EDGAR 10-K Filing

Company CIK: 1694617
Filing Year: 2023
Filename: 1694617_10-K_2023_0001185185-23-000564.json

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ITEM 1. BUSINESS
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.
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.

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ITEM 1A. RISK FACTORS
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.

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ITEM 1B. UNRESOLVED STAFF COMMENTS

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ITEM 2. PROPERTIES
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:
Gross Wells
Net Wells
Gross Wells
Net Wells
Natural Gas
11.1752
12.2620
Oil
20.3997
19.8313
Total
31.5749
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)
Exploratory
Developmental
0.9374
Exploratory
Developmental
1.6781
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.
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.

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ITEM 3. LEGAL PROCEEDINGS
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.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4 Mine Safety Disclosures
Not Applicable
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
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
Low
High
Low
High
Low
High
Low
$ 0.20
$ 0.08
$ 0.11
$ 0.08
$ 0.10
$ 0.05
$ 0.09
$ 0.05
$ 0.14
$ 0.03
$ 0.10
$ 0.06
$ 0.08
$ 0.06
$ 0.07
$ 0.05
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.

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ITEM 6. SELECTED FINANCIAL DATA

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A Qualitative and Quantitative Disclosures About Market Risk
Not a required disclosure for smaller reporting companies.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8 Financial Statements and Supplementary Data
See pages, et seq., included herein.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None

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ITEM 9A. CONTROLS AND PROCEDURES
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

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ITEM 9B. OTHER INFORMATION

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10 Directors, Executive Officers and Corporate Governance
All of our directors serve one-year terms from the time of their election to the time their successor is elected and qualified. The following information is furnished with respect to each director and executive officer who served as such during the fiscal year ended December 31, 2022:
Name
Age
First Became Director or Executive Officer
Positions Held
John Sullivan (1)(2)(3)(4)
Chairman of the Board
Jonathan Gregory (1)(2)(3)(4)
Vice-Chair of the Board of Directors
Johnny Jordan
Chief Executive and Operating Officer
			and Director
Chris Parada (1) (2)(3)(4)
Director
Jeff Kerns (1) (2)(3)(4)
Director
Stephen Hosmer
Director
(1) Members of the Audit Committee
(2) Members of the compensation committee
(3) Members of the nominations committee
(4) Members identified as independent
The board has determined that directors John Sullivan, Chris Parada, Jonathan Gregory and Jeff Kerns qualify as independent directors.
The following summarizes the business experience of each director and executive officer for the past six years.
John Sullivan - Chairman of the Board
Mr. Sullivan first became a director and began serving as the Chairman of the Board in 2021. Mr. Sullivan is the President of LTD Consulting Services LLC, which provides consulting and management services to private and public companies in the US and SE Asia, a position he has held since 2017. Previously, he held the position of Sr. Director at MMI International, a privately held, global supplier to the Data Storage, Aerospace and Oil and Gas industries from 2011-2017. In this role, he oversaw the sales and global operations for the Precision Forming Group, a division of MMI, with $250 million in annual sales.
Prior to this, as Director of Operations, COO and President, he spent eleven years, from 1999 until 2011, with Intri-Plex Technologies Inc., a leading design, engineering and manufacturing company to the Data Storage, Semi-conductor and Medical industries. In his various roles, he led the development and implementation of strategic sales and operating initiatives that resulted in significant top and bottom line growth. Overseeing the expansion of the business from a domestic manufacturing company to an international supplier of precision components with manufacturing facilities located in the US and SE Asia.
Previously, as COO and President of KR Precision Public Co. Ltd., a publicly held, global supplier of precision mechanical components, John was instrumental in transforming a small privately held company from a niche supplier to a publicly held industry leader listed on the SET 50.
John began his career in 1980 as an entrepreneur, spending ten years as a small business owner in the security and life safety industry. He grew his company organically and through acquisition, diversified its offerings and expanded its geographic footprint prior to it being acquired by ADT International in, a global leader in security and life safety industry, in 1990.
Chris Parada - Director
Mr. Parada became a director in 2021. Mr. Parada currently serves as Vice President of Business Development for Finergy Capital/EnRes Resources, an alternative investment fund providing structured capital solutions to upstream oil and gas companies. Additionally, Mr. Parada serves as President of CounterPoint Consulting, LLC, which he founded in 2019. Counterpoint provides a variety of consulting and contract CFO/VP Finance services to upstream and midstream clients. Prior to joining Finergy/EnRes, Mr. Parada served as Managing Director at TenOaks Energy Advisors from April 2020 to February 2021. Prior to 2019, Mr. Parada was an energy banker for over 25 years, most recently, as Managing Director - Head of Energy Finance for LegacyTexas Bank (2013-2019) where he started and built the Energy Finance team for LegacyTexas. While at LegacyTexas, Mr. Parada and the team successfully closed over $1.5 billion in transactions while he managed a team of seven professionals. Over the course of his career in banking, Mr. Parada has originated, led and syndicated several direct and multibank credit facilities of $10-$500 million. Mr. Parada graduated in 1993 from Texas A&M University with a B.B.A. in Finance.
Jonathan Gregory - Vice-Chair of the Board of Directors
Mr. Gregory became a director of Royale in March 2014 and served as Royale’s chief executive officer from September 10, 2015, until June 1, 2018. Prior to becoming Royale’s CEO, Mr. Gregory, from March 2014 to July 2015, served as Chief Financial Officer and Chief Business Development Strategist for Americo Energy Resources, a private exploration and production company located in Houston, Texas. Prior to serving as CFO of Americo Energy, Mr. Gregory was CFO of J&S Oil & Gas, LLC, from April 2012 to February 2014. From December 2004 to April 2012, Mr. Gregory was head of the energy lending group in Houston, Texas for Texas Capital Bank, N.A. Mr. Gregory is presently CEO of RMX, a private Texas based oil and gas company with oil and gas properties primarily located in California, in which, Royale holds an equity interest. Mr. Gregory is also a Credit Advisor to Anvil Capital Partners, a private debt capital provider to upstream energy companies and serves on the advisory board of the Center for Compassionate Leadership. Mr. Gregory graduated from Lamar University in 1986 with a Bachelor’s degree in Finance.
Johnny Jordan - Chief Executive Officer, President, Chief Operating Officer and Director
Mr. Jordan is a petroleum engineer with expertise in acquisitions, field economics and reserves analysis, bank negotiations, reservoir and field operations, and multi-team interaction. Mr. Jordan has been Royale Energy’s Chief Executive Officer since 2019. Mr. Jordan served on the Board of Directors of Matrix and currently serves on the Board of Directors of both RMX Resources and CIPA. Mr. Jordan has been active in the oil and gas industry since 1980 beginning as a floor hand on a well service rig. He has held various staff and supervisory positions for Exxon, Mack Energy, Enron Oil and Gas and Venoco Corporation. He co-founded Matrix Oil Corporation in 1999 and served as its president until its merger with Royale in 2018. Mr. Jordan is a member of the Society of Petroleum Engineers, American Petroleum Institute and the Texas Independent Producers and Royalty Owners Association. Mr. Jordan has managed acquisition evaluations in many of the oil and gas producing basins in the US. Mr. Jordan received a B.S. in Chemical Engineering from the University of Oklahoma in 1983.
Jeff Kerns - Director
Mr. Kerns was a founding partner of Matrix Oil Corp in 1999, which merged with Royale Energy, Inc. nearly 20 years later in 2018. As a director and officer of Matrix, Mr. Kerns participated in growing the Company from zero production to owning and operating nearly 500 bbls of oil per day. Mr. Kerns was involved in all aspects of the Company’s growth, but his primary focus was day to day operations.
Mr. Kerns has served as a consulting engineer to Royale Energy and Matrix Oil Company from 2018 to present.
Mr. Kerns started in the oil and gas business over 40 years ago as a roughneck in North Dakota working on rigs that drilled through the now famous Bakken Shale heading for deeper targets. Prior to Matrix Oil Corp, Mr. Kerns has held various staff and supervisory positions with Mobil Oil Corp (now ExxonMobil) and Venoco Inc, a small independent company headquartered in Santa Barbara, CA. He also gained broad skills working for many years as a consultant in the oil and gas business.
Mr. Kerns is a registered Professional Engineer in the state of CA. He received a BS degree from Stanford University in 1979. He served as an elected public official for 10 years on the local sanitary district board of directors as well as serving as a past president of a local Rotary International club and president of the San Joaquin Chapter of the American Petroleum Institute and has maintained a long term affiliation with SPE.
Stephen Hosmer - Director, Corporate Secretary
Mr. Hosmer first became a director in 1998, and served through 2018. He was then reappointed in January 2022, following his departure as the company’s Chief Financial Officer, where he served since 1995. Mr. Hosmer also served as the company’s Co-Chief Executive Officer from 2008 until September 2015.
During his tenure as CFO, Mr. Hosmer managed the development of over 178 wells, raised capital through a combination of debt and equity sources, and led the acquisition of more than 200 square miles of 3D seismic data. Mr. Hosmer holds a Bachelor of Science degree in Business Administration from Oral Roberts University in Tulsa, Oklahoma and an MBA degree from the President/Key Executive program at Pepperdine University.
Mr. Hosmer currently serves as the CFO for San Diego Rock Church, Managing Partner of Provident Ventures, and has also served on the board and/or consults for a number of not-for-profit organizations, including Venture Expeditions and Exile International, and Wycliffe Bible Translators.
Audit Committee
The board has appointed an audit committee to assist the board of directors in carrying out its responsibility as to the independence and competence of the Company’s independent public accountants. All members of the audit committee are independent members of the board of directors. The audit committee operates pursuant to an audit committee charter, which has been adopted by the board of directors to define the committee’s responsibilities. A copy of the audit committee charter is posted on our website, www.royl.com. The board has determined that Chris Parada qualifies as an “audit committee financial expert” as defined in Item 407(d)(5) of the Securities and Exchange Commission.
At the end of 2022, the members of the audit committee were Chris Parada (Chair), Jeff Kerns, John Sullivan and Jonathan Gregory.
Code of Business Conduct and Ethics
We have adopted a code of business conduct and ethics for our directors and executive officers. The code is posted on our website, www.royl.com.
Delinquent Section 16(a) Reports
Section 16(a) of the Securities Exchange Act of 1934 and Securities and Exchange Commission regulations require that Royale’s directors, certain officers, and greater than 10 percent shareholders file reports of ownership and changes in ownership with the SEC and the NASD and furnish Royale with copies of all such reports they file. The following Form 4’s for common stock issued to current and former board members were filed late or are in process of being filed, each of these filings consisted of two transactions that occurred in 2022, except for Johnny Jordan’s, which had only one transaction:
Form 4 2022 Common Stock Issuance - Late Filings:
Recipient
Shares issued
Form 4 Filing Status
Johnny Jordan
3,073,682
Filed
Jonathan Gregory
423,185
Filed
Robert Vogel
300,513
In Process
John Sullivan
262,950
In Process
Chris Parada
262,950
In Process
Jeffrey Kerns
197,799
In Process
Stephen Hosmer
187,038
In Process
Karen Kerns
300,513
In Process
Thomas Gladney
328,099
In Process
Mel Riggs
300,513
Filed

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ITEM 11. EXECUTIVE COMPENSATION
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)
$ 255,769
$ 9,327
$ 265,096
(CEO)
$ 255,769
$ 7,625
$ 263,394
Donald Hosmer
$ 191,925
$ 102,975
$ 19,032
$ 313,932
(Business Development)
$ 185,176
$ 31,985
$ 18,545
$ 235,706
Stephen Hosmer (4)
$ 67,210
$ -
$ 58,355
$ 125,565
(Former CFO)
$ 230,192
$ 18,750
$ 248,942
Ronald Lipnick
$ 181,654
$ 15,000
$ 6,017
$ 202,671
(Interim CFO)
$ 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)
$ 504,633
$ 593,332
$ 191,925
$ 313,932
(145,594 )
$ 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

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
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.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
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.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
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:
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

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
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
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
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
* Filed herewith