s responsibilities. A copy of the audit committee charter is posted on our website, www.royl.com. The board has determined that Chris Parada qualifies as an “audit committee financial expert” as defined in Item 407(d)(5) of the Securities and Exchange Commission.
At the end of 2022, the members of the audit committee were Chris Parada (Chair), Jeff Kerns, John Sullivan and Jonathan Gregory.
Code of Business Conduct and Ethics
We have adopted a code of business conduct and ethics for our directors and executive officers. The code is posted on our website, www.royl.com.
Delinquent Section 16(a) Reports
Section 16(a) of the Securities Exchange Act of 1934 and Securities and Exchange Commission regulations require that Royale’s directors, certain officers, and greater than 10 percent shareholders file reports of ownership and changes in ownership with the SEC and the NASD and furnish Royale with copies of all such reports they file. The following Form 4’s for common stock issued to current and former board members were filed late or are in process of being filed, each of these filings consisted of two transactions that occurred in 2022, except for Johnny Jordan’s, which had only one transaction:
Form 4 2022 Common Stock Issuance - Late Filings:
|
Recipient
|
Shares issued
|
Form 4 Filing Status
|
Johnny Jordan
|
3,073,682
|
Filed
|
Jonathan Gregory
|
423,185
|
Filed
|
Robert Vogel
|
300,513
|
In Process |
John Sullivan
|
262,950
|
In Process
|
Chris Parada
|
262,950
|
In Process
|
Jeffrey Kerns
|
197,799
|
In Process
|
Stephen Hosmer
|
187,038
|
In Process
|
Karen Kerns
|
300,513
|
In Process
|
Thomas Gladney
|
328,099
|
In Process
|
Mel Riggs
|
300,513
|
Filed |
Item 11 Executive Compensation
The following table summarizes the compensation of the chief executive officer, chief financial officer and the one other most highly compensated non-executive employee of Royale and its subsidiaries during the past three years.
SUMMARY COMPENSATION TABLE
|
|
Year
|
|
Salary (3)
|
|
|
Bonus
|
|
|
Option Awards
|
|
|
All Other
Compensation (1)
|
|
|
Total
|
|
Johnny Jordan (2)(3)(4)
|
|
2022
|
|
$ |
255,769 |
|
|
|
|
|
|
|
|
|
|
$ |
9,327 |
|
|
$ |
265,096 |
|
(CEO)
|
|
2021
|
|
$ |
255,769 |
|
|
|
|
|
|
|
|
|
|
$ |
7,625 |
|
|
$ |
263,394 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Donald Hosmer
|
|
2022
|
|
$ |
191,925 |
|
|
$ |
102,975 |
|
|
|
|
|
|
$ |
19,032 |
|
|
$ |
313,932 |
|
(Business Development)
|
|
2021
|
|
$ |
185,176 |
|
|
$ |
31,985 |
|
|
|
|
|
|
$ |
18,545 |
|
|
$ |
235,706 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stephen Hosmer (4)
|
|
2022
|
|
$ |
67,210 |
|
|
$ |
- |
|
|
|
|
|
|
$ |
58,355 |
|
|
$ |
125,565 |
|
(Former CFO)
|
|
2021
|
|
$ |
230,192 |
|
|
|
|
|
|
|
|
|
|
$ |
18,750 |
|
|
$ |
248,942 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ronald Lipnick
|
|
2022
|
|
$ |
181,654 |
|
|
$ |
15,000 |
|
|
|
|
|
|
$ |
6,017 |
|
|
$ |
202,671 |
|
(Interim CFO)
|
|
2021
|
|
$ |
153,431 |
|
|
|
|
|
|
|
|
|
|
$ |
4,604 |
|
|
$ |
158,035 |
|
(1) All other compensation consists of matching contributions to the Company’s simple IRA plan, except for Donald H. Hosmer and Stephen M. Hosmer, who also received a $12,000 car allowance.
(2) Salary represents either direct payroll or common stock paid in lieu of taking a cash salary.
(3) Mr. Jordan became CEO of the Company in January 2019. Mr. Jordan joined the Company upon the merger with the Matrix entities on March 7, 2018.
(4) There was no compensation paid to Mr. Johnny Jordan for performance (Pay Versus Performance).
(5) Mr. Hosmer resigned from his position as CFO, effective January 31, 2022.
Stock Options and Equity Compensation; Outstanding Equity Awards at Fiscal Year End
No unvested stock awards were outstanding at the end of 2022.
Compensation Committee Report
Our executive compensation committee has reviewed and discussed the following Compensation Discussion and Analysis with management and, based on its discussion and review, has recommended that the Compensation Discussion and Analysis be included in this annual report.
Members of the Compensation Committee:
Chris Parada, John Sullivan (Chair), and Jeff Kerns
All members of the compensation committee are independent members of the Board of Directors.
Compensation Discussion and Analysis
Our executive compensation policy is designed to motivate, reward and retain the key executive talent necessary to achieve our business objectives and contribute to our long-term success. Our compensation policy for our executive officers focuses primarily on determining appropriate salary levels and performance-based cash bonuses.
The elements of executive compensation at Royale consist mainly of cash salary and, if appropriate, a cash bonus at yearend. The compensation committee makes recommendations to the board of directors annually on the compensation of the three top executives: Johnny Jordan, Chief Executive Officer, Donald H. Hosmer, Business Development, and Ronald Lipnick, Interim Chief Financial Officer.
Royale also does not provide extensive personal benefits to its executives beyond those benefits, such as health insurance, that are provided to all employees. Donald Hosmer receives an annual car allowance.
Policy
The compensation committee’s primary responsibility is making recommendations to the board of directors relating to compensation of our officers. The committee also makes recommendations to the board of directors regarding employee benefits, our defined benefit plans, defined contribution plans, and stock-based plans.
Determination
To determine executive compensation, the committee, from time-to-time, meets with our officers to review our compensation programs, discuss the performance of the Company, the duties and responsibilities of each of the officers pay levels and business results compared to others similarly situated within the industry. The committee then makes recommendations to the board of directors for any adjustment to the officers’ compensation levels. The committee does not employ compensation consultants to make recommendations on executive compensation.
Compensation Elements
Base. Base salaries for our executive officers are established based on the scope of their responsibilities, taking into account competitive market compensation paid by our peers. Base salaries are reviewed annually. The salaries we paid to our most highly paid executive officers and next most highly compensated non-executive officer for the last three years are set forth in the Summary Compensation Table included under Executive Compensation.
Bonus. The compensation committee meets annually to determine the quantity, if any, of the cash bonuses of executive officers. The amount granted is based, subjectively, upon the Company’s stock price performance, earnings, revenue, reserves and production. The committee does not use quantifiable metrics for these criteria; but rather uses each in balance to assess the strength of the Company’s performance. The committee believes that formulaic approaches to cash incentives can foster an unhealthy balance between short-term and long-term goals. No cash bonuses were paid to executive officers in 2021 or 2020, other than those listed for Donald Hosmer in the table above.
Pay Versus Performance
As required by Section 953(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 402(v) of Regulation S-K, we are providing the following information about the relationship between executive compensation actually paid (“CAP”) and certain financial performance of our company.
Year
|
|
Summary Compensation Table Total for Principal Executive Officer (“PEO”)
|
|
|
Compensation Actually Paid to PEO
|
|
|
Average Summary Compensation Table Total for Non-PEO Named Executive Officers (“NEOs”)
|
|
|
Average Compensation Actually Paid to Non-PEO NEOs
|
|
|
Value of Initial Fixed $100 Investment Based on Total Shareholder Return
|
|
|
Net Income (loss)
|
|
(a)
|
|
(b)
|
|
|
(c)
|
|
|
(d)
|
|
|
(e)
|
|
|
(f)
|
|
|
(h)
|
|
2022
|
|
$ |
504,633 |
|
|
$ |
593,332 |
|
|
$ |
191,925 |
|
|
$ |
313,932 |
|
|
|
|
|
|
|
(145,594 |
) |
2021
|
|
$ |
639,392 |
|
|
$ |
670,371 |
|
|
$ |
185,176 |
|
|
$ |
235,706 |
|
|
|
|
|
|
|
(3,598,418 |
) |
Compensation of Directors
In 2022, board members or committee member accrued or received fees for attendance at board meetings or committee meetings during the year. In addition to cash payments, Common Stock was issued in lieu of compensation or reimbursements. Royale also reimbursed directors for the expenses incurred for their services.
The following table describes the compensation paid to our directors who are not also named executives for their services in 2022.
Name
|
|
Fees paid in Cash or Common Stock
|
|
|
Stock awards
|
|
|
Option awards
|
|
|
All Other Compensation
|
|
|
Total
|
|
John Sullivan
|
|
$ |
32,000 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
32,000 |
|
Chris Parada
|
|
$ |
32,000 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
32,000 |
|
Jeff Kerns
|
|
$ |
24,000 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
24,000 |
|
Stephen Hosmer
|
|
$ |
24,000 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
24,000 |
|
Jonathan Gregory
|
|
$ |
42,000 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
42,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Former Board Members
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Thomas M. Gladney
|
|
$ |
32,667 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
32,667 |
|
Karen Kerns
|
|
$ |
30,167 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
30,167 |
|
Mel G. Riggs
|
|
$ |
30,167 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
30,167 |
|
Robert Vogel
|
|
$ |
30,167 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
30,167 |
|
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Common Stock
At May 19, 2023, 65,143,012 shares of the registrant’s Common Stock were outstanding.
The following table contains information regarding the ownership of Royale’s Common Stock as March 25, 2023, by each director and executive officer of Royale, and all directors and officers of Royale as a group.
Except pursuant to applicable community property laws and except as otherwise indicated, each shareholder identified in the table below possesses sole voting and investment power with respect to her or his shares. The holdings reported are based on reports filed with the Securities and Exchange Commission and the Company by the officers and directors.
Stockholder (1)
|
|
Number
|
|
|
Percent
|
|
Johnny Jordan (3)
|
|
|
27,315,514 |
|
|
|
44.14 |
% |
Jeff Kerns
|
|
|
19,559,193 |
|
|
|
31.61 |
% |
Stephen M. Hosmer (2)
|
|
|
1,327,267 |
|
|
|
2.15 |
% |
John Sullivan
|
|
|
1,239,350 |
|
|
|
2.00 |
% |
Jonathan Gregory (4)
|
|
|
1,137,140 |
|
|
|
1.84 |
% |
Chris Parada
|
|
|
262,950 |
|
|
|
* |
|
All officers and directors as a group
|
|
|
50,841,414 |
|
|
|
82.17 |
% |
* Less than 1%.
(1) The mailing address of each listed stockholder is 1530 Hilton Head Rd, Suite 205, El Cajon, California 92021.
(2) Includes 6,000 shares owned by Stephen M. Hosmer's minor children.
(3) Includes 10,555,300 shares issuable upon conversion of Series B Convertible Preferred Stock.
(4) Includes 35,000 shares owned by Mr. Gregory's son.
There is no shareholder known by Royale to own beneficially more than 5% of the outstanding shares of each class of equity securities other than Messrs. Jordan and Kerns, as disclosed above.
Item 13 Certain Relationships and Related Transactions, and Director Independence
Our Chief Executive, Johnny Jordan, has accrued certain unpaid salaries, which were assumed by the Company. At December 31, 2022 Mr. Jordan was owed $15,694 in accrued unpaid guaranteed payments.
In 2018 the board of directors terminated the policy allowing employees and directors to participate, at cost, in wells drilled by the Company. Under the prior policy our former Chief Financial Officer and current board of director’s secretary, Stephen Hosmer, had participated individually in 179 wells. At December 31, 2022, the Company had a receivable balance of $18,251 due from Stephen Hosmer and $7,077 from Donald Hosmer for normal drilling and lease operating expenses.
At December 31, 2022, we had a total payable of $23,087 due to RMX and its subsidiary, Matrix Oil Corporation, related to certain lease operating expenses for wells operated by RMX. For the same period, the Company also had prepaid expenses and other current assets of $290,871 primarily for the prepaid drilling costs, expected to be completed in 2023. At December 31, 2022, we had a total payable of $185,049 owed to current and former board members for directors fees.
Royale had outstanding accrued unpaid guaranteed payments for unpaid salaries for periods predating their joining the Company due to certain former Matrix employees. At December 31, 2022, the balance due was $1,616,205. At December 31, 2022, Royale also had accrued unpaid liabilities of $1,306,605 due to certain former Matrix employees for periods predating their joining the Company.
The board has determined that directors John Sullivan, Chris Parada, Jonathan Gregory and Jeff Kerns qualify as independent directors.
Item 14 Principal Accountant Fees and Services
Horne LLP became our independent auditors effective March 31, 2023 for the year end December 31, 2022. Weaver and Tidwell, LLP served as independent registered accounting firm to audit the Company’s financial statements for the fiscal year ended December 31, 2021. Weaver and Tidwell, LLP became our independent auditors effective the second quarter of the year ended December 31, 2021. Moss Adams LLP served as the independent registered accounting firm to audit the Company’s financial statements for the fiscal years ended December 31, 2020 and 2019, through the first quarter of the year ended December 31, 2021. The aggregate fees incurred for the years ended December 31, 2022 and 2021 are as follows:
|
|
2022
|
|
|
2021
|
|
Audit fees (1)
|
|
|
282,120 |
|
|
|
255,376 |
|
Tax fees (2)
|
|
|
- |
|
|
|
- |
|
All other fees (3)
|
|
|
- |
|
|
|
- |
|
Total
|
|
|
282,120 |
|
|
|
255,376 |
|
(1)
|
Audit fees are fees for professional services rendered for the audit of Royale Energy's annual financial statements, reviews of financial statements included in the Company's Forms 10-Q, and reviews of documents filed with the U.S. Securities and Exchange Commission.
|
(2)
|
Tax fees consist of tax planning, consulting and tax return reviews.
|
(3)
|
Other fees consist of work on registration statements under the Securities Act of 1933.
|
The Company’s audit committee has adopted policies for the pre-approval of all audit and non-audit services provided by the Company’s independent auditor. The policy requires pre-approval by the audit committee of specifically defined audit and non-audit services. Unless the specific service has been previously pre-approved with respect to that year, the audit committee must approve the permitted service before the independent auditor is engaged to perform it. During 2022 all fees were pre-approved by the audit committee.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
This summary of significant accounting policies of Royale Energy, Inc. (in these notes sometimes called “we”, “us”, “our”) is presented to assist in understanding our financial statements.
These consolidated financial statements include the accounts of Royale Energy Inc and our controlled subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis. The financial statements and notes are representations of our management, which is responsible for their integrity and objectivity. These accounting policies conform to accounting principles generally accepted in the United States of America and have been consistently applied in the preparation of the financial statements.
Description of Business
We are an independent oil and gas producer and we also perform turnkey drilling operations. We own wells and leases in major geological basins located primarily in California, Texas, Oklahoma, and Utah, and offer fractional working interests and seek to minimize the risks of oil and gas drilling by selling multiple well drilling projects which do not include the use of debt financing.
Use of Estimates
The accompanying consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America and requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Estimated quantities of crude oil and condensate, NGLs and natural gas reserves is a significant estimate that requires judgment. All of the reserve data included in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and condensate, NGLs and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and condensate, NGLs and natural gas reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil and condensate, NGLs and natural gas that are ultimately recovered. See Note 19 – Supplemental Information About Oil and Gas Producing Activities (Unaudited) to our Consolidated Financial Statements for further detail.
Other items subject to estimates and assumptions include the carrying amounts of accounts receivable, property, plant and equipment, equity method investments, asset retirement obligations, and valuation allowances for deferred tax assets, among others. Although we believe these estimates are accurate, actual results could differ from these estimates.
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.
Our 2022 consolidated financial statements reflect a working capital deficiency of $6,445,318 and a net loss from operations of $145,594. 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 we are unable to continue as a going concern.
Management’s plans to alleviate the going concern by implementing cost control measures that include the reduction of overhead costs and through 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 us and whether we will become profitable and generate positive operating cash flow. If we are unable to raise sufficient additional funds, we will have to develop and implement a plan to further extend payables and reduce overhead until sufficient additional capital is raised to support further operations. There can be no assurance that such a plan will be successful.
Restricted Cash
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. If something changes, we 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. We classify 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 sheets that sum to the total of the same amounts shown in the statement of cash flows.
|
|
Year Ended December 31,
|
|
|
|
2022
|
|
|
2021
|
|
Cash and cash equivalents
|
|
$ |
1,650,507 |
|
|
$ |
220,304 |
|
Restricted cash
|
|
|
2,249,627 |
|
|
|
4,002,500 |
|
Total cash, cash equivalents, and restricted cash shown in the Statement of Cash Flows
|
|
$ |
3,900,134 |
|
|
$ |
4,222,804 |
|
Other Receivables
Our other receivables consist of receivables from direct working interest investors and industry partners. We provide for uncollectible accounts receivable using the allowance method of accounting for bad debts. Under this method of accounting, a provision for uncollectible accounts is charged directly to bad debt expense when it becomes probable the receivable will not be fully collected. The allowance account is increased or decreased based on past collection history and management’s evaluation of accounts receivable. All amounts considered uncollectible are charged against the allowance account and recoveries of previously charged off accounts are added to the allowance. At December 31, 2022 and 2021, we established an allowance for uncollectable accounts of $2,757,549 and $2,761,398, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue.
Revenue Receivables
Our revenue receivables consist of receivables related to the sale of our natural gas and oil. Once a production month is completed, we receive payment approximately 15 to 30 days later. Historically, we have not had issues related to the collection of revenue receivables, and as such have determined that an allowance for revenue receivables is not currently necessary.
Equity Method Investments
Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting. Income from equity method investments represents our proportionate share of net income generated by the equity method investees and is reflected in revenue and other income in our consolidated statements of income. Equity method investments are included as noncurrent assets on the consolidated balance sheets.
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, Investments—Equity Method and Joint Ventures. When a loss is deemed to have occurred and is other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income.
Revenue Recognition
A significant portion of our revenues are derived from the sale of crude oil, condensate, natural gas liquids (“NGLs”) and natural gas under spot and term agreements with our customers as follows:
|
|
Year Ended December 31,
|
|
|
|
2022
|
|
|
2021
|
|
Oil & Condensate Sales
|
|
$ |
1,654,840 |
|
|
$ |
1,238,014 |
|
Natural Gas Sales
|
|
|
947,407 |
|
|
|
445,080 |
|
NGL Sales
|
|
|
8,975 |
|
|
|
3,330 |
|
|
|
$ |
2,611,222 |
|
|
$ |
1,686,424 |
|
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 in regard to the sale of our share of production and recognize revenue for the volumes associated with our net production.
We frequently sells a portion of the working interest in each well we drill or participate in to third-party investors and retains 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 with the exception of natural gas sold to PG&E where transportation cost is netted directly against revenues. Under some of our natural gas processing agreements, we have an option to take the processed natural gas and NGLs in-kind and sell to customers other than the processing company. In those circumstances, our performance obligations are complete after delivering the processed hydrocarbons to the customer at the designated delivery points, which may be the tailgate of the processing plant or an alternative delivery point requested by the customer.
Turnkey Drilling Obligations
We manage these Turnkey Agreements for the participants of the well. The collections of pre-drilling Authorization for Expenditure (“AFE”) amounts are segregated 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. We manage the performance obligation for the well participants and only record revenue or expense at the time the performance obligation of the Turnkey Agreement has been satisfied.
Supervisory Fees and Other
For the years ended December 31, 2022 and 2021, we recognized $31,315 and $32,240, respectively in supervisory fees in Pipeline and Compressor fees which were received and allocated based on production volumes.
Oil and Gas Property and Equipment
Successful Efforts
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 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 Cost
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.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization, based on cost less estimated salvage value of the asset, are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized, and the assets replaced are retired.
The project drilling phase commences with the development of the detailed engineering design and ends when the 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.
Impairment
We evaluate our oil and gas producing properties, including capitalized costs of exploratory wells and development costs, for impairment of value whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. Oil and gas producing properties are reviewed for impairment on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure or contractual terms that cause economic interdependency amongst separate, discrete fields. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows or, if available, comparable market value. We evaluate our unproved property investment and record impairment based on time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved property investments are deemed to be impaired, this amount is reported in exploration expenses in our consolidated statements of operations. During 2021 we recorded impairment losses of $177,011, on various capitalized lease and land costs where the carrying value exceeded the fair value. In 2022 there were no impairment losses.
Upon the sale or retirement of a complete field of a proved property, we eliminate the cost from our books, and the resultant gain or loss is recorded to our consolidated statements 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 our consolidated statements 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.
Long-Lived Assets Classified as Held for Sale
We classify long-lived assets as Held-for-Sale when the criteria of ASC 360-10-45-9 through 45-11, Impairment and Disposal of Long-Lived Assets, have been met. This criterion is listed below:
|
●
|
Management has committed to a plan to sell the asset;
|
|
●
|
The asset group is available for immediate sale in its present condition;
|
|
●
|
An active program is underway to locate potential buyers;
|
|
●
|
The sale is probable within one year;
|
|
●
|
The asset group is being marketed at a price that is reasonable relative to its current fair value; and
|
|
●
|
Actions required to complete the plan indicate that it is unlikely that significant changes to the plan will be made or the plan will be withdrawn.
|
Assets held for sale are carried at the lower of cost or fair market value less cost of disposal in current assets. If we retain the responsibility for the P&A, equipment removal or site restoration, the associated anticipated expense is carried as current an asset retirement obligation (“ARO”) (See Note 4, below). We have two property groups that are being Held for Sale as further described in Note 17 – Long-Lived Assets Held for Sale.
Turnkey Drilling
We sponsor turnkey drilling agreement arrangements in proved and 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 and 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 pay us 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 December 31, 2022 and 2021, We had Deferred Drilling Obligations of $8,129,965 and $7,824,939, respectively. During 2022, we disposed of $7,027,474 of drilling obligations as we completed five oil wells in Texas and participated in completing the drilling of two oil wells in southern California, while incurring expenses of $5,301,060, resulting in a gain of $1,726,414. During 2021, we disposed of $1,841,061 of drilling obligations upon completing the drilling of two oil wells in Texas, while incurring expenses of $1,905,529, resulting in a loss of $64,468.
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.
Equipment and Fixtures
Equipment and fixtures are stated at cost and depreciated over the estimated useful lives of the assets, which range from three to seven years, using the straight-line method. Repairs and maintenance are charged to expense as incurred. When assets are sold or retired, the cost and related accumulated depreciation are removed from the accounts and any resulting gain or loss is included in income. Maintenance and repairs, which neither materially add to the value of the property nor appreciably prolong its life, are charged to expense as incurred.
Loss Per Share
Basic and diluted losses per share are calculated as follows:
|
|
Year Ended December 31,
|
|
|
|
2022
|
|
|
2021
|
|
|
|
Basic
|
|
|
Diluted
|
|
|
Basic
|
|
|
Diluted
|
|
Net Loss
|
|
$ |
(145,594 |
)
|
|
$ |
(145,594 |
)
|
|
$ |
(3,598,418 |
)
|
|
$ |
(3,598,418 |
)
|
Less: Preferred Stock Dividend
|
|
|
815,772 |
|
|
|
815,772 |
|
|
|
787,833 |
|
|
|
787,833 |
|
Less: Preferred Stock Dividend in Arrears
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Net Loss Attributable to Common Shareholders
|
|
|
(961,366 |
)
|
|
|
(961,366 |
)
|
|
|
(4,386,251 |
)
|
|
|
(4,386,251 |
)
|
Weighted average common shares outstanding
|
|
|
58,472,340 |
|
|
|
58,472,340 |
|
|
|
55,887,319 |
|
|
|
55,887,319 |
|
Effect of dilutive securities
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Weighted average common shares, including Dilutive effect
|
|
|
58,472,340 |
|
|
|
58,472,340 |
|
|
|
55,887,319 |
|
|
|
55,887,319 |
|
Per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss
|
|
$ |
(0.02 |
)
|
|
$ |
(0.02 |
)
|
|
$ |
(0.06 |
)
|
|
$ |
(0.06 |
)
|
For the years ended December 31, 2022 and 2021, Royale Energy had dilutive securities of 27,058,677 and 26,582,388 respectively. These securities were not included in the dilutive loss per share due to their antidilutive nature.
Stock Based Compensation
We have a stock-based employee compensation plan, which is more fully described in Note 11 – Stock Compensation Plan. We have adopted ASC 718, Compensation – Stock Compensation, for share-based payments. This topic requires that the cost resulting from all share-based payment transactions be recognized in the financial statements. It further establishes fair value as the measurement objective in accounting for share-based payment arrangements and requires all entities to apply a fair-value based measurement method in accounting for share-based payment transactions with employees except for equity instruments held by employee stock ownership plans.
Income Taxes
We utilize the asset and liability approach to measure deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates in accordance with the Income Taxes Topic of the ASC 740. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. Under the Topic, deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more-likely-than-not that some portion or all of the deferred tax assets will not be realized.
The provision for income taxes is based on pretax financial accounting income. Deferred tax assets and liabilities are recognized for the expected tax consequences of temporary differences between the tax basis of assets and liabilities and their reported net amounts.
Fair Value Measurements
According to Fair Value Measurements and Disclosures guidance as provided by ASC 820 and 825, 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 our 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 consider 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 December 31, 2022 and 2021, we do not have any financial assets measured and recognized at fair value on a recurring basis. We estimate asset retirement obligations pursuant to the provisions of ASC 410, Asset Retirement and Environmental Obligations. The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 3 – Oil and Gas Properties, Equipment and Fixtures for further discussion of our asset retirement obligations.
Accounts Payable and Accrued Expenses
At December 31, 2022 and 2021, the components of accounts payable and accrued expenses consisted of:
|
|
2022
|
|
|
2021
|
|
Trade Payables including accruals
|
|
$ |
3,108,931 |
|
|
$ |
2,845,395 |
|
Direct working interest investors related accruals
|
|
|
1,801,818 |
|
|
|
1,409,148 |
|
Current drilling efforts accrued expenses
|
|
|
22,910 |
|
|
|
229,716 |
|
Accrued Liabilities
|
|
|
400,296 |
|
|
|
410,308 |
|
Employee related accruals
|
|
|
189,736 |
|
|
|
266,531 |
|
Deferred rent
|
|
|
5,138 |
|
|
|
(614 |
) |
|
|
$ |
5,528,829 |
|
|
$ |
5,160,484 |
|
Accrued – Non-current
At December 31, 2022 and 2021, we had non-current accrued liabilities of $1,306,605 and accrued unpaid guaranteed payment of $1,616,205, due to certain Matrix Oil Corp (“Matrix”) principals, from periods prior to the merger with the Matrix entities during March of 2018.
Business Combinations
From time-to-time, we acquire businesses in the oil and gas industry. We primarily target businesses in geological basins that we consider to be in a focus area. Businesses are included in the consolidated financial statements from the date of acquisition.
We recognize, separately from goodwill, the identifiable assets acquired and liabilities assumed at their estimated acquisition-date fair values. We measure and recognize goodwill as of the acquisition date as the excess of: (1) the aggregate of the fair value of consideration transferred, the fair value of any noncontrolling interest in the acquiree (if any) and the acquisition date fair value of our previously held equity interest in the acquiree (if any), over (2) the fair value of assets acquired and liabilities assumed. If information about facts and circumstances existing as of the acquisition date is incomplete by the end of the reporting period in which a business combination occurs, we report provisional amounts for the items for which the accounting is incomplete. The measurement or allocation period ends once we receive the information we are seeking; however, this period will generally not exceed one year from the acquisition date. Any material adjustments recognized during the measurement period will be reflected retrospectively in the consolidated financial statements of the subsequent period. We recognize third-party transaction-related costs as expense currently in the period in which they are incurred.
Changes in Accounting Standards
Recently Adopted
ASU 2020-04, Changes to the fair value disclosure requirements
In March 2020, FASB issued ASU 2020-04, Reference Rate Reform (Topic 848), Facilitation of the effects of Reference Rate Reform on Financial Reporting. This pronouncement provides optional expedients and exceptions for applying GAAP to contract modifications, hedging relationships, and other transactions affected by the anticipated transition away from LIBOR. This new ASU is eligible to be applied upon release and has various transition requirements. We acquired certain hedge contracts with the merger with the Matrix Companies in 2018. Those hedge contracts were transferred to RMX with the formation of the RMX Joint Venture as more fully described in Note 2 – RMX Joint Venture. The transition from LIBOR will not have any impact on us or our existing financial instruments or agreements.
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) like us, 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 – RMX JOINT VENTURE
RMX Joint Venture
On April 13, 2018, we and two of our subsidiaries, Royale Energy Funds, Inc. and Matrix Oil Management Corporation (the “Royale Entities”) completed the Subscription and Contribution Agreement (“Contribution Agreement”), in which the Royale Entities and CIC RMX LP (“CIC”) entered into the Contribution Agreement and certain other agreements providing that the Royale Entities would contribute certain assets to RMX (“RMX”), a newly formed Texas limited liability company formed to facilitate the investment from CIC. In exchange for our contributed assets, we received a 20% equity interest in RMX, an equity performance incentive interest and up to $20.0 million to pay off the Royale Entities senior lender, Arena Limited SPV, LLC., in full, and to pay the Royale Entities trade payables and other outstanding obligations. CIC contributed an aggregate of $25.0 million in cash to RMX in exchange for (i) an 80% equity interest in RMX with preferred distributions until certain thresholds are met, (ii) a warrant (“Warrant”) to acquire up to 4,000,000 shares of our common stock at an exercise price of $.01 per share and registration rights pursuant to a Registration Rights Agreement.
RMX has a six-member board of managers. We have two seats on the board giving us a third of the available seats on the Board. We have designated Michael McCaskey and Johnny Jordan as our members of the RMX board. The return targets for CIC through its funding of RMX provide for a “waterfall” style return profile with the first distributions going to CIC until they have received all Unpaid Preferred Return and Unpaid Preferred Enhanced Return, as defined by the Contribution Agreement.
We account for our ownership interest in RMX following the equity method of accounting, in accordance with ASC 323, Investments—Equity Method and Joint Ventures.
Under the provisions of the Amended and Restated Limited Liability Company Agreement of RMX (“RMX Agreement”) dated March 27, 2018, the gains and losses of the partnership are distributed as if all of RMX’s assets were sold for cash at a price equal to their book basis and all RMX liabilities were satisfied at their book basis and all of the remaining assets of RMX were distributed in accordance with Section 5.4 of the RMX Agreement. Notwithstanding the above, for each fiscal year or other relevant period, deductions attributable to exploration costs, IDCs, and operating and maintenance costs shall be allocated 100% to the CIC members pro rata in accordance with their Class B percentage interests for each fiscal year.
RMX Joint Venture Post-Closing
On March 11, 2019, we entered into a Settlement Agreement with RMX Resources to resolve differences resulting from the calculation of certain post-closing amounts as called for under Section 7.3 of the Subscription and Contribution Agreement.
Pursuant to the Settlement Agreement, we continue to be liable for the payment of all royalties and suspended funds incurred prior to March 1, 2018. It also, required RMX to offer us the right, but not the obligation to participate in a portion of the working interest, in a number of wells to be drilled in the Sansinena, Sempra, Whittier and/or East LA properties in Los Angeles County, California. The minimum number of wells to be offered to us each year is two net wells as determined by an agreed upon methodology. The Settlement Agreement also calls for certain credits toward future drilling costs of the offered wells.
The RMX Joint Venture, like any Joint Venture investment following the equity method, is subject to ASC 323-10-35-31 and 32, impairment testing. During the 4th quarter of 2020, we received the RMX engineering reserve report prepared by an independent outside engineering firm. The report reflected reserve values for RMX that were below our expectations. As a result of this and on-going market conditions along with the contractual terms of our investment in RMX, management performed an impairment test. We considered the waterfall formula as called for under the Contribution Agreement and certain other agreements with RMX as well as the preferred return owed to other partners. As part of this computation, we applied a discounted cash flow test as called for under ASC 820-10-55-5(c) and 5(d) incorporating the time value of money and risk premium. In our test, we considered factors including, most significantly, the estimated market value of the reserves of RMX and the amount of preferred return owed to other partners. As a result of this analysis and the fact that management does not believe the values reflected in this most recent reserve report are temporary, we do not expect to realize the entire carrying amount of the RMX investment. Therefore, we recognized an impairment of our investment of $6,185,995 in our Statement of Operations in the year ended December 31, 2020.
Because we do not expect the value of the RMX Joint Venture to improve to a level where the water-fall profit sharing formula will provide us value, and we are no longer providing summarized financial information on the RMX investment in our financial statements or our reserve disclosures. Further the investment in RMX Joint Venture was $0 as of December 31, 2021, due to recording the full impairment in 2020.
NOTE 3 – OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES
Oil and gas properties, equipment and fixtures consist of:
|
|
Year ended December 31,
|
|
|
|
2022
|
|
|
2021
|
|
Oil and Gas
|
|
|
|
|
|
|
|
|
Producing properties, including intangible drilling costs
|
|
$ |
5,712,436 |
|
|
$ |
5,509,568 |
|
Undeveloped properties
|
|
|
148,989 |
|
|
|
128,362 |
|
Lease and well equipment
|
|
|
3,317,718 |
|
|
|
3,317,718 |
|
|
|
|
9,179,143 |
|
|
|
8,955,648 |
|
Accumulated depletion, depreciation and amortization
|
|
|
(7,142,506 |
) |
|
|
(6,879,531 |
) |
Net capitalized costs Total
|
|
$ |
2,036,637 |
|
|
$ |
2,076,117 |
|
Commercial and Other
|
|
2022
|
|
|
2021
|
|
Vehicles
|
|
$ |
40,061 |
|
|
$ |
40,061 |
|
Furniture and equipment
|
|
|
1,097,428 |
|
|
|
1,097,428 |
|
|
|
|
1,137,489 |
|
|
|
1,137,489 |
|
Accumulated depreciation
|
|
|
(1,133,806 |
) |
|
|
(1,133,806 |
) |
|
|
|
3,683 |
|
|
|
3,683 |
|
Net capitalized costs Total
|
|
$ |
2,040,320 |
|
|
$ |
2,079,800 |
|
The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed at December 31:
|
|
Year Ended December 31,
|
|
|
|
2022
|
|
|
2021
|
|
Acquisition - Proved
|
|
|
- |
|
|
|
- |
|
Acquisition - Unproved
|
|
|
- |
|
|
|
- |
|
Development
|
|
$ |
5,301,061 |
|
|
$ |
1,905,529 |
|
Exploration
|
|
|
- |
|
|
|
- |
|
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. We did not make any additions to capitalized exploratory well costs pending a determination of proved reserves during 2022 and 2021. We did not charge any previously capitalized exploratory well costs to expense upon adoption of Topic. Undeveloped properties are not subject to depletion, depreciation or amortization.
Results of Operations from Oil and Gas Producing and Exploration Activities
The results of operations from oil and gas producing and exploration activities (excluding corporate overhead and interest costs) are as follows:
|
|
Year Ended December 31,
|
|
|
|
2022
|
|
|
2021
|
|
Oil and gas sales
|
|
$ |
2,611,222 |
|
|
$ |
1,686,424 |
|
Production-related costs (Lease Operating)
|
|
|
(1,928,521 |
)
|
|
|
(1,814,643 |
)
|
Impairment
|
|
|
- |
|
|
|
(177,011 |
)
|
Depreciation, depletion and amortization
|
|
|
(575,909 |
)
|
|
|
(537,273 |
)
|
|
|
|
|
|
|
|
|
|
Results of operations from producing and exploration activities
|
|
|
106,792 |
|
|
|
(842,503 |
)
|
Income Taxes (Benefit)
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
Net Results
|
|
$ |
106,792 |
|
|
$ |
(842,503 |
)
|
NOTE 4 – ASSET RETIREMENT OBLIGATION
The Asset Retirement and Environmental Obligations Topic of the ASC 410-20 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset. The ARO is recorded at the estimated fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value. Accretion expense is included as part of Depreciation, Depletion and Amortization in the Consolidated Statement of Operations. The fair value (as provided in ASC 820 guidance) of the ARO is measured using expected future cash outflows discounted at our credit-adjusted risk-free interest rate. The provisions of this Topic apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, development, and operation of a long-lived asset. There were no changes in estimates for the years ended December 31, 2022 and 2021.
|
|
2022
|
|
|
2021
|
|
Asset retirement obligation
|
|
|
|
|
|
|
|
|
Beginning of the year
|
|
$ |
2,610,560 |
|
|
$ |
2,478,350 |
|
Liabilities incurred during the period
|
|
|
29,338 |
|
|
|
14,122 |
|
Settlements
|
|
|
(58,889 |
)
|
|
|
- |
|
Sales
|
|
|
- |
|
|
|
- |
|
Changes in estimates
|
|
|
- |
|
|
|
- |
|
Accretion expense
|
|
|
286,470 |
|
|
|
118,088 |
|
Reclassification to ARO - current
|
|
|
- |
|
|
|
- |
|
End of year
|
|
$ |
2,867,479 |
|
|
$ |
2,610,560 |
|
We record accretion expense as part of Depreciation, Depletion and Amortization. Accretion expense was $286,470 and $118,088 for the years ended December 31, 2022 and 2021, respectively.
NOTE 5 – NOTES PAYABLE
On November 1, 2021, we issued a promissory note for a principal amount of $38,490 to Pacific Gillespie Partners IV, LP. Five principal payments of $7,698 are due the first of the month beginning December 1, 2021.
On October 3, 2018, we issued a promissory note for a principal amount of $517,585 to Forza Operating, LLC (“Forza”) at an interest rate of 5.5%. Beginning October 3, 2018, principal and interest was due and payable in 12 monthly installments of $44,428. The note was the result of an agreement regarding the P&A of the CL&F #1 and the CL&F #1 SWD wells. We agreed to include the current joint interest billing balance due to Forza of $233,367 and our share of future P&A costs of $284,218. Forza agreed to accept the principal balance, less a portion of the accrued interest. As a result, we recorded a gain of $13,440 as Other Gain. This note was fully satisfied in October 2022. At December 31, 2022 and 2021, we had Notes Payable of $0 and $113,915, respectively.
On November 2, 2020, in conjunction with the PPP loan forgiveness described in Note 16 – Coronavirus Aid, Relief, And Economic Security Act (“CARES Act”), we entered into a loan for $10,054 to be repaid through monthly interest and principal payments of $560 beginning December 1, 2020, with the final payment of $613 scheduled for April 23, 2022. In February 2021, the balance of the loan and interest of $10,081 was paid by the SBA resulting in a gain on settlement of $10,061 in 2021.
NOTE 6 – 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.
Significant components of our deferred assets and liabilities at December 31, 2022 and 2021, respectively, are as follows:
|
|
2022
|
|
|
2021
|
|
Deferred Tax Assets (Liabilities):
|
|
|
|
|
|
|
|
|
Statutory Depletion Carry Forward
|
|
$ |
310,903 |
|
|
$ |
277,521 |
|
Net Operating Loss
|
|
|
8,542,098 |
|
|
|
8,697,243 |
|
Other
|
|
|
688,377 |
|
|
|
605,684 |
|
Share-Based Compensation
|
|
|
86,510 |
|
|
|
86,510 |
|
Capital Loss / AMT Credit Carry Forward
|
|
|
9,458 |
|
|
|
9,458 |
|
Charitable Contributions Carry Forward
|
|
|
100 |
|
|
|
- |
|
Allowance for Doubtful Accounts
|
|
|
717,514 |
|
|
|
718,516 |
|
Oil and Gas Properties and Fixed Assets
|
|
|
4,976,399 |
|
|
|
3,945,568 |
|
Investment in RMX Joint Venture
|
|
|
(285,626 |
) |
|
|
486,092 |
|
|
|
|
15,045,733 |
|
|
$ |
14,826,592 |
|
Valuation Allowance
|
|
|
(15,045,733 |
) |
|
|
(14,826,592 |
) |
Net Deferred Tax Asset
|
|
$ |
- |
|
|
$ |
- |
|
We recorded a full valuation allowance against the net deferred tax assets in 2016. At the end of 2017, management reviewed the reliability of our net deferred tax assets, and due to our continued cumulative losses in recent years, we and our management 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. We will assess the realizability of the deferred tax assets at least yearly and make appropriate updates as needed. We and our subsidiaries have available net operating loss carryforwards of $20.5 million generated in tax years ended before January 1, 2018, which if not utilized, begin to expire in the year 2026. We have $12.0 million net operating loss carryforwards generated after December 31, 2017, which can be carried forward indefinitely.
A reconciliation of our provision for income taxes and the amount computed by applying the statutory income tax rates at December 31, 2022 and 2021, respectively, to pretax income is as follows:
|
|
2022
|
|
|
2021
|
|
Tax (benefit) computed at statutory rate of 21% at December 31, 2022 and 2021, respectively |
|
$ |
(30,575 |
) |
|
$ |
(755,668 |
) |
|
|
|
|
|
|
|
|
|
Increase (decrease) in taxes resulting from:
|
|
|
|
|
|
|
|
|
PPP Loan Forgiveness
|
|
|
- |
|
|
|
(2,113 |
) |
Employer Retention Credits
|
|
|
(31,527 |
) |
|
|
- |
|
Prior-year true-up for Books
|
|
|
(221,621 |
) |
|
|
241,652 |
|
Deferred State Taxes, net of federal benefit
|
|
|
62,558 |
|
|
|
(131,991 |
) |
Other non-deductible expenses
|
|
|
2,024 |
|
|
|
(6,086 |
) |
Change in valuation allowance
|
|
|
219,141 |
|
|
|
654,206 |
|
Provision (benefit)
|
|
$ |
- |
|
|
$ |
- |
|
In January 2007, we adopted additional provisions from the Income Taxes Topic of the ASC, which clarified the accounting for uncertainty in income taxes recognized in an entity’s financial statements and prescribes a recognition threshold and measurement attribute for financial statement disclosure of tax positions taken or expected to be taken on a tax return. As a result of our implementation of the Topic at the time of adoption and at December 31, 2018, we did not recognize a liability for uncertain tax positions. Currently, the only differences between our financial statements and our income tax returns relate to normal timing differences such as depreciation, depletion and amortization, which are recorded as deferred taxes on our balance sheets. We do not expect our unrecognized tax benefits to change significantly over the next 12 months. The tax years 2018 through 2021 remain open to examination by the taxing jurisdictions in which we file income tax returns.
NOTE 7 – 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 our 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 our Series B Convertible Preferred Stock. Our Board of Directors, 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 shares of common stock 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 of common stock 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, we have determined that the conversion or redemption of these shares are outside our sole control 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 2022 and 2021, 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 12 months ending December 31, 2022, we issued 60,748 shares with a value of $607,465, with 20,832 shares with a value of $208,307 accrued for but not yet issued at 12/31/22. For the 12 months ending December 31, 2021, we issued 58,667 shares with a value of $586,661, with 20,117 shares with a value of $201,172 accrued for but not yet issued at December 31, 2021. During 2022 and 2021, no cash was used to pay dividends on Series B preferred shares.
NOTE 8 – COMMON STOCK
During the years 2022 and 2021, we issued shares of our Common Stock in lieu of cash payments for salaries, fees or incentives to various officers and board members, including our CEO, as noted in the Statement of Stockholders’ Equity (Deficit).
NOTE 9 – LEASES
During 2022 we had two office leases. One at 1530 Hilton Head Road, El Cajon, California the location of our corporate offices and one at 104 W. Anapamu, Santa Barbara, California, the location of our CEO and engineering team. The corporate office lease was entered into on August 12, 2021, began on January 1, 2022 and expires on December 31, 2026, with initial monthly payments of $6,922 with escalations. The lease in Santa Barbara was initiated in December of 2006 and, through several extensions and renewals, expired in March of 2022.
We have elected the short-term lease recognition exemption for all leases that qualify. This means, for those leases that qualify, we will not recognize ROU assets or lease liabilities, and this includes not recognizing ROU assets or lease liabilities for existing short-term leases of those assets in transition. We elected the practical expedient to not separate lease and non-lease components for all of our finance leases. For our real estate operating leases, we have only considered the fixed portion of our lease payment commitment and have excluded the variable components from the capitalized ROU and lease liability.
Lease expense for operating as well as finance leases are included in General and Administrative expense and Interest Expense on the Consolidated Statement of Operations, while the lease expense for those leases that are short-term are included in Oil and Gas Lease Operating Expenses. The amounts are as follows:
|
|
Year Ended December 31,
|
|
|
|
2022
|
|
|
2021
|
|
Operating lease expense
|
|
$ |
174,975 |
|
|
$ |
163,025 |
|
Financing lease expense
|
|
|
19,076 |
|
|
|
18,635 |
|
Short Term - field
|
|
|
6,000 |
|
|
|
6,000 |
|
Total lease expense
|
|
$ |
200,051 |
|
|
$ |
187,660 |
|
The following tables summarized the operating and financing lease obligations.
Lease Obligations
|
|
Operating Lease
Obligations
|
|
|
Financing Lease
Obligations
|
|
|
Total Lease
Obligations
|
|
2023
|
|
$ |
85,560 |
|
|
$ |
12,588 |
|
|
$ |
98,148 |
|
2024
|
|
|
88,128 |
|
|
|
7,343 |
|
|
|
95,471 |
|
2025
|
|
|
90,768 |
|
|
|
- |
|
|
|
90,768 |
|
Thereafter
|
|
|
93,492 |
|
|
|
- |
|
|
|
93,492 |
|
Total undiscounted lease payments
|
|
|
357,948 |
|
|
|
19,931 |
|
|
|
377,879 |
|
Less: Amount representing interest
|
|
|
39,929 |
|
|
|
1,097 |
|
|
|
41,026 |
|
Total Operating & Financing lease liabilities
|
|
|
318,019 |
|
|
|
18,834 |
|
|
|
336,853 |
|
Current lease liabilities as of December 31, 2022
|
|
|
70,200 |
|
|
|
11,795 |
|
|
|
81,995 |
|
Long-term lease liabilities as of December 31, 2022
|
|
$ |
247,819 |
|
|
$ |
7,039 |
|
|
$ |
254,858 |
|
Our two office leases do not contain implicit interest rates that can be readily determined. As a result, we used the available risk-free rate plus 4 basis points. At December 31, 2022 the weighted average discount rate was 4.83% and the term was 4 years.
NOTE 10 – RELATED-PARTY TRANSACTIONS
Our Chief Executive Officer, Johnny Jordan, has accrued certain unpaid salaries. At December 31, 2022, Mr. Jordan was owed $15,694, in accrued unpaid guaranteed payments.
Stephen Hosmer, former CFO, current director, and corporate secretary, has participated individually in 179. During 2022 and 2021, Stephen did not participate in fractional interests. At December 31, 2022, we had a receivable balance of $18,251 due from Stephen Hosmer for normal drilling and lease operating expenses.
At December 31, 2022 and 2021, we had a total payable of $23,087 and $23,087, respectively, due to RMX and its subsidiary, Matrix Oil Corporation, related to certain lease operating expenses for wells operated by RMX. For the same periods, we also had prepaid expenses and other current assets, and deferred drilling costs of $290,871 and $1,327,763, respectively. In 2022, the prepaid amount was for drilling and future plugging costs. In 2021, the prepaid amount was primarily for the drilling of wells. During 2022, RMX Resources LLC operated various oil wells we have interests in, from which we received revenues of approximately $491,000 and incurred lease operating costs of approximately $189,000. At December 31, 2022 and 2021, we had a total revenue receivables of $127,360 and $98,274, respectively, due from RMX and its subsidiary, Matrix Oil Corporation.
We had outstanding accrued unpaid guaranteed payments for unpaid salaries for periods predating their joining our company due to certain former Matrix employees. At December 31, 2022, the balance due was $1,616,205. At December 31, 2022, Royale also had accrued unpaid liabilities of $1,306,605 due to certain former Matrix employees for periods predating their employment.
Michael McCaskey, a former director, and Jeffery Kerns, a current director, each have consulting agreements to provide services as directed and at our discretion. Mr. Kerns’ wife was a director during 2020 and 2021. At December 31, 2022 and 2021, we had total payables of $185,049 and $233,872, a respectively, owed to current and former board members for directors fees.
NOTE 11 – STOCK COMPENSATION PLAN
There were no stock options issued during 2022 and 2021.
NOTE 12 – SIMPLE IRA PLAN
In April 1998, we established a Simple IRA pension plan covering all employees. We will contribute a matching contribution to each eligible employee’s Simple IRA equal to the employee’s salary reduction contributions up to a limit of 3% of the employee’s compensation for the year. The employer contribution for the years ending December 31, 2022 and 2021, were $27,770 and $31,509 respectively.
NOTE 13 – ENVIRONMENTAL MATTERS
We have established procedures for the continuing evaluation of our operations to identify potential environmental exposures and ensure compliance with regulatory policies and procedures. Management monitors these laws and regulations and periodically assesses the propriety of our operational and accounting policies related to environmental issues. The nature of our business requires routine day-to-day compliance with environmental laws and regulations. We incurred no material environmental investigation, compliance and remediation costs in 2022 or 2021.
We are unable to predict whether our future operations will be materially affected by these laws and regulations. It is believed that legislation and regulations relating to environmental protection will not materially affect our results of operations.
NOTE 14 – CONCENTRATIONS
We bid our gas sales on a month-to-month basis and generally sell to a single customer without commitment to future gas sales to any particular customer. We normally sell approximately 44% of our yearly natural gas production to one customer on a month-to-month basis. Since we are able to sell our natural gas to other readily available customers, the loss of any one customer would not have an adverse effect on our overall sales operations.
We maintain cash in depository institutions that are guaranteed by the Federal Deposit Insurance Corporation (FDIC) up to $250,000 per institution for our interest-bearing accounts in the years ended December 31, 2022, and 2021. At December 31, 2022 and 2021, cash in banks exceeded the FDIC limits by approximately $3.6 million and $3.9 million, respectively. We have not experienced any losses on deposits.
NOTE 15 – COMMITMENTS AND CONTINGENCIES
We may become involved from time to time in litigation on various matters, which are routine to the conduct of our business. We believe that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial position or results of operations, though any adverse decision in these cases or the costs of defending or settling such claims could have a material effect on our business.
We sponsor turnkey drilling agreement arrangements in proved and unproved properties as a pooling of assets in a joint undertaking, whereby proceeds from participants are reported as Deferred Drilling Obligations. The contracts require the participants pay us the full contract price upon execution of the agreement. We typically begin the drilling activities within 12 months of funding and reach total depth between 10 and 30 days after drilling begins.
NOTE 16 – CORONAVIRUS AID, RELIEF, AND ECONOMIC SECURITY ACT (“CARES ACT”)
During 2020, the CARES Act provided tax benefits and potential loans/grants for businesses and non-profits. On April 13, 2020, we successfully completed the process to obtain a $207,800 PPP Loan through the SBA with Bank of Southern California (“BSC”) under the CARES Act. The interest rate was 1.00 percent per year fixed with a two-year term and all payments deferred for six months subject to loan forgiveness as provided for under the CARES Act. On November 2, 2020, our loan with BSC was paid down by $198,846 ($197,800 in principal and $1,046 in interest) as a result of completing the process of loan forgiveness under the terms of the CARES Act. The loan balance of $10,054 was forgiven and paid by the SBA in February 2021.
Under the updated regulations, the forgiveness of PPP Loan is not taxable income. Additionally, expenses submitted in support of the PPP Loan forgiveness remain deductible for the purpose of tax reporting. Prior IRS positions in Notice 2020-32 and Rev Ruling 2020-27 no longer apply.
We had also applied for approximately $152,000 in relief under the Employee Retention Credit program of the CARES act, for payroll expenses incurred for 2020 and 2021. We received these funds in December 2022, and recorded them as Other Income.
NOTE 17 – LONG-LIVED ASSETS HELD FOR SALE
Assets held for sale are carried at lower of cost or fair value less cost to sell. Listed below are the two current groups of properties that we defined as long-lived assets held for sale in accordance with ASC 360-10-45.
East Los Angeles Sale
In September 2021, we and our joint venture partner, RMX, sold certain assets in our East Los Angeles property. During 2021, we carried these assets on the books for $1.0 million booked as Held for Sale with a current ARO amount of approximately $721,000 for the existing wells and facilities located on the properties. The sale required us and RMX to plug and abandon the wells on the property and remove and restore the surface land. The sale price of $1.0 million to us resulted in recording a loss on sale of these properties of approximately $254,000.
Non-operated West Texas Property Sale
During 2021, we recorded a gain of approximately $319,000 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 year-end 2020.
NOTE 18 – SUBSEQUENT EVENTS
We have evaluated subsequent events through May 19, 2023, the date these financial statements were available to be issued. At March 1, 2023, we issued 20,832 shares of our Series B Preferred stock with a value of $208,307 for our fourth quarter 2022 dividend that had been accrued for but not yet issued at December 31, 2022.We are not aware of events which would require recognition or disclosure in the financial statements, except as noted here or already recognized or disclosed.
NOTE 19 – SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
The following estimates of proved oil and gas reserves, both developed and undeveloped, represent interest we owned, which are located solely in the United States. Proved reserves represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate to be reasonably certain to be recoverable in the future from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells, with existing equipment and operating methods. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which relatively major expenditures are required for completion.
Disclosures of oil and gas reserves, which follow, are based on estimates prepared by independent petroleum engineering consultant Netherland, Sewell & Associates, Inc., the net reserve value of our proved developed and undeveloped reserves was approximately $23.3 million at December 31, 2022, based on the average Henry Hub natural gas price spot price of $6.357 per MCF and for oil volumes, the average West Texas Intermediate price of $94.14 per barrel as applied on a field-by-field basis. Netherland, Sewell & Associates, Inc. provided reserve value information for our California, Texas, Oklahoma, Utah and Louisiana properties. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. These estimates do not include probable or possible reserves.
The technical persons responsible for preparing the reserves estimates presented in the report of Netherland, Sewell & Associates, Inc., meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Netherland, Sewell & Associates, Inc. is a firm of independent petroleum engineers, geologists, geophysicists, and petrophysicists; and do not own an interest in our properties and are not employed on a contingent basis. All activities and reports performed and completed by Netherland, Sewell & Associates, Inc. with regards to our reserve valuation estimates are reviewed by our management.
These estimates are furnished and calculated in accordance with requirements of the FASB and the SEC. Because of unpredictable variances in expenses and capital forecasts, crude oil and natural gas price changes, largely influenced and controlled by U.S. and foreign government actions, and the fact that the bases for such estimates vary significantly, management believes the usefulness of these projections is limited. Estimates of future net cash flows presented do not represent our management’s assessment of future profitability or future cash flows. Management’s investment and operating decisions are based upon reserve estimates that include proved reserves prescribed by the SEC as well as probable reserves, and upon different price and cost assumptions from those used here.
It should be recognized that applying current costs and prices and a 10 percent standard discount rate does not convey absolute value. The discounted amounts arrived at are only one measure of the value of proved reserves.
Changes in Estimated Reserve Quantities
The net interest in estimated quantities of proved developed reserves of crude oil and natural gas at December 31, 2022 and 2021, and changes in such quantities during each of the years then ended, were as follows:
Total Proved Reserves
|
|
|
|
2022
|
|
|
2021
|
|
|
|
Oil (BBL)
|
|
|
Gas (MCF)
|
|
|
Oil (BBL)
|
|
|
Gas (MCF)
|
|
Beginning of period
|
|
|
1,579,100 |
|
|
|
1,354,300 |
|
|
|
1,541,000 |
|
|
|
2,660,500 |
|
Revisions of previous estimates
|
|
|
(1,283,285 |
)
|
|
|
(85,864 |
)
|
|
|
(1,737 |
)
|
|
|
(1,916,677 |
)
|
Production
|
|
|
(18,015 |
)
|
|
|
(135,136 |
)
|
|
|
(18,963 |
)
|
|
|
(122,151 |
)
|
Extensions, discoveries and improved recovery
|
|
|
94,500 |
|
|
|
- |
|
|
|
146,052 |
|
|
|
782,300 |
|
Sales of minerals in place
|
|
|
- |
|
|
|
- |
|
|
|
(87,252 |
)
|
|
|
(49,672 |
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves end of period
|
|
|
372,300 |
|
|
|
1,133,300 |
|
|
|
1,579,100 |
|
|
|
1,354,300 |
|
Proved Developed
|
|
|
|
2022
|
|
|
2021
|
|
|
|
Oil (BBL)
|
|
|
Gas (MCF)
|
|
|
Oil (BBL)
|
|
|
Gas (MCF)
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
|
|
193,600 |
|
|
|
939,100 |
|
|
|
224,900 |
|
|
|
691,900 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of period
|
|
|
182,000 |
|
|
|
942,000 |
|
|
|
193,600 |
|
|
|
939,100 |
|
Proved Undeveloped
|
|
|
|
2022
|
|
|
2021
|
|
|
|
Oil (BBL)
|
|
|
Gas (MCF)
|
|
|
Oil (BBL)
|
|
|
Gas (MCF)
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
|
|
1,385,500 |
|
|
|
415,200 |
|
|
|
1,316,100 |
|
|
|
1,968,600 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of period
|
|
|
190,300 |
|
|
|
191,300 |
|
|
|
1,385,500 |
|
|
|
415,200 |
|
During 2022, our overall proved developed and undeveloped oil reserves decreased by 76.4% and our previously estimated proved developed and undeveloped oil reserve quantities were revised downward by approximately 1.3 million barrels. This downward revision was mainly the result of a decrease in proved undeveloped oil reserves from drilling locations which the Company had previously estimated. Our overall proved developed and undeveloped natural gas reserves decreased by 16.3% and our previously estimated proved developed and undeveloped natural gas reserve quantities were revised downward by approximately 86 thousand cubic feet of natural gas. This downward revision was mainly the result of a decrease in proved undeveloped natural gas reserves from drilling locations which we had previously estimated.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The future net cash inflows are developed as follows:
•
|
Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions.
|
•
|
The estimated future production of proved reserves is priced on the basis of year-end prices.
|
• | The resulting future gross revenue streams are reduced by estimated future costs to develop and to produce proved reserves, based on year-end estimates. Estimated future development costs by year are as follows: |
2023
|
|
$ |
1,374,500 |
|
2024
|
|
|
- |
|
2025
|
|
|
- |
|
Thereafter
|
|
|
4,000 |
|
|
|
$ |
1,378,500 |
|
The resulting future net revenue streams are reduced to present value amounts by applying a 10 percent discount.
Disclosure of principal components of the standardized measure of discounted future net cash flows provides information concerning the factors involved in making the calculation. In addition, the disclosure of both undiscounted and discounted net cash flows provides a measure of comparing proved oil and gas reserves both with and without an estimate of production timing. The standardized measure of discounted future net cash flow relating to proved reserves reflects estimated income taxes.
Changes in standardized measure of discounted future net cash flow from proved reserve quantities
The standardized measure of discounted future net cash flows is presented below for the years ended December 31, 2022 and 2021.
This statement discloses the sources of changes in the standardized measure from year to year. The amount reported as “Net changes in prices and production costs” represents the present value of changes in prices and production costs multiplied by estimates of proved reserves as of the beginning of the year. The “accretion of discount” was computed by multiplying the 10 percent discount factor by the standardized measure on a pretax basis as of the beginning of the year. The “Sales of oil and gas produced, net of production costs” are expressed in actual dollar amounts. “Revisions of previous quantity estimates” is expressed at year-end prices. The “Net change in income taxes” is computed as the change in present value of future income taxes.
|
|
2022
|
|
|
2021
|
|
Future cash inflows
|
|
$ |
38,766,900 |
|
|
$ |
109,213,000 |
|
Future production costs
|
|
|
(14,094,900 |
) |
|
|
(51,448,200 |
) |
Future development costs
|
|
|
(1,378,500 |
) |
|
|
(15,622,600 |
) |
Future income tax expense
|
|
|
(6,988,050 |
) |
|
|
(12,642,660 |
) |
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
16,305,450 |
|
|
|
29,499,540 |
|
|
|
|
|
|
|
|
|
|
10% annual discount for estimated timing of cash flows
|
|
|
(6,044,467 |
) |
|
|
(13,217,621 |
) |
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
|
10,260,983 |
|
|
|
16,281,919 |
|
|
|
|
|
|
|
|
|
|
Sales of oil and gas produced, net of production costs
|
|
|
(608,735 |
) |
|
|
(261,473 |
) |
|
|
|
|
|
|
|
|
|
Revisions of previous quantity estimates
|
|
|
(12,855,765 |
) |
|
|
9,511,179 |
|
Net changes in prices and production costs
|
|
|
(287,425 |
) |
|
|
1,532,518 |
|
Sales of minerals in place
|
|
|
- |
|
|
|
(1,236,927 |
) |
Extensions, discoveries and improved recovery
|
|
|
4,266,500 |
|
|
|
5,304,521 |
|
Accretion of discount
|
|
|
884,088 |
|
|
|
(2,219,984 |
) |
|
|
|
|
|
|
|
|
|
Net change in income tax
|
|
|
2,580,401 |
|
|
|
(3,788,950 |
) |
|
|
|
|
|
|
|
|
|
Net increase (decrease)
|
|
$ |
(6,020,936 |
) |
|
$ |
8,840,884 |
|
Future Development Costs
In order to realize future revenues from our proved reserves estimated in our reserve report, it will be necessary to incur future costs to develop and produce the proved reserves. The following table estimates the costs to develop and produce our proved reserves in the year 2023.
|
|
2023
|
|
Future development cost of:
|
|
|
|
|
Proved developed reserves (PDP)
|
|
|
- |
|
Proved non-producing reserves (PDNP)
|
|
$ |
74,500 |
|
Proved undeveloped reserves (PUD)
|
|
|
1,300,000 |
|
|
|
|
|
|
Total
|
|
$ |
1,374,500 |
|
Common assumptions include such matters as the real extent and average thickness of a particular reservoir, the average porosity and permeability of the reservoir, the anticipated future production from existing and future wells, future development and production costs and the ultimate hydrocarbon recovery percentage. As a result, oil and gas reserve estimates and discounted present value estimates are frequently revised in subsequent periods to reflect production data obtained after the date of the original estimate. If the reserve estimates are inaccurate, production rates may decline more rapidly than anticipated, and future production revenues may be less than estimated.
Additional data relating to our oil and natural gas properties is disclosed in Supplemental Information About Oil and Gas Producing Activities (Unaudited), attached to our Financial Statements, in Note 19.
Historic Development Costs for Proved Reserves
In each year we expend funds to drill and develop some of our proved undeveloped reserves. We have incurred no cost in any of the past three fiscal years to drill and develop reserves that were classified as proved undeveloped reserves as of December 31 of the immediately preceding year.
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