Item 1 Description of Business
Royale Energy, Inc. ("Royale Energy"), is an independent oil and natural gas producer. Royale Energy's principal lines of business are the production and sale of natural gas, acquisition of oil and gas lease interests and proved reserves, drilling of both exploratory and development wells, and sales of fractional working interests in wells to be drilled by Royale Energy. Royale Energy was incorporated in California in 1986 and began operations in 1988. Royale Energy's common stock is traded on the Nasdaq National Market System (symbol ROYL). On December 31, 2005, Royale Energy had 30 full time employees.
Royale Energy owns wells and leases located mainly in the Sacramento Basin and San Joaquin Basin in California as well as in Utah, Texas and Louisiana. 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. Selling part of the working interest to others allows Royale Energy to reduce its drilling risk by owning a diversified inventory of properties with less of its own funds invested in each drilling prospect, than if Royale Energy owned the whole working interest and paid all drilling and development costs of each prospect itself. Royale Energy generally sells working interests in its prospects to accredited investors in exempt securities offerings. The prospects are bundled into multi-well investments, which permit the third party investors to diversify their investments by investing in several wells at once instead of investing in single well prospects.
During its fiscal year ended December 31, 2005, Royale Energy continued to explore and develop natural gas properties in northern California. We also own proved developed producing reserves of oil and natural gas in Texas and Louisiana. Royale Energy drilled 15 wells in 2005, nine of which are currently commercially productive wells. Royale Energy's estimated total reserves decreased from approximately 15.8 Bcfe (billion cubic feet equivalent) at December 31, 2004 to approximately 11.4 Bcfe at December 31, 2005. According to the reserve report furnished to Royale Energy by WZI, Inc., Royale Energy's independent petroleum engineers, the net present value of its proved developed and undeveloped reserves was more than $67.8 million at December 31, 2005, based on natural gas prices ranging from $7.48 per Mcf to $10.50 per Mcf. Of course, net present value does not represent the fair market value of our reserves on that date, and we cannot be sure what return we will eventually receive on our reserves. The engineer determined our standard measure of discounted future net cash flows at December 31, 2005, to be $34,803,441.
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 $13,066,800 for the year ended December 31, 2005, which represents 51% of its total revenues for the year. In 2004, Royale Energy reported $13,269,996 gross revenues from turnkey drilling operations for the year, representing 51.1% of Royale Energy's total revenues for that year.
These amounts are offset by drilling expenses and development costs of $8,111,248 in 2005, and $8,150,338 in 2004. In addition to Royale Energy's own engineering staff, Royale Energy hires independent contractors to drill, test, complete and equip the wells that it drills.
Approximately 43.8% of Royale Energy's total revenue for the year ended December 31, 2005 came from sales of oil and natural gas from production of its wells in the amount of $11,228,537. In 2004, this amount was $10,892,574, which represented 42.0% 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 7 - 14 days. See Note 1 to Royale Energy's Financial Statements, at page. Royale Energy maintains internal records of the expenditure of each investor's funds for drilling projects.
Royale Energy generally operates the wells it completes. As operator, it receives fees set by industry standards from the owners of fractional interests in the wells and from expense reimbursements. For the year ended December 31, 2005, Royale Energy earned gross revenues from operation of the wells in the amount of $493,415, representing 1.9% of its total revenues on a consolidated basis for that year. In 2004, the amount was $487,406, which represented about 1.8% of total revenues. At December 31, 2005, Royale Energy operated 68 natural gas wells in California. Royale also owns an interest and operates two natural gas wells in Utah and has non-operating interests in 12 oil and gas wells in Texas, three in Oklahoma, 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. Generally we sell an entire month's production to the highest bidder. Because 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 increased during the summer and fall and declined in the winter and spring.
Royale Energy had no subsidiaries in 2005.
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.
Item 1A
Item 1A Risk Factors
In addition to the other information contained in this report, the following risk factors should be considered in evaluating our business.
We Depend on Market Conditions and Prices in the Oil and Gas Industry.
Our success depends heavily upon our ability to market oil and gas production at favorable prices. In recent decades, there have been both periods of worldwide overproduction and underproduction of hydrocarbons and periods of increased and relaxed energy conservation efforts. As a result the world has experienced periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis; these periods have been followed by periods of short supply of, and increased demand for, crude oil and, to a lesser extent, natural gas. The excess or short supply of oil and gas has placed pressures on prices and has resulted in dramatic price fluctuations.
Natural gas demand and the prices paid for gas are seasonal. The fluctuations in gas prices and possible new regulations create uncertainty about whether we can continue to produce gas for a profit.
Prices for oil and natural gas affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of oil and natural gas that we can economically produce. Any substantial and extended decline in the price of oil or natural gas would decrease our cash flows, as well as the carrying value of our proved reserves, our borrowing capacity and our ability to obtain additional capital.
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:
-
the timing of both production and related expenses;
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changes in consumption levels; and
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governmental regulations or taxation.
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.
Increased Activity and Competition for Drilling Rigs and Equipment May Impair Our Ability to Acquire New Reserves.
In 2004 and 2005, drilling activity increased in the areas where we operate. The increased activity made it more difficult for us to obtain drilling rigs, equipment and services in a timely manner and slowed our drilling and development program. These delays have contributed to a decline in our gas reserves as we have been unable to replace normal production declines with production from new wells. Continued delays in drilling could cause further declines in our gas production, reserves and revenues.
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 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 in operations.
We Depend on Key Personnel.
Our business will depend on the continued services of our president and chief executive officer, Donald H. Hosmer, and executive vice president and chief financial officer, Stephen M. Hosmer. 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 president of the company. Stephen M. Hosmer is executive vice president and chief financial officer. Harry E. Hosmer is the chairman of the board. Together, they make up three of the seven members of our board of directors. These individuals own or control the following amounts of Royale Energy common stock, including shares they have the right to acquire on the exercise of outstanding stock options:
Name
Number of Shares
Percent*
Donald H. Hosmer
1,016,437
12.81%
Stephen M. Hosmer
1,221,561
15.40%
Harry E. Hosmer
778,797
9.82%
Total
3,016,795
38.02%
* Based on total of 7,934,736 outstanding shares on December 31, 2005.
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.
Item 2
Item 2 Description of Property
Since 1993, Royale Energy has concentrated on development of properties in the Sacramento Basin and the San Joaquin Basin of Northern and Central California. In 2005, Royale Energy drilled eight wells in northern and central California, four of which were commercially productive wells and are currently producing. Additionally, Royale drilled one well in Utah which was commercially productive and is currently producing. Royale Energy also participated in drilling six wells in Texas, four of which were commercially productive and are currently producing.
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.
Royale Energy maintains 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, 2005, was $6,955,974. At December 31, 2005, Royale Energy owed $6,400,000 under this credit line. 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, 2005, for each property discussed below, have been determined by WZI, Inc., registered professional petroleum engineers, in accordance with its report submitted to Royale Energy on March 21, 2006 (the most recent report available).
Northern California
Royale Energy owns lease interests in 15 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, 2005, Royale operated 68 wells in California with estimated total proven, developed, and undeveloped reserves at approximately 7.8 bcf, according to Royale's
independently prepared reserve report as of December 31, 2005.
Developed and Undeveloped Leasehold Acreage
As of December 31, 2005, 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, 2003, 2004 and 2005. 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 volume
Oil (Bbl)
16,558
20,017
23,411
Gas (Mcf)
1,384,860
1,870,250
1,944,779
Mcfe
1,550,440
2,070,420
2,178,889
Average sales price
Oil (Bbl)
$ 51.95
$ 36.66
$ 28.00
Gas (Mcf)
$ 7.48
$ 5.43
$ 4.86
Net production costs and taxes
$2,751,441
$2,817,448
$ 1,714,382
Lifting costs (per Mcfe)
$ 1.77
$ 1.36
$ 0.79
Net Proved Oil and Natural Gas Reserves
As of December 31, 2005, Royale Energy had proved developed reserves of 6,990 MMcf and total proved reserves of 10,564 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 65 Mbbl and total proved oil reserves of 91 Mbbl.
Oil and gas reserve estimates and the discounted present value estimates associated with the reserve estimates are based on numerous engineering, geological and operational assumptions that generally are derived from limited data.
Item 3
Item 3 Legal Proceedings
None
PART II
Item 5
Item 5 Market for Common Equity and Related Stockholder Matters
Since 1997 Royale Energy's Common Stock has been traded on the Nasdaq National Market System under the symbol "ROYL." As of December 31, 2005, 7,934,736 shares of Royale Energy's Common Stock were held by approximately 3,099 stockholders. The following table reflects high and low quarterly closing sales prices from January 2003 through December 2005. 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
In 2005, we paid no cash or stock dividends. In March 2004, the board of directors declared a 28% stock split, which was distributed to stockholders on June 30, 2004. In March 2003, Royale Energy's board of directors declared stock dividends of 3.75% payable to stockholders of record on each of the last days June, September and December 2003 and March 2004.
Recent Sales of Unregistered Securities
In June 2005, Royale Energy awarded shares of restricted common stock to certain of its employees pursuant to an incentive compensation plan. A total of 6,050 shares of vested restricted common stock were issued in 2005. An additional 12,100 shares of unvested stock were awarded with vesting dates in 2006 and 2007. 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. Royale Energy issued no other equity securities in 2005.
Item 6
Item 6 Selected Financial Data
Item 7
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 twelve years, Royale Energy has primarily acquired and developed producing and non-producing natural gas properties in California. In the past four years, Royale Energy has also participated in drilling oil and gas wells in Texas. In 2004, Royale Energy began developing leases in Utah. The most significant factors affecting the results of operations are (i) changes in the sales price of natural gas, (ii) recording of turnkey drilling revenues and the associated drilling expense, and (iii) the change in natural gas 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, 2005 and 2004, Royale Energy had deferred drilling revenue of $6,490,111 and $5,279,417, respectively.
The second business segment is oil and gas production. Northern California accounts for 78% 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 delay and 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.
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.
Changes in Accounting Principles
Asset Retirement Obligations
In June 2001, the FASB approved for issuance SFAS 143, "Asset Retirement Obligations." SFAS 143 establishes accounting requirements for retirement obligations associated with tangible long-lived assets such as wells and production facilities. See, Note 4 to our Financial Statements - Summary of Significant Accounting Policies - Recently Issued Accounting Pronouncements. Royale Energy adopted the statement as of January 1, 2003. The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment to record a $157,185 increase in the carrying values of proved properties and a $188,007 increase in noncurrent abandonment liabilities. The net impact of these items was to record $41,301, net of tax, as a cumulative effect adjustment of a change in accounting principle in our Statement of Income for 2003.
Suspended Well Costs
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 performed an evaluation of our capitalized costs and determined that no previously capitalized exploratory well costs pending the determination of proved reserves were required to be expensed or reclassified during the third quarter of 2005 or 2004. We did not make any additions to capitalized exploratory well costs pending a determination of proved reserves during 2005 or 2004. We did not charge any previously capitalized exploratory well costs to expense upon adoption of FSP FAS 19-1. At December 31, 2005 and 2004, no capitalized well costs had been capitalized for more than one year.
Results of Operations for the Twelve Months Ended December 31, 2005, as Compared to the Twelve Months Ended December 31, 2004
For the year ended December 31, 2005, we had a net profit of $1,185,903, a $1,006,849 or 45.9% decrease compared to the net profit of $2,192,752 achieved during 2004. We attribute this to higher lease impairment costs and intensifying marketing efforts. Total revenues for the year in 2005 were $25,643,378, a decrease of $300,978 or 1.2% from the total revenues of
$25,944,356 in 2004. This was mainly due to lower cost recovery fees due to decreased production.
In 2005, revenues from oil and gas production increased by 3.1% to $11,228,537 from
$10,892,574, due to increased natural gas and oil prices. The net sales volume of natural gas for the year ended December 31, 2005, was approximately 1,384,860 Mcf with an average price of $7.48 per Mcf, versus 1,870,250 Mcf with an average price of $5.43 per Mcf for 2004. This represents a decrease in net sales volume of 485,390 Mcf or 26%. This decrease in production was a result of several factors including the natural decline on our oil and gas wells and the lack of new production because of a delay in starting our drilling projects due to limited drilling rig availability in California. The net sales volume for oil and condensate (natural gas liquids) production was 16,558 barrels with an average price of $51.95 per barrel for the year ended December 31, 2005, compared to 20,017 barrels at an average price of $36.66 per barrel for the year in 2004. This represents a decrease in net sales volume of 3,459 barrels, or 17.3%.
Oil and gas lease operating expenses decreased by $66,007, or 2.3%, to $2,751,441 for the year ended December 31, 2005, from $2,817,448 for the year in 2004. The decrease was due to a decrease in the number of operated wells. When measuring lease operating costs on a production or lifting cost basis, in 2005, the $2,751,441 equates to a $1.77 per mcfe lifting cost versus a $1.36 per mcfe lifting cost in 2004, a 30.1% increase.
For the year ended December 31, 2005, turnkey drilling revenues decreased $203,196 to $13,066,800 in 2005 from $13,269,996 in 2004, or 1.5%. We also had a $39,090 or 0.5% decrease in turnkey drilling and development costs to $8,111,248 in 2005 from $8,150,338 in 2004. The decrease in turnkey drilling revenues was mainly due to a decrease in direct working interest sales during the year in 2005 when compared to the year in 2004. The decrease in drilling and development costs was due to lower cost wells drilled in 2005 when compared to 2004. We drilled six exploratory wells and nine developmental in 2005 versus ten exploratory wells and four developmental wells in 2004. 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 37.9% and 38.6% for the years ended December 31, 2005 and 2004, 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 $742,642 and $51,414 were recorded in 2005 and 2004, respectively. We periodically review for impairment 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 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.
The aggregate of supervisory fees and other income was $1,348,041 for the year ended December 31, 2005, a decrease of $433,745 (24.3%) from $1,781,786 during the year in 2004. This was due to a decrease in cost recovery received for use of facilities constructed and placed into service during prior periods due to lower production. 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 increased $6,009 or 1.2%, to $493,415 in 2005 from $487,406 in 2004.
Depreciation, depletion and amortization expense increased to $4,062,587 from $3,714,271, an increase of $348,316 (9.4%) for the year ended December 31, 2005, as compared to the same period in 2004. The depletion rate is calculated using production as a percentage of reserves. This increase in depletion expense was mainly due to an increase in the depletion rate because of higher rates of production when compared to total reserves and in the number of oil and gas assets that we own.
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, $381,790 of previously capitalized costs were written off and recorded as geological and geophysical expense during 2005 compared with $321,983 written off in 2004, a $59,807 or 18.6% increase.
General and administrative expenses decreased by $166,852 or 3.2%, from $5,205,190 for the year ended December 31, 2004 to $5,038,338 for the year in 2005. This decrease was mainly due to the decrease in the allowance for bad debts of $239,388, from $641,079 in 2004 to $401,691 in 2005, for receivables from direct working interest investors whose expenses on non-producing wells was unlikely to be collected. Legal and accounting expense decreased to $236,199 for the period, compared to $627,038 for year 2004, a $390,839 or 62.3% decrease. These decreases were due to lower audit, tax preparation and legal fees during the year in 2005. Marketing expense for the year ended December 31, 2005 increased $776,880, or 60.5%, to $2,061,689, compared to $1,284,809 for the year in 2004. Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs. In 2005 we also increased the use of outside brokers to increase direct working interest sales.
During the period in 2005, we increased long-term debt under our commercial bank credit line. The interest rate charged to the company also increased from 6.0% at December 31, 2004, to 7.75% at December 31, 2005. This increased interest expense to $444,271 for the year ended December 31, 2005, from $273,050 for the same period in 2004, a $171,221, or 62.7% increase.
In 2005 our income tax expense decreased to $627,270 from $1,306,063 in 2004, a $678,793 or 52% decrease, mainly due to the decrease in our net income. For the periods in 2004 and 2005,
this represents an effective tax rate of approximately 37.3% and 34.6%, respectively. 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, 2004, as Compared to the Twelve Months Ended December 31, 2003
For the year ended December 31, 2004, we had a net profit of $2,192,752, a $2,208,168 or 50.2% decrease compared to the net profit of $4,400,920 achieved during 2003. We attribute this to several factors, including increased depletion rates, intensifying marketing efforts, the drilling of deeper oil and natural gas wells and the blowout of the Bowerbank Sam #2 well during the year in 2004.
Total revenues for the year in 2004 were $25,944,356, an increase of $2,679,219 or 11.5% from the total revenues of $23,265,137 in 2003.
In 2004, revenues from oil and gas production increased by 7.6% to $10,892,574 from $10,120,148, due to increased natural gas and oil prices. The net sales volume of natural gas for the year ended December 31, 2004, was approximately 1,870,250 Mcf with an average price of $5.43 per Mcf, versus 1,944,779 Mcf with an average price of $4.86 per Mcf for 2003. This represents a decrease in net sales volume of 74,529 Mcf or 3.8%. The net sales volume for oil and condensate (natural gas liquids) production was 20,017 barrels with an average price of $36.66 per barrel for the year ended December 31, 2004, compared to 23,411 barrels at an average price of $28.00 per barrel for the year in 2003. This represents a decrease in net sales volume of 3,394 barrels, or 14.5%.
During the second quarter of 2004, we suffered a blowout of our Bowerbank Sam #2 well during recompletion operations. This is the first blowout to occur on a well operated by us in more than 18 years of operation. Mainly because of the blowout, oil and gas lease operating expenses increased by $1,103,066, or 64.3%, to $2,817,448 for the year ended December 31, 2004, from $1,714,382 for the year in 2003. The increase was also due to the plugging and abandoning of non-producing wells in addition to an increase in workover costs during the year in 2004 when compared to 2003. When measuring lease operating costs on a production or lifting cost basis, in 2004, the $2,817,448 equates to a $1.36 per mcfe lifting cost versus a $0.79 per mcfe lifting cost in 2003, a 73.0% increase. Lifting cost excluding the extraordinary items of the blowout and plugging, was $1.21 per Mcfe. For 2004, our gross margin, or profit, on oil and gas production (excluding drilling and development costs) was 74.1%, compared to 83.1% in 2003.
For the year ended December 31, 2004, turnkey drilling revenues increased $1,303,136, to $13,269,996 in 2004 from $11,966,860 in 2003, or 10.9%. We also had a $2,294,677 or 39.2% increase in turnkey drilling and development costs to $8,150,338 in 2004 from $5,855,661 in 2003. The increase in turnkey drilling revenues was mainly due to an increase in direct working interest sales during the year in 2004 when compared to the year in 2003. The increase in drilling and development costs was due to higher drilling and completion costs of wells drilled in 2004 when compared to 2003 due to the drilling of ten exploratory wells and four developmental in 2004 versus three exploratory wells and fourteen developmental wells in 2003. 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 38.6% and 51.1% for the years ended December 31, 2004 and 2003, 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 $51,414 and $869,991 were recorded in 2004 and 2003, respectively. We periodically review for impairment 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 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.
The aggregate of supervisory fees and other income was $1,781,786 for the year ended December 31, 2004, an increase of $603,657 (51.2%) from $1,178,129 during the year in 2003. This was due to an increase in cost recovery received for new facilities constructed and placed into service during the period in 2004, combined with a gain on sale of a non-oil and gas asset in 2004 and the loss on sale of some of our oil and gas assets during the first quarter in 2003. 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 increased $53,753 or 12.4%, to $487,406 in 2004 from $433,653 in 2003.
Depreciation, depletion and amortization expense increased to $3,714,271 from $2,418,922, an increase of $1,295,349 (53.6%) for the year ended December 31, 2004, as compared to the same period in 2003. The depletion rate is calculated using production as a percentage of reserves. This increase in depletion expense was mainly due to an increase in the depletion rate because of higher rates of production when compared to total reserves and in the number of oil and gas assets that we own.
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, $321,983 of previously capitalized costs were written off and recorded as geological and geophysical expense during 2004 compared with $209,622 written off in 2003, a $112,361 or 53.6% increase.
General and administrative expenses increased by $1,211,522 or 30.3%, from $3,993,668 for the year ended December 31, 2003 to $5,205,190 for the year in 2004. This increase was partially due to an allowance for bad debts of approximately $641,000 for receivables from direct working interest investors whose expenses on non-producing wells was unlikely to be collected. We also had increased employee salaries and related expenses, taxes and insurance, due to increased staffing. There were also increases in rents and related costs due to the opening of two new field offices and expansion in our home office space.
Legal and accounting expense increased to $627,038 for the period, compared to $544,302 for year 2003, an $82,736 or 15.2% increase. These increases were due to higher audit, tax preparation and legal fees during the year in 2004.
Marketing expense for the year ended December 31, 2004 increased $480,443, or 59.7%, to $1,284,809, compared to $804,366 for the year in 2003. Marketing expense varies from period to period according to the number of marketing events attended by personnel and their associated costs.
During the period in 2004, we increased long term debt under our commercial bank credit line and obtained a new term loan on non-oil and gas real estate we own, which increased interest expense to $273,050 for the year ended December 31, 2004, from $194,997 for the same period in 2003, a $78,053, or 40.0% increase. The interest rate charged to the company also increased during 2004, from 4.75% at December 31, 2003, to 6.0% at December 31, 2004.
In 2004 our income tax expense decreased to $1,306,063 from $2,217,005 in 2003, a $910,942 or 41.1% decrease, mainly due to the decrease in our net income. For the periods in 2003 and 2004, this represents an effective tax rate of approximately 33.5% and 37.3%, respectively. 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%).
As mentioned earlier, in 2003 we adopted SFAS 143 for Asset Retirement Obligations, which resulted in a $41,301, net of tax, cumulative effect adjustment of a change in accounting principle in 2003. There were no adjustments for changes in accounting principle in during 2004 or 2005.
Capital Resources and Liquidity
At December 31, 2005, Royale Energy had current assets totaling $11,814,984 and current liabilities totaling $13,956,018, a $2,141,034 working capital deficit. We had cash and cash equivalents at December 31, 2005 of $4,716,772 compared to $7,627,045 at December 31, 2004.
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. During the fourth quarter of each year, we receive a large percentage of the revenue generated by our sales of working interests to third parties, as individual high net worth investors make investments according to their own year-end financial planning. We also incur a large percentage of our costs for drilling activities in the third and fourth quarters of each year. We believe that we have sufficient liquidity for 2006 and do not foresee any liquidity demands that cannot be met from cash flow from operations.
At the end of 2005, our accounts receivable totaled $4,221,601 compared to $3,903,941 at December 31, 2004, a $317,660 (8%) increase, mainly due to increased revenue receivables due to higher natural gas prices at the end of 2005 as compared to 2004. At December 31, 2005, our accounts payable and accrued expenses totaled $7,375,161, a decrease of $2,252,905 or 23.3% over the accounts payable at the end of 2004 of $9,628,066. This was primarily due to the decrease in trade accounts payable due to fewer wells drilled at the end of 2005 when compared to 2004.
Occasionally we borrow from banks, using our oil and gas properties as security. In 2005, we drew $927,500 from our credit line to meet our drilling schedule. During the year ended December 31, 2004, we drew approximately $1,082,500 net, from our credit line in order to purchase new oil and gas assets.
We have 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, 2005, we had outstanding indebtedness of $6,400,000. Unused available credit from this revolving line of credit totaled approximately $555,974 at December 31, 2005. At December 31, 2004, we had outstanding indebtedness under this agreement of $5,472,500. The loan agreement also contains certain restrictive covenants, including the prohibition of payment of dividends on our stock (other than dividends paid in stock). The loan agreement contained covenants that, among other things, we must:
-
Maintain a minimum ratio of earnings before interest, taxes, depreciation and amortization to debt service requirements of at least 1.25 to 1.00;
-
Maintain a ratio of bank determined current assets to bank determined current liabilities of at least 1.00 to 1.00; and
-
Maintain a tangible net worth as of the close of each fiscal quarter of at least $8,188,000 as of September 30, 2002, plus 50% of positive quarterly net income thereafter.
At December 31, 2005, Royale Energy was in compliance with its loan covenants.
During 2004 we obtained a new loan from Guaranty Bank, FSB for $1,000,000, which is secured by our non-oil and gas real estate assets, which was primarily used to fund operations. In 2005,
portion of the real estate was subsequently sold during the year resulting in an additional $175,000 principal payment. At December 31, 2005, we had outstanding indebtedness of $321,344 on this loan.
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, 2005, and the effect such obligations are expected to have on our liquidity and cash flow in future periods.
Total
Obligations
2007-2008
2009-2010
Beyond
Office lease
$ 3,645,593
$333,839
$ 698,023
$ 740,533
$1,873,198
Long-term debt
6,721,344
90,746
6,630,598
-
-
Total
$10,366,937
$424,585
$7,328,621
$740,533
$1,873,198
Operating Activities. For the year ended December 31, 2005, cash provided by operating activities totaled $6,395,442 compared to $8,018,300 provided by operating activities for the same period in 2004, a $1,622,858 or 20.2% decrease, mainly due to decreases in net revenues from operations. Cash provided by operating activities for 2004 decreased $1,866,800 or 18.9% as compared to $9,885,100 for the year ended December 31, 2003 mainly due to decreases in net revenues from operations.
Investing Activities. Net cash used by investing activities, primarily in capital acquisitions of oil and gas properties, amounted to $9,888,809 for the year in 2005, compared to $6,640,103 used by investing activities for the same period in 2004. This increase in cash used was primarily due to the increased number of wells drilled, nine developmental and six exploratory in 2005 and four developmental and 10 exploratory in 2004. Net cashed used by investing activities in 2004 decreased $4,375,941 or 39.7% from $11,016,044 for the year ended December 31, 2003 primarily due to fewer wells drilled in 2004 as compared with 14 developmental and three exploratory in 2003.
Financing Activities. For the year ended December 31, 2005 cash provided by financing activities was $583,094 compared to $1,371,230 provided by financing activities for the same period in 2004. This difference in cash provided was primarily due to decreases in borrowings during 2005 when compared to 2004. Cash provided by financing activities decreased $2,407,388 or 63.7% from $3,778,618 for the year ended December 31, 2003 primarily due to decreases in borrowings in 2004 when compared with 2003.
Changes in Reserve Estimates
In 2005, our estimated proved developed and undeveloped reserve quantities were revised downward by approximately 2.1 million cubic feet of natural gas 200,000 barrels of oil. See, Supplemental Information about Oil and Gas Producing Activities (Unaudited), page. During 2005, three producing wells ceased producing, resulting in a reduction in proved developed reserves. Also during 2005, one prospect that had been previously estimated to
contain proved undeveloped gas reserve was drilled and resulted in a dry hole, and two other prospects 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 93% of the net downward revisions of previous gas reserve estimates.
The reduction in oil reserve estimates in 2005 was mainly due to re-evaluation of one oil/condensate well, which was drilled at the end of 2004 and began production in 2005. Based on its production experience, oil reserves for that well were reduced by 161,409 barrels, which equals 80% of net oil reserve reductions in 2005.
The following table summarizes the major reasons for reserve reductions in 2005.
Oil
Gas
Two existing wells which ceased production
(738,212)
Reduction of PUD due to one dry hole
(461,000)
Reduction of PUD based on drilling results
(161,409)
(781,293)
Total
(161,409)
(1,980,505)
In 2004, the cessation of production from one well and significant downward revision of a second well accounted for downward revisions of more than 1.14 million cubic feet of proved developed reserves, which is 77% of the net revisions in 2004. Both wells had been producing gas wells. The reserve estimate for one well was revised downward by 622,928 cubic feet to 0, and the reserve estimate of the second well was revised downward by 521,714 cubic feet to 182,000 cubic feet.
Item 7A
Item 7A Qualitative and Quantitative Disclosures About Market Risk
Royale Energy is exposed to market risk from changes in commodity prices and in interest rates. In 2005, we sold a majority of our natural gas at the daily market rate through the Pacific Gas & Electric pipeline. In 2005, our natural gas revenues were approximately $10.4 million with an average price of $7.48 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 $1.04 million. 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 $90,000. 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 $60,000 to $120,000, respectively, to our interest expense.
Item 8
Item 8 Financial Statements
See pages, et seq., included herein.
Item 9A
Item 9A Controls and Procedures
Disclosure controls are controls and other procedures that are designed to ensure that information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. Our disclosure controls and procedures are designed to insure that the information required to be filed is accumulated and communicated to our management in a manner designed to enable them to make timely decisions regarding required disclosure.
Our chief executive officer, Donald H. Hosmer, and chief financial officer, Stephen M. Hosmer, evaluated the effectiveness or our disclosure controls and procedures as of the end of the 2005 fiscal year. Based on their evaluation, they concluded that our disclosure controls are effective in providing reasonable assurance that material information relating to our company is made known to management on a timely basis during the period when our periodic reports are being prepared.
No changes in our internal control over financial reporting occurred during the last fiscal quarter of 2005 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Our management, including our CEO and CFO, does not expect that our disclosure controls or internal controls over financial reporting will prevent all error or fraud. A control system, no matter how well conceived and operated, can provide only reasonable, but not absolute, assurance that the objectives of a control system are met. Any control system contains limitations imposed by resources and relevant cost considerations. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues have teen addressed. These inherent limitations include the realities that judgments can be faulty and that breakdowns can occur because of simple error or mistake. In addition, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of a control. Our control system design is also based on assumptions about the likelihood of future events, and we cannot be sure that we have considered all possible future circumstances and events.
PART III
Item 10
Item 10 Directors and Executive Officers of the Registrant
The following table contains certain information about Royale Energy's current directors and executive officers. Directors are elected by stockholders at each annual stockholders' meeting and serve until their successors are elected and qualified. Officers serve at the discretion of the board of directors.
Name
Age
First Became
Director or
Executive
Officer
Positions Held
Harry E. Hosmer
Chairman of the Board
Donald H. Hosmer
President, Secretary and Director
Stephen M. Hosmer
Executive Vice President, Chief Financial Officer and Director
Oscar A. Hildebrandt*+
Director
Rodney Nahama +
Director
Gilbert Kemp*+
Director
George M. Watters*
Director
* Member of the audit committee
+ Member of the compensation committee
A majority of the members of the board of directors may be considered independent directors under Nasdaq rules (including Messrs. Hildebrandt, Nahama, Kemp and Watters). The board of directors has determined that Dr. Oscar Hildebrandt and George Watters are "audit committee financial experts" as defined in Item 401 of Securities and Exchange Commission Regulation
S-K.
Following is a summary of the business experience of each director and executive officer for the past five years.
HARRY E. HOSMER is the Chairman of the Board of Royale Energy. He has served as Chairman since Royale Energy began in 1986, and from inception in 1986 until June 1995, he also served as President and Chief Executive Officer. Mr. Hosmer and his sons founded Royale Energy.
DONALD H. HOSMER is President, Chief Executive Officer, Secretary, and Director of Royale Energy. He has served as an executive officer and Director of Royale Energy since its inception in 1987, and in June 1995 he became President and Chief Executive Officer. Prior to becoming President, he was Executive Vice President, responsible for marketing working interests in oil
and gas projects developed by Royale Energy. He was also responsible for investor relations and communications. Donald H. Hosmer is the son of Harry E. Hosmer and brother of Stephen M. Hosmer.
STEPHEN M. HOSMER is Executive Vice President, Chief Financial Officer and Director of Royale Energy. Mr. Hosmer joined Royale Energy as the Management Information Systems Manager in May 1988, responsible for developing and maintaining Royale Energy's computer software. Mr. Hosmer developed programs and software systems used by Royale Energy. From 1991 to 1995, he served as president of Royale Operating Company, Royale Energy's operating subsidiary. In 1995, he became Chief Financial Officer of Royale Energy. In 1996, he was elected to the board of directors of Royale Energy. Stephen M. Hosmer is the son of Harry E. Hosmer and brother of Donald H. Hosmer. He has a B.S. degree from Oral Roberts University
in Business Administration and a Master of Business Administration from Pepperdine University.
OSCAR HILDEBRANDT, D.V.M., is a Director and is Chairman of Royale Energy's Compensation and Audit Committees. From 1994 to 1995 he served as an advisory member of Royale Energy's Board of Directors. Dr. Hildebrandt practiced veterinary medicine as President of Medford Veterinary Clinic, Medford, Wisconsin, from 1960 to 1990. Since 1990, Dr. Hildebrandt has engaged independently in veterinary practice consulting services. He has served on the board of directors of Fidelity National Bank - Medford, Wisconsin, and its predecessor bank from 1965 to the present and is past chairman of the board of the Bank. From 1990 to the present he has acted as a financial advisor engaged in private business interests. Dr. Hildebrandt received a Bachelor of Science degree from the University of Wisconsin in 1954 and a Doctor of Veterinary Medicine degree from the University of Minnesota in 1958.
GILBERT C. L. KEMP has since 2002 served as an independent consultant for seismic operations in the oil and gas industry. He managed the California operations of Western Atlas, Inc., a New York Stock Exchange company from 1998 until 2002. Mr. Kemp was a founding member of 3-D Geophysical, Inc., where he served as Vice President from 1996 until March 1998. In March 1998 3-D Geophysical, whose stock had been listed on the Nasdaq National Market System since February 1996, merged with Western Atlas, Inc. During the years 1987 to 1995, Mr. Kemp served as President and CEO of Kemp Geophysical Corporation, which owned and operated seismic crews in the United States and Canada.
RODNEY NAHAMA, a Director of Royale Energy, was employed as president and chief executive officer of Nahama & Weagant Energy Co. from 1971 until March 1994. Since March 1994, Mr. Nahama has pursued private business interests, including the provision of geologic consulting services to Royale Energy. Mr. Nahama holds a B.A. degree in geology from the University of California, Los Angeles, and an M.A. degree in geology from the University of Southern California. He was an independent exploration geologist from 1965 to 1971 and prior to that served as a geologist with Franco Western Oil Company from 1963 to 1965. Between 1957 and 1963, Mr. Nahama worked as an exploration geologist with Honolulu Oil Company, Getty Oil Company, and Sunray Oil Company. Mr. Nahama is a member of the American Association of Petroleum Geologists, the San Joaquin Geological Society, the California Independent Petroleum Association and the Independent Petroleum Association of America.
GEORGE M. WATTERS has been retired from full time employment during the last five years. Mr. Watters retired from AMOCO Corporation in 1983 after serving for 24 years in senior management positions with AMOCO Corporation and its affiliates. From 1987 to the present Mr. Watters has managed his personal investments. Mr. Watters received his B.S. degree from Massachusetts Institute of Technology in 1942.
Compliance with Section 16(a) of the Securities Exchange Act
Section 16(a) of the Securities Exchange Act of 1934 and Securities and Exchange Commission regulations require that Royale Energy's directors, certain officers, and greater than 10 percent stockholders file reports of ownership and changes in ownership with the SEC and the NASD and furnish Royale Energy with copies of all such reports they file.
In 2005, director Oscar A. Hildebrandt filed a late report of exercise of options to purchase a total of 39,228 shares of Royale Energy's common stock on four occasions in February, April, and June 2005. Based solely upon a review of the copies of the forms furnished to Royale Energy, or representations from certain reporting persons that no reports were required, Royale Energy believes that no other persons failed to file required reports on a timely basis during or in respect of 2005.
Item 11
Item 11 Executive Compensation
The following table summarizes the compensation of the chief executive officer and the other most highly compensated executive officers (the "named executive officers") of Royale Energy and its subsidiaries during the past year.
All Other Compensation: Consists of Royale Energy's matching contribution to the company's simple IRA plan on behalf of the listed executives.
Royale Energy does not have employment agreements with any of its executives.
No Stock Options Were Granted in 2005
We did not grant any stock options, stock appreciation rights or Long-Term Incentive Plan Awards to our named executive officers during 2005.
Aggregate 2005 Option Exercises and Year End Values
The following table summarizes number and value of shares of stock options exercised by the named executive officers in 2005 and the number and value of all unexercised stock options held by those executive officers at the end of 2005.
Shares
acquired
on exercise
Value
realized
Number of
securities
underlying
unexercised
options/SARS
at 12/31/05
exercisable/
unexercisable
Value of
unexercised in-
the-money
options/SARS
at 12/31/05
exercisable/
unexercisable
Stephen M. Hosmer
19,615
$188,912
-
-
Oscar Hildebrandt
39,228
$285,283
-
-
George Watters
58,843
$311,534
-
-
Compensation Committee Report
Our executive compensation policy is designed to motivate, reward and retain the key executive talent necessary to achieve our business objectives and contribute to our long-term success. Our compensation policy for our executive officers focuses primarily on determining appropriate salary levels and performance-based cash bonuses.
Policy
The compensation committee's primary responsibility is making recommendations to the board of directors relating to compensation of our officers. The committee also makes recommendations to the board of directors regarding employee benefits, our defined benefit plans, defined contribution plans, and stock based plans.
Determination
To determine executive compensation, the committee, in December each year, meets with our
officers to review our compensation programs, discuss the performance of the company, the duties and responsibilities of each of the officers pay levels and business results compared to others similarly situated within the industry. The committee the makes recommendations to the board of directors for any adjustment to the officers compensation levels.
Compensation Elements
Base. Base salaries for our executive officers are established based on the scope of their responsibilities, taking into account competitive market compensation paid by our peers. Base salaries are reviewed annually. The salaries we paid to our most highly paid executive officers for the last three years are set forth in the Summary Compensation Table included under Executive Compensation.
Bonus. The compensation committee meets annually to determine the quantity, if any, of the cash bonuses of executive officers. The amount granted is based, subjectively, upon the company's stock price performance, earnings, revenue, reserves and production. The committee does not use quantifiable metrics for these criteria; but rather uses each in balance to assess the
strength of the company's performance. The committee believes that formulaic approaches to cash incentives can foster an unhealthy balance between short-term and long-term goals. In 2005, the compensation committee did not award bonuses to any of the company's executive officers.
Members of the Compensation Committee:
Oscar A. Hildebrandt, Chair
Rodney Nahama
Gilbert Kemp
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, 2000, with the cumulative total return of the Standard & Poor's Composite 500 Stock Index and the Dow Jones U.S. Exploration and Production Index (formerly Dow Jones Secondary Oils Stock Index) from December 31, 2000 through December 31, 2005.
The Royale Energy performance figures assume retention of stock dividends in 2001, 2002, 2003 and 2004 and a stock split in 2004.
Royale Energy, Inc.
S & P Composite 500 Stock Index
DJ US Exploration and Production Index
Compensation of Directors
Each director who is not an employee of Royale Energy receives a quarterly fee for his services,
which in 2005 was set at $3,025. In addition, Royale Energy reimburses directors for the expenses they incur for their service. No directors received any stock options or stock appreciation rights in 2005.
Item 12
Item 12 Security Ownership of Certain Beneficial Owners and Management
The following tables set forth certain information regarding the ownership of Royale Energy's voting securities as of December 31, 2005, by: (i) each person Royale Energy knows to own beneficially more than 5% of the outstanding shares of each class of equity securities, (ii) each of Royale Energy's directors, and (iii) all of Royale Energy's directors and officers as a group. Except pursuant to applicable community property laws and except as otherwise indicated, each stockholder identified in the table possesses sole voting and investment power with respect to its or his shares.
Common Stock
On December 31, 2005, 7,934,736 shares of our common stock were outstanding.
The following table sets forth share ownership information for our officers, directors, and holders of more than 5% of our equity securities as of December 31, 2005. None of our officers, directors or 5% stockholders own options or other rights to acquire our common stock within 60 days of December 31, 2005.
Stockholder (1)
Number
Percent
Donald H. Hosmer (2)
1,016,437
12.81%
Harry E. Hosmer (2)
778,797
9.82%
Oscar A. Hildebrandt
75,735
Less than 1%
Stephen M. Hosmer (2)
1,221,561
15.40%
Gilbert C. L. Kemp
16,962
Less than 1%
Rodney Nahama
-
-
George M. Watters
58,841
Less than 1%
All officers and directors as a group
3,168,333
39.93%
(1) The mailing address of each listed stockholder is 7676 Hazard Center Drive, Suite 1500, San Diego, California 92108.
(2) Donald H. Hosmer and Stephen M. Hosmer are sons of Harry E. Hosmer, Chairman of the Board.
Preferred Stock
Holders of each series of Convertible Preferred Stock have voting rights equal to the number of shares into which they are convertible. On December 31, 2005, there were 6,122 shares of Series A and 57,416 shares of Series AA Convertible Preferred Stock outstanding. The shares of each series of Preferred shares are convertible into shares of Royale Energy's Common Stock at the option of the security holder, at the rate of two shares of Convertible Preferred Stock for each share of Common Stock. The Preferred Stock is not registered under the Securities Exchange Act of 1934, and no market exists for the Preferred Stock. The total number of shares of Common Stock issuable on conversion of all outstanding shares of Preferred Stock equals less than 1% of the outstanding Common Stock of Royale Energy. To Royale Energy's knowledge,
none of the Preferred stockholders would own more than 1% of Royale Energy's Common Stock, if their Preferred shares were converted to Common shares.
Item 13
Item 13 Certain Relationships and Related Transactions
In 1989, the board of directors adopted a policy (the "1989 policy") that permits each director and officer of Royale Energy to purchase from Royale Energy, at its cost, up to one percent (1%) fractional interest in any well to be drilled by Royale Energy. When an officer or director elects to make such a purchase, the amount charged per each percentage working interest is equal to Royale Energy's actual pro rata cost of drilling and completion, rather than the higher amount that Royale Energy charges to working interest holders for the purchase of a percentage working interest in a well. Of the current officers and directors, Donald Hosmer, Stephen Hosmer, Harry E. Hosmer, George Watters and Oscar Hildebrandt at various times have elected under the 1989 policy to purchase interests in certain wells Royale Energy has drilled.
Under the 1989 policy, officers and directors may elect to participate in wells at any time up until drilling of the prospect begins. Participants are required to pay all direct costs and expenses through completion of a well, whether or not the well drilling and completion expenses exceed Royale Energy's cost estimates, instead of paying a set, turnkey price (as do outside investors who purchase undivided working interests from Royale Energy). Thus, they participate on terms similar to other oil and gas industry participants or joint venturers. Participants are invoiced in advance for their share of estimated direct costs of drilling and completion and later actual costs are reconciled, as Royale Energy incurs expenses and participants make further payments as necessary.
Officer and director participants under this program do not pay some expenses paid by outside, retail investors in working interests, such as sales commissions, if any, or marketing expenses. The outside, turnkey drilling agreement investors, on the other hand, are not obligated to pay additional costs if a drilling project experiences cost overruns or unanticipated expenses in the
drilling and completion stage. Accordingly, Royale Energy's management believes that its officers and directors who participate in wells under the Board of Directors' policy do so on terms the same as could be obtained by unaffiliated oil and gas industry participants in arms-length transactions, albeit those terms are different than the turnkey agreement under which outside investors purchase fractional undivided working interests from Royale Energy.
Donald and Stephen Hosmer each have participated individually in 128 and 129 wells respectively under the 1989 policy. The Hosmer Trust, a trust for the benefit of family members of Harry E. Hosmer, has participated in 128 wells.
Investments in wells under the 1989 policy for the three years ended December 31, 2005, 2004, and 2003 are as follows:
Year
# of
fractional
interests
Amount
Don Hosmer
$104,441
$137,716
$101,291
Stephen Hosmer
$112,020
$132,878
$86,362
Hosmer Trust
$109,413
$138,492
$86,362
Current officers and directors were billed $130,473, $196,323, and $305,489 for their interests for the three years ended December 31, 2005, 2004, and 2003 respectively.
Royale Energy's Chairman of the Board and former President, Harry E. Hosmer, renders management consulting services to Royale Energy on an ongoing basis. Royale Energy compensated Mr. Hosmer $151,437, $138,600, and 126,000 for his consulting services in 2005, 2004, and 2003 respectively, and pays his medical insurance costs. Mr. Hosmer's consulting services are in conjunction with his service on the board of directors, for which he receives reimbursement of expenses to attend meetings.
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.
Item 14
Item 14 Principal Accountant Fees and Services
During 2004 Sprouse & Anderson, LLP became our independent accountants. The aggregate fees billed by them for the years ended December 31, 2005 and 2004 are as follows:
Audit fees (1)
$86,903
$ 19,855
Audit-related fees (2)
-
-
Tax fees (3)
-
-
All other fees (4)
-
-
Total
$86,903
$ 19,855
The following table sets forth the aggregate fees billed by our previous independent accountants, Brown Armstrong Paulden McCown Starbuck & Keeter Accountancy Corporation, for the year ended December 31, 2004.
Audit fees (1)
$ 53,214
Audit-related fees (2)
22,292
Tax fees (3)
7,577
All other fees (4)
10,372
Total
$ 93,455
During 2004, UHY Mann, Frankfort, Stein & Lipp Advisors became our independent tax consultants. For the years ended December 31, 2005 and 2004, $68,280 and $72,871 were billed, respectively.
(1) Audit fees are fees for professional services rendered for the audit of Royale Energy's annual financial statements, reviews of financial statements included in the company's Forms 10-Q, and reviews of documents filed with the U.S. Securities and Exchange Commission.
(2) Audit related fees consist of fees for services reasonably related to performance of the audit or review of Royale Energy's financial statements. For 2005 and 2004, these services include quarterly reviews of financial information.
(3) Tax fees consist of tax planning, consulting and tax return reviews.
(4) Other fees consist of work on registration statements under the Securities Act of 1933.
The audit committee of Royale Energy has adopted policies for the pre-approval of all audit and non-audit services provided by the company's independent auditor. The policy requires pre-approval by the audit committee of specifically defined audit and non-audit services. Unless the specific service has been previously pre-approved with respect to that year, the audit committee must approve the permitted service before the independent auditor is engaged to perform it.
Item 15
Item 15 Exhibits and Financial Statement Schedules
Financial Statements
1. Financial Statements. See Index to Financial Statements, page
2. Schedules. Supplemental Information About Oil and Gas Producing Activities (Unaudited) begins on page.
3. Exhibits
Certain of the exhibits listed in the following index are incorporated by reference.
3.1
Restated Articles of Incorporation of Royale Energy, Inc., incorporated by reference to Exhibit 3.1 of Royale Energy's Form 10-SB Registration Statement.
3.2
Certificate of Amendment to the Articles of Incorporation of Royale Energy, Inc. (effecting reverse stock split and defining certain rights of equity security holders), incorporated by reference to Exhibit 3.1 of Royale Energy's Form 8-K dated October 31, 1994.
3.3
Bylaws of Royale Energy, Inc., incorporated by reference to Exhibit 3.2 of Royale Energy's Form 10-SB Registration Statement.
4.1
Certificate of Determination of the Series A Convertible Preferred Stock, incorporated by reference to Exhibit 4.1 of Royale Energy's Form 10-SB Registration Statement.
4.2
Certificate of Determination of the Series AA Convertible Preferred Stock, incorporated by reference to Exhibit 4.2 of Royale Energy's Form 10-SB Registration Statement.
10.1
Form of Indemnification Agreement, incorporated by reference to Exhibit 10.3 of Royale Energy's Form 10-SB Registration Statement.
31.1
Rules 13a-14(a), 115d-14(a) Certification, attached.
31.2
Rules 13a-14(a), 115d-14(a) Certification, attached.
32.1
Section 1350 Certification, attached.
32.2
Section 1350 Certification, attached.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Royale Energy, Inc.
Date:
April 12, 2006
/s/ Donald H. Hosmer
Donald H. Hosmer
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Date:
April 12, 2006
/s/ Harry E. Hosmer
Harry E. Hosmer
Chairman of the Board of Directors
Date:
April 12, 2006
/s/ Donald H. Hosmer
Donald H. Hosmer
Director, President, Chief Executive Officer and Secretary
Date:
April 12, 2006
/s/ Stephen M. Hosmer
Stephen M. Hosmer
Director, Executive Vice President and Chief Financial Officer
Date:
April 12, 2006
/s/ Oscar A. Hildebrandt
Oscar A. Hildebrandt
Director
Date:
April 12, 2006
/s/ Rodney Nahama
Rodney Nahama
Director
Date:
April 12, 2006
/s/ Gilbert C.L. Kemp
Gilbert C.L. Kemp
Director
Date:
April 12, 2006
/s/ George M. Watters
George M. Watters
Director
ROYALE ENERGY, INC.
AND SUPPLEMENTARY DATA
Report of Sprouse & Anderson, LLP, Independent Auditors
Report of Brown Armstrong Paulden McCown Starbuck & Keeter
Balance Sheets at December 31, 2005 and 2004
Statements of Operations for the Years Ended December 31, 2005, 2004, and 2003
Statements of Stockholders' Equity for the Years Ended December 31, 2005, 2004, and 2003
Statements of Cash Flows for the Years Ended December 31, 2005, 2004, and 2003
Notes to the Financial Statements
Supplemental Information About Oil and Gas Producing Activities (Unaudited)
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.
INDEPENDENT AUDITORS' REPORT
The Board of Directors
Royale Energy, Inc.:
We have audited the accompanying balance sheets of Royale Energy, Inc. (a California corporation) as of December 31, 2005 and 2004, and the related statements of operations, stockholders' equity and cash flows for the years then ended . These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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, 2005 and 2004, and the results of its operations and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.
SPROUSE & ANDERSON, L.L.P.
March 3, 2006
Austin, Texas
REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
To the Shareholders and
Board of Directors
Royale Energy, Inc.
We have audited the accompanying statements of operations, stockholders' equity and cash flows of Royale Energy, Inc. for the year ended December 31, 2003. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with standards of the Public 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statements presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the results of operations, and stockholders' equity, of Royale Energy, Inc. and its cash flows for the year ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.
BROWN ARMSTRONG PAULDEN
McCOWN STARBUCK THORNBURGH & KEETER
ACCOUNTANCY CORPORATION
Bakersfield, California
February 13, 2004
ROYALE ENERGY, INC
BALANCE SHEETS
DECEMBER 31, 2005 AND 2004
ASSETS
Current Assets
Cash and Cash Equivalents
$ 4,716,772
$ 7,627,045
Accounts Receivable
4,221,601
3,903,941
Prepaid Expenses
2,299,333
3,570,850
Deferred Tax Asset
194,468
1,155,338
Inventory
382,810
147,478
Total Current Assets
11,814,984
16,404,652
Investments
6,946
6,946
Oil and Gas Properties (successful efforts basis),
Equipment and Fixtures
31,220,651
26,137,071
Total Assets
$ 43,042,581
$ 42,548,669
The accompanying notes are an integral part of these financial statements.
ROYALE ENERGY, INC.
BALANCE SHEETS
DECEMBER 31, 2005 AND 2004
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable and Accrued Expenses
$ 7,375,161
$ 9,628,066
Current Portion of Long-Term Debt
90,746
69,944
Deferred Revenue from Turnkey Drilling
6,490,111
5,279,417
Total Current Liabilities
13,956,018
14,977,427
Noncurrent Liabilities
Asset Retirement Obligation
245,627
266,462
Deferred Tax Liability
3,892,048
4,138,317
Long-Term Debt, Net of Current Portion
6,630,598
5,977,642
Total Noncurrent Liabilities
10,768,273
10,382,421
Total Liabilities
24,724,291
25,359,848
Redeemable Preferred Stock
Series A, Convertible Preferred Stock, No Par Value,
259,250 Shared Authorized; 6,122 and 6,122 Shares
Issued and Outstanding.
11,589
11,589
Stockholders' Equity
Common Stock, No Par Value, 10,000,000 Shares
Authorized; 7,948,688 and 7,859,223 issued and
7,934,736 and 7,839,223,outstanding.
19,500,374
19,591,039
Convertible Preferred Stock, Series AA, No Par Value,
147,500 Shares Authorized; 57,416 and 57,416
Shares Issued and Outstanding
167,979
167,979
Accumulated (Deficit)
(1,314,738
)
(2,500,641
)
Total Paid in Capital and Accumulated Deficit
18,353,615
17,258,377
Less Cost of Treasury Stock, 13,952 and 20,000 Shares
(68,271)
(97,906)
Paid in Capital, Treasury Stock
21,357
16,761
Total Stockholders' Equity
18,318,290
17,188,821
Total Liabilities and Stockholders' Equity
$ 43,042,581
$ 42,548,669
The accompanying notes are an integral part of these financial statements.
ROYALE ENERGY, INC.
STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2005, 2004, AND 2003
Revenues
Sale of Oil and Gas
$ 11,228,537
$ 10,892,574
$ 10,120,148
Turnkey Drilling
13,066,800
13,269,996
11,966,860
Supervisory Fees and Other
1,348,041
1,781,786
1,178,129
Total Revenues
25,643,378
25,944,356
23,265,137
Costs and Expenses
General and Administrative
5,038,338
5,205,190
3,993,668
Geological and Geophysical Expenses
381,790
321,983
209,622
Turnkey Drilling Development
8,111,248
8,150,338
5,855,661
Lease Operating
2,751,441
2,817,448
1,714,382
Lease Impairment
742,642
51,414
869,991
Legal and Accounting
236,199
627,038
544,302
Marketing
2,061,689
1,284,809
804,366
Depreciation, Depletion and Amortization
4,062,587
3,714,271
2,418,922
Total Costs and Expenses
23,385,934
22,172,491
16,410,914
Income (Loss) from Operations
2,257,444
3,771,865
6,854,223
Other Expenses
Interest Expense
444,271
273,050
194,997
Income (Loss) Before Income Tax Expense
1,813,173
3,498,815
6,659,226
Income Tax Expense (Benefit)
627,270
1,306,063
2,217,005
Net Income Before Cumulative Effect
of Accounting Change
1,185,903
2,192,752
4,442,221
Cumulative Effect of Accounting Change
-
-
(41,301
)
Net Income (Loss)
1,185,903
$ 2,192,752
$ 4,400,920
Basic Earnings Per Share:
Net income (loss) available to common stock
$0.15
$ 0.32
$ 0.72
Cumulative effect of accounting change
$ -
$ -
$ -
Diluted Earnings (Loss) Per Share
$.15
$ 0.31
$ 0.65
The accompanying notes are an integral part of these financial statements.
ROYALE ENERGY, INC.
STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2005, 2004, AND 2003
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, 2005, 2004, AND 2003
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, 2005, 2004, AND 2003
The accompanying notes are an integral part of these financial statements.
ROYALE ENERGY, INC.
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)
$1,185,903
$2,192,752
$4,400,920
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities:
Depreciation, Depletion, and Amortization
4,062,587
3,714,271
2,418,922
Lease Impairment
742,642
51,414
869,991
Bad Debt Expense
401,691
641,079
-
Compensation Expense - Stock Grant
34,231
(Increase) Decrease in:
Accounts Receivable
(719,351)
598,471
(1,407,255)
Prepaid Expenses and Other Assets
1,997,055
(2,409,983)
(587,717)
Increase (Decrease) in:
Accounts Payable and Accrued Expenses
(2,273,741)
875,473
2,721,546
Deferred Revenues - DWI
1,210,694
1,244,536
1,468,693
Deferred Income Taxes
(246,269
)
1,110,287
-
Net Cash Provided by Operating Activities
6,395,442
8,018,300
9,885,100
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for Oil and Gas Properties
And other capital expenditures
(9,888,809)
(6,915,103)
(11,016,044)
Proceeds from Sale of Investments
-
275,000
-
Net Cash Used in Investing Activities
(9,888,809
)
(6,640,103
)
(11,016,044
)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt (Net)
673,759
1,657,586
4,113,742
Exercise of Options for Cash
98,247
Repurchase of Stock Options
(188,912
)
(286,356
)
(335,124
)
Net Cash Provided by Financing Activities
583,094
1,371,230
3,778,618
Net Increase (Decrease) in Cash and Cash Equivalents
(2,910,273)
2,749,427
2,647,674
Cash & Cash Equivalents at Beginning of Year
7,627,045
4,877,618
2,229,944
Cash & Cash Equivalents at End of Year
$4,716,772
$7,627,045
$4,877,618
SUPPLEMENTAL DISCLOSURES OF CASH FLOWS INFORMATION:
Cash Paid for Interest
$ 290,367
$ 211,633
$ 194,997
Cash Paid for Taxes
$ 369,063
$ 601,523
$ 12,670
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, 2005 and 2004 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 gas in the period of delivery.
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 7-14 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 is 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 $742,642, $51,414, and $869,991 were recorded in 2005, 2004, and 2003 respectively.
Upon the sale of oil and gas reserves in place, costs less 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.
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 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, 2005 and 2004, net accounts receivable was $4,221,601 and $3,903,941, respectively. At December 31, 2005 and 2004, the Company established an allowance for bad debts of $401,691 and $641,079, respectively for receivables from direct working interest investors whose expenses on non-producing wells was unlikely to be collected.
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 (SFAS 128)
Basic and diluted earnings (loss) per share are calculated as follows:
Stock Based Compensation
Royale Energy has a stock-based employee and director compensation plan, which is more fully described in Note 13. Royale Energy accounts for this plan under the recognition and measurement principles of APB Opinion No. 25, Accounting for Stock Issued to Employees, and related Interpretations. No stock-based compensation cost is reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant.
The following table illustrates the effect on net income and earnings per share if Royale Energy had applied the fair value recognition provisions of FASB Statement No. 123, Accounting for Stock-Based Compensation, to stock-based compensation:
Net income (loss), as reported
$ 1,185,903
$ 2,192,752
$ 4,400,920
Add: Stock-based employee compensation
expense included in reported net income, net
of related tax effects.
-
-
-
Deduct: Total stock-based employee
compensation expense determined under
fair value method for all awards, net of
related tax effects
-
-
(137,318
)
Pro forma net income
$ 1,185,903
$ 2,192,752
$ 4,263,602
Earnings per share:
Basic -- as reported
$ 0.15
$ 0.32
$ 0.72
Basic -- pro forma
$ 0.15
$ 0.32
$ 0.69
Diluted -- as reported
$ 0.15
$ 0.31
$ 0.65
Diluted -- pro forma
$ 0.15
$ 0.31
$ 0.63
In December 2002, the Financial Accounting Standards Board issued SFAS No. 148, Accounting for Stock-Based Compensation, an Amendment of SFAS No. 123 ("SFAS 123") in an effort to encourage the recognition of compensation expense for the issuance of stock options. Royale Energy has elected to continue accounting for stock-based compensation under APB Opinion No. 25 and disclose pro forma net income and earnings per share, as if the fair value based method of accounting defined in Statement 123 and 148 had been applied.
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 6,048 shares of vested restricted common stock were issued. The Company recognized $34,241 compensation expense in 2005. Additionally, 12,102 shares of unvested stock were awarded with vesting dates in 2006 and 2007 for which compensation expense will be similarly recognized. 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. Royale Energy issued no other equity securities in 2005.
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.
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.
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 January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities." This statement requires the consolidation of certain entities that are determined to be variable interest entities. An entity is determined to be a variable interest entity when either (I) the entity lacks sufficient equity to carry on its principal operations, (II) the equity owners of the entity cannot make decisions about the entity's activities or (III) the entity's equity neither absorbs losses or benefits from gains. The Company has reviewed its financial arrangements and has not identified any material variable interest entities that should be consolidated by the Company in accordance with FASB Interpretation No. 46.
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments
and Hedging Activities." SFAS 149 amends SFAS No.133, "Accounting for Derivative Instruments and hedging Activities." SFAS 149 requires that contracts with comparable characteristics be accounted for similarly. In addition, SFAS 149 also clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative and clarifies when a derivative contains a financing component. This statement became effective for contracts entered into or modified after June 30, 2003. The adoption of this statement did not impact the Company's financial position, results of operations, or cash flows.
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." SFAS 150 will result in a more complete depiction of an entity's liabilities and equity and will, therefore, assist investors and creditors in assessing the amount, timing, and likelihood of potential future cash outflows and equity share issuances. Furthermore, SFAS 150 will enhance the relevance of accounting information by providing more information about an entity's obligations to transfer assets or issue shares, therefore, improving its predictive value to users. SFAS 150 requires that certain obligations that could be settled by issuance of an entity's equity but lack other characteristics of equity be reported as liabilities even though the obligation does not meet the definition of liabilities as stated in Concepts Statement 6. This statement became effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of this statement did not impact the Company's financial position, results of operations, or cash flows.
In December of 2004, the FASB amended SFAS No. 123, "Accounting for Stock-Based Compensation." For equity instruments awarded to employees in exchange for service, companies are required to measure the cost of the employees' service based on fair value and recognize these costs over the vesting period of the equity instrument. This statement eliminates the option in Opinion 25 to use the intrinsic value method of measuring the cost of the employees' service. This statement is effective for non-small business issuers for reporting periods beginning after June 15, 2005 and for small business issuers for fiscal periods beginning after December 15, 2005. We do not expect this statement to materially affect the Company's financial position, results of operations, or cash flows.
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 performed an evaluation of our capitalized costs and determined that no previously capitalized exploratory well costs pending the determination of proved reserves were required to be expensed or reclassified during the third quarter of 2005 or 2004. We did not make any additions to capitalized exploratory well costs pending a determination of proved reserves during the third quarter of 2005 or
2004. We did not charge any previously capitalized exploratory well costs to expense upon adoption of FSP FAS 19-1.
In November 2005, the FASB issued SFAS No. 151, "Inventory Costs," and amendment of ARB No. 43, Chapter 4. SFAS 151 clarifies the language in ARB 43 and IAS 2 in order to promote consistent application of the standards. This new statement requires inventories to be stated at cost but that unallocated overheads, abnormal freight, handling and spoilage are treated as current period charges instead of as part of inventory costs. This statement becomes effective for fiscal years beginning after June 15, 2005. We do not expect adoption of this statement to materially affect the Company's financial position, results of operations, or cash flows.
In December of 2005, the FASB approved SFAS No. 152, "Accounting for Real Estate Time-Sharing Transactions." This statement amends FASB statements No. 66 and 67 to include changes in the real-estate industry that have occurred since the original statements were adopted. Specifically, SFAS 152 addresses time-sharing interests. This statement is effective for fiscal years beginning after June 15, 2005. Since the Company does not own any time-sharing real estate interests, we do not expect this statement to materially affect the Company's financial position, results of operations, or cash flows.
In December of 2005, the FASB approved SFAS No. 153, "Exchange of Nonmonetary Assets". This statement amends APB Opinion No. 29, eliminating the exception for nonmonetary exchanges of similar productive assets. The prior exception is replaced by an exception for the nonmonetary exchange of assets that will not significantly affect the future cash flows of the entity. This should result in financial statements that more accurately show the economics of the exchange. Specific to the oil and gas industry, gain or loss shall not be recognized at the time of the transaction in the pooling of assets designed to find, develop, or product oil or gas. This statement is effective for fiscal periods beginning after June 15, 2005. We do not expect this statement to materially affect the Company's financial position, results of operations, or 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,:
Oil and Gas
Producing properties, including intangible drilling costs
$ 28,805,150
$ 24,268,397
Undeveloped properties
6,232,050
2,082,853
Lease and well equipment
8,777,597
8,041,522
43,814,797
34,392,772
Accumulated depletion, depreciation and amortization
(14,743,316)
(10,897,900)
29,071,481
23,494,872
Commercial and Other
Real estate, including furniture and fixtures
503,344
1,005,916
Vehicles
255,523
255,523
Furniture and equipment
2,391,490
2,142,871
3,150,357
3,404,310
Accumulated depreciation
(1,001,187
)
(762,111
)
2,149,170
2,642,199
$ 31,220,651
$ 26,137,071
The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed:
Acquisition - Proved
$ 394,069
$ 3,217,409
$ 3,058,667
Acquisition - Unproved
$ 848,358
$ 1,906,106
$ 225,054
Development
$ 7,633,536
$ 2,388,723
$ 4,396,398
Exploration
$ 5,507,658
$ 7,925,775
$ 2,828,769
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:
Oil and gas sales
$ 11,228,537
$ 10,892,574
$ 10,120,148
Production related costs
(2,751,441)
(2,817,448)
(1,714,382)
Geological and geophysical expense
(381,790)
(321,983)
(209,622)
Depreciation, depletion and amortization
(4,062,587
)
(3,714,271
)
(2,418,922
)
Results of operations from producing and
exploration activities
$ 4,032,719
$ 4,038,872
$ 5,777,222
Income Taxes
1,391,288
1,393,411
1,993,142
Net Results
$ 2,641,431
$ 2,645,461
$ 3,784,080
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.
The company adopted SFAS 143 as of January 1, 2003. The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment to record a $157,185 increase in the carrying values of proved properties and a $188,007 increase in noncurrent abandonment liabilities. The net impact of these items was to record $41,301, net of tax, as a cumulative effect adjustment of a change in accounting principle in our Statement of Income for 2004. The asset obligation relates to costs to plug and abandon oil and gas properties of the Company.
Asset retirement obligation
Beginning of the year
$ 266,462
$ 195,712
Liabilities incurred during the period
21,007
73,804
Settlements
(14,026)
(31,694)
Accretion expense
10,050
64,113
Revisions in estimated cash flow
(37,866)
(35,473)
Asset retirement obligation
End of year
$ 245,627
$ 266,462
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, 2005 and 2004, Royale Energy had recorded deferred turnkey drilling revenue associated with undrilled wells of $6,490,111 and $5,279,417, 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 2005 and 2004:
Oil and Gas
Producing
Turnkey
and
Drilling
Exploration
Services
Total
Year Ended December 31, 2005
Revenues from External Customers
$ 11,228,537
$ 13,066,800
$ 24,295,337
Supervisory Fees
$ 1,277,105
$ -
$ 1,277,105
Interest Revenue
$ 70,936
$ -
$ 70,936
Interest Expense
$ 222,136
$ 222,135
$ 444,271
Expenditures for Segment Assets
$ 6,245,208
$ 12,335,497
$ 18,580,705
Depreciation, Depletion, and Amortization
$ 3,859,458
$ 203,129
$ 4,062,587
Lease Impairment
$ 371,321
$ 371,321
$ 742,642
Income Tax
$ 313,635
$ 313,635
$ 627,270
Total Assets
$ 43,042,581
$ -
$ 43,042,581
Oil and Gas
Producing
And
Exploration
Turnkey Drilling
Services
Total
Net Income (Loss)
$ 1,564,821
$ (378,918)
$ 1,185,903
Year Ended December 31, 2004
Revenues from External Customers
$ 10,892,574
$ 13,269,996
$ 24,162,570
Supervisory Fees
$ 1,712,673
$ -
$ 1,712,673
Interest Revenue
$ 69,113
$ -
$ 69,113
Interest Expense
$ 136,525
$ 136,525
$ 273,050
Expenditures for Segment Assets
$ 6,580,446
$ 11,826,360
$ 18,406,806
Depreciation, Depletion, and Amortization
$ 3,528,557
$ 185,714
$ 3,714,271
Lease Impairment
$ 25,707
$ 25,707
$ 51,414
Income Tax (Benefit)
$ 653,031
$ 653,032
$ 1,306,063
Total Assets
$ 42,548,669
$ -
$ 42,548,669
Net Income
$ 1,718,987
$ 473,765
$ 2,192,752
Year Ended December 31, 2003
Revenues from External Customers
$ 10,120,148
$ 11,966,860
$ 22,087,008
Supervisory Fees
$ 1,134,116
$ -
$ 1,134,116
Interest Revenue
$ 44,013
$ -
$ 44,013
Interest Expense
$ 97,499
$ 97,498
$ 194,997
Expenditures for Segment Assets
$ 4,801,248
$ 8,320,753
$ 13,122,001
Depreciation, Depletion, and Amortization
$ 2,306,200
$ 112,722
$ 2,418,922
Lease Impairment
$ 434,996
$ 434,995
$ 869,991
Income Tax (Benefit)
$ 1,108,503
$ 1,108,502
$ 2,217,005
Cumulative Effect of Accounting Change
$ (20,651)
$ (20,650)
$ (41,301)
Total Assets
$ 35,670,504
$ -
$ 36,670,504
Net Income (Loss)
$ 2,529,180
$ 1,871,740
$ 4,400,920
NOTE 6 - LONG-TERM DEBT
Revolving line of credit secured by oil and gas properties, with a maximum available of $5,750,000 issued by Guaranty Bank, FSB for the purposes of refinancing Royale's existing debt and to fund development, exploration and acquisition activities as well as other general corporate purposes. The agreement was entered into on January 21, 2003. Interest is at Guaranty Bank's base rate plus .75%, resulting in a rate of 7.75% at December 31, 2005, payable monthly with borrowing base reductions of $125,000 commencing on February 1, 2003. All unpaid principal and interest is payable at maturity on June 1, 2008.
$ 6,400,000
$ 5,472,500
Term Note (Secured by Deed of Trust), dated March 17, 2004, in the original principal amount of $1,0000,000, executed by Royale Energy, Inc., payable to the order of Guaranty Bank, FSB. Monthly payments of principal and interest are $9,000 per month with all unpaid principal and interest due on March 17,2007.
$ 321,344
$ 575,086
Total Long Term Debt
$
6,721,344
$
6,047,586
Less Current Maturity
$
(90,746)
$
(69,944)
Long Term Debt Less Current Portion
$
6,630,598
$
5,977,642
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 the terms of this agreement at December 31, 2005 and 2004.
Maturities of long-term debt for years subsequent to December 31, 2005 are as follows:
Year Ended
December 31,
$ 90,746
$ 230,598
$ 6,400,000
$ 6,721,344
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.
Significant components of the Company's deferred assets and liabilities at December 31, 2005, 2004 and 2003, respectively, are as follows:
Deferred Tax Assets (Liabilities):
Statutory Depletion Carry Forward
$ 816,270
$ 816,270
$ 984,595
Capital Loss / AMT Credit Carry Forward
25,311
133,023
21,357
Charitable Contributions Carry Forward
6,660
-
-
Allowance for Doubtful Accounts
124,097
206,045
-
Oil and Gas Properties and Fixed Assets
(4,669,918
)
(4,138,317
)
(3,028,030)
Net Deferred Tax Liability
$ (3,697,580)
$ (2,982,979)
$
(2,022,078)
Deferred Tax Assets:
Current
194,468
1,155,338
1,005,952
Non-current
-
-
-
Deferred Tax Liabilities:
Current
-
-
-
Non-current
(3,892,048
)
(4,138,317
)
(3,028,030)
Net Deferred Tax Liability
$ (3,697,580)
$ (2,982,979)
$
(2,022,078)
The Company had statutory percentage depletion carry forwards of approximately $2,366,000 and $2,366,000 at December 31, 2005 and 2004 respectively. The depletion has no expiration date. The Company also has a capital loss carryforward of approximately $0 and $41,000 at December 31, 2005 and 2004, respectively.
A reconciliation of Royale Energy's provision for income taxes and the amount computed by applying the statutory income tax rates at December 31, 2005, 2004 and 2003, respectively, to pretax income is as follows:
Tax (benefit) computed at statutory rate
$ 625,440
$ 1,207,874
$ 2,264,137
Increase (decrease) in taxes resulting from:
Net operating loss carryforwards used
-
-
(447,426)
State tax / percentage depletion / other
-
93,987
398,811
Other non deductible expenses
1,830
4,202
1,483
Provision (benefit)
$ 627,270
$ 1,306,063
$
2,217,005
Effective Tax Rate
34.6%
37.3%
33.5%
The components of the Company's tax provision are as follows:
Current tax provision (benefit) - federal
$ 5,570
$ 125,003
$ 79,927
Current tax provision (benefit) - state
14,113
115,000
Deferred tax provision (benefit) - federal
558,064
1,048,561
1,819,870
Deferred tax provision (benefit) - state
63,007
118,386
202,208
Total provision
$
627,270
$
1,306,063
$
2,217,005
Of the 2003 tax provision, $13,836 was attributable to the cumulative effect of the FAS 143 accounting change.
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, which were sold through a private placement offering. The Series A Convertible Preferred Stock was offered in units. Each unit consisted of 25,000 shares of Series A Convertible Preferred Stock and a 0.1% interest in the distributions of the Royale Energy Income Trust, to be formed. Royale Energy had the right to sell fractional units. The Series A Convertible Preferred Stock has a stated value of $4 per share and provides stockholders with a one time 10% cash dividend payable thirty days after the expiration of one year from the date of purchase. The cash dividend has been paid on all outstanding shares at December 31, 1994. The Board authorized a 15% stock dividend to stockholders of record on May 31, 2002 and increased the number of Series A Preferred shares by 1,475. 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 A Preferred shares by 385 for the period ending December 31, 2003 and has been retroactively restated to reflect the 3rd quarterly stock dividend paid in January 2004. On March 31, 2004, the fourth and final of these installments was made resulting in 172 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 A Preferred shares increased by 1,339.
The Series A Convertible Preferred 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.
Royale Energy has the option to call, at any time, the Series A Convertible Preferred Stock at either the issue price of $4 per share plus 10%, if called within one year after issuance, or $4 per share thereafter. (Subject to the holders' conversion rights outlined above).
Upon the sale of 50% of the units of beneficial interest in Royal Energy Income Trust, a holder of Series A Convertible Preferred Stock may require Royale Energy to redeem their Series A Convertible Preferred Stock at the issue price of $4 per share plus accrued dividends, if any.
The Series A Convertible Preferred Stock has a liquidation preference to the common stock equal to $4 per share plus accrued dividends. Holders of Series A Convertible Preferred Stock shall have voting rights equal to the number of shares of common stock into which the Series A Convertible Preferred Stock may be converted.
On October 28, 1993, Royale Energy's Series A Convertible Preferred Stock stockholders were made a one time offer to convert their Series A Convertible Preferred Stock to common stock. This conversion would be at one share of common stock for each share of Series A Convertible Preferred Stock, rather
than at the original conversion price of $4 per share. This conversion would not affect the stockholders' rights and incentives in the Royale Energy Income Trust. As of December 31, 2003 and 2002, 233,011 shares of Series A Convertible Preferred Stock had been converted to 202,723 shares of common stock. No conversions were made in 2004 or 2005.
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 3rd 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, 2005 and 2004, there were 57,416 shares issued and outstanding.
NOTE 10 - COMMON STOCK
Royale Energy's Board of Directors, at its December 1997 meeting, authorized the repurchase and cancellation of up to 15% of the outstanding common stock of Royale Energy. The Board also authorized a 15% stock dividend to stockholders of record on May 31, 2002. The number of common shares increased by 652,959 shares. The effect of the stock dividend decreased retained earnings by $4,472,769. In addition, on May 1, 2003, the Board of Directors authorized a 15% stock dividend to stockholders of record on that date with the dividend to be paid in equal quarterly installments beginning with the quarter ending June 30, 2003. The number of common shares increased by 585,924 shares after the third quarterly payment of the stock dividend. The effect of the stock dividend decreased retained earnings by $3,468,955 at December 31, 2003. On March 31, 2004, the fourth and final of these installments was made resulting in 221,049 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 number of common shares increased by 1,712,093.
The financial statements have been retroactively restated to reflect the stock split distributed in June 2004.
NOTE 11 - STOCK WARRANTS
Changes in Royale Energy's common stock warrants were as follows at December 31:
Outstanding Warrants at Beginning of Period
340,514
Stock Reorganization
(340,514
)
Outstanding Warrants at End of Period
On January 30, 2004, we issued a net 295,801 shares of common stock to Royale Petroleum Corporation, which is owned by our president, Donald H. Hosmer, and our Executive Vice President and Chief Financial Officer, Stephen M. Hosmer, upon exercise of options and warrants. The options and warrants were exercised in cashless exercises in which stock equal to the total exercise price of the securities was in effect withheld from the amount issued on exercise, based on the 5 day average closing price of the common stock for 5 days prior to exercise ($10.996 per share). Royale Petroleum Corporation exercised options and warrants to buy a total of 340,514 shares, bearing exercise prices from $1.02 to $2.03 per share, for the shares, for an aggregate consideration paid equal to $422,923. These shares were issued in reliance on the exemption from registration requirements provided by Section 4(2) of the Securities Act of 1933.
NOTE 12 - 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 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 $35,241, and the Woodland lease calls for monthly payments of $275. Future minimum lease obligations as of December 31, 2005 are as follows:
Year Ended
December 31,
$ 333,839
343,854
354,169
364,795
375,738
Thereafter
1,873,198
Total
$ 3,645,593
Rental expense for the years ended December 31, 2005, 2004, and 2003 are $340,006, $298,165, and $244,041 respectively.
NOTE 13 - RELATED PARTY TRANSACTIONS
Significant Ownership Interests
Donald H. Hosmer, Royale Energy's president, owns 12.99% 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 executive vice president and chief financial officer, owns 15.81% 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 9.93% 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 $130,473 and $196,323 for their interests for the years ended December 31, 2005 and 2004, 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.
NOTE 14 - STOCK COMPENSATION PLAN
On December 18, 1992, the Board of Directors granted the directors and executive officers of Royale Energy 30,000 options to purchase common stock at an exercise or base price of $3.00 per share. All options are exercisable on or after the second anniversary of the date of the grant. Also on this date, the Board of Directors voted to adopt a policy of awarding stock options to key employees and contractors based on performance.
At the March 10, 1995 Board of Directors meeting, directors and executive officers of Royale Energy were granted 154,000 options to purchase common stock at an exercise or base price of $1.90 per share. These options were granted for a period of ten years, and may be exercised after the second anniversary of the grant. Royale Energy applies APB Opinion 25 and related interpretations in accounting for its plans. Royale Energy did not grant stock options during 2005, 2004 or 2003.
On March 26, 2001, the number of options increased from 30,000 to 34,500 and the price decreased from $3.00 per share to $2.60 per share due to the declaration of the 15% stock dividend.
On March 18, 2002, the number of remaining options of 113,850 decreased to 104,478 outstanding and the price decreased from $1.65 per share to $0.83 per share due to expiration of options and the declaration of the 15% stock dividend.
On May 1, 2003, the number of remaining options of 104,478 increased to 114,439 outstanding and the price increased from $0.83 per share to $1.79 per share due to the reinstatement of shares, repurchase of options from employees/directors and the declaration of the 15% stock dividend, which is being paid in equal quarterly installments.
On July 10, 2003, the Company repurchased 10,290 options from Don Hosmer in the amount of $59,270, and 42,000 options from Harry Hosmer amounting to $275,854.
On March 29, 2004, the Company repurchased 14,063 options from Harry Hosmer amounting to $160,178, and 11,078 options from Don Hosmer amounting to $126,178.
On June 24, 2005, the Company repurchased 19,615 options from Stephen Hosmer amounting to $188,912.
A summary of the status of Royale Energy's stock option plan as of December 31, 2005, 2004 and 2003, and changes during the years ending on those dates is presented below:
NOTE 15 - 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, 2005, 2004, and 2003 were $48,445 $46,043 and $42,875, respectively.
NOTE 16 - 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 2005, 2004, or 2003.
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 17 - 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 75% 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 $100,000. At December 31, 2005 and 2004, cash in banks exceeded the FDIC limits by approximately $6.5 and $8.5 million, respectively. The Company has not experienced any losses on deposits.
NOTE 18 : Quarterly Financial Information (Unaudited):
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Total Year
Revenues
$5,552,615
$6,059,735
$6,449,816
7,581,212
25,643,378
Operating income (loss)
(17,606)
402,494
445,675
1,426,881
2,257,444
Net income (loss)
(131,833)
264,071
211,584
842,081
1,185,903
Earnings (loss) per share
Basic and Diluted
(0.02)
0.03
0.03
0.11
0.15
Revenues
$5,513,278
$6,392,400
$5,825,029
$8,213,650
$25,944,356
Operating income (loss)
1,512,412
1,155,487
958,066
145,900
3,771,865
Net income (loss)
961,625
719,582
702,861
(191,316)
2,192,752
Earnings (loss) per share
Basic and Diluted
0.14
0.09
0.09
(0.03)
0.32 / 0.31
Annual Earnings (loss) per share may not equal the sum of the four quarterly amounts due to rounding.
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, 2005, 2004, and 2003. 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, 2005, 2004 and 2003 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, 2005 ranging from $7.48 per MCF to $10.50 per MCF as applied on a field-by-field basis.
In 2004, the discontinuation of one well and significant downward revision of a second well accounted for downward revisions of more than 1.14 million cubic feet of proved developed reserves, which is 77% of the net revisions in 2004. Both wells had been producing gas wells. The reserve estimate for one well was revised downward by 622,928 cubic feet to 0, and the reserve estimate of the second well was revised downward by 521,714 cubic feet to 182,000 cubic feet.
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, 2005.
The future net cash inflows are developed as follows:
-
Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions.
-
The estimated future production of proved reserves is priced on the basis of year-end prices.
-
The resulting future gross revenue streams are reduced by estimated future costs to develop and to produce proved reserves, based on year-end estimates. Estimated future development cost by year are as follows:
$ 5,787,000
3,005,000
511,000
Thereafter
113,000
Total
$ 9,416,000
The resulting future net revenue streams are reduced to present value amounts by applying a ten percent discount.
Disclosure of principal components of the standardized measure of discounted future net cash flows provides information concerning the factors involved in making the calculation. In addition, the disclosure of both undiscounted and discounted net cash flows provides a measure of comparing proved oil and gas reserves both with and without an estimate of production timing. The standardized measure of discounted future net cash flow relating to proved reserves reflects estimated income taxes.
Changes in standardized measure of discounted future net cash flow from proved reserve quantities
This statement discloses the sources of changes in the standardized measure from year to year. The amount reported as "Net changes in prices and production costs" represents the present value of changes in prices and production costs multiplied by estimates of proved reserves as of the beginning of the year. The "accretion of discount" was computed by multiplying the ten percent discount factor by the standardized measure on a pretax basis as of the beginning of the year. The "Sales of oil and gas produced, net of production costs" are expressed in actual dollar amounts. "Revisions of previous quantity estimates" is expressed at year-end prices. The "Net change in income taxes" is computed as the change in present value of future income taxes.
Future cash inflows
95,339,000
91,215,000
68,892,000
Future production costs
(18,086,000)
(16,029,000)
(16,466,000)
Future development costs
(9,416,000)
(8,465,000)
(4,251,000)
Future income tax expense
(20,351,400)
(20,016,153)
(14,452,538)
Future net cash flows
47,485,600
46,704,847
33,722,462
10% annual discount for estimated timing of cash flows
(12,682,159)
(12,423,729)
(9,608,336
)
Standardized measure -of discounted future net cash flows
34,803,441
34,281,118
24,114,126
Sales of oil and gas produced, net of production costs
(7,022,572)
(6,766,942)
(6,995,490)
Revisions of previous quantity estimates
(3,437,217)
(3,745,397)
(1,782,180)
Net changes in prices and production costs
1,269,384
5,498,228
7,651,000
Sales of minerals in place
(3,325,454)
(3,291,184)
(3,801,973)
Purchases of minerals in place
-
2,009,099
-
Extensions, discoveries and improved recovery
8,593,334
17,595,769
9,135,768
Accretion of discount
4,668,700
3,224,700
5,648,921
Net change in income tax
(223,852)
(4,357,282
)
(2,956,814
)
Net increase (decrease)
$
522,323
$10,166,991
$
6,899,232
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 2006 through 2008.
Future development cost of:
Proved developed reserves
$ 294,000
$ -
$ -
Proved non-producing reserves
7,000
36,000
10,000
Proved undeveloped reserves
5,486,000
2,969,000
501,000
Total
$ 5,787,000
$ 3,005,000
$511,000
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. 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, 2005, 2004, and 2003, 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:
$2,428,069
$2,881,835
$2,307,108