What changed in this filing

/stocks — the workspaceLOADING

Item 1. Financial Statements

2025-11-26 compared with 2025-08-14 · 458 added, 413 removed, 373 unchanged (70% of the section changed)

Financial Statements

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS

September 30,

Current Assets:

8 unchanged sentences

Oil and Gas Properties (Successful Efforts Basis), Real Property and Equipment and Fixtures, net

See notes to unaudited condensed consolidated financial

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

notes to unaudited condensed consolidated financial statements.

CONSOLIDATED BALANCE SHEETS

September 30,

LIABILITIES AND STOCKHOLDERS’ DEFICIT

1 unchanged sentence

Accounts Payable and Accrued Expenses

Notes Payable - Current

Royalties Payable

12 unchanged sentences

Stockholders’ Deficit:

Common Stock, $ 0.001 Par Value, 280,000,000 Shares Authorized 96,600,302 and 96,600,302 shares issued and outstanding at June 30, 2025 and December 31, 2024, respectively

Common Stock, $ 0.001 Par Value, 280,000,000 Shares Authorized 96,600,302 and 96,600,302 shares issued and outstanding at September 30, 2025 and December 31, 2024, respectively

Additional Paid in Capital

6 unchanged sentences

Total Liabilities, and Stockholders’ Deficit

See notes to unaudited condensed consolidated financial

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

notes to unaudited condensed consolidated financial statements.

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

For the three months ended

For the six months ended

For the nine months ended

Oil, NGL and Gas Sales

Supervisory Fees and Other

Other Operating Revenue

Total Revenues

2 unchanged sentences

Depreciation, Depletion and Amortization

Settlement of Asset Retirement Obligations

Legal and Accounting

4 unchanged sentences

Loss From Operations

( 1,087,889 )

( 1,408,768 )

( 1,889,032 )

Other Income (Expense):

Interest Income

Interest Expense

Gain on Settlement of Accounts Payable

Gain on Settlement of Asset Retirement Obligations

( 1,184,291 )

( 1,651,014 )

( 2,065,017 )

Preferred Stock Dividend

Net Loss available to common stock

$ ( 550,293 )

$ ( 1,405,701 )

$ ( 1,651,014 )

$ ( 2,718,747 )

Shares used in computing Basic and Diluted Net Loss per share

Basic and Diluted Net Loss Per Share

See notes to unaudited condensed consolidated financial

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE SIX MONTHS ENDED JUNE 30, 2025 AND 2024

For the Six Months Ended

notes to unaudited condensed consolidated financial statements.

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

THE NINE MONTHS ENDED SEPTEMBER 30, 2025 AND 2024

For the Nine Months Ended

CASH FLOWS FROM OPERATING ACTIVITIES

1 unchanged sentence

$ ( 2,065,017 )

Adjustments to Reoconcile Net Loss to Net Cash Used in Operating Activities:

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

Depreciation, Depletion and Amortization

1 unchanged sentence

Credit Loss Expense

Gain on Settlement of Accounts Payable

Gain on Settlement of Asset Retirement Obligation

Settlement of Asset Retirement Obligation

Cash Settlement on Asset Retirement Obligation

Stock-Based Compensation

Accretion of Debt Restructure Notes Payable

Accretion of Discount on Notes Payable

Right of Use Asset Depreciation

7 unchanged sentences

( 2,675,708 )

( 1,381,384 )

CASH FLOWS FROM INVESTING ACTIVITIES

1 unchanged sentence

( 1,969,006 )

( 4,706,411 )

Proceeds from Turnkey Drilling Programs

Net Cash Provided by (Used in) Investing Activities

Net Cash Provided by Investing Activities

CASH FLOWS FROM FINANCING ACTIVITIES

1 unchanged sentence

Lease Financing Payments

Net Cash Provided by (Used in) Financing Activities

Net Increase (Decrease) in Cash and Cash Equivalents, and Restricted Cash

Net Cash Provided by Financing Activities

Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash

( 1,628,284 )

Cash, Cash Equivalents, and Restricted Cash at Beginning of Period

3 unchanged sentences

SUPPLEMENTAL DISCLOSURES OF NON-CASH INVESTING & FINANCING TRANSACTIONS:

Accounts Payable for Oil and Gas Properties

Increase (Decrease) in Capital Accrued Balance

SUPPLEMENTAL DISCLOSURES OF NON CASH INVESTING & FINANCING ACTIVITIES:

Series B Paid-In-Kind Dividends

See notes to unaudited condensed consolidated

financial statements.

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ DEFICIT

FOR THE THREE AND SIX MONTHS ENDED JUNE 30,

2025 AND 2024

Change in Capital Accrued Balance

notes to unaudited condensed consolidated financial statements.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ DEFICIT

THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2025 AND 2024

Comprehensive

1 unchanged sentence

December 31, 2023 Balance

$ ( 90,323,289 )

$ ( 35,633,489 )

Stock Issued in lieu of Compensation

Preferred Series B 3.5 % Dividend

June 30, 2024 Balance

( 2,065,017 )

September 30, 2024 Balance

$ ( 93,042,036 )

$ ( 38,316,237 )

December 31, 2024 Balance

3 unchanged sentences

( 1,651,014 )

June 30, 2025 Balance

September 30, 2025 Balance

$ ( 95,155,483 )

2 unchanged sentences

Stockholders’

March 31, 2024 Balance

June 30, 2024 Balance

$ ( 91,636,335 )

1 unchanged sentence

Preferred Series B 3.5 % Dividend

June 30, 2024 Balance

( 1,184,291 )

March 31, 2025 Balance

September 30, 2024 Balance

$ ( 93,042,036 )

3 unchanged sentences

$ ( 13,430,036 )

See notes to unaudited condensed consolidated financial

ROYALE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL

NOTE 1 – BASIS OF PRESENTATION

September 30, 2025 Balance

$ ( 95,155,483 )

$ ( 13,980,329 )

notes to unaudited condensed consolidated financial statements.

TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1 – BASIS OF PRESENTATION

Consolidation

In the opinion of management, the accompanying unaudited condensed consolidated

financial statements include all adjustments necessary to present fairly the Company’s financial position and the results of its

operations and cash flows for the periods presented.

The accompanying unaudited consolidated financial statements, which include

the accounts of Royale Energy, Inc.

(sometimes referred to as the “Company” “we,” “our,” “us,”

“Royale Energy,” or “Royale”), Royale Energy Funds, Inc.

(“REF”), and Matrix Oil Management Corporation

and its subsidiaries, have been prepared in accordance with U.S.

Generally Accepted Accounting Principles (“GAAP”) for interim

consolidated financial information pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”)

under Article 10 of Regulation S-X and the instructions to Form 10-Q.

Accordingly, certain information and footnote disclosures normally

included in our audited financial statements have been condensed or omitted pursuant to the SEC’s rules and regulations.

intercompany transactions have been eliminated in the consolidation.

In our opinion, all adjustments considered necessary for a fair presentation

have been included.

The consolidated balance sheet as of December 31, 2024 was derived from

the audited financial statements at that date.

The accompanying consolidated financial statements should be read in conjunction with the

consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31,

Operating results for the three and six months ended June 30, 2025 are not necessarily indicative of the results that may be expected

for the fiscal year ending December 31, 2025, or for any other period.

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.

At June 30, 2025, our consolidated financial statements reflect a working

capital deficiency of $ 12,030,955 , and an accumulated deficit of $ 94,605,190 .

We had a net loss of $ 1,100,721 for the six months ended

June 30, 2025.

These factors indicate that there is 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 continuing

to seek to implement cost control measures that include, among other things, reduction of overhead costs, selling non-strategic

the opinion of management, the accompanying unaudited condensed consolidated financial statements include all adjustments necessary to

present fairly the Company’s financial position and the results of its operations and cash flows for the periods presented.

accompanying unaudited consolidated financial statements, which include the accounts of Royale Energy, Inc.

(sometimes referred to as

the “Company” “we,” “our,” “us,” “Royale Energy,” or “Royale”),

Royale Energy Funds, Inc.

(“REF”), and Matrix Oil Management Corporation and its subsidiaries, have been prepared in accordance

Generally Accepted Accounting Principles (“GAAP”) for interim consolidated financial information pursuant to the

rules and regulations of the Securities and Exchange Commission (“SEC”) under Article 10 of Regulation S-X and the instructions

to Form 10-Q.

Accordingly, certain information and footnote disclosures normally included in our audited financial statements have been

condensed or omitted pursuant to the SEC’s rules and regulations.

Significant intercompany transactions have been eliminated in

the consolidation.

In our opinion, all adjustments considered necessary for a fair presentation have been included.

consolidated balance sheet as of December 31, 2024 was derived from the audited financial statements at that date.

The accompanying consolidated

financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual

Report on Form 10-K for the fiscal year ended December 31, 2024.

Operating results for the three and nine months ended September 30,

2025 are not necessarily indicative of the results that may be expected for the fiscal year ending December 31, 2025, or for any other

and Going Concern

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.

At September 30, 2025, our condensed consolidated financial statements

reflect a working capital deficiency of $ 12,226,414 , and an accumulated deficit of $ 95,155,483 .

We had a net loss of $ 1,651,014 for the

nine months ended September 30, 2025.

These factors indicate that there is substantial doubt about our ability to continue as a going

The accompanying condensed 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 uncertainty

by continuing to seek to implement cost control measures that include, among other things, reduction of overhead costs, selling non-strategic

assets, and, if possible, obtaining additional equity and debt financing.

There is no assurance that additional financing will be

available when needed or that we will be able to obtain any financing on terms acceptable to us and whether we will become

profitable and generate positive operating cash flow.

If we are unable to raise sufficient additional capital, we will have to

develop and implement a plan to further extend payables, attempt to extend note repayments, and reduce overhead until sufficient

additional capital is raised to support further operations.

There is no assurance that additional financing will be available

when needed or that we will be able to obtain any financing on terms acceptable to us and whether we will become profitable and generate

positive operating cash flow.

If we are unable to raise sufficient additional capital, we will have to develop and implement a plan to

further extend payables, attempt to extend note repayments, and reduce overhead until sufficient additional capital is raised to support

further operations.

There can be no assurance that any such plan will be successful.

Use of Estimates

The accompanying financial statements have been prepared in conformity

GAAP 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.

accompanying financial statements have been prepared in conformity GAAP 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.

Material estimates that are particularly susceptible to significant change

relate to the estimate of Company oil and gas reserves prepared by an independent engineering consultant.

Such estimates are subject to

numerous uncertainties inherent in the estimation of quantities of proven reserves.

Estimated reserves are used in the calculation of

depletion, depreciation and amortization, unevaluated property costs, impairment of oil and natural gas properties, estimated future net

cash flows, taxes, and contingencies.

Revenue Recognition

A significant portion of our revenues are derived from the sale of crude

oil, condensate, natural gas liquids (“NGLs”) and natural gas under spot and term agreements with our customers as follows:

estimates that are particularly susceptible to significant change relate to the estimate of Company oil and gas reserves prepared by

an independent engineering consultant.

Such estimates are subject to numerous uncertainties inherent in the estimation of quantities

of proven reserves.

Estimated reserves are used in the calculation of depletion, depreciation and amortization, unevaluated property

costs, impairment of oil and natural gas properties, estimated future net cash flows, taxes, and contingencies.

significant portion of our revenues are derived from the sale of crude oil, condensate, natural gas liquids (“NGLs”) and

natural gas under spot and term agreements with our customers as follows:

For the three months

ended June 30,

For the six months

ended June 30,

ended September 30,

For the nine months

ended September 30,

Oil & Condensate Sales

Natural Gas Sales

The pricing in our hydrocarbon sales agreements are variable, 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.

pricing in our hydrocarbon sales agreements are variable, 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

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

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.

we act as a principal only with respect to the sale of our share of production and recognize revenue for the volumes associated with our

net production.

We frequently sell a portion of the working interest in each well we drill,

or participate in, to third-party investors and retain 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, 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 oil 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

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 condensed consolidated statement of operations,

since we make those payments in exchange for distinct services except for natural gas sold to Pacific Gas & Electric where transportation

is netted directly against revenue.

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.

Restricted Cash

We sponsor turnkey drilling arrangements in proved and unproved oil and

gas properties.

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.

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.

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.

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 with respect to the sale of our share

of production and recognize revenue for the volumes associated with our net production.

frequently sell a portion of the working interest in each well we drill, or participate in, to third-party investors and retain a portion

of the prospect for our own account.

We typically guarantee a cost to drill to the third-party drilling participants and record a loss

or gain on the difference between the guaranteed price and the actual cost to drill the well.

When monies are received from third parties

for future drilling obligations, we record the liability as Deferred Drilling Obligations.

Once the contracted depth for the drilling

of the well is reached and a determination as to the commercial viability of the well, 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.

oil and condensate

the crude oil 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.

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.

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 condensed consolidated statement of operations, since we make those payments in exchange for distinct

services except for natural gas sold to Pacific Gas & Electric where transportation is netted directly against revenue.

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.

We sponsor turnkey drilling arrangements in proved and unproved oil

and gas properties.

The contracts require that participants pay us the full contract price upon execution of the drilling agreement.

8 unchanged sentences

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.

of drilling as restricted cash.

In the event that progress payments are made from these funds;

they are recorded

as Prepaid Expenses and Other Current Assets.

The following table provides a reconciliation of cash, cash equivalents,

and restricted cash reported within the condensed consolidated balance sheets that sum to the total of the same amounts shown in the statement

of cash flows.

they are recorded as Prepaid Expenses and

Other Current Assets.

following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed consolidated balance

sheets that sum to the total of the same amounts shown in the statement of cash flows.

September 30,

Cash and Cash Equivalents

1 unchanged sentence

Total cash, cash equivalents, and restricted cash shown in the statement of cash flows

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 condensed consolidated statements

of operations.

Equity method investments are included as noncurrent assets on the condensed 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 the condensed consolidated statement of operations.

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 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 June 30, 2025 and December 31, 2024, we established

an allowance for expected credit losses of $ 2,179,089 and $ 2,194,552 , respectively, for receivables from direct working interest investors

whose expenses on non-producing wells were unlikely to be collected from revenue.

Dividends on Series B Convertible Preferred Stock

On October 11, 2024, we completed a significant equity restructuring transaction,

eliminating our Series B, 3.5 % Convertible Preferred Stock (“Preferred Stock”).

The Preferred Stock had an obligation to pay a 3.5 % cumulative

dividend, in kind or cash, on a quarterly basis.

The Board of Directors authorized the issuance of the Preferred Stock, for the

settlement of dividends accumulated through December 31, 2023.

We accrued $ 653,730 for dividends related to the Preferred Stock for

the first three quarters of 2024.

Each quarter, we charged retained earnings for the accumulating dividend as the amounts add to the

liquidation preference of the Preferred Stock.

Method Investments

in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting.

from equity method investments represents our proportionate share of net income generated by the equity method investees and is reflected

in other income in our condensed consolidated statements of operations.

Equity method investments are included as noncurrent

assets on the condensed consolidated balance sheets.

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 the condensed consolidated statement of operations.

Receivables, net

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 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.

amounts considered uncollectible are charged against the allowance account and recoveries of previously charged off accounts are added

to the allowance.

At September 30, 2025 and December 31, 2024, we established an allowance for expected credit losses of $ 2,277,186 and

$ 2,194,552 , respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely

to be collected.

on Series B Convertible Preferred Stock

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

(“Preferred Stock”).

Preferred Stock had an obligation to pay a 3.5 % cumulative dividend, in kind or cash, on a quarterly basis.

The Board of Directors authorized

the issuance of the Preferred Stock, for the settlement of dividends accumulated through December 31, 2023.

We accrued $ 653,730 for dividends

related to the Preferred Stock for the first three quarters of 2024.

Each quarter, we charged retained earnings for the accumulating

dividend as the amounts add to the liquidation preference of the Preferred Stock.

Reclassification

During the current quarter, the Company identified a prior quarter reclassification

error and missing segment disclosure.

Management determined the errors were not material to prior quarters;

therefore, prior quarter financial

statements have not been restated.

The correction was recorded in the current quarter as an out-of-period adjustment, resulting in a reclassification

of $ 390,000 from non-operating income (expense) to operating expenses and inclusion of the required segment information.

These adjustments

had no impact on net loss or total equity.

Issued, Not Yet Adopted

11 unchanged sentences

The Company is evaluating

the impacts of this standard on our tax disclosures and is not planning to early adopt.

the impacts of this standard on our disclosures and is not planning to early adopt.

December 2023, FASB issued Accounting Standards Update (ASU) No.

8 unchanged sentences

and gas properties, equipment and fixtures consist of:

September 30,

Producing properties, including drilling costs

58 unchanged sentences

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.

in impairment evaluations are developed using quarterly updated evaluation assumptions for crude oil commodity prices.

Quarterly volumes

are based on field production profiles, which are also updated quarterly.

Prices for natural gas and other products are based on assumptions

developed annually for evaluation purposes.

developed quarterly for evaluation purposes.

analyses are generally based on proved reserves.

2 unchanged sentences

Impairments are measured by the amount the carrying value exceeds fair value.

During the six months ended June 30,

During the nine months ended September

30, 2025 and 2024, we incurred an impairment loss of $ 27,250 and $ 400,554 , respectively.

36 unchanged sentences

rig availability and/or contractual obligations.

At June 30, 2025 and December 31, 2024, we had Deferred Drilling Obligations of $ 13,282,996

At September 30, 2025 and December 31, 2024, we had Deferred Drilling Obligations of

$ 13,982,996 and $ 11,457,996 , respectively.

5 unchanged sentences

3 – 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 (“Preferred Stock”).

The Preferred Stock was convertible at the option of the security holder at the rate of ten shares of common stock for one share of Preferred

For 2024, the board authorized the payment of each quarterly dividend of

Preferred shares, as Paid-In-Kind shares (“PIK”) to be paid immediately following the end of the quarter.

During 2024 no cash

was used to pay dividends on share of Preferred Stock.

On October 11, 2024, we completed a significant equity restructuring transaction,

eliminating our Preferred Stock.

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 (“Preferred Stock”).

The Preferred Stock was convertible at the option of the security holder at the rate

of ten shares of common stock for one share of Preferred Stock.

2024, the board authorized the payment of each quarterly dividend of Preferred shares, as Paid-In-Kind shares (“PIK”) to

be paid immediately following the end of the quarter.

During 2024 no cash was used to pay dividends on share of Preferred Stock.

October 11, 2024, we completed a significant equity restructuring transaction, eliminating our Preferred Stock.

4 – LOSS PER SHARE

and diluted loss per share are calculated as follows:

Three Months Ended June 30,

Three Months Ended September 30,

$ ( 550,293 )

$ ( 1,184,291 )

( 1,184,291 )

Preferred Stock Dividend

Net Loss Attributable to Common Shareholders

( 1,405,701 )

Weighted average common shares outstanding

Effect of dilutive securities

Weighted average common shares, including Dilutive effect

Six Months Ended June 30,

Nine Months Ended September 30,

$ ( 1,651,014 )

1 unchanged sentence

$ ( 2,065,017 )

( 2,065,017 )

Preferred Stock Dividend

5 unchanged sentences

Weighted average common shares outstanding

Effect of dilutive securities

Weighted average common shares, including Dilutive effect

the six and three months ended June 30, 2025 and 2024, we had dilutive securities of 0 and 24,664,550 , respectively.

During the six and

three month periods in 2024 and 2025, these securities were not included in the dilutive loss per share, due to their antidilutive nature.

the nine and three months ended September 30, 2025 and 2024, we had dilutive securities of 0 and 24,664,550 , respectively.

nine and three month periods in 2025 and 2024, these securities were not included in the dilutive loss per share, due to their antidilutive

5 – INCOME TAXES

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.

tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.

At the end of 2015,

management reviewed the reliability of our net deferred tax assets, and due to our continued cumulative losses in recent years, we concluded

it is not “more-likely-than-not” our deferred tax assets will be realized.

As a result, we will continue to record a full

valuation allowance against the deferred tax assets in 2025.

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.

Management has reviewed the realizability of our net deferred tax assets, and due to our

continued cumulative losses in recent years, we concluded it is “more-likely-than-not” our deferred tax assets will not be

As a result, we will continue to record a full valuation allowance against the deferred tax assets in 2025.

6 – ISSUANCE OF COMMON STOCK

the six months ended June 30, 2025, no common stock was issued in lieu of cash payments for salaries and board fees.

During the six months

ended June 30, 2024, in lieu of cash payments for board fees, we issued 1,299,641 shares of common stock valued at approximately $ 36,000

the nine months ended September 30, 2025, no common stock was issued in lieu of cash payments for salaries and board fees.

nine months ended September 30, 2024, in lieu of cash payments for board fees, we issued 1,299,641 shares of common stock valued at approximately

$ 36,000 to board members.

6 unchanged sentences

Write-offs charged against the allowance

Balance at June 30, 2024

Balance at September 30, 2024

Balance at December 31, 2024

1 unchanged sentence

Write-offs charged against the allowance

Balance at June 30, 2025

Balance at September 30, 2025

8 – RELATED PARTY NOTES PAYABLE

February 7, 2024 the board of directors of the Company approved a debt facility of up to $ 3 million.

On February 9, 2024, the

Company entered into a Secured Term Loan Note with Walou Investments, LP, a Texas limited partnership, which is under the 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 interest rate of 18.0 %.

The Company began making monthly interest payments on March 1, 2024, and will continue until the maturity date.

On November 1, 2024

the maturity was extended from August 1, 2025 to January 1, 2026.

The loan is secured by a deed of trust, which was recorded in

Ector County, Texas and covers, among other things, certain oil and gas assets of the Company in Ector County, Texas.

February 7, 2024, the Board of Directors of the Company approved a related-party debt facility of up to $ 3 million.

On February 9, 2024,

the Company entered into a Secured Term Loan Note with Walou Investments, LP, a Texas limited partnership under the control of Johnny

Jordan, the Company’s Chief Executive Officer and a member of the Company’s Board of Directors.

Jordan is also the beneficial

owner of approximately 29.2 % of the Company’s issued and outstanding common stock.

The initial advance to the Company was $ 1,400,000

on February 9, 2024.

loan originally bore interest at 18.0 % per annum, with monthly interest-only payments beginning March 1, 2024.

The loan is secured by

a deed of trust recorded in Ector County, Texas, covering certain of the Company’s oil and gas assets located in Ector County.

November 1, 2024, the maturity date of the loan was extended from August 1, 2025 to January 1, 2026.

Subsequently, on August 29, 2025,

the loan was further extended to April 1, 2027, and the Company executed an additional advance of $ 500,000 on the loan, increasing the

total outstanding principal balance to $ 1,900,000 .

Effective September 1, 2025, the interest rate on the outstanding principal was reduced

from 18.0% to 15.0% per annum.

as modified by the amendments described above, all other terms and conditions of the Secured Term Loan Note remain in full force and

9 – Debt and Equity Restructuring Transaction

2 unchanged sentences

The transaction was executed through a combination of common stock issuance, stock options, and

senior promissory notes in exchange for the redemption of all outstanding Series B Preferred Shares as of June 30, 2024.

senior promissory notes in exchange for the redemption of all outstanding Series B Preferred Shares as of September 30, 2024.

The preferred

36 unchanged sentences

issued was allocated between notes payable, common stock, and additional paid-in capital.

of June 30, 2025, the Company had 96,600,302 shares of common stock outstanding, and no preferred shares issued or outstanding.

of September 30, 2025, the Company had 96,600,302 shares of common stock outstanding, and no preferred shares issued or outstanding.

NOTE 10 – BUSINESS COMBINATION:

ACQUISITION OF ADDITIONAL

INTEREST IN PRADERA FUEGO

On September 3, 2025, we completed the acquisition of non-operated

working interests in seven producing Barnett wells adding an additional 18.5 % aggregate working interest and corresponding 13.875 % aggregate

net revenue interest in the Pradera Fuego (the “Pradera Fuego Acquisition”) field located in Ector County, Texas, within the

Permian Basin, for a total of $ 1,500,000 .

We accounted for the transaction as an asset acquisition.

The acquisition increases the Company’s

economic interest in the Pradera Fuego operations.

11 – SEGMENT REPORTING

The Company has one reportable segment, which encompasses the

ownership and investment in onshore oil and natural gas properties in the United States and turnkey drilling programs.

The segment’s revenues are derived

from the Company’s interests in the sales of crude oil, natural gas, and NGL production.

The Company evaluates performance based on various financial metrics, including

but not limited to consolidated income or loss from operations, net revenue, and cash flow from operations.

The Company’s chief

executive officer, chief operating officer, and chief financial officer together function as the chief operating decision maker (“CODM”)

and manage the Company’s business activities as a single operating segment.

The accounting policies of the one reportable segment are identical to

those described for the consolidated Company.

The CODM uses income (loss), as reported in the unaudited condensed consolidated statement

of operations, to measure segment profitability, assess performance, and manage strategic capital resource allocations.

The measure of

segment assets is reported as “Total assets” on the unaudited condensed consolidated balance sheets.

The significant expense

categories regularly provided to and reviewed by the CODM are those presented in the unaudited condensed consolidated statements of operations.

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

31 unchanged sentences

OF OPERATIONS

the six months ended June 30, 2025, and 2024, we incurred net losses of $1,100,721 and $880,726, respectively.

The difference was primarily

due to the gain on turnkey drilling recognized during the six months ended June 30, 2024, where we recognized a gain of $527,715 as we

participated in the drilling and completion of two wells in the Texas Permian basin and decreased oil and gas revenues.

During the three

months ended June 30, 2025 and 2024, we had net losses of $418,770 and $110,616, respectively.

The difference was due primarily to the

$527,715 gain on turnkey drilling recognized during the second quarter of 2024.

the first six months of 2025, revenues from oil and gas production decreased $401,068 or 33.7%, to $788,343 during the period in 2025

from revenues of $1,189,411 during the first six months of 2024.

For the nine months ended September 30, 2025, and 2024, we incurred net

losses of $1,651,014 and $2,065,017, respectively.

The difference was primarily due to lower lease operating, lease impairment, and credit

loss expenses recognized during the nine months ended September 30, 2025 when compared to the same period in 2024.

During the three months

ended September 30, 2025 and 2024, we incurred net losses of $550,293 and $1,184,291, respectively.

The difference was due primarily

an impairment of $337,500 recognized during the period in 2024.

the first nine months of 2025, revenues from oil and gas production decreased $376,201 or 21.5%, to $1,372,919 during the period in 2025

from revenues of $1,749,120 during the first nine months of 2024.

This decrease was mainly due to lower oil and natural gas production

volumes and lower oil commodity prices.

The net sales volume of oil and condensate for the six months ended June 30, 2025, was approximately

10,500 barrels with an average price of $64.29 per barrel, versus 14,280 barrels with an average price of $75.18 per barrel for the six

months of 2024.

This represents a decrease in net sales volume of 3,780 barrels or 26.5%, which was mainly due to 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 six months

ended June 30, 2025, was approximately 50,801 Mcf with an average price of $2.19 per Mcf, versus 61,073 Mcf with an average price of

$1.87 per Mcf for the same period in 2024.

The net sales volume of oil and condensate for the nine months ended September 30, 2025, was

approximately 18,592 barrels with an average price of $63.86 per barrel, versus 21,079 barrels with an average price of $74.88 per barrel

for the nine months of 2024.

This represents a decrease in net sales volume of 2,487 barrels or 11.8%, which was mainly due to 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 nine months ended September 30, 2025, was approximately 84,898 Mcf with an average price of $2.15 per Mcf, versus 91,255 Mcf

with an average price of $1.84 per Mcf for the same period in 2024.

This represents a decrease in net sales volume of 6,357 Mcf or 7.0%.

The decrease in natural

gas production volume was also due to the weather related issues in our Jameson field and to some of our California natural gas wells

being offline for approximately a month due to mandatory pipeline inspections by Pacific Gas and Electric.

For the quarter ended June

30, 2025, revenues from oil and gas production decreased $213,509 or 39.1% to $332,237 from the 2024 second quarter revenues of $545,746.

This decrease was also due to lower oil production volumes and lower oil commodity prices.

The net sales volume of oil and condensate

for the quarter ended June 30, 2025, was approximately 4,812 barrels with an average price of $58.44 per barrel, versus 6,476 barrels

with an average price of $79.41 per barrel for the second quarter of 2024.

This represents a decrease in net sales volume of 1,664 barrels

or 25.7% for the quarter in 2025.

The net sales volume of natural gas for the quarter ended June 30, 2025, was approximately 28,035 Mcf

with an average price of $1.78 per Mcf, versus 28,414 Mcf with an average price of $1.07 per Mcf for the second quarter of 2024.

represents a decrease in net sales volume of 379 Mcf or 1.3% for the quarter in 2025.

and natural gas lease operating expenses decreased by $187,148 or 24.0%, to $592,977 for the six months ended June 30, 2025, from $780,125

for the same period in 2024.

For the second quarter of 2025, lease operating expenses decreased $43,233 or 12.5% from the same quarter

Both of these decreases were due to lower workover related costs and equipment repairs on our Jameson field during the period

in 2025 as we attempted to increase production during the period in 2024.

aggregate of supervisory fees and other income was $52,981 for the six months ended June 30, 2025, an increase of $22,723 from $30,258

during the same period in 2024.

During the second quarter of 2025, supervisory fees and other income increased $7,325 when compared to

the quarter in 2024.

These increases were mainly due to higher interest income on our bank balances.

Depreciation,

depletion and amortization expense decreased to $115,480 from $197,179, a decrease of $81,699 or 41.4% for the six months ended June

30, 2025, as compared to the same period in 2024.

During the second quarter 2025, depreciation, depletion and amortization expenses decreased

$67,891 or 61.6%.

The depletion rate is calculated using production as a percentage of reserves.

This decrease in depletion expense was

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

June 30, 2025, Royale Energy had a Deferred Drilling Obligation of $13,282,996.

During the first six months of 2025, although we participated

in the drilling of a well in the Texas Permian basin, we did not book turnkey gains or losses as we waited for the well to be completed

and the final costs to be determined.

At June 30, 2024, Royale Energy had a Deferred Drilling Obligation of $9,465,832.

During the first

six months of 2024, we removed $3,371,095 of drilling obligations as we participated in the drilling and completion of two oil wells

in the Texas Permian basin, while incurring expenses of $2,843,380, resulting in a gain of $527,715.

and administrative expenses increased by $24,015 or 2.9% from $828,031 for the six months ended June 30, 2024 to $852,046 for the same

period in 2025.

For the second quarter 2025, general and administrative expenses increased $4,921 or 1.3% when compared to the same period

These increases were mainly due to higher employee related expenses due primarily to marketing bonuses paid to employees during

the period in 2025.

For the first six months of 2025, marketing expenses increased $24,755 or 17.5% to $166,528, compared to $141,773

for the first six months of 2024.

For the second quarter 2025, marketing expenses increased $15,712 or 19.2% when compared to the second

quarter in 2024.

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

their associated costs.

and accounting expense decreased to $305,712 for the six-month period in 2025, compared to $342,164 for the same period in 2024, a $36,452

For the second quarter 2025, legal and accounting expenses decreased $2,419 or 3.9%.

These decreases during the period in 2025

were primarily due to higher legal fees related to our debt facility entered into during the period in 2024.

the six months ended June 30, 2025, we recorded a $220,692 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 six months ended June 30, 2025, we recorded

a gain on settlement of $105,494 with a vendor due to an equipment failure which occurred during a workover.

During the six months ended

June 30, 2025, we recorded impairments of $27,250 on various lease and land costs in our California natural gas fields where the carrying

value exceeded the fair value, compared to $63,054, recorded in the first six months of 2024.

During the six months ended June 30, 2025

and 2024, we also recorded Credit Loss expenses of $13,126 and $176,044, 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 (“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.

expense for the six months ended June 30, 2025, and 2024, was $195,112 and $99,740, respectively.

The higher 2025 interest expense was

due to the $1.4 million note payable entered into in February 2024, discussed in Note 8 and the notes payable related to the debt restructuring

in October 2024, discussed in Note 9.

RESOURCES AND LIQUIDITY

June 30, 2025, we had current assets totaling $9,463,845 and current liabilities totaling $21,494,800, resulting in a $12,030,955 working

capital deficit.

We had $1,456,696 in cash and $6,000,000 in restricted cash at June 30, 2025, compared to $1,877,163 in cash and $6,025,000

in restricted cash at December 31, 2024.

June 30, 2025, our other receivables, which consist of joint interest billing receivables from direct working interest investors and

industry partners, totaled $685,566 compared to $868,429 at December 31, 2024, a $182,863 or 21.1% decrease, mainly due to lower joint

interest billing receivables.

At June 30, 2025, revenue receivable was $332,426, a decrease of $432,227, compared to $764,653 at December

31, 2024, due to lower production volumes and commodity prices during the period in 2025 when compared to the fourth quarter of 2024.

At June 30, 2025, our accounts payable and accrued expenses totaled $5,066,253, a decrease of $1,900,352 from the accounts payable at

December 31, 2024 of $6,966,605, which was mainly due to lower revenue payables at the end of the second quarter 2025 and accounts payable

payments and accrued liability settlements during the period in 2025.

have had recurring operating and net losses and cash used in operations and the consolidated financial statements reflect a working capital

deficiency of $12,030,955 and an accumulated deficit of $94,605,190.

These factors raise substantial doubt about our ability to continue

as a going concern, and anticipate that our primary sources of liquidity will be from the sale of oil and gas in the course of normal

operations, the sale of oil and gas property, sales of participation interest and possible issuance of debt and/or equity.

unable to generate sufficient cash from operations or financing sources, it may become necessary to curtail, suspend or cease operations,

sell property, or enter into financing transaction(s) on less favorable terms;

any such outcomes could have a material adverse effect

on our business, results of operations, financial position, and liquidity.

Management has plans to increase revenues by making commitments

to participate with industry partners in drilling wells in the Permian basin and will also continue to drill and workover wells in our

Texas Jameson field.

Although there are no assurances, Management believes that expected increases in revenue together with reduced capital

expenditures for drilling should allow the Company to meet its liquidity needs through the remainder of 2025.

Net cash used in operating activities totaled $2,247,911 and $728,190 for the six months ended June 30, 2025 and 2024,

respectively, a $1,519,721 or 209% difference.

This difference in cash used was mainly due to a decrease in accounts payable and accrued

expenses due to payments made during the period, lower revenue payables to direct working interest owners due to lower revenue receipts,

and to accrued asset retirement liability settlements during the 2025 period.

Net cash provided by investing activities totaled $1,808,069 for the six months ended June 30, 2025, while net cash used

in investing activities totaled $561,191 for the six months ended June 30, 2024.

During the six month period in 2025, we received approximately

$1.8 million in drilling funds while our drilling and lease expenditures were approximately $16,900.

During the six-month period in 2024,

we received approximately $3.1 million in drilling funds while our drilling and lease expenditures were approximately $3.6 million as

we participated in drilling and obtained lease interests in the Permian basin.

Net cash used in financing activities totaled $5,625 for the six months ended June 30, 2025 and net cash provided by

financing activities was $1,393,728 for the six months ended June 30, 2024.

The difference in cash provided, was due to receipt of $1.4

million from the note payable discussed in Note 8.

During the six-month periods in 2025 and 2024, the totals were also used for principal

payments on our financing lease payments.

Accounting Estimates

critical accounting policies are further disclosed in Note 1 to the consolidated financial statements included in our 2024 Annual Report

on Form 10-K.

The decrease in natural gas production volume was also due to the weather related issues in our Jameson field and to some of our California

natural gas wells being offline for approximately a month due to mandatory pipeline inspections by Pacific Gas and Electric.

quarter ended September 30, 2025, revenues from oil and gas production increased $24,867 or 4.4% to $584,576 from the 2024 third quarter

revenues of $559,709.

This increase was due to higher oil and natural gas production volumes during the period in 2025.

The net sales

volume of oil and condensate for the quarter ended September 30, 2025, was approximately 8,092 barrels with an average price of $63.29

per barrel, versus 6,800 barrels with an average price of $74.25 per barrel for the third quarter of 2024.

This represents an increase

in net sales volume of 1,292 barrels or 19.0% for the quarter in 2025.

The net sales volume of natural gas for the quarter ended September

30, 2025, was approximately 34,096 Mcf with an average price of $2.11 per Mcf, versus 30,182 Mcf with an average price of $1.79 per Mcf

for the third quarter of 2024.

This represents an increase in net sales volume of 3,914 Mcf or 13.0% for the quarter in 2025.

Oil and natural gas lease operating expenses decreased by $444,056

or 34.4%, to $848,469 for the nine months ended September 30, 2025, from $1,292,525 for the same period in 2024.

For the third quarter

of 2025, lease operating expenses decreased $151,414 or 29.6% from the same quarter in 2024.

Both of these decreases were partially due

to lower workover related costs and equipment repairs on our Jameson field during the period in 2025 as we attempted to increase production

during the period in 2024.

During the nine months ended September 30, 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 the nine months ended September 30, 2025,

we recorded a settlement of accounts payable of $53,583 due to the write-off of accounts payable where vendors are not legally entitled

The aggregate of supervisory fees and other income was $74,234 for the

nine months ended September 30, 2025, an increase of $29,271 from $44,963 during the same period in 2024.

During the third quarter of

2025, supervisory fees and other income increased $6,548 when compared to the same quarter in 2024.

These increases were mainly due to

higher interest income on our bank balances.

Depreciation, depletion and amortization expense decreased to $198,976

from $253,726, a decrease of $54,750 or 21.6% for the nine months ended September 30, 2025, compared to the same period in 2024.

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

The depreciation

rate is calculated using production as a percentage of reserves.

During the third quarter 2025, depreciation, depletion and amortization

expenses increased $26,949 or 47.7% due to an increase in our oil and gas assets during the quarter due to our purchase of additional

interests in existing wells.

At September 30, 2025, Royale Energy had a Deferred Drilling Obligation

of $13,982,996.

During the first nine months of 2025, although we participated in the drilling of a well in the Texas Permian basin,

we did not book turnkey gains or losses as we waited for the well to be completed and the final costs to be determined.

At December 31,

2024, Royale Energy had a Deferred Drilling Obligation of $11,328,332.

During the first nine months of 2024, we removed $3,371,095 of

drilling obligations as we participated in the drilling and completion of two oil wells in the Texas Permian basin, while incurring expenses

of $2,843,380, resulting in a gain of $527,715.

General and administrative expenses increased by $37,326 or 3.1% from $1,197,677

for the nine months ended September 30, 2024 to $1,235,003 for the same period in 2025.

For the third quarter 2025, general and administrative

expenses increased $13,311 or 3.6% when compared to the same period in 2024.

These increases were mainly due to higher employee related

expenses during the periods in 2025.

For the first nine months of 2025, marketing expenses decreased $41,252 or 15.3% to $228,732, compared

to $269,984 for the first nine months of 2024.

For the third quarter 2025, marketing expenses decreased $66,007 or 51.5% when compared

to the third quarter in 2024.

Marketing expense varies from period to period according to the number of marketing events attended by our

personnel and their associated costs.

Legal and accounting expense decreased to $382,660 for the nine-month period

in 2025, compared to $485,114 for the same period in 2024, a decrease of $102,454 or 21.1%.

For the third quarter 2025, legal and accounting

expenses decreased $66,002 or 46.2%.

These decreases during the periods in 2025 were primarily due to higher legal fees related to our

debt facility entered into during the period in 2024.

During the nine months ended September 30, 2025, we recorded a $230,681

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 nine months ended September 30, 2025 and 2024, we recorded impairments of $27,250 and $400,554, respectively,

on various lease and land costs in our California natural gas fields where the carrying value exceeded the fair value.

During the nine

months ended September 30, 2025 and 2024, we also recorded Credit Loss expenses of $111,558 and $279,491, 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.

Interest expense for the nine months ended September 30, 2025, and

2024, was $296,200 and $207,744, respectively.

The higher 2025 interest expense was due to the $1.4 million note payable entered into

in February 2024, discussed in Note 8 and the notes payable related to the debt restructuring in October 2024, discussed in Note 9.

CAPITAL RESOURCES AND LIQUIDITY

At September 30, 2025, we had current assets totaling $8,765,809 and

current liabilities totaling $20,992,223, resulting in a $12,226,414 working capital deficit.

We had $796,979 in cash and $5,476,900 in

restricted cash at September 30, 2025, compared to $1,877,163 in cash and $6,025,000 in restricted cash at December 31, 2024.

At September 30, 2025, our other receivables, which consist of joint

interest billing receivables from direct working interest investors and industry partners, totaled $663,775 compared to $868,429 at December

31, 2024, a $204,654 or 23.6% decrease, mainly due to lower joint interest billing receivables.

At September 30, 2025, revenue receivable

was $573,638, a decrease of $191,015, compared to $764,653 at December 31, 2024, due to lower production volumes and commodity prices

during the period in 2025 when compared to the fourth quarter of 2024.

At September 30, 2025, our accounts payable and accrued expenses

totaled $5,261,628, a decrease of $1,704,977 from the accounts payable at December 31, 2024 of $6,966,605, which was mainly due to lower

revenue payables at the end of the third quarter 2025 and accounts payable payments and accrued liability settlements during the period

We have had recurring operating and net losses and cash used in operations

and the condensed consolidated financial statements reflect a working capital deficiency of $12,226,414 and an accumulated deficit of $95,155,483.

These factors raise substantial doubt about our ability to continue as a going concern, and anticipate that our primary sources of liquidity

will be from the sale of oil and gas in the course of normal operations, the sale of oil and gas properties, sales of participation interests

in oil and gas wells and possible issuance of debt and/or equity.

If we are unable to generate sufficient cash from operations or financing

sources, it may become necessary to curtail, suspend or cease operations, sell property, or enter into financing transaction(s) on less

favorable terms;

any such outcomes could have a material adverse effect on our business, results of operations, financial position, and

Management has plans to increase revenues by making commitments to participate with industry partners in drilling wells in

the Permian basin and will also continue to drill and workover wells in our Texas Jameson field.

Although there are no assurances, Management

believes that expected increases in revenue together with reduced capital expenditures for drilling should allow the Company to meet its

liquidity needs through the remainder of 2025.

Operating Activities.

Net cash used in operating activities totaled

$2,675,708 and $1,381,384 for the nine months ended September 30, 2025 and 2024, respectively, a $1,294,324 or 93.7% difference.

difference in cash used was mainly due to a decrease in accounts payable and accrued expenses due to payments made during the period,

lower revenue payables to direct working interest owners due to lower revenue receipts, and to accrued asset retirement liability settlements

during the 2025 period.

Investing Activities.

Net cash provided by investing activities

totaled $555,994 and $231,089 for the nine months ended September 30, 2025 and 2024, respectively, a $324,905 or 140.6% difference.

the nine month period in 2025, we received approximately $2.5 million in drilling funds while our drilling and lease expenditures were

approximately $2.0 million, mainly due to our purchase of additional interests in our existing Permian basin wells.

During the nine-month

period in 2024, we received approximately $4.9 million in drilling funds while our drilling and lease expenditures were approximately

$4.7 million as we participated in drilling and obtained lease interests in the Permian basin.

Financing Activities.

Net cash provided by financing activities

totaled $491,430 and $1,393,039 for the nine months ended September 30, 2025 and 2024, respectively.

The difference in cash provided,

was due to receipt of $500,000 during the period in 2025 and $1.4 million received in 2024 from the note payable discussed in Note 8.

During the nine-month periods in 2025 and 2024, $8,570 and $6,961, respectively, were used for principal payments on our financing lease

Critical Accounting Estimates

Our critical accounting policies are further disclosed in Note 1 to

the consolidated financial statements included in our 2024 Annual Report on Form 10-K.

Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

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-Q

Item 1. Financial Statements