UNITED
STATES

 SECURITIES
AND EXCHANGE COMMISSION

 Washington,
D.C. 20549

 FORM

 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)

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

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

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

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.

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.

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).

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

 Item 1A

 Risk Factors

 Item 1B

 Unresolved Staff Comments

 Item 1C

 Cybersecurity

 Item 2

 Description of Property

 Item 3

 Legal Proceedings

 Item 4

 Mine Safety Disclosures

 Item 5

 Market for Common Equity and Related Stockholder Matters

 Item 7

 Management's Discussion and Analysis of Financial Condition and Results of Operations

 Item 7A

 Qualitative and Quantitative Disclosures About Market Risk

 Item 8

 Financial Statements and Supplementary Data

 Item 9

 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 Item 9A

 Controls and Procedures

 Item 10

 Directors, Executive Officers and Corporate Governance

 Item 11

 Executive Compensation

 Item 12

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

 Item 13

 Certain Relationships and Related Transactions, and Director Independence

 Item 14

 Principal Accountant Fees and Services

 Item 15

 Exhibits and Financial Statement Schedules

 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 ( 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.

 ROYALE
ENERGY, INC.

 PART
I

 Item
1 Description of Business

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.

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.

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.

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.

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.

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

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.

 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.

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

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.

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.

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.

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.

 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
Royale also provides access to its SEC reports and other public announcements on its website,  The information on
our website is not part of this Annual Report on Form 10-K.

 Item
1A Risk Factors

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

 Item
 1B Unresolved Staff Comments

 None.

 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

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.

 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

 10.0838

 10.8831

 Oil

 21.1191

 20.8226

 Total

 31.2029

 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

 Developmental

 0.3321

 0.5679

 2024

 Exploratory

 Developmental

 0.0722

 a)
 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.

 b)
 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%.

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

 d)
 A
dry well is a well that is not deemed capable of producing hydrocarbons in paying quantities.

 e)
 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.

 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

 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.

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

 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

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:

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.

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.

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.

 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

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.

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.

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.

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.

 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.

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.

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.

 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.

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.

 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.

 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.

in Reserve Estimates

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.

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.

 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.

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.

 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)

 2021

 Chairman of the Board

 Jonathan Gregory (1)(2)(3)(4)

 2014

 Vice-Chair of the

Board of Directors

 Johnny Jordan

 2018

 Chief Executive and

Operating officer

and Director

 Ronald Lipnick

 2022

 Chief Financial Officer

 John Sullivan (1)(2)(3)(4)

 2021

 Jeff Kerns (1) (2)(3)(4)

 2021

 Stephen Hosmer

 1995

 (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.

 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.

 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.

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.

 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

 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.

 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.

 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

 $

 $
 -

 $
 -

 $
 -

 $

 Chris Parada

 $

 $
 -

 $
 -

 $
 -

 $

 Jeff Kerns

 $
 30,000

 $
 -

 $
 -

 $
 -

 $
 30,000

 Stephen Hosmer

 $

 $
 -

 $
 -

 $
 -

 $

 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.

 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.

 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

 101.SCH

 101.CAL

 101.DEF

 101.LAB

 101.PRE

 *
 Filed herewith.

 Management contract or compensatory
plan or arrangement.

 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.

 /s/ Johnny Jordan

 Johnny Jordan

 Chief Executive Officer

 /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.

 /s/ John Sullivan

 John Sullivan

 Chairman of the Board of Directors

 /s/ Jonathan Gregory

 Jonathan Gregory

 Vice-Chair of the Board of Directors

 /s/ Chris Parada

 Chris Parada

 /s/ Jeff Kerns

 Jeff Kerns

 /s/ Stephen Hosmer

 Stephen Hosmer

 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 AND SUPPLEMENTARY DATA

 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM (PCAOB ID 171)

 CONSOLIDATED BALANCE SHEETS

 CONSOLIDATED STATEMENTS OF OPERATIONS

 CONSOLIDATED STATEMENTS OF STOCKHOLDERS' DEFICIT

 CONSOLIDATED STATEMENTS OF CASH FLOWS

 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 F- 1

 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

 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;

 F- 3

 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

 F- 4

 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

 F- 5

 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

 F- 6

 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

 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

)

)

 Basic and Diluted Loss Per Share

 $
 ( 0.05
)

 $
 ( 0.04
)

 Weighted average number of common shares outstanding, basic and diluted

 F- 7

 CONSOLIDATED STATEMENTS OF
STOCKHOLDERS ' DEFICIT

 FOR THE YEARS ENDED DECEMBER 31, 2024 AND 2023

 Common Stock

 Number

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

)

 -

 -

 -

)

)

 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

 -

 -

 -

)

)

 Balance, December 31, 2024

 96,600,302

 $

 96,600

 $

 81,078,554

 $

 ( 93,504,469

)

 $

 ( 12,329,315

)

 F- 8

 CONSOLIDATED STATEMENTS OF CASH FLOWS

 FOR THE YEARS ENDED DECEMBER 31, 2024 AND 2023

 2024

 2023

 CASH FLOWS FROM OPERATING ACTIVITIES:

 $
)

 $
)

 Adjustments to Reconcile Net Loss to Net Cash Used by Operating Activities:

 Depreciation, Depletion, and Amortization

 308,523

 346,866

 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

 $
 -

 F- 9

 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.

 F- 10

 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

 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.

 F- 11

 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.

 F- 12

 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.

 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.

 F- 13

 Production Cost

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

 Depreciation, Depletion and Amortization

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

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

 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).

 F- 14

 Turnkey Drilling

 We sponsor turnkey drilling agreement arrangements in proved and unproved
properties as a pooling of assets in a joint undertaking, whereby proceeds from participants are reported as Deferred Drilling Obligations,
and then reduced as costs to complete our obligations and are incurred with any excess booked against our property account to reduce any
basis in our own interest. Gains on Turnkey Drilling Programs represent funds received from turnkey drilling participants in excess of
all costs we incur during the drilling programs (e.g., lease acquisition, exploration and development costs), including costs incurred
on behalf of participants and costs incurred for our own account; and are recognized only upon making this determination after our obligations
have been fulfilled.

 The contracts require the participants pay us the full contract price
upon execution of the agreement. We complete the drilling activities typically between 10 and 30 days after drilling begins. The participant
retains an undivided or proportional beneficial interest in the property, and is also responsible for its proportionate share of operating
costs. We retain legal title to the lease. The participants purchase a working interest directly in the well bore.

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

 A certain portion of the turnkey drilling participant's funds
received are non-refundable. We hold all funds invested as Deferred Drilling Obligations until drilling is complete. Occasionally, drilling
is delayed for various reasons such as weather, permitting, drilling rig availability and/or contractual obligations. At December 31,
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

 $
)

 $
)

 $
)

 $
)

 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

 Effect of dilutive securities

 -

 -

 -

 -

 Weighted average common shares, including Dilutive effect

 Per share:

 $
 ( 0.05
)

 $
 ( 0.05
)

 $
 ( 0.04
)

 $
 ( 0.04
)

 F- 15

 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.

 F- 16

 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.

 F- 17

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
)

 ( 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
)

 F- 18

 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

 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

 $
 -

 $
 -

 F- 19

 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

 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.

 F- 20

 NOTE
6 – COMMON STOCK

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

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

 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.

 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.

 F- 21

 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.

 F- 22

 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:

 1.
 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.

 2.

 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.

 3.
 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.

 4.
 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.

 5.
 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.

 F- 23

 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.

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

 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

 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

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.

 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.

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

 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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