Royale Energy, Inc. - Annual Report: 2021 (Form 10-K)

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

ROYALE ENERGY, INC.

(Name of registrant in its charter)

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 USC. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

Indicate by check mark whether the registrant is large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See definition of “large accelerated filer,” “accelerated filer” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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, 2021, the end of the registrant’s most recently completed second fiscal quarter; the aggregate market value of Common Stock held by non-affiliates was $2,766,153.

At March 25, 2022, 56,239,715 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, 2021, Royale and its consolidated subsidiaries had 11 full time employees.

RMX Joint Venture

On April 4, 2018, RMX Resources, LLC (“RMX”), CIC RMX LP (“CIC”), and Royale Energy Funds, Inc., (“REF”), and Matrix Oil Management Corporation (“Matrix”), entered into a Subscription and Contribution Agreement (the “Contribution Agreement”) and certain other agreements contemplated therein (the “Transaction”). The Contribution Agreement provided that Royale, REF and Matrix would contribute certain assets to RMX, a newly formed Texas limited liability company. In exchange for its contributed assets, Royale received a 20% equity interest in RMX, an equity performance incentive interest and $20.0 million to satisfy Matrix’s current senior lender, Arena Limited SPV, LLC, in full, and to pay REF, Matrix and Royale’s 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 Royale’s common stock at an exercise price of $0.01 per share and registration rights pursuant to a Registration Rights Agreement.

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, 2021, Royale continued to explore and develop oil and natural gas properties with concentration in California and Texas. In 2021, Royale drilled and completed two wells, both of which were commercially productive. Royale’s estimated total reserves were approximately 10.8 and 11.9 BCFE (billion cubic feet equivalent) at December 31, 2021 and 2020, 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 $42.1 million at December 31, 2021, based on the average Henry Hub natural gas price spot price of $3.598 per MCF and for oil volumes, the average West Texas Intermediate price of $66.55 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, 2021, was estimated to be $16,281,919. 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 loss on turnkey drilling in connection with the drilling of wells on a “turnkey contract” basis in the amount of $64,468 for the year ended December 31, 2021. For the year ended December 31, 2020, Royale reported a gain on turnkey drilling in the amount of $1,700,462.

In addition to Royale’s own staff, Royale hires independent contractors to drill, test, complete and equip the wells that it drills. Approximately 98.1% of Royale’s total revenue for the year ended December 31, 2021, came from sales of oil and natural gas from production of its wells in the amount of $1,686,424. In 2020, this amount was $1,542,803, which represented 97.2% of Royale’s total revenues for the respective periods presented. See Note 2 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 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. See Note 1 to our Financial Statements, at page F-10.

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, it receives fees set by industry standards from the owners of fractional interests in the wells and from expense reimbursements. For the year ended December 31, 2021, Royale charged overhead from operation of the wells in the amount of $311,754 for the year, which were an offset to general and administrative expenses. In 2020, the amount was $305,900. At December 31, 2021, Royale operated wells in California and Texas. Royale also has non-operating interests in wells in California, Utah, Texas, Oklahoma and Colorado.

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 early 2020, oil prices dropped precipitously, and have since returned to pre-COVID-19 2020 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.

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.

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 it has moved its focus to Southern California in the Los Angeles Basin and in Mitchell County, Texas. In 2021, Royale drilled two developmental oil wells in Texas and at year end 2021 was in process of drilling two oil wells in Texas and participating 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, 2021, 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 16, 2022.

California

Royale owns interests in nine gas fields with locations ranging throughout the Sacramento Basin in California. At December 31, 2021, Royale operated 12 wells and owns interests in 19 non-operated wells in Northern California and 6 non-operated wells in Southern and Central California. Our California estimated total proven, developed, and undeveloped net reserves are approximately 0.717 BCFE, according to Royale’s independently prepared reserve report as of December 31, 2021.

Texas

At December 31, 2021, Royale owned and operated interests in 46 wells in its Jameson field. Our Texas estimated total proven, developed, and undeveloped net reserves are approximately 454.1 MBOE, according to Royale’s independently prepared reserve report as of December 31, 2021.

Developed and Undeveloped Leasehold Acreage

As of December 31, 2021, Royale owned leasehold interests in the following developed and undeveloped properties in both gross and net acreage.

Gross and Net Productive Wells

As of December 31, 2021 and 2020, Royale owned interests in the following oil and gas wells in both gross and net acreage:

Drilling Activities

The following table sets forth Royale’s drilling activities during the years ended December 31, 2021 and 2020. All wells are located in the Continental U.S., in California, Texas, Louisiana, Colorado and Utah.

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, marketable, 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.

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, 2021. 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 37 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

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 193,000 BBL and total proved oil and natural gas liquid combined reserves of 1,579,100 BBL.

As of December 31, 2020, Royale had proved developed reserves of 691,900 MCF and total proved reserves of 2,660,500 MCF of natural gas. For the same period, Royale also had proved developed oil and natural gas liquid combined reserves of 224,893 BBL and total proved oil and natural gas liquid combined reserves of 1,541,000 BBL.

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.

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

Royale’s Common Stock is traded on the OTC QB Market under the symbol “ROYL.” As of December 31, 2021, 56,239,715 shares of Common Stock were held by approximately 3,455 stockholders. As of December 31, 2020, 54,605,488 shares of Royale’s Common Stock were held by approximately 5,018 stockholders. The following table reflects the high and low quarterly closing sales prices on the OTC QB Market from January 2020 through December 2021:

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 2021 or 2020. The Board of Directors did declare dividends during 2021 and 2020 on the preferred stock to be Paid In Kind (“PIK”) of 78,784 and 76,290 shares with a respective par value of $787,833 and $762,900, 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. 

During 2021, as the economy and travel picked up as a result of reduced travel restrictions and stay at home orders, we saw an increase in commodity prices of oil and natural gas above pre-pandemic levels. Although, we did continue to see supply chain issues and labor shortages impact the oil and natural gas industry. These supply chain issues and labor shortages would eventually lead to delays in drilling during the year in 2021, and increased costs of goods and services.

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.

Business Combinations

From time-to-time, the Company acquires businesses in the oil and gas industry. Businesses are included in the Company’s 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.

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 2021 and 2020, impairment losses of $177,011 and $0, 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, 2021 and 2020, Royale had deferred drilling obligations of $7,824,939 and $3,127,500 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 cash and cash equivalents 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, 2021, the Company has an accumulated deficit of $86,685,036, a working capital deficiency of $6,797,815 and a stockholders’ deficit of $32,570,243. 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 2022 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 2022 drilling budget and to support future operations.

Results of Operations for the Year Ended December 31, 2021, as Compared to the Year Ended December 31, 2020

For the year ended December 31, 2021, we had a net loss of $3,598,418 compared to the net loss of $8,148,147 during the year in 2020. The table below reflects the major components of other income and expense.

In 2021, the majority of the loss resulted from a loss from operations of $3,666,161. In 2020, the majority of the net loss resulted from a $6,185,995 impairment of our investment in RMX Resources, LLC, due to year end 2020 reserve valuations and other considerations, see Note 2 to our Financial Statements.

During the year ended 2021, revenues from oil and gas production increased $143,621 or 9.3% to $1,686,424 from the 2020 revenues of $1,542,803. This increase was due to higher commodity prices realized for the sale of oil and gas in 2021. The net sales volume of oil for the year ended December 31, 2021 was approximately 18,963 barrels of oil with an average price of $65.28 versus approximately 31,210 barrels with an average price of $37.96 per barrel, for the year in 2020. This represents a decrease in net sales volume of approximately 12,247 barrels or 39.2%. The net sales volume of natural gas for the year ended December 31, 2021, was approximately 122,151 Mcf with an average price of $3.64 per Mcf, versus 160,406 Mcf with an average price of $2.23 per Mcf for the year in 2020. This represents a decrease in net sales volume of approximately 38,255 Mcf or 23.8%. The decreases in oil and natural gas production volumes were due to the 2021 sales of non-operated wells in East Los Angeles and Texas and to lower volumes on existing wells due to natural declines.

Oil and natural gas lease operating expenses increased by $416,970 or 29.8%, to $1,814,643 for the year ended December 31, 2021, from $1,397,673 for the year in 2020. This was higher in 2021 due to increases in plugging and abandonment by an industry partner of certain non-operated California wells and workover costs of wells in our Texas Jameson field to increase production. When measuring lease operating costs on a production or lifting cost basis, in 2021, the $1,814,643 equates to a $7.69 per Mcfe lifting cost versus a $4.02 per Mcfe lifting cost in 2020, due to higher lease operating costs and lower production volumes in 2021.

The aggregate of Supervisory Fees and other income was $32,240 for year ended December 31, 2021, a decrease of $12,812 or 28.4% from $45,052 during the year in 2020. This decrease was mainly due to lower pipeline and compressor fee income due to lower production volumes during 2021.

Depreciation, depletion and amortization expense increased to $537,273 from $473,647, an increase of $63,626 or 13.4% for the year ended December 31, 2021, as compared to the year in 2020. 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 $158,149 or 7.5% from $2,109,232 for the year ended December 31, 2020, to $1,951,083 for the year ended 2021. This decrease was due to lower employee related expenses and office rents along with lower property tax payments in 2021 as we received pre-merger disputed property tax billings in 2020. Legal and accounting expense increased to $419,587 for the year in 2021, compared to $279,227 for the year in 2020, a $140,360 or 50.3% increase. This increase was primarily due to higher audit related expenses during 2021. Marketing expense for the year ended December 31, 2021, increased $116,732, or 102.7%, to $230,346, compared to $113,614 for the year in 2020. Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs. During 2020 fewer marketing events were attended as the governmental mandate against large gatherings was implemented.

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. At December 31, 2020, Royale had a Deferred Drilling Obligation of $3,127,500. During 2020, we disposed of $6,432,675 of drilling obligations upon completing the drilling of five oil wells, three in California and two in Texas, while incurring expenses of $4,732,213, resulting in a gain of $1,700,462.

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 the year in 2020, as disclosed above, we recorded a loss of $6,185,995, on the impairment of our investment in joint venture of RMX Resources, LLC. During the fourth quarter we recorded a loss on assets held for sale of $566,858, in anticipation of the sale of certain oil and gas assets during the year in 2021. During the third quarter in 2020, we recorded a gain on other of $271,310 based on the contract agreement with an industry partner in the drilling of two wells. During the year in 2020, we also recorded a gain on other of $280,596 on the receipt of a pre-Matrix merger prepayment refunds. During the year in 2020, we recorded a gain on settlement of $197,800 on the forgiveness of our SBA Paycheck Protection Program (“PPP”) loan (discussed further in Note 16 to our Financial Statements) and a loss on settlement of $31,500 related to a 2018 seismic sales agreement. During the year in 2020, we recorded geological and geophysical expense of $14,392 related costs in our Texas Jameson field. We periodically review our proved properties for impairment on a field-by-field basis and charge impairments of value to the expense. 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 2020.

Bad debt expense for 2021 and 2020 were $190,414 and $1,008,003, respectively. Approximately $180,000 of the expenses in 2021 and $800,000 of the expenses in 2020 arose from identified uncollectable receivables relating to our oil and natural gas properties either plugged and abandoned or scheduled for plugging and abandonment and our year-end oil and natural gas reserve values. During the year in 2020, the other bad debt expense of approximately $203,000 was related to revenue receivable from an industry partner whose collectability was in doubt. 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 decreased to $9,206 for the year ended December 31, 2021, from $12,949 in 2020, a $3,743 decrease. This decrease was mainly due to lower principal balances on notes payable during the year in 2021.

In 2021 and 2020, 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, 2021, Royale had current assets totaling $7,684,808 and current liabilities totaling $14,482,623, a $6,797,815 working capital deficit. We had cash and cash equivalents at December 31, 2021 of $220,304 and restricted cash of $4,002,500 compared to cash and cash equivalents of $255,112 and restricted cash of $2,146,571 at December 31, 2020.

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.

At December 31, 2021, our other receivables net, which consist of joint interest billing receivables from direct working interest participants and industry partners, totaled $413,133, compared to $462,777 at December 31, 2020, a $49,644 decrease. This decrease was mainly due to the increase in accounts receivable allowance from direct working interest owners in 2021. At December 31, 2021, revenue receivable was $365,150, an increase of $161,001, compared to $204,149 at December 31, 2020, due to higher commodity prices at year end 2021. At December 31, 2021, our accounts payable and accrued expenses totaled $5,160,484, an increase of $999,375 from the accounts payable at December 31, 2020 of $4,161,109, mainly due to drilling and lease operating costs in 2021.

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, 2021 and 2020, cash used in operating activities totaled $1,624,099 and $381,116, respectively. This $1,242,983 increase in cash used was primarily due to the increase in accounts payable and accrued liabilities during the period in 2021 due to participating in the drilling of two Southern California oil wells at year end.

Investing Activities. Net cash provided by investing activities totaled $3,465,024 for the year ended December 31, 2021 versus net cash used by investing activities of $1,235,485 for the year ended December 31, 2020. The difference was due to cash receipts of approximately $6.5 million in 2021 and $4.3 million in 2020 in direct working interest turnkey investments. Additionally, during 2021, we received approximately $1.07 million from the sale of non-operated properties in Texas and California. 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. In 2020, our turnkey drilling expenditures were approximately $5.6 million as we drilled and completed five oil wells, three in California and two in Texas.

Financing Activities. For the year ended December 31, 2021, net cash used by financing activities totaled $19,804 versus net cash provided by financing activities of $141,755 for the year ended December 31, 2020. 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. During the year in 2020, we received $207,800 in a PPP Loan, of which $197,800 was forgiven. We also had principal payments of approximately $66,000 on our notes payable.

Changes in Reserve Estimates

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 Note 19 - Supplemental Information about Oil and Gas Producing Activities (Unaudited), to our Financial Statements.

During 2020, our overall proved developed and undeveloped natural gas reserves decreased by 38.2% and our previously estimated proved developed and undeveloped natural gas reserve quantities were revised downward by approximately 1.5 million cubic feet of natural gas. This downward revision was mainly the result of a decrease in proved developed natural gas reserves from a decrease in economic life of wells related to a decrease in future expected product price. 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, 2021 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 had 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, 2020, but the material weakness on our financial close and reporting process was not alleviated. We will continue to monitor these throughout 2022 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, 2021 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, 2021:

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 is a Principal of LTD Consulting Services LLC. which provides consulting and management services to private and public companies in the U.S. and Southeast Asia. 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. In this role, he oversaw the sales and global operations for the Precision Forming Group, a division of MMI, with $250M in annual sales.

Chris Parada – Director

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 director of Royale in March 2014 and served as Royale's chief executive officer from September 10, 2015, until June 1, 2018. From April 2018 to present, Mr Gregory has served as the CEO of RMX Resources LLC. 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 Resources, LLC, a private Texas based oil and gas company with oil and gas properties primarily located in California. Mr. Gregory is also a Credit Committee Advisor to Anvil Capital Partners, a private debt capital provider to upstream energy companies. 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. He was appointed as the Company’s CEO in January 2019, having served on the Board of Directors from the closing of the merger with Matrix in 2018. He previously was the President and served on the Board of Directors of Matrix since its inception in 1999. 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 was the team leader of a multi-discipline team from 1992 to 1996 that added 455 BCF and 79 MMCFD through acquisitions (71 BCF) and field development (365 wells) in the Val Verde Basin in West Texas. Mr. Jordan has managed acquisition evaluations in many of the oil and gas producing basins in the US. He has coordinated field development for various recovery mechanisms that include waterflood, tertiary flood, water drive oil and gas reservoirs, and pressure depletion fields with gas cap expansion or gravity drainage. Mr. Jordan received a B.S. in Chemical Engineering from the University of Oklahoma in 1983 and is currently a member of the Society of Petroleum Engineers and the American Petroleum Institute.

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 started in 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 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.

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 2021, 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.

Compliance with Section 16(a) of the Exchange Act

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. Based solely upon a review of the copies of the forms furnished to Royale, or representations from certain reporting persons that no reports were required, Royale believes that no persons failed to file required reports on a timely basis for 2021.

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

(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) 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 2021.

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 Stephen M. Hosmer, 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 and Stephen Hosmer each receive 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.

Compensation of Directors

In 2021, 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 2021.

Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Common Stock

At March 25, 2022, 56,236,715 shares of registrant’s Common Stock were outstanding.

The following table contains information regarding the ownership of Royale’s Common Stock as March 30, 2022, 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.

* Less than 1%.

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, 2021 Mr. Jordan was owed $82,067 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, Stephen Hosmer, had participated individually in 179 wells. At December 31, 2021, the Company had a receivable balance of $17,963 due from Stephen Hosmer and $6,549 from Donald Hosmer for normal drilling and lease operating expenses.

At December 31, 2021, we had a total payable of $23,087 due to RMX Resources, LLC and its subsidiary, Matrix Oil Corporation, related to certain lease operating expenses for wells operated by RMX Resources, LLC. For the same period, the Company also had prepaid expenses and other current assets of $276,423 primarily for the drilling of two wells, expected to be completed in Q1 2022. At December 31, 2021, we had a total payable of $233,872 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, 2021, the balance due was $1,616,205. At December 31, 2021, Royale also had accrued unpaid liabilities of $1,306,605 due to certain former Matrix employees for periods predating their joining the Company.

Michael McCaskey and Jeffery Kerns, each former directors of Royale, have consulting agreements to provide services as directed and at the discretion of the Company. Mr. Kerns wife was a director of Royale.

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

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 billed for the years ended December 31, 2021 and 2020 are as follows:

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 2021 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 agreement parties and:

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.

* 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.

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.

ROYALE ENERGY, INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

AND SUPPLEMENTARY DATA

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:

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:

/S/ WEAVER AND TIDWELL, L.L.P.

We have served as the Company’s auditor since 2021

Dallas, Texas

April 15, 2022

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. (the “Company”) as of December 31, 2020, the related consolidated 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 consolidated financial position of the Company as of December 31, 2020, and the consolidated 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 Company’s management. Our responsibility is to express an opinion on the Company’s 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 consolidated 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 consolidated financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated 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 consolidated financial statements. We believe that our audit provides a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the audit of the consolidated 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 consolidated 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 consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Deferred Drilling Obligation & Gain on Turnkey Drilling

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, 2020, the Company’s Deferred Drilling Obligation was approximately $3.1 million, and the Gain on Turnkey Drilling was approximately $1.7 million.

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.

The primary procedures we performed to address this critical audit matter included:

/s/ Moss Adams LLP

San Diego, California

March 30, 2021

We served as the Company’s auditor from 2019 to 2021.

ROYALE ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

DECEMBER 31,

The accompanying notes are an integral part of these consolidated financial statements.

ROYALE ENERGY, INC.

CONSOLIDATED BALANCE SHEETS (Continued)

DECEMBER 31,

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, 2021 AND 2020

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, 2021 AND 2020

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, 2021 AND 2020

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 “Royale Energy,” “Royale,” or the “Company”) is presented to assist in understanding Royale Energy’s financial statements.

These consolidated financial statements include the accounts of 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 Royale Energy’s 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

Royale Energy is an independent oil and gas producer which also has operations in the area of turnkey drilling. Royale Energy owns wells and leases in major geological basins located primarily in California, Texas, Oklahoma, Colorado, and Utah. Royale Energy offers fractional working interests and seeks 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 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 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, 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 the Company’s ability to meet liquidity demands, and we anticipate that our primary sources of liquidity will be from the issuance of debt and/or equity, the sale of oil and natural gas property participation interests through our normal course of business and the sale of non-strategic assets.

The Company’s 2021 consolidated financial statements reflect a working capital deficiency of $6,797,815 and a net loss from operations of $3,598,418. These factors raise substantial doubt about our ability to continue as a going concern. The accompanying consolidated financial statements do not include any adjustments that might be necessary if the Company is unable to continue as a going concern.

Management’s plans to alleviate the going concern by cost control measures that include the reduction of overhead costs and the sale of non-strategic assets. There is no assurance that additional financing will be available when needed or that management will be able to obtain financing on terms acceptable to the Company and whether the Company will become profitable and generate positive operating cash flow. If the Company is unable to raise sufficient additional funds, it will have to develop and implement a plan to further extend payables, attempt to extend note repayments, and reduce overhead until sufficient additional capital is raised to support further operations. There can be no assurance that such a plan will be successful.

Restricted Cash

Royale sponsors turnkey drilling arrangements in proved and unproved properties. The contracts require that participants pay Royale the full contract price upon execution of the drilling agreement. Each participant earns an undivided interest in the well bore at the completion of the well. A portion of the funds received in advance of the drilling of a well from a working interest participant are held for the expressed purpose of drilling a well. If something changes, the Company may designate these funds for a substitute well. Under certain conditions, a portion of these funds may be required to be returned to a participant. Once the well is drilled, the funds are used to satisfy the drilling cost. Royale classifies these funds prior to commencement of drilling as restricted cash based on guidance codified as under the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 230-10-50-8. In the event that progress payments are made from these funds; they are recorded as Prepaid Expenses and Other Current Assets.

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the statement of financial position that sum to the total of the same amounts shown in the statement of cash flows.

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 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, 2021 and 2020, the Company established an allowance for uncollectable accounts of $2,761,398 and $2,582,093, 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, Royale has not had issues related to the collection of revenue receivables, and as such has 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 sheet.

Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value may have occurred as called for under ASC 323, 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.

The earnings from RMX reflected in these financial statements as Investment in JV, reflect our share of net earnings or losses directly attributable to this equity method investment. At December 31, 2020, we evaluated our investment in RMX and determined that our investment was impaired as further described in Note 2 – RMX Joint Venture.

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.

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 sheet.

Under our hydrocarbon sales agreements, the entire consideration amount is variable either due to pricing and/or volumes. We recognize revenue 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.

The Company frequently sells a portion of the working interest in each well it drills or participates in to third-party investors and retains a portion of the prospect for its own account. The Company typically guarantees a cost to drill to the third-party drilling participants and records a loss or gain on the difference between the guaranteed price and the actual cost to drill the well. When monies are received from third parties for future drilling obligations, the Company records the liability as 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, as defined in the new revenue standard, is transferred to midstream entities and they are entitled to significant risks and rewards of ownership of the natural gas and NGLs.

The amounts due to midstream entities for gathering and processing services are recognized as shipping and handling cost and included as lease operating expense in our consolidated statement of operations, since we make those payments in exchange for distinct services with the exception of natural gas sold to PG&E where transportation is netted directly against revenue. Under some of our natural gas processing agreements, we have an option to take the processed natural gas and NGLs in-kind and sell to customers other than the processing company. In those circumstances, our performance obligations are complete after delivering the processed hydrocarbons to the customer at the designated delivery points, which may be the tailgate of the processing plant or an alternative delivery point requested by the customer.

Turnkey Drilling Obligations

These Turnkey Agreements are managed by the Company for the participants of the well. The collections of pre-drilling AFE amounts are segregated by the Company and the gains and losses on the Turnkey Agreements are recorded in income or expense at the time of the casing point election in accordance with ASC 932-323-25 and 932-360. The Company manages the performance obligation for the well participants and only records revenue or expense at the time the performance obligation of the Turnkey Agreement has been satisfied.

Supervisory Fees and Other

For the years ended December 31, 2021 and 2020, the Company recognized $32,240 and $45,052, respectively in supervisory fees in Pipeline and Compressor fees which are received and allocated based on production volumes.

Oil and Gas Property and Equipment

Successful Efforts

Royale Energy uses the “successful efforts” method to account for its exploration and production activities. Under this method, Royale Energy accumulates its proportionate share of costs on a well-by-well basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred, and capitalizes expenditures for productive wells. Royale Energy amortizes the costs of productive wells under the unit-of-production method.

Royale Energy carries, as an asset, exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where Royale Energy is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred. Acquisition costs of proved 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 Royale Energy’s wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labor costs to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity.

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 income. During 2021 the Company recorded impairment losses of $177,011, on various capitalized lease and land costs where the carrying value exceeded the fair value. In 2020 there were no impairment losses.

Upon the sale or retirement of a complete field of a proved property, Royale Energy eliminates the cost from its books, and the resultant gain or loss is recorded to Royale Energy’s Statement of Operations. Upon the sale of an entire interest in an unproved property where the property has been assessed for impairment individually, a gain or loss is recognized in Royale Energy’s Statement of Operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a recovery of the cost in the interest retained with any excess funds recognized as a gain. Should Royale Energy’s turnkey drilling agreements include unproved property, total drilling costs incurred to satisfy its obligations are recovered by the total funds received under the agreements. Any excess funds are recorded as a Gain on Turnkey Drilling Programs, and any costs not recovered are capitalized and accounted for under the “successful efforts” method.

Long-Lived Assets Classified as Held for Sale

Royale classifies 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:

Assets held for sale are carried at the lower of cost or fair market value less cost of disposal in current assets. If the Company retains the responsibility for the P&A, equipment removal or site restoration, the associated anticipated expense is carried as current ARO. The Company has two property groups that are being Held for Sale as further described in Note 17 – Long-Lived Assets Held for Sale.

Turnkey Drilling

Royale Energy 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, and then reduced as costs to complete its obligations are incurred with any excess booked against its property account to reduce any basis in its own interest. Gains on Turnkey Drilling Programs represent funds received from turnkey drilling participants in excess of all costs Royale incurs during the drilling programs (e.g., lease acquisition, exploration and development costs), including costs incurred on behalf of participants and costs incurred for its own account; and are recognized only upon making this determination after Royale’s obligations have been fulfilled.

The contracts require the participants pay Royale Energy the full contract price upon execution of the agreement. Royale Energy completes the drilling activities typically between 10 and 30 days after drilling begins. The participant retains an undivided or proportional beneficial interest in the property, and is also responsible for its proportionate share of operating costs. Royale Energy retains legal title to the lease. The participants purchase a working interest directly in the well bore.

In these working interest arrangements, the participants are responsible for sharing in the risk of development, but also sharing in a proportional interest in rights to revenues and proportional liability for the cost of operations after drilling is completed and the interest is conveyed to the participant.

A certain portion of the turnkey drilling participant’s funds received are non-refundable. The Company holds all funds invested as Deferred Drilling Obligations until drilling is complete. Occasionally, drilling is delayed for various reasons such as weather, permitting, drilling rig availability and/or contractual obligations. At December 31, 2021 and 2020, Royale Energy had Deferred Drilling Obligations of $7,824,939 and $3,127,500, respectively. 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 2020, we disposed of $6,432,675 of drilling obligations upon completing the drilling of five oil wells, three in California and two in Texas, while incurring expenses of $4,732,213, resulting in a gain of $1,700,462.

If Royale Energy is unable to drill the wells, and a suitable replacement well is not found, Royale would retain the non-refundable portion of the contact and return the remaining funds to the participant. Included in cash and cash equivalents 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. Gains or losses on dispositions of property and equipment, other than oil and gas, are reflected in operations.

Income (Loss) Per Share

Basic and diluted losses per share are calculated as follows:

For the years ended December 31, 2021 and 2020, Royale Energy had dilutive securities of 26,582,388 and 25,137,267 respectively. These securities were not included in the dilutive loss per share due to their antidilutive nature.

Stock Based Compensation

Royale has a stock-based employee compensation plan, which is more fully described in Note 11 – Stock Compensation Plan. The Company has 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

Royale utilizes 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 period subsequent to initial recognition, the reporting entity shall disclose information that enable users of its financial statements to assess the inputs used to develop those measurements and for recurring fair value measurements using significant unobservable inputs, the effect of the measurements on earnings for the period.

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. In determining fair value, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible as well as considers counterparty credit risk in its assessment of fair value. Carrying amounts of the Company’s financial instruments, including cash equivalents, accounts receivable, accounts payable and accrued liabilities, approximate their fair values as of the balance sheet dates because of their generally short maturities.

The fair value hierarchy distinguishes between (1) market participant assumptions developed based on market data obtained from independent sources (observable inputs) and (2) an entity’s own assumptions about market participant assumptions developed based on the best information available in the circumstances (unobservable inputs). The fair value hierarchy consists of three broad levels, which gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy are described below:

Level 1: Quoted prices (unadjusted) in active markets that are accessible at the measurement date for assets or liabilities.

Level 2: Directly or indirectly observable inputs as of the reporting date through correlation with market data, including quoted prices for similar assets and liabilities in active markets and quoted prices in markets that are not active. Level 2 also includes assets and liabilities that are valued using models or other pricing methodologies that do not require significant judgment since the input assumptions used in the models, such as interest rates and volatility factors, are corroborated by readily observable data from actively quoted markets for substantially the full term of the financial instrument.

Level 3: Unobservable inputs that are supported by little or no market activity and reflect the use of significant management judgment. These values are generally determined using pricing models for which the assumptions utilize management’s estimates of market participant assumptions

At December 31, 2021 and 2020, Royale Energy does not have any financial assets measured and recognized at fair value on a recurring basis. The Company estimates asset retirement obligations 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 the Company’s asset retirement obligations.

Accounts Payable and Accrued Expenses

At December 31, 2021 and 2020, the components of accounts payable and accrued expenses consisted of: