Royale Energy Inc

NOTE 1–** SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES**

This summary of significant accounting policies of Royale Energy, Inc. (in these notes sometimes called “we”, “us”, “our”) is presented to assist in understanding our financial statements.

These consolidated financial statements include the accounts of Royale Energy, Inc and our controlled subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis. The consolidated statements and notes are representations of our management, which is responsible for their integrity and objectivity. These accounting policies conform to accounting principles generally accepted in the United States of America and have been consistently applied in the preparation of the consolidated financial statements.

Description of Business

We are an independent oil and gas producer and we also perform turnkey drilling operations. We own wells and leases in major geological basins located primarily in California, Texas, and Oklahoma, and offer fractional working interests and seek to minimize the risks of oil and gas drilling by selling multiple well drilling projects which do not include the use of debt financing.

Use of Estimates

The accompanying consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America 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.

Estimated quantities of crude oil and condensate, NGLs and natural gas reserves is a significant estimate that requires judgment. All of the reserve data included in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and condensate, NGLs and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and condensate, NGLs and natural gas reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil and condensate, NGLs and natural gas that are ultimately recovered. See Note 15 – Supplemental Information About Oil and Gas Producing Activities (Unaudited) to our Consolidated Financial Statements for further detail.

Other items subject to estimates and assumptions include the carrying amounts of accounts receivable, property, plant and equipment, equity method investments, asset retirement obligations, and valuation allowances for deferred tax assets, among others. Although we believe these estimates are accurate, actual results could differ from these estimates.

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.

Our 2023 consolidated financial statements reflect a working capital deficiency of $7,184,318, an accumulated deficit of $90,323,289 and a net loss of $1,832,187. These factors raise 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 plans to alleviate the going concern by implementing cost control measures that include the reduction of overhead costs and through the sale of non-strategic assets, and if necessary seek additional debt and/or equity financing. There is no assurance that additional financing will be available when needed or that management will be able to obtain 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 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.

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. 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. 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.

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 flows.

Other Receivables

Our other receivables consist of receivables from direct working interest investors and industry partners. We provide for uncollectible accounts receivable using the allowance method of accounting for credit risk. Under this method of accounting, a provision for uncollectible accounts is charged directly to bad debt expense when it becomes probable the receivable will not be fully collected. The allowance account is increased or decreased based on past collection history and management’s evaluation of accounts receivable. All amounts considered uncollectible are charged against the allowance account and recoveries of previously charged off accounts are added to the allowance. At December 31, 2023 and 2022, we maintained an allowance for uncollectable accounts of $1,837,551 and $2,757,549, respectively, for receivables from direct working interest investors whose expenses on non-producing wells exceed expected collectable amounts.

Revenue Receivables

Our revenue receivables consist of receivables related to the sale of our natural gas and oil. Once a production month is completed, we receive payment approximately 15 to 30 days later. Historically, we have not had no historical losses related to the collection of revenue receivables, and as such have determined that an allowance for revenue receivables is not currently necessary.

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 of income. 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 the consolidated statement of operations income.

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:

The pricing in our hydrocarbon sales agreements are 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 often serve as the operator for jointly owned oil and gas properties. As part of this role, we perform activities to explore, develop and produce oil and gas properties in accordance with the joint operating arrangement and collective decisions of the joint parties. Other working interest owners reimburse us for costs incurred based on our agreements. We determined that these activities are not performed as part of customer relationships, and such reimbursements are recorded as cost reimbursements.

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 in regard 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 called “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 sales agreements, we satisfy our performance obligations and recognize revenue once customers take control of the crude at the designated delivery points, which include pipelines, trucks or vessels.

Natural Gas and NGLs

When selling natural gas and NGLs, we engage midstream entities to process our production stream by separating natural gas from the NGLs. Frequently, these midstream entities also purchase our natural gas and NGLs under the same agreements. In these situations, we determined the performance obligation is complete and satisfied at the tailgate of the processing plant when the natural gas and NGLs become identifiable and measurable products. We determined the plant tailgate is the point in time where control, is transferred to midstream entities and they are entitled to significant risks and rewards of ownership of the natural gas and NGLs.

The amounts due to midstream entities for gathering and processing services are recognized as shipping and handling cost and included as lease operating expense in our consolidated Statement of Operations, since we make those payments in exchange for distinct services with the exception of natural gas sold to PG&E where transportation cost is netted directly against revenues. 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 Obligations

We manage these Turnkey Agreements for the participants of the well. The collections of pre-drilling Authorization for Expenditure (“AFE”) amounts are segregated 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 ASC 932. 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.

Supervisory Fees and Other

For the years ended December 31, 2023 and 2022, we recognized $46,568 and $31,315, mainly from interest income and subleasing a portion of unused office space. .

Oil and Gas Property and Equipment

Successful Efforts

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. 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.

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 Cost

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. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labor costs to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity.

Depreciation, Depletion and Amortization

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 drilling phase commences with the development of the detailed engineering design and ends when the 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.

Impairment

We evaluate our oil and gas producing properties, including capitalized costs of exploratory wells and development costs, for impairment of value whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. Oil and gas producing properties are reviewed for impairment on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure or contractual terms that cause economic interdependency amongst separate, discrete fields. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows or, if available, comparable market value. We evaluate our unproved property investment and record impairment based on time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved property investments are deemed to be impaired, this amount is reported in exploration expenses in our consolidated statements of operations. During 2023 we recorded impairment losses of $1,599,001, on various capitalized lease and land costs where the carrying value exceeded the fair value. Of this amount $1,292,502 was impaired as a result of increased abandonment cost estimates and increases working interest in those costs. In 2022 there wereno impairment losses.

Upon the sale or retirement of a complete field of a proved property, we eliminate the cost from our books, and the resultant gain or loss is recorded to our 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 our consolidated statements 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.

Long-Lived Assets Classified as Held for Sale

We classify long-lived assets as Held-for-Sale when the criteria of ASC 360-10-45-9 through 45-11, Impairment and Disposal of Long-Lived Assets, have been met. This criterion is listed below:

Assets held for sale are carried at the lower of cost or fair market value less cost of disposal in current assets. If we retain the responsibility for the P&A, equipment removal or site restoration, the associated anticipated expense is carried as current an asset retirement obligation (“ARO”) (See Note 3, below).

Turnkey Drilling

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 and 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 pay us 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 hold 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 December 31, 2023 and 2022, we had Deferred Drilling Obligations of $9,761,927 and $8,129,965, respectively. During 2023, we disposed of $6,228,038 of drilling obligations as we completed one oil well in our Texas Jameson field and participated in drilling and completion of two successful oil wells in the Texas Permian basin and one dry well in southern California, while incurring expenses of $4,120,538, resulting in a gain of $2,107,500. During 2022, we disposed of $7,027,474 of drilling obligations as we completed five oil wells in Texas and participated in the drilling and completion of two wells in southern California, while incurring expenses of $5,301,060, resulting in a gain of $1,726,414.

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 programs in progress.

Equipment and Fixtures

Equipment and fixtures are stated at cost and depreciated over the estimated useful lives of the assets, which range from three toseven years, using the straight-line method. Repairs and maintenance are charged to expense as incurred. When assets are sold or retired, the cost and related accumulated depreciation are removed from the accounts and any resulting gain or loss is included in income. Maintenance and repairs, which neither materially add to the value of the property nor appreciably prolong its life, are charged to expense as incurred.

Loss Per Share

Basic and diluted losses per share are calculated as follows:

For the years ended December 31, 2023 and 2022, Royale Energy had dilutive securities of 24,448,850 and 27,058,677 respectively. These securities were not included in the dilutive loss per share due to their antidilutive nature.

Stock Based Compensation

We have adopted ASC 718, Compensation – Stock Compensation, for share-based payments. This topic requires that the cost resulting from all share-based payment transactions be recognized in the financial statements. It further establishes fair value as the measurement objective in accounting for share-based payment arrangements and requires all entities to apply a fair-value based measurement method in accounting for share-based payment transactions with employees except for equity instruments held by employee stock ownership plans.

Income Taxes

We utilize the asset and liability approach to measure deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates in accordance with the Income Taxes Topic of the ASC 740. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. Under the Topic, 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.

The provision for income taxes is based on pretax financial accounting income. Deferred tax assets and liabilities are recognized for the expected tax consequences of temporary differences between the tax basis of assets and liabilities and their reported net amounts.

Fair Value Measurements

According to Fair Value Measurements and Disclosures guidance as provided by ASC 820 and 825, 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 enable users of our financial statements to assess the inputs used to develop those measurements and for recurring fair value measurements using significant unobservable inputs, 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 consider 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:

Level 1: Quoted prices (unadjusted) in active markets that are accessible at the measurement date for assets or liabilities.

Level 2: 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.

Level 3: 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 December 31, 2023 and 2022, we do not have any financial assets measured and recognized at fair value on a recurring basis. We estimate asset retirement obligations pursuant to the provisions of ASC 410, Asset Retirement and Environmental Obligations. The initial measurement of asset retirement obligations 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. See Note 2 –** **Oil and Gas Properties, Equipment and Fixtures for further discussion of our asset retirement obligations.

Accounts Payable and Accrued Expenses

At December 31, 2023 and 2022, the components of accounts payable and accrued expenses consisted of:

Accrued– Non-current

At December 31, 2023 and 2022, we had non-current accrued liabilities of $1,306,605 and accrued unpaid guaranteed payment of $1,616,205, due to certain Matrix Oil Corp (“Matrix”) principals, from periods prior to the merger with the Matrix entities during March of 2018. These obligations are a result of the merger with Matrix in 2018, and are not expected to be paid in 2024.

Business Combinations

From time-to-time, we acquire businesses in the oil and gas industry. We primarily target businesses in geological basins that we consider to be in a focus area. Businesses are included in the consolidated financial statements from the date of acquisition.

We recognize, separately from goodwill, the identifiable assets acquired and liabilities assumed at their estimated acquisition-date fair values. We measure and recognize goodwill as of the acquisition date as the excess of: (1) the aggregate of the fair value of consideration transferred, the fair value of any noncontrolling interest in the acquiree (if any) and the acquisition date fair value of our previously held equity interest in the acquiree (if any), over (2) the fair value of assets acquired and liabilities assumed. If information about facts and circumstances existing as of the acquisition date is incomplete by the end of the reporting period in which a business combination occurs, we report provisional amounts for the items for which the accounting is incomplete. The measurement or allocation period ends once we receive the information we are seeking; however, this period will generally not exceed one year from the acquisition date. Any material adjustments recognized during the measurement period will be reflected retrospectively in the consolidated financial statements of the subsequent period. We recognize third-party transaction-related costs as expense currently in the period in which they are incurred.

Changes in Accounting Standards

Recently Adopted

ASU 2016-13, Credit Impairment

In June of 2016, the FASB issued ASC Topic 326, Financial Instruments – Credit Losses. This new guidance replaces the current incurred loss impairment model with a requirement to recognize lifetime expected credit losses immediately when a financial asset is originated or purchased. This new Current Expected Credit Losses (“CECL”) model applies to (1) loans, accounts receivable, trade receivables, and other financial assets measured at amortized cost, (2) loan commitments and certain other off-balance sheet credit exposures, (3) debt securities and financial assets measured at fair value, and (4) beneficial interests in securitized financial assets. This ASU was effective for SEC filers beginning after December 15, 2019; however, on November 15, 2019, the FASB issued ASU 2019-10, which delayed the effective date for “smaller reporting companies.” Therefore, ASU 2016-13 is effective for "smaller reporting companies" (as defined by the Securities and Exchange Commission) like us, for fiscal years beginning after December 15, 2022, including interim periods within those years, and must be adopted under the modified retrospective method. We adopted this standard effective January 1, 2022. The adoption of this standard did not have a material impact on our consolidated financial statements and cash flows.

NOTE 2–** OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES**

Oil and gas properties, equipment and fixtures consist of:

The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed at December 31:

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. We did not make any additions to capitalized exploratory well costs pending a determination of proved reserves during 2023 and 2022. Undeveloped properties are not subject to depletion, depreciation or amortization.

Results of Operations from Oil and Gas Producing and Exploration Activities

The results of operations from oil and gas producing and exploration activities (excluding corporate overhead and interest costs) are as follows:

NOTE 3–** ASSET RETIREMENT OBLIGATION**

The Asset Retirement and Environmental Obligations Topic of the ASC 410-20 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset. The ARO is recorded at the estimated fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value. Accretion expense is included as part of Depreciation, Depletion and Amortization in the Consolidated Statement of Operations. The fair value (as provided in ASC 820 guidance) of the ARO is measured using expected future cash outflows discounted at our credit-adjusted risk-free interest rate. The provisions of this Topic apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, development, and operation of a long-lived asset. For the year ended December 31, 2023, we recognized $996,852 related to the increase in expected cost of abandoning our California wells. There were no changes in estimates for the year ended December 31, 2022.

We record accretion expense as part of Depreciation, Depletion and Amortization. Accretion expense was $43,897 and $286,470 for the years ended December 31, 2023 and 2022, respectively.

NOTE 4–** 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.

Significant components of our deferred assets and liabilities at December 31, 2023 and 2022, respectively, are as follows:

We recorded a full valuation allowance against the net deferred tax assets in 2016. At the end of 2017, management reviewed the reliability of our net deferred tax assets, and due to our continued cumulative losses in recent years, we and our management 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. We will assess the realizability of the deferred tax assets at least yearly and make appropriate updates as needed. We and our subsidiaries have available net operating loss carryforwards of $20.5 million generated in tax years ended before January 1, 2018, which if not utilized, begin to expire in the year 2026. We have $12.0 million net operating loss carryforwards generated after December 31, 2017, which can be carried forward indefinitely.

A reconciliation of our provision for income taxes and the amount computed by applying the statutory income tax rates at December 31, 2023 and 2022, respectively, to pretax income is as follows:

In January 2007, we adopted additional provisions from the Income Taxes Topic of the ASC, which clarified the accounting for uncertainty in income taxes recognized in an entity’s financial statements and prescribes a recognition threshold and measurement attribute for financial statement disclosure of tax positions taken or expected to be taken on a tax return. As a result of our implementation of the Topic at the time of adoption and at December 31, 2018, we did not recognize a liability for uncertain tax positions. Currently, the only differences between our financial statements and our income tax returns relate to normal timing differences such as depreciation, depletion and amortization, which are recorded as deferred taxes on our balance sheets. We do not expect our unrecognized tax benefits to change significantly over the next 12 months. The tax years 2019 through 2022 remain open to examination by the taxing jurisdictions in which we file income tax returns.

NOTE 5–** SERIES B PREFERRED STOCK**

Pursuant to the terms of the Merger 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. Our Board of Directors, prior to the merger, authorized 3,000,000 shares of Series B Convertible Preferred, which carries a liquidation preference and a 3.5% annual dividend, payable quarterly in cash or Paid-In-Kind (“PIK”) shares. The Series B Convertible Preferred Stock is 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. The Series B Preferred Stock has never been registered under the Securities Exchange Act of 1934, and no market exists for the shares. Additionally, the Series B Convertible Preferred shares will automatically convert to shares of common stock at any time in which the Volume Weighted Average Price (“VWAP”) of the common stock exceeds $3.50 per share for 20 consecutive trading days, the shares of common stock are registered with the SEC and the volume of common shares trades exceeds 200,000 shares per day. The shareholders of the Series B Convertible Preferred may vote the number of shares into which they would be entitled to convert, beginning in 2020.

In accordance with ASC 480-10-S99-1.02, we have determined that the conversion or redemption of these shares are outside our sole control and that they should be classified in mezzanine or temporary equity as redeemable noncontrolling interest beginning at the reporting period, ended March 31, 2020.

For 2023 and 2022, 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. For the 12 months ending December 31, 2023, we issued 62,899 shares with a value of $629,007, with 21,570 shares with a value of $215,693 accrued for but not yet issued at December 31, 2023. For the 12 months ending December 31, 2022, we issued 60,748 shares with a value of $607,465, of these 20,832 shares with a value of $208,307 were accrued as of December 31, 2022, and paid in the first quarter of 2023 but not yet issued. During 2023 and 2022, no cash was used to pay dividends on Series B preferred shares.

NOTE 6–** COMMON STOCK**

During the years 2023 and 2022, we issued shares of our Common Stock in lieu of cash payments for salaries, fees or incentives to various officers and board members, including our CEO, as noted in the Statement of Stockholders’ Deficit.

During the year ended December 31, 2023, CIC RMX LP (“CIC”) exercised in full its warrant to purchase shares or our common stock. CIC elected to make a cashless exercise of warrant and as a result we issued 3,266,055 shares of our common stock to CIC.

NOTE 7–** LEASES**

During 2023, we had one office lease at 1530 Hilton Head Road, El Cajon, California, the location of our corporate offices. The corporate office lease was entered into on August 12, 2021, began on January 1, 2022 and expires on December 31, 2026, with initial monthly payments of $6,922 with escalations. We also rent office space on a month-to-month basis at 104 W. Anapamu, Santa Barbara, California, the location of our CEO and engineering team.

We have elected the short-term lease recognition exemption for all leases that qualify. This means, for those leases that qualify, we will not recognize ROU assets or lease liabilities, and this includes not recognizing ROU assets or lease liabilities for existing short-term leases of those assets in transition. We elected the practical expedient to not separate lease and non-lease components for all of our finance leases. For our real estate operating leases, we have only considered the fixed portion of our lease payment commitment and have excluded the variable components from the capitalized ROU and lease liability.

Lease expense for operating as well as finance leases are included in General and Administrative expense and Interest Expense on the Consolidated Statement of Operations, while the lease expense for those leases that are short-term are included in Oil and Gas Lease Operating Expenses. The amounts are as follows:

The following tables summarized the operating and financing lease obligations.

Our two office leases do not contain implicit interest rates that can be readily determined. As a result, we used the available risk-free rate plus 4 basis points. At December 31, 2023 and 2022, the weighted average discount rate was 4.83% and the term was 4 years.

NOTE 8–** RELATED-PARTY TRANSACTIONS**

Our Chief Executive Officer, Johnny Jordan, has accrued certain unpaid salaries. At December 31, 2023, Mr. Jordan was owed $46,926, in accrued unpaid guaranteed payments.

Stephen Hosmer, former CFO, current director and corporate secretary At December 31, 2023, we had a receivable balance of $18,495 due from Stephen Hosmer for normal drilling and lease operating expenses.

At December 31, 2023 and 2022, we had a total payable of $23,087 and $23,087, respectively, due to RMX and its subsidiary, Matrix Oil Corporation, related to certain lease operating expenses for wells operated by RMX. For the same periods, we also had prepaid expenses and other current assets, and deferred drilling costs of $382,520 and $290,871, respectively. In 2023, the prepaid amount was for future plugging and abandonment costs. In 2022, the prepaid amount was for drilling and future plugging costs. During 2023, RMX Resources LLC operated various oil wells we have interests in, from which we received revenues of approximately $374,000 and incurred lease operating costs of approximately $181,000. At December 31, 2023 and 2022, we had a total revenue receivables of $120,634 and $127,360, respectively, due from RMX and its subsidiary, Matrix Oil Corporation.

We had outstanding accrued unpaid guaranteed payments for unpaid salaries for periods predating their joining our company due to certain former Matrix employees. At December 31, 2023, the balance due was $1,616,205. At December 31, 2023, Royale also had accrued unpaid liabilities of $1,306,605 due to certain former Matrix employees for periods predating their employment.

Michael McCaskey, a former director, and Jeffery Kerns, a current director, and Stephen Hosmer, a current director, each have consulting agreements to provide services as directed and at our discretion. Mr. Kerns’ wife was a director during 2020 and 2021. At December 31, 2023 and 2022, we had total payables of $164,669 and $185,049, respectively, owed to current and former board members for directors fees.

NOTE 9–** STOCK COMPENSATION PLAN**

There were no stock options issued during 2023 and 2022.

NOTE 10–** SIMPLE IRA PLAN**

In April 1998, we established a Simple IRA pension plan covering all employees. We will contribute a matching contribution to each eligible employee’s Simple IRA equal to the employee’s salary reduction contributions up to a limit of 3% of the employee’s compensation for the year. The employer contribution for the years ending December 31, 2023 and 2022, were $26,051 and $27,770 respectively.

NOTE 11–** ENVIRONMENTAL MATTERS**

We have established procedures for the continuing evaluation of our operations to identify potential environmental exposures and ensure compliance with regulatory policies and procedures. Management monitors these laws and regulations and periodically assesses the propriety of our operational and accounting policies related to environmental issues. The nature of our business requires routine day-to-day compliance with environmental laws and regulations. We incurred no material environmental investigation, compliance and remediation costs in 2023 or 2022.

We are unable to predict whether our future operations will be materially affected by these laws and regulations. It is believed that legislation and regulations relating to environmental protection will not materially affect our results of operations.

NOTE 12–** CONCENTRATIONS**

We bid our gas sales on a month-to-month basis and generally sell to a single customer without commitment to future gas sales to any particular customer. We normally sell approximately 45% of our yearly natural gas production to one customer on a month-to-month basis. Since we are able to sell our natural gas to other readily available customers, the loss of any one customer would not have an adverse effect on our overall sales operations.

We maintain cash in depository institutions that are guaranteed by the Federal Deposit Insurance Corporation (FDIC) up to $250,000 per institution for our interest-bearing accounts in the years ended December 31, 2023, and 2022. At December 31, 2023 and 2022, cash in banks exceeded the FDIC limits by approximately $5.3 million and $3.6 million, respectively. We have not experienced any losses on deposits.

NOTE 13–** COMMITMENTS AND CONTINGENCIES**

We may become involved from time to time in litigation on various matters, which are routine to the conduct of our business. We believe that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial position or results of operations, though any adverse decision in these cases or the costs of defending or settling such claims could have a material effect on our business.

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. The contracts require the participants pay us the full contract price upon execution of the agreement. We typically begin the drilling activities within 12 months of funding and reach total depth between 10 and 30 days after drilling begins.

NOTE 14–** SUBSEQUENT EVENTS**

We have evaluated subsequent events through April 12, 2024, the date of issuance of these consolidated financial statements. At March 1, 2024, we issued 21,570 shares of our Series B Preferred stock with a value of $215,693 for our fourth quarter 2023 dividend that had been accrued for but not yet issued at December 31, 2023.We are not aware of events which would require recognition or disclosure in the financial statements, except as noted here or already recognized or disclosed.

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. In addition, Mr. Jordan is the beneficial owner of 14.8% 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 18.00%. The Company will make monthly interest payments starting on March 1, 2024 until the maturity date.

NOTE 15–** SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)**

The following estimates of proved oil and gas reserves, both developed and undeveloped, represent interest we owned, which are located solely in the United States. Proved reserves represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate to be reasonably certain to be recoverable in the future from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells, with existing equipment and operating methods. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which relatively major expenditures are required for completion.

Disclosures of oil and gas reserves, which follow, are based on estimates prepared by independent petroleum engineering consultant Netherland, Sewell & Associates, Inc., the net reserve value of our proved developed and undeveloped reserves was approximately $10.7 million at December 31, 2023, based on the average Henry Hub natural gas price spot price of $2.637 per MCF and for oil volumes, the average West Texas Intermediate price of $78.21 per barrel as applied on a field-by-field basis. Netherland, Sewell & Associates, Inc. provided reserve value information for our California, Texas, and Oklahoma properties. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. These estimates do not include probable or possible reserves.

The technical persons responsible for preparing the reserves estimates presented in the report of Netherland, Sewell & Associates, Inc., meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Netherland, Sewell & Associates, Inc. is a firm of independent petroleum engineers, geologists, geophysicists, and petrophysicists; and do not own an interest in our properties and are not employed on a contingent basis. All activities and reports performed and completed by Netherland, Sewell & Associates, Inc. with regards to our reserve valuation estimates are reviewed by our management.

These estimates are furnished and calculated in accordance with requirements of the FASB and the SEC. Because of unpredictable variances in expenses and capital forecasts, crude oil and natural gas price changes, largely influenced and controlled by U.S. and foreign government actions, and the fact that the bases for such estimates vary significantly, management believes the usefulness of these projections is limited. Estimates of future net cash flows presented do not represent our management’s assessment of future profitability or future cash flows. Management’s investment and operating decisions are based upon reserve estimates that include proved reserves prescribed by the SEC as well as probable reserves, and upon different price and cost assumptions from those used here.

It should be recognized that applying current costs and prices and a 10 percent standard discount rate does not convey absolute value. The discounted amounts arrived at are only one measure of the value of proved reserves.

Changes in Estimated Reserve Quantities

The net interest in estimated quantities of proved developed reserves of crude oil and natural gas at December 31, 2023 and 2022, and changes in such quantities during each of the years then ended, were as follows:

During 2023, our overall proved developed and undeveloped oil reserves decreased by 41.5% and our previously estimated proved developed and undeveloped oil reserve quantities were revised downward by approximately 185 thousand barrels. This downward revision was mainly the result of a decrease in proved undeveloped oil reserves from drilling locations which the Company had previously estimated. Our overall proved developed and undeveloped natural gas reserves decreased by 58.2% and our previously estimated proved developed and undeveloped natural gas reserve quantities were revised downward by approximately 720 thousand cubic feet of natural gas. This downward revision was mainly the result of a decrease in proved undeveloped natural gas reserves from drilling locations which we had previously estimated.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The future net cash inflows are developed as follows:

The resulting future net revenue streams are reduced to present value amounts by applying a 10 percent discount.

Disclosure of principal components of the standardized measure of discounted future net cash flows provides information concerning the factors involved in making the calculation. In addition, the disclosure of both undiscounted and discounted net cash flows provides a measure of comparing proved oil and gas reserves both with and without an estimate of production timing. The standardized measure of discounted future net cash flow relating to proved reserves reflects estimated income taxes.

Changes in standardized measure of discounted future net cash flow from proved reserve quantities

The standardized measure of discounted future net cash flows is presented below for the years ended December 31, 2023, and 2022.

This statement discloses the sources of changes in the standardized measure from year to year. The amount reported as “Net changes in prices and production costs” represents the present value of changes in prices and production costs multiplied by estimates of proved reserves as of the beginning of the year. The “accretion of discount” was computed by multiplying the 10 percent discount factor by the standardized measure on a pretax basis as of the beginning of the year. The “Sales of oil and gas produced, net of production costs” are expressed in actual dollar amounts. “Revisions of previous quantity estimates” is expressed at year-end prices. The “Net change in income taxes” is computed as the change in present value of future income taxes.

Future Development Costs

In order to realize future revenues from our proved reserves estimated in our reserve report, it will be necessary to incur future costs to develop and produce the proved reserves. The following table estimates the costs to develop and produce our proved reserves in the year 2024.

Common assumptions include such matters as the real extent and average thickness of a particular reservoir, the average porosity and permeability of the reservoir, the anticipated future production from existing and future wells, future development and production costs and the ultimate hydrocarbon recovery percentage. As a result, oil and gas reserve estimates and discounted present value estimates are frequently revised in subsequent periods to reflect production data obtained after the date of the original estimate. If the reserve estimates are inaccurate, production rates may decline more rapidly than anticipated, and future production revenues may be less than estimated.

Additional data relating to our oil and natural gas properties is disclosed in Supplemental Information About Oil and Gas Producing Activities (Unaudited), attached to our Financial Statements, in Note 15.

Historic Development Costs for Proved Reserves

In each year we expend funds to drill and develop some of our proved undeveloped reserves. We have incurred no cost in any of the past three fiscal years to drill and develop reserves that were classified as proved undeveloped reserves as of December 31 of the immediately preceding year.