10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended March 31, 2023

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File No. 000-55912

ROYALE ENERGY, INC.

(Exact name of registrant as specified in its charter)

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

1530 Hilton Head Rd, Suite 205

El Cajon, CA 92021

(Address of principal executive offices) (Zip Code)

(619) 383-6600

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: None.

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 of 1934 during the preceding 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 is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Check one:

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 May 30, 2023, a total of 65,143,012 shares of registrant’s common stock were outstanding.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION	3
Item 1. Financial Statements	3
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
Item 3. Quantitative and Qualitative Disclosures About Market Risk	19
Item 4. Controls and Procedures	19
PART II.  OTHER INFORMATION	20
Item 1. Legal Proceedings	20
Item 1A. Risk Factors	20
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	20
Item 3. Defaults Upon Senior Securities	20
Item 4. Mine Safety Disclosures	20
Item 5. Other Information	20
Item 6. Exhibits	20
Signatures	21

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

	March 31, 2023		December 31, 2022
ASSETS	(unaudited)
Current Assets
Cash and Cash Equivalents	$	1,046,900	$	1,650,507
Restricted Cash		2,609,555		2,249,627
Other Receivables, net		950,438		943,633
Revenue Receivables		589,900		701,937
Prepaid Expenses		1,686,049		1,935,346
Deferred Drilling Costs		979,686		1,219,177
Prepaid Drilling to RMX Resources, LLC		819,062		114,563
Total Current Assets		8,681,590		8,814,790
Right of Use Assets – Leases		314,913		335,213
Other Assets		589,865		589,865
Oil and Gas Properties, (Successful Efforts Basis),  Equipment and Fixtures, net		2,165,722		2,040,320
Total Assets		11,752,090		11,780,188

See notes to unaudited condensed consolidated financial statements.

3

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

	March 31, 2023			December 31, 2022
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)	(unaudited)
Current Liabilities:
Accounts Payable and Accrued Expenses	$	5,789,204		$	5,528,829
Royalties Payable		612,925			612,925
Due to RMX Resources, LLC		23,087			23,087
Accrued Liabilities		205,556			208,307
Asset Retirement Obligation - Current		675,000			675,000
Deferred Drilling Obligation		6,840,855			8,129,965
Operating Leases - Current		83,641			81,995
Total Current Liabilities		14,230,268			15,260,108
Noncurrent Liabilities:
Accrued Liabilities - Long Term		1,306,605			1,306,605
Accrued Unpaid Guaranteed Payments		1,616,205			1,616,205
Operating Leases - Long-Term		232,736			254,858
Asset Retirement Obligation		2,886,248			2,867,479
Total Liabilities		20,272,062			21,305,255
Mezzanine Equity:
Convertible Preferred Stock, Series B, $10 par value, 3.5% annual dividend, 2,381,986 and 2,361,154 shares issued and outstanding as of March 31, 2023 and December 31, 2022 respectively		23,819,843			23,611,536
Stockholders' Equity (Deficit):
Common Stock, .001 Par Value, 280,000,000 Shares Authorized,  61,876,957 shares issued and outstanding as of March 31, 2023 and December 31, 2022		61,876			61,876
Additional Paid in Capital		54,447,923			54,447,923
Accumulated Deficit		(86,849,614	)		(87,646,402	)
Total Stockholders' Equity (Deficit)		(32,339,815	)		(33,136,603	)
Total Liabilities and Stockholders' Equity (Deficit)	$	11,752,090		$	11,780,188

See notes to unaudited condensed consolidated financial statements.

4

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

	For the three months ended			For the three months ended
	March 31, 2023			March 31, 2022
Revenues:
Oil, NGL and Gas Sales		558,451			507,214
Supervisory Fees and Other		13,374			9,291
Total Revenues		571,825			516,505
Costs and Expenses:
Oil and Gas Lease Operating		575,797			414,468
Depreciation, Depletion and Amortization		59,432			124,676
Well Equipment Write Down		9,840			-
Legal and Accounting		27,892			188,271
Marketing		88,819			55,946
General and Administrative		456,481			537,467
Total Costs and Expenses		1,218,261			1,320,828
Gain on Turnkey Drilling		1,594,354			345,605
Gain (Loss) From Operations		947,918			(458,718	)
Other Income (Expense):
Interest Expense		(549	)		(2,277	)
Gain on Other		54,975			-
Gain on Settlement of Accounts Payable		-			408,644
Income (Loss) Before Income Tax Expense		1,002,344			(52,351	)
Income Tax Provision		-			-
Net Income (Loss)		1,002,344			(52,351	)
Less: Preferred Stock Dividend		205,556			198,516
Net Income (Loss) available to common stock		796,788			(250,867	)
Shares used in computing Basic Net Income/Loss per share		61,876,957			56,239,715
Basic Income (Loss) per share		0.01			(0.00	)
Shares used in computing Diluted Net Income (Loss) per share		88,990,264			56,239,715
Diluted Income (Loss) per share		0.01			(0.00	)

See notes to unaudited condensed consolidated financial statements.

5

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

FOR THE THREE MONTHS ENDED MARCH 31, 2023 AND 2022

	For the Three Months Ended
	March 31, 2023			March 31, 2022
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)		1,002,344		(52,351	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Used in Operating Activities:
Depreciation, Depletion and Amortization		59,432		124,676
Gain on Turnkey Drilling Programs		(1,594,354	)	(345,605	)
Gain on Settlement of Accounts Payable		-		(408,644	)
Gain on Other		(54,975	)	-
Well Equipment Write Down		9,840		-
Right of use asset depreciation		2,750		2,746
Changes in assets and liabilities:
Other & Revenue Receivables		105,232		(50,353	)
Prepaid Expenses and Other Assets		(455,202	)	(486,487	)
Accounts Payable and Accrued Expenses		29,931		878,548
Net Cash Used in Operating Activities		(895,002	)	(337,470	)
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for Oil and Gas Properties and Other Capital Expenditures		(618,251	)	(1,567,239	)
Proceeds from Turnkey Drilling Programs		1,272,500		2,495,000
Net Cash Provided by Investing Activities		654,249		927,761
CASH FLOWS FROM FINANCING ACTIVITIES
Principal Payments on Long-Term Debt		(2,926	)	(45,845	)
Net Cash Used in Financing Activities		(2,926	)	(45,845	)
Net Change in Cash and Cash Equivalents		(243,679	)	544,446
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period		3,900,134		4,222,804
Cash, Cash Equivalents, and Restricted Cash at End of Period		3,656,455		4,767,250
Cash Paid for Interest		549		732
Cash Paid for Taxes		2,850		2,050

SUPPLEMENTAL DISCLOSURES OF NON-CASH INVESTING & FINANCING TRANSACTIONS:
Series B Paid-In-Kind Dividends	205,556	198,516

See notes to unaudited condensed consolidated financial statements.

6

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)

FOR THE THREE MONTHS ENDED MARCH 31, 2023 AND 2022
(UNAUDITED)

	Common Stock
	Number of Shares Issued and Outstanding		Amount		Additional Paid in Capital		Accumulated Comprehensive Deficit			Total Stockholders' Deficit
December 31, 2021 Balance		56,239,715	$	56,239	$	54,058,554	$	(86,685,036	)	$	(32,570,243	)
Preferred Series B 3.5% Dividend		-		-		-		(198,516	)		(198,516	)
Net Loss		-		-		-		(52,351	)		(52,351	)
March 31, 2022 Balance		56,239,715		56,239	$	54,058,554	$	(86,935,903	)	$	(32,821,110	)
December 31, 2022 Balance		61,876,957	$	61,876	$	54,447,923	$	(87,646,402	)	$	(33,136,603	)
Net Income		-		-		-		1,002,344			1,002,344
Preferred Series B 3.5% Dividend		-		-		-		(205,556	)		(205,556	)
March 31, 2023 Balance		61,876,957	$	61,876	$	54,447,923	$	(86,849,614	)	$	(32,339,815	)

See notes to unaudited condensed consolidated financial statements.

7

ROYALE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – BASIS OF PRESENTATION: ACCOUNTING STANDARDS

Consolidation

In the opinion of management, the accompanying unaudited condensed consolidated Financial Statements (“statements”) include all adjustments necessary to present fairly the Company’s financial position and the results of its operations and cash flows for the periods presented.

The accompanying unaudited consolidated financial statements, which include the accounts of Royale Energy, Inc. (sometimes referred to as the “Company” “we,” “our,” “us,” “Royale Energy,” or “Royale”), Royale Energy Funds, Inc. (“REF”), and Matrix Oil Management Corporation and its subsidiaries, have been prepared in accordance with GAAP for interim consolidated financial information pursuant to the rules and regulations of the SEC under Article 10 of Regulation S-X and the instructions to Form 10-Q. Accordingly, certain information and footnote disclosures normally included in our audited financial statements have been condensed or omitted pursuant to the SEC’s rules and regulations. Significant intercompany transactions have been eliminated in the consolidation. In management’s opinion, all adjustments considered necessary for a fair presentation have been included, disclosures are adequate, and the presented information is not misleading.

The consolidated balance sheet as of December 31, 2022 was derived from the audited financial statements at that date. The accompanying consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2022 as filed with the SEC. Operating results for the three months ended March 31, 2023 are not necessarily indicative of the results that may be expected for the fiscal year ending December 31, 2023, or for any other period. 

Liquidity and Going Concern

The primary sources of liquidity have historically been issuances of common stock, oil and gas sales through ongoing operations and the sale of oil and gas properties. There are factors that give rise to substantial doubt about our ability to meet liquidity demands, and we anticipate that our primary sources of liquidity will be from the issuance of debt and/or equity, the sale of oil and natural gas property participation interests through our normal course of business and the sale of non-strategic assets.

At March 31, 2023, our consolidated financial statements reflect a working capital deficiency of $5,548,678. Although we had net income of $1,002,344 for the three months ended March 31, 2023, there is substantial doubt about our ability to continue as a going concern. The accompanying consolidated financial statements do not include any adjustments that might be necessary if we are unable to continue as a going concern.

Management’s plans to alleviate the going concern by cost control measures that include, among other things, the reduction of overhead costs and the sale of non-strategic assets, and obtaining additional financing. There is no assurance that additional financing will be available when needed or that we will be able to obtain any financing on terms acceptable to us and whether we will become profitable and generate positive operating cash flow. If the we are 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.

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.

Material estimates that are particularly susceptible to significant change relate to the estimate of Company oil and gas reserves prepared by an independent engineering consultant. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proven reserves. Estimated reserves are used in the calculation of depletion, depreciation and amortization, unevaluated property costs, impairment of oil and natural gas properties, estimated future net cash flows, taxes, and contingencies.

8

Revenue Recognition

A significant portion of our revenues are derived from the sale of crude oil, condensate, natural gas liquids (“NGLs”) and natural gas under spot and term agreements with our customers as follows:

	For the three months ended March 31
	2023		2022
Oil & Condensate Sales	$	347,658	$	359,514
Natural Gas Sales		208,883		146,418
NGL Sales		1,910		1,282
Total	$	558,451	$	507,214

The pricing in our hydrocarbon sales agreements are variable, determined using various published benchmarks which are adjusted for negotiated quality and location differentials. As a result, revenue collected under our agreements with customers is highly dependent on the market conditions and may fluctuate considerably as the hydrocarbon market prices rise or fall. Typically, our customers pay us monthly, within a short period of time after we deliver the hydrocarbon products. As such, we do not have any financing element associated with our contracts. We do not have any issues related to returns or refunds, as product specifications are standardized for the industry and are typically measured when transferred to a common carrier or midstream entity, and other contractual mechanisms (e.g., price adjustments) are used when products do not meet those specifications.

In limited cases, we may also collect advance payments from customers as stipulated in our agreements; payments in excess of recognized revenue are recorded as contract liabilities on our consolidated balance sheets.

Under our hydrocarbon sales agreements, the entire consideration amount is variable either due to pricing and/or volumes. We recognize revenues in the amount of variable consideration allocated to distinct units of hydrocarbons transferred to a customer. Such allocation reflects the amount of total consideration we expect to collect for completed deliveries of hydrocarbons and the terms of variable payment relate specifically to our efforts to satisfy the performance obligations under these contracts. Our performance obligations under our hydrocarbon sales agreements are to deliver either the entire production from the dedicated wells or specified contractual volumes of hydrocarbons.

We often serve as the operator for jointly owned oil and gas properties. As part of this role, we perform activities to explore, develop and produce oil and gas properties in accordance with the joint operating arrangement and collective decisions of the joint parties. Other working interest owners reimburse us for costs incurred based on our agreements. We determined that these activities are not performed as part of customer relationships, and such reimbursements are recorded as cost reimbursements.

We commonly market the share of production belonging to other working interest owners as the operator of jointly owned oil and gas properties. Those marketing activities are carried out as part of the collaborative arrangement, and we do not purchase or otherwise obtain control of other working interest owners’ share of production. Therefore, we act as a principal only with respect to the sale of our share of production and recognize revenue for the volumes associated with our net production.

We frequently sell a portion of the working interest in each well we drill or participate in to third-party investors and retain a portion of the prospect for our own account. We typically guarantee a cost to drill to the third-party drilling participants and record a loss or gain on the difference between the guaranteed price and the actual cost to drill the well. When monies are received from third parties for future drilling obligations, we record the liability as Turnkey Drilling Obligations. Once the contracted depth for the drilling of the well is reached and a determination as to the commercial viability of the well (typically call “Casing Point Election” or “Logging Point”), the difference in the actual cost to drill and the guaranteed cost is recorded as income or expense depending on whether there was a gain or loss.

Crude oil and condensate

For the crude sales agreements, we satisfy our performance obligations and recognize revenue once customers take control of the crude at the designated delivery points, which include pipelines, trucks, or vessels.

9

Natural gas and NGLs

When selling natural gas and NGLs, we engage midstream entities to process our production stream by separating natural gas from the NGLs. Frequently, these midstream entities also purchase our natural gas and NGLs under the same agreements. In these situations, we determined the performance obligation is complete and satisfied at the tailgate of the processing plant when the natural gas and NGLs become identifiable and measurable products. We determined the plant tailgate is the point in time where control is transferred to midstream entities and they are entitled to significant risks and rewards of ownership of the natural gas and NGLs.

The amounts due to midstream entities for gathering and processing services are recognized as shipping and handling cost and included as lease operating expense in our consolidated statement of operations, since we make those payments in exchange for distinct services except for natural gas sold to Pacific Gas & Electric (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

We sponsor turnkey drilling arrangements in proved and unproved properties. The contracts require that participants pay us the full contract price upon execution of the drilling agreement. Each participant earns an undivided interest in the well bore at the completion of the well. A portion of the funds received in advance of the drilling of a well from a working interest participant are held for the expressed purpose of drilling a well (“Drilling Funds”). If something changes, we may designate these funds for a substitute well. Under certain conditions, a portion of these funds may be required to be returned to a participant. Once the well is drilled, the Drilling Funds are used to satisfy the drilling cost.

We manage these Turnkey Agreements for the participants of the well. We segregate the collections of pre-drilling AFE amounts 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 the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 932-323-25 and 932-360. We manage 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.

Restricted Cash

Prior to commencement of drilling, we classify Drilling Funds as restricted cash based on guidance codified as under ASC 230-10-50-8. In the event that progress payments are made from these funds; they are recorded as Prepaid Expenses and Other Current Assets.

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

	March 31, 2023		December 31, 2022
Cash and Cash Equivalents	$	1,046,900	$	1,650,507
Restricted Cash		2,609,555		2,249,627
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows	$	3,656,455	$	3,900,134

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 condensed consolidated statements of operations. 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. 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.

10

Other Receivables, net

Other receivables, net consist of joint interest billing 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 March 31, 2023, and December 31, 2022, we maintained an allowance for uncollectable accounts of $2,749,445 and $2,757,549, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue.

Fair Value Measurements

According to Fair Value Measurements and Disclosures Topic of the FASB ASC, 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, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible as well as considers counterparty credit risk in its assessment of fair value. Carrying amounts of our financial instruments, including cash equivalents, accounts receivable, accounts payable and accrued liabilities, approximate their fair values as of the balance sheet dates because of their generally short maturities.

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

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

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

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

At March 31, 2023 and December 31, 2022, we do not have any financial assets measured and recognized at fair value on a recurring basis. We estimate asset retirement obligations (ARO’s) pursuant to the provisions of ASC 410, “Asset Retirement and Environmental Obligations”. The estimates of the fair value the ARO’s are based on discounted cash flow projections using numerous estimates, assumptions, and judgements regarding such factors as the existence of a legal obligation for an ARO, amounts and timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates.

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.

Other receivables will be reflected as Level 3. The fair value of our other receivables is based on credit factors, oil and gas well reserve profiles and commodity prices both current and forecast specific to these financial instruments.

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Fair Values - Non-recurring

We applied the provisions of the fair value measurement standard to our non-recurring, non-financial measurements including oil and natural gas property impairments and other long-lived asset impairments. These items are not measured at fair value on a recurring basis but are subject to fair value adjustments only in certain circumstances.

Dividends on Series B Convertible Preferred Stock

The Series B Convertible Preferred Stock, (“Preferred Stock”) has an obligation to pay a 3.5% cumulative dividend, in kind or cash, on a quarterly basis. The Board of Directors authorized the issuance of the Preferred Stock, for the settlement of dividends accumulated through December 31, 2023. We accrued $205,556 and $198,516 for dividends related to the Preferred Stock during the first quarters of 2023 and 2022, respectively. Each quarter, we charge retained earnings for the accumulating dividend as the amounts add to the liquidation preference of the Preferred Stock. For further information regarding the Preferred Stock see Note 3, below.

ACCOUNTING STANDARDS

Recently 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 Securities and Exchange Commission (“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 SEC) 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. We adopted this new standard on January 1, 2023, and there is no material impact on our consolidated financial statements. For further information regarding our adoption of this standard, see Note 7 - ALLOWANCE FOR CREDIT LOSSES below.

NOTE 2 – OIL AND GAS PROPERTY AND EQUIPMENT AND FIXTURES

Oil and gas properties, equipment and fixtures consist of the following:

	March 31,			December 31,
	2023			2022
	(Unaudited)
Oil and Gas
Producing properties, including drilling costs	$	5,898,195		$	5,712,436
Undeveloped properties		148,989			148,989
Lease and well equipment		3,307,878			3,317,718
		9,355,062			9,179,143
Accumulated depletion, depreciation & amortization		(7,198,628	)		(7,142,506	)
Net capitalized costs Total		2,156,434			2,036,637
Commercial and Other
Vehicles		40,061			40,061
Furniture and equipment		1,103,362			1,097,428
		1,143,423			1,137,489
Accumulated depreciation		(1,134,135	)		(1,133,806	)
		9,288			3,683
Net capitalized costs Total	$	2,165,722		$	2,040,320

12

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.

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 are expensed as incurred. Major renewals and improvements are capitalized, and the assets replaced are retired.

The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use. Interest costs, to the extent they are incurred to finance expenditures during the construction phase, are included in property, plant and equipment and are depreciated over the service life of the related assets.

We use the “successful efforts” method to account for our exploration and production activities. Under this method, we accumulate our proportionate share of costs on a well-by-well basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred and capitalize expenditures for productive wells. We amortize the costs of productive wells under the unit-of-production method.

We carry, as an asset, exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred.

Acquisition costs of proved oil and gas 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 our wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labor costs to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity. Proved oil and gas properties held and used, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable.

We estimate the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts and whether carrying amounts should be impaired. We perform the evaluation of carrying amounts at least annually or when economic events or commodity prices indicate that a substantial and measurable change in future cash flows has occurred. Cash flows used in impairment evaluations are developed using updated evaluation assumptions for crude oil and natural gas commodity prices. Annual volumes are based on field production profiles, which are also updated annually.

Impairment analyses are generally based on proved reserves. An asset group would be further assessed if the undiscounted cash flows were less than its’ carrying value. Impairments are measured by the amount the carrying value exceeds fair value. During the three months ended March 31, 2023, and 2022, no impairment losses were incurred.

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 Energy expects to hold the properties. The valuation allowances are reviewed at least annually.

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Upon the sale or retirement of a complete field of a proven property, we eliminate the cost from our books, and the resulting gain or loss is recorded to the 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 the 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 our turnkey drilling agreements include unproved property, total drilling costs incurred to satisfy our obligations are recovered by the total funds received under the agreements. Any excess funds are recorded as a Gain on Turnkey Drilling Programs, and any costs not recovered are capitalized and accounted for under the “successful efforts” method.

We sponsor turnkey drilling agreement arrangements in unproved properties as a pooling of assets in a joint undertaking, whereby proceeds from participants are reported as Deferred Drilling Obligations, and then reduced as costs to complete our obligations are incurred with any excess booked against our property account to reduce any basis in our own interest. Gains on Turnkey Drilling Programs represent funds received from turnkey drilling participants in excess of all costs we incur during the drilling programs (e.g., lease acquisition, exploration and development costs), including costs incurred on behalf of participants and costs incurred for our own account; and are recognized only upon making this determination after our obligations have been fulfilled.

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

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

A certain portion of the turnkey drilling participant’s funds received are non-refundable. We hold all funds invested as Deferred Drilling Obligations until drilling is complete. Occasionally, drilling is delayed for various reasons such as weather, permitting, drilling rig availability and/or contractual obligations. At March 31, 2023, and December 31, 2022, we had Deferred Drilling Obligations of $6,840,855 and $8,129,965, respectively.

If we are unable to drill the wells, and a suitable replacement well is not found, we would retain the non-refundable portion of the contract and return the remaining funds to the participant. Included in Restricted Cash are amounts for use in completion of turnkey drilling programs in progress.

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.

NOTE 3 – SERIES B PREFERRED STOCK

The Preferred Stock is convertible at the option of the security holder at the rate of ten shares of common stock for one share of Preferred Stock. The Preferred Stock has never been registered under the Exchange Act and no market exists for the Preferred Stock. Additionally, the Preferred Stock will automatically convert into shares of common stock at any time in which the Volume Weighted Average Price (“VWAP”) of our common stock exceeds $3.50 per share for 20 consecutive trading days, the shares of our common stock are registered with the SEC and the trading volume of common shares exceeds 200,000 shares per day. Beginning in 2020, the holders of the Preferred Stock became entitled to vote the number of shares of our common stock into which the shares of Preferred Stock would be entitled to convert.

In accordance with ASC 480-10-S99-1.02, we have determined that the conversion or redemption of the Preferred Stock 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 2023 and 2022, the board authorized the payment of each quarterly dividend on shares of Preferred Stock, as Paid-In-Kind shares to be paid immediately following the end of the quarter. For the quarter ending March 31, 2023, we accrued 20,555 shares with a value of $205,556. During 2023 and 2022 no cash was used to pay dividends on shares of the Preferred Stock.

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NOTE 4 – LOSS PER SHARE

Basic and diluted loss per share are calculated as follows:

	Three Months Ended March 31,
	March 31, 2023				March 31, 2022
	Basic		Diluted		Basic			Diluted
Net Income (Loss)	$	1,002,344		1,002,344	$	(52,351	)		(52,351	)
Less: Preferred Stock Dividend		205,556		205,556		198,516			198,516
Net Income (Loss) Attributable to Common Shareholders	$	796,788	$	796,788	$	(250,867	)	$	(250,867	)
Weighted average common shares outstanding		61,876,957		61,876,957		56,239,715			56,239,715
Effect of dilutive securities		-		27,113,307		-			-
Weighted average common shares, including Dilutive effect		61,876,957		88,990,264		56,239,715			56,239,715
Per share:
Net Income (Loss)	$	0.01		0.01	$	(0.00	)		(0.00	)

For the three months ended March 31, 2023 and 2022, we had dilutive securities of 27,113,307 and 26,468,433, respectively. In 2022, these securities were not included in the dilutive loss per share, due to their antidilutive nature.

NOTE 5 – 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. At the end of 2015, management reviewed the reliability of our net deferred tax assets, and due to our continued cumulative losses in recent years, the we concluded it is not “more-likely-than-not” our deferred tax assets will be realized. As a result, we will continue to record a full valuation allowance against the deferred tax assets in 2023.

A reconciliation of our provision for income taxes and the amount computed by applying the statutory income tax rates at March 31, 2023 and 2022, respectively, to pretax income is as follows:

	For the three months ended
	March 31, 2023			March 31, 2022
Tax benefit computed at statutory rate of 21% at March 31, 2023 and 2022, respectively	$	210,493			(10,994	)
Increase (decrease) in taxes resulting from:
State tax / percentage depletion / other
Other non-deductible expenses		367			3
Change in valuation allowance		(210,860	)		10,991
Provision (benefit)	$			$

NOTE 6 – ISSUANCE OF COMMON STOCK

In April 2023, CIC RMX LP exercised in full its warrant to purchase shares of our common stock. CIC RMX LP elected to make a cashless exercise of the Warrant and as a result we issued 3,266,055 shares of common stock to the Warrant holder. During the three months ended March 31, 2023, and 2022, no common shares were issued in lieu of cash payments.

NOTE 7 - ALLOWANCE FOR CREDIT LOSSES

We measure our allowance for losses on other receivables including, under ASC 326. The following table summarizes the activity in the balance of allowance for credit losses on other receivables for the period indicated:

Balance at December 31, 2022	$	2,757,549
Provision for credit loss		-
Write-offs charged against the allowance		8,104
Balance at March 31, 2023	$	2,749,445

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

FORWARD-LOOKING STATEMENTS

In addition to historical information contained herein, certain information contained in this Quarterly Report on Form 10-Q, as well as other written and oral statements made or incorporated by reference from time to time by the Company and our representatives in other reports, filings with the SEC, press releases, conferences or otherwise, may be deemed to be “forward-looking statements” within the meaning of Section 21E of the Exchange Act. This information includes, without limitation, statements concerning the Company’s future financial position and results of operations, planned capital expenditures, business strategy and other plans for future operations, the future mix of revenues and business, customer retention, project reversals, commitments and contingent liabilities, future demand, and industry conditions. While we believe our forward-looking statements are based upon reasonable assumptions, we can give no assurance that such expectations will prove to have been correct. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Generally, the words “anticipate,” “believe,” “estimate,” “expect,” “may” and similar expressions, identify forward-looking statements, which generally are not historical in nature. Actual results could differ materially from the results described in the forward-looking statements due to the risks and uncertainties set forth under “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” elsewhere in this Quarterly Report on Form 10-Q, in the Company’s Annual Report on Form 10-K for the year ended December 31, 2022, and those described from time to time in our future reports filed with the SEC.

The following discussion is qualified in its entirety by, and should be read in conjunction with, the Company’s financial statements, including the notes thereto, included in this Quarterly Report on Form 10-Q and the Company’s Annual Report on Form 10-K for the year ended December 31, 2022.

OVERVIEW

Royale is an independent oil and natural gas producer. Royale’s principal lines of business are the production and sale of oil and natural gas, acquisition of oil and gas lease interests and proved reserves, drilling of both exploratory and development wells, and sales of fractional working interests in wells to be drilled by Royale. Since 1993, Royale has primarily acquired and developed producing and non-producing natural gas properties in California. In December 2018, Royale became the operator of a newly acquired field in Texas. The most significant factors affecting our 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.

RESULTS OF OPERATIONS

For the three months ended March 31, 2023, and 2022, we had net income of $1,002,344 and net loss of $52,351, respectively. The difference was primarily due to the completion of one oil well in Texas and participating in the drilling and completion of an oil well in the Texas Permian basin where we recognized a gain on turnkey drilling of $1,594,354.

During the first three months of 2023, revenues from oil and gas production increased $51,237 or 10.1%, to $558,451 from revenues of $507,214 during the first three months of 2022. This increase was mainly due to higher natural gas commodity prices during the period in 2023. The net sales volume of oil and condensate for the three months ended March 31, 2023, were approximately 4,761 barrels with an average price of $73.03 per barrel, versus 3,889 barrels with an average price of $92.44 per barrel for the three months of 2022. This represents an increase in net sales volume of 872 barrels or 22.4%, which was due to higher production volumes due to drilling efforts in 2022 and the first quarter of 2023. The net sales volume of natural gas for the three months ended March 31, 2023, was approximately 30,119 Mcf with an average price of $6.94 per Mcf, versus 33,527 Mcf with an average price of $4.37 per Mcf for the same period in 2022. This represents a decrease in net sales volume of 3,407 Mcf or 10.2%. The decrease in natural gas production volume was due to the natural declines in our existing wells.

Oil and natural gas lease operating expenses increased by $161,329 or 38.9%, to $575,797 for the three months ended March 31, 2023, from $414,468 for the same period in 2022. This increase was mainly due to well equipment repairs and supplies mainly on our Texas Jameson wells to increase production on existing wells.

The aggregate of supervisory fees and other income was $13,374 for three months ended March 31, 2023, an increase of $4,083 from $9,291 during the same period in 2022, mainly due to higher interest income.

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Depreciation, depletion, and amortization expense decreased to $59,432 from $124,676, a decrease of $65,244 or 52.3% for the three months ended March 31, 2023, as compared to the same period in 2022. The depletion rate is calculated using production as a percentage of reserves. This decrease in depletion expense was due to an increase in expected recoverable developed reserves which decreased the depletion rate.

At March 31, 2023, Royale Energy had a Deferred Drilling Obligation of $6,840,855. During the first three months of 2023, we removed $2,561,610 of drilling obligations as we completed one oil well in our Texas Jameson field and participated in the drilling and completion of another oil well in the Permian Basin in Texas, while incurring expenses of $967,256, resulting in a gain of $1,594,354. At March 31, 2022, Royale Energy had a Deferred Drilling Obligation of $8,264,570. During the first three months of 2022, we removed $2,055,369 of drilling obligations as we participated in the drilling and completion of two oil wells in southern California while incurring expenses of $1,709,764, resulting in a gain of $345,605.

General and administrative expenses decreased by $80,986 or 15.1% to $456,481 for the three months ended March 31, 2023, from $537,467 for the same period in 2022. This decrease was mainly due to lower employee related expenses due to cost reduction measures during the period in 2023. For the first three months of 2023, marketing expenses increased $32,873 or 58.8% to $88,819, compared to $55,946 for the first three months of 2022. Marketing expenses vary from period to period according to the number of marketing events attended by personnel and their associated costs.

Legal and accounting expense decreased to $27,892 for the three-month period in 2023, compared to $188,271 for the same period in 2022, a $160,379 or 85.2% decrease. This decrease was primarily due to the audit fees normally expensed in the first quarter but in 2023 will be recognized during the 2^nd quarter 2023 when the audit was performed.

During the three months ended March 31, 2023, we recorded a gain of $54,975 on other as we reconciled employee related items previously recorded as liabilities. During the three months ended March 31, 2022, we recorded a gain of $408,644 on settlement of accounts payable for a reduced amount.

CAPITAL RESOURCES AND LIQUIDITY

At March 31, 2023, we had current assets totaling $8,681,590 and current liabilities totaling $14,230,268, a $5,548,678 working capital deficit. We had $1,046,900 in cash and $2,609,555 in restricted cash at March 31, 2023, compared to $1,650,507 in cash and $2,249,627 in restricted cash at December 31, 2022.

In accordance with ASC 480-10-S99 we reclassified the Series B Convertible Preferred Stock from Permanent Equity to Mezzanine capital as a result of the change in voting rights provided at the time of issuance. For more information, see Note 3 – Series B Convertible Preferred Stock.

At March 31, 2023, our other receivables, which consist of joint interest billing receivables from direct working interest investors and industry partners, totaled $950,438 compared to $943,633 at December 31, 2022, a $6,805 increase. This increase was mainly due to higher accounts receivable from direct working interest owners due mainly to increased lease operating expenses on our Texas Jameson wells to increase production volumes. At March 31, 2023, revenue receivable was $589,900, a decrease of $112,037, compared to $701,937 at December 31, 2022, mainly due to lower net receivables during the first quarter in 2023, mainly due to lower commodity prices. At March 31, 2023, our accounts payable and accrued expenses totaled $5,789,204, an increase of $260,375 from the accounts payable at December 31, 2022 of $5,528,829 which was mainly due to higher lease operating costs during the first quarter in 2023.

We have had recurring operating and net losses and cash used in operations and the financial statements reflect a working capital deficiency of $5,548,678 and an accumulated deficit of $86,849,614. These factors raise substantial doubt about our ability to continue as a going concern. We anticipate that our primary sources of liquidity will be from the sale of oil and gas in the course of normal operations, the sale of oil and gas property, sales of participation interest and possible issuance of debt and/or equity. If we are unable to generate sufficient cash from operations or financing sources, it may become necessary to curtail, suspend or cease operations, sell property, or enter into financing transaction(s) on less favorable terms; any such outcomes could have a material adverse effect on our business, results of operations, financial position and liquidity. Management has plans to continue to increase revenues by making commitments to participate with industry partners in the drilling of wells in the Permian Basin and in southern California. Although in recent months oil and gas lease expenses have increased due to work performed in our Jameson field, we believe these efforts will ultimately improve production.

17

Operating Activities. Net cash used in operating activities totaled $895,002 and $337,470 for the three months ended March 31, 2023 and 2022, respectively. This difference in cash used was mainly due to lower rate of increases in accounts payable and accrued expenses during the period in 2023 when compared to the period in 2022.

Investing Activities. Net cash provided by investing activities totaled $654,249 and $927,761 for the three months ended March 31, 2023, and 2022, respectively. During the three-month period in 2023, we received approximately $1.3 million in direct working interest investor turnkey drilling investments while our drilling expenditures were $618,251 as we drilled and completed one Texas oil well and participated in the drilling and completion of a Texas Permian basin oil well. During the three-month period in 2022, we received approximately $2.5 million in direct working interest investor turnkey drilling investments while our drilling expenditures were approximately $1.6 million as we participated in the drilling and completion of two southern California wells.

Financing Activities. Net cash used in financing activities totaled $2,926 and $45,845 for the three months ended March 31, 2023, and 2022, respectively. During the periods in 2023 and 2022, cash used in financing activities consisted of principal payments on our notes payable and financing lease payments.

Critical Accounting Estimates

Our critical accounting policies are further disclosed in Note 1 to the consolidated financial statements included in our 2022 Annual Report on Form 10-K.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

Item 4. Controls and Procedures

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Disclosure controls and procedures are controls and other procedures of a registrant designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Exchange Act is properly recorded, processed, summarized and reported, within the time periods specified in the SEC rules and forms. Disclosure controls and procedures include processes to accumulate and evaluate relevant information and communicate such information to a registrant’s management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.

As of December 31, 2022, our management, including our Chief Executive and Chief Financial Officers evaluated the effectiveness of the design and operation of our disclosure controls and procedures, as required by Rule 13a-15 of the Exchange Act. Based on the evaluation described above, the company concluded that there was a material weakness in our disclosure controls and procedures. These controls and procedures are based on the definition of disclosure controls and procedures in Rule 13a-15(e) and Rule 15d-15(e) promulgated under the Securities Exchange Act of 1934. 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.

As a result of the review by the CFO and CEO, the material weakness was identified as listed below.

● In connection with the audit of our 2022 and 2021 consolidated financial statements, management has identified a material weakness that exists because we did not maintain effective controls over our financial close and reporting process, and has concluded that the financial close and reporting process needs additional formal procedures to ensure that appropriate reviews occur on all financial reporting analysis. Management has designed and implemented updated control procedures that we believe will mitigate this material weakness and is monitoring these procedures for effectiveness.

Because of the material weaknesses described above, our management was unable to conclude that our internal control over financial reporting was effective as of the end of period to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with generally accepted accounting principles.

Notwithstanding the material weaknesses described above, our management, including our Chief Executive Officer and Chief Financial Officer, believes that the consolidated financial statements contained in this Report on Form 10-Q fairly present, in all material respects, our financial condition, results of operations and cash flows for the fiscal periods presented in conformity with U.S. generally accepted accounting principles. In addition, the material weakness described did not result in the restatements of any of our audited or unaudited consolidated financial statements or disclosures for any previously reported periods.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

Except for the actions described above, that were taken to address the material weaknesses, there were no changes in our internal controls during the period ended March 31, 2023, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

From time to time, the Company may be involved in various legal proceedings or may be subject to claims that arise in the ordinary course of business. The outcome of any such claims or proceedings cannot be predicted with certainty. As of the date of this filing, management is not aware of any such claims against the Company.

Item 1A. Risk Factors

Not applicable to smaller reporting companies.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

During the period covered by this report, we have not issued any unregistered shares.

Item 3. Defaults Upon Senior Securities

None

Item 4. Mine Safety Disclosures

Not applicable

Item 5. Other Information

None

Item 6. Exhibits

31.1	Rule 13a-14(a)/15d-14(a) Certification
31.2	Rule 13a-14(a)/15d-14(a) Certification
32.1	18 U.S.C. § 1350 Certification
32.2	18 U.S.C. § 1350 Certification
101.INS	Inline XBRL Instance Document
101.SCH	Inline XBRL Taxonomy Extension Schema
101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase
101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase
101.LAB	Inline XBRL Taxonomy Extension Label Linkbase
101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

20

Signatures

Pursuant to the requirements 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: June 26, 2023	/s/ Johnny Jordan
	Johnny Jordan, Chief Executive Officer
Date: June 26, 2023	/s/ Ronald Lipnick
	Ronald Lipnick, Interim Chief Financial Officer

21

EX-31.1

Exhibit 31.1

I, Johnny Jordan, certify that:

1. I have reviewed this report on Form 10-Q 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 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: June 26, 2023	/s/ Johnny Jordan
	Johnny Jordan, Chief Executive Officer

EX-31.2

Exhibit 31.2

I, Ronald Lipnick, certify that:

1. I have reviewed this report on Form 10-Q 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 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: June 26, 2023	/s/ Ronald Lipnick
	Ronald Lipnick, Interim 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, to his knowledge:

(1) the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2023 (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: June 26, 2023	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, Ronald Lipnick, 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, to his knowledge:

(1) the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2023 (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: June 26, 2023	By:	/s/ Ronald Lipnick
		Ronald Lipnick, Interim Chief Financial Officer

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Document And Entity Information - shares	3 Months Ended
	Mar. 31, 2023	May 30, 2023
Document Information Line Items
Entity Registrant Name	ROYALE ENERGY, INC.
Document Type	10-Q
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		65,143,012
Amendment Flag	false
Entity Central Index Key	0001694617
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Document Period End Date	Mar. 31, 2023
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	Q1
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false
Document Quarterly Report	true
Document Transition Report	false
Entity File Number	000-55912
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	81-4596368
Entity Address, Address Line One	1530 Hilton Head Rd, Suite 205
Entity Address, City or Town	El Cajon
Entity Address, State or Province	CA
Entity Address, Postal Zip Code	92021
City Area Code	619
Local Phone Number	383-6600
Title of 12(b) Security	None
Entity Interactive Data Current	Yes
No Trading Symbol Flag	true
Security Exchange Name	NONE

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CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($)	Mar. 31, 2023	Dec. 31, 2022
Current Assets
Cash and Cash Equivalents	$ 1,046,900	$ 1,650,507
Restricted Cash	2,609,555	2,249,627
Other Receivables, net	950,438	943,633
Revenue Receivables	589,900	701,937
Prepaid Expenses	1,686,049	1,935,346
Deferred Drilling Costs	979,686	1,219,177
Prepaid Drilling to RMX Resources, LLC	819,062	114,563
Total Current Assets	8,681,590	8,814,790
Right of Use Assets – Leases	314,913	335,213
Other Assets	589,865	589,865
Oil and Gas Properties, (Successful Efforts Basis), Equipment and Fixtures, net	2,165,722	2,040,320
Total Assets	11,752,090	11,780,188
Current Liabilities:
Accounts Payable and Accrued Expenses	5,789,204	5,528,829
Royalties Payable	612,925	612,925
Due to RMX Resources, LLC	23,087	23,087
Accrued Liabilities	205,556	208,307
Asset Retirement Obligation - Current	675,000	675,000
Deferred Drilling Obligation	6,840,855	8,129,965
Operating Leases - Current	83,641	81,995
Total Current Liabilities	14,230,268	15,260,108
Noncurrent Liabilities:
Accrued Liabilities - Long Term	1,306,605	1,306,605
Accrued Unpaid Guaranteed Payments	1,616,205	1,616,205
Operating Leases - Long-Term	232,736	254,858
Asset Retirement Obligation	2,886,248	2,867,479
Total Liabilities	20,272,062	21,305,255
Mezzanine Equity:
Convertible Preferred Stock, Series B, $10 par value, 3.5% annual dividend, 2,381,986 and 2,361,154 shares issued and outstanding as of March 31, 2023 and December 31, 2022 respectively	23,819,843	23,611,536
Stockholders' Equity (Deficit):
Common Stock, .001 Par Value, 280,000,000 Shares Authorized	61,876	61,876
Additional Paid in Capital	54,447,923	54,447,923
Accumulated Deficit	(86,849,614)	(87,646,402)
Total Stockholders' Equity (Deficit)	(32,339,815)	(33,136,603)
Total Liabilities and Stockholders' Equity (Deficit)	$ 11,752,090	$ 11,780,188

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CONDENSED CONSOLIDATED BALANCE SHEETS (Parentheticals) - $ / shares	Mar. 31, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Convertible Preferred Stock, Series B, par value (in Dollars per share)	$ 10	$ 10
Convertible Preferred Stock, shares issued	2,381,986	2,361,154
Convertible Preferred Stock, shares outstanding	2,381,986	2,361,154
Common Stock, Par Value (in Dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized	280,000,000	280,000,000

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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Revenues:
Revenues	$ 571,825	$ 516,505
Costs and Expenses:
Oil and Gas Lease Operating	575,797	414,468
Depreciation, Depletion and Amortization	59,432	124,676
Well Equipment Write Down	9,840	0
Legal and Accounting	27,892	188,271
Marketing	88,819	55,946
General and Administrative	456,481	537,467
Total Costs and Expenses	1,218,261	1,320,828
Gain on Turnkey Drilling	1,594,354	345,605
Gain (Loss) From Operations	947,918	(458,718)
Interest Expense	(549)	(2,277)
Gain on Other	54,975	0
Gain on Settlement of Accounts Payable	0	408,644
Income (Loss) Before Income Tax Expense	1,002,344	(52,351)
Income Tax Provision	0	0
Net Income (Loss)	1,002,344	(52,351)
Less: Preferred Stock Dividend	205,556	198,516
Net Income (Loss) available to common stock	$ 796,788	$ (250,867)
Shares used in computing Basic Net Income/Loss per share (in Shares)	61,876,957	56,239,715
Basic Income (Loss) per share (in Dollars per share)	$ 0.01	$ 0
Shares used in computing Diluted Net Income (Loss) per share (in Shares)	88,990,264	56,239,715
Diluted Income (Loss) per share (in Dollars per share)	$ 0.01	$ 0
Oil and Gas [Member]
Revenues:
Revenues	$ 558,451	$ 507,214
Management Service [Member]
Revenues:
Revenues	$ 13,374	$ 9,291

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$ 1,002,344	$ (52,351)
Adjustments to Reconcile Net Income (Loss) to Net Cash Used in Operating Activities:
Depreciation, Depletion and Amortization	59,432	124,676
Gain on Turnkey Drilling Programs	(1,594,354)	(345,605)
Gain on Settlement of Accounts Payable	0	(408,644)
Gain on Other	(54,975)	0
Well Equipment Write Down	9,840	0
Right of use asset depreciation	2,750	2,746
Changes in assets and liabilities:
Other & Revenue Receivables	105,232	(50,353)
Prepaid Expenses and Other Assets	(455,202)	(486,487)
Accounts Payable and Accrued Expenses	29,931	878,548
Net Cash Used in Operating Activities	(895,002)	(337,470)
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for Oil and Gas Properties and Other Capital Expenditures	(618,251)	(1,567,239)
Proceeds from Turnkey Drilling Programs	1,272,500	2,495,000
Net Cash Provided by Investing Activities	654,249	927,761
CASH FLOWS FROM FINANCING ACTIVITIES
Principal Payments on Long-Term Debt	(2,926)	(45,845)
Net Cash Used in Financing Activities	(2,926)	(45,845)
Net Change in Cash and Cash Equivalents	(243,679)	544,446
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	3,900,134	4,222,804
Cash, Cash Equivalents, and Restricted Cash at End of Period	3,656,455	4,767,250
SUPPLEMENTAL DISCLOSURES OF NON-CASH INVESTING & FINANCING TRANSACTIONS:
Series B Paid-In-Kind Dividends	205,556	198,516
Cash Paid for Interest	549	732
Cash Paid for Taxes	$ 2,850	$ 2,050

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CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT) - USD ($)	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Common Stock [Member]
Statement [Line Items]
Balance	$ 61,876	$ 56,239
Balance (in Shares)	61,876,957	56,239,715
Preferred Series B 3.5% Dividend (in Shares)		0
Balance	$ 61,876	$ 56,239
Balance (in Shares)	61,876,957	56,239,715
Additional Paid-in Capital [Member]
Statement [Line Items]
Balance (in Shares)	54,447,923	54,058,554
Balance (in Shares)	54,447,923	54,058,554
Retained Earnings [Member]
Statement [Line Items]
Balance	$ (87,646,402)	$ (86,685,036)
Preferred Series B 3.5% Dividend	(205,556)	(198,516)
Net Income (Loss)	1,002,344	(52,351)
Balance	(86,849,614)	(86,935,903)
Balance	(33,136,603)	(32,570,243)
Preferred Series B 3.5% Dividend	(205,556)	(198,516)
Net Income (Loss)	1,002,344	(52,351)
Balance	$ (32,339,815)	$ (32,821,110)

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BASIS OF PRESENTATION: ACCOUNTING STANDARDS

3 Months Ended

Mar. 31, 2023

Accounting Policies [Abstract]

Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]

NOTE 1 – BASIS OF PRESENTATION: ACCOUNTING STANDARDS

Consolidation

In the opinion of management, the accompanying unaudited condensed consolidated Financial Statements (“statements”) include all adjustments necessary to present fairly the Company’s financial position and the results of its operations and cash flows for the periods presented.

The accompanying unaudited consolidated financial statements, which include the accounts of Royale Energy, Inc. (sometimes referred to as the “Company” “we,” “our,” “us,” “Royale Energy,” or “Royale”), Royale Energy Funds, Inc. (“REF”), and Matrix Oil Management Corporation and its subsidiaries, have been prepared in accordance with GAAP for interim consolidated financial information pursuant to the rules and regulations of the SEC under Article 10 of Regulation S-X and the instructions to Form 10-Q. Accordingly, certain information and footnote disclosures normally included in our audited financial statements have been condensed or omitted pursuant to the SEC’s rules and regulations. Significant intercompany transactions have been eliminated in the consolidation. In management’s opinion, all adjustments considered necessary for a fair presentation have been included, disclosures are adequate, and the presented information is not misleading.

The consolidated balance sheet as of December 31, 2022 was derived from the audited financial statements at that date. The accompanying consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2022 as filed with the SEC. Operating results for the three months ended March 31, 2023 are not necessarily indicative of the results that may be expected for the fiscal year ending December 31, 2023, or for any other period. 

Liquidity and Going Concern

The primary sources of liquidity have historically been issuances of common stock, oil and gas sales through ongoing operations and the sale of oil and gas properties. There are factors that give rise to substantial doubt about our ability to meet liquidity demands, and we anticipate that our primary sources of liquidity will be from the issuance of debt and/or equity, the sale of oil and natural gas property participation interests through our normal course of business and the sale of non-strategic assets.

At March 31, 2023, our consolidated financial statements reflect a working capital deficiency of $5,548,678. Although we had net income of $1,002,344 for the three months ended March 31, 2023, there is substantial doubt about our ability to continue as a going concern. The accompanying consolidated financial statements do not include any adjustments that might be necessary if we are unable to continue as a going concern.

Management’s plans to alleviate the going concern by cost control measures that include, among other things, the reduction of overhead costs and the sale of non-strategic assets, and obtaining additional financing. There is no assurance that additional financing will be available when needed or that we will be able to obtain any financing on terms acceptable to us and whether we will become profitable and generate positive operating cash flow. If the we are 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.

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.

Material estimates that are particularly susceptible to significant change relate to the estimate of Company oil and gas reserves prepared by an independent engineering consultant. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proven reserves. Estimated reserves are used in the calculation of depletion, depreciation and amortization, unevaluated property costs, impairment of oil and natural gas properties, estimated future net cash flows, taxes, and contingencies.

Revenue Recognition

A significant portion of our revenues are derived from the sale of crude oil, condensate, natural gas liquids (“NGLs”) and natural gas under spot and term agreements with our customers as follows:

	For the three months ended March 31
	2023		2022
Oil & Condensate Sales	$	347,658	$	359,514
Natural Gas Sales		208,883		146,418
NGL Sales		1,910		1,282
Total	$	558,451	$	507,214

The pricing in our hydrocarbon sales agreements are variable, determined using various published benchmarks which are adjusted for negotiated quality and location differentials. As a result, revenue collected under our agreements with customers is highly dependent on the market conditions and may fluctuate considerably as the hydrocarbon market prices rise or fall. Typically, our customers pay us monthly, within a short period of time after we deliver the hydrocarbon products. As such, we do not have any financing element associated with our contracts. We do not have any issues related to returns or refunds, as product specifications are standardized for the industry and are typically measured when transferred to a common carrier or midstream entity, and other contractual mechanisms (e.g., price adjustments) are used when products do not meet those specifications.

In limited cases, we may also collect advance payments from customers as stipulated in our agreements; payments in excess of recognized revenue are recorded as contract liabilities on our consolidated balance sheets.

Under our hydrocarbon sales agreements, the entire consideration amount is variable either due to pricing and/or volumes. We recognize revenues in the amount of variable consideration allocated to distinct units of hydrocarbons transferred to a customer. Such allocation reflects the amount of total consideration we expect to collect for completed deliveries of hydrocarbons and the terms of variable payment relate specifically to our efforts to satisfy the performance obligations under these contracts. Our performance obligations under our hydrocarbon sales agreements are to deliver either the entire production from the dedicated wells or specified contractual volumes of hydrocarbons.

We often serve as the operator for jointly owned oil and gas properties. As part of this role, we perform activities to explore, develop and produce oil and gas properties in accordance with the joint operating arrangement and collective decisions of the joint parties. Other working interest owners reimburse us for costs incurred based on our agreements. We determined that these activities are not performed as part of customer relationships, and such reimbursements are recorded as cost reimbursements.

We commonly market the share of production belonging to other working interest owners as the operator of jointly owned oil and gas properties. Those marketing activities are carried out as part of the collaborative arrangement, and we do not purchase or otherwise obtain control of other working interest owners’ share of production. Therefore, we act as a principal only with respect to the sale of our share of production and recognize revenue for the volumes associated with our net production.

We frequently sell a portion of the working interest in each well we drill or participate in to third-party investors and retain a portion of the prospect for our own account. We typically guarantee a cost to drill to the third-party drilling participants and record a loss or gain on the difference between the guaranteed price and the actual cost to drill the well. When monies are received from third parties for future drilling obligations, we record the liability as Turnkey Drilling Obligations. Once the contracted depth for the drilling of the well is reached and a determination as to the commercial viability of the well (typically call “Casing Point Election” or “Logging Point”), the difference in the actual cost to drill and the guaranteed cost is recorded as income or expense depending on whether there was a gain or loss.

Crude oil and condensate

For the crude sales agreements, we satisfy our performance obligations and recognize revenue once customers take control of the crude at the designated delivery points, which include pipelines, trucks, or vessels.

Natural gas and NGLs

When selling natural gas and NGLs, we engage midstream entities to process our production stream by separating natural gas from the NGLs. Frequently, these midstream entities also purchase our natural gas and NGLs under the same agreements. In these situations, we determined the performance obligation is complete and satisfied at the tailgate of the processing plant when the natural gas and NGLs become identifiable and measurable products. We determined the plant tailgate is the point in time where control is transferred to midstream entities and they are entitled to significant risks and rewards of ownership of the natural gas and NGLs.

The amounts due to midstream entities for gathering and processing services are recognized as shipping and handling cost and included as lease operating expense in our consolidated statement of operations, since we make those payments in exchange for distinct services except for natural gas sold to Pacific Gas & Electric (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

We sponsor turnkey drilling arrangements in proved and unproved properties. The contracts require that participants pay us the full contract price upon execution of the drilling agreement. Each participant earns an undivided interest in the well bore at the completion of the well. A portion of the funds received in advance of the drilling of a well from a working interest participant are held for the expressed purpose of drilling a well (“Drilling Funds”). If something changes, we may designate these funds for a substitute well. Under certain conditions, a portion of these funds may be required to be returned to a participant. Once the well is drilled, the Drilling Funds are used to satisfy the drilling cost.

We manage these Turnkey Agreements for the participants of the well. We segregate the collections of pre-drilling AFE amounts 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 the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 932-323-25 and 932-360. We manage 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.

Restricted Cash

Prior to commencement of drilling, we classify Drilling Funds as restricted cash based on guidance codified as under ASC 230-10-50-8. In the event that progress payments are made from these funds; they are recorded as Prepaid Expenses and Other Current Assets.

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

	March 31, 2023		December 31, 2022
Cash and Cash Equivalents	$	1,046,900	$	1,650,507
Restricted Cash		2,609,555		2,249,627
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows	$	3,656,455	$	3,900,134

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 condensed consolidated statements of operations. 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. 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.

Other Receivables, net

Other receivables, net consist of joint interest billing 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 March 31, 2023, and December 31, 2022, we maintained an allowance for uncollectable accounts of $2,749,445 and $2,757,549, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue.

Fair Value Measurements

According to Fair Value Measurements and Disclosures Topic of the FASB ASC, 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, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible as well as considers counterparty credit risk in its assessment of fair value. Carrying amounts of our financial instruments, including cash equivalents, accounts receivable, accounts payable and accrued liabilities, approximate their fair values as of the balance sheet dates because of their generally short maturities.

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

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

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

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

At March 31, 2023 and December 31, 2022, we do not have any financial assets measured and recognized at fair value on a recurring basis. We estimate asset retirement obligations (ARO’s) pursuant to the provisions of ASC 410, “Asset Retirement and Environmental Obligations”. The estimates of the fair value the ARO’s are based on discounted cash flow projections using numerous estimates, assumptions, and judgements regarding such factors as the existence of a legal obligation for an ARO, amounts and timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates.

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.

Other receivables will be reflected as Level 3. The fair value of our other receivables is based on credit factors, oil and gas well reserve profiles and commodity prices both current and forecast specific to these financial instruments.

Fair Values - Non-recurring

We applied the provisions of the fair value measurement standard to our non-recurring, non-financial measurements including oil and natural gas property impairments and other long-lived asset impairments. These items are not measured at fair value on a recurring basis but are subject to fair value adjustments only in certain circumstances.

Dividends on Series B Convertible Preferred Stock

The Series B Convertible Preferred Stock, (“Preferred Stock”) has an obligation to pay a 3.5% cumulative dividend, in kind or cash, on a quarterly basis. The Board of Directors authorized the issuance of the Preferred Stock, for the settlement of dividends accumulated through December 31, 2023. We accrued $205,556 and $198,516 for dividends related to the Preferred Stock during the first quarters of 2023 and 2022, respectively. Each quarter, we charge retained earnings for the accumulating dividend as the amounts add to the liquidation preference of the Preferred Stock. For further information regarding the Preferred Stock see Note 3, below.

ACCOUNTING STANDARDS

Recently 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 Securities and Exchange Commission (“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 SEC) 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. We adopted this new standard on January 1, 2023, and there is no material impact on our consolidated financial statements. For further information regarding our adoption of this standard, see Note 7 - ALLOWANCE FOR CREDIT LOSSES below.

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OIL AND GAS PROPERTY AND EQUIPMENT AND FIXTURES

3 Months Ended

Mar. 31, 2023

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment Disclosure [Text Block]

NOTE 2 – OIL AND GAS PROPERTY AND EQUIPMENT AND FIXTURES

Oil and gas properties, equipment and fixtures consist of the following:

	March 31,			December 31,
	2023			2022
	(Unaudited)
Oil and Gas
Producing properties, including drilling costs	$	5,898,195		$	5,712,436
Undeveloped properties		148,989			148,989
Lease and well equipment		3,307,878			3,317,718
		9,355,062			9,179,143
Accumulated depletion, depreciation & amortization		(7,198,628	)		(7,142,506	)
Net capitalized costs Total		2,156,434			2,036,637
Commercial and Other
Vehicles		40,061			40,061
Furniture and equipment		1,103,362			1,097,428
		1,143,423			1,137,489
Accumulated depreciation		(1,134,135	)		(1,133,806	)
		9,288			3,683
Net capitalized costs Total	$	2,165,722		$	2,040,320

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.

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 are expensed as incurred. Major renewals and improvements are capitalized, and the assets replaced are retired.

The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use. Interest costs, to the extent they are incurred to finance expenditures during the construction phase, are included in property, plant and equipment and are depreciated over the service life of the related assets.

We use the “successful efforts” method to account for our exploration and production activities. Under this method, we accumulate our proportionate share of costs on a well-by-well basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred and capitalize expenditures for productive wells. We amortize the costs of productive wells under the unit-of-production method.

We carry, as an asset, exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred.

Acquisition costs of proved oil and gas 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 our wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labor costs to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity. Proved oil and gas properties held and used, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable.

We estimate the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts and whether carrying amounts should be impaired. We perform the evaluation of carrying amounts at least annually or when economic events or commodity prices indicate that a substantial and measurable change in future cash flows has occurred. Cash flows used in impairment evaluations are developed using updated evaluation assumptions for crude oil and natural gas commodity prices. Annual volumes are based on field production profiles, which are also updated annually.

Impairment analyses are generally based on proved reserves. An asset group would be further assessed if the undiscounted cash flows were less than its’ carrying value. Impairments are measured by the amount the carrying value exceeds fair value. During the three months ended March 31, 2023, and 2022, no impairment losses were incurred.

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 Energy expects to hold the properties. The valuation allowances are reviewed at least annually.

Upon the sale or retirement of a complete field of a proven property, we eliminate the cost from our books, and the resulting gain or loss is recorded to the 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 the 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 our turnkey drilling agreements include unproved property, total drilling costs incurred to satisfy our obligations are recovered by the total funds received under the agreements. Any excess funds are recorded as a Gain on Turnkey Drilling Programs, and any costs not recovered are capitalized and accounted for under the “successful efforts” method.

We sponsor turnkey drilling agreement arrangements in unproved properties as a pooling of assets in a joint undertaking, whereby proceeds from participants are reported as Deferred Drilling Obligations, and then reduced as costs to complete our obligations are incurred with any excess booked against our property account to reduce any basis in our own interest. Gains on Turnkey Drilling Programs represent funds received from turnkey drilling participants in excess of all costs we incur during the drilling programs (e.g., lease acquisition, exploration and development costs), including costs incurred on behalf of participants and costs incurred for our own account; and are recognized only upon making this determination after our obligations have been fulfilled.

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

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

A certain portion of the turnkey drilling participant’s funds received are non-refundable. We hold all funds invested as Deferred Drilling Obligations until drilling is complete. Occasionally, drilling is delayed for various reasons such as weather, permitting, drilling rig availability and/or contractual obligations. At March 31, 2023, and December 31, 2022, we had Deferred Drilling Obligations of $6,840,855 and $8,129,965, respectively.

If we are unable to drill the wells, and a suitable replacement well is not found, we would retain the non-refundable portion of the contract and return the remaining funds to the participant. Included in Restricted Cash are amounts for use in completion of turnkey drilling programs in progress.

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.

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SERIES B PREFERRED STOCK

3 Months Ended

Mar. 31, 2023

Disclosure Text Block Supplement [Abstract]

Preferred Stock [Text Block]

NOTE 3 – SERIES B PREFERRED STOCK

The Preferred Stock is convertible at the option of the security holder at the rate of ten shares of common stock for one share of Preferred Stock. The Preferred Stock has never been registered under the Exchange Act and no market exists for the Preferred Stock. Additionally, the Preferred Stock will automatically convert into shares of common stock at any time in which the Volume Weighted Average Price (“VWAP”) of our common stock exceeds $3.50 per share for 20 consecutive trading days, the shares of our common stock are registered with the SEC and the trading volume of common shares exceeds 200,000 shares per day. Beginning in 2020, the holders of the Preferred Stock became entitled to vote the number of shares of our common stock into which the shares of Preferred Stock would be entitled to convert.

In accordance with ASC 480-10-S99-1.02, we have determined that the conversion or redemption of the Preferred Stock 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 2023 and 2022, the board authorized the payment of each quarterly dividend on shares of Preferred Stock, as Paid-In-Kind shares to be paid immediately following the end of the quarter. For the quarter ending March 31, 2023, we accrued 20,555 shares with a value of $205,556. During 2023 and 2022 no cash was used to pay dividends on shares of the Preferred Stock.

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LOSS PER SHARE

3 Months Ended

Mar. 31, 2023

Earnings Per Share [Abstract]

Earnings Per Share [Text Block]

NOTE 4 – LOSS PER SHARE

Basic and diluted loss per share are calculated as follows:

	Three Months Ended March 31,
	March 31, 2023				March 31, 2022
	Basic		Diluted		Basic			Diluted
Net Income (Loss)	$	1,002,344		1,002,344	$	(52,351	)		(52,351	)
Less: Preferred Stock Dividend		205,556		205,556		198,516			198,516
Net Income (Loss) Attributable to Common Shareholders	$	796,788	$	796,788	$	(250,867	)	$	(250,867	)
Weighted average common shares outstanding		61,876,957		61,876,957		56,239,715			56,239,715
Effect of dilutive securities		-		27,113,307		-			-
Weighted average common shares, including Dilutive effect		61,876,957		88,990,264		56,239,715			56,239,715
Per share:
Net Income (Loss)	$	0.01		0.01	$	(0.00	)		(0.00	)

For the three months ended March 31, 2023 and 2022, we had dilutive securities of 27,113,307 and 26,468,433, respectively. In 2022, these securities were not included in the dilutive loss per share, due to their antidilutive nature.

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INCOME TAXES

3 Months Ended

Mar. 31, 2023

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

NOTE 5 – 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. At the end of 2015, management reviewed the reliability of our net deferred tax assets, and due to our continued cumulative losses in recent years, the we concluded it is not “more-likely-than-not” our deferred tax assets will be realized. As a result, we will continue to record a full valuation allowance against the deferred tax assets in 2023.

A reconciliation of our provision for income taxes and the amount computed by applying the statutory income tax rates at March 31, 2023 and 2022, respectively, to pretax income is as follows:

	For the three months ended
	March 31, 2023			March 31, 2022
Tax benefit computed at statutory rate of 21% at March 31, 2023 and 2022, respectively	$	210,493			(10,994	)
Increase (decrease) in taxes resulting from:
State tax / percentage depletion / other
Other non-deductible expenses		367			3
Change in valuation allowance		(210,860	)		10,991
Provision (benefit)	$			$

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ISSUANCE OF COMMON STOCK

3 Months Ended

Mar. 31, 2023

Stockholders' Equity Note [Abstract]

Equity [Text Block]

NOTE 6 – ISSUANCE OF COMMON STOCK

In April 2023, CIC RMX LP exercised in full its warrant to purchase shares of our common stock. CIC RMX LP elected to make a cashless exercise of the Warrant and as a result we issued 3,266,055 shares of common stock to the Warrant holder. During the three months ended March 31, 2023, and 2022, no common shares were issued in lieu of cash payments.

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ALLOWANCE FOR CREDIT LOSSES

3 Months Ended

Mar. 31, 2023

Disclosure Text Block Supplement [Abstract]

Allowance for Credit Losses [Text Block]

NOTE 7 - ALLOWANCE FOR CREDIT LOSSES

We measure our allowance for losses on other receivables including, under ASC 326. The following table summarizes the activity in the balance of allowance for credit losses on other receivables for the period indicated:

Balance at December 31, 2022	$	2,757,549
Provision for credit loss		-
Write-offs charged against the allowance		8,104
Balance at March 31, 2023	$	2,749,445

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Accounting Policies, by Policy (Policies)

3 Months Ended

Mar. 31, 2023

Accounting Policies [Abstract]

Consolidation, Policy [Policy Text Block]

Consolidation

In the opinion of management, the accompanying unaudited condensed consolidated Financial Statements (“statements”) include all adjustments necessary to present fairly the Company’s financial position and the results of its operations and cash flows for the periods presented.

The accompanying unaudited consolidated financial statements, which include the accounts of Royale Energy, Inc. (sometimes referred to as the “Company” “we,” “our,” “us,” “Royale Energy,” or “Royale”), Royale Energy Funds, Inc. (“REF”), and Matrix Oil Management Corporation and its subsidiaries, have been prepared in accordance with GAAP for interim consolidated financial information pursuant to the rules and regulations of the SEC under Article 10 of Regulation S-X and the instructions to Form 10-Q. Accordingly, certain information and footnote disclosures normally included in our audited financial statements have been condensed or omitted pursuant to the SEC’s rules and regulations. Significant intercompany transactions have been eliminated in the consolidation. In management’s opinion, all adjustments considered necessary for a fair presentation have been included, disclosures are adequate, and the presented information is not misleading.

The consolidated balance sheet as of December 31, 2022 was derived from the audited financial statements at that date. The accompanying consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2022 as filed with the SEC.

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 our ability to meet liquidity demands, and we anticipate that our primary sources of liquidity will be from the issuance of debt and/or equity, the sale of oil and natural gas property participation interests through our normal course of business and the sale of non-strategic assets.

At March 31, 2023, our consolidated financial statements reflect a working capital deficiency of $5,548,678. Although we had net income of $1,002,344 for the three months ended March 31, 2023, there is substantial doubt about our ability to continue as a going concern. The accompanying consolidated financial statements do not include any adjustments that might be necessary if we are unable to continue as a going concern.

Management’s plans to alleviate the going concern by cost control measures that include, among other things, the reduction of overhead costs and the sale of non-strategic assets, and obtaining additional financing. There is no assurance that additional financing will be available when needed or that we will be able to obtain any financing on terms acceptable to us and whether we will become profitable and generate positive operating cash flow. If the we are 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

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.

Material estimates that are particularly susceptible to significant change relate to the estimate of Company oil and gas reserves prepared by an independent engineering consultant. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proven reserves. Estimated reserves are used in the calculation of depletion, depreciation and amortization, unevaluated property costs, impairment of oil and natural gas properties, estimated future net cash flows, taxes, and contingencies.

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 as follows:

	For the three months ended March 31
	2023		2022
Oil & Condensate Sales	$	347,658	$	359,514
Natural Gas Sales		208,883		146,418
NGL Sales		1,910		1,282
Total	$	558,451	$	507,214

The pricing in our hydrocarbon sales agreements are variable, determined using various published benchmarks which are adjusted for negotiated quality and location differentials. As a result, revenue collected under our agreements with customers is highly dependent on the market conditions and may fluctuate considerably as the hydrocarbon market prices rise or fall. Typically, our customers pay us monthly, within a short period of time after we deliver the hydrocarbon products. As such, we do not have any financing element associated with our contracts. We do not have any issues related to returns or refunds, as product specifications are standardized for the industry and are typically measured when transferred to a common carrier or midstream entity, and other contractual mechanisms (e.g., price adjustments) are used when products do not meet those specifications.

In limited cases, we may also collect advance payments from customers as stipulated in our agreements; payments in excess of recognized revenue are recorded as contract liabilities on our consolidated balance sheets.

Under our hydrocarbon sales agreements, the entire consideration amount is variable either due to pricing and/or volumes. We recognize revenues in the amount of variable consideration allocated to distinct units of hydrocarbons transferred to a customer. Such allocation reflects the amount of total consideration we expect to collect for completed deliveries of hydrocarbons and the terms of variable payment relate specifically to our efforts to satisfy the performance obligations under these contracts. Our performance obligations under our hydrocarbon sales agreements are to deliver either the entire production from the dedicated wells or specified contractual volumes of hydrocarbons.

We often serve as the operator for jointly owned oil and gas properties. As part of this role, we perform activities to explore, develop and produce oil and gas properties in accordance with the joint operating arrangement and collective decisions of the joint parties. Other working interest owners reimburse us for costs incurred based on our agreements. We determined that these activities are not performed as part of customer relationships, and such reimbursements are recorded as cost reimbursements.

We commonly market the share of production belonging to other working interest owners as the operator of jointly owned oil and gas properties. Those marketing activities are carried out as part of the collaborative arrangement, and we do not purchase or otherwise obtain control of other working interest owners’ share of production. Therefore, we act as a principal only with respect to the sale of our share of production and recognize revenue for the volumes associated with our net production.

We frequently sell a portion of the working interest in each well we drill or participate in to third-party investors and retain a portion of the prospect for our own account. We typically guarantee a cost to drill to the third-party drilling participants and record a loss or gain on the difference between the guaranteed price and the actual cost to drill the well. When monies are received from third parties for future drilling obligations, we record the liability as Turnkey Drilling Obligations. Once the contracted depth for the drilling of the well is reached and a determination as to the commercial viability of the well (typically call “Casing Point Election” or “Logging Point”), the difference in the actual cost to drill and the guaranteed cost is recorded as income or expense depending on whether there was a gain or loss.

Crude oil and condensate

For the crude sales agreements, we satisfy our performance obligations and recognize revenue once customers take control of the crude at the designated delivery points, which include pipelines, trucks, or vessels.

Natural gas and NGLs

When selling natural gas and NGLs, we engage midstream entities to process our production stream by separating natural gas from the NGLs. Frequently, these midstream entities also purchase our natural gas and NGLs under the same agreements. In these situations, we determined the performance obligation is complete and satisfied at the tailgate of the processing plant when the natural gas and NGLs become identifiable and measurable products. We determined the plant tailgate is the point in time where control is transferred to midstream entities and they are entitled to significant risks and rewards of ownership of the natural gas and NGLs.

The amounts due to midstream entities for gathering and processing services are recognized as shipping and handling cost and included as lease operating expense in our consolidated statement of operations, since we make those payments in exchange for distinct services except for natural gas sold to Pacific Gas & Electric (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.

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

Turnkey Drilling

We sponsor turnkey drilling arrangements in proved and unproved properties. The contracts require that participants pay us the full contract price upon execution of the drilling agreement. Each participant earns an undivided interest in the well bore at the completion of the well. A portion of the funds received in advance of the drilling of a well from a working interest participant are held for the expressed purpose of drilling a well (“Drilling Funds”). If something changes, we may designate these funds for a substitute well. Under certain conditions, a portion of these funds may be required to be returned to a participant. Once the well is drilled, the Drilling Funds are used to satisfy the drilling cost.

We manage these Turnkey Agreements for the participants of the well. We segregate the collections of pre-drilling AFE amounts 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 the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 932-323-25 and 932-360. We manage 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.

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

Restricted Cash

Prior to commencement of drilling, we classify Drilling Funds as restricted cash based on guidance codified as under ASC 230-10-50-8. In the event that progress payments are made from these funds; they are recorded as Prepaid Expenses and Other Current Assets.

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

	March 31, 2023		December 31, 2022
Cash and Cash Equivalents	$	1,046,900	$	1,650,507
Restricted Cash		2,609,555		2,249,627
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows	$	3,656,455	$	3,900,134

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 condensed consolidated statements of operations. 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. 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.

Receivable [Policy Text Block]

Other Receivables, net

Other receivables, net consist of joint interest billing 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 March 31, 2023, and December 31, 2022, we maintained an allowance for uncollectable accounts of $2,749,445 and $2,757,549, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue.

Fair Value Measurement, Policy [Policy Text Block]

Fair Value Measurements

According to Fair Value Measurements and Disclosures Topic of the FASB ASC, 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, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible as well as considers counterparty credit risk in its assessment of fair value. Carrying amounts of our financial instruments, including cash equivalents, accounts receivable, accounts payable and accrued liabilities, approximate their fair values as of the balance sheet dates because of their generally short maturities.

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

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

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

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

At March 31, 2023 and December 31, 2022, we do not have any financial assets measured and recognized at fair value on a recurring basis. We estimate asset retirement obligations (ARO’s) pursuant to the provisions of ASC 410, “Asset Retirement and Environmental Obligations”. The estimates of the fair value the ARO’s are based on discounted cash flow projections using numerous estimates, assumptions, and judgements regarding such factors as the existence of a legal obligation for an ARO, amounts and timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates.

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.

Other receivables will be reflected as Level 3. The fair value of our other receivables is based on credit factors, oil and gas well reserve profiles and commodity prices both current and forecast specific to these financial instruments.

Fair Values - Non-recurring

We applied the provisions of the fair value measurement standard to our non-recurring, non-financial measurements including oil and natural gas property impairments and other long-lived asset impairments. These items are not measured at fair value on a recurring basis but are subject to fair value adjustments only in certain circumstances.

Stockholders' Equity Note, Redeemable Preferred Stock, Issue, Policy [Policy Text Block]

Dividends on Series B Convertible Preferred Stock

The Series B Convertible Preferred Stock, (“Preferred Stock”) has an obligation to pay a 3.5% cumulative dividend, in kind or cash, on a quarterly basis. The Board of Directors authorized the issuance of the Preferred Stock, for the settlement of dividends accumulated through December 31, 2023. We accrued $205,556 and $198,516 for dividends related to the Preferred Stock during the first quarters of 2023 and 2022, respectively. Each quarter, we charge retained earnings for the accumulating dividend as the amounts add to the liquidation preference of the Preferred Stock. For further information regarding the Preferred Stock see Note 3, below.

New Accounting Pronouncements, Policy [Policy Text Block]

ACCOUNTING STANDARDS

Recently 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 Securities and Exchange Commission (“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 SEC) 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. We adopted this new standard on January 1, 2023, and there is no material impact on our consolidated financial statements.

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BASIS OF PRESENTATION: ACCOUNTING STANDARDS (Tables)

3 Months Ended

Mar. 31, 2023

Accounting Policies [Abstract]

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 as follows:

	For the three months ended March 31
	2023		2022
Oil & Condensate Sales	$	347,658	$	359,514
Natural Gas Sales		208,883		146,418
NGL Sales		1,910		1,282
Total	$	558,451	$	507,214

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 consolidated balance sheet that sum to the total of the same amounts shown in the statement of cash flows.

	March 31, 2023		December 31, 2022
Cash and Cash Equivalents	$	1,046,900	$	1,650,507
Restricted Cash		2,609,555		2,249,627
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows	$	3,656,455	$	3,900,134

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OIL AND GAS PROPERTY AND EQUIPMENT AND FIXTURES (Tables)

3 Months Ended

Mar. 31, 2023

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Table Text Block]

Oil and gas properties, equipment and fixtures consist of the following:

	March 31,			December 31,
	2023			2022
	(Unaudited)
Oil and Gas
Producing properties, including drilling costs	$	5,898,195		$	5,712,436
Undeveloped properties		148,989			148,989
Lease and well equipment		3,307,878			3,317,718
		9,355,062			9,179,143
Accumulated depletion, depreciation & amortization		(7,198,628	)		(7,142,506	)
Net capitalized costs Total		2,156,434			2,036,637
Commercial and Other
Vehicles		40,061			40,061
Furniture and equipment		1,103,362			1,097,428
		1,143,423			1,137,489
Accumulated depreciation		(1,134,135	)		(1,133,806	)
		9,288			3,683
Net capitalized costs Total	$	2,165,722		$	2,040,320

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LOSS PER SHARE (Tables)

3 Months Ended

Mar. 31, 2023

Earnings Per Share [Abstract]

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

Basic and diluted loss per share are calculated as follows:

	Three Months Ended March 31,
	March 31, 2023				March 31, 2022
	Basic		Diluted		Basic			Diluted
Net Income (Loss)	$	1,002,344		1,002,344	$	(52,351	)		(52,351	)
Less: Preferred Stock Dividend		205,556		205,556		198,516			198,516
Net Income (Loss) Attributable to Common Shareholders	$	796,788	$	796,788	$	(250,867	)	$	(250,867	)
Weighted average common shares outstanding		61,876,957		61,876,957		56,239,715			56,239,715
Effect of dilutive securities		-		27,113,307		-			-
Weighted average common shares, including Dilutive effect		61,876,957		88,990,264		56,239,715			56,239,715
Per share:
Net Income (Loss)	$	0.01		0.01	$	(0.00	)		(0.00	)

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INCOME TAXES (Tables)

3 Months Ended

Mar. 31, 2023

Income Tax Disclosure [Abstract]

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

A reconciliation of our provision for income taxes and the amount computed by applying the statutory income tax rates at March 31, 2023 and 2022, respectively, to pretax income is as follows:

	For the three months ended
	March 31, 2023			March 31, 2022
Tax benefit computed at statutory rate of 21% at March 31, 2023 and 2022, respectively	$	210,493			(10,994	)
Increase (decrease) in taxes resulting from:
State tax / percentage depletion / other
Other non-deductible expenses		367			3
Change in valuation allowance		(210,860	)		10,991
Provision (benefit)	$			$

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ALLOWANCE FOR CREDIT LOSSES (Tables)

3 Months Ended

Mar. 31, 2023

Disclosure Text Block Supplement [Abstract]

Accounts Receivable, Allowance for Credit Loss [Table Text Block]

We measure our allowance for losses on other receivables including, under ASC 326. The following table summarizes the activity in the balance of allowance for credit losses on other receivables for the period indicated:

Balance at December 31, 2022	$	2,757,549
Provision for credit loss		-
Write-offs charged against the allowance		8,104
Balance at March 31, 2023	$	2,749,445

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BASIS OF PRESENTATION: ACCOUNTING STANDARDS (Details) - USD ($)	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Accounting Policies [Abstract]
Working Capital (Deficit)	$ 5,548,678
Net Income (Loss) Attributable to Parent	1,002,344	$ (52,351)
Accounts Receivable, Allowance for Credit Loss	$ 2,749,445		$ 2,757,549
Preferred Stock, Dividend Rate, Percentage	3.50%
Dividends, Preferred Stock, Paid-in-kind	$ 205,556	$ 198,516

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BASIS OF PRESENTATION: ACCOUNTING STANDARDS (Details) - Disaggregation of Revenue - USD ($)	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Disaggregation of Revenue [Line Items]
Revenues	$ 571,825	$ 516,505
Oil and Gas [Member]
Disaggregation of Revenue [Line Items]
Revenues	558,451	507,214
Oil [Member]
Disaggregation of Revenue [Line Items]
Revenues	347,658	359,514
Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenues	208,883	146,418
Natural Gas Liquids [Member]
Disaggregation of Revenue [Line Items]
Revenues	$ 1,910	$ 1,282

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BASIS OF PRESENTATION: ACCOUNTING STANDARDS (Details) - Schedule of Cash and Cash Equivalents - USD ($)	Mar. 31, 2023	Dec. 31, 2022	Mar. 31, 2022	Dec. 31, 2021
Schedule Of Cash And Cash Equivalents Abstract
Cash and Cash Equivalents	$ 1,046,900	$ 1,650,507
Restricted Cash	2,609,555	2,249,627
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows	$ 3,656,455	$ 3,900,134	$ 4,767,250	$ 4,222,804

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OIL AND GAS PROPERTY AND EQUIPMENT AND FIXTURES (Details) - USD ($)	Mar. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Contract with Customer, Liability	$ 6,840,855	$ 8,129,965

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OIL AND GAS PROPERTY AND EQUIPMENT AND FIXTURES (Details) - Schedule of Property, Plant and Equipment - USD ($)	Mar. 31, 2023	Dec. 31, 2022
Oil and Gas
Producing properties, including intangible drilling costs	$ 5,898,195	$ 5,712,436
Undeveloped properties	148,989	148,989
Lease and well equipment	3,307,878	3,317,718
Oil and gas, gross	9,355,062	9,179,143
Accumulated depletion, depreciation and amortization	(7,198,628)	(7,142,506)
Oil and gas, net	2,156,434	2,036,637
Commercial and Other
Property, Plant and Equipment, Gross	1,143,423	1,137,489
Accumulated depreciation	(1,134,135)	(1,133,806)
Property, Plant and Equipment, Net	9,288	3,683
Oil and gas properties, equipment and fixtures	2,165,722	2,040,320
Vehicles [Member]
Commercial and Other
Property, Plant and Equipment, Gross	40,061	40,061
Furniture and Fixtures [Member]
Commercial and Other
Property, Plant and Equipment, Gross	$ 1,103,362	$ 1,097,428

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SERIES B PREFERRED STOCK (Details) - USD ($)		3 Months Ended
	Mar. 07, 2018	Mar. 31, 2023	Mar. 31, 2022
SERIES B PREFERRED STOCK (Details) [Line Items]
Preferred Stock Dividends, Shares		20,555
Dividends, Preferred Stock, Paid-in-kind		$ 205,556	$ 198,516
Series B Preferred Stock [Member]
SERIES B PREFERRED STOCK (Details) [Line Items]
Preferred Stock, Convertible, Terms	The Preferred Stock is convertible at the option of the security holder at the rate of ten shares of common stock for one share of Preferred Stock. The Preferred Stock has never been registered under the Exchange Act and no market exists for the Preferred Stock. Additionally, the Preferred Stock will automatically convert into shares of common stock at any time in which the Volume Weighted Average Price (“VWAP”) of our common stock exceeds $3.50 per share for 20 consecutive trading days, the shares of our common stock are registered with the SEC and the trading volume of common shares exceeds 200,000 shares per day.

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LOSS PER SHARE (Details) - shares	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Earnings Per Share [Abstract]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	27,113,307	26,468,433

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LOSS PER SHARE (Details) - Schedule of Earnings Per Share, Basic and Diluted - USD ($)	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Schedule Of Earnings Per Share Basic And Diluted Abstract
Net Income (Loss), Basic	$ 1,002,344	$ (52,351)
Net Income (Loss), Diluted	1,002,344	(52,351)
Less: Preferred Stock Dividend, Basic	205,556	198,516
Less: Preferred Stock Dividend, Diluted	205,556	198,516
Net Income (Loss) Attributable to Common Shareholders, Basic	796,788	(250,867)
Net Income (Loss) Attributable to Common Shareholders, Diluted	$ 796,788	$ (250,867)
Weighted average common shares outstanding, Basic (in Shares)	61,876,957	56,239,715
Weighted average common shares outstanding, Diluted (in Shares)	61,876,957	56,239,715
Effect of dilutive securities, Basic	$ 0	$ 0
Effect of dilutive securities, Diluted (in Shares)	27,113,307	0
Weighted average common shares, including Dilutive effect, Basic (in Shares)	61,876,957	56,239,715
Weighted average common shares, including Dilutive effect, Diluted (in Shares)	88,990,264	56,239,715
Per share:
Net (Loss), Basic (in Dollars per share)	$ 0.01	$ 0
Net (Loss), Diluted (in Dollars per share)	$ 0.01	$ 0

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INCOME TAXES (Details) - Schedule of Effective Income Tax Rate Reconciliation - USD ($)	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Schedule Of Effective Income Tax Rate Reconciliation Abstract
Tax benefit computed at statutory rate of 21% at March 31, 2023 and 2022, respectively	$ 210,493	$ (10,994)
State tax / percentage depletion / other	0	0
Other non-deductible expenses	367	3
Change in valuation allowance	(210,860)	10,991
Provision (benefit)	$ 0	$ 0

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INCOME TAXES (Details) - Schedule of Effective Income Tax Rate Reconciliation (Parentheticals)	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Schedule Of Effective Income Tax Rate Reconciliation Abstract
Tax benefit, statutory rate	21.00%	21.00%

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ISSUANCE OF COMMON STOCK (Details) - shares	1 Months Ended	3 Months Ended
	Apr. 30, 2023	Mar. 31, 2023	Mar. 31, 2022
Stockholders' Equity Note [Abstract]
Stock Issued During Period, Shares, Conversion of Convertible Securities	3,266,055
Shares Issued, Shares, Share-Based Payment Arrangement, after Forfeiture		0	0

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ALLOWANCE FOR CREDIT LOSSES (Details) - Accounts Receivable, Allowance for Credit Loss	3 Months Ended
	Mar. 31, 2023 USD ($)
Accounts Receivable Allowance For Credit Loss Abstract
Balance at	$ 2,757,549
Provision for credit loss	0
Write-offs charged against the allowance	8,104
Balance at	$ 2,749,445