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

For the Fiscal Year Ended December 31, 2020 Commission File No. 055912

ROYALE ENERGY, INC.

(Name of registrant in its charter)

Delaware	81-4596368
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1870 Cordell Court

El Cajon, CA 92020

(Address of principal executive offices)

Issuer’s telephone number:     619-383-6600

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common stock, par value .001 per share	ROYL	OTC: QB

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:

Large accelerated filer ☐	Accelerated filer ☐
Non-accelerated filer ☐	Smaller Reporting Company ☒
Emerging growth company  ☐

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).   Yes ☐ No ☒

At June 30, 2020, the end of the registrant’s most recently completed second fiscal quarter; the aggregate market value of common equity held by non-affiliates was $3,376,913.

At February 17, 2021, 55,192,846 shares of registrant’s Common Stock were outstanding.

TABLE OF CONTENTS

PART I	4
Item 1 Description of Business	4
Royale Business	4
Plan of Business	5
Competition, Markets and Regulation	6
Item 2 Description of Property	7
California	7
Texas	7
Developed and Undeveloped Leasehold Acreage	8
Gross and Net Productive Wells	8
Drilling Activities	8
Production	9
Reserve Estimates	9
Net Proved Oil and Natural Gas Reserves	9
Item 3 Legal Proceedings	10
Item 4 Mine Safety Disclosures	10
PART II	11
Item 3 Defaults Upon Senior Securities
Item 1	11
Item 5 Market for Common Equity and Related Stockholder Matters	11
Transfer Agent	11
Dividends	11
Recent Sales of Unregistered Securities	11
Item 2	11
Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations	11
Global Pandemic	11
General	11
Critical Accounting Policies	12
Results of Operations for the Year Ended December 31, 2020, as Compared to the Year Ended December 31, 2019	15
Capital Resources and Liquidity	16
Changes in Reserve Estimates	17
Item 7A     Qualitative and Quantitative Disclosures About Market Risk	17
Item 8     Financial Statements and Supplementary Data	17
Item 9     Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	18
Item 9A     Controls and Procedures	18
Material Weakness and Remediation	18
Attestation Report of the Independent Registered Public Accounting Firm.	18
Changes in Internal Control over Financial Reporting	18
PART III	19
Item 10 Directors and Executive Officers of the Registrant	19
Audit Committee	20
Code of Business Conduct and Ethics	21
Compliance with Section 16(a) of the Exchange Act	21
Item 11     Executive Compensation	21
Stock Options and Equity Compensation; Outstanding Equity Awards at Fiscal Year End	22
Compensation Committee Report	22
Compensation Discussion and Analysis	22
Compensation of Directors	23
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	23
Common Stock	23
Item 13     Certain Relationships and Related Transactions	24
Item 14     Principal Accountant Fees and Services	24
PART IV	25
Item 15 Exhibits and Financial Statement Schedules	25
SIGNATURES	27

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, 2020, 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 Resources, LLC (“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 (“Registration Rights Agreement”).

Under the terms of a management services agreement (the “Management Services Agreement”), required by the Contribution Agreement, Royale provided RMX with accounting, financial reporting and analysis, and regulatory support services for a payment of $180,000 per month. This agreement ended on March 31, 2019.

Royale Business

In this Annual Report, “Royale” and the “Company” refer to Royale Energy, Inc., a Delaware corporation. Financial information is reported for Royale on a consolidated basis including the following subsidiaries:

◦ Royale Energy Funds, Inc.

◦ Matrix Permian Investment, L.P.

◦ Matrix Las Cienegas L.P.

◦ Matrix Investment, L.P.

◦ Matrix Oil Management, Corp.

Royale and its subsidiaries own wells and leases located mainly in the Sacramento Basin and San Joaquin Basin in California as well as in Texas, Utah, Oklahoma, Colorado and Louisiana, as well as an overriding royalty interest 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.

4

During its fiscal year ended December 31, 2020, Royale continued to explore and develop oil and natural gas properties with concentration in California and Texas.  Additionally, we own proved developed producing and non-producing reserves of oil and natural gas in Utah, Texas, Oklahoma, Colorado and Louisiana, as well as holding an overriding royalty interest in a discovery in Alaska.  In 2020, Royale drilled five (5) wells, all five (5) of which were commercially productive.  Royale’s estimated total reserves were approximately 11.9 and 17.33 BCFE (billion cubic feet equivalent) at December 31, 2020 and 2019, 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 $20.8 million at December 31, 2020, based on the average Henry Hub natural gas price spot price of $1.985 per MCF and for oil volumes, the average West Texas Intermediate price of $39.54 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, Utah, Colorado and Louisiana 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, 2020, was estimated to be $7,441,035.  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 20 to our Financial Statements, Supplemental Information about Oil and Gas Producing Activities – Changes in Standardized Measure of Discounted Future Net Cash Flow from Proved Reserve Quantities.

Royale reported a gain on turnkey drilling in connection with the drilling of wells on a “turnkey contract” basis in the amount of $1,700,462 and $2,909,908 for the years ended December 31, 2020 and 2019, respectively.

In addition to Royale’s own staff, Royale hires independent contractors to drill, test, complete and equip the wells that it drills.  Approximately 97.2% of Royale’s total revenue for the year ended December 31, 2020, came from sales of oil and natural gas from production of its wells in the amount of $1,542,803.  In 2019, this amount was $2,329,275, which represented 78.5% 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.

5

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-9.

Once commenced, drilling is generally completed within 10-30 days.  See Note 1 to Royale’s Financial Statements.  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, 2020, Royale charged overhead from operation of the wells in the amount of $305,900 for the year, which were an offset to general and administrative expenses.  In 2019, the amount was $341,484.  At December 31, 2020, Royale operated wells in California and Texas. Royale also has non-operating interests in wells in California, Utah, Texas, Oklahoma, Colorado and Louisiana.

Royale currently sells most of its California natural gas production through 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.

6

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.

You may obtain a copy of any materials filed by Royale with the Securities and Exchange Commission (“SEC”) at 100 F Street, N.W., Washington, D.C. 20549, by calling 1-800-SEC-0300.  The SEC also maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the 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 2 Description of Property

Since 1993, Royale has concentrated on development of properties in the Sacramento Basin and the San Joaquin Basin of Northern and Central California.  In 2020, Royale drilled two developmental oil wells in Texas and participated in the drilling of three developmental oil wells in 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, 2020, 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 3, 2021.

California

Royale owns interests in nine gas fields with locations ranging throughout the Sacramento Basin in California.  At December 31, 2020, Royale operated 12 wells and owns interests in 21 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 9.303 BCFE, according to Royale’s independently prepared reserve report as of December 31, 2020.

Texas

At December 31, 2020, Royale owned and operated interests in 46 wells in its Jameson field. Our Texas estimated total proven, developed, and undeveloped net reserves are approximately 216.6 MBOE, according to Royale’s independently prepared reserve report as of December 31, 2020.

	Developed				Undeveloped
	Gross Acres		Net Acres		Gross Acres		Net Acres
California		5,092.76		3,890.17		11,431.00		3,308.42
Texas		7,865.00		7,575.22		640.00		128.00
All Other States		2,347.89		1,439.91		6,481.00		6,481.00
Total		15,305.65		12,905.30		18,552.00		9,917.42

7

Developed and Undeveloped Leasehold Acreage

As of December 31, 2020, and 2019, 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, 2020 and 2019, Royale owned interests in the following oil and gas wells in both gross and net acreage:

	2020				2019
	Gross Wells		Net Wells		Gross Wells		Net Wells
Natural Gas		38		12.3241		37		13.0576
Oil		29		19.0597		34		24.0716
Total		67		31.3838		71		37.1292

Drilling Activities

The following table sets forth Royale’s drilling activities during the years ended December 31, 2020 and 2019.  All wells are located in the Continental U.S., in California, Texas, Louisiana, Colorado and Utah.

Year	Type of Well(a)			Gross Wells(b)				Net Wells(e)
		Total		Producing(c)		Dry(d)		Producing(c)		Dry(d)
2019	Exploratory		0		0		0		0		0
	Developmental		10		8		2		1.7859		0
2020	Exploratory		0		0		0		0		0
	Developmental		5		5		0		1.2718		0

a) An exploratory well is one that is drilled in search of new oil and natural gas reservoirs, or to test the boundary limits of a previously discovered reservoir. A developmental well is one drilled on a previously known productive area of an oil and natural gas reservoir with the objective of completing that reservoir.

b) Gross wells represent the number of actual wells in which Royale owns an interest. Royale’s interest in these wells may range from 1% to 100%.

c) A producing well is one that produces oil and/or natural gas that is being purchased on the market.

d) A dry well is a well that is not deemed capable of producing hydrocarbons in paying, 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.

8

Production

The following table summarizes, for the periods 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.

	2020		2019
Net volume
Oil (BBL)		31,210		27,663
Gas (MCF)		160,406		292,472
MCFE		347,666		458,450
Average sales price
Oil (BBL)	$	37.96	$	54.40
Gas (MCF)	$	2.23	$	2.82
Net production costs and taxes	$	1,397,673	$	1,764,538
Lifting costs (per MCFE)	$	4.02	$	3.85

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, 2020. 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 36 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, 2020, Royale had proved developed reserves of 691,831 MCF and total proved reserves of 2,660,456 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 1,540,968 BBL.

As of December 31, 2019, Royale had proved developed reserves of 2,790,300 MCF and total proved reserves of 4,306,900 MCF of natural gas. For the same period, Royale also had proved developed oil and natural gas liquid combined reserves of 232,200 BBL and total proved oil and natural gas liquid combined reserves of 2,171,000 BBL.

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.

9

Item 3 Legal Proceedings

None.

Item 4 Mine Safety Disclosures

Not Applicable

10

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, 2020, 54,605,488 shares of Common Stock were held by approximately 5,018 stockholders. As of December 31, 2019, 51,854,136 shares of Royale’s Common Stock were held by approximately 4,160 stockholders.   The following table reflects the high and low quarterly closing sales prices on the Nasdaq Stock Market and OTC QB Market from January 2019 through December 2020:

	1st Qtr				2nd Qtr				3rd Qtr				4th Qtr
	High		Low		High		Low		High		Low		High		Low
2019	$	0.35	$	0.15	$	0.33	$	0.23	$	0.26	$	0.17	$	0.19	$	0.10
2020	$	0.24	$	0.07	$	0.18	$	0.08	$	0.18	$	0.10	$	0.13	$	0.08

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 2020 or 2019. The Board of Directors did declare dividends during 2020 and 2019 on the preferred stock to be Paid In Kind (“PIK”) of 76,290 and 73,473 shares with a respective par value of $762,900 and $734,725, 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

2020 Challenges

In December 2019, a novel strain of coronavirus (which triggers a respiratory disease called COVID-19) was reported in Wuhan, China. The World Health Organization has declared the outbreak to constitute a “Public Health Emergency of International Concern.” The COVID-19 outbreak has caused a major reduction in the consumption of hydrocarbon-based transportation fuels as airlines have grounded flights worldwide and countries around the world have asked residents to suspend automobile travel. In addition to a substantial loss of demand for crude oil, in March 2020, Saudi Arabia entered into a price war with Russia and added additional supplies of crude oil to an already over supplied market. The result has been a precipitous decline in the price of crude oil received by the Company. As a result, the Company has seen a reduction in its oil and natural gas revenues and resulting cash flows for the year 2020.

General

The following discussion should be read in conjunction with Royale’s Financial Statements and Notes thereto and other financial information relating to Royale included elsewhere in this document.

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.

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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.

The Company recorded amounts received from the Master Service Agreement (“MSA”) with RMX for providing land, engineering, accounting and back-office support as part of revenues. Revenues earned under the MSA were recorded at the end of each month that services were performed in conformity with the Agreement with an offsetting receivable from the RMX joint venture. The service fee income was treated as earned at the end of each month that services were performed.

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.

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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 2020 and 2019, impairment losses of $0 and $977,682, 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.

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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, 2020 and 2019, Royale had deferred drilling obligations of $3,127,500 and $5,232,675 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.

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Going Concern

At December 31, 2020, the Company has an accumulated deficit of $82,298,785, a working capital deficiency of $4,044,437 and a stockholders’ deficit of $28,360,701. 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 2021 budget. Royale is in the process of selling two property groups and has recorded a current asset of $1.5 million as Long-Term Assets Held for Sale. 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, if needed to fully fund our 2021 drilling budget and to support future operations.

Results of Operations for the Year Ended December 31, 2020, as Compared to the Year Ended December 31, 2019

For the year ended December 31, 2020, we had a net loss of $8,148,147 compared to the net loss of $348,383 during the year in 2019. The table below reflects the major components of other income and expense.

	Year Ended December 31,
	2020			2019
Loss from Operations	$	(2,674,329	)	$	(845,071	)
Other Income (Expense):
Interest Expense		(12,949	)		(20,559	)
Gain (Loss) on Investment in Joint Venture		(6,185,995	)		(397,936	)
Gain on Settlement of Payables		166,300			897,708
Other Gain		551,906			172,523
Gain (Loss) on Sale of Assets, net		6,920			(155,048	)
Loss Before Income Tax Expense	$	(8,148,147	)	$	(348,383	)

In 2020, the majority of the net loss resulted from a $6,185,995 write down of our investment in RMX Resources, LLC, due to year end 2020 reserve valuations and other considerations, see Note 2 – RMX Joint Venture. In 2019, the majority of the loss resulted from a loss from Operations of $845,071.

During the year ended 2020, revenues from oil and gas production decreased $786,472 or 33.8% to $1,542,803 from the 2019 revenue of $2,329,275.  This decrease was due to lower prices realized for the sale of oil and gas in 2020.  The net sales volume of oil for the year ended December 31, 2020 was 31,210 barrels of oil with an average price of $37.96 versus approximately 27,663 barrels with an average price of $54.40 per barrel, for the year in 2019.  This represents an increase in net sales volume of 3,547 barrels or 12.8%. The net sales volume of natural gas for the year ended December 31, 2020, was approximately 160,406 Mcf with an average price of $2.23 per Mcf, versus 292,472 Mcf with an average price of $2.82 per Mcf for the year in 2019.  This represents a decrease in net sales volume of 132,066 Mcf or 45.2%.  The decrease in natural gas production volume was due to certain wells that were offline and waiting on workovers and to lower volumes on existing wells due to natural declines.

Oil and natural gas lease operating expenses decreased by $366.865 or 20.8%, to $1,397,673 for the year ended December 31, 2020, from $1,764,538 for the year in 2019. This was lower in 2020 due to decreases in workover costs and outside operated lease operating costs as certain non-operated wells were offline and waiting on workovers. When measuring lease operating costs on a production or lifting cost basis, in 2020, the $1,397,673 equates to a $4.02 per Mcfe lifting cost versus a $3.85 per Mcfe lifting cost in 2019, mainly due to lower production volumes in 2020.

The aggregate of Supervisory Fees and other income was $45,052 for year ended December 31, 2020, a decrease of $592,856 or 92.9% from $637,908 during the year in 2019. This decrease was mainly due to the loss of service agreement fees through an arrangement with RMX Resources, LLC.

Depreciation, depletion and amortization expense increased to $473,647 from $468,143, an increase of $5,504 or 1.2% for the year ended December 31, 2020, as compared to the year in 2019. The depletion rate is calculated using production by comparing capitalized cost to the recoverable reserves remaining.  This increase in depreciation expense was due to the decrease in reserves owned by the Company as compared to the estimated reserves in the prior year, due to the decrease in oil and gas prices in 2020.

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General and administrative expenses increased by $117,413 or 5.9% from $1,991,819 for the year ended December 31, 2019, to $2,109,232 for the year ended 2020. This increase was primarily driven by our absorption of a greater percentage of drilling management costs. Overhead and drilling overhead offset general and administrative costs. Legal and accounting expense decreased to $279,227 for the year in 2020, compared to $751,935 for the year in 2019, a $472,708 or 62.9% decrease.  This decrease was primarily due to higher legal and accounting fees in 2019 as we transitioned to new auditors and to the Matrix post-merger reporting incurred during the year in 2019. Marketing expense for the year ended December 31, 2020, decreased $301,357, or 72.6%, to $113,614, compared to $414,971 for the year in 2019.  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, 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. At December 31, 2019, Royale had a deferred drilling obligation of $5,232,675.  During 2019, we disposed of $11,961,767 of drilling obligations upon completing the drilling of eight natural gas wells and participating in the drilling of two oil wells in California, while incurring expenses of $9,051,859, resulting in a gain of $2,909,908.

During the year in 2020, as disclosed above, we recorded a loss of $6,185,995, on the write down of our investment in joint venture of RMX Resources, LLC, compared to a loss of $397,936 for our 20% share of the RMX Resources net loss of $1,989,680 in 2019. 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 Small Business Administration (“SBA”)  Paycheck Protection Program (“PPP”) loan and a loss on settlement of $31,500 related to a 2018 seismic sales agreement. During the year in 2019, we recorded geological and geophysical expense of $264,219 related mainly to the acquisition of a seismic survey of a Northern California field, while during the year in 2020, we recorded $14,392 in geological and geophysical expenses. During the year in 2019, we recorded a gain of $897,708, mainly on the reconciliation and settlement of royalties payable.  During the first quarter in 2019, we recorded a loss on the sale of assets of $1,237,126 related a settlement agreement with RMX Resources, LLC. During the fourth quarter of 2019, we recorded a gain on the sale of assets of $1,254,204 on the settlement of contingent liabilities related to the merger with Matrix. During 2019, we also recorded a $172,126 loss on the sale of leases obtained in the merger. During 2019, we recorded a gain on settlement of $834,736 on the reconciliation and settlement of royalties payable. During year in 2019, we recorded a gain of $62,972 on the settlement of accounts payable. During the year in 2019, we recorded a gain of $172,523 on the receipt of tax property tax refunds due to adjusted assessments on certain leases from prior years. We periodically review our proved properties for impairment on a field-by-field basis and charge impairments of value to the expense. During 2019, we recorded lease impairments of $977,682, respectively on various lease and land costs that were no longer viable, no lease impairments were recorded in 2020. During the year in 2019, we recorded write downs of $28,343 on certain well equipment that was either written down to their current market value or were no longer useable, no equipment write-downs occurred in 2020.

Bad debt expense for 2020 and 2019 were $1,008,003 and $60,512, respectively.  During the year in 2020, approximately $203,000 was related to revenue receivable from an industry partner whose collectability was in doubt. The other bad debt expenses in 2020 and 2019 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.  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 $12,949 for the year ended December 31, 2020, from $20,559 in 2019, a $7,610 decrease.  This decrease was mainly due to lower principal balances on notes payable during the year in 2020.

In 2020 and 2019, 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, 2020, Royale had current assets totaling $5,070,555 and current liabilities totaling $9,114,992, a $4,044,437 working capital deficit.  We had cash and cash equivalents at December 31, 2020 of $255,112 and restricted cash of $2,146,571 compared to cash and cash equivalents of $1,031,014 and restricted cash of $2,845,515 at December 31, 2019.

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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, 2020, our other receivables, which consist of joint interest billing receivables from direct working interest participants and industry partners, totaled $462,777, compared to $1,189,892 at December 31, 2019, a $727,115 decrease.  This decrease was mainly due to increases in accounts receivable allowances in 2020.  At December 31, 2020, revenue receivable was $204,149, a decrease of $385,002, compared to $589,151 at December 31, 2019, due to lower commodity prices and lower oil and gas production volumes on existing wells.  At December 31, 2020, our accounts payable and accrued expenses totaled $4,161,109, a decrease of $1,869,925 from the accounts payable at December 31, 2019 of $6,031,034, mainly related to payments made on account and lower drilling accruals at year end 2020.

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, 2020 and 2019, cash used by operating activities totaled $381,116 and $3,489,482, respectively.  This $3,108,336 or 89.1% decrease in cash used was primarily due to decreases in prepaid expenses and accounts payable during the period in 2020 due to the drilling and account payments in 2020.

Investing Activities. Net cash used by investing activities totaled $1,235,485 for the year ended December 31, 2020 versus net cash provided by investing activities of $1,587,821 for the year ended December 31, 2019. During 2020, our turnkey drilling expenditures were lower as we drilled five oil wells, while in 2019, we drilled eight natural gas wells and participated in the drilling of two oil wells. Additionally, during 2020 and 2019 we received approximately $4.3 million and $11 million, respectively, in direct working interest turnkey drilling investments.

Financing Activities.  For the year ended December 31, 2020, net cash provided by financing activities totaled $141,755 versus net cash used by financing activities of $576,852 for the year ended December 31, 2019. 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. During 2019, a financing agreement for a seismic survey was recognized when the terms were finalized, on which there were principal payments of approximately $186,000. Additionally, in 2019, there were principal payments of approximately $391,000 on our note with Forza Operating.

Changes in Reserve Estimates

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), page F-27.

During 2019, our overall proved developed and undeveloped reserves increased by 44.2% and our previously estimated proved developed and undeveloped natural gas reserve quantities were revised downward by approximately 0.89 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 contracted.  See Supplemental Information about Oil and Gas Producing Activities (Unaudited), page F-27.

Item 7A     Qualitative and Quantitative Disclosures About Market Risk

Royale is exposed to market risk from changes in commodity prices and interest rates.  In 2020, we sold a portion of our natural gas at the daily market rate through the Pacific Gas & Electric pipeline.  In 2020, our natural gas revenues were approximately $357,587 with an average price of $2.23 per MCF.  At current production levels, a 10% per MCF increase or decrease in our average price received could potentially increase or decrease our natural gas revenues by approximately $36,000.  We currently do not sell any of our natural gas or oil through hedging contracts.

Item 8     Financial Statements and Supplementary Data

See pages F-1, et seq., included herein.

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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, 2020 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. Updated procedures have been implemented through the close process for the year ended December 31, 2019, but the material weakness on our financial close and reporting process was not alleviated. We will continue to monitor these throughout 2021 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, 2020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART III

Item 10 Directors and Executive Officers of the Registrant

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, 2020:

Name	Age	First Became Director or Executive Officer	Positions Held
Robert Vogel (4)	61	2018	Chairman of the Board
Mel G. Riggs (1)(2)(3)(4)	66	2018	Director
Jonathan Gregory	56	2014	Vice-Chair of the Board of Directors
Johnny Jordan	60	2018	Chief Executive and Operating officer and Director
Thomas M. Gladney (1) (2)(3)(4)	68	2018	Director
Karen Kerns (1) (2)(3)(4)	62	2019	Director

(1)	Members of the Audit Committee
(2)	Members of the compensation committee
(3)	Members of the nominations committee
(4)	Members identified as independent

The board has determined that directors Mel G. Riggs, Thomas M. Gladney, Karen Kerns and Robert Vogel qualify as independent directors.

The following summarizes the business experience of each director and executive officer for the past six years.

Robert Vogel – Chairman of the Board

Robert Vogel has been Senior managing Director at Peapack-Gladstone Bank since December 2020. In 2020, Peapack-Gladstone Bank merged the business of Lucas Capital Management, a NJ wealth management firm at which Mr. Vogel was a Principal since 2016. He has started working at Lucas Capital Management in March 2008. He is a seasoned executive with an extensive background in the energy industry. Mr. Vogel previously was Vice President and Treasurer of Hess Corporation. He serves as the Chairman of BlinkNow Foundation, an organization that supports women and children in Nepal. Mr. Vogel holds a BS in Chemical Engineering from the University of Colorado and an MBA from New York University.

Mel G. Riggs – Director

Mr. Riggs has served on the board of directors of NexTier Oilfield Solutions, Inc. (NEX:NYSE) since October 2019. Since July 2018, Mr. Riggs has served on the board of directors of Royale Energy, Inc. (ROYL:OTC). In addition, Mr. Riggs has served on the board of directors of privately held Community National Bank of Midland, Texas since August 2000. Previously, Mr. Riggs served on the board of directors of TransAtlantic Petroleum, Ltd. (TAT:NYSE) from July 2009 until June 2020.

From March 2015 to April 2017, Mr. Riggs served as the President and director of Clayton Williams Energy Inc. (CWEI:NYSE), which was acquired by Noble Energy Inc. (NBL:NYSE) in April 2017 for $2.7 billion. During his tenure with Clayton Williams Energy, Inc., Mr. Riggs also served as the Executive Vice President and Chief Operating Officer of the Company from December 2010 to March 2015 and prior to that position, served as Senior Vice President and Chief Financial Officer of the Company beginning in September 1991.

Since April 2017 Mr. Riggs has served as an officer and director of the Clayton Williams Family Office group of companies. These companies are primarily active in the management of oil and gas minerals and royalties, real estate, agriculture, water, and investments.

Mr. Riggs has served on the boards of the Permian Basin Petroleum Association (PBPA), The Petroleum Club of Midland, and The Texas Business Hall of Fame. Mr. Riggs has extensive knowledge in strategic planning, is an expert in financial matters and is highly qualified to make strategic and operational decisions in the companies with which he is affiliated. Mr. Riggs is a certified public accountant and received a BBA from Texas Tech University in 1977.

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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 _xx 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.

Thomas M. Gladney – Director

Thomas M. Gladney is now and has been continuously since 2006 President of Bodog Resources LLC, a wholly owned private entity which currently invests in oil and gas assets and he also serves as Executive Vice President and managing partner of Foothill Energy LLC, a private partnership which operates oil and gas wells in California. Mr. Gladney previously served as Executive Vice President of Plains Exploration and Production Company and prior to that worked for Sun Company/Oryx Energy Company as Manager of Offshore Operations, Manager of Gulf Coast Development, and Director of Acquisitions among other positions. He has a BS in Petroleum Engineering from Mississippi State University.

Karen Kerns – Director

Karen Kerns is an attorney with expertise in business contracts, real estate and real estate negotiations and investments. Ms. Kerns held various staff and partner positions with law firms prior to serving as General Counsel for a private REIT with over $400 million in private investor funds from 1998-2010. From 2010 to present, Ms. Kerns operates a private legal practice representing real estate investors and small private REITs in formation, private syndication and business oversight. Ms. Kerns is currently Vice Chair of the Santa Barbara Bowl Foundation, a multimillion-dollar outdoor concert venue located in Santa Barbara, CA and has previously served on the board of directors for numerous nonprofit organizations, as well as a four-year term as an elected member of the Montecito Union School District Board of Education, where she spent one year as president.  Ms. Kerns has a BA in education from the University of Wyoming and a Juris Doctor from the University of Denver Sturm College of Law.

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 Robert Vogel qualifies as an “audit committee financial expert” as defined in Item 407(d)(5) of the Securities and Exchange Commission.

At the end of 2020, the members of the audit committee were Mel Riggs (Chair), Karen Kerns, and Thomas M. Gladney.

20

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 2020.

Item 11     Executive Compensation

The following table summarizes the compensation of the chief executive officer, chief financial officer and the one other most highly compensated non-executive employee  of Royale and its subsidiaries during the past three years.

SUMMARY COMPENSATION TABLE

Year	Year	Salary (3)		Bonus		Option Awards (1)		All Other Compensation (2)		Total
Johnny Jordan (5)	2020	$	255,769					$	7,500	$	263,269
(CEO)	2019	$	255,769					$	-	$	255,769
	2018	$	213,141					$	-	$	213,141
Jonathan Gregory (4)	2020	$	-					$	-	$	-
(Vice-Chair)	2019	$	-					$	-	$	-
	2018	$	72,909					$	9,583	$	82,492
Donald Hosmer	2020	$	185,177	$	49,554			$	18,930	$	253,661
(Business Development)	2019	$	189,344	$	95,193			$	18,930	$	303,467
	2018	$	236,331					$	18,930	$	255,261
Stephen Hosmer	2020	$	230,192					$	18,906	$	249,098
(CFO)	2019	$	230,192					$	18,906	$	249,098
	2018	$	230,192			$	64,954	$	18,750	$	313,896

(1)     On October 10, 2018, the Company entered into an agreement to issue Mr. Hosmer 250,000 options to purchase common stock previously approved by the Board of Directors with an exercise price of $0.31. These options were granted for a period of ten years with a maturity date of October 9, 2028.

(2)     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. This category also includes Board fees for Mr. Gregory.

(3)     Salary represents either direct payroll or common stock paid in lieu of taking a cash salary.

(4)     Mr. Gregory served as CEO of the Company during 2016, 2017 and part of 2018. Mr. Gregory resigned from the CEO position with the execution of the RMX joint venture.

(5)     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.

21

Stock Options and Equity Compensation; Outstanding Equity Awards at Fiscal Year End

No unvested stock awards were outstanding at the end of 2020.

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:

Thomas M. Gladney, Karen Kerns (Chair), and Mel Riggs

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, in December each year, 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 2020 or 2019, other than those listed for Donald Hosmer in the table above.

22

Compensation of Directors

In 2020, 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 2020.

Name	Fees paid in Cash or Common Stock		Stock awards		Option awards		All Other Compensation		Total
Mel G. Riggs	$	44,000	$	-	$	-	$	-	$	44,000
Thomas M. Gladney	$	44,000	$	-	$	-	$	-	$	44,000
Karen Kerns	$	44,000	$	-	$	-	$	-	$	44,000
Robert Vogel	$	44,000	$	-	$	-	$	-	$	44,000
Jonathan Gregory	$	33,000	$	-	$	-	$	-	$	33,000

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

Common Stock

At February 17, 2021, 55,192,846 shares of registrant’s Common Stock were outstanding.

The following table contains information regarding the ownership of Royale’s Common Stock as March 6, 2021, 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.

Insider Holdings
Stockholder (1)	Number		Percent
Stephen M. Hosmer (2)		1,140,229		2.07	%
Johnny Jordan (3)		21,195,747		38.40	%
Jonathan Gregory (4)		758,409		1.37	%
Mel G. Riggs		459,396		*
Karen Kerns		-		*
Thomas M. Gladney		532,203		*
Robert Vogel		471,831		*
All officers and directors as a group		24,557,815		44.49	%

*  Less than 1%.

(1)	The mailing address of each listed stockholder is 1870 Cordell Court, Suite 210, El Cajon, California 92020.
(2)	Includes 6,000 shares owned by Stephen M. Hosmer's minor children.
(3)	Includes 9,858,160 shares issuable upon conversion of Series B Convertible Preferred Stock.
(4)	Includes 35,000 shares owned by Mr. Gregory's son.

The following table contains information regarding the ownership of Royale’s Common Stock as March 6, 2020, by each person who is known by Royale to own beneficially more than 5% of the outstanding shares of each class of equity securities. Except pursuant to applicable community property laws and except as otherwise indicated, each shareholder identified in the table possesses sole voting and investment power with respect to its or his shares.  The holdings reported are based on reports filed with the Securities and Exchange Commission and the Company by the 5% shareholders.

23

Ownership
Stockholder (1)	Number		Percent
Johnny Jordan (2)		21,195,747		38.40	%
Jeff Kerns (3)		18,139,303		32.87	%

(1)	The mailing address of each listed stockholder is 1870 Cordell Court, Suite 210, El Cajon, California 92020.
(2)	Includes 9,858,160 shares issuable upon conversion of Series B Convertible Preferred Stock.
(3)	Includes 8,917,540 shares issuable upon conversion of Series B Convertible Preferred Stock.

Item 13     Certain Relationships and Related Transactions

Our Chief Executive, Johnny Jordan, has accrued certain unpaid salaries, which were assumed by the Company. At December 31, 2019 Mr. Jordan was owed $14,648 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 Chief Financial Officer, Stephen Hosmer, had participated individually in 179 wells under the 1989 policy. At December 31, 2020, the Company had a receivable balance of $17,101 due from Stephen Hosmer and $5,385 from Donald Hosmer for normal drilling and lease operating expenses.

At December 31, 2020, 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 $239,036 primarily for the drilling of two wells, expected to commence in 2021.

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, 2020, the balance due was $1,306,605.

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 is a director of Royale.

Item 14     Principal Accountant Fees and Services

Moss Adams LLP served as the independent registered accounting firm to audit the Company’s financial statements for the fiscal year ended December 31, 2020 and 2019.  The aggregate fees billed for the years ended December 31, 2020 and 2019 are as follows:

	2020		2019
Audit fees (1)		270,375		381,075
Tax fees (2)		-		-
All other fees (3)		-		-
Total		270,375		381,075

(1)	Audit fees are fees for professional services rendered for the audit of Royale Energy's annual financial statements, reviews of financial statements included in the Company's Forms 10-Q, and reviews of documents filed with the U.S. Securities and Exchange Commission.
(2)	Tax fees consist of tax planning, consulting and tax return reviews.
(3)	Other fees consist of work on registration statements under the Securities Act of 1933.

The Company’s audit committee has adopted policies for the pre-approval of all audit and non-audit services provided by the Company’s independent auditor.  The policy requires pre-approval by the audit committee of specifically defined audit and non-audit services.  Unless the specific service has been previously pre-approved with respect to that year, the audit committee must approve the permitted service before the independent auditor is engaged to perform it.

No representatives of Moss Adams LLP are expected to be present at the annual meeting.  Although the audit committee has the sole responsibility to appoint the auditors as required under the Securities Exchange Act of 1934, the committee welcomes any comments from the Company’s shareholders on auditor selection or performance.  Comments may be sent to the audit committee chair, Mel Riggs, care of the Company’s executive office, 1870 Cordell Court, Suite 210, El Cajon, California 92020.

24

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:

● should not be treated as categorical statements of fact, but rather as a way of allocating the risk among the parties if those statements prove to be inaccurate;

● have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;

● may apply standards of materiality in a way that is different from the way investors may view materiality; and

● were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.

1.       Financial Statements.  See Index to Financial Statements, page F-1

2.       Schedules.  None.

3.       Exhibits.  Certain of the exhibits listed in the following index are incorporated by reference.

3.2	Amended and Restated Bylaws of Royale Energy, Inc., incorporated by reference to Exhibit 3.3 of Royale Energy’s Form 10-K filed March 27, 2009
3.3	Amendment to the Certificate of Incorporation of Royale Energy, Inc., a California corporation (March 7, 2018), filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K dated March 7, 2018, filed March 12, 2018
4.1	Royale Energy Holdings, Inc., Certificate of Designation of Series B 3.5% Redeemable Convertible Preferred Stock, filed with the Delaware Secretary of State on February 27, 2018, filed as Exhibit 2.5 to the Company’s Form 8-A, filed March 8, 2018
10.11	Company Agreement of RMX (April 4, 2018), filed as Exhibit 10.1 to the Company’s Form 8-K filed April 10, 2018
10.13	Conveyance of Term Overriding Royalty Interest between Sunny Frog Oil, LLC, and Royale (April 4, 2018), filed as Exhibit 10.3 to the Company’s Form 8-K filed April 10, 2018
10.17	Royale Energy, Inc., 2018 Equity Incentive Plan, filed as Exhibit 99.1 to the Company’s Form S-8 filed October 29, 2018
10.19	Employment Agreement between the Company and Thomas M. Gladney, filed as Exhibit 10.3 to the Company’s Form S-8 filed October 29, 2018
10.20	Employment Agreement between the Company and Jonathan Gregory, filed as Exhibit 10.4 to the Company’s Form S-8 filed October 29, 2018
10.21	Employment Agreement between the Company and Harry E. Hosmer, filed as Exhibit 10.5 to the Company’s Form S-8 filed October 29, 2018
10.22	Employment Agreement between the Company and Barry Lasker, filed as Exhibit 10.6 to the Company’s Form S-8 filed October 29, 2018
10.23	Employment Agreement between the Company and Mel. G. Riggs, filed as Exhibit 10.7 to the Company’s Form S-8 filed October 29, 2018
10.24	Employment Agreement between the Company and Robert Vogel, filed as Exhibit 10.8 to the Company’s Form S-8 filed October 29, 2018
10.25	Employment Agreement between the Company and Michael McCaskey, filed as Exhibit 10.9 to the Company’s Form S-8 filed October 29, 2018
10.26	Employment Agreement between the Company and Jeffrey Kerns, filed as Exhibit 10.10 to the Company’s Form S-8 filed October 29, 2018
10.27	Incentive Stock Option Agreement between the Company and Stephen M. Hosmer, filed as Exhibit 10.11 to the Company’s Form S-8 filed October 29, 2018

25

21.1	Subsidiaries, filed herewith.
23.2	Consent of Netherland, Sewel & Associates, Inc., filed herewith
31.1	Rule 13a-14(a), 115d-14(a) Certification, filed herewith.
31.2	Rule 13a-14(a), 115d-14(a) Certification, filed herewith.
32.1	Section 1350 Certification, filed herewith.
32.2	Section 1350 Certification, filed herewith.
99.1	Report of Netherland, Sewell & Associates, Inc., filed herewith.
99.2	Consolidated Financial Statements of RMX Resources, LLC, filed herewith
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase
101.DEF*	XBRL Taxonomy Extension Definition Linkbase
101.LAB*	XBRL Taxonomy Extension Label Linkbase
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase

* Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability.

26

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	Royale Energy, Inc.
Date: March 30, 2021	/s/ Johnny Jordan
	Johnny Jordan
	Chief Executive Officer

Date: March 30, 2021	/s/ Stephen M. Hosmer
	Stephen M. Hosmer
	Chief Financial Officer, Secretary and Principle Accounting Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Date: March 30, 2021	/s/ Robert Vogel
	Robert Vogel
	Chairman of the Board of Directors
Date: March 30, 2021	/s/ Jonathan Gregory
	Jonathan Gregory
	Vice-Chair of the Board of Directors
Date: March 30, 2021	/s/ Thomas M. Gladney
	Thomas M. Gladney
	Director
Date: March 30, 2021	/s/ Karen Kerns
	Karen Kerns
	Director
Date: March 30, 2021	/s/ Mel Riggs
	Mel Riggs
	Director

27

ROYALE ENERGY, INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM	F-2
CONSOLIDATED BALANCE SHEETS	F-4
CONSOLIDATED STATEMENTS OF OPERATIONS	F-6
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY	F-7
CONSOLIDATED STATEMENTS OF CASH FLOWS	F-8
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	F-9

F-1

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 sheets of Royale Energy, Inc. (the “Company”) as of December 31, 2020 and 2019, the related consolidated statements of operations, stockholders’ equity and cash flows for the years 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 2019, and the consolidated results of its operations and its cash flows for the years 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 audits. 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 audits 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 audits 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 audits 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 audits 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 audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period 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.

F-2

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:

● Selecting a sample of wells and:

● Obtaining the master spreadsheet for each selected well, recalculating the worksheet for clerical accuracy, and sampling the direct working interest (DWI) investors;

● Obtaining signed field subscription agreement for each selected investor in each well, verifying the investment ownership amount per the signed field subscription agreement agreed to the amount invested and the number of units within the master spreadsheet, vouching the cash received from the DWI investors, and agreeing the significant terms to the related Private Placement Memorandum;

● Obtaining a schedule of costs incurred to drill the selected well, recalculating the schedule for clerical accuracy, and obtaining support from management to substantiate the costs incurred; and

● Obtaining evidence substantiating the timing and amount of the recognition of turnkey gain pertaining to a sample of wells drilled and assessing that the recognition of the turnkey gain was appropriate as defined under the terms of the Private Placement Memorandums.

San Diego, California

March 30, 2021

We have served as the Company’s auditor since 2019.

F-3

ROYALE ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

DECEMBER 31,

	2020		2019
ASSETS
Current Assets:
Cash and Cash equivalents	$	255,112	$	1,031,014
Restricted Cash		2,146,571		2,845,515
Other Receivables, net		462,777		1,189,892
Revenue Receivables		204,149		589,151
Assets Held For Sale		1,529,141		-
Prepaid Expenses and Other Current Assets		233,769		376,587
Prepaid Drilling to RMX Resources, LLC		239,036		2,680,155
Total Current Assets		5,070,555		8,712,314
Investment in Joint Venture		-		6,185,995
Other Assets		583,554		708,554
Right of Use Asset - Operating Leases		229,516		392,774
Oil and Gas Properties (Successful Efforts Basis), Real Property and Equipment and Fixtures, net		2,541,001		4,590,990
Total Assets	$	8,424,626	$	20,590,627

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

F-4

ROYALE ENERGY, INC.

CONSOLIDATED BALANCE SHEETS (Continued) 

DECEMBER 31,

	2020			2019
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current Liabilities:
Accounts Payable and Accrued Expenses	$	4,161,109		$	6,031,034
Royalties Payable		623,405			623,405
Notes Payable		132,624			55,573
Due RMX Resources, LLC		23,087			32,367
Operating Leases - Current		178,120			162,272
Asset Retirement Obligation - Current		869,147			-
Deferred Drilling Obligations		3,127,500			5,232,675
Total Current Liabilities		9,114,992			12,137,326
Noncurrent Liabilities:
Asset Retirement Obligation		2,478,350			3,632,423
Operating Leases - Non-current		52,937			231,071
Accrued Unpaid Guaranteed Payments		1,616,205			1,616,205
Accrued Liabilities - Non-current		1,306,605			1,306,605
Total Liabilities		14,569,089			18,923,630
Mezzanine Equity:
Convertible Preferred Stock, Series B, $10 par value, 3.5% annual dividend, 2,221,622 shares issued as of December 31, 2020		22,216,238			-
Stockholders’ Equity:
Convertible Preferred Stock, Series B, $10 par value, 3,000,000 Shares Authorized, 2,145,332 shares issued / outstanding at December 31, 2019		-			21,453,338
Common Stock, .001 Par Value, 280,000,000 Shares Authorized 54,605,488 and 51,854,136 shares issued / outstanding at December 31, 2020 and 2019 respectively		54,605			51,854
Additional Paid in Capital		53,883,479			53,549,543
Accumulated Deficit		(82,298,785	)		(73,387,738	)
Total Stockholder’s Equity (Deficit)		(28,360,701	)		1,666,997
Total Liabilities and Stockholders’ Equity	$	8,424,626		$	20,590,627

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

F-5

ROYALE ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS 

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

	2020			2019
Revenues:
Sale of Oil and Gas	$	1,542,803		$	2,329,275
Supervisory Fees and Other		45,052			637,908
Total Revenues		1,587,855			2,967,183
Costs and Expenses:
Lease Operating		1,397,673			1,764,538
Impairment		-			977,682
Geological and Geophysical Expense		14,392			264,219
Well Equipment Write Down		-			28,343
Depreciation, Depletion and Amortization		473,647			468,143
Bad Debt Expense		1,008,003			60,512
General and Administrative		2,109,232			1,991,819
Legal and Accounting		279,227			751,935
Marketing		113,614			414,971
Loss on Assets Held For Sale		566,858			-
Total Costs and Expenses		5,962,646			6,722,162
Gain on Turnkey Drilling		1,700,462			2,909,908
Loss from Operations		(2,674,329	)		(845,071	)
Other Income (Expense):
Interest Expense		(12,949	)		(20,559	)
Loss on Investment in Joint Venture		(6,185,995	)		(397,936	)
Gain on Settlement of Payables		166,300			897,708
Other Gain		551,906			172,523
Gain (Loss) on Sale of Assets		6,920			(155,048	)
Loss Before Income Tax Expense		(8,148,147	)		(348,383	)
Provision for Income Taxes		-			-
Net Loss		(8,148,147	)		(348,383	)
Basic Loss Per Share		(0.17	)		(0.02	)
		-
Diluted Loss Per Share		(0.17	)		(0.02	)

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

F-6

ROYALE ENERGY, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY 

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

	Common Shares		Common Amount		Preferred Shares		Preferred Amount		APIC		ACD			Total
December 31, 2018 Balance		49,421,387	$	49,421		2,071,861	$	20,718,613	$	53,023,350	$	(72,304,630	)	$	1,486,754
Stock Issued in lieu of Compensation		2,432,749		2,433		-		-		526,193		-			528,626
Preferred Series B 3.5% Dividend		-		-		73,473		734,725		-		(734,725	)		-
Net Loss		-		-		-		-		-		(348,383	)		(348,383	)
December 31, 2019 Balance		51,854,136		51,854		2,145,334	$	21,453,338	$	53,549,543	$	(73,387,738	)	$	1,666,997

	Common Shares		Common Amount		Preferred Shares			Preferred Amount			APIC		ACD			Total
December 31, 2019 Balance		51,854,136	$	51,854		2,145,334		$	21,453,338		$	53,549,543	$	(73,387,738	)	$	1,666,997
Stock Issued in lieu of Compensation		2,751,352		2,751		-			-			333,936					336,687
Reclassify Preferred B to Mezzanine		-		-		(2,164,054	)		(21,640,538	)		-		-			(21,640,538	)
Preferred Series B 3.5% Dividend		-		-		18,720			187,200			-		(762,900	)		(575,700	)
Net Loss		-		-		-			-			-		(8,148,147	)		(8,148,147	)
December 31, 2020 Balance		54,605,488	$	54,605		-		$	-		$	53,883,479	$	(82,298,785	)	$	(28,360,701	)

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

F-7

ROYALE ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS 

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

	2020			2019
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (Loss)	$	(8,148,147	)	$	(348,383	)
Adjustments to Reconcile Net Loss to Net Cash Used by Operating Activities:
Depreciation, Depletion, and Amortization		473,647			468,143
Impairment		-			977,682
(Gain) Loss on Sale of Assets		(6,920	)		155,048
Gain on Turnkey Drilling		(1,700,462	)		(2,909,908	)
(Gain) Loss on Settlement of Accounts Payable		(166,300	)		(897,708	)
Loss on Investment in Joint Venture		6,185,995			397,936
Bad Debt Expense		1,008,003			60,512
Loss on Assets Held For Sale		566,858			-
Geological & Geophysical Costs		14,392			264,219
Gain on Other		(271,310	)		(172,523	)
Stock-Based Compensation		336,687			528,626
Well Equipment and Other Assets Write Down					28,343
Right of Use Asset Depreciation		10,945			-
(Increase) Decrease in:
Other & Revenue Receivables		46,210			84,372
Prepaid Expenses and Other Assets		2,583,937			(2,679,919	)
Increase (Decrease) in:
Accounts Payable and Accrued Expenses		(1,305,371	)		866,092
Royalties Payable					(9,386	)
Due to Affiliate		(9,280	)		(302,628	)
Net Cash Used in Operating Activities		(381,116	)		(3,489,482	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for Oil and Gas Properties		(5,562,985	)		(9,393,338	)
Proceeds from Turnkey Drilling		4,327,500			10,981,159
Proceeds from Sale of Assets		-			-
Net Cash (Used In) Provided by Investing Activities		(1,235,485	)		1,587,821
CASH FLOWS FROM FINANCING ACTIVITIES:
Principal Payments on Long-Term Debt		(66,045	)		(390,840	)
Proceeds from Long-Term Debt		207,800
Seismic Financing Agreement Payments					(186,012	)
Net Cash Provided by (Used In) Financing Activities		141,755			(576,852	)
Net Increase (Decrease) in Cash		(1,474,846	)		(2,478,513	)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year		3,876,529			6,355,042
Cash, Cash Equivalents, and Restricted Cash at End of Year	$	2,401,683		$	3,876,529
Cash Paid for Interest	$	12,949		$	20,559
Cash Paid for Taxes	$	5,559		$	19,374
Supplemental Schedule of Non-Cash Investing and Financing Transactions:
Increase (Decrease) in Capital Accrued Balance	$	(487,323	)	$	(94,546	)
Series B Paid-In-Kind Dividends	$	762,900		$	734,725
Issuance of Common Stock for Accrued Compensation Expense	$	-		$	-

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

F-8

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 17 – Supplemental Information About Oil and Gas Producing Activities (Unaudited) 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. At December 31, 2020, the Company has $1.529 million in Long Lived Assets Held for Sale.

The Company’s 2020 consolidated financial statements reflect a working capital deficiency of $4,044,437 and a net loss from operations of $2,674,329. 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.

F-9

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.

Correction of Immaterial Errors in Previously Issued Financial Statements

Subsequent to the issuance of the consolidated financial statements for the year ended December 31, 2019, the Company concluded that the Statement of Cash Flows for the year ending December 31, 2019, contained immaterial errors related to the classification of payments arising from operating leases and to the quantification of the amount of capital expenditures that had been accrued for but not yet paid. These immaterial errors have been corrected for the comparative period, resulting in an increase in cash flows used in operating activities of $239,362; an increase in cash flows provided by investing activities of $94,546; and a decrease in cash flows used in financing activities of $144,816 for the period ending December 31, 2019. These immaterial errors did not have any impact on our financial position, net loss or total cash flow for the period ending December 31, 2019.

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.

	Year Ended December 31,
	2020		2019
Cash and cash equivalents	$	255,112	$	1,031,014
Restricted cash		2,146,571		2,845,515
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows		2,401,683		3,876,529

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, 2020 and 2019, the Company established an allowance for uncollectable accounts of $2,582,093 and $1,791,162, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue. During 2020 and 2019, the Company closed a number of accounts as uncollectable, offsetting the allowance in the amount of $2,553 and $519,333 respectively.

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.

F-10

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. We evaluated our investment in RMX as of December 31, 2019, and determined that any losses were not other than temporary. 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.

	Year Ended December 31,
	2020		2019
Oil & Condensate Sales	$	1,184,680	$	1,504,936
Natural Gas Sales		357,587		824,339
NGL Sales		536		-
	$	1,542,803	$	2,329,275

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.

F-11

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

These amounts include proceeds from the Master Service Agreement (“MSA”) with RMX for the providing of land, engineering, accounting and support services for the RMX joint venture. Revenues earned under the MSA were recorded at the end of each month that services were performed, in conformity with the Agreement. The service fee income was deemed earned at the end of each month that services were performed as prescribed by the contract. On December 31, 2018, Royale received notice of cancelation of the MSA by RMX effective March 31, 2019. For the year ended 2019, the Company recognized $540,000 in supervisory fees from RMX. Also included in the caption are 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.

F-12

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 2020 there were no impairment losses, while 2019 the Company recorded impairment losses of $977,682, on various capitalized base and land costs as well as certain fields acquired through the merger with the matrix entities.

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.

F-13

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:

● Management has committed to a plan to sell the asset;

● The asset group is available for immediate sale in its present condition;

● An active program is underway to locate potential buyers;

● The sale is probable within one year;

● The asset group is being marketed at a price that is reasonable relative to its current fair value; and

● Actions required to complete the plan indicate that it is unlikely that significant changes to the plan will be made or the plan will be withdrawn.

Assets held for sale are carried at the lower of cost or fair market value less cost of disposal in current assets. If 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, 2020 and 2019, Royale Energy had Deferred Drilling Obligations of $ 3,127,500 and $5,232,675, respectively.

If Royale Energy is unable to drill the wells, and a suitable replacement well is not found, Royale would retain the non-refundable portion of the 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.

F-14

Income (Loss) Per Share

Basic and diluted losses per share are calculated as follows:

	Year Ended December 31,
	2020						2019
	Basic			Diluted			Basic			Diluted
Net Loss	$	(8,148,147	)	$	(8,148,147	)	$	(348,383	)	$	(348,383	)
Less: Preferred Stock Dividend		762,900			762,900			734,725			734,725
Less: Preferred Stock Dividend in Arrears		-			-			-			-
Net Loss Attributable to Common Shareholders		(8,911,047	)		(8,911,047	)		(1,083,108	)		(1,083,108	)
Weighted average common shares outstanding		53,292,647			53,292,647			50,871,447			50,871,447
Effect of dilutive securities		-			-			-			-
Weighted average common shares, including Dilutive effect		53,292,647			53,292,647			50,871,447			50,871,447
Per share:
Net Loss	$	(0.17	)	$	(0.17	)	$	(0.02	)	$	(0.02	)

For the years ended December 31, 2020 and 2019, Royale Energy had dilutive securities of 25,137,267 and 23,947,519 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.

F-15

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, 2020 and 2019, 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, 2020 and 2019, the components of accounts payable and accrued expenses consisted of:

	2020		2019
Trade Payables including accruals		2,264,562		3,107,012
Direct working interest investors related accruals		1,277,428		1,811,649
Current drilling efforts accrued expenses		20,924		508,246
Accrued Liabilities		391,434		393,245
Employee related accruals		196,014		195,998
Deferred rent		10,747		14,884
Federal and State income taxes payable		-		-
		4,161,109		6,031,034

Accrued – Non-current

At December 31, 2020, the Company had non-current accrued liabilities of $1,306,605 and accrued unpaid guaranteed payment of $1,616,205, due to certain Matrix principals, from periods prior to the merger with the Matrix entities during March of 2018.

Business Combinations

From time-to-time, the Company acquires businesses in the oil and gas industry. Royale primarily targets businesses in geological basins that the Company considers to be in a focus area. Businesses are included in the consolidated financial statements from the date of acquisition.

F-16

We recognize, separately from goodwill, the identifiable assets acquired and liabilities assumed at their estimated acquisition-date fair values. We measure and recognize goodwill as of the acquisition date as the excess of: (1) the aggregate of the fair value of consideration transferred, the fair value of any noncontrolling interest in the acquiree (if any) and the acquisition date fair value of our previously held equity interest in the acquiree (if any), over (2) the fair value of assets acquired and liabilities assumed. If information about facts and circumstances existing as of the acquisition date is incomplete by the end of the reporting period in which a business combination occurs, we report provisional amounts for the items for which the accounting is incomplete. The measurement or allocation period ends once we receive the information we are seeking; however, this period will generally not exceed one year from the acquisition date. Any material adjustments recognized during the measurement period will be reflected retrospectively in the consolidated financial statements of the subsequent period. We recognize third-party transaction-related costs as expense currently in the period in which they are incurred.

Changes in Accounting Standards

Recently Adopted

ASU 2017-04, Simplifying the test for goodwill impairment

In January 2017, FASB issued Accounting Standards Update (ASU) 2017-04, Intangibles—Goodwill and Other (Topic 350), Simplifying the Test for Goodwill Impairment, which eliminated the calculation of implied goodwill fair value. This guidance simplifies the accounting as compared to prior Generally Accepted Accounting Principles “GAAP.” This ASU was effective for SEC filers beginning after December 15, 2019. Adoption of this standard did not have a material impact on our consolidated financial statements.

ASU 2018-13, Changes to the fair value disclosure requirements

In August 2018, FASB issued ASU 2018-13, Fair Value Measurement (Topic 820), Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement. This pronouncement modifies, eliminates and adds disclosure requirements for fair value measurements. This ASU was effective for SEC filers beginning after December 15, 2019. Adoption of this standard did not have a material impact on our consolidated financial statements.

ASU 2020-04, Changes to the fair value disclosure requirements

In March 2020, FASB issued ASU 2020-04, Reference Rate Reform (Topic 848), Facilitation of the effects of Reference Rate Reform on Financial Reporting. This pronouncement provides optional expedients and exceptions for applying GAAP to contract modifications, hedging relationships, and other transactions affected by the anticipated transition away from LIBOR. This new ASU is eligible to be applied upon release and has various transition requirements. The Company acquired certain hedge contracts with the merger with the Matrix Companies in 2018. Those hedge contracts were transferred to RMX with the formation of the RMX Joint Venture as more fully described in Note 2 – RMX Joint Venture. The transition from LIBOR currently taking place in the financial markets will not have any impact on the Company or its existing financial instruments or agreements.

ASU 2018-18, Clarifying the interaction between ASC 808 and ASC 606

In November 2018, FASB issued ASU 2018-18, Collaborative Arrangements (Topic 808). This pronouncement clarifies that certain transactions between collaborative partners should be accounted for as revenue under Topic 606 (Revenue Recognition) when one is a customer of the other. Adoption of this standard did not have a material impact on our consolidated financial statements.

F-17

Not Adopted

ASU 2016-13, Credit Impairment

In June of 2016, the FASB issued ASC Topic 326, Financial Instruments – Credit Losses. This new guidance replaces the current incurred loss impairment model with a requirement to recognize lifetime expected credit losses immediately when a financial asset is originated or purchased. This new Current Expected Credit Losses (“CECL”) model applies to (1) loans, accounts receivable, trade receivables, and other financial assets measured at amortized cost, (2) loan commitments and certain other off-balance sheet credit exposures, (3) debt securities and financial assets measured at fair value, and (4) beneficial interests in securitized financial assets. This ASU was effective for SEC filers beginning after December 15, 2019; however, on November 15, 2019, the FASB issued ASU 2019-10, which delayed the effective date for “smaller reporting companies.” Therefore, ASU 2016-13 is effective for "smaller reporting companies" (as defined by the Securities and Exchange Commission) such as Royale, for fiscal years beginning after December 15, 2022, including interim periods within those years, and must be adopted under the modified retrospective method. Entities may adopt ASU 2016-13 earlier as of the fiscal years beginning after December 15, 2018, including interim periods within those years. Adoption of this standard is not expected to have a material impact on our consolidated financial statements and cash flows.

NOTE 2 – RMX JOINT VENTURE

RMX Joint Venture

On April 13, 2018, Royale Energy, Inc., and two of Royale’s subsidiaries, Royale Energy Funds, Inc. and Matrix Oil Management Corporation (the “Royale Entities”) completed  the Subscription and Contribution Agreement (“Contribution Agreement”), in which the Royale Entities and CIC RMX LP (“CIC”) entered into the Contribution Agreement and certain other agreements providing that the Royale Entities would contribute certain assets to RMX Resources, LLC (“RMX”), a newly formed Texas limited liability company formed to facilitate the investment from CIC.  In exchange for its contributed assets, Royale received a 20% equity interest in RMX, an equity performance incentive interest and up to $20.0 million to pay off Royale Entities senior lender, Arena Limited SPV, LLC., in full, and to pay Royale Entities trade payables and other outstanding obligations. CIC contributed an aggregate of $25.0 million in cash to RMX in exchange for (i) an 80% equity interest in RMX with preferred distributions until certain thresholds are met, (ii) a warrant (“Warrant”) to acquire up to 4,000,000 shares of Royale’s common stock at an exercise price of $.01 per share and registration rights pursuant to a Registration Rights Agreement.

RMX has a six-member board of managers. Royale has two seats on the board giving it a third of the Board.  Royale has designated Michael McCaskey and Johnny Jordan as its members of the RMX board.  The return targets for CIC through its funding of RMX provide for a “waterfall” style return profile with the first distributions going to CIC until it has received all Unpaid Preferred Return and Unpaid Preferred Enhanced Return, as defined by the Company’s Agreement.

Royale accounts for its ownership interest in RMX following the equity method of accounting, in accordance with ASC 323, Investments—Equity Method and Joint Ventures.

Under the provisions of the Amended and Restated Limited Liability Company Agreement of RMX Resources, LLC (“RMX Agreement”) dated March 27, 2018, the gains and losses of the partnership are distributed as if all of RMX’s assets were sold for cash at a price equal to their book basis and all RMX liabilities were satisfied at their book basis and all of the remaining assets of RMX were distributed in accordance with Section 5.4 of the RMX Agreement. Notwithstanding the above, for each fiscal year or other relevant period, deductions attributable to exploration costs, IDCs, and operating and maintenance costs shall be allocated 100% to the CIC members pro rata in accordance with their Class B percentage interests for each fiscal year.

RMX Joint Venture MSA

As part of the joint venture, RMX entered into a Master Service Agreement (“MSA”) calling for Royale Energy to provide land, engineering and support services for the joint venture.  For these services, Royale received $180,000 per month for the period April 2018 through March 2019.  These amounts are included in Supervisory Fees, Service Agreement and Other as more fully described in Note 1.

On December 31, 2018, Royale was formally notified of RMX’s intent to terminate the MSA as of March 31, 2019. The Termination Notice called for Royale to continue to provide accounting and other services through March 31, 2019.

F-18

RMX Joint Venture Post-Closing

On March 11, 2019, Royale entered into a Settlement Agreement with RMX Resources to resolve differences resulting from the calculation of certain post-closing amounts as called for under Section 7.3 of the Subscription and Contribution Agreement. In settlement of these differences, Royale agreed to assign its remaining interests in the Bellevue Field, located in Kern County and the W. Whittier Field located in Los Angeles County, California to RMX. These fields accounted for 5.145 and 140.647 Mboe in reserves and were valued at $67,671 and $2.4 million, respectively using SEC pricing and discounted at 10 percent at December 31, 2018.

Royale continues to be liable for the payment of all royalties and suspended funds incurred prior to March 1, 2018. Also, as part of this Settlement Agreement, RMX will offer Royale the right, but not the obligation to participate in a portion of the working interest, in a number of wells to be drilled in the Sansinena, Sempra, Whittier and/or East LA properties in Los Angeles County, California. The minimum number of wells to be offered to Royale in each year is 2 net wells as determined by an agreed upon methodology. The Agreement also calls for certain credits toward future drilling costs of the offered wells. The Company recorded a loss of $1,237,126 on the settlement, recorded in Loss on Sale of Assets in the Statement of Operations during 2019.

In conjunction with the merger between the Matrix entities and Royale, there were $1,254,204 of assets included on the books of Matrix for which documentary support could not be identified. At December 31, 2018, the Company concluded that these amounts were a contingent liability and recorded them in Current - Accrued Liabilities. On October 11, 2019, the Company received documentary support enabling management to conclude that the liability was no longer probable and should be derecognized. The Company recorded a gain of $1,254,204 on extinguishment, recorded in Loss on Sale of Assets in the Statement of Operations during 2019.

The RMX Joint Venture, like any Joint Venture investment following the equity method, is subject to ASC 323-10-35-31 and 32, impairment testing. During the 4th quarter of 2020, Royale received the RMX engineering reserve report prepared by an independent outside engineering firm. The report reflected reserve values for RMX that were below the Company’s expectations. As a result, of this and on-going market conditions along with the contractual terms of Royale’s investment in RMX, management performed an impairment test. Royale considered the waterfall formula as called for under its agreements with RMX as well as the preferred return owed to other partners. As part of this computation, Royale applied a discounted cash flow test as called for under ASC 820-10-55-5(c) and 5(d) incorporating the time value of money and risk premium. In our test, we considered factors including, most significantly, the estimated market value of the reserves of RMX and the amount of preferred return owed to other partners. As a result of this analysis and the fact that Management does not believe the values reflected in this most recent reserve report are temporary, Royale does not expect to realize the entire carrying amount of the RMX investment. Therefore, the entire amount of $6,185,995 is impaired and was taken to the Statement of Operations.

Additional reasons that Royale considers this impairment to be permanent is that these assets are located in California close to urban dwellings and subject to increasing regulatory scrutiny. Further, the current state administration has indicated a strong desire to impose increasing regulations on oil and gas producing properties thereby reducing their economic value.

Because the Company does not expect the value of the RMX Joint Venture to improve to a level where the water-fall profit sharing formula will provide value to Royale, the Company is no longer providing summarized financial information on the RMX investment in its financial statements or its reserve disclosures.

Listed below is summarized information the Company’s investment in RMX:

	Twelve Months Ended December 31, 2020			Twelve Months Ended December 31, 2019
	RMX Resources, LLC			RMX Resources, LLC
Balance Sheet:
Total Assets	$	77,168,147		$	72,401,841
Total Liabilities	$	46,213,651		$	41,573,426
Members Equity	$	30,954,496		$	30,828,415
Results of Operations:
Net operating revenue	$	9,376,395		$	16,392,305
Income (Loss) from operations	$	(3,352,584	)	$	1,456,290
Net income	$	126,081		$	(2,091,239	)

F-19

NOTE 3 – OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES

Oil and gas properties, equipment and fixtures consist of:

	Year Ended December 31,
	2020			2019
Oil and Gas
Producing properties, including intangible drilling costs	$	5,672,457		$	7,792,156
Undeveloped properties		13,993			46,990
Lease and well equipment		3,317,718			3,304,565
	$	9,004,168		$	11,143,711
Accumulated depletion, depreciation and amortization		(6,467,626	)		(6,559,182	)
Net capitalized costs Total		2,536,542			4,584,529

Commercial and Other	2020			2019
Real estate, including furniture and fixtures	$	-		$	-
Vehicles		40,061			40,061
Furniture and equipment		1,097,428			1,097,428
		1,137,489			1,137,489
Accumulated depreciation		(1,133,030	)		(1,131,028	)
		4,459			6,461
Net capitalized costs Total	$	2,541,001		$	4,590,990

The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed at December 31:

	Year Ended December 31,
	2020		2019
Acquisition - Proved		-		-
Acquisition - Unproved		-		-
Development		5,306,639		9,680,298
Exploration		-		-

The guidance set forth in the Continued Capitalization of Exploratory Well Costs paragraph of the Extractive Activities Topic of the FASB ASC requires that we evaluate all existing capitalized exploratory well costs and disclose the extent to which any such capitalized costs have become impaired and are expensed or reclassified during a fiscal period. We did not make any additions to capitalized exploratory well costs pending a determination of proved reserves during 2020 and 2019. We did not charge any previously capitalized exploratory well costs to expense upon adoption of Topic.  Undeveloped properties are not subject to depletion, depreciation or amortization.

	Year Ended December 31,
	2020		2019
Beginning balance at January 1		-		-
Additions to capitalized exploratory well costs pending the determination of proved reserves		-		-
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves		-		-
Ending balance at December 31		-		-

F-20

Results of Operations from Oil and Gas Producing and Exploration Activities

The results of operations from oil and gas producing and exploration activities (excluding corporate overhead and interest costs) are as follows:

	Year Ended December 31,
	2020			2019
Oil and gas sales	$	1,542,803		$	2,329,275
Production-related costs (Lease Operating)		(1,397,673	)		(1,764,538	)
Impairment		-			(977,682	)
Depreciation, depletion and amortization		(473,647	)		(468,143	)
Results of operations from producing and exploration activities	$	(328,517	)	$	(881,088	)
Income Taxes (Benefit)		-			-
Net Results	$	(328,517	)	$	(881,088	)

NOTE 4 – ASSET RETIREMENT OBLIGATION

The Asset Retirement and Environmental Obligations Topic of the ASC 410-20 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset.  The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset.  The ARO is recorded at the estimated fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value. Accretion expense is included as part of Depreciation, Depletion and Amortization in the Consolidated Statement of Operations. The fair value (as provided in ASC 820 guidance) of the ARO is measured using expected future cash outflows discounted at the Company’s credit-adjusted risk-free interest rate.  The provisions of this Topic apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, development, and operation of a long-lived asset. There were no changes in estimates for the year ended December 31, 2020. During the year ended December 31, 2019, the Company recorded $922,698 in increased costs related to estimates for abandonment of its’ share of certain California oil properties. These estimates relate to properties likely to be abandoned in the current period. As a result, the Company recorded them as impairment expense at year end 2019.

	2020			2019
Asset retirement obligation
Beginning of the year	$	3,632,422		$	2,366,456
Liabilities incurred during the period		29,323			210,643
Settlements		(508,538	)		-
Merger Additions		-			-
Sales		-			(33,026	)
Changes in estimates		-			922,698
Accretion expense		194,290			165,651
Reclassification to ARO - current		(869,147	)		-
End of year	$	2,478,350		$	3,632,422

The Company records accretion expense as part of Depreciation, Depletion and Amortization

NOTE 5 – NOTES PAYABLE

On October 3, 2018, the Company issued a promissory note for a principal amount of $517,585 to Forza Operating, LLC. At an interest rate of 5.5%. Beginning October 3, 2018, principal and interest is due and payable in 12 monthly installments of $44,428. The note was the result of an agreement regarding the plugging and abandonment of the CL&F #1 and the CL&F #1 SWD wells. The Company agreed to include the current joint interest billing balance due to Forza Operating of $233,367 and Royale’s share of future plugging and abandonment costs of $284,218. At December 31, 2020 and 2019, Royale Energy had Notes Payable of $132,624 and $55,573, respectively, as a current liability.

F-21

On November 2, 2020, in conjunction with the PPP loan forgiveness described in Note 16 – Coronavirus Aid, Relief, And Economic Security Act (“CARES Act”), Royale’s entered into a loan for $10,054 to be repaid through monthly interest and principal payments of $560 beginning December 1, 2020, with the final payment of $613 scheduled for April 23, 2022. The loan is being amortized over 18 months at an annual interest rate of 1.00 percent with the last payment being a balloon payment to complete the loan repayment.

NOTE 6 – INCOME TAXES

Deferred tax assets and liabilities reflect the net tax effect of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and amounts used for income tax purposes.  Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more-likely-than-not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.  In 2016, the Company adopted Accounting Standards Update (ASU) 2015-17 and has classified all of its deferred tax assets and liabilities as noncurrent on its balance sheet.

On December 22, 2017, the U.S. enacted significant changes to U.S. tax law following the passage and signing of H.R.1, An Act to Provide for Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018 (the “Tax Act”). The Tax Act permanently reduces the U.S. federal corporate tax rate from a maximum 35% to 21%, eliminated corporate Alternative Minimum Tax, modified rules for expensing capital investment, and limits the deduction of interest expense for certain companies. ASC 740 requires filers to record the effect of tax law changes in the period enacted. However, the SEC issued Staff Accounting Bulletin (“SAB”) 118 that permits filers to record provisional amounts during a measurement period ending no later than one year from the date of enactment. For the period ending December 31, 2018, the Company re-measured the applicable deferred tax assets based on the rates at which they are expected to reverse. The gross deferred tax assets and liabilities have been adjusted and a corresponding offset has been recorded to the full valuation allowance against the Company’s net deferred tax assets, which resulted in no net effect to its provision for income taxes and effective tax rate. No other provisional adjustments have been made as a result of the Act.

Significant components of the Company’s deferred assets and liabilities at December 31, 2020 and 2019, respectively, are as follows:

	2020			2019
Deferred Tax Assets (Liabilities):
Statutory Depletion Carry Forward	$	361,444		$	367,149
Net Operating Loss		7,361,230			6,489,891
Other		583,281			595,990
Share-Based Compensation		86,510			86,510
Capital Loss / AMT Credit Carry Forward		9,458			9,458
Charitable Contributions Carry Forward		3,396			3,890
Allowance for Doubtful Accounts		671,861			466,060
Oil and Gas Properties and Fixed Assets		4,860,069			5,404,787
Investment in RMX Joint Venture		342,569			(1,238,551	)
Section 481(a) Adjustments		(107,432	)		(214,859	)
	$	14,172,386		$	11,970,325
Valuation Allowance		(14,172,386	)		(11,970,325	)
Net Deferred Tax Asset	$	-		$	-

The Company recorded a full valuation allowance against the net deferred tax assets in 2016.  At the end of 2017, management reviewed the reliability of the Company’s net deferred tax assets, and due to the Company’s continued cumulative losses in recent years, Royale and its management concluded it is not “more-likely-than-not” its deferred tax assets will be realized.  As a result, the Company will continue to record a full valuation allowance against the deferred tax assets in 2019.  The Company will assess the realizability of the deferred tax assets at least yearly and make appropriate updates as needed.  Royale Energy, Inc. and its subsidiaries have available net operating loss carryforwards of $27.5 million generated in tax years ended before January 1, 2018, which if not utilized, begin to expire in the year 2027. Royale Energy, Inc. has no net operating loss carryforwards generated after December 31, 2017, which can be carried forward indefinitely.

F-22

A reconciliation of Royale Energy’s provision for income taxes and the amount computed by applying the statutory income tax rates at December 31, 2020 and 2019, respectively, to pretax income is as follows:

	2020			2019
Tax (benefit) computed at statutory rate of 21% at December 31, 2020 and 2019, respectively	$	(1,708,463	)	$	(71,680	)
Increase (decrease) in taxes resulting from:
Meals & Entertainment		740			1,583
PPP Loan Forgiveness		(41,538	)		-
Prior-year true-up for Books		(126,541	)		1,461,914
Deferred State Taxes, net of federal benefit		(330,367	)		214,161
Other non-deductible expenses		4,108			59,674
Change in valuation allowance		2,202,061			(1,665,652	)
Provision (benefit)		-			-

The components of the Company’s tax provision are as follows:

	2020		2019
Current tax provision (benefit) - federal	$	-	$	-
Current tax provision (benefit) - state		-		-
Deferred tax provision (benefit) - federal		-		-
Deferred tax provision (benefit) - state		-		-
Total provision (benefit)	$	-	$	-

In January 2007, Royale adopted additional provisions from the Income Taxes Topic of the ASC, which clarified the accounting for uncertainty in income taxes recognized in an entity’s financial statements and prescribes a recognition threshold and measurement attribute for financial statement disclosure of tax positions taken or expected to be taken on a tax return.  As a result of our implementation of the Topic at the time of adoption and at December 31, 2018, the Company did not recognize a liability for uncertain tax positions.  Currently, the only differences between our financial statements and our income tax returns relate to normal timing differences such as depreciation, depletion and amortization, which are recorded as deferred taxes on our balance sheets. We do not expect our unrecognized tax benefits to change significantly over the next 12 months. The tax years 2013 through 2018 remain open to examination by the taxing jurisdictions in which we file income tax returns.

NOTE 7 – SERIES B PREFERRED STOCK

Pursuant to the terms of the Merger all Class A limited partnership interests of Matrix Investments, LP (“Matrix Investments”) were exchanged for Royale Common stock using conversion ratios according to the relative value of the Class A limited partnership interests, and $20,124,000 of Matrix Investments preferred limited partnership interests were converted into 2,012,400 shares of Series B Convertible Preferred Stock of Royale. The Board of Directors of Royale Energy, prior to the merger, authorized 3,000,000 shares of Series B Convertible Preferred, which carries a liquidation preference and a 3.5% annual dividend, payable quarterly in cash or Paid-In-Kind (“PIK”) shares. The Series B Convertible Preferred Stock is convertible at the option of the security holder at the rate of ten shares of common stock for one share of Series B Convertible Preferred Stock. The Series B Preferred Stock has never been registered under the Securities Exchange Act of 1934, and no market exists for the shares. Additionally, the Series B Convertible Preferred shares will automatically convert to common at any time in which the Volume Weighted Average Price (“VWAP”) of the common stock exceeds $3.50 per share for 20 consecutive trading days, the shares are registered with the SEC and the volume of common shares trades exceeds 200,000 shares per day. The shareholders of the Series B Convertible Preferred may vote the number of shares into which they would be entitled to convert, beginning in 2020.

In accordance with ASC 480-10-S99-1.02, the Company has determined that the conversion or redemption of these shares are outside the sole control of the Company and that they should be classified in mezzanine or temporary equity as redeemable noncontrolling interest beginning at the reporting period, ended March 31, 2020.

For 2020 and 2019, the board authorized the payment of each quarterly dividend of Series B Convertible Preferred shares, as Paid-In-Kind shares (“PIK”) to be paid immediately following the end of the quarter. For the 12 months ending December 31, 2020, the Company issued 76,290 shares with a value of $762,900. During 2020 and 2019, no cash was used to pay dividends on Series B preferred shares.

F-23

NOTE 8 – COMMON STOCK

During the year 2020 and 2019, the Company issued shares of its Common Stock in lieu of cash payments for salaries, fees or incentives to various officers and board members, including our CEO.

NOTE 9 – OPERATING LEASES

The Company has two office leases. One at 1870 Cordell Court, El Cajon, California, the location of its corporate offices and one at 104 W. Anapamu, Santa Barbara, California, the location of the Company’s CEO and engineering team. The corporate office lease was entered into on August 31, 2016 and expires on October 31, 2021, with initial monthly payments of $6,148 with escalations. The lease in Santa Barbara was initiated in December of 2006 and, through several extensions and renewals, will expire in March of 2022.

The Company has elected the short-term lease recognition exemption for all leases that qualify. This means, for those leases that qualify, we will not recognize ROU assets or lease liabilities, and this includes not recognizing ROU assets or lease liabilities for existing short-term leases of those assets in transition. We also currently expect to elect the practical expedient to not separate lease and non-lease components for all of our finance leases. For our real estate operating leases, we have only considered the fixed portion of our lease payment commitment and have excluded the variable components from the capitalized ROU and lease liability.

Lease expense for operating as well as finance leases are included in General and Administrative expense and interest expense on the Consolidated Statement of Operations, while the lease expense for those leases that are short-term are included in Oil and Gas Lease Operating Expenses. The amounts are as follows:

	Year Ended December 31,
	2020		2019
Operating lease expense		200,836		184,374
Financing lease expense		19,137		10,757
Operating - short-term		-		7,886
Short Term - field		6,000		6,000
Total lease expense		225,973		209,017

The following tables summarized the operating and financing lease obligations.

Lease Obligations	Operating Lease Obligations		Financing Lease Obligations		Total Lease Obligations
2021	$	179,630		12,588		192,218
2022		24,408		12,588		36,996
2023		-		12,588		12,588
Thereafter		-		7,343		7,343
Total undiscounted lease payments	$	204,038		45,107		249,145
Less:  Amount representing interest		13,679		4,409		18,088
Total Operating & Financing lease liabilities	$	190,359		40,698		231,057
Current lease liabilities as of December 31, 2020	$	167,578		10,542		178,120
Long-term lease liabilities as of December 31, 2020	$	22,781		30,156		52,937

NOTE 10 – RELATED-PARTY TRANSACTIONS

Significant Ownership Interests

Our Chief Executive, Johnny Jordan, has accrued certain unpaid salaries, which were assumed by the Company. At December 31, 2020, Mr. Jordan was owed $14,648, in accrued unpaid guaranteed payments.

Our Chief Financial Officer, Stephen Hosmer, has participated individually in 179 wells under the 1989 policy.  During 2020 and 2019, Stephen did not participate in fractional interests.  At December 31, 2020, the Company had a receivable balance of $17,101 due from Stephen Hosmer for normal drilling and lease operating expenses.

F-24

Donald Hosmer has participated individually in 179 wells under the 1989 policy. During 2020 and 2019, Donald did not participate in fractional interests. At December 31, 2020, Royale had a receivable balance of $5,385 due from Donald Hosmer for normal drilling and lease operating expenses.

At December 31, 2020 and 2019, we had a total payable of $23,087 and $32,367, respectively, 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 periods, the Company also had prepaid expenses and other current assets of $239,036 and $2,680,155, respectively. The prepaid amount where primarily for the drilling of wells.

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, 2020, the balance due was $1,306,605.

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 is a director.

NOTE 11 – STOCK COMPENSATION PLAN

There were no stock options issued during 2020 and 2019.

NOTE 12 – SIMPLE IRA PLAN

In April 1998, the Company established a Simple IRA pension plan covering all employees. The Company will contribute a matching contribution to each eligible employee’s Simple IRA equal to the employee’s salary reduction contributions up to a limit of 3% of the employee’s compensation for the year. The employer contribution for the years ending December 31, 2020 and 2019, were $41,921 and $30,336 respectively.

NOTE 13 – ENVIRONMENTAL MATTERS

Royale Energy has established procedures for the continuing evaluation of its operations to identify potential environmental exposures and ensure compliance with regulatory policies and procedures. Management monitors these laws and regulations and periodically assesses the propriety of its operational and accounting policies related to environmental issues. The nature of Royale Energy’s business requires routine day-to-day compliance with environmental laws and regulations. Royale Energy incurred no material environmental investigation, compliance and remediation costs in 2020 or 2019.

Royale Energy is unable to predict whether its future operations will be materially affected by these laws and regulations. It is believed that legislation and regulations relating to environmental protection will not materially affect the results of operations of Royale Energy.

NOTE 14 – CONCENTRATIONS

The Company bids its gas sales on a month-to-month basis and generally sells to a single customer without commitment to future gas sales to any particular customer. The Company normally sells approximately 32% of its monthly natural gas production to one customer on a month-to-month basis.  Since we are able to sell our natural gas to other readily available customers, the loss of any one customer would not have an adverse effect on our overall sales operations.

The Company maintains cash in depository institutions that are guaranteed by the Federal Deposit Insurance Corporation (FDIC) up to $250,000 per institution for our interest-bearing accounts in the years ended December 31, 2020 and 2019.   At December 31, 2020 and 2019, cash in banks exceeded the FDIC limits by approximately $1.9 million and $3.4 million, respectively. The Company has not experienced any losses on deposits.

NOTE 15 – COMMITMENTS AND CONTINGENCIES

The Company may become involved from time to time in litigation on various matters, which are routine to the conduct of its business.  The Company believes that none of these actions, individually or in the aggregate, will have a material adverse effect on its financial position or results of operations, though any adverse decision in these cases or the costs of defending or settling such claims could have a material effect on its business.

F-25

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. The contracts require the participants pay Royale the full contract price upon execution of the agreement. Royale typically begins the drilling activities within 12 months of funding and reaches total depth between 10 and 30 days after drilling begins.

NOTE 16 – CORONAVIRUS AID, RELIEF, AND ECONOMIC SECURITY ACT (“CARES ACT”)

In December 2019, a novel strain of coronavirus (which triggers a respiratory disease called COVID-19) was reported in Wuhan, China. The World health Organization has declared the outbreak to constitute a “Public Health Emergency of International Concern.” The COVID-19 outbreak has caused a major reduction in the consumption of hydrocarbon-based transportation fuels as airlines have grounded flights worldwide and countries around the world have asked residents to suspend automobile travel. In addition to a substantial loss of demand for crude oil, In March, Saudi Arabia entered into a price war with Russia and added additional supplies of crude oil to an already over supplied market. The result has been a precipitous decline in the price of crude oil received by the Company. As a result, the Company has seen a reduction in its oil and gas revenues and resulting cash flows for the year 2020.

The CARES Act provided tax benefits and potential loans/grants for businesses and non-profits. On April 13, 2020, the Company successfully completed the process to obtain a $207,800 PPP loan through the SBA with Bank of Southern California (“BSC”) under the CARES Act. The interest rate was 1.00 percent per year fixed with a two-year term and all payments deferred for six months subject to loan forgiveness as provided for under the CARES Act. On November 2, 2020, Royale’s loan with BSC was paid down by $198,846 ($197,800 in principal and $1,046 in interest) as a result of completing the process of loan forgiveness under the terms of the CARES Act. The loan balance of $10,054 will be repaid through monthly interest and principal payments of $560 beginning December 1, 2020, with the final payment of $614 scheduled for April 23, 2022. The loan is being amortized over 18 months at an annual interest rate of 1.00 percent with the last payment being a balloon payment to complete the loan repayment.

On the Statement of Cash Flows, the Company has shown this PPP loan as a cash inflow from financing activities, principal repayments as cash outflows from financing activities, and interest payments as outflows from operating activities.  The amounts of principal and interest forgiven are shown as reconciling items to net loss in determining net cash used in operating activities.

Under the updated regulations, the forgiveness of PPP loan in not taxable income. Additionally, expenses submitted in support of the PPP loan forgiveness remain deductible for the purpose of tax reporting. Prior IRS positions in Notice 2020-32 and Rev Ruling 2020-27 no longer apply.

NOTE 17 – LONG-LIVED ASSETS HELD FOR SALE

Assets held for sale are carried at lower of cost or fair value less cost to sell. Listed below are the two current groups of properties that the Company has defined as long-lived assets held for sale in accordance with ASC 360-10-45.

East Los Angeles

The Company and its joint venture partner, RMX, have entered into a purchase and sales agreement as well as a second amendment to that certain purchase and sales agreement extending the closing date to the second quarter of 2021. The Company carries these assets on the books for $1.9 million with an ARO amount of approximately $1.1 million for the existing wells and facilities located on the properties providing a net book value of approximately $0.846 million. The sale would require the Company to plug and abandon the wells on the property and remove and restore the surface land with an estimated cost of $0.721 million. The sale price is approximately $1.0 million to the Company. Therefore, the Company will record a loss on the pending sale of these properties of $0.567 million and reflect Assets Held for Sale of $1.0 million reflected in current assets with an ARO balance of $0.721 million in current liabilities.

Texas Properties

The Company and its partners in these producing properties have exchanged document drafts of a purchase and sales agreement during 2021. The Company has a net book value for the properties of $0.381 million including an ARO liability of $0.149 million and expects to receive approximately $0.700 million at the consummation of the sale. Negotiations are ongoing with the sale expected to close during the second quarter of 2021. The Company is reflecting these properties at $0.529 million in Assets Held for Sale in current assets.

F-26

NOTE 18 – SUBSEQUENT EVENTS

The Company has evaluated subsequent events through March 30, 2021, the date these financial statements were available to be issued. The Company is not aware of any subsequent events which would require recognition or disclosure in the financial statements, except as noted below or already recognized or disclosed.

Texas Properties

The Purchase and Sales Agreement for the Texas properties was executed between all the parties on February 18, 2021, with closing anticipated in the 2nd quarter of 2021.

NOTE 19 – SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

The following estimates of proved oil and gas reserves, both developed and undeveloped, represent interests owned by Royale Energy which are located solely in the United States.  Proved reserves represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate to be reasonably certain to be recoverable in the future from known reservoirs under existing economic and operating conditions.  Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells, with existing equipment and operating methods.  Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which relatively major expenditures are required for completion.

Disclosures of oil and gas reserves, which follow, are based on estimates prepared by independent petroleum engineering consultant Netherland, Sewell & Associates, Inc., the net reserve value of its proved developed and undeveloped reserves was approximately $20.8 million at December 31, 2020, based on the average Henry Hub natural gas price spot price of $1.985 per MCF and for oil volumes, the average West Texas Intermediate price of $39.54 per barrel as applied on a field-by-field basis.  Netherland, Sewell & Associates, Inc. provided reserve value information for the Company’s California, Texas, Oklahoma, Utah and Louisiana properties. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures.  These estimates do not include probable or possible reserves.

The technical persons responsible for preparing the reserves estimates presented in the report of Netherland, Sewell & Associates, Inc., meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.  Netherland, Sewell & Associates, Inc. is a firm of independent petroleum engineers, geologists, geophysicists, and petrophysicists; and do not own an interest in our properties and are not employed on a contingent basis.  All activities and reports performed and completed by Netherland, Sewell & Associates, Inc. with regards to our reserve valuation estimates are reviewed Royale’s management.

These estimates are furnished and calculated in accordance with requirements of the FASB and the SEC.  Because of unpredictable variances in expenses and capital forecasts, crude oil and natural gas price changes, largely influenced and controlled by U.S. and foreign government actions, and the fact that the bases for such estimates vary significantly, management believes the usefulness of these projections is limited.  Estimates of future net cash flows presented do not represent Management’s assessment of future profitability or future cash flows to Royale Energy.  Management’s investment and operating decisions are based upon reserve estimates that include proved reserves prescribed by the SEC as well as probable reserves, and upon different price and cost assumptions from those used here.

It should be recognized that applying current costs and prices and a 10 percent standard discount rate does not convey absolute value.  The discounted amounts arrived at are only one measure of the value of proved reserves.

F-27

Changes in Estimated Reserve Quantities

The net interest in estimated quantities of proved developed reserves of crude oil and natural gas at December 31, 2020 and 2019, and changes in such quantities during each of the years then ended, were as follows:

Total Proved Reserves
	2020						2019
	Oil (BBL)			Gas (MCF)			Oil (BBL)			Gas (MCF)
Beginning of period		2,171,000			4,306,900			1,146,400			2,986,200
Revisions of previous estimates		(646,080	)		(1,515,637	)		1,052,086			(890,032	)
Production		(31,210	)		(160,406	)		(27,663	)		(292,472	)
Extensions, discoveries and improved recovery		47,290			29,643			22,042			2,516,046
Merger Acquisition								-			-
Purchase of minerals in place								-			-
Sales of minerals in place								(21,865	)		(12,842	)
Proved reserves end of period		1,541,000			2,660,500			2,171,000			4,306,900

Proved Developed
	2020				2019
	Oil (BBL)		Gas (MCF)		Oil (BBL)		Gas (MCF)
Proved developed reserves:
Beginning of period		232,200		2,790,300		148,600		1,914,900
End of period		224,900		691,900		232,200		2,790,300

Proved Undeveloped
	2020				2019
	Oil (BBL)		Gas (MCF)		Oil (BBL)		Gas (MCF)
Proved undeveloped reserves:
Beginning of period		1,938,800		1,516,600		997,800		1,071,300
End of period		1,316,100		1,968,600		1,938,800		1,516,600

At December 31, 2020, our previously estimated proved developed and undeveloped natural gas reserve quantities were revised downward by approximately 1,515,637 MCF of natural gas. This downward revision was mainly the result of a decrease in proved developed natural gas reserves from drilling locations which the Company had contracted.   At December 31, 2020, our previously estimated proved developed and undeveloped oil reserve quantities were revised downward by approximately 646,080 BBL of oil. This downward revision was mainly the result a decrease in the price of oil, which resulted in a decrease in the economic life.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The future net cash inflows are developed as follows:

• Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions.

• The estimated future production of proved reserves is priced on the basis of year-end prices.

• The resulting future gross revenue streams are reduced by estimated future costs to develop and to produce proved reserves, based on year-end estimates. Estimated future development costs by year are as follows:

F-28

2021	8,954,000
2022	6,750,000
2023	1,404,500
Thereafter	-
	17,108,500

The resulting future net revenue streams are reduced to present value amounts by applying a 10 percent discount.

Disclosure of principal components of the standardized measure of discounted future net cash flows provides information concerning the factors involved in making the calculation.  In addition, the disclosure of both undiscounted and discounted net cash flows provides a measure of comparing proved oil and gas reserves both with and without an estimate of production timing.  The standardized measure of discounted future net cash flow relating to proved reserves reflects estimated income taxes.

Changes in standardized measure of discounted future net cash flow from proved reserve quantities

The standardized measure of discounted future net cash flows is presented below for the years ended December 31, 2020 and 2019.

This statement discloses the sources of changes in the standardized measure from year to year. The amount reported as “Net changes in prices and production costs” represents the present value of changes in prices and production costs multiplied by estimates of proved reserves as of the beginning of the year. The “accretion of discount” was computed by multiplying the 10 percent discount factor by the standardized measure on a pretax basis as of the beginning of the year. The “Sales of oil and gas produced, net of production costs” are expressed in actual dollar amounts. “Revisions of previous quantity estimates” is expressed at year-end prices. The “Net change in income taxes” is computed as the change in present value of future income taxes.

	2020			2019
Future cash inflows		65,939,300			143,045,000
Future production costs		(28,008,100	)		(28,967,400	)
Future development costs		(17,108,400	)		(20,587,800	)
Future income tax expense		(6,246,840	)		(28,046,940	)
Future net cash flows		14,575,960			65,442,860
10% annual discount for estimated timing of cash flows		(7,134,925	)		(35,801,989	)
Standardized measure of discounted future net cash flows		7,441,035			29,640,871
Sales of oil and gas produced, net of production costs		(351,478	)		(624,744	)
Revisions of previous quantity estimates		(31,231,533	)		14,035,099
Net changes in prices and production costs		(617,847	)		(14,331,770	)
Sales of minerals in place		-			(272,507	)
Purchases of minerals in place					-
Merger Acquisition					-
Extensions, discoveries and improved recovery		587,311			2,157,052
Accretion of discount		(100,504	)		2,900,123
Net change in income tax		9,514,215			(4,868,296	)
Net increase (decrease)		(22,199,836	)		(1,005,043	)

F-29

Future Development Costs

In order to realize future revenues from our proved reserves estimated in our reserve report, it will be necessary to incur future costs to develop and produce the proved reserves.  The following table estimates the costs to develop and produce our proved reserves in the years 2021 through 2023.

	2021		2022		2023
Future development cost of:
Proved developed reserves (PDP)		-		-		-
Proved non-producing reserves (PDNP)		54,000		-		-
Proved undeveloped reserves (PUD)		8,900,000		6,750,000		1,404,500
Total		8,954,000		6,750,000		1,404,500

Common assumptions include such matters as the real extent and average thickness of a particular reservoir, the average porosity and permeability of the reservoir, the anticipated future production from existing and future wells, future development and production costs and the ultimate hydrocarbon recovery percentage.  As a result, oil and gas reserve estimates and discounted present value estimates are frequently revised in subsequent periods to reflect production data obtained after the date of the original estimate.  If the reserve estimates are inaccurate, production rates may decline more rapidly than anticipated, and future production revenues may be less than estimated.

Additional data relating to Royale Energy’s oil and natural gas properties is disclosed in Supplemental Information About Oil and Gas Producing Activities (Unaudited), attached to Royale Energy’s Financial Statements, beginning on page F-1.

Historic Development Costs for Proved Reserves

In each year we expend funds to drill and develop some of our proved undeveloped reserves.  We have incurred no cost in any of the past three fiscal years to drill and develop reserves that were classified as proved undeveloped reserves as of December 31 of the immediately preceding year.

F-30

EX-21.1

Exhibit 21.1

ROYALE ENERGY, INC.

SUBSIDIARIES

December 31, 2020

Royale Energy Funds, Inc

Matrix Permian Investment, L.P.

Matrix Las Cienegas L.P.

Matrix Investment, L.P.

Royale DWI Investors, LLC

Matrix Oil Management, Corp.

Matrix Pipeline, L.P. (Limited Partner only, General Partner is Matrix Oil Corp. part of the RMX Joint Venture)

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the inclusion of our report of Royale Energy, Inc. (the “Company”) dated February 3, 2021, in the Annual Report on Form 10-K for the year ended December 31, 2020, of the Company and its subsidiaries, to be filed with the Securities and Exchange Commission.

NETHERLAND, SEWELL & ASSOCIATES, INC.

By: /s/ Danny D. Simmons                             

Danny D. Simmons, P.E.

President and Chief Operating Officer

Houston, Texas

March 30, 2021

EX-31.1

Exhibit 31.1

I, Johnny Jordan, certify that:

1. I have reviewed this report on Form 10-K of Royale Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 30, 2021	By:	/s/ Johnny Jordan
		Johnny Jordan, Chief Executive Officer

EX-31.2

Exhibit 31.2

I, Stephen M. Hosmer, certify that:

1. I have reviewed this report on Form 10-K of Royale Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions)

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 30, 2021	By:	/s/ Stephen M. Hosmer
		Stephen M. Hosmer, Chief Financial Officer

EX-32.1

Exhibit 32.1

Certification Pursuant to 18 U.S.C. § 1350

The undersigned, Johnny Jordan, Chief Executive Officer of Royale Energy, Inc., a Delaware corporation (the “Company”), pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes Oxley Act of 2002, hereby certifies that:

(1) the Company’s Annual Report on Form 10-K for the year ended December 31, 2020 (the “Report”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: March 30, 2021	By:	/s/ Johnny Jordan
		Johnny Jordan, Chief Executive Officer

EX-32.2

Exhibit 32.2

Certification Pursuant to 18 U.S.C. § 1350

The undersigned, Stephen M. Hosmer, Co-President, Co-Chief Executive Officer and Chief Financial Officer of Royale Energy, Inc., a Delaware corporation (the “Company”), pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes Oxley Act of 2002, hereby certifies that:

(1) the Company’s Annual Report on Form 10-K for the year ended December 31, 2020 (the “Report”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: March 30, 2021	By:	/s/ Stephen M. Hosmer
		Stephen M. Hosmer, Chief Financial Officer

EX-99.1

Exhibit 99.1

February 3, 2021

Mr. Stephen M. Hosmer

Royale Energy, Inc.

1870 Cordell Court, Suite 210

El Cajon, California 92020

Dear Mr. Hosmer:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2020, to the Royale Energy, Inc. (Royale) interest in certain oil and gas properties located in California, Oklahoma, Texas, and Utah, as listed in the accompanying tabulations. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Royale. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, except that future income taxes are excluded and, as requested, abandonment costs have only been included in our estimates of future net revenue for proved undeveloped properties located in Jameson North Field, Texas. Definitions are presented immediately following this letter.

We estimate the net reserves and future net revenue to the Royale interest in these properties, as of December 31, 2020, to be:

	Net Reserves		Future Net Revenue (M$)
	Oil	Gas		Present Worth
Category	(MBBL)	(MMCF)	Total	at 10%
Proved Developed Producing	224.9	465.5	5,247.4	3,300.5
Proved Developed Non-Producing	0.0	226.3	201.8	174.8
Proved Undeveloped	1,316.1	1,968.6	15,373.6	7,523.9
Total Proved	1,541.0	2,660.5	20,822.8	10,999.3

Totals may not add because of rounding.

The oil volumes shown include crude oil and condensate. Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases. Oil equivalent volumes shown in this report are expressed in thousands of barrels of oil equivalent (MBOE), determined using the ratio of 6 MCF of gas to 1 barrel of oil.

Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. No study was made to determine whether probable or possible reserves might be established for these properties. The estimates of reserves and future revenue included herein have not been adjusted for risk. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.

As shown in the Table of Contents, this report includes summary projections of reserves and revenue by reserves category. Also included are reserves and economics data for each reserves category; these data include a summary projection of reserves and revenue along with one-line summaries of basic data, reserves, and economics by lease.

Gross revenue shown in this report is Royale's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Royale's share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2020. For oil volumes, the average West Texas Intermediate spot price of $39.54 per barrel is adjusted by field for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $1.985 per MMBTU is adjusted by field for energy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $39.96 per barrel of oil and $1.639 per MCF of gas.

Operating costs used in this report are based on operating expense records of Royale. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Headquarters general and administrative overhead expenses of Royale are included to the extent that they are covered under joint operating agreements for the operated properties. Operating costs are not escalated for inflation.

Capital costs used in this report were provided by Royale and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. For proved undeveloped properties located in Jameson North Field, Texas, abandonment costs used in this report are Royale's estimates of the costs to abandon the wells and production facilities, net of any salvage value. As requested, for all other properties, our estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties. Capital costs and abandonment costs are not escalated for inflation.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Royale interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Royale receiving its net revenue interest share of estimated future gross production. Additionally, we have made no specific investigation of any firm transportation contracts that may be in place for these properties; our estimates of future revenue include the effects of such contracts only to the extent that the associated fees are accounted for in the historical field- and lease-level accounting statements.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Royale, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the

estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for behind-pipe zones and undeveloped locations; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Royale, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

	Sincerely,
	NETHERLAND, SEWELL & ASSOCIATES, INC. Texas Registered Engineering Firm F-2699
	By:	/s/ C.H. (Scott) Rees III
		C.H. (Scott) Rees III, P.E.
		Chairman and Chief Executive Officer
By: /s/ C. Ashley Smith	By:	/s/ Shane M. Howell
C. Ashley Smith, P.E. 100560		Shane M. Howell, P.G. 11276
Vice President		Vice President
Date Signed: February 3, 2021		Date Signed: February 3, 2021

CAS:RQH

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

EX-99.2

 

Exhibit 99.2

RMX Resources, LLC
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM	2
CONSOLIDATED BALANCE SHEETS	3
CONSOLIDATED STATEMENTS OF OPERATIONS	5
CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY	6
CONSOLIDATED STATEMENTS OF CASH FLOWS	7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	8

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Managers of

RMX Resources, LLC

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of RMX Resources, LLC (the “Company”) as of December 31, 2020 and 2019, the related consolidated statements of operations, members’ equity and cash flows for the years 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 2019, and the consolidated results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

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 audits. 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 audits 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 audits 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 audits 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 audits 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 audits provide a reasonable basis for our opinion.

/s/ Moss Adams LLP

Dallas, Texas

March 30, 2021

We have served as the Company’s auditor since 2018.

2

RMX Resources, LLC

CONSOLIDATED BALANCE SHEETS

December 31, 2020 and 2019

ASSETS
	December 31,			December 31,
	2020			2019
CURRENT ASSETS
Cash and cash equivalents	$	3,363,834		$	1,559,897
Restricted cash		-			-
Accounts receivable:
Oil and gas sales		1,088,013			1,740,687
Joint interest billings		287,913			31,981
Receivable from Royale Energy short-term		431,849			298,794
Other		36,381			34,295
Prepaid expenses		226,636			214,476
Commodity derivatives short-term		12,942			-
Total current assets		5,447,568			3,880,130
OIL AND GAS PROPERTIES,
(successful efforts method)
Proved properties, subject to amortization		75,477,292			70,984,015
Other fixed assets		329,293			254,210
Less: Accumulated depreciation, depletion and amortization		(4,824,693	)		(2,962,793	)
Net oil and gas properties		70,981,892			68,275,432
OTHER ASSETS
Deposits		40,200			36,700
Commodity derivatives, long-term		-			209,579
Receivable from Royale Energy long-term		698,487			-
Total other assets		738,687			246,279
TOTAL ASSETS	$	77,168,147		$	72,401,841

3

RMX Resources, LLC

CONSOLIDATED BALANCE SHEETS

December 31, 2020 and 2019

LIABILITIES AND MEMBERS' EQUITY
	December 31,		December 31,
	2020		2019
CURRENT LIABILITIES
Trade payables	$	1,987,715	$	913,465
Royalties payable		867,935		902,176
Asset retirement obligations		345,636		492,709
Accrued liabilities		411,912		843,519
Advance from Royale		326,845		2,826,103
Commodity derivatives, short-term		-		334,960
Total current liabilities		3,940,043		6,312,932
LONG-TERM LIABILITIES AND DEBT
Secured term debt, net of unamortized loan costs		26,185,049		19,403,800
Commodity derivatives, long-term		442,836		-
Asset retirement obligations		15,645,723		15,856,694
Total long-term liabilities and debt		42,273,608		35,260,494
TOTAL LIABILITIES		46,213,651		41,573,426
MEMBERS' EQUITY
Members' Equity		30,954,496		30,828,415
Total member's equity		30,954,496		30,828,415
TOTAL LIABILITIES AND MEMBERS' EQUITY	$	77,168,147	$	72,401,841

4

RMX Resources, LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended			Year Ended
	December 31,			December 31,
	2020			2019
OPERATING REVENUES
Oil and gas sales, net	$	9,376,395		$	16,392,305
Net Operating Revenue		9,376,395			16,392,305
OPERATING EXPENSES
Oil and gas production costs		7,829,065			9,401,825
General and administrative expense		2,338,525			2,726,296
Depletion, depreciation and amortization		1,923,573			2,258,245
Accretion of asset retirement obligations		637,816			549,649
Total operating expense		12,728,979			14,936,015
Income (loss) from operations		(3,352,584	)		1,456,290
OTHER INCOME (EXPENSE)
Interest expense		(911,892	)		(1,260,948	)
Realized Gain on commodity derivatives, net		4,213,705			128,988
Unrealized (loss) on commodity derivatives, net		(304,512	)		(2,372,283	)
Gain on sale of oil and gas properties		473,382			-
Income tax expense		(26,503	)		(14,584	)
Other income (expense)		34,485			(28,702	)
Total other income (expense), net		3,478,665			(3,547,529	)
NET INCOME (LOSS)	$	126,081		$	(2,091,239	)

5

RMX Resources, LLC

CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY

December 31, 2019 and December 31, 2020

	Series A			Series B			Total
Balances at December 31, 2018	$	6,583,931		$	26,335,723		$	32,919,654
Net loss		(418,248	)		(1,672,991	)		(2,091,239	)
Balances at December 31, 2019	$	6,165,683		$	24,662,732		$	30,828,415
Net income		25,216			100,865			126,081
Balances at December 31, 2020	$	6,190,899		$	24,763,597		$	30,954,496

6

RMX Resources, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended			Year Ended
	December 31,			December 31,
	2020			2019
OPERATING
Net income (loss)	$	126,081		$	(2,091,239	)
Reconciliation of net income (loss) to net cash provided by
Operating activities
Depletion, depreciation and amortization		1,923,573			2,258,245
Accretion of discount on ARO		637,816			549,649
Amortization of deferred loan costs		31,249			31,250
Unrealized loss on commodity derivatives		304,512			2,372,283
Gain on sale of assets		(473,382	)		-
Changes in operating assets and liabilities
Accounts receivable		(419,653	)		21,874
Prepaid expenses		(12,160	)		17,999
Deposits		(3,500	)		(6,700	)
Payables		1,022,776			(852,594	)
Accrued liabilities		(2,930,865	)		3,061,259
Net cash provided by operating activities		206,447			5,362,026
INVESTING
Additions to oil and gas properties		(5,573,164	)		(2,887,684	)
Proceeds from sale of assets		420,654			-
Net cash used in investing activities		(5,152,510	)		(2,887,684	)
FINANCING
Borrowings under revolving lines of credit		6,750,000			5,500,000
Repayments under revolving lines of credit		-			(8,950,000	)
Net cash provided by (used in) financing activities		6,750,000			(3,450,000	)
Net increase (decrease) in cash and cash equivalents and restricted cash		1,803,937			(975,658	)
Cash and cash equivalents at beginning of year		1,559,897			2,535,555
Cash and cash equivalents at end of period	$	3,363,834		$	1,559,897
SUPPLEMENTAL DISCLOSURES:
Cash paid for:
Interest	$	871,480		$	1,229,698

7

RMX RESOURCES, LLC

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2020 and 2019

NOTE 1 – Organization and Basis of Presentation

Organization

RMX Resources, LLC, is a Texas limited liability company (“RMX”, or the “Company”) formed on March 27, 2018 with CIC RMX LP (“CIC”) as the sole member to acquire and develop onshore oil and gas reserves in certain fields in Los Angeles and Kern Counties of California. Pursuant to the Subscription and Contribution Agreement dated April 4, 2018, between RMX and Royale Energy, Inc. (‘Royale”), RMX acquired its initial oil and gas properties and its ownership of Matrix Oil Corporation (“MOC”), its wholly owned subsidiary.

Basis of Presentation and Consolidation

The accompanying consolidated financial statements of RMX and its wholly owned subsidiary, MOC, have been prepared in conformity with the generally accepted accounting principles of the United States of America (“GAAP”). Significant intercompany balances and transactions have been eliminated upon consolidation. The preparation of financial statements requires management to make estimates and assumptions that effect the reported amounts of assets and liabilities, the 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 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 and gas reserve volumes, future development costs and allowance for doubtful accounts.   Actual results could differ from those estimates.

Cash, Restricted Cash and Cash Equivalents

RMX considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. At times, the amount of cash and cash equivalents on deposit in financial institutions exceeds federally insured limits. We monitor the soundness of the financial institutions and believe the Company’s risk is negligible.

Accounts Receivable

Accounts receivable, joint interest billings, consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date. Accounts receivable, oil and gas sales, consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. No such allowance was considered necessary at December 31, 2020 or 2019.

Prepaid Expenses and Other Assets

Prepaid expenses represent expenditures that have not yet been recorded by the Company as an expense, but have been paid for in advance. The cost is charged to expense each month for which the future benefit is recognized.

8

RMX RESOURCES, LLC

Notes to Consolidated Financial Statements -- Continued

December 31, 2020 and 2019

Deposits

RMX maintains a rolling deposit for use in ongoing negotiations with governmental entities whereby the Company has agreed to assist those entities with costs which they might incur during those negotiations. This deposit will be maintained until numerous negotiations are concluded, which will likely take more than twelve months.

Royalties Payable

The Company receives gross proceeds from oil and gas sales. The proceeds include amounts due to royalty owners and are recorded as royalties payable until such time they are paid.

Revenue Recognition

Revenue is recognized when oil and gas is delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership and takes control of the product. Revenue is measured based on a consideration specified in a contract with a customer, and excludes any sales incentives and amounts collected on behalf of third parties. The Company recognizes revenue when it satisfies a performance obligation by transferring control over a product or service to a customer.

Taxes assessed by a governmental authority that are both imposed on and concurrent

with a specific revenue-producing transaction, that are collected by the Company from a

customer, are excluded from revenue. The Company bears no shipping and handling costs related to its sales of oil and gas.

The principal activity from which the Company generates its revenue is oil and gas sales by way of contracts with customers. Contracts with customers stipulate how the products are priced and payment terms. RMX generally sells crude oil and natural gas under short-term agreements at prevailing market prices. Prices are fixed or determinable and collectability is reasonably assured. Revenues from the production of oil and natural gas properties, in which RMX has an interest with other producers, are recognized on the basis of RMX’s net working interest. Differences between actual production and net working interest volumes are not significant. RMX’s financial statements reflect its pro rata ownership of wells.  

All oil and gas sales of the Company are generated in California. The following table presents disaggregated revenue by major sources for the year ended December 31, 2020 and 2019:

	2020		2019
Revenue
Oil	$	9,178,744	$	16,102,123
Gas		197,651		290,182
Total Revenue from contracts with customers	$	9,376,395	$	16,392,305

Dependence on Major Customers

For the year ended December 31, 2020, sales to Conoco Phillips accounted for approximately 68% of our total sales and PBF Holding Company accounted for approximately 18% of our total sales. RMX switch purchaser from PBF Holding Company to Plains Marketing LP for production month July 2020. Accounts receivable, oil and gas sales, from Conoco Phillips and Plains, amounted to 97% of the amount outstanding at December 31, 2020. For the year ended December 31, 2019, sales to Conoco Phillips accounted for approximately 66% of our total sales and PBF Holding Company accounted for approximately 29% of our total sales. Accounts receivable, oil and gas sales, from Conoco Phillips and PBF, amounted to 95% of the amount outstanding at December 31, 2019. Although we are exposed to a concentration of credit risk, we believe that our primary purchasers are credit worthy.

9

RMX RESOURCES, LLC

Notes to Consolidated Financial Statements -- Continued

December 31, 2020 and 2019

Oil and Gas Property and Equipment

RMX uses the successful efforts method to account for its development, exploration and production activities.  Under this method, RMX 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 all developmental wells and successful exploratory wells.   Maintenance and repair costs, including planned major maintenance, are expensed as incurred.  Major renewals and improvements are capitalized and the assets replaced are retired.

Interest costs, to the extent they are incurred to finance expenditures during the construction phase, are capitalized and included in amounts subject to depletion. The Company had no capitalized interest for any projects under this accounting policy during the reporting period.

RMX 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 RMX 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.

Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of gas to one barrel of oil equivalent (“Boe”), and one barrel of NGLs to one Boe. The ratios of six Mcf of natural gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe for natural gas may differ significantly from the price for a barrel of oil. Capitalized costs of proved mineral interests are depleted over total estimated proved reserves, and capitalized costs of wells and related equipment and facilities are depleted over estimated proved developed reserves.

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 point when custody transfers to the buyer. Production costs are those incurred to operate and maintain RMX’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 RMX are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable.

RMX 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. No impairment was indicated at December 31, 2020 or 2019.

10

RMX RESOURCES, LLC

Notes to Consolidated Financial Statements -- Continued

December 31, 2020 and 2019

Council of Petroleum Accounting Societies (“COPAS”) Overhead

The operations and accounting for oil and gas properties is governed by a Joint Operating Agreement. Most operating agreements call for the charging of an overhead rate to cover the cost of company personnel performing engineering, land and accounting functions to support the operations of the property. The amounts charged to properties as COPAS overhead are treated as a reduction to general and administrative expense.

Royalty Owner Transportation and Marketing Charges

Many lease agreements provide that oil and gas marketing and transportation expenses may be charged to the lease owner as a reduction to their royalty compensation. RMX regularly charges this amount to royalty owners and credits the amount through the joint owner billings to working interest participants.

Fair Value Measurements

According to Fair Value Measurements and Disclosures Topic of the FASB Accounting Standards Codification, 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.

Fair Value of Financial Instruments (other than Commodity Derivative Instruments, see below) – The carrying values of financial instruments, excluding commodity derivative instruments, comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments.

11

RMX RESOURCES, LLC

Notes to Consolidated Financial Statements -- Continued

December 31, 2020 and 2019

Derivatives – The fair values of the Company’s commodity derivatives are considered Level 2 as their fair values are based on third-party pricing models which utilize inputs that are either readily available in the public market, such as natural gas and oil forward curves and discount rates, or can be corroborated from active markets or broker quotes. These values are then compared to the values given by the Company’s counterparties for reasonableness. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which results in the Company using market prices and implied volatility factors related to changes in the forward curves. Derivatives are also subject to the risk that counterparties will be unable to meet their obligations.

Debt -- The Company’s debt is recorded at the carrying amount on its Consolidated Balance Sheets. For further discussion of the Company’s debt, please see Note 3 – Debt and Interest Expense. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates.

ARO Amounts - The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic 410, "Asset Retirement and Environmental Obligations" ("FASB ASC 410"). 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 a non-recurring Level 3 fair value measurement. See Note 2 for further discussion of the Company's asset retirement obligations.

Financial assets are considered Level 3 when their fair values are determined using pricing models, discounted cash flow methodologies or similar techniques, and at least one significant model assumption or input is unobservable.

	Fair value measurements at December 31, 2020
	Quoted	Significant
	prices	other			Significant
	in active	observable			unobservable
	markets	inputs			inputs
	(Level 1)	(Level 2)			(Level 3)	Total
Commodity derivatives - oil			(429,893	)			(429,893	)

	Fair value measurements at December 31, 2019
	Quoted	Significant
	prices	other			Significant
	in active	observable			unobservable
	markets	inputs			inputs
	(Level 1)	(Level 2)			(Level 3)	Total
Commodity derivatives - oil			(125,382	)			(125,382	)

Derivative instruments listed above include swaps and two-way collars. For additional information on the Company’s derivative instruments and derivative liabilities, see Note 5 – Commodity Derivative Instruments.

We measure and record compensation expense for Series C Unit awards to employees and others based on estimated grant date fair values. We recognize compensation costs for awards granted over the requisite service period based on the grant date fair value in general and administrative expenses on our consolidated statements of operations. Additionally, we recognize forfeitures of share-based compensation as they occur.

12

RMX RESOURCES, LLC

Notes to Consolidated Financial Statements -- Continued

December 31, 2020 and 2019

Accounting Standards

Not Yet Adopted

Lease accounting standard -- In February 2016, the FASB issued a new lease accounting standard, which requires lessees to recognize most leases, including operating leases, on the balance sheet as a right of use asset and lease liability. Short-term leases can continue being accounted for off balance sheet based on a policy election. This standard does not apply to leases to explore for or use minerals, oil, natural gas and similar non-regenerative resources, including the intangible right to explore for those natural resources and rights to use the land in which those natural resources are contained. This standard is effective for us in the first quarter of 2022 and shall be applied using a modified retrospective approach at the beginning of the earliest period presented in the financial statements. Early adoption is permitted.

We have made policy elections to (i) not capitalize short-term leases for all asset classes, (ii) to not separate non-lease components from lease components for all of our current asset classes, (iii) apply the package of practical expedients that allows us to not reassess: whether any expired or existing contracts contain leases, lease classification for any expired or existing leases and initial direct costs for existing leases, (iv) apply the land easement practical expedient to not evaluate land easements that existed or expired prior to adoption and (v) apply the practical expedient to apply hindsight in estimating lease term and impairment.  

NOTE 2 - Asset Retirement Obligations

The Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification requires that an asset retirement obligation (ARO) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset.  The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset.  The ARO is recorded at fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value.  The fair value of the ARO is measured using expected future cash outflows discounted at the Company’s credit-adjusted risk-free interest rate.  The provisions of this topic apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, development, and operation of a long-lived asset. The following table summarizes ARO for the periods ended December 31, 2020 and December 31, 2019.

	Twelve months ended December 31, 2020			Twelve months ended December 31, 2019
Asset retirement obligation, beginning of period	$	16,349,403		$	12,739,462
Liabilities incurred during the period		358,043			66,944
Changes in assumptions		(1,353,902	)		2,993,348
Accretion expense		637,816			549,649
Asset retirement obligation, end of period	$	15,991,360		$	16,349,403

The change in assumptions resulted from additional information gathered during the year about the expected lives of the wells and the number of wellbores in the field.

13

RMX RESOURCES, LLC

Notes to Consolidated Financial Statements -- Continued

December 31, 2020 and 2019

NOTE 3 - Debt and Interest Expense

	Twelve months ended December 31, 2020			Twelve months ended December 31, 2019
Long-term debt consist of the following:
Senior credit facility, balance outstanding		26,244,946			19,494,946
Deferred Loan costs, net of amortization		(59,897	)		(91,146	)
Secured tern debt net of amortized loan costs		26,185,049			19,403,800

Senior Credit Facility – Washington Federal Bank

On November 30, 2018, RMX entered into a Credit Agreement providing for a $50.0 million four-year senior secured revolving credit facility (the “Credit Agreement”) with Washington Federal Bank, as administrative agent, lead arranger and bookrunner.

As of December 31, 2020, the credit facility had a borrowing base of $30 million with $26.2 million outstanding. The amounts borrowed under the Credit Agreement bear annual interest rates at prime lending rate as published from time to time in the “Money Rates” section of The Wall Street Journal as the prime rate. Additional payments due under the Credit Agreement include paying a commitment fee to the Lender in respect of the unutilized commitments thereunder. The commitment rate is 0.50% per year of the unutilized portion of the borrowing base in effect from time to time. The Company is also required to pay customary letter of credit fees. The effective interest rate under the revolving line of credit was 4.75% as of December 31, 2020. The bank charges associated with the commitment rate are reflected on the Statement of Operations as part of interest expense. The note requires payment of interest monthly until maturity on December 1, 2022 at which time all outstanding principal and interest amounts are due.

The Credit Agreement requires the Company to maintain the following financial covenants: commencing with the quarter ended March 31, 2019, a current ratio of not less than 1.0 to 1.0 on the last day of each quarter and, a ratio of total debt to earnings (“Leverage Ratio”) before interest, taxes, depreciation, depletion, amortization and exploration expenses (“EBITDAX”) ratio of not greater than 3.5 to 1.0 for the four fiscal quarters ending on the last day immediately preceding such date of determination, and an interest coverage ratio of greater than or equal to 2.5. to 1.0 at the end of each quarter. The Credit Agreement contains customary affirmative covenants and defines events of default for credit facilities of this type, including failure to pay principal or interest, breach of covenants, breach of representations and warranties, insolvency, judgment default, and a change of control. Upon the occurrence and continuance of an event of default, the Lender has the right to accelerate repayment of the loans and exercise its remedies with respect to the collateral. The borrowing base under the Credit Agreement is subject to redetermination on February 1 and August 1 of each year, as well as special redeterminations described in the Credit Agreement.

RMX was not in compliance with the Leverage Ratio as of December 31, 2020 and anticipated a breach of the ratio through the period ending March 31, 2021. On March 25, 2021, Washington Federal reaffirmed the Borrowing Base at $30 million. At that same time Washington Federal waived fourth quarter 2020 and first quarter 2021 Debt Leverage covenants and reset EBITDAX buildout to begin annualizing second quarter 2021.

14

RMX RESOURCES, LLC

Notes to Consolidated Financial Statements -- Continued

December 31, 2020 and 2019

NOTE 4 – Income Taxes

RMX has elected to be taxed as a partnership under Treasury Regulations § 301.7701-3 and provisions of subchapter K of chapter 1 of subtitle A of the Code. RMX is subject only to California Franchise Tax which is not material and no provisions for current or deferred taxes have been included in these statements. RMX has reviewed its income tax positions and concluded that no uncertain tax positions exist. Penalties and interest, if any, are included in income tax expense on the consolidated statement of operations. There were no such amounts recorded through December 31, 2020

MOC is a “C” Corporation for income tax purposes. Deferred tax assets and liabilities related to MOC were inconsequential as of December 31, 2020 and 2019 for the periods then ended.

The MOC tax calculation has no impact on the financial statements at December 31, 2020 or 2019 and is not reflected in them. The effective rate of 0% differs from the statutory rate of 21% due to adjustments to the valuation allowance against deferred taxes and the portion of RMX’s consolidated taxable income generated in RMX which is not subject to tax.

NOTE 5 – Commodity Derivative Instruments

Objective and Strategies for Using Commodity Derivative Instruments – In order to mitigate the effect of commodity price uncertainty and enhance the predictability of cash flows relating to the marketing of the Company’s crude oil the Company enters into crude oil price commodity derivative instruments with respect to a portion of the Company’s expected production. The commodity derivative instruments used include futures, swaps, and options to manage exposure to commodity price risk inherent in the Company’s crude oil operations.

Futures contracts and commodity price swap agreements are used to fix the price of expected future oil sales at major industry trading locations such as Cushing, Oklahoma for oil. Basis swaps are used to fix or float the price differential between product prices at one market location versus another. Options are used to establish a floor price, a ceiling price, or a floor and ceiling price (collar) for expected future oil sales. (RMX does not hold any basis swaps as of December 31, 2020.)

While these instruments mitigate the cash flow risk of future reductions in commodity prices, they may also curtail benefits from future increases in commodity prices.

The Company does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses associated with derivative instruments are recognized currently in earnings. The change in the mark-to-market value of all hedge instruments are included in other income and expense while the realized settlement amount each month is included in oil and gas revenue.

Counterparty Credit Risk – Commodity derivative instruments expose the Company to counterparty credit risk. The Company’s commodity derivative instruments are with Cargill. Cargill, Inc.’s long-term rating is “A” by Standard & Poor’s, “A2” by Moody’s Investor Service and “A” by Fitch Ratings. If the Company chooses to elect early termination, all asset and liability positions would be netted and settled at the time of election.

15

RMX RESOURCES, LLC

Notes to Consolidated Financial Statements -- Continued

December 31, 2020 and 2019

Commodity derivative instruments open as of December 31, 2020 are provided below.

	2021		2022
CRUDE OIL (bbls)	Settlement		Settlement
Volume Hedged - West Texas Intermediate WTI		54,000		18,000
Average Prices (WTI Hedges)
Swap	$	41.55	$	41.55
Call	$	47.15	$	47.15
Put	$	40.00	$	40.00

	2021		2022
CRUDE OIL (bbls)	Settlement		Settlement
Volume Hedged - Brent		111,000		30,000
Average Prices (Brent Hedges)
Swap	$	60.10	$	-
Call	$	59.13	$	48.60
Put	$	50.00	$	40.00

The following table presents the fair value associated with our derivative financial instruments as of December 31, 2020 and 2019. All of our derivative instruments are subject to master netting arrangements which provide for the unconditional right of offset for all derivative assets and liabilities with a given counterparty in the event of default. We present assets and liabilities related to these instruments in our consolidated balance sheets as either current or non-current assets or liabilities based on their anticipated settlement date, net of the impact of master netting agreements. On derivative contracts recorded as assets in the table below, we are exposed to the risk that our counterparties may not perform.

	Derivative Assets									Derivative Liabilities
						Balance Sheet Location									Balance Sheet Location
	Gross Fair Value		Impact of Netting			Current		Non-current		Gross Fair Value			Impact of Netting		Current			Non-current
December 31, 2020
Derivative instruments	$	456,339	$	(443,396	)	$	12,943		—	$	(442,836	)		—		—		$	(442,836	)
December 31, 2019
Derivative instruments	$	487,955	$	(278,376	)		—	$	209,579	$	(613,336	)	$	278,376	$	(334,960	)		—

16

RMX RESOURCES, LLC

Notes to Consolidated Financial Statements -- Continued

December 31, 2020 and 2019

The following summarizes the cash settlements and change in fair value of our commodity derivatives:

	Year ended			Year ended
	December 31, 2020			December 31, 2019
Derivative not designated as hedging instruments
Net cash payment on derivative settlements		4,213,705			128,988
Non-cash fair value gain (loss) on derivatives		(304,512	)		(2,372,283	)
Commodity derivative gain (loss)		3,909,193			(2,243,295	)

NOTE 6 – General and Administrative

General and administrative expense for the periods ending December 31, 2020 and 2019 is summarized in the table below.

	Year ended December 31, 2020			Year ended December 31, 2019
General and administrative expense	$	2,419,565		$	2,359,790
Master Service Agreement (See Note 9-Related Party Transactions)		-			540,000
COPAS overhead reimbursement		(81,040	)		(173,494	)
Total general and administrative for the period	$	2,338,525		$	2,726,296

NOTE 7 – Equity

The RMX Company Agreement provides for three classes of ownership, which are issued as follows:

● A Units – These units are all held by Royale and are issued and outstanding for their contribution to RMX of oil and gas property interests and the stock of MOC.

● B Units – These units are held by CIC RMX LP and are issued and outstanding for their contribution of cash. All distributions are allocated to B Units until they exceed the amounts of contributed capital, plus a minimum return of 12% per annum.

● C Units – These units are available at the direction of the Company. They have a restricted participation under which all B units must first have all of their investment returned plus a return of twelve and one-half percent. All 1,000 C-1 units are issued and outstanding to Royale. Of 1,000 available C-2 units, 66% are issued and outstanding to management, with the 34% balance unallocated. As of December 31, 2020 there were 80 class B Units outstanding. As of December 31, 2020 there were 1,610 class C Units outstanding. During 2019, 50 class C Units were awarded to an employee.

C-1 units vested on April 13, 2020. C-2 units vest immediately upon the sale of all or substantially all of the Company's assets.

Compensation associated with C units has not been recognized due to performance conditions not being met. Compensation of $400,000 will be recognized upon the meeting of performance conditions.

Net income of RMX is allocated based on the pro-rata share of voting interests of the A and B units. As an LLC, each member is limited in liability to their investment in the Company.

17

RMX RESOURCES, LLC

Notes to Consolidated Financial Statements -- Continued

December 31, 2020 and 2019

NOTE 8 – Related Party Transactions

At December 31, 2020, the Company had a receivable from Royale of $ 272,849 arising from Royale’s collection of revenues belonging to the Company, or related to joint interest billings to Royale related to the ongoing transactions between the Royale Energy and the Company. At December 31, 2020, RMX had a receivable from Royale of $857,487 arising from Royale’s 43.75% share of Pipeline/Infrastructure Costs Beginning in 2021, the Company will recoup these costs by charging Royale a $3.50 per net barrel fee for oil sold from each of the 2019 and 2020 wells. Of the $857,487 receivable from Royal, $698,487 is considered a long-term receivable. The $3.50 per net barrel amount will be added to Royale’s monthly Joint Interest Billing for each well. This is recorded as accounts receivable from Royale on the consolidated balance sheet as of December 31, 2020.

At December 31, 2020, we had a advance from Royale of $ 326,845 for cash call advances on drilling prospect Sansinena 8B13.

A Master Service Agreement (“MSA”) was entered into on April 4, 2018 between the Company and Royale, whereby Royale would provide accounting, engineering and land back office services at $180,000 per month. As provided by the MSA, the contract was terminated on March 31, 2019 by the Company giving a thirty-day notice.

Settlement and Well Participation Agreement with Royale Energy

On March 11, 2019, RMX entered into a Settlement Agreement with Royale Energy to resolve differences resulting from the calculation of certain post-closing amounts as called for under Section 7.3 of the Subscription and Contribution Agreement. Under the terms of this provision, RMX estimated that Royale owed RMX approximately $3.4 million related to its calculation of the post-closing amount. This amount included amounts claimed by Sunny Frog related to its audit of joint owner billings by MOC prior to March 31, 2018. In settlement of these differences, Royale assigned to RMX its remaining interests in the Bellevue Field, located in Kern County and the W. Whittier Field located in Los Angeles County. Royale retained its liability for the payment of all royalties and suspended funds incurred by MOC prior to March 1, 2018. As part of this Settlement Agreement, RMX forgave a net $150,000 of past due joint interest billings owed by Royale to RMX, and agreed to offer Royale the right, but not the obligation to participate in a number of wells to be drilled in the Sansinena, and W Whittier at an offered working interest up to 75% of RMX’s working interest in each of the offered wells for two years. The minimum number of wells to be offered to Royale in each year is 2 net wells as determined by an agreed upon methodology. The Agreement also calls for certain credits toward future drilling costs of the offered wells. The results of the settlement agreement were recorded as in an increase to oil and gas properties.

NOTE 9 – Commitments and Contingencies

General Litigation

We are involved in various legal and regulatory proceedings arising in the normal course of business. While we cannot predict the outcome of these proceedings with certainty, we do not believe that an adverse result in any pending legal or regulatory proceeding, individually or in the aggregate, would be material to our consolidated financial condition or cash flow.

18

RMX RESOURCES, LLC

Notes to Consolidated Financial Statements -- Continued

December 31, 2020 and 2019

Environmental Remediation Contingencies

We are engaged in oil and gas exploration and production and may become subject to certain liabilities or damages as they relate to environmental cleanup of well sites or other environmental restoration or ground water contamination, in connection with drilling or operating oil and gas wells. In connection with our acquisition of existing or previously drilled well bores, we may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental clean up, restoration or contamination, we would be responsible for curing such a violation or paying damages. As of December 31, 2020, no claim has been made, nor are we aware of any liability that exists, as it relates to any environmental clean up, restoration, contamination or the violation of any rules or regulations relating thereto.

Employment Agreement with CEO

On April 4, 2018 RMX entered a two-year employment agreement with its chief executive officer. The agreement automatically extends on its anniversary for subsequent one year periods unless either party provides written notice of its intention not to extend the term of the agreement at least 60 days prior to the anniversary date. In the event of a termination by the company without cause, the executive shall be entitled to receive a lump sum in cash, equal to the executive’s then current base salary.

The base salary of the chief executive officer is presently $275,000 per year, which is the total future commitment of the Company under the employment agreement.

NOTE 10 – Subsequent Events

We face risks related to epidemics, outbreaks or other public health events that are outside of our control, and could significantly disrupt our operations and adversely affect our financial condition. For example, the COVID-19 outbreak of 2020, which has spread across the globe and impacted financial markets and worldwide economic activity, may adversely affect our operations or the health of our workforce by rendering employees or contractors unable to work or unable to access our facilities for an indefinite periods of time. In addition, the effects of COVID-19 and concerns regarding its global spread could negatively impact the domestic and international demand for crude oil and natural gas, which could contribute to price volatility, impact the price we receive for oil and natural gas and materially and adversely affect the demand for and marketability of our production. As the potential impact from COVID-19 is difficult to predict, the extent to which it may negatively affect our operating results or the duration of any potential business disruption is uncertain. Any potential impact will depend on future developments and new information that may emerge regarding the severity and duration of COVID-19 and the actions taken by authorities to contain it or treat its impact, all of which are beyond our control. These potential impacts, while uncertain, could adversely affect our operating results.

Management has evaluated subsequent events through March 30, 2021, the date on which these consolidated financial statements were available for issuance.

19

XML

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2020	Feb. 17, 2021	Jun. 30, 2020
Document Information Line Items
Entity Registrant Name	Royale Energy, Inc.
Document Type	10-K
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		55,192,846
Entity Public Float			$ 3,376,913
Amendment Flag	false
Entity Central Index Key	0001694617
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Well-known Seasoned Issuer	No
Document Period End Date	Dec. 31, 2020
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Interactive Data Current	Yes

XML

CONSOLIDATED BALANCE SHEETS - USD ($)	Dec. 31, 2020	Dec. 31, 2019
Current Assets:
Cash and Cash equivalents	$ 255,112	$ 1,031,014
Restricted Cash	2,146,571	2,845,515
Other Receivables, net	462,777	1,189,892
Revenue Receivables	204,149	589,151
Assets Held For Sale	1,529,141	0
Prepaid Expenses and Other Current Assets	233,769	376,587
Prepaid Drilling to RMX Resources, LLC	239,036	2,680,155
Total Current Assets	5,070,555	8,712,314
Investment in Joint Venture	0	6,185,995
Other Assets	583,554	708,554
Right of Use Asset - Operating Leases	229,516	392,774
Oil and Gas Properties (Successful Efforts Basis), Real Property and Equipment and Fixtures, net	2,541,001	4,590,990
Total Assets	8,424,626	20,590,627
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Accounts Payable and Accrued Expenses	4,161,109	6,031,034
Royalties Payable	623,405	623,405
Notes Payable	132,624	55,573
Due RMX Resources, LLC	23,087	32,367
Operating Leases - Current	178,120	162,272
Asset Retirement Obligation - Current	869,147	0
Deferred Drilling Obligations	3,127,500	5,232,675
Total Current Liabilities	9,114,992	12,137,326
Asset Retirement Obligation	2,478,350	3,632,423
Operating Leases - Non-current	52,937	231,071
Accrued Unpaid Guaranteed Payments	1,616,205	1,616,205
Accrued Liabilities - Non-current	1,306,605	1,306,605
Total Liabilities	14,569,089	18,923,630
Mezzanine Equity:
Convertible Preferred Stock, Series B, $10 par value, 3.5% annual dividend, 2,221,622 shares issued as of December 31, 2020	22,216,238	0
Convertible Preferred Stock, Series B, $10 par value, 3,000,000 Shares Authorized, 2,145,332 shares issued / outstanding at December 31, 2019	0	21,453,338
Common Stock	54,605	51,854
Additional Paid in Capital	53,883,479	53,549,543
Accumulated Deficit	(82,298,785)	(73,387,738)
Total Stockholder’s Equity (Deficit)	(28,360,701)	1,666,997
Total Liabilities and Stockholders’ Equity	$ 8,424,626	$ 20,590,627

XML

CONSOLIDATED BALANCE SHEETS (Parentheticals) - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Statement of Financial Position [Abstract]
Convertible Preferred, shares issued	2,221,622
Convertible Preferred Stock, Series B, annual dividend	3.50%
Convertible Preferred Stock, Series B, par value (in Dollars per share)	$ 10
Convertible Preferred Stock, Series B, par value (in Dollars per share)	10	$ 10
Common Stock, Par Value (in Dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized	280,000,000	280,000,000
Common Stock, shares issued	54,605,488	51,854,136
Common Stock, shares outstanding	54,605,488	51,854,136

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Revenues:
Revenues	$ 1,587,855	$ 2,967,183
Costs and Expenses:
Lease Operating	1,397,673	1,764,538
Impairment	0	977,682
Geological and Geophysical Expense	14,392	264,219
Well Equipment Write Down	0	28,343
Depreciation, Depletion and Amortization	473,647	468,143
Bad Debt Expense	1,008,003	60,512
General and Administrative	2,109,232	1,991,819
Legal and Accounting	279,227	751,935
Marketing	113,614	414,971
Loss on Assets Held For Sale	566,858	0
Total Costs and Expenses	5,962,646	6,722,162
Gain on Turnkey Drilling	1,700,462	2,909,908
Loss from Operations	(2,674,329)	(845,071)
Interest Expense	(12,949)	(20,559)
Loss on Investment in Joint Venture	(6,185,995)	(397,936)
Gain on Settlement of Payables	166,300	897,708
Other Gain	551,906	172,523
Gain (Loss) on Sale of Assets	6,920	(155,048)
Loss Before Income Tax Expense	(8,148,147)	(348,383)
Net Loss	$ (8,148,147)	$ (348,383)
Basic Loss Per Share (in Dollars per share)	$ (0.17)	$ (0.02)
Diluted Loss Per Share (in Dollars per share)	$ (0.17)	$ (0.02)
Oil and Gas [Member]
Revenues:
Revenues	$ 1,542,803	$ 2,329,275
Management Service [Member]
Revenues:
Revenues	$ 45,052	$ 637,908

XML

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT) - USD ($)	Common Stock [Member]	Preferred Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Total
Balance at Dec. 31, 2018	$ 49,421	$ 20,718,613	$ 53,023,350	$ (72,304,630)	$ 1,486,754
Balance (in Shares) at Dec. 31, 2018	49,421,387	2,071,861
Stock issued in lieu of Compensation	$ 2,433		526,193		528,626
Stock issued in lieu of Compensation (in Shares)	2,432,749
Preferred Series B 3.5% Dividend		$ 734,725		(734,725)
Preferred Series B 3.5% Dividend (in Shares)		73,473
Net Loss				(348,383)	(348,383)
Balance at Dec. 31, 2019	$ 51,854	$ 21,453,338	53,549,543	(73,387,738)	1,666,997
Balance (in Shares) at Dec. 31, 2019	51,854,136	2,145,334
Stock issued in lieu of Compensation	$ 2,751		333,936		336,687
Stock issued in lieu of Compensation (in Shares)	2,751,352
Reclassify Preferred B to Mezzanine		$ (21,640,538)			(21,640,538)
Reclassify Preferred B to Mezzanine (in Shares)		(2,164,054)
Preferred Series B 3.5% Dividend		$ 187,200		(762,900)	(575,700)
Preferred Series B 3.5% Dividend (in Shares)		18,720
Net Loss				(8,148,147)	(8,148,147)
Balance at Dec. 31, 2020	$ 54,605		$ 53,883,479	$ (82,298,785)	$ (28,360,701)
Balance (in Shares) at Dec. 31, 2020	54,605,488

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (Loss)	$ (8,148,147)	$ (348,383)
Adjustments to Reconcile Net Loss to Net Cash Used by Operating Activities:
Depreciation, Depletion, and Amortization	473,647	468,143
Impairment	0	977,682
(Gain) Loss on Sale of Assets	(6,920)	155,048
Gain on Turnkey Drilling	(1,700,462)	(2,909,908)
(Gain) Loss on Settlement of Accounts Payable	(166,300)	(897,708)
Loss on Investment in Joint Venture	6,185,995	397,936
Bad Debt Expense	1,008,003	60,512
Loss on Assets Held For Sale	566,858	0
Geological & Geophysical Costs	14,392	264,219
Gain on Other	(271,310)	(172,523)
Stock-Based Compensation	336,687	528,626
Well Equipment and Other Assets Write Down	0	28,343
Right of Use Asset Depreciation	10,945	0
(Increase) Decrease in:
Other & Revenue Receivables	46,210	84,372
Prepaid Expenses and Other Assets	2,583,937	(2,679,919)
Increase (Decrease) in:
Accounts Payable and Accrued Expenses	(1,305,371)	866,092
Royalties Payable	0	(9,386)
Due to Affiliate	(9,280)	(302,628)
Net Cash Used in Operating Activities	(381,116)	(3,489,482)
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for Oil and Gas Properties	(5,562,985)	(9,393,338)
Proceeds from Turnkey Drilling	4,327,500	10,981,159
Net Cash (Used In) Provided by Investing Activities	(1,235,485)	1,587,821
CASH FLOWS FROM FINANCING ACTIVITIES:
Principal Payments on Long-Term Debt	(66,045)	(390,840)
Proceeds from Long-Term Debt	207,800	0
Seismic Financing Agreement Payments	0	(186,012)
Net Cash Provided by (Used In) Financing Activities	141,755	(576,852)
Net Increase (Decrease) in Cash	(1,474,846)	(2,478,513)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year	3,876,529	6,355,042
Cash, Cash Equivalents, and Restricted Cash at End of Year	2,401,683	3,876,529
Cash Paid for Interest	12,949	20,559
Cash Paid for Taxes	5,559	19,374
Increase (Decrease) in Capital Accrued Balance	(487,323)	(94,546)
Series B Paid-In-Kind Dividends	$ 762,900	$ 734,725

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2020

Accounting Policies [Abstract]

Significant Accounting Policies [Text Block]

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 17 – Supplemental Information About Oil and Gas Producing Activities (Unaudited) 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. At December 31, 2020, the Company has $1.529 million in Long Lived Assets Held for Sale.

The Company’s 2020 consolidated financial statements reflect a working capital deficiency of $4,044,437 and a net loss from operations of $2,674,329. 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.

Correction of Immaterial Errors in Previously Issued Financial Statements

Subsequent to the issuance of the consolidated financial statements for the year ended December 31, 2019, the Company concluded that the Statement of Cash Flows for the year ending December 31, 2019, contained immaterial errors related to the classification of payments arising from operating leases and to the quantification of the amount of capital expenditures that had been accrued for but not yet paid. These immaterial errors have been corrected for the comparative period, resulting in an increase in cash flows used in operating activities of $239,362; an increase in cash flows provided by investing activities of $94,546; and a decrease in cash flows used in financing activities of $144,816 for the period ending December 31, 2019. These immaterial errors did not have any impact on our financial position, net loss or total cash flow for the period ending December 31, 2019.

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.

	Year Ended December 31,
	2020		2019
Cash and cash equivalents	$	255,112	$	1,031,014
Restricted cash		2,146,571		2,845,515
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows		2,401,683		3,876,529

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, 2020 and 2019, the Company established an allowance for uncollectable accounts of $2,582,093 and $1,791,162, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue. During 2020 and 2019, the Company closed a number of accounts as uncollectable, offsetting the allowance in the amount of $2,553 and $519,333 respectively.

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. We evaluated our investment in RMX as of December 31, 2019, and determined that any losses were not other than temporary. 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.

	Year Ended December 31,
	2020		2019
Oil & Condensate Sales	$	1,184,680	$	1,504,936
Natural Gas Sales		357,587		824,339
NGL Sales		536		-
	$	1,542,803	$	2,329,275

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

These amounts include proceeds from the Master Service Agreement (“MSA”) with RMX for the providing of land, engineering, accounting and support services for the RMX joint venture. Revenues earned under the MSA were recorded at the end of each month that services were performed, in conformity with the Agreement. The service fee income was deemed earned at the end of each month that services were performed as prescribed by the contract. On December 31, 2018, Royale received notice of cancelation of the MSA by RMX effective March 31, 2019. For the year ended 2019, the Company recognized $540,000 in supervisory fees from RMX. Also included in the caption are 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 2020 there were no impairment losses, while 2019 the Company recorded impairment losses of $977,682, on various capitalized base and land costs as well as certain fields acquired through the merger with the matrix entities.

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:

● Management has committed to a plan to sell the asset;

● The asset group is available for immediate sale in its present condition;

● An active program is underway to locate potential buyers;

● The sale is probable within one year;

● The asset group is being marketed at a price that is reasonable relative to its current fair value; and

● Actions required to complete the plan indicate that it is unlikely that significant changes to the plan will be made or the plan will be withdrawn.

Assets held for sale are carried at the lower of cost or fair market value less cost of disposal in current assets. If 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, 2020 and 2019, Royale Energy had Deferred Drilling Obligations of $ 3,127,500 and $5,232,675, respectively.

If Royale Energy is unable to drill the wells, and a suitable replacement well is not found, Royale would retain the non-refundable portion of the 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:

	Year Ended December 31,
	2020						2019
	Basic			Diluted			Basic			Diluted
Net Loss	$	(8,148,147	)	$	(8,148,147	)	$	(348,383	)	$	(348,383	)
Less: Preferred Stock Dividend		762,900			762,900			734,725			734,725
Less: Preferred Stock Dividend in Arrears		-			-			-			-
Net Loss Attributable to Common Shareholders		(8,911,047	)		(8,911,047	)		(1,083,108	)		(1,083,108	)
Weighted average common shares outstanding		53,292,647			53,292,647			50,871,447			50,871,447
Effect of dilutive securities		-			-			-			-
Weighted average common shares, including Dilutive effect		53,292,647			53,292,647			50,871,447			50,871,447
Per share:
Net Loss	$	(0.17	)	$	(0.17	)	$	(0.02	)	$	(0.02	)

For the years ended December 31, 2020 and 2019, Royale Energy had dilutive securities of 25,137,267 and 23,947,519 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, 2020 and 2019, 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, 2020 and 2019, the components of accounts payable and accrued expenses consisted of:

	2020		2019
Trade Payables including accruals		2,264,562		3,107,012
Direct working interest investors related accruals		1,277,428		1,811,649
Current drilling efforts accrued expenses		20,924		508,246
Accrued Liabilities		391,434		393,245
Employee related accruals		196,014		195,998
Deferred rent		10,747		14,884
Federal and State income taxes payable		-		-
		4,161,109		6,031,034

Accrued – Non-current

At December 31, 2020, the Company had non-current accrued liabilities of $1,306,605 and accrued unpaid guaranteed payment of $1,616,205, due to certain Matrix principals, from periods prior to the merger with the Matrix entities during March of 2018.

Business Combinations

From time-to-time, the Company acquires businesses in the oil and gas industry. Royale primarily targets businesses in geological basins that the Company considers to be in a focus area. Businesses are included in the consolidated financial statements from the date of acquisition.

We recognize, separately from goodwill, the identifiable assets acquired and liabilities assumed at their estimated acquisition-date fair values. We measure and recognize goodwill as of the acquisition date as the excess of: (1) the aggregate of the fair value of consideration transferred, the fair value of any noncontrolling interest in the acquiree (if any) and the acquisition date fair value of our previously held equity interest in the acquiree (if any), over (2) the fair value of assets acquired and liabilities assumed. If information about facts and circumstances existing as of the acquisition date is incomplete by the end of the reporting period in which a business combination occurs, we report provisional amounts for the items for which the accounting is incomplete. The measurement or allocation period ends once we receive the information we are seeking; however, this period will generally not exceed one year from the acquisition date. Any material adjustments recognized during the measurement period will be reflected retrospectively in the consolidated financial statements of the subsequent period. We recognize third-party transaction-related costs as expense currently in the period in which they are incurred.

Changes in Accounting Standards

Recently Adopted

ASU 2017-04, Simplifying the test for goodwill impairment

In January 2017, FASB issued Accounting Standards Update (ASU) 2017-04, Intangibles—Goodwill and Other (Topic 350), Simplifying the Test for Goodwill Impairment, which eliminated the calculation of implied goodwill fair value. This guidance simplifies the accounting as compared to prior Generally Accepted Accounting Principles “GAAP.” This ASU was effective for SEC filers beginning after December 15, 2019. Adoption of this standard did not have a material impact on our consolidated financial statements.

ASU 2018-13, Changes to the fair value disclosure requirements

In August 2018, FASB issued ASU 2018-13, Fair Value Measurement (Topic 820), Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement. This pronouncement modifies, eliminates and adds disclosure requirements for fair value measurements. This ASU was effective for SEC filers beginning after December 15, 2019. Adoption of this standard did not have a material impact on our consolidated financial statements.

ASU 2020-04, Changes to the fair value disclosure requirements

In March 2020, FASB issued ASU 2020-04, Reference Rate Reform (Topic 848), Facilitation of the effects of Reference Rate Reform on Financial Reporting. This pronouncement provides optional expedients and exceptions for applying GAAP to contract modifications, hedging relationships, and other transactions affected by the anticipated transition away from LIBOR. This new ASU is eligible to be applied upon release and has various transition requirements. The Company acquired certain hedge contracts with the merger with the Matrix Companies in 2018. Those hedge contracts were transferred to RMX with the formation of the RMX Joint Venture as more fully described in Note 2 – RMX Joint Venture. The transition from LIBOR currently taking place in the financial markets will not have any impact on the Company or its existing financial instruments or agreements.

ASU 2018-18, Clarifying the interaction between ASC 808 and ASC 606

In November 2018, FASB issued ASU 2018-18, Collaborative Arrangements (Topic 808). This pronouncement clarifies that certain transactions between collaborative partners should be accounted for as revenue under Topic 606 (Revenue Recognition) when one is a customer of the other. Adoption of this standard did not have a material impact on our consolidated financial statements.

Not Adopted

ASU 2016-13, Credit Impairment

In June of 2016, the FASB issued ASC Topic 326, Financial Instruments – Credit Losses. This new guidance replaces the current incurred loss impairment model with a requirement to recognize lifetime expected credit losses immediately when a financial asset is originated or purchased. This new Current Expected Credit Losses (“CECL”) model applies to (1) loans, accounts receivable, trade receivables, and other financial assets measured at amortized cost, (2) loan commitments and certain other off-balance sheet credit exposures, (3) debt securities and financial assets measured at fair value, and (4) beneficial interests in securitized financial assets. This ASU was effective for SEC filers beginning after December 15, 2019; however, on November 15, 2019, the FASB issued ASU 2019-10, which delayed the effective date for “smaller reporting companies.” Therefore, ASU 2016-13 is effective for "smaller reporting companies" (as defined by the Securities and Exchange Commission) such as Royale, for fiscal years beginning after December 15, 2022, including interim periods within those years, and must be adopted under the modified retrospective method. Entities may adopt ASU 2016-13 earlier as of the fiscal years beginning after December 15, 2018, including interim periods within those years. Adoption of this standard is not expected to have a material impact on our consolidated financial statements and cash flows.

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RMX JOINT VENTURE

12 Months Ended

Dec. 31, 2020

Business Combinations [Abstract]

Business Combination Disclosure [Text Block]

NOTE 2 – RMX JOINT VENTURE

RMX Joint Venture

On April 13, 2018, Royale Energy, Inc., and two of Royale’s subsidiaries, Royale Energy Funds, Inc. and Matrix Oil Management Corporation (the “Royale Entities”) completed  the Subscription and Contribution Agreement (“Contribution Agreement”), in which the Royale Entities and CIC RMX LP (“CIC”) entered into the Contribution Agreement and certain other agreements providing that the Royale Entities would contribute certain assets to RMX Resources, LLC (“RMX”), a newly formed Texas limited liability company formed to facilitate the investment from CIC.  In exchange for its contributed assets, Royale received a 20% equity interest in RMX, an equity performance incentive interest and up to $20.0 million to pay off Royale Entities senior lender, Arena Limited SPV, LLC., in full, and to pay Royale Entities trade payables and other outstanding obligations. CIC contributed an aggregate of $25.0 million in cash to RMX in exchange for (i) an 80% equity interest in RMX with preferred distributions until certain thresholds are met, (ii) a warrant (“Warrant”) to acquire up to 4,000,000 shares of Royale’s common stock at an exercise price of $.01 per share and registration rights pursuant to a Registration Rights Agreement.

RMX has a six-member board of managers. Royale has two seats on the board giving it a third of the Board.  Royale has designated Michael McCaskey and Johnny Jordan as its members of the RMX board.  The return targets for CIC through its funding of RMX provide for a “waterfall” style return profile with the first distributions going to CIC until it has received all Unpaid Preferred Return and Unpaid Preferred Enhanced Return, as defined by the Company’s Agreement.

Royale accounts for its ownership interest in RMX following the equity method of accounting, in accordance with ASC 323, Investments—Equity Method and Joint Ventures.

Under the provisions of the Amended and Restated Limited Liability Company Agreement of RMX Resources, LLC (“RMX Agreement”) dated March 27, 2018, the gains and losses of the partnership are distributed as if all of RMX’s assets were sold for cash at a price equal to their book basis and all RMX liabilities were satisfied at their book basis and all of the remaining assets of RMX were distributed in accordance with Section 5.4 of the RMX Agreement. Notwithstanding the above, for each fiscal year or other relevant period, deductions attributable to exploration costs, IDCs, and operating and maintenance costs shall be allocated 100% to the CIC members pro rata in accordance with their Class B percentage interests for each fiscal year.

RMX Joint Venture MSA

As part of the joint venture, RMX entered into a Master Service Agreement (“MSA”) calling for Royale Energy to provide land, engineering and support services for the joint venture.  For these services, Royale received $180,000 per month for the period April 2018 through March 2019.  These amounts are included in Supervisory Fees, Service Agreement and Other as more fully described in Note 1.

On December 31, 2018, Royale was formally notified of RMX’s intent to terminate the MSA as of March 31, 2019. The Termination Notice called for Royale to continue to provide accounting and other services through March 31, 2019.

RMX Joint Venture Post-Closing

On March 11, 2019, Royale entered into a Settlement Agreement with RMX Resources to resolve differences resulting from the calculation of certain post-closing amounts as called for under Section 7.3 of the Subscription and Contribution Agreement. In settlement of these differences, Royale agreed to assign its remaining interests in the Bellevue Field, located in Kern County and the W. Whittier Field located in Los Angeles County, California to RMX. These fields accounted for 5.145 and 140.647 Mboe in reserves and were valued at $67,671 and $2.4 million, respectively using SEC pricing and discounted at 10 percent at December 31, 2018.

Royale continues to be liable for the payment of all royalties and suspended funds incurred prior to March 1, 2018. Also, as part of this Settlement Agreement, RMX will offer Royale the right, but not the obligation to participate in a portion of the working interest, in a number of wells to be drilled in the Sansinena, Sempra, Whittier and/or East LA properties in Los Angeles County, California. The minimum number of wells to be offered to Royale in each year is 2 net wells as determined by an agreed upon methodology. The Agreement also calls for certain credits toward future drilling costs of the offered wells. The Company recorded a loss of $1,237,126 on the settlement, recorded in Loss on Sale of Assets in the Statement of Operations during 2019.

In conjunction with the merger between the Matrix entities and Royale, there were $1,254,204 of assets included on the books of Matrix for which documentary support could not be identified. At December 31, 2018, the Company concluded that these amounts were a contingent liability and recorded them in Current - Accrued Liabilities. On October 11, 2019, the Company received documentary support enabling management to conclude that the liability was no longer probable and should be derecognized. The Company recorded a gain of $1,254,204 on extinguishment, recorded in Loss on Sale of Assets in the Statement of Operations during 2019.

The RMX Joint Venture, like any Joint Venture investment following the equity method, is subject to ASC 323-10-35-31 and 32, impairment testing. During the 4th quarter of 2020, Royale received the RMX engineering reserve report prepared by an independent outside engineering firm. The report reflected reserve values for RMX that were below the Company’s expectations. As a result, of this and on-going market conditions along with the contractual terms of Royale’s investment in RMX, management performed an impairment test. Royale considered the waterfall formula as called for under its agreements with RMX as well as the preferred return owed to other partners. As part of this computation, Royale applied a discounted cash flow test as called for under ASC 820-10-55-5(c) and 5(d) incorporating the time value of money and risk premium. In our test, we considered factors including, most significantly, the estimated market value of the reserves of RMX and the amount of preferred return owed to other partners. As a result of this analysis and the fact that Management does not believe the values reflected in this most recent reserve report are temporary, Royale does not expect to realize the entire carrying amount of the RMX investment. Therefore, the entire amount of $6,185,995 is impaired and was taken to the Statement of Operations.

Additional reasons that Royale considers this impairment to be permanent is that these assets are located in California close to urban dwellings and subject to increasing regulatory scrutiny. Further, the current state administration has indicated a strong desire to impose increasing regulations on oil and gas producing properties thereby reducing their economic value.

Because the Company does not expect the value of the RMX Joint Venture to improve to a level where the water-fall profit sharing formula will provide value to Royale, the Company is no longer providing summarized financial information on the RMX investment in its financial statements or its reserve disclosures.

Listed below is summarized information the Company’s investment in RMX:

	Twelve Months Ended December 31, 2020			Twelve Months Ended December 31, 2019
	RMX Resources, LLC			RMX Resources, LLC
Balance Sheet:
Total Assets	$	77,168,147		$	72,401,841
Total Liabilities	$	46,213,651		$	41,573,426
Members Equity	$	30,954,496		$	30,828,415
Results of Operations:
Net operating revenue	$	9,376,395		$	16,392,305
Income (Loss) from operations	$	(3,352,584	)	$	1,456,290
Net income	$	126,081		$	(2,091,239	)

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OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES

12 Months Ended

Dec. 31, 2020

Oil and Gas Property [Abstract]

Oil and Gas Properties [Text Block]

NOTE 3 – OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES

Oil and gas properties, equipment and fixtures consist of:

	Year Ended December 31,
	2020			2019
Oil and Gas
Producing properties, including intangible drilling costs	$	5,672,457		$	7,792,156
Undeveloped properties		13,993			46,990
Lease and well equipment		3,317,718			3,304,565
	$	9,004,168		$	11,143,711
Accumulated depletion, depreciation and amortization		(6,467,626	)		(6,559,182	)
Net capitalized costs Total		2,536,542			4,584,529

Commercial and Other	2020			2019
Real estate, including furniture and fixtures	$	-		$	-
Vehicles		40,061			40,061
Furniture and equipment		1,097,428			1,097,428
		1,137,489			1,137,489
Accumulated depreciation		(1,133,030	)		(1,131,028	)
		4,459			6,461
Net capitalized costs Total	$	2,541,001		$	4,590,990

The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed at December 31:

	Year Ended December 31,
	2020		2019
Acquisition - Proved		-		-
Acquisition - Unproved		-		-
Development		5,306,639		9,680,298
Exploration		-		-

The guidance set forth in the Continued Capitalization of Exploratory Well Costs paragraph of the Extractive Activities Topic of the FASB ASC requires that we evaluate all existing capitalized exploratory well costs and disclose the extent to which any such capitalized costs have become impaired and are expensed or reclassified during a fiscal period. We did not make any additions to capitalized exploratory well costs pending a determination of proved reserves during 2020 and 2019. We did not charge any previously capitalized exploratory well costs to expense upon adoption of Topic.  Undeveloped properties are not subject to depletion, depreciation or amortization.

	Year Ended December 31,
	2020		2019
Beginning balance at January 1		-		-
Additions to capitalized exploratory well costs pending the determination of proved reserves		-		-
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves		-		-
Ending balance at December 31		-		-

Results of Operations from Oil and Gas Producing and Exploration Activities

The results of operations from oil and gas producing and exploration activities (excluding corporate overhead and interest costs) are as follows:

	Year Ended December 31,
	2020			2019
Oil and gas sales	$	1,542,803		$	2,329,275
Production-related costs (Lease Operating)		(1,397,673	)		(1,764,538	)
Impairment		-			(977,682	)
Depreciation, depletion and amortization		(473,647	)		(468,143	)
Results of operations from producing and exploration activities	$	(328,517	)	$	(881,088	)
Income Taxes (Benefit)		-			-
Net Results	$	(328,517	)	$	(881,088	)

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ASSET RETIREMENT OBLIGATION

12 Months Ended

Dec. 31, 2020

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation Disclosure [Text Block]

NOTE 4 – ASSET RETIREMENT OBLIGATION

The Asset Retirement and Environmental Obligations Topic of the ASC 410-20 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset.  The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset.  The ARO is recorded at the estimated fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value. Accretion expense is included as part of Depreciation, Depletion and Amortization in the Consolidated Statement of Operations. The fair value (as provided in ASC 820 guidance) of the ARO is measured using expected future cash outflows discounted at the Company’s credit-adjusted risk-free interest rate.  The provisions of this Topic apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, development, and operation of a long-lived asset. There were no changes in estimates for the year ended December 31, 2020. During the year ended December 31, 2019, the Company recorded $922,698 in increased costs related to estimates for abandonment of its’ share of certain California oil properties. These estimates relate to properties likely to be abandoned in the current period. As a result, the Company recorded them as impairment expense at year end 2019.

	2020			2019
Asset retirement obligation
Beginning of the year	$	3,632,422		$	2,366,456
Liabilities incurred during the period		29,323			210,643
Settlements		(508,538	)		-
Merger Additions		-			-
Sales		-			(33,026	)
Changes in estimates		-			922,698
Accretion expense		194,290			165,651
Reclassification to ARO - current		(869,147	)		-
End of year	$	2,478,350		$	3,632,422

The Company records accretion expense as part of Depreciation, Depletion and Amortization

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NOTES PAYABLE

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Short-term Debt [Text Block]

NOTE 5 – NOTES PAYABLE

On October 3, 2018, the Company issued a promissory note for a principal amount of $517,585 to Forza Operating, LLC. At an interest rate of 5.5%. Beginning October 3, 2018, principal and interest is due and payable in 12 monthly installments of $44,428. The note was the result of an agreement regarding the plugging and abandonment of the CL&F #1 and the CL&F #1 SWD wells. The Company agreed to include the current joint interest billing balance due to Forza Operating of $233,367 and Royale’s share of future plugging and abandonment costs of $284,218. At December 31, 2020 and 2019, Royale Energy had Notes Payable of $132,624 and $55,573, respectively, as a current liability.

On November 2, 2020, in conjunction with the PPP loan forgiveness described in Note 16 – Coronavirus Aid, Relief, And Economic Security Act (“CARES Act”), Royale’s entered into a loan for $10,054 to be repaid through monthly interest and principal payments of $560 beginning December 1, 2020, with the final payment of $613 scheduled for April 23, 2022. The loan is being amortized over 18 months at an annual interest rate of 1.00 percent with the last payment being a balloon payment to complete the loan repayment.

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INCOME TAXES

12 Months Ended

Dec. 31, 2020

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

NOTE 6 – INCOME TAXES

Deferred tax assets and liabilities reflect the net tax effect of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and amounts used for income tax purposes.  Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more-likely-than-not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.  In 2016, the Company adopted Accounting Standards Update (ASU) 2015-17 and has classified all of its deferred tax assets and liabilities as noncurrent on its balance sheet.

On December 22, 2017, the U.S. enacted significant changes to U.S. tax law following the passage and signing of H.R.1, An Act to Provide for Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018 (the “Tax Act”). The Tax Act permanently reduces the U.S. federal corporate tax rate from a maximum 35% to 21%, eliminated corporate Alternative Minimum Tax, modified rules for expensing capital investment, and limits the deduction of interest expense for certain companies. ASC 740 requires filers to record the effect of tax law changes in the period enacted. However, the SEC issued Staff Accounting Bulletin (“SAB”) 118 that permits filers to record provisional amounts during a measurement period ending no later than one year from the date of enactment. For the period ending December 31, 2018, the Company re-measured the applicable deferred tax assets based on the rates at which they are expected to reverse. The gross deferred tax assets and liabilities have been adjusted and a corresponding offset has been recorded to the full valuation allowance against the Company’s net deferred tax assets, which resulted in no net effect to its provision for income taxes and effective tax rate. No other provisional adjustments have been made as a result of the Act.

Significant components of the Company’s deferred assets and liabilities at December 31, 2020 and 2019, respectively, are as follows:

	2020			2019
Deferred Tax Assets (Liabilities):
Statutory Depletion Carry Forward	$	361,444		$	367,149
Net Operating Loss		7,361,230			6,489,891
Other		583,281			595,990
Share-Based Compensation		86,510			86,510
Capital Loss / AMT Credit Carry Forward		9,458			9,458
Charitable Contributions Carry Forward		3,396			3,890
Allowance for Doubtful Accounts		671,861			466,060
Oil and Gas Properties and Fixed Assets		4,860,069			5,404,787
Investment in RMX Joint Venture		342,569			(1,238,551	)
Section 481(a) Adjustments		(107,432	)		(214,859	)
	$	14,172,386		$	11,970,325
Valuation Allowance		(14,172,386	)		(11,970,325	)
Net Deferred Tax Asset	$	-		$	-

The Company recorded a full valuation allowance against the net deferred tax assets in 2016.  At the end of 2017, management reviewed the reliability of the Company’s net deferred tax assets, and due to the Company’s continued cumulative losses in recent years, Royale and its management concluded it is not “more-likely-than-not” its deferred tax assets will be realized.  As a result, the Company will continue to record a full valuation allowance against the deferred tax assets in 2019.  The Company will assess the realizability of the deferred tax assets at least yearly and make appropriate updates as needed.  Royale Energy, Inc. and its subsidiaries have available net operating loss carryforwards of $27.5 million generated in tax years ended before January 1, 2018, which if not utilized, begin to expire in the year 2027. Royale Energy, Inc. has no net operating loss carryforwards generated after December 31, 2017, which can be carried forward indefinitely.

A reconciliation of Royale Energy’s provision for income taxes and the amount computed by applying the statutory income tax rates at December 31, 2020 and 2019, respectively, to pretax income is as follows:

	2020			2019
Tax (benefit) computed at statutory rate of 21% at December 31, 2020 and 2019, respectively	$	(1,708,463	)	$	(71,680	)
Increase (decrease) in taxes resulting from:
Meals & Entertainment		740			1,583
PPP Loan Forgiveness		(41,538	)		-
Prior-year true-up for Books		(126,541	)		1,461,914
Deferred State Taxes, net of federal benefit		(330,367	)		214,161
Other non-deductible expenses		4,108			59,674
Change in valuation allowance		2,202,061			(1,665,652	)
Provision (benefit)		-			-

The components of the Company’s tax provision are as follows:

	2020		2019
Current tax provision (benefit) - federal	$	-	$	-
Current tax provision (benefit) - state		-		-
Deferred tax provision (benefit) - federal		-		-
Deferred tax provision (benefit) - state		-		-
Total provision (benefit)	$	-	$	-

In January 2007, Royale adopted additional provisions from the Income Taxes Topic of the ASC, which clarified the accounting for uncertainty in income taxes recognized in an entity’s financial statements and prescribes a recognition threshold and measurement attribute for financial statement disclosure of tax positions taken or expected to be taken on a tax return.  As a result of our implementation of the Topic at the time of adoption and at December 31, 2018, the Company did not recognize a liability for uncertain tax positions.  Currently, the only differences between our financial statements and our income tax returns relate to normal timing differences such as depreciation, depletion and amortization, which are recorded as deferred taxes on our balance sheets. We do not expect our unrecognized tax benefits to change significantly over the next 12 months. The tax years 2013 through 2018 remain open to examination by the taxing jurisdictions in which we file income tax returns.

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SERIES B PREFERRED STOCK

12 Months Ended

Dec. 31, 2020

Disclosure Text Block Supplement [Abstract]

Preferred Stock [Text Block]

NOTE 7 – SERIES B PREFERRED STOCK

Pursuant to the terms of the Merger all Class A limited partnership interests of Matrix Investments, LP (“Matrix Investments”) were exchanged for Royale Common stock using conversion ratios according to the relative value of the Class A limited partnership interests, and $20,124,000 of Matrix Investments preferred limited partnership interests were converted into 2,012,400 shares of Series B Convertible Preferred Stock of Royale. The Board of Directors of Royale Energy, prior to the merger, authorized 3,000,000 shares of Series B Convertible Preferred, which carries a liquidation preference and a 3.5% annual dividend, payable quarterly in cash or Paid-In-Kind (“PIK”) shares. The Series B Convertible Preferred Stock is convertible at the option of the security holder at the rate of ten shares of common stock for one share of Series B Convertible Preferred Stock. The Series B Preferred Stock has never been registered under the Securities Exchange Act of 1934, and no market exists for the shares. Additionally, the Series B Convertible Preferred shares will automatically convert to common at any time in which the Volume Weighted Average Price (“VWAP”) of the common stock exceeds $3.50 per share for 20 consecutive trading days, the shares are registered with the SEC and the volume of common shares trades exceeds 200,000 shares per day. The shareholders of the Series B Convertible Preferred may vote the number of shares into which they would be entitled to convert, beginning in 2020.

In accordance with ASC 480-10-S99-1.02, the Company has determined that the conversion or redemption of these shares are outside the sole control of the Company and that they should be classified in mezzanine or temporary equity as redeemable noncontrolling interest beginning at the reporting period, ended March 31, 2020.

For 2020 and 2019, the board authorized the payment of each quarterly dividend of Series B Convertible Preferred shares, as Paid-In-Kind shares (“PIK”) to be paid immediately following the end of the quarter. For the 12 months ending December 31, 2020, the Company issued 76,290 shares with a value of $762,900. During 2020 and 2019, no cash was used to pay dividends on Series B preferred shares.

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COMMON STOCK

12 Months Ended

Dec. 31, 2020

Stockholders' Equity Note [Abstract]

Stockholders' Equity Note Disclosure [Text Block]

NOTE 8 – COMMON STOCK

During the year 2020 and 2019, the Company issued shares of its Common Stock in lieu of cash payments for salaries, fees or incentives to various officers and board members, including our CEO.

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OPERATING LEASES

12 Months Ended

Dec. 31, 2020

Disclosure Text Block [Abstract]

Leases of Lessee Disclosure [Text Block]

NOTE 9 – OPERATING LEASES

The Company has two office leases. One at 1870 Cordell Court, El Cajon, California, the location of its corporate offices and one at 104 W. Anapamu, Santa Barbara, California, the location of the Company’s CEO and engineering team. The corporate office lease was entered into on August 31, 2016 and expires on October 31, 2021, with initial monthly payments of $6,148 with escalations. The lease in Santa Barbara was initiated in December of 2006 and, through several extensions and renewals, will expire in March of 2022.

The Company has elected the short-term lease recognition exemption for all leases that qualify. This means, for those leases that qualify, we will not recognize ROU assets or lease liabilities, and this includes not recognizing ROU assets or lease liabilities for existing short-term leases of those assets in transition. We also currently expect to elect the practical expedient to not separate lease and non-lease components for all of our finance leases. For our real estate operating leases, we have only considered the fixed portion of our lease payment commitment and have excluded the variable components from the capitalized ROU and lease liability.

Lease expense for operating as well as finance leases are included in General and Administrative expense and interest expense on the Consolidated Statement of Operations, while the lease expense for those leases that are short-term are included in Oil and Gas Lease Operating Expenses. The amounts are as follows:

	Year Ended December 31,
	2020		2019
Operating lease expense		200,836		184,374
Financing lease expense		19,137		10,757
Operating - short-term		-		7,886
Short Term - field		6,000		6,000
Total lease expense		225,973		209,017

The following tables summarized the operating and financing lease obligations.

Lease Obligations	Operating Lease Obligations		Financing Lease Obligations		Total Lease Obligations
2021	$	179,630		12,588		192,218
2022		24,408		12,588		36,996
2023		-		12,588		12,588
Thereafter		-		7,343		7,343
Total undiscounted lease payments	$	204,038		45,107		249,145
Less:  Amount representing interest		13,679		4,409		18,088
Total Operating & Financing lease liabilities	$	190,359		40,698		231,057
Current lease liabilities as of December 31, 2020	$	167,578		10,542		178,120
Long-term lease liabilities as of December 31, 2020	$	22,781		30,156		52,937

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RELATED PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2020

Related Party Transactions [Abstract]

Related Party Transactions Disclosure [Text Block]

NOTE 10 – RELATED-PARTY TRANSACTIONS

Significant Ownership Interests

Our Chief Executive, Johnny Jordan, has accrued certain unpaid salaries, which were assumed by the Company. At December 31, 2020, Mr. Jordan was owed $14,648, in accrued unpaid guaranteed payments.

Our Chief Financial Officer, Stephen Hosmer, has participated individually in 179 wells under the 1989 policy.  During 2020 and 2019, Stephen did not participate in fractional interests.  At December 31, 2020, the Company had a receivable balance of $17,101 due from Stephen Hosmer for normal drilling and lease operating expenses.

Donald Hosmer has participated individually in 179 wells under the 1989 policy. During 2020 and 2019, Donald did not participate in fractional interests. At December 31, 2020, Royale had a receivable balance of $5,385 due from Donald Hosmer for normal drilling and lease operating expenses.

At December 31, 2020 and 2019, we had a total payable of $23,087 and $32,367, respectively, 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 periods, the Company also had prepaid expenses and other current assets of $239,036 and $2,680,155, respectively. The prepaid amount where primarily for the drilling of wells.

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, 2020, the balance due was $1,306,605.

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 is a director.

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STOCK COMPENSATION PLAN

12 Months Ended

Dec. 31, 2020

Share-based Payment Arrangement [Abstract]

Share-based Payment Arrangement [Text Block]

NOTE 11 – STOCK COMPENSATION PLAN

There were no stock options issued during 2020 and 2019.

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SIMPLE IRA PLAN

12 Months Ended

Dec. 31, 2020

Retirement Benefits [Abstract]

Retirement Benefits [Text Block]

NOTE 12 – SIMPLE IRA PLAN

In April 1998, the Company established a Simple IRA pension plan covering all employees. The Company will contribute a matching contribution to each eligible employee’s Simple IRA equal to the employee’s salary reduction contributions up to a limit of 3% of the employee’s compensation for the year. The employer contribution for the years ending December 31, 2020 and 2019, were $41,921 and $30,336 respectively.

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ENVIRONMENTAL MATTERS

12 Months Ended

Dec. 31, 2020

Environmental Remediation Obligations [Abstract]

Environmental Loss Contingency Disclosure [Text Block]

NOTE 13 – ENVIRONMENTAL MATTERS

Royale Energy has established procedures for the continuing evaluation of its operations to identify potential environmental exposures and ensure compliance with regulatory policies and procedures. Management monitors these laws and regulations and periodically assesses the propriety of its operational and accounting policies related to environmental issues. The nature of Royale Energy’s business requires routine day-to-day compliance with environmental laws and regulations. Royale Energy incurred no material environmental investigation, compliance and remediation costs in 2020 or 2019.

Royale Energy is unable to predict whether its future operations will be materially affected by these laws and regulations. It is believed that legislation and regulations relating to environmental protection will not materially affect the results of operations of Royale Energy.

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CONCENTRATIONS

12 Months Ended

Dec. 31, 2020

Risks and Uncertainties [Abstract]

Concentration Risk Disclosure [Text Block]

NOTE 14 – CONCENTRATIONS

The Company bids its gas sales on a month-to-month basis and generally sells to a single customer without commitment to future gas sales to any particular customer. The Company normally sells approximately 32% of its monthly natural gas production to one customer on a month-to-month basis.  Since we are able to sell our natural gas to other readily available customers, the loss of any one customer would not have an adverse effect on our overall sales operations.

The Company maintains cash in depository institutions that are guaranteed by the Federal Deposit Insurance Corporation (FDIC) up to $250,000 per institution for our interest-bearing accounts in the years ended December 31, 2020 and 2019.   At December 31, 2020 and 2019, cash in banks exceeded the FDIC limits by approximately $1.9 million and $3.4 million, respectively. The Company has not experienced any losses on deposits.

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COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2020

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies Disclosure [Text Block]

NOTE 15 – COMMITMENTS AND CONTINGENCIES

The Company may become involved from time to time in litigation on various matters, which are routine to the conduct of its business.  The Company believes that none of these actions, individually or in the aggregate, will have a material adverse effect on its financial position or results of operations, though any adverse decision in these cases or the costs of defending or settling such claims could have a material effect on its business.

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. The contracts require the participants pay Royale the full contract price upon execution of the agreement. Royale typically begins the drilling activities within 12 months of funding and reaches total depth between 10 and 30 days after drilling begins.

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CORONAVIRUS AID, RELIEF, AND ECONOMIC SECURITY ACT (“CARES ACT”)

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Debt Disclosure [Text Block]

NOTE 16 – CORONAVIRUS AID, RELIEF, AND ECONOMIC SECURITY ACT (“CARES ACT”)

In December 2019, a novel strain of coronavirus (which triggers a respiratory disease called COVID-19) was reported in Wuhan, China. The World health Organization has declared the outbreak to constitute a “Public Health Emergency of International Concern.” The COVID-19 outbreak has caused a major reduction in the consumption of hydrocarbon-based transportation fuels as airlines have grounded flights worldwide and countries around the world have asked residents to suspend automobile travel. In addition to a substantial loss of demand for crude oil, In March, Saudi Arabia entered into a price war with Russia and added additional supplies of crude oil to an already over supplied market. The result has been a precipitous decline in the price of crude oil received by the Company. As a result, the Company has seen a reduction in its oil and gas revenues and resulting cash flows for the year 2020.

The CARES Act provided tax benefits and potential loans/grants for businesses and non-profits. On April 13, 2020, the Company successfully completed the process to obtain a $207,800 PPP loan through the SBA with Bank of Southern California (“BSC”) under the CARES Act. The interest rate was 1.00 percent per year fixed with a two-year term and all payments deferred for six months subject to loan forgiveness as provided for under the CARES Act. On November 2, 2020, Royale’s loan with BSC was paid down by $198,846 ($197,800 in principal and $1,046 in interest) as a result of completing the process of loan forgiveness under the terms of the CARES Act. The loan balance of $10,054 will be repaid through monthly interest and principal payments of $560 beginning December 1, 2020, with the final payment of $614 scheduled for April 23, 2022. The loan is being amortized over 18 months at an annual interest rate of 1.00 percent with the last payment being a balloon payment to complete the loan repayment.

On the Statement of Cash Flows, the Company has shown this PPP loan as a cash inflow from financing activities, principal repayments as cash outflows from financing activities, and interest payments as outflows from operating activities.  The amounts of principal and interest forgiven are shown as reconciling items to net loss in determining net cash used in operating activities.

Under the updated regulations, the forgiveness of PPP loan in not taxable income. Additionally, expenses submitted in support of the PPP loan forgiveness remain deductible for the purpose of tax reporting. Prior IRS positions in Notice 2020-32 and Rev Ruling 2020-27 no longer apply.

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LONG-LIVED ASSETS HELD FOR SALE

12 Months Ended

Dec. 31, 2020

Disclosure Text Block Supplement [Abstract]

Other Assets Disclosure [Text Block]

NOTE 17 – LONG-LIVED ASSETS HELD FOR SALE

Assets held for sale are carried at lower of cost or fair value less cost to sell. Listed below are the two current groups of properties that the Company has defined as long-lived assets held for sale in accordance with ASC 360-10-45.

East Los Angeles

The Company and its joint venture partner, RMX, have entered into a purchase and sales agreement as well as a second amendment to that certain purchase and sales agreement extending the closing date to the second quarter of 2021. The Company carries these assets on the books for $1.9 million with an ARO amount of approximately $1.1 million for the existing wells and facilities located on the properties providing a net book value of approximately $0.846 million. The sale would require the Company to plug and abandon the wells on the property and remove and restore the surface land with an estimated cost of $0.721 million. The sale price is approximately $1.0 million to the Company. Therefore, the Company will record a loss on the pending sale of these properties of $0.567 million and reflect Assets Held for Sale of $1.0 million reflected in current assets with an ARO balance of $0.721 million in current liabilities.

Texas Properties

The Company and its partners in these producing properties have exchanged document drafts of a purchase and sales agreement during 2021. The Company has a net book value for the properties of $0.381 million including an ARO liability of $0.149 million and expects to receive approximately $0.700 million at the consummation of the sale. Negotiations are ongoing with the sale expected to close during the second quarter of 2021. The Company is reflecting these properties at $0.529 million in Assets Held for Sale in current assets.

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SUBSEQUENT EVENTS

12 Months Ended

Dec. 31, 2020

Subsequent Events [Abstract]

Subsequent Events [Text Block]

NOTE 18 – SUBSEQUENT EVENTS

The Company has evaluated subsequent events through March 30, 2021, the date these financial statements were available to be issued. The Company is not aware of any subsequent events which would require recognition or disclosure in the financial statements, except as noted below or already recognized or disclosed.

Texas Properties

The Purchase and Sales Agreement for the Texas properties was executed between all the parties on February 18, 2021, with closing anticipated in the 2nd quarter of 2021.

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SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

12 Months Ended

Dec. 31, 2020

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Oil and Gas Exploration and Production Industries Disclosures [Text Block]

NOTE 19 – SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

The following estimates of proved oil and gas reserves, both developed and undeveloped, represent interests owned by Royale Energy which are located solely in the United States.  Proved reserves represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate to be reasonably certain to be recoverable in the future from known reservoirs under existing economic and operating conditions.  Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells, with existing equipment and operating methods.  Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which relatively major expenditures are required for completion.

Disclosures of oil and gas reserves, which follow, are based on estimates prepared by independent petroleum engineering consultant Netherland, Sewell & Associates, Inc., the net reserve value of its proved developed and undeveloped reserves was approximately $20.8 million at December 31, 2020, based on the average Henry Hub natural gas price spot price of $1.985 per MCF and for oil volumes, the average West Texas Intermediate price of $39.54 per barrel as applied on a field-by-field basis.  Netherland, Sewell & Associates, Inc. provided reserve value information for the Company’s California, Texas, Oklahoma, Utah and Louisiana properties. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures.  These estimates do not include probable or possible reserves.

The technical persons responsible for preparing the reserves estimates presented in the report of Netherland, Sewell & Associates, Inc., meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.  Netherland, Sewell & Associates, Inc. is a firm of independent petroleum engineers, geologists, geophysicists, and petrophysicists; and do not own an interest in our properties and are not employed on a contingent basis.  All activities and reports performed and completed by Netherland, Sewell & Associates, Inc. with regards to our reserve valuation estimates are reviewed Royale’s management.

These estimates are furnished and calculated in accordance with requirements of the FASB and the SEC.  Because of unpredictable variances in expenses and capital forecasts, crude oil and natural gas price changes, largely influenced and controlled by U.S. and foreign government actions, and the fact that the bases for such estimates vary significantly, management believes the usefulness of these projections is limited.  Estimates of future net cash flows presented do not represent Management’s assessment of future profitability or future cash flows to Royale Energy.  Management’s investment and operating decisions are based upon reserve estimates that include proved reserves prescribed by the SEC as well as probable reserves, and upon different price and cost assumptions from those used here.

It should be recognized that applying current costs and prices and a 10 percent standard discount rate does not convey absolute value.  The discounted amounts arrived at are only one measure of the value of proved reserves.

Changes in Estimated Reserve Quantities

The net interest in estimated quantities of proved developed reserves of crude oil and natural gas at December 31, 2020 and 2019, and changes in such quantities during each of the years then ended, were as follows:

Total Proved Reserves
	2020						2019
	Oil (BBL)			Gas (MCF)			Oil (BBL)			Gas (MCF)
Beginning of period		2,171,000			4,306,900			1,146,400			2,986,200
Revisions of previous estimates		(646,080	)		(1,515,637	)		1,052,086			(890,032	)
Production		(31,210	)		(160,406	)		(27,663	)		(292,472	)
Extensions, discoveries and improved recovery		47,290			29,643			22,042			2,516,046
Merger Acquisition								-			-
Purchase of minerals in place								-			-
Sales of minerals in place								(21,865	)		(12,842	)
Proved reserves end of period		1,541,000			2,660,500			2,171,000			4,306,900

Proved Developed
	2020				2019
	Oil (BBL)		Gas (MCF)		Oil (BBL)		Gas (MCF)
Proved developed reserves:
Beginning of period		232,200		2,790,300		148,600		1,914,900
End of period		224,900		691,900		232,200		2,790,300

Proved Undeveloped
	2020				2019
	Oil (BBL)		Gas (MCF)		Oil (BBL)		Gas (MCF)
Proved undeveloped reserves:
Beginning of period		1,938,800		1,516,600		997,800		1,071,300
End of period		1,316,100		1,968,600		1,938,800		1,516,600

At December 31, 2020, our previously estimated proved developed and undeveloped natural gas reserve quantities were revised downward by approximately 1,515,637 MCF of natural gas. This downward revision was mainly the result of a decrease in proved developed natural gas reserves from drilling locations which the Company had contracted.   At December 31, 2020, our previously estimated proved developed and undeveloped oil reserve quantities were revised downward by approximately 646,080 BBL of oil. This downward revision was mainly the result a decrease in the price of oil, which resulted in a decrease in the economic life.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The future net cash inflows are developed as follows:

• Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions.

• The estimated future production of proved reserves is priced on the basis of year-end prices.

• The resulting future gross revenue streams are reduced by estimated future costs to develop and to produce proved reserves, based on year-end estimates. Estimated future development costs by year are as follows:

2021	8,954,000
2022	6,750,000
2023	1,404,500
Thereafter	-
	17,108,500

The resulting future net revenue streams are reduced to present value amounts by applying a 10 percent discount.

Disclosure of principal components of the standardized measure of discounted future net cash flows provides information concerning the factors involved in making the calculation.  In addition, the disclosure of both undiscounted and discounted net cash flows provides a measure of comparing proved oil and gas reserves both with and without an estimate of production timing.  The standardized measure of discounted future net cash flow relating to proved reserves reflects estimated income taxes.

Changes in standardized measure of discounted future net cash flow from proved reserve quantities

The standardized measure of discounted future net cash flows is presented below for the years ended December 31, 2020 and 2019.

This statement discloses the sources of changes in the standardized measure from year to year. The amount reported as “Net changes in prices and production costs” represents the present value of changes in prices and production costs multiplied by estimates of proved reserves as of the beginning of the year. The “accretion of discount” was computed by multiplying the 10 percent discount factor by the standardized measure on a pretax basis as of the beginning of the year. The “Sales of oil and gas produced, net of production costs” are expressed in actual dollar amounts. “Revisions of previous quantity estimates” is expressed at year-end prices. The “Net change in income taxes” is computed as the change in present value of future income taxes.

	2020			2019
Future cash inflows		65,939,300			143,045,000
Future production costs		(28,008,100	)		(28,967,400	)
Future development costs		(17,108,400	)		(20,587,800	)
Future income tax expense		(6,246,840	)		(28,046,940	)
Future net cash flows		14,575,960			65,442,860
10% annual discount for estimated timing of cash flows		(7,134,925	)		(35,801,989	)
Standardized measure of discounted future net cash flows		7,441,035			29,640,871
Sales of oil and gas produced, net of production costs		(351,478	)		(624,744	)
Revisions of previous quantity estimates		(31,231,533	)		14,035,099
Net changes in prices and production costs		(617,847	)		(14,331,770	)
Sales of minerals in place		-			(272,507	)
Purchases of minerals in place					-
Merger Acquisition					-
Extensions, discoveries and improved recovery		587,311			2,157,052
Accretion of discount		(100,504	)		2,900,123
Net change in income tax		9,514,215			(4,868,296	)
Net increase (decrease)		(22,199,836	)		(1,005,043	)

Future Development Costs

In order to realize future revenues from our proved reserves estimated in our reserve report, it will be necessary to incur future costs to develop and produce the proved reserves.  The following table estimates the costs to develop and produce our proved reserves in the years 2021 through 2023.

	2021		2022		2023
Future development cost of:
Proved developed reserves (PDP)		-		-		-
Proved non-producing reserves (PDNP)		54,000		-		-
Proved undeveloped reserves (PUD)		8,900,000		6,750,000		1,404,500
Total		8,954,000		6,750,000		1,404,500

Common assumptions include such matters as the real extent and average thickness of a particular reservoir, the average porosity and permeability of the reservoir, the anticipated future production from existing and future wells, future development and production costs and the ultimate hydrocarbon recovery percentage.  As a result, oil and gas reserve estimates and discounted present value estimates are frequently revised in subsequent periods to reflect production data obtained after the date of the original estimate.  If the reserve estimates are inaccurate, production rates may decline more rapidly than anticipated, and future production revenues may be less than estimated.

Additional data relating to Royale Energy’s oil and natural gas properties is disclosed in Supplemental Information About Oil and Gas Producing Activities (Unaudited), attached to Royale Energy’s Financial Statements, beginning on page F-1.

Historic Development Costs for Proved Reserves

In each year we expend funds to drill and develop some of our proved undeveloped reserves.  We have incurred no cost in any of the past three fiscal years to drill and develop reserves that were classified as proved undeveloped reserves as of December 31 of the immediately preceding year.

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Accounting Policies, by Policy (Policies)

12 Months Ended

Dec. 31, 2020

Accounting Policies [Abstract]

Basis of Accounting, Policy [Policy Text Block]

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, Policy [Policy Text Block]

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 17 – Supplemental Information About Oil and Gas Producing Activities (Unaudited) 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 [Policy Text Block]

Liquidity and Going Concern The primary sources of liquidity have historically been issuances of common stock, oil and gas sales through ongoing operations and the sale of oil and gas properties. There are factors that give rise to substantial doubt about the Company’s ability to meet liquidity demands, and we anticipate that our primary sources of liquidity will be from the issuance of debt and/or equity, the sale of oil and natural gas property participation interests through our normal course of business and the sale of non-strategic assets. At December 31, 2020, the Company has $1.529 million in Long Lived Assets Held for Sale. The Company’s 2020 consolidated financial statements reflect a working capital deficiency of $4,044,437 and a net loss from operations of $2,674,329. 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.

Reclassification, Comparability Adjustment [Policy Text Block]

Correction of Immaterial Errors in Previously Issued Financial Statements

Subsequent to the issuance of the consolidated financial statements for the year ended December 31, 2019, the Company concluded that the Statement of Cash Flows for the year ending December 31, 2019, contained immaterial errors related to the classification of payments arising from operating leases and to the quantification of the amount of capital expenditures that had been accrued for but not yet paid. These immaterial errors have been corrected for the comparative period, resulting in an increase in cash flows used in operating activities of $239,362; an increase in cash flows provided by investing activities of $94,546; and a decrease in cash flows used in financing activities of $144,816 for the period ending December 31, 2019. These immaterial errors did not have any impact on our financial position, net loss or total cash flow for the period ending December 31, 2019.

Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block]

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.

	Year Ended December 31,
	2020		2019
Cash and cash equivalents	$	255,112	$	1,031,014
Restricted cash		2,146,571		2,845,515
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows		2,401,683		3,876,529

Receivable [Policy Text Block]

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, 2020 and 2019, the Company established an allowance for uncollectable accounts of $2,582,093 and $1,791,162, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue. During 2020 and 2019, the Company closed a number of accounts as uncollectable, offsetting the allowance in the amount of $2,553 and $519,333 respectively.

Accounts Receivable [Policy Text Block]

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.

Investment, Policy [Policy Text Block]

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. We evaluated our investment in RMX as of December 31, 2019, and determined that any losses were not other than temporary. 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 [Policy Text Block]

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.

	Year Ended December 31,
	2020		2019
Oil & Condensate Sales	$	1,184,680	$	1,504,936
Natural Gas Sales		357,587		824,339
NGL Sales		536		-
	$	1,542,803	$	2,329,275

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

These amounts include proceeds from the Master Service Agreement (“MSA”) with RMX for the providing of land, engineering, accounting and support services for the RMX joint venture. Revenues earned under the MSA were recorded at the end of each month that services were performed, in conformity with the Agreement. The service fee income was deemed earned at the end of each month that services were performed as prescribed by the contract. On December 31, 2018, Royale received notice of cancelation of the MSA by RMX effective March 31, 2019. For the year ended 2019, the Company recognized $540,000 in supervisory fees from RMX. Also included in the caption are Pipeline and Compressor fees which are received and allocated based on production volumes.

Oil and Gas Properties Policy [Policy Text Block]

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 2020 there were no impairment losses, while 2019 the Company recorded impairment losses of $977,682, on various capitalized base and land costs as well as certain fields acquired through the merger with the matrix entities.

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.

Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block]

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:

● Management has committed to a plan to sell the asset;

● The asset group is available for immediate sale in its present condition;

● An active program is underway to locate potential buyers;

● The sale is probable within one year;

● The asset group is being marketed at a price that is reasonable relative to its current fair value; and

● Actions required to complete the plan indicate that it is unlikely that significant changes to the plan will be made or the plan will be withdrawn.

Assets held for sale are carried at the lower of cost or fair market value less cost of disposal in current assets. If 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

Industry Specific Policies, Oil and Gas [Policy Text Block]

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, 2020 and 2019, Royale Energy had Deferred Drilling Obligations of $ 3,127,500 and $5,232,675, respectively.

If Royale Energy is unable to drill the wells, and a suitable replacement well is not found, Royale would retain the non-refundable portion of the 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.

Property, Plant and Equipment, Policy [Policy Text Block]

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.

Earnings Per Share, Policy [Policy Text Block]

Income (Loss) Per Share

Basic and diluted losses per share are calculated as follows:

	Year Ended December 31,
	2020						2019
	Basic			Diluted			Basic			Diluted
Net Loss	$	(8,148,147	)	$	(8,148,147	)	$	(348,383	)	$	(348,383	)
Less: Preferred Stock Dividend		762,900			762,900			734,725			734,725
Less: Preferred Stock Dividend in Arrears		-			-			-			-
Net Loss Attributable to Common Shareholders		(8,911,047	)		(8,911,047	)		(1,083,108	)		(1,083,108	)
Weighted average common shares outstanding		53,292,647			53,292,647			50,871,447			50,871,447
Effect of dilutive securities		-			-			-			-
Weighted average common shares, including Dilutive effect		53,292,647			53,292,647			50,871,447			50,871,447
Per share:
Net Loss	$	(0.17	)	$	(0.17	)	$	(0.02	)	$	(0.02	)

For the years ended December 31, 2020 and 2019, Royale Energy had dilutive securities of 25,137,267 and 23,947,519 respectively. These securities were not included in the dilutive loss per share due to their antidilutive nature.

Share-based Payment Arrangement [Policy Text Block]

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 Tax, Policy [Policy Text Block]

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 Measurement, Policy [Policy Text Block]

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, 2020 and 2019, 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 [Policy Text Block]

Accounts Payable and Accrued Expenses At December 31, 2020 and 2019, the components of accounts payable and accrued expenses consisted of: 2020 2019 Trade Payables including accruals 2,264,562 3,107,012 Direct working interest investors related accruals 1,277,428 1,811,649 Current drilling efforts accrued expenses 20,924 508,246 Accrued Liabilities 391,434 393,245 Employee related accruals 196,014 195,998 Deferred rent 10,747 14,884 Federal and State income taxes payable - - 4,161,109 6,031,034

Accrued Liabilitites Policy [Policy Text Block]

Accrued – Non-current At December 31, 2020, the Company had non-current accrued liabilities of $1,306,605 and accrued unpaid guaranteed payment of $1,616,205, due to certain Matrix principals, from periods prior to the merger with the Matrix entities during March of

Business Combinations Policy [Policy Text Block]

Business Combinations

From time-to-time, the Company acquires businesses in the oil and gas industry. Royale primarily targets businesses in geological basins that the Company considers to be in a focus area. Businesses are included in the consolidated financial statements from the date of acquisition.

We recognize, separately from goodwill, the identifiable assets acquired and liabilities assumed at their estimated acquisition-date fair values. We measure and recognize goodwill as of the acquisition date as the excess of: (1) the aggregate of the fair value of consideration transferred, the fair value of any noncontrolling interest in the acquiree (if any) and the acquisition date fair value of our previously held equity interest in the acquiree (if any), over (2) the fair value of assets acquired and liabilities assumed. If information about facts and circumstances existing as of the acquisition date is incomplete by the end of the reporting period in which a business combination occurs, we report provisional amounts for the items for which the accounting is incomplete. The measurement or allocation period ends once we receive the information we are seeking; however, this period will generally not exceed one year from the acquisition date. Any material adjustments recognized during the measurement period will be reflected retrospectively in the consolidated financial statements of the subsequent period. We recognize third-party transaction-related costs as expense currently in the period in which they are incurred.

New Accounting Pronouncements, Policy [Policy Text Block]

Changes in Accounting Standards

Recently Adopted

ASU 2017-04, Simplifying the test for goodwill impairment

In January 2017, FASB issued Accounting Standards Update (ASU) 2017-04, Intangibles—Goodwill and Other (Topic 350), Simplifying the Test for Goodwill Impairment, which eliminated the calculation of implied goodwill fair value. This guidance simplifies the accounting as compared to prior Generally Accepted Accounting Principles “GAAP.” This ASU was effective for SEC filers beginning after December 15, 2019. Adoption of this standard did not have a material impact on our consolidated financial statements.

ASU 2018-13, Changes to the fair value disclosure requirements

In August 2018, FASB issued ASU 2018-13, Fair Value Measurement (Topic 820), Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement. This pronouncement modifies, eliminates and adds disclosure requirements for fair value measurements. This ASU was effective for SEC filers beginning after December 15, 2019. Adoption of this standard did not have a material impact on our consolidated financial statements.

ASU 2020-04, Changes to the fair value disclosure requirements

In March 2020, FASB issued ASU 2020-04, Reference Rate Reform (Topic 848), Facilitation of the effects of Reference Rate Reform on Financial Reporting. This pronouncement provides optional expedients and exceptions for applying GAAP to contract modifications, hedging relationships, and other transactions affected by the anticipated transition away from LIBOR. This new ASU is eligible to be applied upon release and has various transition requirements. The Company acquired certain hedge contracts with the merger with the Matrix Companies in 2018. Those hedge contracts were transferred to RMX with the formation of the RMX Joint Venture as more fully described in Note 2 – RMX Joint Venture. The transition from LIBOR currently taking place in the financial markets will not have any impact on the Company or its existing financial instruments or agreements.

ASU 2018-18, Clarifying the interaction between ASC 808 and ASC 606

In November 2018, FASB issued ASU 2018-18, Collaborative Arrangements (Topic 808). This pronouncement clarifies that certain transactions between collaborative partners should be accounted for as revenue under Topic 606 (Revenue Recognition) when one is a customer of the other. Adoption of this standard did not have a material impact on our consolidated financial statements.

Not Adopted

ASU 2016-13, Credit Impairment

In June of 2016, the FASB issued ASC Topic 326, Financial Instruments – Credit Losses. This new guidance replaces the current incurred loss impairment model with a requirement to recognize lifetime expected credit losses immediately when a financial asset is originated or purchased. This new Current Expected Credit Losses (“CECL”) model applies to (1) loans, accounts receivable, trade receivables, and other financial assets measured at amortized cost, (2) loan commitments and certain other off-balance sheet credit exposures, (3) debt securities and financial assets measured at fair value, and (4) beneficial interests in securitized financial assets. This ASU was effective for SEC filers beginning after December 15, 2019; however, on November 15, 2019, the FASB issued ASU 2019-10, which delayed the effective date for “smaller reporting companies.” Therefore, ASU 2016-13 is effective for "smaller reporting companies" (as defined by the Securities and Exchange Commission) such as Royale, for fiscal years beginning after December 15, 2022, including interim periods within those years, and must be adopted under the modified retrospective method. Entities may adopt ASU 2016-13 earlier as of the fiscal years beginning after December 15, 2018, including interim periods within those years. Adoption of this standard is not expected to have a material impact on our consolidated financial statements and cash flows.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2020

Accounting Policies [Abstract]

Schedule of Cash and Cash Equivalents [Table Text Block]

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.

	Year Ended December 31,
	2020		2019
Cash and cash equivalents	$	255,112	$	1,031,014
Restricted cash		2,146,571		2,845,515
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows		2,401,683		3,876,529

Disaggregation of Revenue [Table Text Block]

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.

	Year Ended December 31,
	2020		2019
Oil & Condensate Sales	$	1,184,680	$	1,504,936
Natural Gas Sales		357,587		824,339
NGL Sales		536		-
	$	1,542,803	$	2,329,275

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

Basic and diluted losses per share are calculated as follows:

	Year Ended December 31,
	2020						2019
	Basic			Diluted			Basic			Diluted
Net Loss	$	(8,148,147	)	$	(8,148,147	)	$	(348,383	)	$	(348,383	)
Less: Preferred Stock Dividend		762,900			762,900			734,725			734,725
Less: Preferred Stock Dividend in Arrears		-			-			-			-
Net Loss Attributable to Common Shareholders		(8,911,047	)		(8,911,047	)		(1,083,108	)		(1,083,108	)
Weighted average common shares outstanding		53,292,647			53,292,647			50,871,447			50,871,447
Effect of dilutive securities		-			-			-			-
Weighted average common shares, including Dilutive effect		53,292,647			53,292,647			50,871,447			50,871,447
Per share:
Net Loss	$	(0.17	)	$	(0.17	)	$	(0.02	)	$	(0.02	)

Schedule of Accounts Payable and Accrued Liabilities [Table Text Block]

At December 31, 2020 and 2019, the components of accounts payable and accrued expenses consisted of:

	2020		2019
Trade Payables including accruals		2,264,562		3,107,012
Direct working interest investors related accruals		1,277,428		1,811,649
Current drilling efforts accrued expenses		20,924		508,246
Accrued Liabilities		391,434		393,245
Employee related accruals		196,014		195,998
Deferred rent		10,747		14,884
Federal and State income taxes payable		-		-
		4,161,109		6,031,034

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RMX JOINT VENTURE (Tables)

12 Months Ended

Dec. 31, 2020

Business Combinations [Abstract]

Equity Method Investments [Table Text Block]

Listed below is summarized information the Company’s investment in RMX:

	Twelve Months Ended December 31, 2020			Twelve Months Ended December 31, 2019
	RMX Resources, LLC			RMX Resources, LLC
Balance Sheet:
Total Assets	$	77,168,147		$	72,401,841
Total Liabilities	$	46,213,651		$	41,573,426
Members Equity	$	30,954,496		$	30,828,415
Results of Operations:
Net operating revenue	$	9,376,395		$	16,392,305
Income (Loss) from operations	$	(3,352,584	)	$	1,456,290
Net income	$	126,081		$	(2,091,239	)

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OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Tables)

12 Months Ended

Dec. 31, 2020

Oil and Gas Property [Abstract]

Property, Plant and Equipment [Table Text Block]

Oil and gas properties, equipment and fixtures consist of:

	Year Ended December 31,
	2020			2019
Oil and Gas
Producing properties, including intangible drilling costs	$	5,672,457		$	7,792,156
Undeveloped properties		13,993			46,990
Lease and well equipment		3,317,718			3,304,565
	$	9,004,168		$	11,143,711
Accumulated depletion, depreciation and amortization		(6,467,626	)		(6,559,182	)
Net capitalized costs Total		2,536,542			4,584,529

Commercial and Other	2020			2019
Real estate, including furniture and fixtures	$	-		$	-
Vehicles		40,061			40,061
Furniture and equipment		1,097,428			1,097,428
		1,137,489			1,137,489
Accumulated depreciation		(1,133,030	)		(1,131,028	)
		4,459			6,461
Net capitalized costs Total	$	2,541,001		$	4,590,990

Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]

The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed at December 31:

	Year Ended December 31,
	2020		2019
Acquisition - Proved		-		-
Acquisition - Unproved		-		-
Development		5,306,639		9,680,298
Exploration		-		-

Capitalized Exploratory Well Costs, Roll Forward [Table Text Block]

Undeveloped properties are not subject to depletion, depreciation or amortization.

	Year Ended December 31,
	2020		2019
Beginning balance at January 1		-		-
Additions to capitalized exploratory well costs pending the determination of proved reserves		-		-
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves		-		-
Ending balance at December 31		-		-

Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block]

The results of operations from oil and gas producing and exploration activities (excluding corporate overhead and interest costs) are as follows:

	Year Ended December 31,
	2020			2019
Oil and gas sales	$	1,542,803		$	2,329,275
Production-related costs (Lease Operating)		(1,397,673	)		(1,764,538	)
Impairment		-			(977,682	)
Depreciation, depletion and amortization		(473,647	)		(468,143	)
Results of operations from producing and exploration activities	$	(328,517	)	$	(881,088	)
Income Taxes (Benefit)		-			-
Net Results	$	(328,517	)	$	(881,088	)

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ASSET RETIREMENT OBLIGATION (Tables)

12 Months Ended

Dec. 31, 2020

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation [Table Text Block]

The Asset Retirement and Environmental Obligations Topic of the ASC 410-20 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset. The ARO is recorded at the estimated fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value. Accretion expense is included as part of Depreciation, Depletion and Amortization in the Consolidated Statement of Operations. The fair value (as provided in ASC 820 guidance) of the ARO is measured using expected future cash outflows discounted at the Company’s credit-adjusted risk-free interest rate. The provisions of this Topic apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, development, and operation of a long-lived asset. There were no changes in estimates for the year ended December 31, 2020. During the year ended December 31, 2019, the Company recorded $922,698 in increased costs related to estimates for abandonment of its’ share of certain California oil properties. These estimates relate to properties likely to be abandoned in the current period. As a result, the Company recorded them as impairment expense at year end 2019.

	2020			2019
Asset retirement obligation
Beginning of the year	$	3,632,422		$	2,366,456
Liabilities incurred during the period		29,323			210,643
Settlements		(508,538	)		-
Merger Additions		-			-
Sales		-			(33,026	)
Changes in estimates		-			922,698
Accretion expense		194,290			165,651
Reclassification to ARO - current		(869,147	)		-
End of year	$	2,478,350		$	3,632,422

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INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2020

Income Tax Disclosure [Abstract]

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

Significant components of the Company’s deferred assets and liabilities at December 31, 2020 and 2019, respectively, are as follows:

	2020			2019
Deferred Tax Assets (Liabilities):
Statutory Depletion Carry Forward	$	361,444		$	367,149
Net Operating Loss		7,361,230			6,489,891
Other		583,281			595,990
Share-Based Compensation		86,510			86,510
Capital Loss / AMT Credit Carry Forward		9,458			9,458
Charitable Contributions Carry Forward		3,396			3,890
Allowance for Doubtful Accounts		671,861			466,060
Oil and Gas Properties and Fixed Assets		4,860,069			5,404,787
Investment in RMX Joint Venture		342,569			(1,238,551	)
Section 481(a) Adjustments		(107,432	)		(214,859	)
	$	14,172,386		$	11,970,325
Valuation Allowance		(14,172,386	)		(11,970,325	)
Net Deferred Tax Asset	$	-		$	-

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

A reconciliation of Royale Energy’s provision for income taxes and the amount computed by applying the statutory income tax rates at December 31, 2020 and 2019, respectively, to pretax income is as follows:

	2020			2019
Tax (benefit) computed at statutory rate of 21% at December 31, 2020 and 2019, respectively	$	(1,708,463	)	$	(71,680	)
Increase (decrease) in taxes resulting from:
Meals & Entertainment		740			1,583
PPP Loan Forgiveness		(41,538	)		-
Prior-year true-up for Books		(126,541	)		1,461,914
Deferred State Taxes, net of federal benefit		(330,367	)		214,161
Other non-deductible expenses		4,108			59,674
Change in valuation allowance		2,202,061			(1,665,652	)
Provision (benefit)		-			-

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

The components of the Company’s tax provision are as follows:

	2020		2019
Current tax provision (benefit) - federal	$	-	$	-
Current tax provision (benefit) - state		-		-
Deferred tax provision (benefit) - federal		-		-
Deferred tax provision (benefit) - state		-		-
Total provision (benefit)	$	-	$	-

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OPERATING LEASES (Tables)

12 Months Ended

Dec. 31, 2020

Disclosure Text Block [Abstract]

Lease, Cost [Table Text Block]

Lease expense for operating as well as finance leases are included in General and Administrative expense and interest expense on the Consolidated Statement of Operations, while the lease expense for those leases that are short-term are included in Oil and Gas Lease Operating Expenses. The amounts are as follows:

	Year Ended December 31,
	2020		2019
Operating lease expense		200,836		184,374
Financing lease expense		19,137		10,757
Operating - short-term		-		7,886
Short Term - field		6,000		6,000
Total lease expense		225,973		209,017

Lessee, Operating Lease, Liability, Maturity [Table Text Block]

The following tables summarized the operating and financing lease obligations.

Lease Obligations	Operating Lease Obligations		Financing Lease Obligations		Total Lease Obligations
2021	$	179,630		12,588		192,218
2022		24,408		12,588		36,996
2023		-		12,588		12,588
Thereafter		-		7,343		7,343
Total undiscounted lease payments	$	204,038		45,107		249,145
Less:  Amount representing interest		13,679		4,409		18,088
Total Operating & Financing lease liabilities	$	190,359		40,698		231,057
Current lease liabilities as of December 31, 2020	$	167,578		10,542		178,120
Long-term lease liabilities as of December 31, 2020	$	22,781		30,156		52,937

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SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables)

12 Months Ended

Dec. 31, 2020

SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables) [Line Items]

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]

The net interest in estimated quantities of proved developed reserves of crude oil and natural gas at December 31, 2020 and 2019, and changes in such quantities during each of the years then ended, were as follows:

Total Proved Reserves
	2020						2019
	Oil (BBL)			Gas (MCF)			Oil (BBL)			Gas (MCF)
Beginning of period		2,171,000			4,306,900			1,146,400			2,986,200
Revisions of previous estimates		(646,080	)		(1,515,637	)		1,052,086			(890,032	)
Production		(31,210	)		(160,406	)		(27,663	)		(292,472	)
Extensions, discoveries and improved recovery		47,290			29,643			22,042			2,516,046
Merger Acquisition								-			-
Purchase of minerals in place								-			-
Sales of minerals in place								(21,865	)		(12,842	)
Proved reserves end of period		1,541,000			2,660,500			2,171,000			4,306,900

Proved Developed
	2020				2019
	Oil (BBL)		Gas (MCF)		Oil (BBL)		Gas (MCF)
Proved developed reserves:
Beginning of period		232,200		2,790,300		148,600		1,914,900
End of period		224,900		691,900		232,200		2,790,300

Proved Undeveloped
	2020				2019
	Oil (BBL)		Gas (MCF)		Oil (BBL)		Gas (MCF)
Proved undeveloped reserves:
Beginning of period		1,938,800		1,516,600		997,800		1,071,300
End of period		1,316,100		1,968,600		1,938,800		1,516,600

Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]

The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed at December 31:

	Year Ended December 31,
	2020		2019
Acquisition - Proved		-		-
Acquisition - Unproved		-		-
Development		5,306,639		9,680,298
Exploration		-		-

Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block]

	2020			2019
Future cash inflows		65,939,300			143,045,000
Future production costs		(28,008,100	)		(28,967,400	)
Future development costs		(17,108,400	)		(20,587,800	)
Future income tax expense		(6,246,840	)		(28,046,940	)
Future net cash flows		14,575,960			65,442,860
10% annual discount for estimated timing of cash flows		(7,134,925	)		(35,801,989	)
Standardized measure of discounted future net cash flows		7,441,035			29,640,871
Sales of oil and gas produced, net of production costs		(351,478	)		(624,744	)
Revisions of previous quantity estimates		(31,231,533	)		14,035,099
Net changes in prices and production costs		(617,847	)		(14,331,770	)
Sales of minerals in place		-			(272,507	)
Purchases of minerals in place					-
Merger Acquisition					-
Extensions, discoveries and improved recovery		587,311			2,157,052
Accretion of discount		(100,504	)		2,900,123
Net change in income tax		9,514,215			(4,868,296	)
Net increase (decrease)		(22,199,836	)		(1,005,043	)

Proved Undeveloped Reserves [Member]

SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables) [Line Items]

Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]

The resulting future gross revenue streams are reduced by estimated future costs to develop and to produce proved reserves, based on year-end estimates. Estimated future development costs by year are as follows:

2021	8,954,000
2022	6,750,000
2023	1,404,500
Thereafter	-
	17,108,500

Proved Developed, Proved Non-Producing and Proved Undeveloped Reserves [Member]

SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables) [Line Items]

Schedule of Future Development Costs, Oil and Gas Production [Table Text Block]

In order to realize future revenues from our proved reserves estimated in our reserve report, it will be necessary to incur future costs to develop and produce the proved reserves. The following table estimates the costs to develop and produce our proved reserves in the years 2021 through 2023.

	2021		2022		2023
Future development cost of:
Proved developed reserves (PDP)		-		-		-
Proved non-producing reserves (PDNP)		54,000		-		-
Proved undeveloped reserves (PUD)		8,900,000		6,750,000		1,404,500
Total		8,954,000		6,750,000		1,404,500

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Assets Held-for-sale, Long Lived, Fair Value Disclosure	$ 1,529,000
Working Capital (Deficit)	(4,044,437)
Operating Income (Loss)	(2,674,329)	$ (845,071)
Immaterial Error Correction		These immaterial errors have been corrected for the comparative period, resulting in an increase in cash flows used in operating activities of $239,362; an increase in cash flows provided by investing activities of $94,546; and a decrease in cash flows used in financing activities of $144,816 for the period ending December 31, 2019.
Accounts Receivable, Allowance for Credit Loss	2,582,093	$ 1,791,162
Accounts Receivable, Allowance for Credit Loss, Writeoff	2,553	519,333
Revenues	1,587,855	2,967,183
Impairment of Oil and Gas Properties		977,682
Contract with Customer, Liability, Current	$ 3,127,500	$ 5,232,675
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount (in Shares)	25,137,267	23,947,519
Other Accrued Liabilities, Noncurrent	$ 1,306,605	$ 1,306,605
Other Liabilities, Noncurrent	1,616,205	$ 1,616,205
Supervisory, Services [Member]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Revenues	$ 540,000
Minimum [Member]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	three
Maximum [Member]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	seven

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - Schedule of Cash and Cash Equivalents - USD ($)	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Schedule of Cash and Cash Equivalents [Abstract]
Cash and cash equivalents	$ 255,112	$ 1,031,014
Restricted cash	2,146,571	2,845,515
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows	$ 2,401,683	$ 3,876,529	$ 6,355,042

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - Disaggregation of Revenue - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Oil [Member]
Disaggregation of Revenue [Line Items]
Revenues	$ 1,184,680	$ 1,504,936
Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenues	357,587	824,339
Natural Gas Liquids [Member]
Disaggregation of Revenue [Line Items]
Revenues	536	0
Natural Gas Liquids [Member] | Oil and Gas [Member]
Disaggregation of Revenue [Line Items]
Revenues	$ 1,542,803	$ 2,329,275

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - Schedule of Earnings Per Share, Basic and Diluted - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Schedule of Earnings Per Share, Basic and Diluted [Abstract]
Net Loss	$ (8,148,147)	$ (348,383)
Less: Preferred Stock Dividend	762,900	734,725
Less: Preferred Stock Dividend in Arrears	0	0
Less: Preferred Stock Dividend in Arrears	0	0
Net Loss Attributable to Common Shareholders	$ (8,911,047)	$ (1,083,108)
Weighted average common shares outstanding (in Shares)	53,292,647	50,871,447
Weighted average common shares outstanding (in Shares)	53,292,647	50,871,447
Effect of dilutive securities	$ 0	$ 0
Effect of dilutive securities (in Shares)	0	0
Weighted average common shares, including Dilutive effect (in Shares)	53,292,647	50,871,447
Weighted average common shares, including Dilutive effect (in Shares)	53,292,647	50,871,447
Net Loss (in Dollars per share)	$ (0.17)	$ (0.02)
Net Loss (in Dollars per share)	$ (0.17)	$ (0.02)

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - Schedule of Accounts Payable and Accrued Liabilities - USD ($)	Dec. 31, 2020	Dec. 31, 2019
Schedule of Accounts Payable and Accrued Liabilities [Abstract]
Trade Payables including accruals	$ 2,264,562	$ 3,107,012
Direct working interest investors related accruals	1,277,428	1,811,649
Current drilling efforts accrued expenses	20,924	508,246
Accrued Liabilities	391,434	393,245
Employee related taxes and accruals	196,014	195,998
Deferred rent	10,747	14,884
Federal and State income taxes payable	0	0
	$ 4,161,109	$ 6,031,034

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RMX JOINT VENTURE (Details)		12 Months Ended
	Apr. 30, 2018 USD ($) shares	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Mar. 11, 2019 USD ($) Boe
RMX JOINT VENTURE (Details) [Line Items]
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves		$ 7,441,035	$ 29,640,871
Gain (Loss) on Disposition of Assets		6,920	(155,048)
Gain (Loss) on Extinguishment of Debt			1,254,204
Equity Method Investment, Other than Temporary Impairment		$ 6,185,995
Bellevue Field [Member]
RMX JOINT VENTURE (Details) [Line Items]
Proved Developed Reserves (Energy) (in Barrels of Oil Equivalent) | Boe					5.145
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves					$ 67,671
Whittier Field [Member]
RMX JOINT VENTURE (Details) [Line Items]
Proved Developed Reserves (Energy) (in Barrels of Oil Equivalent) | Boe					140.647
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves					$ 2,400,000
RMX Resources, LLC [Member]
RMX JOINT VENTURE (Details) [Line Items]
Equity Method Investment, Ownership Percentage	20.00%
Supervisory Fees, Service Agreements, and Other				$ 180,000
Gain (Loss) on Disposition of Assets			$ 1,237,126
RMX Resources, LLC [Member] | Maximum [Member]
RMX JOINT VENTURE (Details) [Line Items]
Cash Acquired from Acquisition	$ 20,000,000
CIC RMX LP [Member] | RMX Resources, LLC [Member]
RMX JOINT VENTURE (Details) [Line Items]
Equity Method Investment, Ownership Percentage	80.00%
Payments to Acquire Businesses, Gross	$ 25,000,000
Class Of Warrant or Rights Granted (in Shares) | shares	4,000,000

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RMX JOINT VENTURE (Details) - Equity Method Investments - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Schedule of Equity Method Investments [Line Items]
Total Assets	$ 8,424,626	$ 20,590,627
Total Liabilities	14,569,089	18,923,630
Net Operating Revenue	1,587,855	2,967,183
Net Loss	(8,148,147)	(348,383)
RMX Resources, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Total Assets	77,168,147
Total Liabilities	46,213,651
Members Equity	30,954,496
Net Operating Revenue	9,376,395
Loss from Continuing Operations	(3,352,584)
Net Loss	$ 126,081
RMX Resources, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Total Assets		72,401,841
Total Liabilities		41,573,426
Members Equity		30,828,415
Net Operating Revenue		16,392,305
Loss from Continuing Operations		1,456,290
Net Loss		$ (2,091,239)

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OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Details) - Schedule of Property, Plant and Equipment - USD ($)	Dec. 31, 2020	Dec. 31, 2019
Oil and Gas
Producing properties, including intangible drilling costs	$ 5,672,457	$ 7,792,156
Undeveloped properties	13,993	46,990
Lease and well equipment	3,317,718	3,304,565
Oil and gas, gross	9,004,168	11,143,711
Accumulated depletion, depreciation and amortization	(6,467,626)	(6,559,182)
Oil and gas, net	2,536,542	4,584,529
Property, Plant and Equipment, Gross	1,137,489	1,137,489
Accumulated depreciation	(1,133,030)	(1,131,028)
Property, Plant and Equipment, Net	4,459	6,461
Oil and gas properties, equipment and fixtures	2,541,001	4,590,990
Vehicles [Member]
Oil and Gas
Property, Plant and Equipment, Gross	40,061	40,061
Furniture and Fixtures [Member]
Oil and Gas
Property, Plant and Equipment, Gross	$ 1,097,428	$ 1,097,428

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OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Details) - Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Abstract]
Acquisition - Proved	$ 0	$ 0
Acquisition - Unproved	0	0
Development	5,306,639	9,680,298
Exploration	$ 0	$ 0

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OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Details) - Capitalized Exploratory Well Costs, Roll Forward - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Capitalized Exploratory Well Costs, Roll Forward [Abstract]
Beginning balance at January 1	$ 0	$ 0
Additions to capitalized exploratory well costs pending the determination of proved reserves	0	0
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves	0	0
Ending balance at December 31	$ 0	$ 0

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OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Details) - Results of Operations for Oil and Gas Producing Activities Disclosure - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Results of Operations for Oil and Gas Producing Activities Disclosure [Abstract]
Oil and gas sales	$ 1,542,803	$ 2,329,275
Production-related costs (Lease Operating)	(1,397,673)	(1,764,538)
Impairment	0	(977,682)
Depreciation, depletion and amortization	(473,647)	(468,143)
Results of operations from producing and exploration activities	(328,517)	(881,088)
Income Taxes (Benefit)	0	0
Net Results	$ (328,517)	$ (881,088)

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ASSET RETIREMENT OBLIGATION (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation, Revision of Estimate	$ 0	$ 922,698

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ASSET RETIREMENT OBLIGATION (Details) - Schedule of Change in Asset Retirement Obligation - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Asset retirement obligation
Beginning of the year	$ 3,632,422	$ 2,366,456
Liabilities incurred	29,323	210,643
Sales	0	(33,026)
Changes in estimates	0	922,698
Accretion expense	194,290	165,651
Reclassification to ARO - current	(869,147)	0
End of year	2,478,350	3,632,422
Settlements	(508,538)	0
RMX Resources, LLC [Member]
Asset retirement obligation
Liabilities incurred	$ 0	$ 0

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NOTES PAYABLE (Details) - USD ($)	Nov. 10, 2020	Nov. 02, 2020	Oct. 03, 2018	Dec. 31, 2020	Apr. 22, 2020	Dec. 31, 2019
NOTES PAYABLE (Details) [Line Items]
Notes Payable				$ 132,624		$ 55,573
Debt, Forza Operating, LCC [Member]
NOTES PAYABLE (Details) [Line Items]
Debt Instrument, Face Amount			$ 517,585
Debt Instrument, Interest Rate, Stated Percentage			5.50%
Debt Instrument, Frequency of Periodic Payment			12 monthly installments
Debt Instrument, Periodic Payment			$ 44,428
Oil and Gas Joint Interest Billing Receivables			233,367
Exploration Abandonment and Impairment Expense			$ 284,218
PPP Loan [Member]
NOTES PAYABLE (Details) [Line Items]
Debt Instrument, Face Amount		$ 10,054
Debt Instrument, Interest Rate, Stated Percentage		1.00%			1.00%
Debt Instrument, Periodic Payment	$ 560	$ 560
Debt Instrument, Term	18 months	18 months
PPP Loan [Member] | Final Payment [Member]
NOTES PAYABLE (Details) [Line Items]
Debt Instrument, Periodic Payment	$ 614	$ 613

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INCOME TAXES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2017
INCOME TAXES (Details) [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	21.00%
Operating Loss Carryforwards (in Dollars)	$ 27.5
Operating Loss Carryforwards, Expiration Date	2027
Domestic Tax Authority [Member]
INCOME TAXES (Details) [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%		35.00%

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INCOME TAXES (Details) - Schedule of Deferred Tax Assets and Liabilities - USD ($)	Dec. 31, 2020	Dec. 31, 2019
Schedule of Deferred Tax Assets and Liabilities [Abstract]
Statutory Depletion Carry Forward	$ 361,444	$ 367,149
Net Operating Loss	7,361,230	6,489,891
Other	583,281	595,990
Share-Based Compensation	86,510	86,510
Capital Loss / AMT Credit Carry Forward	9,458	9,458
Charitable Contributions Carry Forward	3,396	3,890
Allowance for Doubtful Accounts	671,861	466,060
Oil and Gas Properties and Fixed Assets	4,860,069	5,404,787
Investment in RMX Joint Venture	342,569	(1,238,551)
Section 481(a) Adjustments	(107,432)	(214,859)
	14,172,386	11,970,325
Valuation Allowance	(14,172,386)	(11,970,325)
Net Deferred Tax Asset	$ 0	$ 0

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INCOME TAXES (Details) - Schedule of Effective Income Tax Rate Reconciliation - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Schedule of Effective Income Tax Rate Reconciliation [Abstract]
Tax (benefit) computed at statutory rate of 21% at December 31, 2020 and 2019, respectively	$ (1,708,463)	$ (71,680)
Meals & Entertainment	740	1,583
PPP Loan Forgiveness	(41,538)	0
Prior-year true-up for Books	(126,541)	1,461,914
Deferred State Taxes, net of federal benefit	(330,367)	214,161
Other non-deductible expenses	4,108	59,674
Change in valuation allowance	2,202,061	(1,665,652)
Provision (benefit)	$ 0	$ 0

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INCOME TAXES (Details) - Schedule of Effective Income Tax Rate Reconciliation (Parentheticals)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Schedule of Effective Income Tax Rate Reconciliation [Abstract]
Statutory rate	21.00%	21.00%

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INCOME TAXES (Details) - Schedule of Components of Income Tax Expense (Benefit) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Schedule of Components of Income Tax Expense (Benefit) [Abstract]
Current tax provision (benefit) - federal	$ 0	$ 0
Current tax provision (benefit) - state	0	0
Deferred tax provision (benefit) - federal	0	0
Deferred tax provision (benefit) - state	0	0
Total provision (benefit)	$ 0	$ 0

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SERIES B PREFERRED STOCK (Details) - Series B Preferred Stock [Member] - USD ($)		12 Months Ended
	Mar. 07, 2018	Dec. 31, 2020	Mar. 06, 2018
SERIES B PREFERRED STOCK (Details) [Line Items]
Preferred Stock, Value, Issued (in Dollars)	$ 20,124,000
Preferred Stock, Shares Issued	2,012,400
Preferred Stock, Shares Authorized			3,000,000
Preferred Stock, Dividend Rate, Percentage	3.50%
Convertible Preferred Stock, Terms of Conversion		The Series B Convertible Preferred Stock is convertible at the option of the security holder at the rate of ten shares of common stock for one share of Series B Convertible Preferred Stock. The Series B Preferred Stock has never been registered under the Securities Exchange Act of 1934, and no market exists for the shares. Additionally, the Series B Convertible Preferred shares will automatically convert to common at any time in which the Volume Weighted Average Price (“VWAP”) of the common stock exceeds $3.50 per share for 20 consecutive trading days, the shares are registered with the SEC and the volume of common shares trades exceeds 200,000 shares per day.
Preferred Stock Dividends, Shares		76,290
Dividends, Preferred Stock, Paid-in-kind (in Dollars)		$ 762,900

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OPERATING LEASES (Details)	12 Months Ended
	Dec. 31, 2020 USD ($)
San Diego, CA [Member]
OPERATING LEASES (Details) [Line Items]
Operating Leases, Rent Expense, Minimum Rentals	$ 6,148

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OPERATING LEASES (Details) - Lease, Cost - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Lease, Cost [Abstract]
Operating lease expense	$ 200,836	$ 184,374
Financing lease expense	19,137	10,757
Operating – short-term	0	7,886
Short Term - field	6,000	6,000
Total lease expense	$ 225,973	$ 209,017

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OPERATING LEASES (Details) - Lessee, Operating Lease, Liability, Maturity - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Lessee, Operating Lease, Liability, Maturity [Abstract]
2020	$ 179,630
2020	12,588
2020	192,218
2021	24,408
2021	12,588
2021	36,996
2022	0
2022	12,588
2022	12,588
Thereafter	0
Thereafter	7,343
Thereafter	7,343
Total undiscounted lease payments	204,038
Total undiscounted lease payments	45,107
Total undiscounted lease payments	249,145
Less: Amount representing interest	13,679
Less: Amount representing interest	4,409
Less: Amount representing interest	18,088
Total Operating & Financing lease liabilities	190,359
Total Operating & Financing lease liabilities	40,698
Total Operating & Financing lease liabilities	231,057
Current portion of long-term liabilities as September 30, 2019	167,578
Current portion of long-term liabilities as September 30, 2019	10,542
Current portion of long-term liabilities as September 30, 2019	178,120	$ 162,272
Long-term lease liabilities as of September 30, 2019	22,781
Long-term lease liabilities as of September 30, 2019	30,156
Long-term lease liabilities as of September 30, 2019	$ 52,937	$ 231,071

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RELATED PARTY TRANSACTIONS (Details)	12 Months Ended
	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Stephen M. Hosmer, co-president, co-chief executive officer and chief financial officer [Member]
RELATED PARTY TRANSACTIONS (Details) [Line Items]
Due to Related Parties	$ 17,101
Number of Wells, Participated Individually	179
Donald H. Hosmer, co-president and co-chief executive officer [Member]
RELATED PARTY TRANSACTIONS (Details) [Line Items]
Number of Wells, Participated Individually	179
Due from Related Parties	$ 5,385
RMX Resources, LLC [Member]
RELATED PARTY TRANSACTIONS (Details) [Line Items]
Due to Related Parties	23,087	$ 32,367
Prepaid Expense and Other Assets	239,036	$ 2,680,155
Chief Executive Officer [Member]
RELATED PARTY TRANSACTIONS (Details) [Line Items]
Due to Related Parties	14,648
Matrix Oil Corporation (“MOC”) [Member] | Unpaid Salaries [Member] | Certain Matrix Employees [Member]
RELATED PARTY TRANSACTIONS (Details) [Line Items]
Due to Related Parties	$ 1,306,605

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SIMPLE IRA PLAN (Details) - Pension Plan [Member] - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
SIMPLE IRA PLAN (Details) [Line Items]
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	3.00%
Defined Contribution Plan, Cost	$ 41,921	$ 30,336

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CONCENTRATIONS (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
CONCENTRATIONS (Details) [Line Items]
Cash, FDIC Insured Amount	$ 250,000
Cash, Uninsured Amount	$ 1,900,000	$ 3,400,000
Customer Concentration Risk [Member] | Customer A [Member] | Revenue Benchmark [Member]
CONCENTRATIONS (Details) [Line Items]
Concentration Risk, Percentage	32.00%

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CORONAVIRUS AID, RELIEF, AND ECONOMIC SECURITY ACT (“CARES ACT”) (Details) - PPP Loan [Member] - USD ($)	Nov. 10, 2020	Nov. 02, 2020	Apr. 22, 2020
CORONAVIRUS AID, RELIEF, AND ECONOMIC SECURITY ACT (“CARES ACT”) (Details) [Line Items]
Notes Payable to Bank	$ 10,054		$ 207,800
Debt Instrument, Interest Rate, Stated Percentage		1.00%	1.00%
Debt Instrument, Decrease, Forgiveness	198,846
Debt Instrument, Periodic Payment	$ 560	$ 560
Debt Instrument, Term	18 months	18 months
Final Payment [Member]
CORONAVIRUS AID, RELIEF, AND ECONOMIC SECURITY ACT (“CARES ACT”) (Details) [Line Items]
Debt Instrument, Periodic Payment	$ 614	$ 613
Principal Forgiveness [Member]
CORONAVIRUS AID, RELIEF, AND ECONOMIC SECURITY ACT (“CARES ACT”) (Details) [Line Items]
Debt Instrument, Decrease, Forgiveness	197,800
Interest Forgiveness [Member]
CORONAVIRUS AID, RELIEF, AND ECONOMIC SECURITY ACT (“CARES ACT”) (Details) [Line Items]
Debt Instrument, Decrease, Forgiveness	$ 1,046

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LONG-LIVED ASSETS HELD FOR SALE (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020 USD ($)
East Los Angeles [Member]
LONG-LIVED ASSETS HELD FOR SALE (Details) [Line Items]
Assets Held-for-sale, Not Part of Disposal Group	$ 1,900
Asset Retirement Obligation	1,100
Property, Plant and Equipment, Net	846
Oil and Gas Reclamation Liability, Noncurrent	721
Proceeds from Sale of Property, Plant, and Equipment	1,000
Gain (Loss) on Disposition of Property Plant Equipment	(567)
Assets Held-for-sale, Not Part of Disposal Group, Current	1,000
Asset Retirement Obligation, Current	721
Texas Properties [Member]
LONG-LIVED ASSETS HELD FOR SALE (Details) [Line Items]
Asset Retirement Obligation	149
Property, Plant and Equipment, Net	381
Proceeds from Sale of Property, Plant, and Equipment	700
Assets Held-for-sale, Not Part of Disposal Group, Current	$ 529

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SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details)	12 Months Ended
	Dec. 31, 2020 USD ($) $ / Mcf $ / bbl Mcf bbl	Dec. 31, 2019 USD ($) Mcf bbl
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Oil and Gas Property, Successful Effort Method (in Dollars)	$ 5,672,457	$ 7,792,156
Natural Gas [Member]
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | Mcf	(1,515,637)	(890,032)
Oil [Member]
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | bbl	(646,080)	1,052,086
Oil and Gas Properties [Member]
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Proved Oil and Gas Property, Successful Effort Method (in Dollars)	$ 20,800,000
Measurement Input, Discount Rate [Member]
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Oil and Gas Property, Measurement Input	10
PG&E Citygate [Member] | Natural Gas [Member]
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Oil and Gas, Average Sale Price | $ / Mcf	1.985
West Texas Intermediate [Member] | Oil [Member]
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) [Line Items]
Oil and Gas, Average Sale Price | $ / bbl	39.54

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SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities	12 Months Ended
	Dec. 31, 2020 Mcf bbl	Dec. 31, 2019 Mcf bbl
Oil [Member]
Reserve Quantities [Line Items]
Beginning of period | bbl	2,171,000	1,146,400
Proved reserves end of period | bbl	1,541,000	2,171,000
Beginning of period | bbl	232,200	148,600
End of period | bbl	224,900	232,200
Beginning of period | bbl	1,938,800	997,800
End of period | bbl	1,316,100	1,938,800
Revisions of previous estimates | bbl	(646,080)	1,052,086
Production | bbl	(31,210)	(27,663)
Extensions, discoveries and improved recovery | bbl	47,290	22,042
Sales of minerals in place | bbl		(21,865)
Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning of period | Mcf	4,306,900	2,986,200
Proved reserves end of period | Mcf	2,660,500	4,306,900
Beginning of period | Mcf	2,790,300	1,914,900
End of period | Mcf	691,900	2,790,300
Beginning of period | Mcf	1,516,600	1,071,300
End of period | Mcf	1,968,600	1,516,600
Revisions of previous estimates | Mcf	(1,515,637)	(890,032)
Production | Mcf	(160,406)	(292,472)
Extensions, discoveries and improved recovery | Mcf	29,643	2,516,046
Sales of minerals in place | Mcf		(12,842)

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SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure - Proved Developed, Proved Non-Producing and Proved Undeveloped Reserves [Member]	Dec. 31, 2020 USD ($)
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
2021	$ 8,954,000
2022	6,750,000
2023	1,404,500
Thereafter	0
	$ 17,108,500

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SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Abstract]
Future cash inflows	$ 65,939,300	$ 143,045,000
Future production costs	(28,008,100)	(28,967,400)
Future development costs	(17,108,400)	(20,587,800)
Future income tax expense	(6,246,840)	(28,046,940)
Future net cash flows	14,575,960	65,442,860
10% annual discount for estimated timing of cash flows	(7,134,925)	(35,801,989)
Standardized measure of discounted future net cash flows	7,441,035	29,640,871
Sales of oil and gas produced, net of production costs	(351,478)	(624,744)
Revisions of previous quantity estimates	(31,231,533)	14,035,099
Net changes in prices and production costs	(617,847)	(14,331,770)
Sales of minerals in place	0	(272,507)
Extensions, discoveries and improved recovery	587,311	2,157,052
Accretion of discount	(100,504)	2,900,123
Net change in income tax	9,514,215	(4,868,296)
Net increase (decrease)	$ (22,199,836)	$ (1,005,043)

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SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Future Development Costs, Oil and Gas Production	Dec. 31, 2020 USD ($)
Proved Developed Reserves [Member]
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Future Development Costs, Oil and Gas Production [Line Items]
Estimated Future Costs, Year 1	$ 0
Estimated Future Costs, Year 2	0
Estimated Future Costs, Year 3	0
Proved Non-Producing Reserves [Member]
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Future Development Costs, Oil and Gas Production [Line Items]
Estimated Future Costs, Year 1	54,000
Estimated Future Costs, Year 2	0
Estimated Future Costs, Year 3	0
Proved Undeveloped Reserves [Member]
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Future Development Costs, Oil and Gas Production [Line Items]
Estimated Future Costs, Year 1	8,900,000
Estimated Future Costs, Year 2	6,750,000
Estimated Future Costs, Year 3	1,404,500
Proved Developed, Proved Non-Producing and Proved Undeveloped Reserves [Member]
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) - Schedule of Future Development Costs, Oil and Gas Production [Line Items]
Estimated Future Costs, Year 1	8,954,000
Estimated Future Costs, Year 2	6,750,000
Estimated Future Costs, Year 3	$ 1,404,500