Royale Energy, Inc. - Quarter Report: 2019 March (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 May 15, 2019, a total of 50,742,248 shares of registrant’s common stock were outstanding.

TABLE OF CONTENTS

PART I.     FINANCIAL INFORMATION

Item 1.     Financial Statements

ROYALE ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

See notes to unaudited consolidated financial statements.

ROYALE ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

 See notes to unaudited consolidated financial statements.

ROYALE ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

FOR THE THREE MONTHS ENDED MARCH 31, 2019 AND 2018

See notes to unaudited consolidated financial statements.

ROYALE ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

FOR THE THREE MONTHS ENDED MARCH 31,

See notes to unaudited consolidated financial statements.

ROYALE ENERGY, INC.

Consolidated Statements of Stockholders' Equity (Deficit)

(Unaudited)

See notes to unaudited consolidated financial statements.

ROYALE ENERGY, INC.

NOTES TO UNAUDITED 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 three-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.

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 (“RMX”) intent to terminate the 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 as which point all services under the Master Service Agreement (“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 the three months ended March 31, 2019.

Liquidity and Going Concern

The primary sources of liquidity have historically been issuances of common stock and operations. The Company’s consolidated financial statements reflect an accumulated deficit of $75,104,161, a working capital deficiency of $6,793,013 and a stockholders’ deficit of $893,975. These factors raise substantial doubt about our ability to continue as a going concern, however; we anticipate that our primary sources of liquidity will be from the sale of oil and natural gas property, participation interest and issuance of debt and/or equity. Additionally, Management plans increase revenue and reduce overhead and LOE costs, as a result of increased production in new wells drilled.

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. 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.

Revenue Recognition

On January 1, 2018, we adopted the new ASC Topic 606, Revenue from Contracts with Customers and all the related amendments ("new revenue standard") using the modified retrospective method.

We evaluated the effect of transition by applying the provisions of the new revenue standard to contracts with remaining obligations as of January 1, 2018. No cumulative adjustment to retained earnings was necessary as a result of adopting this standard.

Results for reporting periods beginning after January 1, 2018 are presented under the new revenue standard, while prior period amounts are not adjusted and continue to be reported in accordance with our historic accounting policies.

We concluded that the adoption of the new revenue standard did not result in any changes to our consolidated balance sheet or statement of cash flow.

The majority of our 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.

In limited cases, we may also collect advance payments from customers as stipulated in our agreements; payments in excess of recognized revenue are recorded as contract liabilities on our consolidated balance sheet.

Under our hydrocarbon sales agreements, the entire consideration amount is variable either due to pricing and/or volumes. We recognize revenue in the amount of variable consideration allocated to distinct units of hydrocarbons transferred to a customer. Such allocation reflects the amount of total consideration we expect to collect for completed deliveries of hydrocarbons and the terms of variable payment relate specifically to our efforts to satisfy the performance obligations under these contracts. Our performance obligations under our hydrocarbon sales agreements are to deliver either the entire production from the dedicated wells or specified contractual volumes of hydrocarbons.

We often serve as the operator for jointly owned oil and gas properties. As part of this role, we perform activities to explore, develop and produce oil and gas properties in accordance with the joint operating arrangement and collective decisions of the joint parties. Other working interest owners reimburse us for costs incurred based on our agreements. We determined that these activities are not performed as part of customer relationships, in accordance with the new revenue standard, and such reimbursements will continue to not be recorded as revenues within the scope of the new revenue standard after the first quarter of 2018.  Prior to this, such cost reimbursements were included in revenue.

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, 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 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

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 (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 December 31, 2018 we had Deferred Drilling Obligations of $6,213,283, during the first three months of 2019 we disposed of $2,627,520 of drilling obligations upon completing the drilling of two natural gas wells in Northern California.

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. Payment is due on the thirteenth day following the end of the month following the performance of the services. Although payment is not necessarily received in accordance with the contract terms, it is eventually received. During the first quarter of 2019, we recognized $540,000 or 55.5% 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 as called for under ASU 2016-15 and later codified as ASC 230-10-50-8 (Statement of Cash Flows).

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 March 31, 2019 and December 31, 2018, the Company established 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 receive payment approximately 45 to 60 days later.

Fair Value Measurements

According to Fair Value Measurements and Disclosures Topic of the 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.

At March 31, 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.

Note Payable

The Company entered into a one year installment plan with Seismic Exchange on December 21, 2018 for the acquisition of seismic data. The terms called for four payments with the first in the amount of $25,000 due on December 31, 2018 the remaining payments of $56,500 due quarterly with the final payment due on December 31, 2019. This was treated as an imputed note with an interest rate of 6.62% as called for under ASC 835-30.

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.

Accounting Standards

Recently Adopted

ASU 2017-09, Revenue from Contracts with Customers (ASC 606)  

On January 1, 2018, we adopted the new ASC Topic 606, Revenue from Contracts with Customers and all the related amendments (“new revenue standard”) using the modified retrospective method. 

We evaluated the effect of transition by applying the provisions of the new revenue standard to contracts with remaining obligation as of January 1, 2018. No cumulative adjustment to retained earnings was necessary as a result of adopting this standard. 

Results for reporting periods beginning after January 1, 2018 are presented under the new revenue standard.

We concluded that the adoption of the new revenue standard did not result in any changes to our consolidated balance sheet or statement of cash flow.

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 above using the modified retrospective method and applied to all leases that existed as of that date. It does not apply to leases 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.

ASU 2017-01: Business Combinations–Clarifying the Definition of a Business

In January 2017, the FASB issued a new ASU that changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities constitutes a business. The guidance requires us to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities would not represent a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described in the new revenue guidance. This standard was effective for us in the first quarter of 2018, and was applied prospectively. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

 ASU 2016-18: Statement of Cash Flow-Restricted Cash (ASC-230-10-50-8)

In November 2016, the FASB issued a new ASU that requires entities to show the changes in the total of cash, cash equivalents and restricted cash in the statement of cash flows. As a result, we no longer present transfers between cash and cash equivalents and restricted cash in the statement of cash flows. When cash, cash equivalents, and restricted cash are presented in more than one-line item on the balance sheet, the standard requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. This reconciliation can be presented either on the face of the statement of cash flows or in the notes to the financial statements.

Royale has adopted this new ASU 2016-18 with the reporting of year-end 2018 financials. This standard requires Royale to show cash received specifically for drilling operations separately on the balance sheet as Restricted Cash. See note above.

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

ASU 2016-13, Credit Losses – Measurement of Credit Losses on Financial Instruments 

In June 2016, the FASB issued an ASU related to the accounting for credit losses on certain financial instruments. 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 change is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Application of this ASU did not have a material impact on our consolidated financial statements.

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 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, we do not expect adoption of this ASU to have a material impact on our consolidated financial statements.

ASU 2018-19, Codification Improvements to Topic 326, financial Instruments – Credit Losses

This was issued in November of 2018 and is effective upon adoption of the amendments in ASU 2016-13.

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 – Internet 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.

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 March 31, 2019 or 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, including planned major maintenance, are expensed as incurred.  Major renewals and improvements are capitalized and the assets replaced are retired.

The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use.  Interest costs, to the extent they are incurred to finance expenditures during the construction phase, are included in property, plant and equipment and are depreciated over the service life of the related assets.

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 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. Cash flows used in impairment evaluations are developed using annually updated evaluation assumptions for crude oil commodity prices.  Annual volumes are based on field production profiles, which are also updated annually. Prices for natural gas and other products are based on assumptions developed annually for evaluation purposes.

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 three months ended March 31, 2018 and 2019, 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 March 31, 2019 and December 31, 2018, Royale Energy had Deferred Drilling Obligations of $5,782,285 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 contact and return the remaining funds to the participant.  Included in cash and cash equivalents 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:

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 March 31, 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 will not be updated and the disclosures required under the new standard will not be 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.

This standard causes a material impact to our financial statements. 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 standard did not materially impact our consolidated results of operations, earnings per share, and had no impact on cash flows.

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. This compares fairly closely with the prime rate for the same period.

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.

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 is 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 lease obligations for through December 31, 2030.

NOTE 6 – SUBSEQUENT EVENTS 

Issuance of Common Stock

During the second quarter of 2019, through May 15, 2019, in lieu of cash payments for salaries and fees, Royale issued 330,895 shares of its Common stock valued at approximately $93,324 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.

Going Concern

As specified in ASC 205-40-50-2, conditions or events that raise probable substantial doubt about an entity’s ability to continue as a going concern relate to an entity’s ability to meet its obligations as they become due, which assert as being 70-75 percent or more likely the entity cannot meet its obligations as they become due.

At March 31, 2019, the Company has an accumulated deficit of $75,104,161, a working capital deficiency (current assets less current liabilities) of $6,793,013 and a stockholders’ equity deficit of $893,975. As a result, our financial statements include a “going concern qualification” reflecting substantial doubt as to our ability to continue as a going concern.

We are exploring commitments to provide additional financing, but there is no guarantee that we will be able to secure additional financing on acceptable terms, or at all, if needed to fully fund our 2019 drilling budget and to support future operations. In addition, the Company is actively in the market selling various non-strategic assets. The Company has undertaken certain steps to reduce General and Administrative expenses and one member of the senior management team is being compensated in stock rather than cash.

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 three month period for Royale Energy, Inc. and the month of March 2018 for Matrix Oil Management and its subsidiaries.

For the three months ended March 31, 2019, we had a net loss of $2,637,183, a $1,003,470 or 61.4% difference when compared to the net loss of $1,633,713 during the first quarter of 2018.  This difference was due to a loss on the sale of assets of $1,237,126 related the settlement agreement, (see note Settlement Agreement and Well Participation Agreement with RMX). Total revenues for the first quarter in 2019 were $973,276, an increase of $250,104 or 34.6% from the total revenues of $723,172 during the same period in 2018. 

In the first quarter of 2019, revenues from oil and gas production decreased $268,033 or 39.9% to $403,169 from the 2018 first quarter revenues of $671,202.  This decrease was primarily due to lower oil production volumes during the quarter in 2019 when compared to the first quarter of 2018, the time of the merger, due to the sale of oil and gas properties in the subsequent month.  The net sales volume of oil and condensate for the quarter ended March 31, 2019, was approximately 3,045 barrels with an average price of $48.02 per barrel, versus 9,309 barrels with an average price of $62.75 per barrel for the first quarter of 2018.  The net sales volume of natural gas for the quarter ended March 31, 2019, was approximately 62,467 Mcf with an average price of $4.11 per Mcf, versus 33,164 Mcf with an average price of $2.57 per Mcf for the first quarter of 2018.  This represents an increase in net sales volume of 29,303 Mcf or 88.4%.  The increase in natural gas production volume was due to wells drilled in 2018 coming online and a number of our operated wells coming back online after being offline at the beginning of 2018 due to new pipeline equipment requirements by Pacific Gas & Electric. 

Oil and natural gas lease operating expenses increased by $87,962 or 32.9%, to $355,610 for the quarter ended March 31, 2019, from $267,648 for the same quarter in 2018.  This was higher due to the increase in the number of well interests owned by the Company, both operated and non-operated, during the period in 2019, due to the merger, the December 2018 Jameson North acquisition and the 2018 drilling efforts.  

The aggregate of supervisory fees and other income was $570,107 for quarter ended March 31, 2019, an increase of $518,137 from $51,970 during the same period in 2018.  This increase was mainly due to the receipt of service agreement fees through an arrangement with RMX Resources, LLC, which began during the second quarter of 2018.

Depreciation, depletion and amortization expense decreased to $52,083 from $173,716, a decrease of $121,633 or 70.0% for the quarter ended March 31, 2019, as compared to the same period in 2018. The depletion rate is calculated using production as a percentage of reserves.  This decrease in depreciation expense was due to the higher reserves at the end of the year in 2018 resulting in a lower depreciation rate. Also, the merger concluded during the first quarter of 2018, a majority of the properties were sold in the subsequent month to RMX Resources, LLC.

General and administrative expenses decreased by $161,194 or 18.7% from $859,357 for the quarter ended March 31, 2018, to $698,163 for the same period in 2019, due mainly to the offset of operations and drilling overhead of $173,738, which began offsetting general and administrative expenses during the second quarter of 2018.  Marketing expense for the quarter ended March 31, 2019, decreased $1,352, or 2.0%, to $67,131, compared to $68,483 for the same period 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 $277,772 for the period, compared to $712,722 for the same period in 2018, a $434,950 or 61.0% decrease.  This decrease was primarily due to legal fees related to the Matrix merger during the quarter in 2018.

During the quarter in 2019, we recorded geological and geophysical expense of $262,586 related to the acquisition of a seismic survey of a Northern California field. During the period in 2019, we also recorded a loss on investment in joint venture of $741,795 as our 20% share of RMX Resources, LLC’s period net loss of $3,708,976. During the period in 2019, we recorded a gain of $62,972 on the settlement of accounts payable.  During the quarter ended March 31, 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. 

At March 31, 2019, Royale Energy had a Deferred Drilling Obligation of $5,782,285.  During the first quarter in 2019, we disposed of $2,627,520 of drilling obligations upon completing the drilling of two natural gas wells in Northern California, while incurring expenses of $2,601,051, resulting in a gain of $26,469.  At March 31, 2018, Royale Energy had a Deferred Drilling Obligation of $7,237,731.  During the first quarter of 2018, we were unable to drill new wells due to wet weather conditions in our Northern California fields.  

Interest expense decreased to $5,707 for the quarter ended March 31, 2019, from $169,829 for the same period in 2018, a $164,122 decrease.  This decrease resulted from interest accrued during the quarter 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 March 31, 2019, Royale Energy had current assets totaling $9,235,725 and current liabilities totaling $16,028,738 a $6,793,013 working capital deficit.  We had $2,617,172 in cash and $2,872,505 in restricted cash at March 31, 2019, compared to $1,853,742 in cash and $4,501,300 in restricted cash at December 31, 2018. Prepaid expenses at March 31, 2019, included cash paid to RMX for the drilling of two wells in the Sansinena field, totaled $2,076,806 compared to $174,852 in the same period of 2018.

Ordinarily, we fund our operations and cash needs from our available credit and cash flows generated from operations.  There is doubt as to the ability to meet liquidity demands through cash flow or ongoing operations.  In that event, the Company will seek alternative capital sources through the sale of oil and natural gas property, participation interest and issuance of debt and/or equity.

At March 31, 2019, our other receivables, which consist of joint interest billing receivables from direct working interest investors and industry partners, totaled $1,142,946, compared to $1,411,144 at December 31, 2018, a $268,198 decrease.  This decrease was mainly due to receipts from RMX Resources for contracted services.  At March 31, 2019, revenue receivable was $526,296, an increase of $209,322, compared to $316,974 at December 31, 2018, due to higher oil and gas production volumes on wells drilled at the end of the year in 2018.  At March 31, 2019, our accounts payable and accrued expenses totaled $6,669,229, an increase of $1,773,696 from the accounts payable at December 31, 2018 of $4,895,533, which was related to higher accrued drilling costs due to the drilling of two wells at the end of the quarter in 2019 and higher revenues payables due to direct working interest investors. 

In July 2016, we received a cash investment of $1,580,000 from two investors to purchase convertible promissory notes with principal amounts of $1,280,000 and $300,000, with a conversion price of $0.40 per share, with warrants to purchase one share of common stock for every three shares of common stock issuable upon conversion of the notes.  The notes originally matured on August 2, 2017, one year from the date of issuance, and carried a 10% interest rate, with a default rate of 25%.  Shortly before completion of the Merger, the $300,000 note was converted into 750,000 shares of Royale common stock, and Royale agreed to a cash settlement with the holder of the $1,280,000 note for $1,900,000.

In conjunction with the Purchase and Sale Agreement on June 15, 2016, Matrix Oil Management Corp entered into a term loan agreement with Arena Limited SPV, LLC (Term Loan) for approximately $12.4 million. 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 $164,017 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 $595,876 and $27,447 for the three month periods ended March 31, 2019 and 2018, respectively.  This increase in cash used was mainly due to the prepayments of drilling costs due to the drilling of two wells during the quarter in 2019.

Investing Activities.  During the three month period ended March 31, 2019, net cash used in investing activities totaled $322,809. During the same period in 2018, net cash provided by investing activities was $1,869,605.  The difference in cash during the periods was mainly due to the drilling and completion of two Northern California natural gas wells during the quarter in 2019 and $548,805 in cash received from the merger during the quarter in 2018.

Financing Activities.  During the three month period ended March 31, 2019, net cash provided by financing activities totaled $53,320.  Net cash used by financing activities totaled $274,914 in the first quarter of 2018. During the period in 2019, a financing agreement for a seismic survey was recognized when the terms were finalized.  Additionally, in 2019, there were principal payments on our note with Forza Operating and in 2018 there were 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 $3.02 per Mcf to a high of $5.86 per Mcf for the first three months of 2019. 

Item 4.      Controls and Procedures

As of March 31, 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. 

Material Weaknesses

As a result of the review by the CFO and CEO, a number of weaknesses were 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 three months ended March 31, 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.

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.