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 September 30, 2025

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

Commission File No. 000-55912

ROYALE ENERGY, INC.

(Exact name of registrant as specified in its charter)

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

1530 Hilton Head Rd, Suite 205
El Cajon, CA 92021

(Address of principal executive offices) (Zip Code)

(619) 383-6600

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Check one:

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

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

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

At November 7, 2025, a total of 96,600,302 shares of registrant’s common stock were outstanding.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION		3

Item 1. Financial Statements		3

Condensed consolidated Balance Sheets as of September 30, 2025 and December 31, 2024		3

Condensed consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2025 and 2024		5

Condensed consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2025 and 2024		6

Condensed consolidated Statements of Stockholders’ Deficit for the Three and Nine Months Ended September 30, 2025 and 2024		7

Notes to Condensed consolidated Financial Statements		8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		17

Item 3. Quantitative and Qualitative Disclosures About Market Risk		20

Item 4. Controls and Procedures		20

PART II. OTHER INFORMATION		21

Item 1. Legal Proceedings		21

Item 1A. Risk Factors		21

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		21

Item 3. Defaults Upon Senior Securities		21

Item 4. Mine Safety Disclosures		21

Item 5. Other Information		21

Item 6. Exhibits		22

Signatures		23

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30, 2025		December 31, 2024
	(unaudited)
ASSETS
Current Assets:
Cash and Cash Equivalents	$	796,979	$	1,877,163
Restricted Cash		5,476,900		6,025,000
Other Receivables, net		663,775		868,429
Revenue Receivables		573,638		764,653
Prepaid Expenses and Other Current Assets		725,907		619,913
Deferred Drilling Costs		528,610		-
Total Current Assets		8,765,809		10,155,158

Other Assets		576,265		589,865
Right of Use Asset - Operating Leases		165,835		238,509
Oil and Gas Properties (Successful Efforts Basis), Real Property and Equipment and Fixtures, net		5,878,626		4,656,659
Total Assets	$	15,386,535	$	15,640,191

See notes to unaudited condensed consolidated financial statements.

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ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30, 2025			December 31, 2024
	(unaudited)
LIABILITIES AND STOCKHOLDERS’ DEFICIT
Current Liabilities:
Accounts Payable and Accrued Expenses	$	5,261,628		$	6,966,605
Royalties Payable		611,833			611,833
RMX Resources, LLC		23,087			23,087
Operating Leases - Current		100,179			94,070
Asset Retirement Obligation - Current		1,012,500			1,012,500
Deferred Drilling Obligations		13,982,996			11,457,996
Total Current Liabilities		20,992,223			20,166,091

Noncurrent Liabilities:
Asset Retirement Obligation		4,116,391			4,066,095
Notes Payable - Non-current		4,086,756			3,489,290
Operating Leases - Non-current		69,108			145,644
Accrued Unpaid Guaranteed Payments		90,000			90,000
Accrued Liabilities - Non-current		12,386			12,386
Total Liabilities		29,366,864			27,969,506

Stockholders’ Deficit:
Common Stock, $0.001 Par Value, 280,000,000 Shares Authorized 96,600,302 and 96,600,302 shares issued and outstanding at September 30, 2025 and December 31, 2024, respectively		96,600			96,600
Additional Paid in Capital		81,078,554			81,078,554

Accumulated Deficit		(95,155,483	)		(93,504,469	)

Total Stockholders’ Deficit		(13,980,329	)		(12,329,315	)

Total Liabilities, and Stockholders’ Deficit	$	15,386,535		$	15,640,191

See notes to unaudited condensed consolidated financial statements.

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ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

	For the three months ended						For the nine months ended
	9/30/2025			9/30/2024			9/30/2025			9/30/2024
Revenues:
Oil, NGL and Gas Sales	$	584,576		$	559,709		$	1,372,919		$	1,749,120
Other Operating Revenue		5,161			3,103			20,280			13,204
Total Revenues		589,737			562,812			1,393,199			1,762,324

Costs and Expenses:
Oil and Gas Lease Operating		360,986			512,400			848,469			1,292,525
Depreciation, Depletion and Amortization		83,496			56,547			198,976			253,726
Settlement of Asset Retirement Obligations		(9,989	)		-			(230,681	)		-
Impairment		-			337,500			27,250			400,554
Legal and Accounting		76,948			142,950			382,660			485,114
Credit Loss Expense		98,432			103,447			111,558			279,491
Marketing		62,204			128,211			228,732			269,984
General and Administrative		382,957			369,646			1,235,003			1,197,677
Total Costs and Expenses		1,055,034			1,650,701			2,801,967			4,179,071

Gain on Turnkey Drilling		-			-			-			527,715

Loss From Operations		(465,297	)		(1,087,889	)		(1,408,768	)		(1,889,032	)
Other Income (Expense):
Interest Income		16,092			11,602			53,954			31,759
Interest Expense		(101,088	)		(108,004	)		(296,200	)		(207,744	)

Net Loss		(550,293	)		(1,184,291	)		(1,651,014	)		(2,065,017	)
Less: Preferred Stock Dividend		-			221,410			-			653,730
Net Loss available to common stock	$	(550,293	)	$	(1,405,701	)	$	(1,651,014	)	$	(2,718,747	)

Shares used in computing Basic and Diluted Net Loss per share		96,600,302			71,863,529			96,600,302			71,693,073

Basic and Diluted Net Loss Per Share	$	(0.01	)	$	(0.02	)	$	(0.02	)	$	(0.04	)

See notes to unaudited condensed consolidated financial statements.

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ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2025 AND 2024

	For the Nine Months Ended
	9/30/2025			9/30/2024
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	(1,651,014	)	$	(2,065,017	)
Adjustments to Reconcile Net Loss to Net Cash Used in Operating Activities:
Depreciation, Depletion and Amortization		198,976			253,726
Gain on Turnkey Drilling Programs		-			(527,715	)
Impairment		27,250			400,554
Credit Loss Expense		111,558			279,491
Settlement of Asset Retirement Obligation		(230,681	)		-
Cash Settlement on Asset Retirement Obligation		9,199			-
Stock-Based Compensation		-			35,999
Accretion of Discount on Notes Payable		97,466			-
Right of Use Asset Depreciation		10,817			6,615
Changes in Operating Assets and Liabilities:
Other & Revenue Receivables		284,111			498,949
Prepaid Expenses and Other Assets		(92,394	)		773
Royalties Payable		-			(1,092	)
Accounts Payable and Accrued Expenses		(1,440,996	)		(263,667	)
Net Cash Used in Operating Activities		(2,675,708	)		(1,381,384	)
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for Oil and Gas Properties and Other Capital Expenditures		(1,969,006	)		(4,706,411	)
Proceeds from Turnkey Drilling Programs		2,525,000			4,937,500
Net Cash Provided by Investing Activities		555,994			231,089

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt		500,000			1,400,000
Lease Financing Payments		(8,570	)		(6,961	)
Net Cash Provided by Financing Activities		491,430			1,393,039

Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash		(1,628,284	)		242,744

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	$	6,273,879		$	5,770,265
Cash Paid for Interest	$	198,734		$	207,744
Cash Paid for Taxes	$	9,218		$	8,050

SUPPLEMENTAL DISCLOSURES OF NON-CASH INVESTING & FINANCING TRANSACTIONS:
Change in Capital Accrued Balance	$	(7,548	)	$	-

See notes to unaudited condensed consolidated financial statements.

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ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ DEFICIT

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2025 AND 2024
(UNAUDITED)

	Common Stock
	Number of Shares Issued and Outstanding		Amount		Additional Paid in Capital		Accumulated Comprehensive Deficit			Total Stockholders’ Deficit

	Common Shares		Common Amount		APIC		ACD			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		-		-		-		(653,730	)		(653,730	)
Net Loss		-		-		-		(2,065,017	)		(2,065,017	)
September 30, 2024 Balance		71,863,829	$	71,863	$	54,653,936	$	(93,042,036	)	$	(38,316,237	)

	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		-		-		-		(1,651,014	)		(1,651,014	)
September 30, 2025 Balance		96,600,302	$	96,600	$	81,078,554	$	(95,155,483	)	$	(13,980,329	)

	Common Stock
	Number of Shares Issued and Outstanding		Amount		Additional Paid in Capital		Accumulated Comprehensive Deficit			Total Stockholders’ Deficit

	Common Shares		Common Amount		APIC		ACD			Total
June 30, 2024 Balance		71,863,829	$	71,863	$	54,653,936	$	(91,636,335	)	$	(36,910,536	)
Preferred Series B 3.5% Dividend		-		-		-		(221,410	)		(221,410	)
Net Loss		-		-		-		(1,184,291	)		(1,184,291	)
September 30, 2024 Balance		71,863,829	$	71,863	$	54,653,936	$	(93,042,036	)	$	(38,316,237	)

	Common Shares		Common Amount		APIC		ACD			Total
June 30, 2025 Balance		96,600,302	$	96,600	$	81,078,554	$	(94,605,190	)	$	(13,430,036	)
Net Loss		-		-		-		(550,293	)		(550,293	)
September 30, 2025 Balance		96,600,302	$	96,600	$	81,078,554	$	(95,155,483	)	$	(13,980,329	)

See notes to unaudited condensed consolidated financial statements.

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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 nine months ended September 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 September 30, 2025, our condensed consolidated financial statements reflect a working capital deficiency of $12,226,414, and an accumulated deficit of $95,155,483. We had a net loss of $1,651,014 for the nine months ended September 30, 2025. These factors indicate that there is substantial doubt about our ability to continue as a going concern. The accompanying condensed 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 uncertainty 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.

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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 September 30,				For the nine months ended September 30,
	2025		2024		2025		2024
Oil & Condensate Sales	$	512,171	$	504,915	$	1,187,236	$	1,578,513
Natural Gas Sales		71,800		53,896		182,925		167,966
NGL Sales		605		898		2,758		2,641
Total	$	584,576	$	559,709	$	1,372,919	$	1,749,120

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.

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 Deferred 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.

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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. 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.

	September 30, 2025		December 31, 2024
Cash and Cash Equivalents	$	796,979	$	1,877,163
Restricted Cash		5,476,900		6,025,000
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows	$	6,273,879	$	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 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 September 30, 2025 and December 31, 2024, we established an allowance for expected credit losses of $2,277,186 and $2,194,552, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected.

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.

Reclassification

During the current quarter, the Company identified a prior quarter reclassification error and missing segment disclosure. Management determined the errors were not material to prior quarters; therefore, prior quarter financial statements have not been restated. The correction was recorded in the current quarter as an out-of-period adjustment, resulting in a reclassification of $390,000 from non-operating income (expense) to operating expenses and inclusion of the required segment information. These adjustments had no impact on net loss or total equity.

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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 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:

	September 30,			December 31,
	2025			2024
	(Unaudited)
Oil and Gas
Producing properties, including drilling costs	$	7,261,928		$	5,764,761
Undeveloped properties		3,252,830			3,339,234
Lease and well equipment		3,298,441			3,295,028
		13,813,199			12,399,023

Accumulated depletion, depreciation & amortization		(7,938,916	)		(7,748,190	)
Net capitalized Oil and Gas costs	$	5,874,283		$	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		(1,139,080	)		(1,137,597	)
		4,343			5,826
Net capitalized costs Total	$	5,878,626		$	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.

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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 quarterly updated evaluation assumptions for crude oil commodity prices. Quarterly volumes are based on field production profiles, which are also updated quarterly. Prices for natural gas and other products are based on assumptions developed quarterly 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 nine months ended September 30, 2025 and 2024, we incurred an impairment loss of $27,250 and $400,554, 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.

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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 September 30, 2025 and December 31, 2024, we had Deferred Drilling Obligations of $13,982,996 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:

	Three Months Ended September 30,
	2025						2024
	Basic			Diluted			Basic			Diluted
Net Loss	$	(550,293	)		(550,293	)	$	(1,184,291	)		(1,184,291	)
Less: Preferred Stock Dividend		-			-			221,410			221,410
Net Loss Attributable to Common Shareholders		(550,293	)		(550,293	)		(1,405,701	)		(1,405,701	)
Weighted average common shares outstanding		96,600,302			96,600,302			71,863,529			71,863,529
Weighted average common shares, including Dilutive effect		96,600,302			96,600,302			71,863,529			71,863,529
Per share:
Net Loss	$	(0.01	)	$	(0.01	)	$	(0.02	)	$	(0.02	)

	Nine Months Ended September 30,
	2025						2024
	Basic			Diluted			Basic			Diluted
Net Loss	$	(1,651,014	)		(1,651,014	)	$	(2,065,017	)		(2,065,017	)
Less: Preferred Stock Dividend		-			-			653,730			653,730
Net Loss Attributable to Common Shareholders		(1,651,014	)		(1,651,014	)		(2,718,747	)		(2,718,747	)
Weighted average common shares outstanding		96,600,302			96,600,302			71,693,073			71,693,073
Weighted average common shares, including Dilutive effect		96,600,302			96,600,302			71,693,073			71,693,073
Per share:
Net Loss	$	(0.02	)	$	(0.02	)	$	(0.04	)	$	(0.04	)

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For the nine and three months ended September 30, 2025 and 2024, we had dilutive securities of 0 and 24,664,550, respectively. During the nine and three month periods in 2025 and 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. Management has reviewed the realizability of our net deferred tax assets, and due to our continued cumulative losses in recent years, we concluded it is “more-likely-than-not” our deferred tax assets will not 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 nine months ended September 30, 2025, no common stock was issued in lieu of cash payments for salaries and board fees. During the nine months ended September 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:

Balance at December 31, 2023	$	1,837,551
Provision for credit loss		279,491
Write-offs charged against the allowance		93,740
Balance at September 30, 2024	$	2,023,302

Balance at December 31, 2024	$	2,194,552
Provision for credit loss		111,558
Write-offs charged against the allowance		28,924
Balance at September 30, 2025	$	2,277,186

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NOTE 8 – RELATED PARTY NOTES PAYABLE

On February 7, 2024, the Board of Directors of the Company approved a related-party 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 under the control of Johnny Jordan, the Company’s Chief Executive Officer and a member of the Company’s Board of Directors. Mr. Jordan is also the beneficial owner of approximately 29.2% of the Company’s issued and outstanding common stock. The initial advance to the Company was $1,400,000 on February 9, 2024.

The loan originally bore interest at 18.0% per annum, with monthly interest-only payments beginning March 1, 2024. The loan is secured by a deed of trust recorded in Ector County, Texas, covering certain of the Company’s oil and gas assets located in Ector County.

On November 1, 2024, the maturity date of the loan was extended from August 1, 2025 to January 1, 2026. Subsequently, on August 29, 2025, the loan was further extended to April 1, 2027, and the Company executed an additional advance of $500,000 on the loan, increasing the total outstanding principal balance to $1,900,000. Effective September 1, 2025, the interest rate on the outstanding principal was reduced from 18.0% to 15.0% per annum.

Except as modified by the amendments described above, all other terms and conditions of the Secured Term Loan Note remain in full force and effect.

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 September 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:

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.

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.

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.

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.

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 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 September 30, 2025, the Company had 96,600,302 shares of common stock outstanding, and no preferred shares issued or outstanding.

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NOTE 10 – BUSINESS COMBINATION: ACQUISITION OF ADDITIONAL INTEREST IN PRADERA FUEGO

On September 3, 2025, we completed the acquisition of non-operated working interests in seven producing Barnett wells adding an additional 18.5% aggregate working interest and corresponding 13.875% aggregate net revenue interest in the Pradera Fuego (the “Pradera Fuego Acquisition”) field located in Ector County, Texas, within the Permian Basin, for a total of $1,500,000. We accounted for the transaction as an asset acquisition. The acquisition increases the Company’s economic interest in the Pradera Fuego operations.

NOTE 11 – SEGMENT REPORTING

The Company has one reportable segment, which encompasses the ownership and investment in onshore oil and natural gas properties in the United States and turnkey drilling programs. The segment’s revenues are derived from the Company’s interests in the sales of crude oil, natural gas, and NGL production.

The Company evaluates performance based on various financial metrics, including but not limited to consolidated income or loss from operations, net revenue, and cash flow from operations. The Company’s chief executive officer, chief operating officer, and chief financial officer together function as the chief operating decision maker (“CODM”) and manage the Company’s business activities as a single operating segment.

The accounting policies of the one reportable segment are identical to those described for the consolidated Company. The CODM uses income (loss), as reported in the unaudited condensed consolidated statement of operations, to measure segment profitability, assess performance, and manage strategic capital resource allocations. The measure of segment assets is reported as “Total assets” on the unaudited condensed consolidated balance sheets. The significant expense categories regularly provided to and reviewed by the CODM are those presented in the unaudited condensed consolidated statements of operations.

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

FORWARD-LOOKING STATEMENTS

In addition to historical information contained herein, certain information contained in this Quarterly Report on Form 10-Q, as well as other written and oral statements made or incorporated by reference from time to time by the Company and 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 Securities Exchange Act of 1934 (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 be 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. Prior to 2019, Royale primarily acquired and developed producing and non-producing natural gas properties in California. In December 2018, Royale became the operator of an 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 nine months ended September 30, 2025, and 2024, we incurred net losses of $1,651,014 and $2,065,017, respectively. The difference was primarily due to lower lease operating, lease impairment, and credit loss expenses recognized during the nine months ended September 30, 2025 when compared to the same period in 2024. During the three months ended September 30, 2025 and 2024, we incurred net losses of $550,293 and $1,184,291, respectively. The difference was due primarily an impairment of $337,500 recognized during the period in 2024.

During the first nine months of 2025, revenues from oil and gas production decreased $376,201 or 21.5%, to $1,372,919 during the period in 2025 from revenues of $1,749,120 during the first nine months of 2024. This decrease was mainly due to lower oil and natural gas production volumes and lower oil commodity prices. The net sales volume of oil and condensate for the nine months ended September 30, 2025, was approximately 18,592 barrels with an average price of $63.86 per barrel, versus 21,079 barrels with an average price of $74.88 per barrel for the nine months of 2024. This represents a decrease in net sales volume of 2,487 barrels or 11.8%, which was mainly due to wells being offline during the period in 2025 due to weather related issues in our Texas Jameson field. The net sales volume of natural gas for the nine months ended September 30, 2025, was approximately 84,898 Mcf with an average price of $2.15 per Mcf, versus 91,255 Mcf with an average price of $1.84 per Mcf for the same period in 2024. This represents a decrease in net sales volume of 6,357 Mcf or 7.0%. The decrease in natural gas production volume was also due to the weather related issues in our Jameson field and to some of our California natural gas wells being offline for approximately a month due to mandatory pipeline inspections by Pacific Gas and Electric. For the quarter ended September 30, 2025, revenues from oil and gas production increased $24,867 or 4.4% to $584,576 from the 2024 third quarter revenues of $559,709. This increase was due to higher oil and natural gas production volumes during the period in 2025. The net sales volume of oil and condensate for the quarter ended September 30, 2025, was approximately 8,092 barrels with an average price of $63.29 per barrel, versus 6,800 barrels with an average price of $74.25 per barrel for the third quarter of 2024. This represents an increase in net sales volume of 1,292 barrels or 19.0% for the quarter in 2025. The net sales volume of natural gas for the quarter ended September 30, 2025, was approximately 34,096 Mcf with an average price of $2.11 per Mcf, versus 30,182 Mcf with an average price of $1.79 per Mcf for the third quarter of 2024. This represents an increase in net sales volume of 3,914 Mcf or 13.0% for the quarter in 2025.

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Oil and natural gas lease operating expenses decreased by $444,056 or 34.4%, to $848,469 for the nine months ended September 30, 2025, from $1,292,525 for the same period in 2024. For the third quarter of 2025, lease operating expenses decreased $151,414 or 29.6% from the same quarter in 2024. Both of these decreases were partially due to lower workover related costs and equipment repairs on our Jameson field during the period in 2025 as we attempted to increase production during the period in 2024. During the nine months ended September 30, 2025, we also recorded settlement of accounts payable of $105,494 with a vendor due to an equipment failure which occurred during a workover. Additionally, during the nine months ended September 30, 2025, we recorded a settlement of accounts payable of $53,583 due to the write-off of accounts payable where vendors are not legally entitled to collect.

The aggregate of supervisory fees and other income was $74,234 for the nine months ended September 30, 2025, an increase of $29,271 from $44,963 during the same period in 2024. During the third quarter of 2025, supervisory fees and other income increased $6,548 when compared to the same quarter in 2024. These increases were mainly due to higher interest income on our bank balances.

Depreciation, depletion and amortization expense decreased to $198,976 from $253,726, a decrease of $54,750 or 21.6% for the nine months ended September 30, 2025, compared to the same period in 2024. This decrease in depletion expense was due to an increase in expected recoverable reserves which decreased the depletion rate. The depreciation rate is calculated using production as a percentage of reserves. During the third quarter 2025, depreciation, depletion and amortization expenses increased $26,949 or 47.7% due to an increase in our oil and gas assets during the quarter due to our purchase of additional interests in existing wells.

At September 30, 2025, Royale Energy had a Deferred Drilling Obligation of $13,982,996. During the first nine months of 2025, although we participated in the drilling of a well in the Texas Permian basin, we did not book turnkey gains or losses as we waited for the well to be completed and the final costs to be determined. At December 31, 2024, Royale Energy had a Deferred Drilling Obligation of $11,328,332. During the first nine months of 2024, we removed $3,371,095 of drilling obligations as we participated in the drilling and completion of two oil wells in the Texas Permian basin, while incurring expenses of $2,843,380, resulting in a gain of $527,715.

General and administrative expenses increased by $37,326 or 3.1% from $1,197,677 for the nine months ended September 30, 2024 to $1,235,003 for the same period in 2025. For the third quarter 2025, general and administrative expenses increased $13,311 or 3.6% when compared to the same period in 2024. These increases were mainly due to higher employee related expenses during the periods in 2025. For the first nine months of 2025, marketing expenses decreased $41,252 or 15.3% to $228,732, compared to $269,984 for the first nine months of 2024. For the third quarter 2025, marketing expenses decreased $66,007 or 51.5% when compared to the third quarter in 2024. Marketing expense varies from period to period according to the number of marketing events attended by our personnel and their associated costs.

Legal and accounting expense decreased to $382,660 for the nine-month period in 2025, compared to $485,114 for the same period in 2024, a decrease of $102,454 or 21.1%. For the third quarter 2025, legal and accounting expenses decreased $66,002 or 46.2%. These decreases during the periods in 2025 were primarily due to higher legal fees related to our debt facility entered into during the period in 2024.

During the nine months ended September 30, 2025, we recorded a $230,681 gain on settlement of asset retirement obligation liability due mainly to finalizing the plugging and abandonment of three natural gas sites in California. During the nine months ended September 30, 2025 and 2024, we recorded impairments of $27,250 and $400,554, respectively, on various lease and land costs in our California natural gas fields where the carrying value exceeded the fair value. During the nine months ended September 30, 2025 and 2024, we also recorded Credit Loss expenses of $111,558 and $279,491, 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 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 nine months ended September 30, 2025, and 2024, was $296,200 and $207,744, respectively. The higher 2025 interest expense was due to the $1.4 million note payable entered into in February 2024, discussed in Note 8 and the notes payable related to the debt restructuring in October 2024, discussed in Note 9.

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CAPITAL RESOURCES AND LIQUIDITY

At September 30, 2025, we had current assets totaling $8,765,809 and current liabilities totaling $20,992,223, resulting in a $12,226,414 working capital deficit. We had $796,979 in cash and $5,476,900 in restricted cash at September 30, 2025, compared to $1,877,163 in cash and $6,025,000 in restricted cash at December 31, 2024.

At September 30, 2025, our other receivables, which consist of joint interest billing receivables from direct working interest investors and industry partners, totaled $663,775 compared to $868,429 at December 31, 2024, a $204,654 or 23.6% decrease, mainly due to lower joint interest billing receivables. At September 30, 2025, revenue receivable was $573,638, a decrease of $191,015, compared to $764,653 at December 31, 2024, due to lower production volumes and commodity prices during the period in 2025 when compared to the fourth quarter of 2024. At September 30, 2025, our accounts payable and accrued expenses totaled $5,261,628, a decrease of $1,704,977 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 third quarter 2025 and accounts payable payments and accrued liability settlements during the period in 2025.

We have had recurring operating and net losses and cash used in operations and the condensed consolidated financial statements reflect a working capital deficiency of $12,226,414 and an accumulated deficit of $95,155,483. 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 properties, sales of participation interests in oil and gas wells 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 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 should allow the Company to meet its liquidity needs through the remainder of 2025.

Operating Activities. Net cash used in operating activities totaled $2,675,708 and $1,381,384 for the nine months ended September 30, 2025 and 2024, respectively, a $1,294,324 or 93.7% difference. This difference in cash used was mainly due to a decrease in accounts payable and accrued expenses due to payments made during the period, lower revenue payables to direct working interest owners due to lower revenue receipts, and to accrued asset retirement liability settlements during the 2025 period.

Investing Activities. Net cash provided by investing activities totaled $555,994 and $231,089 for the nine months ended September 30, 2025 and 2024, respectively, a $324,905 or 140.6% difference. During the nine month period in 2025, we received approximately $2.5 million in drilling funds while our drilling and lease expenditures were approximately $2.0 million, mainly due to our purchase of additional interests in our existing Permian basin wells. During the nine-month period in 2024, we received approximately $4.9 million in drilling funds while our drilling and lease expenditures were approximately $4.7 million as we participated in drilling and obtained lease interests in the Permian basin.

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Financing Activities. Net cash provided by financing activities totaled $491,430 and $1,393,039 for the nine months ended September 30, 2025 and 2024, respectively. The difference in cash provided, was due to receipt of $500,000 during the period in 2025 and $1.4 million received in 2024 from the note payable discussed in Note 8. During the nine-month periods in 2025 and 2024, $8,570 and $6,961, respectively, were 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.

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, 2024, 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 Exchange Act. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

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

●

In connection with the audit of our 2024 consolidated financial statements, management identified a material weakness that exists because we did not maintain effective controls over our financial close and reporting process, and has concluded that the financial close and reporting process needs additional formal procedures to ensure that appropriate reviews occur on all financial reporting analysis. Management has designed and implemented updated control procedures that we believe will mitigate this material weakness and is monitoring these procedures for effectiveness.

We evaluated the effectiveness of our disclosure controls and procedures as of September 30, 2025, with the participation of our CEO and CFO, as well as other key members of our management. Based on this evaluation, our CEO and CFO concluded that our disclosure controls and procedures were not effective as of September 30, 2025.

Notwithstanding the material weaknesses described above, our management, including our Chief Executive Officer and Chief Financial Officer, believes that the condensed 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 interim 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 condensed 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 September 30, 2025, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

Not applicable to smaller reporting companies.

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

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

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits

10.1		Secured Term Loan dated as of February 9, 2024 among Royale Energy, Inc., as borrower, Walou Investments, LP as administrative agent for the lenders, and Walou Investments, LP, as lender. Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 15, 2024.
10.2		Deed of Trust, Mortgage, Security Agreement, Fixture Filing, Financing Statement and Assignment of Production dated as of February 15, 2024, executed by Royale Energy Funds, Inc., as mortgagor, to Johnny Jordan, as Trustee, for the benefit of Agent, as mortgagee. Incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on February 15, 2024.
31.1		Rule 13a-14(a)/15d-14(a) Certification
31.2		Rule 13a-14(a)/15d-14(a) Certification
32.1		18 U.S.C. § 1350 Certification
32.2		18 U.S.C. § 1350 Certification
101.INS		Inline XBRL Instance Document
101.SCH		Inline XBRL Taxonomy Extension Schema
101.CAL		Inline XBRL Taxonomy Extension Calculation Linkbase
101.DEF		Inline XBRL Taxonomy Extension Definition Linkbase
101.LAB		Inline XBRL Taxonomy Extension Label Linkbase
101.PRE		Inline XBRL Taxonomy Extension Presentation Linkbase
104		Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

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Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	ROYALE ENERGY, INC.

Date: November 26, 2025	/s/ Johnny Jordan
	Johnny Jordan,
	Chief Executive Officer

Date: November 26, 2025	/s/ Ronald Lipnick
	Ronald Lipnick,
	Chief Financial Officer

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Royale Energy, Inc. 10-Q