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, 2024

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, 2024, 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 March 18, 2025, 96,600,302 shares of the registrant’s Common Stock were outstanding.

TABLE OF CONTENTS

Item 1	Description of Business	5
Item 1A	Risk Factors	8
Item 1B	Unresolved Staff Comments	8
Item 1C	Cybersecurity	8
Item 2	Description of Property	8
Item 3	Legal Proceedings	11
Item 4	Mine Safety Disclosures	11
Item 5	Market for Common Equity and Related Stockholder Matters	12
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13
Item 7A	Qualitative and Quantitative Disclosures About Market Risk	17
Item 8	Financial Statements and Supplementary Data	17
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	17
Item 9A	Controls and Procedures	17
Item 10	Directors, Executive Officers and Corporate Governance	19
Item 11	Executive Compensation	22
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	24
Item 13	Certain Relationships and Related Transactions, and Director Independence	25
Item 14	Principal Accountant Fees and Services	25
Item 15	Exhibits and Financial Statement Schedules	26

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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 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, 2024, Royale and its consolidated subsidiaries had 11 full-time employees.

Royale Business

Royale and its subsidiaries own wells, leases, and proved and non-proved reserves of oil and 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 discovery 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, 2024, Royale continued to explore and develop oil and natural gas properties with concentration in Texas. In 2024, Royale participated in the drilling of four gross (0.0722 net) wells, which were all commercially productive. Royale’s estimated total reserves were approximately 1.8 BCFE (billion cubic feet equivalent) at both December 31, 2024 and 2023. 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 $11.0 million at December 31, 2024, based on the average Henry Hub natural gas price spot price of $2.13 per MCF and for oil volumes, the average West Texas Intermediate price of $76.32 per barrel 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.

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 our 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.

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Our standardized measure of discounted future net cash flows or “PV-10” at December 31, 2024, of our reserves was estimated to be $4,394,986. This figure was calculated by subtracting our 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 our standardized measure of discounted future net cash flow is contained in Note 17 to our Financial Statements, Supplemental Information about Oil and Gas Producing Activities (Unaudited) – Changes in Standardized Measure of Discounted Future Net Cash Flow from Proved Reserve Quantities.

Royale reported a gain on turnkey drilling in connection with the drilling of wells on a “turnkey contract” basis in the amount of $1,607,677 for the year ended December 31, 2024. For the year ended December 31, 2023, Royale reported a gain on turnkey drilling in the amount of $2,107,500. We cannot assure that gains of this type will occur in 2025 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 97% of Royale’s total revenue for the year ended December 31, 2024, came from sales of oil and natural gas from production of its wells in the amount of $2,164,241. In 2023, this amount was $2,114,026, which represented 98% 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-8.

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, 2024, Royale charged overhead from the operation of the wells in the amount of $430,680, which were an offset to general and administrative expenses. In 2023, such amount was $401,233. At December 31, 2024, Royale operated wells in California and Texas. Royale also has non-operating interests in wells in California, Texas, and Oklahoma.

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.

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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.

On September 16, 2022, California Governor Gavin Newsom signed Senate Bill No. 1137 (SB 1137) into law, prohibiting the issuance of well permits and the construction and operation of new production facilities within a “health protection zone” of 3,200 feet from certain sensitive receptors, such as homes, schools, nursing homes, or hospitals. This law also imposed additional health, safety, and environmental requirements on existing wells within these zones. We and our industry partner, RMX Resources, LLC (RMX), operate wells, production facilities, and future drilling locations within these health protection zones.

In December 2022, proponents of a voter referendum initiated a challenge to SB 1137 (the “Referendum”) and collected the requisite signatures to place SB 1137 on the November 2024 ballot. On February 3, 2023, the California Secretary of State certified that the requisite number of signatures had been submitted and validated for the Referendum to become duly qualified for the November 2024 ballot. By law, the effectiveness of a statute challenged in its entirety by a duly validated Referendum is stayed until it has been approved by the voters at the required election. Thus, the implementation of SB 1137’s provisions was stayed as of February 3, 2023, until the Referendum challenge could be resolved by a vote of the California electorate on November 5, 2024.

However, on June 27, 2024, the oil industry withdrew its referendum challenging SB 1137, allowing the law to take effect immediately. This development means that the restrictions and requirements outlined in SB 1137 are now in force, impacting our operations within the designated health protection zones. Consequently, certain undeveloped drilling locations are now restricted, and our participation in future drilling efforts with RMX within these zones is significantly deterred. Additionally, we cannot predict any future actions the State of California or other parties may take that could further limit our ability to drill in certain areas.

In September 2024, Governor Newsom signed additional laws aimed at reducing oil and gas pollution near neighborhoods, further increasing the regulatory burden affecting our operations in California.

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.

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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.

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. 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, 2024, 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 2024, Royale participated in the drilling of four gross (0.0722 net) oil wells in Texas all of which are 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, 2024, 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 February 17, 2025.

California

Royale owns interests in nine gas fields with locations ranging throughout the Sacramento Basin in California. At December 31, 2024, Royale operated 10 wells and owns interests in 13 non-operated gas wells in Northern California and 8 non-operated oil wells in Southern and Central California. Our California estimated total proven, developed, and undeveloped net reserves are approximately 0.160 BCFE, according to Royale’s independently prepared reserve report as of December 31, 2024.

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Texas

At December 31, 2024, Royale owned and operated interests in 26 oil wells in its Jameson field. Additionally, Royale owns interests in six 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 277.6 million barrels of oil equivalent (“MBOE”) , according to Royale’s independently prepared reserve report as of December 31, 2024. 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.

Developed and Undeveloped Leasehold Acreage

As of December 31, 2024, 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
California		2,401.02		1,784.84		3,097.25		996.80
All Other States		7,465.00		7,465.00		0.00		0.00
Total		9,866.02		9,249.84		3,097.25		996.80

MMBoe is one million BOE, determined using a ratio of six Mcf of natural gas equal to one BOE.

Gross and Net Productive Wells

As of December 31, 2024 and 2023, Royale owned interests in the following oil and gas wells in both gross and net:

	2024				2023
	Gross Wells		Net Wells		Gross Wells		Net Wells
Natural Gas		26		10.0838		28		10.8831
Oil		40		21.1191		38		20.8226
Total		66		31.2029		66		31.7057

Drilling Activities

The following table sets forth Royale’s drilling activities during the years ended December 31, 2024 and 2023. All wells are located in the continental U.S., in California and Texas.

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

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

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

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 paying 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.

	2024		2023
Net volume
Oil (BBL)		26,573		22,399
Gas (MCF)		116,406		128,160
MCFE		275,846		262,554

Average sales price
Oil (BBL)	$	72.83	$	74.27
Gas (MCF)	$	1.94	$	3.47

Net production costs and taxes	$	1,983,173	$	1,731,670

Lifting costs (per MCFE)	$	7.19	$	6.60

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 are routinely tested. 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 Chief Executive Officer oversaw our outside independent engineering firm, Netherland, Sewell & Associates, Inc. (“NSAI”), in connection with the preparation of their estimates of our proved reserves as of December 31, 2024. We also regularly communicate with NSAI throughout the year regarding technical and operational matters critical to our 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. Our Chief Executive Officer has over 39 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. The third-party engineering reports are also provided to our Audit Committee.

Net Proved Oil and Natural Gas Reserves

Category	Oil (MBBL)		Natural Gas (MMCF)
PROVED
Developed:
California		25.820		1.950
Texas		126.730		233.750
All other states		-		2.620
Undeveloped:
California		-		-
Texas		86.190		154.450
All other states		-		-
TOTAL PROVED		238.740		392.770
Prices used:	$	76.32	$	2.13

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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.

As of December 31, 2023, Royale had proved developed reserves of 357,940 MCF and total proved reserves of 473,540 MCF of natural gas. For the same period, Royale also had proved developed oil and NGL combined reserves of 138,060 BBL and total proved oil and NGL combined reserves of 217,780 BBL.

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% 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.

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 OTC QB Market under the symbol “ROYL.” As of December 31, 2024, 96,600,302 shares of Common Stock were held by approximately 3,052 stockholders. The following table reflects the high and low quarterly bid prices as reported on the OTC QB Market from January 2023 through December 2024:

	1st Qtr				2nd Qtr				3rd Qtr				4th Qtr
	High		Low		High		Low		High		Low		High		Low
2023	$	0.06	$	0.04	$	0.06	$	0.04	$	0.05	$	0.03	$	0.04	$	0.02
2024	$	0.07	$	0.02	$	0.07	$	0.03	$	0.08	$	0.03	$	0.07	$	0.04

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 2024 or 2023. The Board of Directors did declare dividends during 2024 and 2023 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, 2024, Royale Energy, Inc. 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

The Company 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 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 restructuring transaction, the Company also issued common stock to settle approximately $3 million in historical 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 is the Company’s analysis of its 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” 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 Policies

Revenue Recognition

Royale’s primary business is oil and gas production. Natural gas flows from the wells into gathering line systems, which are equipped occasionally with compressor systems, which in turn flow into metered transportation and customer pipelines. Monthly, price data and daily production are used to invoice customers for amounts due to Royale and other working interest owners. Royale operates most of its own wells and receives industry standard operator fees (“Supervisory Fees”). Supervisory Fees are recognized as a reduction to the Company’s General and Administrative Expenses.

Royale generally sells crude oil and natural gas under short-term agreements at prevailing market prices. Revenues are recognized when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured.

Revenues from the production of oil and natural gas properties in which the Royale has an interest with other producers are recognized on the basis of Royale’s net working interest. Differences between actual production and net working interest volumes are not significant.

The Company’s Financial Statements include its pro rata ownership of wells. The Company usually sells to third-party participants a portion of the working interest in each well it drills or participates in, and retains a portion of the prospect for its own account. All results, successful or not, are included at its pro-rata ownership amounts: revenue, expenses, assets, and liabilities as defined in FASB ASC 932-323-25 and 932-360.

Oil and Gas Property and Equipment

Depreciation, depletion and amortization, based on cost less estimated salvage value of the asset, are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired.

The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use. Interest costs, to the extent they are incurred to finance expenditures during the construction phase, are included in property, plant and equipment and are depreciated over the service life of the related assets.

Royale uses the “successful efforts” method to account for its exploration and production activities. Under this method, Royale accumulates its proportionate share of costs on a well-by-well basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred, and capitalizes expenditures for productive wells. Royale amortizes the costs of productive wells under the unit-of-production method.

Royale carries, 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 Royale is making sufficient progress assessing the reserves and the economic and operating viability of the project. 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.

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Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using unit-of-production rates based on the amount of proved developed reserves of oil and gas that are estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production method, oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank.

Production costs are expensed as incurred. Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain Royale’s wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labor costs to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity. Proved oil and gas properties held and used by Royale are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable.

Royale estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated evaluation assumptions for crude oil commodity prices. Annual volumes are based on field production profiles, which are also updated annually. Prices for natural gas and other products are based on assumptions developed annually for evaluation purposes.

Impairment analyses are generally based on proved reserves. An asset group would be impaired if the undiscounted cash flows were less than its’ carrying value. Impairments are measured by the amount the carrying value exceeds fair value. During 2024 and 2023, impairment losses of $400,719 and $1,599,001, respectively, were recorded on various capitalized lease and land costs where the carrying value exceeded the fair value or where the leases were no longer viable.

Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that Royale expects to hold the properties. The valuation allowances are reviewed at least annually.

Upon the sale or retirement of a complete field of a proved property, Royale eliminates the cost from its books, and the resultant gain or loss is recorded to Royale’s Statement of Operations. Upon the sale of an entire interest in an unproved property where the property has been assessed for impairment individually, a gain or loss is recognized in Royale’s Statement of Operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a recovery of the cost in the interest retained with any excess funds recognized as a gain. Should Royale’s turnkey drilling agreements include unproved property, total drilling costs incurred to satisfy its obligations are recovered by the total funds received under the agreements. Any excess funds are recorded as a Gain on Turnkey Drilling Programs, and any costs not recovered are capitalized and accounted for under the “successful efforts” method.

The Company sponsors turnkey drilling agreement arrangements in 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 its obligations are incurred with any excess booked against its property account to reduce any basis in its own interest. Gains on Turnkey Drilling Programs represent funds received from turnkey drilling participants in excess of all costs Royale incurs 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; and are recognized only upon making this determination after Royale’s obligations have been fulfilled.

The contracts require the participants to pay Royale the full contract price upon execution of the agreement. Royale completes the drilling activities typically between 10 and 30 days after drilling begins. The participant retains an undivided or proportional beneficial interest in the property, and is also responsible for their proportionate share of operating costs. Royale retains 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.

Since the participant’s interest in the prospect is limited to the well, and not the lease, the participant does not have a legal right to participate in additional wells drilled within the same lease. However, it is the Company’s policy to offer to participants 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 with similar turnkey drilling agreement terms.

A certain portion of the turnkey drilling participant’s funds received are non-refundable. The Company records a liability for all funds invested as deferred drilling obligations until each individual well is complete. Occasionally, drilling is delayed for various reasons such as weather, permitting, drilling rig availability and/or contractual obligations. At December 31, 2024 and 2023, Royale had deferred drilling obligations of $11,457,996 and $9,761,927 respectively.

If Royale is unable to drill the wells, and a suitable replacement well is not found, Royale 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.

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Losses on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value.

Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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. The most significant estimates pertain to proved oil, plant products and gas reserve volumes and the future development costs. Actual results could differ from those estimates.

Going Concern

At December 31, 2024, the Company has an accumulated deficit of $93,504,469, a working capital deficiency of $10,010,933 and a stockholders’ deficit of $12,329,315. As a result, our financial statements include a “going concern qualification” reflecting substantial doubt as to our ability to continue as a going concern. See Note 1 to our audited financial statements. We do not possess funds necessary to implement our 2025 budget. Royale is continuing its drilling efforts with its direct working interest owners. In addition, we are exploring commitments to provide additional financing, but there is no guarantee that we will be able to secure additional financing on acceptable terms, or at all, needed to fully fund our 2025 drilling budget and to support future operations.

Results of Operations for the Year Ended December 31, 2024, as Compared to the Year Ended December 31, 2023

For the year ended December 31, 2024, we had a net loss of $2,159,016 compared to the net loss of $1,832,187 during the year in 2023. Total revenues from operations in 2024 were $2,227,035, an increase of $66,441 or 3.1%, from the total revenues of $2,160,594 in 2023, due to higher oil production volumes due to drilling activity during 2024. Total expenses for operations in 2024 were $5,706,355, a decrease of $504,684 or 8.1%, from total expenses of $6,211,039 in 2023, mainly due to lower lease impairments during 2024.

During the year ended 2024, revenues from oil and gas production increased $50,215 or 2.4% to $2,164,241 from the 2023 revenues of $ 2,114,026. This increase was mainly due to higher oil production volumes due to 2024 drilling activity. The net sales volume of oil and condensate for the year ended December 31, 2024 was approximately 26,573 barrels of oil with an average price of $72.83 versus approximately 22,399 barrels with an average price of $74.27 per barrel, in 2023. This represents an increase in net sales volume of approximately 4,174 barrels or 18.6%, which was higher due to wells completed and put online in 2024 and at the end of 2023. The net sales volume of natural gas for the year ended December 31, 2024, was approximately 116,406 Mcf with an average price of $1.94 per Mcf, versus 128,160 Mcf with an average price of $3.47 per Mcf for the year in 2023. This represents a decrease in net sales volume of approximately 11,754 Mcf or 9.2%. The decrease in natural gas production volume was due to lower production volumes on existing wells due to natural declines.

Oil and natural gas lease operating expenses increased by $251,503 or 14.5%, to $1,983,173 for the year ended December 31, 2024, from $1,731,670 for the year in 2023. This increase was mainly due to repairs and restoration of well equipment in our Texas Jameson field due to weather related damage. When measuring lease operating costs on a production or lifting cost basis, in 2024, the $1,983,173 equates to a $7.19 per Mcfe lifting cost versus a $6.60 per Mcfe lifting cost in 2023.

The aggregate of Supervisory Fees and Other Revenue was $62,794 for year ended December 31, 2024, an increase of $16,226 or 34.8% from $46,568 during the year in 2023. This increase was mainly due to higher interest income received in 2024 due to our higher cash balances.

Depreciation, depletion and amortization expense decreased to $308,523 from $346,866, a decrease of $38,343 or 11.1% for the year ended December 31, 2024, as compared to 2023. The depletion rate is calculated using production by comparing capitalized cost to the recoverable reserves remaining. The decrease in depreciation expense was due to a increase in expected recoverable reserves which decreased the depletion rate.

General and administrative expenses decreased by $91,275 or 5.3% from $1,725,015 for the year ended December 31, 2023, to $1,633,740 in 2024. This decrease was due to lower board related expenses due to cost reduction measures and higher overhead offsets in 2024 when compared to 2023. Legal and accounting expense increased to $582,413 in 2024, compared to $435,372 in 2023, a $147,041 or 33.8% increase. This increase was primarily due to higher legal fees related to our debt facility entered into during the first quarter of 2024, and preparation of the transaction documents related to the conversion of the Series B Convertible Preferred shares described in Note 14. Marketing expense for the year ended December 31, 2024, decreased $3,381, or 1.0%, to $347,044, compared to $350,425 for the year in 2023. Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs.

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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 $4,955,045, resulting in a gain of $1,607,677. At December 31, 2023, Royale had a Deferred Drilling Obligation of $9,761,927. During 2023, we removed $6,228,038 of drilling obligations as we completed one gross (0.3176 net) oil well in our Texas Jameson field and participated in drilling and completion of two gross (0.0145 net) successful oil wells in the Texas Permian basin and one dry well in southern California, while incurring expenses of $4,120,538, resulting in a gain of $2,107,500.

During 2024, we recorded Credit Loss expense of $450,743 which arose from identified uncollectable receivables relating to our oil and natural gas properties either plugged and abandoned or scheduled for plugging and abandonment (“P&A”) and our period end oil and natural gas reserve values. We periodically review our accounts receivable from working interest owners to determine whether collection of any of these charges appears doubtful. During the period in 2024, we also recorded lease impairments of $400,719 on various lease and land costs in our California fields where the carrying value exceeded the fair value. 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. During 2023, we recorded lease impairments of $1.6 million on lease and land costs in our California fields where the carrying value exceeded the fair value. In 2023, we recorded a gain on other of $54,975 as we reconciled employee related items previously recorded as liabilities. In 2023, we also recorded a gain on other of approximately $57,000 on our share of prior years property tax refunds received by RMX Resources, LLC. During 2023, we recorded a write down of $22,690 on certain well equipment that were either written down to their current market value or written off as they were no longer useable.

Interest expense for the year ended December 31, 2024 and 2023, was $304,873 and $1,970, respectively. The higher 2024 interest expense was due to the $1.4 million note payable obtained in February 2024, discussed in Note 15 and the new notes payable related to the debt restructuring, discussed in Note 14.

In 2024 and 2023, 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, 2024, Royale had current assets totaling $10,155,158 and current liabilities totaling $20,166,091, a $10,010,933 working capital deficit. We had cash and cash equivalents at December 31, 2024 of $1,877,163 and restricted cash of $6,025,000 compared to cash and cash equivalents of $2,202,521 and restricted cash of $3,325,000 at December 31, 2023.

Ordinarily, we fund our operations and cash needs from our available credit and cash flows generated from operations. We believe there is some doubt that the Company has the ability to meet liquidity demands through cash-flow from operations. In that event, the Company will 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 with commitments to participate in the drilling and completion of several non-operated wells in the Permian Basin in Texas.

At December 31, 2024, our other receivables net, which consists of joint interest billing receivables from direct working interest participants and industry partners, totaled $868,429, compared to $1,036,401 at December 31, 2023, a $167,972 decrease. This decrease was mainly due to lower accounts receivables from payment of Joint Interest Bills by direct working interest owners for lease operating expenses of our Texas Jameson wells. At December 31, 2024, revenue receivable was $764,653, a decrease of $113,725, compared to $878,378 at December 31, 2023, due to lower uncollected production volumes and commodity prices at year end 2024 when compared to year end 2023. At December 31, 2024, our accounts payable and accrued expenses totaled $6,966,605, an increase of $1,484,531 from the accounts payable at December 31, 2023 of $5,482,074, mainly due to mainly due to higher trade payables primarily related to drilling costs during 2024.

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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, 2024 and 2023, cash used in operating activities totaled $2,210,999 and $769,919, respectively. This $1,441,080 difference in cash used was mainly due to the difference in non-cash expenses especially lease impairments, and the difference in prepayments mainly for drilling costs, when comparing 2024 and 2023.

Investing Activities. Net cash provided by investing activities totaled $3,192,264 and $2,409,291 for the years ended December 31, 2024 and 2023, respectively. The difference was due to cash receipts of approximately $8.3 million in 2024 and $7.9 million in 2023 in direct working interest turnkey investments. 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) Texas oil wells in the Permian basin. During 2023, our turnkey drilling expenditures were approximately $5.5 million as we drilled and completed one gross (0.3176 net) oil well in our Texas Jameson field and participated in the drilling and completion of two gross (0.0145 net) Texas oil wells in the Permian basin and the drilling one gross (0.5679 net) California oil well.

Financing Activities. Net cash provided by financing activities totaled $1,393,377 for the year ended December 31, 2024. Net cash used in financing activities totaled $11,985 for the year ended December 31, 2023. The difference in cash was due to receipt of $1.4 million from the note payable discussed in Note 8. During the year ended December 31, 2024 and 2023, $6,623 and $11,985, 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 17 – Supplemental Information About Oil and Gas Producing Activities (Unaudited), to our Financial Statements.

During 2023, our overall proved developed and undeveloped oil reserves decreased by 41.5% and our previously estimated proved developed and undeveloped oil reserve quantities were revised downward by approximately 185 thousand barrels. This downward revision was mainly the result of a decrease 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 58.2% and our previously estimated proved developed and undeveloped natural gas reserve quantities were revised downward by approximately 720 thousand cubic feet of natural gas. This downward revision was mainly the result of a decrease in proved undeveloped natural gas reserves from drilling locations which the Company had previously estimated. See Note 17 – Supplemental Information About Oil and Gas Producing Activities (Unaudited), to our Financial Statements.

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 effective to give reasonable assurance that information required to be publicly disclosed is recorded, processed, summarized and reported on a timely basis as of the end of the period covered by this annual report.

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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 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, 2024 due to the deficiencies described below.

Material Weakness and Remediation

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

In connection with the audit of our 2019 consolidated financial statements, management identified a material weakness that existed because we did not maintain effective controls over our financial close and reporting process, and concluded that the financial close and reporting process needed additional formal procedures to ensure there are appropriate reviews over all financial reporting analysis. Management has identified a material weakness that existed due to the lack of segregation of duties and controls, regarding our financial reporting system. Updated procedures were implemented through the close process for the year ended December 31, 2023 and 2024, but the material weakness on our financial close and reporting process was not alleviated.

We will continue to monitor these throughout 2025 to be able to fully assess whether the procedures and controls are effective.

Attestation Report of the Independent Registered Public Accounting Firm.

This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.

Changes in Internal Control over Financial Reporting

Other than the remedial activities described above, no changes in our internal control over financial reporting occurred during the year ended December 31, 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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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, 2024:

Name	Age		First Became Director or Executive Officer		Positions Held
Chris Parada ^{(1) (2)(3)(4)}		54		2021		Chairman of the Board
Jonathan Gregory ^(1)(2)(3)(4)		60		2014		Vice-Chair of the Board of Directors
Johnny Jordan		64		2018		Chief Executive and Operating officer and Director
Ronald Lipnick		64		2022		Chief Financial Officer
John Sullivan ^(1)(2)(3)(4)		66		2021		Director
Jeff Kerns ^{(1) (2)(3)(4)}		68		2021		Director
Stephen Hosmer		58		1995		Director

(1)

Members of the audit committee

(2)

Members of the compensation committee

(3)

Members of the nominations committee

(4)

Members identified as independent

The board has determined that directors John Sullivan, Chris Parada, Jonathan Gregory 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. Cornerstone is a privately held financial institution with almost $2.0 billion in assets and over $325 million of regulatory capital. 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. For over 25 years, most recently, as Managing Director - Head of Energy Finance for Legacy Texas Bank (2013-2019) where he started and built the Energy Finance team for Legacy Texas. While at Legacy Texas, Mr. Parada and the team successfully closed over $1.5 billion in transactions while he managed a team of seven professionals. Mr. Parada graduated in 1993 from Texas A&M University with a B.B.A. in Finance.

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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.

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, 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 the Company from zero production to owning and operating nearly 500 bbls of oil per day. Mr. Kerns was involved in all aspects of the Company’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.

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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.

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 36 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 2024, the members of the audit committee were John Sullivan (Chair), Jeff Kerns, Chris Parada and Jonathan Gregory.

In 2024 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 in fulfilling their responsibilities to shareholders, potential shareholders and the investment community related to executive recruitment, selection, evaluation and compensation. The Committee reviews and advises on matters involving the personnel/human resource policies of the Corporation, 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 2024, the members of the Compensation Committee were [Jeff Kerns, John Sullivan, Chris Parada, Jonathan Gregory].

In 2024, there were 0 meetings 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 (2) independent directors. A copy of the Nominating Committee charter is posted on our website, www.royl.com.

At the end of 2024, the members of the Nominating Committee were Chris Parada, John Sullivan (Chair), and Jeff Kerns, each of whom is an independent director.

In 2024, there was 1 meeting of the Nominating Committee, at which all members participated.

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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.

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 or are in process of being filed, 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 three years.

SUMMARY COMPENSATION TABLE

	Year	Salary (3)		Bonus		Option Awards		All Other Compensation (1)		Total
Johnny Jordan (2)(3)(4)	2024	$	255,769	$	-	$	-	$	10,018	$	265,787
(CEO)	2023	$	255,769	$	-	$	-	$	11,328	$	267,097

Donald Hosmer(1)	2024	$	185,175	$	81,080	$	-	$	27,930	$	294,185
(Business Development)	2023	$	185,175	$	84,475	$	-	$	18,930	$	288,580

Ronald Lipnick	2024	$	184,154	$	-	$	-	$	5,525	$	189,679
(CFO)	2023	$	194,654	$	10,500	$	-	$	5,840	$	210,994

(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 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. In 2023, Johnny Jordan received a salary of $255,769. He did not receive any bonus or option awards. His additional compensation amounted to $11,328, resulting in a total compensation of $267,097.

For 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. In 2023, Donald Hosmer’s salary was $185,175. He received a bonus of $84,475 but no option awards. His additional compensation was $18,930, resulting in a total compensation of $288,580.

Ronald Lipnick’s 2024 salary was $184,154. He received no option awards. His additional compensation was $5,525, resulting in a total compensation of $189,679. In 2023, his salary was $194,654, with a bonus of $10,500. There were no option awards, but his additional compensation amounted to $5,840, resulting in a total compensation of $210,994.

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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 2024.

Compensation Committee Report

Our executive 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 2024 or 2023, other than those listed for Donald Hosmer and Ronald Lipnick in the table above.

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Compensation of Directors

In 2024, 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 2024.

Name	Fees paid in Cash or Common Stock		Stock awards		Option awards		All Other Compensation		Total
John Sullivan	$	42,000	$	-	$	-	$	-	$	42,000
Chris Parada	$	42,000	$	-	$	-	$	-	$	42,000
Jeff Kerns	$	30,000	$	-	$	-	$	-	$	30,000
Stephen Hosmer	$	42,000	$	-	$	-	$	-	$	42,000
Jonathan Gregory	$	30,000	$	-	$	-	$	-	$	30,000

Former Board Members
Thomas M. Gladney	$	3,167	$	-	$	-	$	-	$	3,167
Mel G. Riggs	$	2,917	$	-	$	-	$	-	$	2,917

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

Common Stock

At March 8, 2025, 96,600,302 shares of the registrant’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 (3)		28,162,723		29.15	%
Jeff Kerns(5)		20,323,008		21.04	%
Stephen M. Hosmer (2)		2,820,782		2.92	%
John Sullivan		2,732,865		2.83	%
Jonathan Gregory (3)		2,256,276		2.34	%
Chris Parada		1,756,465		1.82	%
All officers and directors as a group		58,052,119		60.10	%

(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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Item 13 Certain Relationships and Related Transactions, and Director Independence

Our Chief Executive Officer, Johnny Jordan, had accrued certain unpaid salaries, at December 31, 2023, 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, 2024, the Company had a receivable balance of $20,926 due from Stephen Hosmer and $10,848 from Donald Hosmer for normal drilling and lease operating expenses.

At December 31, 2024, 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 $556,019 primarily for future plugging and abandonment costs for wells operated by RMX. At December 31, 2024, we had a total payable of $139,006 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, 2024, the balance due was $90,000. At December 31, 2024, 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 became our independent auditors for the year end December 31, 2022. The aggregate fees incurred for the years ended December 31, 2024 and 2023 are as follows:

	2024		2023
Audit fees (1)	$	250,000	$	250,000
Tax fees (2)		-		-
All other fees (3)		6,500		-
Total	$	256,500	$	250,000

(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, 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 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.
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.
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 Horne LLP
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: April 8, 2025	/s/ Johnny Jordan
	Johnny Jordan
	Chief Executive Officer

Date: April 8, 2025	/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: April 8, 2025	/s/ John Sullivan
	John Sullivan
	Chairman of the Board of Directors

Date: April 8, 2025	/s/ Jonathan Gregory
	Jonathan Gregory
	Vice-Chair of the Board of Directors

Date: April 8, 2025	/s/ Chris Parada
	Chris Parada
	Director

Date: April 8, 2025	/s/ Jeff Kerns
	Jeff Kerns
	Director

Date: April 8, 2025	/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 (PCAOB ID 171)		F-2

CONSOLIDATED BALANCE SHEETS		F-5

CONSOLIDATED STATEMENTS OF OPERATIONS		F-7

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ DEFICIT		F-8

CONSOLIDATED STATEMENTS OF CASH FLOWS		F-9

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS		F-10

F-1

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and the Board of Directors of Royale Energy, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Royale Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2024 and 2023, the related consolidated statements of operations, stockholders’ deficit and cash flows for the years then ended, and the related notes to the consolidated financial statements (collectively, the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, 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

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

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s 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 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 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 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 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 financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

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

F-2

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Estimation of Proved Reserves of Oil and Gas Properties

Critical Audit Matter Description

As described in Note 1 to the financial statements, the Company accounts for its oil and gas properties using the successful efforts method of accounting which requires management to make estimates of proved reserve volumes and future revenues and expenses to calculate depletion expense and measure its oil and gas properties for potential impairment. To estimate the volume of proved reserves and future revenues, management makes significant estimates and assumptions, including forecasting the production decline rate of producing properties and the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required in the estimation of depletion expense and potential impairment measurements. We identified the estimation of proved reserves of oil and gas properties, due to its impact on depletion expense and impairment evaluation, as a critical audit matter.

The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions necessary to estimate the volumes and future net revenues of the Company’s proved reserves require a high degree of subjectivity and could have a significant impact on the measurement of depletion expense or the impairment assessment. In turn, auditing those inputs and assumptions required subjective and complex auditor judgement.

How the Critical Audit Matter was Addressed in the Audit

We obtained an understanding of the design and implementation of management’s controls related to the estimation of proved reserves by evaluating the level of knowledge, skill, and ability of the Company’s reservoir engineering specialists and their relationship to the Company, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and reviewed the reserve report prepared by the Company’s specialists.

To the extent key, sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, such as commodity pricing, historical pricing differentials, operating costs, estimated capital costs and working and net revenue interests, we evaluated management’s process for determining the assumptions, including examining the underlying support, on a sample basis. These audit procedures, among others included the following:

●

Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials;

●

Evaluated the models used to estimate the operating costs at year-end compared to historical operating costs;

●

Compared the models used to determine the future capital expenditures and compared estimated future capital expenditures used in the reserve report to amounts expended for recently drilled and completed wells with similar locations;

●

Evaluated the working and net revenue interests used in the reserve report by inspecting a sample of ownership interest, historical pricing differentials and operating costs to underlying support from the Company’s accounting records;

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●

Evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining support for the Company’s or the operator’s ability and intent to develop the proved undeveloped properties; and

●

Applied analytical procedures to the reserve report by comparing to historical actual results and to the prior year reserve report.

Deferred Drilling Obligation and Gain on Turnkey Drilling

Critical Audit Matter Description

As described in Note 1 to the financial statements, the Company sponsors turnkey drilling 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. That obligation is reduced as costs to complete are incurred, with any excess costs booked as an increase to the Company’s property account. Gain on turnkey drilling represents funds received from turnkey drilling participants in excess of all costs the Company incurs during the drilling programs and is recognized only upon making the determination that the Company’s obligations have been fulfilled in accordance with the turnkey drilling agreement. The Company’s deferred drilling obligation was approximately $11.5 million as of December 31, 2024, and the gain on turnkey drilling was approximately $1.6 million for the year ended December 31, 2024.

Company management applies significant estimation in determining the expected cost to drill a well and to develop the well site, and significant judgment in determining when they have fulfilled their obligations under the turnkey drilling agreement triggering the recognition of turnkey gain. Both factors may impact the amount and timing of the recognition of a turnkey gain and involve a high degree of auditor judgement related to the matter. These factors were the principal considerations that led us to determine that the deferred drilling obligation and the related gain on turnkey drilling arrangements is a critical audit matter.

How the Critical Audit Matter was Addressed in the Audit

We obtained an understanding of the design and implementation of management’s controls related to the estimations in determining the expected cost to drill a well, develop the well site, and when obligations under the turnkey drilling agreements have been fulfilled. Other audit procedures involved selecting a sample of wells to test management’s estimates as follows:

●

Obtained the master worksheet for each selected well, recalculated the worksheet for clerical accuracy and selected a sample of direct working interest (“DWI”) investors;

●

Obtained the signed field subscription agreement for each selected investor in each well, verified the investment ownership amount per the signed field subscription agreement agreed to the amount invested and the number of units within the master worksheet, vouched the cash received from the DWI investors and agreed the significant terms to the related turnkey drilling agreement;

●

Obtained a schedule of costs incurred to drill the selected well, recalculated the schedule for clerical accuracy and obtained support from management to substantiate the costs incurred; and

●

Obtained evidence substantiating the timing and amount of the turnkey gain pertaining to a sample of wells drilled and assessed that the recognized turnkey gain was appropriate as defined under the terms of the related turnkey drilling agreement.

/s/ HORNE LLP

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

Ridgeland, Mississippi

April 8, 2025

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ROYALE ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

DECEMBER 31,

	2024		2023
ASSETS
Current Assets:
Cash and Cash Equivalents	$	1,877,163	$	2,202,521
Restricted Cash		6,025,000		3,325,000
Other Receivables, net		868,429		1,036,401
Revenue Receivables		764,653		878,378
Prepaid Expenses and Other Current Assets		619,913		558,169
Deferred Drilling Costs		-		1,669,149
Total Current Assets		10,155,158		9,669,618

Other Assets		589,865		589,865
Right of Use Asset - Operating Leases		238,509		254,008
Oil and Gas Properties (Successful Efforts Basis), Real Property and Equipment and Fixtures, net		4,656,659		2,401,902

Total Assets	$	15,640,191	$	12,915,393

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

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ROYALE ENERGY, INC.

CONSOLIDATED BALANCE SHEETS (Continued)

DECEMBER 31,

	2024			2023
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts Payable and Accrued Expenses	$	6,966,605		$	5,482,074
Royalties Payable		611,833			612,925
RMX Resources, LLC		23,087			23,087
Accrued Liabilities		-			215,693
Operating Leases - Current		94,070			83,230
Asset Retirement Obligation - Current		1,012,500			675,000
Deferred Drilling Obligations		11,457,996			9,761,927

Total Current Liabilities		20,166,091			16,853,936

Noncurrent Liabilities:
Asset Retirement Obligation		4,066,095			4,151,847
Notes Payable		3,489,290			-
Operating Leases - Non-current		145,644			171,439
Accrued Unpaid Guaranteed Payments		90,000			1,616,205
Accrued Liabilities - Non-current		12,386			1,306,605

Total Liabilities		27,969,506			24,100,032

Mezzanine Equity:
Convertible Preferred Stock, Series B, $10 par value, 3,000,000 Shares Authorized, 0 and 2,444,885 shares issued and outstanding at December 31, 2024 and 2023, respectively		-			24,448,850

Stockholders’ Deficit:
Common Stock, .001 Par Value, 280,000,000 Shares Authorized 96,600,302 and 70,564,188 shares issued and outstanding at December 31, 2024 and 2023, respectively		96,600			70,564

Additional Paid in Capital		81,078,554			54,619,236

Accumulated Deficit		(93,504,469	)		(90,323,289	)

Total Stockholder’s Deficit		(12,329,315	)		(35,633,489	)

Total Liabilities, Mezzanine Equity and Stockholders’ Deficit	$	15,640,191		$	12,915,393

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, 2024 AND 2023

	2024			2023
Revenues:
Sale of Oil and Gas	$	2,164,241		$	2,114,026
Supervisory Fees and Other		62,794			46,568
Total Revenues		2,227,035			2,160,594

Costs and Expenses:
Lease Operating		1,983,173			1,731,670
Impairment		400,719			1,599,001
Depreciation, Depletion and Amortization		308,523			346,866
Well Equipment Write down		-			22,690
General and Administrative		1,633,740			1,725,015
Credit Loss Expense		450,743			-
Legal and Accounting		582,413			435,372
Marketing		347,044			350,425
Total Costs and Expenses		5,706,355			6,211,039

Gain on Turnkey Drilling Programs		1,607,677			2,107,500

Loss from Operations		(1,871,643	)		(1,942,945	)

Other Income (Expense):
Interest Expense		(304,873	)		(1,970	)
Gain on Sale of Assets		17,500			-
Other Gain		-			112,728
Total Other Income (Expense)		(287,373	)		110,758
Net Loss		(2,159,016	)		(1,832,187	)

Basic and Diluted Loss Per Share	$	(0.05	)	$	(0.04	)

Weighted average number of common shares outstanding, basic and diluted		77,278,047			65,758,185

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, 2024 AND 2023

	Common Stock
	Number Shares Issued and Outstanding		Amount		Additional Paid in Capital			Accumulated Comprehensive Deficit			Total Stockholders’ Deficit
Balance, December 31, 2022		61,876,957	$	61,876	$	54,447,923		$	(87,646,402	)	$	(33,136,603	)
Cashless Warrant Exercise Issuance		3,266,055		3,266		(3,266	)		-			-
Stock issued in lieu of Cash Compensation		5,421,176		5,422		174,579			-			180,001
Preferred Series B 3.5% Dividend		-		-		-			(844,700	)		(844,700	)
Net Loss		-		-		-			(1,832,187	)		(1,832,187	)
Balance, December 31, 2023		70,564,188		70,564		54,619,236			(90,323,289	)		(35,633,489	)
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		$	(93,504,469	)	$	(12,329,315	)

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, 2024 AND 2023

	2024			2023
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Loss	$	(2,159,016	)	$	(1,832,187	)
Adjustments to Reconcile Net Loss to Net Cash Used by Operating Activities:
Depreciation, Depletion, and Amortization		308,523			346,866
Impairment		400,719			1,599,001
Gain on Sale of Assets		(17,500	)		-
(Gain) Loss on Turnkey Drilling Programs		(1,607,677	)		(2,107,500	)
Credit Loss Expense		450,743			-
Other Gain		-			(112,728	)
Well Equipment Write Down		-			22,690
Stock-Based Compensation		35,999			180,001
Accretion of Debt Restructure Note Payable Interest		31,514			-
Right of Use Asset Depreciation		7,167			11,006
(Increase) Decrease in:
Other & Revenue Receivables		(169,046	)		(269,209	)
Prepaid Expenses and Other Assets		(44,244	)		1,491,740
Increase (Decrease) in:
Accounts Payable and Accrued Expenses		552,911			(99,599	)
Royalties Payable		(1,092	)		-
Net Cash Used in Operating Activities		(2,210,999	)		(769,919	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for Oil and Gas Properties		(5,066,527	)		(5,450,709	)
Proceeds from Turnkey Drilling Programs		8,258,791			7,860,000
Net Cash Provided by Investing Activities		3,192,264			2,409,291

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from Long-Term Debt		1,400,000			-
Principal Payments on Long-Term Debt		(6,623	)		(11,985	)
Net Cash Provided by (Used in) Financing Activities		1,393,377			(11,985	)

Net Increase in Cash, Cash Equivalents, and Restricted Cash		2,374,642			1,627,387

Cash, Cash Equivalents, and Restricted Cash at Beginning of Year		5,527,521			3,900,134

Cash, Cash Equivalents, and Restricted Cash at End of Year	$	7,902,163		$	5,527,521
Cash Paid for Interest	$	273,360		$	1,970

Cash Paid for Taxes	$	8,150		$	10,427

Supplemental Schedule of Non-Cash Investing and Financing Transactions:
Asset Retirement Obligation Addition	$	-		$	37,260
(Decrease) Increase in Capital Accrued Balance	$	(68,380	)	$	165,572
Series B Paid-In-Kind Dividends	$	-		$	844,700
Conversion of Preferred Stock to Common	$	24,664,543		$	-
Issuance of Notes Payable in Settlement of Liability	$	2,057,777		$	-

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”) 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, 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 16 – 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

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 2024 consolidated financial statements reflect a working capital deficiency of $10,010,933, an accumulated deficit of $93,504,469 and a net loss of $2,159,016. 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.

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.

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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 based on guidance codified as under the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 230-10-50-8. In the event that progress payments are made from these funds; they are recorded as Prepaid Expenses and Other Current Assets.

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

	Year Ended December 31,
	2024		2023
Cash and cash equivalents	$	1,877,163	$	2,202,521
Restricted cash		6,025,000		3,325,000
Total cash, cash equivalents, and restricted cash shown in the statement of cash flows	$	7,902,163	$	5,527,521

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, 2024 and 2023, we established an allowance for expected credit loses of $2,194,552 and $1,837,551, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue.

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, 2022	$	2,757,549
Provision for credit loss		0
Write-offs charged against the allowance		919,998
Balance at December 31, 2023	$	1,837,551

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

Equity Method Investments

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

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

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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,
	2024		2023
Oil & Condensate Sales	$	1,935,414	$	1,663,546
Natural Gas Sales		225,261		445,111
NGL Sales		3,566		5,369
	$	2,164,241	$	2,114,026

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.

Under our hydrocarbon sales agreements, the entire consideration amount is variable either due to pricing and/or volumes. We recognize revenues in the amount of variable consideration allocated to distinct units of hydrocarbons transferred to a customer. Such allocation reflects the amount of total consideration we expect to collect for completed deliveries of hydrocarbons and the terms of variable payment relate specifically to our efforts to satisfy the performance obligations under these contracts. Our performance obligations under our hydrocarbon sales agreements are to deliver either the entire production from the dedicated wells or specified contractual volumes of hydrocarbons.

We often serve as the operator for jointly owned oil and gas properties. As part of this role, we perform activities to explore, develop and produce oil and gas properties in accordance with the joint operating arrangement and collective decisions of the joint parties. Other working interest owners reimburse us for costs incurred based on our agreements. We determined that these activities are not performed as part of customer relationships, and such reimbursements are recorded as cost reimbursements.

We commonly market the share of production belonging to other working interest owners as the operator of jointly owned oil and gas properties. Those marketing activities are carried out as part of the collaborative arrangement, and we do not purchase or otherwise obtain control of other working interest owners’ share of production. Therefore, we act as a principal only 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 Turnkey Drilling Obligations. Once the contracted depth for the drilling of the well is reached and a determination as to the commercial viability of the well (typically call “Casing Point Election” or “Logging Point”), the difference in the actual cost to drill and the guaranteed cost is recorded as income or expense depending on whether there was a gain or loss.

Crude oil and condensate

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

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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.

Supervisory Fees and Other

For the years ended December 31, 2024 and 2023, we recognized $62,794 and $46,568, respectively in supervisory fees in Pipeline and Compressor fees which were received and allocated based on production volumes.

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.

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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

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 2024 we recorded impairment losses of $400,719, on various capitalized lease and land costs where the carrying value exceeded the estimated fair value. In 2023 we recorded impairment losses of $1,599,001. Of this amount $1,292,502 was impaired as a result of increased abandonment cost estimates and increases working interest in those costs.

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.

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).

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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.

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, 2024 and 2023, we had Deferred Drilling Obligations of $11,457,996 and $9,761,927, respectively. 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. During 2023, we disposed of $6,228,038 of drilling obligations as we completed one gross (0.3176 net) oil well in our Texas Jameson field and participated in drilling and completion of two gross (0.0145 net) successful oil wells in the Texas Permian basin and one gross (0.05679 net) dry well in southern California, while incurring expenses of $4,120,538, resulting in a gain of $2,107,500.

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,
	2024						2023
	Basic			Diluted			Basic			Diluted
Net Loss	$	(2,159,016	)	$	(2,159,016	)	$	(1,832,187	)	$	(1,832,187	)
Less: Preferred Stock Dividend		653,730			653,730			844,700			844,700
Less: Non-Cash Restructuring Inducements		674,341			674,341			-			-
Net Loss Attributable to Common Shareholders		(3,487,087	)		(3,487,087	)		(2,676,887	)		(2,676,887	)
Weighted average common shares outstanding		77,278,047			77,278,047			65,758,185			65,758,185
Effect of dilutive securities		-			-			-			-
Weighted average common shares, including Dilutive effect		77,278,047			77,278,047			65,758,185			65,758,185
Per share:
Net Loss	$	(0.05	)	$	(0.05	)	$	(0.04	)	$	(0.04	)

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For the year ended December 31, 2023, Royale Energy had dilutive securities of 24,448,850. These securities were not included in the dilutive loss per share due to their antidilutive nature.

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.

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, 2024, we do not have any financial assets measured and recognized at fair value on a recurring basis. However, we have financial liabilities, including outstanding notes, measured at fair value on a nonrecurring basis.

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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 fair value of the notes issued in connection with the restructuring was $1,846,613 for notes related to the Preferred Stock conversion and $211,163 for notes related to liability extinguishment, which represents a discount to the face value of the notes.

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.

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, 2024 and 2023, the components of accounts payable and accrued expenses consisted of:

	2024		2023
Trade Payables including accruals	$	3,946,583	$	2,736,661
Direct working interest investors related accruals		2,322,690		1,978,542
Current drilling efforts accrued expenses		120,102		188,482
Accrued Liabilities		400,296		400,296
Employee related accruals		169,079		170,312
Deferred rent		7,855		7,781
	$	6,966,605	$	5,482,074

Accrued – Non-current

At December 31, 2024, we had non-current accrued liabilities of $12,386 and accrued unpaid guaranteed payment of $90,000, compared to accrued liabilities of $1,306,605 and accrued unpaid guaranteed payment of $1,616,205 as of December 31, 2023. 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.

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Changes in Accounting Standards

Recently Issued, Not Yet Adopted

In December 2023, FASB issued Accounting Standards Update (ASU) No. 2023-09, “Improvements to Income Tax Disclosures,” issued by the Financial Accounting Standards Board (FASB). ASU 2023-09 requires enhanced disclosures around income taxes, including additional detail regarding the rate reconciliation and the presentation of income taxes paid, to provide financial statement users with more transparent information about tax exposures and cash flow implications. While we are still evaluating the implications of this standard, the adoption of ASU 2023-09 should not materially impact our financial position, results of operations, or cash flows, as the update affects disclosures only.

NOTE 2 – OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES

Oil and gas properties, equipment and fixtures consist of:

	Year ended December 31,
	2024			2023
Oil and Gas
Producing properties, including intangible drilling costs	$	5,764,761		$	5,763,892
Undeveloped properties		3,339,234			778,839
Lease and well equipment		3,295,028			3,295,028
		12,399,023			9,837,759
Accumulated depletion, depreciation and amortization		(7,748,190	)		(7,443,661	)
Net capitalized costs Total	$	4,650,833		$	2,394,098

Commercial and Other		2024			2023
Vehicles	$	40,061		$	40,061
Furniture and equipment		1,103,362			1,103,362
		1,143,423			1,143,423
Accumulated depreciation		(1,137,597	)		(1,135,619	)
		5,826			7,804
Net capitalized costs Total	$	4,656,659		$	2,401,902

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,
	2024		2023
Acquisition - Proved		-		-
Acquisition - Unproved		-		-
Development		4,955,045		4,120,538
Exploration		-		-

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 did not make any additions to capitalized exploratory well costs pending a determination of proved reserves during 2024 and 2023. We did not charge any previously capitalized exploratory well costs to expense upon adoption of Topic. Undeveloped properties are not subject to depletion, depreciation or amortization.

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,
	2024			2023
Oil and gas sales	$	2,164,241		$	2,114,026
Production related costs (Lease Operating)		(1,983,173	)		(1,731,670	)
Impairment		(400,719	)		(1,599,001	)
Depreciation, depletion and amortization		(308,524	)		(346,866	)

Results of operations from producing and exploration activities	$	(528,175	)	$	(1,563,511	)
Income Taxes (Benefit)		-			-

Net Results	$	(528,175	)	$	(1,563,511	)

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NOTE 3 – ASSET RETIREMENT OBLIGATION

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 measured 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. There were no changes in estimates for the years ended December 31, 2024 and 2023.

	2024			2023
Asset retirement obligation
Beginning of the year	$	4,826,847		$	3,542,479
Liabilities incurred during the period		865			37,260
Settlements		(151,856	)		(141,751	)
Changes in Working Interest		(4,716	)		348,109

Changes in estimates		405,440			996,853
Accretion expense		2,015			43,897
End of year	$	5,078,595		$	4,826,847

We record accretion expense as part of Depreciation, Depletion and Amortization. Accretion expense was $2,015 and $43,897 for the years ended December 31, 2024 and 2023, respectively.

NOTE 4 – INCOME TAXES

Deferred tax assets and liabilities reflect the net tax effect of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and amounts used for income tax purposes. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more-likely-than-not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.

Significant components of our deferred assets and liabilities at December 31, 2024 and 2023, respectively, are as follows:

	2024			2023
Deferred Tax Assets (Liabilities):
Statutory Depletion Carry Forward	$	310,903		$	310,903
Net Operating Loss		9,288,524			9,171,527
Other		734,888			668,815
Share-Based Compensation		86,510			86,510
Capital Loss / AMT Credit Carry Forward		9,458			9,458
Charitable Contributions Carry Forward		2,743			2,702
Allowance for Doubtful Accounts		571,022			478,131
Oil and Gas Properties and Fixed Assets		5,364,825			5,088,608
Investment in RMX Joint Venture		123,640			67,371
		16,492,513		$	15,884,025
Valuation Allowance		(16,492,513	)		(15,884,025	)
Net Deferred Tax Asset	$	-		$	-

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As of December 31, 2024, 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, begin to expire in the year 2026. We have $13.1 million net operating loss carryforwards generated after December 31, 2017, which can be carried forward indefinitely.

A reconciliation of our provision for income taxes and the amount computed by applying the statutory income tax rates at December 31, 2024 and 2023, respectively, to pretax income is as follows:

	2024			2023
Tax (benefit) computed at statutory rate of 21% at December 31, 2023 and 2022, respectively	$	(453,393	)	$	(384,759	)

Increase (decrease) in taxes resulting from:
Meals & Entertainment		915			1,233
Prior-year true-up for Books		5,201			33,539
Deferred State Taxes, net of federal benefit		(161,211	)		(499,164	)
Other non-deductible expenses		-			10,859
Change in valuation allowance		608,488			838,292
Provision (benefit)	$	-		$	-

As of December 31, 2024, 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 2019 through 2023 remain open to examination by the tax jurisdictions in which we file income tax returns.

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 2023 and 2024, the board authorized the payment of each quarterly dividend of Series B Convertible Preferred shares, as Paid-In-Kind shares (“PIK”) to be paid immediately following the end of the quarter. For the year ended December 31, 2023, we issued 62,899 shares with a value of $629,007. During 2024 and 2023, 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.

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NOTE 6 – COMMON STOCK

During the years 2024 and 2023, 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. In April 2023, CIC RMX LP (“CIC”) exercised in full its warrant to purchase shares or our common stock. CIC elected to make a cashless exercise of warrant and as a result we issued 3,266,055 shares of our common stock to CIC.

NOTE 7 – LEASES

During 2024, we had one office lease at 1530 Hilton Head Road, El Cajon, California, 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 at 104 W. Anapamu, Santa Barbara, California, the location of our CEO and engineering team for $5,100 per month.

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 of those assets in transition. 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.

Lease expense for operating as well as finance leases are included in General and Administrative expense and Interest Expense on the Consolidated Statement of Operations, while the lease expense for those leases that are short-term are included in Oil and Gas Lease Operating Expenses. The amounts are as follows:

	Year ended December 31,
	2024		2023
Operating lease expense	$	161,858	$	161,858
Financing lease expense		17,567		17,322
Short Term - field		6,000		6,000
Total lease expense	$	185,425	$	185,180

The following tables summarized the operating and financing lease obligations.

Our two office leases do not contain implicit interest rates that can be readily determined. As a result, we used the available risk-free rate plus 4 basis points. At December 31, 2024 the weighted average annual discount rate was 4.83% and the term was 4 years.

NOTE 8 – RELATED-PARTY TRANSACTIONS

At December 31, 2024, we had a receivable balance of $20,926 due from Stephen Hosmer, a director and corporate secretary, for normal drilling and lease operating expenses.

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At December 31, 2024 and 2023, we had a total payable 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. For the same periods, we also had prepaid expenses and other current assets, and deferred drilling costs with RMX of $556,019 and $382,520, respectively. In 2023, the prepaid amount was for future plugging and abandonment costs. During 2024, RMX operated various oil wells we have interests in, from which we received revenues of approximately $372,000 and incurred lease operating costs of approximately $168,390. At December 31, 2024 and 2023, we had a total revenue receivables of $108,344 and $120,634, respectively, due from RMX and its subsidiary, Matrix Oil Corporation.

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, 2024, the balance due was $90,000. At December 31, 2024, Royale also had accrued unpaid liabilities of $12,386 due to a certain former Matrix employee for periods predating his employment.

Michael McCaskey, a former director, and Jeffery Kerns, a current director, and Stephen Hosmer, a current director, each have consulting agreements to provide services as directed and at our discretion. At December 31, 2024 and 2023, we had total payables of $139,006 and $164,669, respectively, owed to current and former board members for directors fees.

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 29.2% of the Company’s issued and outstanding common stock. The initial loan to the Company was $1,400,000 which was received on February 9, 2024. The outstanding principal balance of the loan has an annual interest rate of 18.00%. On November 1, 2024 the maturity was extended from August 1, 2025 to January 1, 2026.

NOTE 9 – STOCK COMPENSATION PLAN

There were no stock options issued during 2024 and 2023.

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, 2024 and 2023, were $28,653 and $26,051 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 2024 or 2023.

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. We normally sell approximately 45% 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.

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, 2023, and 2022. At December 31, 2024 and 2023, cash in banks exceeded the FDIC limits by approximately $7.6 million and $5.3 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.

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We sponsor turnkey drilling agreement arrangements in proved and unproved properties as a pooling of assets in a joint undertaking, whereby proceeds from participants are reported as Deferred Drilling Obligations. 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, stock options, and senior promissory notes in exchange for the retirement of all outstanding Series B Preferred Shares as of June 30, 2024. The preferred holders waived the payment of any unpaid dividends.

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

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, totalling $1.85 million. These notes bear an interest rate of 0% until December 31, 2025, increasing to 5% through 2027 and 8% through June 30, 2029, when all principal and interest is due.

Issuance of Warrants – As part of the exchange, Royale issued 25 million warrants with an exercise price of $0.10 per share, expiring on June 30, 2029. The fair value of the warrants was determined to be $959,637 using a Black-Scholes-Merton model.

Transfer of Additional Assets – The Company transferred a 0.5% overriding royalty interest (ORRI) in an Alaskan property and three parcels of Bellevue, Kern County real estate to a holding entity controlled by the Preferred Shareholders. The real estate was assigned a fair value of $368,434, which was recognized as an inducement to convert the preferred shares.

Settlement of Historical Liabilities – Royale also settled approximately $3 million in pre-merger obligations by issuing additional common stock and promissory notes.

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

As of December 31, 2024, the Company had 96,600,302 shares of common stock outstanding, and no preferred shares issued or outstanding.

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.

NOTE 15 – Notes Payable

On February 7, 2024 the board of directors approved a debt facility of up to $3 million. On February 9, 2024, Royale Energy, Inc. entered into a Secured Term Loan Note with Walou Investments, LP, a Texas limited partnership, which is under the 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 29.15% of the Company’s issued and outstanding common stock. The initial loan to the Company was $1,400,000 which was received on February 9, 2024. The outstanding principal balance of the loan has an interest rate of 18.00%. On November 1, 2024 the maturity was extended from August 1, 2025 to January 1, 2026.

In connection with the restructuring transaction described in Note 14, we issued 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.

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NOTE 16 – 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 $11.0 million at December 31, 2024, based on the average Henry Hub natural gas price spot price of $2.130 per MCF and for oil volumes, the average West Texas Intermediate price of $76.32 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.

Changes in Estimated Reserve Quantities

The net interest in estimated quantities of proved developed reserves of crude oil and natural gas at December 31, 2024 and 2023, and changes in such quantities during each of the years then ended, were as follows:

Total Proved Reserves
	2024						2023
	Oil (BBL)			Gas (MCF)			Oil (BBL)			Gas (MCF)

Beginning of period		217,780			473,540			372,300			1,133,300
Revisions of previous estimates		32,490			4,115			(185,261	)		(720,023	)
Production		(26,573	)		(116,406	)		(22,399	)		(128,160	)
Extensions, discoveries and improved recovery		15,043			31,511			53,140			188,423
Merger Acquisition		-			-			-			-
Purchase of minerals in place		-			-			-			-
Sales of minerals in place		-			-			-			-

Proved reserves end of period		238,740			392,760			217,780			473,540

Proved Developed
	2024				2023
	Oil (BBL)		Gas (MCF)		Oil (BBL)		Gas (MCF)
Proved developed reserves:

Beginning of period		138,060		357,940		182,000		942,000

End of period		152,550		238,310		138,060		357,940

F-24

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Proved Undeveloped
	2024				2023
	Oil (BBL)		Gas (MCF)		Oil (BBL)		Gas (MCF)
Proved undeveloped reserves:

Beginning of period		79,720		115,600		190,300		191,300

End of period		86,190		154,450		79,720		115,600

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The future net cash inflows are developed as follows:

	●	Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions.
	●	The estimated future production of proved reserves is priced on the basis of year-end prices.
	●	The resulting future gross revenue streams are reduced by estimated future costs to develop and to produce proved reserves, based on year-end estimates. Estimated future development costs by year are as follows:

2025	$	34,600
2026		-
2027		-
Thereafter		-
	$	34,600

The resulting future net revenue streams are reduced to present value amounts by applying a 10 percent discount.

Disclosure of principal components of the standardized measure of discounted future net cash flows provides information concerning the factors involved in making the calculation. In addition, the disclosure of both undiscounted and discounted net cash flows provides a measure of comparing proved oil and gas reserves both with and without an estimate of production timing. The standardized measure of discounted future net cash flow relating to proved reserves reflects estimated income taxes.

Changes in standardized measure of discounted future net cash flow from proved reserve quantities

The standardized measure of discounted future net cash flows is presented below for the years ended December 31, 2024, and 2023.

F-25

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This statement discloses the sources of changes in the standardized measure from year to year. The amount reported as “Net changes in prices and production costs” represents the present value of changes in prices and production costs multiplied by estimates of proved reserves as of the beginning of the year. The “accretion of discount” was computed by multiplying the 10 percent discount factor by the standardized measure on a pretax basis as of the beginning of the year. The “Sales of oil and gas produced, net of production costs” are expressed in actual dollar amounts. “Revisions of previous quantity estimates” is expressed at year-end prices. The “Net change in income taxes” is computed as the change in present value of future income taxes.

	2024			2023
Future cash inflows	$	17,957,800		$	17,559,800
Future production costs		(6,884,900	)		(6,860,800	)
Future development costs		(34,600	)		(8,200	)
Future income tax expense		(3,311,490	)		(3,207,240	)

Future net cash flows		7,726,810			7,483,560

10% annual discount for estimated timing of cash flows		(3,331,824	)		(3,011,664	)

Standardized measure of discounted future net cash flows		4,394,986			4,471,896

Sales of oil and gas produced, net of production costs		(538,336	)		(322,560	)

Revisions of previous quantity estimates		(78,051	)		(10,359,602	)
Net changes in prices and production costs		624,047			946,740
Extensions, discoveries and improved recovery		461,377			2,067,392
Accretion of discount		(578,909	)		(602,094	)

Net change in income tax		32,962			2,481,037

Net increase (decrease)	$	(76,910	)	$	(5,789,087	)

Future Development Costs

In order to realize future revenues from our proved reserves estimated in our reserve report, it will be necessary to incur future costs to develop and produce the proved reserves. The following table estimates the costs to develop and produce our proved reserves in the year 2025.

	2025
Future development cost of:
Proved developed reserves (PDP)	$	-
Proved non-producing reserves (PDNP)		34,600
Proved undeveloped reserves (PUD)		-

Total	$	34,600

Common assumptions include such matters as the real extent and average thickness of a particular reservoir, the average porosity and permeability of the reservoir, the anticipated future production from existing and future wells, future development and production costs and the ultimate hydrocarbon recovery percentage. As a result, oil and gas reserve estimates and discounted present value estimates are frequently revised in subsequent periods to reflect production data obtained after the date of the original estimate. If the reserve estimates are inaccurate, production rates may decline more rapidly than anticipated, and future production revenues may be less than estimated.

Additional data relating to our oil and natural gas properties is disclosed in Supplemental Information About Oil and Gas Producing Activities (Unaudited), attached to our Financial Statements, in Note 15.

Historic Development Costs for Proved Reserves

In each year we expend funds to drill and develop some of our proved undeveloped reserves. We have incurred no cost in any of the past three fiscal years to drill and develop reserves that were classified as proved undeveloped reserves as of December 31 of the immediately preceding year.

F-26

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Royale Energy, Inc. 10-K