Royale Energy, Inc.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 –BASIS OF PRESENTATION

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 and six months ended June 30, 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 June 30, 2025, our consolidated financial statements reflect a working capital deficiency of $12,030,955, and an accumulated deficit of $94,605,190. We had a net loss of $1,100,721 for the six months ended June 30, 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 continuing to seek to implement cost control measures that include, among other things, reduction of overhead costs, selling non-strategic assets, and, if possible, obtaining additional equity and debt 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 capital, 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 any such 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, 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 oil 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 condensed 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 oil and gas 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. Under certain circumstances, 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 condensed consolidated balance sheets 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 condensed 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 the condensed consolidated statement of operations.

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 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 June 30, 2025 and December 31, 2024, we established an allowance for expected credit losses of $2,179,089 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 (“Preferred Stock”). See Note 9.

The 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.

ACCOUNTING STANDARDS

Recently Issued, Not Yet Adopted

In November 2024, the FASB issued ASU 2024-03, Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. This update requires public business entities to disclose disaggregated information about certain income statement expenses—including categories such as employee compensation, intangible asset amortization and depreciation, and selling expense—in the notes to the financial statements. Public business entities are required to apply the guidance prospectively and may apply it retrospectively. The guidance is effective for fiscal years beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027. Early adoption is permitted. The Company is evaluating the impacts of this standard on our tax disclosures and is not planning to early adopt.

In December 2023, FASB issued Accounting Standards Update (ASU) No. 2023-09, “Improvements to Income Tax Disclosures,”. 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 PROPERTIES AND EQUIPMENT

Oil and gas properties, equipment and fixtures consist of:

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.

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.

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 six months ended June 30, 2025 and 2024, we incurred an impairment loss of $27,250 and $63,054, 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 Condensed Consolidated Statements 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 of the well, 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 June 30, 2025 and December 31, 2024, we had Deferred Drilling Obligations of $13,282,996 and $11,457,996, 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 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 (“Preferred Stock”). The Preferred Stock was convertible at the option of the security holder at the rate of ten shares of common stock for one share of Preferred Stock.

For 2024, the board authorized the payment of each quarterly dividend of 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 share of Preferred Stock.

On October 11, 2024, we completed a significant equity restructuring transaction, eliminating our Preferred Stock. See Note 9.

NOTE 4–LOSS PER SHARE

Basic and diluted loss per share are calculated as follows:

For the six and three months ended June 30, 2025 and 2024, we had dilutive securities of 0 and 24,664,550, respectively. During the six and three month periods in 2024 and 2025, 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.

NOTE 6–ISSUANCE OF COMMON STOCK

During the six months ended June 30, 2025, no common stock was issued in lieu of cash payments for salaries and board fees. During the six months ended June 30, 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:

NOTE 8–RELATED PARTY NOTES PAYABLE

On February 7, 2024 the board of directors of the Company approved a debt facility of up to $3 million. On February 9, 2024, the Company 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 of the Company in Ector County, Texas.

Note 9 – Debt and Equity Restructuring Transaction

On October 11, 2024, we completed a significant equity restructuring transaction, redeeming 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 redemption 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 redemption 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:

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 an inducement expense. The inducement expense was accounted for as an equity transaction and increased 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 June 30, 2025, the Company had 96,600,302 shares of common stock outstanding, andno preferred shares issued or outstanding.