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 JuneSeptember 30, 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)

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:

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 AugustNovember 3, 2023, a total of 67,684,188 shares of registrant’s common stock were outstanding.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

See notes to unaudited condensed consolidated financial statements.

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

See notes to unaudited condensed consolidated financial statements.

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

See notes to unaudited condensed consolidated financial statements.

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

FOR THE SIXNINE MONTHS ENDED JUNESEPTEMBER 30, 2023 AND 2022

See notes to unaudited condensed consolidated financial statements.

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)

FOR THE THREE AND SIXNINE MONTHS ENDED JUNESEPTEMBER 30, 2023 AND 2022
(UNAUDITED)

See notes to unaudited condensed consolidated financial statements.

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”)financial 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 U.S. Generally Accepted Accounting Principles (“GAAP”) for interim consolidated financial information pursuant to the rules and regulations of the Securities and Exchange Commission (“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 our 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 and sixnine months ended JuneSeptember 30, 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 JuneSeptember 30, 2023, our consolidated financial statements reflect a working capital deficiency of $6,984,331.$7,482,591. We had net losses of $1,035,375$470,730 and $33,031$503,761 for the three and sixnine months ended JuneSeptember 30, 2023, respectively. This indicates that 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 implementing cost control measures that include, among other things, the reduction of overhead costs, the sale of non-strategic assets, and, if possible, 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 we are unable to raise sufficient additional funds, we 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 GAAP 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:

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 the Drilling Funds a substitute well. Under certain conditions, a portion of the Drilling 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.

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 JuneSeptember 30, 2023, and December 31, 2022, we maintained an allowance for uncollectable accounts of $2,748,626$2,746,925 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 periods 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 considering counterparty credit risk in our assessment of fair value. Carrying amounts of our financial instruments, including cash equivalents, accounts receivable, accounts payable and accrued liabilities, approximate their fair values as of the balance sheet dates because of their generally short maturities.

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

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

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

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

At JuneSeptember 30, 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 (AROs)(“ARO’s”) pursuant to the provisions of ASC 410, “Asset Retirement and Environmental Obligations”. The estimates of the fair value the AROs 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 AROs 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 $209,644$213,807 and $202,464$206,485 for dividends related to the Preferred Stock for the secondthird 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 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:

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 sixnine months ended JuneSeptember 30, 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 their proportionate share of operating costs. We retain legal title to the lease. The participants purchase a working interest directly in the well bore.

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

A certain portion of the turnkey drilling participant’s funds received are non-refundable. We hold all funds invested as Deferred Drilling Obligations until drilling is complete. Occasionally, drilling is delayed for various reasons such as weather, permitting, drilling rig availability and/or contractual obligations. At JuneSeptember 30, 2023, and December 31, 2022, we had Deferred Drilling Obligations of $8,190,855$10,140,855 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 Securities Exchange Act of 1934, as amended, (“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 shares of our common stock exceed 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 June 30, 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 JuneSeptember 30, 2023, we accrued 20,96421,380 shares with a value of $209,644.$213,807. During 2023 and 2022 no cash was used to pay dividends on shares of the Preferred Stock.

NOTE 4 – LOSS PER SHARE

Basic and diluted loss per share are calculated as follows:

For the sixnine months ended JuneSeptember 30, 2023 and 2022, we had dilutive securities of 24,025,41024,235,050 and 26,683,208,26,867,129, respectively. For the three months ended JuneSeptember 30, 2023 and 2022, we had dilutive securities of 24,025,41024,235,050 and 26,698,515,26,827,162, respectively. In both periods, 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 June 30, 2023 and 2022, respectively, to pretax income is as follows:

NOTE 6 – ISSUANCE OF COMMON STOCK

In April 2023, CIC RMX LP (“CIC”) exercised in full its warrant to purchase shares of our common stock. CIC elected to make a cashless exercise of the warrant and as a result we issued 3,266,055 shares of our common stock to CIC. During the sixnine months ended JuneSeptember 30, 2023, in lieu of cash payments for board fees, we issued 2,541,176 shares of common stock valued at approximately $108,001 to board members. During the sixnine months ended JuneSeptember 30, 2022, in lieu of cash payments for salaries and board fees, we issued 1,929,0785,637,242 shares of common stock valued at approximately $136,000$395,006 to an executive officer and board members.

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:

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 its 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, sources and availability of financing, 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 oil and gas property 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 sixnine months ended JuneSeptember 30, 2023 and 2022, we had net losses of $33,031$503,761 and $312,853,$739,184, respectively. The decrease in net losses were 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 $1,339,382.$1,338,305 for the nine months ended September 30, 2023 compared to $627,136 for the nine months ended September 30, 2022. During the three months ended JuneSeptember 30, 2023 and 2022, we had net losses of $1,035,375$470,730 and $260,502,$426,331, respectively. The difference was primarily due to higher turnkey drilling costs incurred in the second quarter of 2023 in the Texas well in which we participated and lower oil and gas revenues due to lower oil and gas commodity prices during the secondthird quarter 2023.

During the first sixnine months of 2023, revenues from oil and gas production decreased $197,875$281,431 or 16.7%16.3%, to $988,744$1,447,698 in 2023 from revenues of $1,186,619$1,729,129 during the first sixnine months of 2022. This decrease was mainly due to lower oil and natural gas commodity prices. The net sales volume of oil and condensate for the sixnine months ended JuneSeptember 30, 2023, was approximately 9,86414,851 barrels with an average price of $71.69$73.20 per barrel, versus 8,18611,330 barrels with an average price of $99.58$98.69 per barrel for the sixnine months of 2022. This represents an increase in net sales volume of 1,6783,521 barrels or 20.5%31.1%, which was due to wells completed and put online during the latter half of 2022 and first half of 2023. The net sales volume of natural gas for the sixnine months ended JuneSeptember 30, 2023, was approximately 68,081101,324 Mcf with an average price of $4.10$3.51 per Mcf, versus 65,30899,830 Mcf with an average price of $5.61$6.04 per Mcf for the same period in 2022. This represents an increase in net sales volume of 2,7731,494 Mcf or 4.2%1.5%. The increase in natural gas production volume was also due to new wells being brought online. For the quarter ended JuneSeptember 30, 2023, revenues from oil and gas production decreased $249,112$83,556 or 36.7%15.4% to $430,293$458,954 from the 2022 secondthird quarter revenues of $679,405.$542,510. This decrease was also due to lower oil and natural gas commodity prices. The net sales volume of oil and condensate for the quarter ended JuneSeptember 30, 2022,2023, was approximately 5,1044,987 barrels with an average price of $70.45$76.19 per barrel, versus 4,2973,143 barrels with an average price of $106.05$96.37 per barrel for the secondthird quarter of 2022. This represents an increase in net sales volume of 8071,844 barrels or 18.8%58.7% for the third quarter in 2023. The net sales volume of natural gas for the quarter ended JuneSeptember 30, 2023, was approximately 37,96233,242 Mcf with an average price of $1.84$2.32 per Mcf, versus 31,78134,522 Mcf with an average price of $6.92$6.86 per Mcf for the secondthird quarter of 2022. This represents an increasea decrease in net sales volume of 6,1811,280 Mcf or 19.4%3.7% for the third quarter in 2023.

Oil and natural gas lease operating expenses increased by $289,117$240,811 or 35.6%19.6%, to $1,102,095$1,469,988 for the sixnine months ended JuneSeptember 30, 2023, from $812,978$1,229,177 for the same period in 2022. This increase was mainly due to higher well equipment and supplies costs in order to increase production primarily on our Texas Jameson wells to increase production.wells. For the secondthird quarter in 2023, lease operating expenses increased $127,788decreased $48,306 or 32.1%11.6% from the same quarter in 2022, mainly due to increases in workovers and water disposal feeslower workover costs in our Texas Jameson field during the third quarter in 2023.

The aggregate of supervisory fees and other income was $111,966$171,577 for the sixnine months ended JuneSeptember 30, 2023, an increase of $94,925$147,228 from $17,041$24,349 during the same period in 2022. During the secondthird quarter 2023, supervisory fees and other income increased $90,842$52,303 when compared to the quarter in 2022. These increases were mainly due to increases in water disposal recovery income as we converted an existing non-producing oil well into a water injection well in order to reduce water disposal hauling costs paid to outside vendors.

Depreciation, depletion and amortization expense decreased to $173,907$231,224 from $244,208,$301,235, a decrease of $70,301$70,011 or 28.8%23.2% for the sixnine months ended JuneSeptember 30, 2023, as compared to the same period in 2022. During the secondthird quarter 2023, depreciation, depletion and amortization expenses also decreased $5,057increased $290 or 4.2%0.5%. The depletion rate is calculated using production as a percentage of reserves. ThisThe decrease in depletion expense was due to an increase in expected recoverable reserves which decreased the depletion rate.

At JuneSeptember 30, 2023, Royale Energy had a Deferred Drilling Obligation of $8,190,855.$10,140,855. During the first sixnine 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 an oil well in the Texas Permian basin, while incurring expenses of $1,222,228,$1,223,305, resulting in a gain of $1,339,382.$1,338,305. At JuneSeptember 30, 2022, Royale Energy had a Deferred Drilling Obligation of $8,359,011.$10,084,011. During the first sixnine months of 2022, we disposed of $3,185,928 of drilling obligations upon completing one oil well in Texas and participated in the drilling and completion of two oil wells in southern California, while incurring expenses of $2,558,792, resulting in a gain of $627,136.

General and administrative expenses decreased by $145,648$118,740 or 14.2%8.6% from $1,023,817$1,381,282 for the sixnine months ended JuneSeptember 30, 2022 to $878,169$1,262,542 for the same period in 2023. For the second quarter 2023, general and administrative expenses decreased $64,662 or 13.3% when compared to the same period in 2022. These decreases wereThis decrease was mainly due to lower employee related expenses due to cost reduction measures during the periodsperiod in 2023. For the third quarter 2023, general and administrative expenses increased $26,908 or 7.5% when compared to the same period in 2022, mainly due to higher employee related insurance expenses and outside services during the quarter in 2023. For the first sixnine months of 2023, marketing expenses increased $12,572$46,242 or 9.4%25.1% to $146,891,$230,282, compared to $134,319$184,040 for the first sixnine months of 2022. For the secondthird quarter 2023, marketing expenses decreased $20,301increased $33,670 or 25.9%67.7% when compared to the secondthird quarter in 2022. Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs.

Legal and accounting expense decreased to $273,143$368,810 for the six-monthnine-month period in 2023, compared to $346,410$440,130 for the same period in 2022, a $73,267$71,320 or 21.2%.16.2% decrease. This decrease during the period in 2023 was primarily due to higher fees related to the conversion of our accounting software during the period in 2022. For the secondthird quarter 2023, legal and accounting expenses increased $87,112$1,947 or 55.1%2.1%, when compared to the secondthird quarter in 2022, primarily due to the delay in our 2022 audit and its related fees, which occurred during the second quarter 2023.2022.

During the sixnine months ended JuneSeptember 30, 2023, we recorded a gain on other of $54,975 as we reconciled employee related items previously recorded as liabilities. We also recorded a gain on other of approximately $57,000 on our share of prior years property tax refunds received by RMX Resources, LLC during the period in 2023. During the sixnine months ended JuneSeptember 30, 2022, we recorded a gain of $422,614 on settlement of accounts payable for a reduced amount.

CAPITAL RESOURCES AND LIQUIDITY

At JuneSeptember 30, 2023, we had current assets totaling $8,155,268$9,970,189 and current liabilities totaling $15,139,599,$17,452,780, a $6,984,331$7,482,591 working capital deficit. We had $974,496$523,619 in cash and $1,236,665$3,169,999 in restricted cash at JuneSeptember 30, 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 JuneSeptember 30, 2023, our other receivables, which consist of joint interest billing receivables from direct working interest investors and industry partners, totaled $999,030$1,029,774 compared to $943,633 at December 31, 2022, a $55,397$86,141 increase. This increase was mainly due to accounts receivables from direct working interest owners for lease operating expenses to increase production volumes on our Texas Jameson wells to increase production volumes.wells. At JuneSeptember 30, 2023, revenue receivable was $381,821,$273,356, a decrease of $320,116,$428,581, compared to $701,937 at December 31, 2022, due to lower commodity prices during the secondthird quarter in 2023. At JuneSeptember 30, 2023, our accounts payable and accrued expenses totaled $5,342,800$5,702,296 a decrease of $186,029$173,467 from the accounts payable at December 31, 2022 of $5,528,829, which was mainly due to lower revenue payables due to the lower commodity prices during the period 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 $6,984,331$7,482,591 and an accumulated deficit of $88,094,633.$88,779,170. 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 drilling wells in the Permian basin and will also continue to drill and workover wells in our Texas Jameson field. We are also looking for possible ways to increase production on some of our California natural gas wells.

Operating Activities. Net cash used in operating activities totaled $1,658,304$198,937 and $1,078,217$1,331,314 for the sixnine months ended JuneSeptember 30, 2023 and 2022, respectively. This difference in cash used was mainly due to lower revenue receivables, due to lower commodity prices in 2023, and lower accounts payable during the period in 2023 when compared to higher revenue receivables and accounts payables during the period in 2022 where we increased our accounts payable.2022.

Investing Activities. Net cash provided by investing activities totaled $24,774$1,337 and $1,100,610$1,598,227 for the sixnine months ended JuneSeptember 30, 2023, and 2022, respectively. During the six-monthnine-month period in 2023, we received approximately $2.6$4.6 million in direct working interest investor turnkey drilling investments while our drilling expenditures were approximately $2.6$4.6 million as we drilled and completed one Texas well and participated in the drilling and completing of another Texas well in the Permian basin. Additionally, we are participating in the drilling of in progress wells, one in Southern California and three in the Permian basin. During the six monthnine-month period in 2022, we received approximately $3.7$5.4 million in direct working interest investor turnkey drilling investments while our drilling expenditures were approximately $2.6$3.8 million as we drilled and completed one Texas well and participated in the drilling and completing of two southern California oil wells.

Financing Activities. Net cash used in financing activities totaled $5,895$8,916 and $76,333$99,173 for the sixnine months ended JuneSeptember 30, 2023, and 2022, respectively. During the periods in 2023 and 2022, the totals were used for 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.

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.

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 JuneSeptember 30, 2023, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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

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.