What changed in this filing

/stocks — the workspaceLOADING

Item 5. Market for Registrant’s Common Equity

2026-07-13 compared with 2025-04-09 · 280 added, 338 removed, 5 unchanged (99% of the section changed)

5 Market for Common Equity and Related Stockholder Matters

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:

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.

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

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.

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

Company issued 1,299,641 shares of common stock to its officers, directors, and consultants in lieu of cash compensation for services

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

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

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.

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.

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

Discussion and Analysis is the Company’s analysis of its financial performance and of significant trends that may affect future

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

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.

Accounting Policies

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.

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

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

revenue, expenses, assets, and liabilities as defined in FASB ASC 932-323-25 and 932-360.

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.

and repairs, including planned major maintenance, are expensed as incurred.

Major renewals and improvements are capitalized and the assets

replaced are retired.

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

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.

costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves.

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.

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.

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.

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.

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.

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;

recognized only upon making this determination after Royale’s obligations have been fulfilled.

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.

participants purchase a working interest directly in the well bore.

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.

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.

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.

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.

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.

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

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.

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.

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

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.

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.

Item 5 Market for Common Equity and Related Stockholder Matters

There is no established trading market for Royale’s Common Stock,

which is quoted on the OTCQB Market under the symbol “ROYL.” As of June 30, 2025, 96,600,302 shares of Common Stock were held

by approximately 3,052 stockholders of record.

The following table reflects the high and low quarterly bid prices as reported on

the OTCQB Market from January 2024 through December 2025:

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.

The board of directors did not declare cash dividends in either 2025

The board of directors did declare dividends during 2024 on the preferred stock to be Paid In Kind (“PIK”) of 65,372

and 84,470 shares with a respective par value of $653,730 and $844,700, as more fully set forth in Note 5 to our Financial Statements.

Recent Sales of Unregistered Securities

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

unregistered securities.

During the fiscal year ended December 31, 2024, we issued the following

unregistered securities in transactions exempt from registration under the Securities Act of 1933, as amended, pursuant to Section 4(a)(2)

and/or Regulation D thereunder:

Shares Issued for Compensation

Royale issued 1,299,641 shares of common stock to its officers, directors,

and consultants in lieu of cash compensation for services rendered.

These shares were issued at prevailing market prices or pursuant to

existing contractual arrangements, and no underwriters or selling agents were involved.

Shares Issued Upon Conversion of Preferred Stock

On October 11, 2024, Royale completed a significant equity restructuring

in which it issued 22,198,095 shares of common stock to former holders of Series B 3.5% Convertible Preferred Stock, representing approximately

90% of the total preferred stock retired.

Additionally, 2,538,378 shares were issued for conversion of accrued preferred dividends, resulting

in a total of 24,736,473 shares issued related to the preferred equity conversion.

Shares Issued Upon Conversion of Debt

As part of the same, October 11, 2024 restructuring transaction, the

Company also issued common stock to settle approximately $3 million in liabilities, including certain outstanding debt.

The specific number

of shares issued in connection with debt settlement was not separately disclosed but was included as part of the equity issued in the

restructuring.

All of the above issuances were conducted without general solicitation,

and the recipients were either accredited investors or had access to such information as would be required to make an informed investment

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 of Financial Condition and

Results of Operations provides management’s analysis of the Company’s financial performance and of significant trends that

may affect future performance.

It should be read in conjunction with the financial statements and notes, and supplemental oil and gas

disclosures included elsewhere in this report.

It contains forward-looking statements including, without limitation, statements relating

to the Company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor”

provisions of the Private Securities Litigation Reform Act of 1995.

Readers are cautioned that such forward-looking statements should

be read in conjunction with the Company’s disclosures under the heading:

“Cautionary Statement about Forward-Looking Statements”

included elsewhere in this Annual Report.

Royale is an independent oil and natural gas producer.

principal lines of business are the production and sale of oil and natural gas, acquisition of oil and gas lease interests and proved

reserves, drilling of both exploratory and development wells, and sales of fractional working interests in wells to be drilled by Royale.

Since 1993, Royale has acquired and developed producing and non-producing natural gas properties in California.

In December 2018, Royale

became the operator of a newly acquired field in Texas.

The most significant factors affecting the results of operations are (i) changes

in oil and natural gas prices, production levels and reserves, (ii) turnkey drilling activities, and (iii) the increase in future cost

associated with abandonment of wells.

Critical Accounting Estimates

The preparation of financial statements in conformity with U.S.

requires us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes.

consider an accounting estimate to be critical if it requires difficult, subjective, or complex judgments and if changes in those judgments

could materially affect our financial condition or results of operations.

Our most critical accounting estimates relate to (i) estimates

of proved oil and natural gas reserves, (ii) asset retirement obligations, (iii) impairment of oil and natural gas properties under the

successful efforts methods of accounting for oil and gas related operations.

These estimates involve significant judgment because they

rely on assumptions about future commodity prices, production profiles, operating and development costs, and other economic factors that

are inherently uncertain.

Estimates of proved oil and natural gas reserves

Management considers the estimation of proved oil and natural gas reserve

quantities to be the most critical of these estimates, because those quantities drive the rate at which the Company depletes its oil and

gas properties under the unit-of-production method and are the basis on which proved properties are tested for impairment.

Reserve quantities

are estimates, not exact measurements, and their estimation requires the application of significant judgment.

The estimates depend on

a number of subjective assumptions, including projected production decline rates of producing wells, the timing and volume of production

from proved undeveloped locations, the commodity prices prescribed by SEC rules (the unweighted average of the first-of-the-month prices

for the prior twelve months), future development and operating costs, and judgments about whether wells are, with reasonable certainty,

expected to be economically producible.

These assumptions are inherently uncertain, are developed by the Company’s reservoir engineering

specialist, and are revised as additional production history, well performance data, commodity prices and economic conditions become available.

Accordingly, actual reserves and the timing and amount of future production may differ materially from the estimates used, and revisions

can occur from period to period.

Changes in estimated proved reserves have a direct and measurable effect

on the Company’s results of operations.

Depreciation, depletion and amortization expense was $259,438 for the year ended December 31,

2025, compared to $308,523 for 2024;

the decrease of $49,085, or 15.9%, resulted from an increase in expected recoverable reserves that

lowered the unit-of-production depletion rate.

Because depletion is computed by comparing capitalized cost to remaining recoverable reserves,

a downward revision in estimated proved reserves would increase the depletion rate and depletion expense and could indicate that the carrying

amount of a proved property is not recoverable, while an upward revision would have the opposite effect.

Holding current-year production

and net capitalized costs constant, a hypothetical 10% reduction in estimated proved reserves would have increased 2025 depreciation,

depletion and amortization expense by approximately $17,640.

Asset Retirement Obligations

We recognize an asset retirement obligation (“ARO”) for

the estimated present value of the future costs to plug and abandon wells, remove equipment and facilities, and restore land and surface

ARO estimates require significant judgment regarding the timing of retirement activities, future regulatory requirements,

expected inflation rates, technological changes, and the credit-adjusted discount rate used to measure the obligation.

Because these obligations

typically will not be settled for many years, the ultimate costs may differ materially from our recorded estimates.

Changes in estimated

settlement dates, cost assumptions, or discount rates are recognized prospectively and may result in significant increases or decreases

in the ARO liability and corresponding asset.

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

We evaluate our proved oil and natural gas properties for impairment

whenever events or changes in circumstances indicate that the carrying amount of an asset group may not be recoverable.

Under the successful

efforts method, impairment is assessed at the lowest level for which identifiable cash flows are largely independent, which is generally

a field or reservoir.

The recoverability test compares the carrying amount of the asset group to the estimated undiscounted future net

cash flows expected to result from the use and eventual disposition of the assets.

Estimating future cash flows requires significant judgment regarding

future commodity prices, production profiles, operating and development costs, reserve estimates, and the timing of development activities.

These assumptions are inherently uncertain and are based on management’s expectations of future economic and operating conditions,

which may differ materially from actual results.

If the carrying amount of an asset group exceeds the estimated undiscounted

future net cash flows, we measure the impairment loss as the amount by which the carrying amount exceeds fair value.

Fair value is typically

determined using a discounted cash flow model that incorporates Level 3 inputs, including internally developed price forecasts, production

estimates, cost assumptions, and a market-participant discount rate.

Because our asset base is relatively small and concentrated, changes

in commodity prices, reserve estimates, or operating cost assumptions may have a more pronounced impact on the recoverability of our properties

than would be the case for larger, more diversified producers.

Actual results may differ materially from our estimates, and such differences

could result in impairment charges in future periods.

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

to the Year Ended December 31, 2024

For the year ended December 31, 2025, we incurred a net loss of $1,251,680

compared to a net loss of $2,159,016 during 2024.

Total revenues from operations in 2025 were $1,947,203, a decrease of $315,136 or 13.9%,

from the total revenues of $2,262,339 in 2024, mainly due to lower oil prices during 2025.

Total expenses for operations in 2025 were

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.

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.

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

The decrease in depreciation expense was due to a increase in expected recoverable reserves which decreased the depletion

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

Legal and accounting expense increased to $582,413 in 2024, compared to $435,372 in 2023, a $147,041 or 33.8% increase.

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.

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.

$4,183,060 a decrease of $1,605,127 or 27.7%, from total expenses of $5,788,187 in 2024, mainly due to lower lease operating expenses,

lease impairments and credit loss expenses during 2025.

During the year ended December 31, 2025, revenues from oil and gas

production decreased $319,631 or 14.23% to $1,926,442 from 2024 revenues of $2,246,073,mainly due to lower oil commodity prices during

The net sales volume of oil and condensate for the year ended December 31, 2025 was approximately 25,976 barrels of oil with an

average price of $64.23 versus approximately 26,570 barrels with an average price of $72.83 per barrel, in 2024.

This represents a decrease

in net sales volume of approximately 593 barrels or 2.2%, which was mainly due to some wells being offline during the period in 2025 due

to weather related issues in our Texas Jameson field.

The net sales volume of natural gas for the year ended December 31, 2025, was approximately

117,219 Mcf with an average price of $2.20 per Mcf, versus 116,406 Mcf with an average price of $1.94 per Mcf for the year in 2024.

represents an increase in net sales volume of approximately 813 Mcf or 0.7%, primarily due to wells coming online during the period in

Oil and natural gas lease operating expenses decreased by $659,840

or 33.3%, to $1,323,333 for the year ended December 31, 2025, from $1,983,173 for the year in 2024.

This decrease was mainly due to lower

workover-related costs and equipment repairs on our Jameson field during 2025 as we attempted to increase production in 2024.

we also recorded settlement of accounts payable of $105,494 with a vendor due to an equipment failure which occurred during a workover.

Additionally, during 2025, we recorded a settlement of accounts payable of $53,583 due to the write-off of accounts payable.

When measuring

lease operating costs on a production or lifting cost basis, in 2025, the $1,323,333 equates to a $4.85 per Mcfe or $30.61 per BOE lifting

cost versus $7.19 per Mcfe or $50.70 per BOE lifting cost in 2024.

The aggregate of Other Operating Revenue was $20,761 for the year ended

December 31, 2025, an increase of $4,495 or 27.6% from $16,266 for 2024, due to higher rental income received in 2025.

Depreciation, depletion and amortization expense decreased to $259,438

from $308,523, a decrease of $49,085 or 15.9% for the year ended December 31, 2025, as compared to 2024.

The depletion rate is calculated

using production by comparing capitalized cost to the recoverable reserves remaining.

The decrease in depreciation, depletion and amortization

expense was due to an increase in expected recoverable reserves which decreased the depletion rate.

General and administrative expenses decreased by $1,637 or 0.1% from

$1,633,740 for the year ended December 31, 2024, to $1,632,103 in 2025.

Legal and accounting expense decreased to $446,593 in 2025, compared

to $582,413 in 2024, a $135,820 or 23.3% decrease.

This decrease was primarily due to higher legal fees related to our debt facility entered

into during 2024, and preparation of the transaction documents related to the conversion of the Series B Convertible Preferred shares,

also during 2024.

Marketing expense for the year ended December 31, 2025, decreased $44,589, or 12.9%, to $302,455, compared to $347,044

Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated

At December 31, 2025, Royale had a Deferred Drilling Obligation of

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.

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.

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%).

Resources and Liquidity

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.

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.

During 2025, we removed $2,755,500 of drilling obligations as we participated in drilling and completion of one gross (0.0035

net) successful oil well in the Texas Permian basin, while incurring expenses of $1,433,351, resulting in a gain of $1,322,149.

31, 2024, Royale had a Deferred Drilling Obligation of $11,457,996.

During 2024, we removed $6,562,721 of drilling obligations as we participated

in drilling and completion of four gross (0.0722 net) successful oil wells in the Texas Permian basin, while incurring expenses of $4,955,044,

resulting in a gain of $1,607,677.

During 2025, we recorded a $18,710 gain on settlement of asset retirement

obligation liability due mainly to finalizing the plugging and abandonment of three natural gas sites in California.

During the years

ended December 31, 2025 and 2024, we recorded impairments of $27,250 and $400,719, respectively, on various lease and land costs in our

California natural gas fields where the carrying value exceeded the fair value.

During 2025 and 2024, we also recorded Credit Loss expenses

of $137,221 and $450,743, respectively, which arose from identified uncollectable receivables relating to our oil and natural gas properties

either plugged and abandoned or scheduled for plugging and abandonment and our period end oil and natural gas reserve values.

We periodically

review our accounts receivable from working interest owners to determine whether collection of any of these charges appears doubtful.

During 2024, we also recorded a gain on sale of assets of $17,500 as we received a credit for well equipment sold during a 2021 sales

Interest income for the year ended December 31, 2025 and 2024, was

$66,079 and $46,528, respectively.

The higher 2025 interest income was due to higher bank balances during 2025.

Interest expense for the

year ended December 31, 2025 and 2024, was $404,051 and $304,873, respectively.

The higher 2025 interest expense was due to the $1.9 million

note payable discussed in Note 15 and the notes payable related to the debt restructuring, discussed in Note 14.

In 2025 and 2024, we did not have an income tax expense due to

the use of a percentage depletion carryover valuation allowance created from the current and past operations resulting in an effective

tax rate less than the new federal rate of 21% plus the relevant state rates (mostly California, 8.8%).

Capital Resources and Liquidity

At December 31, 2025, Royale had current assets totaling $10,510,193

and current liabilities totaling $22,061,032, an $11,550,839 working capital deficit.

We had cash and cash equivalents at December 31,

2025 of $1,099,044 and restricted cash of $7,175,950 compared to cash and cash equivalents of $1,877,163 and restricted cash of $6,025,000

at December 31, 2024.

Ordinarily, we fund our operations and cash needs from our available

credit and cash flows generated from operations.

We believe there is doubt that the Company has the ability to meet liquidity demands

through cash-flow from operations.

In that event, the Company expects to seek alternative capital sources through additional sales of

equity or debt securities, or the sale of property, which may not be available at all, or on terms we deem reasonable.

We have plans to

increase oil and gas revenue participation in the drilling and completion of non-operated wells in the Permian Basin in Texas.

At December 31, 2025, our other receivables net, which consists of

1 unchanged sentence

at December 31, 2024, a $74,821 decrease.

This decrease was mainly due to lower accounts receivables from payment of

Joint Interest Bills by direct working interest owners 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.

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

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.

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.

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.

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

See Note 17 – Supplemental Information About Oil and Gas Producing Activities (Unaudited), to our Financial Statements.

7A Qualitative and Quantitative Disclosures About Market Risk

a required disclosure for smaller reporting companies.

8 Financial Statements and Supplementary Data

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

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

This decrease was mainly due to lower accounts receivables from payment of Joint Interest Bills

by direct working interest owners.

At December 31, 2025, revenue receivable was $694,729, a decrease of $69,924, compared to $764,653

at December 31, 2024, due to lower uncollected production volumes and commodity prices at year end 2025 when compared to year end 2024.

At December 31, 2025, our accounts payable and accrued expenses totaled $6,033,878, a decrease of $932,727 from the accounts payable at

December 31, 2024 of $6,966,605, mainly due to lower trade payables and lower revenue payables to direct working interest owners at year

We have not engaged in hedging activities nor do we use derivative

instruments to manage market risks.

Operating Activities.

For the years ended December 31, 2025

and 2024, cash used in operating activities totaled $2,699,820 and $2,362,855, respectively.

This $366,965 difference in cash used was

mainly due to a decrease in accounts payable and accrued expenses due to payments made during 2025 and lower revenue payables to direct

working interest owners.

Investing Activities .

Net cash provided by investing activities

totaled $2,584,264 and $3,344,120 for the years ended December 31, 2025 and 2024, respectively.

The $759,856 difference was due to cash

receipts of approximately $5.6 million in 2025 and $8.3 million in 2024 in direct working interest turnkey investments.

Also, during 2025,

our turnkey drilling expenditures were approximately $2.7 million as we participated in the drilling and completion of one gross (0.0035

net) well in the Permian basin.

During 2024, our turnkey drilling expenditures were approximately $5.1 million as we participated in the

drilling and completion of four gross (0.0722 net) wells in the Permian basin.

Financing Activities.

Net cash provided by financing activities

totaled $488,387 and $1,393,377 for the years ended December 31, 2025 and 2024, respectively.

The difference in cash provided was due

to receipt of $500,000 during 2025 and $1.4 million received in 2024 from the note payable discussed in Note 15.

During the years ended

December 31, 2025 and 2024, $11,613 and $6,623, respectively, were used for principal payments on our financing lease payments.

Changes in Reserve Estimates

During 2025, our overall proved developed and undeveloped oil reserves

increased by 171.1% and our previously estimated proved developed and undeveloped oil reserve quantities were revised upward by approximately

107 thousand barrels.

This upward revision was mainly the result of an increase in proved undeveloped oil reserves from drilling locations

which the Company had previously estimated.

Our overall proved developed and undeveloped natural gas reserves increased by 362.3% and

our previously estimated proved developed and undeveloped natural gas reserve quantities were revised upward by approximately 688 thousand

cubic feet of natural gas.

This upward revision was mainly the result of an increase in proved undeveloped natural gas reserves from drilling

locations which the Company had previously estimated.

See Note 18 – Supplemental Information About Oil and Gas Producing Activities

(Unaudited), to our Financial Statements.

During 2024, our overall proved developed and undeveloped oil reserves

increased by 9.6% and our previously estimated proved developed and undeveloped oil reserve quantities were revised upward by approximately

32 thousand barrels.

This upward revision was mainly the result of an increase in proved undeveloped oil reserves from drilling locations

which the Company had previously estimated.

Our overall proved developed and undeveloped natural gas reserves decreased by 17.1% mainly

due to production and our previously estimated proved developed and undeveloped natural gas reserve quantities were revised upward by

approximately 4 thousand cubic feet of natural gas.

This upward revision was mainly the result of an increase in proved undeveloped natural

gas reserves from drilling locations which the Company had previously estimated.

See Note 18 – Supplemental Information About Oil

and Gas Producing Activities (Unaudited), to our Financial Statements.

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

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 5. Market for Registrant’s Common Equity