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Item 1

Description of Business

 

 

further applying a 10% annual discount for estimated timing of cash flows. A detailed calculation of our standardized measure of discounted future net cash flow is contained in Supplemental Information About Oil and Gas Producing Activities – Changes in Standardized Measure of Discounted Future Net Cash Flow from Proved Reserve Quantities, page F-31.

Royale Energy reported gross revenues in connection with the drilling of wells on a "turnkey contract" basis, or sales of fractional interests in undeveloped wells, in the amount of $11,472,065 for the year ended December 31, 2008, which represents approximately 60% of its total revenues for the year. In 2007, Royale Energy reported $9,408,103 gross revenues from turnkey drilling operations for the year, representing 57% of Royale Energy's total revenues for that year.

 

These amounts are offset by drilling expenses and development costs of $6,015,390 in 2008, and $4,977,811 in 2007. 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 37% of Royale Energy's total revenue for the year ended December 31, 2008, came from sales of oil and natural gas from production of its wells in the amount of $6,999,022. In 2007, this amount was $6,110,092, which represented 37% 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 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 interests 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 recognizes gross revenue for the amount paid by the purchaser and agrees to pay the expense of drilling and development of the well for the participants. Sometimes the actual drilling and development costs are less than the fixed amount that Royale Energy received from the fractional interest sale.

 

 

When Royale Energy authorizes a turnkey drilling project for sale, a calculation is made to estimate the pre-drilling costs and the drilling costs. A percentage for each is calculated. The turnkey drilling project is then sold to investors who execute a contract with Royale Energy. In this agreement, the investor agrees to share in the pre-drilling costs, which include lease costs, geological and geophysical costs, and other costs as required so that the drilling of the project can proceed. As stated in the contract, the percentage of the pre-drilling costs that the investor contributes is non-refundable, and thus on its financial statements, Royale Energy recognizes these non-refundable payments as revenue since the pre-drilling costs have commenced. The remaining investment is held and reported by Royale Energy as deferred revenue until drilling is complete.

 

Drilling is generally completed within 10-30 days. See Note 1 to Royale Energy's Financial Statements, at page F-11. 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, 2008, Royale Energy earned gross revenues from operation of the wells in the amount of $392,318, representing 2% of its total revenues on a consolidated basis for that year. In 2007, the amount was $400,897, which represented about 2.4% of total revenues. At December 31, 2008, Royale Energy operated 49 natural gas wells in California. Royale also owns an interest and operates six natural gas wells in Utah and has non-operating interests in 17 oil and gas wells in Texas, three in Oklahoma, one in California, and two in Louisiana.

 

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

 

All oil and natural gas properties are depleting assets in which production naturally decreases over time as the finite amount of existing reserves are produced and sold. It is Royale Energy’s business as an oil and natural gas exploration and production company to continually search for new development properties. The company’s success will ultimately depend on its ability to continue locating and developing new oil and natural gas resources.

 

Natural gas demand and the prices paid for gas are seasonal. In recent years, natural gas demand and prices in Northern California have fluctuated unpredictably throughout the year.

 

Royale Energy had no subsidiaries in 2008.

 

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 or by calling 1-800-SEC-0300. The SEC also maintains an Internet site that contains reports, proxy and information statements, and other

information regarding issuers that file electronically with the SEC at http://www.sec.gov. Royale Energy also provides access to its SEC reports and other public announcements on its website, http://www.royl.com.

 

 

In addition to the other information contained in this report, the following risk factors should be considered in evaluating our business.

 

We Depend on Market Conditions and Prices in the Oil and Gas Industry.

 

Our success depends heavily upon our ability to market oil and gas production at favorable prices. In recent decades, there have been both periods of worldwide overproduction and underproduction of hydrocarbons and periods of increased and relaxed energy conservation efforts. As a result the world has experienced periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis; these periods have been followed by periods of short supply of, and increased demand for, crude oil and, to a lesser extent, natural gas. The excess or short supply of oil and gas has placed pressures on prices and has resulted in dramatic price fluctuations.

 

Natural gas demand and the prices paid for gas are seasonal. The fluctuations in gas prices and possible new regulations create uncertainty about whether we can continue to produce gas for a profit.

 

Prices for oil and natural gas affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of oil and natural gas that we can economically produce. Any substantial and extended decline in the price of oil or natural gas would decrease our cash flows, as well as the carrying value of our proved reserves, our borrowing capacity and our ability to obtain additional capital.

 

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 prices and costs as of the date of the estimate, whereas actual future prices and costs may vary significantly. The following factors may also affect actual future net cash flows:

 

 

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 exploitation 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 assessments 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 Hosmer Family Exerts Significant Influence Over Stockholder Matters.

 

The control positions held by members of the Hosmer family may discourage others from making bids to buy Royale Energy or change its management without their consent. Donald H. Hosmer is the co-president of the company. Stephen M. Hosmer is the co-president and chief financial officer. Harry E. Hosmer is the chairman of the board. Together, they make up three of the eight members of our board of directors. At December 31, 2008, these individuals owned or controlled the following amounts of Royale Energy common stock, including shares they had the right to acquire on the exercise of outstanding stock options:

 

 

(1) Includes the following options to purchase shares of stock: Donald H. Hosmer – 45,000, Stephen M. Hosmer – 30,000, and Harry E. Hosmer – 30,000.

(2) Based on total of 8,506,098 outstanding shares on December 31, 2008.

(3) Calculated pursuant to Rule 13d-3 of the Securities and Exchange Commission.

(4) Includes 12,000 shares of stock owned by the minor children of Stephen M. Hosmer. Mr. Hosmer disclaims beneficial ownership of the shares owned by his children.

 

The amounts of stock owned by Hosmer family members make it quite likely that they could control the outcome of any contested vote of the stockholders on matters related to management of the corporation.

 

 

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.

 

 

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 2008, Royale Energy drilled five wells in northern and central California, four of which were commercially productive wells and are currently producing. We participated in the workover of an existing well which proved unsuccessful. We also drilled two wells in Utah, which are being tested, but due to weather conditions in the Rockies, full results have been delayed.

 

Following industry standards, Royale Energy generally acquires oil and natural gas acreage without warranty of title except as to claims made by, through, 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.

 

During 2008, Royale Energy maintained a revolving credit agreement with Guaranty Bank, FSB. Under the terms of the agreement, from time to time, Royale Energy may borrow, repay, and reborrow money from Guaranty Bank with a total credit line of $15,000,000. The maximum allowable amount of each credit request is governed by a formula in the agreement. The maximum allowable amount at December 31, 2008, was $2,075,974. At December 31, 2008, Royale Energy owed $1,975,974 under this credit line. In early 2009 the Guaranty Bank credit agreement was replaced with another, similar agreement with Texas Capital Bank, N.A. Royale uses advances under this credit line to finance lease acquisition operations and for temporary working capital. Following is a discussion of Royale Energy's significant oil and natural gas properties. Reserves at December 31, 2008, 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 17, 2009.

 

Northern California

Royale Energy owns lease interests in eleven 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, 2008, Royale operated 49 wells in California with estimated total proven, developed, and undeveloped reserves at approximately 3.0 bcf, according to Royale’s independently prepared reserve report as of December 31, 2008.

 

 

 

Developed and Undeveloped Leasehold Acreage

 

As of December 31, 2008, Royale Energy owned leasehold interests in the following developed and undeveloped properties in both gross and net acreage.

 

Drilling Activities

The following table sets forth Royale Energy's drilling activities during the years ended December 31, 2006, 2007 and 2008. 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 10 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, 2008, Royale Energy had proved developed reserves of 3,185 MMcf and total proved reserves of 3,377 MMcf of natural gas on all of the properties Royale Energy leases. For the same period, Royale Energy also had proved developed oil reserves of 25 Mbbl and total proved oil reserves of 25 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.

 

 

National Fuel Corporation (“NFC”) v. Royale Energy, Inc., No. 080800735, Uintah County, Utah. This lawsuit was filed on October 10, 2008, after the close of the third fiscal quarter. It arose from a dispute over jointly operated property in which Royale in the 75% owner and operator and NFC is a non-operator with a 25% ownership.  NFC disagrees with the Company’s operations and seeks to remove the Company as operator.  NFC also seeks unspecified damages.  The case is in its very beginning, and the Company has not yet responded to the Complaint.  Royale disputes the claims and intends to defend the complaint vigorously. 

 

 

 

No matters were submitted to a vote of security holders during the fourth quarter of 2008.

 

PART II

 

Since 1997 Royale Energy's Common Stock has been traded on the Nasdaq National Market System under the symbol "ROYL." As of December 31, 2008, 8,506,098 shares of Royale Energy's Common Stock were held by approximately 2,842 stockholders. The following table reflects high and low quarterly closing sales prices from January 2007 through December 2008. Share prices in this table have been adjusted to give effect to the issuance of stock dividends in 2003, 2004 and 2005, and a stock split in 2004, as described in the next subsection, Dividends.

 

Dividends

The Board of Directors did not issue cash or stock dividends in 2008. On January 18, 2007 the Board of Directors authorized the issuance of a cash dividend of $0.05 per share for shareholders of record on February 19, 2007. The dividend was paid March 5, 2007 in the amount of $397,049. In 2006 we paid no cash or stock dividends.

 

Recent Sales of Unregistered Securities

In March 2008, Royale Energy awarded options to purchase 45,000 shares of common stock at $3.50 per share (the fair market value of Royale’s common stock on the date of grant) to each of its eight directors (a total of 360,000 shares). In June 2008, three directors exercised their options to acquire a total of 36,844 shares during 2008. The options were issued and the stock was purchased in reliance on the exemption from registrations requirements of the Securities Act of 1933 contained in Section 4(2) thereof.

 

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, 2003, with the cumulative total return of the Standard & Poor’s Composite 500 Stock Index and the Dow Jones U.S. Exploration and Production Index from December 31, 2003 through December 31, 2008.

 

 

The Royale Energy performance figures assume retention of stock dividends in 2003 and 2004 and a stock split issued in the form of a stock dividend in 2004.

 

 

 

 

 

 

Item 7             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 fifteen 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) recording of turnkey drilling revenues and the associated drilling expense, and (iii) the change in commodities price of natural gas and oil reserves owned by Royale Energy.

 

Critical Accounting Policies

Revenue Recognition

 

Royale Energy’s financial statements include its pro rata ownership of wells. Royale Energy usually sells a portion of the working interest in each lease that it acquires 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.

 

Royale Energy has developed two profit-oriented segments of business: marketing direct working interests (DWI), and producing and selling oil and gas.

 

Royale Energy derives DWI revenue from sales of working interests to high net worth individuals. The DWI revenue is divided into payments for pre-drilling costs and for drilling costs. DWI investments are non-refundable. Royale Energy recognizes the pre-drilling revenue portion when the investor deposits money with Royale Energy. The company holds the remaining investment in trust as deferred revenue until drilling is complete. Occasionally, drilling is delayed due to the permitting process, or drilling rig availability. At December 31, 2008 and 2007, Royale Energy had deferred drilling revenue of $4,005,800 and $3,947,097, respectively.

 

The primary business segment is oil and gas production. Northern and central California account for approximately 93% of the company’s successful natural 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.

 

Oil and Gas Property and Equipment

 

Royale Energy follows the successful efforts method of accounting for oil and gas properties.

 

Costs are accumulated on a field-by-field basis. These costs include pre-drilling activities such as leasing rents paid, drilling costs, and post-drilling tangible costs. Costs of unproved properties are excluded from amortization until the properties are evaluated. Royale Energy regularly evaluates its unproved properties on a field-by-field basis for possible impairment. Due to the unpredictable nature of exploration drilling activities, the amount and timing of impairment expenses are difficult to predict with any certainty.

 

 

Depletion

 

The units of production method of accounting uses proved reserves in the calculation of depletion, depreciation and amortization. Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions. Proved reserves cannot be measured exactly, and the estimation of reserves involves judgment determinations. Independent engineering reserve estimates must be reviewed and adjusted periodically to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. The estimates are based on current technology and economic conditions, and Royale Energy considers such estimates to be reasonable and consistent with current knowledge of the characteristics and extent of production. The independent engineering estimates include only those amounts considered to be proved reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place or for which transportation and/or marketing contracts are not in place. Changes in previous estimates of proved reserves result from new information obtained from production history and changes in economic factors.

 

Impairment Of Assets

 

Producing property costs are evaluated for impairment and reduced to fair value if the sum of expected undiscounted future cash flows is less than net book value pursuant to Statement of Financial Accounting Standard 144 "Accounting for the Impairment or Disposal of Long-Lived Assets." Impairment of non-producing leasehold costs and undeveloped mineral and royalty interests are assessed periodically on a property-by-property basis and any impairment in value is charged to expense. We periodically review for impairment of proved properties on a field-by-field basis. Unamortized capital costs are measured on a field basis and are reduced to fair value if it is determined that the sum of expected future net cash flows are less than the net book value. We determine if impairment has occurred through either adverse changes or as a result of its periodic review for impairment. Impairment is measured on discounted cash flows utilizing a discount rate appropriate for risks associated with the related properties or based on fair market values. We regard impairment costs of undeveloped properties as a component of our turnkey drilling overhead, since impairment costs amount to a write-down of previously acquired property inventory that we were unable to successfully develop as part of our turnkey drilling program.

 

Estimates

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, plant products and gas reserve volumes and the future development costs. Actual results could differ from those estimates.

 

 

Deferred Income Taxes

 

Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts attributable to events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax credit carry forwards. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

 

Results of Operations for the Twelve Months Ended December 31, 2008, as Compared to the Twelve Months Ended December 31, 2007

For the year ended December 31, 2008, we had a net loss of $8,777,614 compared to the net loss of $2,779,207 during 2007. The loss was primarily the result of an impairment of $15,691,348 due to a decrease in asset reserve values at year end 2008. This was mainly due to the industry wide collapse of oil and natural gas prices at year end which reduced reserve values.

 

Total revenues from operations for the year in 2008 were $19,174,114, an increase of $2,616,715, or 15.8%, from the total revenues of $16,557,399 in 2007. In 2008 our turnkey drilling revenues increased due to an increase in the number of wells drilled and our natural gas revenues increased due to higher mid-year natural gas and oil prices. Higher turnkey drilling revenues accounted for 78.9% of the increase.

 

In 2008, revenues from oil and gas production increased by 14.5% to $6,999,022 from $6,110,092 in 2007, due to higher mid year prices that the industry experienced for a portion of 2008. The net sales volume of natural gas for the year ended December 31, 2008, was approximately 714,230 Mcf with an average price of $8.32 per Mcf, versus 791,195 Mcf with an average price of $6.56 per Mcf for 2007. This represents a decrease in net sales volume of 76,965 Mcf or 9.7%. This decrease in production was due to a natural decline in production from existing oil and gas wells. The net sales volume for oil and condensate (natural gas liquids) production was approximately 11,089 barrels with an average price of $95.04 per barrel for the year ended December 31, 2008, compared to 14,088 barrels at an average price of $65.02 per barrel for the year in 2007. This represents a decrease in net sales volume of 2,999 barrels, or 21.3%.

 

Oil and gas lease operating expenses increased by $715,436, or 33.8%, to $2,832,413 for the year ended December 31, 2008, from $2,116,977 for the year in 2007. This increase was mainly due to higher plugging and abandoning and workover costs during the period in 2008 when compared to 2007, as we continue efforts to increase production on some of our existing wells. When measuring lease operating costs on a production or lifting cost basis, in 2008, the $2,832,413 equates to a $3.43 per mcfe lifting cost versus a $2.27 per mcfe lifting cost in 2007, a 51.1% increase. Without plugging, abandonment, and workover costs, our lifting costs would have been $1,688,271, or $2.05 per mcfe.

 

For the year ended December 31, 2008, turnkey drilling revenues increased $2,063,962 to $11,472,065 in 2008 from $9,408,103 in 2007, or 21.9%. We also had a $1,037,579 or 20.8% increase in turnkey drilling and development costs to $6,015,390 in 2008 from $4,977,811 in 2007. In 2008, we drilled seven wells and incurred work over expenses for an existing well and we expensed another, previously drilled exploratory dry hole in 2008. We drilled five

 

 

developmental wells and two exploratory wells in 2008 versus four exploratory wells and three developmental wells in 2007. Our gross margins, or profits, on drilling depend on our ability to accurately estimate the costs associated with the development of projects in which we sell working interests and to acquire viable properties that can be successfully developed. Costs associated with contract drilling depend on location, well depth, weather, and availability of drilling contractors and equipment. Our gross margin on drilling increased to 47.6% from 47.1% for the years ended December 31, 2008 and 2007, respectively. Gross margin is calculated as the difference between turnkey drilling revenue and turnkey drilling expense. However, management believes that a portion of its impairment losses should also be considered as a cost of drilling in determining the profitability of this segment, because impairment costs are incurred in the selection of higher quality prospects for ultimate development.

 

Impairment losses of $15,691,348 and $2,106,670 were recorded in 2008 and 2007, respectively. In 2008 and 2007, we recorded impairments in fields where year end reserve values were less than the net book values of wells in those fields. In 2008, $9,508,294 of this impairment was recorded in our Utah field where the weather delays caused lower than expected production to support the proved reserves values that were lower than their current net book values. The Texas and Gulf Coast fields were impaired $4,950,417, of which $1,936,390 was due to wells which had lower proved reserve values than their current net book values and $3,014,027 was due to previously capitalized lease and land costs which were not expected to be developed within the current year. We impaired two wells in California, one drilled in 2008 was impaired for $348,376 and the other a workover was impaired $340,129, due to lower reserves. Two fields in California, the Elkhorn Slough and Bowerbank, were impaired $284,379 and $100,436, respectively due to lower proved reserves than their current book values. In 2007, the majority of this impairment, $1,248,843, was recorded in our Bowerbank field in California, where various recently drilled wells had significantly lower proved undeveloped reserves than originally estimated. The Afton field in California was impaired for $389,946 mainly on acquired wells which ceased producing due to their natural declines and had lower reserves than originally estimated. Our Texas and Gulf Coast fields were impaired $283,371 due to wells in these areas which had lower production and reserves than originally estimated. Our Elkhorn Slough field was impaired for $148,734 due to lower proved undeveloped reserves than originally estimated.

 

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. As a result of that review in 2008 and 2007, we established an allowance of $973,319 and $546,874, respectively, for receivables from these Direct Working Interest owners.

 

The aggregate of supervisory fees and other income was $703,027 for the year ended December 31, 2008, a decrease of $336,177 (32.3%) from $1,039,204 during the year in 2007. This decrease was the result of several factors including the decrease in cost recovery received for use of facilities constructed and placed into service during prior periods as a result of lower production levels. 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, Public Accountants. Supervisory fees decreased $8,579

 

 

or 2.1%, to $392,318 in 2008 from $400,897 in 2007.

 

Depreciation, depletion and amortization expense increased to $4,148,415 from $3,585,682 an increase of $562,733 (15.7%) for the year ended December 31, 2008, as compared to 2007. The depletion rate is calculated using production as a percentage of reserves. This increase in depletion expense was mainly due to the decrease in our oil and gas reserves at year end 2008.

 

General and administrative expenses increased by $237,359 or 5%, from $4,712,624 for the year ended December 31, 2007 to $4,949,983 for the year in 2008. This increase was primarily due to a bad debts write-off in 2008 of approximately $567,521, compared to $262,532 in 2007, for receivables from direct working interest investors whose expenses on non-producing wells are contractually not collectable. Legal and accounting expense increased to $1,211,989 for the year, compared to $928,628 for year 2007, a $283,361 or 30.5% increase. This increase was due to higher legal fees due to litigation defending property rights during 2008 and 2007.

 

Marketing expense for the year ended December 31, 2008, decreased $294,297 or 20.2%, to $1,160,999, compared to $1,455,296 for the year in 2007. Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs.

 

In September 2008, the company sold its Rio Bravo field located in Kern County, California for $4.75 million, resulting in a net gain from the sale of $2,637,203. During the first quarter in 2008, we also recorded a loss of $27,823 on the sale of a non-oil and gas asset. During 2007, we sold our interests in two non oil and gas assets resulting in a loss on sale of $135,396.

 

During 2008, interest expense increased to $221,667 from $152,547 in 2007, a $69,120 or 45.3% increase. This was due to an increase in the usage of our bank line of credit.

 

In 2008, we had an income tax benefit of $5,806,938 mainly due to our net loss before taxes of $14,584,552. In 2007, we also had an income tax benefit of $1,258,484 also due to our net loss before taxes of $4,037,691. The use of percentage depletion created from the current operations, and from utilization of unused percentage depletion carryforwards, results in an effective tax rate less than the normal federal rate of 35% plus the relevant state rates (mostly California, 9.3%).

 

Results of Operations for the Twelve Months Ended December 31, 2007, as Compared to the Twelve Months Ended December 31, 2006

For the year ended December 31, 2007, we had a net loss of $2,779,207 compared to the net loss of $2,649,701 achieved during 2006. A major component of the loss was an impairment of $2,106,670 due to a decrease in reserve values at year end 2007. The loss also resulted from decreases in revenues from both the turnkey drilling and the oil and natural gas production segments of our business.

 

Total revenues from operations for the year in 2007 were $16,557,399, a decrease of $8,338,644, or 33.5%, from the total revenues of $24,896,043 in 2006. In 2007 our natural gas revenues decreased due to lower natural gas and oil production and our turnkey drilling revenues declined due to a decrease in the number of wells drilled. Lower oil and natural gas production accounted for 22% of the decrease, and lower turnkey drilling revenues accounted for 76% of the decrease.

 

 

In 2007, revenues from oil and gas production decreased by 23.3% to $6,110,092 from $7,965,633 in 2006, due to a decrease in natural gas and oil production. The net sales volume of natural gas for the year ended December 31, 2007, was approximately 791,195 Mcf with an average price of $6.56 per Mcf, versus 1,074,573 Mcf with an average price of $6.21 per Mcf for 2006. This represents a decrease in net sales volume of 283,378 Mcf or 26.4%. This decrease in production was due to a natural decline in production from existing oil and gas wells and to the sale of a number of underperforming properties at the end of 2006. The net sales volume for oil and condensate (natural gas liquids) production was approximately 14,088 barrels with an average price of $65.02 per barrel for the year ended December 31, 2007, compared to 21,325 barrels at an average price of $60.34 per barrel for the year in 2006. This represents a decrease in net sales volume of 7,237 barrels, or 33.9%.

 

Oil and gas lease operating expenses increased by $148,708, or 7.6%, to $2,116,977 for the year ended December 31, 2007, from $1,968,269 for the year in 2006. This increase was mainly due to higher workover costs during the period in 2007 when compared to 2006, as we attempted to increase production on some of our existing wells. When measuring lease operating costs on a production or lifting cost basis, in 2007, the $2,116,977 equates to a $2.27 per mcfe lifting cost versus a $1.53 per mcfe lifting cost in 2006, a 48.4% increase.

 

For the year ended December 31, 2007, turnkey drilling revenues decreased $6,303,447 to $9,408,103 in 2007 from $15,711,550 in 2006, or 40.1%. We also had a $4,650,583 or 48.3% decrease in turnkey drilling and development costs to $4,977,811 in 2007 from $9,628,394 in 2006. These decreases were mainly due to fewer wells drilled, seven during the year in 2007 while sixteen wells were drilled during the year in 2006, as we focused our efforts into developing the Utah property. We drilled four exploratory wells and three developmental wells in 2007 versus six exploratory wells and ten developmental wells in 2006. Exploratory wells tend to be more expensive due to new lease, geological and geophysical and facility costs. Our gross margins, or profits, on drilling depend on our ability to accurately estimate the costs associated with the development of projects in which we sell working interests and to acquire viable properties that can be successfully developed. Costs associated with contract drilling depend on location, well depth, weather, and availability of drilling contractors and equipment. Our gross margin on drilling was 47.1% and 38.7% for the years ended December 31, 2007 and 2006, respectively. Gross margin is calculated as the difference between turnkey drilling revenue and turnkey drilling expense. However, management believes that a portion of its impairment losses should also be considered as a cost of drilling in determining the profitability of this segment, because impairment costs are incurred in the selection of higher quality prospects for ultimate development.

 

Impairment losses of $2,106,670 and $6,191,417 were recorded in 2007 and 2006, respectively. In 2007 and 2006, we recorded impairments in fields where year end reserve values no longer supported the net book values of wells in those fields. In 2007, the majority of this impairment, $1,248,843, was recorded in our Bowerbank field in California, where various recently drilled wells had significantly lower proved undeveloped reserves than originally estimated. The Afton field in California was impaired for $389,946 mainly on acquired wells which ceased producing due to their natural declines and had lower reserves than originally estimated. Our Texas and Gulf Coast fields were impaired $283,371 due to wells in these areas which had lower production and reserves than originally estimated. Our Elkhorn Slough field was impaired for $148,734 due to lower proved undeveloped reserves than originally estimated. In 2006, the primary focus of this impairment, $4,068,843, was recorded for our wells in the Texas and Gulf

 

 

Coast fields. There were several wells in this area that had been drilled in the last few years which had significantly lower production and reserves than originally estimated. The Bowerbank field in California was impaired for $1,331,093 mainly for older wells which ceased producing due to their natural declines. Our Cache Creek field was impaired for its remaining value of $399,269 due to the drilling of the North Crossroads 6-34 which proved unsuccessful. The Willows field was also impaired for $255,109 due to the drilling of the North Willows 3 which although successful had lower reserves than originally estimated.

 

We periodically review our accounts receivable from working interest owners to determine whether collection of any of these charges where doubtful. The Company does not attempt collection 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. As a result of that review in 2007 and 2006, we established an allowance of $546,874 and $567,000, respectively, for receivables from these Direct Working Interest owners.

 

The aggregate of supervisory fees and other income was $1,039,204 for the year ended December 31, 2007, a decrease of $179,656 (14.7%) from $1,218,860 during the year in 2006. This decrease was the result of several factors including the decrease in the number of wells operated due to the sale of properties in 2006, the decrease in drilling and the decrease in cost recovery received for use of facilities constructed and placed into service during prior periods as a result of lower production levels. 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, Public Accountants. Supervisory fees decreased $83,718 or 17.3%, to $400,897 in 2007 from $484,615 in 2006.

 

Depreciation, depletion and amortization expense decreased to $3,585,682 from $5,833,904 a decrease of $2,248,222 (38.5%) for the year ended December 31, 2007, as compared to 2006. The depletion rate is calculated using production as a percentage of reserves. This decrease in depletion expense was mainly due to the decrease in our oil and gas assets from our 2006 asset sale and impairments.

 

We also reevaluated our inventory of capitalized geological lease and land costs, in order to write off those prospects that may be no longer viable. As a result, $423,459 of previously capitalized costs were written off and recorded as geological and geophysical expense during 2007, compared with $400,306 written off in 2006, a $23,153 or 5.8% increase. This expense is directly attributable to the selection and prioritization of the quality of the company’s drilling prospects.

 

General and administrative expenses decreased by $416,450 or 8.1%, from $5,129,074 for the year ended December 31, 2006 to $4,712,624 for the year in 2007. This decrease was primarily due to a bad debts write-off in 2006 of approximately $582,204, compared to $262,532 in 2007, for receivables from direct working interest investors whose expenses on non-producing wells are contractually not collectable. Legal and accounting expense increased to $928,628 for the year, compared to $397,575 for year 2006, a $531,053 or 133.6% increase. This increase was due to higher legal fees due to litigation defending property rights during 2007.

 

 

Marketing expense for the year ended December 31, 2007 decreased $343,792 or 19.1%, to $1,455,296, compared to $1,799,088 for the year in 2006. Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs.

 

During 2007 we sold our interests in two non oil and gas assets resulting in a loss on sale of $135,396. In November 2006 we sold 19 of our producing Sacramento Basin wells and support facilities for $4,510,000, resulting in a gain on sale of $3,263,368.

 

During 2007 interest expense decreased to $152,547 from $523,139 in 2006, a $370,592 or 70.8% decrease. This decrease was due to principal balance reduction on our line of credit and to the decrease in the interest rate charged to the company, which went from 8.75% at December 31, 2006, to 7.75% at December 31, 2007.

 

In 2007 we had an income tax benefit of $1,258,484 mainly due to our net loss before taxes of $4,037,691. In 2006 we also had an income tax benefit of $1,062,054 also due to our net loss before taxes of $3,711,755 and the utilization of our depletion carryforwards. The use of percentage depletion created from the current operations, and from utilization of unused percentage depletion carryforwards, results in an effective tax rate less than the normal federal rate of 35% plus the relevant state rates (mostly California, 9.3%).

 

Capital Resources and Liquidity

At December 31, 2008, Royale Energy had current assets totaling $8,891,126 and current liabilities totaling $14,325,985, a $5,434,859 working capital deficit. We had cash and cash equivalents at December 31, 2008 of $1,330,739 compared to $3,848,968 at December 31, 2007.

 

Our capital expenditure commitments occur as we decide to drill wells to develop our prospects. We generally do not decide to drill any prospect until we have sold a portion of the working interest in a prospect to third parties to diversify our risk and receive a portion of the funds to drill each prospect. We place funds that we receive from third party investors into a separate cash account until they are required for expenditures on each well. Our capital expenditure needs in addition to those needs are satisfied by selling part of the working interest in prospects.

 

We have not, in past years, experienced shortages of funds needed to satisfy our capital expenditure requirements. We expect that our available credit and cash flows from operations will be sufficient for capital expenditure needs beyond those satisfied from sales of working interests. We ordinarily fund our operations and cash needs from cash flows generated from operations. We believe that we have sufficient liquidity for 2008 and do not foresee any liquidity demands that cannot be met from cash flow from operations.

 

At the end of 2008, our accounts receivable totaled $3,750,557 compared to $4,090,341 at December 31, 2007, a $339,784 or 8.3% decrease, primarily due to receivables from industry members participating in wells we drilled at the end of 2007. At December 31, 2008, our accounts payable and accrued expenses totaled $10,320,187, an increase of $240,151 or 2.4% over the accounts payable at the end of 2007 of $10,080,034. This increase was primarily due to drilling and completion of two Utah wells and one California well, and the workover of an additional California well at year end in 2008.

 

 

Occasionally we borrow from banks, using our oil and gas properties as security. In 2008, we made net principal repayments of approximately $3,200,000 on our credit line. In 2007, we drew approximately $1,132,929 net, in order to meet our drilling schedule.

 

In 2008 we had a revolving line of credit under a loan agreement with Guaranty Bank, FSB, which is secured by all of our oil and gas properties. At December 31, 2008, we had outstanding indebtedness of $1,975,974. Unused available credit from this revolving line of credit totaled approximately $100,000 at December 31, 2008. At December 31, 2007, we had outstanding indebtedness of $5,175,974 with unused available credit of approximately $200,000.

 

In February 2009, the Guaranty Bank loan was repaid and 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. Interest is to be the greater of Texas Capital Bank’s base rate and the Federal Funds rate but in no event less than 3% per year. The borrowing base at the closing date was $4,900,000 with borrowing base reductions of $175,000 commencing on March 1, 2009. All unpaid principal and interest is payable at maturity on February 13, 2013.

 

The Texas Capital Bank loan agreement contains certain restrictive covenants, including a prohibition of payment of dividends on Royale’s stock (other than dividends paid in stock). The loan agreement contains covenants that, among other things, Royale must:

 

 

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, 2008, and the effect such obligations are expected to have on our liquidity and cash flow in future periods.

 

Operating Activities. For the year ended December 31, 2008, cash provided by operating activities totaled $1,540,924 compared to $4,427,012 provided by operating activities for the same period in 2007, a $2,886,088 or 65.2% decrease, mainly due to our decrease in deferred income taxes due to our year end loss which provided an income tax benefit for the Company. In 2007 cash provided by operating activities totaled $4,427,012 compared to $3,406,393 provided by operating activities for the same period in 2006, a $1,020,619 or 30% increase, mainly due to our increase in accounts payable and accrued expenses from drilling.

 

 

 

Investing Activities. Net cash used by investing activities netted to $4,689,152 for the year in 2008, which included $9,865,255, used mainly for oil and gas capital expenditures, along with proceeds from our oil and gas asset sale of $5,698,911. Beginning in July 2008, the Company began to purchase a material amount of equity securities. Based upon management’s intent for the items, the Company has categorized these as available-for-sale securities. For the year ended December 31, 2008, we have purchased $633,427 and sold $110,619 in equity securities. In 2007, net cash used by investing activities netted to $8,691,528 for the year in 2007, which included $8,835,180, used mainly for oil and gas capital expenditures, along with proceeds from our non oil and gas assets sale of $143,652. In 2006, net cash provided by investing netted to $1,932,738 which included $3,091,316 used for oil and gas and other capital expenditures along with proceeds from our oil and gas asset sales of $5,024,054.

 

Financing Activities. For the year ended December 31, 2008 cash provided by financing activities was $629,999 compared to $735,880 provided by financing activities in 2007. In the second quarter of 2008 we received net proceeds of $3,724,999 from the sale of common stock and warrants to one investor in a private placement. The proceeds were used to pay $2,000,000 to reduce long term debt payments and for working capital. We also received $105,000 from the exercise of stock options. During 2007 cash provided by financing activities was $735,880 compared to $2,678,299 used by financing activities in 2006. This difference was primarily due to an increase in net borrowings on our commercial bank line of credit during the period in 2007. Also in January 2007, the Board of Directors declared a cash dividend of $0.05 per share for shareholders of record on February 19, 2007. This dividend was paid March 5, 2007, in the amount of $397,049.

 

Changes in Reserve Estimates

In 2008, our estimated proved developed and undeveloped reserve quantities were revised slightly upward by approximately .10 million cubic feet of natural gas mainly due to two California wells which had higher than originally estimated proved producing reserves. Also in 2008 our estimated proved developed and undeveloped oil reserves were revised upward by approximately 11,900 barrels primarily due to one Texas well which had higher than originally estimated proved producing reserves.

 

The following table summarizes the major reasons for reserve increases in 2007.

 

 

 

 

In 2007, our estimated proved developed and undeveloped reserve quantities were revised downward by approximately 4.05 million cubic feet of natural gas. See, Supplemental Information about Oil and Gas Producing Activities (Unaudited), page F-31. During 2007, it was discovered that two producing wells had lower than previously estimated proved producing gas reserves, resulting in a reduction of proved developed producing gas reserves. There were also reductions on two additional producing wells that had lower than previously estimated proved non-producing reserves. Also during 2007, four prospects that had been previously estimated to contain proved undeveloped gas reserve were re-evaluated and found to have lower than expected reserves and as a result were not drilled. Three other prospects that had been previously estimated to contain proved undeveloped gas reserve are still being evaluated and pending final results expected reserves were reduced. One other prospect with proved undeveloped reserves were drilled and resulted in proved reserves less than prior estimates. The revisions of previous estimates attributable to these wells accounted for approximately 98% of the net downward revisions of previous gas reserve estimates.

 

The following table summarizes the major reasons for reserve reductions in 2007.

 

 

In 2006, our estimated proved developed and undeveloped reserve quantities were revised downward by approximately 1.02 million cubic feet of natural gas and 34,000 barrels of oil. See, Supplemental Information about Oil and Gas Producing Activities (Unaudited), page F-31. During 2006, it was discovered that four producing wells had lower than previously estimated non-producing gas reserves, resulting in a reduction of proved developed non-producing gas reserves. Also during 2006, two prospects that had been previously estimated to contain proved undeveloped gas reserve were re-evaluated and found to have lower than expected reserves and as a result were not drilled. One other prospect with proved undeveloped reserves was drilled and resulted in proved reserves less than prior estimates. The revisions of previous estimates attributable to these wells accounted for approximately 99% of the net downward revisions of previous gas reserve estimates.

 

The reduction in oil reserve estimates in 2006 was due to a re-evaluation of two prospects that had been previously estimated to contain proved undeveloped oil reserves were found to have lower than expected reserves and as a result were not drilled. Also, one prospect with proved undeveloped oil reserves was drilled and resulted in proved oil reserves less than prior estimates. The revisions of previous estimates attributable to these wells accounted for approximately 74% of the net downward revisions of previous gas reserve estimates.

 

The following table summarizes the major reasons for reserve reductions in 2006.

 

 

 

 

 

 

 

Royale Energy is exposed to market risk from changes in commodity prices and in interest rates. In 2008, we sold a majority of our natural gas at the daily market rate through the Pacific Gas & Electric pipeline. In 2008, our natural gas revenues were approximately $5.9 million with an average price of $8.32 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 $590,000. 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 $105,000. We currently do not sell any of our natural gas or oil through hedging contracts.

 

We have a line of credit used in funding purchases of oil and gas assets, meeting drilling schedules and assisting in funding operations. This line of credit is tied to increases or decreases in the bank prime interest rate. If the interest rate on our line of credit were to increase 1% or 2% during the year this could potentially add approximately $20,000 to $40,000, respectively, to our interest expense.

 

 

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

 

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

There are no disagreements with Accountants on Accounting and Financial Disclosure.

 

In 2007, our auditors, Sprouse & Anderson, LLP, merged with the firm of Padgett, Stratemann & Co., LLP. At the time of the merger, our audit committee approved a mutual agreement with our independent auditor to terminate Sprouse & Anderson’s engagement as our independent auditor and to engage their successor firm, Padgett, Stratemann & Co., LLP as our new auditor. We expect to maintain a continuity of auditing experience and personnel.

 

At the time of terminating the audit engagement, there were no disagreements between us and Sprouse & Anderson on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which, if not resolved to Sprouse & Anderson’s satisfaction, would have caused it to make reference to the subject matter of the disagreement in connection with its report. Sprouse & Anderson reported on our financial statements for the fiscal years from 2004 through 2006.

 

 

The auditor’s reports on our financial statements during the two most recent fiscal years contained no adverse opinion or disclaimer of opinion and were not modified as to uncertainty, audit scope, or accounting principles.

 

 

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, evaluated the effectiveness or our disclosure controls and procedures as of the end of the 2008 fiscal year. Based on their evaluation, they concluded that our disclosure controls are effective as of December 31, 2008.

 

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, 2008, 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. Our independent registered public accounting firm, Padgett Stratemann & Co. LLP, audited our consolidated financial statements, and will be required to independently assess the effectiveness of our internal control over financial reporting as of December 31, 2009.

 

Changes in Internal Control over Financial Reporting

 

No changes in our internal control over financial reporting occurred during the last fiscal quarter of 2008 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

 

The information required by this Item will be contained in, and incorporated by reference to, the Proxy Statement for the annual meeting of Royale Energy, which will be filed with the SEC and mailed to stockholders within 120 days of December 31, 2008.

 

 

The information required by this Item will be contained in, and incorporated by reference to, the Proxy Statement for the annual meeting of Royale Energy, which will be filed with the SEC and mailed to stockholders within 120 days of December 31, 2008.

 

 

The information required by this Item will be contained in, and incorporated by reference to, the Proxy Statement for the annual meeting of Royale Energy, which will be filed with the SEC and mailed to stockholders within 120 days of December 31, 2008.

 

 

The information required by this Item will be contained in, and incorporated by reference to, the Proxy Statement for the annual meeting of Royale Energy, which will be filed with the SEC and mailed to stockholders within 120 days of December 31, 2008.

 

 

The information required by this Item will be contained in, and incorporated by reference to, the Proxy Statement for the annual meeting of Royale Energy, which will be filed with the SEC and mailed to stockholders within 120 days of December 31, 2008.

 

 

Financial Statements

 

 

2.         Schedules. Supplemental Information About Oil and Gas Producing Activities (Unaudited) begins on page F-29.

 

3.         Exhibits. Certain of the exhibits listed in the following index are incorporated by reference.

 

 

 

 

 

 

 

 

Signatures

 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

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

 

 

 

ROYALE ENERGY, INC.

INDEX TO FINANCIAL STATEMENTS

AND SUPPLEMENTARY DATA

 

 

 

 

 

 

 

 

 

 

 

 

Financial statement schedules have been omitted since they are either not required, are not applicable, or the required information is shown in the financial statements and related notes.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors

of Royale Energy, Inc.

 

We have audited the accompanying balance sheets of Royale Energy, Inc. (the “Company”) as of December 31, 2008 and December 31, 2007, and the related statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2007. 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 audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our 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, 2008 and 2007, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America.

 

PADGETT, STRATEMANN & COMPANY, L.L.P.

 

Austin, Texas

 

March 26, 2009

 

 

 

 

 

 

 

ROYALE ENERGY, INC

BALANCE SHEETS

DECEMBER 31, 2008 AND 2007

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

ROYALE ENERGY, INC.

BALANCE SHEETS

DECEMBER 31, 2008 AND 2007

 

 

 

 

 

 

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

 

 

ROYALE ENERGY, INC.

STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2008, 2007, AND 2006

 

 

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

 

 

ROYALE ENERGY, INC.

STATEMENTS OF STOCKHOLDERS' EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2008, 2007, AND 2006

                                                                                                                                     

 

 

 

 

 

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

 

 

ROYALE ENERGY, INC.

STATEMENTS OF STOCKHOLDERS' EQUITY (Continued)

FOR THE YEARS ENDED DECEMBER 31, 2008, 2007, AND 2006

 

 

 

 

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

 

 

ROYALE ENERGY, INC.

STATEMENTS OF STOCKHOLDERS' EQUITY (Continued)

FOR THE YEARS ENDED DECEMBER 31, 2008, 2007, AND 2006

 

 

 

 

 

 

 

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

 

 

ROYALE ENERGY, INC.

STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006

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") 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, estimated future net cash flows, taxes, and contingencies.

 

Joint Ventures

 

The accompanying financial statements as of December 31, 2008 and 2007 include the accounts of Royale Energy and its proportionate share of the assets, liabilities and results of operations. Royale Energy generally retains an ownership interest of approximately 50% in wells it drills with its joint venture projects. Royale Energy is the operator of the majority of properties in which it has an ownership interest. In connection with the drilling and operation of wells, the Company receives industry standard COPAS fees, which are recorded as supervisory fee income.

 

Revenue Recognition

 

Royale Energy recognizes revenues from the sales of oil and natural gas upon transfer of title, net of royalties, in the period of delivery. Settlements for oil and natural gas sales can occur up to two months after the end of the month in which the oil and natural gas were produced. We estimate and accrue for the value of these sales using information available to us at the time our financial statements are generated.

 

Royale Energy recognizes revenues from the sale of natural gas in which the Company has an interest with other producers using the entitlements method of accounting. Under this method we recognize revenue based on our entitled ownership percentage of sales of natural gas delivered to purchasers. Gas imbalances occur when we sell more or less than our entitled ownership percentage of total natural gas production. When we receive more than our entitled share, a liability is recorded. Gas imbalances on our production at December 31, 2008, 2007 and 2006 were not significant.

 

Royale Energy enters into turnkey drilling agreements with investors to develop leasehold acreage it has acquired. When Royale Energy sponsors a turnkey drilling project for sale, a calculation is made to estimate the pre-drilling

 

 

costs and the drilling costs. A percentage for each is calculated. The turnkey drilling project is then sold to investors who enter into a signed contract with Royale Energy. In this agreement, the investor agrees to share in the pre-drilling costs, which include lease costs, and other costs as required so that the drilling of the project can proceed. As stated in the contract, the percentage of the pre-drilling costs that the investor contributes is non-refundable, and thus on its financial statements, Royale Energy recognizes these non-refundable payments as revenue since the pre-drilling costs have commenced. The remaining investment is held and reported by Royale Energy as deferred revenue until drilling is complete. Drilling is generally completed within 10-30 days. If costs exceed revenues and Royale Energy participates as a working interest owner, Royale’s proportional share of the excess is capitalized as the cost of Royale Energy's working interest. If Royale Energy is unable to drill the wells, and a suitable replacement well is not found, the deferred funds received would be returned to the investors. Included in cash and cash equivalents are amounts for use in the completion of turnkey drilling programs in progress.

 

Oil and Gas Property and Equipment (Successful Efforts)

 

Royale Energy accounts for its oil and gas exploration and development costs using the successful efforts method. Leasehold acquisition costs are capitalized. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Significant undeveloped leases are reviewed periodically and a valuation allowance is provided for any estimated decline in value. Cost of other undeveloped leases is expensed over the estimated average life of the leases. Cost of exploratory drilling is initially capitalized. In the absence of a determination that proved reserves are found, the costs of drilling such exploratory wells are charged to expense. Royale Energy makes this determination within one year following the completion of drilling. Other exploratory costs are charged to expense as incurred. Development costs, including unsuccessful development wells, are capitalized. Depletion, depreciation and amortization of oil and gas producing properties are computed on an aggregate basis using the units-of-production method.

 

Financial Accounting Standards Board (FASB), Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets ", requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. It establishes guidelines for determining recoverability based on future net cash flows from the use of the asset and for the measurement of the impairment loss. Impairment loss under SFAS No. 144 is calculated as the difference between the carrying amount of the asset and its fair value. Any impairment loss is recorded in the current period in which the recognition criteria are first applied and met. Under the successful efforts method of accounting for oil and gas operations, Royale Energy periodically assessed its proved properties for impairments by comparing the aggregate net book carrying amount of all proved properties with their aggregate future net cash flows. The statement requires that the impairment review be performed on the lowest level of asset groupings for which there are identifiable cash flows.

 

Royale Energy performs a periodic review for impairment of proved properties on a field-by-field basis. Unamortized capital costs are measured on a field basis and are reduced to fair value if it is determined that the sum of expected future net cash flows are less than the net book value. Royale Energy determines if impairment has occurred through either adverse changes or as a result of its periodic review for impairment. Impairment is measured on discounted cash flows utilizing a discount rate appropriate for risks associated with the related properties or based on fair market values. Impairment losses of $15,691,348, $2,106,670, and $6,191,417, were recorded in 2008, 2007, and 2006 respectively.

 

Upon the sale of oil and gas reserves in place, costs and accumulated amortization of such property are removed from the accounts and resulting gain or loss on sale is reflected in operations. Impairment of unproved properties is assessed periodically on a property-by-property basis, and any impairment in value is currently charged to expense. In addition, capitalized costs of unproved properties are assessed periodically to determine whether their value has been impaired below the capitalized costs. Loss is recognized to the extent that such impairment is indicated. In making these assessments, factors such as exploratory drilling results, future drilling plans, and lease expiration terms are considered. When an entire interest in an unproved property is sold, gain or loss is recognized, taking into consideration any recorded impairment. Upon abandonment of properties, the reserves are deemed fully depleted and any unamortized costs are recorded in the statement of income under impairment expense.

 

 

In 2008, Royale Energy recorded an impairment of $15,691,348 in fields where year end reserve values no longer supported net book values of the related wells in those fields. Moreover, 2008 impairments also include significant impairments of nonviable geological lease and land costs. The majority of these impairments, $9,508,294, were recorded in our Moon Ridge field in Utah, where recently drilled wells had significantly lower proved reserves than originally estimated. Royale’s Texas and Gulf Coast fields were impaired $1,936,390 due to lower production, and lower than originally estimated reserves. In addition, the company also had $3,014,027 in nonviable geological lease and land costs incurred in developing its Gulf Coast and Texas fields with Brigham Exploration Company. In reviewing these carried costs, management determined Royale Energy would not be able to pursue any additional wells with Brigham where these costs would be allocated. Royale had impairment in its Dunnigan Hills, Bowerbank, Elkhorn Slough, and Afton fields in the amounts of $55,616, $100,436, $284,379, and $42,828, respectively. The impairments were the result of natural declines and lower reserves than originally estimated. Management also impaired its costs relating to it two recently drilled wells in Colusa County and Laris Well field by $348,376 and $340,129, respectively. These wells, drilled as developmental to existing reserves, produced no gas, and as such, their related costs were impaired.

 

In 2007, management recorded an impairment of $2,106,670 in fields where year end reserve values no longer supported the net book values of wells in those fields. The majority of this impairment, $1,248,843 was recorded in our Bowerbank field in California, were various recently drilled wells had significantly lower proved undeveloped reserves than originally estimated. The Afton field in California was impaired for $389,946 mainly on acquired wells which ceased producing due to their natural declines and had lower reserves than originally estimated. Our Texas and Gulf Coast fields were impaired $283,371 due to wells in these areas that had been drilled in the last few years which had significantly lower production and reserves than originally estimated. Our Elkhorn Slough field was impaired for $148,734 due to lower proved undeveloped reserves than originally estimated.

 

In 2006, Royale Energy recorded an impairment of $6,191,417 in fields where year end reserve values no longer supported the net book values of wells in those fields. The primary focus of this impairment, $4,068,843 was recorded for our wells in the Texas and Gulf Coast fields. There were several wells in this area that had been drilled in the last few years which had significantly lower production and reserves than originally estimated. The Bowerbank field in California was impaired for $1,331,093 mainly for older wells which ceased producing due to their natural declines. Our Cache Creek field was impaired for its remaining value of $399,269 due to the drilling of the North Crossroads 6-34 which proved unsuccessful. The Willows field was also impaired for $255,109 due to the drilling of the North Willows 3 which although successful had lower reserves than originally estimated.

 

Reclassification

 

Certain items in the financial statements have been reclassified to maintain consistency and comparability for all periods presented herein. The company has determined that certain G&A charges are presented more fairly as Marketing. The reclassification is reflected in all years presented.

 

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 and spare parts and is carried at cost.

 

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, 2008 and 2007, net accounts receivable was $3,750,557 and $4,090,341 respectively. At December 31, 2008 and 2007, the Company established an allowance for uncollectable accounts of $973,319 and

 

 

$546,874, 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.

 

Earnings (Loss) Per Share  

 

Basic and diluted earnings (loss) per share are calculated as follows:

 

 

 

 

 

 

For the years ended December 31, 2008, 2007, and 2006, Royale Energy had dilutive securities of 43,700, 28,708, and 28,708, respectively. These securities were not included in the dilutive earning 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 14. Effective January 1, 2006, the Company adopted SFAS No. 123 (revised 2004) (“SFAS No. 123R”), Share-Based Payment, 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. SFAS No. 123R eliminates the ability to account for stock-based compensation transactions using the intrinsic value method under Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees, and instead generally requires that such transactions be accounted for using a fair-value-based method. The Company uses the Black-Scholes option-pricing model to determine the fair-value of stock-based awards under SFAS No. 123R, consistent with that used for pro forma disclosures under SFAS No. 123, Accounting for Stock-Based Compensation. The Company has elected to use the modified prospective transition method as permitted by SFAS No. 123R and accordingly prior periods have not been restated to reflect the impact of SFAS No. 123R. The modified prospective transition method requires that stock-based compensation expense be recorded for all new and unvested stock options, restricted stock, restricted stock units, and employee stock purchase plan shares that are ultimately expected to vest as the requisite service is rendered beginning on January 1, 2006. Stock-based compensation expense for awards granted prior to January 1, 2006 is based on the grant-date fair-value as determined under the pro forma provisions of SFAS No. 123. The Company recognized incremental stock-based compensation expense of $0 during 2006 as a result of the adoption of SFAS No. 123R.

 

Prior to the adoption of SFAS No. 123R, the Company measured compensation expense for its employee stock-based compensation plans using the intrinsic value method prescribed by APB Opinion No. 25. The Company applied the disclosure provisions of SFAS No. 123 as amended by SFAS No. 148, Accounting for Stock-Based Compensation—Transition and Disclosure, as if the fair-value-based method had been applied in measuring compensation expense. Under APB Opinion No. 25, when the exercise price of the Company’s employee stock options was equal to the market price of the underlying stock on the date of the grant, no compensation expense was recognized.

 

During the year ended December 31, 2008, the Board of Directors authorized approximately 550,000 shares to be issued for equity awards through a stock grant plan adopted in November 2008 and stock option grant plan adopted in March 2008. At this time, these new shares will be issued based upon the availability of authorized shares when exercised. These new shares, upon exercise, will not be issued from the Company’s Treasury stock holdings.

 

 

Income Taxes

 

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.

 

In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109” (FIN 48). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes,” by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. If a tax position is more likely than not to be sustained upon examination, then an enterprise would be required to recognize in its financial statements the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. As discussed in Note 7, the adoption of FIN 48 effective January 1, 2007 did not materially affect our financial position or results of operations.

 

Fair Values of Financial Instruments

 

Disclosure of the estimated fair value of financial instruments is required under SFAS No. 107, "Disclosure about Fair Value of Financial Instruments." The fair value estimates are made at discrete points in time based on relevant market information and information about the financial instruments. These estimates may be subjective in nature and involve uncertainties and significant judgment and therefore cannot be determined with precision.

 

Royale Energy includes fair value in the notes to financial statements when the fair value of its financial instruments is different from the book value. Royale Energy assumes that the book value of financial instruments that are classified as current approximate fair value because of the short maturity of these instruments. For noncurrent financial instruments, Royale Energy uses quoted market prices or, to the extent that there are no available quoted market prices, market prices for similar instruments.

 

At December 31, 2008, Royale Energy reported a fair value of $218,938 relating to available for sale securities. For the purposes of identifying related costs to its available for sale securities, the Company uses a specific identification method. On December 31, 2008, the total cost for those securities amounted to $450,813. An unrealized holding loss of $140,053 was recorded in the equity’s other comprehensive loss section. The unrealized holding loss included an income tax benefit of $91,823.

 

Fair Value Measurements

 

According to SFAS No. 157, “Fair Value Measurements,” for 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.

 

In 2008, Royale Energy reported the fair value of $218,938 in available for sale securities. The fair value was determined using the number of shares owned as of December 31, 2008 multiplied by the market price of those securities on December 31, 2008.

 

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, 2008, Royale Energy quoted prices in active markets for identical assets when determining the fair value measurements at the reporting date.

 

 

Treasury Stock

 

The Company records acquisition of its capital stock for treasury at cost. Differences between proceeds for reissuance of treasury stock and average cost are charged to retained earnings or credited thereto to the extent of prior charges and thereafter to capital in excess of par value.

 

 

 

Recently Issued Accounting Pronouncements

 

In September 2006, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 157 “Fair Value Measurements” (SFAS 157,) which provides expanded guidance for using fair value to measure assets and liabilities. SFAS 157 establishes a hierarchy for data used to value assets and liabilities, and requires additional disclosures about the extent to which a company measures assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings. Implementation of SFAS 157 is required on January 1, 2008.

 

In December 2007, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 160 “Noncontrolling Interest in Consolidated Financial Statements – an Amendment of ARB 51” (SFAS 160). SFAS 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. It also requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest, and requires disclosure, on the face of the consolidated statement of income, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is prohibited.

We are currently evaluating the impact on the financial statements.

 

On December 12, 2007, the Financial Accounting Standards Board ratified the consensus reached by the Emerging Issues Task Force on Issue No. 07-01 “Accounting for Collaborative Arrangements”. This Issue will be effective for the fiscal year beginning January 1, 2009. This pronouncement is not expected to have a material impact on our financial statements.

 

In March 2008, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 161 “Disclosures about Derivative Instruments and Hedging Activities — An Amendment of FASB Statement No. 133” (SFAS 161), that requires new and expanded disclosures regarding hedging activities. These disclosures include, but are not limited to, a proscribed tabular presentation of derivative data; financial statement presentation of fair values on a gross basis, including those that currently qualify for netting under FASB Interpretation No. 39; and specific footnote narrative regarding how and why derivatives are used. The disclosures are required in all interim and annual reports. SFAS 161 is effective for fiscal and interim periods beginning after November 15, 2008.

 

SEC Rulemaking

 

On December 31, 2008, the SEC published the final rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions include the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, permitting disclosure of probable and possible reserves, and changes to the pricing used to determine reserves in that companies must use a 12-month average price. The average is calculated using the first-day-of-the-month price for each of the 12 months that make up the reporting period. The SEC will require companies to comply with the amended disclosure requirements for registration statements filed after January 1, 2010, and for annual reports for fiscal years ending on or after December 15, 2009. Early adoption is not permitted. We are currently assessing the impact that the adoption will have on our disclosures, operating results, financial position and cash flows.

 

 

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:

 

 

On April 4, 2005, the Financial Accounting Standards Board posted FSP FAS 19-1, Accounting for Suspended Well Costs, to be effective for reporting periods beginning after April 4, 2005. We have adopted FSP FAS 19-1 effective as of July 1, 2005. The guidance set forth in the FSP 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 2007 or 2006. We did not charge any previously capitalized exploratory well costs to expense upon adoption of FSP FAS 19-1.

 

 

 

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 three years ended December 31, are as follows:

 

 

In September 2008, Royale Energy sold its Rio Bravo field located in Kern County, California for $4.75 million to Occidental Petroleum of Elk Hills Inc, resulting in a net gain from the sale of $2,637,203. The proceeds from this sale were used in drilling additional natural gas wells as well as in the operations of the company.

 

NOTE 3 – ASSET RETIREMENT OBLIGATION

 

In June 2001, the FASB issued FAS 143, “Accounting for Asset Retirement Obligations.” FAS 143 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 statement 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 CONTRACTS

 

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, 2008 and 2007, Royale Energy had recorded deferred turnkey drilling revenue associated with undrilled wells of $4,005,800 and $3,947,097, respectively, as a current liability.

 

NOTE 5 - FINANCIAL INFORMATION RELATING TO INDUSTRY SEGMENTS

 

Royale Energy identifies reportable segments by product and country, although Royale Energy currently does not have foreign country segments. Royale Energy includes revenues from both external customers and revenues from transactions with other operating segments in its measure of segment profit or loss. Royale Energy also includes interest revenue and expense, DD&A, and other operating expenses in its measure of segment profit or loss.

 

The accounting policies of the reportable segments are the same as those described in the Summary of Significant Accounting Principles (see Note 1).

 

Royale Energy's operations are classified into two principal industry segments. Following is a summary of segmented information for 2008, 2007 and 2006

 

 

 

 

 

 

 

NOTE 6 - LONG-TERM DEBT

 

 

Significant covenants under the terms of the line of credit agreement include that the Company will have a tangible net worth not less than $8,188,000 as of September 30, 2002, plus 50% of positive quarterly net income thereafter, a debt coverage ratio not less than 1.25:1, a bank defined current ratio not less than 1:1, general and administrative expenses (excluding litigation and accounting expenses) at the close of any fiscal quarter not to exceed 27.5% of net revenues. The Company was in compliance with, or had obtained a waiver from, the terms of this agreement at December 31, 2007.

 

Maturities of long-term debt for years subsequent to December 31, 2008 are as follows:

 

 

NOTE 7 - 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, 2008, 2007 and 2006, respectively, are as follows:

 

 

The Company had statutory percentage depletion carry forwards of approximately $2,300,000 and $1,800,000 at December 31, 2008 and 2007, respectively. The depletion has no expiration date. The Company also has a net operating loss carry forward of approximately $ 2,800,000 and $1,100,000 at December 31, 2008 and 2007, respectively. The first portion of Royale’s net operating loss, $1,100,000, will expire in 2027 with the remaining portion, $1,600,000, expiring in 2028.

 

A reconciliation of Royale Energy's provision for income taxes and the amount computed by applying the statutory income tax rates at December 31, 2008, 2007 and 2006, respectively, to pretax income is as follows:

 

 

 

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

 

 

We adopted the provisions of FASB Interpretation (“FIN”) 48, Accounting for Uncertainty in Income Taxes — an interpretation of Statement of Financial Accounting Standards (“SFAS”) 109 on January 1, 2007. FIN 48 clarifies 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 FIN 48 at the time of adoption and December 31, 2008, the Company did not recognize a liability for uncertain tax positions.  As a result, 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 consolidated balance sheets. We do not expect our unrecognized tax benefits to change significantly over the next 12 months. The tax years 2001 through 2008 remain open to examination by the taxing jurisdictions in which we file income tax returns.

 

NOTE 8 - REDEEMABLE PREFERRED STOCK

 

In 1993, Royale Energy's Board of Directors authorized the issuance of 259,250 shares of Series A Convertible Preferred Stock. The Stock is convertible any time at the basic conversion rate of one share of common stock for two shares of Series A Convertible Preferred Stock, subject to adjustment.

 

There were no common stock conversions in 2005. In June 2006, we issued 3,060 shares of common stock to one stockholder on conversion of the remaining outstanding shares of our Series A convertible preferred stock to common, pursuant to the conversion terms of the Series A preferred.

 

NOTE 9 - 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. As of December 31, 2003 and 2002, there were 43,240 and 48,581 shares issued and outstanding. The Board authorized a 15% stock dividend to stockholders of record on May 31, 2002 and increased the number of Series AA Preferred shares by 6,466. In addition, on May 1, 2003, the Board authorized a 15% stock dividend to stockholders of record on that date payable in equal monthly installments beginning with the quarter ending June 30, 2003. This dividend increased the number of Series AA Preferred shares by 3,701 for the period ending December 31, 2003 and has been retroactively restated to reflect the 3^rd quarterly stock dividend paid in January 2004. On March 31, 2004, the fourth and final of these installments was made resulting in 1,619 shares being issued. On March 23, 2004, the Board of Directors declared a 28% stock split, which was distributed to stockholders on June 30, 2004. As a result, the Series AA Preferred shares increased by 12,557. As of December 31, 2007 and 2006, there were 57,416 shares issued and outstanding. In 2008, a Preferred AA stockholder was issued 2,316 shares of common stock in exchange for 4,632 share of Series AA Preferred stock resulting in 52,784 shares of Series AA Preferred stock issued and outstanding as of December 31, 2008.

 

NOTE 10 - COMMON STOCK

 

On March 23, 2004, the Board of Directors declared a 28% stock split issued in the form of a stock dividend, which was distributed to stockholders on June 30, 2004. As a result, the number of common shares increased by 1,712,093. There were no stock dividends during the years ended December 31, 2007 or 2006.

 

 

 

On January 18, 2007 the Board of Directors authorized the issuance of a cash dividend of $0.05 per share for shareholders of record on February 19, 2007. The dividend was paid March 5, 2007 in the amount of $397,049.

 

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, which expires on June 10, 2013, 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. The net proceeds from the private placement went towards general corporate purposes, including the acquisition of oil and natural properties for future development.

 

NOTE 11 - 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, 2008 are as follows:

 

Rental expense for the years ended December 31, 2008, 2007, and 2006 are $370,620, $403,497, and $370,658, respectively.

 

NOTE 12 - RELATED PARTY TRANSACTIONS

 

Significant Ownership Interests

 

Donald H. Hosmer, Royale Energy’s co-president, owns 11.0% 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 and chief financial officer, owns 13.8% 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 8.8% 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.

 

The Board of Directors adopted a policy in 1989 that permits directors and officers of the Company to purchase from the Company, at the Company’s actual costs, up to one percent of a fractional interest in any well to be drilled by the Company. Current and former officers and directors were billed $38,326, $21,759 and $49,787 for their interests for the years ended December 31, 2008, 2007 and 2006, respectively.

 

For the year ended December 31, 2005, Royale Energy repurchased 19,615 stock options held by Stephen Hosmer amounting to $188,912. For the year ended December 31, 2004, the company repurchased 14,063 stock

 

 

options held by Harry Hosmer, and 11,078 held by Don Hosmer, amounting to $160,178 and $126,178 respectively. For the year ended December 31, 2003 the company repurchased 10,290 options from Don Hosmer and 42,000 from Harry Hosmer amounting to $59,270 and $275,854 respectively.

 

Donald H. Hosmer delivered 26,000 shares of common stock of Royale Energy, Inc., owned by him, to the company on September 26, 2006, in exchange for interests in oil and gas drilling projects sponsored by the company. The value of the common stock received by the company in consideration for the exchange was $146,380, based on the closing market price of the company's common stock on the NASDAQ Stock Market on June 12, 2006; the date the agreement to invest was made. Mr. Hosmer continues to hold the remainder of his common shares, equal to 11.0% of the company's common stock, as an investment.

 

 

On June 1, 2005, Royale Energy awarded shares of restricted common stock to certain of its employees pursuant to an incentive compensation plan. On that date, the Company’s stock price was $5.66 per share. A total of 2,253 and 4,612 shares of vested restricted common stock were issued in 2007, and 2006, respectively. The Company recognized $12,752, $26,105 in compensation expenses in 2007, and 2006, respectively. Moreover, the company also recognized a tax benefit from this stock grant arrangement of $3,978, and 7,466 for the years ended December 31, 2007, and 2006, respectively. The stock issued pursuant to the plan was issued in reliance on the exemption from registrations requirements of the Securities Act of 1933 contained in Section 4(2) thereof

 

At the March 23, 2008 Board of Directors meeting, directors and executive officers of Royale Energy were each granted 45,000 options, a total of 360,000 options, to purchase common stock at an exercise or base price of $3.50 per share. These options are to be vested in three parts; the first 120,000 have vested March 31, 2008, and 120,000 will vest in each of the next two years March 31, 2009 and 2010. The options were granted for a legal life of four years with a service period of three years. Royale Energy recorded compensation expense of $74,748 in 2008 relating to these options. The total income tax benefit recognized in the income statement for these option arrangements was $29,600 in 2008.

 

The fair value of the options was calculated using the Black-Scholes option pricing method. Since there is 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, 2008, 2007 and 2006, and changes during the years ending on those dates is presented below:

 

 

The weighted-average grant-date fair value of options granted during 2008 was $0.62 per share, and the fair value of the share vested in 2008 was $74,748. The total intrinsic value of options exercised during 2008 was $220,846. At December 31, 2008, Royale Energy’s stock price 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 40 months as of December 31, 2008.

 

In November 2008, the Board of Directors granted the directors and executive officers of Royale Energy 95,000 shares of restricted common stock. The number of granted share will double to 190,000 shares of common stock if Royale’s stock price reaches $15 a share during the period. The grant is to be vested in three parts, 31,667 or 63,334 shares, depending on Royale’s stock price, which will vest on November 30, 2009, 2010, and 2011. Royale has recognized share-based compensation expense of $20,688 and $8,192 as a tax benefit in 2008 relating to this grant.

 

A summary of the status of Royale Energy's restricted stock grant plans as of December 31, 2008, 2007 and 2006, and changes during the years ending on those dates is presented below:

 

 

 

 

As of December 31, 2008, there was $227,572 of total unrecognized compensation cost related to non-vested share based compensation arrangements granted. That cost is expected to be recognized over a weighted-average period of 33 months.

 

NOTE 14 - 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, 2008, 2007, and 2006 were $61,787, $53,761 and $48,986, respectively.

 

NOTE 15 - 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 2008, 2007, or 2006.

 

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 16 - 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 93% 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 affect 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 for our interest bearing account. For the Company’s non-interest bearing account, Royale Energy’s account balances are fully insured by the FDIC through December 31, 2009. At December 31, 2008 and 2007, cash in banks exceeded the FDIC limits by approximately $247,000 and $4.6 million, respectively. The Company has not experienced any losses on deposits.

 

 

NOTE 17: Quarterly Financial Information (Unaudited):

 

 

Annual Earnings (loss) per share may not equal the sum of the four quarterly amounts due to rounding.

 

NOTE 18: 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.

 

National Fuel Corporation ("NFC") v. Royale Energy, Inc., No. 080800735, Uintah County, Utah.  This lawsuit was filed on October 10, 2008, after the close of the third fiscal quarter.  It arose from a dispute over jointly operated property in which Royale is the 75% owner and operator and NFC is a non-operator with a 25% ownership.  NFC disagrees with the Company's operations and seeks to remove the Company as operator.  NFC also seeks unspecified damages.  The case is in its very beginning, and the Company has not yet responded to the Complaint.  Royale disputes the claims and intends to defend the complaint vigorously.

 

NOTE 19 – SUBSEQUENT EVENTS

 

On February 13, 2009 Royale Energy entered into an agreement with Texas Capital Bank, N.A. for a new revolving line of credit and letter of credit facility, secured by 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. Interest is to be the greater of Texas Capital Bank’s base rate and the Federal Funds rate but in no event less than 3% per year. The borrowing base at the closing date was $4,900,000 with borrowing base reductions of $175,000 commencing on March 1, 2009. All unpaid principal and interest is payable at maturity on February 13, 2013.

 

 

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 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 engineering consultants for the years ended December 31, 2008, 2007, and 2006. 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.

 

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, 2008, 2007 and 2006 and changes in such quantities during each of the years then ended, were as follows:

 

 

 

 

 

 

These estimates were determined using gas prices at December 31, 2008 ranging from $4.60 per MCF to $6.29 per MCF as applied on a field-by-field basis.

 

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 three years ended December 31, 2008.

 

The future net cash inflows are developed 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 2009 through 2011.

 

 

 

Common assumptions include such matters as the real extant and average thickness of a particular reservoir, the average porosity and permeability of the reservoir, the anticipated future production from existing and future wells, future development and production costs and the ultimate hydrocarbon recovery percentage. As a result, oil and gas reserve estimates and discounted present value estimates are frequently revised in subsequent periods to reflect production data obtained after the date of the original estimate. If the reserve estimates are inaccurate, production rates may decline more rapidly than anticipated, and future production revenues may be less than estimated.

 

Additional data relating to Royale Energy's oil and natural gas properties is disclosed in Supplemental Information About Oil and Gas Producing Activities (Unaudited), attached to Royale Energy's Financial Statements, beginning on page F-1. The oil and natural gas reserve information disclosed in the supplement to the financial statements are based upon the reserve reports for the three years ended December 31, 2008, 2007, and 2006, prepared by Royale Energy's independent reserve engineering consultants.

 

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: