Royale Energy, Inc. - Quarter Report: 2021 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549 

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D)

OF THE SECURITIES EXCHANGE ACT OF 1934

ROYALE ENERGY, INC.

(Exact name of registrant as specified in its charter)

1870 Cordell Court, Suite 210

El Cajon, CA 92020

(Address of principal executive offices) (Zip Code)

619-383-6600

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and  (2) has been subject to such filing requirements for the past 90 days. Yes  ☒  No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Check one:

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act  ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒

Indicate by check mark whether the registrant is a blank check company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

Securities registered pursuant to Section 12(b) of the Act:

At November 4, 2021, a total of 56,239,715 shares of registrant’s common stock were outstanding. 

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

See notes to unaudited condensed consolidated financial statements.

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

See notes to unaudited condensed consolidated financial statements.

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

See notes to unaudited condensed consolidated financial statements.

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2021 AND 2020

See notes to unaudited condensed consolidated financial statements.

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)

(UNAUDITED)

See notes to unaudited condensed consolidated financial statements.

ROYALE ENERGY, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – In the opinion of management, the accompanying unaudited condensed consolidated financial statements (“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 results of operations for the nine-month period are not, in management’s opinion, indicative of the results to be expected for a full year of operations.  It is suggested that these financial statements be read in conjunction with the financial statements and the notes thereto included in the Company’s latest annual report as filed on Form 10-K.

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 the Company’s ability to meet liquidity demands, and we anticipate that our primary sources of liquidity will be from the issuance of debt and/or equity, the sale of oil and natural gas property participation interests through our normal course of business and the sale of non-strategic assets

At September 30, 2021, the Company’s consolidated financial statements reflect a working capital deficiency of $6,038,231 and a net loss of $982,328 and $2,577,999 for three months and nine months ended September 30, 2021. 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 the Company is unable to continue as a going concern.

Management’s plans to alleviate the going concern by cost control measures that include the reduction of overhead costs and the sale of non-strategic assets. 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 the Company and whether the Company will become profitable and generate positive operating cash flow. If the Company is unable to raise sufficient additional funds, it will have to develop and implement a plan to further extend payables, attempt to extend note repayments, and reduce overhead until sufficient additional capital is raised to support further operations. There can be no assurance that such a plan will be successful.

East LA Sale

The Company and its joint venture partner, RMX, entered into a purchase and sales agreement as well as a second amendment to that certain purchase and sales agreement which closed in September 2021. During the period in 2021, the Company carried these assets on the books for $1.0 million booked as Held for Sale with an current ARO amount of approximately $721,000 for the existing wells and facilities located on the properties. The sale required RMX and the Company to plug and abandon one well on the property and remove and restore the surface land. The sale price of $1.0 million to the Company resulted in recording a loss on the sale of these properties of approximately $254,000.

Non-operated West Texas Property Sale

During the six months ended June 30, 2021, we recorded a gain of $291,249 on the sale of asset on the sale of certain non-operated Texas properties. These non-operated properties were originally acquired during the 2018 merger with Matrix Oil Management Corporation and booked as Held for Sale at the end 2020.

Consolidation

The accompanying financial statements include the accounts of Royale Energy, Inc. (sometimes called the “Company” “we,” “our,” “us,” “Royale Energy,” or “Royale”), Royale Energy Funds, Inc. (“REF”), and Matrix Oil Management Corporation and its subsidiaries.  All entities comprising the financial statements of Royale Energy have fiscal years ending December 31.  All material intercompany accounts and transactions have been eliminated in the financial statements.

Use of Estimates

The accompanying 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.  

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

The majority of our ongoing revenues are derived from the sale of crude oil and condensate, natural gas liquids ("NGLs") and natural gas under spot and term agreements with our customers.

The pricing in our hydrocarbon sales agreements are variable, determined using various published benchmarks which are adjusted for negotiated quality and location differentials. As a result, revenue collected under our agreements with customers is highly dependent on the market conditions and may fluctuate considerably as the hydrocarbon market prices rise or fall. Typically, our customers pay us monthly, within a short period of time after we deliver the hydrocarbon products. As such, we do not have any financing element associated with our contracts. We do not have any issues related to returns or refunds, as product specifications are standardized for the industry and are typically measured when transferred to a common carrier or midstream entity, and other contractual mechanisms (e.g., price adjustments) are used when products do not meet those specifications.

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 regards to the sale of our share of production and recognize revenue for the volumes associated with our net production.

The Company frequently sells a portion of the working interest in each well it drills or participates in, to third-party investors and retains a portion of the prospect for its own account.  The Company typically guarantees a cost to drill to the third-party drilling participants and records 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, the Company records the liability as Deferred Drilling Obligations.  Once the contracted depth for the drilling of the well is reached and a determination as to the commercial viability of the well (typically call “Casing Point Election” or “Logging Point”), the difference in the actual cost to drill and the guaranteed cost is recorded as income or expense depending on whether there was a gain or loss.

Crude oil and condensate

For the crude 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, as defined in the new revenue standard, 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 Pacific Gas & Electric (PG&E) where transportation is netted directly against revenue. Under some of our natural gas processing agreements, we have an option to take the processed natural gas and NGLs in-kind and sell to customers other than the processing company. In those circumstances, our performance obligations are complete after delivering the processed hydrocarbons to the customer at the designated delivery points, which may be the tailgate of the processing plant or an alternative delivery point requested by the customer.

Turnkey Drilling

Royale sponsors turnkey drilling arrangements in proved and unproved properties. The contracts require that participants pay Royale 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, the Company 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.

These Turnkey Agreements are managed by the Company for the participants of the well. The collections of pre-drilling AFE amounts are segregated by the Company 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 932-323-25 and 932-360. The Company manages the performance obligation for the well participants and only records revenue or expense at the time the performance obligation of the Turnkey Agreement has been satisfied. 

Restricted Cash

Royale sponsors turnkey drilling arrangements in proved and unproved properties. The contracts require that participants pay Royale 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, the Company 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. Royale classifies 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 sheet that sum to the total of the same amounts shown in the statement of cash flows.

Equity Method Investments

Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting. Income from equity method investments represents our proportionate share of net income generated by the equity method investees and is reflected in revenue and other income in our condensed consolidated statements of operations. Equity method investments are included as noncurrent assets on the consolidated balance sheet.

Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value may have occurred as called for under ASC 323. When a loss is deemed to have occurred and is other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income.

At year-end 2020, we evaluated our investment in RMX and determined that the investment was fully impaired at December 31, 2020. As a result of the valuation allowance, the Company has not included any gain or loss on its Investment in Joint Venture for the period ended September 30, 2021. During the period ended September 30, 2020, the Company recorded a loss of $301,015 reflecting our share of losses directly attributable to this equity method investment. For the period ending September 30, 2021, no earnings or loss was recorded as a result of full impairment of the investment balance at December 31, 2020.

Other Receivables

Other receivables consist of joint interest billing receivables from direct working interest investors and industry partners. We provide for uncollectible accounts receivable using the allowance method of accounting for bad debts.  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 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 September 30, 2021 and December 31, 2020, the Company maintained an allowance for uncollectable accounts of $2,761,398 and $2,582,093, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue.

Fair Value Measurements

According to Fair Value Measurements and Disclosures Topic of the FASB ASC, assets and liabilities that are measured at fair value on a recurring and nonrecurring basis in period subsequent to initial recognition, the reporting entity shall disclose information that enable users of its 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, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible as well as considers counterparty credit risk in its assessment of fair value. Carrying amounts of the Company’s 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 September 30, 2021 and December 31, 2020, Royale Energy does not have any financial assets measured and recognized at fair value on a recurring basis. The Company estimates asset retirement obligations (ARO’s) pursuant to the provisions of ASC 410, “Asset Retirement and Environmental Obligations”. The estimates of the fair value the ARO’s are based on discounted cash flow projections using numerous estimates, assumptions and judgements regarding such factors as the existence of a legal obligation for an ARO, amounts and timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates.

The initial measurement of 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.

Fair Values - Non-recurring

The Company applies the provisions of the fair value measurement standard to its non-recurring, non-financial measurements including oil and natural gas property impairments and other long-lived asset impairments. These items are not measured at fair value on a recurring basis but are subject to fair value adjustments only in certain circumstances.

Dividends on Series B Convertible Preferred Stock

The Series B Convertible Preferred Stock, (“Preferred”), has an obligation to pay a 3.5% cumulative dividend, in kind or cash, on a quarterly basis. In the third quarter of 2020, the Board of Directors authorized the issuance of Preferred shares, for the settlement of dividends accumulated through December 31, 2021.  The Company accrued $199,413 and $192,583 for dividends related to the Preferred shares during the third quarters of 2021 and 2020, respectively. Each quarter, the Company charges retained earnings for the accumulating dividend as the amounts add to the liquidation preference of the Preferred. For further information regarding the Preferred Stock see Note 3, below.

Risks and Uncertainties

In December 2019, a novel strain of coronavirus (which triggers a respiratory disease called COVID-19) was reported in Wuhan, China. The World health Organization has declared the outbreak to constitute a “Public Health Emergency of International Concern.” The COVID-19 outbreak has caused a major reduction in the consumption of hydrocarbon-based transportation fuels as airlines have grounded flights worldwide and countries around the world have asked residents to suspend automobile travel. In addition to a substantial loss of demand for crude oil, in March, Saudi Arabia entered into a price war with Russia and added additional supplies of crude oil to an already over supplied market. The result was a precipitous decline in the price of crude oil received by the Company in 2020. At September 30, 2021 the price of West Texas Intermediate crude oil had reached $75.03 per barrel.

ACCOUNTING STANDARDS

Not Yet 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) such as Royale, for fiscal years beginning after December 15, 2022, including interim periods within those years, and must be adopted under the modified retrospective method. Entities may adopt ASU 2016-13 earlier as of the fiscal years beginning after December 15, 2018, including interim periods within those years. Adoption of this standard is not expected to have a material impact on our consolidated financial statements and cash flows.

NOTE 2 – OIL AND GAS PROPERTY AND EQUIPMENT AND FIXTURES

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

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

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

Royale Energy uses the “successful efforts” method to account for its exploration and production activities.  Under this method, Royale Energy accumulates its proportionate share of costs on a well-by-well basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred and capitalizes expenditures for productive wells.  Royale Energy amortizes the costs of productive wells under the unit-of-production method.

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

Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using unit-of-production rates based on the amount of proved developed reserves of oil and gas that are estimated to be recoverable from existing facilities using current operating methods.  Under the unit-of-production method, oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank.

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 Energy’s wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labor costs to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; 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 Energy are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable.

Royale Energy estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts and whether carrying amounts should be impaired. The Company performs the evaluation of carrying amounts at least annually or when economic events or commodity prices indicate that a substantial and measurable change in future cash flows has occurred. Cash flows used in impairment evaluations are developed using updated evaluation assumptions for crude oil and natural gas commodity prices.  Annual volumes are based on field production profiles, which are also updated annually.

Impairment analyses are generally based on proved reserves. An asset group would be further assessed if the undiscounted cash flows were less than its’ carrying value.  Impairments are measured by the amount the carrying value exceeds fair value. During the nine months ended September 30, 2021 and 2020, no impairment losses were incurred.

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

Upon the sale or retirement of a complete field of a proved property, Royale Energy eliminates the cost from its books, and the resultant gain or loss is recorded to Royale Energy’s Statement of Operations.  Upon the sale of an entire interest in an unproved property where the property has been assessed for impairment individually, a gain or loss is recognized in Royale Energy’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 Energy’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. 

Royale Energy sponsors turnkey drilling agreement arrangements in unproved properties as a pooling of assets in a joint undertaking, whereby proceeds from participants are reported as Deferred Drilling Obligations, and then reduced as costs to complete its obligations are incurred with any excess booked against its property account to reduce any basis in its own interest.  Gains on Turnkey Drilling Programs represent funds received from turnkey drilling participants in excess of all costs Royale incurs during the drilling programs (e.g., lease acquisition, exploration and development costs), including costs incurred on behalf of participants and costs incurred for its own account; and are recognized only upon making this determination after Royale’s obligations have been fulfilled.

The contracts require the participants pay Royale Energy the full contract price upon execution of the agreement.  Royale Energy completes 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 its proportionate share of operating costs.  Royale Energy retains 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.  The Company holds all funds invested as Deferred Drilling Obligations until drilling is complete.  Occasionally, drilling is delayed for various reasons such as weather, permitting, drilling rig availability and/or contractual obligations.  At September 30, 2021 and December 31, 2020, Royale Energy had Deferred Drilling Obligations of $4,922,439 and $3,127,500, respectively.

If Royale Energy is unable to drill the wells, and a suitable replacement well is not found, Royale 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.

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.

During the nine months ended September 30, 2021, we recorded a gain of $36,954 on the sale of asset on the sale of certain non-operated California and Texas properties. These non-operated properties were originally acquired during the 2018 merger with Matrix Oil Management Corporation and booked as Held for Sale at the end of 2020.

NOTE 3 – 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 Royale 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 Series B Convertible Preferred Stock of Royale. The Board of Directors of Royale Energy, 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 common 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 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, the Company has determined that the conversion or redemption of these shares are outside the sole control of the Company and that they should be classified in mezzanine or temporary equity as redeemable noncontrolling interest beginning at the reporting period ended March 31, 2020.

For 2021 and 2020, 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 quarter ending September 30, 2021, the Company accrued 19,942 shares with a value of $199,413. During 2021 and 2020 no cash was used to pay dividends on Series B preferred shares.

NOTE 4 – LOSS PER SHARE

Basic and diluted loss per share are calculated as follows:

For the nine months ended September 30, 2021 and 2020, Royale Energy had dilutive securities of 26,212,211 and 25,160,750, respectively. For the three months ended September 30, 2021 and 2020, Royale Energy had dilutive securities of 26,071,245 and 25,166,967, respectively. In both periods, 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 the Company’s net deferred tax assets, and due to the Company’s continued cumulative losses in recent years, the Company concluded it is not “more-likely-than-not” its deferred tax assets will be realized.  As a result, the Company will continue to record a full valuation allowance against the deferred tax assets in 2021.

A reconciliation of Royale Energy’s provision for income taxes and the amount computed by applying the statutory income tax rates at September 30, 2021 and 2020, respectively, to pretax income is as follows: 

NOTE 6 – ISSUANCE OF COMMON STOCK

During the nine months ended September 30, 2021, in lieu of cash payments for salaries and board fees, Royale issued 1,634,227 shares of its Common stock valued at approximately $176,709 to an executive officer and board members, compared to the issuance of 2,273,245 shares issued with an approximate value of $288,876 in the same period of 2020.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

FORWARD-LOOKING STATEMENTS

In addition to historical information contained herein, this discussion contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, subject to various risks and uncertainties that could cause our actual results to differ materially from those in the “forward-looking statements”. While we believe our forward-looking statements are based upon reasonable assumptions, there are factors that are difficult to predict and that are influenced by economic and other conditions beyond our control. Investors are directed to consider such risks and other uncertainties discussed in documents filed by the Company with the Securities and Exchange Commission.

RESULTS OF OPERATIONS

In late 2019 and continuing into 2021, there was a global outbreak of novel coronavirus (COVID-19) that has resulted in changes in global supply and demand of certain mineral and energy products. While the direct and indirect negative impacts that may affect the Company cannot be determined, they could have a prospective material impact.  For more information, see Item 3 below.

For the nine months ended September 30, 2021 and 2020, we had net losses of $2,577,999 and $540,251, respectively. The difference was primarily due to a gain on turnkey drilling of approximately $1 million during nine months in 2020 compared to a loss on turnkey drilling of approximately $65,000 during the period in 2021. During the nine months ended September 30, 2020, we also recognized a gain of $532,510 relating to our equity method investment in RMX. During the fourth quarter in 2020, it was determined that a full impairment of the equity method investment was warranted, so there was no comparative gain or loss in the current year period. During the three months ended September 30, 2021 and 2020, we had net losses of $982,328 and $612,229, respectively, mainly due to a loss on sale of assets recognized during the third quarter in 2021 as a result of the completion of the sale of certain properties in California.

During the first nine months of 2021, revenues from oil and gas production increased $64,501 or 5.7% to $1,202,346 from the 2020 first nine months revenues of $1,137,845. This increase was mainly due to higher oil and natural gas commodity prices. The net sales volume of oil and condensate for the nine months ended September 30, 2021, was approximately 14,734 barrels with an average price of $62.02 per barrel, versus 23,432 barrels with an average price of $37.34 per barrel for the first nine months of 2020. This represents a decrease in net sales volume of 8,698 barrels or 37.1%, which was due to the sales of non-operated oil and gas properties in Texas and California. The net sales volume of natural gas for the nine months ended September 30, 2021, was approximately 88,287 Mcf with an average price of $3.26 per Mcf, versus 121,097 Mcf with an average price of $2.17 per Mcf for the same period in 2020. This represents a decrease in net sales volume of 32,810 Mcf or 27.1%. The decrease in natural gas production volume was due to certain wells that were offline and waiting on workovers and to lower volumes on existing wells due to natural declines. For the quarter ended September 30, 2021, revenues from oil and gas production decreased $126,376 or 22.9% to $425,470 from the 2020 third quarter revenues of $551,846. This decrease was due to lower oil and natural gas production volumes. The net sales volume of oil and condensate for the quarter ended September 30, 2021, was approximately 4,564 barrels with an average price of $68.05 per barrel, versus 11,933 barrels with an average price of $40.03 per barrel for the third quarter of 2020. This represents a decrease in net sales volume of 7,369 barrels or 61.8% for the quarter in 2021. The net sales volume of natural gas for the quarter ended September 30, 2021, was approximately 26,996 Mcf with an average price of $4.24 per Mcf, versus 38,057 Mcf with an average price of $1.94 per Mcf for the third quarter of 2020. This represents a decrease in net sales volume of 11,061 Mcf or 29.1% for the quarter in 2021.

Oil and natural gas lease operating expenses increased by $9,563 or 0.8%, to $1,172,991 for the nine months ended September 30, 2021, from $1,163,428 for the same period in 2020. For the third quarter in 2021, lease operating expenses increased $74,950 or 19.5% from the same quarter in 2020. These increases were mainly due to work on existing wells in our operated Texas field to increase production.

The aggregate of supervisory fees and other income was $25,221 for nine months ended September 30, 2021, a decrease of $6,044 from $31,265 during the same period in 2020. During the third quarter 2021, supervisory fees and other income decreased $3,190 when compared to the quarter in 2020. These decreases were primarily due to lower pipeline and compressor fee income due to lower production volumes during the period in 2021.

Depreciation, depletion and amortization expense increased to $397,629 from $249,492, an increase of $148,137 or 59.4% for the nine months ended September 30, 2021, as compared to the same period in 2020. During the third quarter 2021, depreciation, depletion and amortization expenses also increased $9,401 or 10.0%. The depletion rate is calculated using production as a percentage of reserves. This increase in depletion expense was due to a decrease in expected recoverable reserves which increased the depletion rate.

At September 30, 2021, Royale Energy had a Deferred Drilling Obligation of $4,922,439. During the first nine months of 2021, we disposed of $1,841,061 of drilling obligations upon completing the drilling of two oil wells in Texas, while incurring expenses of $1,906,204, resulting in a loss of $65,143. Although these two wells were originally drilled during the first quarter of 2021, we continued additional work during second quarter 2021 to increase production. At September 30, 2020, Royale Energy had a Deferred Drilling Obligation of $3,870,774. During the first nine months of 2020, we disposed of $4,386,901 of drilling obligations upon completing the drilling of three oil wells, one in California and two wells in Texas, while incurring expenses of $3,358,206, resulting in a gain of $1,028,695.

General and administrative expenses decreased by $18,702 or 1.2% from $1,580,637 for the nine months ended September 30, 2020, to $1,561,935 for the same period in 2021. For the third quarter 2021, general and administrative expenses decreased $20,027 or 4.0% when compared to the same period in 2020. Marketing expense for the nine months ended September 30, 2021, increased $37,317, or 43.1%, to $123,818, compared to $86,501 for the same period in 2020. For the third quarter 2021, marketing expenses increased $9,886 or 31.5% when compared to the third quarter in 2020. Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs.

Legal and accounting expense increased to $338,870 for the nine-month period in 2021, compared to $238,124 for the same period in 2020, a $100,746 or 42.3% increase. This increase was primarily due to higher audit related expenses during the period in 2021. For the third quarter 2021, legal and accounting expenses decreased $594 or 0.9%, when compared to the third quarter in 2020.

During the three months ended September 30, 2021, we recorded a loss of $254,295 on sale of asset upon the sale of certain non-operated California properties which was completed during the third quarter of 2021. We also recorded a gain of $291,249 on the sale of asset upon the sale of certain non-operated Texas properties which was recognized during the second quarter of 2021. In both instances, these non-operated properties were originally acquired during the 2018 merger with Matrix and booked as Held for Sale at the end of 2020, which resulted in a net gain on sale of assets of $36,954 for the nine months ended September 30, 2021. During the first quarter of 2021, we recorded a gain on settlement of $10,061 due to the payment by the SBA of the remaining balance on our PPP loan obtained in 2020. During the nine months ended September 30, 2020, we recorded a gain of $532,510, on investment in joint venture as our 20% share of RMX Resources, LLC’s. As a result of recognizing an impairment for the full value of the investment, the Company did not recognize any gain or loss in subsequent periods. See note Equity Method Investment in Note 1 above. During the second quarter in 2020 we recorded a gain of $200,001 on the receipt of a pre-Matrix merger prepayment refund. During the first quarter in 2020, we recorded a loss on settlement of $31,500 related to a 2018 seismic sales agreement. During the nine-month period in 2020, we recorded $14,392 in geological and geophysical expenses, related to costs in our Texas Jameson field.

Bad debt expense for the nine months ended September 30, 2021, and 2020 were $187,348 and $368,417, respectively.  Approximately $180,000 of the expenses in 2021 and $154,000 of the expenses in 2020 arose from identified uncollectable receivables relating to our oil and natural gas properties either plugged and abandoned or scheduled for plugging and abandonment and our period end oil and natural gas reserve values. We periodically review our accounts receivable from working interest owners to determine whether collection of any of these charges appears doubtful.  By contract, the Company may not collect some charges from its Direct Working Interest owners for certain wells that ceased production or had been sold during the year, to the extent that these charges exceed production revenue. During the period in 2020 approximately $203,000 was related to revenue receivable from an industry partner whose collectability was in doubt.

Interest expense decreased to $6,857 for the nine months ended September 30, 2021, from $10,306 for the same period in 2020, a $3,449 decrease.  This decrease was mainly due to lower principal balances on notes payable during the nine-month period in 2021.

CAPITAL RESOURCES AND LIQUIDITY

At September 30, 2021, we had current assets totaling $4,971,915 and current liabilities totaling $11,010,146, a $6,038,231 working capital deficit.  We had $472,925 in cash and $1,694,521 in restricted cash at September 30, 2021, compared to $255,112 in cash and $2,146,571 in restricted cash at December 31, 2020.

In accordance with ASC 480-10-S99 the Company reclassified the Series B Convertible Preferred Stock from Permanent Equity to Mezzanine capital as a result of the change in voting rights provided at the time it of issuance. For more information, see Note 3 – Series B Convertible Preferred Stock.

At September 30, 2021, our other receivables, which consist of joint interest billing receivables from direct working interest investors and industry partners, totaled $318,913 compared to $462,777 at December 31, 2020, a $143,864 decrease.  This decrease was mainly due to the increase in the accounts receivable allowance from direct working interest owners. At September 30, 2021, revenue receivable was $257,067, an increase of $52,918, compared to $204,149 at December 31, 2020, due to higher commodity prices during the quarter in 2021.  At September 30, 2021, our accounts payable and accrued expenses totaled $4,626,077, an increase of $464,968 from the accounts payable at December 31, 2020 of $4,161,109, which was mainly due to drilling costs and lease operating costs during the first nine months in 2021. 

The Company has had recurring operating and net losses and cash used in operations and the financial statements reflect a working capital deficiency of $6,038,231 and an accumulated deficit of $85,463,445. These factors raise substantial doubt about our ability to continue as a going concern. We anticipate that our primary sources of liquidity will be from the sale of oil and gas in the course of normal operations, the sale of oil and gas property, sales of participation interest and possible issuance of debt and/or equity. If the Company is 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 the Company’s business, results of operations, financial position and liquidity. Additionally, management has, and plans to continue, to increase revenue and reduce overhead and Lease Operating Expense (LOE) costs.

Operating Activities.  Net cash used by operating activities totaled $2,366,587 and $645,657 for the nine months ended September 30, 2021, respectively. This difference in cash used was mainly due to drilling prepayments made during the period in 2021 versus the use of previously made drilling prepayments during the 2020 period.

Investing Activities.  Net cash provided by investing activities totaled $2,160,234 and net cash used in investing activities totaled $992,429 for the nine months ended September 30, 2021, and 2020, respectively. During the nine month period in 2021, we received approximately $3.6 million in direct working interest investor turnkey drilling investments while our drilling expenditures were approximately $2.5 million in the drilling and completing of two Texas oil wells. During the period in 2021, we also received approximately $1 million for the sale of non-operated properties in Texas and California. During the period in 2020, we received approximately $3 million in direct working interest investor turnkey drilling investments while our drilling expenditures were approximately $4 million in the drilling and completing of one Southern California oil well and two Texas oil wells.

Financing Activities.  Net cash used in financing activities totaled $27,884 and net cash provided by financing activities was $144,806 for the nine months ended September 30, 2021, and 2020, respectively. During the period in 2021, the total used was for note and financing lease payments while during the period in 2020, we received $207,800 in SBA-PPP loan and made principal payments of approximately $63,000 on existing notes payable.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

In late 2019 and continuing into 2021, there was a global outbreak of COVID-19 that has resulted in changes in global supply and demand of certain mineral and energy products. While the direct and indirect negative impacts that may affect the Company cannot be determined, they could have a prospective material impact to the Company's operations, cash flows and liquidity, primarily related to the decline in product price, in part, as a result of a decline in demand related to “shelter-in-place” orders by various governmental bodies.

Our major market risk exposure relates to pricing of oil and gas production, which during the period in 2020 resulted in historically low prices due to stay at home orders.  The prices we receive for oil and gas are closely related to worldwide market prices for crude oil and local spot prices paid for natural gas production.  Prices have been volatile for the last several years and have become even more unpredictable in the current period. We expect that volatility to continue.  For the first nine months of 2021 our monthly average oil and condensate prices ranged from a high of $70.07 per barrel to a low of $55.56 per barrel and our monthly average natural gas prices ranged from a high of $4.95 per Mcf to a low of $2.50 per Mcf.

Item 4. Controls and Procedures

As of September 30, 2021, an evaluation was performed under the supervision and with the participation of our management, including our CEO and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures.  These controls and procedures are based on the definition of disclosure controls and procedures in Rule 13a-15(e) and Rule 15d-15(e) promulgated under the Securities Exchange Act of 1934.  A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. 

As a result of the review by the CFO and CEO, the material weakness was identified as listed below.

Because of the material weaknesses described above, our management was unable to conclude that our internal control over financial reporting was effective as of the end of period to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with generally accepted accounting principles.

Except for the actions described above that were taken to address the material weaknesses, there were no changes in our internal controls during the period ended September 30, 2021, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Notwithstanding the material weaknesses described above, our management, including our Chief Executive Officer and Chief Financial Officer, believes that the consolidated financial statements contained in this Report on Form 10-Q fairly present, in all material respects, our financial condition, results of operations and cash flows for the fiscal periods presented in conformity with U.S. generally accepted accounting principles. In addition, the material weakness described did not result in the restatements of any of our audited or unaudited consolidated financial statements or disclosures for any previously reported periods.

INTERNAL CONTROL OVER FINANCIAL REPORTING AND CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

During the nine months ended September 30, 2021, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

None

Item 1A. Risk Factors

Not applicable to smaller reporting companies.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

During the period covered by this report, we have not issued any unregistered shares.

Item 4. Mine Safety Disclosures

Not applicable

Item 5.  Other Information

None

Item 6.  Exhibits

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.