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Item 1. Financial Statements

2025-05-15 compared with 2024-11-14 · 585 added, 402 removed, 134 unchanged (88% of the section changed)

2 unchanged sentences

CONDENSED CONSOLIDATED BALANCE SHEETS

September 30, 2024

December 31, 2023

Current Assets:

3 unchanged sentences

Revenue Receivables

Prepaid Expenses

Deferred Drilling Costs

Prepaid Expenses and Other Current Assets

Total Current Assets

Right of Use Assets - Leases

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

See notes to unaudited condensed consolidated financial statements.

Right of Use Asset - Operating Leases

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

September 30, 2024

December 31, 2023

LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)

LIABILITIES AND STOCKHOLDERS’ DEFICIT

Current Liabilities:

Accounts Payable and Accrued Expenses

Notes Payable - Current

Royalties Payable

Due to RMX Resources, LLC

Accrued Liabilities

Asset Retirement Obligation - Current

Deferred Drilling Obligation

RMX Resources, LLC

Operating Leases - Current

Asset Retirement Obligation - Current

Deferred Drilling Obligations

Total Current Liabilities

Noncurrent Liabilities:

Accrued Liabilities - Long Term

Accrued Unpaid Guaranteed Payments

Notes Payable to Related Parties

Operating Leases - Long-Term

Asset Retirement Obligation

Notes Payable - Non-current

Operating Leases - Non-current

Accrued Unpaid Guaranteed Payments

Accrued Liabilities - Non-current

Total Liabilities

Mezzanine Equity:

Convertible Preferred Stock, Series B, $ 10 par value, 3.5 % annual dividend, 2,466,455 and 2,444,885 shares issued and outstanding as of September 30, 2024 and December 31, 2023, respectively.

Stockholders' Equity (Deficit):

Common Stock, .001 Par Value, 280,000,000 Shares Authorized, 71,863,829 and 70,564,188 shares issued and outstanding as of September 30, 2024 and December 31, 2023, respectively.

Stockholders’ Deficit:

Common Stock, .001 Par Value, 280,000,000 Shares Authorized 96,600,302 and 96,600,302 shares issued and outstanding at March 31 2025 and December 31, 2024, respectively

Additional Paid in Capital

Accumulated Deficit

Total Stockholders' Equity (Deficit)

Total Liabilities and Stockholders' Equity (Deficit)

See notes to unaudited condensed consolidated financial statements.

( 94,186,420 )

( 93,504,469 )

Total Stockholders’ Deficit

( 13,011,266 )

( 12,329,315 )

Total Liabilities, and Stockholders’ Deficit

See notes to unaudited condensed consolidated financial

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

For the three months ended

For the nine months ended

September 30, 2024

September 30, 2023

September 30, 2024

September 30, 2023

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Oil, NGL and Gas Sales

4 unchanged sentences

Depreciation, Depletion and Amortization

Well Equipment Write Down

Lease Impairment

Credit Loss Expense

Legal and Accounting

Bad Debt Expense

General and Administrative

Total Costs and Expenses

Gain (Loss) on Turnkey Drilling

Loss From Operations

1 unchanged sentence

Interest Expense

Preferred Stock Dividend

Gain on Settlement of Liability

Gain on Settlement of Accounts Payable

Preferred Stock Dividend in Arrears

Net Loss available to common stock

$ ( 681,951 )

$ ( 985,331 )

Shares used in computing Basic Net Loss per share

Basic and Diluted (Loss) Per Share

Basic Loss per share

Shares used in computing Diluted Net Loss per share

Diluted Net Income (Loss) per Share

See notes to unaudited condensed consolidated financial statements.

Diluted Loss per share

See notes to unaudited condensed consolidated financial

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

For the Nine Months Ended

September 30, 2024

September 30, 2023

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE THREE MONTHS ENDED MARCH 31, 2025 AND

For the Three Months Ended

CASH FLOWS FROM OPERATING ACTIVITIES

Adjustments to Reconcile Net Loss to Net

Cash Used in Operating Activities:

$ ( 681,951 )

$ ( 770,110 )

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

Depreciation, Depletion and Amortization

Gain on Turnkey Drilling Programs

Lease Impairment

Bad debt expense

Well Equipment Write Down

Credit Loss Expense

Gain on Settlement of Accounts Payable

Gain on Settlement of Liability

Stock-Based Compensation

Gain on Other

Accretion of Debt Restructure Notes Payable

Right of use asset depreciation

(Increase) Decrease in:

Changes in assets and liabilities:

Other & Revenue Receivables

Prepaid Expenses and Other Assets

Increase (Decrease) in:

Accounts Payable and Accrued Expenses

Royalties Payable

Net Cash Used in Operating Activities

1 unchanged sentence

Expenditures for Oil and Gas Properties and Other Capital Expenditures

( 3,188,357 )

Proceeds from Turnkey Drilling Programs

Net Cash Provided by Investing Activities

Net Cash Provided (Used) by Investing Activities

( 2,038,357 )

CASH FLOWS FROM FINANCING ACTIVITIES

Proceeds from Related Party Note Payable

Principal Payments on Long-Term Debt

Net Cash Provided by (Used in) Financing Activities

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

Proceeds from Long Term Debt

Lease Financing Payments

Net Cash Provided (Used) by Financing Activities

Net Decrease in Cash, Cash Equivalents, and Restricted Cash

( 1,220,734 )

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

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

SUPPLEMENTAL DISCLOSURES OF CASH FLOWS INFORMATION:

Cash Paid for Interest

Cash Paid for Taxes

See notes to unaudited condensed consolidated financial statements.

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' EQUITY (DEFICIT)

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2024 AND 2023

Number of Shares Issued and Outstanding

Additional Paid in Capital

Comprehensive Deficit

Stockholders' Deficit

Common Shares

Common Amount

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’

EQUITY (DEFICIT)

FOR THE THREE MONTHS ENDED MARCH 31, 2025 AND

Comprehensive

Stockholders’

December 31, 2023 Balance

Cashless Warrant Exercise Issuance

$ ( 90,323,289 )

$ ( 35,633,489 )

Stock Issued in lieu of Compensation

Preferred Series B 3.5 % Dividend

September 30, 2023 Balance

Common Shares

Common Amount

March 31, 2024 Balance

$ ( 91,308,620 )

$ ( 36,582,821 )

December 31, 2024 Balance

Stock Issued in lieu of Compensation

Preferred Series B 3.5 % Dividend

September 30, 2024 Balance

Number of Shares Issued and Outstanding

Additional Paid in Capital

Accumulated Comprehensive Deficit

Stockholders' Deficit

Common Shares

Common Amount

June 30, 2023 Balance

Preferred Series B 3.5 % Dividend

September 30, 2023 Balance

Common Shares

Common Amount

June 30, 2024 Balance

Preferred Series B 3.5 % Dividend

September 30, 2024 Balance

See notes to unaudited condensed consolidated financial statements.

$ ( 93,504,469 )

$ ( 12,329,315 )

March 31, 2025 Balance

$ ( 94,186,420 )

$ ( 13,011,266 )

See notes to unaudited condensed consolidated financial

ROYALE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL

NOTE 1 – BASIS OF PRESENTATION:

1 unchanged sentence

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.

Significant 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, 2023 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, 2023 as filed with the SEC.

Operating results for the nine months ended September 30, 2024 are not necessarily indicative of the results that may be expected for the fiscal year ending December 31, 2024, or for any other period.

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

Operating results for the three months ended March 31, 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 Company’s 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, 2024, our consolidated financial statements reflect a working capital deficiency of $ 10,990,782 , and an accumulated deficit of $ 93,042,036 .

We had a net loss of $ 2,065,017 for the nine months ended September 30, 2024.

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 March 31, 2025, our consolidated financial statements reflect a

working capital deficiency of $ 11,969,565 , and an accumulated deficit of $ 94,186,420 .

We had a net loss of $ 681,951 for the three months

ended March 31, 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 implementing cost control measures that include, among other things, the reduction of overhead costs, the sale of non-strategic assets, and, if possible, obtaining additional 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 funds, 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 such a plan will be successful.

Reclassifications

Certain reclassifications of amounts previously reported have been made to the accompanying financial statements to maintain consistency between periods presented.

The reclassifications had no impact on previously reported equity.

The accompanying

consolidated financial statements do not include any adjustments that might be necessary if we are unable to continue as a going concern.

Management’s plans to alleviate the going concern by implementing

cost control measures that include, among other things, the reduction of overhead costs, the sale of non-strategic assets, and, if possible,

obtaining additional 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.

we are unable to raise sufficient additional funds, 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.

no assurance that such a plan will be successful.

Use of Estimates

The accompanying financial statements have been prepared in conformity with 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.

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.

Actual results could differ from those estimates.

Material estimates that are particularly susceptible to significant change relate to the estimate of the Company’s 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.

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:

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:

For the three months 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.

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.

As such, we do not have any financing element associated with our contracts.

We do not have any issues related to returns or refunds, as product specifications are standardized for the industry and are typically measured when transferred to a common carrier or midstream entity, and other contractual mechanisms (e.g., price adjustments) are used when products do not meet those specifications.

In limited cases, we may also collect advance payments from customers as stipulated in our agreements;

payments in excess of recognized revenue are recorded as contract liabilities on our consolidated balance sheets.

Under our hydrocarbon sales agreements, the entire consideration amount is variable either due to pricing and/or volumes.

We recognize revenues in the amount of variable consideration allocated to distinct units of hydrocarbons transferred to a customer.

Such allocation reflects the amount of total consideration we expect to collect for completed deliveries of hydrocarbons, and the terms of variable payment relate specifically to our efforts to satisfy the performance obligations under these contracts.

Our performance obligations under our hydrocarbon sales agreements are to deliver either the entire production from the dedicated wells or specified contractual volumes of hydrocarbons.

We 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 applicable joint operating arrangement and collective decisions of the joint parties.

Other working interest owners reimburse us for costs incurred based on our agreements.

We determined that these activities are not performed as part of customer relationships, and such reimbursements are recorded as cost reimbursements.

We commonly market the share of production belonging to other working interest owners as the operator of jointly owned oil and gas properties.

Those marketing activities are carried out as part of the collaborative arrangement, and we do not purchase or otherwise obtain control of other working interest owners’ share of production.

Therefore, we act as a principal only 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 (typically call “Casing Point Election” or “Logging Point”), the difference in the actual cost to drill and the guaranteed cost is recorded as income or expense depending on whether there was a gain or loss.

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 (typically call “Casing Point Election” or “Logging Point”), the difference in the actual

cost to drill and the guaranteed cost is recorded as income or expense depending on whether there was a gain or loss.

Crude oil and condensate

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

For the crude sales agreements, we satisfy our performance obligations

and recognize revenue once customers take control of the crude at the designated delivery points, which include pipelines, trucks, or

Natural gas and NGLs

When selling natural gas and natural gas liquids (“NGLs”), we engage midstream entities to process our production stream by separating natural gas from the NGLs.

Frequently, these midstream entities also purchase our natural gas and NGLs under the same agreements.

In these situations, we determined the performance obligation is complete and satisfied at the tailgate of the processing plant when the natural gas and NGLs become identifiable and measurable products.

We determined the plant tailgate is the point in time where control is transferred to midstream entities and they are entitled to significant risks and rewards of ownership of the natural gas and NGLs.

The amounts due to midstream entities for gathering and processing services are recognized as shipping and handling cost and included as lease operating expense in our consolidated statement of operations, since we make those payments in exchange for distinct services 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.

Turnkey Drilling

When selling natural gas and NGLs, we engage midstream entities to

process our production stream by separating natural gas from the NGLs.

Frequently, these midstream entities also purchase our natural

gas and NGLs under the same agreements.

In these situations, we determined the performance obligation is complete and satisfied at the

tailgate of the processing plant when the natural gas and NGLs become identifiable and measurable products.

We determined the plant tailgate

is the point in time where control is transferred to midstream entities and they are entitled to significant risks and rewards of ownership

of the natural gas and NGLs.

The amounts due to midstream entities for gathering and processing

services are recognized as shipping and handling cost and included as lease operating expense in our consolidated statement of operations,

since we make those payments in exchange for distinct services 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 properties.

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

Each participant earns an undivided interest in the well bore at the completion of the well.

A portion of the funds received in advance of the drilling of a well from a working interest participant are held for the expressed purpose of drilling a well (“Drilling Funds”).

If something changes, we may designate the Drilling Funds to drill a substitute well.

Under certain conditions, a portion of the Drilling Funds may be required to be returned to a participant.

Once the well is drilled, the Drilling Funds are used to satisfy the drilling cost.

We manage these Turnkey Agreements for the participants of the well.

We segregate the collections of pre-drilling Authorization for Expenditure (“AFE”) amounts and the gains and losses on the Turnkey Agreements are recorded in income or expense at the time of the casing point election in accordance with the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 932-323-25 and 932-360.

We manage the performance obligation for the well participants and only record revenue or expense at the time the performance obligation of the Turnkey Agreement has been satisfied.

Restricted Cash

Prior to commencement of drilling, we classify Drilling Funds as restricted cash based on guidance codified under ASC 230-10-50-8.

In the event that progress payments are made from these funds, they are recorded as Prepaid Expenses and Other Current Assets.

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

September 30, 2024

December 31, 2023

Each participant earns

an undivided interest in the well bore at the completion of the well.

A portion of the funds received in advance of the drilling of a

well from a working interest participant are held for the express purpose of drilling a well.

If something changes, we may designate these

funds for a substitute well.

Under certain conditions, a portion of these funds may be required to be returned to a participant.

the well is drilled, the funds are used to satisfy the drilling cost.

We classify these funds prior to commencement of drilling as restricted

cash based on guidance codified as under the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification

(“ASC”) 230-10-50-8.

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

they are recorded as Prepaid Expenses

and Other Current Assets.

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

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

Cash and Cash Equivalents

2 unchanged sentences

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 consolidated balance sheet.

Currently, the Company has no equity investments.

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.

When a loss is deemed to have occurred and is other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income.

Investments in entities over which we have significant influence, but

not control, are accounted for using the equity method of accounting.

Income from equity method investments represents our proportionate

share of net income generated by the equity method investees and is reflected in revenue and other income in our consolidated statements

Equity method investments are included as noncurrent assets on the consolidated balance sheets.

Equity method investments are assessed for impairment whenever changes

in the facts and circumstances indicate a loss in value may have occurred as called for under ASC 323, Investments—Equity Method

and Joint Ventures.

When a loss is deemed to have occurred and is other than temporary, the carrying value of the equity method investment

is written down to fair value, and the amount of the write-down is included in income.

Other Receivables, net

Other receivables, net, consist of joint interest billing receivables from direct working interest investors and industry partners.

Our other receivables consist of receivables from direct working interest

investors and industry partners.

We account for expected credit losses on receivables using the Current Expected Credit Loss (CECL) methodology.

Under this standard, an allowance for expected credit losses is established and adjusted based on historical loss experience, current conditions, and reasonable and supportable forecasts of future economic conditions.

The allowance account is increased or decreased in response to changes in these factors, reflecting our best estimate of credit losses over the remaining life of the receivables.

All amounts considered uncollectible are charged against the allowance account, while recoveries of previously charged-off accounts are added back to the allowance.

At September 30, 2024, and December 31, 2023, we maintained an allowance for expected credit losses of $ 2,023,302 and $ 1,837,551 , respectively, primarily for receivables from direct working interest investors whose expenses on non-producing wells are unlikely to be collected from revenue.

Fair Value Measurements

According to the Fair Value Measurements and Disclosures Topic of the FASB ASC, assets and liabilities that are measured at fair value on a recurring and nonrecurring basis in periods subsequent to initial recognition, the reporting entity shall disclose information that enables users of its financial statements to assess the inputs used to develop those measurements and for recurring fair value measurements using significant unobservable inputs and the effect of the measurements on earnings for the period.

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

In determining fair value, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible as well as considering counterparty credit risk in our assessment of fair value.

Carrying amounts of our financial instruments, including cash equivalents, accounts receivable, accounts payable and accrued liabilities, approximate their fair values as of the balance sheet dates because of their generally short maturities.

The fair value hierarchy distinguishes between (1) market participant assumptions developed based on market data obtained from independent sources (observable inputs) and (2) an entity’s own assumptions about market participant assumptions developed based on the best information available in the circumstances (unobservable inputs).

The fair value hierarchy consists of three broad levels, which gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

The three levels of the fair value hierarchy are described below:

Quoted prices (unadjusted) in active markets that are accessible at the measurement date for assets or liabilities.

Directly or indirectly observable inputs as of the reporting date through correlation with market data, including quoted prices for similar assets and liabilities in active markets and quoted prices in markets that are not active.

Level 2 also includes assets and liabilities that are valued using models or other pricing methodologies that do not require significant judgment since the input assumptions used in the models, such as interest rates and volatility factors, are corroborated by readily observable data from actively quoted markets for substantially the full term of the financial instrument.

Unobservable inputs that are supported by little or no market activity and reflect the use of significant management judgment.

These values are generally determined using pricing models for which the assumptions utilize management’s estimates of market participant assumptions.

At September 30, 2024 and December 31, 2023, we do not have any financial assets measured and recognized at fair value on a recurring basis.

We estimate asset retirement obligations (AROs) pursuant to the provisions of ASC 410, “ Asset Retirement and Environmental Obligations ”.

The estimates of the fair value the ARO's are based on discounted cash flow projections using numerous estimates, assumptions, and judgements regarding such factors as the existence of a legal obligation for an ARO, amounts and timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates.

The initial measurement of AROs at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties.

Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs.

Other receivables will be reflected as Level 3.

The fair value of our other receivables is based on credit factors, oil and gas well reserve profiles and commodity prices both current and forecast specific to these financial instruments.

Fair Values - Non-recurring

We applied the provisions of the fair value measurement standard to our non-recurring, non-financial measurements including oil and natural gas property impairments and other long-lived asset impairments.

These items are not measured at fair value on a recurring basis but are subject to fair value adjustments only in certain circumstances.

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 March 31, 2025 and December 31, 2024, we established

an allowance for expected credit losses of $ 2,182,424 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

The Series B Convertible Preferred Stock (“Preferred Stock”) has 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 additional shares of the Preferred Stock, for the settlement of dividends paid in kind and accumulated through December 31, 2023.

We accrued $ 653,730 and $ 629,007 for dividends related to the Preferred Stock for the first nine months of 2024 and 2023, respectively.

Each quarter, we charge retained earnings for the accumulating dividend as the amounts add to the liquidation preference of the Preferred Stock.

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

transaction, eliminating our Series B, 3.5 % Convertible Preferred Stock.

The Series B Convertible 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.

ACCOUNTING STANDARDS

Recently Adopted

NOTE 2 – OIL AND GAS PROPERTY AND EQUIPMENT AND FIXTURES

Oil and gas properties, equipment and fixtures consist of the following:

September 30,

Recently Issued, Not Yet Adopted

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

2023-09, “Improvements to Income Tax Disclosures,” issued by the Financial Accounting Standards Board (FASB).

requires enhanced disclosures around income taxes, including additional detail regarding the rate reconciliation and the presentation

of income taxes paid, to provide financial statement users with more transparent information about tax exposures and cash flow implications

with an effective date for annual periods beginning after December 15, 2024.

While we are still evaluating the implications of this standard,

the adoption of ASU 2023-09 should not materially impact our financial position, results of operations, or cash flows, as the update affects

disclosures only.

NOTE 2 – OIL AND GAS PROPERTY AND EQUIPMENT

Oil and gas properties, equipment and fixtures consist of:

Producing properties, including drilling costs

2 unchanged sentences

Accumulated depletion, depreciation & amortization

Net capitalized costs

( 7,819,955 )

( 7,748,190 )

Net capitalized costs Total

Commercial and Other

1 unchanged sentence

Accumulated depreciation

Net capitalized costs

The guidance set forth in the Continued Capitalization of Exploratory Well Costs paragraph of the Extractive Activities Topic of the FASB ASC requires that we evaluate all existing capitalized exploratory well costs and disclose the extent to which any such capitalized costs have become impaired and are expensed or reclassified during a fiscal period.

Depreciation, depletion, and amortization, based on cost less estimated salvage value of the asset, are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration.

Maintenance and repairs are expensed as incurred.

( 1,138,091 )

( 1,137,597 )

Net capitalized costs Total

The guidance set forth in the Continued Capitalization of Exploratory

Well Costs paragraph of the Extractive Activities Topic of the FASB ASC requires that we evaluate all existing capitalized exploratory

well costs and disclose the extent to which any such capitalized costs have become impaired and are expensed or reclassified during a

fiscal period.

Depreciation, depletion and amortization, based on cost less estimated

salvage value of the asset, are primarily determined under either the unit-of-production method or the straight-line method, which is

based on estimated asset service life taking obsolescence into consideration.

Maintenance and repairs, including planned major maintenance,

are expensed as incurred.

Major renewals and improvements are capitalized and the assets replaced are retired.

The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use.

Interest costs, to the extent they are incurred to finance expenditures during the construction phase, are included in property, plant and equipment and are depreciated over the service life of the related assets.

We use the “successful efforts” method to account for our exploration and production activities.

Under this method, we accumulate our proportionate share of costs on a well-by-well basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred and capitalize expenditures for productive wells.

The project construction phase commences with the development of the

detailed engineering design and ends when the constructed assets are ready for their intended use.

Interest costs, to the extent they

are incurred to finance expenditures during the construction phase, are included in property, plant and equipment and are depreciated

over the service life of the related assets.

We use the “successful efforts” method to account for our

exploration and production activities.

Under this method, we accumulate our proportionate share of costs on a well-by-well basis with

certain exploratory expenditures and exploratory dry holes being expensed as incurred, and capitalize expenditures for productive wells.

We amortize the costs of productive wells under the unit-of-production method.

We carry, as an asset, exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where we are making sufficient progress assessing the reserves and the economic and operating viability of the project.

We carry, as an asset, exploratory well costs when the well has found

a sufficient quantity of reserves to justify its completion as a producing well and where we are making sufficient progress assessing

the reserves and the economic and operating viability of the well.

Exploratory well costs not meeting these criteria are charged to expense.

Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred.

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

Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using unit-of-production rates based on the amount of proved developed reserves of oil and gas that are estimated to be recoverable from existing facilities using current operating methods.

Under the unit-of-production method, oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank.

Acquisition costs of proved

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

Acquisition costs of proved properties are amortized using a unit-of-production

method, computed on the basis of total proved oil and gas reserves.

Capitalized exploratory drilling and development costs associated with

productive depletable extractive properties are amortized using unit-of-production rates based on the amount of proved developed reserves

of oil and gas that are estimated to be recoverable from existing facilities using current operating methods.

Under the unit-of-production

method, oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction

points at the outlet valve on the lease or field storage tank.

Production costs are expensed as incurred.

Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas.

The production function normally terminates at the outlet valve on the lease or field production storage tank.

Production costs are those incurred to operate and maintain our wells and related equipment and facilities.

Production involves lifting

the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas.

The production function

normally terminates at the outlet valve on the lease or field production storage tank.

Production costs are those incurred to operate

and maintain Royale’s wells and related equipment and facilities.

They become part of the cost of oil and gas produced.

These costs, sometimes referred to as lifting costs, include such items as labor costs to operate the wells and related equipment;

repair and maintenance costs on the wells and equipment;

sometimes referred to as lifting costs, include such items as labor costs to operate the wells and related equipment;

repair and maintenance

costs on the wells and equipment;

materials, supplies and energy costs required to operate the wells and related equipment;

and administrative expenses related to the production activity.

Proved oil and gas properties held and used, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable.

We estimate the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts and whether carrying amounts should be impaired.

We perform the evaluation of carrying amounts at least annually or when economic events or commodity prices indicate that a substantial and measurable change in future cash flows has occurred.

Cash flows used in impairment evaluations are developed using updated evaluation assumptions for crude oil and natural gas commodity prices.

and administrative

expenses related to the production activity.

Proved oil and gas properties held and used by Royale are reviewed for impairment whenever

events or changes in circumstances indicate that the carrying amounts may not be recoverable.

We estimate the future undiscounted cash flows of the affected properties

to judge the recoverability of carrying amounts.

Cash flows used in impairment evaluations are developed using annually updated evaluation

assumptions for crude oil commodity prices.

Annual volumes are based on field production profiles, which are also updated annually.

for natural gas and other products are based on assumptions developed annually for evaluation purposes.

Impairment analyses are generally based on proved reserves.

An asset group would be further assessed if the undiscounted cash flows were less than its carrying value.

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

During the nine months ended September 30, 2024, we incurred an impairment loss of $ 400,554 .

No impairment losses were incurred during the nine months ended September 30, 2023.

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

group would be further assessed if the undiscounted cash flows were less than its’ carrying value.

Impairments are measured by the

amount the carrying value exceeds fair value.

During the three months ended March 31, 2025 and 2024, we incurred an impairment loss of

$ 27,250 and $ 56,209 , respectively.

Significant unproved properties are assessed for impairment individually,

and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of

time that Royale expects to hold the properties.

The valuation allowances are reviewed at least annually.

Upon the sale or retirement of a complete field of a proven property, we eliminate the cost, and the resulting gain or loss is recorded to the Consolidated Statement of Operations.

Upon the sale of an entire interest in an unproved property where the property has been assessed for impairment individually, a gain or loss is recognized in the Consolidated Statement of Operations.

If a partial interest in an unproved property is sold, any funds received are accounted for as a recovery of the cost in the interest retained with any excess funds recognized as a gain.

Should our turnkey drilling agreements include unproved property, total drilling costs incurred to satisfy our obligations are recovered by the total funds received under the agreements.

Any excess funds are recorded as a Gain on Turnkey Drilling Programs, and any costs not recovered are capitalized and accounted for under the “successful efforts” method.

We sponsor turnkey drilling agreement arrangements in unproved properties as a pooling of assets in a joint undertaking, whereby proceeds from participants are reported as Deferred Drilling Obligations, and then reduced as costs to complete our obligations are incurred with any excess booked against our property account to reduce any basis in our own interest.

Gains on Turnkey Drilling Programs represent funds received from turnkey drilling participants in excess of all costs we incur during the drilling programs (e.g., lease acquisition, exploration and development costs), including costs incurred on behalf of participants and costs incurred for our own account;

and are recognized only upon making this determination after our obligations have been fulfilled.

The contracts require the participants to pay the full contract price upon execution of the agreement.

Upon the sale or retirement of a complete field of a proved property,

Royale eliminates the cost from its books, and the resultant gain or loss is recorded to Royale’s Statement of Operations.

the sale of an entire interest in an unproved property where the property has been assessed for impairment individually, a gain or loss

is recognized in Royale’s Statement of Operations.

If a partial interest in an unproved property is sold, any funds received are

accounted for as a recovery of the cost in the interest retained with any excess funds recognized as a gain.

Should Royale’s turnkey

drilling agreements include unproved property, total drilling costs incurred to satisfy its obligations are recovered by the total funds

received under the agreements.

Any excess funds are recorded as a Gain on Turnkey Drilling Programs, and any costs not recovered are capitalized

and accounted for under the “successful efforts” method.

We sponsor turnkey drilling agreement arrangements in proved and unproved

properties as a pooling of assets in a joint undertaking, whereby proceeds from participants are reported as Deferred Drilling Obligations,

and then reduced as costs to complete our obligations are incurred with any excess booked against our property account to reduce any basis

in our own interest.

Gains on Turnkey Drilling Programs represent funds received from turnkey drilling participants in excess of all costs

we incur during the drilling programs (e.g., lease acquisition, exploration and development costs), including costs incurred on behalf

of participants and costs incurred for our own account;

and are recognized only upon making this determination after our obligations have

been fulfilled.

The contracts require the participants to pay the full contract price

upon execution of the agreement.

We complete the drilling activities typically between 10 and 30 days after drilling begins.

The participant retains an undivided or proportional beneficial interest in the property and is also responsible for their proportionate share of operating costs.

The participant

retains an undivided or proportional beneficial interest in the property and is also responsible for their proportionate share of operating

We retain legal title to the lease.

The participants purchase a working interest directly in the well bore.

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

A certain portion of the turnkey drilling participant’s funds received are non-refundable.

In these working interest arrangements, the participants are responsible

for sharing in the risk of development, but also sharing in a proportional interest in rights to revenues and proportional liability for

the cost of operations after drilling is completed and the interest is conveyed to the participant.

A certain portion of the turnkey drilling participant’s funds

received are non-refundable.

We record all funds invested as Deferred Drilling Obligations until drilling is complete.

Occasionally, drilling is delayed for various reasons such as weather, permitting, drilling rig availability and/or contractual obligations.

At September 30, 2024, and December 31, 2023, we had Deferred Drilling Obligations of $ 11,328,332 and $ 9,761,927 , respectively.

If we are unable to drill the wells, and a suitable replacement well is not found, we would retain the non-refundable portion of the contract and return the remaining funds to the participant.

Included in Restricted Cash are amounts for use in completion of turnkey drilling in progress.

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

Occasionally, drilling

is delayed for various reasons such as weather, permitting, drilling rig availability and/or contractual obligations.

At March 31, 2025,

and December 31, 2024, we had Deferred Drilling Obligations of $ 12,032,996 and $ 11,457,996 , respectively.

If we are unable to drill the wells, and a suitable replacement well

is not found, we would retain the non-refundable portion of the contract and return the remaining funds to the participant.

Restricted Cash are amounts for use in completion of turnkey drilling in progress.

Losses on properties sold are recognized when incurred or when the

properties are held for sale and the fair value of the properties is less than the carrying value.

NOTE 3 – SERIES B PREFERRED STOCK

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

The Preferred Stock has never been registered under the Securities Exchange Act of 1934, as amended, (“Exchange Act”), and no market exists for the Preferred Stock.

Additionally, the Preferred Stock will automatically convert into shares of common stock at any time in which the Volume Weighted Average Price (“VWAP”) of our common stock exceeds $3.50 per share for 20 consecutive trading days, the shares of our common stock are registered under the Exchange Act, and the trading volume of shares of our common stock exceed 200,000 shares per day.

Beginning in 2020, the holders of the Preferred Stock became entitled to vote the number of shares of our common stock into which the shares of Preferred Stock would be entitled to convert.

In accordance with ASC 480-10-S99-1.02, we have determined that the conversion or redemption of the Preferred Stock are outside the sole control of the Company and that they should be classified in mezzanine or temporary equity as redeemable noncontrolling interest beginning at the reporting period ended June 30, 2020.

For 2023, the board authorized the payment of each quarterly dividend on shares of Preferred Stock as additional shares of Preferred Stock to be Paid-In-Kind and to be paid immediately following the end of the quarter.

During 2024 and 2023 no cash was used to pay dividends on shares of the Preferred Stock.

On October 11, 2024, we entered into an agreement with all of our preferred shareholders, to exchange their shares of Preferred Stock, thereby eliminating the class of stock.

For further information see Note 9 – Subsequent Events.

NOTE 4 – INCOME (LOSS) PER SHARE

Pursuant to the terms of the merger completed in 2018, all Class A

limited partnership interests of Matrix Investments, LP (“Matrix Investments”) were exchanged for our common stock using conversion

ratios according to the relative value of the Class A limited partnership interests, and $20,124,000 of Matrix Investments preferred limited

partnership interests were converted into 2,012,400 shares of our Series B Convertible Preferred Stock.

The Series B Convertible Preferred

Stock was convertible at the option of the security holder at the rate of ten shares of common stock for one share of Series B Convertible

Preferred Stock.

For 2023 and 2024, the board authorized the payment of each quarterly

dividend of Series B Convertible Preferred shares, as Paid-In-Kind shares (“PIK”) to be paid immediately following the end

of the quarter.

During 2024 no cash was used to pay dividends on Series B preferred shares.

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

transaction, eliminating our Series B, 3.5 % Convertible Preferred Stock.

NOTE 4 – LOSS PER SHARE

Basic and diluted loss per share are calculated as follows:

Three Months Ended September 30,

Net Income (Loss)

Preferred Stock Dividend

Net Income (Loss) Attributable to Common Shareholders

Weighted average common shares outstanding

Effect of dilutive securities

Weighted average common shares, including Dilutive effect

Nine Months Ended September 30,

Net Income (Loss)

Preferred Stock Dividend

Net Income (Loss) Attributable to Common Shareholders

Three Months Ended

March 31, 2025

March 31, 2024

$ ( 681,951 )

$ ( 770,110 )

Preferred Stock Dividend In Arrears

Net Loss Attributable to Common Shareholders

Weighted average common shares outstanding

1 unchanged sentence

Weighted average common shares, including Dilutive effect

For the nine and three months ended September 30, 2024 and 2023, we had dilutive securities of 24,664,550 and 24,235,050 , respectively.

During the nine and three month periods in 2024 and 2023, these securities were not included in the dilutive loss per share, due to their antidilutive nature.

For the three months ended March 31, 2025 and 2024, we had dilutive

securities of 0 and 24,664,550 , respectively.

During the period in 2024, these securities were not included in the dilutive loss per share,

due to their antidilutive nature.

NOTE 5 – INCOME TAXES

Deferred tax assets and liabilities reflect the net tax effect of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and amounts used for income tax purposes.

Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more-likely-than-not that some portion or all of the deferred tax assets will not be realized.

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

Prior to 2022, 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.

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.

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.

For the nine months ended

September 30, 2024

September 30, 2023

Tax benefit computed at statutory rate of 21 % at September 30, 2024 and 2023, respectively

Increase (decrease) in taxes resulting from:

Other non-deductible expenses

Change in valuation allowance

Provision (benefit)

NOTE 6 – ISSUANCE OF COMMON STOCK

In April 2023, CIC RMX LP (“CIC”) exercised in full its warrant to purchase shares of our common stock.

CIC elected to make a cashless exercise of the warrant and as a result we issued 3,266,055 shares of our common stock to CIC.

During the 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.

During the nine months ended September 30, 2023, in lieu of cash payments for board fees, we issued 2,541,176 shares of common stock valued at approximately $ 108,001 to board members.

OF COMMON STOCK

During the three months ended March 31, 2025, no common stock was issued

in lieu of cash payments for salaries and board fees.

During the three months ended March 31, 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.

NOTE 7 – ALLOWANCE FOR CREDIT LOSSES

We measure our allowance for losses on other receivables including, under ASC 326.

The following table summarizes the activity in the balance of allowance for credit losses on other receivables for the period indicated:

We measure our allowance for losses on other receivables including,

under ASC 326.

The following table summarizes the activity in the balance of allowance for credit losses on other receivables for the

period indicated:

Balance at December 31, 2023

1 unchanged sentence

Write-offs charged against the allowance

Balance at September 30, 2023

Balance at March 31, 2024

Balance at December 31, 2024

1 unchanged sentence

Write-offs charged against the allowance

Balance at September 30, 2024

NOTE 8 – NOTE PAYABLE TO RELATED PARTIES

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

Balance at March 31, 2025

NOTE 8 – RELATED PARTY NOTES PAYABLE

On February 7, 2024 the board of directors approved a debt facility

of up to $ 3 million.

On February 9, 2024, Royale Energy, Inc.

entered into a Secured Term Loan Note with Walou Investments, LP, a Texas limited partnership, which is under the direct and indirect control of Johnny Jordan, the Company’s Chief Executive Officer and a member of the Company’s board of directors.

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 approximately 14.8 % of the Company’s issued and outstanding common stock, as of September 30, 2024.

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 original maturity date, August 1, 2025, when the unpaid principal balance would become due.

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 in Ector County, Texas.

As of September 30, 2024, there was $ 1.4 million outstanding under the loan with Walou Investments, LP.

Effective September 30, 2024, the note was amended to extend the maturity date from August 1, 2025, to January 1, 2026, with no other terms amended.

The loan is secured by a deed of trust recorded in Ector County, Texas, covering, among other things, certain oil and gas assets in Ector County, Texas.

As of September 30, 2024, there was $ 1.4 million outstanding under the loan with Walou Investments, LP.

NOTE 9 – SUBSEQUENT EVENTS

Series B Preferred Stock Exchange and Redemption

On October 11, 2024, we entered into privately negotiated Exchange Agreements with holders of our Preferred Stock.

Under these agreements, effective as of June 30, 2024, all 2,466,455 outstanding shares of Series B Preferred Stock , valued at $ 10 per share, with a total value of $ 24,664,550 , were exchanged for a combination of 22,198,095 shares of common stock, senior notes totaling $ 2,466,455 , and options to purchase 25,000,000 shares of common stock at an exercise price of $ 0.10 per share.

Additionally, 50% of the overriding royalty interests in certain Alaska oil and gas properties and ownership in real property located in Kern County California, were transferred to a holding company owned by the preferred stockholders.

As a result of these transactions, we no longer have any outstanding shares of Preferred Stock.

Release of Historical Liabilities

In conjunction with the exchange of the Preferred Stock, we also entered into Release Agreements with certain creditors to discharge approximately $ 2,820,423 of historical liabilities.

These liabilities were settled through the issuance of 2,538,378 shares of common stock and additional senior notes totaling $ 282,042 .

These transactions resulted in the complete redemption of the Preferred Stock, with 2,466,455 shares exchanged, and the satisfaction of related historical payment obligations, which we expect will have a material impact on the Company's capital structure and financial obligations.

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

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 in Ector County, Texas.

9 – Debt and Equity Restructuring Transaction

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

transaction, eliminating our Series B, 3.5 % Convertible Preferred Stock and simplifying our capital structure.

The transaction was executed

through a combination of common stock issuance, stock options, and senior promissory notes in exchange for the retirement of all outstanding

Series B Preferred Shares as of June 30, 2024.

The preferred holders waived the payment of any unpaid dividends.

The restructuring involved the exchange and extinguishment of 2,466,455

shares of Series B Preferred Stock, which carried an aggregate liquidation preference of $ 24.7 million.

The exchange was structured as

90% Conversion to Common Stock – Former holders of the Series B Preferred Stock received 22,198,095 shares of Royale common stock at an exchange ratio of 10 shares of common stock for each share of Series B Preferred Stock.

10% Conversion to Notes Payable – The remaining portion of the Series B Preferred Stock was exchanged for Senior Unsecured Promissory Notes, totaling $1.85 million.

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

Issuance of Warrants – As part of the exchange, Royale issued 25 million warrants with an exercise price of $0.10 per share, expiring on June 30, 2029.

The fair value of the warrants was determined to be $959,637 using a Black-Scholes-Merton model.

Transfer of Additional Assets – The Company transferred a 0.5% overriding royalty interest (ORRI) in an Alaskan property and three parcels of Bellevue, Kern County real estate to a holding entity controlled by the Preferred Shareholders.

The real estate was assigned a fair value of $368,434, which was recognized as an inducement to convert the preferred shares.

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

The transaction was accounted for as an extinguishment of equity in

accordance with ASC 470-50 and ASC 260-10-S99-2, as it represented a fundamental change in the structure and rights of the preferred stockholders.

No gain or loss was recognized on the conversion of Series B Preferred Stock, as it was deemed to be an equity transaction per authoritative

However, the issuance of warrants and asset transfers was treated as an inducement expense.

The excess of the fair value of

the warrants and assets transferred over the accrued dividend forgiven totaling $ 674,341 was treated as inducement.

The inducement was

accounted for as an equity transaction and increases the net loss attributable to common shareholders in the Loss Per Share computation

The Company concurrently settled approximately $ 3.47 million of accrued

liabilities and unpaid guaranteed payments through the issuance of common stock and additional promissory notes valued at fair market

The liabilities extinguished included obligations associated with prior merger activity and were held primarily by related parties.

The exchange of these liabilities was accounted for as a capital transaction with no gain or loss recognized on extinguishment, in accordance

with guidance in ASC 470-50.

The fair value of the new instruments issued was allocated between notes payable, common stock, and additional

paid-in capital.

As of March 31, 2025, the Company had 96,600,302 shares of common stock

outstanding, and no preferred shares issued or outstanding.

Management ’ s Discussion and Analysis of Financial

Condition and Results of Operations

FORWARD-LOOKING STATEMENTS

In addition to historical information contained herein, certain information contained in this Quarterly Report on Form 10-Q, as well as other written and oral statements made or incorporated by reference from time to time by the Company and its representatives in other reports, filings with the SEC, press releases, conferences or otherwise, may be deemed to be “forward-looking statements” within the meaning of Section 21E of the Exchange Act.

This information includes, without limitation, statements concerning the Company’s future financial position and results of operations, planned capital expenditures, sources and availability of financing, business strategy and other plans for future operations, the future mix of revenues and business, customer retention, project reversals, commitments and contingent liabilities, future demand, and industry conditions.

While we believe our forward-looking statements are based upon reasonable assumptions, we can give no assurance that such expectations will prove to have been correct.

We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Generally, the words “anticipate,” “believe,” “estimate,” “expect,” “may” and similar expressions, identify forward-looking statements, which generally are not historical in nature.

Actual results could differ materially from the results described in the forward-looking statements due to the risks and uncertainties set forth under “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” elsewhere in this Quarterly Report on Form 10-Q, in the Company’s Annual Report on Form 10-K for the year ended December 31, 2023, and those described from time to time in our future reports filed with the SEC.

The following discussion is qualified in its entirety by, and should be read in conjunction with, the Company’s financial statements, including the notes thereto, included in this Quarterly Report on Form 10-Q and the Company’s Annual Report on Form 10-K for the year ended December 31, 2023.

In addition to historical information contained herein, certain information

contained in this Quarterly Report on Form 10-Q, as well as other written and oral statements made or incorporated by reference from time

to time by the Company and its representatives in other reports, filings with the SEC, press releases, conferences or otherwise, may be

deemed to be “forward-looking statements” within the meaning of Section 21E of the Exchange Act.

This information includes,

without limitation, statements concerning the Company’s future financial position and results of operations, planned capital expenditures,

sources and availability of financing, business strategy and other plans for future operations, the future mix of revenues and business,

customer retention, project reversals, commitments and contingent liabilities, future demand, and industry conditions.

While we believe

our forward-looking statements are based upon reasonable assumptions, we can give no assurance that such expectations will prove to have

been correct.

We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information,

future events or otherwise.

Generally, the words “anticipate,” “believe,” “estimate,” “expect,”

“may” and similar expressions, identify forward-looking statements, which generally are not historical in nature.

Actual results

could differ materially from the results described in the forward-looking statements due to the risks and uncertainties set forth under

“Management’s Discussion and Analysis of Financial Condition and Results of Operations,” elsewhere in this Quarterly

Report on Form 10-Q, in the Company’s Annual Report on Form 10-K for the year ended December 31, 2024, and those described from

time to time in our future reports filed with the SEC.

The following discussion is qualified in its entirety by, and should

be read in conjunction with, the Company’s financial statements, including the notes thereto, included in this Quarterly Report

on Form 10-Q and the Company’s Annual Report on Form 10-K for the year ended December 31, 2024.

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.

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 primarily acquired and developed producing and non-producing natural gas properties in California.

In December 2018, Royale became the operator of a newly acquired oil and gas property in Texas.

The most significant factors affecting our 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.

2018, Royale became the operator of a newly acquired oil and gas property in Texas.

The most significant factors affecting our 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.

RESULTS OF OPERATIONS

For the nine months ended September 30, 2024, and 2023, we had a net loss of $2,065,017 and $503,761, respectively.

The difference was due to gains on turnkey drilling recognized during the nine months ended September 30, 2024 and 2023, of $527,715 and $1,338,305, respectively.

In addition, during the nine month period in 2024, we had higher lease impairments, bad debt expenses and interest expenses, more fully discussed below.

During the three months ended September 30, 2024 and 2023, we had net losses of $1,184,291 and $470,730, respectively.

The difference was also due to higher lease impairments, bad debt expenses and interest expenses recorded during the three month period in 2024 when compared to the period in 2023.

During the first nine months of 2024, revenues from oil and gas production increased $301,422 or 20.8%, to $1,749,120 in 2024 from revenues of $1,447,698 during the first nine months of 2023.

This increase was mainly due to higher oil production volumes during the period in 2024.

The net sales volume of oil and condensate for the nine months ended September 30, 2024, was approximately 21,079 barrels with an average price of $74.88 per barrel, versus 14,851 barrels with an average price of $73.20 per barrel for the nine months of 2023.

This represents an increase in net sales volume of 6,228 barrels or 41.9%, which was due to wells completed and put online during the latter half of 2023 and first half of 2024.

The net sales volume of natural gas for the nine months ended September 30, 2024, was approximately 91,255 Mcf with an average price of $1.84 per Mcf, versus 101,324 Mcf with an average price of $3.51 per Mcf for the same period in 2023.

This represents a decrease in net sales volume of 10,069 Mcf or 9.9%.

The decrease in natural gas production volume was also due to the natural declines of our wells.

For the quarter ended September 30, 2024, revenues from oil and gas production increased $100,755 or 22.0% to $559,709 from the 2023 third quarter revenues of $458,954.

This increase was also due to higher oil production volumes.

The net sales volume of oil and condensate for the quarter ended September 30, 2024, was approximately 6,800 barrels with an average price of $74.25 per barrel, versus 4,987 barrels with an average price of $76.19 per barrel for the third quarter of 2023.

This represents an increase in net sales volume of 1,813 barrels or 36.4% for the quarter in 2024.

The net sales volume of natural gas for the quarter ended September 30, 2024, was approximately 30,182 Mcf with an average price of $1.79 per Mcf, versus 33,242 Mcf with an average price of $2.32 per Mcf for the third quarter of 2023.

This represents a decrease in net sales volume of 3,060 Mcf or 9.2% for the quarter in 2023.

Oil and natural gas lease operating expenses decreased by $38,640 or 2.9%, to $1,292,525 for the nine months ended September 30, 2024, from $1,331,165 for the same period in 2023.

This decrease was due to lower water disposal hauling costs paid to outside vendors, which decreased our trucking costs as we converted an existing non-producing oil well into a water injection well to reduce water disposal hauling costs in 2023.

For the third quarter in 2024, lease operating expenses increased $196,037 or 62.0% from the same quarter in 2023, primarily due to repairs and restoration of well equipment in our Jameson field due to weather related damage.

The aggregate of supervisory fees and other income was $44,963 for the nine months ended September 30, 2024, an increase of $12,209 from $32,754 during the same period in 2023.

During the third quarter 2024, supervisory fees and other income increased $6,624 when compared to the quarter in 2023.

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

Depreciation, depletion and amortization expense increased to $253,726 from $231,224, an increase of $22,502 or 9.7% for the nine months ended September 30, 2024, as compared to the same period in 2023.

During the third quarter 2024, depreciation, depletion and amortization expenses decreased $770 or 1.3%.

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

The increase in depletion expense was due to a decrease in expected recoverable reserves which increased the depletion rate.

At September 30, 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.

At September 30, 2023, Royale Energy had a Deferred Drilling Obligation of $9,761,927.

At September 30, 2023, Royale Energy had a Deferred Drilling Obligation of $10,140,855.

During the first nine months of 2023, we removed $2,561,610 of drilling obligations as we completed one oil well in our Texas Jameson field and participated in the drilling and completion of an oil well in the Texas Permian basin, while incurring expenses of $1,223,305, resulting in a gain of $1,338,305.

General and administrative expenses decreased by $64,865 or 5.1% from $1,262,542 for the nine months ended September 30, 2023 to $1,197,677 for the same period in 2024.

For the second quarter 2024, general and administrative expenses decreased $14,727 or 3.8% when compared to the same period in 2023.

These decreases were mainly due to lower employee and board related expenses due to cost reduction measures during the periods in 2024.

For the first nine months of 2024, marketing expenses increased $39,702 or 17.2% to $269,984, compared to $230,282 for the first nine months of 2023.

For the third quarter 2024, marketing expenses increased $44,820 or 53.8% when compared to the third quarter in 2023.

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

Legal and accounting expense increased to $485,114 for the nine-month period in 2024, compared to $368,810 for the same period in 2023, a $116,304 or 31.5%.

This increase during the period in 2024 was primarily due to higher legal fees related to our debt facility entered into during the first quarter of 2024, and preparation of the transaction documents related to the conversion of the Series B Convertible Preferred shares described in Note 9.

For the third quarter 2024, legal and accounting expenses increased $47,283 or 49.4%, when compared to the third quarter in 2023, primarily due to fees related to conversion document preparation.

During the nine months ended September 30, 2024, we recorded Bad Debts expense of $279,491 which arose from identified uncollectable receivables relating to our oil and natural gas properties either plugged and abandoned or scheduled for plugging and abandonment (“P&A”) and our period end oil and natural gas reserve values.

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

During the period in 2024, we also recorded lease impairments of $400,554 on various lease and land costs in our California fields where the carrying value exceeded the fair value, no lease impairments were recorded in the first nine months of 2023.

During the nine months ended September 30, 2023, we recorded a gain on other of $54,975 as we reconciled employee related items previously recorded as liabilities.

We also recorded a gain on other of approximately $57,000 on our share of property tax refunds for prior years received by RMX Resources, LLC during the period in 2023.

During the period in 2023, we recorded a write down of $9,840 on certain well equipment that was either written down to its current market value or written off as it was no longer usable.

Interest expense for the nine months ended September 30, 2024, and 2023, were $207,744 and $1,383, respectively.

The higher 2024 interest expense was due to the $1.4 million note payable obtained in February 2024, discussed in Note 8.

For the three months ended March 31, 2025, and 2024, we incurred a

net loss of $681,951 and $770,110, respectively.

The difference was primarily due to the gain on settlement of approximately $105,000

from a vendor for an equipment failure during a workover.

During the first three months of 2025, revenues from oil and gas production

decreased $187,559 or 29.1%, to $456,106 from revenues of $643,665 during the first three months of 2024.

This decrease was mainly due

to lower oil and gas production volumes during the quarter in 2025.

The net sales volume of oil and condensate for the three months ended

March 31, 2025, was approximately 5,688 barrels with an average price of $69.24 per barrel, versus 7,804 barrels with an average price

of $71.68 per barrel for the first three months of 2024.

This represents a decrease in net sales volume of 2,116 barrels or 27.1%.

lower production volumes was due to weather and equipment related issues in our Texas Jameson field during the first quarter of 2025.

The net sales volume of natural gas for the three months ended March 31, 2025, was approximately 22,767 Mcf with an average price of $2.68

per Mcf, versus 32,659 Mcf with an average price of $2.56 per Mcf for the same period in 2024.

This represents a decrease in net sales

volume of 9,892 Mcf or 30.3%.

The decrease in natural gas production volume was due to some of our California natural gas wells being

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

Oil and natural gas lease operating expenses decreased by $143,915

or 33.3%, to $288,839 for the three months ended March 31, 2025, from $432,754 for the same period in 2024.

This decrease was due to higher

workover-related costs during the first quarter of 2024 in our Texas Jameson as we attempted to increase production.

The aggregate of supervisory fees and other income was $31,667 and

$16,269 for the three months ended March 31, 2025 and 2024, respectively, an increase of $15,398 mainly due to higher interest and rental

income during the first quarter of 2025.

Depreciation, depletion and amortization expense decreased to $73,218

from $87,026, a decrease of $13,808 or 15.9% for the three months ended March 31, 2025, as compared to the same period in 2024.

The depletion

rate is calculated using production as a percentage of reserves.

The decrease in depletion expense was due to a increase in expected recoverable

reserves which decreased the depletion rate.

At March 31, 2025, Royale Energy had a Deferred Drilling Obligation

of $12,032,996.

During the first three months of 2025, we did not participate in the drilling of any wells.

At March 31, 2024, Royale

Energy had a Deferred Drilling Obligation of $10,911,927.

During the first 3 months of 2024, although we participated in the drilling

and completion of a well in the Texas Permian basin, we did not book turnkey gains or losses as we waited for final costs to be determined.

General and administrative expenses increased by $19,094 or 4.3% from

$447,324 for the three months ended March 31, 2024, to $466,418 for the same period in 2025, primarily due to marketing bonuses paid to

employees during the quarter in 2025.

For the first three months of 2025, marketing expenses increased $9,043 or 15.1% to $69,035, compared

to $59,992 for the first three months of 2024.

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

attended by personnel and their associated exhibition and travel costs.

Legal and accounting expense decreased to $245,506 for the three-month

period in 2025, compared to $279,539 for the same period in 2024, a $34,033 or 12.2% decrease.

This decrease was primarily due to higher

legal fees related to our debt facility entered into during the first quarter of 2024.

During the three months ended March 31, 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 three months ended March

31, 2025, we recorded a $5,353 gain on settlement of liability due to a reconciliation of our asset retirement obligation.

three months ended March 31, 2025, we recorded lease 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 $56,209, recorded in the first three months of 2024.

three months ended March 31, 2025 and 2024, we also recorded Credit Loss expenses of $13,126 and $30,958, 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.

Interest expense for the three months ended March 31, 2025, and 2024,

were $97,179 and $36,242, respectively.

The higher 2025 interest expense was due to the $1.4 million note payable obtained 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, 2024, we had current assets totaling $8,971,747 and current liabilities totaling $19,962,529, a $10,990,782 working capital deficit.

We had $1,737,465 in cash and $4,032,800 in restricted cash at September 30, 2024, compared to $2,202,521 in cash and $3,325,000 in restricted cash at December 31, 2023.

At September 30, 2024, our other receivables, which consist of joint interest billing receivables from direct working interest investors and industry partners, totaled $622,921 compared to $1,036,401 at December 31, 2023, a $413,480 or 39.9% decrease.

This decrease was mainly due to lower accounts receivables from payment of Joint Interest Bills by direct working interest owners for lease operating expenses from our Texas Jameson wells.

At September 30, 2024, revenue receivable was $513,418 a decrease of $364,960, compared to $878,378 at December 31, 2023, due to lower production volumes during the third quarter in 2024 when compared to the year-end 2023.

At September 30, 2024, our accounts payable and accrued expenses totaled $6,240,895 an increase of $758,821 from the accounts payable at December 31, 2023 of $5,482,074, which was mainly due to higher trade payables primarily related to drilling costs during the period in 2024.

We have had recurring operating and net losses and cash used in operations and the financial statements reflect a working capital deficiency of $10,990,782 and an accumulated deficit of $93,042,036.

These factors raise substantial doubt about our ability to continue as a going concern.

We 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.

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 liquidity.

Management plans to continue 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 will allow the company to meet its liquidity needs through the remainder of the year.

At March 31, 2025, we had current assets totaling $9,717,825 and current

liabilities totaling $21,687,390, resulting in a $11,969,565 working capital deficit.

We had $1,850,831 in cash and $6,000,000 in restricted

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

At March 31, 2025, our other receivables, which consist of joint interest

billing receivables from direct working interest investors and industry partners, totaled $669,873 compared to $868,429 at December 31,

2024, a $198,556 or 22.9% decrease, mainly due to lower joint interest billing receivables.

At March 31, 2025, revenue receivable was

$439,207, a decrease of $325,446, compared to $764,653 at December 31, 2024, due to lower production volumes during the first quarter

in 2025 when compared to the fourth quarter of 2024.

At March 31, 2025, our accounts payable and accrued expenses totaled $6,510,879,

a decrease of $455,726 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 first quarter 2025.

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

and the financial statements reflect a working capital deficiency of $11,969,565 and an accumulated deficit of $94,186,420.

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.

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;

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

has plans to continue 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 will allow the company to meet its liquidity

needs through the remainder of the year.

Operating Activities.

Net cash used in operating activities totaled $1,381,384 and $198,937 for the nine months ended September 30, 2024 and 2023, respectively.

This difference in cash was mainly due to an increase in accounts payable and expenses during the period in 2024 mainly due to drilling and lease costs when compared to the period in 2023.

Net cash used by operating activities

totaled $617,612 and $579,264 for the three months ended March 31, 2025 and 2024, respectively, a $38,348 or 6.6% difference.

Investing Activities.

Net cash provided by investing activities totaled $231,089 and $1,337 for the nine months ended September 30, 2024 and 2023, respectively.

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 the drilling and completion of two oil wells in the Texas Permian basin and obtained lease interests in the Permian basin.

During the nine-month period in 2023, we received approximately $4.6 million in drilling funds while our drilling expenditures were approximately $4.6 million as we drilled and completed one Texas oil well and participated in the drilling and completion of a Texas Permian basin oil well.

Net cash provided by investing activities

totaled $569,051 for the three months ended March 31, 2025, while net cash used by investing activities totaled $2,038,357 for the three

months ended March 31, 2024.

During the three-month period in 2025, we received $575,000 in drilling funds while our drilling and lease

expenditures were approximately $6,000.

During the three-month period in 2024, we received approximately $1.2 million in drilling funds

while our drilling and lease expenditures were approximately $3.2 million as we participated in drilling and obtained lease interests

in the Permian basin.

Financing Activities.

Net cash provided by financing activities totaled $1,393,039 for the nine months ended September 30, 2024.

Net cash used in financing activities totaled $8,916 for the nine months ended September 30, 2023.

The difference in cash was due to receipt of $1.4 million from the note payable discussed in Note 8.

During the nine-month periods in 2024 and 2023, $6,961 and $8,916, respectively, were used for principal payments on our financing lease payments.

Net cash used by financing activities

totaled $2,771 for the three months ended March 31, 2025 and net cash provided by financing activities were $1,396,8877 for the three

months ended March 31, 2024.

The difference in cash provided, was due to receipt of $1.4 million from the note payable discussed in Note

During the three-month periods in 2025 and 2024, the totals were also used for principal payments on our financing lease payments.

Critical Accounting Estimates

Our critical accounting policies are further disclosed in Note 1 to the consolidated financial statements included in our 2023 Annual Report on Form 10-K.

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

1 unchanged sentence

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What changed 10-Q

Item 1. Financial Statements