UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
| For the Fiscal Year Ended December 31, 2022 | | | Commission File No. 055912 |
ROYALE ENERGY, INC.
(Name of registrant in its charter)
| Delaware | | 81-4596368 |
| (State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
1530 Hilton Head Road #205
El Cajon, CA 92019
(Address of principal executive offices)
Registrant’s telephone number: 619-383-6600
Securities registered pursuant to Section 12(b) of the Act: None.
Securities to be registered pursuant to Section 12(g) of the Act:
Common Stock, 0.001 par value per share
(Title of Class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically 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:
| Large accelerated filer ☐ | | Accelerated filer ☐ |
| | | |
| Non-accelerated filer ☒ | | Smaller Reporting Company ☒ |
| | | |
| Emerging growth company ☐ | | |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
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.
TABLE OF CONTENTS
ROYALE ENERGY, INC.
PART I
Item 1 Description of Business
Royale Energy, Inc. (“Royale” or the “Company”) is an independent oil and natural gas producer incorporated under the laws of Delaware. Royale’s principal lines of business are the production and sale of oil and natural gas, acquisition of oil and gas lease interests and proved reserves, drilling of both exploratory and development wells, and sales of fractional working interests in wells to be drilled by Royale. Royale was incorporated in Delaware in 2017 and is the successor by merger (as described below) to Royale Energy Funds, Inc., a California corporation formed in 1983. On December 31, 2022, Royale and its consolidated subsidiaries had 10 full time employees.
Royale Business
Royale and its subsidiaries own wells, leases, and proved and non-proved reserves of oil and gas located mainly in Mitchell County, Texas and in the Sacramento Basin and San Joaquin Basin in California, as well as in Utah, Oklahoma, Louisiana and Colorado. Royale also owns an overriding royalty interest in a discovery in Alaska. Royale usually sells a portion of the working interest in each well it drills or participates in to third-party participants and retains a portion of the prospect for its own account. Selling part of the working interest to others allows Royale to reduce its drilling risk by owning a diversified inventory of properties with less of its own funds invested in each drilling prospect, than if Royale owned all the working interest and paid all drilling and development costs of each prospect itself. Royale generally sells working interests in its prospects to accredited investors in exempt securities offerings. The prospects are typically bundled into multi-well investments, which permit the third-party investors to diversify their investments by investing in several wells at once instead of investing in single well prospects.
During its fiscal year ended December 31, 2022, Royale continued to explore and develop oil and natural gas properties with concentration in California and Texas. In 2022, Royale drilled and completed five wells and participated in the drilling of two wells, all of which were commercially productive. Royale’s estimated total reserves were approximately 3.4 and 10.8 BCFE (billion cubic feet equivalent) at December 31, 2022 and 2021, respectively. According to the reserve reports furnished by Netherland, Sewell & Associates, Inc., Royale’s independent petroleum engineers, the net reserve value of its 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. supplied reserve value estimates for the Company’s California, Texas, Oklahoma, and Utah properties.
Net reserve value does not represent the fair market value of our reserves on that date, and we cannot be sure what return we will eventually receive on our reserves. Net reserve value of proved developed and undeveloped reserves was calculated by subtracting estimated future development costs, future production costs and other operating expenses from estimated net future cash flows from our developed and undeveloped reserves.
Our standardized measure of discounted future net cash flows at December 31, 2022, was estimated to be $10,260,983. This figure was calculated by subtracting our estimated future income tax expense from the net reserve value of proved developed and undeveloped reserves, and by further applying a 10% annual discount for estimated timing of cash flows. A detailed calculation of our standardized measure of discounted future net cash flow is contained in Note 19 to our Financial Statements, Supplemental Information about Oil and Gas Producing Activities (Unaudited) – Changes in Standardized Measure of Discounted Future Net Cash Flow from Proved Reserve Quantities.
Royale reported a gain on turnkey drilling in connection with the drilling of wells on a “turnkey contract” basis in the amount of $1,726,414 for the year ended December 31, 2022. For the year ended December 31, 2021, Royale reported a loss on turnkey drilling in the amount of $64,468.
In addition to Royale’s own staff, Royale hires independent contractors to drill, test, complete and equip the wells that it drills. Approximately 98.8% of Royale’s total revenue for the year ended December 31, 2022, came from sales of oil and natural gas from production of its wells in the amount of $2,611,222. In 2021, this amount was $1,686,424, which represented 98.1% of Royale’s total revenues for the respective periods presented. See Note 3 to our Financial Statements.
Plan of Business
Royale acquires interests in oil and natural gas reserves and sponsors private joint ventures. Royale believes that its stockholders are better served by diversification of its investments among individual drilling prospects. Through its sale of joint ventures, Royale can acquire interests and develop oil and natural gas properties with greater diversification of risk and still receive an interest in the revenues and reserves produced from these properties. By selling some of its working interest in most projects, Royale decreases the amount of its investment required in the projects and diversifies its oil and gas property holdings, to reduce the risk of concentrating a large amount of its capital in a few projects that may not be successful.
After acquiring the leases or lease participation, Royale drills or participates in the drilling of development and exploratory oil and natural gas wells on its property. Royale pays its proportionate share of the actual cost of drilling, testing, and completing the project to the extent that it retains all or any portion of the working interest.
Royale also may sell fractional working interests in undeveloped wells to finance part of the drilling cost. A drilling contract that calls for a company to drill a well, for a fixed price, to a specified depth or geological formation is called a “turnkey contract.” When Royale sells fractional working interests in undeveloped property to raise capital to drill oil and natural gas wells, generally it agrees to drill these wells on a turnkey contract basis, so that the holders of the fractional interests prepay a fixed amount for the drilling and completion of a specified number of wells. Under a turnkey contract, Royale may record a gain if total funds received to drill a well were more than the actual cost to drill those wells including costs incurred on behalf of the participants and costs incurred for its own account.
Although Royale’s operating agreements do not usually address whether investors have a right to participate in subsequent wells in the same area of interest as a proposed well, it is the Company’s policy to offer to investors in a successful well the right to participate in subsequent wells at the same percentage level as their working interest investment in the prior successful well.
Our policy for turnkey drilling agreements is to recognize a gain on turnkey drilling programs after our obligations have been fulfilled, and a gain is only recorded when funds received from participants are in excess of all costs 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 its own account. See Note 1 to our Financial Statements, at page F-14.
Once commenced, drilling is generally completed within 10-30 days. Royale maintains internal records of the expenditure of each investor’s funds for drilling projects.
Royale generally operates the wells it completes. As operator, we receive fees set by industry standards from the owners of fractional interests in the wells and from expense reimbursements. For the year ended December 31, 2022, Royale charged overhead from operation of the wells in the amount of $355,681 for the year, which were an offset to general and administrative expenses. In 2021, the amount was $311,754. At December 31, 2022, Royale operated wells in California and Texas. Royale also has non-operating interests in wells in California, Utah, Texas, and Oklahoma.
Royale currently sells most of its California natural gas production through Pacific Gas & Electric (“PG&E”) pipelines to independent customers on a monthly contract basis, while some gas is delivered through privately owned pipelines to independent customers. Since many users are willing to make such purchase arrangements, the loss of any one customer would not affect our overall sales operations.
All oil and natural gas properties are depleting assets in which production naturally decreases over time as the finite amount of existing reserves are produced and sold. It is Royale’s business as an oil and natural gas exploration and production company to continually search for new development properties. The Company’s success will ultimately depend on its ability to continue locating and developing new oil and natural gas resources. Oil demand is subject to global demand and prices can fluctuate widely. In mid-2022, oil prices increased dramatically due to worldwide speculation caused by Russia’s invasion of Ukraine, but by the end of 2022 had returned to pre-invasion levels. The future market is likely to be subject to continued similar price dynamics. Natural gas demand and the prices paid for gas are seasonal. In recent years, natural gas demand and prices in Northern California have fluctuated unpredictably throughout the year.
Competition, Markets and Regulation
Competition
The exploration and production of oil and natural gas is an intensely competitive industry. The sale of interests in oil and gas projects, like those Royale sells, is also very competitive. Royale encounters competition from other oil and natural gas producers, as well as from other entities that invest in oil and gas for their own account or for others, and many of these companies are substantially larger than Royale.
Markets
Market factors affect the quantities of oil and natural gas production and the price Royale can obtain for the production from its oil and natural gas properties. Such factors include: the extent of domestic production; the level of imports of foreign oil and natural gas; the general level of market demand on a regional, national and worldwide basis; domestic and foreign economic conditions that determine levels of industrial production; political events in foreign oil-producing regions; and variations in governmental regulations including environmental, energy conservation, and tax laws or the imposition of new regulatory requirements upon the oil and natural gas industry.
Regulation
Federal and state laws and regulations affect, to some degree, the production, transportation, and sale of oil and natural gas from Royale’s operations. States in which Royale operates have statutory provisions regulating the production and sale of oil and natural gas, including provisions regarding deliverability. These statutes, along with the regulations interpreting the statutes, generally are intended to prevent waste of oil and natural gas, and to protect correlative rights to produce oil and natural gas by assigning allowable rates of production to each well or proration unit. On September 16, 2022, the Governor of California, Gavin Newsom, signed Senate Bill No. 1137 (“SB1137”) into law. SB1137 prohibits the issuance of well permits and the construction and operation of new production facilities within a “health protection zone” of 3,200 feet from certain sensitive (receptors such as homes, schools, nursing homes, or hospitals). We and our industry partner, RMX Resources, LLC (“RMX”) operate wells, production facilities, and future drilling located within a health protection zone. In December 2022, proponents of a voter referendum initiated to challenge SB1137 (the “Referendum”) collected the requisite signatures to place SB1137 on the November 2024 ballot. On February 3, 2023, the Secretary of State of California certified that the requisite number of signatures had been submitted and validated for the Referendum to become duly qualified for the November 2024 ballot. By law, the effectiveness of a statute challenged in its entirety by a duly validated Referendum is stayed until it has been approved by the voters at the required election. Thus, the implementation of SB1137’s provisions are stayed as of February 3, 2023, until the Referendum challenge has been resolved by a vote of the California electorate on November 5, 2024. If SB 1137 were to be left in effect, it would limit certain undeveloped drilling locations, and significantly deter our participation in future drilling efforts with RMX. Additionally, we cannot predict any future actions the State of California, or other parties, may take that could further limit our ability to drill in certain areas.
The exploration, development, production and processing of oil and natural gas are subject to various federal and state laws and regulations to protect the environment. Various federal and state agencies are considering, and some have adopted, other laws and regulations regarding environmental controls that could increase the cost of doing business. These laws and regulations may require: the acquisition of permits by operators before drilling commences; the prohibition of drilling activities on certain lands lying within wilderness areas or where pollution arises; and the imposition of substantial liabilities for pollution resulting from drilling operations, particularly operations in offshore waters or on submerged lands. The cost of oil and natural gas development and production also may increase because of the cost of compliance with such legislation and regulations, together with any penalties resulting from failing to comply with the legislation and regulations. Ultimately, Royale may bear some of these costs.
Presently, Royale does not hold any undeveloped federal acreage on which it had plans to drill, and does not anticipate that compliance with federal, state and local environmental regulations will have a material adverse effect on capital expenditures, earnings, or its competitive position in the oil and natural gas industry; however, changes in the laws, rules or regulations, or the interpretation thereof, could have a materially adverse effect on Royale’s financial condition or results of operation.
Availability of Public Filings
You may obtain a copy of any materials filed by Royale with the Securities and Exchange Commission (“SEC”) at http://www.sec.gov. Royale also provides access to its SEC reports and other public announcements on its website, http://www.royl.com. The information on our website is not part of this Annual Report on Form 10-K.
Item 1A Risk Factors
As a smaller reporting company, as defined in Rule 12b-2 of the Exchange Act, Royale is not required to provide the information required by this Item.
Item 2 Description of Property
Since 1993, Royale had concentrated on development of properties in the Sacramento Basin and the San Joaquin Basin of Northern and Central California. In the last few years it has moved its focus to the Los Angeles Basin in Southern California and to Mitchell County, Texas. In 2022, Royale drilled five developmental oil wells in Texas and participated in the drilling of two oil wells in southern California.
Following industry standards, Royale generally acquires oil and natural gas acreage without warranty of title except as to claims made by, though, or under the transferor. In these cases, Royale attempts to conduct due diligence as to title before the acquisition, but it cannot assure that there will be no losses resulting from title defects or from defects in the assignment of leasehold rights. Title to property most often carries encumbrances, such as royalties, overriding royalties, carried and other similar interests, and contractual obligations, all of which are customary within the oil and natural gas industry.
Following is a discussion of Royale’s significant oil and natural gas properties. Reserves at December 31, 2022, for each property discussed below, have been determined by Netherland, Sewell & Associates, Inc., registered professional petroleum engineers, in accordance with reports submitted to Royale on February 8, 2023.
California
Royale owns interests in nine gas fields with locations ranging throughout the Sacramento Basin in California. At December 31, 2022, Royale operated 12 wells and owns interests in 13 non-operated gas wells in Northern California and 8 non-operated oil wells in Southern and Central California. Our California estimated total proven, developed, and undeveloped net reserves are approximately 0.921 BCFE, according to Royale’s independently prepared reserve report as of December 31, 2022.
Texas
At December 31, 2022, Royale owned and operated interests in 25 oil wells in its Jameson field. Our Texas estimated total proven, developed, and undeveloped net reserves are approximately 334.2 MBOE, according to Royale’s independently prepared reserve report as of December 31, 2022. Additionally, Royale owns interests in four non-operated gas wells, two located in Oklahoma, one located in Texas and one located in Utah.
Developed and Undeveloped Leasehold Acreage
As of December 31, 2022, Royale owned leasehold interests in the following developed and undeveloped properties in both gross and net acreage.
| |
|
Developed
|
|
|
Undeveloped
|
|
| |
|
Gross Acres
|
|
|
Net Acres
|
|
|
Gross Acres
|
|
|
Net Acres
|
|
|
California
|
|
|
3,906.87 |
|
|
|
2,808.93 |
|
|
|
8,531.70 |
|
|
|
2,197.37 |
|
|
All Other States
|
|
|
9,189.25 |
|
|
|
8,278.19 |
|
|
|
0.00 |
|
|
|
0.00 |
|
|
Total
|
|
|
13,096.12 |
|
|
|
11,087.12 |
|
|
|
8,531.70 |
|
|
|
2,197.37 |
|
Gross and Net Productive Wells
As of December 31, 2022 and 2021, Royale owned interests in the following oil and gas wells in both gross and net acreage:
| |
|
2022
|
|
|
2021
|
|
| |
|
Gross Wells
|
|
|
Net Wells
|
|
|
Gross Wells
|
|
|
Net Wells
|
|
|
Natural Gas
|
|
|
29 |
|
|
|
11.1752 |
|
|
|
36 |
|
|
|
12.2620 |
|
|
Oil
|
|
|
33 |
|
|
|
20.3997 |
|
|
|
28 |
|
|
|
19.8313 |
|
|
Total
|
|
|
62 |
|
|
|
31.5749 |
|
|
|
64 |
|
|
|
32.0933 |
|
Drilling Activities
The following table sets forth Royale’s drilling activities during the years ended December 31, 2022 and 2021. All wells are located in the Continental U.S., in California, Texas, Louisiana, Colorado and Utah.
|
Year
|
|
Type of Well(a)
|
|
|
|
|
|
Gross Wells(b)
|
|
|
Net Wells(e)
|
|
| |
|
|
|
Total
|
|
|
Producing(c)
|
|
|
Dry(d)
|
|
|
Producing(c)
|
|
|
Dry(d)
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2021
|
|
Exploratory
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
| |
|
Developmental
|
|
|
2 |
|
|
|
2 |
|
|
|
0 |
|
|
|
0.9374 |
|
|
|
0 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2022
|
|
Exploratory
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
| |
|
Developmental
|
|
|
7 |
|
|
|
7 |
|
|
|
0 |
|
|
|
1.6781 |
|
|
|
0 |
|
a) An exploratory well is one that is drilled in search of new oil and natural gas reservoirs, or to test the boundary limits of a previously discovered reservoir. A developmental well is one drilled on a previously known productive area of an oil and natural gas reservoir with the objective of completing that reservoir.
b) Gross wells represent the number of actual wells in which Royale owns an interest. Royale’s interest in these wells may range from 1% to 100%.
c) A producing well is one that produces oil and/or natural gas that is being purchased on the market.
d) A dry well is a well that is not deemed capable of producing hydrocarbons in paying quantities.
e) One “net well” is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as a whole number or a fraction.
Production
The following table summarizes, for the years indicated, Royale’s net share of oil and natural gas production, average sales price per barrel (BBL), per thousand cubic feet (MCF) of natural gas, and the MCF equivalent (MCFE) for the barrels of oil based on a 6 to 1 ratio of the price per barrel of oil to the price per MCF of natural gas. “Net” production is production that Royale owns either directly or indirectly through partnership or joint venture interests produced to its interest after deducting royalty, limited partner or other similar interests. Royale generally sells its oil and natural gas at prices then prevailing on the “spot market” and does not have any material long term contracts for the sale of natural gas at a fixed price.
| |
|
2022
|
|
|
2021
|
|
|
Net volume
|
|
|
|
|
|
|
|
|
|
Oil (BBL)
|
|
|
18,015 |
|
|
|
18,963 |
|
|
Gas (MCF)
|
|
|
135,136 |
|
|
|
122,151 |
|
|
MCFE
|
|
|
243,226 |
|
|
|
235,929 |
|
| |
|
|
|
|
|
|
|
|
|
Average sales price
|
|
|
|
|
|
|
|
|
|
Oil (BBL)
|
|
$ |
91.86 |
|
|
$ |
65.28 |
|
|
Gas (MCF)
|
|
$ |
7.01 |
|
|
$ |
3.64 |
|
| |
|
|
|
|
|
|
|
|
|
Net production costs and taxes
|
|
$ |
1,928,521 |
|
|
$ |
1,814,643 |
|
| |
|
|
|
|
|
|
|
|
|
Lifting costs (per MCFE)
|
|
$ |
7.93 |
|
|
$ |
7.69 |
|
Reserve Estimates
Management has established, and is responsible for, internal controls designed to provide reasonable assurance that the estimates of Proved Reserves are computed and reported in accordance with rules and regulations promulgated by the SEC as well as established industry practices used by independent engineering firms and our peers. These internal controls include documented process workflows and qualified professional engineering and geological personnel with specific reservoir experience. Our internal processes and controls surrounding this process are routinely tested. We also retain outside independent engineering firms to prepare estimates of our Proved Reserves. Management reviews and approves our reserve estimates, whether prepared internally or by third parties. Our Chief Executive Officer oversaw our outside independent engineering firm, Netherland, Sewell & Associates, Inc. ("NSAI"), in connection with the preparation of their estimates of our Proved Reserves as of December 31, 2022. We also regularly communicate with NSAI throughout the year regarding technical and operational matters critical to our reserve estimations. Our Chief Executive Officer, with input from other members of management, is responsible for the selection of our third-party engineering firms and review of the reports generated. Our Chief Executive Officer has over 38 years of experience in the oil and natural gas industry and is a graduate of the University of Oklahoma with a degree in Chemical Engineering. During his career, he has had various relevant responsibilities in technical and leadership roles including asset management, drilling and completions, production engineering, reservoir engineering and reserves management, economic evaluations and field development in U.S. onshore projects. The third-party engineering reports are also provided to the Audit Committee.
Net Proved Oil and Natural Gas Reserves
|
Reserves
|
|
|
|
|
|
|
|
|
|
Category
|
|
Oil (MBBL)
|
|
|
Natural Gas (MMCF)
|
|
|
PROVED
|
|
|
|
|
|
|
|
|
|
Developed:
|
|
|
|
|
|
|
|
|
|
California
|
|
|
35.035 |
|
|
|
542.436 |
|
|
Texas
|
|
|
146.736 |
|
|
|
359.408 |
|
|
All other states
|
|
|
0.242 |
|
|
|
40.121 |
|
|
Undeveloped:
|
|
|
|
|
|
|
|
|
|
California
|
|
|
28.131 |
|
|
|
- |
|
|
Texas
|
|
|
162.120 |
|
|
|
191.333 |
|
|
All other states
|
|
|
- |
|
|
|
- |
|
|
TOTAL PROVED
|
|
|
372.264 |
|
|
|
1,133.298 |
|
|
Prices used:
|
|
$ |
94.14 |
|
|
$ |
6.357 |
|
As of December 31, 2022, Royale had proved developed reserves of 942,000 MCF and total proved reserves of 1,133,300 MCF of natural gas. For the same period, Royale also had proved developed oil and natural gas liquid combined reserves of 182,000 BBL and total proved oil and natural gas liquid combined reserves of 372,300 BBL.
As of December 31, 2021, Royale had proved developed reserves of 939,100 MCF and total proved reserves of 1,354,300 MCF of natural gas. For the same period, Royale also had proved developed oil and natural gas liquid combined reserves of 193,600 BBL and total proved oil and natural gas liquid combined reserves of 1,579,100 BBL.
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 the Company had previously estimated.
Oil and gas reserve estimates and the discounted present value estimates associated with the reserve estimates are based on numerous engineering, geological and operational assumptions that generally are derived from limited data.
Item 3 Legal Proceedings
From time to time, the Company may be involved in various legal proceedings or may be subject to claims that arise in the ordinary course of business. The outcome of any such claims or proceedings cannot be predicted with certainty. As of the date of this filing, management is not aware of any such claims against the Company.
Item 4 Mine Safety Disclosures
Not Applicable
PART II
Item 5 Market for Common Equity and Related Stockholder Matters
There is no established trading market for Royale’s Common Stock, which is quoted on the OTC QB Market under the symbol “ROYL.” As of December 31, 2022, 61,876,957 shares of Common Stock were held by approximately 3,258 stockholders. As of December 31, 2021, 56,239,715 shares of Royale’s Common Stock were held by approximately 3,455 stockholders. The following table reflects the high and low quarterly bid prices as reported on the OTC QB Market from January 2021 through December 2022:
| |
|
1st Qtr
|
|
|
2nd Qtr
|
|
|
3rd Qtr
|
|
|
4th Qtr
|
|
| |
|
High
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2021
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0.03 |
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The OTC QB Market is not an exchange, and any over the counter quotations reflect inter-dealer prices, without retail markup, markdown or commission, and may not necessarily represent actual transactions.
Transfer Agent
The Company utilizes the independent transfer agent services of American Stock Transfer & Trust Company as its transfer agent.
Dividends
The Board of Directors did not issue cash dividends in either 2022 or 2021. The Board of Directors did declare dividends during 2022 and 2021 on the preferred stock to be Paid In Kind (“PIK”) of 81,580 and 78,784 shares with a respective par value of $815,772 and $787,833, as more fully set forth in Note 7 to our Financial Statements.
Recent Sales of Unregistered Securities
None.
Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management’s Discussion and Analysis is the Company’s analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes, and supplemental oil and gas disclosures included elsewhere in this report. It contains forward-looking statements including, without limitation, statements relating to the Company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. Readers are cautioned that such forward-looking statements should be read in conjunction with the Company’s disclosures under the heading: “Cautionary Statement about Forward-Looking Statements” in this Annual Report.
Overview
Royale is an independent oil and natural gas producer. Royale’s principal lines of business are the production and sale of oil and natural gas, acquisition of oil and gas lease interests and proved reserves, drilling of both exploratory and development wells, and sales of fractional working interests in wells to be drilled by Royale. Since 1993, Royale has primarily acquired and developed producing and non-producing natural gas properties in California. In December 2018, Royale became the operator of a newly acquired field in Texas. The most significant factors affecting the results of operations are (i) changes in oil and natural gas prices, production levels and reserves, (ii) turnkey drilling activities, and (iii) the increase in future cost associated with abandonment of wells.
Critical Accounting Policies
Revenue Recognition
Royale’s primary business is oil and gas production. Natural gas flows from the wells into gathering line systems, which are equipped occasionally with compressor systems, which in turn flow into metered transportation and customer pipelines. Monthly, price data and daily production are used to invoice customers for amounts due to Royale and other working interest owners. Royale operates most of its own wells and receives industry standard operator fees (“Supervisory Fees”). Supervisory Fees are recognized as a reduction to the Company’s General and Administrative Expenses.
Royale generally sells crude oil and natural gas under short-term agreements at prevailing market prices. Revenues are recognized when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured.
Revenues from the production of oil and natural gas properties in which the Royale has an interest with other producers are recognized on the basis of Royale’s net working interest. Differences between actual production and net working interest volumes are not significant.
The Company’s Financial Statements include its pro rata ownership of wells. The Company usually sells a portion of the working interest in each well it drills or participates in to third-party participants and retains a portion of the prospect for its own account. All results, successful or not, are included at its pro rata ownership amounts: revenue, expenses, assets, and liabilities as defined in FASB ASC 932-323-25 and 932-360.
Equity Method Investments
Investments in entities over which the Company has significant influence, but not control, are accounted for using the equity method of accounting. Income from equity method investments represents Royale’s proportionate share of net income generated by the equity method. Equity method investments are included as noncurrent assets on the consolidated balance sheet.
Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value may have occurred. 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.
Oil and Gas Property and Equipment
Depreciation, depletion and amortization, based on cost less estimated salvage value of the asset, are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired.
The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use. Interest costs, to the extent they are incurred to finance expenditures during the construction phase, are included in property, plant and equipment and are depreciated over the service life of the related assets.
Royale uses the “successful efforts” method to account for its exploration and production activities. Under this method, Royale accumulates its proportionate share of costs on a well-by-well basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred, and capitalizes expenditures for productive wells. Royale amortizes the costs of productive wells under the unit-of-production method.
Royale carries, as an asset, exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where Royale is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred.
Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves.
Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using unit-of-production rates based on the amount of proved developed reserves of oil and gas that are estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production method, oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank.
Production costs are expensed as incurred. Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain Royale’s wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labor costs to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity. Proved oil and gas properties held and used by Royale are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable.
Royale estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated evaluation assumptions for crude oil commodity prices. Annual volumes are based on field production profiles, which are also updated annually. Prices for natural gas and other products are based on assumptions developed annually for evaluation purposes.
Impairment analyses are generally based on proved reserves. An asset group would be impaired if the undiscounted cash flows were less than its’ carrying value. Impairments are measured by the amount the carrying value exceeds fair value. During 2022 and 2021, impairment losses of $0 and $177,011, respectively, were recorded on various capitalized lease and land costs where the carrying value exceeded the fair value or where the leases were no longer viable.
Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that Royale expects to hold the properties. The valuation allowances are reviewed at least annually.
Upon the sale or retirement of a complete field of a proved property, Royale eliminates the cost from its books, and the resultant gain or loss is recorded to Royale’s Statement of Operations. Upon the sale of an entire interest in an unproved property where the property has been assessed for impairment individually, a gain or loss is recognized in Royale’s Statement of Operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a recovery of the cost in the interest retained with any excess funds recognized as a gain. Should Royale’s turnkey drilling agreements include unproved property, total drilling costs incurred to satisfy its obligations are recovered by the total funds received under the agreements. Any excess funds are recorded as a Gain on Turnkey Drilling Programs, and any costs not recovered are capitalized and accounted for under the “successful efforts” method.
The Company sponsors turnkey drilling agreement arrangements in properties as a pooling of assets in a joint undertaking, whereby proceeds from participants are reported as Deferred Drilling Obligations, and then reduced as costs to complete its obligations are incurred with any excess booked against its property account to reduce any basis in its own interest. Gains on Turnkey Drilling Programs represent funds received from turnkey drilling participants in excess of all costs Royale incurs during the drilling programs (e.g., lease acquisition, exploration and development costs), including costs incurred on behalf of participants and costs incurred for its own account; and are recognized only upon making this determination after Royale’s obligations have been fulfilled.
The contracts require the participants to pay Royale the full contract price upon execution of the agreement. Royale completes the drilling activities typically between 10 and 30 days after drilling begins. The participant retains an undivided or proportional beneficial interest in the property, and is also responsible for their proportionate share of operating costs. Royale retains legal title to the lease. The participants purchase a working interest directly in the well bore.
In these working interest arrangements, the participants are responsible for sharing in the risk of development, but also sharing in a proportional interest in rights to revenues and proportional liability for the cost of operations after drilling is completed.
Since the participant’s interest in the prospect is limited to the well, and not the lease, the participant does not have a legal right to participate in additional wells drilled within the same lease. However, it is the Company’s policy to offer to participants in a successful well the right to participate in subsequent wells at the same percentage level as their working interest investment in the prior successful well with similar turnkey drilling agreement terms.
A certain portion of the turnkey drilling participant’s funds received are non-refundable. The Company records a liability for all funds invested as deferred drilling obligations until each individual well is complete. Occasionally, drilling is delayed for various reasons such as weather, permitting, drilling rig availability and/or contractual obligations. At December 31, 2022 and 2021, Royale had deferred drilling obligations of $8,129,965 and $7,824,939 respectively.
If Royale is unable to drill the wells, and a suitable replacement well is not found, Royale would retain the non-refundable portion of the contract and return the remaining funds to the participant. Included in restricted cash are amounts for use in completion of turnkey drilling programs in progress.
Losses on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value.
Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, plant products and gas reserve volumes and the future development costs. Actual results could differ from those estimates.
Deferred Income Taxes
Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts attributable to events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax credit carry forwards. All available evidence, both positive and negative, must be considered to determine whether, based on the weight of that evidence, a valuation allowance for deferred tax assets is needed. The Company uses information about the Company’s financial position and its results of operations for the current and preceding years.
The Company must use its judgment in considering the relative impact of negative and positive evidence. The weight given to the potential effect of negative and positive evidence is commensurate with the extent to which it can be objectively verified. The more negative evidence that exists, the more positive evidence is necessary and the more difficult it is to support a conclusion that a valuation allowance is not needed for some portion or all of the deferred tax asset. A cumulative loss in recent years is a significant piece of negative evidence that is difficult to overcome.
Future realization of a tax benefit sometimes will be expected for a portion, but not all, of a deferred tax asset, and the dividing line between the two portions may be unclear. In those circumstances, application of judgment based on a careful assessment of all available evidence is required to determine the portion of a deferred tax asset for which it is more-likely-than-not a tax benefit will not be realized.
Going Concern
At December 31, 2022, the Company has an accumulated deficit of $87,646,402, a working capital deficiency of $6,445,318 and a stockholders’ deficit of $33,136,603. As a result, our financial statements include a “going concern qualification” reflecting substantial doubt as to our ability to continue as a going concern. See Note 1 to our audited financial statements. We do not possess funds necessary to implement our 2023 budget. Royale is continuing its drilling efforts with its direct working interest owners. In addition, we are exploring commitments to provide additional financing, but there is no guarantee that we will be able to secure additional financing on acceptable terms, or at all, needed to fully fund our 2023 drilling budget and to support future operations.
Results of Operations for the Year Ended December 31, 2022, as Compared to the Year Ended December 31, 2021
For the year ended December 31, 2022, we had a net loss of $145,594 compared to the net loss of $3,598,418 during the year in 2021. Total revenues from operations in 2022 were $2,642,537, an increase of $923,873 or 53.8%, from the total revenues of $1,718,664 in 2021, due to higher oil and natural gas commodity prices during 2022. Total expenses for operations in 2022 were $5,098,278, a decrease of $222,079 or 4.2%, from total expenses of $5,320,357 in 2021, mainly due to higher lease impairments and bad debt expenses during 2021.
During the year ended 2022, revenues from oil and gas production increased $924,798 or 54.8% to $2,611,222 from the 2021 revenues of $1,686,424. This increase was mainly due to higher commodity prices realized for the sale of oil and gas in 2022. The net sales volume of oil and condensate for the year ended December 31, 2022 was approximately 18,015 barrels of oil with an average price of $91.86 versus approximately 18,963 barrels with an average price of $65.28 per barrel, for the year in 2021. This represents a decrease in net sales volume of approximately 948 barrels or 5.0%, which was due to lower production volumes on existing wells due to natural declines and to the sale of certain non-operated wells during the period in 2021. The net sales volume of natural gas for the year ended December 31, 2022, was approximately 135,136 Mcf with an average price of $7.01 per Mcf, versus 122,151 Mcf with an average price of $3.64 per Mcf for the year in 2021. This represents an increase in net sales volume of approximately 12,985 Mcf or 10.6%. The increase in natural gas production volume was due to certain non-operated wells that had previously been offline were brought back online at the end of 2021.
Oil and natural gas lease operating expenses increased by $113,878 or 6.3%, to $1,928,521 for the year ended December 31, 2022, from $1,814,643 for the year in 2021. This increase was mainly due to higher trucking and water disposal costs due to increases in manpower and fuel costs from outside vendors. When measuring lease operating costs on a production or lifting cost basis, in 2022, the $1,928,521 equates to a $7.93 per Mcfe lifting cost versus a $7.69 per Mcfe lifting cost in 2021, due to higher lease operating costs in 2022.
The aggregate of Supervisory Fees and Other Revenue was $31,315 for year ended December 31, 2022, a decrease of $925 or 2.9% from $32,240 during the year in 2021.
Depreciation, depletion and amortization expense increased to $575,909 from $537,273, an increase of $38,636 or 7.2% for the year ended December 31, 2022, as compared to the year in 2021. The depletion rate is calculated using production by comparing capitalized cost to the recoverable reserves remaining. This increase in depreciation expense was due to a decrease in expected recoverable reserves which increased the depletion rate.
General and administrative expenses decreased by $142,149 or 7.3% from $1,951,083 for the year ended December 31, 2021, to $1,808,197 for the year ended 2022. This decrease was due to lower employee related expenses and other administrative cost reduction measures during 2022. Legal and accounting expense increased to $526,550 for the year in 2022, compared to $419,587 for the year in 2021, a $106,963 or 25.5% increase. This increase was primarily due to higher outside accounting fees mainly related to conversion of our accounting software during 2022. Marketing expense for the year ended December 31, 2022, increased $28,755, or 12.5%, to $259,101, compared to $230,346 for the year in 2021. Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs.
At December 31, 2022, Royale had a Deferred Drilling Obligation of $8,129,965. During 2022, we removed $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. At December 31, 2021, Royale had a Deferred Drilling Obligation of $7,824,939. 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.
During the year in 2022, we recorded a gain of $422,614 on settlement of accounts payable for a reduced amount. During 2022, we also recorded an Other Gain of $163,571, mainly due to the receipt of Employee Retention Credit (ERC) payroll tax refunds from the Internal Revenue Service. During the year in 2021, we recorded a loss of $253,956 on sale of asset upon the sale of certain non-operated California properties which was completed during the third quarter of 2021. We also recorded a gain of $318,834 on the sale of asset upon the sale of certain non-operated Texas properties which was completed during the second quarter of 2021. In both sales, these non-operated properties were originally acquired during the 2018 merger with Matrix and booked as Held for Sale at the end of 2020, which resulted in a net gain on sale of assets of $64,878 in 2021. During the first quarter of 2021, we recorded a gain on settlement of $10,061 due to the payment by the Small Business Administration (“SBA”) of the remaining balance of our PPP loan obtained in 2020. During 2021, we recorded lease impairments of $177,011 on various lease and land costs in our California natural gas fields where the carrying value exceeded the fair value, no lease impairments were recorded in 2022.
Bad debt expense for 2022 and 2021 were $0 and $190,414, respectively. Approximately $180,000 of the expenses in 2021 arose from identified uncollectable receivables relating to our oil and natural gas properties either plugged and abandoned or scheduled for plugging and abandonment (“P&A”) and our year-end oil and natural gas reserve values. We periodically review our accounts receivable from working interest owners to determine whether collection of any of these charges appears doubtful. By contract, the Company may not collect some charges from its Direct Working Interest owners for certain wells that ceased production or had been sold during the year, to the extent that these charges exceed production revenue.
Interest expense for the year ended December 31, 2022 and 2021, were $2,452 and $9,206, respectively.
In 2022 and 2021, we did not have an income tax expense due to the use of a percentage depletion carryover valuation allowance created from the current and past operations resulting in an effective tax rate less than the new federal rate of 21% plus the relevant state rates (mostly California, 8.8%).
Capital Resources and Liquidity
At December 31, 2022, Royale had current assets totaling $8,814,790 and current liabilities totaling $15,260,108, a $6,445,318 working capital deficit. We had cash and cash equivalents at December 31, 2022 of $1,650,507 and restricted cash of $2,249,627 compared to cash and cash equivalents of $220,304 and restricted cash of $4,002,500 at December 31, 2021.
Ordinarily, we fund our operations and cash needs from our available credit and cash flows generated from operations. We believe there is some doubt that the Company has the ability to meet liquidity demands through cash-flow from operations. In that event, the Company will seek alternative capital sources through additional sales of equity or debt securities, or the sale of property, which may not be available at all, or on terms we deem reasonable. We have plans to increase oil and gas revenue in our Texas Jameson field through the workover of existing wells and drilling of new wells. During the fourth quarter 2022 and continuing into the first quarter of 2023, we have completed several successful workovers on existing wells in our Texas Jameson field. These workovers will lead to a significant increase in lease operating expenses but should eventually be offset by higher production volumes. We have commitments to continue to drill and workover wells in the Texas Jameson field and we have also made commitments to participate in the drilling and completion of several non-operated wells in the Permian Basin and in the redrill and completion of a Southern California well.
At December 31, 2022, our other receivables net, which consist of joint interest billing receivables from direct working interest participants and industry partners, totaled $943,633, compared to $413,133 at December 31, 2021, a $530,500 increase. This increase was mainly due higher accounts receivables from direct working interest owners for lease operating expenses due to workovers and stimulation work in our Texas Jameson field during the 4th quarter of 2022 in order to increase production. At December 31, 2022, revenue receivable was $701,937, an increase of $336,787, compared to $365,150 at December 31, 2021, due to higher commodity prices at year end 2022. At December 31, 2022, our accounts payable and accrued expenses totaled $5,528,829, an increase of $368,345 from the accounts payable at December 31, 2021 of $5,160,484, mainly due to drilling and lease operating costs at year end 2022.
We have not engaged in hedging activities nor do we use derivative instruments to manage market risks.
Operating Activities. For the years ended December 31, 2022 and 2021, cash used in operating activities totaled $2,809,788 and $1,624,099, respectively. This $1,185,689 increase in cash used was primarily due to the increase in prepaid drilling costs during the period in 2022 due to participating in the drilling of four non-operated Texas oil wells at year end which are scheduled to be completed in 2023.
Investing Activities. Net cash provided by investing activities totaled $2,608,871 and $3,465,024 for the years ended December 31, 2022 and 2021, respectively. The difference was due to cash receipts of approximately $7.3 million in 2022 and $6.5 million in 2021 in direct working interest turnkey investments. During 2022, our turnkey drilling expenditures were approximately $4.7 million as we drilled and completed five oil wells in Texas and participated in the drilling of two California oil wells. During 2021, our turnkey drilling expenditures were approximately $4.1 million as we drilled and completed two oil wells in Texas and were in process at year end of drilling two California oil wells and two Texas oil wells. Additionally, during 2021, we received approximately $1.07 million from the sale of non-operated properties in Texas and California.
Financing Activities. Net cash used in financing activities totaled $121,753 and $19,804 for the years ended December 31, 2022 and 2021, respectively. During 2022, we had note and financing lease payments of $121,753. During 2021, we entered into an agreement in settlement of amounts due at the end of our office lease for $38,490. In 2021, we also had note and financing lease payments of $58,294.
Changes in Reserve Estimates
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 the Company had previously estimated. See Note 19 - Supplemental Information about Oil and Gas Producing Activities (Unaudited), to our Financial Statements.
During 2021, our overall proved developed and undeveloped natural gas reserves decreased by 49.1% and our previously estimated proved developed and undeveloped natural gas reserve quantities were revised downward by approximately 1.9 million 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 the Company had previously estimated. See Supplemental Information about Oil and Gas Producing Activities (Unaudited), Note 19 to our Financial Statements.
Item 7A Qualitative and Quantitative Disclosures About Market Risk
Not a required disclosure for smaller reporting companies.
Item 8 Financial Statements and Supplementary Data
See pages F-1, et seq., included herein.
Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None
Item 9A Controls and Procedures
Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined under Rules 13a-15(e) or 15d-15(e) under the Exchange Act. Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were effective to give reasonable assurance that information required to be publicly disclosed is recorded, processed, summarized and reported on a timely basis as of the end of the period covered by this annual report.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over our financial reporting. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act, management has conducted an assessment, including testing, using the criteria in Internal Control-Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Our system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Based on our evaluation under the framework in Internal Control-Integrated Framework, our Chief Executive Officer and Chief Financial Officer concluded that our internal control over financial reporting was not effective as of December 31, 2022 due to the material weakness that is described below.
Material Weakness and Remediation
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.
In connection with the audit of our 2019 consolidated financial statements, management identified a material weakness that existed because we did not maintain effective controls over our financial close and reporting process, and concluded that the financial close and reporting process needed additional formal procedures to ensure there are appropriate reviews over all financial reporting analysis. Management has also identified a material weakness that existed due to the lack of segregation of duties and controls, including user access, regarding our financial reporting system. Updated procedures have been implemented through the close process for the year ended December 31, 2022, but the material weakness on our financial close and reporting process was not alleviated. We will continue to monitor these throughout 2023 to be able to fully assess whether the procedures and controls are effective.
Attestation Report of the Independent Registered Public Accounting Firm.
This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.
Changes in Internal Control over Financial Reporting
Other than the remedial activities described above, no changes in our internal control over financial reporting occurred during the year ended December 31, 2022 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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
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|
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
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|
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
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|
(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.
PART IV
Item 15 Exhibits and Financial Statement Schedules
The agreements included as exhibits to this report are included to provide information about their terms and not to provide any other factual or disclosure information about Royale or the other parties to the agreements. The agreements contain representations and warranties by each of the parties to the applicable agreement that were made solely for the benefit of the other parties to the respective agreement, and:
| |
●
|
should not be treated as categorical statements of fact, but rather as a way of allocating the risk among the parties if those statements prove to be inaccurate;
|
| |
|
|
| |
●
|
have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;
|
| |
|
|
| |
●
|
may apply standards of materiality in a way that is different from the way investors may view materiality; and
|
| |
|
|
| |
●
|
were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.
|
1. Financial Statements. See Index to Financial Statements, page F-1
2. Schedules. None.
3. Exhibits. Certain of the exhibits listed in the following index are incorporated by reference.
|
3.2
|
Amended and Restated Bylaws of Royale Energy, Inc., incorporated by reference to Exhibit 3.3 of Royale Energy’s Form 10-K filed March 27, 2009 |
|
3.3
|
Amendment to the Certificate of Incorporation of Royale Energy, Inc., a California corporation (March 7, 2018), filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K dated March 7, 2018, filed March 12, 2018
|
|
4.1
|
Royale Energy Holdings, Inc., Certificate of Designation of Series B 3.5% Redeemable Convertible Preferred Stock, filed with the Delaware Secretary of State on February 27, 2018, filed as Exhibit 2.5 to the Company’s Form 8-A, filed March 8, 2018
|
|
10.11
|
Company Agreement of RMX (April 4, 2018), filed as Exhibit 10.1 to the Company’s Form 8-K filed April 10, 2018
|
|
10.13
|
Conveyance of Term Overriding Royalty Interest between Sunny Frog Oil, LLC, and Royale (April 4, 2018), filed as Exhibit 10.3 to the Company’s Form 8-K filed April 10, 2018
|
|
10.17
|
Royale Energy, Inc., 2018 Equity Incentive Plan, filed as Exhibit 99.1 to the Company’s Form S-8 filed October 29, 2018
|
|
10.25
|
Employment Agreement between the Company and Michael McCaskey, filed as Exhibit 10.9 to the Company’s Form S-8 filed October 29, 2018
|
|
10.26
|
Employment Agreement between the Company and Jeffrey Kerns, filed as Exhibit 10.10 to the Company’s Form S-8 filed October 29, 2018
|
|
10.27
|
Incentive Stock Option Agreement between the Company and Stephen M. Hosmer, filed as Exhibit 10.11 to the Company’s Form S-8 filed October 29, 2018
|
|
16.1
|
Letter of Weaver & Tidwell L.L.P. to the Securities and Exchange Commission dated December 7, 2022, files as Exhibit 16.1 to the Company’s Form 8-K filed December 7, 2022
|
|
21.1*
|
Subsidiaries of Registrant
|
|
23.1*
|
Consent of Horne LLP
|
|
23.2*
|
Consent of Weaver Tidwell LLP
|
| 23.3* |
Consent of Netherland, Sewell & Associates, Inc. |
| 31.1* |
Rule 13a-14(a), 115d-14(a) Certification |
|
31.2*
|
Rule 13a-14(a), 115d-14(a) Certification
|
|
32.1*
|
Section 1350 Certification
|
|
32.2*
|
Section 1350 Certification
|
|
99.1*
|
Report of Netherland, Sewell & Associates, Inc.
|
|
101.INS
|
Inline XBRL Instance Document
|
|
101.SCH
|
Inline XBRL Taxonomy Extension Schema
|
|
101.CAL
|
Inline XBRL Taxonomy Extension Calculation Linkbase
|
|
101.DEF
|
Inline XBRL Taxonomy Extension Definition Linkbase
|
|
101.LAB
|
Inline XBRL Taxonomy Extension Label Linkbase
|
|
101.PRE
|
Inline XBRL Taxonomy Extension Presentation Linkbase
|
|
104
|
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
|
* Filed herewith
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| |
|
Royale Energy, Inc.
|
| |
|
|
|
Date: May 19, 2023
|
|
/s/ Johnny Jordan
|
| |
|
Johnny Jordan
|
| |
|
Chief Executive Officer
|
|
Date: May 19, 2023
|
|
/s/ Ronald Lipnick
|
| |
|
Ronald Lipnick
|
| |
|
Interim Chief Financial Officer
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
|
Date: May 19, 2023
|
|
/s/ John Sullivan
|
| |
|
John Sullivan
|
| |
|
Chairman of the Board of Directors
|
| |
|
|
|
Date: May 19, 2023
|
|
/s/ Jonathan Gregory
|
| |
|
Jonathan Gregory
|
| |
|
Vice-Chair of the Board of Directors
|
| |
|
|
|
Date: May 19, 2023
|
|
/s/ Chris Parada
|
| |
|
Chris Parada
|
| |
|
Director
|
| |
|
|
|
Date: May 19, 2023
|
|
/s/ Jeff Kerns
|
| |
|
Jeff Kerns
|
| |
|
Director
|
| |
|
|
|
Date: May 19, 2023
|
|
/s/ Stephen Hosmer
|
| |
|
Stephen Hosmer
|
| |
|
Director
|
ROYALE ENERGY, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of Royale Energy, Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheet of Royale Energy, Inc. and subsidiaries (the "Company") as of December 31, 2022, the related consolidated statements of operations, stockholders' deficit and cash flows for the year then ended, and the related notes (collectively, the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022, and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.
Going Concern Uncertainty
The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company has suffered recurring losses from operations and its total liabilities exceed its total assets. This raises substantial doubt about the Company's ability to continue as a going concern. Management's plans in regard to these matters also are described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audit, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Estimation of Proved Reserves of Oil and Gas Properties
Critical Accounting Matter Description
As described in Note 1 to the financial statements, the Company accounts for its oil and gas properties using the successful efforts method of accounting which requires management to make estimates of proved reserve volumes and future revenues and expenses to calculate depletion expense and measure its oil and gas properties for potential impairment. To estimate the volume of proved reserves and future revenues, management makes significant estimates and assumptions, including forecasting the production decline rate of producing properties and the timing and volume of production associated with the Company's development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management's judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required in the estimation of depletion expense and potential impairment measurements. We identified the estimation of proved reserves of oil and gas properties, due to its impact on depletion expense and impairment evaluation, as a critical audit matter.
The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions necessary to estimate the volumes and future net revenues of the Company’s proved reserves require a high degree of subjectivity and could have a significant impact on the measurement of depletion expense or the impairment assessment. In turn, auditing those inputs and assumptions required subjective and complex auditor judgement.
How the Critical Audit Matter was Addressed in the Audit
We obtained an understanding of the design and implementation of management's controls related to the estimation of proved reserves by evaluating the level of knowledge, skill, and ability of the Company's reservoir engineering specialists and their relationship to the Company, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company's proved reserve volumes, and read the reserve report prepared by the Company's specialists.
To the extent key, sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company's accounting records, such as commodity pricing, historical pricing differentials, operating costs, estimated capital costs and working and net revenue interests, we evaluated management's process for determining the assumptions, including examining the underlying support, on a sample basis. These audit procedures, among others included the following:
| |
●
|
Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials;
|
| |
●
|
Evaluated the models used to estimate the operating costs at year-end compared to historical operating costs;
|
| |
●
|
Compared the models used to determine the future capital expenditures and compared estimated future capital expenditures used in the reserve report to amounts expended for recently drilled and completed wells with similar locations;
|
| |
●
|
Evaluated the working and net revenue interests used in the reserve report by inspecting a sample of ownership interest, historical pricing differentials and operating costs to underlying support from the Company's accounting records;
|
| |
●
|
Evaluated the Company's evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining support for the Company's or the operator's ability and intent to develop the proved undeveloped properties; and
|
| |
●
|
Applied analytical procedures to the reserve report by comparing to historical actual results and to the prior year reserve report.
|
Deferred Drilling Obligation & Gain or Loss on Turnkey Drilling
Critical Accounting Matter Description
As described in Note 1 to the financial statements, the Company sponsors turnkey drilling 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. That obligation is reduced as costs to complete are incurred, with any excess costs booked as an increase to the Company's property account. Gain on turnkey drilling represents funds received from turnkey drilling participants in excess of all costs the Company incurs during the drilling programs and is recognized only upon making the determination that the Company's obligations have been fulfilled in accordance with the turnkey drilling agreement. The Company's deferred drilling obligation was approximately $8.1 million as of December 31, 2022, and the gain on turnkey drilling was $1,726,414 for the year ended December 31, 2022.
Company management applies significant estimation in determining the expected cost to drill a well and to develop the well site, and significant judgment in determining when they have fulfilled their obligations under the turnkey drilling agreement triggering the recognition of turnkey gain. Both factors may impact the amount and timing of the recognition of a turnkey gain and involve a high degree of auditor judgement related to the matter. These factors were the principal considerations that led us to determine that the deferred drilling obligation and the related gain on turnkey drilling arrangements is a critical audit matter.
How the Critical Audit Matter was Addressed in the Audit
We obtained an understanding of the design and implementation of management's controls related to the estimations in determining the expected cost to drill a well, develop the well site, and when obligations under the turnkey drilling agreements have been fulfilled. Other audit procedures involved selecting a sample of wells to test management's estimates as follows:
| |
●
|
Obtained the master worksheet for each selected well, recalculated the worksheet for clerical accuracy and selected a sample of direct working interest ("DWI") investors;
|
| |
●
|
Obtained the signed field subscription agreement for each selected investor in each well, verified the investment ownership amount per the signed field subscription agreement agreed to the amount invested and the number of units within the master worksheet, vouched the cash received from the DWI investors and agreed the significant terms to the related turnkey drilling agreement;
|
| |
●
|
Obtained a schedule of costs incurred to drill the selected well, recalculated the schedule for clerical accuracy and obtained support from management to substantiate the costs incurred; and
|
| |
●
|
Obtained evidence substantiating the timing and amount of the turnkey gain pertaining to a sample of wells drilled and assessed that the recognized turnkey gain was appropriate as defined under the terms of the related turnkey drilling agreement.
|
/s/ HORNE LLP
We have served as the Company's auditor since 2023.
Ridgeland, Mississippi
May 19, 2023
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of
Royale Energy, Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheet of Royale Energy, Inc. (the “Company”) as of December 31, 2021, and the related statements of operations, stockholders’ equity, and cash flows for the year then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021, and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.
Going Concern Uncertainty
The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company has suffered recurring losses from operations and has a net capital deficiency that raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
Basis for Opinion
These consolidated financial statements are the responsibility of the entity’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audit we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.
The Board of Directors and Shareholders of
Royale Energy, Inc.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Estimation of Proved Reserves Impacting the Recognition and Valuation of Depletion Expense and Impairment and Oil and Gas Properties
Critical Accounting Matter Description
As described in Note 1 to the consolidated financial statements, the Company accounts for its oil and gas properties using the successful efforts method of accounting which requires management to make estimates of proved reserve volumes and future revenues and expenses to calculate depletion expense and measure its oil and gas properties for potential impairment. To estimate the volume of proved reserves and future revenues, management makes significant estimates and assumptions, including forecasting the production decline rate of producing properties and the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required in the estimation of depletion expense and potential impairment measurements. We identified the estimation of proved reserves of oil and gas properties, due to its impact on depletion expense and impairment evaluation, as a critical audit matter.
The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions, which require a high degree of subjectivity necessary to estimate the volume and future revenues of the Company’s proved reserves could have a significant impact on the measurement of depletion expense or the impairment assessment. In turn, auditing those inputs and assumptions required subjective and complex auditor judgement.
How the Critical Audit Matter was Addressed in the Audit
We obtained an understanding of the design and implementation of management’s controls related to the estimation of proved reserves by evaluating the level of knowledge, skill, and ability of the Company’s reservoir engineering specialists and their relationship to the Company, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists.
The Board of Directors and Shareholders of
Royale Energy, Inc.
To the extent key, sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from Company’s accounting records, such as commodity pricing, historical pricing differentials, operating costs, estimated capital costs and working and net revenue interests, we evaluated management’s process for determining the assumptions, including examining the underlying support, on a sample basis. These audit procedures, among others included the following:
| |
●
|
Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials;
|
| |
●
|
Evaluated the models used to estimate the operating costs at year-end compared to historical operating costs;
|
| |
●
|
Compared the models used to determine the future capital expenditures and compared estimated future capital expenditures used in the reserve report to amounts expended for recently drilled and completed wells with similar locations;
|
| |
●
|
Evaluated the working and net revenue interests used in the reserve report by inspecting a sample of ownership interests, historical pricing differentials, and operating costs to underlying support from the Company’s accounting records;
|
| |
●
|
Evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining support for the Company’s or the operator’s ability and intent to develop the proved undeveloped properties;
|
| |
●
|
Applied analytical procedures to the reserve report by comparing to historical actual results and to the prior year reserve report.
|
Deferred Drilling Obligation & Gain/Loss on Turnkey Drilling
Critical Accounting Matter Description
As described in Note 1 to the consolidated financial statements, the Company sponsors 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. That obligation is reduced as costs to complete are incurred, with any excess cost incurred booked against the Company’s property account to reduce any basis in its own interest. Gain on Turnkey Drilling represents funds received from turnkey drilling participants in excess of all costs the Company incurs during the drilling programs and is recognized only upon making the determination that the Company’s obligations have been fulfilled. For the fiscal year ended December 31, 2021, the Company’s Deferred Drilling Obligation was approximately $7.8 million, and the Loss on Turnkey Drilling was $64,468.
The Board of Directors and Shareholders of
Royale Energy, Inc.
Company management applies significant estimation in determining the expected cost to drill a well and to develop the well site, and significant judgment in determining when they have fulfilled their obligations under the Private Placement Memorandums triggering the recognition of turnkey gain. Both factors may impact the amount and timing of the recognition of a turnkey gain and involve a high degree of auditor judgement related to the matter. These factors were the principal considerations that led us to determine that Deferred Drilling Obligation and Gain on Turnkey Drilling is a critical audit matter.
We obtained an understanding of the design and implementation of management’s controls related to the estimations in determining the expected cost to drill a well, develop the well site, and when obligations under the Private Placement Memorandums have been fulfilled. Other audit procedures involved selecting a sample of wells to test management’s estimates as follows:
| |
●
|
Obtained the master spreadsheet for each selected well, recalculated the worksheet for clerical accuracy, and sampled the direct working interest (DWI) investors;
|
| |
●
|
Obtained the signed field subscription agreement for each selected investor in each well, verified the investment ownership amount per the signed field subscription agreement agreed to the amount invested and the number of units within the master spreadsheet, vouched the cash received from the DWI investors, and agreed the significant terms to the related Private Placement Memorandum;
|
| |
●
|
Obtained a schedule of costs incurred to drill the selected well, recalculated the schedule for clerical accuracy, and obtained support from management to substantiate the costs incurred; and
|
| |
●
|
Obtained evidence substantiating the timing and amount of the turnkey gain recognized for a sample of wells drilled and assessed that the recognized turnkey gain was appropriate as defined under the terms of the Private Placement Memorandums.
|
/S/ WEAVER AND TIDWELL, L.L.P.
We have served as the Company’s auditor since 2021
Dallas, Texas
April 15, 2022
ROYALE ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
| |
|
2022
|
|
|
2021
|
|
| |
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
Current Assets:
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents
|
|
$ |
1,650,507 |
|
|
$ |
220,304 |
|
|
Restricted Cash
|
|
|
2,249,627 |
|
|
|
4,002,500 |
|
|
Other Receivables, net
|
|
|
943,633 |
|
|
|
413,133 |
|
|
Revenue Receivables
|
|
|
701,937 |
|
|
|
365,150 |
|
|
Prepaid Expenses and Other Current Assets
|
|
|
1,935,346 |
|
|
|
150,837 |
|
|
Deferred Drilling Costs
|
|
|
1,219,177 |
|
|
|
2,256,461 |
|
|
Prepaid Drilling to RMX Resources, LLC
|
|
|
114,563 |
|
|
|
276,423 |
|
|
Total Current Assets
|
|
|
8,814,790 |
|
|
|
7,684,808 |
|
| |
|
|
|
|
|
|
|
|
|
Other Assets
|
|
|
589,865 |
|
|
|
598,873 |
|
|
Right of Use Asset - Operating Leases
|
|
|
335,213 |
|
|
|
423,299 |
|
|
Oil and Gas Properties (Successful Efforts Basis), Real Property and Equipment and Fixtures, net
|
|
|
2,040,320 |
|
|
|
2,079,800 |
|
| |
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$ |
11,780,188 |
|
|
$ |
10,786,780 |
|
The accompanying notes are an integral part of these consolidated financial statements.
ROYALE ENERGY, INC.
CONSOLIDATED BALANCE SHEETS (Continued)
DECEMBER 31,
| |
|
2022
|
|
|
2021
|
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
Current Liabilities:
|
|
|
|
|
|
|
|
|
|
Accounts Payable and Accrued Expenses
|
|
$ |
5,528,829 |
|
|
$ |
5,160,484 |
|
|
Royalties Payable
|
|
|
612,925 |
|
|
|
623,405 |
|
|
Notes Payable
|
|
|
- |
|
|
|
113,915 |
|
|
Due RMX Resources, LLC
|
|
|
23,087 |
|
|
|
23,087 |
|
|
Accrued Liabilities
|
|
|
208,307 |
|
|
|
201,172 |
|
|
Operating Leases - Current
|
|
|
81,995 |
|
|
|
88,257 |
|
|
Asset Retirement Obligation - Current
|
|
|
675,000 |
|
|
|
648,536 |
|
|
Deferred Drilling Obligations
|
|
|
8,129,965 |
|
|
|
7,824,939 |
|
| |
|
|
|
|
|
|
|
|
|
Total Current Liabilities
|
|
|
15,260,108 |
|
|
|
14,683,795 |
|
| |
|
|
|
|
|
|
|
|
|
Noncurrent Liabilities:
|
|
|
|
|
|
|
|
|
|
Asset Retirement Obligation
|
|
|
2,867,479 |
|
|
|
2,610,560 |
|
|
Operating Leases - Non-current
|
|
|
254,858 |
|
|
|
336,959 |
|
|
Accrued Unpaid Guaranteed Payments
|
|
|
1,616,205 |
|
|
|
1,616,205 |
|
|
Accrued Liabilities - Non-current
|
|
|
1,306,605 |
|
|
|
1,306,605 |
|
| |
|
|
|
|
|
|
|
|
|
Total Liabilities
|
|
|
21,305,255 |
|
|
|
20,554,124 |
|
| |
|
|
|
|
|
|
|
|
|
Mezzanine Equity:
|
|
|
|
|
|
|
|
|
| Convertible Preferred Stock, Series B, $10 par value, 3,000,000
Shares Authorized, 2,361,154 and 2,280,289 shares issued and outstanding
at December 31, 2022 and 2021, respectively |
|
|
23,611,536 |
|
|
|
22,802,899 |
|
|
Stockholders’ Deficit:
|
|
|
|
|
|
|
|
|
| Common Stock, .001 Par Value, 280,000,000 Shares Authorized
61,876,957 and 56,239,715 shares issued and outstanding
at December 31, 2022 and 2021, respectively |
|
|
61,876 |
|
|
|
56,239 |
|
| |
|
|
|
|
|
|
|
|
|
Additional Paid in Capital
|
|
|
54,447,923 |
|
|
|
54,058,554 |
|
| |
|
|
|
|
|
|
|
|
|
Accumulated Deficit
|
|
|
(87,646,402 |
) |
|
|
(86,685,036 |
) |
| |
|
|
|
|
|
|
|
|
|
Total Stockholder’s Deficit
|
|
|
(33,136,603 |
) |
|
|
(32,570,243 |
) |
| |
|
|
|
|
|
|
|
|
|
Total Liabilities, Mezzanine Equity and Stockholders’ Deficit
|
|
$ |
11,780,188 |
|
|
$ |
10,786,780 |
|
The accompanying notes are an integral part of these consolidated financial statements.
ROYALE ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2022 AND 2021
| |
|
2022
|
|
|
2021
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
Sale of Oil and Gas
|
|
$ |
2,611,222 |
|
|
$ |
1,686,424 |
|
|
Supervisory Fees and Other
|
|
|
31,315 |
|
|
|
32,240 |
|
|
Total Revenues
|
|
|
2,642,537 |
|
|
|
1,718,664 |
|
| |
|
|
|
|
|
|
|
|
|
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
Lease Operating
|
|
|
1,928,521 |
|
|
|
1,814,643 |
|
|
Impairment
|
|
|
- |
|
|
|
177,011 |
|
|
Depreciation, Depletion and Amortization
|
|
|
575,909 |
|
|
|
537,273 |
|
|
Bad Debt Expense
|
|
|
- |
|
|
|
190,414 |
|
|
General and Administrative
|
|
|
1,808,197 |
|
|
|
1,951,083 |
|
|
Legal and Accounting
|
|
|
526,550 |
|
|
|
419,587 |
|
|
Marketing
|
|
|
259,101 |
|
|
|
230,346 |
|
|
Total Costs and Expenses
|
|
|
5,098,278 |
|
|
|
5,320,357 |
|
| |
|
|
|
|
|
|
|
|
|
Gain (Loss) on Turnkey Drilling Programs
|
|
|
1,726,414 |
|
|
|
(64,468 |
) |
| |
|
|
|
|
|
|
|
|
|
Loss from Operations
|
|
|
(729,327 |
) |
|
|
(3,666,161 |
) |
| |
|
|
|
|
|
|
|
|
|
Other Income (Expense):
|
|
|
|
|
|
|
|
|
|
Interest Expense
|
|
|
(2,452 |
) |
|
|
(9,206 |
) |
|
Gain on Settlement of Payables
|
|
|
422,614 |
|
|
|
12,071 |
|
|
Other Gain
|
|
|
163,571 |
|
|
|
- |
|
|
Gain on Sale of Assets
|
|
|
- |
|
|
|
64,878 |
|
|
Loss Before Income Tax Expense
|
|
|
(145,594 |
) |
|
|
(3,598,418 |
) |
|
Provision for Income Taxes
|
|
|
- |
|
|
|
- |
|
|
Net Loss
|
|
|
(145,594 |
) |
|
|
(3,598,418 |
) |
| |
|
|
|
|
|
|
|
|
|
Basic and Diluted Loss Per Share
|
|
$ |
(0.02 |
) |
|
$ |
(0.06 |
) |
| |
|
|
|
|
|
|
|
|
| Weighted average number of common shares outstanding, basic and diluted |
|
|
58,472,340 |
|
|
|
55,887,319 |
|
The accompanying notes are an integral part of these consolidated financial statements.
ROYALE ENERGY, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)
FOR THE YEARS ENDED DECEMBER 31, 2022 AND 2021
| |
|
Common Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Number Shares Issued and Outstanding
|
|
|
Amount
|
|
|
Additional
Paid in Capital
|
|
|
Accumulated
Comprehensive
Deficit
|
|
|
Total Stockholders' Deficit
|
|
|
Balance, December 31, 2020
|
|
|
54,605,488 |
|
|
$ |
54,605 |
|
|
$ |
53,883,479 |
|
|
$ |
(82,298,785 |
) |
|
$ |
(28,360,701 |
) |
|
Stock issued in lieu of Cash Compensation
|
|
|
1,634,227 |
|
|
|
1,634 |
|
|
|
175,075 |
|
|
|
- |
|
|
|
176,709 |
|
|
Preferred Series B 3.5% Dividend
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(787,833 |
) |
|
|
(787,833 |
) |
|
Net Loss
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(3,598,418 |
) |
|
|
(3,598,418 |
) |
|
Balance, December 31, 2021
|
|
|
56,239,715 |
|
|
|
56,239 |
|
|
|
54,058,554 |
|
|
|
(86,685,036 |
) |
|
|
(32,570,243 |
) |
|
Stock issued in lieu of Cash Compensation
|
|
|
5,637,242 |
|
|
|
5,637 |
|
|
|
389,369 |
|
|
|
- |
|
|
|
395,006 |
|
|
Preferred Series B 3.5% Dividend
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(815,772 |
) |
|
|
(815,772 |
) |
|
Net Loss
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(145,594 |
) |
|
|
(145,594 |
) |
|
Balance, December 31, 2022
|
|
|
61,876,957 |
|
|
$ |
61,876 |
|
|
$ |
54,447,923 |
|
|
$ |
(87,646,402 |
) |
|
$ |
(33,136,603 |
) |
The accompanying notes are an integral part of these consolidated financial statements.
ROYALE ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2022 AND 2021
| |
|
2022
|
|
|
2021
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
Net Loss
|
|
$ |
(145,594 |
) |
|
$ |
(3,598,418 |
) |
|
Adjustments to Reconcile Net Loss to Net Cash Used by Operating Activities:
|
|
|
|
|
|
|
|
|
|
Depreciation, Depletion, and Amortization
|
|
|
575,909 |
|
|
|
537,273 |
|
|
Impairment
|
|
|
- |
|
|
|
177,011 |
|
|
Gain on Sale of Assets
|
|
|
- |
|
|
|
(64,878 |
) |
|
(Gain) Loss on Turnkey Drilling Programs
|
|
|
(1,726,414 |
) |
|
|
64,468 |
|
|
Gain on Settlement of Accounts Payable
|
|
|
(422,614 |
) |
|
|
(12,071 |
) |
|
Bad Debt Expense
|
|
|
- |
|
|
|
190,414 |
|
|
Other Gain
|
|
|
(163,571 |
) |
|
|
- |
|
|
Stock-Based Compensation
|
|
|
395,006 |
|
|
|
176,709 |
|
|
Right of Use Asset Depreciation
|
|
|
10,989 |
|
|
|
10,972 |
|
|
(Increase) Decrease in:
|
|
|
|
|
|
|
|
|
|
Other & Revenue Receivables
|
|
|
(867,287 |
) |
|
|
(301,771 |
) |
|
Prepaid Expenses and Other Assets
|
|
|
(1,613,641 |
) |
|
|
30,226 |
|
|
Increase (Decrease) in:
|
|
|
|
|
|
|
|
|
|
Accounts Payable and Accrued Expenses
|
|
|
1,157,909 |
|
|
|
1,165,966 |
|
|
Royalties Payable
|
|
|
(10,480 |
) |
|
|
- |
|
|
Net Cash Used in Operating Activities
|
|
|
(2,809,788 |
) |
|
|
(1,624,099 |
) |
| |
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
Expenditures for Oil and Gas Properties
|
|
|
(4,723,629 |
) |
|
|
(4,146,131 |
) |
|
Proceeds from Turnkey Drilling Programs
|
|
|
7,332,500 |
|
|
|
6,538,500 |
|
|
Proceeds from Sale of Assets
|
|
|
- |
|
|
|
1,072,655 |
|
|
Net Cash Provided by Investing Activities
|
|
|
2,608,871 |
|
|
|
3,465,024 |
|
| |
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
Principal Payments on Long-Term Debt
|
|
|
(121,753 |
) |
|
|
(58,294 |
) |
|
Office Rent Financing Agreement
|
|
|
- |
|
|
|
38,490 |
|
|
Net Used by Financing Activities
|
|
|
(121,753 |
) |
|
|
(19,804 |
) |
| |
|
|
|
|
|
|
|
|
|
Net (Decrease) Increase in Cash
|
|
|
(322,670 |
) |
|
|
1,821,121 |
|
| |
|
|
|
|
|
|
|
|
|
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year
|
|
|
4,222,804 |
|
|
|
2,401,683 |
|
| |
|
|
|
|
|
|
|
|
|
Cash, Cash Equivalents, and Restricted Cash at End of Year
|
|
$ |
3,900,134 |
|
|
$ |
4,222,804 |
|
|
Cash Paid for Interest
|
|
$ |
2,452 |
|
|
$ |
2,942 |
|
| |
|
|
|
|
|
|
|
|
|
Cash Paid for Taxes
|
|
$ |
6,850 |
|
|
$ |
10,394 |
|
| |
|
|
|
|
|
|
|
|
|
Supplemental Schedule of Non-Cash Investing and Financing Transactions:
|
|
|
|
|
|
|
|
|
|
Asset Retirement Obligation Addition
|
|
|
29,338 |
|
|
|
- |
|
|
(Decrease) Increase in Capital Accrued Balance
|
|
$ |
(206,806 |
) |
|
$ |
208,792 |
|
|
Series B Paid-In-Kind Dividends
|
|
$ |
815,772 |
|
|
$ |
787,833 |
|
The accompanying notes are an integral part of these consolidated financial statements.
ROYALE ENERGY, INC.
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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