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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549   

 

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FORM 10-Q 

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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D)

OF THE SECURITIES EXCHANGE ACT OF 1934

 

 

(Exact name of registrant as specified in its charter)

 

1870 Cordell Court, Suite 210

(Address of principal executive offices) (Zip Code)

 

(Registrant’s telephone number, including area code)

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

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).              Yes ☒     No ☐

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer  (as defined in Rule 12b-2 of the Exchange Act).  Check one:

 

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

 

At November 7, 2016, a total of 21,723,389 shares of registrant’s common stock were outstanding.

 

TABLE OF CONTENTS

 

 

 

PART I.   FINANCIAL INFORMATION

Item 1.  Financial Statements

 

ROYALE ENERGY, INC.

BALANCE SHEETS

 

 

See notes to unaudited financial statements.

 

ROYALE ENERGY, INC.

BALANCE SHEETS

 

 

See notes to unaudited financial statements.

 

ROYALE ENERGY, INC.

STATEMENTS OF OPERATIONS

FOR THE PERIODS ENDED SEPTEMBER 30, 2016 AND 2015

 

See notes to unaudited financial statements.

 

ROYALE ENERGY, INC.

STATEMENTS OF CASH FLOWS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2016 AND 2015

 

		2016				2015
		(Unaudited)				(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss		$	(1,718,917	)		$	(2,059,959	)
Adjustments to Reconcile Net Loss to Net  Cash Used in Operating Activities:
Depreciation, Depletion and Amortization			245,013				209,238
Lease Impairment			46,303				96,436
Gain on Sale of Assets			(198,975	)			(10,070	)
(Gain) Loss on Turnkey Drilling Programs			(218,971	)			(903,677	)
Gain on Settlement of Accounts Payable			(345,683	)			-
Well Equipment Write Down			19,151				19,000
Stock-Based Compensation			615,365				86,878
(Increase) Decrease in:
Other & Revenue Receivables			(264,028	)			29,294
Prepaid Expenses and Other Assets			(445,692	)			(20,700	)
Increase (Decrease) in:
Accounts Payable and Accrued Expenses			(641,816	)			(885,795	)
Net Cash Used In Operating Activities			(2,908,250	)			(3,439,355	)
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for Oil and Gas Properties and Other Capital Expenditures			(1,053,654	)			(2,193,233	)
Proceeds from Turnkey Drilling Programs			1,997,499				3,372,975
Proceeds from Sale of Assets			935,927				506,537
Net Cash Provided By Investing Activities			1,879,772				1,686,279
CASH FLOWS FROM FINANCING ACTIVITIES
Cash Advances From Investors			1,950,000				-
Proceeds from Issuance of Common Stock			790,884				419,114
Principal Payments on Long-Term Debt			(1,446,853	)			(21,558	)
Net Cash Provided By Financing Activities			1,294,031				397,556
Net Increase (Decrease) in Cash and Cash Equivalents			265,553				(1,355,520	)
Cash at Beginning of Period			3,763,819				3,061,841
Cash at End of Period		$	4,029,372			$	1,706,321
SUPPLEMENTAL DISCLOSURES OF CASH FLOWS INFORMATION:
Cash Paid for Interest		$	47,913			$	64,495
Cash Paid for Taxes		$	2,100			$	3,000

 

See notes to unaudited financial statements.

ROYALE ENERGY, INC.

NOTES TO UNAUDITED FINANCIAL STATEMENTS

NOTE 1 – In the opinion of management, the accompanying unaudited financial statements include all adjustments, consisting only of normally recurring 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.

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.

 

 

The primary sources of liquidity have historically been issuances of common stock and operations. Until we become cash flow positive, we anticipate that our primary sources of liquidity will be from the issuance of debt and/or equity, and the sale of oil and natural gas property participation interest. Assuming there are no further changes in expected sales and expense trends subsequent to November 14, 2016, the Company believes that its cash position together with anticipated financing activities, which include the sale of our office building and land, will be sufficient to continue operations for the foreseeable future. 

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.

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.

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 analysis 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, 2016 and 2015, impairment losses of $46,303 and $96,436, respectively, were recorded on various capitalized lease and land costs that were no longer viable.

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 due to the permitting process or drilling rig availability.  At September 30, 2016 and December 31, 2015, Royale Energy had Deferred Drilling Obligations of $7,261,398 and $8,415,528, 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 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.

 

Cash includes cash on hand and on deposit.

Our other receivables consists of 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, 2016 and December 31, 2015, the Company had an allowance for uncollectable accounts of $2,270,773 and $2,270,773, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue.

Our revenue receivables consists 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.

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

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 September 30, 2016 and December 31, 2015, 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.

 

Certain items in the financial statements have been reclassified to maintain consistency and comparability for all periods presented herein.

The Company has reviewed the updates issued by the Financial Accounting Standards Board (FASB) during the nine months ended September 30, 2016:

ASU 2016-01: Financial Instruments – Overall – Recognition and Measurement of Financial Assets and Financial Liabilities (Subtopic 825-10) In January 2016, FASB issued ASU 2016-01 which requires an entity to: (i) measure equity investments at fair value through net income, with certain exceptions; (ii) present in Other Comprehensive Income the changes in instrument-specific credit risk for financial liabilities measured using the fair value option; (iii) present financial assets and financial liabilities by measurement category and form of financial asset; (iv) calculate the fair value of financial instruments for disclosure purposes based on an exit price and; (v) assess a valuation allowance on deferred tax assets related to unrealized losses of AFS debt securities in combination with other deferred tax assets. The Update provides an election to subsequently measure certain nonmarketable equity investments at cost less any impairment and adjusted for certain observable price changes. The Update also requires a qualitative impairment assessment of such equity investments and amends certain fair value disclosure requirements. The new standard becomes effective for fiscal years beginning after December 15, 2017. Early adoption is only permitted for the provision related to instrument-specific credit risk and the fair value disclosure exemption provided to nonpublic entities.  The Company is currently evaluating the effects of adopting ASU 2016-01 on its consolidated financial statements but the adoption is not expected to have a significant impact on the Company’s consolidated financial statements. 

 

ASU No. 2016-02: Leases (Topic 842). In February 2016, FASB issued ASU 2016-02 which aims to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and requiring disclosure of key information about leasing agreements. Entities are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. The Company is currently evaluating the effects of adopting ASU 2016-02 on its consolidated financial statements but the adoption is not expected to have a significant impact on the Company’s financial statements. 

ASU 2016-09: Compensation—Stock Compensation (Topic 718): Improvements to Employee Share- Based Payment Accounting. In March 2016, FASB issued ASU 2016-09 which amends several aspects of the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Early adoption is permitted. If early adopted, an entity must adopt all of the amendments in the same period. The Company is currently evaluating the impact of the adoption of ASU 2016-09 on the Company’s financial statements. 

ASU 2016-15: Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.  In August 2016, FASB issued ASU 2016-15 which addresses several specific cash flow issues. ASU 2016-15 is effective for annual and interim periods beginning January 1, 2018, with early adoption permitted, and requires full retrospective application on adoption. The Company is currently evaluating the effects of adopting ASU 2016-15 on its financial statements but the adoption is not expected to have a significant impact on the Company’s financial statements.

NOTE 2 – LOSS PER SHARE

Basic and diluted loss per share are calculated as follows:

 

 

 

For the nine months ended September 30, 2016 and 2015, Royale Energy had dilutive securities of 23,331 and 23,331, respectively.  These securities were not included in the dilutive loss per share due to their antidilutive nature.

NOTE 3 – OIL AND GAS PROPERTIES, 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 in 2016 or 2015. 

 

NOTE 4 – STOCK COMPENSATION PLAN

 

During the October 10, 2014 Board of Directors meeting, directors and executive offices of Royale Energy were granted 20,000 options each, 140,000 total, to purchase common stock at an exercise price of $5.00 per share. These options were granted for a period of 3 years and will expire after December 31, 2017.  As of September 30, 2016, 100,000 options are currently exercisable and 40,000 options have expired.   There were no stock compensation costs related to this option grant recognized during the nine months ended September 30, 2016.  During the nine months ended September 30, 2015, Royale recognized compensation costs of $86,878 relating to this option grant.  

NOTE 5 – INCOME TAXES

 

Deferred tax assets and liabilities reflect the net tax effect of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and amounts used for income tax purposes.  Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.  At the end of 2015, management reviewed the reliability of the Company’s net deferred tax assets, and due to the Company’s continued cumulative losses in recent years, Royale and it management 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 2016.

A reconciliation of Royale Energy’s provision for income taxes and the amount computed by applying the statutory income tax rates at September 30, 2016 and 2015, respectively, to pretax income is as follows: 

 

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.

Merger Announcement

In July 2016, we entered into a letter of intent with Matrix Oil Management Corporation to merge Royale and Matrix in a combined stock and assumption of debt transaction.  In the proposed merger, Royale will issue one share of common stock for each share of common stock outstanding at the time of the execution of definitive documents, assume all of Matrix’s $12.5 million of secured term debt, and issue 2,000,000 shares of convertible preferred stock with a par redemption value of $10.00 per share. Assuming a $0.50 price per common share, the transaction is valued at approximately $41.5 million.

Royale and Matrix are presently conducting due diligence reviews for the merger transaction and negotiating the definitive agreements necessary to complete the proposed combination.  The merger and related transactions will require the approval of the shareholders of each company and registration of the Royale equity securities to be issued in the merger under the Securities Act of 1933 prior to completion of the transaction.  Northland Capital Markets has been retained to serve as financial advisor to Royale for the transaction.

Results of Operations

For the nine months ended September 30, 2016, we had a net loss of $1,718,917, a $341,042 or 16.6% improvement when compared to net loss of $2,059,959 during the nine months ended September 30, 2015.   This improvement was mainly due to the gains from the sale of the Company’s office building and accounts payable settlements during the period in 2016.  During the quarter ended September 30, 2016, we had a net loss of $619,200, compared to the net loss of $394 for the same quarter in 2015.  Total revenues for the first nine months of 2016 were $938,184, a decrease of $422,370 or 31% from the total revenues of $1,360,554 during the period in 2015.  The lower revenues were the result of decreases in both natural gas prices and production volumes during the period in 2016, when compared to 2015.

During the first nine months of 2016, revenues from oil and gas production decreased $415,279 or 50% to $416,193 from the 2015 nine month revenues of $831,472.  This decrease was due to lower natural gas production, due to the natural declines of our wells, and lower commodity prices.  The net sales volume of natural gas for the nine months ended September 30, 2016, was approximately 190,431 Mcf with an average price of $2.17 per Mcf, versus 288,531 Mcf with an average price of $2.82 per Mcf for the period in 2015.  This represents a decrease in net sales volume of 98,100 Mcf or 34%.  For the quarter ended September 30, 2016, revenues from oil and gas production decreased $88,926 or 34.9% to $166,253 from the 2015 third quarter revenues of $255,179.  This decrease was also due to lower natural gas commodity prices and decreased production.  The net sales volume of natural gas for the quarter ended September 30, 2016, was approximately 58,734 Mcf with an average price of $2.80 per Mcf, versus 86,054 Mcf with an average price of $2.88 per Mcf for the third quarter of 2015.  This represents a decrease in net sales volume of 27,320 Mcf or 31.8% for the quarter in 2016.

Oil and natural gas lease operating expenses decreased by $290,854 or 36.2%, to $512,695 for the nine months ended September 30, 2016, from $803,549 for the same period in 2015.  For the third quarter in 2016, lease operating expenses decreased $45,201 or 20.6% from the same period in 2015.  These decreases were mainly due to cost reduction measures especially in lower workover costs and operating costs for non-operated wells during the period in 2016.   For the nine months ended September 30, 2016, delay rental costs decreased by $49,565, as there were no delay rental costs paid during the period in 2016.

The aggregate of supervisory fees and other income was $521,991 for nine months ended September 30, 2016, a decrease of $7,091 or 1.3% from $529,082 during the nine months in 2015.  During the third quarter 2016, supervisory fees and other income decreased $33,985 or 18.2% when compared to the period in 2015.  These decreases were the result of lower operations overhead and pipeline fees during the period in 2016, due to lower production volumes.  

Depreciation, depletion and amortization expense increased to $245,013 from $209,238, an increase of $35,775 or 17.1% for the nine months ended September 30, 2016, as compared to the same period in 2015.  During the third quarter 2016, depreciation, depletion and amortization expenses increased $25,823 or 36.9%.   The depletion rate is calculated using production as a percentage of reserves.  These increases in depreciation expense were mainly due to a higher depletion rate as reserve volumes were lower during the period.

General and administrative expenses decreased by $519,980 or 21.7% from $2,397,434 for the nine months ended September 30, 2015, to $1,877,454, for the nine month period in 2016.  This decrease was primarily due to employee related cost reduction measures. For the third quarter 2016, general and administrative expenses increased $39,545 or 5.6% when compared to the same period in 2015.   Marketing expense for the nine months ended September 30, 2016, decreased $17,711, or 7.4%, to $222,897, compared to $240,608 for the same period in 2015.  For the third quarter 2016, marketing expenses increased $24,125 or 25.4% when compared to the third quarter in 2015.   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 $422,970 for the nine months ended September 30, 2016, compared to $453,935 for the same period in 2015, a $30,965 or 6.8% decrease. This decrease was mainly a result of lower tax preparation and audit fees paid during the period in 2016.  For the third quarter 2016, legal and accounting expenses increased $60,654 or 46.6%, when compared to the third quarter in 2015.  This increase was mainly due to legal and accounting expenses related to the proposed merger.  

We periodically review our proved properties for impairment on a field-by-field basis and charge impairments of value to the expense. During the periods ended September 30, 2016 and 2015, we recorded lease impairments of $46,303 and $96,436, respectively, on various lease and land costs that were no longer viable.  Also, during the same periods in 2016 and 2015, we recorded write downs of $19,151 and $19,000, respectively, on certain well equipment to their estimated fair value.

 

At September 30, 2016, Royale Energy had a Deferred Drilling Obligation of $7,261,398.  During the first nine months of 2016, we disposed of $3,151,629 of these obligations upon completing the drilling of two wells, while incurring expenses of $2,932,658, resulting in a gain of $218,971. During the same nine month period in 2015, we disposed of $3,173,208 of deferred drilling obligations upon completing the drilling of four wells, while incurring expenses of $2,833,877, resulting in a gain of $339,331.  During the period in 2015, we also recorded a gain of $564,346 on accounts payable invoices as the vendor went into bankruptcy, which excluded these payables and under the opinion of legal counsel, were deemed no longer payable.

During the nine months ended September 30, 2016, we recorded a gain of $198,975 on the sale of our Company owned office building located in El Cajon, California.  Also during the period in 2016, we recorded a gain of $345,683 on the settlement of accounts payable.  During the same period in 2015, we recorded a gain of $10,070 on the sale of a company owned condominium located in San Diego, California.

Interest expense increased to $72,247 for the nine months ended September 30, 2016, from $64,495 for the same period in 2015, a $9,752, or 15.1% increase. This increase resulted from interest accrued on its convertible promissory notes issued in August 2016, see Capital Resources and Liquidity section.  

Capital Resources and Liquidity

At September 30, 2016, Royale Energy had current assets totaling $5,476,957 and current liabilities totaling $11,448,077 a $5,971,120 working capital deficit.  We had cash at September 30, 2016, of $4,029,372 compared to $3,763,819 at December 31, 2015.

 

In December of 2013, Royale purchased an office building for $2,000,000, of which $500,000 was paid in cash on the date of purchase, and $1,500,000 was borrowed from AmericanWest Bank, with a note secured by the property being purchased.  The note carried an interest rate of 5.75% until paid in full. In February 2016, Royale Energy entered into a purchase and sale agreement for the sale of the office building for $2.5 million.  In June 2016, the sale of the building was completed which resulted in a gain of $198,975 and the related principal and interest payments were paid in full.

 

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 $1.89 per Mcf to a high of $3.36 per Mcf during the first nine months of 2016.  We have not entered into any hedging or derivative agreements to limit our exposure to changes in oil and gas prices or interest rates.

 

Item 4.  Controls and Procedures

 

 

PART II.   OTHER INFORMATION

 

Item 1.  Legal Proceedings

 

None

Item 1A.  Risk Factors

Please review the risk factors contained in our Annual Report on Form 10-K for the year ended December 31, 2015.

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.