UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2025

Commission File No. 000-055912

ROYALE ENERGY, INC.

(Name of registrant in its charter)

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

1530 Hilton Head Road #205

El Cajon, CA 92019

(Address of principal executive offices)

Registrant’s telephone number: 619-383-6600

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

Securities to be registered pursuant to Section 12(g) of the Act:

Common Stock, 0.001 par value per share

(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ☐ No ☒

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 during the past 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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

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

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. ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☒

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to § 240.10D-1(b). ☐

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

At June 30, 2025, the end of the registrant’s most recently completed second fiscal quarter; the aggregate market value of Common Stock held by non-affiliates was $1,545,769.

At June 30, 2026, 96,600,302 shares of the registrant’s Common Stock were outstanding.

TABLE OF CONTENTS

Item 1	Description of Business	1
Item 1A	Risk Factors	3
Item 1B	Unresolved Staff Comments	3
Item 1C	Cybersecurity	4
Item 2	Description of Property	4
Item 3	Legal Proceedings	7
Item 4	Mine Safety Disclosures	7
Item 5	Market for Common Equity and Related Stockholder Matters	8
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	9
Item 7A	Qualitative and Quantitative Disclosures About Market Risk	13
Item 8	Financial Statements and Supplementary Data	13
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	13
Item 9A	Controls and Procedures	13
Item 10	Directors, Executive Officers and Corporate Governance	14
Item 11	Executive Compensation	17
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	19
Item 13	Certain Relationships and Related Transactions, and Director Independence	20
Item 14	Principal Accountant Fees and Services	20
Item 15	Exhibits and Financial Statement Schedules	21

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Forward Looking Statements

This Annual Report on Form 10-K (herein, “Annual Report”) contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Annual Report regarding our strategy, future operations, financial position, estimated revenues and expenses, projected costs, prospects, plans, and objectives of management are forward-looking statements. When used in this Annual Report, the words “may,” “will,” “could,” “would,” “should,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “plan,” “pursue,” “target,” “continue,” “potential,” “guidance,” “project,” or other similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. All forward-looking statements speak only as of the date of this Annual Report. Although we believe that our plans, intentions, and expectations reflected in or suggested by the forward-looking statements we make in this Annual Report are reasonable, we can give no assurance that these plans, intentions, or expectations will be achieved. We are making investors aware that such forward-looking statements, because they relate to future events, are by their very nature subject to many important factors that could cause actual results to differ materially from those contemplated. Such factors include:

●

our significant working capital deficit and our ability to continue as a going concern;

●

declines or volatility in the prices we receive for our oil and natural gas;

●

our ability to raise additional capital;

●

our ability to generate sufficient net cash provided by operating activities, borrowings, or other sources to enable us to fully develop and produce our oil and natural gas properties;

●

general economic conditions, whether internationally, nationally, or in the regional and local market areas in which we do business;

●

risks associated with drilling, including completion risks, cost overruns, mechanical failures, and the drilling of noneconomic wells or dry holes;

●

uncertainties associated with estimates of proved oil and natural gas reserves;

●

the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;

●

the effects of inflation on our cost structure;

●

substantial declines in the estimated values of our proved oil and natural gas reserves;

●

our ability to replace our oil and natural gas reserves;

●

the potential for production decline rates and associated production costs for our wells to be greater than we forecast;

●

cost and availability of drilling rigs, and related equipment, supplies, personnel, and oilfield services;

●

the timing and extent of our success in acquiring, discovering, developing, and producing oil and natural gas reserves;

●

our dependence on the availability, use, and disposal of water in our drilling, completion, and production operations;

●

significant competition for oil and natural gas acreage and acquisitions;

●

environmental or other governmental regulations;

●

the occurrence of cybersecurity incidents, attacks or other breaches to our information technology systems or on systems and infrastructure used by the oil and gas industry;

●

our ability to find and retain highly skilled personnel and our ability to retain key members of our management team on commercially reasonable terms;

●

adverse weather conditions;

●

costs and liabilities associated with environmental, health, and safety laws;

●

social unrest, political instability, or armed conflict in major oil and natural gas producing regions outside the United States, including evolving geopolitical and military hostilities in the Middle East, Russia and Ukraine and acts of terrorism or sabotage; and

●

our insurance coverage may not adequately cover all losses that may be sustained in connection with our business activities.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date that such statements are made. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise

We use our website as a channel of distribution for Company information. We make available free of charge on the Investor Relations section of our website (https://www.royl.com/investor/) our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K. We also make available through our website other reports filed with or furnished to the Securities and Exchange Commission (“SEC”) under the Exchange Act including our proxy statements and reports filed by officers and directors under Section 16(a) of the Exchange Act, as well as our Code of Business Ethics and our Audit Charter of our board of directors. Paper copies of our filings are also available, without charge upon written request. Please email requests to ir@royl.com or call 800-447-8505. The information contained on our website is not part of this Annual Report.

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ROYALE ENERGY, INC.

PART I

Item 1 Description of Business

Royale Energy, Inc. (“Royale” or the “Company”) is an independent oil and natural gas producer incorporated under the laws of Delaware. 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. Royale was incorporated in Delaware in 2017 and is the successor by merger (as described below) to Royale Energy Funds, Inc., a California corporation formed in 1983. On December 31, 2025, Royale and its consolidated subsidiaries had 11 full-time employees.

Recent Activity

On September 3, 2025, the Company, through its wholly-owned subsidiary Royale Energy Funds, Inc, acquired certain non-operated working and net revenue interests in seven gross ( .189 net) producing horizontal wells and approximately 382.9 net acres of associated leasehold acreage within the Pradera Fuego project (the “Pradera Fuego Acquisition” or the “Pradera Fuego Acquisition Properties”) from Pradera Fuego, LP (the “Seller”) effective July 1, 2025, for total consideration of $1.5 million in cash. Prior to the Pradera Fuego Acquisition, Royale held working and revenue interests in certain wells within the Pradera Fuego project, and therefore, the acquisition increased the Company’s aggregate working and revenue interests in the project. The acquisition was financed through a combination of $1.0 million of cash on hand and an increase in its existing borrowings of additional $500,000.

Royale Business

Royale and its subsidiaries own wells, leases, and proved and non-proved reserves of oil and natural gas located mainly in Mitchell County and Ector County, Texas and in the Sacramento Basin and San Joaquin Basin in California, as well as in, Oklahoma. Royale also owns an overriding royalty interest in a non-producing well in Alaska. Royale usually sells a portion of the working interest in each well it drills or participates with third-party participants and retains a portion of the prospect for its own account. Selling part of the working interest to others allows Royale to reduce its drilling risk by owning a diversified inventory of properties with less of its own funds invested in each drilling prospect, than if Royale owned all the working interest and paid all drilling and development costs of each prospect itself. Royale generally sells working interests in its prospects to accredited investors (as defined in Regulation D of the SEC) in securities offerings exempt from registration with federal and state securities regulators. The prospects are typically bundled into multi-well investments, which permit the third-party investors to diversify their investments by investing in several wells instead of investing in single well prospects.

During its fiscal year ended December 31, 2025, Royale continued to explore and develop oil and natural gas properties with concentration in Texas. In 2025, Royale participated in the drilling of one gross (0.0035 net) wells, which was commercially productive. Royale’s estimated total proved reserves were approximately 949,727 and 304,200 BOE (barrels of oil equivalent) or 5.7 and 1.8 BCFE (billion cubic feet equivalent) at December 31, 2025 and 2024, respectively. According to the reserve reports prepared by Netherland, Sewell & Associates, Inc., Royale’s independent petroleum engineers, the net reserve value of its proved developed and undeveloped reserves was approximately $20.5 million at December 31, 2025, based on the average West Texas Intermediate price of $66.01 per barrel for oil, and the average Henry Hub natural gas spot price of $3.39 per MCF for gas as applied on a field-by-field basis. Netherland, Sewell & Associates, Inc. supplied reserve value estimates for all of the Company’s California, Texas, and Oklahoma properties.

Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

Proved developed reserves are estimated quantities of oil, natural gas and natural gas liquids (“NGL”) that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved developed producing reserves are reserves that can be expected to be recovered from existing wells and completions with existing equipment and operating methods.

Proved developed nonproducing reserves are hydrocarbons in a potentially producing horizon penetrated by a wellbore, the production of which has been postponed pending completion activities and the installation of surface equipment or gathering facilities or pending the production of hydrocarbons from another formation penetrated by the wellbore. The hydrocarbons are classified as proved developed but nonproducing reserves.

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Net reserve value does not represent the fair market value of our reserves on that date, and we cannot be sure what return we will eventually receive on its reserves. Net reserve value of proved developed and undeveloped reserves was calculated by subtracting estimated future development costs, future production costs and other operating expenses from estimated net future cash flows from our developed and undeveloped reserves.

Royale’s standardized measure of discounted future net cash flows or “PV-10” a non-GAAP measure, at December 31, 2025, of its reserves was estimated to be $11,176,100. This figure was calculated by subtracting Royale’s estimated future income tax expense from the net reserve value of proved developed and undeveloped reserves, and by further applying a 10% annual discount for estimated timing of cash flows. PV-10 is the present value of estimated future revenues, discounted at 10% annually, to be generated from the production of proved reserves determined in accordance with the SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to (i) non-property related expenses such as general and administrative expenses, debt service, and future income tax expense, and (ii) depreciation, depletion and amortization. A calculation of Royale’s standardized measure of discounted future net cash flow is contained in Note 18 to its Financial Statements, Supplemental Information about Oil and Gas Producing Activities (Unaudited)

Royale reported a gain on turnkey drilling in connection with the drilling of wells on a “turnkey contract” basis in the amount of $1,322,149 for the year ended December 31, 2025. For the year ended December 31, 2024, Royale reported a gain on turnkey drilling in the amount of $1,607,677. We cannot assure that gains of this type will occur in 2026 or if they do, they will be of similar magnitude.

In addition to Royale’s own staff, Royale hires independent contractors to drill, test, complete and equip the wells that it drills. Approximately 99% of Royale’s total revenue for the year ended December 31, 2025, came from sales of oil and natural gas from production of its wells in the amount of $1,926,442. In 2024, this amount was $2,246,073, which represented 99% of Royale’s total revenues for the respective periods presented. See Note 2 to our Financial Statements.

Plan of Business

Royale acquires interests in oil and natural gas reserves and sponsors private working interest participations. Royale believes that its stockholders are better served by diversification of its investments among individual drilling prospects. Through its private placement sale of working interest in certain oil and gas properties, Royale can acquire interests and develop oil and natural gas properties with greater diversification of risk and still receive an interest in the revenues and reserves produced from these properties. By selling some of its working interest in most projects, Royale decreases the amount of its investment required in the projects and diversifies its oil and gas property holdings, to reduce the risk of concentrating a large amount of its capital in a few projects that may not be successful.

After acquiring the leases or lease participation, Royale drills or participates in the drilling of development and exploratory oil and natural gas wells on a property. Royale pays its proportionate share of the actual cost of drilling, testing, and completing the wells to the extent that it retains all or any portion of the working interest.

Royale also sells fractional working interests in undeveloped wells to finance part of the drilling cost. A drilling contract that calls for a company to drill a well, for a fixed price, to a specified depth or geological formation is called a “turnkey contract.” When Royale sells fractional working interests in undeveloped property to raise capital to drill oil and natural gas wells, generally it agrees to drill these wells on a turnkey contract basis, so that the holders of the fractional interests prepay a fixed amount for the drilling and completion of a specified number of wells. Under a turnkey contract, Royale may record a gain if total funds received to drill a well were more than the actual cost to drill those wells including costs incurred on behalf of the participants and costs incurred for its own account.

Although Royale does not usually address whether investors have a right to participate in subsequent wells in the same area of interest as a proposed well, it is the Company’s policy to typically offer to investors in a successful well the right to participate in subsequent wells at the same percentage level as their working interest investment in the prior successful well.

Our policy for turnkey drilling agreements is to recognize a gain on turnkey drilling programs after our obligations have been fulfilled, and a gain is only recorded when funds received from participants are 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 its own account. See Note 1 to our Financial Statements, at page F-9.

Once commenced, drilling is generally completed within 10-30 days. Royale maintains internal records of the expenditure of each investor’s funds for drilling projects.

Royale generally operates the wells it completes. As operator, we receive fees set in line with industry standards from the owners of fractional interests in the wells as well as expense reimbursements. For the year ended December 31, 2025, Royale charged overhead from the operation of the wells in the amount of $441,965, which were an offset to general and administrative expenses. In 2024, such amount was $430,680. At December 31, 2025, Royale operated wells in California and Texas. Royale also has non-operating interests in wells in California, Texas, and Oklahoma.

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Royale currently sells most of its California natural gas production through Pacific Gas & Electric (“PG&E”) pipelines to independent customers on a monthly contract basis, while some gas is delivered through privately owned pipelines to independent customers. Since many users are willing to make such purchase arrangements, we believe the loss of any one customer would not affect our overall sales operations.

Oil production from the operated Jameson property, in Texas, is sold to Energy Transfer Crude Marketing LLC, less transportation on a renewable evergreen contract based on West Texas Intermediate spot prices. The natural gas is sold pursuant to a long term contract with WTG Jameson, L.P., based on Henry Hub, spot gas prices. Production from the non-operated Pradera Fuego field is sold pursuant to contracts engaged by the operator, and is generally based on posted “spot” prices for the respective products.

All oil and natural gas properties are depleting assets in which production naturally decreases over time as the finite amount of existing reserves are produced and sold. It is Royale’s business as an oil and natural gas exploration and production company to continually search for new development properties. The Company’s success will ultimately depend on its ability to continue locating and developing new oil and natural gas resources. Oil demand is subject to global demand and prices can fluctuate widely. The future market is likely to be subject to continued price dynamics. Natural gas demand and the prices paid for gas are seasonal. In recent years, natural gas demand and prices in Northern California have fluctuated unpredictably throughout the year.

Competition, Markets and Regulation

Competition

The exploration and production of oil and natural gas is an intensely competitive industry. The sale of interests in oil and gas projects, like those Royale sells, is also very competitive. Royale encounters competition from other oil and natural gas producers, as well as from other entities that invest in oil and gas for their own account or for others, and many of these companies are substantially larger than Royale.

Markets

Market factors affect the quantities of oil and natural gas production and the price Royale can obtain for the production from its oil and natural gas properties. Such factors include: the extent of domestic production; the level of imports of foreign oil and natural gas; the general level of market demand on a regional, national and worldwide basis; domestic and foreign economic conditions that determine levels of industrial production; political events in foreign oil-producing regions; and variations in governmental regulations including environmental, energy conservation, and tax laws or the imposition of new regulatory requirements upon the oil and natural gas industry.

Regulation

Federal and state laws and regulations affect, to some degree, the production, transportation, and sale of oil and natural gas from Royale’s operations. States in which Royale operates have statutory provisions regulating the production and sale of oil and natural gas, including provisions regarding deliverability. These statutes, along with the regulations interpreting them, generally are intended to prevent waste of oil and natural gas and to protect correlative rights to produce oil and natural gas by assigning allowable rates of production to each well or proration unit.

Availability of Public Filings

You may obtain a copy of any materials filed by Royale with the Securities and Exchange Commission (“SEC”) at http://www.sec.gov. Royale also provides access to its SEC reports and other public announcements on its website, http://www.royl.com. The information on our website is not part of this Annual Report on Form 10-K.

Item 1A Risk Factors

As a smaller reporting company, as defined in Rule 12b-2 of the Exchange Act, Royale is not required to provide the information required by this Item.

Item  1B Unresolved Staff Comments

None.

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Item  1C Cybersecurity

Risk Management and Strategy

The Company’s cybersecurity environment is led by our third-party information technology (IT) contractor, which, in addition to cybersecurity matters, oversees the Company’s IT infrastructure. The IT contractor is responsible for monitoring and managing the security of the Company’s corporate network and enterprise systems, including technical controls, and safety protocols and responding to security threats.

The Company maintains a cybersecurity risk management program that establishes safeguards for protecting the confidentiality, integrity, and availability of our data, technology, and information systems. The program includes general controls for managing changes in and access to the Company’s IT environment, cybersecurity awareness and training to help employees identify and mitigate against cybersecurity threats, cybersecurity incident response plans and third-party incident response retainers to help expedite the Company’s response in the event of a cybersecurity incident.

The Company’s IT contractor is primarily responsible for the day-to-day operation of the Company’s cybersecurity program and for identifying cybersecurity threats and incidents and managing the material risks associated with the cybersecurity threats. The Company’s IT contractor engages third-party vendors and cybersecurity consortiums periodically for cybersecurity-related guidance and certifications. In the event of a cybersecurity incident, the Company’s process calls for the IT contractor, our Chief Executive Officer and our Chief Financial Officer, to work to assess and respond to the incident and provide briefings to the audit committee of the board of directors.

The audit committee is responsible for providing oversight over management’s processes to identify and evaluate cybersecurity risks to which the Company is exposed and to implement processes and programs to manage cybersecurity risks and mitigate any incidents. The Audit Committee also reports material cybersecurity risks to the board of directors. We believe this risk management process provides visibility and oversight to allow the board and executive leadership team to make timely, data-driven decisions ensuring that the Company, its employees, investors, and partners are adequately protected.

As of and for the year ended December 31, 2025, there have been no cybersecurity incidents that have materially affected the Company’s business strategy, results of operations, or financial condition.

Item 2. Description of Property

Since 1993, Royale had concentrated on development of properties in the Sacramento Basin and the San Joaquin Basin of Northern and Central California. In the last few years it has moved its focus to Mitchell County and Ector County, Texas. In 2025, Royale participated in the drilling of one gross (0.0035 net) oil well in Texas which was productive.

Following industry standards, Royale generally acquires oil and natural gas acreage without warranty of title except as to claims made by, though, or under the transferor. In these cases, Royale attempts to conduct due diligence as to title before the acquisition, but it cannot assure that there will be no losses resulting from title defects or from defects in the assignment of leasehold rights. Title to property most often carries encumbrances, such as royalties, overriding royalties, carried and other similar interests, and contractual obligations, all of which are customary within the oil and natural gas industry.

Following is a discussion of Royale’s significant oil and natural gas properties. Reserves at December 31, 2025, for each property discussed below, have been determined by Netherland, Sewell & Associates, Inc., registered professional petroleum engineers, in accordance with reports submitted to Royale on March 11, 2026.

Texas

At December 31, 2025, Royale owned and operated interests in 26 oil wells in its Jameson field. Additionally, Royale owns interests in eight non-operated oil wells in the Permian Basin in Texas and three non-operated gas wells, two located in Oklahoma and one located in Texas. Our Texas estimated total producing, developed, and undeveloped reserves are approximately 919.6 thousand barrels of oil equivalent (“MBOE”), according to Royale’s independently prepared reserve report as of December 31, 2025. Barrel of oil equivalent or BOE is determined using a ratio of six Mcf of natural gas equal to one barrel of oil equivalent. The ratio does not assume price equivalency and, given price differentials, the price for a BOE for natural gas differs significantly from the price for a barrel of oil. A barrel of NGL also differs significantly in price from a barrel of oil.

California

Royale owns interests in nine gas fields with locations ranging throughout the Sacramento Basin in California. At December 31, 2025, Royale operated 10 wells and owns interests in 12 non-operated gas wells in Northern California and 8 non-operated oil wells in Southern and Central California. Our California estimated total proved, developed, and undeveloped net reserves are approximately 0.170 BCFE, according to Royale’s independently prepared reserve report as of December 31, 2025.

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Developed and Undeveloped Leasehold Acreage

As of December 31, 2025, Royale owned leasehold interests in the following developed and undeveloped properties in both gross and net acreage.

	Developed				Undeveloped
	Gross Acres		Net Acres		Gross Acres		Net Acres
Texas		23,035.00		8,632.75		9,170.00		687.75

California		2,401.02		1,784.84		3,097.25		996.80
Total		25,436.02		10,417.59		12,267.25		1,684.55

Gross and Net Productive Wells

As of December 31, 2025 and 2024, Royale owned interests in the following oil and gas wells in both gross and net:

	2025				2024
	Gross Wells		Net Wells		Gross Wells		Net Wells
Natural Gas		25		10.2366		26		10.0838
Oil		42		22.0245		40		21.1191
Total		67		32.2611		66		31.2029

Drilling Activities

The following table sets forth Royale’s drilling activities during the years ended December 31, 2025 and 2024. All wells are located in the continental U.S., in California and Texas.

				Gross Wells(b)				Net Wells(e)
Year	Type of Well(a)	Total		Producing(c)		Dry(d)		Producing(c)		Dry(d)

2025	Exploratory		0		0		0		0		0
	Developmental		1		1		0		0.0035		0

2024	Exploratory		0		0		0		0		0
	Developmental		4		4		0		0.0722		0

2023	Exploratory		0		0		0		0		0
	Developmental		4		3		1		0.3321		0.5679

An exploratory well is one that is drilled in search of new oil and natural gas reservoirs, or to test the boundary limits of a previously discovered reservoir. A developmental well is one drilled on a previously known productive area of an oil and natural gas reservoir with the objective of completing that reservoir.

Gross wells represent the number of actual wells in which Royale owns an interest. Royale’s interest in these wells may range from 1% to 100%.

A producing well is one that produces oil and/or natural gas that is being purchased on the market.

A dry well is a well that is not deemed capable of producing hydrocarbons in economic quantities.

One “net well” is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as a whole number or a fraction.

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Production

The following table summarizes, for the years indicated, Royale’s net share of oil and natural gas production, average sales price per barrel (BBL), per thousand cubic feet (MCF) of natural gas, and the MCF equivalent (MCFE) for the barrels of oil based on a 6 to 1 ratio of the price per barrel of oil to the price per MCF of natural gas. “Net” production is production that Royale owns either directly or indirectly through partnership or joint venture interests produced to its interest after deducting royalty, limited partner or other similar interests. Royale generally sells its oil and natural gas at prices then prevailing on the “spot market” and does not have any material long term contracts for the sale of natural gas at a fixed price.

	2025			2024		2023
Net volume
Oil (BBL)
California		3,597			4,779		4,768
Texas		22,366			21,777		17,615
Other		13			13		16
Total Oil		25,976			26,570		22,399

Gas (MCF)
California		54,489			58,642		72,167
Texas		60,924			56,153		53,772
Other		1,806			1,610		2,221
Total Gas		117,219			116,406		128,160

BOE		45,513			45,971		43,759

Average sales price
Oil (BBL)
California	$	65.87		$	77.84	$	78.44
Texas	$	60.87		$	71.74	$	73.14
Other	$	60.00		$	68.78	$	72.93
Gas (MCF)
California	$	2.58		$	2.80	$	5.40
Texas	$	1.75		$	1.59	$	0.93
Other	$	1.62		$	1.28	$	2.31

Net production costs and taxes
California	$	520,240		$	564,428	$	621,658
Texas	$	898,160		$	1,760,925	$	1,358,206
Other	$	(24,849	)	$	3,019	$	8,375

Lifting costs (per BOE)
California	$	41.03		$	38.78	$	37.01
Texas	$	27.62		$	56.56	$	51.10
Other	$	(79.12	)	$	10.72	$	21.69

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Reserve Estimates

Management has established, and is responsible for, internal controls designed to provide reasonable assurance that the estimates of proved reserves are computed and reported in accordance with rules and regulations promulgated by the SEC as well as established industry practices used by independent engineering firms and our peers. These internal controls include documented process workflows and qualified professional engineering and geological personnel with specific reservoir experience. Our internal processes and controls surrounding this process include collection and submission of data reconciled with reviewed accounting records for production, lease operating expense, and revenue to our independent reserve engineering firm. We also retain outside independent engineering firms to prepare estimates of our proved reserves. Management reviews and approves our reserve estimates, whether prepared internally or by third parties. Our reserve estimates as of December 31, 2025, which we refer to as the Reserve Report, were prepared based on a report by Netherland, Sewell & Associates, Inc. (“NSAI”), our independent petroleum engineering firm. The Royale’s technical person primarily responsible for overseeing the preparation of its reserve estimates is Johnny Jordan, Royale’s Chief Executive Officer, who oversaw NSAI in connection with the preparation of their estimates of our proved reserves as of December 31, 2025. We also regularly communicate with NSAI throughout the year regarding technical and operational matters critical to Royale’s reserve estimations. Our Chief Executive Officer, with input from other members of management, is responsible for the selection of our third-party engineering firms and review of the reports generated. Mr. Jordan has over 40 years of experience in the oil and natural gas industry and is a graduate of the University of Oklahoma with a degree in Chemical Engineering. During his career, he has had various relevant responsibilities in technical and leadership roles including asset management, drilling and completions, production engineering, reservoir engineering and reserves management, economic evaluations and field development in U.S. onshore projects. Within NSAI, the technical person primarily responsible for preparing the estimates set forth in the Reserve Report meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers, and is proficient in applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the Reserve Report each have over 20 years of industry experience. NSAI does not own an interest in any of our properties, nor is it employed by us on a contingent basis. The Reserve Report was also provided to Royale’s audit committee.

Net Proved Oil and Natural Gas Reserves

	2025				2024
Category	Oil (MBBL)		Natural Gas (MMCF)		Oil (MBBL)		Natural Gas (MMCF)
PROVED
Developed:
Texas		192.378		573.572		126.730		233.750
California		25.336		22.206		25.820		1.950
All other states		-		6.601		-		2.650
Undeveloped:
Texas		429.375		1,213.380		86.190		154.450
California		-		-		-		-
All other states		-		-		-
TOTAL PROVED		647.089		1,815.759		238.740		392.800
Prices used:	$	66.01	$	3.39	$	76.32	$	2.13

As of December 31, 2025, Royale had proved developed reserves of 602,379 MCF and total proved reserves of 1,815,759 MCF of natural gas. As of December 31, 2025, Royale also had proved developed oil and NGL combined reserves of 217,714 BBL and total proved oil and NGL combined reserves of 647,089 BBL.

As of December 31, 2024, Royale had proved developed reserves of 238,310 MCF and total proved reserves of 392,760 MCF of natural gas. As of December 31, 2024, Royale also had proved developed oil and NGL combined reserves of 152,550 BBL and total proved oil and NGL combined reserves of 238,740 BBL.

During 2025, our overall proved developed and undeveloped oil reserves increased by 171.1% and our previously estimated proved developed and undeveloped oil reserve quantities were revised upward by approximately 107 thousand barrels. This upward revision was mainly the result of an increase in proved undeveloped oil reserves from drilling locations which the Company had previously estimated. Our overall proved developed and undeveloped natural gas reserves increased by 362.3% and our previously estimated proved developed and undeveloped natural gas reserve quantities were revised upward by approximately 688 thousand cubic feet of natural gas. This upward revision was mainly the result of an increase in proved undeveloped natural gas reserves from drilling locations which the Company had previously estimated.

Proved Undeveloped Reserves. As of December 31, 2025, the Company’s proved undeveloped reserves totaled approximately 631,605 BOE, consisting of 429,375 barrels of oil and NGL and 1,213,380 MCF of natural gas. During 2025, the Company added 550,400 BOE of proved undeveloped reserves in its Jameson field as a result of new drilling plans in that field. In its other non-operated Texas properties, one gross ( 0.35 net) well was drilled during 2025, converting 22,400 BOE of proved undeveloped reserves into proved developed reserves, and two newly planned undeveloped wells were added to the Company’s estimates, bringing the total number of proved undeveloped well locations in those properties to six. Capital expenditures incurred during 2025 in connection with the development of the Company’s reserves are set forth in the drilling and capital cost information presented elsewhere in this Annual Report. None of the Company’s proved undeveloped reserves have remained undeveloped for five years or more following their initial disclosure as proved undeveloped reserves.

Oil and gas reserve estimates and the discounted present value estimates associated with the reserve estimates are based on numerous engineering, geological and operational assumptions that generally are derived from limited data.

Item 3 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 4 Mine Safety Disclosures

Not Applicable

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PART II

Item 5 Market for Common Equity and Related Stockholder Matters

There is no established trading market for Royale’s Common Stock, which is quoted on the OTCQB Market under the symbol “ROYL.” As of June 30, 2025, 96,600,302 shares of Common Stock were held by approximately 3,052 stockholders of record. The following table reflects the high and low quarterly bid prices as reported on the OTCQB Market from January 2024 through December 2025:

	1st Qtr				2nd Qtr				3rd Qtr				4th Qtr
	High		Low		High		Low		High		Low		High		Low
2024	$	0.07	$	0.02	$	0.07	$	0.03	$	0.08	$	0.03	$	0.07	$	0.04
2025	$	0.06	$	0.03	$	0.05	$	0.04	$	0.04	$	0.04	$	0.04	$	0.03

The OTC QB Market is not an exchange, and any over the counter quotations reflect inter-dealer prices, without retail markup, markdown or commission, and may not necessarily represent actual transactions.

Transfer Agent

The Company utilizes the independent transfer agent services of American Stock Transfer & Trust Company as its transfer agent.

Dividends

The board of directors did not declare cash dividends in either 2025 or 2024. The board of directors did declare dividends during 2024 on the preferred stock to be Paid In Kind (“PIK”) of 65,372 and 84,470 shares with a respective par value of $653,730 and $844,700, as more fully set forth in Note 5 to our Financial Statements.

Recent Sales of Unregistered Securities

During the fiscal year ended December 31, 2025, we did not issue any unregistered securities.

During the fiscal year ended December 31, 2024, we issued the following unregistered securities in transactions exempt from registration under the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) and/or Regulation D thereunder:

Shares Issued for Compensation

Royale issued 1,299,641 shares of common stock to its officers, directors, and consultants in lieu of cash compensation for services rendered. These shares were issued at prevailing market prices or pursuant to existing contractual arrangements, and no underwriters or selling agents were involved.

Shares Issued Upon Conversion of Preferred Stock

On October 11, 2024, Royale completed a significant equity restructuring in which it issued 22,198,095 shares of common stock to former holders of Series B 3.5% Convertible Preferred Stock, representing approximately 90% of the total preferred stock retired. Additionally, 2,538,378 shares were issued for conversion of accrued preferred dividends, resulting in a total of 24,736,473 shares issued related to the preferred equity conversion.

Shares Issued Upon Conversion of Debt

As part of the same, October 11, 2024 restructuring transaction, the Company also issued common stock to settle approximately $3 million in liabilities, including certain outstanding debt. The specific number of shares issued in connection with debt settlement was not separately disclosed but was included as part of the equity issued in the restructuring.

All of the above issuances were conducted without general solicitation, and the recipients were either accredited investors or had access to such information as would be required to make an informed investment decision. No underwriters or placement agents were involved, and no commissions were paid.

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Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations

Management’s Discussion and Analysis of Financial Condition and Results of Operations provides management’s analysis of the Company’s financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes, and supplemental oil and gas disclosures included elsewhere in this report. It contains forward-looking statements including, without limitation, statements relating to the Company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. Readers are cautioned that such forward-looking statements should be read in conjunction with the Company’s disclosures under the heading: “Cautionary Statement about Forward-Looking Statements” included elsewhere in this Annual Report.

Overview

Royale is an independent oil and natural gas producer. Royale’s principal lines of business are the production and sale of oil and natural gas, acquisition of oil and gas lease interests and proved reserves, drilling of both exploratory and development wells, and sales of fractional working interests in wells to be drilled by Royale. Since 1993, Royale has acquired and developed producing and non-producing natural gas properties in California. In December 2018, Royale became the operator of a newly acquired field in Texas. The most significant factors affecting the 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.

Critical Accounting Estimates

The preparation of financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. We consider an accounting estimate to be critical if it requires difficult, subjective, or complex judgments and if changes in those judgments could materially affect our financial condition or results of operations. Our most critical accounting estimates relate to (i) estimates of proved oil and natural gas reserves, (ii) asset retirement obligations, (iii) impairment of oil and natural gas properties under the successful efforts methods of accounting for oil and gas related operations. These estimates involve significant judgment because they rely on assumptions about future commodity prices, production profiles, operating and development costs, and other economic factors that are inherently uncertain.

Estimates of proved oil and natural gas reserves

Management considers the estimation of proved oil and natural gas reserve quantities to be the most critical of these estimates, because those quantities drive the rate at which the Company depletes its oil and gas properties under the unit-of-production method and are the basis on which proved properties are tested for impairment. Reserve quantities are estimates, not exact measurements, and their estimation requires the application of significant judgment. The estimates depend on a number of subjective assumptions, including projected production decline rates of producing wells, the timing and volume of production from proved undeveloped locations, the commodity prices prescribed by SEC rules (the unweighted average of the first-of-the-month prices for the prior twelve months), future development and operating costs, and judgments about whether wells are, with reasonable certainty, expected to be economically producible. These assumptions are inherently uncertain, are developed by the Company’s reservoir engineering specialist, and are revised as additional production history, well performance data, commodity prices and economic conditions become available. Accordingly, actual reserves and the timing and amount of future production may differ materially from the estimates used, and revisions can occur from period to period.

Changes in estimated proved reserves have a direct and measurable effect on the Company’s results of operations. Depreciation, depletion and amortization expense was $259,438 for the year ended December 31, 2025, compared to $308,523 for 2024; the decrease of $49,085, or 15.9%, resulted from an increase in expected recoverable reserves that lowered the unit-of-production depletion rate. Because depletion is computed by comparing capitalized cost to remaining recoverable reserves, a downward revision in estimated proved reserves would increase the depletion rate and depletion expense and could indicate that the carrying amount of a proved property is not recoverable, while an upward revision would have the opposite effect. Holding current-year production and net capitalized costs constant, a hypothetical 10% reduction in estimated proved reserves would have increased 2025 depreciation, depletion and amortization expense by approximately $17,640.

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Asset Retirement Obligations

We recognize an asset retirement obligation (“ARO”) for the estimated present value of the future costs to plug and abandon wells, remove equipment and facilities, and restore land and surface conditions. ARO estimates require significant judgment regarding the timing of retirement activities, future regulatory requirements, expected inflation rates, technological changes, and the credit-adjusted discount rate used to measure the obligation. Because these obligations typically will not be settled for many years, the ultimate costs may differ materially from our recorded estimates. Changes in estimated settlement dates, cost assumptions, or discount rates are recognized prospectively and may result in significant increases or decreases in the ARO liability and corresponding asset.

Impairment of Oil and Natural Gas Properties (Successful Efforts Method)

We evaluate our proved oil and natural gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset group may not be recoverable. Under the successful efforts method, impairment is assessed at the lowest level for which identifiable cash flows are largely independent, which is generally a field or reservoir. The recoverability test compares the carrying amount of the asset group to the estimated undiscounted future net cash flows expected to result from the use and eventual disposition of the assets.

Estimating future cash flows requires significant judgment regarding future commodity prices, production profiles, operating and development costs, reserve estimates, and the timing of development activities. These assumptions are inherently uncertain and are based on management’s expectations of future economic and operating conditions, which may differ materially from actual results.

If the carrying amount of an asset group exceeds the estimated undiscounted future net cash flows, we measure the impairment loss as the amount by which the carrying amount exceeds fair value. Fair value is typically determined using a discounted cash flow model that incorporates Level 3 inputs, including internally developed price forecasts, production estimates, cost assumptions, and a market-participant discount rate. Because our asset base is relatively small and concentrated, changes in commodity prices, reserve estimates, or operating cost assumptions may have a more pronounced impact on the recoverability of our properties than would be the case for larger, more diversified producers. Actual results may differ materially from our estimates, and such differences could result in impairment charges in future periods.

Results of Operations for the Year Ended December 31, 2025, as Compared to the Year Ended December 31, 2024

For the year ended December 31, 2025, we incurred a net loss of $1,251,680 compared to a net loss of $2,159,016 during 2024. Total revenues from operations in 2025 were $1,947,203, a decrease of $315,136 or 13.9%, from the total revenues of $2,262,339 in 2024, mainly due to lower oil prices during 2025. Total expenses for operations in 2025 were $4,183,060 a decrease of $1,605,127 or 27.7%, from total expenses of $5,788,187 in 2024, mainly due to lower lease operating expenses, lease impairments and credit loss expenses during 2025.

During the year ended December 31, 2025, revenues from oil and gas production decreased $319,631 or 14.23% to $1,926,442 from 2024 revenues of $2,246,073,mainly due to lower oil commodity prices during 2025. The net sales volume of oil and condensate for the year ended December 31, 2025 was approximately 25,976 barrels of oil with an average price of $64.23 versus approximately 26,570 barrels with an average price of $72.83 per barrel, in 2024. This represents a decrease in net sales volume of approximately 593 barrels or 2.2%, which was mainly due to some 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 year ended December 31, 2025, was approximately 117,219 Mcf with an average price of $2.20 per Mcf, versus 116,406 Mcf with an average price of $1.94 per Mcf for the year in 2024. This represents an increase in net sales volume of approximately 813 Mcf or 0.7%, primarily due to wells coming online during the period in 2025.

Oil and natural gas lease operating expenses decreased by $659,840 or 33.3%, to $1,323,333 for the year ended December 31, 2025, from $1,983,173 for the year in 2024. This decrease was mainly due to lower workover-related costs and equipment repairs on our Jameson field during 2025 as we attempted to increase production in 2024. During 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 2025, we recorded a settlement of accounts payable of $53,583 due to the write-off of accounts payable. When measuring lease operating costs on a production or lifting cost basis, in 2025, the $1,323,333 equates to a $4.85 per Mcfe or $30.61 per BOE lifting cost versus $7.19 per Mcfe or $50.70 per BOE lifting cost in 2024.

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The aggregate of Other Operating Revenue was $20,761 for the year ended December 31, 2025, an increase of $4,495 or 27.6% from $16,266 for 2024, due to higher rental income received in 2025.

Depreciation, depletion and amortization expense decreased to $259,438 from $308,523, a decrease of $49,085 or 15.9% for the year ended December 31, 2025, as compared to 2024. The depletion rate is calculated using production by comparing capitalized cost to the recoverable reserves remaining. The decrease in depreciation, depletion and amortization expense was due to an increase in expected recoverable reserves which decreased the depletion rate.

General and administrative expenses decreased by $1,637 or 0.1% from $1,633,740 for the year ended December 31, 2024, to $1,632,103 in 2025. Legal and accounting expense decreased to $446,593 in 2025, compared to $582,413 in 2024, a $135,820 or 23.3% decrease. This decrease was primarily due to higher legal fees related to our debt facility entered into during 2024, and preparation of the transaction documents related to the conversion of the Series B Convertible Preferred shares, also during 2024. Marketing expense for the year ended December 31, 2025, decreased $44,589, or 12.9%, to $302,455, compared to $347,044 for 2024. Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs.

At December 31, 2025, Royale had a Deferred Drilling Obligation of $14,277,496. During 2025, we removed $2,755,500 of drilling obligations as we participated in drilling and completion of one gross (0.0035 net) successful oil well in the Texas Permian basin, while incurring expenses of $1,433,351, resulting in a gain of $1,322,149. At December 31, 2024, Royale had a Deferred Drilling Obligation of $11,457,996. During 2024, we removed $6,562,721 of drilling obligations as we participated in drilling and completion of four gross (0.0722 net) successful oil wells in the Texas Permian basin, while incurring expenses of $4,955,044, resulting in a gain of $1,607,677.

During 2025, we recorded a $18,710 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 years ended December 31, 2025 and 2024, we recorded impairments of $27,250 and $400,719, respectively, on various lease and land costs in our California natural gas fields where the carrying value exceeded the fair value. During 2025 and 2024, we also recorded Credit Loss expenses of $137,221 and $450,743, 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. During 2024, we also recorded a gain on sale of assets of $17,500 as we received a credit for well equipment sold during a 2021 sales transaction.

Interest income for the year ended December 31, 2025 and 2024, was $66,079 and $46,528, respectively. The higher 2025 interest income was due to higher bank balances during 2025. Interest expense for the year ended December 31, 2025 and 2024, was $404,051 and $304,873, respectively. The higher 2025 interest expense was due to the $1.9 million note payable discussed in Note 15 and the notes payable related to the debt restructuring, discussed in Note 14.

In 2025 and 2024, we did not have an income tax expense due to the use of a percentage depletion carryover valuation allowance created from the current and past operations resulting in an effective tax rate less than the new federal rate of 21% plus the relevant state rates (mostly California, 8.8%).

Capital Resources and Liquidity

At December 31, 2025, Royale had current assets totaling $10,510,193 and current liabilities totaling $22,061,032, an $11,550,839 working capital deficit. We had cash and cash equivalents at December 31, 2025 of $1,099,044 and restricted cash of $7,175,950 compared to cash and cash equivalents of $1,877,163 and restricted cash of $6,025,000 at December 31, 2024.

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Ordinarily, we fund our operations and cash needs from our available credit and cash flows generated from operations. We believe there is doubt that the Company has the ability to meet liquidity demands through cash-flow from operations. In that event, the Company expects to seek alternative capital sources through additional sales of equity or debt securities, or the sale of property, which may not be available at all, or on terms we deem reasonable. We have plans to increase oil and gas revenue participation in the drilling and completion of non-operated wells in the Permian Basin in Texas.

At December 31, 2025, our other receivables net, which consists of joint interest billing receivables from direct working interest participants and industry partners, totaled $793,608, compared to $868,429 at December 31, 2024, a $74,821 decrease. This decrease was mainly due to lower accounts receivables from payment of Joint Interest Bills by direct working interest owners. At December 31, 2025, revenue receivable was $694,729, a decrease of $69,924, compared to $764,653 at December 31, 2024, due to lower uncollected production volumes and commodity prices at year end 2025 when compared to year end 2024. At December 31, 2025, our accounts payable and accrued expenses totaled $6,033,878, a decrease of $932,727 from the accounts payable at December 31, 2024 of $6,966,605, mainly due to lower trade payables and lower revenue payables to direct working interest owners at year end 2025.

We have not engaged in hedging activities nor do we use derivative instruments to manage market risks.

Operating Activities. For the years ended December 31, 2025 and 2024, cash used in operating activities totaled $2,699,820 and $2,362,855, respectively. This $366,965 difference in cash used was mainly due to a decrease in accounts payable and accrued expenses due to payments made during 2025 and lower revenue payables to direct working interest owners.

Investing Activities. Net cash provided by investing activities totaled $2,584,264 and $3,344,120 for the years ended December 31, 2025 and 2024, respectively. The $759,856 difference was due to cash receipts of approximately $5.6 million in 2025 and $8.3 million in 2024 in direct working interest turnkey investments. Also, during 2025, our turnkey drilling expenditures were approximately $2.7 million as we participated in the drilling and completion of one gross (0.0035 net) well in the Permian basin. During 2024, our turnkey drilling expenditures were approximately $5.1 million as we participated in the drilling and completion of four gross (0.0722 net) wells in the Permian basin.

Financing Activities. Net cash provided by financing activities totaled $488,387 and $1,393,377 for the years ended December 31, 2025 and 2024, respectively. The difference in cash provided was due to receipt of $500,000 during 2025 and $1.4 million received in 2024 from the note payable discussed in Note 15. During the years ended December 31, 2025 and 2024, $11,613 and $6,623, respectively, were used for principal payments on our financing lease payments.

Changes in Reserve Estimates

During 2024, our overall proved developed and undeveloped oil reserves increased by 9.6% and our previously estimated proved developed and undeveloped oil reserve quantities were revised upward by approximately 32 thousand barrels. This upward revision was mainly the result of an increase in proved undeveloped oil reserves from drilling locations which the Company had previously estimated. Our overall proved developed and undeveloped natural gas reserves decreased by 17.1% mainly due to production and our previously estimated proved developed and undeveloped natural gas reserve quantities were revised upward by approximately 4 thousand cubic feet of natural gas. This upward revision was mainly the result of an increase in proved undeveloped natural gas reserves from drilling locations which the Company had previously estimated. See Note 18 – Supplemental Information About Oil and Gas Producing Activities (Unaudited), to our Financial Statements.

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Item 7A Qualitative and Quantitative Disclosures About Market Risk

Not a required disclosure for smaller reporting companies.

Item 8 Financial Statements and Supplementary Data

See pages F-1, et seq., included herein.

Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None

Item 9A Controls and Procedures

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined under Rules 13a-15(e) or 15d-15(e) under the Exchange Act. Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were not effective as of the end of the period covered by this annual report, as a result of a material weakness in our internal control over financial reporting discussed below.

Management’s Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over our financial reporting. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act, management has conducted an assessment, including testing, using the criteria in the 2013 Internal Control-Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Our system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Based on our evaluation under the framework in Internal Control-Integrated Framework, our Chief Executive Officer and Chief Financial Officer concluded that our internal control over financial reporting was not effective as of December 31, 2025, due to a material weakness described below.

Material Weakness and Remediation

Management identified a material weakness that existed because we lack sufficient financial reporting personnel, proper review controls and proper segregation of duties, including within our financial reporting systems, to produce accurate and complete financial records in accordance with SEC and US GAAP requirements. The material weakness continues to exist as of December 31, 2025. Management is in the process of developing a remediation plan designed to improve its internal control over financial reporting and address the identified material weakness. Management will not be able to conclude that it has remediated the material weakness until controls are implemented, operate for a sufficient period of time, and management is able to conclude, through formal testing, that the controls are operating effectively.

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PART III

Item 10 Directors, Executive Officers and Corporate Governance

All of our directors serve one-year terms from the time of their election to the time their successor is elected and qualified. The following information is furnished with respect to each director and executive officer who served as such during the fiscal year ended December 31, 2025:

Name	Age	First Became Director or Executive Officer	Positions Held
Chris Parada ^{(1) (2)(3)(4)}	55	2021	Chairman of the Board
Jonathan Gregory ⁽²⁾⁽³⁾	62	2014	Vice-Chair of the Board of Directors
Johnny Jordan	66	2018	Chief Executive and Operating officer and Director
Ronald Lipnick	66	2021	Chief Financial Officer
John Sullivan ^(1)(2)(3)(4)	68	2021	Director
Jeff Kerns ^{(1) (2)(3)(4)}	69	2021	Director
Stephen Hosmer	59	1995	Director

(1)	Members of the audit committee
(2)	Members of the compensation committee
(3)	Members of the nominations committee
(4)	Members indentified as independent

The board has determined that directors John Sullivan, Chris Parada, and Jeff Kerns qualify as independent directors.

The following summarizes the business experience of each director and executive officer for the past six years.

Chris Parada – Chairman of the Board

Mr. Parada currently serves as Managing Director – Energy Finance for Cornerstone Capital Bank, a position he has held since January 2023. With over 30 years of experience in energy finance, Mr. Parada specializes in providing debt capital and structured solutions to private exploration and production (E&P) and midstream oil and gas companies throughout the United States. From April 2021 through December 2022, Mr. Parada was an energy banker, with the title of Vice President of Business Development for Finergy Capital/EnRes Resources, an alternative investment fund providing structured capital solutions to upstream oil and gas companies. From 2013-2019 he served as Managing Director - Head of Energy Finance at LegacyTexas Bank, where his team executed over $1.5 billion of transactions. Mr. Parada has over 25 years of experience in oil and gas banking and finance. Mr. Parada holds a Bachelor of Business Administration in Finance from Texas A&M University.

Jonathan Gregory – Vice-Chair of the board of directors

Mr. Gregory became a director of Royale in March 2014 and served as Royale’s chief executive officer from September 10, 2015, until June 1, 2018. Prior to becoming Royale’s CEO, Mr. Gregory, from March 2014 to July 2015, served as Chief Financial Officer and Chief Business Development Strategist for Americo Energy Resources, a private exploration and production company located in Houston, Texas. Prior to serving as CFO of Americo Energy, Mr. Gregory was CFO of J&S Oil & Gas, LLC, from April 2012 to February 2014. From December 2004 to April 2012, Mr. Gregory was head of the energy lending group in Houston, Texas for Texas Capital Bank, N.A. Mr. Gregory is presently CEO of RMX, a private Texas based oil and gas company with oil and gas properties primarily located in California, in which, Royale holds an equity interest. Mr. Gregory is also a Credit Advisor to Anvil Capital Partners, a private debt capital provider to upstream energy companies and serves on the advisory board of the Center for Compassionate Leadership. Mr. Gregory graduated from Lamar University in 1986 with a Bachelor’s degree in Finance.

John Sullivan – Director

Mr. Sullivan first became a director and began serving as the Chairman of the board in 2021. Mr. Sullivan is the President of LTD Consulting Services LLC, which provides consulting and management services to private and public companies in the US and SE Asia, a position he has held since 2017. Previously, he held the position of Sr. Director at MMI International, a privately held, global supplier to the Data Storage, Aerospace and Oil and Gas industries from 2011-2017. In this role, he oversaw the sales and global operations for the Precision Forming Group, a division of MMI, with $250 million in annual sales.

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Prior to this, as Director of Operations, COO and President, he spent eleven years, from 1999 until 2011, with Intri-Plex Technologies Inc., a leading design, engineering and manufacturing company to the Data Storage, Semi-conductor and Medical industries. In his various roles, he led the development and implementation of strategic sales and operating initiatives that resulted in significant top and bottom line growth. Overseeing the expansion of the business from a domestic manufacturing company to an international supplier of precision components with manufacturing facilities located in the US and SE Asia.

Previously, he served as COO and President of KR Precision Public Co. Ltd., a publicly held, global supplier of precision mechanical components, John was instrumental in transforming a small privately held company from a niche supplier to a publicly held industry leader listed on the SET 50.

John began his career in 1980 as an entrepreneur, spending ten years as a small business owner in the security and life safety industry. He grew his company organically and through acquisition, diversified its offerings and expanded its geographic footprint prior to it being acquired by ADT International in, a global leader in security and life safety industry, in 1990.

Johnny Jordan – Chief Executive Officer, President, Chief Operating Officer and Director

Mr. Jordan is a petroleum engineer with expertise in acquisitions, field economics and reserves analysis, bank negotiations, reservoir and field operations, and multi-team interaction. Mr. Jordan has been Royale Energy’s Chief Executive Officer since 2019. Mr. Jordan served on the board of directors of Matrix Oil Corporation (“Matrix”) and currently serves on the board of directors of both RMX Resources and CIPA. Mr. Jordan has been active in the oil and gas industry since 1980 beginning as a floor hand on a well service rig. He has held various staff and supervisory positions for Exxon, Mack Energy, Enron Oil and Gas and Venoco Corporation. He co-founded Matrix in 1999 and served as its president until its merger with Royale in 2018. Mr. Jordan is a member of the Society of Petroleum Engineers, American Petroleum Institute and the Texas Independent Producers and Royalty Owners Association. Mr. Jordan has managed acquisition evaluations in many of the oil and gas producing basins in the US. Mr. Jordan received a B.S. in Chemical Engineering from the University of Oklahoma in 1983.

Jeff Kerns – Director

Mr. Kerns was a founding partner of Matrix in 1999, which merged with Royale Energy, Inc. nearly 20 years later in 2018. As a director and officer of Matrix, Mr. Kerns participated in growing Matrix from zero production to owning and operating nearly 500 bbls of oil per day. Mr. Kerns was involved in all aspects of Matrix’s growth, but his primary focus was day to day operations.

Mr. Kerns has served as a consulting engineer to Royale Energy and Matrix from 2018 to present.

Mr. Kerns started in the oil and gas business over 40 years ago as a roughneck in North Dakota working on rigs that drilled through the now famous Bakken Shale heading for deeper targets. Prior to Matrix, Mr. Kerns has held various staff and supervisory positions with Mobil Oil Corp (now ExxonMobil) and Venoco Inc, a small independent company headquartered in Santa Barbara, CA. He also gained broad skills working for many years as a consultant in the oil and gas business.

Mr. Kerns is a registered Professional Engineer in the state of CA. He received a BS degree from Stanford University in 1979. He served as an elected public official for 10 years on the local sanitary district board of directors as well as serving as a past president of a local Rotary International club and president of the San Joaquin Chapter of the American Petroleum Institute and has maintained a long term affiliation with SPE.

Stephen Hosmer – Director, Corporate Secretary

Mr. Hosmer first became a director in 1998, and served through 2018. He was then reappointed in January 2022, following his departure as the Company’s Chief Financial Officer, where he served since 1995. Mr. Hosmer also served as the Company’s Co-Chief Executive Officer from 2008 until September 2015.

During his tenure as CFO, Mr. Hosmer managed the development of over 178 wells, raised capital through a combination of debt and equity sources, and led the acquisition of more than 200 square miles of 3D seismic data. Mr. Hosmer holds a Bachelor of Science degree in Business Administration from Oral Roberts University in Tulsa, Oklahoma and an MBA degree from the President/Key Executive program at Pepperdine University.

Mr. Hosmer currently serves as the CFO for Owners in Honor, Managing Partner of Provident Ventures, and has also served on the board and/or consults for a number of not-for-profit organizations, including Venture Expeditions and Exile International, and Wycliffe Bible Translators.

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Ronald Lipnick – Chief Financial Officer

Mr. Lipnick has been with the Company since May 1993 and has been the Chief Financial Officer since February 2022. Prior to that he had been the Controller since February 1994. He is responsible for the Company’s accounting operations from daily accounting activities and general ledger reconciliation to the preparation of financial statements for the Company’s SEC filings. He also works closely with Royale’s certified public accountants during their yearly audits. Mr. Lipnick has more than 37 years of experience in the accounting field. He has a Bachelor of Science in Accounting and a Master of Business Administration in Finance from Oral Roberts University, Tulsa, Oklahoma.

Audit Committee

The board has appointed an audit committee to assist the board of directors in carrying out its responsibility as to the independence and competence of the Company’s independent public accountants. All members of the audit committee are independent members of the board of directors. The audit committee operates pursuant to an audit committee charter, which has been adopted by the board of directors to define the committee’s responsibilities. A copy of the audit committee charter is posted on our website, www.royl.com. The board has determined that Chris Parada qualifies as an “audit committee financial expert” as defined in Item 407(d)(5) of Regulation S-K.

At the end of 2025, the members of the audit committee were John Sullivan (Chair), Jeff Kerns, Chris Parada and Jonathan Gregory.

In 2025 there were four meetings of the audit committee, at which all members participated.

Compensation Committee

Although the Company is not required to maintain a compensation committee, the board has nonetheless appointed a compensation committee to assist the board of directors with respect to executive recruitment, selection, evaluation and compensation. This committee reviews and advises the board of directors on matters involving the personnel/human resource policies, its compensation program, and corporate strategy in compliance with public policy personnel/employment regulations in a changing environment. The compensation committee operates pursuant to a charter, which has been adopted by the board of directors to define the committee’s responsibilities. The compensation committee charter provides that the committee consist of at least two (2) independent directors. A copy of the compensation committee charter is posted on our website, www.royl.com.

At the end of 2025, the members of the compensation committee were Jeff Kerns, John Sullivan, Chris Parada, Jonathan Gregory.

In 2025, there was 1 meeting of the compensation committee, at which all members participated.

Nominating Committee

Although the Company is not required to maintain a nominating committee, the board has nonetheless appointed a nominating committee to assist the board of directors in identifying qualified individuals to become board members, receive and review recommendations by shareholders for board nominations, and determine whether existing board members should be nominated for re-election. The nominating committee operates pursuant to a charter, which has been adopted by the board of directors to define the committee’s responsibilities. The nominating committee charter provides that the committee consist of at least two independent directors. A copy of the nominating committee charter is posted on our website, www.royl.com.

At the end of 2025, the members of the nominating committee were Chris Parada, John Sullivan (Chair), and Jeff Kerns, each of whom is an independent director.

In 2025, there was 1 meeting of the nominating committee, at which all members participated.

Code of Business Conduct and Ethics

We have adopted a code of business conduct and ethics for our directors and executive officers. The code is posted on our website, www.royl.com.

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Delinquent Section 16(a) Reports

Section 16(a) of the Exchange Act and Securities and Exchange Commission regulations require that Royale’s directors, certain officers, and greater than 10 percent shareholders file reports of ownership and changes in ownership with the SEC and furnish Royale with copies of all such reports they file. The following Form 4’s for common stock issued to current and former board members were filed late, each of these filings consisted of two transactions that occurred in 2024:

Form 4 2024 Common Stock Issuance - Late Filings:

Recipient	Shares issued 2024		Form 4 Filing Status
Johnny Jordan		10,498,464	In Process
Jeffrey Kerns		9,836,649	In Process

Item 11 Executive Compensation

The following table summarizes the compensation of the chief executive officer, chief financial officer and the one other most highly compensated non-executive employee of Royale and its subsidiaries during the past two years.

SUMMARY COMPENSATION TABLE

	Year	Salary (3)		Bonus		Option Awards		All Other Compensation (1)		Total
Johnny Jordan (2)(3)(4)	2025	$	255,769	$	-	$	-	$	7,673	$	263,442
(CEO)	2024	$	255,769	$	-	$	-	$	10,018	$	265,787

Donald Hosmer	2025	$	185,175	$	42,500	$	-	$	27,930	$	255,605
(Business Development)	2024	$	185,175	$	81,080	$	-	$	27,930	$	294,185

Ronald Lipnick	2025	$	184,154	$	-	$	-	$	5,525	$	189,679
(CFO)	2024	$	184,154	$	-	$	-	$	5,525	$	189,679

(1)

All other compensation consists of matching contributions to the Company’s simple IRA plan, except for Donald H. Hosmer, who also received a $12,000 car allowance.

(2)

Salary represents either direct payroll or common stock paid in lieu of taking a cash salary.

(3)

Mr. Jordan became CEO of the Company in January 2019. Mr. Jordan joined the Company as an officer on March 7, 2018.

(4)

There was no compensation paid to Mr. Johnny Jordan for performance (Pay Versus Performance).

In 2025, Johnny Jordan received a salary of $255,769. He did not receive any bonus or option awards. His additional compensation amounted to $7,673, resulting in a total compensation of $263,442. In 2024, Johnny Jordan received a salary of $255,769. He did not receive any bonus or option awards. His additional compensation amounted to $10,018, resulting in a total compensation of $265,787.

For 2025, Donald Hosmer’s salary was $185,175. He received a bonus of $42,500 but no option awards. His additional compensation was $27,930, resulting in a total compensation of $255,605. In 2024, Donald Hosmer’s salary was $185,175. He received a bonus of $81,080 but no option awards. His additional compensation was $27,930, resulting in a total compensation of $294,185.

Ronald Lipnick’s 2025 salary was $184,154. He received no option awards. His additional compensation was $5,525, resulting in a total compensation of $189,679. In 2024, his salary was $184,154. He received no option awards. His additional compensation was $5,525, resulting in a total compensation of $189,679.

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Stock Options and Equity Compensation; Outstanding Equity Awards at Fiscal Year End

No unvested stock awards were outstanding at the end of 2025.

Compensation Committee Report

Our compensation committee has reviewed and discussed the following Compensation Discussion and Analysis with management and, based on its discussion and review, has recommended that the Compensation Discussion and Analysis be included in this annual report.

Members of the compensation committee:

Chris Parada, John Sullivan (Chair), and Jeff Kerns

All members of the compensation committee are independent members of the board of directors.

Compensation Discussion and Analysis

Our executive compensation policy is designed to motivate, reward and retain the key executive talent necessary to achieve our business objectives and contribute to our long-term success. Our compensation policy for our executive officers focuses primarily on determining appropriate salary levels and performance-based cash bonuses.

The elements of executive compensation at Royale consist mainly of cash salary and, if appropriate, a cash bonus at yearend. The compensation committee makes recommendations to the board of directors annually on the compensation of the three top executives: Johnny Jordan, Chief Executive Officer, Donald H. Hosmer, Business Development, and Ronald Lipnick, Chief Financial Officer.

Royale also does not provide extensive personal benefits to its executives beyond those benefits, such as health insurance, that are provided to all employees. Donald Hosmer receives an annual car allowance.

Policy

The compensation committee’s primary responsibility is making recommendations to the board of directors relating to compensation of our officers. The committee also makes recommendations to the board of directors regarding employee benefits, our defined benefit plans, defined contribution plans, and stock-based plans.

Determination

To determine executive compensation, the committee, from time-to-time, meets with our officers to review our compensation programs, discuss the performance of the Company, the duties and responsibilities of each of the officers pay levels and business results compared to others similarly situated within the industry. The committee then makes recommendations to the board of directors for any adjustment to the officers’ compensation levels. The committee does not employ compensation consultants to make recommendations on executive compensation.

Compensation Elements

Base. Base salaries for our executive officers are established based on the scope of their responsibilities, taking into account competitive market compensation paid by our peers. Base salaries are reviewed annually. The salaries we paid to our most highly paid executive officers and next most highly compensated non-executive officer for the last three years are set forth in the Summary Compensation Table included under Executive Compensation.

Bonus. The compensation committee meets annually to determine the quantity, if any, of the cash bonuses of executive officers. The amount granted is based, subjectively, upon the Company’s stock price performance, earnings, revenue, reserves and production. The committee does not use quantifiable metrics for these criteria; but rather uses each in balance to assess the strength of the Company’s performance. The committee believes that formulaic approaches to cash incentives can foster an unhealthy balance between short-term and long-term goals. No cash bonuses were paid to executive officers in 2025 or 2024, other than those listed for Donald Hosmer in the table above.

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Compensation of Directors

In 2025, board members or committee member accrued or received fees for attendance at board meetings or committee meetings during the year. In addition to cash payments, Common Stock was issued in lieu of compensation or reimbursements. Royale also reimbursed directors for the expenses incurred for their services.

The following table describes the compensation paid to our directors who are not also named executives for their services in 2025.

Name	Fees paid in Cash or Common Stock		Stock awards		Option awards		All Other Compensation		Total
John Sullivan	$	36,000	$	-	$	-	$	-	$	36,000
Chris Parada	$	36,000	$	-	$	-	$	-	$	36,000
Jeff Kerns	$	24,000	$	-	$	-	$	-	$	24,000
Stephen Hosmer	$	36,000	$	-	$	-	$	-	$	36,000
Jonathan Gregory	$	24,000	$	-	$	-	$	-	$	24,000

Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Common Stock

At March 31, 2026, 96,600,302 shares of Royale’s common stock were outstanding.

The following table contains information regarding the ownership of Royale’s common stock as March 19, 2025, by each director and executive officer of Royale, and all directors and officers of Royale as a group and persons owning greater than 5% of the issued

and outstanding shares of common stock.

Except pursuant to applicable community property laws and except as otherwise indicated, each shareholder identified in the table below possesses sole voting and investment power with respect to her or his shares. The holdings reported are based on reports filed with the Securities and Exchange Commission and the Company by the officers and directors.

Stockholder (1)	Number		Percent
Johnny Jordan		28,162,723		29.15	%
Jeff Kerns		20,225,636		20.94	%
Stephen M. Hosmer (2)		2,820,782		2.92	%
John Sullivan		2,732,865		2.83	%
Jonathan Gregory (3)		2,257,865		2.34	%
Chris Parada		1,756,465		1.82	%
All officers and directors as a group		57,956,336		60.00	%

(1)	The mailing address of each listed stockholder is 1530 Hilton Head Rd, Suite 205, El Cajon, California 92021.

(2)	Includes 6,000 shares owned by Stephen M. Hosmer’s minor children.

(3)	Includes 35,000 shares owned by Mr. Gregory’s son.

Other than Messrs. Jordan and Kerns, as disclosed above, there is no shareholder known by Royale to own beneficially more than 5% of our common stock.

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Our Chief Executive Officer, Johnny Jordan, had accrued certain unpaid salary, at December 31, 2024, Mr. Jordan was owed $46,926, in accrued unpaid guaranteed payments. These amounts were discharged in the restructuring transaction described in Note 14.

In 2018 the board of directors terminated the policy allowing employees and directors to participate, at cost, in wells drilled by the Company. Under the prior policy our former Chief Financial Officer and current board of director’s secretary, Stephen Hosmer, had participated individually in 179 wells. At December 31, 2025, the Company had a receivable balance of $22,266 due from Stephen Hosmer and $13,149 from Donald Hosmer for normal lease operating expenses.

At December 31, 2025, we had a total payable of $23,087 due to RMX and its subsidiary, Matrix, related to certain lease operating expenses for wells operated by RMX, and also had prepaid expenses of $710,590 primarily for future plugging and abandonment costs for wells operated by RMX. At December 31, 2025, we had a total payable of $146,596 owed to current and former board members for directors fees.

Royale had outstanding accrued unpaid guaranteed payments for unpaid salaries for employees for periods predating their joining the Company due to a former Matrix employee. At December 31, 2025, the balance due was $90,000. At December 31, 2025, Royale also had accrued unpaid liabilities of $12,386 due to a former Matrix employees for periods predating their joining the Company.

Item 14. Principal Accountant Fees and Services

HORNE LLP (“HORNE”) was the Company’s independent registered public accounting firm for the year ended December 31, 2024. Effective as of November 1, 2025, the partners and professional staff of HORNE joined BDO USA, P.C. (“BDO”). As a result of this transaction, HORNE resigned as the Company’s independent registered public accounting firm effective as of November 1, 2025 and the Company, through and with the approval of the Audit Committee, appointed BDO as its independent registered public accounting firm. The following table sets forth the aggregate fees incurred by HORNE for the fiscal year ended December 31, 2024 and by HORNE and BDO for the fiscal year ended December 31, 2025.

	2025		2024
Audit fees (1)	$	280,000	$	250,000
Tax fees (2)		-		-
All other fees (3)		-		6,500
Total	$	280,000	$	256,500

(1)	Audit fees are fees for professional services rendered for the audit of Royale Energy’s annual financial statements, reviews of financial statements included in the Company’s Forms 10-Q, audit and review of financial statements of an acquired asset, and reviews of documents filed with the U.S. Securities and Exchange Commission.

(2)	Tax fees consist of tax planning, consulting and tax return reviews.

(3)	Additional fees related to debt and equity restructuring transaction.

The Company’s audit committee has adopted policies for the pre-approval of all audit and non-audit services provided by the Company’s independent auditor. The policy requires pre-approval by the audit committee of specifically defined audit and non-audit services. Unless the specific service has been previously pre-approved with respect to that year, the audit committee must approve the permitted service before the independent auditor is engaged to perform it. During 2025 and 2024 all such audit services and their fees were pre-approved by the audit committee.

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PART IV

Item 15 Exhibits and Financial Statement Schedules

The agreements included as exhibits to this report are included to provide information about their terms and not to provide any other factual or disclosure information about Royale or the other parties to the agreements. The agreements contain representations and warranties by each of the parties to the applicable agreement that were made solely for the benefit of the other parties to the respective agreement, and:

	●	should not be treated as categorical statements of fact, but rather as a way of allocating the risk among the parties if those statements prove to be inaccurate;

	●	have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;

	●	may apply standards of materiality in a way that is different from the way investors may view materiality; and

	●	were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.

1. Financial Statements. See Index to Financial Statements, page F-1

2. Schedules. None.

3. Exhibits. Certain of the exhibits listed in the following index are incorporated by reference.

3.1*		Certificate of Incorporation of Royale Energy, Inc. (formerly Royale Energy Holdings, Inc.) filed with the Secretary of State of Delaware on November 22, 2016 (Incorporated by reference to Exhibit 3.1 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2024, filed with the Securities and Exchange Commission on April 9, 2025).
3.2		Amendment to the Certificate of Incorporation of Royale Energy, Inc., a Delaware corporation, dated February 28th, 2018 (Incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on March 12, 2018.)
3.3*		Bylaws of Royale Energy, Inc. Bylaws of Royale Energy, Inc. (Incorporated by reference to Exhibit 3.3 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2024, filed with the Securities and Exchange Commission on April 9, 2025).
4.1		Royale Energy Holdings, Inc., Certificate of Designation of Series B 3.5% Redeemable Convertible Preferred Stock, filed with the Delaware Secretary of State on February 27, 2018, filed as Exhibit 2.5 to the Company’s Form 8-A, filed March 8, 2018
10.17†		Royale Energy, Inc., 2018 Equity Incentive Plan, filed as Exhibit 99.1 to the Company’s Form S-8 filed October 29, 2018
10.27†		Incentive Stock Option Agreement between the Company and Stephen M. Hosmer, filed as Exhibit 10.11 to the Company’s Form S-8 filed October 29, 2018
10.28		Secured Term Loan Note dated February 9, 2024, filed as Exhibit 10.1 to the Company’s form 8-K filed on February 15, 2024
10.29		Amendment to Secured Term Loan Note dated November 1, 2024 (Incorporated by reference to Exhibit 10.1 to the Company’s Report on Form 10-Q filed with the Securities and Exchange Commission on November 14, 2024.)
10.30		Exchange Agreement, filed as Exhibit 10.1 to the Company’s Form 8-K filed on October 17, 2024
10.31		Form of Series 2024 Senior Promissory Note, filed as Exhibit 10.2 to the Company’s Form 8-K filed on October 17, 2024
10.32		Stock Option Agreement, filed as Exhibit 10.3 to the Company’s Form 8-K filed on October 17, 2024
10.33		Release Agreement, filed as Exhibit 10.4 to the Company’s Form 8-K filed on October 17, 2024
21.1*		Subsidiaries of Registrant
23.1*		Consent of BDO USA, P.C.
23.3*		Consent of Netherland, Sewell & Associates, Inc.
31.1*		Rule 13a-14(a), 115d-14(a) Certification
31.2*		Rule 13a-14(a), 115d-14(a) Certification
32.1*		Section 1350 Certification
32.2*		Section 1350 Certification
99.1*		Report of Netherland, Sewell & Associates, Inc.
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)

*	Filed herewith.

†	Management contract or compensatory plan or arrangement.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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: July 10, 2026	/s/ Johnny Jordan
	Johnny Jordan
	Chief Executive Officer

Date: July 10, 2026	/s/ Ronald Lipnick
	Ronald Lipnick
	Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Date: July 10, 2026	/s/ John Sullivan
	John Sullivan
	Chairman of the board of directors

Date: July 10, 2026	/s/ Jonathan Gregory
	Jonathan Gregory
	Vice-Chair of the board of directors

Date: July 10, 2026	/s/ Chris Parada
	Chris Parada
	Director

Date: July 10, 2026	/s/ Jeff Kerns
	Jeff Kerns
	Director

Date: July 10, 2026	/s/ Stephen Hosmer
	Stephen Hosmer
	Director

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ROYALE ENERGY, INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM (BDO USA, P.C.(formerly HORNE, LLP); Houston, Texas; PCAOB ID #243)		F-2

CONSOLIDATED BALANCE SHEETS		F-4

CONSOLIDATED STATEMENTS OF OPERATIONS		F-6

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ DEFICIT		F-7

CONSOLIDATED STATEMENTS OF CASH FLOWS		F-8

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS		F-9

F-1

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Report of Independent Registered Public Accounting Firm

Shareholders and Board of Directors

Royale Energy, Inc.

El Cajon, California

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Royale Energy, Inc. (the “Company”) as of December 31, 2025 and 2024, the related consolidated statements operations, stockholders’ deficit, and cash flows for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2025 and 2024, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

Going Concern Uncertainty

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company has suffered recurring losses from operations and has a working capital deficiency that raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

F-2

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Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Estimation of Quantities of Future Production Volumes Used to Estimate Proved Oil and Gas Reserves and the Associated Effect on Depreciation, Depletion and Amortization (“DD&A”) Expense Related to Proved Oil and Gas Properties

As disclosed by management and described in Notes 1 and 2 to the consolidated financial statements, the Company uses the successful efforts method of accounting for its oil and gas producing activities. Management uses internal and independent petroleum engineers to make significant estimates, including estimating quantities of proved oil and gas reserves. The Company’s oil and gas properties, net as of December 31, 2025 was $5.7 million, which includes proved oil and gas properties of $10.5 million and accumulated depletion, depreciation, and amortization (“DD&A”) of $8.0 million. DD&A expense was $0.3 million for the year ended December 31, 2025.

We have identified the estimation of future production volumes used to estimate proved oil and gas reserves and the associated effect on DD&A expense related to proved oil and gas properties as a critical audit matter. Estimating future production volumes involves a high degree of subjectivity from management and their internal and independent petroleum engineers. Auditing the estimation of future production volumes required subjective and complex auditor judgement.

The primary procedures we performed to address this critical audit matter included:

	●	Evaluating the professional qualifications and objectivity of the internal and independent petroleum engineers, including their relationship to the Company.

	●	Assessing the reasonableness of the future production volumes by comparing estimates of future production volumes against historical results of production volumes on a summary basis for all wells and on a detailed basis for a sample of wells.

●

Performing a retrospective review over management estimates of future production volumes made in the prior period as compared to actual results.

/s/ BDO USA, P.C.

(formerly HORNE LLP)

We have served as the Company’s auditor since 2023.

Houston, Texas

July 10, 2026

F-3

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ROYALE ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

DECEMBER 31,

	2025		2024
ASSETS
Current Assets:
Cash and Cash Equivalents	$	1,099,044	$	1,877,163
Restricted Cash		7,175,950		6,025,000
Other Receivables, net		793,608		868,429
Revenue Receivables		694,729		764,653
Prepaid Expenses and Other Current Assets		746,862		619,913
Total Current Assets		10,510,193		10,155,158

Other Assets		576,265		589,865
Right of Use Asset - Leases		141,417		238,509
Oil and Gas Properties (Successful Efforts Basis), Real Property and Equipment and Fixtures, net		5,774,178		4,656,659
Total Assets	$	17,002,053	$	15,640,191

The accompanying notes are an integral part of these consolidated financial statements.

F-4

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ROYALE ENERGY, INC.

CONSOLIDATED BALANCE SHEETS (Continued)

DECEMBER 31,

	2025			2024
LIABILITIES AND STOCKHOLDERS’ DEFICIT
Current Liabilities:
Accounts Payable and Accrued Expenses	$	6,033,878		$	6,776,825
Royalties Payable		611,833			611,833
RMX Resources, LLC		23,087			23,087
Leases - Current		102,238			94,070
Asset Retirement Obligation - Current		1,012,500			1,012,500
Deferred Drilling Obligations		14,277,496			11,457,996

Total Current Liabilities		22,061,032			19,976,311

Noncurrent Liabilities:
Asset Retirement Obligation		4,065,352			4,066,095
Notes Payable		4,121,112			3,489,290
Leases - Non-current		43,386			145,644
Accrued Unpaid Guaranteed Payments		90,000			90,000
Accrued Liabilities - Non-current		12,386			12,386

Total Liabilities		30,393,268			27,779,726
Commitments and Contingencies (See Note 13)
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 December 31, 2025 and 2024, respectively		96,600			96,600

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

Accumulated Deficit		(94,566,369	)		(93,314,689	)

Total Stockholder’s Deficit		(13,391,215	)		(12,139,535	)

Total Liabilities, Stockholders’ Deficit	$	17,002,053		$	15,640,191

The accompanying notes are an integral part of these consolidated financial statements.

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ROYALE ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2025 AND 2024

	2025			2024
Revenues:
Oil, NGL and Gas Sales	$	1,926,442		$	2,246,073
Other Operating Revenue		20,761			16,266
Total Revenues		1,947,203			2,262,339

Costs and Expenses:
Oil and Gas Lease Operating		1,323,333			1,983,173
Severance Taxes		73,377			81,832
Impairment		27,250			400,719
Depreciation, Depletion, Amortization, and Accretion		259,438			308,523
Settlement of Asset Retirement Obligation		(18,710	)		-
General and Administrative		1,632,103			1,633,740
Credit Loss Expense		137,221			450,743
Legal and Accounting		446,593			582,413
Marketing		302,455			347,044
Total Costs and Expenses		4,183,060			5,788,187

Gain on Turnkey Drilling Programs		1,322,149			1,607,677

Loss from Operations		(913,708	)		(1,918,171	)

Other Income (Expense):
Interest Expense		(404,051	)		(304,873	)
Interest Income		66,079			46,528
Gain on Sale of Assets		-			17,500
Total Other Expense (net)		(337,972	)		(240,845	)
Net Loss		(1,251,680	)		(2,159,016	)

Basic and Diluted Loss Per Share	$	(0.01	)	$	(0.03	)

Weighted average number of common shares outstanding, basic and diluted		96,600,302			77,278,047

The accompanying notes are an integral part of these consolidated financial statements.

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ROYALE ENERGY, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ DEFICIT

FOR THE YEARS ENDED DECEMBER 31, 2025 AND 2024

	Common Stock
	Number Shares Issued and Outstanding		Amount		Additional Paid in Capital		Accumulated Deficit			Total Stockholders’ Deficit
Balance, December 31, 2023		70,564,188	$	70,564	$	54,619,236	$	(90,133,509	)	$	(35,443,709	)
Stock issued in lieu of Cash Compensation		1,299,641		1,299		34,700		-			35,999
Preferred Series B 3.5% Dividend		-		-		-		(653,730	)		(653,730	)
Preferred Series B Retirement & Conversion to Common		24,736,473		24,737		25,096,547		-			25,121,284
Equity and Debt Restructuring		-		-		1,328,071		(368,434	)		959,637
Net Loss		-		-		-		(2,159,016	)		(2,159,016	)
Balance, December 31, 2024		96,600,302		96,600		81,078,554		(93,314,689	)		(12,139,535	)
Net Loss		-		-		-		(1,251,680	)		(1,251,680	)
Balance, December 31, 2025		96,600,302	$	96,600	$	81,078,554	$	(94,566,369	)	$	(13,391,215	)

The accompanying notes are an integral part of these consolidated financial statements.

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ROYALE ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2025 AND 2024

	2025			2024
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Loss	$	(1,251,680	)	$	(2,159,016	)
Adjustments to Reconcile Net Loss to Net Cash Used by Operating Activities:
Depreciation, Depletion, and Amortization		259,438			308,523
Impairment		27,250			400,719
Gain on Sale of Assets		-			(17,500	)
Gain on Turnkey Drilling Programs		(1,322,149	)		(1,607,677	)
Credit Loss Expense		137,221			450,743
Settlement on Asset Retirement Obligation		(78,839	)		(151,856	)
Stock-Based Compensation		-			35,999
Accretion of Debt Restructure Note Payable Interest		131,822			31,514
Right of Use Asset Depreciation		14,615			7,167
(Increase) Decrease in:
Other & Revenue Receivables		69,924			(169,046	)
Prepaid Expenses and Other Assets		(62,400	)		(44,244	)
Increase (Decrease) in:
Accounts Payable and Accrued Expenses		(625,022	)		552,911
Royalties Payable		-			(1,092	)
Net Cash Used in Operating Activities		(2,699,820	)		(2,362,855	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for Oil and Gas Properties		(1,490,736	)		(4,914,671	)
Acquisition of property		(1,500,000	)		-
Proceeds from Turnkey Drilling Programs		5,575,000			8,258,791
Net Cash Provided by Investing Activities		2,584,264			3,344,120

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from Long-Term Debt		500,000			1,400,000
Principal Payments on Long-Term Debt		(11,613	)		(6,623	)
Net Cash Provided by Financing Activities		488,387			1,393,377

Net Increase in Cash, Cash Equivalents, and Restricted Cash		372,831			2,374,642

Cash, Cash Equivalents, and Restricted Cash at Beginning of Year		7,902,163			5,527,521

Cash, Cash Equivalents, and Restricted Cash at End of Year	$	8,274,994		$	7,902,163

Supplemental Schedule of Cashflow information
Cash Paid for Interest	$	272,229		$	273,360
Cash Paid for Taxes	$	9,218		$	8,150

Supplemental Schedule of Non-Cash Investing and Financing Transactions:
Conversion of Preferred Stock to Common	$	-		$	24,664,543
Additions to asset retirement obligation		112,417			865
Revisions to asset retirement obligations		(41,622	)		63,224

The accompanying notes are an integral part of these consolidated financial statements.

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ROYALE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

This summary of significant accounting policies of Royale Energy, Inc. (in these notes sometimes called “we”, “us”, “our”, “the Company”) is presented to assist in understanding our financial statements.

These consolidated financial statements include the accounts of Royale Energy Inc and our controlled subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis. The financial statements and notes are representations of our management, which is responsible for their integrity and objectivity. These accounting policies conform to accounting principles generally accepted in the United States of America and have been consistently applied in the preparation of the financial statements.

Description of Business

We are an independent oil and gas producer and we also perform turnkey drilling operations. We own wells and leases in major geological basins located primarily in California, Texas, and Oklahoma, and offer fractional working interests and seek to minimize the risks of oil and gas drilling by selling multiple well drilling projects which do not include the use of debt financing.

Use of Estimates

The accompanying consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America 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.

Estimated quantities of crude oil and condensate, Natural Gas Liquids (“NGLs”) and natural gas reserves is a significant estimate that requires judgment. All of the reserve data included in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and condensate, NGLs and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and condensate, NGLs and natural gas reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil and condensate, NGLs and natural gas that are ultimately recovered. See Note 18 – Supplemental Information About Oil and Gas Producing Activities (Unaudited) to our Consolidated Financial Statements for further detail.

Other items subject to estimates and assumptions include the carrying amounts of accounts receivable, property, plant and equipment, equity method investments, asset retirement obligations, and valuation allowances for deferred tax assets, among others. Although we believe these estimates are accurate, actual results could differ from these estimates.

Liquidity and Going Concern

Management evaluated whether conditions and events, considered in the aggregate, raise substantial doubt about the Company’s ability to continue as a going concern within one year after the date the accompanying consolidated financial statements are issued. The accompanying financial statements have been prepared assuming the Company will continue as a going concern, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. The consolidated financial statements do not include any adjustments related to the recoverability and classification of recorded asset amounts or the amounts and classifications of liabilities that might result from the outcome of this uncertainty.

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.

Our 2025 consolidated financial statements reflect a working capital deficiency of $11,550,839, an accumulated deficit of $94,566,369 and recurring net losses from operations. These factors raise 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.

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Management’s plans to alleviate the going concern by implementing cost control measures that include the reduction of overhead costs and through the sale of non-strategic assets, and to seek additional debt and/or equity financing. There is no assurance that additional financing will be available when needed or that management will be able to obtain financing on terms acceptable to us and whether we will generate positive operating cash flow or become profitable. If we are unable to raise sufficient additional funds, we will have to develop and implement a plan to further extend payables and reduce overhead until sufficient additional capital is raised to support further operations. There can be no assurance that such a plan will be successful.

Revision of Previously Issued Financial Statements

During the preparation of the 2025 consolidated financial statements, immaterial errors were identified related to:

	●	Severance taxes were inappropriately netted against Sale of Oil and Gas Revenue within our statement of operations, resulting in the understatement of Sale of Oil & Gas Revenue and Lease Operating Expense of $81 thousand during 2024.

	●	Errors in the calculation of the tax basis of Oil and Gas Properties resulted in a $2.4 million overstatement of the disclosure of deferred tax assets and the related valuation allowance, resulting in zero net impact on Net Deferred Tax Assets.

	●	An error in the treatment of future income tax expense resulted in an understatement of approximately $2 million (unaudited) in our disclosures of the standardized measure of discounted future cash flows as of December 31, 2024. In addition, there were errors in the calculation of the various changes in the standardized measure (unaudited).

	●	Accrued liabilities and accumulated deficit were overstated by $189 thousand as a result of an error that occurred prior to 2023. This overaccrual was corrected by the Company during the quarter ended June 30, 2025.

●

Settlements of ARO liabilities of approximately $152 thousand were incorrectly presented in the statement of cash flows during the year ended December 31, 2024.

We assessed the materiality of the errors, both quantitatively and qualitatively, in accordance with the SEC’s Staff Accounting Bulletin No. 99 and Staff Accounting Bulletin No. 108, and concluded the errors were not material to any of our previously issued financial statements. Notwithstanding the results of the assessment, we have revised the applicable items in our previously issued financial statements to correct these misstatements. Accordingly, all consolidated financial information contained in these consolidated financial statements and the accompanying notes have been revised to reflect the corrections. Previously reported financial information will be corrected in future filings, as applicable.

Restricted Cash

We sponsor turnkey drilling arrangements in proved and unproved properties. The contracts require that participants pay us the full contract price upon execution of the drilling agreement. Each participant earns an undivided interest in the well bore at the completion of the well. A portion of the funds received in advance of the drilling of a well from a working interest participant are held for the expressed purpose of drilling a well. If something changes, we may designate these funds for a substitute well. Under certain conditions, a portion of these funds may be required to be returned to a participant. Once the well is drilled, the funds are used to satisfy the drilling cost. We classify these funds prior to commencement of drilling as restricted cash. In the event that progress payments are made from these funds; they are recorded as Prepaid Expenses and Other Current Assets.

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheets that sum to the total of the same amounts shown in the statement of cash flows.

	Year Ended December 31,
	2025		2024
Cash and cash equivalents	$	1,099,044	$	1,877,163
Restricted cash		7,175,950		6,025,000
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows	$	8,274,994	$	7,902,163

Other Receivables, net

Our other receivables consist of receivables from direct working interest investors and industry partners. We account for expected credit losses on receivables using the Current Expected Credit Loss (CECL) methodology. Under this standard, an allowance for expected credit losses is established and adjusted based on historical loss experience, current conditions, and reasonable and supportable forecasts of future economic conditions. The allowance account is increased or decreased in response to changes in these factors, reflecting our best estimate of credit losses over the remaining life of the receivables.

All amounts considered uncollectible are charged against the allowance account and recoveries of previously charged off accounts are added to the allowance. At December 31, 2025 and 2024, we established an allowance for expected credit loses of $2,302,873 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.

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Revenue Receivables

Our revenue receivables consist of receivables related to the sale of our natural gas and oil. Once a production month is completed, we receive payment approximately 15 to 30 days later. Historically, we have not had issues related to the collection of revenue receivables, and as such have determined that an allowance for revenue receivables is not currently necessary.

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		450,743
Write-offs charged against the allowance		(93,742	)
Balance at December 31, 2024	$	2,194,552

Balance at December 31, 2024	$	2,194,552
Provision for credit loss		137,221
Write-offs charged against the allowance		(28,900	)
Balance at December 31, 2025	$	2,302,873

Equity Method Investments

Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value may have occurred as called for under ASC 323, Investments—Equity Method and Joint Ventures. When a loss is deemed to have occurred and is other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income.

The Company’s only equity method investment is its holding in the RMX joint venture. At December 31, 2025, the Company had no balance related its investment in RMX, due to previously recognized impairments.

Revenue Recognition

A significant portion of our revenues are derived from the sale of crude oil, condensate, NGL and natural gas under spot and term agreements with our customers as follows:

	Year Ended December 31,
	2025		2024
Oil & Condensate Sales	$	1,664,862	$	2,010,742
Natural Gas Sales		257,684		231,765
NGL Sales		3,896		3,566
	$	1,926,442	$	2,246,073

The pricing in our hydrocarbon sales agreements are 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.

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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 of Lease Operating Expense.

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 in regard to the sale of our share of production and recognize revenue for the volumes associated with our net production.

We frequently sells a portion of the working interest in each well we drill or participate in to third-party investors and retains 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 (typically call “Casing Point Election” or “Logging Point”), the difference in the actual cost to drill and the guaranteed cost is recorded as income or expense depending on whether there was a gain or loss.

Crude oil and condensate

For the crude sales agreements, we satisfy our performance obligations and recognize revenue once customers take control of the crude at the designated delivery points, which include pipelines, trucks or vessels.

Natural Gas and NGLs

When selling natural gas and NGLs, we engage midstream entities to process our production stream by separating natural gas from the NGLs. Frequently, these midstream entities also purchase our natural gas and NGLs under the same agreements. In these situations, we determined the performance obligation is complete and satisfied at the tailgate of the processing plant when the natural gas and NGLs become identifiable and measurable products. We determined the plant tailgate is the point in time where control, is transferred to midstream entities and they are entitled to significant risks and rewards of ownership of the natural gas and NGLs.

The amounts due to midstream entities for gathering and processing services are recognized as shipping and handling cost and included as lease operating expense in our consolidated Statement of Operations, since we make those payments in exchange for distinct services with the exception of natural gas sold to PG&E where transportation cost is netted directly against revenues. Under some of our natural gas processing agreements, we have an option to take the processed natural gas and NGLs in-kind and sell to customers other than the processing company. In those circumstances, our performance obligations are complete after delivering the processed hydrocarbons to the customer at the designated delivery points, which may be the tailgate of the processing plant or an alternative delivery point requested by the customer.

Turnkey Drilling Obligations

We manage these Turnkey Agreements for the participants of the well. The collections of pre-drilling Authorization for Expenditure (“AFE”) amounts are segregated and the gains and losses on the Turnkey Agreements are recorded in income or expense at the time of the casing point election in accordance with ASC 932-323-25 and 932-360. We manage the performance obligation for the well participants and only record revenue or expense at the time the performance obligation of the Turnkey Agreement has been satisfied.

Other Operating Revenue

For the years ended December 31, 2025 and 2024, we recognized $20,761 and $16,266, respectively in supervisory fees in Pipeline and Compressor fees which were received and allocated based on production volumes.

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Oil and Gas Property and Equipment

Successful Efforts

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 Cost

Production costs are expensed as incurred. Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain our wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labor costs to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity.

Depreciation, Depletion and Amortization

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 drilling phase commences with the development of the detailed engineering design and ends when the 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.

Impairment

We evaluate our oil and gas producing properties, including capitalized costs of exploratory wells and development costs, for impairment of value whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. Oil and gas producing properties are reviewed for impairment on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure or contractual terms that cause economic interdependency amongst separate, discrete fields. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows or, if available, comparable market value. We evaluate our unproved property investment and record impairment based on time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved property investments are deemed to be impaired, this amount is reported in exploration expenses in our consolidated statements of operations. During 2025 we recorded impairment losses of $27,250, on various capitalized lease and land costs where the carrying value exceeded the estimated fair value. In 2024 we recorded impairment losses of $400,719.

Upon the sale or retirement of a complete field of a proved property, we eliminate the cost from our books, and the resultant gain or loss is recorded to our 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 our consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a recovery of the cost in the interest retained with any excess funds recognized as a gain. Should our turnkey drilling agreements include unproved property, total drilling costs incurred to satisfy our obligations are recovered by the total funds received under the agreements. Any excess funds are recorded as a Gain on Turnkey Drilling Programs, and any costs not recovered are capitalized and accounted for under the “successful efforts” method.

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Asset Retirement Obligations

The Asset Retirement and Environmental Obligations Topic of the ASC 410-20 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset. The ARO is recorded at the estimated fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value. Accretion expense is included as part of Depreciation, Depletion and Amortization in the Consolidated Statement of Operations. The fair value (as provided in ASC 820 guidance) of the ARO is a Level 3 measurement using expected future cash outflows discounted at our credit-adjusted risk-free interest rate. The provisions of this Topic apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, development, and operation of a long-lived asset.

Long-Lived Assets Classified as Held for Sale

We classify long-lived assets as Held-for-Sale when the criteria of ASC 360-10-45-9 through 45-11, Impairment and Disposal of Long-Lived Assets, have been met. This criterion is listed below:

	●	Management has committed to a plan to sell the asset;

	●	The asset group is available for immediate sale in its present condition;

	●	An active program is underway to locate potential buyers;

	●	The sale is probable within one year;

	●	The asset group is being marketed at a price that is reasonable relative to its current fair value; and

	●	Actions required to complete the plan indicate that it is unlikely that significant changes to the plan will be made or the plan will be withdrawn.

Assets held for sale are carried at the lower of cost or fair market value less cost of disposal in current assets. If we retain the responsibility for the P&A, equipment removal or site restoration, the associated anticipated expense is carried as current an asset retirement obligation (“ARO”) (See Note 3, below).

Turnkey Drilling

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 and 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 pay us 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 its proportionate share of operating costs. We retain legal title to the lease. The participants purchase a working interest directly in the well bore.

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

A certain portion of the turnkey drilling participant’s funds received are non-refundable. We hold all funds invested as Deferred Drilling Obligations until drilling is complete. Occasionally, drilling is delayed for various reasons such as weather, permitting, drilling rig availability and/or contractual obligations. At December 31, 2025 and 2024, we had Deferred Drilling Obligations of $14,277,496 and $11,457,996, respectively. During 2025, we disposed of $2,755,500 of drilling obligations as we participated in drilling and completion of one gross (0.0035 net) successful oil well in the Texas Permian basin, while incurring expenses of $1,433,351, resulting in a gain of $1,322,149. During 2024, we disposed of $6,562,721 of drilling obligations as we participated in the drilling and completion of four gross (0.0722 net) wells in Texas Permian basin, while incurring expenses of $4,955,044, resulting in a gain of $1,607,677.

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If we are unable to drill the wells, and a suitable replacement well is not found, we would retain the non-refundable portion of the contract and return the remaining funds to the participant. Included in restricted cash are amounts for use in completion of turnkey drilling programs in progress.

Equipment and Fixtures

Equipment and fixtures are stated at cost and depreciated over the estimated useful lives of the assets, which range from three to seven years, using the straight-line method. Repairs and maintenance are charged to expense as incurred. When assets are sold or retired, the cost and related accumulated depreciation are removed from the accounts and any resulting gain or loss is included in income. Maintenance and repairs, which neither materially add to the value of the property nor appreciably prolong its life, are charged to expense as incurred.

Loss Per Share

Basic and diluted losses per share are calculated as follows:

	Year Ended December 31,
	2025						2024
	Basic			Diluted			Basic			Diluted
Net Loss	$	(1,251,680	)	$	(1,251,680	)	$	(2,159,016	)	$	(2,159,016	)
Less: Preferred Stock Dividend		-			-			653,730			653,730
Less: Non-cash Restructuring Inducements		-			-			674,341			674,341
Net Loss Attributable to Common Shareholders		(1,251,680	)		(1,251,680	)		(3,487,087	)		(3,487,087	)
Weighted average common shares outstanding		96,600,302			96,600,302			77,278,047			77,278,047
Effect of dilutive securities		-			-			-			-
Weighted average common shares, including Dilutive effect		96,600,302			96,600,302			77,278,047			77,278,047
Per share:
Net Loss	$	(0.01	)	$	(0.01	)	$	(0.03	)	$	(0.03	)

Income Taxes

We utilize the asset and liability approach to measure deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates in accordance with the Income Taxes Topic of the ASC 740. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. Under the Topic, 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.

The provision for income taxes is based on pretax financial accounting income. Deferred tax assets and liabilities are recognized for the expected tax consequences of temporary differences between the tax basis of assets and liabilities and their reported net amounts.

Fair Value Measurements

According to Fair Value Measurements and Disclosures guidance as provided by ASC 820 and 825, assets and liabilities that are measured at fair value on a recurring and nonrecurring basis in periods subsequent to initial recognition, the reporting entity shall disclose information that enable users of our financial statements to assess the inputs used to develop those measurements and for recurring fair value measurements using significant unobservable inputs, the effect of the measurements on earnings for the period.

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. In determining fair value, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible as well as consider counterparty credit risk in our assessment of fair value. Carrying amounts of our financial instruments, including cash equivalents, accounts receivable, accounts payable and accrued liabilities, approximate their fair values as of the balance sheet dates because of their generally short maturities.

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

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

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

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

As of December 31, 2025, we have financial liabilities, including outstanding notes, that have been measured at fair value on a nonrecurring basis. The carrying values of financial instruments comprising cash, payables, and receivables, approximate fair values due to the short-term maturities of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying amounts of cash and cash equivalents, accounts receivable, and other current assets approximate their fair values due to the short-term maturities of these instruments.

As part of the Series B Convertible Preferred Stock restructuring transaction, the Company issued Series 2024 Senior Unsecured Promissory Notes in exchange for approximately 10% of the outstanding Series B shares. These notes have varying interest rate periods:

●

0.0% interest through December 31, 2025

●

5.0% interest from January 1, 2026, to December 31, 2027

●

8.0% interest from January 1, 2028, to June 30, 2029 (maturity date)

The fair value of these notes was determined using a discounted cash flow model based on an assumed market interest rate of 11.912%, reflecting the Company’s estimated borrowing rate (Wall Street Journal Prime Rate plus 400 basis points as of October 1, 2024). Based on this valuation methodology, the following table sets out the fair value and carrying value of the notes issued.

The fair value measurement of these notes is classified as Level 3 in the fair value hierarchy due to the use of significant unobservable inputs, including management’s assessment of credit risk and cash flow projections. The carrying amount of these notes will be accreted to their face value over the term using the effective interest rate method.

The carrying values and estimated fair values of these notes were as follows:

	Carrying Value		Fair Value
December 31, 2025
Series 2024 Senior Unsecured Promissory Notes	$	2,221,112	$	2,369,158
Walou Note		1,900,000		2,032,792
December 31, 2024
Series 2024 Senior Unsecured Promissory Notes		2,057,775		2,116,983
Walou Note		1,400,000		1,497,847

Additionally, the restructuring included the issuance of 25,000,000 stock warrants exercisable at $0.10 per share, expiring June 30, 2029. The warrants were valued using the Black-Scholes-Merton model, resulting in a fair value of $0.04 per warrant or an aggregate value of $995,503, which is classified as equity and not a liability for fair value measurement purposes.

See Note 2 – Oil and Gas Properties, Equipment and Fixtures for further discussion of our asset retirement obligations and property transactions.

Accounts Payable and Accrued Expenses

At December 31, 2025 and 2024, the components of accounts payable and accrued expenses consisted of:

	2025		2024
Trade Payables and accruals	$	3,235,457	$	3,946,583
Direct working interest investors related accruals		2,050,399		2,322,690
Current drilling efforts accrued expenses		335,041		120,102
Accrued Liabilities		210,516		210,516
Employee related accruals		197,175		169,079
Deferred rent		5,290		7,855
	$	6,033,878	$	6,776,825

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Accrued – Non-current

At December 31, 2025 and 2024, we had non-current accrued liabilities of $12,386 and accrued unpaid guaranteed payment of $90,000. These were due to certain Matrix Oil Corp (“Matrix”) principals, from periods prior to the merger with the Matrix entities during March of 2018.

Business Combinations

From time-to-time, we acquire businesses in the oil and gas industry. We primarily target businesses in geological basins that we consider to be in a focus area. Businesses are included in the consolidated financial statements from the date of acquisition.

We recognize, separately from goodwill, the identifiable assets acquired and liabilities assumed at their estimated acquisition-date fair values. We measure and recognize goodwill as of the acquisition date as the excess of: (1) the aggregate of the fair value of consideration transferred, the fair value of any noncontrolling interest in the acquiree (if any) and the acquisition date fair value of our previously held equity interest in the acquiree (if any), over (2) the fair value of assets acquired and liabilities assumed. If information about facts and circumstances existing as of the acquisition date is incomplete by the end of the reporting period in which a business combination occurs, we report provisional amounts for the items for which the accounting is incomplete. The measurement or allocation period ends once we receive the information we are seeking; however, this period will generally not exceed one year from the acquisition date. Any material adjustments recognized during the measurement period will be reflected retrospectively in the consolidated financial statements of the subsequent period. We recognize third-party transaction-related costs as expense currently in the period in which they are incurred.

If the set of assets and activities acquired is not considered a business under GAAP, the acquisition is accounted for as an asset acquisition using a cost accumulation model. In the cost accumulation model, the cost of the acquisition, including certain transaction costs, is allocated to the assets acquired on the basis of relative fair values, and no goodwill is recognized. The Pradera Fuego Acquisition was accounted for as an asset acquisition under GAAP.

Changes in Accounting Standards

Recently Adopted

In December 2023, the FASB issued Accounting Standards Update (“ASU”) 2023-09, Income Taxes (Topic 740) (“ASC 740”): Improvements to Income Tax Disclosures (“ASU 2023-09”) to expand the disclosure requirements for income taxes, specifically related to the rate reconciliation and income taxes paid. ASU 2023-09 is effective for annual periods beginning January 1, 2025, with early adoption permitted. We have adopted ASU 2023-09 for the annual period ended December 31, 2025 and have conformed our income tax disclosures in Note 4 to reflect the new requirements.

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which enhances the disclosures required for operating segments in the Company’s annual and interim consolidated financial statements. This ASU is effective retrospectively for fiscal years beginning after December 15, 2023, and for interim periods within fiscal years beginning after December 15, 2024. The Company adopted this update effective January 1, 2024. See Note 14 - Segments. The adoption and implementation of this standard did not have a material impact on the Company’s disclosures.

Recently Issued, Not Yet Adopted

We have reviewed all other recently issued accounting pronouncements that are not yet effective and have determined that none are currently expected to have a material impact on our consolidated financial statements upon adoption.

In November 2024, the FASB issued ASU 2024-03, Income Statement (Subtopic 220-40) Reporting Comprehensive Income-Expense Disaggregation Disclosures, which broadens the disclosures required for certain costs and expenses in the Company’s annual and interim consolidated financial statements. This ASU is effective prospectively for fiscal years beginning after December 15, 2026, and interim reporting periods within fiscal years beginning after December 15, 2027. The Company is currently evaluating disclosures related to our annual report for fiscal year 2027.

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NOTE 2 – OIL AND GAS PROPERTIES, REAL PROPERTY AND EQUIPMENT AND FIXTURES

Oil and gas properties, real property and equipment and fixtures consist of:

	Year ended December 31,
	2025			2024
Oil and Gas
Producing properties, including intangible drilling costs	$	7,229,767		$	5,764,761
Undeveloped properties		3,237,624			3,339,234
Lease and well equipment		3,298,441			3,295,028
Total Oil and Gas Properties		13,765,832			12,399,023
Accumulated depletion, depreciation and amortization		(7,995,503	)		(7,748,190	)
Net capitalized costs Total	$	5,770,329		$	4,650,833

Commercial and Other	2025				2024
Vehicles		40,061			40,061
Furniture and equipment		1,103,362			1,103,362
Total Commercial and Other		1,143,423			1,143,423
Accumulated depreciation		(1,139,574	)		(1,137,597	)
		3,849			5,826
Net capitalized costs Total	$	5,774,178		$	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. We do not have any capitalized exploratory well costs. Undeveloped properties are not subject to depletion, depreciation or amortization.

NOTE 3 – ASSET RETIREMENT OBLIGATION

There were no changes in estimates for the years ended December 31, 2025 and 2024.

	2025			2024
Asset retirement obligation
Beginning of the year	$	5,078,595		$	4,826,847
Liabilities incurred during the period		112,417			865
Settlements		(78,839	)		(151,856	)
Changes in Working Interest		26,085			(4,716	)
Changes in estimates		(67,707	)		405,440
Accretion expense		7,300			2,015
End of year	$	5,077,852		$	5,078,595

We record accretion expense as part of Depreciation, Depletion and Amortization. Accretion expense was $7,300 and $2,015 for the years ended December 31, 2025 and 2024, respectively.

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NOTE 4 – INCOME TAXES

The components of income (loss) before income taxes were as follows:

	2025			2024

U.S.	$	(1,251,680	)	$	92,159,014	)
Non-U.S.	$	-		$	-

The reconciliation between the actual provision for income taxes and that computed by applying the U.S. statutory rate to income (loss) before income taxes are outlined below based on the updated requirements of ASU 2023-09 for 2025.

	2025

Current tax at U.S. statutory rate	$	(222,999	)	21.00	%
State and local income taxes, net of federal taxes		(37,891	)	3.57	%
Foreign Tax Effects		-		-	%
Effects of Changes in Tax Law or Rates Enacted in the Current Period		-		-	%
Effect of cross-border tax law		-		-	%
Tax Credits		-		-	%
Changes in Valuation Allowance		176,562		16.63	%
Nondeductible/nontaxable items
Nondeductible/nontaxable items		1,642		(0.15	%)
Changes in Unrecognized Tax Benefit		-		-	%
Other Adjustments
Deferred Adjustment		82,686		79	%
Income tax expense	$	-		-	%

As previously disclosed prior to the adoption of ASU 2023-09, the effective income tax rate differs from the statutory federal income tax rate as follows

	2024
Tax (benefit) computed at statutory rate of 21% at December 31, 2024, respectively	$	(518,740	)

Increase (decrease) in taxes resulting from:
Meals & Entertainment		915
Prior-year true-up for Books		2,380,175
Deferred State Taxes, net of federal benefit		(102,681	)
Other non-deductible expenses		-
Change in valuation allowance		(1,759,669	)
Provision (benefit)	$	-

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.

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Significant components of our deferred assets and liabilities at December 31, 2025 and 2024, respectively, are as follows:

	2025			2024
Deferred Tax Assets (Liabilities):
Accrued Expenses	$	98,999		$	22,249
Net Operating Loss		9,450,310			9,288,524
Accretion		615,894			613,254
Share-Based Compensation		86,510			86,510
Charitable Contributions Carry Forward		2,796			2,743
Other					14,266
Allowance for Doubtful Accounts		599,207			571,022
Interest Expense Limitations					67,221
Oil and Gas Properties and Fixed Assets		3,292,967			3,320,659
Investment in RMX Joint Venture		139,969			123,640
Total deferred tax assets		14,286,652		$	14,110,089
Valuation Allowance		(14,286,652	)		(14,110,089	)
Net Deferred Tax Asset	$	-		$	-

During the current year audit, it was determined that there were two immaterial errors in the 2024 income tax disclosures. The deferred tax asset for Oil and Gas Properties and Fixed Assets was overstated by $2.4 million. The error was caused by two different items. The first error was to record a deferred tax liability in work in process where none should have been recorded. The second error was to have recorded a deferred tax liability twice related to the book impairment on oil and gas properties. Both of these changes are completely offset by an equal offsetting change to the valuation allowance resulting in a net impact of $0 on the face of the financials. Only the income tax footnote disclosures were impacted by these errors.

As of December 31, 2025, management reviewed the reliability of our net deferred tax assets, and due to our continued cumulative losses, we concluded it is not “more-likely-than-not” our deferred tax assets will be realized. As a result, we have continued to record a full valuation allowance against the deferred tax assets. We will assess the realizability of the deferred tax assets at least yearly and make appropriate updates as needed. We and our subsidiaries have available net operating loss carryforwards of $20.5 million generated in tax years ended before January 1, 2018, which if not utilized, expire in varying amounts between 2026 and 2037. We have $13.7 million net operating loss carryforwards generated after December 31, 2017, which can be carried forward indefinitely.

As of December 31, 2025, we did not recognize a liability for uncertain tax positions. Currently, the only differences between our financial statements and our income tax returns relate to normal timing differences such as depreciation, depletion and amortization, which are recorded as deferred taxes on our balance sheets. We do not expect our unrecognized tax benefits to change significantly over the next 12 months. The tax years of 2020 through 2024 remain open to examination by the tax jurisdictions in which we file income tax returns.

Net income taxes paid (received) during the years ended December 31, 2025 and 2024, by federal and state jurisdiction (all states combined), were as follows:

	2025		2024
Federal	$	-	$	-
State		9,218		8,150
Total income taxes paid, net	$	11,243	$	10,174

NOTE 5 – SERIES B PREFERRED STOCK

Pursuant to the terms of the merger completed in 2018, all Class A limited partnership interests of Matrix Investments, LP (“Matrix Investments”) were exchanged for our Common stock using conversion ratios according to the relative value of the Class A limited partnership interests, and $20,124,000 of Matrix Investments preferred limited partnership interests were converted into 2,012,400 shares of our Series B Convertible Preferred Stock. The Series B Convertible Preferred Stock was convertible at the option of the security holder at the rate of ten shares of common stock for one share of Series B Convertible Preferred Stock.

For 2024, the board authorized the payment of each quarterly dividend of Series B Convertible Preferred shares, as Paid-In-Kind shares (“PIK”) to be paid immediately following the end of the quarter. For the year ended December 31, 2023, we issued 62,899 shares with a value of $629,007. During 2024, no cash was used to pay dividends on Series B preferred shares.

On October 11, 2024, we completed a significant equity restructuring transaction, eliminating our Series B, 3.5% Convertible Preferred Stock. See Note 14.

NOTE 6 – COMMON STOCK

During 2024, we issued shares of our Common Stock in lieu of cash payments for salaries, fees or incentives to various officers and board members, including our CEO, as noted in the Statement of Stockholders’ Deficit. Common stock was also issued on October 11, 2024, when we completed a significant equity restructuring transaction, see Note 14.

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NOTE 7 – LEASES

During 2024, we had one office lease, the location of our corporate offices. The corporate office lease was entered into on August 12, 2021, began on January 1, 2022 and expires on December 31, 2026, with initial monthly payments of $6,922 with escalations. We also rent office space on a month-to-month basis in Santa Barbara, California, the location of our CEO for $1,000 per month. In addition, we have a finance lease for miscellaneous small office equipment, which commenced in the fourth quarter of 2024 with an 84-month term and an original balance of $71,622.

Lease Obligations	Operating Lease Obligations		Financing Lease Obligations		Total Lease Obligations
2026	$	93,492	$	19,080	$	112,572
2027		-		19,080		19,080
2028		-		19,080		19,080
Thereafter		-		14,310		14,310
Total undiscounted lease payments		93,492		71,550		165,042
Less: Amount representing interest		4,308		15,110		19,418
Total Operating & Financing lease liabilities		89,184		56,440		145,624
Current lease liabilities as of December 31, 2025		89,184		13,054		102,238
Long-term lease liabilities as of December 31, 2025	$	-	$	43,386	$	43,386

We have elected the short-term lease recognition exemption for all leases with an original term of 12 months or less. This means, for those leases that qualify, we will not recognize rights of use (“ROU”) assets or lease liabilities, and this includes not recognizing ROU assets or lease liabilities for existing short-term leases. We elected the practical expedient to not separate lease and non-lease components for all of our finance leases. For our real estate operating leases, we have only considered the fixed portion of our lease payment commitment and have excluded the variable components from the capitalized ROU and lease liability.

The amounts are as follows:

	Year ended December 31,
	2025		2024
Operating lease expense	$	119,658	$	161,858
Financing lease expense		21,303		17,567
Short Term - field		6,000		6,000
Total lease expense	$	146,961	$	185,425

The following tables summarized the operating and financing lease obligations.

	Debit/Credit
	Financing Leases			Operating Leases			Total
Right of Use Asset - Leases	$	54,655		$	89,184		$	143,839
Leases - Current		(9,725	)		(89,184	)		(98,909	)
Leases - Non-current		(44,930	)		-			(44,930	)

Our two office leases do not contain implicit interest rates that can be readily determined. As a result, we used the best estimate of our incremental borrowing rate. At December 31, 2025 and 2024 the weighted average annual discount rate for our operating leases was 4.83% and the weighted average remaining term was 3 and 4 years, respectively. The weighted average annual discount rate for our finance lease was 11.91% for 2025 and 2024, and the weighted average remaining term was 6 and 7 years.

NOTE 8 – RELATED-PARTY TRANSACTIONS

At December 31, 2025, and 2024, we had a receivable balance of $22,266 and $22,226 respectively, due from Stephen Hosmer, a director and corporate secretary, for normal lease operating expenses, recorded in Other Receivables, net.

At December 31, 2025 and 2024, we had payables of $23,087 and $23,087, respectively, due to RMX and its subsidiary, Matrix Oil Corporation, related to certain lease operating expenses for wells operated by RMX, included in accounts payable and accrued expenses on our Consolidated Balance Sheets.. For the same periods, we also had prepaid expenses and other current assets, and deferred drilling obligations with RMX of $710,590 and $556,019, respectively. During 2025 and 2024, RMX operated various oil wells we have interests in, from which we received revenues of approximately $236,900 and $372,028 respectively, and incurred lease operating costs of approximately $129,450 and $158,664 respectively. At December 31, 2025 and 2024, we had a total revenue receivables of $122,262 and $108,344, respectively, due from RMX and its subsidiary, Matrix Oil Corporation.

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We had outstanding accrued unpaid guaranteed payments for unpaid salary due to a certain Matrix employee for periods predating joining our company. At December 31, 2025 and 2024, the balance due was $90,000 which is included in the Noncurrent Liabilities on our Consolidated Balance Sheets. At December 31, 2025 and 2024, Royale also had accrued unpaid liabilities of $12,386 due to a certain former Matrix employee for periods predating his employment.

Michael McCaskey, Jeffery Kerns, and Stephen Hosmer, current directors, each provide services as directed and at our discretion directly or through an entity controlled by them. The following table sets amounts paid to entities owned or controlled by these individuals:

	2025		2024
Michael McCaskey	$	60,000	$	60,000
Jeffery Kerns		-		4,726
Stephen Hosmer		83,873		79,448

The following table sets amounts owed to entities owned or controlled by these individuals at December 31, reflected in Accounts Payable and Accrued Expenses on the Consolidated Balance Sheet.

	2025		2024
Michael McCaskey	$	21,455	$	21,455
Jeffery Kerns		26,844		26,844
Stephen Hosmer		14,783		11,400

On February 7, 2024 the board of directors approved a debt facility of up to $3 million. On February 9, 2024, Royale Energy, Inc. entered into a Secured Term Loan Note with Walou Investments, LP, a Texas limited partnership, which is under the direct and indirect 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 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 annual interest rate of 18.00%. On November 1, 2024 the maturity 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.

NOTE 9 – STOCK COMPENSATION PLAN

There were no stock options issued for compensation during 2025 and 2024.

NOTE 10 – SIMPLE IRA PLAN

In April 1998, we established a Simple IRA plan covering all employees. We will contribute a matching contribution to each eligible employee’s Simple IRA equal to the employee’s salary reduction contributions up to a limit of 3% of the employee’s compensation for the year. The employer contribution for the years ending December 31, 2025 and 2024, were $30,333 and $28,653 respectively.

NOTE 11 – ENVIRONMENTAL MATTERS

We have established procedures for the continuing evaluation of our operations to identify potential environmental exposures and ensure compliance with regulatory policies and procedures. Management monitors these laws and regulations and periodically assesses the propriety of our operational and accounting policies related to environmental issues. The nature of our business requires routine day-to-day compliance with environmental laws and regulations. We incurred no material environmental investigation, compliance and remediation costs in 2025 or 2024.

We are unable to predict whether our future operations will be materially affected by these laws and regulations. We believe that legislation and regulations relating to environmental protection will not materially affect our results of operations.

NOTE 12 – CONCENTRATIONS

We bid our gas sales on a month-to-month basis and generally sell to a single customer without commitment to future gas sales to any particular customer. For both years presented we sold approximately 36% of our yearly natural gas production to one customer on a month-to-month basis. Since we are able to sell our natural gas to other readily available customers, we believe the loss of any one customer would not have an adverse effect on our overall sales operations.

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We maintain cash in depository institutions that are guaranteed by the Federal Deposit Insurance Corporation (FDIC) up to $250,000 per institution for our interest-bearing accounts in the years ended December 31, 2025, and 2024. At December 31, 2025 and 2024, cash in banks exceeded the FDIC limits by approximately $8.0 million and $7.6 million, respectively. We have not experienced any losses on deposits.

NOTE 13 – COMMITMENTS AND CONTINGENCIES

We may become involved from time to time in litigation on various matters, which are routine to the conduct of our business. We believe that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial position or results of operations, though any adverse decision in these cases or the costs of defending or settling such claims could have a material effect on our business.

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. The contracts require the participants pay us the full contract price upon execution of the agreement. We typically begin the drilling activities within 12 months of funding and reach total depth between 10 and 30 days after drilling begins.

Note 14 – Debt and Equity Restructuring Transaction

On October 11, 2024, we completed a significant equity restructuring transaction, eliminating our Series B, 3.5% Convertible Preferred Stock and simplifying our capital structure. The transaction was executed through a combination of common stock issuance, warrants, and senior promissory notes in exchange for the retirement of all outstanding Series B Preferred Shares as of June 30, 2024. The preferred holders waived the payment of any unpaid dividends.

The restructuring involved the exchange and extinguishment of 2,466,455 shares of Series B Preferred Stock, which carried an aggregate liquidation preference of $24.7 million. The exchange was structured as follows:

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 2,508,509 shares common stock and promissory notes for $278,724 on the same terms stated above.

The transaction was accounted for as an extinguishment of equity in accordance with ASC 470-50 and ASC 260-10-S99-2, as it represented a fundamental change in the structure and rights of the preferred stockholders. No gain or loss was recognized on the conversion of Series B Preferred Stock, as it was deemed to be an equity transaction per authoritative guidance. However, the issuance of warrants and asset transfers was treated as an inducement expense. The excess of the fair value of the warrants and assets transferred over the accrued dividend forgiven totaling $674,341 was treated as inducement. The inducement was accounted for as an equity transaction and increases the net loss attributable to common shareholders in the Loss Per Share computation in Note 1.

The Company concurrently settled approximately $3.47 million of accrued liabilities and unpaid guaranteed payments through the issuance of common stock and additional promissory notes valued at fair market rates. The liabilities extinguished included obligations associated with prior merger activity and were held primarily by related parties. The exchange of these liabilities was accounted for as a capital transaction with no gain or loss recognized on extinguishment, in accordance with guidance in ASC 470-50. The fair value of the new instruments issued was allocated between notes payable, common stock, and additional paid-in capital.

F-23

Table of Contents

NOTE 15 – Notes Payable

Walou Note

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 original terms and conditions of the Secured Term Loan Note remain in full force and effect at December 31, 2025.

Senior Unsecured Promissory Notes

On December 31, 2025 the outstanding balance of the Senior Unsecured Promissory Notes was $2,221,112 and is further discussed in Note 14 – Debt and Equity Restructuring Transaction. The carrying value and fair value is further discussed in note 1.

NOTE 16 – 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 consolidated net income (loss), as reported in the consolidated statement of 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 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 consolidated balance sheets. The significant expense categories regularly provided to and reviewed by the CODM are those presented in the consolidated statements of operations.

F-24

Table of Contents

NOTE 17 – SUBSEQUENT EVENTS

On March 1, 2026, the Company completed the purchase of 8 gross (0.14 net) wells for $200,000. Other than as disclosed above, the Company has determined that no events or transactions have occurred subsequent to December 31, 2025 that require recognition or disclosure in these consolidated financial statements.

NOTE 18 – SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

The following estimates of proved oil and gas reserves, both developed and undeveloped, represent interest we own, which are located solely in the United States. Proved reserves represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate to be reasonably certain to be recoverable in the future from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells, with existing equipment and operating methods. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which relatively major expenditures are required for completion.

Disclosures of oil and gas reserves, which follow, are based on estimates prepared by independent petroleum engineering consultant Netherland, Sewell & Associates, Inc. The net reserve value of our proved developed and undeveloped reserves was approximately $20.5 million at December 31, 2025, based on the average Henry Hub natural gas price spot price of $3.387 per MCF and for oil volumes, the average West Texas Intermediate price of $66.01 per barrel as applied on a field-by-field basis. Netherland, Sewell & Associates, Inc. provided reserve estimates for our California, Texas, and Oklahoma properties. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. These estimates do not include probable or possible reserves.

The technical persons responsible for preparing the reserves estimates presented in the report of Netherland, Sewell & Associates, Inc., meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Netherland, Sewell & Associates, Inc. is a firm of independent petroleum engineers, geologists, geophysicists, and petrophysicists; and do not own an interest in our properties and are not employed on a contingent basis. All activities and reports performed and completed by Netherland, Sewell & Associates, Inc. with regards to our reserve valuation estimates are reviewed by our management.

These estimates are furnished and calculated in accordance with requirements of the FASB and the SEC. Because of unpredictable variances in expenses and capital forecasts, crude oil and natural gas price changes, and the fact that the bases for such estimates vary significantly, management believes the usefulness of these projections is limited. Estimates of future net cash flows presented do not represent our management’s assessment of future profitability or future cash flows. Management’s investment and operating decisions are based upon reserve estimates that include proved reserves prescribed by the SEC as well as probable reserves, and upon different price and cost assumptions from those used here.

It should be recognized that applying current costs and prices and a 10 percent standard discount rate does not convey absolute value. The discounted amounts arrived at are only one measure of the value of proved reserves.

F-25

Table of Contents

Changes in Estimated Reserve Quantities

Proved Oil and Gas Reserve Quantities

The Company's proved reserves and changes in proved reserves are as follows:

	Crude Oil (Bbls)			Natural Gas (Mcf)			Total Proved Reserves (Boe)
Proved reserves:
December 31, 2023		217,780			473,540			296,703
Extensions and discoveries		15,043			31,511			20,295
Revisions of previous estimates		32,490			4,115			33,176
Purchases of reserves in place		-			-			-
Production		(26,573	)		(116,406	)		(45,974	)
December 31, 2024		238,740			392,760			304,200
Extensions and discoveries		248,005			746,679			372,452
Revisions of previous estimates		107,313			688,044			221,987
Purchases of reserves in place		79,022			105,496			96,605
Production		(25,980	)		(117,219	)		(45,517	)
December 31, 2025		647,100			1,815,760			949,727

Proved developed producing reserves:
December 31, 2024		132,600			199,800			165,900
December 1, 2025		199,000			569,500			293,917

Proved developed non-producing reserves:
December 31, 2024		19,900			38,500			26,350
December 1, 2025		18,700			32,900			24,183

Proved undeveloped reserves:
December 31, 2024		86,240			154,460			111,950
December 1, 2025		429,400			1,213,360			631,627

Total proved reserves:
December 31, 2024		238,740			392,760			304,200
December 1, 2025		647,100			1,815,760			949,727

Proved oil and gas reserves are generally those quantities of crude oil, NGLs and natural gas, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods and government regulations. Proved developed reserves include reserves that can be expected to be produced through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves include reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved reserve quantities at December 31, 2024, and 2025 and the related discounted future net cash flows before income taxes are based on estimates prepared by Netherland, Sewell & Associates, Inc. Such estimates have been prepared in accordance with guidelines established by the SEC. All the Company’s proved reserves are attributable to properties within the United States.

Standardized Measure

The standardized measure of discounted future net cash flows relating to proved reserves is as follows:

	December 31,
	2025			2024
Future cash inflows	$	43,694,600		$	17,957,800
Future production costs		(17,820,400	)		(6,885,000	)
Future development costs		(5,411,900	)		(34,600	)
Future income taxes (1)		-			-
Future net cash flows		20,462,300			11,038,200
Less 10% annual discount to reflect timing of cash flows		(9,286,200	)		(4,689,500	)
Standardized measure of discounted future net cash flows		11,176,100			6,348,700

(1)

Future income taxes in the calculation of the standardized measure of discounted future net cash flows were zero as of December 31, 2024, and 2025, as the historical tax basis of proved oil and gas properties, net operating loss carryforwards, and future tax deductions exceeded the undiscounted future net cash flows before income taxes of the Company’s proved oil and gas reserves as of December 31, 2024, and 2025.

Proved reserve estimates and future cash flows are based on the average realized prices for sales of crude oil, NGLs and natural gas on the first calendar day of each month during the year. The following average realized prices were used in the calculation of proved reserves and the standardized measure of discounted future net cash flows.

	December 31,
	2025		2024
Crude oil ($/Bbl)	$	61.92	$	72.01
Natural gas ($/Mcf)	$	2.00	$	1.95

F-26

Table of Contents

Future operating and development costs are computed primarily by the Company’s petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company’s proved reserves at the end of the year, based on current costs and assuming continuation of existing economic conditions. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the Company’s oil and gas properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in proved reserve estimates.

	December 31,
	2025			2024
Standardized measure at beginning of year	$	6,348,700		$	6,503,720
Revisions to reserves proved in prior years:
Net change in sales prices and production costs related to future production		(2,084,125	)		(102,367	)
Net change in estimated future development costs		(4,458,464	)		(34,600	)
Net change due to revisions in quantity estimates		3,216,276			900,932
Accretion of discount		634,870			650,372
Changes in production rates (timing) and other		191,993			(143,080	)
Total revisions to reserves proved in prior years		(2,499,450	)		1,271,257
Net change due to extensions and discoveries, net of estimated future development and production costs		6,849,699			448,423
Net change due to purchases of reserves in place		2,090,951			-
Sales of crude oil, NGLs and natural gas produced, net of production costs		(1,613,800	)		(1,874,700	)
Net change in standardized measure of discounted future net cash flows		4,827,400			(155,020	)
Standardized measure at end of year	$	11,176,100		$	6,348,700

The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed at December 31:

	Year ended December 31,
	2025		2024
Acquisition - Proved	$	1,508,167	$	-
Acquisition - Unproved		-		-
Development		1,433,352		4,955,045
Exploration		-		-
Total Costs	$	2,941,519	$	4,955,045

Results of Operations from Oil and Gas Producing and Exploration Activities

The results of operations from oil and gas producing and exploration activities (excluding corporate overhead and interest costs) are as follows:

	Year ended December 31,
	2025			2024
Oil and gas sales	$	1,926,442		$	2,246,073
Production related costs (Lease Operating)		(1,396,710	)		(2,065,005	)
Impairment		(27,250	)		(400,719	)
Depreciation, depletion, amortization, and accretion		(259,438	)		(308,524	)

Results of operations from producing and exploration activities	$	243,044		$	(528,175	)
Income Taxes (Benefit)		-			-

Net Results	$	243,044		$	(528,175	)

F-27

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Royale Energy, Inc. 10-K