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 June 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 August 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

Consolidated Balance Sheets as of June 30, 2025 and December 31, 2024		3

Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2025 and 2024		5

Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2025 and 2024		6

Consolidated Statements of Stockholders’ Deficit for the Three and Six Months Ended June 30, 2025 and 2024		7

Notes to Consolidated Financial Statements		8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		16

Item 3. Quantitative and Qualitative Disclosures About Market Risk		18

Item 4. Controls and Procedures		18

PART II. OTHER INFORMATION		20

Item 1. Legal Proceedings		20

Item 1A. Risk Factors		20

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		20

Item 3. Defaults Upon Senior Securities		20

Item 4. Mine Safety Disclosures		20

Item 5. Other Information		20

Item 6. Exhibits		20

Signatures		21

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30, 2025		December 31, 2024
	(unaudited)
ASSETS
Current Assets:
Cash and Cash Equivalents	$	1,456,696	$	1,877,163
Restricted Cash		6,000,000		6,025,000
Other Receivables, net		685,566		868,429
Revenue Receivables		332,426		764,653
Prepaid Expenses and Other Current Assets		754,105		619,913
Deferred Drilling Costs		235,052		-
Total Current Assets		9,463,845		10,155,158

Other Assets		576,265		589,865
Right of Use Asset - Operating Leases		190,108		238,509
Oil and Gas Properties (Successful Efforts Basis), Real Property and Equipment and Fixtures, net		4,213,972		4,656,659
Total Assets	$	14,444,190	$	15,640,191

See notes to unaudited condensed consolidated financial statements.

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ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30, 2025			December 31, 2024
	(unaudited)
LIABILITIES AND STOCKHOLDERS’ DEFICIT
Current Liabilities:
Accounts Payable and Accrued Expenses	$	5,066,253		$	6,966,605
Notes Payable - Current		1,400,000			-
Royalties Payable		611,833			611,833
RMX Resources, LLC		23,087			23,087
Operating Leases - Current		98,131			94,070
Asset Retirement Obligation - Current		1,012,500			1,012,500
Deferred Drilling Obligations		13,282,996			11,457,996

Total Current Liabilities		21,494,800			20,166,091

Noncurrent Liabilities:
Asset Retirement Obligation		4,028,905			4,066,095
Notes Payable - Non-current		2,153,415			3,489,290
Operating Leases - Non-current		94,720			145,644
Accrued Unpaid Guaranteed Payments		90,000			90,000
Accrued Liabilities - Non-current		12,386			12,386

Total Liabilities		27,874,226			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 June 30, 2025 and December 31, 2024, respectively		96,600			96,600

Additional Paid in Capital		81,078,554			81,078,554

Accumulated Deficit		(94,605,190	)		(93,504,469	)

Total Stockholders’ Deficit		(13,430,036	)		(12,329,315	)

Total Liabilities, and Stockholders’ Deficit	$	14,444,190		$	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 six months ended
	June 30, 2025			June 30, 2024			June 30, 2025			June 30, 2024
Revenues:
Oil, NGL and Gas Sales	$	332,237		$	545,746		$	788,343		$	1,189,411
Supervisory Fees and Other		21,314			13,989			52,981			30,258
Total Revenues		353,551			559,735			841,324			1,219,669

Costs and Expenses:
Oil and Gas Lease Operating		304,138			347,371			592,977			780,125
Depreciation, Depletion and Amortization		42,262			110,153			115,480			197,179
Impairment		-			6,845			27,250			63,054
Legal and Accounting		60,206			62,625			305,712			342,164
Credit Loss Expense		-			145,086			13,126			176,044
Marketing		97,493			81,781			166,528			141,773
General and Administrative		385,628			380,707			852,046			828,031
Total Costs and Expenses		889,727			1,134,568			2,073,119			2,528,370

Gain on Turnkey Drilling		-			527,715			-			527,715

Loss From Operations		(536,176	)		(47,118	)		(1,231,795	)		(780,986	)
Other Income (Expense):
Interest Expense		(97,933	)		(63,498	)		(195,112	)		(99,740	)
Gain on Settlement of Accounts Payable		-			-			105,494			-
Gain on Settlement of Asset Retirement Obligations		215,339			-			220,692			-
Net Loss		(418,770	)		(110,616	)		(1,100,721	)		(880,726	)
Less: Preferred Stock Dividend		-			217,099			-			432,320
Net Loss available to common stock	$	(418,770	)	$	(327,715	)	$	(1,100,721	)	$	(1,313,046	)

Shares used in computing Basic and Diluted Net Loss per share		96,600,302			71,863,529			96,600,302			71,606,757

Basic and Diluted Net Loss Per Share	$	(0.00	)	$	(0.00	)	$	(0.01	)	$	(0.02	)

See notes to unaudited condensed consolidated financial statements.

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ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

FOR THE SIX MONTHS ENDED JUNE 30, 2025 AND 2024

	For the Six Months Ended
	June 30, 2025			June 30, 2024
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	(1,100,721	)	$	(880,726	)
Adjustments to Reoconcile Net Loss to Net Cash Used in Operating Activities:
Depreciation, Depletion and Amortization		115,480			197,179
Gain on Turnkey Drilling Programs		-			(527,715	)
Impairment		27,250			63,054
Credit Loss Expense		13,126			176,044
Gain on Settlement of Accounts Payable		(105,494	)		-
Gain on Settlement of Asset Retirement Obligation		(220,692	)		-
Stock-Based Compensation		-			35,999
Accretion of Debt Restructure Notes Payable		64,125			-
Right of Use Asset Depreciation		7,163			5,508
Changes in Operating Assets and Liabilities:
Other & Revenue Receivables		601,964			646,346
Prepaid Expenses and Other Assets		(120,592	)		(62,431	)
Royalties Payable		-			(1,092	)
Accounts Payable and Accrued Expenses		(1,529,520	)		(380,356	)
Net Cash Used in Operating Activities		(2,247,911	)		(728,190	)
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for Oil and Gas Properties and Other Capital Expenditures		(16,931	)		(3,636,191	)
Proceeds from Turnkey Drilling Programs		1,825,000			3,075,000
Net Cash Provided by (Used in) Investing Activities		1,808,069			(561,191	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long Term Debt		-			1,400,000
Lease Financing Payments		(5,625	)		(6,272	)
Net Cash Provided by (Used in) Financing Activities		(5,625	)		1,393,728

Net Increase (Decrease) in Cash and Cash Equivalents, and Restricted Cash		(445,467	)		104,347

Cash, Cash Equivalents, and Restricted Cash at Beginning of Period		7,902,163			5,527,521
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	7,456,696		$	5,631,868
Cash Paid for Interest	$	130,987		$	99,740
Cash Paid for Taxes	$	8,250		$	7,950

SUPPLEMENTAL DISCLOSURES OF NON-CASH INVESTING & FINANCING TRANSACTIONS:
Accounts Payable for Oil and Gas Properties	$	-		$	1,000,000
Increase (Decrease) in Capital Accrued Balance	$	(8,905	)	$	14,481
SUPPLEMENTAL DISCLOSURES OF NON CASH INVESTING & FINANCING ACTIVITIES:
Series B Paid-In-Kind Dividends	$	-		$	432,320

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 SIX MONTHS ENDED JUNE 30, 2025 AND 2024
(UNAUDITED)

	Common Stock
	Number of Shares Issued and Outstanding		Amount		Additionl Paid in		Accumulated Comprehensive			Total Stockholders’
	Common Shares		Common Amount		Capital APIC		Deficit ACD			Deficit Total
December 31, 2023 Balance		70,564,188	$	70,564	$	54,619,236	$	(90,323,289	)	$	(35,633,489	)
Stock Issued in lieu of Compensation		1,299,641		1,299		34,700		-			35,999
Preferred Series B 3.5% Dividend		-		-		-		(432,320	)		(432,320	)
Net Loss		-		-		-		(880,726	)		(880,726	)
June 30, 2024 Balance		71,863,829	$	71,863	$	54,653,936	$	(91,636,335	)	$	(36,910,536	)

	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								(1,100,721	)		(1,100,721	)
June 30, 2025 Balance		96,600,302	$	96,600	$	81,078,554	$	(94,605,190	)	$	(13,430,036	)

	Common Stock
	Number of Shares Issued and Outstanding		Amount		Additional Paid in		Accumulated Comprehensive			Total Stockholders’
	Common Shares		Common Amount		Capital APIC		Deficit ACD			Deficit Total
March 31, 2024 Balance		71,863,829	$	71,863	$	54,653,936	$	(91,308,620	)	$	(36,582,821	)
Preferred Series B 3.5% Dividend		-		-		-		(217,099	)		(217,099	)
Net Loss		-		-		-		(110,616	)		(110,616	)
June 30, 2024 Balance		71,863,829	$	71,863	$	54,653,936	$	(91,636,335	)	$	(36,910,536	)

	Common Shares		Common Amount		APIC		ACD			Total
March 31, 2025 Balance		96,600,302	$	96,600	$	81,078,554	$	(94,186,420	)	$	(13,011,266	)
Net Loss		-		-		-		(418,770	)		(418,770	)
June 30, 2025 Balance		96,600,302	$	96,600	$	81,078,554	$	(94,605,190	)	$	(13,430,036	)

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 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.

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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 June 30,				For the six months ended June 30,
	2025		2024		2025		2024
Oil & Condensate Sales	$	281,205	$	514,240	$	675,065	$	1,073,598
Natural Gas Sales		50,029		30,335		111,125		114,070
NGL Sales		1,003		1,171		2,153		1,743
Total	$	332,237	$	545,746	$	788,343	$	1,189,411

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.

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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 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.

	June 30, 2025		December 31, 2024
Cash and Cash Equivalents	$	1,456,696	$	1,877,163
Restricted Cash		6,000,000		6,025,000
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows	$	7,456,696	$	7,902,163

Equity Method Investments

Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting. Income from equity method investments represents our proportionate share of net income generated by the equity method investees and is reflected in revenue and other income in our 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.

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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 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:

	June 30,			December 31,
	2025			2024
	(Unaudited)
Oil and Gas
Producing properties, including drilling costs	$	5,667,301		$	5,764,761
Undeveloped properties		3,102,157			3,339,234
Lease and well equipment		3,298,441			3,295,028
		12,067,899			12,399,023

Accumulated depletion, depreciation & amortization		(7,858,764	)		(7,748,190	)
Net capitalized Oil and Gas costs	$	4,209,135		$	4,650,833

Commercial and Other
Vehicles		40,061			40,061
Furniture and equipment		1,103,362			1,103,362
		1,143,423			1,143,423
Accumulated depreciation		(1,138,586	)		(1,137,597	)
		4,837			5,826
Net capitalized costs Total	$	4,213,972		$	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.

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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.

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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.

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NOTE 4 – LOSS PER SHARE

Basic and diluted loss per share are calculated as follows:

	Three Months Ended June 30,
	2025						2024
	Basic			Diluted			Basic			Diluted
Net Loss	$	(418,770	)		(418,770	)	$	(110,616	)		(110,616	)
Less: Preferred Stock Dividend		-			-			217,099			217,099
Net Loss Attributable to Common Shareholders		(418,770	)		(418,770	)		(327,715	)		(327,715	)
Weighted average common shares outstanding		96,600,302			96,600,302			71,863,529			71,863,529
Effect of dilutive securities		-			-			-			-
Weighted average common shares, including Dilutive effect		96,600,302			96,600,302			71,863,529			71,863,529
Per share:
Net Loss	$	(0.00	)	$	(0.00	)	$	(0.00	)	$	(0.00	)

	Six Months Ended June 30,
	2025						2024
	Basic			Diluted			Basic			Diluted
Net Loss	$	(1,100,721	)		(1,100,721	)	$	(880,726	)		(880,726	)
Less: Preferred Stock Dividend		-			-			432,320			432,320
Net Loss Attributable to Common Shareholders		(1,100,721	)		(1,100,721	)		(1,313,046	)		(1,313,046	)
Weighted average common shares outstanding		96,600,302			96,600,302			71,606,757			71,606,757
Effect of dilutive securities		-			-			-			-
Weighted average common shares, including Dilutive effect		96,600,302			96,600,302			71,606,757			71,606,757
Per share:
Net Loss	$	(0.01	)	$	(0.01	)	$	(0.02	)	$	(0.02	)

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.

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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		176,044
Write-offs charged against the allowance		68,077
Balance at June 30, 2024	$	1,945,518

Balance at December 31, 2024	$	2,194,552
Provision for credit loss		13,126
Write-offs charged against the allowance		28,589
Balance at June 30, 2025	$	2,179,089

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:

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

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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 six months ended June 30, 2025, and 2024, we incurred net losses of $1,100,721 and $880,726, respectively. The difference was primarily due to the gain on turnkey drilling recognized during the six months ended June 30, 2024, where we recognized a gain of $527,715 as we participated in the drilling and completion of two wells in the Texas Permian basin and decreased oil and gas revenues. During the three months ended June 30, 2025 and 2024, we had net losses of $418,770 and $110,616, respectively. The difference was due primarily to the $527,715 gain on turnkey drilling recognized during the second quarter of 2024.

During the first six months of 2025, revenues from oil and gas production decreased $401,068 or 33.7%, to $788,343 during the period in 2025 from revenues of $1,189,411 during the first six 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 six months ended June 30, 2025, was approximately 10,500 barrels with an average price of $64.29 per barrel, versus 14,280 barrels with an average price of $75.18 per barrel for the six months of 2024. This represents a decrease in net sales volume of 3,780 barrels or 26.5%, 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 six months ended June 30, 2025, was approximately 50,801 Mcf with an average price of $2.19 per Mcf, versus 61,073 Mcf with an average price of $1.87 per Mcf for the same period in 2024. This represents a decrease in net sales volume of 10,272 Mcf or 16.8%. 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 June 30, 2025, revenues from oil and gas production decreased $213,509 or 39.1% to $332,237 from the 2024 second quarter revenues of $545,746. This decrease was also due to lower oil production volumes and lower oil commodity prices. The net sales volume of oil and condensate for the quarter ended June 30, 2025, was approximately 4,812 barrels with an average price of $58.44 per barrel, versus 6,476 barrels with an average price of $79.41 per barrel for the second quarter of 2024. This represents a decrease in net sales volume of 1,664 barrels or 25.7% for the quarter in 2025. The net sales volume of natural gas for the quarter ended June 30, 2025, was approximately 28,035 Mcf with an average price of $1.78 per Mcf, versus 28,414 Mcf with an average price of $1.07 per Mcf for the second quarter of 2024. This represents a decrease in net sales volume of 379 Mcf or 1.3% for the quarter in 2025.

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Oil and natural gas lease operating expenses decreased by $187,148 or 24.0%, to $592,977 for the six months ended June 30, 2025, from $780,125 for the same period in 2024. For the second quarter of 2025, lease operating expenses decreased $43,233 or 12.5% from the same quarter in 2024. Both of these decreases were 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.

The aggregate of supervisory fees and other income was $52,981 for the six months ended June 30, 2025, an increase of $22,723 from $30,258 during the same period in 2024. During the second quarter of 2025, supervisory fees and other income increased $7,325 when compared to the quarter in 2024. These increases were mainly due to higher interest income on our bank balances.

Depreciation, depletion and amortization expense decreased to $115,480 from $197,179, a decrease of $81,699 or 41.4% for the six months ended June 30, 2025, as compared to the same period in 2024. During the second quarter 2025, depreciation, depletion and amortization expenses decreased $67,891 or 61.6%. The depletion rate is calculated using production as a percentage of reserves. This decrease in depletion expense was due to an increase in expected recoverable reserves which decreased the depletion rate.

At June 30, 2025, Royale Energy had a Deferred Drilling Obligation of $13,282,996. During the first six 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 June 30, 2024, Royale Energy had a Deferred Drilling Obligation of $9,465,832. During the first six 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 $24,015 or 2.9% from $828,031 for the six months ended June 30, 2024 to $852,046 for the same period in 2025. For the second quarter 2025, general and administrative expenses increased $4,921 or 1.3% when compared to the same period in 2024. These increases were mainly due to higher employee related expenses due primarily to marketing bonuses paid to employees during the period in 2025. For the first six months of 2025, marketing expenses increased $24,755 or 17.5% to $166,528, compared to $141,773 for the first six months of 2024. For the second quarter 2025, marketing expenses increased $15,712 or 19.2% when compared to the second quarter in 2024. Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs.

Legal and accounting expense decreased to $305,712 for the six-month period in 2025, compared to $342,164 for the same period in 2024, a $36,452 or 10.7%. For the second quarter 2025, legal and accounting expenses decreased $2,419 or 3.9%. These decreases during the period in 2025 were primarily due to higher legal fees related to our debt facility entered into during the period in 2024.

During the six months ended June 30, 2025, we recorded a $220,692 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 six months ended June 30, 2025, we recorded a gain on settlement of $105,494 with a vendor due to an equipment failure which occurred during a workover. During the six months ended June 30, 2025, we recorded impairments of $27,250 on various lease and land costs in our California natural gas fields where the carrying value exceeded the fair value, compared to $63,054, recorded in the first six months of 2024. During the six months ended June 30, 2025 and 2024, we also recorded Credit Loss expenses of $13,126 and $176,044, respectively, which arose from identified uncollectable receivables relating to our oil and natural gas properties either plugged and abandoned or scheduled for plugging and abandonment (“P&A”) and our period end oil and natural gas reserve values. We periodically review our accounts receivable from working interest owners to determine whether collection of any of these charges appears doubtful.

Interest expense for the six months ended June 30, 2025, and 2024, was $195,112 and $99,740, 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.

CAPITAL RESOURCES AND LIQUIDITY

At June 30, 2025, we had current assets totaling $9,463,845 and current liabilities totaling $21,494,800, resulting in a $12,030,955 working capital deficit. We had $1,456,696 in cash and $6,000,000 in restricted cash at June 30, 2025, compared to $1,877,163 in cash and $6,025,000 in restricted cash at December 31, 2024.

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At June 30, 2025, our other receivables, which consist of joint interest billing receivables from direct working interest investors and industry partners, totaled $685,566 compared to $868,429 at December 31, 2024, a $182,863 or 21.1% decrease, mainly due to lower joint interest billing receivables. At June 30, 2025, revenue receivable was $332,426, a decrease of $432,227, 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 June 30, 2025, our accounts payable and accrued expenses totaled $5,066,253, a decrease of $1,900,352 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 second 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 consolidated financial statements reflect a working capital deficiency of $12,030,955 and an accumulated deficit of $94,605,190. These factors raise substantial doubt about our ability to continue as a going concern, and anticipate that our primary sources of liquidity will be from the sale of oil and gas in the course of normal operations, the sale of oil and gas property, sales of participation interest and possible issuance of debt and/or equity. If we are unable to generate sufficient cash from operations or financing sources, it may become necessary to curtail, suspend or cease operations, sell property, or enter into financing transaction(s) on less favorable terms; any such outcomes could have a material adverse effect on our business, results of operations, financial position, and liquidity. Management has plans to 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 $2,247,911 and $728,190 for the six months ended June 30, 2025 and 2024, respectively, a $1,519,721 or 209% 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 $1,808,069 for the six months ended June 30, 2025, while net cash used in investing activities totaled $561,191 for the six months ended June 30, 2024. During the six month period in 2025, we received approximately $1.8 million in drilling funds while our drilling and lease expenditures were approximately $16,900. During the six-month period in 2024, we received approximately $3.1 million in drilling funds while our drilling and lease expenditures were approximately $3.6 million as we participated in drilling and obtained lease interests in the Permian basin.

Financing Activities. Net cash used in financing activities totaled $5,625 for the six months ended June 30, 2025 and net cash provided by financing activities was $1,393,728 for the six months ended June 30, 2024. The difference in cash provided, was due to receipt of $1.4 million from the note payable discussed in Note 8. During the six-month periods in 2025 and 2024, the totals were also used for principal payments on our financing lease payments.

Critical Accounting Estimates

Our critical accounting policies are further disclosed in Note 1 to the consolidated financial statements included in our 2024 Annual Report on Form 10-K.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

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.

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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 and 2023 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.

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

Notwithstanding the material weaknesses described above, our management, including our Chief Executive Officer and Chief Financial Officer, believes that the consolidated financial statements contained in this Report on Form 10-Q fairly present, in all material respects, our financial condition, results of operations and cash flows for the 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 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 June 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.

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)

Table of Contents

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: August 14, 2025	/s/ Johnny Jordan
	Johnny Jordan,
	Chief Executive Officer

Date: August 14, 2025	/s/ Ronald Lipnick
	Ronald Lipnick,
	Chief Financial Officer

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Royale Energy, Inc. 10-Q