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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

 

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FORM 10-K

 

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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

 

 

(Name of registrant in its charter)

 

 

1870 Cordell Court

(Address of principal executive offices)

 

Issuer's telephone number:     619-383-6600

 

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

None

 

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

(Title of Class)

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.   Yes ☐ No ☒

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.   Yes ☐ No ☒

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-B is not contained herein, and will not be contained, to the best or registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ☐

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.

 

Large accelerated filer ☐                                                                Accelerated filer ☐

Non-accelerated filer ☐                                                                  Smaller Reporting Company ☒

 

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

 

At June 30, 2016, the end of the registrant’s most recently completed second fiscal quarter; the aggregate market value of common equity held by non-affiliates was $5,395,938.

 

At March 24, 2017, 21,836,033 shares of registrant's Common Stock were outstanding.

 

TABLE OF CONTENTS

 

ROYALE ENERGY, INC.

PART I

 

Item 1                          Description of Business

Royale Energy, Inc. ("Royale Energy” or the “Company") is an independent oil and natural gas producer.  Royale Energy's principal lines of business are the production and sale of natural gas, acquisition of oil and gas lease interests and proved reserves, drilling of both exploratory and development wells, and sales of fractional working interests in wells to be drilled by Royale Energy.  Royale Energy was incorporated in California in 1986 and began operations in 1988.  Royale Energy's common stock is traded on the Over-The-Counter QB (OTCQB) Market System (symbol ROYL).  On December 31, 2016, Royale Energy had 11 full time employees.

Merger with Matrix Oil Management Corporation

In July 2016, we entered into a letter of intent with Matrix Oil Management Corporation (“Matrix”) to merge Royale Energy and Matrix in a combined stock and assumption of debt transaction.  On November 30, 2016, we entered into an Agreement and Plan of Merger and Reorganization dated November 30, 2016, among Royale, Royale Energy Holdings, Inc., a Delaware corporation (the “Parent”), Royale Merger Sub, Inc., a California corporation and wholly-owned subsidiary of Parent, Matrix Merger Sub, Inc., a California corporation and wholly-owned subsidiary of Parent, and Matrix.  The Merger Agreement was subsequently amended and restated as of December 31, 2016 (the “Merger Agreement”).

The Merger Agreement is part of a series of related transactions in which the Parent will (i) issue its common stock to acquire all of (A) the common stock of Royale Energy, Matrix and Matrix’s affiliate, Matrix Oil Corporation, a California corporation, and (B) the partnership interests of three limited partnerships affiliated with Matrix and (ii) issue newly created Series B 3.5% Convertible Preferred Stock in exchange for approximately $20,124,000 of subordinated debt issued by Matrix and its affiliates.

Immediately after the mergers and the related transactions, it is expected that (i) former holders of Matrix common stock, Matrix Oil Corporation capital stock and the three limited partnerships affiliated with Matrix will collectively own 50% of the Parent’s common stock then outstanding, (ii) former holders of Royale Energy common stock will collectively own 50% of the Parent’s common stock then outstanding, in each case giving effect to the number of shares of the Parent’s common stock issuable under all options and warrants outstanding immediately after the mergers other than shares issuable on exercise of certain options and warrants issued by Royale Energy and (iii) former holders of subordinated debt issued by Matrix and its affiliates will collectively own 100% of all of the Parent’s Series B Convertible Preferred Stock then outstanding.

The merger and related transactions will require the approval of the shareholders of each company and registration of the Royale Energy equity securities to be issued in the merger under the Securities Act of 1933 prior to completion of the transaction. 

Matrix is an independent oil and natural gas producer based in Santa Barbara, California.  Matrix and its affiliates are privately held by fewer than ten equity holders and partners.

Royale Energy, Inc.

Royale Energy owns wells and leases located mainly in the Sacramento Basin and San Joaquin Basin in California as well as in Utah, Texas, Oklahoma, and Louisiana.  Royale Energy usually 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.  Selling part of the working interest to others allows Royale Energy to reduce its drilling risk by owning a diversified inventory of properties with less of its own funds invested in each drilling prospect, than if Royale Energy owned all the working interest and paid all drilling and development costs of each prospect itself.  Royale Energy generally sells working interests in its prospects to accredited investors in exempt securities offerings.  The prospects are bundled into multi-well investments, which permit the third party investors to diversify their investments by investing in several wells at once instead of investing in single well prospects.

  

During its fiscal year ended December 31, 2016, Royale Energy continued to explore and develop natural gas properties with a concentration in California.  Additionally, we own proved developed producing and non-producing reserves of oil and natural gas in Utah, Texas, Oklahoma and Louisiana, as well as holding an overriding royalty interest in a discovery in Alaska.  In 2016, Royale Energy drilled three wells in northern California; which were all commercially productive.  Royale Energy's estimated total reserves were approximately 2.1 and 2.5 BCFE (billion cubic feet equivalent) at December 31, 2016 and 2015, respectively.  According to the reserve reports furnished by Netherland, Sewell & Associates, Inc., Royale Energy's independent petroleum engineers, the undiscounted net reserve value of its proved developed and undeveloped reserves was approximately $3.0 million at December 31, 2016, based on the natural gas average PG&E city-gate spot price of $2.76 per MCF.  Netherland, Sewell & Associates, Inc. supplied reserve value estimates for the Company’s California, Texas, Oklahoma, Utah and Louisiana properties.  

   

Of course, net reserve value does not represent the fair market value of our reserves on that date, and we cannot be sure what return we will eventually receive on our reserves.  Net reserve value of proved developed and undeveloped reserves was calculated by subtracting estimated future development costs, future production costs and other operating expenses from estimated net future cash flows from our developed and undeveloped reserves.

Our standardized measure of discounted future net cash flows at December 31, 2016, was estimated to be $1,483,272.  This figure was calculated by subtracting our estimated future income tax expense from the net reserve value of proved developed and undeveloped reserves, and by further applying a 10% annual discount for estimated timing of cash flows.  A detailed calculation of our standardized measure of discounted future net cash flow is contained in Supplemental Information about Oil and Gas Producing Activities – Changes in Standardized Measure of Discounted Future Net Cash Flow from Proved Reserve Quantities, page F-24.

 

Royale Energy reported a gain on turnkey drilling in connection with the drilling of wells on a "turnkey contract" basis in the amount of $460,210 and $2,330,969 for the years ended December 31, 2016 and 2015, respectively.

In addition to Royale Energy's own staff, Royale Energy hires independent contractors to drill, test, complete and equip the wells that it drills.  Approximately 44.4% of Royale Energy's total revenue for the year ended December 31, 2016, came from sales of oil and natural gas from production of its wells in the amount of $538,631.  In 2015, this amount was $1,018,928, which represented 59.5% of Royale Energy's total revenues.

 

Plan of Business

 

Royale Energy acquires interests in oil and natural gas reserves and sponsors private joint ventures.  Royale Energy believes that its stockholders are better served by diversification of its investments among individual drilling prospects.  Through its sale of joint ventures, Royale Energy can acquire interests and develop oil and natural gas properties with greater diversification of risk and still receive an interest in the revenues and reserves produced from these properties.  By selling some of its working interest in most projects, Royale Energy decreases the amount of its investment in the projects and diversifies its oil and gas property holdings, to reduce the risk of concentrating a large amount of its capital in a few projects that may not be successful.

 

After acquiring the leases or lease participation, Royale Energy drills or participates in the drilling of development and exploratory oil and natural gas wells on its property.  Royale Energy pays its proportionate share of the actual cost of drilling, testing, and completing the project to the extent that it retains all or any portion of the working interest.

Royale Energy also may sell fractional working interests in undeveloped wells to finance part of the drilling cost. A drilling contract that calls for a company to drill a well, for a fixed price, to a specified depth or geological formation is called a "turnkey contract." When Royale Energy sells fractional working interests in unproved property to raise capital to drill oil and natural gas wells, generally it agrees to drill these wells on a turnkey contract basis, so that the holders of the fractional interests prepay a fixed amount for the drilling and completion of a specified number of wells.  Under a turnkey contract, Royale Energy may record a gain if total funds received to drill a well were more than the actual cost to drill those wells including costs incurred on behalf of the participants and costs incurred for its own account.

 

Although Royale Energy’s operating agreements do not usually address whether investors have a right to participate in subsequent wells in the same area of interest as a proposed well, it is the Company’s policy to offer to investors in a successful well the right to participate in subsequent wells at the same percentage level as their working interest investment in the prior successful well.

Our policy for turnkey drilling agreements is to recognize a gain on turnkey drilling programs after our obligations have been fulfilled, and a gain is only recorded when funds received from participants are 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.  See Note 1 to our Financial Statements, at page F-8.

 

Once drilling has commenced, it is generally completed within 10-30 days.  See Note 1 to Royale Energy's Financial Statements, at page F-8.  Royale Energy maintains internal records of the expenditure of each investor's funds for drilling projects.

 

Royale Energy generally operates the wells it completes.  As operator, it receives fees set by industry standards from the owners of fractional interests in the wells and from expense reimbursements.  For the year ended December 31, 2016, Royale Energy earned gross revenues from operation of the wells in the amount of $406,560 representing 33.5% of its total revenues for the year.  In 2015, the amount was $503,441, which represented about 29.4% of total revenues.  At December 31, 2016, Royale Energy operated 31 natural gas wells in California. Royale also has non-operating interests in three natural gas wells in Utah, four oil and gas wells in Texas, two in Oklahoma, four in California, and two in Louisiana.

Royale Energy currently sells most of its California natural gas production through PG&E pipelines to independent customers on a monthly contract basis, while some gas is delivered through privately owned pipelines to independent customers. Since many users are willing to make such purchase arrangements, the loss of any one customer would not affect our overall sales operations.

All oil and natural gas properties are depleting assets in which production naturally decreases over time as the finite amount of existing reserves are produced and sold.  It is Royale Energy’s business as an oil and natural gas exploration and production company to continually search for new development properties.  The Company’s success will ultimately depend on its ability to continue locating and developing new oil and natural gas resources.  Natural gas demand and the prices paid for gas are seasonal. In recent years, natural gas demand and prices in Northern California have fluctuated unpredictably throughout the year.

In 2016, Royale Energy formed a wholly owned subsidiary, Royale DWI Investors, LLC, a California limited liability company, to hold legal title to certain oil and gas working interests which Royale Energy owns for the benefit of its working interest investors.  Royale Energy had no subsidiaries in 2015.

 

Competition, Markets and Regulation

 

The exploration and production of oil and natural gas is an intensely competitive industry.  The sale of interests in oil and gas projects, like those Royale Energy sells, is also very competitive.  Royale Energy encounters competition from other oil and natural gas producers, as well as from other entities that invest in oil and gas for their own account or for others, and many of these companies are substantially larger than Royale Energy.

 

Market factors affect the quantities of oil and natural gas production and the price Royale Energy can obtain for the production from its oil and natural gas properties.  Such factors include: the extent of domestic production; the level of imports of foreign oil and natural gas; the general level of market demand on a regional, national and worldwide basis; domestic and foreign economic conditions that determine levels of industrial production; political events in foreign oil-producing regions; and variations in governmental regulations including environmental, energy conservation, and tax laws or the imposition of new regulatory requirements upon the oil and natural gas industry.

 

Federal and state laws and regulations affect, to some degree, the production, transportation, and sale of oil and natural gas from Royale Energy’s operations.  States in which Royale Energy operates have statutory provisions regulating the production and sale of oil and natural gas, including provisions regarding deliverability.  These statutes, along with the regulations interpreting the statutes, generally are intended to prevent waste of oil and natural gas, and to protect correlative rights to produce oil and natural gas by assigning allowable rates of production to each well or proration unit.

The exploration, development, production and processing of oil and natural gas are subject to various federal and state laws and regulations to protect the environment.  Various federal and state agencies are considering, and some have adopted, other laws and regulations regarding environmental controls that could increase the cost of doing business.  These laws and regulations may require: the acquisition of permits by operators before drilling commences; the prohibition of drilling activities on certain lands lying within wilderness areas or where pollution arises; and the imposition of substantial liabilities for pollution resulting from drilling operations, particularly operations in offshore waters or on submerged lands.  The cost of oil and natural gas development and production also may increase because of the cost of compliance with such legislation and regulations, together with any penalties resulting from failing to comply with the legislation and regulations.  Ultimately, Royale Energy may bear some of these costs.

Presently, Royale Energy does not anticipate that compliance with federal, state and local environmental regulations will have a material adverse effect on capital expenditures, earnings, or its competitive position in the oil and natural gas industry; however, changes in the laws, rules or regulations, or the interpretation thereof, could have a materially adverse effect on Royale Energy’s financial condition or results of operation.

Royale Energy files quarterly, yearly and other reports with the Securities Exchange Commission.  You may obtain a copy of any materials filed by Royale Energy with the SEC at 100 F Street, N.W., Washington, D.C. 20549, by calling 1-800-SEC-0300.  The SEC also maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov.  Royale Energy also provides access to its SEC reports and other public announcements on its website, http://www.royl.com.

Item 2                          Description of Property

 

Since 1993, Royale Energy has concentrated on development of properties in the Sacramento Basin and the San Joaquin Basin of Northern and Central California.  In 2016, Royale Energy drilled three wells in northern California, two exploratory producing wells and one developmental producing well.   

 

Following industry standards, Royale Energy generally acquires oil and natural gas acreage without warranty of title except as to claims made by, though, or under the transferor.  In these cases, Royale Energy attempts to conduct due diligence as to title before the acquisition, but it cannot assure that there will be no losses resulting from title defects or from defects in the assignment of leasehold rights.  Title to property most often carries encumbrances, such as royalties, overriding royalties, carried and other similar interests, and contractual obligations, all of which are customary within the oil and natural gas industry.

 

Following is a discussion of Royale Energy's significant oil and natural gas properties.  Reserves at December 31, 2016, for each property discussed below, have been determined by Netherland, Sewell & Associates, Inc., registered professional petroleum engineers, in accordance with reports submitted to Royale Energy on February 22, 2017.

 

Northern California

 

Royale Energy owns lease interests in nine gas fields with locations ranging from Glenn County in the north to Madera County in the south, in the Sacramento Basin in California.  At December 31, 2016, Royale operated 31 wells in California with estimated total proven, developed, and undeveloped reserves at approximately 2.0 BCF, according to Royale’s independently prepared reserve report as of December 31, 2016.

Developed and Undeveloped Leasehold Acreage

 

As of December 31, 2016, Royale Energy owned leasehold interests in the following developed and undeveloped properties in both gross and net acreage.

 

Gross and Net Productive Wells

As of December 31, 2016, Royale Energy owned interests in the following oil and gas wells in both gross and net acreage:

 

Drilling Activities

 

The following table sets forth Royale Energy's drilling activities during the years ended December 31, 2015 and 2016.  All wells are located in the Continental U.S., in California, Texas, Louisiana and Utah.

 

 

 

 

 

 

Production

 

The following table summarizes, for the periods indicated, Royale Energy's net share of oil and natural gas production, average sales price per barrel (BBL), per thousand cubic feet (MCF) of natural gas, and the MCF equivalent (MCFE) for the barrels of oil based on a 6 to 1 ratio of the price per barrel of oil to the price per MCF of natural gas.  "Net" production is production that Royale Energy owns either directly or indirectly through partnership or joint venture interests produced to its interest after deducting royalty, limited partner or other similar interests.  Royale Energy generally sells its oil and natural gas at prices then prevailing on the "spot market" and does not have any material long term contracts for the sale of natural gas at a fixed price.

 

Net Proved Oil and Natural Gas Reserves

 

As of December 31, 2016, Royale Energy had proved developed reserves of 1,700 MMCF and total proved reserves of 2,015 MMCF of natural gas on all of the properties Royale Energy leases.  For the same period, Royale Energy also had proved developed oil and natural gas liquid combined reserves of 6 MBBL and total proved oil and natural gas liquid combined reserves of 6 MBBL.

 

Oil and gas reserve estimates and the discounted present value estimates associated with the reserve estimates are based on numerous engineering, geological and operational assumptions that generally are derived from limited data.

Item 3                          Legal Proceedings

None

 

Item 4                          Mine Safety Disclosures

 

Not Applicable 

 

PART II

 

Item 5                          Market for Common Equity and Related Stockholder Matters

 

Royale Energy’s Common Stock is traded under the symbol “ROYL”.  Since January 21, 2016, Royale Energy’s Common Stock has been traded on the OTC QB Market.  Prior to that, Royale energy’s Common Stock was traded on the Nasdaq Stock Market.  As of December 31, 2016, 21,836,033 shares of Royale Energy’s Common Stock were held by approximately 6,008 stockholders.  The following table reflects the high and low quarterly closing sales prices on the Nasdaq Stock Market and OTC QB Market from January 2015 through December 2016.

 

 

Dividends

 

The Board of Directors did not issue cash or stock dividends in 2016 or 2015.

Recent Sales of Unregistered Securities

 

None.

Item 6                          Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

The following discussion should be read in conjunction with Royale Energy’s Financial Statements and Notes thereto and other financial information relating to Royale Energy included elsewhere in this document.

 

Since 1993, Royale Energy has primarily acquired and developed producing and non-producing natural gas properties in California.   In 2004, Royale Energy began developing leases in Utah and in 2012 began acquiring leases in Alaska.  The most significant factors affecting the results of operations are (i) the change in commodities price of natural gas and oil reserves owned by Royale Energy, (ii) changes in oil and natural gas production levels and reserves, and (iii) turnkey drilling activities and (iv) the impairment of our Alaska leases.

 

Merger with Matrix Oil Management Corporation

Royale Energy has entered into an amended and restated merger agreement dated as of December 31, 2016, among Royale Energy, Royale Energy Holdings, Inc., a Delaware corporation (the “Parent”), Royale Merger Sub, Inc., Matrix Merger Sub, Inc., a wholly-owned subsidiary of Parent, and Matrix Oil Management Corporation (“Matrix”).  The Merger Agreement is part of a series of related transactions in which the Parent will (i) issue its common stock to acquire all of (A) the common stock of Royale Energy, Matrix and Matrix’s affiliate, Matrix Oil Corporation, and (B) the partnership interests of three limited partnerships affiliated with Matrix and (ii) issue newly created Series B 3.5% Convertible Preferred Stock in exchange for approximately $20,124,000 of subordinated debt issued by Matrix and its affiliates.

Immediately after the mergers and the related transactions, it is expected that (i) former holders of Matrix common stock, Matrix Oil Corporation capital stock and the three limited partnerships affiliated with Matrix will collectively own 50% of the Parent’s common stock then outstanding, (ii) former holders of Royale Energy common stock will collectively own 50% of the Parent’s common stock then outstanding, in each case giving effect to the number of shares of the Parent’s common stock issuable under all options and warrants outstanding immediately after the mergers other than shares issuable on exercise of certain options and warrants issued by Royale Energy and (iii) former holders of subordinated debt issued by Matrix and its affiliates will collectively own 100% of all of the Parent’s Series B Convertible Preferred Stock then outstanding.

Critical Accounting Policies

 

 

Royale’s primary business is oil and gas production.  Natural gas flows from the wells into gathering line systems, which are equipped occasionally with compressor systems, which in turn flow into metered transportation and customer pipelines.  Monthly, price data and daily production are used to invoice customers for amounts due to Royale Energy and other working interest owners.  Royale Energy operates most of its own wells and receives industry standard operator fees.

 

Royale Energy generally sells crude oil and natural gas under short-term agreements at prevailing market prices. Revenues are recognized when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured.

 

Revenues from the production of oil and natural gas properties in which the Royale Energy has an interest with other producers are recognized on the basis of Royale Energy’s net working interest. Differences between actual production and net working interest volumes are not significant.

 

Royale Energy’s financial statements include its pro rata ownership of wells.  Royale Energy usually 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.  Royale Energy generally retains about a 50% working interest.  All results, successful or not, are included at its pro rata ownership amounts: revenue, expenses, assets, and liabilities as defined in FASB ASC 932-323-25 and 932-360.

 

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 2016 and 2015, impairment losses of $2,071,849 and $424,163, respectively, were recorded on various capitalized lease and land costs where the carrying value exceeded the fair value or where the leases 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.

Since the participant’s interest in the prospect is limited to the well, and not the lease, the investor does not have a legal right to participate in additional wells drilled within the same lease.  However, it is the Company’s policy to offer to participants in a successful well the right to participate in subsequent wells at the same percentage level as their working interest investment in the prior successful well with similar turnkey drilling agreement terms.

 

A certain portion of the turnkey drilling participant’s funds received are non-refundable.    The company records a liability for all funds invested as deferred drilling obligations until each individual well is complete.  Occasionally, drilling is delayed for various reasons such as weather, permitting, drilling rig availability and/or contractual obligations.  At December 31, 2016 and 2015, Royale Energy had deferred drilling obligations of $7,894,001 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 contract 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.

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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.  The most significant estimates pertain to proved oil, plant products and gas reserve volumes and the future development costs.  Actual results could differ from those estimates.

 

 

Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts attributable to events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax credit carry forwards.  All available evidence, both positive and negative, must be considered to determine whether, based on the weight of that evidence, a valuation allowance for deferred tax assets is needed.  The Company uses information about the Company’s financial position and its results of operations for the current and preceding years.

 

The Company must use its judgment in considering the relative impact of negative and positive evidence. The weight given to the potential effect of negative and positive evidence is commensurate with the extent to which it can be objectively verified. The more negative evidence that exists, the more positive evidence is necessary and the more difficult it is to support a conclusion that a valuation allowance is not needed for some portion or all of the deferred tax asset. A cumulative loss in recent years is a significant piece of negative evidence that is difficult to overcome.

 

Future realization of a tax benefit sometimes will be expected for a portion, but not all, of a deferred tax asset, and the dividing line between the two portions may be unclear. In those circumstances, application of judgment based on a careful assessment of all available evidence is required to determine the portion of a deferred tax asset for which it is more likely than not a tax benefit will not be realized.

 

Results of Operations for the Twelve Months Ended December 31, 2016, as Compared to the Twelve Months Ended December 31, 2015

 

For the year ended December 31, 2016, we recorded a net loss of $4,144,462, compared to net loss of $2,010,816 during 2015.  Total revenues from operations in 2016 were $1,213,839, a decrease of $499,249, or 29.1% from the total revenues of $1,713,088 in 2015, due to lower natural gas production and commodity prices during 2016.  Total expenses for operations in 2016 were $6,505,716, a decrease of $432,025, or 6.2%, from the total expenses of $6,937,741 in 2015, mainly due to cost reduction measures in most of our operating expense categories.

 

In 2016, revenues from oil and gas production decreased by 47.1% to $538,631 from $1,018,928 in 2015. This decrease was due to lower production volumes and lower natural gas commodity prices received during 2016.  The net sales volume of natural gas for the year ended December 31, 2016, was approximately 232,539 MCF with an average price of $2.31 per MCF, versus 363,168 MCF with an average price of $2.75 per MCF for 2015.  This represents a decrease in net sales volume of 130,629 MCF or 36%.  This decrease in production volume was mainly due to the natural declines in our wells, and the sale of our Victor Ranch field interests which had an effective date of September 1, 2016.  The net sales volume for oil and condensate (natural gas liquids) production was approximately 193 barrels with an average price of $12.11 per barrel, which was lower due to the inclusion of oil byproducts in the barrel count, for the year ended December 31, 2016, compared to 403 barrels at an average price of $46.11 per barrel for the year in 2015.  This represents a decrease in net sales volume of 210 barrels, or 52.1%, also due to the natural declines on existing oil and condensate wells.  Northern and central California accounted for approximately 97% of the Company’s successful natural gas production in 2016.

 

Oil and natural gas lease operating expenses decreased by $406,528, or 40.6% to $594,241 for the year ended December 31, 2016, from $1,000,769 for the year in 2015.  This decrease was due to lower production volumes and to cost reduction measures especially in lower workover costs and operating costs for non-operated wells during 2016.  When measuring lease operating costs on a production or lifting cost basis, in 2016, the $594,241 equates to a $2.54 per MCFE lifting cost versus a $2.74 per MCFE lifting cost in 2015, a 7.3% decrease, due to lower production volumes in 2016.  For the year ended December 31, 2016, delay rental costs decreased by $448,313, as there were no delay rental costs paid in 2016.

 

At December 31, 2016, Royale Energy had a deferred drilling obligation of $7,894,001.  During 2016, we disposed of $4,502,026 of obligations relating to 2015, upon completing the drilling of three wells, two exploratory and one developmental.  This resulted in a gain of $460,210.  During 2015, we disposed of $4,955,734 of obligations relating to 2014, upon completing the drilling of four wells, two exploratory and two developmental.  Additionally we purchased an interest in an existing well from an industry partner.  In 2015, we also recorded a gain of $564,346 on accounts payable invoices in dispute as the vendor went into bankruptcy, and under the opinion of legal counsel, these invoices were deemed no longer payable.  This resulted in a gain of $2,330,969.   The three wells drilled in 2016 were higher in costs than those drilled in 2015, due to their locations, depths completion costs and additional directional costs associated with one of the wells.  Royale Energy expects to dispose of approximately $3.5 million of its deferred drilling obligation in the first six months of 2017 with $6.4 million of its deferred drilling obligation disposed of by the end of 2017.

 

During 2016, we recorded a gain of $284,419 on the sale of interests in our Victor Ranch field wells and leases.  During 2016, we also recorded a gain of $198,975 on the sale of our Company owned office building located in El Cajon, California.  During the year in 2016, we recorded a gain of $341,751 on the settlement of accounts payable.  In 2016, we recorded a loss on disposal of assets of $23,781, on fixed assets that were no longer viable.  During 2016, we also recorded a write down of $19,151 on certain oil and gas well equipment to its current estimated market value.  During 2015, we recorded a gain of $468,759 related to the sale of a portion of our western block oil and gas lease acreage in Alaska.  During this period, we also recorded a gain of $87,127 on the settlement of accounts payable due to vendors.  In 2015, we also recorded a gain of $403,000 on the sale of a license agreement to our Alaska seismic survey.  Additionally in 2015, we recorded a gain of $10,070 on the sale of a Company owned condominium located in San Diego, California.  During 2015, we recorded a write down of $60,960 on certain oil and gas well equipment to its current estimated market value.  

Impairment losses of $2,071,849 and $424,163 were recorded in 2016 and 2015, respectively.  In 2016, $2,025,546 of the impairment loss was due to termination of our remaining Alaska leases which were not renewed due to nonpayment of the delay rental payments.  Also in 2016, $46,303 of the impairment loss was due to capitalized lease and land costs on a Texas lease that was no longer viable.  In 2015, $327,727 of the impairment loss was due to two Utah wells, one Louisiana well, and our Alaska acreage where the carrying value exceeded the fair value.  For the balance of the loss in 2015, we recorded impairments on various capitalized lease and land costs that were no longer viable.  

Bad debt expense for 2016 and 2015 were $0 and $536,538, respectively.  The expenses in 2015 arose from identified uncollectable receivables relating to our oil and natural gas properties either plugged and abandoned or scheduled for plugging and abandonment and our year-end oil and natural gas reserve values.  We periodically review our accounts receivable from working interest owners to determine whether collection of any of these charges appears doubtful.  By contract, the Company may not collect some charges from its Direct Working Interest owners for certain wells that ceased production or had been sold during the year, to the extent that these charges exceed production revenue.

 

The aggregate of supervisory fees and other income was $675,208 for the year ended December 31, 2016, a decrease of $18,952 or 2.7% from $694,160 during the year in 2015.  This decrease was mainly due to lower operations overhead and pipeline fees during 2016, due to lower production volumes.  Supervisory fees are charged in accordance with the Council for Petroleum Accountants Societies (COPAS) policy for reimbursement of expenses associated with the joint accounting for billing, revenue disbursement, and payment of taxes and royalties.  These charges are reevaluated each year and adjusted up or down as deemed appropriate by a published report to the industry by Ernst & Young, LLP, Certified Public Accountants.  Supervisory fees decreased $96,881 or 19.2%, to $406,560 in 2016 from $503,441 in 2015.

 

Depreciation, depletion and amortization expense decreased to $283,874 from $400,813 a decrease of $116,939 or 29.2% for the year ended December 31, 2016, as compared to 2015.  The depletion rate is calculated using production as a percentage of reserves.  This decrease in depreciation expense was due to a lower depletion rate as reserve volumes were higher at the end of 2016 and a lower asset base due to the sale of our Victor Ranch field interests.

  

General and administrative expenses decreased by $567,069 or 17.8%, to $2,614,502 for the year ended December 31, 2016, from $3,181,571 for the year in 2015.  This decrease was primarily due to employee related, salaries, insurance and taxes, cost reduction measures.  Legal and accounting expense increased to $627,577 for the year, compared to $558,471 for 2015, a $69,106 or 12.4% increase.  The increase in 2016 was mainly due to legal and accounting expenses related to the proposed merger.

Marketing expense for the year ended December 31, 2016, decreased $31,621 or 9.7%, to $294,522, compared to $326,143 for the year in 2015.  Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs.

 

During 2016, interest expense increased to $114,159 from $86,088 in 2015, a $28,071 or 32.6% increase.  This increase resulted from interest accrued on its convertible promissory notes issued in August 2016.  Further details concerning Royale’s notes payable can be found in Capital Resources and Liquidity, below.

In 2016 and 2015, we did not have an income tax expense due to the use of a percentage depletion carryover valuation allowance created from the current and past operations resulting in an effective tax rate less than the normal federal rate of 34% plus the relevant state rates (mostly California, 8.8%).  

Capital Resources and Liquidity

 

At December 31, 2016, Royale Energy had current assets totaling $6,038,081 and current liabilities totaling $11,943,246, a $5,905,165 working capital deficit.  We had cash and cash equivalents at December 31, 2016 of $4,994,598 compared to $3,763,819 at December 31, 2015.

Ordinarily, we fund our operations and cash needs from our available credit and cash flows generated from operations.  We believe that, should the merger be consummated, for the foreseeable future we will be able to meet our liquidity demands.  However, should the merger fail to close, 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 additional sales of equity or debt securities.

 

At December 31, 2016, our other receivables, which consist of receivables from direct working interest investors and industry partners, totaled $676,647, compared to $381,192 at December 31, 2015, a $295,455 or 77.5% decrease.  This increase was mainly due to new well placed into production during the year whose operating costs were not yet recovered.  Royale’s revenue receivable at the end of 2016 was $303,528, a decrease of $155,592 or 105.2%, compared to $147,936 at the end of 2015, due to higher oil and gas production from two new wells which began production during the fourth quarter of 2016, and higher natural gas commodity prices.  At December 31, 2016, our accounts payable and accrued expenses totaled $2,469,245, a decrease of $467,981 or 15.9% over the accounts payable at the end of 2015 of $2,937,226, mainly due to payments and settlements of trade accounts payable during the year in 2016. 

In July 2016, we entered in negotiations with two separate investors to issue convertible promissory notes 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 mature one year from the date of issuance and carry a 10% interest rate, which is due at maturity.  The conversion of the notes to shares is subject to shareholder approval.   The funds from these transactions is to be used to continue drilling activities, fund expenses to be incurred in connection with completion of Royale Energy’s proposed merger with Matrix Oil Corporation and for general corporate purposes.  Both of these negotiations are expected to conclude in the first quarter of 2017 and as such were included as Cash Advances on Pending Transactions as December 31, 2016.

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.

 

In May 2015, we entered into a sales agreement with Roth Capital, LLC (Roth) relating to the sale of shares of our common stock.  Pursuant to the sales agreement, we sold 701,397 shares of common stock to the public for $556,123 in 2015.  In October 2015, we discontinued such sales and the sales agreement was terminated.

On November 25, 2015, we entered into a securities purchase agreement and related agreements with a group of individual investors pursuant to a registered direct offering.  Under the terms of the agreements, the investors purchased 497,948 shares of Royale’s common stock at $0.408 per share, and received warrants to purchase up to 248,973 shares (the “Warrants’) of stock at $1.00 per share for three (3) years, for a total of $203,165 in gross proceeds,.  Each Warrant becomes exercisable one year from the date of issuance.  Each Warrant contains customary adjustments for corporate events such as reorganizations, splits, and dividends.

 

We do not engage in hedging activities or use derivative instruments to manage market risks.

 

The following schedule summarizes our known contractual cash obligations at December 31, 2016, and the effect such obligations are expected to have on our liquidity and cash flow in future periods.

 

		Total Obligations				2017				2018-2019				2020				Beyond
Office Lease		$	612,562			$	97,266			$	242,537			$	127,355			$	145,404

 

Changes in Reserve Estimates

 

During 2016, our overall proved developed and undeveloped reserves decreased by 19% and our previously estimated proved developed and undeveloped reserve quantities were revised upward by approximately .07 million cubic feet of natural gas.  This upward revision reflected higher than previously estimated proved producing and non-producing natural gas reserves at eight California wells and one Louisiana well.  See Supplemental Information about Oil and Gas Producing Activities (Unaudited), page F-20. 

During 2015, our overall proved developed and undeveloped reserves decreased by 39% and our previously estimated proved developed and undeveloped reserve quantities were revised downward by approximately 1.3 million cubic feet of natural gas.  This downward revision reflected lower than previously estimated proved producing and non-producing natural gas reserves at seven California wells and one Utah well.  See Supplemental Information about Oil and Gas Producing Activities (Unaudited), page F-20.  

 

Item 7                          Qualitative and Quantitative Disclosures About Market Risk

 

Royale Energy is exposed to market risk from changes in commodity prices and in interest rates.  In 2016, we sold a majority of our natural gas at the daily market rate through the Pacific Gas & Electric pipeline.  In 2016, our natural gas revenues were approximately $536,000 with an average price of $2.31 per MCF.  At current production levels, a 10% per MCF increase or decrease in our average price received could potentially increase or decrease our natural gas revenues by approximately $50,000.  We currently do not sell any of our natural gas or oil through hedging contracts. 

 

Item 8                          Financial Statements and Supplementary Data

 

See pages F-1, et seq., included herein.

Item 9                          Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None

 

Item 9A                       Controls and Procedures

Disclosure Controls

 

Disclosure controls are controls and other procedures that are designed to ensure that information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.  Our disclosure controls and procedures are designed to insure that the information required to be filed is accumulated and communicated to our management in a manner designed to enable them to make timely decisions regarding required disclosure.

Our executive officers, Jonathan Gregory, Chief Executive Officer, Donald H. Hosmer, President of Business Development and Stephen M. Hosmer, President and Chief Financial Officer, evaluated the effectiveness or our disclosure controls and procedures as of the end of the 2016 fiscal year.  Based on their evaluation, they concluded that our disclosure controls are effective as of December 31, 2016.

 

Management Report on Internal Control over Financial Reporting

 

Our management is responsible for establishing and maintaining adequate internal control over financial reporting to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company, (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.  Management assessed our internal control over financial reporting as of December 31, 2016, which was the end of our fiscal year. Management based its assessment on criteria established in the SEC Commission Guidance Regarding Management’s Report on Internal Control Over Financial Reporting Under Section 13(a) or 15(d) of the Securities Exchange Act of 1934. The guidance sets forth an approach by which management can conduct a top-down, risk-based evaluation of internal control over financial reporting. Management’s assessment included an evaluation of risks to reliable financial reporting, whether controls exist to address those risks and evaluated evidence about the operation of the controls included in the evaluation based on its assessment of risk.

 

The control deficiency that gave rise to the material weakness did not result in a material misstatement of our financial statements for the fiscal year ending December 31, 2016.

Because of the material weakness described above, our management was unable to conclude that our internal control over financial reporting was effective as of the end of the fiscal year 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. Management is seeking written acknowledgement of the note transactions from the note holders in order to remediate the material weakness described above and will require written acknowledgement from counterparties of all similar future transactions.

Except for the actions described above that were taken to address the material weaknesses, there were no changes in our internal controls during the fiscal year ended December 31, 2016 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.  We reviewed the results of management’s assessment with the Audit Committee of our Board of Directors.

 

This annual report does not include an attestation report of the company's registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by the company's registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the company to provide only management's report in this annual report.

Changes in Internal Control over Financial Reporting

 

No changes in our internal control over financial reporting occurred during the last fiscal quarter of 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Limitations on Effectiveness of Controls

 

Our management, including our CEO and CFO, does not expect that our disclosure controls or internal controls over financial reporting will prevent all error or fraud.  A control system, no matter how well conceived and operated, can provide only reasonable, but not absolute, assurance that the objectives of a control system are met.  Any control system contains limitations imposed by resources and relevant cost considerations.  Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues have been addressed.  These inherent limitations include the realities that judgments can be faulty and that breakdowns can occur because of simple error or mistake.  In addition, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of a control.  Our control system design is also based on assumptions about the likelihood of future events, and we cannot be sure that we have considered all possible future circumstances and events.

 

 

PART III

 

Item 10                        Directors and Executive Officers of the Registrant

 

Pursuant to General Instruction G to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement/prospectus for our 2016 Annual Meeting of Shareholders.

 

Item 11                        Executive Compensation

 

Pursuant to General Instruction G to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement/prospectus for our 2016 Annual Meeting of Shareholders.

 

Item 12                        Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 

Pursuant to General Instruction G to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement/prospectus for our 2016 Annual Meeting of Shareholders.

Item 13                        Certain Relationships and Related Transactions

 

Pursuant to General Instruction G to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement/prospectus for our 2016 Annual Meeting of Shareholders.

 

Item 14                        Principal Accountant Fees and Services

 

Pursuant to General Instruction G to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement/prospectus for our 2016 Annual Meeting of Shareholders.

PART IV

 

Item 15                        Exhibits and Financial Statement Schedules

 

The agreements included as exhibits to this report are included to provide information about their terms and not to provide any other factual or disclosure information about Royale Energy or the other parties to the agreements.  The agreements contain representations and warranties by each of the parties to the applicable agreement that were made solely for the benefit of the other agreement parties and:

 

 

 

2.1	Amended and Restated Agreement and Plan of Merger among Royale Energy, Inc., Royale Energy Holdings, Inc., Royale Merger Sub, Inc., Matrix Merger Sub, Inc., and Matrix Oil Management Corporation, incorporated by reference to Exhibit 2.1, Annex A to Royale Energy’s Registration Statement on Form S-4 filed February 14, 2017.
2.2	Form of Preferred Exchange Agreement with the holders of all of the Matrix Preferred Interests, incorporated by reference to Exhibit 2.2, Annex B to Royale Energy’s Registration Statement on Form S-4 filed February 14, 2017.
2.3	Form of LP Exchange Agreement between Royale Energy, Inc., Royale Energy Holdings, Inc., and holders of LP Interests of Matrix Investments, L.P. other than Preferred LP Interests, incorporated by reference to Exhibit 2.3, Annex C to Royale Energy’s Registration Statement on Form S-4 filed February 14, 2017.
2.4	Form of LP Exchange Agreement between Royale Energy, Inc., Royale Energy Holdings, Inc., and holders of LP Interests of Matrix Las Cienegas Limited Partnership, incorporated by reference to Exhibit 2.4, Annex D to Royale Energy’s Registration Statement on Form S-4 filed February 14, 2017.
2.5	Form of LP Exchange Agreement between Royale Energy, Inc., Royale Energy Holdings, Inc., and holders of all LP Interests of Matrix Permian Investments, L.P. , incorporated by reference to Exhibit 2.5, Annex E to Royale Energy’s Registration Statement on Form S-4 filed February 14, 2017.
2.6	Form of Matrix Operator Stock Exchange Agreement between Royale Energy, Inc., Royale Energy Holdings, Inc., and the holders of all outstanding common stock of Matrix Oil Corporation, incorporated by reference to Exhibit 2.6, Annex F to Royale Energy’s Registration Statement on Form S-4 filed February 14, 2017.
2.7	Form of Section 351 Plan of Merger and Exchange, incorporated by reference to Exhibit 2.7, Annex G to Royale Energy’s Registration Statement on Form S-4 filed February 14, 2017.
2.8	This Amendment No. 1 to the Amended and Restated Agreement and Plan of Merger dated March 30, 2017, filed herewith.
3.1	Restated Articles of Incorporation of Royale Energy, Inc., incorporated by reference to Exhibit 3.1 of Royale Energy’s Form 10-Q filed August 14, 2009.
3.2	Amended and Restated Bylaws of Royale Energy, Inc., incorporated by reference to Exhibit 3.2 of Royale Energy’s Form 10-K filed March 27, 2009.
21.1	Subsidiaries, filed herewith.
23.1	Consent of SingerLewak L.L.P., filed herewith.
31.1	Rule 13a-14(a), 115d-14(a) Certification, filed herewith.
31.2	Rule 13a-14(a), 115d-14(a) Certification, filed herewith.
31.3	Rule 13a-14(a), 115d-14(a) Certification, filed herewith.
32.1	Section 1350 Certification, filed herewith.
32.2	Section 1350 Certification, filed herewith.
32.3	Section 1350 Certification, filed herewith.
99.1	Report of Netherland Sewell & Associates, Inc., filed herewith.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase
101.DEF*	XBRL Taxonomy Extension Definition Linkbase
101.LAB*	XBRL Taxonomy Extension Label Linkbase
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase

 

* Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability.

 

 

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.

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

 

ROYALE ENERGY, INC.

INDEX TO FINANCIAL STATEMENTS

AND SUPPLEMENTARY DATA

 

 

 

ROYALE ENERGY, INC.

BALANCE SHEETS

DECEMBER 31, 2016 AND 2015

 

 

The accompanying notes are an integral part of these financial statements.

ROYALE ENERGY, INC.

BALANCE SHEETS

DECEMBER 31, 2016 AND 2015

 

 

The accompanying notes are an integral part of these financial statements.

 

ROYALE ENERGY, INC.

STATEMENTS OF COMPREHENSIVE LOSS

FOR THE YEARS ENDED DECEMBER 31, 2016, AND 2015

 

 

The accompanying notes are an integral part of these financial statements.

 

ROYALE ENERGY, INC.

STATEMENTS OF STOCKHOLDERS' DEFICIT

FOR THE YEARS ENDED DECEMBER 31, 2016 and 2015

 

										Preferred Stock
		Common Stock								Series AA												Accumulated Other Comprehensive Income (Loss)
		Number of Shares Issued and Outstanding								Number of Shares Issued and Outstanding
																		Accumulated Deficit
						Amount								Amount												Total
Balance,  December 31, 2014			14,945,789			$	38,352,370				46,662			$	136,149			$	(39,623,243	)		$	(6,503	)		$	(1,141,227	)
Common Stock Private Placement Sale			701,397			$	490,116																				490,116
Director’s Stock Option Grant							86,877																				86,877
Common Stock RDO Private Placement Sale			485,486				199,195																				199,195
Common Stock Issued to Executives in lieu of Compensation			263,907				143,871																				143,871
Available for Sale Securities – Reclassification Adjustment for Losses Included in Net Income																							6,503				6,503
Net Loss																			(2,010,816	)							(2,010,816	)
Balance,  December 31, 2015			16,396,579			$	39,272,429				46,662			$	136,149			$	(41,634,059	)		$	-			$	(2,225,481	)
Common Stock Private Placement Sale			3,027,070				1,160,885																				1,160,885
Common Stock Issued to Executives in lieu of Compensation			2,335,461				645,986																				645,986
Issuance of Common Stock in Settlement of AP			76,923				50,000																				50,000
Preferred Series AA Converted to Common Stock			23,331				136,149				(46,662	)			(136,149	)											-
Net Loss																			(4,144,462	)							(4,144,462	)
Balance,  December 31, 2016			21,859,364			$	41,265,449				-			$	-			$	(45,778,521	)		$	-			$	(4,513,072	)

 

The accompanying notes are an integral part of these financial statements.

 

ROYALE ENERGY, INC.

STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2016 and 2015

 

		2016				2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (Loss)		$	(4,144,462	)		$	(2,010,816	)
Adjustments to Reconcile Net Loss to Net Cash Used by Operating Activities:
Depreciation, Depletion, and Amortization			283,874				400,813
Lease Impairment			2,071,849				424,163
Gain on Sale of Assets			(483,394	)			(968,956	)
Gain on Turnkey Drilling Programs			(460,210	)			(2,330,969	)
Gain on Settlement of Accounts Payable			(341,751	)			-
Loss on Disposal of Assets			23,781				-
Bad Debt Expense			-				536,538
Stock-Based Compensation			645,986				230,749
Realized Loss on Equity Securities			-				6,503
Well Equipment and Other Assets Write Down			19,151				60,960
(Increase) Decrease in:
Other & Revenue Receivables			(451,047	)			1,187,810
Prepaid Expenses and Other Assets			151,642				(236,615	)
Increase (Decrease) in:
Accounts Payable and Accrued Expenses			(587,050	)			(1,273,360	)
Net Cash Used by Operating Activities			(3,271,631	)			(3,973,180	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for Oil And Gas Properties			(2,058,357	)			(3,753,134	)
Proceeds from Turnkey Drilling Programs			3,980,499				5,433,476
Proceeds from Sale of Assets			1,286,236				2,334,537
Net Cash Provided by Investing Activities			3,208,378				4,014,879
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash Advances From Investors			1,580,000				-
Principal Payments on Long-Term Debt			(1,446,853	)			(29,031	)
Proceeds from Issuance of Common Stock			1,160,885				689,310
Net Cash Provided by Financing Activities			1,294,032				660,279
Net Increase in Cash			1,230,779				701,978
Cash at Beginning of Year			3,763,819				3,061,841
Cash at End of Year		$	4,994,598			$	3,763,819
Cash Paid for Interest		$	48,325				86,088
Cash Paid for Taxes		$	2,100				1,000
Supplemental Schedule of Non-Cash Investing and Financing Transactions:
Conversion of Series AA Stock to Common Stock		$	136,149			$	-
Reclassification Adjustment for Losses Included in Net Income		$	-			$	(6,503	)
Warrants Issued with Common Stock		$	156,205			$	-

 

The accompanying notes are an integral part of these financial statements.

 

ROYALE ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

 

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

This summary of significant accounting policies of Royale Energy, Inc. (“Royale Energy,” “Royale,” or the “Company”) is presented to assist in understanding Royale Energy's financial statements.  The financial statements and notes are representations of Royale Energy's management, which is responsible for their integrity and objectivity.  These accounting policies conform to accounting principles generally accepted in the United States of America and have been consistently applied in the preparation of the financial statements.

Royale Energy is an independent oil and gas producer which also has operations in the area of turnkey drilling.  Royale Energy owns wells and leases in major geological basins located primarily in California, Texas, Oklahoma and Utah. Royale Energy offers fractional working interests and seeks to minimize the risks of oil and gas drilling by selling multiple well drilling projects which do not include the use of debt financing.

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.

 

Liquidity and going concern

 

The primary sources of liquidity have historically been issuances of common stock and operations. We believe that the completion of the contemplated merger with will enable us to return to positive cash flow.  There is some doubt about the company’s ability to meet liquidity demands, and we anticipate that our primary sources of liquidity will be from the issuance of debt and/or equity, and the sale of oil and natural gas property participation interest.

 

 

 

Royale’s primary business is oil and gas production.  Natural gas flows from the wells into gathering line systems, which are equipped occasionally with compressor systems, which in turn flow into metered transportation and customer pipelines.  Monthly, price data and daily production are used to invoice customers for amounts due to Royale Energy and other working interest owners.  Royale Energy operates virtually all of its own wells and receives industry standard operator fees.

 

Royale Energy generally sells crude oil and natural gas under short-term agreements at prevailing market prices. Revenues are recognized when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured.

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.

 

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.

 

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 December 31, 2016 and 2015, the Company established 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.

 

Income (Loss) Per Share

 

Basic and diluted losses per share are calculated as follows:

 

 

For the years ended December 31, 2016 and 2015, Royale Energy had dilutive securities of 0 and 23,331, respectively.  These securities were not included in the dilutive loss per share due to their antidilutive nature.

Royale Energy has a stock-based employee compensation plan, which is more fully described in Note 11.  Effective January 1, 2006, the Company adopted the Compensation – Stock Compensation Topic of the FASB Accounting Standards Codification, which addresses the accounting for stock-based payment transactions in which an enterprise receives employee services in exchange for (a) equity instruments of the enterprise or (b) liabilities that are based on the fair value of the enterprise’s equity instruments or that may be settled by the issuance of such equity instruments. The Company uses the Black-Scholes option-pricing model to determine the fair value of stock-based awards.

 

Royale utilizes the asset and liability approach to measure deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates in accordance with the Income Taxes Topic of the FASB Accounting Standards Codification. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. Under the Topic, deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

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

 

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:

 

At December 31, 2016 and 2015, Royale Energy does 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. See Note 3 for further discussion of the Company's asset retirement obligations.

At December 31, 2016, the components of accounts payable and accrued expenses consisted of $1,205,740 in trade accounts payable due to various vendors, $699,068 in payables and accruals related to direct working interest investors revenues and operating costs, $98,172 in accrued expenses related to current drilling efforts, $266,110 for accrued liabilities for amounts set aside mainly for the plugging and abandonment of certain wells, $103,212 for employee related taxes and accruals, $65,833 related to interest payable on cash advances from investors and $18,662 in federal and state income taxes payable.  At December 31, 2015, the components of accounts payable and accrued expenses consisted of $2,167,809 in trade accounts payable due to various vendors, $238,320 in payables and accruals related to direct working interest investors operating costs, $369,837 for accrued liabilities for amounts set aside mainly for the plugging and abandonment of certain wells, $140,798 for employee related taxes and accruals and $20,462 in federal and state income taxes payable.

In July 2016, Royale entered into negotiations for certain equity and debt financing transactions, described below. The funds from these transactions is to be used to continue drilling activities, fund expenses to be incurred in connection with completion of Royale Energy’s proposed merger with Matrix Oil Corporation and for general corporate purposes.  At December 31, 2016, the paperwork for these transactions had not been finalized and as such have been included as Cash Advances from Investors:

The Company entered in negotiations with two separate investors for convertible promissory notes 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 mature one year from the date of issuance and carry a 10% interest rate, which is due at maturity.  The conversion of the notes to shares is subject to shareholder approval.

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 year ended December 31, 2016.

ASU 2015-17: Income Taxes (Topic740) Balance Sheet Classification of Deferred Taxes – In November 2015, FASB issued ASU 2015-17 which eliminates the requirement to present deferred tax assets and liabilities as current and noncurrent amounts in a classified balance sheet. The new standard requires deferred tax assets and liabilities to be classified as noncurrent. The amendments in this update are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Earlier application is permitted for all entities as of the beginning of an interim or annual reporting period and may be applied either prospectively or retrospectively to all periods presented. In 2016, the Company adopted Accounting Standards Update (ASU) 2015-17 and has classified all of its deferred tax assets and liabilities as noncurrent on its balance sheet.  The adoption of this guidance has no impact on our results of operations or cash flows.

 

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 2016-13: Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. In June 2016, FASB issued ASU 2016-13 which was issued to provide more decision-useful information about the expected credit losses on financial instruments and changes the loss impairment methodology. To achieve this objective, the amendments in ASU 2016-13 replace the incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. The amendments affect entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance-sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash.  This pronouncement is effective for reporting periods beginning after December 15, 2019 using a modified retrospective adoption method. A prospective transition approach is required for debt securities for which an other-than-temporary impairment had been recognized before the effective date. The Company is currently evaluating the impact of the adoption of ASU 2016-13 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 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES

 

Oil and gas properties, equipment and fixtures consist of the following at December 31:

 

 

 

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

 

 

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 2016 or 2015. We did not charge any previously capitalized exploratory well costs to expense upon adoption of Topic.  Undeveloped properties are not subject to depletion, depreciation or amortization.

 

 

The results of operations from oil and gas producing and exploration activities (excluding corporate overhead and interest costs) for the two years ended December 31, are as follows: 

 

 

NOTE 3 - ASSET RETIREMENT OBLIGATION

 

The Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification requires that an asset retirement obligation (ARO) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset.  The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset.  The ARO is recorded at fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value.  The fair value of the ARO is measured using expected future cash outflows discounted at the Company’s credit-adjusted risk-free interest rate.  The provisions of this Topic apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, development, and operation of a long-lived asset.

 

 

NOTE 4 - TURNKEY DRILLING OBLIGATION

Royale Energy receives funds under turnkey drilling contracts, which require Royale Energy to drill oil and gas wells within a reasonable time period from the date of receipt of the funds.  As of December 31, 2016 and 2015, Royale Energy had recorded deferred turnkey drilling associated with undrilled wells of $7,894,001 and $8,415,528, respectively, as a current liability.

 

 

NOTE 6 - 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.  In 2016, the Company adopted Accounting Standards Update (ASU) 2015-17 and has classified all of its deferred tax assets and liabilities as noncurrent on its balance sheet.

Significant components of the Company’s deferred assets and liabilities at December 31, 2016 and 2015, respectively, are as follows:

 

A reconciliation of Royale Energy's provision for income taxes and the amount computed by applying the statutory income tax rates at December 31, 2016 and 2015, respectively, to pretax income is as follows: 

The components of the Company’s tax provision are as follows: 

 

In January 2007, Royale adopted additional provisions from the Income Taxes Topic of the FASB Accounting Standards Codification, which clarified the accounting for uncertainty in income taxes recognized in an entity’s financial statements and prescribes a recognition threshold and measurement attribute for financial statement disclosure of tax positions taken or expected to be taken on a tax return.  As a result of our implementation of the Topic at the time of adoption and at December 31, 2016, the Company did not recognize a liability for uncertain tax positions.  Currently, the only differences between our financial statements and our income tax returns relate to normal timing differences such as depreciation, depletion and amortization, which are recorded as deferred taxes on our balance sheets. We do not expect our unrecognized tax benefits to change significantly over the next 12 months. The tax years 2011 through 2015 remain open to examination by the taxing jurisdictions in which we file income tax returns.

 

NOTE 7 - SERIES AA PREFERRED STOCK

 

In April 1992, Royale Energy's Board of Directors authorized the sale of 147,500 shares of Series AA Convertible Preferred Stock.  The resolution authorizing the Series AA Convertible Preferred Stock provided for a stated value of $4 per share.  The Series AA Convertible Preferred Stock is convertible at the option of the security holder at the rate of one share of common stock for two shares of Series AA Convertible Preferred Stock.  The Series AA Preferred Stock has never been registered under the Securities Exchange Act of 1934, and no market exists for the shares.  No shares of Series AA Preferred Stock have been issued since the original shares were issued in 1992.  

 

As of September 30, 2016, Royale Energy’s transfer records reflected that certificates representing 46,662 shares of Series AA Preferred stock remained outstanding, but Royale Energy has lost contact with the registered holders of the Series AA Preferred Stock and does not have a means to communicate with them concerning the status of their shares. 

In November 2016, Royale entered into a securities purchase agreement with one vendor for the settlement an outstanding accounts payable of $25,000.  Under the terms of the agreement, Royale issued 76,923 shares of its Series AA convertible preferred stock at $0.325 per share.  On the basis of a resolution by the Board of Directors’, these Series AA shares were immediately converted to common stock on a one to one basis.

In late 2016, Royale Energy learned that the records of the Secretary of State of California do not reflect that a certificate of determination, amendment to the company’s articles of incorporation, or any other document had ever been filed with the Secretary of State authorizing the issuance of the Series AA Preferred Stock.  Royale Energy has reserved 23,331 shares of its common stock (the amount of common stock into which the Series AA Preferred shares would be convertible) for issuance to holders of the outstanding certificates for Series AA Preferred Stock at such time as Royale Energy is able to make contact with the Series AA Preferred shareholders.

 

NOTE 8 - COMMON STOCK

 

In April 2016, Royale entered in a securities purchase agreement and related agreements with one investor.  Under the terms of the agreement, the investor purchased 622,316 shares of Royale’s common stock at $0.3214 per share, and received warrants to purchase up to 311,158 shares (the “Warrants’) of stock at $0.5356 per share for three (3) years, for a total of $200,000 in gross proceeds.  In July 2016, Royale entered in securities purchase agreements and related agreements with three investors.  Under the terms of the agreement, the investors purchased 2,392,500 shares of Royale’s common stock at $0.40 per share, and received warrants to purchase up to 478,500 shares (the “Warrants’) of stock at $0.80 per share for two (2) years, for a total of $957,000 in gross proceeds.

In May 2015 and April 2014, Royale Energy entered into Sales Agreements with Roth Capital Partners, LLC (Roth), under which the Company had the ability to issue and sell shares of its common stock from time to time in an at the market equity offering program with Roth acting as the Company’s sales agent.  Royale Energy sold 701,397 shares of common stock for total consideration of $556,123 under the 2015 Sales Agreement and no shares of common stock under the 2014 Sales Agreement.  Both agreements have been terminated as of December 31, 2015.

On November 25, 2015, Royale Energy entered into a securities purchase agreement and related agreements with a group of individual investors pursuant to a registered direct offering.  Under the terms of the agreements, the investors purchased 497,948 shares of Royale’s common stock at $0.408 per share, and received warrants to purchase up to 248,973 shares (the “Warrants’) of stock at $1.00 per share for three (3) years, for a total of $203,165 in gross proceeds,.  Each Warrant becomes exercisable one year from the date of issuance.  Each Warrant contains customary adjustments for corporate events such as reorganizations, splits, and dividends.  The fair value of each warrant was estimated on the grant date using the Black-Scholes option-pricing model.  This model incorporates certain assumptions for inputs including a risk-free market interest rate, expected dividend yield of the underlying common stock, expected warrant life and expected volatility in the market value of the underlying common stock.  For these warrants, the value was calculated with the following assumptions: expected volatility of 78.96%, risk-free market interest rate of 1.13%, an expected term of 1,460 days, and an exercise price of $1.00.

NOTE 9 - OPERATING LEASES

 

Royale Energy occupies office space through the use of two leases, one for their office in El Cajon, CA and one for an office and yard in Woodland, CA.  The El Cajon lease is under a 62 month lease contract, with a yearly increase of 3.5%, which expires in January 2020. The El Cajon lease calls for monthly payments ranging from $6,148 to $10,801, and the Woodland lease calls for monthly payments of $500.  Royale rents an office and yard in Woodland, CA on a month-to-month basis that currently calls for monthly payments of $500.  Rental expense for the years ended December 31, 2016 and 2015 was $63,733 and $10,400 respectively. 

 

NOTE 10 - RELATED PARTY TRANSACTIONS

 

 

Harry E. Hosmer, Royale Energy’s chairman of the board of directors, is the father of Royale Energy executives Donald H. Hosmer, president of business development and director; and Stephen M. Hosmer, chief financial officer and director.

As of March 20, 2017, Donald H. Hosmer owned 6.84% of Royale Energy common stock (as calculated under SEC Rule 13d-3).  Donald Hosmer has participated individually in 179 wells under the 1989 policy.  During 2016, Donald participated in fractional interests of one well in the amount of $1,556 and in 2015 participated in fractional interests of two wells in the amount of $3,143.  At December 31, 2016, Royale had a receivable balance of $2,318 due from Donald Hosmer for normal drilling and lease operating expenses.

 

As of March 20, 2017, Stephen M. Hosmer owned 6.31% of Royale Energy common stock (as calculated under SEC Rule 13d-3).  Stephen Hosmer has participated individually in 179 wells under the 1989 policy.  During 2016, Stephen participated in fractional interests of one well in the amount of $1,556 and in 2015 participated in fractional interests of four wells in the amount of $4,389.  At December 31, 2016, Royale had a receivable balance of $12,912 due from Stephen Hosmer for normal drilling and lease operating expenses.

 

As of March 20, 2017, Harry E. Hosmer owned 7.18% of Royale Energy common stock (as calculated under SEC Rule 13d-3). During 2016, Harry Hosmer participated in fractional interests of one well in the amount of $1,556 and in 2015 participated in fractional interests of four wells in the amount of $5,633.  At December 31, 2016, Royale had a receivable balance of $6,459 due from Harry Hosmer for normal drilling and lease operating expenses.

 

NOTE 11 - STOCK COMPENSATION PLAN

 

A summary of the status of Royale Energy's stock option plan as of December 31, 2016 and 2015, and changes during the years ending on those dates is presented below:

 

 

At December 31, 2016, Royale Energy’s stock price, $0.62, was less than the weighted average exercise price, and as such the outstanding and exercisable stock options had no intrinsic value.  The remaining outstanding stock options have a weighted-average remaining contractual term of one year as of December 31, 2016. There were no stock options granted during 2016.

A summary of the status of Royale Energy's non-vested stock options as of December 31, 2016 and 2015, and changes during the years ending on those dates is presented below: