Royale Energy, Inc. 10-Q

Item 1. Financial Statements ROYALE ENERGY, INC. CONDENSED CONSOLIDATED BALANCE SHEETS ASSETS March 31, 2025 December 31, 2024 (unaudited) Current Assets: Cash and Cash Equivalents $ 1,850,831 $ 1,877,163 Restricted Cash 6,000,000 6,025,000 Other Receivables, net 669,873 868,429 Revenue Receivables 439,207 764,653 Prepaid Expenses and Other Current Assets 757,914 619,913 Total Current Assets 9,717,825 10,155,158 Other Assets 584,865 589,865 Right of Use Asset - Operating Leases 214,308 238,509 Oil and Gas Properties (Successful Efforts Basis), Real Property and Equipment and Fixtures, net 4,584,033 4,656,659 Total Assets $ 15,101,031 $ 15,640,191 See notes to unaudited condensed consolidated financial statements. 3 Table of Contents ROYALE ENERGY, INC. CONDENSED CONSOLIDATED BALANCE SHEETS March 31, 2025 December 31, 2024 LIABILITIES AND STOCKHOLDERS’ DEFICIT (unaudited) Current Liabilities: Accounts Payable and Accrued Expenses $ 6,510,879 $ 6,966,605 Notes Payable - Current 1,400,000 - Royalties Payable 611,833 611,833 RMX Resources, LLC 23,087 23,087 Operating Leases - Current 96,095 94,070 Asset Retirement Obligation - Current 1,012,500 1,012,500 Deferred Drilling Obligations 12,032,996 11,457,996 Total Current Liabilities 21,687,390 20,166,091 Noncurrent Liabilities: Asset Retirement Obligation 4,081,358 4,066,095 Notes Payable - Non-current 2,120,934 3,489,290 Operating Leases - Non-current 120,229 145,644 Accrued Unpaid Guaranteed Payments 90,000 90,000 Accrued Liabilities - Non-current 12,386 12,386 Total Liabilities 28,112,297 27,969,506 Stockholders’ Deficit: Common Stock, .001 Par Value, 280,000,000 Shares Authorized 96,600,302 and 96,600,302 shares issued and outstanding at March 31 2025 and December 31, 2024, respectively 96,600 96,600 Additional Paid in Capital 81,078,554 81,078,554 Accumulated Deficit ( 94,186,420 ) ( 93,504,469 ) Total Stockholders’ Deficit ( 13,011,266 ) ( 12,329,315 ) Total Liabilities, and Stockholders’ Deficit $ 15,101,031 $ 15,640,191 See notes to unaudited condensed consolidated financial statements. 4 Table of Contents ROYALE ENERGY, INC. CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) For the 3 months ended For the 3 months ended March 31, 2025 March 31, 2024 Revenues: Oil, NGL and Gas Sales $ 456,106 $ 643,665 Supervisory Fees and Other 31,667 16,269 Total Revenues 487,773 659,934 Costs and Expenses: Oil and Gas Lease Operating 288,839 432,754 Depreciation, Depletion and Amortization 73,218 87,026 Impairment 27,250 56,209 Credit Loss Expense 13,126 30,958 Legal and Accounting 245,506 279,539 Marketing 69,035 59,992 General and Administrative 466,418 447,324 Total Costs and Expenses 1,183,392 1,393,802 Loss From Operations ( 695,619 ) ( 733,868 ) Other Income (Expense): Interest Expense ( 97,179 ) ( 36,242 ) Gain on Settlement of Liability 5,353 - Gain on Settlement of Accounts Payable 105,494 - Net Loss ( 681,951 ) ( 770,110 ) Less: Preferred Stock Dividend in Arrears - 215,221 Net Loss available to common stock $ ( 681,951 ) $ ( 985,331 ) Shares used in computing Basic Net Loss per share 96,600,302 71,349,685 Basic Loss per share ( 0.01 ) ( 0.01 ) Shares used in computing Diluted Net Loss per share 96,600,302 71,349,685 Diluted Loss per share ( 0.01 ) ( 0.01 ) See notes to unaudited condensed consolidated financial statements. 5 Table of Contents ROYALE ENERGY, INC. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) FOR THE THREE MONTHS ENDED MARCH 31, 2025 AND 2024 For the Three Months Ended March 31, 2025 March 31, 2024 CASH FLOWS FROM OPERATING ACTIVITIES Net Loss $ ( 681,951 ) $ ( 770,110 ) Adjustments to Reconcile Net Loss to Net Cash Used in Operating Activities: Depreciation, Depletion and Amortization 73,218 87,026 Impairment 27,250 56,209 Credit Loss Expense 13,126 30,958 Gain on Settlement of Accounts Payable ( 105,494 ) - Gain on Settlement of Liability ( 5,353 ) - Stock-Based Compensation - 35,999 Accretion of Debt Restructure Notes Payable 31,644 - Right of use asset depreciation 3,582 2,753 Changes in assets and liabilities: Other & Revenue Receivables 510,876 314,961 Prepaid Expenses and Other Assets ( 133,001 ) ( 46,341 ) Accounts Payable and Accrued Expenses ( 351,509 ) ( 290,719 ) Net Cash Used in Operating Activities ( 617,612 ) ( 579,264 ) CASH FLOWS FROM INVESTING ACTIVITIES Expenditures for Oil and Gas Properties and Other Capital Expenditures ( 5,949 ) ( 3,188,357 ) Proceeds from Turnkey Drilling Programs 575,000 1,150,000 Net Cash Provided (Used) by Investing Activities 569,051 ( 2,038,357 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long Term Debt - 1,400,000 Lease Financing Payments ( 2,771 ) ( 3,113 ) Net Cash Provided (Used) by Financing Activities ( 2,771 ) 1,396,887 Net Decrease in Cash, Cash Equivalents, and Restricted Cash ( 51,332 ) ( 1,220,734 ) Cash, Cash Equivalents, and Restricted Cash at Beginning of Period 7,902,163 5,527,521 Cash, Cash Equivalents, and Restricted Cash at End of Period 7,850,831 4,306,787 Cash Paid for Interest 65,535 36,242 Cash Paid for Taxes 1,250 550 SUPPLEMENTAL DISCLOSURES OF NON-CASH INVESTING & FINANCING TRANSACTIONS: Accounts Payable for Oil and Gas Properties - 1,000,000 Increase (Decrease) in Capital Accrued Balance 1,277 ( 152,652 ) SUPPLEMENTAL DISCLOSURES OF NON CASH INVESTING & FINANCING ACTIVITIES: Series B Paid-In-Kind Dividends - 215,221 See notes to unaudited condensed consolidated financial statements. 6 Table of Contents ROYALE ENERGY, INC. CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT) FOR THE THREE MONTHS ENDED MARCH 31, 2025 AND 2024 (UNAUDITED) Common Stock Number of Shares Issued and Outstanding Amount Additional Paid in Accumulated Comprehensive Total Stockholders’ Common Shares Common Amount Capital APIC Deficit ACD Deficit Total December 31, 2023 Balance 70,564,188 $ 70,564 $ 54,619,236 $ ( 90,323,289 ) $ ( 35,633,489 ) Stock Issued in lieu of Compensation 1,299,641 1,299 34,700 - 35,999 Preferred Series B 3.5 % Dividend - - - ( 215,221 ) ( 215,221 ) Net Loss - - - ( 770,110 ) ( 770,110 ) March 31, 2024 Balance 71,863,829 $ 71,863 $ 54,653,936 $ ( 91,308,620 ) $ ( 36,582,821 ) Common Shares Common Amount APIC ACD Total December 31, 2024 Balance 96,600,302 $ 96,600 $ 81,078,554 $ ( 93,504,469 ) $ ( 12,329,315 ) Net Loss ( 681,951 ) ( 681,951 ) March 31, 2025 Balance 96,600,302 $ 96,600 $ 81,078,554 $ ( 94,186,420 ) $ ( 13,011,266 ) See notes to unaudited condensed consolidated financial statements. 7 Table of Contents 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 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. The consolidated balance sheet as of December 31, 2024 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, 2024. Operating results for the three months ended March 31, 2025 are not necessarily indicative of the results that may be expected for the fiscal year ending December 31, 2025, 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, 2025, our consolidated financial statements reflect a working capital deficiency of $ 11,969,565 , and an accumulated deficit of $ 94,186,420 . We had a net loss of $ 681,951 for the three months ended March 31, 2025. These factors indicate 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. 8 Table of Contents 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 2025 2024 Oil & Condensate Sales $ 393,860 $ 559,358 Natural Gas Sales 61,096 83,735 NGL Sales 1,150 572 Total $ 456,106 $ 643,665 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. 9 Table of Contents 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 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. Restricted Cash 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 express purpose of drilling a well. 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 funds are used to satisfy the drilling cost. We classify these funds prior to commencement of drilling as restricted cash based on guidance codified as under the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 230-10-50-8. In the event that progress payments are made from these funds; they are recorded as Prepaid Expenses and Other Current Assets. The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheets that sum to the total of the same amounts shown in the statement of cash flows. March 31, 2025 December 31, 2024 Cash and Cash Equivalents $ 1,850,831 $ 1,877,163 Restricted Cash 6,000,000 6,025,000 Total cash, cash equivalents, and restricted cash shown in the statement of cash flows $ 7,850,831 $ 7,902,163 Equity Method Investments Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting. Income from equity method investments represents our proportionate share of net income generated by the equity method investees and is reflected in revenue and other income in our consolidated statements of income. Equity method investments are included as noncurrent assets on the consolidated balance sheets. Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value may have occurred as called for under ASC 323, Investments—Equity Method and Joint Ventures. When a loss is deemed to have occurred and is other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income. Other Receivables, net Our other receivables consist of receivables from direct working interest investors and industry partners. We account for expected credit losses on receivables using the Current Expected Credit Loss (CECL) methodology. Under this standard, an allowance for expected credit losses is established and adjusted based on historical loss experience, current conditions, and reasonable and supportable forecasts of future economic conditions. The allowance account is increased or decreased in response to changes in these factors, reflecting our best estimate of credit losses over the remaining life of the receivables. 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, 2025 and December 31, 2024, we established an allowance for expected credit losses of $ 2,182,424 and $ 2,194,552 , respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue. Dividends on Series B Convertible Preferred Stock On October 11, 2024, we completed a significant equity restructuring transaction, eliminating our Series B, 3.5 % Convertible Preferred Stock. See Note 9. The Series B Convertible Preferred Stock, (“Preferred Stock”) had 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 $ 653,730 for dividends related to the Preferred Stock for the first three quarters of 2024. Each quarter, we charged retained earnings for the accumulating dividend as the amounts add to the liquidation preference of the Preferred Stock. 10 Table of Contents ACCOUNTING STANDARDS Recently Issued, Not Yet Adopted In December 2023, FASB issued Accounting Standards Update (ASU) No. 2023-09, “Improvements to Income Tax Disclosures,” issued by the Financial Accounting Standards Board (FASB). ASU 2023-09 requires enhanced disclosures around income taxes, including additional detail regarding the rate reconciliation and the presentation of income taxes paid, to provide financial statement users with more transparent information about tax exposures and cash flow implications with an effective date for annual periods beginning after December 15, 2024. While we are still evaluating the implications of this standard, the adoption of ASU 2023-09 should not materially impact our financial position, results of operations, or cash flows, as the update affects disclosures only. NOTE 2 – OIL AND GAS PROPERTY AND EQUIPMENT AND FIXTURES Oil and gas properties, equipment and fixtures consist of: March 31, December 31, 2025 2024 (Unaudited) Oil and Gas Producing properties, including drilling costs $ 5,760,981 $ 5,764,761 Undeveloped properties 3,339,234 3,339,234 Lease and well equipment 3,298,441 3,295,028 12,398,656 12,399,023 Accumulated depletion, depreciation & amortization ( 7,819,955 ) ( 7,748,190 ) Net capitalized costs Total 4,578,701 4,650,833 Commercial and Other Vehicles 40,061 40,061 Furniture and equipment 1,103,362 1,103,362 1,143,423 1,143,423 Accumulated depreciation ( 1,138,091 ) ( 1,137,597 ) 5,332 5,826 Net capitalized costs Total $ 4,584,033 $ 4,656,659 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, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired. The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use. Interest costs, to the extent they are incurred to finance expenditures during the construction phase, are included in property, plant and equipment and are depreciated over the service life of the related assets. 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. 11 Table of Contents 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 well. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred. Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves. Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves. Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using unit-of-production rates based on the amount of proved developed reserves of oil and gas that are estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production method, oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank. Production costs are expensed as incurred. Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain Royale’s wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labor costs to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity. Proved oil and gas properties held and used by Royale are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. We estimate the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated evaluation assumptions for crude oil commodity prices. Annual volumes are based on field production profiles, which are also updated annually. Prices for natural gas and other products are based on assumptions developed annually for evaluation purposes. Impairment analyses are generally based on proved reserves. An asset group would be 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, 2025 and 2024, we incurred an impairment loss of $ 27,250 and $ 56,209 , respectively. Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that Royale expects to hold the properties. The valuation allowances are reviewed at least annually. Upon the sale or retirement of a complete field of a proved property, Royale eliminates the cost from its books, and the resultant gain or loss is recorded to Royale’s Statement of Operations. Upon the sale of an entire interest in an unproved property where the property has been assessed for impairment individually, a gain or loss is recognized in Royale’s Statement of Operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a recovery of the cost in the interest retained with any excess funds recognized as a gain. Should Royale’s turnkey drilling agreements include unproved property, total drilling costs incurred to satisfy its obligations are recovered by the total funds received under the agreements. Any excess funds are recorded as a Gain on Turnkey Drilling Programs, and any costs not recovered are capitalized and accounted for under the “successful efforts” method. We sponsor turnkey drilling agreement arrangements in proved and unproved properties as a pooling of assets in a joint undertaking, whereby proceeds from participants are reported as Deferred Drilling Obligations, and then reduced as costs to complete 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 record 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, 2025, and December 31, 2024, we had Deferred Drilling Obligations of $ 12,032,996 and $ 11,457,996 , respectively. 12 Table of Contents 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 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 Pursuant to the terms of the merger completed in 2018, all Class A limited partnership interests of Matrix Investments, LP (“Matrix Investments”) were exchanged for our common stock using conversion ratios according to the relative value of the Class A limited partnership interests, and $20,124,000 of Matrix Investments preferred limited partnership interests were converted into 2,012,400 shares of our Series B Convertible Preferred Stock. The Series B Convertible Preferred Stock was convertible at the option of the security holder at the rate of ten shares of common stock for one share of Series B Convertible Preferred Stock. For 2023 and 2024, the board authorized the payment of each quarterly dividend of Series B Convertible Preferred shares, as Paid-In-Kind shares (“PIK”) to be paid immediately following the end of the quarter. During 2024 no cash was used to pay dividends on Series B preferred shares. On October 11, 2024, we completed a significant equity restructuring transaction, eliminating our Series B, 3.5 % Convertible Preferred Stock. See Note 9. NOTE 4 – LOSS PER SHARE Basic and diluted loss per share are calculated as follows: Three Months Ended March 31, 2025 March 31, 2024 Basic Diluted Basic Diluted Net Loss $ ( 681,951 ) ( 681,951 ) $ ( 770,110 ) ( 770,110 ) Less: Preferred Stock Dividend In Arrears - - 215,221 215,221 Net Loss Attributable to Common Shareholders ( 681,951 ) ( 681,951 ) ( 985,331 ) ( 985,331 ) Weighted average common shares outstanding 96,600,302 96,600,302 71,349,685 71,349,685 Effect of dilutive securities - - - - Weighted average common shares, including Dilutive effect 96,600,302 96,600,302 71,349,685 71,349,685 Per share: Net Loss $ ( 0.01 ) ( 0.01 ) $ ( 0.01 ) ( 0.01 ) For the three months ended March 31, 2025 and 2024, we had dilutive securities of 0 and 24,664,550 , respectively. During the period in 2024, 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, 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 2025. 13 Table of Contents NOTE 6 – ISSUANCE OF COMMON STOCK During the three months ended March 31, 2025, no common stock was issued in lieu of cash payments for salaries and board fees. During the three months ended March 31, 2024, in lieu of cash payments for board fees, we issued 1,299,641 shares of common stock valued at approximately $ 36,000 to 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: Balance at December 31, 2023 $ 1,837,551 Provision for credit loss 30,958 Write-offs charged against the allowance 59,024 Balance at March 31, 2024 $ 1,809,485 Balance at December 31, 2024 $ 2,194,552 Provision for credit loss 13,126 Write-offs charged against the allowance 25,254 Balance at March 31, 2025 $ 2,182,424 NOTE 8 – RELATED PARTY NOTES PAYABLE On February 7, 2024 the board of directors approved a debt facility of up to $ 3 million. On February 9, 2024, Royale Energy, Inc. entered into a Secured Term Loan Note with Walou Investments, LP, a Texas limited partnership, which is under the control of Johnny Jordan, the Company’s Chief Executive Officer and a member of the Company’s Board of Directors. In addition, Mr. Jordan is the beneficial owner of 29.2 % of the Company’s issued and outstanding common stock. The initial loan to the Company was $ 1,400,000 which was received on February 9, 2024.The outstanding principal balance of the loan has an interest rate of 18.0 %. The Company began making monthly interest payments on March 1, 2024, and will continue until the maturity date. On November 1, 2024 the maturity was extended from August 1, 2025 to January 1, 2026. The loan is secured by a deed of trust, which was recorded in Ector County, Texas and covers, among other things, certain oil and gas assets in Ector County, Texas. 14 Table of Contents Note 9 – Debt and Equity Restructuring Transaction On October 11, 2024, we completed a significant equity restructuring transaction, eliminating our Series B, 3.5 % Convertible Preferred Stock and simplifying our capital structure. The transaction was executed through a combination of common stock issuance, stock options, and senior promissory notes in exchange for the retirement of all outstanding Series B Preferred Shares as of June 30, 2024. The preferred holders waived the payment of any unpaid dividends. The restructuring involved the exchange and extinguishment of 2,466,455 shares of Series B Preferred Stock, which carried an aggregate liquidation preference of $ 24.7 million. The exchange was structured as follows: 1. 90% Conversion to Common Stock – Former holders of the Series B Preferred Stock received 22,198,095 shares of Royale common stock at an exchange ratio of 10 shares of common stock for each share of Series B Preferred Stock. 2. 10% Conversion to Notes Payable – The remaining portion of the Series B Preferred Stock was exchanged for Senior Unsecured Promissory Notes, totaling $1.85 million. These notes bear an interest rate of 0% until December 31, 2025, increasing to 5% through 2027 and 8% through June 30, 2029, when all principal and interest is due. 3. Issuance of Warrants – As part of the exchange, Royale issued 25 million warrants with an exercise price of $0.10 per share, expiring on June 30, 2029. The fair value of the warrants was determined to be $959,637 using a Black-Scholes-Merton model. 4. Transfer of Additional Assets – The Company transferred a 0.5% overriding royalty interest (ORRI) in an Alaskan property and three parcels of Bellevue, Kern County real estate to a holding entity controlled by the Preferred Shareholders. The real estate was assigned a fair value of $368,434, which was recognized as an inducement to convert the preferred shares. 5. Settlement of Historical Liabilities – Royale also settled approximately $3 million in pre-merger obligations by issuing additional common stock and promissory notes. The transaction was accounted for as an extinguishment of equity in accordance with ASC 470-50 and ASC 260-10-S99-2, as it represented a fundamental change in the structure and rights of the preferred stockholders. No gain or loss was recognized on the conversion of Series B Preferred Stock, as it was deemed to be an equity transaction per authoritative guidance. However, the issuance of warrants and asset transfers was treated as an inducement expense. The excess of the fair value of the warrants and assets transferred over the accrued dividend forgiven totaling $ 674,341 was treated as inducement. The inducement was accounted for as an equity transaction and increases the net loss attributable to common shareholders in the Loss Per Share computation in Note 1. The Company concurrently settled approximately $ 3.47 million of accrued liabilities and unpaid guaranteed payments through the issuance of common stock and additional promissory notes valued at fair market rates. The liabilities extinguished included obligations associated with prior merger activity and were held primarily by related parties. The exchange of these liabilities was accounted for as a capital transaction with no gain or loss recognized on extinguishment, in accordance with guidance in ASC 470-50. The fair value of the new instruments issued was allocated between notes payable, common stock, and additional paid-in capital. As of March 31, 2025, the Company had 96,600,302 shares of common stock outstanding, and no preferred shares issued or outstanding. 15 Table of Contents 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, 2024, 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, 2024. 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 three months ended March 31, 2025, and 2024, we incurred a net loss of $681,951 and $770,110, respectively. The difference was primarily due to the gain on settlement of approximately $105,000 from a vendor for an equipment failure during a workover. During the first three months of 2025, revenues from oil and gas production decreased $187,559 or 29.1%, to $456,106 from revenues of $643,665 during the first three months of 2024. This decrease was mainly due to lower oil and gas production volumes during the quarter in 2025. The net sales volume of oil and condensate for the three months ended March 31, 2025, was approximately 5,688 barrels with an average price of $69.24 per barrel, versus 7,804 barrels with an average price of $71.68 per barrel for the first three months of 2024. This represents a decrease in net sales volume of 2,116 barrels or 27.1%. The lower production volumes was due to weather and equipment related issues in our Texas Jameson field during the first quarter of 2025. The net sales volume of natural gas for the three months ended March 31, 2025, was approximately 22,767 Mcf with an average price of $2.68 per Mcf, versus 32,659 Mcf with an average price of $2.56 per Mcf for the same period in 2024. This represents a decrease in net sales volume of 9,892 Mcf or 30.3%. The decrease in natural gas production volume was due to some of our California natural gas wells being offline for approximately a month due to mandatory pipeline inspections by Pacific Gas and Electric. Oil and natural gas lease operating expenses decreased by $143,915 or 33.3%, to $288,839 for the three months ended March 31, 2025, from $432,754 for the same period in 2024. This decrease was due to higher workover-related costs during the first quarter of 2024 in our Texas Jameson as we attempted to increase production. The aggregate of supervisory fees and other income was $31,667 and $16,269 for the three months ended March 31, 2025 and 2024, respectively, an increase of $15,398 mainly due to higher interest and rental income during the first quarter of 2025. Depreciation, depletion and amortization expense decreased to $73,218 from $87,026, a decrease of $13,808 or 15.9% for the three months ended March 31, 2025, as compared to the same period in 2024. The depletion rate is calculated using production as a percentage of reserves. The decrease in depletion expense was due to a increase in expected recoverable reserves which decreased the depletion rate. 16 Table of Contents At March 31, 2025, Royale Energy had a Deferred Drilling Obligation of $12,032,996. During the first three months of 2025, we did not participate in the drilling of any wells. At March 31, 2024, Royale Energy had a Deferred Drilling Obligation of $10,911,927. During the first 3 months of 2024, although we participated in the drilling and completion of a well in the Texas Permian basin, we did not book turnkey gains or losses as we waited for final costs to be determined. General and administrative expenses increased by $19,094 or 4.3% from $447,324 for the three months ended March 31, 2024, to $466,418 for the same period in 2025, primarily due to marketing bonuses paid to employees during the quarter in 2025. For the first three months of 2025, marketing expenses increased $9,043 or 15.1% to $69,035, compared to $59,992 for the first three months of 2024. Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated exhibition and travel costs. Legal and accounting expense decreased to $245,506 for the three-month period in 2025, compared to $279,539 for the same period in 2024, a $34,033 or 12.2% decrease. This decrease was primarily due to higher legal fees related to our debt facility entered into during the first quarter of 2024. During the three months ended March 31, 2025, we recorded a gain on settlement of $105,494 with a vendor due to an equipment failure which occurred during a workover. During the three months ended March 31, 2025, we recorded a $5,353 gain on settlement of liability due to a reconciliation of our asset retirement obligation. During the three months ended March 31, 2025, we recorded lease impairments of $27,250 on various lease and land costs in our California natural gas fields where the carrying value exceeded the fair value, compared to $56,209, recorded in the first three months of 2024. During the three months ended March 31, 2025 and 2024, we also recorded Credit Loss expenses of $13,126 and $30,958, respectively, which arose from identified uncollectable receivables relating to our oil and natural gas properties either plugged and abandoned or scheduled for plugging and abandonment (“P&A”) and our period end oil and natural gas reserve values. We periodically review our accounts receivable from working interest owners to determine whether collection of any of these charges appears doubtful. Interest expense for the three months ended March 31, 2025, and 2024, were $97,179 and $36,242, respectively. The higher 2025 interest expense was due to the $1.4 million note payable obtained in February 2024, discussed in Note 8 and the notes payable related to the debt restructuring in October 2024, discussed in Note 9. CAPITAL RESOURCES AND LIQUIDITY At March 31, 2025, we had current assets totaling $9,717,825 and current liabilities totaling $21,687,390, resulting in a $11,969,565 working capital deficit. We had $1,850,831 in cash and $6,000,000 in restricted cash at March 31, 2025, compared to $1,877,163 in cash and $6,025,000 in restricted cash at December 31, 2024. At March 31, 2025, our other receivables, which consist of joint interest billing receivables from direct working interest investors and industry partners, totaled $669,873 compared to $868,429 at December 31, 2024, a $198,556 or 22.9% decrease, mainly due to lower joint interest billing receivables. At March 31, 2025, revenue receivable was $439,207, a decrease of $325,446, compared to $764,653 at December 31, 2024, due to lower production volumes during the first quarter in 2025 when compared to the fourth quarter of 2024. At March 31, 2025, our accounts payable and accrued expenses totaled $6,510,879, a decrease of $455,726 from the accounts payable at December 31, 2024 of $6,966,605, which was mainly due to lower revenue payables at the end of the first quarter 2025. We have had recurring operating and net losses and cash used in operations and the financial statements reflect a working capital deficiency of $11,969,565 and an accumulated deficit of $94,186,420. These factors raise substantial doubt about our ability to continue as a going concern, and 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. Although there are no assurances, Management believes that expected increases in revenue together with reduced capital expenditures for drilling will allow the company to meet its liquidity needs through the remainder of the year. Operating Activities. Net cash used by operating activities totaled $617,612 and $579,264 for the three months ended March 31, 2025 and 2024, respectively, a $38,348 or 6.6% difference. Investing Activities. Net cash provided by investing activities totaled $569,051 for the three months ended March 31, 2025, while net cash used by investing activities totaled $2,038,357 for the three months ended March 31, 2024. During the three-month period in 2025, we received $575,000 in drilling funds while our drilling and lease expenditures were approximately $6,000. During the three-month period in 2024, we received approximately $1.2 million in drilling funds while our drilling and lease expenditures were approximately $3.2 million as we participated in drilling and obtained lease interests in the Permian basin. 17 Table of Contents Financing Activities. Net cash used by financing activities totaled $2,771 for the three months ended March 31, 2025 and net cash provided by financing activities were $1,396,8877 for the three months ended March 31, 2024. The difference in cash provided, was due to receipt of $1.4 million from the note payable discussed in Note 8. During the three-month periods in 2025 and 2024, the totals were also used for principal payments on our financing lease payments. Critical Accounting Estimates Our critical accounting policies are further disclosed in Note 1 to the consolidated financial statements included in our 2024 Annual Report on Form 10-K. Item 3. Quantitative and Qualitative Disclosures About Market Risk Not applicable.