Item 5. Market for Registrant’s Common Equity
Item 5 Market for Common Equity and Related Stockholder Matters
There is no established trading market for Royale’s Common Stock,
which is quoted on the OTCQB Market under the symbol “ROYL.” As of June 30, 2025, 96,600,302 shares of Common Stock were held
by approximately 3,052 stockholders of record. The following table reflects the high and low quarterly bid prices as reported on
the OTCQB Market from January 2024 through December 2025:
1st Qtr
2nd Qtr
3rd Qtr
4th Qtr
High
Low
High
Low
High
Low
High
Low
2024
$ 0.07
$ 0.02
$ 0.07
$ 0.03
$ 0.08
$ 0.03
$ 0.07
$ 0.04
2025
$ 0.06
$ 0.03
$ 0.05
$ 0.04
$ 0.04
$ 0.04
$ 0.04
$ 0.03
The OTC QB Market is not an exchange, and any over the counter quotations
reflect inter-dealer prices, without retail markup, markdown or commission, and may not necessarily represent actual transactions.
Transfer Agent
The Company utilizes the independent transfer agent services of American
Stock Transfer & Trust Company as its transfer agent.
Dividends
The board of directors did not declare cash dividends in either 2025
or 2024. The board of directors did declare dividends during 2024 on the preferred stock to be Paid In Kind (“PIK”) of 65,372
and 84,470 shares with a respective par value of $653,730 and $844,700, as more fully set forth in Note 5 to our Financial Statements.
Recent Sales of Unregistered Securities
During the fiscal year ended December 31, 2025, we did not issue any
unregistered securities.
During the fiscal year ended December 31, 2024, we issued the following
unregistered securities in transactions exempt from registration under the Securities Act of 1933, as amended, pursuant to Section 4(a)(2)
and/or Regulation D thereunder:
Shares Issued for Compensation
Royale issued 1,299,641 shares of common stock to its officers, directors,
and consultants in lieu of cash compensation for services rendered. These shares were issued at prevailing market prices or pursuant to
existing contractual arrangements, and no underwriters or selling agents were involved.
Shares Issued Upon Conversion of Preferred Stock
On October 11, 2024, Royale completed a significant equity restructuring
in which it issued 22,198,095 shares of common stock to former holders of Series B 3.5% Convertible Preferred Stock, representing approximately
90% of the total preferred stock retired. Additionally, 2,538,378 shares were issued for conversion of accrued preferred dividends, resulting
in a total of 24,736,473 shares issued related to the preferred equity conversion.
Shares Issued Upon Conversion of Debt
As part of the same, October 11, 2024 restructuring transaction, the
Company also issued common stock to settle approximately $3 million in liabilities, including certain outstanding debt. The specific number
of shares issued in connection with debt settlement was not separately disclosed but was included as part of the equity issued in the
restructuring.
All of the above issuances were conducted without general solicitation,
and the recipients were either accredited investors or had access to such information as would be required to make an informed investment
decision. No underwriters or placement agents were involved, and no commissions were paid.
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Item 7 Management ’ s Discussion and Analysis of Financial
Condition and Results of Operations
Management’s Discussion and Analysis of Financial Condition and
Results of Operations provides management’s analysis of the Company’s financial performance and of significant trends that
may affect future performance. It should be read in conjunction with the financial statements and notes, and supplemental oil and gas
disclosures included elsewhere in this report. It contains forward-looking statements including, without limitation, statements relating
to the Company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor”
provisions of the Private Securities Litigation Reform Act of 1995. Readers are cautioned that such forward-looking statements should
be read in conjunction with the Company’s disclosures under the heading: “Cautionary Statement about Forward-Looking Statements”
included elsewhere in this Annual Report.
Overview
Royale is an independent oil and natural gas producer. Royale’s
principal lines of business are the production and sale of oil and natural gas, acquisition of oil and gas lease interests and proved
reserves, drilling of both exploratory and development wells, and sales of fractional working interests in wells to be drilled by Royale.
Since 1993, Royale has acquired and developed producing and non-producing natural gas properties in California. In December 2018, Royale
became the operator of a newly acquired field in Texas. The most significant factors affecting the results of operations are (i) changes
in oil and natural gas prices, production levels and reserves, (ii) turnkey drilling activities, and (iii) the increase in future cost
associated with abandonment of wells.
Critical Accounting Estimates
The preparation of financial statements in conformity with U.S. GAAP
requires us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. We
consider an accounting estimate to be critical if it requires difficult, subjective, or complex judgments and if changes in those judgments
could materially affect our financial condition or results of operations. Our most critical accounting estimates relate to (i) estimates
of proved oil and natural gas reserves, (ii) asset retirement obligations, (iii) impairment of oil and natural gas properties under the
successful efforts methods of accounting for oil and gas related operations. These estimates involve significant judgment because they
rely on assumptions about future commodity prices, production profiles, operating and development costs, and other economic factors that
are inherently uncertain.
Estimates of proved oil and natural gas reserves
Management considers the estimation of proved oil and natural gas reserve
quantities to be the most critical of these estimates, because those quantities drive the rate at which the Company depletes its oil and
gas properties under the unit-of-production method and are the basis on which proved properties are tested for impairment. Reserve quantities
are estimates, not exact measurements, and their estimation requires the application of significant judgment. The estimates depend on
a number of subjective assumptions, including projected production decline rates of producing wells, the timing and volume of production
from proved undeveloped locations, the commodity prices prescribed by SEC rules (the unweighted average of the first-of-the-month prices
for the prior twelve months), future development and operating costs, and judgments about whether wells are, with reasonable certainty,
expected to be economically producible. These assumptions are inherently uncertain, are developed by the Company’s reservoir engineering
specialist, and are revised as additional production history, well performance data, commodity prices and economic conditions become available.
Accordingly, actual reserves and the timing and amount of future production may differ materially from the estimates used, and revisions
can occur from period to period.
Changes in estimated proved reserves have a direct and measurable effect
on the Company’s results of operations. Depreciation, depletion and amortization expense was $259,438 for the year ended December 31,
2025, compared to $308,523 for 2024; the decrease of $49,085, or 15.9%, resulted from an increase in expected recoverable reserves that
lowered the unit-of-production depletion rate. Because depletion is computed by comparing capitalized cost to remaining recoverable reserves,
a downward revision in estimated proved reserves would increase the depletion rate and depletion expense and could indicate that the carrying
amount of a proved property is not recoverable, while an upward revision would have the opposite effect. Holding current-year production
and net capitalized costs constant, a hypothetical 10% reduction in estimated proved reserves would have increased 2025 depreciation,
depletion and amortization expense by approximately $17,640.
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Asset Retirement Obligations
We recognize an asset retirement obligation (“ARO”) for
the estimated present value of the future costs to plug and abandon wells, remove equipment and facilities, and restore land and surface
conditions. ARO estimates require significant judgment regarding the timing of retirement activities, future regulatory requirements,
expected inflation rates, technological changes, and the credit-adjusted discount rate used to measure the obligation. Because these obligations
typically will not be settled for many years, the ultimate costs may differ materially from our recorded estimates. Changes in estimated
settlement dates, cost assumptions, or discount rates are recognized prospectively and may result in significant increases or decreases
in the ARO liability and corresponding asset.
Impairment of Oil and Natural Gas Properties (Successful Efforts Method)
We evaluate our proved oil and natural gas properties for impairment
whenever events or changes in circumstances indicate that the carrying amount of an asset group may not be recoverable. Under the successful
efforts method, impairment is assessed at the lowest level for which identifiable cash flows are largely independent, which is generally
a field or reservoir. The recoverability test compares the carrying amount of the asset group to the estimated undiscounted future net
cash flows expected to result from the use and eventual disposition of the assets.
Estimating future cash flows requires significant judgment regarding
future commodity prices, production profiles, operating and development costs, reserve estimates, and the timing of development activities.
These assumptions are inherently uncertain and are based on management’s expectations of future economic and operating conditions,
which may differ materially from actual results.
If the carrying amount of an asset group exceeds the estimated undiscounted
future net cash flows, we measure the impairment loss as the amount by which the carrying amount exceeds fair value. Fair value is typically
determined using a discounted cash flow model that incorporates Level 3 inputs, including internally developed price forecasts, production
estimates, cost assumptions, and a market-participant discount rate. Because our asset base is relatively small and concentrated, changes
in commodity prices, reserve estimates, or operating cost assumptions may have a more pronounced impact on the recoverability of our properties
than would be the case for larger, more diversified producers. Actual results may differ materially from our estimates, and such differences
could result in impairment charges in future periods.
Results of Operations for the Year Ended December 31, 2025, as Compared
to the Year Ended December 31, 2024
For the year ended December 31, 2025, we incurred a net loss of $1,251,680
compared to a net loss of $2,159,016 during 2024. Total revenues from operations in 2025 were $1,947,203, a decrease of $315,136 or 13.9%,
from the total revenues of $2,262,339 in 2024, mainly due to lower oil prices during 2025. Total expenses for operations in 2025 were
$4,183,060 a decrease of $1,605,127 or 27.7%, from total expenses of $5,788,187 in 2024, mainly due to lower lease operating expenses,
lease impairments and credit loss expenses during 2025.
During the year ended December 31, 2025, revenues from oil and gas
production decreased $319,631 or 14.23% to $1,926,442 from 2024 revenues of $2,246,073,mainly due to lower oil commodity prices during
2025. The net sales volume of oil and condensate for the year ended December 31, 2025 was approximately 25,976 barrels of oil with an
average price of $64.23 versus approximately 26,570 barrels with an average price of $72.83 per barrel, in 2024. This represents a decrease
in net sales volume of approximately 593 barrels or 2.2%, which was mainly due to some wells being offline during the period in 2025 due
to weather related issues in our Texas Jameson field. The net sales volume of natural gas for the year ended December 31, 2025, was approximately
117,219 Mcf with an average price of $2.20 per Mcf, versus 116,406 Mcf with an average price of $1.94 per Mcf for the year in 2024. This
represents an increase in net sales volume of approximately 813 Mcf or 0.7%, primarily due to wells coming online during the period in
2025.
Oil and natural gas lease operating expenses decreased by $659,840
or 33.3%, to $1,323,333 for the year ended December 31, 2025, from $1,983,173 for the year in 2024. This decrease was mainly due to lower
workover-related costs and equipment repairs on our Jameson field during 2025 as we attempted to increase production in 2024. During 2025,
we also recorded settlement of accounts payable of $105,494 with a vendor due to an equipment failure which occurred during a workover.
Additionally, during 2025, we recorded a settlement of accounts payable of $53,583 due to the write-off of accounts payable. When measuring
lease operating costs on a production or lifting cost basis, in 2025, the $1,323,333 equates to a $4.85 per Mcfe or $30.61 per BOE lifting
cost versus $7.19 per Mcfe or $50.70 per BOE lifting cost in 2024.
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The aggregate of Other Operating Revenue was $20,761 for the year ended
December 31, 2025, an increase of $4,495 or 27.6% from $16,266 for 2024, due to higher rental income received in 2025.
Depreciation, depletion and amortization expense decreased to $259,438
from $308,523, a decrease of $49,085 or 15.9% for the year ended December 31, 2025, as compared to 2024. The depletion rate is calculated
using production by comparing capitalized cost to the recoverable reserves remaining. The decrease in depreciation, depletion and amortization
expense was due to an increase in expected recoverable reserves which decreased the depletion rate.
General and administrative expenses decreased by $1,637 or 0.1% from
$1,633,740 for the year ended December 31, 2024, to $1,632,103 in 2025. Legal and accounting expense decreased to $446,593 in 2025, compared
to $582,413 in 2024, a $135,820 or 23.3% decrease. This decrease was primarily due to higher legal fees related to our debt facility entered
into during 2024, and preparation of the transaction documents related to the conversion of the Series B Convertible Preferred shares,
also during 2024. Marketing expense for the year ended December 31, 2025, decreased $44,589, or 12.9%, to $302,455, compared to $347,044
for 2024. Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated
costs.
At December 31, 2025, Royale had a Deferred Drilling Obligation of
$14,277,496. During 2025, we removed $2,755,500 of drilling obligations as we participated in drilling and completion of one gross (0.0035
net) successful oil well in the Texas Permian basin, while incurring expenses of $1,433,351, resulting in a gain of $1,322,149. At December
31, 2024, Royale had a Deferred Drilling Obligation of $11,457,996. During 2024, we removed $6,562,721 of drilling obligations as we participated
in drilling and completion of four gross (0.0722 net) successful oil wells in the Texas Permian basin, while incurring expenses of $4,955,044,
resulting in a gain of $1,607,677.
During 2025, we recorded a $18,710 gain on settlement of asset retirement
obligation liability due mainly to finalizing the plugging and abandonment of three natural gas sites in California. During the years
ended December 31, 2025 and 2024, we recorded impairments of $27,250 and $400,719, respectively, on various lease and land costs in our
California natural gas fields where the carrying value exceeded the fair value. During 2025 and 2024, we also recorded Credit Loss expenses
of $137,221 and $450,743, respectively, which arose from identified uncollectable receivables relating to our oil and natural gas properties
either plugged and abandoned or scheduled for plugging and abandonment and our period end oil and natural gas reserve values. We periodically
review our accounts receivable from working interest owners to determine whether collection of any of these charges appears doubtful.
During 2024, we also recorded a gain on sale of assets of $17,500 as we received a credit for well equipment sold during a 2021 sales
transaction.
Interest income for the year ended December 31, 2025 and 2024, was
$66,079 and $46,528, respectively. The higher 2025 interest income was due to higher bank balances during 2025. Interest expense for the
year ended December 31, 2025 and 2024, was $404,051 and $304,873, respectively. The higher 2025 interest expense was due to the $1.9 million
note payable discussed in Note 15 and the notes payable related to the debt restructuring, discussed in Note 14.
In 2025 and 2024, we did not have an income tax expense due to
the use of a percentage depletion carryover valuation allowance created from the current and past operations resulting in an effective
tax rate less than the new federal rate of 21% plus the relevant state rates (mostly California, 8.8%).
Capital Resources and Liquidity
At December 31, 2025, Royale had current assets totaling $10,510,193
and current liabilities totaling $22,061,032, an $11,550,839 working capital deficit. We had cash and cash equivalents at December 31,
2025 of $1,099,044 and restricted cash of $7,175,950 compared to cash and cash equivalents of $1,877,163 and restricted cash of $6,025,000
at December 31, 2024.
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Ordinarily, we fund our operations and cash needs from our available
credit and cash flows generated from operations. We believe there is doubt that the Company has the ability to meet liquidity demands
through cash-flow from operations. In that event, the Company expects to seek alternative capital sources through additional sales of
equity or debt securities, or the sale of property, which may not be available at all, or on terms we deem reasonable. We have plans to
increase oil and gas revenue participation in the drilling and completion of non-operated wells in the Permian Basin in Texas.
At December 31, 2025, our other receivables net, which consists of
joint interest billing receivables from direct working interest participants and industry partners, totaled $793,608, compared to $868,429
at December 31, 2024, a $74,821 decrease. This decrease was mainly due to lower accounts receivables from payment of Joint Interest Bills
by direct working interest owners. At December 31, 2025, revenue receivable was $694,729, a decrease of $69,924, compared to $764,653
at December 31, 2024, due to lower uncollected production volumes and commodity prices at year end 2025 when compared to year end 2024.
At December 31, 2025, our accounts payable and accrued expenses totaled $6,033,878, a decrease of $932,727 from the accounts payable at
December 31, 2024 of $6,966,605, mainly due to lower trade payables and lower revenue payables to direct working interest owners at year
end 2025.
We have not engaged in hedging activities nor do we use derivative
instruments to manage market risks.
Operating Activities. For the years ended December 31, 2025
and 2024, cash used in operating activities totaled $2,699,820 and $2,362,855, respectively. This $366,965 difference in cash used was
mainly due to a decrease in accounts payable and accrued expenses due to payments made during 2025 and lower revenue payables to direct
working interest owners.
Investing Activities . Net cash provided by investing activities
totaled $2,584,264 and $3,344,120 for the years ended December 31, 2025 and 2024, respectively. The $759,856 difference was due to cash
receipts of approximately $5.6 million in 2025 and $8.3 million in 2024 in direct working interest turnkey investments. Also, during 2025,
our turnkey drilling expenditures were approximately $2.7 million as we participated in the drilling and completion of one gross (0.0035
net) well in the Permian basin. During 2024, our turnkey drilling expenditures were approximately $5.1 million as we participated in the
drilling and completion of four gross (0.0722 net) wells in the Permian basin.
Financing Activities. Net cash provided by financing activities
totaled $488,387 and $1,393,377 for the years ended December 31, 2025 and 2024, respectively. The difference in cash provided was due
to receipt of $500,000 during 2025 and $1.4 million received in 2024 from the note payable discussed in Note 15. During the years ended
December 31, 2025 and 2024, $11,613 and $6,623, respectively, were used for principal payments on our financing lease payments.
Changes in Reserve Estimates
During 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.
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Item 7A Qualitative and Quantitative Disclosures About Market Risk
Not a required disclosure for smaller reporting companies.
Item 8 Financial Statements and Supplementary Data
See pages F-1, et seq., included herein.
Item 9 Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure
None