UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2015 | | Commission File No. 0-22750 |
ROYALE ENERGY, INC.
(Name of registrant in its charter)
| California | | 33-0224120 |
(State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
3777 Willow Glen Drive
El Cajon, CA 92019
(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:
Common Stock, no par value per share
(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 o No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes o No x
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 x No o
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 x No o
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. o
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 o Accelerated filer o
Non-accelerated filer o Smaller Reporting Company x
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).�� Yes o No x
At June 30, 2015, the end of the registrant’s most recently completed second fiscal quarter; the aggregate market value of common equity held by non-affiliates was $13,006,018.
At March 14, 2016, 17,616,663 shares of registrant's Common Stock were outstanding.
| PART I | | |
| | Item 1 | | 1 |
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| | | | 2 |
| | Item 1A | | 3 |
| | Item 1B | | 6 |
| | Item 2 | | 6 |
| | | | 7 |
| | | | 7 |
| | | | 7 |
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| | | | 8 |
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| | Item 3 | | 8 |
| | Item 4 | | 8 |
| PART II | | |
| | Item 5 | | 9 |
| | | | 9 |
| | | | 9 |
| | Item 6 | | 9 |
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| | | | 12 |
| | | | 13 |
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| | Item 7 | | 15 |
| | Item 8 | | 15 |
| | Item 9 | | 15 |
| | Item 9A | | 15 |
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| PART III | | |
| | Item 10 | | 17 |
| | Item 11 | | 19 |
| | Item 12 | | 22 |
| | Item 13 | | 23 |
| | Item 14 | | 24 |
| PART IV | | |
| | Item 15 | | 25 |
| | 26 |
| F-1 |
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, 2015, Royale Energy had 15 full time employees.
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, Louisiana, and Alaska. 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, 2015, 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 prospective shale oil property in Alaska. In 2015, Royale Energy drilled two wells in northern California; one was commercially productive and one was a dry hole. We also drilled one commercially productive well and one dry hole in Texas. Royale Energy's estimated total reserves were approximately 2.5 and 4.1 BCFE (billion cubic feet equivalent) at December 31, 2015 and 2014, 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 $3.2 million at December 31, 2015, based on natural gas prices ranging from $2.59 per MCF to $2.98 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, 2015, was estimated to be $1,559,716. 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 $2,330,969 and $1,640,731 for the years ended December 31, 2015 and 2014, 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 59.5% of Royale Energy's total revenue for the year ended December 31, 2015, came from sales of oil and natural gas from production of its wells in the amount of $1,018,928. In 2014, this amount was $2,598,297, which represented 80.7% of Royale Energy's total revenues.
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, 2015, Royale Energy earned gross revenues from operation of the wells in the amount of $503,441 representing 29.4% of its total revenues for the year. In 2014, the amount was $464,429, which represented about 14.4% of total revenues. At December 31, 2015, Royale Energy operated 52 natural gas wells in California. Royale also has non-operating interests in three natural gas wells in Utah, twelve oil and gas wells in Texas, two in Oklahoma, one in California, and one 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.
Royale Energy had no subsidiaries in 2015 or 2014.
Competition
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.
Markets
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.
Regulation
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 450 Fifth 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.
In addition to the other information contained in this report, the following risk factors should be considered in evaluating our business.
We Depend on Market Conditions and Prices in the Oil and Gas Industry.
Our success depends heavily upon our ability to market oil and gas production at favorable prices. In recent decades, there have been both periods of worldwide overproduction and underproduction of hydrocarbons and periods of increased and relaxed energy conservation efforts. As a result the world has experienced periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis; these periods have been followed by periods of short supply of, and increased demand for, crude oil and, to a lesser extent, natural gas. The excess or short supply of oil and gas has placed pressures on prices and has resulted in dramatic price fluctuations.
Natural gas demand and the prices paid for gas are seasonal. The fluctuations in gas prices and possible new regulations create uncertainty about whether we can continue to produce gas for a profit.
Prices for oil and natural gas affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of oil and natural gas that we can economically produce. Any substantial and extended decline in the price of oil or natural gas would decrease our cash flows, as well as the carrying value of our proved reserves, our borrowing capacity and our ability to obtain additional capital.
The Price of Natural Gas
Large parts of our established production and reserves in California consist of natural gas. The price of natural gas has been volatile recently, and for 2015 the average sales price we received for natural gas was $2.75 per MCF, compared to $4.64 in 2014. The decrease in our natural gas production and the lower gas prices resulted in a 60.8% decrease in natural gas revenues in 2015 when compared to 2014. See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations for the Twelve Months Ended December 31, 2015, as Compared to the Twelve Months Ended December 31, 2014.
Variance in Estimates of Oil and Gas Reserves could be Material.
The process of estimating oil and gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. As a result, such estimates are inherently imprecise. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves may vary substantially from those estimated in reserve reports that we periodically obtain from independent reserve engineers.
You should not construe the standardized measure of proved reserves contained in our annual report as the current market value of the estimated proved reserves of oil and gas attributable to our properties. In accordance with Securities and Exchange Commission requirements, we have based the standardized measure of future net cash flows from the standardized measure of proved reserves on the average price during the 12-month period before the ending date of the period covered by the report, whereas actual future prices and costs may vary significantly. The following factors may also affect actual future net cash flows:
| · | the timing of both production and related expenses; |
| · | changes in consumption levels; and |
| · | governmental regulations or taxation. |
In addition, the calculation of the standardized measure of the future net cash flows using a 10% discount as required by the Securities and Exchange Commission is not necessarily the most appropriate discount rate based on interest rates in effect from time to time and risks associated with our reserves or the oil and gas industry in general. Furthermore, we may need to revise our reserves downward or upward based upon actual production, results of future development, supply and demand for oil and gas, prevailing oil and gas prices and other factors.
Any significant variance in these assumptions could materially affect the estimated quantities and present value of our reserves. In addition, our standardized measure of proved reserves may be revised downward or upward, based upon production history, results of future exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control. Actual production, revenues, taxes, development expenditures and operating expenses with respect to our reserves will likely vary from the estimates used, and such variances may be material.
Future Acquisitions and Development Activities May Not Result in Additional Proved Reserves, and We May Not be Able to Drill Productive Wells at Acceptable Costs.
In general, the volume of production from oil and gas properties declines as reserves are depleted. Except to the extent that we acquire properties containing proved reserves or conduct successful development and exploration activities, or both, our proved reserves will decline as reserves are produced. Our future oil and gas production is, therefore, highly dependent upon our ability to find or acquire additional reserves.
The business of acquiring, enhancing or developing reserves is capital intensive. We require cash flow from operations as well as outside investments to fund our acquisition and development activities. If our cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be impaired.
The Oil and Gas Industry has Mechanical and Environmental Risks.
Oil and gas drilling and production activities are subject to numerous risks. These risks include the risk that no commercially productive oil or gas reservoirs will be encountered, that operations may be curtailed, delayed or canceled, and that title problems, weather conditions, compliance with governmental requirements, mechanical difficulties or shortages or delays in the delivery of drilling rigs and other equipment may limit our ability to develop, produce or market our reserves. New wells we drill may not be productive and we may not recover all or any portion of our investment in the well. Drilling for oil and gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. In addition, our properties may be susceptible to hydrocarbon drainage from production by other operators on adjacent properties.
Industry operating risks include the risks of fire, explosions, blow outs, pipe failure, abnormally pressured formations and environmental hazards, such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, the occurrence of any of which could result in substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean up responsibilities, regulatory investigation and penalties and suspension of operations. In accordance with customary industry practice, we maintain insurance for these kinds of risks, but we cannot be sure that our level of insurance will cover all losses in the event of a drilling or production catastrophe. Insurance is not available for all operational risks, such as risks that we will drill a dry hole, fail in an attempt to complete a well or have problems maintaining production from existing wells.
Drilling is a Speculative Activity Even with Newer Technology.
Assessing drilling prospects is uncertain and risky for many reasons. We have grown in the past several years by using 3-D seismic technology to acquire and develop exploratory projects in northern California, as well as by acquiring producing properties for further development. The successful acquisition of such properties depends on our ability to assess recoverable reserves, future oil and gas prices, operating costs, potential environmental and other liabilities and other factors.
Nevertheless, exploratory drilling remains a speculative activity. Even when fully utilized and properly interpreted, 3-D seismic data and other advanced technologies assist geoscientists in identifying subsurface structures but do not enable the interpreter to know whether hydrocarbons are in fact present. In addition, 3-D seismic and other advanced technologies require greater pre-drilling expenditures than traditional drilling strategies, and we could incur losses as a result of these costs.
Therefore, our assessment of drilling prospects are necessarily imprecise and their accuracy inherently uncertain. In connection with such an assessment, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Such a review, however, will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities.
Breaches of Contract by Sellers of Properties Could Adversely Affect Operations.
In most cases, we are not entitled to contractual indemnification for pre closing liabilities, including environmental liabilities, and we generally acquire interests in the properties on an "as is" basis with limited remedies for breaches of representations and warranties. In those circumstances in which we have contractual indemnification rights for pre-closing liabilities, the seller may not fulfill those obligations and leave us with the costs.
We May Not be Able to Acquire Producing Oil and Gas Properties Which Contain Economically Recoverable Reserves.
Competition for producing oil and gas properties is intense and many of our competitors have substantially greater financial and other resources than we do. Acquisitions of producing oil and gas properties may be at prices that are too high to be acceptable.
We Require Substantial Capital for Exploration and Development.
We make substantial capital expenditures for our exploration and development projects. We will finance these capital expenditures with cash flow from operations and sales of direct working interests to third party investors. We will need additional financing in the future to fund our developmental and exploration activities. Additional financing that may be required may not be available or continue to be available to us. If additional capital resources are not available to us, our developmental and other activities may be curtailed, which would harm our business, financial condition and results of operations.
Profit Depends on the Marketability of Production.
The marketability of our natural gas production depends in part upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. Most of our natural gas is delivered through natural gas gathering systems and natural gas pipelines that we do not own. Federal, state and local regulation of oil and gas production and transportation, tax and energy policies, and/or changes in supply and demand and general economic conditions could adversely affect our ability to produce and market its oil and gas. Any dramatic change in market factors could have a material adverse effect on our financial condition and results of operations.
We Depend on Key Personnel.
Our business will depend on the continued services of our executive officers, Jonathan Gregory, Chief Executive Officer, Donald H. Hosmer, President of Business Development and Stephen M. Hosmer, President and Chief Financial Officer. We do not have employment agreements with Jonathan Gregory, Donald or Stephen Hosmer. The loss of the services of any of these individuals would be particularly detrimental to us because of their background and experience in the oil and gas industry.
The Oil and Gas Industry is Highly Competitive.
The oil and gas industry is highly competitive in all its phases. Competition is particularly intense with respect to the acquisition of desirable producing properties, the acquisition of oil and gas prospects suitable for enhanced production efforts, and the hiring of experienced personnel. Our competitors in oil and gas acquisition, development, and production include the major oil companies in addition to numerous independent oil and gas companies, individual proprietors and drilling programs.
Many of our competitors possess and employ financial and personnel resources far greater than those which are available to us. They may be able to pay more for desirable producing properties and prospects and to define, evaluate, bid for, and purchase a greater number of producing properties and prospects than we can. We must compete against these larger companies for suitable producing properties and prospects, to generate future oil and gas reserves.
Governmental Regulations Can Hinder Production.
Domestic oil and gas exploration, production and sales are extensively regulated at both the federal and state levels. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, have legal authority to issue, and have issued, rules and regulations affecting the oil and gas industry which often are difficult and costly to comply with and which carry substantial penalties for noncompliance. State statutes and regulations require permits for drilling operations, drilling bonds, and reports concerning operations. Most states where we operate also have statutes and regulations governing conservation matters, including the unitization or pooling of properties. Our operations are also subject to numerous laws and regulations governing plugging and abandonment, discharging materials into the environment or otherwise relating to environmental protection. The heavy regulatory burden on the oil and gas industry increases its costs of doing business and consequently affects its profitability. Changes in the laws, rules or regulations, or the interpretation thereof, could have a materially adverse effect on our financial condition or results of operation.
Minority or Royalty Interest Purchases Do Not Allow Us to Control Production Completely.
We sometimes acquire less than the controlling working interest in oil and gas properties. In such cases, it is likely that these properties would not be operated by us. When we do not have controlling interest, the operator or the other co-owners might take actions we do not agree with and possibly increase costs or reduce production income in ways we do not agree with.
Environmental Regulations Can Hinder Production.
Oil and gas activities can result in liability under federal, state and local environmental regulations for activities involving, among other things, water pollution and hazardous waste transport, storage, and disposal. Such liability can attach not only to the operator of record of the well, but also to other parties that may be deemed current or prior operators or owners of the wells or the equipment involved. We have inspections performed on our properties to assure environmental law compliance, but inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken.
We may need to raise additional capital to continue operations.
We may require additional funding to complete our planned drilling activities. It may be necessary for us to raise additional capital to fund our drilling program or other operating capital needs through additional financing such as the sale of equity or debt securities in a public offering or through private placements of securities. We do not know if additional financing will be available when needed, or if it is available, whether it will be available on acceptable terms. Insufficient capital and liquidity may prevent or limit us from implementing our full business strategy.
Item 1B Unresolved Staff Comments
None
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 2015, Royale Energy drilled two wells in northern California, one exploratory producing well and one exploratory dry hole. We also drilled two wells in Texas, one developmental producing and one developmental dry hole.
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.
In December of 2013, Royale purchased an office building valued at $2,000,000, of which Royale paid $500,000 in cash on the date of purchase, and borrowed $1,500,000 from American West Bank, with a note secured by the property being purchased. The note carries an interest rate of 5.75% until paid in full with a balloon payment in 2024. On February 11, 2016, Royale Energy, Inc. entered into a purchase and sale agreement for the sale of its office building for $2.5 million. The buyer is currently conducting its due diligence process.
Following is a discussion of Royale Energy's significant oil and natural gas properties. Reserves at December 31, 2015, 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 1, 2016.
Royale Energy owns lease interests in nine gas fields with locations ranging from Tehama County in the north to Kern County in the south, in the Sacramento and San Joaquin Basins in California. At December 31, 2015, Royale operated 52 wells in California with estimated total proven, developed, and undeveloped reserves at approximately 2.5 BCF, according to Royale’s independently prepared reserve report as of December 31, 2015.
As of December 31, 2015, Royale Energy owned leasehold interests in the following developed and undeveloped properties in both gross and net acreage.
| | | Developed | | | Undeveloped | |
| | | Gross Acres | | | Net Acres | | | Gross Acres | | | Net Acres | |
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Gross and Net Productive Wells
As of December 31, 2015, Royale Energy owned interests in the following oil and gas wells in both gross and net acreage:
The following table sets forth Royale Energy's drilling activities during the years ended December 31, 2014 and 2015. All wells are located in the Continental U.S., in California, Texas, Louisiana and Utah.
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| Year | | Type of Well(a) | | | | | Gross Wells(b) | | | Net Wells(e) | |
| | | | | Total | | | Producing(c) | | | Dry(d) | | | Producing(c) | | | Dry(d) | |
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| a) | An exploratory well is one that is drilled in search of new oil and natural gas reservoirs, or to test the boundary limits of a previously discovered reservoir. A developmental well is one drilled on a previously known productive area of an oil and natural gas reservoir with the objective of completing that reservoir. |
| b) | Gross wells represent the number of actual wells in which Royale Energy owns an interest. Royale Energy's interest in these wells may range from 1% to 100%. |
| c) | A producing well is one that produces oil and/or natural gas that is being purchased on the market. |
| d) | A dry well is a well that is not deemed capable of producing hydrocarbons in paying quantities. |
| e) | One "net well" is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as a whole number or a fraction. |
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.
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Net production costs and taxes | | | | | | | | |
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Net Proved Oil and Natural Gas Reserves
As of December 31, 2015, Royale Energy had proved developed reserves of 2,174 MMCF and total proved reserves of 2,511 MMCF of natural gas on all of the properties Royale Energy leases. For the same period, Royale Energy also had no proved developed oil and natural gas liquid combined reserves.
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.
Royale Energy, Inc. vs. Rampart Alaska LLC, Superior Court, Nome, Alaska. On November 14, 2014, Royale Energy, Inc. caused a complaint for lien foreclosure to be filed in the Superior Court for the State of Alaska, Second Judicial District at Nome. Royale Energy caused certain liens to be filed against the working interests of Rampart Alaska LLC involving oil leases on the North Slope Alaska. The filing of the liens came about as the result of Rampart’s failure to reimburse for joint interest billings and cash calls. Royale sought in the litigation to foreclose the liens to recover the sums secured thereby or the working interests themselves. Rampart Alaska answered the complaint and asserted a counterclaim against Royale for damages alleging breach of contract, violation of the covenant of good faith and fair dealing, unjust enrichment, defamation, violations of the Alaska Securities Act and seeking to undo the filing of the lien claims. Stephen Hosmer, as an officer of Royale, was also independently named as a third party defendant by Rampart for claims arising out of defamation and violation of the Alaska Securities Act. On September 25, 2015, Royale and Rampart Alaska, LLC entered into a settlement agreement in which Rampart assigned its interest in the Property to Royale, and Rampart received cash and a note totaling $500,000. The note was subsequently repaid in November 2015 when Royale Energy sold the property, and the litigation between the parties has been concluded.
Hemco Development LLC vs. Royale Energy, Inc., et al, 44th Judicial District, Dallas County, Texas, Case No. DC-15-10958. On September 14, 2015, Hemco Development, LLC (“Hemco”) filed a complaint, asserting that the Company owed Hemco $451,080.10 for the Company’s share of operating costs. While this amount is already included in its Accounts Payable, the Company disputes that this amount is owed or that the claimed costs were properly incurred. The Company has answered the complaint and intends to vigorously defend the lawsuit.
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, 2015, 16,396,579 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 from January 2014 through December 2015.
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| | | High | | | Low | | | High | | | Low | | | High | | | Low | | | High | | | Low | |
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The Board of Directors did not issue cash or stock dividends in 2015 or 2014.
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.
For the past twenty-three years, 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.
Revenue Recognition
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.
Oil and Gas Property and Equipment
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 2015 and 2014, impairment losses of $424,163 and $268,093, 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 due to the permitting process or drilling rig availability. At December 31, 2015 and 2014, Royale Energy had deferred drilling obligations of $8,415,528 and $7,937,786 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.
Estimates
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
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, 2015, as Compared to the Twelve Months Ended December 31, 2014
For the year ended December 31, 2015, we recorded a net loss of $2,010,816, a $141,040 improvement when compared to net loss of $2,151,856 during 2014. Total revenues from operations in 2015 were $1,713,088, a decrease of $1,508,410, or 46.8% from the total revenues of $3,221,498 in 2014, due to lower natural gas production and the industry wide decrease in commodity prices during 2015. Total expenses for operations in 2015 were $6,937,741, a decrease of $337,590, or 4.6%, from the total expenses of $7,275,331 in 2014, due mainly to decreases in lease operating expenses and delay rental costs.
In 2015, revenues from oil and gas production decreased by 60.8% to $1,018,928 from $2,598,297 in 2014. This decrease was due to lower production volumes and lower natural gas commodity prices received during 2015. The net sales volume of natural gas for the year ended December 31, 2015, was approximately 363,168 MCF with an average price of $2.75 per MCF, versus 547,898 MCF with an average price of $4.64 per MCF for 2014. This represents a decrease in net sales volume of 184,730 MCF or 33.7%. This decrease in production volume was mainly due to the natural declines in our wells. The net sales volume for oil and condensate (natural gas liquids) production was approximately 403 barrels with an average price of $46.11 per barrel for the year ended December 31, 2015, compared to 685 barrels at an average price of $85.20 per barrel for the year in 2014. This represents a decrease in net sales volume of 282 barrels, or 41.2%, also due to the natural declines on existing oil and condensate wells. Northern and central California accounted for approximately 98% of the Company’s successful natural gas production in 2015.
Oil and natural gas lease operating expenses decreased by $426,904, or 29.9% to $1,000,769 for the year ended December 31, 2015, from $1,427,673 for the year in 2014. This decrease was due to lower plugging and abandonment costs and workover related costs in 2015. During 2014, two wells that were plugged and abandoned had much higher costs than anticipated. In addition, we had more workover activity in 2014 as we attempted to increase production on various wells. When measuring lease operating costs on a production or lifting cost basis, in 2015, the $1,000,769 equates to a $2.74 per MCFE lifting cost versus a $2.59 per MCFE lifting cost in 2014, a 5.8% increase, due to lower production volumes. Delay rental costs decreased by $168,493 or 27.3%, to $448,313 for the year in 2015 from $616,806 in 2014. This decrease was due to lower costs related to our ownership of our Alaska leases, some of which we chose not to renew and a portion of which was sold during 2015.
At December 31, 2015, Royale Energy had a deferred drilling obligation of $8,415,528. 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. During 2014, we disposed of $4,172,296 of obligations relating to 2013, upon completing the drilling of four wells, two exploratory and two developmental, in addition to participating in the drilling of one additional well with an industry partner. There was also an adjustment of approximately $550,000 of accrued costs on a well where the additional work would no longer prove viable. These factors resulted in a gain of $1,640,731. Royale Energy expects to dispose of approximately $3.4 million of its deferred drilling obligation in the first six months of 2016 with $5.5 million of its deferred drilling obligation disposed of by the end of 2016.
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. During 2014, we recorded a gain of $369,977 on the sale of certain oil and natural gas leases in Utah. In 2014, we also recorded a loss of $34,601 on previously capitalized office leasehold improvements due to our office relocation.
Impairment losses of $424,163 and $268,093 were recorded in 2015 and 2014, respectively. In 2015, $327,727 of the impairment loss was due to two Utah wells, one Louisiana well, and our remaining Alaska acreage where the carrying value exceeded the fair value. In 2014, $217,629 of the impairment loss was due to two Utah wells where the carrying value exceeded the fair value. For the balance of the loss in 2015 and the 2014, we recorded impairments on various capitalized lease and land costs that were no longer viable.
Bad debt expense for 2015 and 2014 were $536,538 and $653,133, respectively. The expenses in 2015 and 2014 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 $694,160 for the year ended December 31, 2015, an increase of $70,959 or 11.4% from $623,201 during the year in 2014. This increase was mainly due to lower costs in 2015 associated with pipeline and compressor fees due to costs to rebuild a compressor in one of our main fields during 2014. 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 increased $39,012 or 8.4%, to $503,441 in 2015 from $464,429 in 2014.
Depreciation, depletion and amortization expense increased to $400,813 from $315,574 an increase of $85,239 or 27.0% for the year ended December 31, 2015, as compared to 2014. The depletion rate is calculated using production as a percentage of reserves. This increase in depreciation expense was mainly due to a higher depletion rate as reserve volumes were lower at the end of 2015.
General and administrative expenses increased slightly by $19,458 or 0.6%, to $3,181,571 for the year ended December 31, 2015, from $3,162,113 for the year in 2014. This increase was primarily due to higher market fees relating to its market equity offering issuances. Legal and accounting expense increased to $558,471 for the year, compared to $401,160 for 2014, a $157,311 or 39.2% increase. The increased expense was the result of higher legal fees primarily related to the Rampart litigation, which was settled at the end of 2015.
Marketing expense for the year ended December 31, 2015, decreased $104,636 or 24.3%, to $326,143, compared to $430,779 for the year in 2014. The decrease was due to higher broker fees paid in 2014 as we used an outside broker to sell direct working interests to investors.
During 2015, interest expense increased to $86,088 from $81,605 in 2014, a $4,483 or 5.5% increase. This increase resulted from interest paid on the outstanding loan for the corporate headquarters. Further details concerning Royale’s notes payable can be found in Capital Resources and Liquidity, below.
In 2015 and 2014, 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, 9.3%).
At December 31, 2015, Royale Energy had current assets totaling $4,406,983 and current liabilities totaling $11,383,282, a $6,976,299 working capital deficit. We had cash and cash equivalents at December 31, 2015 of $3,763,819 compared to $3,061,841 at December 31, 2014.
Ordinarily, we fund our operations and cash needs from our available credit and cash flows generated from operations. We believe that for the foreseeable future we will be able to meet our liquidity demands through cash flow or financing activities, including ongoing operations as the Company continues to increase its well inventory or additional sales of equity or debt securities.
At December 31, 2015, our other receivables, which consist of receivables from direct working interest investors and industry partners, totaled $381,192, compared to $1,760,181 at December 31, 2014, a $1,378,989 or 78.3% decrease. This was primarily due to the litigation settlement with an industry partner, which removed approximately $1,200,000 in other receivables at year end 2015. Royale’s revenue receivable at the end of 2015 was $147,936, a decrease of $345,359 or 70.0%, compared to $493,295 at the end of 2014, due to lower oil and gas production and commodity prices. At December 31, 2015, our accounts payable and accrued expenses totaled $2,937,226, a decrease of $1,565,333 or 34.8% over the accounts payable at the end of 2014 of $4,502,559, mainly due to lower trade accounts payable at the end of 2015.
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.
In December of 2013, Royale purchased an office building valued at $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 carries an interest rate of 5.75% until paid in full. Royale will pay this loan in 119 regular payments of $9,525 each and one balloon payment estimated at $1,150,435. Royale’s final payment will be due on January 1, 2024, and will be for all principal and all accrued interest not yet paid. Payments include principal and interest. Stephen M Hosmer, President and CFO is named as a personal guarantor of the loan. At December 31, 2015, the outstanding balance of this note was $1,446,853. The loan agreement contains certain covenants that, among other things, Royale must maintain a ratio of EBITDA-Debt Service Coverage in excess of 1.50 to 1.00. At December 31, 2015, Royale was not in compliance with this covenant, but obtained a forbearance from the bank from terms of that covenant. On February 11, 2016, Royale Energy entered into a purchase and sale agreement for the sale of the office building for $2.5 million. The buyer is currently conducting their due diligence process prior to completion of the sale.
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, 2015, and the effect such obligations are expected to have on our liquidity and cash flow in future periods.
| | | Total Obligations | | | 2016 | | | 2017-2018 | | | 2019 | | | Beyond | |
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Operating Activities. For the years ended December 31, 2015 and 2014, cash used by operating activities totaled $3,495,438 and $3,151,949, respectively. This $343,489 increase in cash used was mainly due to the decrease in our trade accounts payable during the year in 2015, through a combination of payments and settlements with our vendors.
Investing Activities. For the year ended December 31, 2015 and 2014, cash provided by investing activities was $3,537,137 and $1,359,673, respectively. This $2,177,464 increase in cash provided in 2015 was primarily due to the sale of a portion of our leases in Alaska, from which we received proceeds of approximately $1.4 million. In 2015, we also received approximately $400,000 from the sale of a license agreement to our Alaska seismic survey and we received proceeds of approximately $500,000 from the sale of the company owned condominium located in San Diego, California. Additionally, our turnkey drilling program proceeds and expenditures were higher in 2015, when we drilled four wells and purchased an interest in an existing well, while in 2014 we drilled four wells and participated in the drilling of one well. The wells drilled in 2015 were higher in costs due to their locations and depths.
Financing Activities. Net cash provided by financing activities totaled $660,279 and net cash used by financing activities was $24,116 for the years ended December 31, 2015 and 2014, respectively. This difference was mainly due to the proceeds received during 2015 for common stock sales. During 2015, Royale issued 701,397 shares of its common stock and received net proceeds of $534,274 in a registered market equity offering program. Also in 2015, we received net proceeds of $153,876 and issued 485,486 shares of its common stock and 242,746 additional warrants in a registered direct offering. These proceeds were added to working capital and used for ordinary operating expense. In 2015 and 2014, cash used from financing activities was used in principal payments from the loan used to finance the purchase of our corporate headquarters.
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 was primarily due to seven California wells and one Utah well, which had lower than previously estimated proved producing and non-producing natural gas reserves. See Supplemental Information about Oil and Gas Producing Activities (Unaudited), page F-20.
During 2014, our overall proved developed and undeveloped reserves increased by 6% and our previously estimated proved developed and undeveloped reserve quantities were revised downward by approximately 0.1 million cubic feet of natural gas. This downward revision was primarily due to two California wells, one drilled in 2013 and the other drilled in 2014, which had lower than previously estimated proved producing and proved undeveloped natural gas reserves. 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 2015, we sold a majority of our natural gas at the daily market rate through the Pacific Gas & Electric pipeline. In 2015, our natural gas revenues were approximately $1.0 million with an average price of $2.75 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 $100,000. At our current production levels of oil and natural gas condensate, a 10% increase or decrease in our average price per barrel could potentially increase or decrease our oil and natural gas revenues by approximately $2,000. 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 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 2015 fiscal year. Based on their evaluation, they concluded that our disclosure controls are effective as of December 31, 2015.
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, 2015, 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.
Based on our assessment, management has concluded 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. 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 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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
All of our directors serve one year terms from the time of their election to the time their successor is elected and qualified. The following information is furnished with respect to each director and executive officer who served as such during the fiscal year ended December 31, 2015:
| Name | | Age | | | First Became Director or Executive Officer | | Positions Held |
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| | | | | | | |
| | | | | | | President of Business Development and Director |
| | | | | | | President, Chief Financial Officer, Secretary, and Director |
| | | | | | | |
| | | | | | | Chief Executive Officer and Director |
Gary Grinsfelder (1) (2) (3) | | | | | | | |
| | | | | | | |
(1) Member of the audit committee.
(2) Member of the compensation committee.
(3) Member of the nominations committee.
The board has determined that directors Gary Grinsfelder, Ronald Buck, and Ronald Verdier qualify as independent directors.
The following summarizes the business experience of each director and executive officer for the past five years.
Harry E. Hosmer – Chairman of the Board
Harry E. Hosmer has served as chairman since Royale Energy began in 1986, and from inception in 1986 until June 1995, he also served as president and chief executive officer.
Jonathan Gregory – Chief Executive Officer and Director
Mr. Gregory was appointed Royale’s chief executive officer on September 10, 2015. Mr. Gregory has previously served as chief financial officer for private independent exploration and production companies, where he was actively engaged in multiple debt and equity financings, and overseeing acquisition and development activities. Mr. Gregory has over 20 years of oil and gas reserve based lending experience. Mr. Gregory is a member of Houston Energy Finance Group; and ADAM Houston Energy Network. He is also a Co-Founder of Bread of Life, Inc., a non-profit organization committed to empowering homeless Houstonians; and a past director of Small Steps Nurturing Center, a non-profit Christian organization that provides early childhood education for economically at-risk children in the inner-city of Houston, Texas. Mr. Gregory graduated from Lamar University in 1986 with a Bachelors degree in Finance.
Donald H. Hosmer – President of Business Development and Director
Donald H. Hosmer has served as an executive officer and director of Royale Energy since its inception in 1986. In June 1995 he became president and chief executive officer. In October 2008, he became co-president and co-chief executive officer, with primary responsibility for marketing and investor/shareholder relations for the company. Donald H. Hosmer is the son of Harry E. Hosmer and brother of Stephen M. Hosmer.
Stephen M. Hosmer – President, Chief Financial Officer, Secretary, and Director
Stephen M. Hosmer joined Royale Energy as the management information systems manager in May 1988, responsible for developing and maintaining Royale Energy’s computer software. Mr. Hosmer developed programs and software systems used by Royale Energy. From 1991 to 1995, he served as president of Royale Operating Company, Royale Energy’s operating subsidiary. In 1995, he became chief financial officer of Royale Energy. In 1996, he was elected to the board of directors of Royale Energy. In 2003, he was elected executive vice president. In October 2008, he became co-president and co-chief executive officer with primary responsibility for oil and gas exploration operations. Mr. Hosmer served seven years on the board of directors of Youth for Christ, a charitable organization in San Diego, California. He currently serves on the board of Venture Expeditions (www.ventureexpeditions.org), a charitable organization based in Minneapolis MN. Stephen M. Hosmer is the son of Harry E. Hosmer and brother of Donald H. Hosmer. Mr. Hosmer holds a Bachelor of Science degree in Business Administration from Oral Roberts University in Tulsa, Oklahoma, as well as earning his MBA degree via the prestigious President/Key Executive program at Pepperdine University in Malibu, California.
Gary Grinsfelder – Director
Mr. Grinsfelder is a geologist and manager with 38 years’ experience in oil and gas exploration, exploitation and property evaluation. Currently Mr. Grinsfelder is an independent industry consultant. Previously, Mr. Grinsfelder was Vice President of Exploration at LeFrak Energy and President of TXCO Resources. He has also served in geologic and management roles for Output Exploration, LLC, Araxas Exploration, Inc., Triad Energy Corporation, Spartan Petroleum Corporation, American Petrofina Company of Texas, Union Oil Company of California and Degolyer and MacNaughton. He received a Bachelor of Science degree in 1972 from Southern Methodist University and has performed graduate studies at the University of Puerto Rico Department of Marine Science and University of Houston Department of Geology.
Ronald B Verdier
Mr. Verdier was appointed to the board in 2015 following the resignation of Tony Hall. Mr. Verdier is a retired banker who began his career in banking in 1968. He served as an employee and officer of Mercantile Trust & Savings Bank, Quincy, Illinois, for thirty-three years, ending as Senior Vice President. In 2002, Mr. Verdier retired from Mercantile Trust & Savings Bank and became President of Hannibal National Bank, Hannibal Missouri, where he served until his retirement in 2012. Mr. Verdier is a graduate of the School of Banking at the University of Wisconsin, Madison, and of the School of Banking at the University of Oklahoma. Based on his qualifications, the board of directors has designated Mr. Verdier as an audit committee financial expert.
Ronald L. Buck
Mr. Buck was elected to the board in 2015. Mr. Buck received a Bachelor of Science degree in Marketing and a Minor in Geology and Economics from Northwestern University. After building his business into a large scale distribution company, he sold the company to his two sons in 1992. Since 1992 he has been in finance and managing family assets including oil and gas wells and oil gathering pipeline investments. In this capacity, he also travels extensively to financial meetings and is a member of the National Association of Financial Advisors.
Audit Committee
The board has appointed an audit committee to assist the board of directors in carrying out its responsibility as to the independence and competence of the Company’s independent public accountants. All members of the audit committee are independent members of the board of directors. The audit committee operates pursuant to an audit committee charger, which has been adopted by the board of directors to define the committee’s responsibilities. A copy of the audit committee charter is posted on our website, www.royl.com The board has determined that Ronald Verdier qualifies as an “audit committee financial expert” as defined in Item 407(d)(5) of the Securities and Exchange Commission.
At the end of 2015, the members of the audit committee were Ronald Verdier, chair, Ronald Buck and Gary Grinsfelder.
Code of Business Conduct and Ethics
We have adopted a code of business conduct and ethics for our directors and executive officers. The code is posted on our website, www.royl.com.
Compliance with Section 16(a) of the Exchange Act
Section 16(a) of the Securities Exchange Act of 1934 and Securities and Exchange Commission regulations require that Royale Energy's directors, certain officers, and greater than 10 percent shareholders file reports of ownership and changes in ownership with the SEC and the NASD and furnish Royale Energy with copies of all such reports they file. Based solely upon a review of the copies of the forms furnished to Royale Energy, or representations from certain reporting persons that no reports were required, Royale Energy believes that no persons failed to file required reports on a timely basis for 2015, except that the initial ownership report of Mr. Buck on Form 3 was filed late, in January 2016, after his election to the board in June 2015.
Item 11 Executive Compensation
The following table summarizes the compensation of the chief executive officer, chief financial officer and the two other most highly non-executive employees (the “named executives and employees”) of Royale Energy and its subsidiaries during the past year. No stock options, stock awards or other plan based compensation awards were made during 2015.
| | | | | | | | | | | | | | All Other | | | | |
| Name and Principal Position | | Year | | Salary (4) | | | Bonus | | | Option Awards (1) | | | Compensation (2) | | | Total | |
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Jonathan Gregory, CEO (4) (5) | | | | | | | | $ | - | | | | | | | | - | | | | | |
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| | | | | | | | | $ | | | | | | | | | | | | | | |
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| | | | | | | | $ | - | | | | | | | | | | | | | |
| | | | | | | | $ | - | | | | | | | | | | | | | |
| | | | | | | | | $ | - | | | | | | | | | | | | | |
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| | (1) | In October 2014, Donald Hosmer and Stephen Hosmer (together with the other members of the board of directors) were each granted 20,000 options to purchase common stock at an exercise or base price of $5.00 per shares, which vested during 2015. These options were granted for a period of 3 years and will expire on December 31, 2017. At December 31, 2015, Royale Energy’s stock price, $0.358, was less than the weighted average exercise price, and as such the outstanding and exercisable stock options had no intrinsic value. |
| | (2) | All other compensation consists of matching contributions to the Company’s simple IRA plan, except for Donald H. Hosmer and Stephen M. Hosmer, who also received a $12,000 car allowance. |
| | (3) | Mr. Abdel-Rahmen and Mr. Tiano are highly compensated employees under SEC rules who did not serve as executive officers during 2015. Mr Abdel-Rahmen retired from the Company in October 2015. |
| | (4) | During 2015, Jonathan Gregory and Stephen Hosmer received a portion of their compensation in shares of common stock, valued at the closing market price on the date of grant, instead of cash. Of the $70,823 paid to Jonathan Gregory, $21,581 was paid in cash and 108,644 shares of common stock were issued, valued at $49,242. Of the $230,192 paid to Stephen Hosmer, $173,945 was paid in cash and 200,564 share of common stock were issued, valued at $56,247. |
| | (5) | Mr. Gregory was appointed CEO (principal executive officer) in 2015. |
Stock Options and Equity Compensation; Outstanding Equity Awards at Fiscal Year End
The following table presents the number of unexercised options at the 2015 year end for each named executive officer. No unvested stock awards were outstanding at the end of 2015.
| Options |
| Name | | Number of securities underlying unexercised options (#) exercisable | | | Number of securities underlying unexercised options (#) unexercisable | | | Option exercise price ($) | | Option expiration date |
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| (1) | At the October 10, 2014 Board of Directors meeting, directors of Royale Energy were granted 20,000 options each to purchase common stock at an exercise price of $5.00 per share. These options have become exercisable and will expire on December 31, 2017. |
Compensation Committee Report
Our executive compensation committee has reviewed and discussed the following Compensation Discussion and Analysis with management and, based on its discussion and review, has recommended that the Compensation Discussion and Analysis be included in this proxy statement.
Members of the Compensation Committee:
Ronald Buck and Gary Grinsfelder
All members of the compensation committee are independent members of the board of directors.
Compensation Discussion and Analysis
Our executive compensation policy is designed to motivate, reward and retain the key executive talent necessary to achieve our business objectives and contribute to our long-term success. Our compensation policy for our executive officers focuses primarily on determining appropriate salary levels and performance-based cash bonuses.
The elements of executive compensation at Royale Energy consist mainly of cash salary and, if appropriate, a cash bonus at year end. The compensation committee makes recommendations to the board of directors annually on the compensation of the three top executives: Jonathan Gregory, Chief Executive Officer, Donald H. Hosmer, President of Business Development and Stephen M. Hosmer, President and Chief Financial Officer. We do not have employment contracts with either of our executive officers.
Royale Energy also does not provide extensive personal benefits to its executives beyond those benefits, such as health insurance, that are provided to all employees. Donald Hosmer and Stephen Hosmer each receive an annual car allowance.
Policy
The compensation committee’s primary responsibility is making recommendations to the board of directors relating to compensation of our officers. The committee also makes recommendations to the board of directors regarding employee benefits, our defined benefit plans, defined contribution plans, and stock based plans.
Determination
To determine executive compensation, the committee, in December each year, meets with our officers to review our compensation programs, discuss the performance of the company, the duties and responsibilities of each of the officers pay levels and business results compared to others similarly situated within the industry. The committee then makes recommendations to the board of directors for any adjustment to the officers’ compensation levels. The committee does not employ compensation consultants to make recommendations on executive compensation.
Compensation Elements
Base. Base salaries for our executive officers are established based on the scope of their responsibilities, taking into account competitive market compensation paid by our peers. Base salaries are reviewed annually. The salaries we paid to our most highly paid executive officers for the last three years are set forth in the Summary Compensation Table included under Executive Compensation.
Bonus. The compensation committee meets annually to determine the quantity, if any, of the cash bonuses of executive officers. The amount granted is based, subjectively, upon the company’s stock price performance, earnings, revenue, reserves and production. The committee does not use quantifiable metrics for these criteria; but rather uses each in balance to assess the strength of the company’s performance. The committee believes that formulaic approaches to cash incentives can foster an unhealthy balance between short-term and long-term goals. In 2014, the compensation committee did award bonuses to the company’s executive officers, Stephen and Don Hosmer, in the amount of $25,000 to each officer. No bonuses were paid to executive officers in 2015.
Compensation of Directors
In 2015, board members or committee member received fees for attendance at board meetings or committee meetings during the year. In addition to cash payments, common stock was issued in lieu of compensation or reimbursements. Royale Energy also reimbursed directors for the expenses incurred for their services.
In addition, Royale Energy's Chairman of the Board and former President, Harry E. Hosmer, renders and receives compensation for management consulting services to Royale Energy on an ongoing basis. See Certain Relationships and Related Transactions, page 23.
The following table describes the compensation paid to our directors who are not also named executives for their services in 2015.
| Name | | Fees earned or paid in cash or Common Stock | | | Stock awards | | | Option awards | | | All Other Compensation (1) | | | Total | |
| | | ($) | | | ($) | | | ($) | | | ($) | | | ($) | |
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| (1) | Other compensation paid to Harry E. Hosmer in 2015 consisted of payments for medical and dental insurance coverage. |
| (2) | Harry E. Hosmer’s compensation in 2015 includes compensation of $13,854, which was paid by the issuance of 49,768 shares of Royale’s common stock. The stock was valued at the closing market prices on the dates immediately preceding their issuance. |
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Common Stock
On February 23, 2016, 17,303,831 shares of Royale Energy’s common stock were outstanding.
The following table contains information regarding the ownership of Royale Energy’s common stock as of February 23, 2016, by:
| i) | each person who is known by Royale Energy to own beneficially more than 5% of the outstanding shares of each class of equity securities; |
| ii) | each director of Royale Energy, and |
| iii) | all directors and officers of Royale Energy as a group. Except pursuant to applicable community property laws and except as otherwise indicated, each shareholder identified in the table possesses sole voting and investment power with respect to its or his shares. The holdings reported are based on reports filed with the Securities and Exchange Commission and the Company by the officers, directors and 5% shareholders pursuant to Section 16 of the Securities Exchange Act of 1934. |
| Stockholder (1) | | Number (2) | | | Percent | |
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Donald H. Hosmer, (2) (3) | | | | | | | | |
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Stephen M. Hosmer, (2) (3) (4) | | | | | | | | |
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All officers and directors as a group | | | | | | | | |
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(1) The mailing address of each listed stockholder is 3777 Willow Glen Drive, El Cajon, California 92019.
(2) Includes options to purchase the following number of shares of common stock which were vested and exercisable on March 6, 2016: Harry E. Hosmer 20,000, Donald H. Hosmer 20,000; Stephen M. Hosmer 20,000; Gary Grinsfelder 20,000; Jonathan Gregory 20,000.
(3) Donald H. Hosmer and Stephen M. Hosmer are sons of Harry E. Hosmer, chairman of the board.
(4) Includes 24,000 shares owned by Stephen M. Hosmer’s minor children.
Preferred Stock
Holders Series AA convertible preferred stock have voting rights equal to the number of shares into which they are convertible. On December 31, 2015, 46,662 shares of Series AA convertible preferred stock were outstanding. The shares of each series of preferred shares are convertible into shares of Royale Energy's common stock at the option of the security holder, at the rate of two shares of convertible preferred stock for each share of common stock. The preferred stock is not registered under the Securities Exchange Act of 1934, and no market exists for the preferred stock. The total number of shares of common stock issuable on conversion of all outstanding shares of preferred stock equals less than 1% of the outstanding common stock of Royale Energy. To Royale Energy's knowledge, none of the preferred shareholders would own more than 1% of Royale Energy's common stock, if their preferred shares were converted to common shares.
Item 13 Certain Relationships and Related Transactions
In 1989, the board of directors adopted a policy (the “1989 policy”) that permits each director and officer of Royale Energy to purchase from Royale Energy, at its cost, up to one percent (1%) fractional interest in any well to be drilled by Royale Energy. When an officer or director elects to make such a purchase, the amount charged per each percentage working interest is equal to Royale Energy's actual pro rata cost of drilling and completion, rather than the higher amount that Royale Energy charges to working interest holders for the purchase of a percentage working interest in a well. Of the current officers and directors, Donald Hosmer, Stephen Hosmer and Harry E. Hosmer at various times have elected under the 1989 policy to purchase interests in certain wells Royale Energy has drilled.
Under the 1989 policy, officers and directors may elect to participate in wells at any time up until drilling of the prospect begins. Participants are required to pay all direct costs and expenses through completion of a well, whether or not the well drilling and completion expenses exceed Royale Energy's cost estimates, instead of paying a set, turnkey price (as do outside investors who purchase undivided working interests from Royale Energy). Thus, they participate on terms similar to other oil and gas industry participants or joint venturers. Participants are invoiced in advance for their share of estimated direct costs of drilling and completion and later actual costs are reconciled, as Royale Energy incurs expenses and participants make further payments as necessary.
Officer and director participants under this program do not pay some expenses paid by outside, retail investors in working interests, such as sales commissions, if any, or marketing expenses. The outside, turnkey drilling agreement investors, on the other hand, are not obligated to pay additional costs if a drilling project experiences cost overruns or unanticipated expenses in the drilling and completion stage. Accordingly, Royale Energy's management believes that its officers and directors who participate in wells under the board of directors' policy do so on terms the same as could be obtained by unaffiliated oil and gas industry participants in arms-length transactions, albeit those terms are different than the turnkey agreement under which outside investors purchase fractional undivided working interests from Royale Energy.
Donald and Stephen Hosmer each have participated individually in 178 wells each under the 1989 policy. The Hosmer Trust, a trust for the benefit of family members of Harry E. Hosmer, has participated in 177 wells.
Investments in wells under the 1989 policy for the three years ended December 31, 2015, 2014, and 2013 are as follows:
| | | Year | | # of fractional interests | | | Amount | |
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Current and former officers and directors were billed $0, $0 and $16,967 for their interests for the three years ended December 31, 2015, 2014, and 2013, respectively.
Royale Energy's chairman of the board and former president, Harry E. Hosmer, renders management consulting services to Royale Energy on an ongoing basis. Royale Energy compensated Mr. Hosmer $165,660, $165,660 and $193,270 for his consulting services in 2015, 2014, and 2013, respectively, and pays his medical insurance costs. Mr. Hosmer's consulting services are in conjunction with his service on the board of directors, for which he receives reimbursement of expenses to attend meetings.
Item 14 Principal Accountant Fees and Services
SingerLewak LLP served as the independent auditors to audit the Company’s financial statements for the fiscal year ended December 31, 2015 and 2014. This is the second annual audit performed by SingerLewak LLP, Padgett Stratemann & Co., LLP previously performed annual audits. The aggregate fees billed by SingerLewak LLP and Padgett Stratemann & Co., LLP for the years ended December 31, 2015 and 2014 are as follows, respectively:
(1) Audit fees are fees for professional services rendered for the audit of Royale Energy’s annual financial statements, reviews of financial statements included in the company’s Forms 10-Q, and reviews of documents filed with the U.S. Securities and Exchange Commission.
(2) Tax fees consist of tax planning, consulting and tax return reviews.
(3) Other fees consist of work on registration statements under the Securities Act of 1933.
The audit committee of Royale Energy has adopted policies for the pre-approval of all audit and non-audit services provided by the company’s independent auditor. The policy requires pre-approval by the audit committee of specifically defined audit and non-audit services. Unless the specific service has been previously pre-approved with respect to that year, the audit committee must approve the permitted service before the independent auditor is engaged to perform it.
No representatives of SingerLewak LLP are expected to be present at the annual meeting. Although the audit committee has the sole responsibility to appoint the auditors as required under the Securities Exchange Act of 1934, the committee welcomes any comments from shareholders on auditor selection or performance. Comments may be sent to the audit committee chair, Ronald Verdier, care of Royale Energy’s executive office, 3777 Willow Glen Drive, El Cajon, California 92019.
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:
| · | should not be treated as categorical statements of fact, but rather as a way of allocating the risk among the parties if those statements prove to be inaccurate; |
| | |
| · | have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement; |
| | |
| · | may apply standards of materiality in a way that is different from the way investors may view materiality; and |
| | |
| · | were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments. |
| 1. | Financial Statements. See Index to Financial Statements, page F-1 |
| 2. | Schedules. Supplemental Information About Oil and Gas Producing Activities (Unaudited) begins on page F-20. |
| 3. | Exhibits. Certain of the exhibits listed in the following index are incorporated by reference. |
| 1.1 | Placement Agent Agreement between the Company and C.K. Cooper & Company, Inc., dated October 25, 2013, incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K filed October 29, 2013. |
| 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. |
| 4.1 | Series E Warrant issued to certain affiliates of Cranshire Capital, L.P., incorporated by reference to Exhibit 4.2 of the Company’s Form 8-K filed October 29, 2013. |
| 4.2 | Certificate of Determination of the Series AA Convertible Preferred Stock, incorporated by reference to Exhibit 4.2 of Royale Energy's Form 10-SB Registration Statement. |
| 10.1 | Form of Indemnification Agreement, incorporated by reference to Exhibit 10.3 of Royale Energy's Form 10-SB Registration Statement. |
| 10.2 | Sales Agreement between the Company and C.K. Cooper & Company, Inc., dated February 17, 2013, incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed February 17, 2013. |
| 10.3 | Securities Purchase Agreement between the Company and certain buyers dated as of October 28, 2013, incorporated by reference to Exhibit 4.3 of the Company’s Form 8-K filed October 29, 2013. |
| 10.4 | Convertible Note issued to certain affiliates of Cranshire Capital, L.P., incorporated by reference to Exhibit 4.1 of the Company’s Form 8-K filed October 29, 2013. |
| 10.5 | |
| 23.1 | |
| 23.2 | Consent of Padgett Stratemann & Co, L.L.P., filed herewith. |
| 23.3 | |
| 23.4 | Consent of Source Energy, LLC, filed herewith. |
| 31.1 | |
| 31.2 | |
| 31.3 | |
| 32.1 | |
| 32.2 | |
| 32.3 | |
| 99.1 | |
| 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.
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.
| | | Royale Energy, Inc. |
| | | |
| Date: March 14, 2016 | | /s/ Jonathan Gregory |
| | | Jonathan Gregory |
| | | Chief Executive Officer |
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.
| Date: March 14, 2016 | | /s/ Harry E. Hosmer |
| | | Harry E. Hosmer |
| | | Chairman of the Board of Directors |
| Date: March 14, 2016 | | /s/ Donald H. Hosmer |
| | | Donald H. Hosmer |
| | | Director, and President of Business Development |
| Date: March 14, 2016 | | /s/ Stephen M. Hosmer |
| | | Stephen M. Hosmer |
| | | Director, President, Chief Financial Officer and Secretary |
| Date: March 14, 2016 | | /s/ Ronald Buck |
| | | Ronald Buck |
| | | Director |
| Date: March 14, 2016 | | /s/ Ronald Verdier |
| | | Ronald Verdier |
| | | Director |
| Date: March 14, 2016 | | /s/ Gary Grinsfelder |
| | | Gary Grinsfelder |
| | | Director |
| Date: March 14, 2016 | | /s/ Jonathan Gregory |
| | | Jonathan Gregory |
| | | Director, Chief Executive Officer |
INDEX TO FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA
| F-1 |
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| F-2 |
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| F-4 |
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| F-6 |
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| F-7 |
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| F-8 |
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| F-20 |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
Royale Energy, Inc.
We have audited the accompanying balance sheets of Royale Energy, Inc. (the “Company”) as of December 31, 2015 and 2014, and the related statements of comprehensive loss, stockholders’ deficit and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Royale Energy, Inc. as of December 31, 2015 and 2014, and the results of its operations and its cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.
SingerLewak LLP
Los Angeles, California
March 14, 2016
BALANCE SHEETS
DECEMBER 31, 2015 AND 2014
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| Current Assets: | | | | | | |
Cash and Cash Equivalents | | | | | | | | |
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Oil And Gas Properties (Successful Efforts Basis), Real Property and Equipment and Fixtures, net | | | | | | | | |
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The accompanying notes are an integral part of these financial statements.
ROYALE ENERGY, INC.
BALANCE SHEETS
DECEMBER 31, 2015 AND 2014
| | | 2015 | | | 2014 | |
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| LIABILITIES AND STOCKHOLDERS' DEFICIT | |
| Current Liabilities: | | | | | | |
Accounts Payable and Accrued Expenses | | | | | | | | |
Current Portion of Long-Term Debt | | | | | | | | |
Deferred Drilling Obligations | | | | | | | | |
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Total Current Liabilities | | | | | | | | |
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Asset Retirement Obligation | | | | | | | | |
Note Payable, less current portion | | | | | | | | |
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Total Noncurrent Liabilities | | | | | | | | |
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Convertible Preferred Stock, Series AA, No Par Value, 147,500 Shares Authorized; 46,662 Shares Issued and Outstanding, at December 31, 2015 and 2014, Respectively | | | | | | | | |
Common Stock, No Par Value, 30,000,000 Shares Authorized; 16,396,579 and 14,945,789 Shares Issued and Outstanding, at December 31, 2015 and 2014, respectively | | | | | | | | |
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Accumulated Other Comprehensive Loss | | | | | | | | |
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Total Stockholders' Deficit | | | | | | | | |
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Total Liabilities and Stockholders' Deficit | | | | | | | | |
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE LOSS
FOR THE YEARS ENDED DECEMBER 31, 2015, AND 2014
| | | 2015 | | | 2014 | |
| Revenues: | | | | | | |
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Supervisory Fees and Other | | | | | | | | |
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General and Administrative | | | | | | | | |
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Well Equipment Write Down | | | | | | | | |
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Depreciation, Depletion and Amortization | | | | | | | | |
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Gain on Turnkey Drilling Programs | | | | | | | | |
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Loss Before Income Tax Expense | | | | | | | | |
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Provision for Income Taxes | | | | | | | | |
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Other Comprehensive Income (Loss) | | | | | | | | |
Unrealized Loss on Equity Securities | | | | | | | | |
Less: Reclassification Adjustment for Losses Included in Net Income | | | | | | | | |
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Other Comprehensive Gain (Loss) before tax | | | | | | | | |
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Other Comprehensive Gain (Loss), net of tax | | | | | | | | |
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The accompanying notes are an integral part of these financial statements.
STATEMENTS OF STOCKHOLDERS' DEFICIT
FOR THE YEARS ENDED DECEMBER 31, 2015 and 2014
| | | | | | | | | Preferred Stock | | | | | | | | | | | | | |
| | | Common Stock | | | Series AA | | | | | | | | | Accumulated | | | | |
| | | Number of Shares | | | | | | Number of Shares | | | | | | Additional | | | | | | Other | | | | |
| | | Issued and | | | | | | Issued and | | | | | | Paid in | | | Accumulated | | | Comprehensive | | | | |
| | | Outstanding | | | Amount | | | Outstanding | | | Amount | | | Capital | | | Deficit | | | Income (Loss) | | | Total | |
Balance, December 31, 2013 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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Series AA Conversion to Common (2 for 1) | | | | | | | | | | | | ) | | | | ) | | | | | | | | | | | | | | | | |
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Director’s Stock Option Grant | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | �� | | | | | | | | | | | | | | | | |
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Available for Sale Securities - Unrealized Gain (Loss), net of tax | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | ) |
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Balance, December 31, 2014 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) |
Common Stock Private Placement Sale | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | |
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Director's Stock Options Grant | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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Common Stock RDO Private Placement Sale | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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Common Stock Issued to Executives in lieu of Compensation | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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Available for Sale Securities - Reclassification Adjustment for Losses Included in Net Income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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Balance, December 31, 2015 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2015 and 2014
| | | 2015 | | | 2014 | |
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| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
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Adjustments to Reconcile Net Loss to Net Cash Used by Operating Activities: | | | | | | | | |
Depreciation, Depletion, and Amortization | | | | | | | | |
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Gain on Turnkey Drilling Programs | | | | | | | | |
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Realized Loss on Equity Securities | | | | | | | | |
Well Equipment and Other Assets Write Down | | | | | | | | |
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Other & Revenue Receivables | | | | | | | | |
Prepaid Expenses and Other Assets | | | | | | | | |
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Accounts Payable and Accrued Expenses | | | | | | | | |
Deferred Drilling Obligations | | | | | | | | |
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Net Cash Used by Operating Activities | | | | | | | | |
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CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Expenditures for Oil And Gas Properties | | | | | | | | |
Proceeds from Turnkey Drilling Programs | | | | | | | | |
Proceeds from Sale of Assets | | | | | | | | |
Net Cash Provided by Investing Activities | | | | | | | | |
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CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
Proceeds from Long-Term Debt | | | | | | | | |
Principal Payments on Long-Term Debt | | | | | | | | |
Proceeds from Stock Options and Warrant Exercises | | | | | | | | |
Proceeds from Sale of Common Stock | | | | | | | | |
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Net Cash Provided by (Used In) Financing Activities | | | | | | | | |
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Net Increase (Decrease) in Cash and Cash Equivalents | | | | | | | | |
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Cash & Cash Equivalents at Beginning of Year | | | | | | | | |
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Cash & Cash Equivalents at End of Year | | | | | | | | |
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Supplemental Schedule of Non-Cash Investing and Financing Transactions: | | | | | | | | |
Conversion of Series AA Stock to Common Stock | | | | | | | | |
Unrealized Gain (Loss) on Available-for-Sale Securities, net of tax effect | | | | | | | | |
Reclassification Adjustment for Losses Included in Net Income | | | | | | $ | - | |
The accompanying notes are an integral part of these financial statements.
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.
Description of Business
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, Alaska 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.
Use of Estimates
The accompanying financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America and requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. As reflected in the accompanying financial statements, the Company has negative working capital, losses from operations and negative cash flows from operations.
Material estimates that are particularly susceptible to significant change relate to the estimate of Company oil and gas reserves prepared by an independent engineering consultant. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proven reserves. Estimated reserves are used in the calculation of depletion, depreciation and amortization, unevaluated property costs, impairment of oil and natural gas properties, estimated future net cash flows, taxes, and contingencies.
Liquidity
The primary sources of liquidity have historically been issuances of common stock and operations. Until we become cash flow positive, we anticipate that our primary sources of liquidity will be from the issuance of debt and/or equity, and the sale of oil and natural gas property participation interest. Assuming there are no further changes in expected sales and expense trends subsequent to March 14, 2016, the Company believes that its cash position together with anticipated financing activities, which include the sale of our office building and land, will be sufficient to continue operations for the foreseeable next twelve months.
Revenue Recognition
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.
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.
Oil and Gas Property and Equipment
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 2015 and 2014, impairment losses of $424,163 and $268,093, respectively, were recorded on various capitalized lease and land costs that were no longer viable.
Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that Royale Energy expects to hold the properties. The valuation allowances are reviewed at least annually.
Upon the sale or retirement of a complete field of a proved property, Royale Energy eliminates the cost from its books, and the resultant gain or loss is recorded to Royale Energy’s Statement of Operations. Upon the sale of an entire interest in an unproved property where the property has been assessed for impairment individually, a gain or loss is recognized in Royale Energy’s Statement of Operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a recovery of the cost in the interest retained with any excess funds recognized as a gain. Should Royale Energy’s turnkey drilling agreements include unproved property, total drilling costs incurred to satisfy its obligations are recovered by the total funds received under the agreements. Any excess funds are recorded as a Gain on Turnkey Drilling Programs, and any costs not recovered are capitalized and accounted for under the “successful efforts” method.
Royale Energy sponsors turnkey drilling agreement arrangements in unproved properties as a pooling of assets in a joint undertaking, whereby proceeds from participants are reported as Deferred Drilling Obligations, and then reduced as costs to complete its obligations are incurred with any excess booked against its property account to reduce any basis in its own interest. Gains on Turnkey Drilling Programs represent funds received from turnkey drilling participants in excess of all costs Royale incurs during the drilling programs (e.g., lease acquisition, exploration and development costs), including costs incurred on behalf of participants and costs incurred for its own account; and are recognized only upon making this determination after Royale’s obligations have been fulfilled.
The contracts require the participants pay Royale Energy the full contract price upon execution of the agreement. Royale Energy completes the drilling activities typically between 10 and 30 days after drilling begins. The participant retains an undivided or proportional beneficial interest in the property, and is also responsible for its proportionate share of operating costs. Royale Energy retains legal title to the lease. The participants purchase a working interest directly in the well bore.
In these working interest arrangements, the participants are responsible for sharing in the risk of development, but also sharing in a proportional interest in rights to revenues and proportional liability for the cost of operations after drilling is completed and the interest is conveyed to the participant.
A certain portion of the turnkey drilling participant’s funds received are non-refundable. The company holds all funds invested as Deferred Drilling Obligations until drilling is complete. Occasionally, drilling is delayed due to the permitting process or drilling rig availability. At December 31, 2015 and 2014, Royale Energy had Deferred Drilling Obligations of $8,415,528 and $7,937,786, respectively.
If Royale Energy is unable to drill the wells, and a suitable replacement well is not found, Royale would retain the non-refundable portion of the contact and return the remaining funds to the participant. Included in cash and cash equivalents are amounts for use in completion of turnkey drilling programs in progress.
Losses on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and on deposit, and highly liquid debt instruments with maturities of three months or less.
Other Receivables
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, 2015 and 2014, the Company established an allowance for uncollectable accounts of $2,270,773 and $1,734,713, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue.
Revenue Receivables
Our revenue receivables 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
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 Year Ended December 31, 2015 | |
| | | Loss (Numerator) | | | Shares (Denominator) | | | Per-Share Amount | |
| Basic Loss Per Share: | | | | | | | | | |
Net loss available to common stock | | | | | | | | | | | | |
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Effect of dilutive securities and stock options | | | | | | | | | | | | |
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Net loss available to common stock | | | | | | | | | | | | |
| | | For the Year Ended December 31, 2014 | |
| | | Loss (Numerator) | | | Shares (Denominator) | | | Per-Share Amount | |
| Basic Loss Per Share: | | | | | | | | | | | | |
Net income available to common stock | | | | | | | | | | | | |
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Effect of dilutive securities and stock options | | | | | | | | | | | | |
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Net loss available to common stock | | | | ) | | | | | | | | ) |
For the years ended December 31, 2015 and 2014, Royale Energy had dilutive securities of 23,331 and 161,966, respectively. These securities were not included in the dilutive loss per share due to their antidilutive nature.
Stock Based Compensation
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.
Income Taxes
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.
Fair Value Measurements
According to Fair Value Measurements and Disclosures Topic of the FASB Accounting Standards Codification, assets and liabilities that are measured at fair value on a recurring and nonrecurring basis in period subsequent to initial recognition, the reporting entity shall disclose information that enable users of its financial statements to assess the inputs used to develop those measurements and for recurring fair value measurements using significant unobservable inputs, the effect of the measurements on earnings for the period.
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. In determining fair value, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible as well as considers counterparty credit risk in its assessment of fair value. Carrying amounts of the Company’s financial instruments, including cash equivalents, accounts receivable, accounts payable and accrued liabilities, approximate their fair values as of the balance sheet dates because of their generally short maturities.
The fair value hierarchy distinguishes between (1) market participant assumptions developed based on market data obtained from independent sources (observable inputs) and (2) an entity’s own assumptions about market participant assumptions developed based on the best information available in the circumstances (unobservable inputs). The fair value hierarchy consists of three broad levels, which gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy are described below:
| | | Level 1: Quoted prices (unadjusted) in active markets that are accessible at the measurement date for assets or liabilities. |
| | | Level 2: Directly or indirectly observable inputs as of the reporting date through correlation with market data, including quoted prices for similar assets and liabilities in active markets and quoted prices in markets that are not active. Level 2 also includes assets and liabilities that are valued using models or other pricing methodologies that do not require significant judgment since the input assumptions used in the models, such as interest rates and volatility factors, are corroborated by readily observable data from actively quoted markets for substantially the full term of the financial instrument. Level 3: Unobservable inputs that are supported by little or no market activity and reflect the use of significant management judgment. These values are generally determined using pricing models for which the assumptions utilize management’s estimates of market participant assumptions |
At December 31, 2015 and 2014, 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.
Reclassifications
Certain items in the financial statements have been reclassified to maintain consistency and comparability for all periods presented herein.
Recently Issued Accounting Pronouncements
The Company has reviewed the updates issued by the Financial Accounting Standards Board (FASB) during the year ended December 31, 2015.
ASU 2014-15: Presentation of Financial Statements – Going Concern (Subtopic 205-40)
In June 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements – Going Concern. Before the issuance of ASU 2014-15, there was no guidance in U.S. GAAP about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern or to provide related footnote disclosures. ASU 2014-15 requires management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards as specified in the guidance. ASU 2014-15 becomes effective for the annual period ending after December 15, 2016 and for annual and interim periods thereafter. Early adoption is permitted. The Company is currently evaluating the effects of adopting ASU 2014-15 on its consolidated financial statements but the adoption is not expected to have a significant impact on the Company’s consolidated financial statements.
ASU 2015-14: Revenue from Contracts with Customers (Topic 606)
In August 2015, the FASB issued ASU No. 2015-14, Revenue From Contracts With Customers (Topic 606)." The amendments in this ASU defer the effective date of ASU 2014-09. Public business entities should apply the guidance in ASU 2014-09 to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier application is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. The Company is still evaluating the effect of the adoption of ASU 2014-09.
ASU 2016-01: Financial Instruments – Overall – Recognition and Measurement of Financial Assets and Financial Liabilities (Subtopic 825-10)
In January 2016, FASB issued ASU 2016-0,1 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.
NOTE 2 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES
Oil and gas properties, equipment and fixtures consist of the following at December 31:
| | | 2015 | | | 2014 | |
| Oil and Gas | | | | | | |
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Producing properties, including intangible drilling costs | | | | | | | | |
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Accumulated depletion, depreciation and amortization | | | | | | | | |
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| Commercial and Other | | 2015 | | | 2014 | |
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Real estate, including furniture and fixtures | | | | | | | | |
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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 2015 or 2014. 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.
| | | 12 Months Ended December 31, | |
| | | 2015 | | | 2014 | |
Beginning balance at January 1 | | | | | | | | |
| | | | | | | | | |
Additions to capitalized exploratory well costs pending the determination of proved reserves | | | | | | | | |
| | | | | | | | | |
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves | | | | | | | | |
| | | | | | | | | |
Ending balance at December 31 | | | | | | | | |
Results of Operations from Oil and Gas Producing and Exploration Activities
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:
| | | 2015 | | | 2014 | |
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| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Depreciation, depletion and amortization | | | | | | | | |
| | | | | | | | | |
Results of operations from producing and exploration activities | | | | | | | | |
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| | | | | | | | | |
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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.
| | | 2015 | | | 2014 | |
Asset retirement obligation, Beginning of the year | | | | | | | | |
Liabilities incurred during the period | | | | | | | | |
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| | | | | | | | |
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Asset retirement obligation, End of year | | | | | | | | |
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, 2015 and 2014, Royale Energy had recorded deferred turnkey drilling associated with undrilled wells of $8,415,528 and $7,937,786, respectively, as a current liability.
NOTE 5 - LONG-TERM DEBT
| | | 2015 | | | 2014 | |
| | | | | | | | | |
On December 24, 2013, Royale Energy, Inc. entered into an agreement between the Company, as buyer, and North Island Financial Credit Union as seller, for the purchase of commercial property in San Diego, California, for a purchase price of $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, NA, with a note secured by the property being purchased. The note carries an interest rate of 5.75% until paid in full. Royale will pay this loan in 119 regular payments of $9,525 each and one balloon payment estimated at $1,150,435. Royale’s first payment was due February 1, 2014, and all subsequent payments are due on the same day of each month after that. Royale’s final payment will be due on January 1, 2024, and will be for all principal and all accrued interest not yet paid. Payments include principal and interest. Stephen M Hosmer, President, CFO is named as a personal guarantor of the loan. The loan agreement contains certain covenants that, among other things, Royale must maintain a ratio of EBITDA-Debt Service Coverage in excess of 1.50 to 1.00. At December 31, 2015, Royale was not in compliance with this covenant, but obtained a forbearance from the bank from terms of that covenant to May 26, 2016. The Company is currently in the process of finalizing the sale of the office building and associated land, which is expected to resulting full payment of the long-term debt. However, there is no guarantee that the sale will be completed. | | | | | | | | |
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Long Term Debt Less Current Portion | | | | | | | | |
Maturities of long-term debt for the years subsequent to December 31, 2015 are as follows:
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.
Significant components of the Company’s deferred assets and liabilities at December 31, 2015 and 2014, respectively, are as follows:
| | | 2015 | | | 2014 | |
| Deferred Tax Assets (Liabilities): | | | | | | |
Statutory Depletion Carry Forward | | | | | | | | |
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| | | | | | | | |
| | | | | | | | |
Capital Loss / AMT Credit Carry Forward | | | | | | | | |
Charitable Contributions Carry Forward | | | | | | | | |
Allowance for Doubtful Accounts | | | | | | | | |
Oil and Gas Properties and Fixed Assets | | | | | | | | |
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Deferred Tax Liabilities: | | | | | | | | |
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At the end of 2014, management reviewed the realizability of the Company’s net deferred tax assets. Due to the Company’s cumulative losses in recent years, Royale and its management concluded that it is not “more-likely-than-not” its deferred tax assets will be realized. As a result, the Company recorded a full valuation allowance against the net deferred tax assets in 2014. At the end of 2015, management reviewed the reliability of the Company’s net deferred tax assets, and due to the Company’s continued cumulative losses in recent years, Royale and its management concluded it is not “more-likely-than-not” its deferred tax assets will be realized. As a result, the Company will continue to record a full valuation allowance against the deferred tax assets in 2015. The Company will assess the realizability of the deferred tax assets at least yearly and make appropriate updates as needed. The Company had statutory percentage depletion carry forwards of approximately $1.4 million at December 31, 2015. The depletion has no expiration date. The Company also has a net operating loss carry forward of approximately $11.6 million at December 31, 2015, which will begin to expire in 2027.
A reconciliation of Royale Energy's provision for income taxes and the amount computed by applying the statutory income tax rates at December 31, 2014 and 2013, respectively, to pretax income is as follows:
| | | 2015 | | | 2014 | |
| | | | | | | |
Tax (benefit) computed at statutory rate of 34% | | | | | | | | |
| | | | | | | | | |
Increase (decrease) in taxes resulting from: | | | | | | | | |
| | | | | | | | | |
State tax / percentage depletion / other | | | | | | | | |
Other non-deductible expenses | | | | | | | | |
Change in valuation allowance | | | | | | | | |
| | | | | | | | |
The components of the Company’s tax provision are as follows:
| | | 2015 | | | 2014 | |
| | | | | | | |
Current tax provision (benefit) – federal | | | | | | | | |
Current tax provision (benefit) – state | | | | | | | | |
Deferred tax provision (benefit) – federal | | | | | | | | |
Deferred tax provision (benefit) – state | | | | | | | | |
| | | | | | | | | |
Total provision (benefit) | | | | | | | | |
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, 2015, 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 2014 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. Holders of Series AA Convertible Preferred Stock have dividend, conversion and preference rights identical to Series A Convertible Preferred Stockholders. The Series AA Convertible Preferred Stock has a stated value of $4 per share and provides shareholders with a one-time dividend payable equal to forty cents ($0.40) per share of Series AA Convertible Preferred Stock within thirty days after the expiration of one year from the date of purchase. The dividend has been paid on all outstanding shares as of December 31, 1994.
The Series AA Convertible Preferred Stock is convertible any time at the basic conversion rate of one share of common stock for two shares of Series AA Convertible Preferred Stock, subject to adjustment. Royale Energy has the option to call, at any time after six months from the issuance, the Series AA Convertible Preferred Stock at either the issue price of $4 per share plus 10%, if called within one year after issuance, or $4 per share thereafter. (Subject to the holders' conversion rights outlined above). The Series AA Convertible Preferred Stock has a liquidation preference to the common stock equal to $4 per share plus accrued dividends. In the event of any voluntary or involuntary liquidation, dissolution or winding up of the Corporation, the holders of the shares of the Series AA Convertible Preferred Stock shall be entitled to be paid out of the assets of the Corporation available for distribution to its shareholders before any payment shall be made in respect of the Corporation’s common stock, but only after payment to its creditors, an amount equal to $4.40 per share, if called within one year after issuance, or $4 per share thereafter. Holders of Series AA Convertible Preferred Stock shall have voting rights equal to the number of shares of common stock into which the Series AA Convertible Preferred Stock may be converted.
The Series AA Convertible Preferred Stock does not have the right of redemption at the stockholders' option. The preferred stock is not registered under the Securities Exchange Act of 1934, and no market exists for the preferred stock. The shares of Series AA Preferred stock are convertible into shares of Royale Energy's common stock at the option of the security holder, at the rate of two shares of convertible preferred stock for each share of common stock. During the year ending December 31, 2014, there was a conversion of 6,122 Series AA Preferred shares, with a book value of $17,865, for 3,061 common shares. There were no such conversions during 2015. As of December 31, 2015 and 2014, and there were 46,662 and 46,662 shares, respectively of Series AA Preferred stock issued and outstanding.
NOTE 8 - COMMON STOCK
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 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, 2015 and 2014 was $10,400 and $74,047 respectively.
NOTE 10 - RELATED PARTY TRANSACTIONS
Significant Ownership Interests
As of February 23, 2016, Donald H. Hosmer, Royale Energy’s co-president and co-chief executive officer owns 8.08% of Royale Energy common stock. Donald H. Hosmer is the brother of Stephen M. Hosmer, and son of Harry E. Hosmer. Donald has participated individually in 178 wells under the 1989 policy. During 2015, Donald participated in fractional interests of two wells in the amount of $3,143 and in 2014 participated in fractional interests of four wells in the amount of $18,692. At December 31, 2015, Royale had a receivable balance of $991 due from Donald Hosmer for normal drilling and lease operating expenses.
As of February 23, 2016, Stephen M. Hosmer, Royale Energy’s co-president, co-chief executive officer and chief financial officer, owns 7.89% of Royale Energy common stock. Stephen M. Hosmer is the brother of Donald H. Hosmer and son of Harry E. Hosmer. Stephen has participated individually in 178 wells under the 1989 policy. During 2015, Stephen participated in fractional interests of four wells in the amount of $4,389 and in 2014 participated in fractional interests of four wells in the amount of $7,714. At December 31, 2015, Royale had a receivable balance of $7,696 due from Stephen Hosmer for normal drilling and lease operating expenses.
As of February 23, 2016, Harry E. Hosmer, Royale Energy's former president and former chief executive officer, owns 4.41% of Royale Energy common stock. Donald H. and Stephen M. Hosmer are sons of Harry E. Hosmer. Donald H. Hosmer and Stephen M. Hosmer are also officers and directors of Royale Energy. Harry Hosmer also assists Royale Energy on a consulting basis and receives $13,805 monthly for these services. During 2015, Harry Hosmer participated in fractional interests of four wells in the amount of $5,633 and in 2014 participated in fractional interests of three wells in the amount of $9,985. At December 31, 2015, Royale had a receivable balance of $4,380 due from Harry Hosmer for normal drilling and lease operating expenses.
NOTE 11 - STOCK COMPENSATION PLAN
During the Board of Directors meeting held in December 2010, directors and executive officers of Royale Energy were each granted 50,000 stock options, a total of 400,000 options, to purchase common stock at an exercise or base price of $3.25 per share. These options vested in two parts; the first 200,000 options vested on January 1, 2012; the remaining 200,000 options vested on January 1, 2013. The options were granted with a legal life of five years, and a service period of two years beginning January 1, 2012. In 2013, Royale did not recognize any compensation costs or tax effect related to this grant.
During the October 10, 2014 Board of Directors meeting, directors and executive offices of Royale Energy were granted 20,000 options each, 140,000 total, to purchase common stock at an exercise price of $5.00 per share. These options were granted for a period of 3 years and will expire on December 31, 2017. These options became exercisable at 5,000 shares per period beginning October 13, 2014, January 1, 2015, April 1, 2015 and July 1 2015. During 2015 and 2014, Royale recognized compensation costs of $86,877 and $33,785, respectively, relating to this option grant. There were no stock options granted during 2015.
The fair value of each option is estimated on the date of grant 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 option life and expected volatility in the market value of the underlying common stock. There were 0 and 140,000 options granted in the years ended December 31, 2015 and 2014, respectively. The 2014 options were granted with the following assumptions:
| Options | | 2015 | | | 2014 | |
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Weighted-average volatility | | | | | | | | % |
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Since, at the time of option grant, there was currently no market for options of Royale’s common stock, expected volatilities are based on historical volatility of the Company’s common stock and other factors. The risk-free rate for the periods within the contractual life of the option is based on quoted market yields for U.S. Treasury debt securities. The expected dividend yield was zero as the Company was subject to debt covenant prohibiting the payment of dividends. Royale Energy uses historical data to estimate option exercise and board member turnover within the valuation model. Compensation expense related to stock options was recorded net of estimated forfeitures, which for options remaining at December 31, 2016, Royale expects no additional forfeitures.
A summary of the status of Royale Energy's stock option plan as of December 31, 2015 and 2014, and changes during the years ending on those dates is presented below:
| | | 2015 | | | 2014 | |
| | | | | Weighted- | | | | | Weighted- | |
| | | | | Average | | | | | Average | |
| | | | | Exercise | | | | | Exercise | |
| | | Shares | | | Price | | | Shares | | | Price | |
| | | | | | | | | |
| Options | | | | | | | | |
Outstanding and Exercisable at Beginning of Year | | | | | | | | | | | | | | | | |
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Options Outstanding and Exercisable at Year End | | | | | | | | | | | | | | | | |
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Weighted-average Fair Value of Options Granted During the Year | | | | | | | | | | | | | | | | |
At December 31, 2015, Royale Energy’s stock price, $0.36, was less than the weighted average exercise price, and as such the outstanding and exercisable stock options had no intrinsic value. The stock options granted in 2014 have a weighted-average remaining contractual term of two years as of December 31, 2015. There were no stock options granted during 2015.
A summary of the status of Royale Energy's non-vested stock options as of December 31, 2015 and 2014, and changes during the years ending on those dates is presented below:
| | | 2015 | | | 2014 | |
| | | | | Weighted- | | | | | Weighted- | |
| | | | | Average | | | | | Average | |
| | | | | Grant-Date | | | | | Grant-Date | |
| | | Shares | | | Fair Value | | | Shares | | | Fair Value | |
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| Non-vested Stock Options | | | | | | | | |
Non-vested at Beginning of Year | | | | | | | | | | | | | | | | |
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Non-vested at End of Year | | | | | | | | | | | | | | | | |
During 2015 and 2014, we recognized $86,877 and $33,785, respectively, in compensation costs for the vested stock options.
NOTE 12 - SIMPLE IRA PLAN
In April 1998, the Company established a Simple IRA pension plan covering all employees. The Company will contribute a matching contribution to each eligible employee’s Simple IRA equal to the employee’s salary reduction contributions up to a limit of 3% of the employee’s compensation for the year. The employer contribution for the years ending December 31, 2015 and 2014, were $43,001, and $47,081 respectively.
NOTE 13 - ENVIRONMENTAL MATTERS
Royale Energy has established procedures for the continuing evaluation of its operations to identify potential environmental exposures and assure compliance with regulatory policies and procedures. Management monitors these laws and regulations and periodically assesses the propriety of its operational and accounting policies related to environmental issues. The nature of Royale Energy's business requires routine day-to-day compliance with environmental laws and regulations. Royale Energy incurred no material environmental investigation, compliance and remediation costs in 2015 or 2014.
Royale Energy is unable to predict whether its future operations will be materially affected by these laws and regulations. It is believed that legislation and regulations relating to environmental protection will not materially affect the results of operations of Royale Energy.
NOTE 14 - CONCENTRATIONS OF CREDIT RISK
The Company bids its gas sales on a month to month basis and generally sells to a single customer without commitment to future gas sales to any particular customer. The Company normally sells approximately 87% of its monthly natural gas production to one customer on a month to month basis. Since we are able to sell our natural gas to other readily available customers, the loss of any one customer would not have an adverse effect on our overall sales operations.
The Company maintains cash in depository institutions that are guaranteed by the Federal Deposit Insurance Corporation (FDIC) up to $250,000 per institution for our interest bearing accounts in the years ended December 31, 2015, and 2014. At December 31, 2015, and 2014, the Company’s non-interest bearing accounts were fully insured by the FDIC. At December 31, 2015 and 2014, cash in banks exceeded the FDIC limits by approximately $3.4 million and $2.8 million, respectively. The Company has not experienced any losses on deposits.
NOTE 15 - COMMITMENTS AND CONTINGENCIES
The Company may become involved from time to time in litigation on various matters, which are routine to the conduct of its business. The Company believes that none of these actions, individually or in the aggregate, will have a material adverse effect on its financial position or results of operations, though any adverse decision in these cases or the costs of defending or settling such claims could have a material effect on its business.
NOTE 16 – SUBSEQUENT EVENTS
On February 11, 2016, Royale Energy, Inc. entered into a purchase and sale agreement for the sale of its corporate headquarters building located in El Cajon, California for $2.5 million. The buyer is currently conducting its due diligence process.
Pursuant to the Form S-8 filed with the Securities and Exchange Commission on December 15, 2015 (File No. 333-208555), Royale Energy, Inc. has issued 1,220,084 shares of Royale Energy, Inc. common stock valued at $163,437 to its directors and offices as a portion of their compensation from January 2016 through the date of filing. The shares were valued at the closing market price on the date of grant, and were instead of their cash compensation. Since the Form S-8 was filed in December 2015, Royale has issued 1,405,821 shares of Royale Energy, Inc. common stock valued at $251,805 to it directors and officer under this registration statement.
ROYALE ENERGY, INC.
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
The following estimates of proved oil and gas reserves, both developed and undeveloped, represent interests owned by Royale Energy which are located solely in the United States. Proved reserves represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate to be reasonably certain to be recoverable in the future from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells, with existing equipment and operating methods. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which relatively major expenditures are required for completion.
Disclosures of oil and gas reserves, which follow, are based on estimates prepared by independent petroleum engineering consultant Netherland, Sewell & Associates, Inc., the net reserve value of its proved developed and undeveloped reserves was approximately $3.2 million at December 31, 2015, based on natural gas prices ranging from $2.59 per MCF to $2.98 per MCF as applied on a field-by-field basis. Netherland, Sewell & Associates, Inc. provided reserve value information for the Company’s California, Texas, Oklahoma, Utah and Louisiana properties. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. These estimates do not include probable or possible reserves.
The technical persons responsible for preparing the reserves estimates presented in the report of Netherland, Sewell & Associates, Inc., meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Netherland, Sewell & Associates, Inc. is a firm of independent petroleum engineers, geologists, geophysicists, and petrophysicists; and do not own an interest in our properties and are not employed on a contingent basis. All activities and reports performed and completed by Netherland, Sewell & Associates, Inc. with regards to our reserve valuation estimates are reviewed Royale’s management.
These estimates are furnished and calculated in accordance with requirements of the Financial Accounting Standards Board and the Securities and Exchange Commission (SEC). Because of unpredictable variances in expenses and capital forecasts, crude oil and natural gas price changes, largely influenced and controlled by U.S. and foreign government actions, and the fact that the bases for such estimates vary significantly, management believes the usefulness of these projections is limited. Estimates of future net cash flows presented do not represent management's assessment of future profitability or future cash flows to Royale Energy. Management's investment and operating decisions are based upon reserve estimates that include proved reserves prescribed by the SEC as well as probable reserves, and upon different price and cost assumptions from those used here.
It should be recognized that applying current costs and prices and a 10 percent standard discount rate does not convey absolute value. The discounted amounts arrived at are only one measure of the value of proved reserves.
Changes in Estimated Reserve Quantities
The net interest in estimated quantities of proved developed reserves of crude oil and natural gas at December 31, 2015 and 2014, and changes in such quantities during each of the years then ended, were as follows:
| | | 2015 | | | 2014 | |
| | | | | | | | | | | | | |
| | | Oil (BBL) | | | Gas (MCF) | | | Oil (BBL) | | | Gas (MCF) | |
| Proved developed and undeveloped reserves: | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Revisions of previous estimates | | | | | | | | | | | | | | | | |
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Extensions, discoveries and improved recovery | | | | | | | | | | | | | | | | |
Purchase of minerals in place | | | | | | | | | | | | | | | | |
Sales of minerals in place | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Proved reserves end of period | | | | | | | | | | | | | | | | |
| | | 2015 | | | 2014 | |
| | | | | | | | | | | | | |
| | | Oil (BBL) | | | Gas (MCF) | | | Oil (BBL) | | | Gas (MCF) | |
| Proved developed reserves: | | | | | | | | | | | | |
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| | | 2015 | | | 2014 | |
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| | | Oil (BBL) | | | Gas (MCF) | | | Oil (BBL) | | | Gas (MCF) | |
| Proved undeveloped reserves: | | | | | | | | | | | | |
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For December 31, 2015, natural gas extensions, discoveries and improved recovery were 48,912 MCF which was added due to the drilling one new exploratory well during 2015. This new well consisted of 4,312 MCF of proved developed producing reserves and 44,600 proved developed non-producing reserves. A location which had 658,894 MCF in proved developed reserves at December 31, 2014, was drilled and began producing in 2014, was revised downward 566,405 MCF at December 31, 2015. A location which was drilled in 2011 and began producing in 2013, was revised downward 135,729 MCF at December 31, 2015. A location which was drilled and began producing in 2012, had proved developed producing reserves of 229,287 at December 31, 2014, was revised downward 184,436 MCF at December 31, 2015. A location which was drilled and began producing in 2013, had proved developed producing reserves of 111,445 at December 31, 2014, was revised downward 80,486 MCF at December 31, 2015. Additionally in 2015, four locations which were drilled prior to 2011, had a total of 905,646 MCF of proved developed reserves at December 31, 2014, were revised downward 306,366 MCF at December 31, 2015.
For December 31, 2014, natural gas extensions, discoveries and improved recovery came to 867,398 MCF which were added due to the drilling two new exploratory wells during 2014. These new wells consisted of 644,553 MCF of proved developed producing reserves and 222,845 proved developed non-producing reserves. A location which was drilled in 2011 and began producing in 2013, was revised upward 251,800 MCF at December 31, 2014. A location which had 395,760 MCF in proved undeveloped reserves at December 31, 2013, was drilled and began producing in 2014, was revised downward 321,703 MCF at December 31, 2014. A location which was drilled and began producing in 2013, had proved developed producing reserves of 196,162 at December 31, 2013, was revised downward 187,540 MCF at December 31, 2014. Additionally in 2014, two locations which had a total of 32,282 BBL of proved undeveloped reserves at December 31, 2013, were revised downward 31,088 BBL at December 31, 2014.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The standardized measure of discounted future net cash flows is presented below for the two years ended December 31, 2015.
The future net cash inflows are developed as follows:
| • | Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. |
| • | The estimated future production of proved reserves is priced on the basis of year-end prices. |
| • | The resulting future gross revenue streams are reduced by estimated future costs to develop and to produce proved reserves, based on year-end estimates. Estimated future development costs by year are as follows: |
The resulting future net revenue streams are reduced to present value amounts by applying a ten percent discount.
Disclosure of principal components of the standardized measure of discounted future net cash flows provides information concerning the factors involved in making the calculation. In addition, the disclosure of both undiscounted and discounted net cash flows provides a measure of comparing proved oil and gas reserves both with and without an estimate of production timing. The standardized measure of discounted future net cash flow relating to proved reserves reflects estimated income taxes.
Changes in standardized measure of discounted future net cash flow from proved reserve quantities
This statement discloses the sources of changes in the standardized measure from year to year. The amount reported as “Net changes in prices and production costs” represents the present value of changes in prices and production costs multiplied by estimates of proved reserves as of the beginning of the year. The “accretion of discount” was computed by multiplying the ten percent discount factor by the standardized measure on a pretax basis as of the beginning of the year. The “Sales of oil and gas produced, net of production costs” are expressed in actual dollar amounts. “Revisions of previous quantity estimates” is expressed at year-end prices. The “Net change in income taxes” is computed as the change in present value of future income taxes.
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Future income tax expense | | | | | | | | |
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10% annual discount for estimated timing of cash flows | | | | | | | | |
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Standardized measure of discounted future net cash flows | | | | | | | | |
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Sales of oil and gas produced, net of production costs | | | | | | | | |
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Revisions of previous quantity estimates | | | | | | | | |
Net changes in prices and production costs | | | | | | | | |
Sales of minerals in place | | | | | | | | |
Purchases of minerals in place | | | | | | | | |
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Extensions, discoveries and improved recovery | | | | | | | | |
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Future Development Costs
In order to realize future revenues from our proved reserves estimated in our reserve report, it will be necessary to incur future costs to develop and produce the proved reserves. The following table estimates the costs to develop and produce our proved reserves in the years 2016 through 2018.
| Future development cost of: | | 2016 | | | 2017 | | | 2018 | |
Proved developed reserves | | | | | | | | | | | | |
Proved non-producing reserves | | | | | | | | | | | | |
Proved undeveloped reserves | | | | | | | | | | | | |
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Common assumptions include such matters as the real extent and average thickness of a particular reservoir, the average porosity and permeability of the reservoir, the anticipated future production from existing and future wells, future development and production costs and the ultimate hydrocarbon recovery percentage. As a result, oil and gas reserve estimates and discounted present value estimates are frequently revised in subsequent periods to reflect production data obtained after the date of the original estimate. If the reserve estimates are inaccurate, production rates may decline more rapidly than anticipated, and future production revenues may be less than estimated.
Additional data relating to Royale Energy's oil and natural gas properties is disclosed in Supplemental Information About Oil and Gas Producing Activities (Unaudited), attached to Royale Energy's Financial Statements, beginning on page F-1
Historic Development Costs for Proved Reserves
In each year we expend funds to drill and develop some of our proved undeveloped reserves. The following table summarizes our historic costs incurred in each of the past three fiscal years to drill and develop reserves that were classified as proved undeveloped reserves as of December 31 of the immediately preceding year:
