UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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For the Fiscal Year Ended December 31, 2014
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Commission File No. 0-22750
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ROYALE ENERGY, INC.
(Name of registrant in its charter)
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California
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33-0224120
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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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, 2014, the end of the registrant’s most recently completed second fiscal quarter; the aggregate market value of common equity held by non-affiliates was $42,785,383.
At March 6, 2015, 14,945,789 shares of registrant's Common Stock were outstanding.
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PART I
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Item 1
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1
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1
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2
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Item 1A
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3
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Item 1B
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6
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Item 2
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6
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7
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7
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7
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7
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8
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8
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Item 3
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8
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Item 4
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8
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PART II
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Item 5
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9
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9
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9
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9
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Item 6
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10
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10
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12
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13
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15
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Item 7
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15
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Item 8
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15
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Item 9
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15
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Item 9A
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15
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15
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16
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16
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16
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PART III
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Item 10
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17
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Item 11
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19
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Item 12
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22
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Item 13
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23
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Item 14
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24
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PART IV
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Item 15
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25
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26
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F-1
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ROYALE ENERGY, INC.
PART I
Item 1 Description of Business
Royale Energy, Inc. ("Royale Energy") 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 NASDAQ Capital Market System (symbol ROYL). On December 31, 2014, Royale Energy had 20 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, 2014, 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 2014, Royale Energy drilled four wells in northern California; three were commercially productive and one was a dry hole. We also participated in the drilling of an additional well with an industry partner which turned out to be a dry hole. Royale Energy's estimated total reserves remained constant at approximately 4.1 BCFE (billion cubic feet equivalent) at December 31, 2014 and December 31, 2013, respectively. According to the reserve reports furnished to Royale Energy by Netherland, Sewell & Associates, Inc., and Source Energy, LLC, Royale Energy's independent petroleum engineers, the undiscounted net reserve value of its proved developed and undeveloped reserves was approximately $12.4 million at December 31, 2014, based on natural gas prices ranging from $4.33 per MCF to $4.89 per MCF. Source Energy, LLC, supplied reserve value estimates for Royale Energy’s Utah properties, and Netherland, Sewell & Associates, Inc. provided reserve information for the Company’s California, Texas, Oklahoma 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, 2014, was estimated to be $6,615,039. 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 $1,640,731 and $2,008,734 for the years ended December 31, 2014 and 2013, respectively.
In addition to Royale Energy's own geological, land, and engineering staff, Royale Energy hires independent contractors to drill, test, complete and equip the wells that it drills. Approximately 80.7% of Royale Energy's total revenue for the year ended December 31, 2014, came from sales of oil and natural gas from production of its wells in the amount of $2,598,297. In 2013, this amount was $1,913,364, which represented 74.4% 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-9.
Once drilling has commenced, it is generally completed within 10-30 days. See Note 1 to Royale Energy's Financial Statements, at page F-9. 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, 2014, Royale Energy earned gross revenues from operation of the wells in the amount of $464,429 representing 14.4% of its total revenues for the year. In 2013, the amount was $414,850, which represented about 16.1% of total revenues. At December 31, 2014, Royale Energy operated 54 natural gas wells in California. Royale also has non-operating interests in four natural gas wells in Utah, eleven 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 2014 or 2013.
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 which 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 2014 the average sales price we received for natural gas was $4.64 per MCF, compared to $3.64 in 2013. The increase in our natural gas production and the higher gas prices resulted in a 35.8% increase in natural gas revenues in 2014 when compared to 2013. See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations for the Twelve Months Ended December 31, 2014, as Compared to the Twelve Months Ended December 31, 2013.
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:
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the timing of both production and related expenses;
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changes in consumption levels; and
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governmental regulations or taxation.
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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 inexact 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 co-presidents and co-chief executive officers, Donald H. Hosmer and Stephen M. Hosmer. Stephen Hosmer is also the chief financial officer. We do not have employment agreements with either Donald or Stephen Hosmer. The loss of the services of either 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 to be 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.
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 2014, Royale Energy drilled four wells in northern California, two exploratory producing wells, one developmental producing well 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 $500,000 was paid in cash on the date of purchase, and $1,500,000 was borrowed 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. 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 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.
Following is a discussion of Royale Energy's significant oil and natural gas properties. Reserves at December 31, 2014, for each property discussed below, have been determined by Netherland, Sewell & Associates, Inc., and Source Energy, LLC, registered professional petroleum engineers, in accordance with reports submitted to Royale Energy on February 14, 2015 and February 27, 2015, respectively.
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, 2014, Royale operated 54 wells in California with estimated total proven, developed, and undeveloped reserves at approximately 4.1 BCF, according to Royale’s independently prepared reserve report as of December 31, 2014.
As of December 31, 2014, Royale Energy owned leasehold interests in the following developed and undeveloped properties in both gross and net acreage.
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Developed
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Undeveloped
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Gross Acres
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Net Acres
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Gross Acres
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Net Acres
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California
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6,470.01
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4,092.34
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7,440.99
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6,654.19
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Alaska
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0
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0
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96,842.59
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96,842.59
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All Other States
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5,331.63
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2,011.62
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8,540.98
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4,988.80
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Total
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11,801.64
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6,103.96
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112,824.56
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108,485.58
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Gross and Net Productive Wells
As of December 31, 2014, Royale Energy owned interests in the following oil and gas wells in both gross and net acreage:
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Gross Wells
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Net Wells
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Natural Gas
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65.00
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29.08
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Oil
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8.00
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0.88
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Total
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|
|
73.00
|
|
|
|
29.96
|
|
The following table sets forth Royale Energy's drilling activities during the years ended December 31, 2013 and 2014. All wells are located in the Continental U.S., in California, Texas, Louisiana and Utah.
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|
|
|
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|
|
|
|
|
|
|
|
|
Year
|
|
Type of Well(a)
|
|
|
|
|
Gross Wells(b)
|
|
|
Net Wells(e)
|
|
| |
|
|
|
Total
|
|
|
Producing(c)
|
|
|
Dry(d)
|
|
|
Producing(c)
|
|
|
Dry(d)
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013
|
|
Exploratory
|
|
|
5
|
|
|
|
3
|
|
|
|
2
|
|
|
|
1.2350
|
|
|
|
0.9805
|
|
| |
|
Developmental
|
|
|
1
|
|
|
|
1
|
|
|
|
0
|
|
|
|
0.3135
|
|
|
|
0.0000
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2014
|
|
Exploratory
|
|
|
2
|
|
|
|
2
|
|
|
|
0
|
|
|
|
0.8734
|
|
|
|
0.0000
|
|
| |
|
Developmental
|
|
|
2
|
|
|
|
1
|
|
|
|
1
|
|
|
|
0.2173
|
|
|
|
0.3612
|
|
|
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.
| |
|
2014
|
|
|
2013
|
|
|
Net volume
|
|
|
|
|
|
|
|
Oil (BBL)
|
|
|
685
|
|
|
|
1,019
|
|
|
Gas (MCF)
|
|
|
547,898
|
|
|
|
498,778
|
|
|
MCFE
|
|
|
552,008
|
|
|
|
504,892
|
|
| |
|
|
|
|
|
|
|
|
|
Average sales price
|
|
|
|
|
|
|
|
|
|
Oil (BBL)
|
|
$
|
85.20
|
|
|
$
|
93.79
|
|
|
Gas (MCF)
|
|
$
|
4.64
|
|
|
$
|
3.64
|
|
| |
|
|
|
|
|
|
|
|
|
Net production costs and taxes
|
|
$
|
1,427,673
|
|
|
$
|
936,631
|
|
| |
|
|
|
|
|
|
|
|
|
Lifting costs (per MCFE)
|
|
$
|
2.59
|
|
|
$
|
1.86
|
|
Net Proved Oil and Natural Gas Reserves
As of December 31, 2014, Royale Energy had proved developed reserves of 3,787 MMCF and total proved reserves of 4,132 MMCF of natural gas on all of the properties Royale Energy leases. For the same period, Royale Energy also had proved developed oil and natural gas liquid combined reserves of .6 MBBL and total proved oil and natural gas liquid combined reserves of 2 MBBL.
Oil and gas reserve estimates and the discounted present value estimates associated with the reserve estimates are based on numerous engineering, geological and operational assumptions that generally are derived from limited data.
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 files 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 seeks 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. At this juncture, the case is in its preliminary phase and we are unable to provide a possible outcome other than to note that management vigorously will contest the allegations of the counterclaim and third-party complaint and will seek to aggressively move to realize on its lien claims to recover funds due and owing from Rampart. Because the case is only a number of months old, we are unable to provide an evaluation of the likelihood of an unfavorable outcome nor can we estimate the amount or range of potential loss.
Douglas Jones v. Royale Energy, Broward County Circuit Court, Florida. On July 1, 2010, Douglas Jones filed a lawsuit against the Company in the Circuit Court, 17th Judicial District, Broward County, Florida. Mr. Jones was an independent contractor handling certain aspects of sales for the Company prior to July 2, 2008. He asserts that he is entitled to an unspecified amount for commissions and expenses. The Company denies that any money is owed to Mr. Jones. On August 16, 2010, the Company, through Florida counsel Adam Hodkin, filed a motion to dismiss the lawsuit for lack of jurisdiction in the Florida courts. The Court ruled that it wanted to have an evidentiary hearing on the motion. The Court has finally set a date for the evidentiary hearing on whether to grant or deny the motion to dismiss. That date is May 5, 2014. On December 23, 2014 the court denied the motion to dismiss for lack of jurisdiction, meaning that the case could go forward in Florida. In February 2015, although the Company denied any liability to Mr. Jones, it agreed to settle the case for $20,000 to avoid the costs of long distance ligation.
Item 4 Mine Safety Disclosures
Not Applicable
PART II
Item 5 Market for Common Equity and Related Stockholder Matters
Since 1997 Royale Energy’s Common Stock has been traded on the Nasdaq National Market System under the symbol “ROYL”. Since July 1, 2009, Royale Energy’s stock has been listed on the NASDAQ Capital Market, and prior to that, our stock was listed on the NASDAQ Global Market. As of December 31, 2014, 14,945,789 shares of Royale Energy’s Common Stock were held by approximately 7,736 stockholders. The following table reflects the high and low quarterly closing sales prices from January 2013 through December 2014.
| |
|
1st Qtr
|
|
|
2nd Qtr
|
|
|
3rd Qtr
|
|
|
4th Qtr
|
|
| |
|
High
|
|
|
Low
|
|
|
High
|
|
|
Low
|
|
|
High
|
|
|
Low
|
|
|
High
|
|
|
Low
|
|
|
2013
|
|
2.76
|
|
|
2.08
|
|
|
3.34
|
|
|
1.98
|
|
|
2.97
|
|
|
2.58
|
|
|
2.74
|
|
|
2.51
|
|
|
2014
|
|
|
3.13
|
|
|
|
2.53
|
|
|
|
3.57
|
|
|
|
2.70
|
|
|
|
4.78
|
|
|
|
2.69
|
|
|
|
2.79
|
|
|
|
2.02
|
|
The Board of Directors did not issue cash or stock dividends in 2014 or 2013.
Recent Sales of Unregistered Securities
None.
The following stock price performance graph is included in accordance with the SEC’s executive compensation disclosure rules and is intended to allow stockholders to review Royale Energy’s executive compensation policies in light of corresponding stockholder returns, expressed in terms of the appreciation of Royale Energy’s common stock relative to two broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. The graph compares total return on $100 value of Royale Energy’s common stock on December 31, 2009, with the cumulative total return of the Standard & Poor’s Composite 500 Stock Index and the Dow Jones U.S. Oil & Gas Index from December 31, 2009 through December 31, 2014.
| |
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
Royale Energy, Inc.
|
|
|
100
|
|
|
|
85
|
|
|
|
173
|
|
|
|
98
|
|
|
|
98
|
|
|
|
80
|
|
|
S&P 500 Stock Index
|
|
|
100
|
|
|
|
113
|
|
|
|
113
|
|
|
|
128
|
|
|
|
166
|
|
|
|
185
|
|
|
DJ US Oil & Gas Index
|
|
|
100
|
|
|
|
117
|
|
|
|
120
|
|
|
|
123
|
|
|
|
152
|
|
|
|
135
|
|
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-two 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) changes in oil and natural gas production levels and reserves, (ii) turnkey drilling activities, and (iii) the change in commodities price of natural gas and oil reserves owned by Royale Energy.
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 2014 and 2013, impairment losses of $268,093 and $70,203, 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 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, 2014 and 2013, Royale Energy had Deferred Drilling Obligations of $7,937,786 and $6,125,933 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.
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, 2014, as Compared to the Twelve Months Ended December 31, 2013
For the year ended December 31, 2014, we recorded a net loss of $2,151,856 a $3,301,009 decline when compared to net income of $1,149,153 during 2013. Total revenues from operations in 2014 were $3,221,498, an increase of $648,437, or 25.2% from the total revenues of $2,573,061 in 2013, due to higher natural gas prices and production during 2014. Total expenses from operations in 2014 were $7,275,331, an increase of $1,326,846, or 22.3%, from the total expenses of $5,948,485 in 2013, due to increases in lease operating, bad debts and impairment costs.
In 2014, revenues from oil and gas production increased by 35.8% to $2,598,297 from $1,913,364 in 2013. This increase was due to higher natural gas commodity prices received during 2014. The net sales volume of natural gas for the year ended December 31, 2014, was approximately 547,898 MCF with an average price of $4.64 per MCF, versus 498,778 MCF with an average price of $3.64 per MCF for 2013. This represents an increase in net sales volume of 49,121 MCF or 9.9%. This increase in production volume was due to various wells coming online that were drilled in late 2013 and early 2014. The net sales volume for oil and condensate (natural gas liquids) production was approximately 685 barrels with an average price of $85.20 per barrel for the year ended December 31, 2014, compared to 1,019 barrels at an average price of $93.79 per barrel for the year in 2013. This represents a decrease in net sales volume of 335 barrels, or 32.8%. This decrease was due to the natural declines on existing wells. Northern and central California accounted for approximately 97% of the Company’s successful natural gas production in 2014.
Oil and natural gas lease operating expenses increased by $491,042, or 52.4% to $1,427,673 for the year ended December 31, 2014, from $936,631 for the year in 2013. This increase was mainly due to higher plugging and abandonment costs on several older wells in 2014. When measuring lease operating costs on a production or lifting cost basis, in 2014, the $1,427,673 equates to a $2.59 per MCFE lifting cost versus a $1.86 per MCFE lifting cost in 2013, a 39% increase, also due to higher plugging costs. Delay rental costs increased by $159,252 or 34.8%, to $616,806 for the year in 2014 from $457,554 in 2013. This increase was due to delay rental costs and our increased ownership of our Alaska leases.
At December 31, 2014, Royale Energy had a Deferred Drilling Obligation of $7,937,786. 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. In 2013, we disposed of $8,028,190 upon completing our obligation by drilling six wells, five exploratory and one developmental, in addition to participating in the drilling of two additional wells with an industry partner, resulting in a gain of $2,008,734. Royale expects to dispose of approximately $3 million in the first six months of 2015 with $3.2 million disposed of by the end of 2015.
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. During 2013 we recorded a gain of $2,684,801 from the sale of a portion of our western block oil and gas leases in Alaska. In 2013, we also recorded a gain of $173,013 on the sale of certain California natural gas leases. During the year in 2013, we recorded a gain of $40,000 on the sale of oil and gas leases in Texas and recorded a loss of $82,184 on the sale of surface casing previously included in inventory. Additionally in 2013, we recorded a write down of $39,185 on certain oil and gas inventory that no longer appeared viable.
Impairment losses of $268,093 and $70,203 were recorded in 2014 and 2013, respectively. 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 2014 and the 2013 loss, we recorded impairments on various capitalized lease and land costs that were no longer viable.
Bad debt expense for 2014 and 2013 were $653,133 and $146,704, respectively. The expenses in 2014 and 2013 arose from identified uncollectable receivables relating to our oil and natural gas properties either plugged and abandoned or scheduled for plugging and abandonment. We periodically review our accounts receivable from working interest owners to determine whether collection of any of these charges where 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 $623,201 for the year ended December 31, 2014, a decrease of $36,496 or 5.5% from $659,697 during the year in 2013. This decrease was mainly due to lower revenues from pipeline and compressor fees due to costs to rebuild a compressor in one of our main fields. 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 $49,579 or 12%, to $464,429 in 2014 from $414,850 in 2013.
Depreciation, depletion and amortization expense increased to $315,574 from $309,806 an increase of $5,768 or 1.9% for the year ended December 31, 2014, as compared to 2013. 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 production volumes were higher during the period.
General and administrative expenses decreased by $117,392 or 3.6%, from $3,279,505 for the year ended December 31, 2013, to $3,162,113 for the year in 2014. This decrease was primarily due to lower office rent expense during the period in 2014, as the company relocated into its own office building which was purchased at the end of 2013. Legal and accounting expense increased to $401,160 for the year, compared to $326,270 for 2013, a $74,890 or 23% increase. The increased expense was the result of higher legal fees primarily related to the Rampart litigation.
Marketing expense for the year ended December 31, 2014, increased $98,297 or 29.6%, to $430,779, compared to $332,482 for the year in 2013. The increase was due to higher broker fees in 2014 as we used outside brokers to sell direct working interests to investors.
During 2013, we incurred $50,145 in geological and geophysical from a well which was drilled based on seismic data we gathered during our 2011 Lake Mendocino survey. This seismic data was expensed once the well was drilled. No wells drilled in 2014 were based on this survey.
During 2014, interest expense decreased to $81,605 from $304,472 in 2013, a $222,867 or 73.2% decrease. This decrease mainly resulted from a reduction of outstanding indebtedness after the 2013 repayment of a convertible note. Further details concerning Royale’s notes payable and line of credit usage can be found in Capital Resources and Liquidity, below.
In 2014 and 2013, 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, 2014, Royale Energy had current assets totaling $5,473,721 and current liabilities totaling $12,469,376, a $6,995,655 working capital deficit. We had cash and cash equivalents at December 31, 2014 of $3,061,841 compared to $4,878,233 at December 31, 2013.
Ordinarily, we fund our operations and cash needs from our available credit and cash flows generated from operations. We believe that we have sufficient liquidity for the foreseeable future and do not foresee any liquidity demands that cannot be met from 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 pursuant to a Registration Statement on Form S-3 filed with the SEC.
At the end of 2014, our other receivables, which consists of receivables from direct working interest investors and industry partners, totaled $1,760,181 compared to $1,152,473 at December 31, 2013, a $607,708 or 52.7% increase. This was primarily due to a receivable from an industry partner at year end 2014. Royale’s revenue receivable at the end of 2014 was $493,295, a decrease of $35,024 or 6.6%, compared to $528,319 at the end of 2013. At December 31, 2014, our accounts payable and accrued expenses totaled $4,502,559, a decrease of $829,764 or 15.6% over the accounts payable at the end of 2013 of $5,332,323, mainly due to lower accrued drilling costs at the end of 2014.
In April 2014, Royale entered into a sales agreement with Roth Capital, LLC (Roth) relating to the sale of shares of our common stock. See the Company’s Prospectus Supplement filed pursuant to Rule 424(b) on April 4, 2014, and the Company’s Form 8-K filed on April 4, 2014. In accordance with the terms of the sales agreement, Royale may sell up to $10,000,000 in aggregate amount of the Company’s shares from time to time through Roth, as our sales agent. Roth is not required to sell any specific number or dollar amount of shares of our common stock, but will use its commercially reasonable efforts, as our sales agent and subject to the terms of the sales agreement, to sell the shares offered by the Prospectus Supplement and the accompanying prospectus.
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 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, Co-CEO, CFO is named as a personal guarantor of the loan. At December 31, 2014, the outstanding balance of this note was $1,475,884. 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, 2014, Royale was not in compliance with this covenant, but obtained a forbearance from the bank from terms of that covenant.
In October 2012, the Company obtained $3 million from the issuance of a convertible note. See the Company’s Prospectus Supplement filed pursuant to Rule 424(b) on October 29, 2012, and the Company’s Form 8-K filed on October 29, 2012. The Company used these proceeds for general corporate purposes, including the reduction of outstanding bank debt and for capital expenditures on oil and gas developments. The note may, at the Company’s option, be repaid by converting the interest and principal amounts due to common stock, thus reducing the Company’s cash needs to service its debt. In January 2013, the scheduled payment of $854,167 was paid in cash, which included $833,333 in principal and $20,834 in interest. In April 2013, 479,589 common shares were issued in lieu of the scheduled payment of $833,333. According to the note agreement, the note holders may elect to convert the principal balance into shares of the Company's common stock. During 2013, the note holders submitted conversion notices to the Company such that 787,055 common shares were issued for a reduction in the note principal of $1,666,666. In September 2013, this note was paid in full. In addition to the note, Royale issued a warrant for 500,000 shares of its common stock. The fair market value of this warrant was offset against the value of the warrant and amortized over the life of the loan. During the life of the loan, $100,779 was expensed to interest expense in 2012 in excess 301,415 in 2013 with the remaining 1,144,084 recorded to additional paid in capital in 2013.
In February 2009, we entered into an agreement with Texas Capital Bank, N.A. for a new revolving line of credit and letter of credit facility, also secured by our oil and gas properties, of up to $14,250,000 and separate letter of credit facility of up to $750,000, for the purposes of refinancing Royale’s existing debt and to fund development, exploration and acquisition activities as well as other general corporate purposes. The scheduled maturity date for the loan was February 13, 2013. During January 2013, the balance of $350,000 on this credit facility was paid in full. In February 2013, the revolving credit agreement matured.
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, 2014, and the effect such obligations are expected to have on our liquidity and cash flow in future periods.
| |
|
Total Obligations
|
|
|
2015
|
|
|
2016-2017 |
|
|
2018 |
|
|
Beyond
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Building Purchase Note
|
|
$ |
2,179,143 |
|
|
$ |
114,301 |
|
|
$ |
228,602 |
|
|
$ |
114,301 |
|
|
$ |
1,721,939 |
|
Operating Activities. For the years ended December 31, 2014 and 2013, cash used by operating activities totaled $3,151,949 and $2,911,000, respectively. This $240,949 increase in cash used was mainly due to the increase in our other receivables during the year in 2014, due to a receivable from an industry partner.
Investing Activities. For the year ended December 31, 2014, cash provided by investing activities was $1,359,673 compared to $5,233,341 provided by investing activities in 2013, a difference of $3,873,668. This difference was primarily due to the sale of a portion of our leases in Alaska, from which we received proceeds of approximately $4 million, during the period in 2013. Additionally, our turnkey drilling program proceeds and expenditures were lower in 2014, where we drilled four wells and participated in the drilling of one well, while in 2013 we drilled six wells and participated in the drilling of two wells.
Financing Activities. Net cash used by financing activities totaled $24,116 and net cash provided by financing activities was $1,065,962 for the years ended December 31, 2014 and 2013, respectively. This difference in cash was mainly due to the proceeds received during 2013 for common stock sales and warrant exercises. During 2013 Royale received proceeds of $1,021,668 and issued 500,000 shares of its common stock relating to its market equity offering program. Also during the period in 2013, several warrants were exercised in exchange for shares of Royale’s common stock, and we received $1,227,627 and issued 630,619 shares of our common stock relating to these exercises. These proceeds were added to working capital and used for ordinary operating expense. In 2014 the cash used from financing activities was used in principal payments from the loan used to finance the purchase of our corporate headquarters.
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-22.
During 2013, our overall proved developed and undeveloped reserves decreased by 13% and our previously estimated proved developed and undeveloped reserve quantities were revised downward by approximately 0.8 million cubic feet of natural gas. This downward revision was primarily due to three California wells, two drilled in 2011 and one drilled in 2012, 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-22.
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 2014, we sold a majority of our natural gas at the daily market rate through the Pacific Gas & Electric pipeline. In 2014, our natural gas revenues were approximately $2.5 million with an average price of $4.64 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 $250,000. 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 $6,000. 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 co-chief executive officers, Donald H. Hosmer and Stephen M. Hosmer (who is also our chief financial officer), evaluated the effectiveness or our disclosure controls and procedures as of the end of the 2014 fiscal year. Based on their evaluation, they concluded that our disclosure controls are effective as of December 31, 2014.
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, 2014, 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 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Our management, including our CEO’s 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, 2014:
|
Name
|
|
Age
|
|
|
First Became Director or
Executive Officer
|
|
Positions Held
|
| |
|
|
|
|
|
|
|
|
Harry E. Hosmer
|
|
84
|
|
|
1986
|
|
Chairman of the Board
|
|
Donald H. Hosmer
|
|
61
|
|
|
1987
|
|
Co-President, Co-Chief Executive Officer and Director
|
|
Stephen M. Hosmer
|
|
48
|
|
|
1996
|
|
Co-President, Co-Chief Executive Officer, Chief Financial Officer, Secretary, and Director
|
|
Oscar A. Hildebrandt (1) (2) (3)
|
|
79
|
|
|
1995
|
|
Director
|
|
Jonathan Gregory (1) (2)
|
|
50
|
|
|
2014
|
|
Director
|
|
Gary Grinsfelder (1), (3)
|
|
66
|
|
|
2007
|
|
Director
|
|
Tony Hall (2) (3)
|
|
73
|
|
|
2007
|
|
Director
|
(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, Tony Hall, Oscar Hildebrandt, and Jonathan Gregory qualify as independent directors under NASDAQ rules.
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.
Donald H. Hosmer – Co-President, Co-Chief Executive Officer 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 – Co-President, Co-Chief Executive Officer, 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.
Oscar Hildebrandt, D.V.M. – Director
Dr. Hildebrandt served as an advisory member of Royale Energy’s board of directors from 1994 to 1995 and became a director in 1995. Dr. Hildebrandt practiced veterinary medicine as President of Medford Veterinary Clinic, Medford, Wisconsin, from 1960 to 1990. Since 1990, Dr. Hildebrandt has engaged independently in veterinary practice consulting services. He has served on the board of directors of Fidelity National Bank - Medford, Wisconsin, and its predecessor bank from 1965 to the present and is past chairman of the board of the Bank. From 1990 to the present he has acted as a financial advisor engaged in private business interests. Dr. Hildebrandt received a Bachelor of Science degree from the University of Wisconsin in 1954 and a Doctor of Veterinary Medicine degree from the University of Minnesota in 1958.
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.
Tony Hall – Director
Ambassador Hall served as a member of the United States House of Representatives, representing the people of the Third District of Ohio, for almost twenty-four years, from 1979 to 2002. In 2002 he was appointed U.S. Ambassador to the United Nations Agencies for Food and Agriculture. He served as chief of the U.S. Mission to the U.N. Agencies in Rome – the Work Food Program, Food and Agriculture Organization and International Fund for Agricultural Development. He has been nominated for the Nobel Peace Prize on three occasions for his humanitarian and hunger-related work. He received his A. B. degree from Denison University, Granville, Ohio, in 1964.
Jonathan Gregory – Director
Mr. Gregory’s appointment replaces the resignation for health reasons of long time board member George Watters. Mr. Watters joined the Royale Board in 1991 and has contributed a great deal of wisdom and industry experience for more than 20 years. Most recently, Jonathan served as chief financial officer for a private independent exploration and production company, where he was actively engaged in raising equity and acquisitions and development activities. Mr. Gregory is a member of Houston Producers Forum; 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 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. He serves as chairman of Royale Energy’s audit committee.
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. In accordance with the rules of NASDAQ for listed companies, 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 Oscar A. Hildebrandt qualifies as an “audit committee financial expert” as defined in Item 407(d)(5) of the Securities and Exchange Commission.
In 2014, the members of the audit committee were Jonathan Gregory, chair, Oscar A. Hildebrandt 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 2014.
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 were made during 2014.
|
Name and
|
|
|
|
|
|
|
|
|
|
Option
|
|
|
All Other
|
|
|
|
|
|
Principal Position
|
|
Year
|
|
Salary
|
|
|
Bonus
|
|
|
Awards
|
|
|
Compensation (2)
|
|
|
Total
|
|
| |
|
|
|
($)
|
|
|
($)
|
|
|
($)
|
|
|
($)
|
|
|
($)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Donald H. Hosmer
|
|
2014
|
|
$ |
230,192 |
|
|
$ |
25,000 |
|
|
|
(1) |
|
|
$ |
6,906 |
|
|
$ |
262,098 |
|
|
Co-President and Co-CEO
|
|
2013
|
|
$ |
230,192 |
|
|
$ |
25,000 |
|
|
|
|
|
|
$ |
7,656 |
|
|
$ |
262,848 |
|
|
|
|
2012
|
|
$ |
230,192 |
|
|
|
|
|
|
|
|
|
|
$ |
6,906 |
|
|
$ |
237,098 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stephen M. Hosmer
|
|
2014
|
|
$ |
230,192 |
|
|
$ |
25,000 |
|
|
|
(1) |
|
|
$ |
18,906 |
|
|
$ |
274,098 |
|
|
Co-President, Co-CEO & CFO
|
|
2013
|
|
$ |
230,192 |
|
|
$ |
25,000 |
|
|
|
|
|
|
$ |
19,656 |
|
|
$ |
274,848 |
|
| |
|
2012
|
|
$ |
230,192 |
|
|
|
|
|
|
|
|
|
|
$ |
19,110 |
|
|
$ |
249,302 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mohamed Abdel-Rahmen (3)
|
|
2014
|
|
$ |
163,692 |
|
|
|
|
|
|
|
|
|
|
$ |
4,911 |
|
|
$ |
168,603 |
|
|
VP Exploration
|
|
2013
|
|
$ |
167,025 |
|
|
|
|
|
|
|
|
|
|
$ |
5,011 |
|
|
$ |
172,036 |
|
|
|
|
2012
|
|
$ |
204,615 |
|
|
|
|
|
|
|
|
|
|
$ |
6,138 |
|
|
$ |
217,085 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Charles Tiano (3)
|
|
2014
|
|
$ |
50,642 |
|
|
|
178,892 |
|
|
|
|
|
|
$ |
6,886 |
|
|
$ |
236,420 |
|
|
Director of Investor Relations
|
|
2013
|
|
$ |
49,955 |
|
|
$ |
193,825 |
|
|
|
|
|
|
$ |
7,313 |
|
|
$ |
251,093 |
|
|
|
|
2012
|
|
$ |
56,269 |
|
|
$ |
138,450 |
|
|
|
|
|
|
$ |
9,736 |
|
|
$ |
204,455 |
|
|
(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. These options vest in four parts on October 13, 2014, January 1, 2015, April 1, 2015 and July 1, 2015. These options were granted for a period of 3 years and will expire on December 31, 2017. At December 31, 2014, Royale Energy’s stock price, $2.11, 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 Stephen M. Hosmer, who also received a $12,000 car allowance. |
| |
|
(3) Mr. Abdel-Rahmen and Mr. Tiano are highly compensated employees under SEC rules who did not serve as executive officers during 2014.
|
Stock Options and Equity Compensation; Outstanding Equity Awards at Fiscal Year End
The following table presents the number of unexercised options at the 2014 year end for each named executive officer. No unvested stock awards were outstanding at the end of 2014.
|
Options
|
|
Name
|
|
Number of securities underlying unexercised options
(#)
exercisable
|
|
|
Number of securities underlying unexercised options
(#)
unexercisable
|
|
|
Option exercise price
($)
|
|
Option
expiration
date
|
| |
|
|
|
|
|
|
|
|
|
|
|
Donald H. Hosmer
|
|
|
50,000
|
(1)
|
|
|
-
|
|
|
$
|
3.25
|
|
12/31/2015
|
| |
|
|
10,000
|
(2)
|
|
|
10,000
|
(2)
|
|
|
5.00
|
|
12/31/2017
|
|
Stephen M. Hosmer
|
|
|
50,000
|
(1)
|
|
|
-
|
|
|
$
|
3.25
|
|
12/31/2015
|
| |
|
|
10,000
|
(2)
|
|
|
10,000
|
(2)
|
|
|
5.00
|
|
12/31/2017
|
|
(1)
|
In December 2010, the directors and executive officers of Royale Energy were each granted 20,000 options to purchase common stock at an exercise or base price of $3.25 per share, in consideration of their past service on the board. These options vested and became exercisable over two years, on January 1, 2012 and 2013. They were granted for a period of five years with a service period of two years.
|
|
(2)
|
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 were granted for a period of 3 years and will expire on December 31, 2017. These options become exercisable at 5,000 shares per period beginning October 13, 2014, January 1, 2015, April 1, 2015 and July 1 2015.
|
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:
Oscar A. Hildebrandt, Chair
Tony P. Hall
Jonathan Gregory
In accordance with the rules of NASDAQ for listed companies, 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 two top executives: Co-Presidents and the Co-Chief Executive Officers Donald H. Hosmer and Stephen M. Hosmer. 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. Each executive does 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 $25,000 to each officer.
Compensation of Directors
In 2014, none of the board members or committee member received fees for attendance at board meetings or committee meetings during the year. Royale Energy did reimburse directors for the expenses incurred for their services.
In addition, Royale Energy's Chairman of the Board and former President, Harry E. Hosmer, renders and receives compensation for management consulting services to Royale Energy on an ongoing basis. See Certain Relationships and Related Transactions, page 23.
The following table describes the compensation paid to our directors who are not also named executives for their services in 2014.
|
Name
|
|
Fees earned or
paid in cash
|
|
|
Stock awards
|
|
|
Option awards
|
|
|
All Other Compensation (1)
|
|
|
Total
|
|
| |
|
($)
|
|
|
($)
|
|
|
($)
|
|
|
($)
|
|
|
($)
|
|
|
Harry E. Hosmer
|
|
$
|
190,660
|
|
|
$
|
0
|
|
|
$
|
0
|
|
|
$
|
7,622
|
|
|
$
|
198,282
|
|
|
Oscar A. Hildebrandt
|
|
$
|
25,000
|
|
|
$
|
0
|
|
|
$
|
0
|
|
|
|
0
|
|
|
$
|
25,000
|
|
|
Jonathan Gregory
|
|
$
|
6,250
|
|
|
$
|
0
|
|
|
$
|
0
|
|
|
|
0
|
|
|
$
|
6,250
|
|
|
Gary Grinsfelder
|
|
$
|
25,000
|
|
|
$
|
0
|
|
|
$
|
0
|
|
|
|
0
|
|
|
$
|
25,000
|
|
|
Tony P. Hall
|
|
$
|
25,000
|
|
|
$
|
0
|
|
|
$
|
0
|
|
|
|
0
|
|
|
$
|
25,000
|
|
(1) Other compensation paid to Harry E. Hosmer in 2014 consisted of payments for medical and dental insurance coverage.
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Common Stock
On March 6, 2015, 14,945,789 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 March 6, 2015, 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
|
|
| |
|
|
|
|
|
|
|
Harry E. Hosmer, (3)
|
|
|
667,692
|
|
|
|
4.45%
|
|
| |
|
|
|
|
|
|
|
|
|
Donald H. Hosmer, (3)
|
|
|
936,162
|
|
|
|
6.23%
|
|
| |
|
|
|
|
|
|
|
|
|
Stephen M. Hosmer, (3) (4)
|
|
|
1,221,035
|
|
|
|
8.13%
|
|
| |
|
|
|
|
|
|
|
|
|
Oscar A. Hildebrandt, (2) (5)
|
|
|
83,936
|
|
|
|
*
|
|
| |
|
|
|
|
|
|
|
|
|
Jonathan Gregory, (2)
|
|
|
21,000
|
|
|
|
*
|
|
| |
|
|
|
|
|
|
|
|
|
Gary Grinsfelder, (2)
|
|
|
65,440
|
|
|
|
*
|
|
| |
|
|
|
|
|
|
|
|
|
Tony P. Hall, (2)
|
|
|
88,749
|
|
|
|
*
|
|
| |
|
|
|
|
|
|
|
|
|
All officers and directors as a group
|
|
|
3,064,014
|
|
|
|
20.01%
|
|
| |
|
|
|
|
|
|
|
|
|
* Less than 1%
|
|
|
|
|
|
|
|
|
(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 31, 2013: Harry E. Hosmer 70,000, Donald H. Hosmer 70,000; Stephen M. Hosmer 70,000; Gary Grinsfelder 60,000; Tony Hall 70,000; Oscar A. Hildebrandt 26,308; 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.
(5) Includes 33,064 shares held by a trust.
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, 2014, 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, Harry E. Hosmer, Oscar Hildebrandt and Tony Hall 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 176 and 174 wells respectively under the 1989 policy. The Hosmer Trust, a trust for the benefit of family members of Harry E. Hosmer, has participated in 173 wells.
Investments in wells under the 1989 policy for the three years ended December 31, 2014, 2013, and 2012 are as follows:
| |
|
Year
|
|
# of fractional interests
|
|
|
Amount
|
|
|
Donald Hosmer
|
|
2014
|
|
|
4
|
|
|
$
|
18,692
|
|
| |
|
2013
|
|
|
6
|
|
|
$
|
31,767
|
|
| |
|
2012
|
|
|
2
|
|
|
$
|
4,186
|
|
|
Stephen Hosmer
|
|
2014
|
|
|
4
|
|
|
$
|
7,714
|
|
| |
|
2013
|
|
|
5
|
|
|
$
|
12,262
|
|
| |
|
2012
|
|
|
2
|
|
|
$
|
2,537
|
|
|
Hosmer Trust
|
|
2014
|
|
|
3
|
|
|
$
|
9,985
|
|
| |
|
2013
|
|
|
6
|
|
|
$
|
41,488
|
|
| |
|
2012
|
|
|
2
|
|
|
$
|
2,537
|
|
Current officers and directors were billed $0, $16,967 and $3,451 for their interests for the three years ended December 31, 2014, 2013, and 2012, 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, $193,270 and $138,050 for his consulting services in 2014, 2013, and 2012, 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, 2014. This is the first annual audit performed by SingerLewak LLP, Padgett Stratemann & Co., LLP previously performed annual audits. The aggregate fees billed by Padgett Stratemann & Co., LLP and SingerLewak LLP for the years ended December 31, 2014 and 2013 are as follows, respectively:
| |
|
2014
|
|
|
2013
|
|
|
Audit fees (1)
|
|
$
|
159,891
|
|
|
$
|
153,271
|
|
|
Tax fees (2)
|
|
|
-
|
|
|
|
-
|
|
|
All other fees (3)
|
|
$
|
25,600
|
|
|
$
|
21,650
|
|
|
Total
|
|
$
|
185,491
|
|
|
$
|
174,921
|
|
(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, Jonathan Gregory, 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-22.
|
|
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
|
|
|
23.3
|
|
|
23.4
|
|
|
31.1
|
|
|
31.2
|
|
|
32.1
|
|
|
32.2
|
|
|
99.1
|
|
|
99.2
|
|
|
99.3
|
Waiver Letter from Cranshire Capital, L.P. to the Company dated October 28, 2013, incorporated by reference to Exhibit 99.1 of the Company’s Form 8-K filed October 29, 2013.
|
|
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 30, 2015
|
|
/s/ Donald H. Hosmer
|
| |
|
Donald H. Hosmer
|
| |
|
Co-President and Co-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 30, 2015
|
|
/s/ Harry E. Hosmer
|
| |
|
Harry E. Hosmer
|
| |
|
Chairman of the Board of Directors
|
|
Date: March 30, 2015
|
|
/s/ Donald H. Hosmer
|
| |
|
Donald H. Hosmer
|
| |
|
Director, Co-President, Co-Chief Executive Officer
|
|
Date: March 30, 2015
|
|
/s/ Stephen M. Hosmer
|
| |
|
Stephen M. Hosmer
|
| |
|
Director, Co-President, Co-Chief Executive Officer, Chief Financial Officer and Secretary
|
|
Date: March 30, 2015
|
|
/s/ Tony Hall
|
| |
|
Tony Hall
|
| |
|
Director
|
|
Date: March 30, 2015
|
|
/s/ Oscar A. Hildebrandt
|
| |
|
Oscar A. Hildebrandt
|
| |
|
Director
|
|
Date: March 30, 2015
|
|
/s/ Gary Grinsfelder
|
| |
|
Gary Grinsfelder
|
| |
|
Director
|
|
Date: March 30, 2015
|
|
/s/ Jonathan Gregory
|
| |
|
Jonathan Gregory
|
| |
|
Director
|
INDEX TO FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA
|
|
F-1
|
| |
|
|
|
F-2
|
| |
|
|
|
F-3
|
| |
|
|
|
F-5
|
| |
|
|
|
F-6
|
| |
|
|
|
F-7
|
| |
|
|
|
F-8
|
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders
Royale Energy, Inc.
We have audited the accompanying balance sheet of Royale Energy, Inc. (the “Company”) as of December 31, 2014, and the related statements of comprehensive (loss), stockholders’ (deficit) and cash flows for the year 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 audit.
We conducted our audit 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 audit provides a reasonable basis for our opinion.
In our opinion, the 2014 financial statements referred to above present fairly, in all material respects, the financial position of Royale Energy, Inc. as of December 31, 2014, and the results of its operations and its cash flows for the year then ended in conformity with U.S. generally accepted accounting principles.
SingerLewak LLP
Los Angeles, California
March 30, 2015
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Royale Energy, Inc.
We have audited the accompanying balance sheet of Royale Energy, Inc. (the “Company”) as of December 31, 2013, and the related statements of comprehensive income (loss), stockholders’ equity (deficit), and cash flows for the year 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 audit.
We conducted our audit 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 audit 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 audit provides 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, 2013, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.
/s/ Padgett, Stratemann & Co., L.L.P.
San Antonio, Texas
March 11, 2014
BALANCE SHEETS
DECEMBER 31, 2014 AND 2013
ASSETS
| |
|
2014
|
|
|
2013
|
|
| |
|
|
|
|
|
|
|
Current Assets
|
|
|
|
|
|
|
|
Cash and Cash Equivalents
|
|
$ |
3,061,841 |
|
|
$ |
4,878,233 |
|
|
Other Receivables, net
|
|
|
1,760,181 |
|
|
|
1,152,473 |
|
|
Revenue Receivables
|
|
|
493,295 |
|
|
|
528,319 |
|
|
Prepaid Expenses
|
|
|
158,404 |
|
|
|
191,202 |
|
|
Available for Sale Securities
|
|
|
0 |
|
|
|
16,448 |
|
| |
|
|
|
|
|
|
|
|
|
Total Current Assets
|
|
|
5,473,721 |
|
|
|
6,766,675 |
|
| |
|
|
|
|
|
|
|
|
|
Other Assets
|
|
|
510,821 |
|
|
|
494,592 |
|
| |
|
|
|
|
|
|
|
|
|
Oil And Gas Properties (Successful Efforts Basis), Real Property and Equipment and Fixtures, net
|
|
|
7,594,666 |
|
|
|
7,554,425 |
|
| |
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$ |
13,579,208 |
|
|
$ |
14,815,692 |
|
The accompanying notes are an integral part of these financial statements.
ROYALE ENERGY, INC.
BALANCE SHEETS
DECEMBER 31, 2014 AND 2013
LIABILITIES AND STOCKHOLDERS' EQUITY
| |
|
2014
|
|
|
2013
|
|
|
Current Liabilities:
|
|
|
|
|
|
|
|
Accounts Payable and Accrued Expenses
|
|
$ |
4,502,559 |
|
|
$ |
5,332,323 |
|
|
Current Portion of Long-Term Debt
|
|
|
29,031 |
|
|
|
22,916 |
|
|
Current Portion of Deferred Tax Liability
|
|
|
0 |
|
|
|
1,775 |
|
|
Deferred Drilling Obligations
|
|
|
7,937,786 |
|
|
|
6,125,933 |
|
| |
|
|
|
|
|
|
|
|
|
Total Current Liabilities
|
|
|
12,469,376 |
|
|
|
11,482,947 |
|
| |
|
|
|
|
|
|
|
|
|
Noncurrent Liabilities:
|
|
|
|
|
|
|
|
|
|
Asset Retirement Obligation
|
|
|
804,206 |
|
|
|
862,369 |
|
|
Note Payable, less current portion
|
|
|
1,446,853 |
|
|
|
1,477,084 |
|
| |
|
|
|
|
|
|
|
|
|
Total Noncurrent Liabilities
|
|
|
2,251,059 |
|
|
|
2,339,453 |
|
| |
|
|
|
|
|
|
|
|
|
Total Liabilities
|
|
|
14,720,435 |
|
|
|
13,822,400 |
|
| |
|
|
|
|
|
|
|
|
|
Stockholders' Equity (Deficit)
|
|
|
|
|
|
|
|
|
|
Convertible Preferred Stock, Series AA, No Par Value, 147,500 Shares Authorized; 46,662 and 52,784 Shares Issued and Outstanding, at December 31, 2014 and 2013 Respectively
|
|
|
136,149 |
|
|
|
154,014 |
|
|
Common Stock, No Par Value, 20,000,000 Shares Authorized; 14,945,789 and 14,942,728 Shares Issued and Outstanding, at December 31, 2014 and 2013 respectively
|
|
|
38,014,730 |
|
|
|
37,996,866 |
|
|
Paid in Capital
|
|
|
337,640 |
|
|
|
303,855 |
|
| |
|
|
|
|
|
|
|
|
|
Accumulated (Deficit)
|
|
|
(39,623,243 |
) |
|
|
(37,471,388 |
) |
|
Accumulated Other Comprehensive Income (Loss)
|
|
|
(6,503 |
) |
|
|
9,945 |
|
| |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
Total Stockholders' Equity (Deficit)
|
|
|
(1,141,227 |
) |
|
|
993,292 |
|
| |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
Total Liabilities and Stockholders' Equity (Deficit)
|
|
$ |
13,579,208 |
|
|
$ |
14,815,692 |
|
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
FOR THE YEARS ENDED DECEMBER 31, 2014, AND 2013
| |
|
2014
|
|
|
2013
|
|
|
Revenues:
|
|
|
|
|
|
|
|
Sale of Oil and Gas
|
|
$ |
2,598,297 |
|
|
$ |
1,913,364 |
|
|
Supervisory Fees and Other
|
|
|
623,201 |
|
|
|
659,697 |
|
| |
|
|
|
|
|
|
|
|
|
Total Revenues
|
|
|
3,221,498 |
|
|
|
2,573,061 |
|
| |
|
|
|
|
|
|
|
|
|
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
General and Administrative
|
|
|
3,162,113 |
|
|
|
3,279,505 |
|
|
Lease Operating
|
|
|
1,427,673 |
|
|
|
936,631 |
|
|
Delay Rentals
|
|
|
616,806 |
|
|
|
457,554 |
|
|
Lease Impairment
|
|
|
268,093 |
|
|
|
70,203 |
|
|
Geological and Geophysical
|
|
|
0 |
|
|
|
50,145 |
|
|
Inventory Write Down
|
|
|
0 |
|
|
|
39,185 |
|
|
Bad Debt Expense
|
|
|
653,133 |
|
|
|
146,704 |
|
|
Legal and Accounting
|
|
|
401,160 |
|
|
|
326,270 |
|
|
Marketing
|
|
|
430,779 |
|
|
|
332,482 |
|
|
Depreciation, Depletion and Amortization
|
|
|
315,574 |
|
|
|
309,806 |
|
| |
|
|
|
|
|
|
|
|
|
Total Costs and Expenses
|
|
|
7,275,331 |
|
|
|
5,948,485 |
|
| |
|
|
|
|
|
|
|
|
|
Gain on Turnkey Drilling Programs
|
|
|
1,640,731 |
|
|
|
2,008,734 |
|
|
Gain on Sale of Assets
|
|
|
342,851 |
|
|
|
2,820,315 |
|
| |
|
|
|
|
|
|
|
|
|
Income (Loss) from Operations
|
|
|
(2,070,251 |
) |
|
|
1,453,625 |
|
| |
|
|
|
|
|
|
|
|
|
Other Income (Expense):
|
|
|
|
|
|
|
|
|
|
Interest Expense
|
|
|
(81,605 |
) |
|
|
(304,472 |
) |
| |
|
|
|
|
|
|
|
|
|
Income Before Income Tax Expense
|
|
|
(2,151,856 |
) |
|
|
1,149,153 |
|
| |
|
|
|
|
|
|
|
|
|
Net Income (Loss)
|
|
|
(2,151,856 |
) |
|
|
1,149,153 |
|
| |
|
|
|
|
|
|
|
|
|
Basic Earnings (Loss) Per Share:
|
|
|
(0.14 |
) |
|
|
0.08 |
|
| |
|
|
|
|
|
|
|
|
|
Diluted Earnings (Loss) Per Share
|
|
|
(0.14 |
) |
|
|
0.08 |
|
| |
|
|
|
|
|
|
|
|
|
Other Comprehensive Income (Loss)
|
|
|
|
|
|
|
|
|
|
Unrealized Gain on Equity Securities
|
|
|
(16,448 |
) |
|
|
9,945 |
|
|
Less: Reclassification Adjustment for Gains Included in Net Income
|
|
|
0 |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
Other Comprehensive Income (Loss) , before tax
|
|
|
(16,448 |
) |
|
|
9,945 |
|
| |
|
|
|
|
|
|
|
|
|
Other Comprehensive Income (Loss), net of tax
|
|
|
(16,448 |
) |
|
|
9,945 |
|
| |
|
|
|
|
|
|
|
|
|
Comprehensive Income (Loss)
|
|
|
(2,168,304 |
) |
|
|
1,159,098 |
|
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)
FOR THE YEARS ENDED DECEMBER 31, 2014, and 2013
| |
|
|
|
|
|
|
|
Preferred Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Common Stock
|
|
|
Series AA
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
| |
|
Number Shares
|
|
|
|
|
|
Number Shares
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
| |
|
Issued and
|
|
|
|
|
|
Issued and
|
|
|
|
|
|
Additional
|
|
|
Accumulated
|
|
|
Comprehensive
|
|
|
|
|
| |
|
Outstanding
|
|
|
Amount
|
|
|
Outstanding
|
|
|
Amount
|
|
|
Paid in Capital
|
|
|
Deficit
|
|
|
Income (Loss)
|
|
|
Total
|
|
Balance, December 31, 2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock Warrant Exercise
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock Private Placement Sale
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Available for Sale Securities -
Unrealized Gain (Loss), net of tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Series AA Conversion to Common (2 for 1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Director's Stock Options Grant
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Available for Sale Securities -
Unrealized Gain (Loss), net of tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2014, and 2013
| |
|
2014
|
|
|
2013
|
|
| |
|
|
|
|
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments to Reconcile Net Income (Loss) to Net Cash Used by Operating Activities:
|
|
|
|
|
|
|
|
|
Depreciation, Depletion, and Amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on Turnkey Drilling Programs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt Discount Amortization
|
|
|
|
|
|
|
|
|
Inventory and Other Assets Write Down
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other & Revenue Receivables
|
|
|
|
|
|
|
|
|
Prepaid Expenses and Other Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts Payable and Accrued Expenses
|
|
|
|
|
|
|
|
|
Deferred –Drilling Obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Used by Operating Activities
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Expenditures For Oil And Gas Properties and
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
Proceeds from Turnkey Drilling Programs
|
|
|
|
|
|
|
|
|
Proceeds from Sale of Assets
|
|
|
|
|
|
|
|
|
Net Cash Provided by Investing Activities
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
Net Cash Provided by (Used In) Financing Activities
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
Net Increase (Decrease) in Cash and Cash Equivalents
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
Cash & Cash Equivalents at Beginning of Year
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
Cash & Cash Equivalents at End of Year
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
Supplemental Schedule of Non-Cash Investing and Financing Transactions:
|
|
|
|
|
|
|
|
|
Purchase of Office building with note payable financing
|
|
|
|
|
|
|
|
|
Conversion of convertible notes to common stock
|
|
|
|
|
|
|
|
|
Accretion of discount to paid-in-capital upon early conversion of convertible notes
|
|
|
|
|
|
|
|
|
Conversion of Series AA Stock to Common Stock
|
|
|
|
|
|
|
|
|
Unrealized Gain (Loss) on Available-for-Sale Securities, net of tax effect
|
|
|
|
|
|
|
|
|
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” 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, 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 interests . Assuming there are no further changes in expected sales and expense trends subsequent to March 30, 2015, the Company believes that its cash position 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 2014 and 2013, impairment losses of $268,093 and $70,203, 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, 2014 and 2013, Royale Energy had Deferred Drilling Obligations of $7,937,786 and $6,125,933 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, 2014 and 2013, the Company established an allowance for uncollectable accounts of $1,734,713 and $1,081,580, 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 income (losses) per share are calculated as follows:
| |
|
For the Year Ended December 31, 2014
|
|
| |
|
Income
(Numerator)
|
|
|
Shares
(Denominator)
|
|
|
Per-Share
Amount
|
|
|
Basic Income Per Share:
|
|
|
|
|
|
|
|
|
|
|
Net loss available to common stock
|
|
$
|
(2,151,856
|
) |
|
|
14,943,323
|
|
|
$
|
(.14
|
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted Income Per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of dilutive securities and stock options
|
|
|
|
|
|
|
-
|
|
|
$
|
-
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stock
|
|
$
|
(2,151,856
|
) |
|
|
14,943,323
|
|
|
$
|
(.14
|
) |
| |
|
For the Year Ended December 31, 2013
|
|
| |
|
Income
(Numerator)
|
|
|
Shares
(Denominator)
|
|
|
Per-Share
Amount
|
|
|
Basic Loss Per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stock
|
|
$
|
1,149,153
|
|
|
|
13,853,290
|
|
|
$
|
0.08
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss Per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of dilutive securities and stock options
|
|
|
|
|
|
|
435,195
|
|
|
$
|
0.00
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stock
|
|
$
|
1,149,153
|
|
|
|
14,288,485
|
|
|
$
|
0.08
|
|
For the year ended December 31, 2014, Royale Energy had dilutive securities of 161,966. 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, 2014, Royale Energy reported the fair value of $0 in available for sale securities. The fair value was determined using the number of shares owned as of December 31, 2014, multiplied by the market price of those securities on December 31, 2014. At December 31, 2013, Royale Energy quoted prices in active markets for identical assets when determining the fair value measurements at the reporting date. The following table summarizes Royale’s financial assets measured and recognized at fair value on a recurring basis and classified under the appropriate level of the fair value hierarchy as described above:
|
December 31, 2014
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
|
Cash equivalents:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Money market funds
|
|
$
|
--
|
|
|
$
|
--
|
|
|
$
|
--
|
|
|
$
|
--
|
|
|
Commercial paper
|
|
|
--
|
|
|
|
--
|
|
|
|
--
|
|
|
|
--
|
|
|
Short term marketable investments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Available-for-sale securities
|
|
|
--
|
|
|
|
--
|
|
|
|
--
|
|
|
|
--
|
|
|
Total assets at fair value
|
|
$
|
--
|
|
|
$
|
--
|
|
|
$
|
--
|
|
|
$
|
--
|
|
|
December 31, 2013
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
|
Cash equivalents:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Money market funds
|
|
$
|
--
|
|
|
$
|
--
|
|
|
$
|
--
|
|
|
$
|
--
|
|
|
Commercial paper
|
|
|
--
|
|
|
|
--
|
|
|
|
--
|
|
|
|
--
|
|
|
Short term marketable investments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Available-for-sale securities
|
|
|
16,448
|
|
|
|
--
|
|
|
|
--
|
|
|
|
16,448
|
|
|
Total assets at fair value
|
|
$
|
16,448
|
|
|
$
|
--
|
|
|
$
|
--
|
|
|
$
|
16,448
|
|
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, 2014, and have determined that the updates are not applicable to the Company.
NOTE 2 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES
Oil and gas properties, equipment and fixtures consist of the following at December 31:
| |
|
2014
|
|
|
2013
|
|
|
Oil and Gas
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
Producing properties, including intangible drilling costs
|
|
$ |
4,920,521 |
|
|
$ |
4,862,657 |
|
|
Undeveloped properties
|
|
|
2,773,422 |
|
|
|
2,779,672 |
|
|
Lease and well equipment
|
|
|
4,410,120 |
|
|
|
4,392,363 |
|
| |
|
|
12,104,063 |
|
|
|
12,034,692 |
|
|
Accumulated depletion, depreciation and amortization
|
|
|
(7,318,510 |
) |
|
|
(7,065,362 |
) |
| |
|
|
|
|
|
|
|
|
| |
|
|
4,785,553 |
|
|
$ |
4,969,330 |
|
| |
|
2014
|
|
|
2013
|
|
|
Commercial and Other
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
Real estate, including furniture and fixtures
|
|
$ |
2,768,394 |
|
|
$ |
2,503,803 |
|
|
Vehicles
|
|
|
116,830 |
|
|
|
120,314 |
|
|
Furniture and equipment
|
|
|
1,114,086 |
|
|
|
1,300,523 |
|
| |
|
|
3,999,310 |
|
|
|
3,924,640 |
|
|
Accumulated depreciation
|
|
|
(1,190,197 |
) |
|
|
(1,339,545 |
) |
| |
|
|
2,809,113 |
|
|
|
2,585,095 |
|
| |
|
$ |
7,594,666 |
|
|
|
7,554,425 |
|
The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed:
| |
|
2014
|
|
|
2013
|
|
| |
|
|
|
|
|
|
|
Acquisition - Proved
|
|
$
|
3,215
|
|
|
|
7,663
|
|
|
Acquisition- Unproved
|
|
$
|
84,715
|
|
|
|
0
|
|
|
Development
|
|
$
|
1,346,433
|
|
|
|
1,080,043
|
|
|
Exploration
|
|
$
|
2,309,105
|
|
|
|
4,822,260
|
|
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 2014 or 2013. 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,
|
|
| |
|
2014
|
|
|
2013
|
|
|
Beginning balance at January 1
|
|
$
|
0
|
|
|
$
|
0
|
|
| |
|
|
|
|
|
|
|
|
|
Additions to capitalized exploratory well costs pending the determination of proved reserves
|
|
$
|
188,017
|
|
|
$
|
410,303
|
|
| |
|
|
|
|
|
|
|
|
|
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves
|
|
$
|
(188,017
|
) |
|
$
|
(410,303
|
) |
| |
|
|
|
|
|
|
|
|
|
Ending balance at December 31
|
|
$
|
0
|
|
|
$
|
0
|
|
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:
| |
|
2014
|
|
|
2013
|
|
| |
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
2,598,297
|
|
|
|
1,913,364
|
|
|
Production related costs
|
|
|
(2,044,479
|
) |
|
|
(1,394,185
|
)
|
|
Lease Impairment
|
|
|
(268,093
|
) |
|
|
(70,203
|
)
|
|
Depreciation, depletion and amortization
|
|
|
(315,574
|
) |
|
|
(309,806
|
)
|
| |
|
|
|
|
|
|
|
|
|
Results of operations from producing and
exploration activities
|
|
$
|
(29,849
|
) |
|
|
139,170
|
|
|
Income Taxes (Benefit)
|
|
|
0 |
|
|
|
0
|
|
| |
|
|
|
|
|
|
|
|
|
Net Results
|
|
$
|
(29,849
|
) |
|
|
139,170
|
|
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.
| |
|
2014
|
|
|
2013
|
|
|
Asset retirement obligation, Beginning of the year
|
|
$
|
862,369
|
|
|
$
|
954,088
|
|
|
Liabilities incurred during the period
|
|
|
7,638
|
|
|
|
12,358
|
|
|
Settlements
|
|
|
(66,304
|
) |
|
|
(97,522
|
)
|
|
Accretion expense
|
|
|
503
|
|
|
|
17,106
|
|
|
Revisions in estimated cash flow
|
|
|
|
|
|
|
(23,661
|
) |
| |
|
|
|
|
|
|
|
|
|
Asset retirement obligation, End of year
|
|
$
|
804,206
|
|
|
$
|
862,369
|
|
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, 2014 and 2013 Royale Energy had recorded deferred turnkey drilling associated with undrilled wells of $7,937,786 and $6,125,933, respectively, as a current liability.
| |
|
2014
|
|
|
2013
|
|
| |
|
|
|
|
|
|
|
|
|
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 is 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, Co-CEO, 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, 2014, Royale was not in compliance with this covenant, but obtained a forbearance from the bank from terms of that covenant.
|
|
$
|
1,475,884
|
|
|
$
|
1,500,000
|
|
| |
|
|
|
|
|
|
|
|
|
Total Long Term Debt
|
|
$
|
1,475,884
|
|
|
$
|
1,500,000
|
|
| |
|
|
|
|
|
|
|
|
|
Less Current Maturity
|
|
|
29,031
|
|
|
$
|
22,916
|
|
| |
|
|
|
|
|
|
|
|
|
Long Term Debt Less Current Portion
|
|
$
|
1,445,853
|
|
|
$
|
1,477,084
|
|
Maturities of long-term debt for the years subsequent to December 31, 2014 are as follows:
|
Year Ended December 31,
|
|
|
|
|
2015
|
|
$
|
29,031
|
|
|
2016
|
|
$
|
30,528
|
|
|
2017
|
|
$
|
32,597
|
|
|
2018
|
|
$
|
34,549
|
|
|
Thereafter
|
|
$
|
1,349,179
|
|
| |
|
|
|
|
|
Total
|
|
$
|
1,475,884
|
|
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, 2014 and 2013, respectively, are as follows:
| |
|
2014
|
|
|
2013
|
|
|
Deferred Tax Assets (Liabilities):
|
|
|
|
|
|
|
|
Statutory Depletion Carry Forward
|
|
$
|
672,480
|
|
|
$
|
678,617
|
|
|
Net Operating Loss
|
|
|
4,568,737
|
|
|
|
4,053,001
|
|
|
Other
|
|
|
939,061
|
|
|
|
702,275
|
|
|
Share-Based Compensation
|
|
|
70,921
|
|
|
|
55,990
|
|
|
Capital Loss / AMT Credit Carry Forward
|
|
|
76,410
|
|
|
|
76,410
|
|
|
Charitable Contributions Carry Forward
|
|
|
16,602
|
|
|
|
15,510
|
|
|
Allowance for Doubtful Accounts
|
|
|
681,052
|
|
|
|
412,353
|
|
|
Oil and Gas Properties and Fixed Assets
|
|
|
4,828,214
|
|
|
|
4,723,641
|
|
| |
|
$
|
11,853,477
|
|
|
$
|
10,717,797
|
|
|
Valuation Allowance
|
|
|
(11,853,477
|
) |
|
|
(10,717,797
|
)
|
|
Net Deferred Tax Asset
|
|
$
|
-
|
|
|
$
|
-
|
|
| |
|
|
|
|
|
|
|
|
|
Deferred Tax Assets:
|
|
|
|
|
|
|
|
|
|
Current
|
|
$
|
126,499
|
|
|
$
|
62,333
|
|
|
Non-current
|
|
|
(126,499
|
) |
|
|
(62,333
|
)
|
|
Deferred Tax Liabilities:
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
|
|
|
|
|
|
|
Non-current
|
|
|
|
|
|
|
|
|
|
Net Deferred Tax Asset
|
|
$
|
- |
|
|
$
|
-
|
|
At the end of 2013, 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 2013. At the end of 2014, management reviewed the reliability of the Company’s net deferred tax assets, and due to the Company’s continued cumulative losses in recent years, Royale and it management concluded it is not “more-likely-than-not” its deferred tax assets will be realized. As a result, the Company will continue to record a full valuation allowance against the deferred tax assets in 2014. 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 $1,700,000 at December 31, 2014. The depletion has no expiration date. The Company also has a net operating loss carry forward of approximately $11,300,000 at December 31, 2014, 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:
| |
|
2014
|
|
|
2013
|
|
| |
|
|
|
|
|
|
|
Tax (benefit) computed at statutory rate of 34%
|
|
$
|
(731,630
|
) |
|
$
|
390,712
|
|
| |
|
|
|
|
|
|
|
|
|
Increase (decrease) in taxes resulting from:
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
State tax / percentage depletion / other
|
|
|
|
|
|
|
|
|
|
Other non-deductible expenses
|
|
|
1,665
|
|
|
|
3,078
|
|
|
Change in valuation allowance
|
|
|
729,965
|
|
|
|
(393,790
|
) |
|
Provision (benefit)
|
|
$
|
-
|
|
|
$
|
-
|
|
The components of the Company’s tax provision are as follows:
| |
|
2014
|
|
|
2013
|
|
| |
|
|
|
|
|
|
|
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, 2014, 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 2010 through 2013 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 conversions of 6,122 Series AA Preferred shares, with a book value of $17,865, for 3,061 common shares, and as of December 31, 2014 and 2013, and there were 46,662 and 52,784 shares, respectively of Series AA Preferred stock issued and outstanding.
NOTE 8 - COMMON STOCK
In April 2014, Royale Energy entered into a Sales Agreement with Roth Capital Partners, LLC (Roth), under which the Company may issue and sell shares of its common stock for consideration of up to $10,000,000, from time to time in an at the market equity offering program with Roth acting as the Company’s sales agent (the “Offering”). Sales of common stock if any, under the program will depend upon market conditions and other factors to be determined by the Company and may be made in negotiated transactions or transactions that are deemed to be “at the market offerings” as defined in Rule 415 under the Securities Act of 1933, as amended, including sales made directly on the NASDAQ Capital Market, on any other existing trading market for the common stock or through a market maker. The Company has no obligation to sell any common shares in the program and may at any time suspend solicitation and offers under the program or terminate the program. The Company will pay Roth a commission equal to 3.5% of the gross sales price of any such shares sold, through it as sales agent, as set forth in the Sales Agreement. The Company has also agreed to reimburse Roth for certain expenses incurred in connection with entering into the Sales Agreement and has provided Roth with customary indemnification rights.
In February 2013, Royale Energy entered into a Sales Agreement with C. K. Cooper & Company, Inc. (“CKCC”), under which the Company may issue and sell shares of its common stock for consideration of up to $10,000,000, from time to time in an at the market equity offering program with CKCC acting as the Company’s sales agent (the “Offering”). Sales of common stock if any, under the program will depend upon market conditions and other factors to be determined by the Company and may be made in negotiated transactions or transactions that are deemed to be “at the market offerings” as defined in Rule 415 under the Securities Act of 1933, as amended, including sales made directly on the NASDAQ Capital Market, on any other existing trading market for the common stock or through a market maker. The Company has no obligation to sell any common shares in the program and may at any time suspend solicitation and offers under the program or terminate the program. The Company will pay CKCC a commission equal to 3.5% of the gross sales price of any such shares sold, through it as sales agent, as set forth in the Sales Agreement. The Company has also agreed to reimburse CKCC for certain expenses incurred in connection with entering into the Sales Agreement and has provided CKCC with customary indemnification rights.
In June 2008, Royale Energy entered into a Securities Purchase Agreement with Cranshire Capital, L.P. to issue and sell 547,945 shares of its common stock in exchange for approximately $4,000,000 (i.e. $7.30 per share). As part of the agreement, Cranshire was also issued a warrant to acquire additional shares of its common stock. The warrant is exercisable for an aggregate of 191,781 shares at an exercise price of $7.30 per share. The $7.30 per share price was negotiated as a 15% discount from the 10 day dollar volume weighted average price of the Company’s Common Stock on the NASDAQ Global Market. In conjunction with the August 2009 agreement (see below) the price of these share were adjusted to an exercise price of $1.99 per share. In March 2011, warrants were exercised for 71,918 shares of the Company’s common stock for approximately $143,117 ($1.99 per share). In May and June 2013 warrants were exercised for 321,443 shares of the Company’s Common Stock for approximately $639,672. The net proceeds from the private placement and warrant exercises went towards general corporate purposes, including the acquisition of oil and natural gas properties for future development.
On August 4, 2009, Royale Energy, Inc., entered into a Securities Purchase Agreement with Cranshire Capital, L.P. The terms of the agreement include the sale of 552,764 shares of common stock at $1.99 per share. The warrants include: (i) Series A Warrants, which are immediately exercisable for a period of 5 years into 329,850 shares at $2.19 per share; (ii) Series A-1 Warrants, which are exercisable beginning February 6, 2010 for a period of 5 years into 1,808 shares at $2.19 per share, (iii) Series B Warrants, which are immediately exercisable for a period of up to 1 year into 511,628 shares at $2.15 per share and (iv) Series C Warrants, which are immediately exercisable for a period of 5 years into 306,977 shares at $2.19 per share but only to the extent that the Series B Warrants are exercised and only in the same percentage that the Series B Warrants are exercised. All of such warrants contain customary adjustments for corporate events such as reorganizations, splits, dividends, and the exercise prices of all such warrants are subject to weighted-average anti-dilution adjustments in the event of additional issuances of common stock below the exercise price then in effect. The exercise price of the Series B Warrants is also subject to increases if the market price of the common stock equals or exceeds $2.40, in which case the exercise price of such Series B warrant will be increased to 90% of the closing sale price of the common stock on the trading day immediately preceding the date of exercise thereof. The Company will also provide customary registration rights in connection with the transaction. In September and October 2009, the Series B warrants were exercised for 511,628 shares of Royale Energy common stock. The net proceeds received for the shares, $1,080,650, were used for general working capital purposes. During March and April 2011, the Series A warrants were exercised for 329,850 shares of Royale Energy common stock. The net proceeds received for the shares, approximately $722,372, were used for general working capital purposes. During February and March 2012, in a separate exercise, warrants were exercised for 67,160 of the Company’s common stock. The net proceeds of approximately $185,999 were used for general working capital purposes.
NOTE 9 - OPERATING LEASES
Royale rents an office and yard in Woodland, CA on a month to month basis that calls for monthly payments of $900. Rental expense for the years ended December 31, 2014 and 2013 was $74,047 and $361,020 respectively.
NOTE 10 - RELATED PARTY TRANSACTIONS
Significant Ownership Interests
Donald H. Hosmer, Royale Energy’s co-president and co-chief executive officer owns 6.23% 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 176 wells under the 1989 policy. During 2014, Donald participated in fractional interests of four wells in the amount of $18,692. At December 31, 2014, Royale had a receivable balance of $3,806 due from Donald Hosmer for normal drilling and lease operating expenses.
Stephen M. Hosmer, Royale Energy’s co-president, co-chief executive officer and chief financial officer, owns 8.13% 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 174 wells under the 1989 policy. During 2014, Stephen participated in fractional interests of 4 wells in the amount of $7,714. At December 31, 2014, Royale had a receivable balance of $3,050 due from Stephen Hosmer for normal drilling and lease operating expenses.
Harry E. Hosmer, Royale Energy's former president and former chief executive officer, owns 4.45% 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 2014, Harry Hosmer participated in fractional interests of 3 wells in the amount of $9,985. At December 31, 2014, Royale had a receivable balance of $942 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 are to vest 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 after December 31, 2017. These options become exercisable at 5,000 shares per period beginning October 13, 2014, January 1, 2015, April 1, 2015 and July 1 2015. During 2014, Royale recognized compensation costs of $33,785 relating to this option grant.
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 140,000 and 0 options granted in the years ended December 31, 2014 and 2013, respectively. The 2014 options were granted with the following assumptions:.
|
Options
|
|
2014
|
|
|
2013
|
|
| |
|
|
|
|
|
|
|
Expected volatility
|
|
|
81.33
|
%
|
|
|
-
|
|
| |
|
|
|
|
|
|
|
|
|
Weighted-average volatility
|
|
|
81.33
|
%
|
|
|
-
|
|
| |
|
|
|
|
|
|
|
|
|
Expected dividends
|
|
|
-
|
|
|
|
-
|
|
| |
|
|
|
|
|
|
|
|
|
Expected term (months)
|
|
|
39
|
|
|
|
-
|
|
| |
|
|
|
|
|
|
|
|
|
Risk-free rate
|
|
|
.57
|
%
|
|
|
-
|
|
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 of
A summary of the status of Royale Energy's stock option plan as of December 31, 2014 and 2013, and changes during the years ending on those dates is presented below:
|
|
2014
|
|
2013
|
|
| |
|
|
Weighted-
|
|
|
|
Weighted-
|
|
| |
|
|
Average
|
|
|
|
Average
|
|
| |
|
|
Exercise
|
|
|
|
Exercise
|
|
| |
Shares
|
|
Price
|
|
Shares
|
|
Price
|
|
| |
|
|
|
|
|
|
|
|
|
Options
|
|
|
|
|
|
|
|
|
|
Outstanding at Beginning of Year
|
|
|
346,308
|
|
|
$
|
3.25
|
|
|
|
346,308
|
|
|
$
|
3.25
|
|
|
Granted
|
|
|
35,000
|
|
|
|
5.00
|
|
|
|
-
|
|
|
|
|
|
|
Exercised
|
|
|
-
|
|
|
|
|
|
|
|
-
|
|
|
|
|
|
|
Forfeited
|
|
|
(100,000
|
)
|
|
|
|
|
|
|
-
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at End of Year
|
|
|
281,308
|
|
|
$
|
3.47
|
|
|
|
346,308
|
|
|
$
|
3.25
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Exercisable at Year End
|
|
|
281,308
|
|
|
$
|
3.47
|
|
|
|
346,308
|
|
|
$
|
3.25
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average Fair Value of Options
Granted During the Year
|
|
$
|
-
|
|
|
|
|
|
|
$
|
-
|
|
|
|
|
|
At December 31, 2014, Royale Energy’s stock price, $2.11, 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 and 2010 have a weighted-average remaining contractual term of three years and one year, respectively as of December 31, 2014.
A summary of the status of Royale Energy's restricted stock grant plans as of December 31, 2014 and 2013, and changes during the years ending on those dates is presented below:
| |
2014
|
|
2013
|
|
| |
|
|
Weighted-
|
|
|
|
Weighted-
|
|
| |
|
|
Average
|
|
|
|
Average
|
|
| |
|
|
Grant-Date
|
|
|
|
Grant-Date
|
|
| |
Shares
|
|
Fair Value
|
|
Shares
|
|
Fair Value
|
|
| |
|
|
|
|
|
|
|
|
|
Non-vested Shares
|
|
|
|
|
|
|
|
|
|
Non-vested at Beginning of Year
|
|
|
-
|
|
|
$
|
-
|
|
|
|
-
|
|
|
$
|
-
|
|
|
Granted
|
|
|
140,000
|
|
|
|
0.97
|
|
|
|
-
|
|
|
|
|
|
|
Reinstated
|
|
|
-
|
|
|
|
|
|
|
|
-
|
|
|
|
|
|
|
Vested
|
|
|
35,000
|
|
|
|
0.97
|
|
|
|
-
|
|
|
|
|
|
|
Expired or Ineligible
|
|
|
-
|
|
|
$
|
|
|
|
|
-
|
|
|
$
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-vested at End of Year
|
|
|
105,000
|
|
|
$
|
0.97
|
|
|
|
-
|
|
|
|
|
|
During 2014, we recognized $33,785 in compensation costs for the vested shares related to this grant and in 2015 we will recognize a total of $91,704 for the additional 105,000 shares as they become vested.
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, 2014 and 2013, were $47,081, and $49,846 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 2014 or 2013.
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 81% 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, 2014, and 2013. At December 31, 2014, and 2013, the Company’s non-interest bearing accounts were fully insured by the FDIC. At December 31, 2014 and 2013, cash in banks exceeded the FDIC limits by approximately $2.8 million and $4.3 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.
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 files 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 seeks 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. At this juncture, the case is in its preliminary phase and we are unable to provide a possible outcome other than to note that management vigorously will contest the allegations of the counterclaim and third-party complaint and will seek to aggressively move to realize on its lien claims to recover funds due and owing from Rampart. Because the case is only a number of months old, we are unable to provide an evaluation of the likelihood of an unfavorable outcome nor can we estimate the amount or range of potential loss.
Douglas Jones v. Royale Energy, Broward County Circuit Court, Florida. On July 1, 2010, Douglas Jones filed a lawsuit against the Company in the Circuit Court, 17th Judicial District, Broward County, Florida. Mr. Jones was an independent contractor handling certain aspects of sales for the Company prior to July 2, 2008. He asserts that he is entitled to an unspecified amount for commissions and expenses. The Company denies that any money is owed to Mr. Jones. On August 16, 2010, the Company, through Florida counsel Adam Hodkin, filed a motion to dismiss the lawsuit for lack of jurisdiction in the Florida courts. The Court ruled that it wanted to have an evidentiary hearing on the motion. The Court has finally set a date for the evidentiary hearing on whether to grant or deny the motion to dismiss. That date is May 5, 2014. On December 23, 2014 the court denied the motion to dismiss for lack of jurisdiction, meaning that the case could go forward in Florida. In February 2015, although the Company denied any liability to Mr. Jones, it agreed to settle the case for $20,000 to avoid the costs of long distance ligation.
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 consultants Netherland, Sewell & Associates, Inc. and Source Energy, LLC, the net reserve value of its proved developed and undeveloped reserves was approximately $12.4 million at December 31, 2014, based on natural gas prices ranging from $4.33 per MCF to $4.89 per MCF as applied on a field-by-field basis. Source Energy, LLC supplied reserve value estimates for Royale Energy’s Utah properties, and Netherland, Sewell & Associates, Inc. provided reserve information for the Company’s California, Texas, Oklahoma, 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 managed and reviewed by Royale’s Chief Geologist and Vice President of Exploration. This person earned a Ph.D. in geosciences from the University of Sheffield, England, and has over 30 years of experience in the petroleum exploration industry. After our Chief Geologist and Vice President of Exploration completes his review and analysis of the estimates from Netherland, Sewell & Associates, the estimates are reviewed again by Royale’s Co-CEO, Co-President, and CFO.
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, 2014 and 2013, and changes in such quantities during each of the years then ended, were as follows:
| |
|
2014
|
|
|
2013
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Oil (BBL)
|
|
|
Gas (MCF)
|
|
|
Oil (BBL)
|
|
|
Gas (MCF)
|
|
|
Proved developed and undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
|
|
38,265
|
|
|
|
3,914,250
|
|
|
|
63,900
|
|
|
|
4,497,970
|
|
|
Revisions of previous estimates
|
|
|
(35,799
|
)
|
|
|
(101,944
|
)
|
|
|
(24,596
|
)
|
|
|
(801,011
|
)
|
|
Production
|
|
|
(685
|
)
|
|
|
(547,898
|
)
|
|
|
(1,039
|
)
|
|
|
(498,948
|
)
|
|
Extensions, discoveries and improved recovery
|
|
|
|
|
|
|
867,398
|
|
|
|
|
|
|
|
790,814
|
|
|
Purchase of minerals in place
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of minerals in place
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(74,576
|
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves end of period
|
|
|
1,781
|
|
|
|
4,131,806
|
|
|
|
38,265
|
|
|
|
3,914,250
|
|
| |
|
2014
|
|
|
2013
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Oil (BBL)
|
|
|
Gas (MCF)
|
|
|
Oil (BBL)
|
|
|
Gas (MCF)
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
|
|
5,984
|
|
|
|
3,168,142
|
|
|
|
700
|
|
|
|
3,188,390
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of period
|
|
|
587
|
|
|
|
3,786,785
|
|
|
|
5,984
|
|
|
|
3,168,142
|
|
| |
|
2014
|
|
|
2013
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Oil (BBL)
|
|
|
Gas (MCF)
|
|
|
Oil (BBL)
|
|
|
Gas (MCF)
|
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
|
|
32,281
|
|
|
|
746,108
|
|
|
|
63,200
|
|
|
|
1,309,580
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of period
|
|
|
1,194
|
|
|
|
345,021
|
|
|
|
32,281
|
|
|
|
746,108
|
|
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.
For December 31, 2013, natural gas extensions, discoveries and improved recovery came to 790,814 MCF which was added mainly as a result of drilling three new exploratory wells and one development well in 2013. These new wells consisted of 440,466 MCF of proved developed producing reserves. A location which consisted of 350,348 MCF of proved undeveloped reserves was discovered from an exploratory well drilled in 2012. A location which had 856,030 MCF in proved developed reserves at December 31, 2012, was drilled and began producing in 2012, was revised downward 456,258 MCF at December 31, 2013. A location which was drilled in 2011 and began producing in 2013, had proved developed non-producing reserves of 268,610 at December 31, 2012, was revised downward 239,941 MCF at December 31, 2013. An additional location, which was also drilled and began producing in 2011, had proved developed reserves of 188,910 at December 31, 2012, was revised downward 162,039 MCF at December 31, 2013.
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, 2014.
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:
|
|
2015
|
|
$
|
46,000
|
|
|
2016
|
|
|
397,700
|
|
|
2017
|
|
|
0
|
|
|
Thereafter
|
|
|
204,300
|
|
| |
|
|
|
|
|
Total
|
|
$
|
648,000
|
|
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.
| |
|
2014
|
|
|
2013
|
|
| |
|
|
|
|
|
|
|
Future cash inflows
|
|
$
|
19,919,930
|
|
|
|
17,740,100
|
|
|
Future production costs
|
|
|
(6,860,440
|
)
|
|
|
(5,924,280
|
)
|
|
Future development costs
|
|
|
(648,000
|
)
|
|
|
(2,599,510
|
)
|
|
Future income tax expense
|
|
|
(3,723,477
|
)
|
|
|
(2,764,893
|
)
|
| |
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
8,688,013
|
|
|
|
6,451,417
|
|
| |
|
|
|
|
|
|
|
|
|
10% annual discount for estimated timing of cash flows
|
|
|
(2,072,974
|
)
|
|
|
(1,817,442
|
)
|
| |
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
6,615,039
|
|
|
|
4,633,975
|
|
| |
|
|
|
|
|
|
|
|
|
Sales of oil and gas produced, net of production costs
|
|
$
|
(936,266
|
)
|
|
|
(558,858
|
)
|
| |
|
|
|
|
|
|
|
|
|
Revisions of previous quantity estimates
|
|
|
1,082,838
|
|
|
|
74,660
|
|
|
Net changes in prices and production costs
|
|
|
708,607
|
|
|
|
(421,741
|
)
|
|
Sales of minerals in place
|
|
|
-
|
|
|
|
(122,760
|
)
|
|
Purchases of minerals in place
|
|
|
-
|
|
|
|
-
|
|
| |
|
|
|
|
|
|
|
|
|
Extensions, discoveries and improved recovery
|
|
|
1,234,621
|
|
|
|
1,421,319
|
|
|
Accretion of discount
|
|
|
740,292
|
|
|
|
602,171
|
|
| |
|
|
|
|
|
|
|
|
|
Net change in income tax
|
|
|
(849,028
|
)
|
|
|
(298,437)
|
|
| |
|
|
|
|
|
|
|
|
|
Net increase (decrease)
|
|
$
|
1,981,064
|
|
|
|
696,354
|
|
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 2015 through 2017.
|
Future development cost of:
|
|
2015
|
|
|
2016
|
|
|
2017
|
|
|
Proved developed reserves
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
Proved non-producing reserves
|
|
|
46,000
|
|
|
|
55,000
|
|
|
|
-
|
|
|
Proved undeveloped reserves
|
|
|
-
|
|
|
|
342,700
|
|
|
|
-
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
46,000
|
|
|
$
|
397,700
|
|
|
$
|
-
|
|
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:
Exhibit 10.5
Exhibit 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement on Form S-3 of Royale Energy, Inc. of our report dated March 30, 2015, relating to our audit of the financial statements, which appear in this Annual Report on Form 10-K of Royale Energy, Inc. for the year ended December 31, 2014.
We also consent to the reference to our Firm under the caption “Experts” in the Prospectus, which is part of this Registration Statement.
SingerLewak LLP
Los Angeles, California
March 30, 2015
Exhibit 23.2
Consent of Independent
Registered Public Accounting Firm
We consent to the incorporation by reference in Registration Statement (No. 333-178484) filed December 14, 2011 on Form S-3 of Royale Energy, Inc. (the “Company”), of our report dated March 11, 2014, relating to our audit of the financial statements which appear in the Annual Report on Form 10-K of the Company as of December 31, 2013, and for the years then ended.
We also consent to the reference to our firm under the caption "Experts" in the Prospectus, which is part of this Registration Statement.
Padgett, Stratemann & Co., LLP
San Antonio, Texas
March 30, 2015
Consent of Independent
Registered Public Accounting Firm
We consent to the incorporation by reference in Registration Statement (No. 333-163184) filed November 18, 2009 on Form S-3 of Royale Energy, Inc. (the “Company”), of our report dated March 11, 2014, relating to our audit of the financial statements which appear in the Annual Report on Form 10-K of the Company as of December 31, 2013 and for the year then ended.
We also consent to the reference to our firm under the caption "Experts" in the Prospectus, which is part of this Registration Statement.
Padgett, Stratemann & Co., LLP
San Antonio, Texas
March 30, 2015
Exhibit 23.3
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
We hereby consent to the inclusion of our report of Royale Energy, Inc. (the “Company”) dated February 5, 2015, in the Annual Report on Form 10-K for the year ended December 31, 2014, of the Company and its subsidiaries, to be filed with the Securities and Exchange Commission.
We also consent to the reference to our firm under the captions "Experts" in the Prospectus, which is part of the Registration Statement.
NETHERLAND, SEWELL & ASSOCIATES, INC.
By: /s/ Danny D. Simmons
Danny D. Simmons, P.E.
President and Chief Operating Officer
Houston, Texas
March 30, 2015
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
We hereby consent to the incorporation by reference in the registration statement (No. 333-178484) on Form S-3 of Royale Energy, Inc. (the “Company”) of the reference to Netherland, Sewell & Associates, Inc., and the inclusion of our report dated February 5, 2015, in the Annual Report on Form 10-K for the year ended December 31, 2014, of the Company, filed with the Securities and Exchange Commission.
We also consent to the reference to our firm under the captions “Experts” in the Prospectus, which is part of this Registration Statement.
NETHERLAND, SEWELL & ASSOCIATES, INC.
By: /s/ Danny D. Simmons
Danny D. Simmons, P.E.
President and Chief Operating Officer
Houston, Texas
March 30, 2015
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.
Exhibit 23.4
Source Energy Corp.
3555 Santoro Way, Suite A
San Diego, CA 92130
Phone (858) 259-2271
Fax (858) 259-2273
March 30, 2015
Mr. Stephen Hosmer
Royale Energy Inc.
3777 Willow Glen Drive
El Cajon, CA 92019
Dear Mr. Hosmer:
We hereby consent to the incorporation by reference in the registration statement (No. 333-163184) on Form S-3 of Royale Energy, Inc. (the “Company”) of the reference to Source Energy Corp. and the inclusion of our report dated February 24, 2015, in the Annual Report on Form 10-K for the year ended December 31, 2014, of the Company, filed with the Securities and Exchange Commission.
We also consent to the reference to our firm under the captions "Experts" in the Prospectus, which is part of this Registration Statement.
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Source Energy Corp
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By: /s/ James Frimodig
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Title: President
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Exhibit 31.1
I, Donald H. Hosmer, certify that:
1. I have reviewed this report on Form 10-K of Royale Energy, Inc.;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
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Date: March 30, 2015
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/s/ Donald H. Hosmer
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Donald H. Hosmer, Co-President and Co-Chief Executive Officer
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Exhibit 31.2
I, Stephen M. Hosmer, certify that:
1. I have reviewed this report on Form 10-K of Royale Energy, Inc.;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions)
a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
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Date: March 30, 2015
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/s/ Stephen M. Hosmer
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Stephen M. Hosmer, Co-President, Co-Chief Executive Officer and Chief Financial Officer
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Exhibit 32.1
Certification Pursuant to 18 U.S.C. § 1350
The undersigned, Donald H. Hosmer, Co-President and Co-Chief Executive Officer of Royale Energy, Inc., a California corporation (the "Company"), pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes Oxley Act of 2002, hereby certifies that:
(1) the Company's Quarterly Report on Form 10-K for the period ended December 31, 2014 (the "Report") fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and
(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
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Date: March 30, 2015
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By:
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/s/ Donald H. Hosmer
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Donald H. Hosmer, Co-President and Co Chief Executive Officer
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Exhibit 32.2
Certification Pursuant to 18 U.S.C. § 1350
The undersigned, Stephen M. Hosmer, Co-President, Co-Chief Executive Officer and Chief Financial Officer of Royale Energy, Inc., a California corporation (the "Company"), pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes Oxley Act of 2002, hereby certifies that:
(1) the Company's Annual Report on Form 10-K for the period ended December 31, 2014 (the "Report") fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and
(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
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Date: March 30, 2015
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By:
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/s/ Stephen M. Hosmer
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Stephen M. Hosmer, Co-President, Co-Chief Executive Officer and Chief Financial Officer
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Exhibit 99.1
February 5, 2015
Mr. Kevin Biddick
Royale Energy, Inc.
7676 Hazard Center Drive, Suite 1500
San Diego, California 92108
Dear Mr. Biddick:
In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2014, to the Royale Energy, Inc. (Royale) interest in certain oil and gas properties located in California, Louisiana, Oklahoma, and Texas. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute approximately 98 percent of all proved reserves owned by Royale. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Royale's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.
We estimate the net reserves and future net revenue to the Royale interest in these properties, as of December 31, 2014, to be:
Totals may not add because of rounding.
The oil volumes shown include crude oil and condensate. Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.
The estimates shown in this report are for proved reserves. No study was made to determine whether probable or possible reserves might be established for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.
Gross revenue is Royale's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Royale's share of production taxes, ad valorem taxes, capital costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.
Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2014. For oil volumes, the average West Texas Intermediate posted price of $91.48 per barrel is adjusted by field for quality, transportation fees, and market differentials. Gas prices for properties in California are based on the average PG&E city-gate price of $4.893 per MMBTU and are adjusted by field for energy content, transportation fees, and market differentials. Gas prices for all other properties are based on the average Henry Hub price of $4.350 per MMBTU and are adjusted by field for energy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $88.56 per barrel of oil and $4.793 per MCF of gas.
Operating costs used in this report are based on operating expense records of Royale. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Headquarters general and administrative overhead expenses of Royale are included to the extent that they are covered under joint operating agreements for the operated properties. Operating costs are not escalated for inflation.
Capital costs used in this report were provided by Royale and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Capital costs are not escalated for inflation. Our estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties. It is our understanding that Royale has fully prefunded accounts that meet or exceed its estimates of abandonment costs for the properties, net of any salvage value.
For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.
We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Royale interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Royale receiving its net revenue interest share of estimated future gross production.
The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Royale, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.
For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for behind-pipe zones and undeveloped locations; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.
The data used in our estimates were obtained from Royale, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. C. Ashley Smith, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2006 and has over 5 years of prior industry experience. Shane M. Howell, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 2005 and has over 7 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.
Sincerely,
NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699
/s/ C.H. (Scott) Rees III
By:
C.H. (Scott) Rees III, P.E.
Chairman and Chief Executive Officer
/s/ C. Ashley Smith /s/ Shane M. Howell
By: By:
C. Ashley Smith, P.E. 100560 Shane M. Howell, P.G. 11276
Vice President Vice President
Date Signed: February 5, 2015 Date Signed: February 5, 2015
CAS:AZH
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.
The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.
(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.
(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:
(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
(ii) Same environment of deposition;
(iii) Similar geological structure; and
(iv) Same drive mechanism.
Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.
(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.
(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.
(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Supplemental definitions from the 2007 Petroleum Resources Management System:
Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
(iv) Provide improved recovery systems.
(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.
(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:
(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.
(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
(iii) Dry hole contributions and bottom hole contributions.
(iv) Costs of drilling and equipping exploratory wells.
(v) Costs of drilling exploratory-type stratigraphic test wells.
(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.
(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.
(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
(16) Oil and gas producing activities.
(i) Oil and gas producing activities include:
(A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;
(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
(1) Lifting the oil and gas to the surface; and
(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.
Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:
a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.
(ii) Oil and gas producing activities do not include:
(A) Transporting, refining, or marketing oil and gas;
(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
(D) Production of geothermal steam.
(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
(i)When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
(ii)Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
(iii)Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
(iv)The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
(v)Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
(vi)Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.
(20) Production costs.
(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:
(A) Costs of labor to operate the wells and related equipment and facilities.
(B) Repairs and maintenance.
(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
(ii )Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.
(21) Proved area. The part of a property to which proved reserves have been specifically attributed.
(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i)The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii)In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii)Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv)Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v)Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
(23) Proved properties. Properties with proved reserves.
(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:
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a.
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Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
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b.
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Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).
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The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
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a.
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Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.
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b.
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Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.
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c.
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Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.
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d.
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Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.
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e.
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Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
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f.
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Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.
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(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.
(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.
(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:
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The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);
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The company's historical record at completing development of comparable long-term projects;
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The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
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The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and
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The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).
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(iii)Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
(32) Unproved properties. Properties with no proved reserves.
Exhibit 99.2
Source Energy Corp.
3555 Santoro Way, Suite A
San Diego, CA 92130
February 24, 2015
Mr. Stephen Hosmer
Royale Energy, Inc.
3777 Willow Glen Drive
El Cajon, California 92019
Dear Mr. Hosmer:
In accordance with your request, I have estimated the proved reserves and future revenue, as of December 31, 2014, to the Royale Energy, Inc. (Royale) interest in certain oil and gas properties located in Grand County, Utah, as listed in the following table. I completed my evaluation on or about the date of this letter. It is my understanding that the proved reserves estimated in this report constitute approximately 2 percent of all proved reserves owned by Royale. In my opinion, the estimates in this report have been prepared in accordance with the definitions and guidelines of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas. Definitions employed within are taken from Netherland, Swell & Associates and are attached.
As presented in the accompanying summary projections, I estimate the net reserves and future net revenue to the Royale interest in these properties, as of December 31, 2014, to be:
Gas volumes shown above are expressed in millions of cubic feet (MMCF) at standard temperature and pressure basis.
The estimates shown in this report are for proved reserves. No study was made to determine whether probable or possible reserves might be established for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.
As shown in the attached tables for each reserve category, this report includes a detailed projection of reserves, revenue and economics by well.
Gross revenue shown in this report is Royale’s share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Royale’s share of production taxes, ad valorem taxes, capital costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.
Gas prices used in this report were provided by Royale and are based on the 12-month unweighted arithmetic average of the first-day-of-the-month actual sales price for the period January through December 2014, or $4.33 per MCF. Prices are held constant throughout the lives of the properties.
Lease and well operating costs used in this report are based on the operating expense records of the operator. As requested, lease and well operating costs for the operated properties are limited to direct lease- and field-level costs and the operator per-well overhead expenses allowed under the joint operating agreement(s). Lease and well operating costs are held constant throughout the lives of the properties. Capital costs are included as required for workovers. The future capital costs are held constant to the date of expenditure.
I have performed a field inspection and generally concluded the mechanical operation and condition of the wells should not be inconsistent with the attached forecast. I did not observe any environmental liability related to the properties and my estimates do not include any costs due to any such liability. Also my estimates do not include any salvage value for the leases and well equipment or the cost of abandoning the properties. It is my understanding that Royale has fully prefunded accounts that meet or exceed its estimates of abandonment costs for the properties, net of any salvage value.
I have made no investigation or inclusion of potential gas volume and value imbalances resulting from over-delivery or under-delivery to the Royale interest. Therefore, my estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; my projections are based on Royale receiving its net revenue interest share of estimated future gross gas production.
The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, my estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the estimated amounts, and that my projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves that may vary from assumptions made while preparing this report.
For the purposes of this report, I used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). I used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis and analogy that I considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, my conclusions necessarily represent only informed professional judgment.
The data used in my estimates were obtained from Royale and were accepted as accurate. Supporting work data are on file in my office. The titles to the properties were not examined by me nor has the actual degree or type of interest owned been independently confirmed. I am an independent petroleum engineer and do not own an interest in these properties and I am not employed by Royale on a contingent basis.
Sincerely,
Source Energy Corp.
By:
James Frimodig
President
Royale Energy (QB) (USOTC:ROYL)
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