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, 2013, Royale Energy had 19 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 the whole 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, 2013, 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 2013, Royale Energy drilled six wells in northern California; four were commercially productive and two were dry holes. Royale Energy's estimated total reserves decreased from approximately 4.9 BCFE (billion cubic feet equivalent) at December 31, 2012 to approximately 4.1 BCFE at December 31, 2013. 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 net reserve value of its proved developed and undeveloped reserves was approximately $9.2 million at December 31, 2013, based on natural gas prices ranging from $3.51 per MCF to $3.92 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, 2013, was estimated to be $4,633,975. 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.
Royale Energy reported a gain on turnkey drilling in connection with the drilling of wells on a "turnkey contract" basis in the amount of $2,008,734 and $763,461 for the years ended December 31, 2013 and 2012, 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 74.4% of Royale Energy's total revenue for the year ended December 31, 2013, came from sales of oil and natural gas from production of its wells in the amount of $1,913,364. In 2012, this amount was $1,673,538, which represented 70.7% of Royale Energy's total revenues.
Plan of Business
Royale Energy acquires interests in oil and natural gas reserves and sponsors private joint ventures. Royale Energy believes that its stockholders are better served by diversification of its investments among individual drilling prospects. Through its sale of joint ventures, Royale Energy can acquire interests and develop oil and natural gas properties with greater diversification of risk and still receive an interest in the revenues and reserves produced from these properties. By selling some of its working interest in most projects, Royale Energy decreases the amount of its investment in the projects and diversifies its oil and gas property holdings, to reduce the risk of concentrating a large amount of its capital in a few projects that may not be successful.
After acquiring the leases or lease participation, Royale Energy drills or participates in the drilling of development and exploratory oil and natural gas wells on its property. Royale Energy pays its proportionate share of the actual cost of drilling, testing, and completing the project to the extent that it retains all or any portion of the working interest.
Royale Energy also may sell fractional working interests in undeveloped wells to finance part of the drilling cost. A drilling contract that calls for a company to drill a well, for a fixed price, to a specified depth or geological formation is called a "turnkey contract." When Royale Energy sells fractional working interests in unproved property to raise capital to drill oil and natural gas wells, generally it agrees to drill these wells on a turnkey contract basis, so that the holders of the fractional interests prepay a fixed amount for the drilling and completion of a specified number of wells. Under a turnkey contract, Royale Energy may record a gain if total funds received to drill a well were more than the actual cost to drill those wells including costs incurred on behalf of the participants and costs incurred for its own account.
Although Royale Energy’s operating agreements do not usually address whether investors have a right to participate in subsequent wells in the same area of interest as a proposed well, it is the Company’s policy to offer to investors in a successful well the right to participate in subsequent wells at the same percentage level as their working interest investment in the prior successful well.
Our policy for turnkey drilling agreements is to recognize a gain on turnkey drilling programs after our obligations have been fulfilled, and a gain is only recorded when funds received from participants are in excess of all costs Royale incurs during the drilling programs (e.g., lease acquisition, exploration and development costs), including costs incurred on behalf of participants and costs incurred for its own account. See Note 1 to our Financial Statements, at page.
Once drilling has commenced, it is generally completed within 10-30 days. See Note 1 to Royale Energy's Financial Statements, at page. 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, 2013, Royale Energy earned gross revenues from operation of the wells in the amount of $414,850 representing 16.1% of its total revenues for the year. In 2012, the amount was $455,396, which represented about 19.2% of total revenues. At December 31, 2013, Royale Energy operated 55 natural gas wells in California. Royale also owns an interest in six natural gas wells in Utah and has non-operating interests in 13 oil and gas wells in Texas, three in Oklahoma, two 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 2013.
Competition, Markets and Regulation
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 a permit 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.
Item 1A
Item 1A Risk Factors
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 2013 the average sales price we received for natural gas was $3.64 per MCF, compared to $2.74 in 2012. Although our natural gas production was lower in 2013, the higher gas prices resulted in an 18.6% increase in natural gas revenues in 2013. See Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations for the Twelve Months Ended December 31, 2013, as Compared to the Twelve Months Ended December 31, 2012.
Variance in Estimates of Oil and Gas Reserves could be Material.
The process of estimating oil and gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. As a result, such estimates are inherently imprecise. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves may vary substantially from those estimated in reserve reports that we periodically obtain from independent reserve engineers.
You should not construe the standardized measure of proved reserves contained in our annual report as the current market value of the estimated proved reserves of oil and gas attributable to our properties. In accordance with Securities and Exchange Commission requirements, we have based the standardized measure of future net cash flows from the standardized measure of proved reserves on the average price during the 12-month period before the ending date of the period covered by the report, whereas actual future prices and costs may vary significantly. The following factors may also affect actual future net cash flows:
·
the timing of both production and related expenses;
·
changes in consumption levels; and
·
governmental regulations or taxation.
In addition, the calculation of the standardized measure of the future net cash flows using a 10% discount as required by the Securities and Exchange Commission is not necessarily the most appropriate discount rate based on interest rates in effect from time to time and risks associated with our reserves or the oil and gas industry in general. Furthermore, we may need to revise our reserves downward or upward based upon actual production, results of future development, supply and demand for oil and gas, prevailing oil and gas prices and other factors.
Any significant variance in these assumptions could materially affect the estimated quantities and present value of our reserves. In addition, our standardized measure of proved reserves may be revised downward or upward, based upon production history, results of future exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control. Actual production, revenues, taxes, development expenditures and operating expenses with respect to our reserves will likely vary from the estimates used, and such variances may be material.
Future Acquisitions and Development Activities May Not Result in Additional Proved Reserves, and We May Not be Able to Drill Productive Wells at Acceptable Costs.
In general, the volume of production from oil and gas properties declines as reserves are depleted. Except to the extent that we acquire properties containing proved reserves or conduct successful development and exploration activities, or both, our proved reserves will decline as reserves are produced. Our future oil and gas production is, therefore, highly dependent upon our ability to find or acquire additional reserves.
The business of acquiring, enhancing or developing reserves is capital intensive. We require cash flow from operations as well as outside investments to fund our acquisition and development activities. If our cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be impaired.
The Oil and Gas Industry has Mechanical and Environmental Risks.
Oil and gas drilling and production activities are subject to numerous risks. These risks include the risk that no commercially productive oil or gas reservoirs will be encountered, that operations may be curtailed, delayed or canceled, and that title problems, weather conditions, compliance with governmental requirements, mechanical difficulties or shortages or delays in the delivery of drilling rigs and other equipment may limit our ability to develop, produce or market our reserves. New wells we drill may not be productive and we may not recover all or any portion of our investment in the well. Drilling for oil and gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. In addition, our properties may be susceptible to hydrocarbon drainage from production by other operators on adjacent properties.
Industry operating risks include the risks of fire, explosions, blow outs, pipe failure, abnormally pressured formations and environmental hazards, such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, the occurrence of any of which could result in substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean up responsibilities, regulatory investigation and penalties and suspension of operations. In accordance with customary industry practice, we maintain insurance for these kinds of risks, but we cannot be sure that our level of insurance will cover all losses in the event of a drilling or production catastrophe. Insurance is not available for all operational risks, such as risks that we will drill a dry hole, fail in an attempt to complete a well or have problems maintaining production from existing wells.
Drilling is a Speculative Activity Even with Newer Technology.
Assessing drilling prospects is uncertain and risky for many reasons. We have grown in the past several years by using 3-D seismic technology to acquire and develop exploratory projects in northern California, as well as by acquiring producing properties for further development. The successful acquisition of such properties depends on our ability to assess recoverable reserves, future oil and gas prices, operating costs, potential environmental and other liabilities and other factors.
Nevertheless, exploratory drilling remains a speculative activity. Even when fully utilized and properly interpreted, 3-D seismic data and other advanced technologies assist geoscientists in identifying subsurface structures but do not enable the interpreter to know whether hydrocarbons are in fact present. In addition, 3-D seismic and other advanced technologies require greater pre-drilling expenditures than traditional drilling strategies, and we could incur losses as a result of these costs.
Therefore, our assessment of drilling prospects are necessarily 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
Item 1B Unresolved Staff Comments
In 2013, the staff of the Securities and Exchange Commission commented on the Company’s revenue recognition policy as it related to recognition of income from turnkey drilling programs and related issues. After considering the staff’s comments, the Company’s audit committee determined that its revenue recognition policies incorrectly recognized (a) amounts received from sales of direct working interests to third parties as revenue, and (b) expenditures to complete development obligations for those working interests as expense. Rather, the receipt of funds from sales of direct working interests should be treated as a recovery of the Company’s capitalized costs of oil and gas properties until such costs are fully recovered. Accordingly, the financial statements as of December 31, 2012, and for the year then ended, have been restated to correct an error in our method of revenue recognition to reduce its basis in oil and gas properties, and to reduce both revenue and expense related to turnkey drilling and related depreciation expense. Changes occurred in Retained Earnings, Deferred Income Tax Asset, Turnkey Drilling Revenue, Drilling and Development Expenses, Lease Impairment Expense, and Oil and Gas Properties (Successful Efforts Basis) and Equipment and Fixtures.
As a result, the Company has restated its financial statements for the fiscal year ended December 31, 2012 to reflect these changes. A detailed discussion of the restatement appears in Note 16 to the Company’s audited financial statements for the years ended December 31, 2013 and 2012, which are contained in this Annual Report. In addition, a summary of restated, unaudited financial statements for the first three quarters of 2013 is contained in Item 6, Management’s Discussion and Analysis of Financial Condition and Results of Operations.
As of the date of filing this Annual Report, the staff of the SEC has not stated whether they have additional comments on the issues related to the Company’s restatement and revision of its revenue recognition policy.
Item 2
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 2013, Royale Energy drilled six wells in northern California, three exploratory producing wells, one developmental producing well and two exploratory dry holes. In 2012, Royale Energy completed the acquisition of approximately 91,000 acres on the North Slope in a lease sale by the State of Alaska. Out of 13 companies bidding on 178 tracts, Royale won 56 tracts in the heart of the oil window. The company's 96,909 acre position represents 29% of the 334,969 acres leased in this sale.
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 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.
Following is a discussion of Royale Energy's significant oil and natural gas properties. Reserves at December 31, 2013, 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, 2014 and February 27, 2014, respectively.
Northern California
Royale Energy owns lease interests in ten 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, 2013, Royale operated 55 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, 2013.
Developed and Undeveloped Leasehold Acreage
As of December 31, 2013, Royale Energy owned leasehold interests in the following developed and undeveloped properties in both gross and net acreage.
Gross and Net Productive Wells
As of December 31, 2013, Royale Energy owned interests in the following oil and gas wells in both gross and net acreage:
Drilling Activities
The following table sets forth Royale Energy's drilling activities during the years ended December 31, 2012 and 2013. All wells are located in the Continental U.S., in California, Texas, Louisiana and Utah.
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.
Production
The following table summarizes, for the periods indicated, Royale Energy's net share of oil and natural gas production, average sales price per barrel (BBL), per thousand cubic feet (MCF) of natural gas, and the MCF equivalent (MCFE) for the barrels of oil based on a 6 to 1 ratio of the price per barrel of oil to the price per MCF of natural gas. "Net" production is production that Royale Energy owns either directly or indirectly through partnership or joint venture interests produced to its interest after deducting royalty, limited partner or other similar interests. Royale Energy generally sells its oil and natural gas at prices then prevailing on the "spot market" and does not have any material long term contracts for the sale of natural gas at a fixed price.
Net Proved Oil and Natural Gas Reserves
As of December 31, 2013, Royale Energy had proved developed reserves of 3,168 MMCF and total proved reserves of 3,914 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 38 MBBL.
Oil and gas reserve estimates and the discounted present value estimates associated with the reserve estimates are based on numerous engineering, geological and operational assumptions that generally are derived from limited data.
Item 3
Item 3 Legal Proceedings
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. If the motion to dismiss is denied, Royale intends to answer the complaint and oppose the lawsuit vigorously. At this time, we do not expect to incur any material losses resulting from these proceedings.
Item 4
Item 4 Mine Safety Disclosures
Not Applicable
PART II
Item 5
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, 2013, 14,942,728 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 2012 through December 2013.
Dividends
The Board of Directors did not issue cash or stock dividends in 2013 or 2012.
Recent Sales of Unregistered Securities
In February and March 2012, five directors exercised stock options to purchase a total of 76,346 shares of common stock in cashless exercises. The stock options had originally been awarded in 2008 at exercise prices of $3.50 per share. In February and March 2012, one director exercised stock options, which also had been awarded in 2008 and 2010, to purchase 45,000 and 43,692 shares of common stock for cash at an exercise price of $3.50 and $3.25 per share, respectively. The options had been issued and the stock was purchased in reliance on the exemption from registration requirements of the Securities Act of 1933 contained in Section 4(2) thereof. No options were exercised by directors for the year in 2013.
Performance Graph
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, 2008, 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, 2013.
Item 6
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-one 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. 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.
Critical Accounting Policies
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 2013 and 2012, impairment losses of $70,203 and $145,461, 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.
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, 2013 and 2012, Royale Energy had Deferred Drilling Obligations of $6,125,933 and $8,693,743 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 prove 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, shall be considered to determine whether, based on the weight of that evidence, a valuation allowance for deferred tax assets is needed. Information about the company’s financial position and its results of operations for the current and preceding years will be used.
The company shall use judgment in considering the relative impact of negative and positive evidence. The weight given to the potential effect of negative and positive evidence shall be 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, 2013, as Compared to the Restated Twelve Months Ended December 31, 2012
For the year ended December 31, 2013, we recorded a net income of $1,149,153 a $14,839,769 improvement when compared to a net loss of $13,690,616 during 2012. Total revenues from operations in 2013 were $2,573,061, an increase of $207,179, or 8.8%, from the total revenues of $2,365,882 in 2012, due to higher natural gas prices during 2013. Total expenses from operations in 2013 were $5,948,485, a decrease of $1,503,792, or 20.1%, from the total expenses of $7,452,277 in 2012, due to decreases in most categories due to continued cost control measures. At year end 2012, management reviewed the likelihood of realizing the Company’s net deferred tax assets and concluded that certain conditions were met, as outlined above in the Certain Accounting Policy’s Deferred Income Tax section and in FASB ASC 740-10, under which it was appropriate for Royale to record a valuation allowance against the net deferred tax assets resulting in a tax adjustment of $9,187,821. The higher net profits in 2013 were also the result of gains from our turnkey drilling programs and the sale of a portion of our oil and gas leases in Alaska.
In 2013, revenues from oil and gas production increased by 14.3% to $1,913,364 from $1,673,538 in 2012. This increase was due to higher natural gas commodity prices received during 2013. The net sales volume of natural gas for the year ended December 31, 2013, was approximately 498,778 MCF with an average price of $3.64 per MCF, versus 559,590 MCF with an average price of $2.74 per MCF for 2012. This represents a decrease in net sales volume of 60,812 MCF or 10.9%. This decrease in production volume was due to the natural declines of our existing wells. The net sales volume for oil and condensate (natural gas liquids) production was approximately 1,019 barrels with an average price of $93.79 per barrel for the year ended December 31, 2013, compared to 1,558 barrels at an average price of $90.75 per barrel for the year in 2012. This represents a decrease in net sales volume of 539 barrels, or 34.6%. This decrease was also due to the natural declines on existing wells. Northern and central California accounted for approximately 99% of the Company’s successful natural gas production in 2013.
Oil and natural gas lease operating expenses decreased by $154,317, or 14.2%, to $936,631 for the year ended December 31, 2013, from $1,090,948 for the year in 2012. This decrease was mainly due to lower tax expenses from lower production and sales volumes in previous years. When measuring lease operating costs on a production or lifting cost basis, in 2013, the $936,631 equates to a $ 1.86 per MCFE lifting cost versus a $ 1.92 per MCFE lifting cost in 2012, a 3% decrease, due to cost cutting efforts in 2013. Delay rental costs increased by $408,752 or 838%, to $457,554 for the year in 2013 from $48,802 in 2012. This increase was due to higher delay rentals for our Alaska leases.
At December 31, 2013, Royale Energy had a Deferred Drilling Obligation of $6,125,933. During 2013, we disposed of $8,028,190 of these obligations upon completing the drilling of six wells, five exploratory and one developmental, in addition in participating in the drilling of two additional wells with an industry partner, resulting in a gain of $2,008,734. In 2012, we disposed of $1,468,384 upon completing our obligation by drilling two wells, one exploratory and one developmental, resulting in a gain of $763,461. Royale expects to dispose of approximately $2.8 million in the first six months of 2014 with the remaining $3.3 million disposed of by the end of 2014.
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. See our Current Report Form 8-K filed on May 24, 2013. 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. During the year in 2012, we recorded a gain of $7,048 on the sale of a non-company owned stock and recorded a write down of $62,744 on certain oil and gas inventory to its estimated current market value.
Impairment losses of $70,203 and $145,461 were recorded in 2013 and 2012, respectively. In both years, we recorded impairments on various capitalized lease and land costs that were no longer viable.
Bad debt expense for 2013 and 2012 were $146,704 and $263,767, respectively. The expenses in 2013 and 2012 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 $659,697 for the year ended December 31, 2013, a decrease of $32,647 (4.7%) from $692,344 during the year in 2012. This decrease was mainly due to lower overhead rates during the period in 2013 due to lower production volumes. Supervisory fees are charged in accordance with the Council for Petroleum Accountants Societies (COPAS) policy for reimbursement of expenses associated with the joint accounting for billing, revenue disbursement, and payment of taxes and royalties. These charges are reevaluated each year and adjusted up or down as deemed appropriate by a published report to the industry by Ernst & Young, LLP, Certified Public Accountants. Supervisory fees decreased $40,546 or 8.9%, to $414,850 in 2013 from $455,396 in 2012.
Depreciation, depletion and amortization expense decreased to $309,806 from $664,131 a decrease of $354,325 (53.4%) for the year ended December 31, 2013, as compared to 2012. The depletion rate is calculated using production as a percentage of reserves. This decreased expense in 2013 was mainly due to a lower depreciation rate because of changes to our cost recovery method. See Note 16 to our Financial Statements for the Years Ended December 31, 2013 and 2012 - Restatement to Reflect Change in Revenue Recognition Policy.
General and administrative expenses decreased by $360,831 or 9.9%, from $3,640,336 for the year ended December 31, 2012, to $3,279,505 for the year in 2013. This decrease was primarily due to lower employee related compensation expenses during the period in 2013, resulting from continued cost control measures. Legal and accounting expense decreased to $326,270 for the year, compared to $518,511 for 2012, a $192,241 or 37.1% decrease. This decrease was the result of lower legal fees in 2013 primarily related to a litigation settlement reached in 2012.
Marketing expense for the year ended December 31, 2013, decreased $261,636 or 44%, to $332,482, compared to $594,118 for the year in 2012. Marketing expense usually varies from period to period according to the number of marketing events attended by personnel and their associated costs. During 2013, in an effort to control costs, we attended fewer marketing conferences and attempted to negotiate lower conference fees.
During the years in 2013 and 2012, we incurred $50,145 and $423,459, respectively, in geological and geophysical costs in order to increase our oil and natural gas prospect base. During 2011, we began a seismic survey in Northern California of which a majority of the actual seismic work took place during the first quarter of 2012.
During 2013, interest expense increased to $304,472 from $195,009 in 2012, a $109,463 or 56.1% increase. This increase was mainly due to the interest on a convertible note payable obtained during the fourth quarter of 2012. Further details concerning Royale’s notes payable and line of credit usage can be found in the Capital Resources and Liquidity section below.
In 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%). In 2012, we had income tax expense of $9,187,821 due mainly to the valuation allowance recognized against our net deferred tax assets.
Capital Resources and Liquidity
At December 31, 2013, Royale Energy had current assets totaling $7,724,068 and current liabilities totaling $11,482,947, a $3,758,879 working capital deficit. We had cash and cash equivalents at December 31, 2013 of $4,878,233 compared to $1,489,930 at December 31, 2012.
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 2013, our accounts receivable totaled $ 1,680,792 compared to $3,969,160 at December 31, 2012, a $2,288,368 or 57.7% decrease. This was primarily due to an approximately $2,500,000 receivable, as part of the sale of common stock due at December 31, 2012. This common stock receivable was collected on January 4, 2013. At December 31, 2013, our accounts payable and accrued expenses totaled $5,332,323, an increase of $399,855 or 8.1% over the accounts payable at the end of 2012 of $4,932,468. This increase was mainly due to increased drilling activity at year end 2013 when compared to year end 2012.
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. At December 31, 2012, we had a current borrowing base and outstanding indebtedness on this loan of $350,000. 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, 2013, and the effect such obligations are expected to have on our liquidity and cash flow in future periods.
Operating Activities. For the years ended December 31, 2013 and 2012, cash used by operating activities totaled $2,911,000 and $1,353,134, respectively. This $1,557,866 increase in cash used was mainly due to the gain on sale of a portion of its Alaska leases of approximately $2.8 million and the decrease of our deferred drilling obligations through increased drilling during the period in 2013.
Investing Activities. For the year ended December 31, 2013, cash provided by investing activities was $5,233,341 compared to $2,906,766 used by investing activities in 2012, a difference of $8,134,107. 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. During 2013, we also drilled 6 wells resulting in expenditures of approximately $7 million and proceeds of approximately $8 million from our Turnkey drilling programs. In 2012 we drilled two wells and finalized our purchase of the Alaska leases resulting in expenditures of $4.4 million and proceeds from our drilling program of approximately $1.5 million.
Financing Activities. Net cash provided by financing activities totaled $1,065,962 and $2,803,699 for the years ended December 31, 2013 and 2012, 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 2012, options were exercised by one director for a total of 88,692 shares of the Company’s common stock in exchange for proceeds of $299,500. Additionally during the year, Royale received proceeds, net of fees, of $2,119,510 and issued 528,996 shares of its common stock relating to its market equity offering program. The Company received approximately $2.8 million from a convertible note payable during the year in 2012. These proceeds were added to working capital and used for ordinary operating expense. Also during the period in 2012, five directors exchanged 195,000 options in a cashless exercise for 76,346 common shares.
The following schedule summarizes our quarterly unaudited Balance Sheet and Statement of Operations for the three months ended March 31, June 30, September 30, and December 31, 2013.
Changes in Reserve Estimates
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.
During 2012, our overall proved developed and undeveloped reserves decreased by 1.6% and our previously estimated proved developed and undeveloped reserve quantities were revised downward by approximately 0.4 million cubic feet of natural gas. This downward revision was primarily due to two California wells, drilled in 2011, which had lower than previously estimated proved producing and non-producing natural gas reserves.
Item 7
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 2013, we sold a majority of our natural gas at the daily market rate through the Pacific Gas & Electric pipeline. In 2013, our natural gas revenues were approximately $1.8 million with an average price of $3.64 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 $180,000. 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 $9,600. We currently do not sell any of our natural gas or oil through hedging contracts.
Item 8
Item 8 Financial Statements and Supplementary Data
See pages, et seq., included herein.
Item 9
Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None
Item 9A
Item 9A Controls and Procedures
Disclosure Controls
Disclosure controls are controls and other procedures that are designed to ensure that information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Our disclosure controls and procedures are designed to insure that the information required to be filed is accumulated and communicated to our management in a manner designed to enable them to make timely decisions regarding required disclosure.
Our 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 2013 fiscal year. Based on their evaluation, they concluded that our disclosure controls are effective as of December 31, 2013.
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, 2013, 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 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Limitations on Effectiveness of Controls
Our management, including our CEO’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
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, 2013:
(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 George M. Watters 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. He serves as chairman of Royale Energy’s audit committee. 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.
George M. Watters - Director
Mr. Watters has been a Director of Royale Energy, Inc. since 1991. He has many years of senior management experience, including 23 years with Amoco, in all phases of downstream petroleum operations - marketing, refining, trading and commercial development. As CEO, he was instrumental in the conception and development of two successful grass roots refining and marketing projects in Australia and Singapore. His last assignment was Chief Executive of Amoco Shipping and Trading Company, residing in London. Prior to his affiliation with Amoco, he held various senior management positions with the former Standard-Vacuum Oil Company, jointly owned by Exxon and Mobil. He is a graduate of MIT and also attended their Management Program for Senior Executives. During World War II, Mr. Watters served four years as an officer in the U.S. Navy Civil Engineering Corps.
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 2013, the members of the audit committee were Oscar A. Hildebrandt, chair, George M. Watters 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 2013.
Item 11
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 2013.
(1) On November 6, 2008, Donald H. Hosmer and Stephen M. Hosmer were each awarded 15,000 shares of common stock for services rendered during 2008. The closing price of Royale Energy’s common stock on that date was $3.31 per share. One third of the shares vested on November 6, 2009, 2010 and 2012.
(2) On March 23, 2008, Donald Hosmer and Stephen Hosmer (together with the other members of the board of directors) were each granted 45,000 options to purchase common stock at an exercise or base price of $3.50 per share. These options vested in three parts on March 31, 2008, 2009, and 2010. The options were granted for a legal life of four years with a service period of three years.
On December 10, 2010, Donald Hosmer and Stephen Hosmer (together with the other members of the board of directors) were each granted 50,000 options to purchase common stock at an exercise or base price of $3.25 per share. These options vested in two parts on January 1, 2012 and 2013. The options were granted for a legal life of five years with a service period of two years.
Amounts represent grant date fair value. See Note 11 of the financial statements contained in our annual report to shareholders on Form 10-K for the year ended December 31, 2012, regarding assumptions underlying the valuation of stock options. The fair value of the options was calculated using the Black-Scholes option pricing method.
(3) 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.
(4) Mr. Abdel-Rahmen and Mr. Tiano are highly compensated employees under SEC rules who did not serve as executive officers during 2012.
Stock Options and Equity Compensation; Outstanding Equity Awards at Fiscal Year End
The following table presents the number of unexercised options at the 2013 year end for each named executive officer. No unvested stock awards were outstanding at the end of 2013.
(1)
In December 2010, the directors and executive officers of Royale Energy were each granted 50,000 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.
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
George M. Watters
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 2013, the compensation committee did not award bonuses to the company’s executive officers.
Compensation of Directors
In 2013, 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 10.
The following table describes the compensation paid to our directors who are not also named executives for their services in 2013.
(1) Other compensation paid to Harry E. Hosmer in 2013 consisted of payments for medical and dental insurance coverage.
Item 12
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Common Stock
On March 5, 2014, 14,942,728 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 5, 2014, 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.
(1) The mailing address of each listed stockholder is 7676 Hazard Center Drive, Suite 1500, San Diego, California 92108.
(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 50,000, Donald H. Hosmer 50,000; Stephen M. Hosmer 50,000; Gary Grinsfelder 40,000; Tony Hall 50,000; Oscar A. Hildebrandt 6,308; George Watters 50,000.
(3) Donald H. Hosmer and Stephen M. Hosmer are sons of Harry E. Hosmer, Chairman of the Board.
(4) Includes 34,000 shares owned by Stephen M. Hosmer’s minor children.
(5) Includes 48,936 shares held by a trust.
(6) Includes 65,481 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 March 31, 2013, 52,784 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
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, George Watters, 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 172 and 170 wells respectively under the 1989 policy. The Hosmer Trust, a trust for the benefit of family members of Harry E. Hosmer, has participated in 170 wells.
Investments in wells under the 1989 policy for the three years ended December 31, 2013, 2012, and 2011 are as follows:
Current officers and directors were billed $16,967, $3,451 and $23,010 for their interests for the three years ended December 31, 2013, 2012, and 2011, 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 $193,270, $138,050 and $165,660 for his consulting services in 2013, 2012, and 2011, 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
Item 14 Principal Accountant Fees and Services
Padgett, Stratemann & Co. LLP served as the independent auditors to audit the Company’s financial statements for the fiscal year ended December 31, 2013. The aggregate fees billed by them for the years ended December 31, 2013 and 2012 are as follows:
(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 Padgett, Stratemann & Co. 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, Dr. Oscar A. Hildebrandt, care of Royale Energy’s executive office, 7676 Hazard Center Drive, Suite 1500, San Diego, California 92108.
PART IV
Item 15
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
2.
Schedules. Supplemental Information About Oil and Gas Producing Activities (Unaudited) begins on page.
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 A-1 Warrant issued to Cranshire Capital, L.P., incorporated by reference to Exhibit 4.2 of the Company’s Form 8-K filed August 6, 2009.
4.2
Series C Warrant issued to Cranshire Capital, L.P., incorporated by reference to Exhibit 4.4 of the Company’s Form 8-K filed August 6, 2009.
4.3
Series D Warrant issued to Cranshire Capital, L.P., incorporated by reference to Exhibit 4.1 of the Company’s Form 8-K filed October 21, 2009.
4.4
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.
4.5
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
Amended and Restated Credit Agreement between Royale Energy and Texas Capital Bank, N.A. (February 13, 2009), incorporated by reference to Exhibit 310.2 of Royale Energy’s Form 10-K filed March 27, 2009.
10.3
Form of Promissory Note between Royale Energy and Texas Capital Bank, N.A., incorporated by reference to Exhibit 10.3 of Royale Energy’s Form 10-K filed March 27, 2009.
10.4
Securities Purchase Agreement between the Company and Cranshire Capital, L.P., dated as of August 4, 2009, incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed August 6, 2009.
10.5
Registration Rights Agreement between the Company and Cranshire Capital, L.P., dated as of August 5, 2009, incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K filed August 6, 2009.
10.6
Securities Purchase Agreement between the Company and Cranshire Capital, L.P., dated as of October 16, 2009, incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed October 21, 2009.
10.7
Registration Rights Agreement between the Company and Cranshire Capital, L.P., dated as of October 16, 2009, incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K filed October 21, 2009.
10.8
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.
10.9
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.
10.10
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.
23.1
Consent of Padgett, Stratemann & Co., L.L.P., filed herewith.
23.2
Consent of Netherland, Sewell & Associates, Inc., filed herewith.
23.3
Consent of Source Energy, LLC, filed herewith.
31.1
Rule 13a-14(a), 115d-14(a) Certification, filed herewith.
31.2
Rule 13a-14(a), 115d-14(a) Certification, filed herewith.
32.1
Section 1350 Certification, filed herewith.
32.2
Section 1350 Certification, filed herewith.
99.1
Report of Netherland Sewell & Associates, Inc., filed herewith.
99.2
Report of Source Energy, LLC, filed herewith.
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.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Royale Energy, Inc.
Date:
March 11, 2014
/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 11, 2014
/s/ Harry E. Hosmer
Harry E. Hosmer
Chairman of the Board of Directors
Date:
March 11, 2014
/s/ Donald H. Hosmer
Donald H. Hosmer
Director, Co-President, Co-Chief Executive Officer
Date:
March 11, 2014
/s/ Stephen M. Hosmer
Stephen M. Hosmer
Director, Co-President, Co-Chief Executive Officer, Chief Financial Officer and Secretary
Date:
March 11, 2014
/s/ Tony Hall
Tony Hall
Director
Date:
March 11, 2014
/s/ Oscar A. Hildebrandt
Oscar A. Hildebrandt
Director
Date:
March 11, 2014
/s/ Gary Grinsfelder
Gary Grinsfelder
Director
Date:
March 11, 2014
/s/ George M. Watters
George M. Watters
Director
ROYALE ENERGY, INC.
AND SUPPLEMENTARY DATA
REPORT OF PADGETT, STRATEMANN & CO., LLP, INDEPENDENT AUDITORS
BALANCE SHEETS
STATEMENTS OF COMPREHENSIVE INCOME LOSS
STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)
STATEMENTS OF CASH FLOWS
NOTES TO FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders
of Royale Energy, Inc.
We have audited the accompanying balance sheets of Royale Energy, Inc. (the “Company”) as of December 31, 2013 and 2012, and the related statements of comprehensive income (loss), stockholders' equity (deficit), and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Royale Energy, Inc. as of December 31, 2013 and 2012, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
As disclosed in Note 16 to the financial statements, the 2012 financial statements have been restated to reflect the correction of an error related to revenue recognition.
Padgett, Stratemann & Co., LLP
San Antonio, Texas
March 15, 2014
ROYALE ENERGY, INC
BALANCE SHEETS
DECEMBER 31, 2013 AND 2012
ASSETS
The accompanying notes are an integral part of these financial statements.
ROYALE ENERGY, INC.
BALANCE SHEETS
DECEMBER 31, 2013 AND 2012
LIABILITIES AND STOCKHOLDERS' EQUITY
The accompanying notes are an integral part of these financial statements.
ROYALE ENERGY, INC.
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
FOR THE YEARS ENDED DECEMBER 31, 2013, AND 2012
The accompanying notes are an integral part of these financial statements.
ROYALE ENERGY, INC.
STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2013, and 2012
The accompanying notes are an integral part of these financial statements.
ROYALE ENERGY, INC.
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2013, and 2012
The accompanying notes are an integral part of these financial statements.
ROYALE ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
This summary of significant accounting policies of Royale Energy, Inc. (“Royale Energy” 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 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. Actual results could differ from those estimates.
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.
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 2013 and 2012, impairment losses of $70,203 and $145,461, 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, 2013 and 2012, Royale Energy had Deferred Drilling Obligations of $6,125,933 and $8,693,743 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.
Inventory
Inventory consists of well supplies, pipeline and spare parts and is carried at lower of cost or market. During 2013, we had a write down of $39,185 on certain oil and gas inventory and in 2012 we had a write down of $62,744 on certain oil and gas inventory to its estimated current market value.
Accounts Receivable
The Company provides 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 to earnings. 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, 2013 and 2012, the Company established an allowance for uncollectable accounts of $1,081,580 and $934,876, respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue.
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, 2012, Royale Energy had dilutive securities of 1,104,314. These securities were not included in the dilutive earnings per share due to their anti-dilutive nature.
Stock Based Compensation
Royale Energy has a stock-based employee compensation plan, which is more fully described in Note 12. 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.
At December 31, 2013, Royale Energy reported the fair value of $16,448 in available for sale securities. The fair value was determined using the number of shares owned as of December 31, 2013, multiplied by the market price of those securities on December 31, 2013.
The table below summarizes Royale’s fair value measurements and the level within the fair value hierarchy in which the fair value measurements fall. At December 31, 2012, Royale Energy quoted prices in active markets for identical assets when determining the fair value measurements at the reporting date.
Reclassifications
Certain items in the financial statements have been reclassified to maintain consistency and comparability for all
periods presented herein. The company has determined that Delay Rentals expenses are more fairly broken out of Lease Operating Expenses. The reclassification is reflected in all years presented.
Recently Issued Accounting Pronouncements
The Company has reviewed the updates issued by the Financial Accounting Standards Board (FASB) during the year ended December 31, 2013, 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:
The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed:
The guidance set forth in the Continued Capitalization of Exploratory Well Costs paragraph of the Extractive Activities Topic of the FASB Accounting Standards Codification requires that we evaluate all existing capitalized exploratory well costs and disclose the extent to which any such capitalized costs have become impaired and are expensed or reclassified during a fiscal period. We did not make any additions to capitalized exploratory well costs pending a determination of proved reserves during 2013 or 2012. We did not charge any previously capitalized exploratory well costs to expense upon adoption of Topic.
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:
NOTE 3 - ASSET RETIREMENT OBLIGATION
The Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification requires that an asset retirement obligation (ARO) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset. The ARO is recorded at fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value. The fair value of the ARO is measured using expected future cash outflows discounted at the Company’s credit-adjusted risk-free interest rate. The provisions of this Topic apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, development, and operation of a long-lived asset.
NOTE 4 - TURNKEY DRILLING OBLIGATION
Royale Energy receives funds under turnkey drilling contracts, which require Royale Energy to drill oil and gas wells within a reasonable time period from the date of receipt of the funds. As of December 31, 2013 and 2012 Royale Energy had recorded deferred turnkey drilling associated with undrilled wells of $6,125,933 and $8,693,743, respectively, as a current liability.
NOTE 5 - LONG-TERM DEBT
The Warrant Agreement entitles the holder to purchase, in whole or in part, an aggregate of 500,000 shares of Royale’s Common stock at an initial exercise price of $3.00 per share. During 2013, the exercise price of these warrants was adjusted from $3.00 to $2.1176 due to the issuance of shares under the Company’s Securities Purchase Agreement. The warrant has a three year term and becomes exercisable on April 29, 2013. The value of the warrant was determined using the Black-Scholes pricing method utilizing a strike price of $3.00, 3 year maturity, a risk free interest of 0.8805%, and expected volatility of 107.7%. Based upon these inputs, the value of each warrant share was calculated to be $1.9536.
Maturities of long-term debt for the years subsequent to December 31, 2013 are as follows:
NOTE 6 - INCOME TAXES
Deferred tax assets and liabilities reflect the net tax effect of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and amounts used for income tax purposes. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.
Significant components of the Company’s deferred assets and liabilities at December 31, 2013 and 2012, respectively, are as follows:
At the end of 2012, management reviewed the realizability of the Company’s net deferred tax assets. Due to the Company’s cumulative losses in recent years and its inability to conclude a transaction concerning its Alaska acreage by the end of 2012, 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 2012. At the end of 2013, management again 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 2013. 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 $1,800,000 at December 31, 2013. The depletion has no expiration date. The Company also has a net operating loss carry forward of approximately $10,400,000 at December 31, 2013, 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, 2013 and 2012, respectively, to pretax income is as follows:
The components of the Company’s tax provision are as follows:
In January 2007, Royale adopted additional provisions from the Income Taxes Topic of the FASB Accounting Standards Codification, which clarified the accounting for uncertainty in income taxes recognized in an entity’s financial statements and prescribes a recognition threshold and measurement attribute for financial statement disclosure of tax positions taken or expected to be taken on a tax return. As a result of our implementation of the Topic at the time of adoption and at December 31, 2013, 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 2009 through 2012 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 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 does not have the right of redemption at the stockholders' option. During the years ending December 31, 2013, and 2012, there were no conversions of Series AA Preferred stock, and as of December 31, 2013, and 2012 there were 52,784 shares of Series AA Preferred stock issued and outstanding.
NOTE 8 - COMMON STOCK
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 Energy occupies office space through the use of two leases, one for their office in San Diego, CA and one for an office and yard in Woodland, CA. The San Diego lease is under a 120 month noncancellable lease contract, which expires in July 2015. The San Diego lease calls for monthly payments ranging from $27,010 to $35,271, and the Woodland lease calls for monthly payments of $900. Future minimum lease obligations as of December 31, 2013 are as follows:
Rental expense for the years ended December 31, 2013 and 2012 was $ 361,020 and $370,750 respectively.
NOTE 10 - RELATED PARTY TRANSACTIONS
Significant Ownership Interests
Donald H. Hosmer, Royale Energy’s co-president and co-chief executive officer owns 6.24% of Royale Energy common stock. Donald H. Hosmer is the brother of Stephen M. Hosmer, and son of Harry E. Hosmer.
Stephen M. Hosmer, Royale Energy’s co-president, co-chief executive officer and chief financial officer, owns 8.41% of Royale Energy common stock. Stephen M. Hosmer is the brother of Donald H. Hosmer and son of Harry E. Hosmer.
Harry E. Hosmer, Royale Energy's former president and former chief executive officer, owns 4.32% 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.
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. During 2012, Royale recognized compensation costs of $39,260 and a tax expense of $38,652 relating to this option grant. In 2013, Royale did not recognize any compensation costs or tax effect related to this grant.
The fair value of the options was calculated using the Black-Scholes option pricing method. 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 stock and other factors. Royale Energy uses historical data to estimate option exercise and board member turnover within the valuation model. The risk-free rate for the periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of the grant.
A summary of the status of Royale Energy's stock option plan as of December 31, 2013 and 2012, and changes during the years ending on those dates is presented below:
At December 31, 2013, Royale Energy’s stock price, $2.59, was less than the weighted average exercise price, and as such the outstanding and exercisable stock options had no intrinsic value. These stock options have a weighted-average remaining contractual term of 2 years as of December 31, 2013. There were no new stock options granted during 2013.
A summary of the status of Royale Energy's restricted stock grant plans as of December 31, 2013 and 2012, and changes during the years ending on those dates is presented below:
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, 2013 and 2012, were $49,846, and $57,405 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 2013 or 2012.
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 80% 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, 2013, and 2012. At December 31, 2013, and 2012, the Company’s non-interest bearing accounts were fully insured by the FDIC. At December 31, 2013 and 2012, cash in banks exceeded the FDIC limits by approximately $4.3 million and $1.2 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.
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. If the motion to dismiss is denied, Royale intends to answer the complaint and oppose the lawsuit vigorously. At this time, we do not expect to incur any material losses resulting from these proceedings.
NOTE 16 - RESTATEMENT TO REFLECT CHANGE IN REVENUE RECOGNITION POLICY
In response to comments from the staff of the Securities and Exchange Commission’s Division of Corporation Finance, and after consultation with the Company’s Chief Financial Officer and with Padgett Stratemann & Co., LLP, the Company’s independent registered public accounting firm, the Audit Committee concluded that the Company’s revenue recognition policies incorrectly recognized (a) amounts received from sales of direct working interests to third parties as revenue, and (b) expenditures to complete development obligations for those working interests as expense. Rather, the receipt of funds from sales of direct working interests should be treated as a recovery of the Company’s capitalized costs of oil and gas properties until such costs are fully recovered. Accordingly, the financial statements as of December 31, 2012, and for the year then ended, have been restated to correct an error in our method of revenue recognition to reduce its basis in oil and gas properties, and to reduce both revenue and expense related to turnkey drilling and related depletion expense. Changes occurred in Retained Earnings, Deferred Income Tax Asset, Turnkey Drilling Revenue, Drilling and Development Expenses, Lease Impairment Expense, and Oil and Gas Properties (Successful Efforts Basis) and Equipment and Fixtures.
The revisions to the balance sheet dated December 31, 2012, results in a reduction of the carrying value of the Company’s oil and gas properties, although there has been no change in the actual ownership, market value, or reserve value (at December 31,2012) of those properties. The revision to the statement of comprehensive loss for fiscal 2012 reduces revenue from turnkey drilling activity and reduces expenses from turnkey drilling and development, lease impairment, and depreciation, depletion and amortization, increasing the loss by $1,729,590 to $13,693,651 from $11,964,061.
Royale’s Oil and Gas Properties (Successful Efforts Basis) and Equipment and Fixtures were evaluated at December 31, 2011 based upon the revised policies. An adjustment of $4,456,933 was recorded against Royale’s oil and gas properties offset by corresponding entries to its deferred tax asset and retained earnings.
For a detailed explanation of the changes to the Company’s revenue recognition policies and its effect on the Company’s balance sheet and statement of operations, see our revenue recognition policy and policy on property, plant and equipment.
The following table illustrates the effect of these changes in 2012.
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 $7.6 million at December 31, 2013, based on natural gas prices ranging from $2.59 per MCF to $3.09 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, 2013 and 2012 and changes in such quantities during each of the years then ended, were as follows:
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.
For December 31, 2012, natural gas extensions, discoveries and improved recovery amounted to 892,990 MCF which was mainly the result of drilling one new exploratory well in 2012, which consisted of 856,030 MCF of proved undeveloped reserves. Another location, carried over from December 31, 2011, which was not drilled in 2012, was revised upward to 416,590 MCF in proved undeveloped reserves at year end 2012. Additionally in 2012, oil extensions, discoveries and improved recovery came to 63,200 BBL which was due to four new locations, on previously owned leases, which during 2012 were proven by new outside development in the area. Each of the four locations has approximately 15,800 BBL and 9,240 MCF of proved undeveloped reserves. A location which had 347,000 MCF in proved developed reserves at December 31, 2011, was drilled and began producing in 2011, was revised downward 306,837 MCF at December 31, 2012. An additional location, which was also drilled and began producing in 2011, had proved developed reserves of 379,300 at December 31, 2011, revised downward 126,653 MCF at December 31, 2012.
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, 2013.
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.
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The resulting future gross revenue streams are reduced by estimated future costs to develop and to produce proved reserves, based on year-end estimates. Estimated future development costs by year are as follows:
The resulting future net revenue streams are reduced to present value amounts by applying a ten percent discount.
Disclosure of principal components of the standardized measure of discounted future net cash flows provides information concerning the factors involved in making the calculation. In addition, the disclosure of both undiscounted and discounted net cash flows provides a measure of comparing proved oil and gas reserves both with and without an estimate of production timing. The standardized measure of discounted future net cash flow relating to proved reserves reflects estimated income taxes.
Changes in standardized measure of discounted future net cash flow from proved reserve quantities
This statement discloses the sources of changes in the standardized measure from year to year. The amount reported as “Net changes in prices and production costs” represents the present value of changes in prices and production costs multiplied by estimates of proved reserves as of the beginning of the year. The “accretion of discount” was computed by multiplying the ten percent discount factor by the standardized measure on a pretax basis as of the beginning of the year. The “Sales of oil and gas produced, net of production costs” are expressed in actual dollar amounts. “Revisions of previous quantity estimates” is expressed at year-end prices. The “Net change in income taxes” is computed as the change in present value of future income taxes.
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 2014 through 2016.
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
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: