What changed in this filing

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Item 1. Financial Statements

2025-08-14 compared with 2025-05-15 · 538 added, 471 removed, 248 unchanged (80% of the section changed)

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Prepaid Expenses and Other Current Assets

Deferred Drilling Costs

Total Current Assets

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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

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

Additional Paid in Capital

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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

For the three months ended

For the six months ended

Oil, NGL and Gas Sales

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Depreciation, Depletion and Amortization

Credit Loss Expense

Legal and Accounting

Credit Loss Expense

General and Administrative

Total Costs and Expenses

Gain on Turnkey Drilling

Loss From Operations

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Interest Expense

Gain on Settlement of Liability

Gain on Settlement of Accounts Payable

Preferred Stock Dividend in Arrears

Gain on Settlement of Asset Retirement Obligations

Preferred Stock Dividend

Net Loss available to common stock

$ ( 681,951 )

$ ( 985,331 )

Shares used in computing Basic Net Loss per share

Basic Loss per share

Shares used in computing Diluted Net Loss per share

Diluted Loss per share

Shares used in computing Basic and Diluted Net Loss per share

Basic and Diluted Net Loss Per Share

See notes to unaudited condensed consolidated financial

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE THREE MONTHS ENDED MARCH 31, 2025 AND

For the Three Months Ended

FOR THE SIX MONTHS ENDED JUNE 30, 2025 AND 2024

For the Six Months Ended

CASH FLOWS FROM OPERATING ACTIVITIES

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$ ( 880,726 )

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

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

Depreciation, Depletion and Amortization

Gain on Turnkey Drilling Programs

Credit Loss Expense

Gain on Settlement of Accounts Payable

Gain on Settlement of Liability

Gain on Settlement of Asset Retirement Obligation

Stock-Based Compensation

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Right of Use Asset Depreciation

Changes in assets and liabilities:

Changes in Operating Assets and Liabilities:

Other & Revenue Receivables

Prepaid Expenses and Other Assets

Royalties Payable

Accounts Payable and Accrued Expenses

( 1,529,520 )

Net Cash Used in Operating Activities

( 2,247,911 )

CASH FLOWS FROM INVESTING ACTIVITIES

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Proceeds from Turnkey Drilling Programs

Net Cash Provided (Used) by Investing Activities

( 2,038,357 )

Net Cash Provided by (Used in) Investing Activities

CASH FLOWS FROM FINANCING ACTIVITIES

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Lease Financing Payments

Net Cash Provided (Used) by Financing Activities

Net Decrease in Cash, Cash Equivalents, and Restricted Cash

( 1,220,734 )

Net Cash Provided by (Used in) Financing Activities

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

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

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Series B Paid-In-Kind Dividends

See notes to unaudited condensed

consolidated financial statements.

See notes to unaudited condensed consolidated

financial statements.

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’

EQUITY (DEFICIT)

FOR THE THREE MONTHS ENDED MARCH 31, 2025 AND

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ DEFICIT

FOR THE THREE AND SIX MONTHS ENDED JUNE 30,

2025 AND 2024

Comprehensive

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December 31, 2023 Balance

$ ( 90,323,289 )

$ ( 35,633,489 )

Stock Issued in lieu of Compensation

Preferred Series B 3.5 % Dividend

June 30, 2024 Balance

December 31, 2024 Balance

$ ( 93,504,469 )

$ ( 12,329,315 )

( 1,100,721 )

June 30, 2025 Balance

$ ( 94,605,190 )

$ ( 13,430,036 )

Comprehensive

Stockholders’

March 31, 2024 Balance

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$ ( 36,582,821 )

December 31, 2024 Balance

Preferred Series B 3.5 % Dividend

June 30, 2024 Balance

$ ( 91,636,335 )

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$ ( 13,011,266 )

June 30, 2025 Balance

$ ( 94,605,190 )

$ ( 13,430,036 )

See notes to unaudited condensed consolidated financial

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NOTE 1 – BASIS OF PRESENTATION

ACCOUNTING STANDARDS

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.

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,”

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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

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

the audited financial statements at that date.

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

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

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

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

Liquidity and Going Concern

The primary sources of liquidity have historically been issuances of

common stock, oil and gas sales through ongoing operations and the sale of oil and gas properties.

There are factors that give rise to

substantial doubt about our ability to meet liquidity demands, and we anticipate that our primary sources of liquidity will be from the

issuance of debt and/or equity, the sale of oil and natural gas property participation interests through our normal course of business

and the sale of non-strategic assets.

At 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.

The primary sources of liquidity have historically been issuances of common

stock, oil and gas sales through ongoing operations and the sale of oil and gas properties.

There are factors that give rise to substantial

doubt about our ability to meet liquidity demands, and we anticipate that our primary sources of liquidity will be from the issuance of

debt and/or equity, the sale of oil and natural gas property participation interests through our normal course of business and the sale

of non-strategic assets.

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

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

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

June 30, 2025.

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

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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.

Management’s plans to alleviate the going concern by continuing

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

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

There is no assurance that additional financing will be

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

profitable and generate positive operating cash flow.

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

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

additional capital is raised to support further operations.

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

Use of Estimates

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Actual results could differ from those estimates.

Material estimates that are particularly susceptible to significant

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

Such estimates are subject

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

Estimated reserves are used in the calculation

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

net cash flows, taxes, and contingencies.

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:

For the three months ended

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 June 30,

For the six months

ended June 30,

Oil & Condensate Sales

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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;

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

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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.

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

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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.

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

or participate in, to third-party investors and retain a portion of the prospect for our own account.

We typically guarantee a cost to

drill to the third-party drilling participants and record a loss or gain on the difference between the guaranteed price and the actual

cost to drill the well.

When monies are received from third parties for future drilling obligations, we record the liability as Turnkey

Drilling Obligations.

Once the contracted depth for the drilling of the well is reached and a determination as to the commercial viability

of the well, the difference in the actual cost to drill and the guaranteed cost is recorded as income or expense depending on whether

there was a gain or loss.

Crude oil and condensate

For the crude sales agreements, we satisfy our performance obligations

For the crude oil sales agreements, we satisfy our performance obligations

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

Natural gas and NGLs

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

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

Frequently, these midstream entities also purchase our natural

gas and NGLs under the same agreements.

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

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

We determined the plant tailgate

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

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,

The amounts due to midstream entities for gathering and processing services

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

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

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Restricted Cash

We sponsor turnkey drilling arrangements in proved and unproved properties.

We sponsor turnkey drilling arrangements in proved and unproved oil and

gas properties.

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

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.

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.

Under certain circumstances,

we may designate these funds for a substitute well.

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

to a participant.

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

We classify these funds prior to commencement

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

Standards Codification (“ASC”) 230-10-50-8.

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

they are recorded as Prepaid Expenses

and Other Current Assets.

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

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

of cash flows.

Cash and Cash Equivalents

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Equity Method Investments

Investments in entities over which we have significant influence, but

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

Income from equity method investments represents our proportionate

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

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

Investments in entities over which we have significant influence, but not

control, are accounted for using the equity method of accounting.

Income from equity method investments represents our proportionate share

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

of operations.

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

Equity method investments are assessed for impairment whenever changes

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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.

is written down to fair value, and the amount of the write-down is included in the condensed consolidated statement of operations.

Other Receivables, net

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investors and industry partners.

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

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

Under this standard, an allowance for expected credit losses is established and adjusted based on historical loss experience, current

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account and recoveries of previously charged off accounts are added to the allowance.

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

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

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

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Dividends on Series B Convertible Preferred Stock

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

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

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 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).

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

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

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

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

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

settlement of dividends accumulated through December 31, 2023.

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

the first three quarters of 2024.

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

liquidation preference of the Preferred Stock.

Issued, Not Yet Adopted

November 2024, the FASB issued ASU 2024-03, Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures

(Subtopic 220-40):

Disaggregation of Income Statement Expenses.

This update requires public business entities to disclose disaggregated

information about certain income statement expenses—including categories such as employee compensation, intangible asset amortization

and depreciation, and selling expense—in the notes to the financial statements.

Public business entities are required to apply

the guidance prospectively and may apply it retrospectively.

The guidance is effective for fiscal years beginning after December 15,

2026, and interim periods within fiscal years beginning after December 15, 2027.

Early adoption is permitted.

The Company is evaluating

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

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

2023-09, “Improvements to Income Tax Disclosures,”.

2023-09 requires enhanced disclosures around income taxes, including additional detail regarding the rate reconciliation and the presentation

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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:

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.

2 – OIL AND GAS PROPERTIES AND EQUIPMENT

and gas properties, equipment and fixtures consist of:

Producing properties, including drilling costs

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( 7,748,190 )

Net capitalized costs Total

Net capitalized Oil and Gas costs

Commercial and Other

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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.

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

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

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

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

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

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

Acquisition costs of proved

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

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

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

Capitalized exploratory drilling and development costs associated with

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

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

Under the unit-of-production

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

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

Production costs are expensed as incurred.

Production involves lifting

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

The production function

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

Production costs are those incurred to operate

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

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.

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

Major renewals and improvements are capitalized and the assets

replaced are retired.

project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are

ready for their intended use.

Interest costs, to the extent they are incurred to finance expenditures during the construction phase,

are included in property, plant and equipment and are depreciated over the service life of the related assets.

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

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.

well costs not meeting these criteria are charged to expense.

Other exploratory expenditures, including geophysical costs and annual

lease rentals, are expensed as incurred.

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

on the basis of total proved oil and gas reserves.

exploratory drilling and development costs associated with productive depletable extractive properties are amortized using unit-of-production

rates based on the amount of proved developed reserves of oil and gas that are estimated to be recoverable from existing facilities using

current operating methods.

Under the unit-of-production method, oil and gas volumes are considered produced once they have been measured

through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank.

costs are expensed as incurred.

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

and field storage of the oil and gas.

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

storage tank.

Production costs are those incurred to operate and maintain Royale’s wells and related equipment and facilities.

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

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

repair and maintenance

costs on the wells and equipment;

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

and administrative

expenses related to the production activity.

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

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

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.

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 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

These costs, sometimes referred to as lifting costs, include such items as labor

costs to operate the wells and related equipment;

repair and maintenance costs on the wells and equipment;

materials, supplies and energy

costs required to operate the wells and related equipment;

and administrative expenses related to the production activity.

and gas properties held and used by Royale are reviewed for impairment whenever events or changes in circumstances indicate that the

carrying amounts may not be recoverable.

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.

Prices for natural gas and other products are based on assumptions

developed annually for evaluation purposes.

analyses are generally based on proved reserves.

An asset group would be 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 six months ended June 30,

2025 and 2024, we incurred an impairment loss of $ 27,250 and $ 63,054 , respectively.

unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based

on the estimated economic chance of success and the length of time that Royale expects to hold the properties.

The valuation allowances

are reviewed at least annually.

the sale or retirement of a complete field of a proved property, Royale eliminates the cost from its books, and the resultant gain or

loss is recorded to Royale’s Condensed Consolidated Statements of Operations.

Upon the sale of an entire interest in an unproved

property where the property has been assessed for impairment individually, a gain or loss is recognized in Royale’s Statement of

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.

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.

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;

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

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.

We retain legal title to the lease.

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

In these working interest arrangements, the participants are responsible

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

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

A certain portion of the turnkey drilling participant’s funds

received are non-refundable.

We 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 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

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

The participants

purchase a working interest directly in the well bore.

these working interest arrangements, the participants are responsible for sharing in the risk of development of the well, 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.

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

and $ 11,457,996 , respectively.

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

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.

3 – SERIES B PREFERRED STOCK

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

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

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

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

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

March 31, 2025

March 31, 2024

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

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

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

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

During 2024 no cash

was used to pay dividends on share of Preferred Stock.

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

eliminating our Preferred Stock.

4 – LOSS PER SHARE

and diluted loss per share are calculated as follows:

Three Months Ended June 30,

$ ( 418,770 )

$ ( 110,616 )

Preferred Stock Dividend In Arrears

Preferred Stock Dividend

Net Loss Attributable to Common Shareholders

2 unchanged sentences

Weighted average common shares, including Dilutive effect

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.

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.

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:

Six Months Ended June 30,

$ ( 1,100,721 )

( 1,100,721 )

$ ( 880,726 )

Preferred Stock Dividend

Net Loss Attributable to Common Shareholders

( 1,100,721 )

( 1,313,046 )

Weighted average common shares outstanding

Effect of dilutive securities

Weighted average common shares, including Dilutive effect

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

During the six and

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

5 – INCOME TAXES

tax assets and liabilities reflect the net tax effect of temporary differences between the carrying amount of assets and liabilities

for financial reporting purposes and amounts used for income tax purposes.

Deferred tax assets are reduced by a valuation allowance when,

in the opinion of management, it is more-likely-than-not that some portion or all of the deferred tax assets will not be realized.

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

At the end of 2015,

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

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

As a result, we will continue to record a full

valuation allowance against the deferred tax assets in 2025.

6 – ISSUANCE OF COMMON STOCK

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

During the six months

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

to board members.

7 – ALLOWANCE FOR CREDIT LOSSES

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 March 31, 2024

Balance at June 30, 2024

Balance at December 31, 2024

1 unchanged sentence

Write-offs charged against the allowance

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 control of Johnny Jordan, the Company’s Chief Executive Officer and a member of the Company’s

Board of Directors.

Balance at June 30, 2025

8 – RELATED PARTY NOTES PAYABLE

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

On February 9, 2024, the

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

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

In addition, Mr.

Jordan is the beneficial owner of 29.2 % of the Company’s issued and outstanding common stock.

The initial loan to the Company was $ 1,400,000 which was received on February 9, 2024.The outstanding principal balance of the loan has

an interest rate of 18.0 %.

The 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.

On November 1, 2024

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

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

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

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.

October 11, 2024, we completed a significant equity restructuring transaction, redeeming 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 redemption of all outstanding Series B Preferred Shares as of June 30, 2024.

The preferred

holders waived the payment of any unpaid dividends.

restructuring involved the exchange and redemption of 2,466,455 shares of Series B Preferred Stock, which carried an aggregate liquidation

preference of $ 24.7 million.

The exchange was structured as follows:

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.

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.

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.

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.

of Historical Liabilities – Royale also settled approximately $3 million in pre-merger obligations by issuing additional common

stock and promissory notes.

transaction was accounted for as an extinguishment of equity in accordance with ASC 470-50 and ASC 260-10-S99-2, as it represented a

fundamental change in the structure and rights of the preferred stockholders.

No gain or loss was recognized on the conversion of Series

B Preferred Stock, as it was deemed to be an equity transaction per authoritative guidance.

However, the issuance of warrants and asset

transfers was treated as an inducement expense.

The excess of the fair value of the warrants and assets transferred over the accrued

dividend forgiven totaling $ 674,341 was treated as an inducement expense.

The inducement expense was accounted for as an equity transaction

and increased the net loss attributable to common shareholders in the Loss Per Share computation in Note 1.

Company concurrently settled approximately $ 3.47 million of accrued liabilities and unpaid guaranteed payments through the issuance of

common stock and additional promissory notes valued at fair market rates.

The liabilities extinguished included obligations associated

with prior merger activity and were held primarily by related parties.

The exchange of these liabilities was accounted for as a capital

transaction with no gain or loss recognized on extinguishment, in accordance with guidance in ASC 470-50.

The fair value of the new instruments

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

of June 30, 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

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 Securities Exchange Act of 1934 (the “Exchange Act”).

This information includes,

3 unchanged sentences

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.

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

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

2 unchanged sentences

“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

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.

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.

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 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 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 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 $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 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 2024 Annual Report on Form 10-K.

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.

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.

Prior to 2019, Royale primarily acquired and developed producing and non-producing

natural gas properties in California.

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

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.

OF OPERATIONS

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

The difference was primarily

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

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

During the three

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

The difference was due primarily to the

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

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

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

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

volumes and lower oil commodity prices.

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

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

months of 2024.

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

during the period in 2025 due to weather related issues in our Texas Jameson field.

The net sales volume of natural gas for the six months

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

$1.87 per Mcf for the same period in 2024.

This represents a decrease in net sales volume of 10,272 Mcf or 16.8%.

The decrease in natural

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

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

For the quarter ended June

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

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

The net sales volume of oil and condensate

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

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

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

or 25.7% for the quarter in 2025.

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

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

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

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

for the same period in 2024.

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

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

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

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

during the same period in 2024.

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

the quarter in 2024.

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

Depreciation,

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

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

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

$67,891 or 61.6%.

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

This decrease in depletion expense was

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

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

During the first six months of 2025, although we participated

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

and the final costs to be determined.

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

During the first

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

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

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

period in 2025.

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

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

the period in 2025.

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

for the first six months of 2024.

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

quarter in 2024.

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

their associated costs.

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

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

These decreases during the period in 2025

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

the six months ended June 30, 2025, we recorded a $220,692 gain on settlement of asset retirement obligation liability due mainly to

finalizing the plugging and abandonment of three natural gas sites in California.

During the six months ended June 30, 2025, we recorded

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

During the six months ended

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

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

During the six months ended June 30, 2025

and 2024, we also recorded Credit Loss expenses of $13,126 and $176,044, respectively, which arose from identified uncollectable receivables

relating to our oil and natural gas properties either plugged and abandoned or scheduled for plugging and abandonment (“P&A”)

and our period end oil and natural gas reserve values.

We periodically review our accounts receivable from working interest owners to

determine whether collection of any of these charges appears doubtful.

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

The higher 2025 interest expense was

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

in October 2024, discussed in Note 9.

RESOURCES AND LIQUIDITY

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

capital deficit.

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

in restricted cash at December 31, 2024.

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

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

interest billing receivables.

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

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

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

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

payments and accrued liability settlements during the period in 2025.

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

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

These factors raise substantial doubt about our ability to continue

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

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

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

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

any such outcomes could have a material adverse effect

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

Management has plans to increase revenues by making commitments

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

Texas Jameson field.

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

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

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

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

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

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

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

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

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

During the six month period in 2025, we received approximately

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

During the six-month period in 2024,

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

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

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

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

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

million from the note payable discussed in Note 8.

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

payments on our financing lease payments.

Accounting Estimates

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

on Form 10-K.

Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

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

What changed 10-Q

Item 1. Financial Statements