Royale Energy, Inc. - Quarter Report: 2019 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)

Royale Energy Holdings, Inc.

(Former name, former address and former fiscal year, if changed since last report)

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 an emerging growth company (as defined 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 1, 2019, a total of 51,401,873 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 (UNAUDITED)

See notes to unaudited condensed consolidated financial statements.

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

See notes to unaudited condensed consolidated financial statements.

ROYALE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

FOR THE PERIODS ENDED SEPTEMBER 30, 2019 AND 2018

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, 2019 AND 2018

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 financial statements include all adjustments, necessary to present fairly the Company’s financial position and the results of its operations and cash flows for the periods presented.  The 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.

The Company has a substantial investment in RMX Resources, LLC (“RMX”), a joint venture with CIC RMX LP. Royale entered into the RMX joint venture on April 13, 2018 and records its interest in RMX under the equity method as further described below.

Liquidity and Going Concern

The Company has had recurring operating and net losses and cash used in operations and the consolidated financial statements reflect a working capital deficiency of $5,662,446 and an accumulated deficit of $73,652,310. 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 & 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.

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.

Consolidation

The accompanying consolidated 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 consolidated financial statements of Royale Energy have fiscal years ending December 31.  All material intercompany accounts and transactions have been eliminated in the consolidated 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.  As reflected in the accompanying financial statements, the Company has negative working capital, losses from operations and negative cash flows from operations.

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.

Termination of RMX MSA

On December 31, 2018, Royale was formally notified of RMX Resources, LLC’s intent to terminate the Master Service Agreement (“MSA”) as of March 31, 2019. The Termination Notice calls for Royale to continue to provide accounting and other services through March 31, 2019. Thereafter, per Article VII, Section 7.2 of the MSA, Royale has provided all reasonable assistance requested, by the RMX Board of Directors, to transition the management of RMX through April 30, 2019 at which point all services under the MSA terminated.

Settlement Agreement and Well Participation Agreement with RMX

On March 11, 2019 Royale entered into a Settlement Agreement with RMX to resolve differences resulting from the calculation of certain post-closing amounts as called for under Section 7.3 of the Subscription and Contribution Agreement. Under the terms of this provision, Royale estimated that it may owe RMX approximately $552,645 related to its calculation of this post-closing amount under this provision. In addition, there are other disputed amounts related to certain joint owner billing amounts remaining unpaid at year end. In settlement of these differences, Royale has agreed to assign its remaining interests in the Bellevue Field, located in Kern County and the W. Whittier Field located in Los Angeles County, California to RMX. At December 31, 2018, the Bellevue and W. Whittier fields accounted for 5.145 and 140.647 Mboe in reserves and were valued at $67,671 and $2.4 million, respectively, using SEC pricing and discounted at 10 percent. Royale will continue to be responsible for the liability for the payment of all royalties and suspended funds incurred prior to March 1, 2018. As part of this Settlement Agreement, RMX will offer Royale the right, but not the obligation, to participate in a number of wells to be drilled in the Sansinena, Sempra, Whittier and/or East LA properties in Los Angeles County, California at an offered working interest up to 75% of RMX’s working interest in each of the offered wells. The minimum number of wells to be offered to Royale in each year is 2 net wells as determined by an agreed upon methodology. The Agreement also calls for certain credits toward future drilling costs of the offered wells. The Company recorded a loss of $1,237,126 on the settlement during 1^st quarter 2019.

West Coast Settlement

On December 5, 2018, Royale entered into a Purchase and Sales Agreement (“West Coast Agreement”) for properties located in the Jameson North Field Area in Mitchell and Nolan Counties, Texas and the Big Mineral Creek Field Area in Grayson County, Texas. The seller was West Coast Energy Properties, LP. The West Coast Agreement called for a post-closing settlement. On July 11, 2019, Royale entered into a post-closing settlement as called for under the terms of the West Coast Agreement calling for payment due seller of $156,975 to be made in equal monthly payments of $26,163 commencing July 31, 2019 with the final payment on December 31, 2019. As part of the post-closing settlement, we capitalized approximately $165,000 to the North Jameson field and increased short term liabilities for approximately $165,000, approximately $157,000 for the total settlement payments and $8,000 for royalties payable assumed in the settlement.

Vanco Agreement

On September 10, 2019, Royale granted to Vanco Oil and Gas Corporation, the right to purchase all of Matrix’s right, title and interest in certain non-operated oil and gas properties in west Texas. While the purchase has not been consummated, the company is engaged in an ongoing effort to complete this, or a similar transaction in the near future.

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.

When we serve as the operator for jointly owned oil and gas properties, 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, accordingly, these reimbursements are not reported as revenue.

When we serve as operator, we commonly market the share of production belonging to other working interest owners as the operator of jointly owned oil and gas properties. We concluded that 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 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 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 Obligations

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 (Extractive Activities - Investments - Equity Method and Joint Ventures) and 932-360 (Extractive Activities - Oil and Gas Property, Plant, and Equipment).  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. At September 30, 2019 we had Deferred Drilling Obligations of $6,077,583, during the first nine months of 2019 we disposed of $9,382,519 of drilling obligations upon completing the drilling of eight wells, six natural gas wells in Northern California and two oil wells in Southern California, while incurring expenses of $7,484,260 resulting in a gain of $1,898,259. At September 30, 2018, Royale Energy had a Deferred Drilling Obligation of $5,406,678.  During the first nine months of 2018, we disposed of $4,797,720 of drilling obligations upon completing the drilling of three natural gas wells in Northern California while incurring expenses of $2,603,261, resulting in a gain of $2,194,459.

Supervisory Fees and Other

These amounts include proceeds from the MSA with RMX for the providing of land, engineering, accounting and support services for the RMX joint venture. Revenues earned under the MSA are recorded at the end of each month that services were performed in conformity with the Agreement with an offsetting receivable from the RMX joint venture. The service fee income is deemed earned at the end of each month that services are performed as prescribed by the contract. During the first half of 2019, we recognized $540,000 or 39% of our total revenues from these services. Royale has a single supervisory fee customer, that being RMX, which represents 100% of the Supervisory Fee income. On December 31, 2018, Royale received notice of cancelation of the MSA by RMX effective March 31, 2019. Also included are Pipeline and Compressor fees which are received and allocated based on production volumes.

Restricted Cash

Royale sponsors turnkey drilling arrangements in both proved and exploratory 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 drilling as restricted cash.

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 consolidated statements of income. 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.

Listed below is the summarized information required under Rule 3-09 of regulation S-X, Article 10 for Royale’s investment in RMX:

Other Receivables

Our 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, 2019 and December 31, 2018, the Company maintained an allowance for uncollectable accounts of $2,260,077 and $2,296,384, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue.

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 for Company operated properties. For outside operated properties, we generally receive payment approximately 45 to 60 days later.

Fair Value Measurements

According to Fair Value Measurements and Disclosures Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification, 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. The Company estimates the fair value of asset retirement obligations (ARO’s) 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.

At September 30, 2019 and December 31, 2018, Royale Energy did not have any financial assets measured and recognized at fair value on a recurring basis.  The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic 410, “Asset Retirement and Environmental Obligations” (“FASB ASC 410”). 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 Convertible Preferred Stock, Series B

The Convertible Preferred Stock, Series B (“Preferred”), has an obligation to pay a 3.5% cumulative dividend, in kind or cash, on a quarterly basis. In the first quarter of 2019, the Board of Directors authorized the issuance of Preferred shares, for the settlement of dividends accumulated through March 31, 2019.  As a result, the Company issued 59,461 Preferred shares for dividends accumulated through December 31, 2018 and 17,879 additional shares for dividends accumulated for the quarter ended March 31, 2019. On September 20, 2019, the Board authorized the settlement, via the issuance of Preferred shares, of each quarterly dividend that will accrue in 2019.  Each quarter, the Company charges retained earnings for the accumulating dividend as the amounts add to the liquidation preference of the Preferred.   Through September 30, 2019, the total number of shares issued was 77,340.

Accounting Standards

Recently Adopted

ASU 842, Lease Accounting Standard

In February 2016, the FASB issued a new leasing accounting standard, which modified the definition of a lease and established comprehensive accounting and financial reporting requirements for leasing arrangements. It requires lessees to recognize a lease liability and a right-of-use ("ROU") asset for all leases, including operating leases, with a term of greater than 12 months on the balance sheet. On January 1, 2019, we adopted the new lease accounting standard as further described in Note 5 using the modified retrospective method and applied to all leases that existed as of that date. It does not apply to oil & gas mineral leases and contracts to explore for or use minerals, oil, natural gas and similar non-regenerative resources, including the intangible right to explore for those natural resources and rights to use the land in which those natural resources are contained.

We also adopted the following ASUs during 2018, none of which had a material impact to our financial statements or financial statement disclosures:

ASU 2018-02, Reporting Comprehensive Income – Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income

In February 2018, the FASB issued an ASU allowing an entity the choice to retained earnings the tax effects related to the TCJA that are stranded in accumulated other comprehensive income. We adopted this standard during the first quarter of 2019. It did not have a material impact to our financial statements or financial statement disclosures.

ASU 2017-12, Derivatives and Hedging – Targeted Improvement to Accounting for Hedging Activities

In August 2017, the FASB issued an ASU to amend the hedge accounting rules to simplify the application of hedge accounting guidance and better portray the economic results of risk management activities in the financial statements. The guidance expands the ability to hedge nonfinancial and financial risk components, reduces complexity in fair value hedges of interest rate risk, eliminates the requirements to separately measure and report hedge ineffectiveness and eases certain hedge effectiveness assessment requirements. The guidance is effective beginning in 2019. We have not historically used derivatives to hedge our commodity price risk; this ASU did not have a material impact on our consolidated financial statements.

NOT YET ADOPTED

ASU 2018-18, Collaborative Arrangements (Topic 808) Clarifying the Interaction between Topic 808 and Topic 606

This is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Application of this ASU is not expected to have a material impact on our consolidated financial statements.

ASU 2018-17, Consolidation (Topic 810), Targeted Improvements to Related Party Guidance for Variable Interest Entities

Effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Application of this ASU is not expected to have a material impact on our consolidated financial statements.

ASU 2018-15, Intangibles – Goodwill and Other – Internal Use Software (Subtopic 350-400), Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract

Effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2019. Application of this ASU is not expected to have a material impact on our consolidated financial statements.

ASU 2018-14, Compensation – Retirement Benefits – Defined Benefit Plans – General (Subtopic 715-720), Disclosure Framework – Changes to the Disclosure Requirements for Defined Benefit Plans

Effective for financial statements issued for fiscal years ending after December 15, 2020. Application of this ASU is not expected to have a material impact on our consolidated financial statements.

ASU 2018-13, Fair Value Measurement (Topic 820), Disclosure Framework – Changes to the Disclosure Requirements for fair value measurement

Effective for fiscal years, and interim periods within those years, beginning after December 15, 2019. Application of this ASU is not expected to have a material impact on our consolidated financial statements.

ASU 2017-04, Intangible – Goodwill and Other (Topic 350), Simplifying the Test for Goodwill Impairment

In January 2017, the FASB issued a new ASU that eliminates the requirement to calculate the implied fair value of the goodwill (Step 2 of goodwill impairment test under the current guidance) to measure a goodwill impairment charge. We anticipate the standard to require entities to record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value (measure the charge based on Step 1 under the current guidance). This standard is effective for us in the first quarter of 2020 and shall be applied on a prospective basis. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We plan to adopt the standard on a prospective basis, and do not expect a material impact on our consolidated results of operations, financial position or cash flows for prior periods.

ASU 2016-13, Financial Instruments – Credit Losses (Topic 326), Measurement of Credit Losses on Financial Instruments

Effective for fiscal years beginning after December 15, 2020 including interim periods within those fiscal years. Earlier application is permitted only for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Application of this ASU is not expected to have a material impact on our consolidated financial statements.

ASU 2016-13, Credit Losses - CECL – Current Expected Credit Losses Methodology

The Financial Accounting Standards Board (FASB) issued a new expected credit loss accounting standard in June 2016. The new accounting standard introduces the current expected credit losses methodology (CECL) for estimating allowances for credit losses. The guidance requires that for most financial assets, losses be based on an expected loss approach which includes estimates of losses over the life of exposures that considers historical, current and forecasted information. Expanded disclosures related to the methods used to estimate the losses as well as a specific disaggregation of balances for financial assets are also required. The standard is effective for SEC filers in fiscal years and interim periods beginning after December 15, 2019. For public business entities that are not SEC filers, the standard takes effect in fiscal years and interim periods beginning after December 15, 2020. For an entity that is not a public business entity, it takes effect in fiscal years beginning after December 15, 2020.

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 Accounting Standards Codification 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 the periods ended September 30, 2019 or in 2018.

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 & 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 impaired 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, 2019, we recorded a lease impairment of $40,223 on various lease and land costs that were no longer viable. During the nine months ended September 30, 2018, 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, 2019 and December 31, 2018, Royale Energy had Deferred Drilling Obligations of $6,077,583 and $6,213,283, 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.

NOTE 3 – LOSS PER SHARE

Basic and diluted loss per share are calculated as follows:

For the nine months ended September 30, 2019 and 2018, Royale Energy had dilutive securities of 23,967,039 and 24,024,647, respectively.  These securities were not included in the dilutive loss per share due to their antidilutive nature.

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.  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 2019.

A reconciliation of Royale Energy’s provision for income taxes and the amount computed by applying the statutory income tax rates at September 30, 2019 and 2018, respectively, to pretax income is as follows: 

NOTE 5 – IMPLEMENTATION OF ASC 842 – LEASE ACCOUNTING

In February 2016, the FASB established Topic 842, Leases, by issuing Accounting Standards Update (ASU) No. 2016-02, which requires lessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. Topic 842 was subsequently amended by ASU No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842; ASU No. 2018-10, Codification Improvements to Topic 842, Leases; and ASU No. 2018-11, Targeted Improvements. The new standard establishes a right-of-use model (“ROU”) that requires a lessee to recognize a ROU asset and lease liability on the balance sheet for all leases with a term longer than 12 months. As a public company, the new standard is effective for us on January 1, 2019. A modified retrospective transition approach is the implementation methodology we have selected; applying the new standard to all leases existing at the date of initial application, in this case January 1, 2019. Consequently, financial information has not been updated and the disclosures required under the new standard have not been provided for dates and periods before January 1, 2019.

The new standard provides a number of optional practical expedients for the transition. We have elected the ‘package of practical expedients’, which permits us not to reassess under the new standard our prior conclusions about lease identification, lease classification and initial direct costs. We do not expect to elect the use-of hindsight or the practical expedient pertaining to land easements; the latter not being applicable to us. We have elected all of the new standard’s available transition practical expedients.

The standard did not materially impact our consolidated results of operations, earnings per share, and had no impact on cash flows. The most significant effects relate to: (1) the recognition of new ROU assets in long-term assets on the balance sheet; (2) lease liabilities, both short-term and long-term, on our balance sheet; and, (3) providing significant new disclosures about our leasing activities. We do not expect a significant change in our leasing activities as a result of the adoption of this new pronouncement

The interest rate used in each lease analysis was the risk-free rate for the period of the lease plus 400 basis points as the Company’s risk premium.

The Company has two office leases. One at 1870 Cordell Court, El Cajon, California, the location of its corporate offices and one at 104 W. Anapamu, Santa Barbara, California, the location of the Company’s CEO and engineering team. The corporate office lease was entered into on August 31, 2016 and expires on October 31, 2021 with initial monthly payments of $6,148 with escalations. The lease in Santa Barbara was initiated in December of 2006 and, through several extensions and renewals, will expire in March of 2022. The initial base rental payment was $5,086 with various adjustments to market and planned escalations. These two leases were initially recorded as operating leases at January 1, 2019 as listed below.

In July 2019, we entered into a 60 month agreement with MRC for the leasing of two Xerox machines with monthly payments of $1,049. This lease was initially recorded as a financing lease on July 31, 2019 as listed below:

The new standard provides practical expedients for an entity’s ongoing accounting. 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 also currently expect to elect 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.

NOTE 6 – ISSUANCE OF COMMON STOCK

During the nine months ended September 30, 2019, in lieu of cash payments for salaries and fees, Royale issued 1,881,491 shares of its Common stock valued at approximately $455,146 to various officers and board members.

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

The merger between Royale Energy and Matrix Oil Management was completed during the first quarter of 2018.  For the period in 2018, the consolidated amounts represented here are for the nine-month period for Royale Energy, Inc. and the seven-month period from March through September for Matrix Oil Management and its subsidiaries. For a further discussion regarding the 2018 merger and subsequent sale of oil and gas assets to RMX Resources, LLC, please refer to our 2018 Form 10-K.

For the nine months ended September 30, 2019, we had a net loss of $800,566, when compared to the net loss of $19,701,406 during the nine months ended September 30, 2018.  This difference was primarily due to the loss in the second quarter 2018 on the transfer of assets of $16,353,600 which was recorded upon the transfer of oil and gas properties to RMX and surface rights in exchange for cash and a 20 percent working interest in RMX under the Contribution Agreement. Under the Contribution Agreement, we also issued warrants to acquire 4,000,000 shares of Royale common stock and recorded a loss of $1,439,990.  During the third quarter of 2019, we had a net income of $2,304,108, mainly due to a third quarter gain of $1,787,860 on Turnkey drilling. In the third quarter of 2018, we had a net income of $1,072,910 also mainly due to a $2,194,059 gain on Turnkey drilling during the period in 2018. Total revenues for the first nine months of 2019 and 2018 were $2,030,792 and $2,391,224, respectively.  

During the first nine months of 2019, revenues from oil and gas production increased $153,863 or 12.2% to $1,419,821 from the 2018 nine-month revenues of $1,265,958.  This increase was mainly due to higher production volumes during the period in 2019, due to our 2019 drilling and fourth quarter 2018 Jameson North field acquisition.  The net sales volume of oil and condensate for the nine months ended September 30, 2019, was approximately 14,851 barrels with an average price of $56.03 per barrel, versus 15,358 barrels with an average price of $65.28 per barrel for the first nine months of 2018.  This represents a decrease in net sales volume of 507 barrels. The net sales volume of natural gas for the nine months ended September 30, 2019, was approximately 198,439 Mcf with an average price of $2.96 per Mcf, versus 95,970 Mcf with an average price of $2.54 per Mcf for the same period in 2018.  This represents an increase in net sales volume of 102,469 Mcf or 106.8%.  The increase in natural gas production volume was due to wells that were drilled and put into production during the period in 2019 and to several of our operated wells being offline during the period in 2018 due to new pipeline equipment requirements by Pacific Gas & Electric. For the quarter ended September 30, 2019, revenues from oil and gas production increased $297,600 or 95.1% to $610,427 from the 2018 third quarter revenues of $312,827.  This increase was also to the wells which came online during the period in 2019 and to several of our operated wells being offline during the period in 2018.  The net sales volume of oil and condensate for the quarter ended September 30, 2019, was approximately 8,222 barrels with an average price of $57.31 per barrel, versus 3,143 barrels with an average price of $67.17 per barrel for the third quarter of 2018.  This represents an increase in net sales volume of 5,079 barrels for the quarter in 2019. The net sales volume of natural gas for the quarter ended September 30, 2019, was approximately 62,553 Mcf with an average price of $2.23 per Mcf, versus 33,585 Mcf with an average price of $2.78 per Mcf for the third quarter of 2018.  This represents an increase in net sales volume of 28,968 Mcf or 86.3% for the quarter in 2019.

Oil and natural gas lease operating expenses increased by $32,208 or 2.7%, to $1,237,785 for the nine months ended September 30, 2019, from $1,205,577 for the same period in 2018.  For the third quarter in 2019, lease operating expenses increased $78,868 or 18.0% from the same quarter in 2018. These were both higher due to the increase in the number of wells operated by the Company during the period in 2019, related to our 2019 drilling and the fourth quarter 2018 Jameson North acquisition.  

The aggregate of supervisory fees and other income was $610,971 for nine months ended September 30, 2019, a decrease of $514,295 from $1,125,266 during the same period in 2018.  During the third quarter 2019, supervisory fees and other income decreased $535,905 or 95.6% when compared to the quarter in 2018, These decreases were due to the cancellation of the service agreement with RMX Resources as of March 31, 2019.

Depreciation, depletion and amortization expense decreased to $217,327 from $344,532, a decrease of $127,205 or 36.9% for the nine months ended September 30, 2019, as compared to the same period in 2018. During the third quarter 2019, depreciation, depletion and amortization expenses increased $23,884 or 34.8%. The depletion rate is calculated using production as a percentage of reserves.  The nine-month decrease in depreciation expense was due to the decrease in the number of wells and related equipment, as a result of the transfer of properties during the sale and final settlement with RMX Resources, LLC.

General and administrative expenses decreased by $581,970 or 26.0% from $2,242,891 for the nine months ended September 30, 2018, to $1,660,921 for the same period in 2019, due to reductions in employee related costs and outside consulting services, in an effort for the Company to reduce costs and lower fees, and was also due to higher costs in 2018, related to a loan Matrix had at the time of the merger.  For the third quarter 2019, general and administrative expenses decreased $417,242 or 53.8% when compared to the same period in 2018, also due to decreases in employee related costs and outside consulting services. Marketing expense for the nine months ended September 30, 2019, increased $35,097, or 12.3%, to $319,906, compared to $284,809 for the same period in 2018.  For the third quarter 2019, marketing expenses decreased $1,750 or 1.1% when compared to the third quarter in 2018. 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 decreased to $502,995 for the nine month period in 2019, compared to $1,267,896 for the same period in 2018, a $764,901 or 60.3% decrease.  For the third quarter 2019, legal and accounting expenses decreased $76,403 or 40.1%, when compared to the third quarter in 2018. These decreases were primarily due to legal fees related to the Matrix merger during the periods in 2018.

During the first quarter in 2019 we recorded a loss on the sale of assets of $1,237,126 related a settlement agreement with RMX Resources, LLC, see Note 1, Settlement Agreement and Well Participation Agreement with RMX. During the nine-month period in 2019, we recorded geological and geophysical expense of $263,277 related mainly to the acquisition of a seismic survey of a Northern California field. During the nine months ended September 30, 2019 and 2018, we recorded losses of $124,716 and $1,026,404, respectively on investment in joint venture as our 20% share of RMX Resources, LLC’s period net losses of $623,579 and $5,132,019. During the nine months ended September 30, 2019, we recorded a gain of $897,708, mainly on the reconciliation and settlement of royalties payable.  We periodically review our proved properties for impairment on a field-by-field basis and charge impairments of value to the expense. During the nine months ended September 30, 2019, we recorded a lease impairment of $40,223 on various lease and land costs that were no longer viable. During the nine months ended September 30, 2018, we recorded gains of $163,681 on the settlement of accounts payable. During the period ended September 30, 2018, we recorded a $105,130 loss on derivative instruments, reflecting the period end market-to market changes in the fair value positions, related to Matrix operations prior to the conclusion of the merger. During the nine months ended September 30, 2018, we recorded a write down of $9,790 on certain well equipment that was no longer useable.

During the first nine months of 2019, we disposed of $9,382,519 of drilling obligations upon completing the drilling of eight wells, six natural gas wells in Northern California and two oil wells in Southern California, while incurring expenses of $7,484,260, resulting in a gain of $1,898,259.  At September 30, 2019, Royale Energy had a remaining Deferred Drilling Obligation of $6,077,583. During the same period in 2018, we disposed of $4,797,720 of drilling obligations upon completing the drilling of three natural gas wells in Northern California, while incurring expenses of $2,603,262, resulting in a gain of $2,194,459.  At September 30, 2018, Royale Energy had a Deferred Drilling Obligation of $5,406,678.   

Interest expense decreased to $17,186 for the nine months ended September 30, 2019, from $170,151 for the same period in 2018, a $152,965 decrease.  This decrease resulted from interest accrued during the period in 2018 on the term loan agreement originated by Matrix.  Further details concerning this agreement can be found in Capital Resources and Liquidity, below.  

Capital Resources and Liquidity

At September 30, 2019, Royale Energy had current assets totaling $9,181,971 and current liabilities totaling $14,844,417, a $5,662,446 working capital deficit.  We had $724,994 in cash and $5,622,772 in restricted cash at September 30, 2019, compared to $1,853,742 in cash and $4,501,300 in restricted cash at December 31, 2018.

At September 30, 2019, our other receivables, which consist of joint interest billing receivables from direct working interest investors and industry partners, totaled $1,218,527, compared to $1,411,144 at December 31, 2018, a $192,617 decrease.  This decrease was mainly due to receipts from RMX Resources for contracted services.  At September 30, 2019, revenue receivable was $910,663, an increase of $593,689, compared to $316,974 at December 31, 2018, due to higher oil and gas production volumes on wells drilled during the period in 2019.  At September 30, 2019, our accounts payable and accrued expenses totaled $6,597,640, an increase of $1,702,107 from the accounts payable at December 31, 2018 of $4,895,533, which was related to increased drilling activities during the period in 2019. 

The Company has had recurring operating and net losses and cash used in operations and the consolidated financial statements reflect a working capital deficiency of $5,662,446 and an accumulated deficit of $73,652,310. 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 & 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.

Matrix Oil Management Corp entered into a term loan agreement with Arena Limited SPV, LLC (Term Loan) for approximately $12.4 million, in conjunction with a Purchase and Sale Agreement on June 15, 2016. The original maturity date of the Term Loan was June 15, 2018, it was secured by the assets of Matrix, and contained financial covenants commencing June 30, 2016 and thereafter, as defined in the term loan agreement. The Term Loan contained preferential payment requirements in advance of the amounts outstanding under the subordinated notes payable to partners, as defined in the term loan agreement.  The Term Loan Agreement called for interest at the rate of nine percent (9%) plus the adjusted LIBOR Rate computed on a daily basis.  The loan balance as of March 31, 2018 was $11,140,749.  The Company recognized $164,401 in interest expense for the period ended March 31, 2018.  This loan agreement was paid in full in April 2018.

Operating Activities.  Net cash used by operating activities totaled $630,090 and $1,451,832 for the nine months ended September 30, 2019 and 2018, respectively.  This decrease in cash used was mainly due to lower receivables due from affiliates during the period in 2018 related to the sale of oil and gas assets in the formation of RMX Resources, LLC.

Investing Activities.  Net cash provided by investing activities totaled $1,240,515 and $6,033,768 for the nine months ended September 30, 2019 and 2018, respectively. During the period in 2019, we received approximately $9.3 million in direct working interest investor turnkey drilling investments while our drilling expenditures were approximately $7.5 million in the drilling of six Northern California natural gas wells and two Southern California oil wells. During the 2018 period, the cash provided was due to approximately $4.3 million received in the merger and for the oil and gas asset sale and contribution in the formation of RMX Resources, LLC. In the 2018 period, we also received $4.3 million in direct working interest investor turnkey drilling investments while our drilling expenditures were approximately $2.6 million in the drilling of three Northern California natural gas wells.

Financing Activities.  Net cash used by financing activities totaled $617,701 and $2,174,920 for the nine months ended September 30, 2019, respectively. During the period in 2019, a financing agreement for a seismic survey was recognized when the terms were finalized, on which there were principal payments of approximately $131,000.  Additionally, in 2019, there were principal payments of approximately $391,000 on our note with Forza Operating and payments of approximately $95,000 on our leasing obligations. During the period in 2018, we paid a $1.9 million settlement payment for the cash advances on pending transactions. During the period in 2018, we also paid approximately $275,000 for principal and fee payments on the Matrix originated term loan agreement.

Item 3.      Quantitative and Qualitative Disclosures About Market Risk

Our major market risk exposure relates to pricing of oil and gas production.  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 we expect that volatility to continue.  Monthly average natural gas prices ranged from a low of $2.14 per Mcf to a high of $5.87 per Mcf for the first nine months of 2019. 

Item 4.      Controls and Procedures

As of September 30, 2019, 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 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.

The CFO and CEO have monitored the prior conditions of weakness listed below and concluded that they have been remediated as described.

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, 2019, 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 weaknesses 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, 2019, 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.