As filed with the SEC on December 11, 2003
| For the Fiscal Year Ended December 31, 2001 | Commission File No. 0-22750 |
ROYALE ENERGY, INC.
(Name of Small Business Issuer
in its charter)
| California | 33-0224120 | |
| (State or other jurisdiction of | (I.R.S. Employer | |
| incorporation or organization) | Identification No.) |
7676 Hazard Center
Drive, Suite 1500
San Diego, CA 92108
(Address of principal
executive offices)
Issuer’s telephone
number: 619-881-2800
Securities registered
pursuant to Section 12(b) of the Act:
None
Securities to be
registered pursuant to Section 12(g) of the Act:
Common Stock, par value $.01 per share
(Title
of Class)
Check whether the issuer (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X ; No _____
Check if there is no disclosure of delinquent filers in response to Item 405 of Regulation S-B is not contained herein, and will not be contained, to the best or registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-KSB or any amendment to this Form 10-KSB. [ ]
State issuer's revenues for its most recent fiscal year: $15,858,273.
At December 31, 2001, there were 3,267,695 outstanding shares of registrant’s Common Stock held by non-affiliates (after making adjustments for stock dividends distributed after December 31, 2001), with an aggregate market value of approximately $18,103,030, based on the closing Nasdaq price on that date.
At December 31, 2001, a total of 5,213,883 shares of registrant’s Common Stock were outstanding (after making adjustments for stock dividends distributed after December 31, 2001).
DOCUMENTS INCORPORATED BY REFERENCE: None
Exhibit Index appears on page 23
TABLE OF CONTENTS
| PART I | 1 | |
| Item 1 | Description of Business | 1 |
| Plan of Business | 2 | |
| Competition, Markets and Regulation | 4 | |
| Item 2 | Description of Property | 5 |
| Northern California | 5 | |
| Developed and Undeveloped Leasehold Acreage | 6 | |
| Drilling Activities | 6 | |
| Production | 7 | |
| Net proved Oil and Natural Gas Reserves | 7 | |
| Item 3 | Legal Proceedings | 8 |
| Item 4 | Submission of Matters to a Vote of Security Holders | 8 |
| PART II | 8 | |
| Item 5 | Market Price of Royale Energy's Common Stock
and Related Stockholder Matters |
8 |
| Dividends | 9 | |
| No Recent Sales of Equity Securities | 9 | |
| Critical Accounting Policies | 10 | |
| Results of Operations for the Twelve Months Ended
December 31, 2001, as Compared to the Twelve Months Ended December 31, 2000 |
11 | |
| Capital Resources and Liquidity | 14 | |
| Item 7 | Financial Statements and Supplementary Data | 16 |
| PART III | 16 | |
| Item 8 | Directors, Executive Officers, Promoters and Control Persons,
Compliance with Section 16(a) of the Exchange Act |
16 |
| Item 8 | Compliance with Section 16(a) of the Exchange Act | 18 |
| Item 9 | Executive Compensation | 18 |
| No Stock Options Were Granted in 2001 | 19 | |
| Aggregated 2001 Option Exercises and Year-End Values | 19 | |
| Compensation of Directors | 20 | |
| Item 10 | Security Ownership of Certain Beneficial Owners and Management | 20 |
| Common Stock | 20 | |
| Preferred Stock | 22 | |
| Item 11 | Certain Relationships and Related Transactions | 22 |
| Item 12 | Exhibits, Lists, and Reports on Form 8-K | 23 |
| Signatures | ||
| Financial | Statements | F-1 |
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ROYALE ENERGY, INC.
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 March 23, 2002, Royale Energy had 17 full time employees.
Royale Energy owns wells and leases located mainly in the Sacramento Basin and San Joaquin Basin in California. 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 permits 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, 2001, Royale Energy continued to explore and develop natural gas properties in northern California. Royale Energy drilled eleven wells in 2001, seven of which are currently commercially productive wells. One well is waiting on completion. In 2001, four previously drilled wells were “shut-in,” which means that the wellhead valves were closed, shutting off production. The shut-in wells were awaiting further equipment or production arrangements to begin or recommence operations, such as production equipment or pipeline easements. Royale Energy’s estimated total natural gas reserves decreased from approximately 16.7 Bcf (billion cubic feet) at December 31, 2000 to approximately 13.2 Bcf at December 31, 2001. 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 $13.6 million at December 31, 2001, based on natural gas prices ranging from $2.41 per Mcf to $2.85 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, 2001, to be $9,013,270.
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 $6,703,452 for the year ended December 31, 2001, which represents 42.3% of its total revenues for the year.
In the year ended 2000, Royale Energy reported $4,792,151 gross revenues for the year, representing 41.0% of Royale Energy’s total revenues for that year. These amounts are offset by
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drilling expenses and development costs of $3,065,747 in 2001, and $1,975,242 in 2000. 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 53.3% of Royale Energy’s total revenue for the year ended December 31, 2001 came from oil and natural gas sales from production of its wells ($8,452,282). In 2000, this amount was $6,194,451, which represented 53.0% of Royale Energy’s total revenues.
Royale Energy acquires interests in oil and natural gas reserves and sponsors private joint ventures. Royale Energy believes that its shareholders are better served by diversification of its investments among individual drilling projects. 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 drilling contractor to drill a well, for a fixed price, to a specified depth 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 the well is spudded (begun). The deferred revenue is referred to as “remaining funds” in Royale Energy’s
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disclosure. See Note 1 to Royale Energy’s Financial Statements on page F-7. 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, 2001, Royale Energy earned gross revenues from operation of the wells in the amount of $702,539, representing 4.4% of its total revenues on a consolidated basis for that year. In 2000, the amount was $700,750, which represented 6.0% of the consolidated total revenues. As of December 31, 2001, Royale Energy holds working interests in 69 gas wells in California, with locations ranging from Tehama County in the north to Kern County in the south.
Royale Energy’s business does not depend on a single customer or a few customers and Royale Energy’s management does not believe this will change in the foreseeable future. Oil and natural gas purchasers are readily available in today’s markets, and Royale Energy does not believe that the loss of any customer would materially affect its business or its ability to find ready purchasers for its oil and gas production at current market prices.
Natural gas demand and the prices paid for gas are seasonal. In recent years, natural gas demand and prices in Northern California have decreased during the fall and winter and risen in the spring and summer, reflecting increased electricity consumption. In the winter and spring of 2001, a gas shortage in Northern California caused dramatic rises in the price Royale Energy received for its gas production. The high prices in the first half of 2001 materially increased Royale Energy’s revenues from gas production and sales in that period Gas prices fell again in the summer of 2001. Discussions of a few natural gas price regulations, including price caps, have taken place at the state and federal levels. The fluctuations in gas prices and possible new regulations create uncertainty about whether Royale Energy can continue to produce gas for a profit. Royale Energy does not expect natural gas prices to return to their winter 2001 levels in the foreseeable future.
Affiliated Entities
On December 31, 2001, Royale Petroleum Corporation (“RPC”) owned 31.5% of Royale Energy’s Common Stock (including rights to purchase shares pursuant to warrants). RPC is owned equally by Donald H. Hosmer and Stephen M. Hosmer, who are brothers. Donald H. Hosmer is president and director of Royale Energy, and Stephen Hosmer is chief financial officer and director of Royale Energy. Donald H. and Stephen M. Hosmer are sons of Harry E. Hosmer, chairman of Royale Energy’s board of directors. See, Security Ownership of Certain Beneficial Owners and Management on page 21. RPC is a predecessor and affiliate of Royale Energy. RPC is a Delaware corporation formed in 1985.
Royale Energy had no subsidiaries at December 31, 2001.
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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. Many 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 produced 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.
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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.
Since 1993, Royale Energy has concentrated on development of properties in the Sacramento Basin and the San Joaquin Basin of Northern California. In 2001, Royale Energy drilled eleven wells in northern California, eight of which are currently commercially productive wells. There are nine shut-in wells that Royale Energy plans to return to production. In 2001, Royale Energy performed perforating programs in three wells to recover gas reserves that were previously unrecoverable. There are plans to perforate four other wells to recover gas.
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.
In December of 2000, Royale Energy entered into an agreement with BankOne, Texas, NA (“Bank One”), in which BankOne assumed the revolving line of credit that was originally extended to Royale Energy by Hibernia National Bank. Under the terms of the agreement, from time to time, Royale Energy may borrow, repay, and reborrow money from Bank One 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 initial maximum allowable amount was $6,000,000. At December 31, 2001, Royale Energy owed $2,000,000 under this credit line. In January 2003, Royale Energy replaced its Bank One credit line with a credit agreement from Guaranty Bank, FSB, which assumed the revolving line of credit from BankOne, on substantially similar terms.
Following is a discussion of Royale Energy’s significant oil and natural gas properties. Reserves at December 31, 2001, 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 6, 2002 (the most recent report available).
Royale Energy owns lease interests in 12 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 northern California. At December 31, 2001, Royale Energy operated 69 wells in Northern California, and its estimated total proved developed and undeveloped gas reserves in Northern California were approximately 13.2 Bcf, according to Royale Energy’s independently prepared reserve report.
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Developed and Undeveloped Leasehold Acreage
As of December 31, 2001, Royale Energy owned leasehold interests in the following developed and undeveloped properties in both gross and net acreage.
| Developed |
Undeveloped |
||||||||
|---|---|---|---|---|---|---|---|---|---|
| Gross Acres | Net Acres | Gross Acres | Net Acres | ||||||
| California | 15,817.56 | 11,582.27 | 1,027.65 | 913.39 | |||||
| All other States | 875.00 | 455.50 | 800.00 | 595.90 | |||||
| Total | 16,692.56 | 12,037.77 | 1,827.65 | 1,509.29 | |||||
The following table sets forth Royale Energy’s drilling activities during the years ended December 31, 1999, 2000, and 2001. All wells are located in the Continental U.S., in California, Texas, and Oklahoma.
| Year | Type of Well(a) | Gross Wells(b) | Net Wells(e) | |||
|---|---|---|---|---|---|---|
| Total | Producing(c) | Dry(d) | Producing(c) | Dry(d) | ||
| 1999 | Exploratory Developmental |
3 9 |
1 6 |
2 3 |
.4320 1.8156 |
.9653 1.0758 |
| 2000 | Exploratory Developmental |
2 7 |
2 6 |
-- 1 |
.4104 -- |
2.7971 .5295 |
| 2001 | Exploratory Developmental |
5 6 |
3 5 |
2 1 |
1.4311 .6682 |
1.8565 .6082 |
(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 is producing 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.
As of December 31, 2001, Royale Energy had 52 gross (30.57 net) currently producing natural gas wells.
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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.
| 2001 |
2000 |
1999 |
|||||
|---|---|---|---|---|---|---|---|
| NET VOLUME | |||||||
| Oil (Bbl) | 1,893 | 596 | 2,215 | ||||
| Gas (Mcf) | 1,371,286 | 1,161,513 | 1,331,887 | ||||
| Mcfe | 1,390,216 | 1,167,473 | 1,354,037 | ||||
| AVERAGE SALES PRICE | |||||||
| Oil (Bbl) | $ | 26.55 | $ | 23.59 | $ | 16.30 | |
| Gas (Mcf) | $ | 6.12 | $ | 5.32 | $ | 2.34 | |
| Net Production Costs &
Taxes |
$ | 1,266,245 | $ | 936,841 | $ | 896,321 | |
| Lifting Costs (per Mcfe) | $ | 0.91 | $ | 0.60 | $ | 0.49 | |
As of December 31, 2001, Royale Energy had proved developed reserves of 11,245 MMcf and total proved reserves of 13,161 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 8 Mbbl and total proved oil reserves of 8 Mbbl on the same properties.
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.
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.
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Additional data relating to Royale Energy’s oil and natural gas properties is disclosed in Supplemental Information About Oil and Gas Producing Activities (Unaudited), attached to Royale Energy’s Financial Statements, beginning on page F-1. The oil and natural gas reserve information disclosed in the supplement to the financial statements are based upon the reserve reports for the years ended December 31, 2001 and 2000, prepared by Royale Energy’s independent reserve engineering consultants.
Buck, et al., v. Royale Energy, et al., No. C 00-CV-1499-K (NLS), U.S. District Court, Southern District of California. On December 10, 1999, a group of 16 investors in drilling projects sponsored by Royale Energy from 1994 to 1998 filed suit against Royale Energy and certain of its officers and former officers in U.S. District Court for the Northern District of California, alleging fraud, negligent misrepresentation, breach of fiduciary duties and other related claims in connection with the sales of working interests in those projects. The complaint generally states that the defendants failed to adequately disclose the company’s track record regarding previously drilled wells and makes other general statements about misconduct which are not, in Royale Energy’s view, supported by specific factual allegations. The suit seeks an unspecified amount of damages, restitution of amounts the plaintiffs invested, and punitive damages. In July 2000, the court granted Royale Energy’s motion to transfer the case to the U.S. District Court for the Southern District of California. No discovery has been conducted in the case. No discovery has ever been conducted in the case since it was filed in December 1999. If the plaintiffs elect to pursue this case, Royale Energy will contend that the plaintiffs suffered no damages, that their claims are completely without merit and that the complaint fails to state a claim on which relief can be based.
Blue Star Resources, et al., v. Royale Energy, Inc., No. 49460, Superior Court of Tehama County, California. On October 12, 2001, Blue Star Resources, Inc. and others filed suit against Royale Energy for declaratory relief, money damages, and imposition of a constructive trust, seeking a working interest and drilling rights to certain properties covered by a joint operating agreement between plaintiffs and Royale Energy. The dispute is over whether plaintiffs failed to consent to drilling operations that resulted in a commercially productive well drilled by Royale Energy and thereby lost their rights to working interests in the well. The case is set for trial in January 2003. In March 2001, the court dismissed the plaintiffs’ motion for partial summary judgment. Royale Energy has sought leave of the court to file a partial summary judgment of its own. The Plaintiffs alleged money damages of more than $1,000,000.
No matters were submitted to a vote of security holders during the fourth quarter of 2001.
Since 1997 Royale Energy’s Common Stock has been traded on the Nasdaq National Market System under the symbol “ROYL.” As of December 31, 2001, 5,213,883 shares (after making
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adjustments for stock dividends paid after December 31, 2001) of Royale Energy’s Common Stock were held by approximately 2,800 shareholders. The following table reflects high and low quarterly sales prices from January 2000 through December 2001 (as adjusted for subsequent stock dividends).
| 1st Quarter | 2nd Quarter | 3rd Quarter | 4th Quarter | |||||
|---|---|---|---|---|---|---|---|---|
| High | Low | High | Low | High | Low | High | Low | |
| 2000 | 2.72 | 1.85 | 2.89 | 1.96 | 6.09 | 2.12 | 6.47 | 2.39 |
| 2001 | 6.85 | 4.78 | 18.26 | 5.70 | 14.95 | 5.83 | 8.26 | 3.50 |
On June 15, 2001, Royale Energy paid a 15% stock dividend to its security holders of record on May 25, 2001. All common shareholders received the dividend in common shares, equal to 15% of their share holdings as of the record date. The dividend also increased by 15%, the number of shares of common stock issuable on exercise of all outstanding warrants and options and on conversion of all outstanding preferred shares. As a result of the dividend, the number of outstanding common shares increased by 569,147 shares (not including shares that may be issued on the exercise of options and warrants and on the conversion of preferred stock).
On March 18, 2002, Royale Energy’s board of directors declared a 15% stock dividend to its security holders of record as of May 31, 2002. The dividend increased the number of shares of common stock outstanding and those issuable on exercise of all outstanding warrants and options and on conversion of all outstanding shares. The dividend increased the number of outstanding common shares by 655,959 shares to 5,029,473 shares (not including shares that may be issued on the exercise of options and warrants and on the conversion of preferred stock).
On May 18, 2003, Royale Energy’s board of directors announced a stock dividend payable to holders of record in four installments of 3.75% each to holders of record on the last day of June 30, September 30, and December 31, 2003, and March 31, 2004. The first of these dividends was paid on June 30, 2003, and increased the number of outstanding shares by 191,652 shares to 5,221,753 shares (not including shares that may be issued on the exercise of options and warrants and on the conversion of preferred stock).
Royale Energy sold no equity securities in the fourth quarter of 2001.
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 seven years, Royale Energy has primarily acquired and developed producing and non-producing natural gas properties in Northern California. The most significant factors
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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.
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 30% 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 oil and gas.
Revenue Recognition
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 the well is spudded (begun). Occasionally, spudding is delayed due to the permitting process, or drilling rig availability. At June 30, 2002 and December 31, 2001, Royale Energy had deferred drilling revenue of $1,890,675 and $2,740,991, respectively. Gross profit from this line of business declined from 54% in the fiscal year ended December 31, 2001, to 37% in the nine months ended September 30, 2002.
The second business segment is oil and gas production. Over 80% of Royale Energy’s successful wells produce gas in Northern California. Natural gas flows from the wells into gathering line systems, which are equipped occasionally with compressor systems, which in turn flow into metered customer pipelines. Monthly, customers measure and price gas flows and compute the compensation due to Royale Energy and other working interest owners. Royale Energy operates virtually all of its own wells and receives industry approved operator fees.
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.
The successful efforts 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
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judgment determinations. 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 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 No. 121 (SFAS 121) “Accounting for the Impairment of Long-Lived Assets and for the Long-Lived Assets to Be Disposed Of.” 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 currently charged to expense.
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 reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts attributable to events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax credit carry forwards. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
Results of Operations for the Twelve Months Ended December 31, 2001, as Compared to the Twelve Months Ended December 31, 2000
For the year ended December 31, 2001, Royale Energy achieved a net profit of $3,746,524, a $945,533 or 33.8% increase over the net profit of $2,800,991 achieved during the year in 2000. Royale Energy’s management attribute this to an increase in oil and gas sales resulting from increased production and higher natural gas prices, and an increase in turnkey drilling revenues. Total revenues for the year ended December 31, 2001 were $15,858,273, a $4,170,921 or 35.7% increase from the total revenues in 2000 of $11,687,352, again as a result of higher turnkey drilling revenues and natural gas sales. For the year in 2001, Royale Energy’s net operating profit was $4,171,514, an increase of $864,765 or 26% over the net operating profit of $3,306,749 during the year in 2000.
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Oil and gas revenues for the year ended December 31, 2001, were $8,452,282 compared to $6,194,451 for the same period in 2000, which represents a $2,257,831 or 36.5% increase. This increase in revenues was mainly due to an increase in production and price Royale Energy received for its natural gas production during the year in 2001. The net sales volume for the year ended December 31, 2001, was 1,371,286 Mcf with an average price of $6.12 per Mcf, versus 1,161,513 Mcf with an average price of $5.32 per Mcf for 2000, which represents an increase in net sales volume of 209,773 Mcf or 18.1%. The net sales volume for oil and condensate (natural gas liquids) production was 1,893 barrels with an average price of $26.55 per Bbl for the period ended December 31, 2001, compared to 596 barrels at an average price of $23.59 per Bbl for the same period in 2000, which represents an increase in net sales volume of 1,297 barrels or 217.6%.
Royale Energy’s oil and gas lease operating expenses increased by 35.2% or $329,404, to $1,266,245 for the year ended December 31, 2001, from $936,841 for the same period in 2000. This can be attributed to the increase in the number of wells operated by Royale Energy during the year in 2001 when compared to 2000, due to the wells drilled and placed into production during 2000 and 2001. For 2001, Royale Energy’s gross margin on oil and gas production (excluding drilling and development costs) was 85%, compared to 84.9% in 2000.
For the year ended December 31, 2001, turnkey drilling revenues increased $1,911,301, to $6,703,452 in 2001 from $4,792,151 in 2000, or 39.9% for the year. Royale Energy also experienced a $1,090,505 or 55.2% increase in turnkey drilling and development costs from $1,975,242 in 2000 to $3,065,747 in 2001. This increase in turnkey revenues and costs was due to the drilling of more wells and higher drilling costs per well during the year in 2001 when compared to 2000.
Royale Energy’s 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. Costs associated with contract drilling depend on location, well depth, weather, and availability of drilling contractors and equipment. Royale Energy’s gross margin on drilling was 54.3% and 58.8% for the years ended December 31, 2001 and 2000, respectively.
Royale Energy’s aggregate of supervisory fees and other income was $702,539 for the year ended December 31, 2001, an increase of $1,789 (.26%) from $700,750 during 2000. 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, Public Accountants. Supervisory fees increased $27,537 or 7.9%, from $350,371 in 2000 to $377,908 in 2001.
In fiscal 2001, Royale Energy restated its 1997 – 2000 financial statements because it changed the method of reviewing for impairment of proved oil and gas properties from a region by region to field by field basis. When the impairment analysis method was changed, Royale Energy determined to write off certain oil and gas properties in 1998, 1999 and 2000 because their expected future net cash flows on a field basis were less than the net book value, though the future net cash flows in the region where they were located had previously been viewed as
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supporting a higher value when taken as a whole. The impairment change caused restatements reducing income in each of these years, as described in Note 2, Restatements, of our financial statements. These restatements reduced the depreciation, depletion and amortization expenses we reported for 2000.
Impairment losses of $2,062,028 and $1,540,845 were recorded in 2001 and 2000, respectively. 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 an 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.
Effective December 31, 1998, Royale Energy began to perform a periodic review for impairment on a region by region basis, and our annual reports for the fiscal years ended December 31, 1998, 1999 and 2000 reflected this impairment procedure. In 2001, after the Royale Energy filed its annual report for December 31, 2000, the company determined that it is more appropriate to conduct the impairment analysis on a field by field basis. When the impairment analysis method was changed, Royale Energy determined to write down certain proved oil and gas properties in 1998, 1999 and 2000 because their expected future net cash flows on a field basis were less than the net book value, though the future net cash flows in the region where they were located previously had been viewed as supporting a higher value when taken as a whole. This resulted in a restatement that increased the amount of impaired properties in 1998, 1999, and 2000, and in the additional impairment of properties in 2001. See, Note 2, Restatements, to our financial statements.
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 are assessed periodically on the basis of the lowest available unit, either field by field or property-by-property as appropriate, 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.
Depreciation, depletion and amortization expense increased to $1,282,640 from $846,051, an increase of $436,589 (51.6%) for 2001, compared to 2000. The depletion rate increased from 8.37% in 2000 to 10.85% in 2001, as a result of increased production. This increased the amount of depletion. In addition, the depletable basis or our proven oil and gas properties increased from 2000 to 2001.
This Amendment No. 2 to the Form 10-KSB for 2001 also restates the amount of depreciation, depletion and amortization expense for 2000, increasing it from $586,907 to $846,051, a
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$309,069 increase. The restatement is necessary because in Amendment No. 1, depreciation was incorrectly reduced when an adjustment for data library expenses was incorrectly deducted from this deprecation.
Royale Energy also reevaluated its inventory of geological lease and land costs, which had been previously capitalized, in order to write off those prospects which may be no longer viable. As a result, $56,806 of previously capitalized costs were written off and recorded as geological and geophysical expense during 2001 compared with $22,337 written off in 2000, a $34,469 or 154.3% increase.
General and administration expenses increased by $508,580, or 29.3%, from $1,737,201 for the year ended December 31, 2000 to $2,245,781 for the same period in 2001. We attribute the increase to higher employee salary costs and related expenses, and management bonuses paid in 2001. We also had an increase in fees related to our bank credit line. Legal and accounting expense increased to $644,812 for the year, compared to $635,893 for 2000, an $8,919 (1.4%) increase. The increase can be attributed to the higher litigation costs during the year in 2001 when compared to 2000. Marketing expense for the year ended December 31, 2001, increased $376,507 or 54.9%, to $1,062,700, compared to $686,193 for 2000. Royale Energy’s marketing expense varies from period to period according to the number of marketing events attended by personnel and associated travel costs.
During the year in 2000, Royale Energy extended an existing credit line from a major commercial bank. Because of a marked decrease in borrowings pursuant to this credit line, interest expense decreased to $54,455 for the year ended December 31, 2001, from $427,304 for the same period in 2000, a $372,849 or 87.3% decrease.
At December 31, 2000, Royale Energy had current assets totaling $9,055,604 and current liabilities totaling $8,275,108, a $780,496 working capital reserve. 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 enough of the working interest in a prospect to third parties to assure that we have sufficient funds on hand 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. We have only negligible capital expenditure needs in addition to those needs that are satisfied from 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 any capital expenditure needs that are not satisfied from sales of working interests.
We ordinarily fund our operations and cash needs from current revenues from operations. We receive a large percentage of the revenue generated by our sales of working interests to third parties during the fourth quarter of each year, 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
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believe that we have sufficient liquidity for the remainder of 2001 and do not foresee any liquidity demands that cannot be met from cash flow from operations.
Occasionally we borrow from banks, using our oil and gas properties as security. We usually borrow for the purpose of acquiring oil and gas properties. We have repaid such borrowings from operating income.
At the end of 2000, our accounts receivable totaled $6,407,397, compared to $1,745,408 at December 31, 1999, a $4,661,898 (267%) increase. Most of the increase in accounts receivable occurred during the fourth quarter of 2000. The vast majority of the increase in accounts receivable resulted from the sudden spike in gas prices at the end of 2000, which lasted through the first quarter of 2001. Some of the increase also occurred because of slower payments by our gas purchasers at the end of 2000. We view this increase in accounts receivable as temporary. Subsequently, in 2001, our accounts receivable decreased to $3,867,003 at March 31, 2001, and $2,921,527 at June 30, 2001. This decrease appears to be in line with the fall in gas prices in 2001. We have not experienced a long term increase in account payment problems from our gas purchasers.
In 2000, 2001 and 2002, we had a revolving line of credit under a loan agreement with Bank One, Texas, N. A. We had outstanding indebtedness under this agreement of $2,000,000 at December 31, 2001 and $3,750,000 at September 30, 2002. It was secured by all of our oil and gas properties. The loan agreement also contained 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:
| o |
maintain a minimum ratio of earnings before interest, taxes, depreciation and
amortizationto debt service requirements of at least 1.25 to 1.00; |
||
| o | maintain a ratio of current assets to current liabilities of at least 1.00 to 1.00; and | ||
| o | maintain a tangible net worth as of the close of each fiscal quarter of at least $6,086,850 as of September 30, 2000, plus 50% of positive quarterly net income thereafter. |
In January 2003, Royale Energy replaced the BankOne credit agreement with one from Guaranty Bank, FSB. The new credit agreement contains the same restrictive covenants as the prior agreement, except that the minimum tangible net worth requirement has been raised to at least $8,188,000 as of September 30,2002, plus 50% of positive quarterly net income thereafter. Royale Energy was in compliance with all covenants at January 31, 2003.
Operating Activities. For the year ended December 31, 2001, cash provided by operating activities totaled $7,705,142 or $1.85 per basic share compared to $3,415,118 or $0.82 per basic share provided by operations for 2000 which represents a $4,290,024 or 125.6% increase. This increase in cash provided in 2001 can be mainly attributed to increased oil and gas sales during the year in 2001.
Investing Activities. Net cash used by investing activities, primarily in capital acquisitions of oil and gas properties, amounted to $3,728,035 for the period in 2001, compared to $2,234,845 used by investing activities for 2000. The increase in cash used by investing activities can be
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primarily attributable to the drilling of eleven wells during the year in 2001 versus the drilling of nine wells during the year in 2000.
Financing Activities. Net cash used by financing activities for the year ended December 31, 2001, was $2,952,089, compared to cash used by financing activities during the year in 2000 of $90,411. The increase in net cash used by financing activities was mainly due to the decrease in the use of Royale Energy’s credit facility during the period in 2001 when compared to 2000.
See, pages F-1, et seq., included herein.
Listed below is certain information about Royale Energy’s current directors and executive officers. Directors are elected by shareholders at each annual shareholders’ meeting and serve until their successors are elected and qualified. Officers serve at the discretion of the board of directors.
The following persons currently serve as the directors and executive officers of Royale Energy, its subsidiaries and affiliated companies.
| Name | Age | First Became
Director or Executive Officer |
Positions Held |
|---|---|---|---|
| Harry E. Hosmer* | 71 | 1986 | Chairman of the Board |
| Donald H. Hosmer+ | 48 | 1987 | President, Secretary and Director
Chairman of the Board and President of Royale Petroleum Corporation ("RPC") |
| Stephen M. Hosmer+ | 35 | 1996 | Chief Financial Officer and Director
Secretary and Director of RPC |
| Oscar A. Hildebrandt*+ | 66 | 1995 | Director |
| Rodney Nahama | 70 | 1994 | Director |
| Gilbert Kemp | 68 | 1998 | Director |
| George M. Watters*+ | 82 | 1991 | Director |
* Member of the audit
committee.
+ Member of the compensation
committee.
Following is a summary of the business experience of each director and executive officer for the past five years.
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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. In October 1985, Mr. Hosmer and his sons founded Royale Petroleum Corporation, an affiliate of 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 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 for Royale Energy. In 1996, he was elected to the board of directors of Royale Energy. Mr. Hosmer serves on the board of directors of Youth for Christ, a charitable organization in San Diego, California. 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.
OSCAR HILDEBRANDT, D.V.M., is a Director and is Chairman of Royale Energy’s Compensation Committee. 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 currently manages the California operations of Western Atlas, Inc., a New York Stock Exchange company. 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
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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.
Section 16(a) of the Securities Exchange Act of 1934 and Securities and Exchange Commission regulations require that Royale Energy’s directors, certain officers, and greater than 10 percent shareholders file reports of ownership and changes in ownership with the SEC and the NASD and furnish Royale Energy with copies of all such reports they file. One director, Harry E. Hosmer, filed a late report on Form 5 of his reacquisition of 392,500 shares of Royale Energy’s common stock from two charitable trusts in May 2000.
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 2001.
The following table summarizes the compensation of the chief executive officer and the other most highly compensated executive officers of Royale Energy and its subsidiaries during the past year.
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| Annual Compensation | Long Term Compensation | ||||
|---|---|---|---|---|---|
|
(a) Name |
(b) Year |
(c) Salary |
(d) Bonus |
(e) Other Annual Compensation1 |
(i) All Other Compensation2 |
| Donald Hosmer | 2001 | $143,289 | $ 50,000 | $2,541 | $4,000 |
| President | 2000 | $135,046 | $ 10,000 | $ 653 | $2,400 |
| 1999 | $135,046 | $ 415 | $2,400 | ||
| Stephen Hosmer | 2001 | $119,656 | $ 50,000 | $1,757 | $3,500 |
| CFO | 2000 | $112,539 | $ 10,000 | $ 630 | $3,300 |
| 1999 | $112,539 | $ 321 | $3,300 | ||
Royale Energy does not have employment agreements with any of its executives.
Royale Energy did not grant any stock options or stock appreciation rights or Long-Term Incentive Plan Awards to its officers or employees during 2001.
None of the executive officers named in the Summary Compensation Table exercised any stock options or stock appreciation rights in 2001, 2000, or 1999. The following table summarizes the number and value of all unexercised stock options held by those executive officers at the end of 2001.
_________________
1 Under the terms of a plan adopted by the board of directors in 1989, each of the listed executives has elected to participate in wells drilled by Royale Energy. See, Certain Relationships and Related Transactions on page 23. The costs that they incurred for interests acquired in wells pursuant to this policy are less than would have been the cost of purchasing an equivalent percentage as working interests in these wells which are sold to unaffiliated outside investors. The difference between the executives’ actual cost and the cost incurred by outside investors could be considered as additional compensation to them. However, Royale Energy’s management does not believe that the amount of such difference is significant. In addition, prior to June 1995, Royale Energy advanced funds to the executives to pay for their well participation interests. To the extent that the advances amount to interest free loans, the executives could also be considered to have received additional compensation. The Other Annual Compensation in the foregoing table consists of the amounts which the management believes may be considered income to be imputed from such foregone interest. The imputed interest was estimated using approximate amounts due at the end of each period, as if that amount had been due for the entire period. Royale Energy used the imputed interest rate of 7% simple interest per annum. In June 1995, Royale Energy’s policy regarding advancement of funds was changed. The current policy requires that all such purchases of interests in wells must be paid in cash.
2 Includes Royale Energy’s matching contribution in 2001 for Donald Hosmer ($4,000) and Stephen Hosmer ($3,500) to Royale Energy’s retirement savings plan initiated in April 1998. For year ending 2000, includes matching contribution for Donald Hosmer ($2,400) and Stephen Hosmer ($3,300) and for the year ending 1999, includes matching contribution for Donald Hosmer ($2,400) and Stephen Hosmer ($3,300).
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| (a) | (b) | (c) | (d)
Number of Securities Underlying Unexercised Options/SARs at FY-End (1) |
(e) Value of Unexercised In-the- Money Options/SARs at FY- End (2) |
||
|---|---|---|---|---|---|---|
| Name | Shares
Acquired on Exercise |
Value
Realized |
Exercisable | Unexercisable | Exercisable | Unexercisable |
| Donald Hosmer, |
||||||
| President | 0 | $0 | 20,581 | 0 | $69,019 | $0 |
| Stephen Hosmer, | ||||||
| CFO | 0 | $0 | 13,721 | 0 | $46,014 | $0 |
(1) The number and price of shares has been adjusted for stock dividends distributed after December 31, 2003.
(2) Based on a fair market value of $5.54 per share, which was the closing bid price of Royale Energy’s Common Stock in the Nasdaq National Market System on Friday, December 29, 2001 (as adjusted for stock dividends distributed after December 31, 2001).
Each director who is not an employee of Royale Energy receives a quarterly fee for his services, which in 2001 was set at $2,500. 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 2001.
The following tables set forth certain information regarding the ownership of Royale Energy’s voting securities as of December 31, 2001, 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 shareholder identified in the table possesses sole voting and investment power with respect to its or his shares.
On December 31, 2001, 5,213,883 shares of Royale Energy’s Common Stock were outstanding, as adjusted for stock dividends distributed after December 31, 2001. All share figures in the following table were adjusted to account for the dividends distributed after December 31, 2001.
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| Shares Owned(1) |
|||
|---|---|---|---|
| Shareholder(2) | Number | Percent | |
| Donald H. Hosmer | 896,029 | (3),(4) | 16.62% |
| Harry E. Hosmer | 530,046 | (4),(5) | 10.06% |
| Oscar A. Hildebrandt | 56,835 | (6 | 1.08% |
| Stephen M. Hosmer | 889,388 | (3),(4) | 16.51% |
| Gilbert C. L. Kemp | 6,860 | Less than 1% | |
| Rodney Nahama | 19,209 | Less than 1% | |
| George M. Watters | 41,163 | Less than 1% | |
| All directors and officers
as a group (7 persons) |
2,799,666 | (3) | 49.05% |
(1) Includes shares which the listed shareholder has the right to acquire before March 1, 2001, from options or warrants, as follows: Royale Petroleum Corporation 316,343, Donald H. Hosmer 20,581, Harry E. Hosmer 54,884, Stephen M. Hosmer 13,721, Oscar Hildebrandt 27,442, Rodney Nahama 19,209, George M. Watters 41,163, and all officers and directors as a group (excluding Royale Petroleum Corporation) 177,000.
(2) The mailing address of each listed shareholder is 7676 Hazard Center Drive, Suite 1500, San Diego, California 92108.
(3) The shares owned by Donald and Stephen Hosmer each include shares owned by Royale Petroleum Corporation (“RPC”). RPC owns 1,748,152 shares (31.61%) of Royale Energy. Donald and Stephen Hosmer each own and have power to vote 50% of RPC’s equity securities, so each of them may be deemed to be the beneficial owner of the Common Stock owned by RPC pursuant to Rule 13d-3 promulgated under the Securities Exchange Act of 1934, as amended. To illustrate the relative economic and voting interests owned by the directors, the above table attributes 50% (732,594) shares of the Royale Energy shares owned by RPC to each of Donald and Stephen Hosmer. The total number of Royale Energy shares owned by RPC (1,748,152 shares) are included in the number of shares both Donald and Stephen Hosmer own and in the number of shares owned by all officers and directors as a group.
(4) Donald H. and Stephen M. Hosmer are sons of Harry E. Hosmer, Chairman of the Board.
(5) Includes shares held by two family trusts of which Harry. E. Hosmer and his wife are beneficiaries.
(6) Includes shares held by a family partnership of which Dr. Hildebrandt is a 50% partner and shares held by a trust of which Dr. Hildebrandt is trustee.
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Holders of each series of Convertible Preferred Stock have voting rights equal to the number of shares into which they are convertible. None of the Preferred shareholders have the right to vote as much as 5% of the shares entitled to vote when taking into account the total number of both Common and Preferred shares. On December 31, 2001, there were 10,780 shares of Series A and 43,125 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. To Royale Energy’s knowledge, none of the Preferred shareholders would own more than 1% of Royale Energy’s Common Stock, if their Preferred shares were converted to Common shares.
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, 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 do not pay a set, turnkey price (as do outside investors who purchase undivided working interests from Royale Energy), but they are liable for 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. Thus, they participate on terms similar to other oil and gas industry participants or joint venturers. Participants are invoiced for their share of direct costs of drilling and completion as Royale Energy incurs expenses.
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 67 wells under the 1989 policy. The Hosmer Trust, a trust for the benefit of family members of Harry E. Hosmer, has participated in 66 wells.
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Donald Hosmer’s 2001 investments in wells under the 1989 policy totaled $23,092 in fractional interests in 11 wells. In 2001, Stephen Hosmer purchased fractional interests in 11 wells under the 1989 policy, for a total investment of $21,466.
The Hosmer Trust purchased .003% interest in 11 wells during 2001 for a total investment of $21,794.
Prior to June 1995, Royale Energy had advanced to the participants under the 1989 policy the funds with which to purchase their interests, and the funds would be repaid from future production from the working interests and advances repaid from well production.
Each month, participants are credited with well income and charged with well expenses from producing wells, at the same time as other investors including working interest purchasers. Each officer and director who participates in one or more wells with Royale Energy has a single account to which all charges and income from all wells is credited. In June 1995, Royale Energy changed its policy regarding the advancement of funds. Current policy requires that all such purchases of interests in wells must be paid in cash. At December 31, 2001, the following executive officers and their affiliates owed the following amounts on advances for well participations: Donald Hosmer $43,501; Stephen Hosmer $28,972; RPC $527; the Hosmer Trust $93,851.
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 $120,000 annually for his consulting services in 2001 and pays his medical insurance costs. Mr. Hosmer’s consulting services are in addition to his service on the board of directors, for which he receives no compensation other than reimbursement of expenses to attend meetings.
| (a) | Certain of the Exhibits set forth 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 |
-23-
| 10.1 | Form of Indemnification Agreement, incorporated by reference to Exhibit 10.3 of Royale
Energy's Form 10-SB Registration Statement |
| (b) | Reports on Form 8-K |
| Royale Energy filed no Reports on Form 8-K during the last fiscal quarter of 2001 |
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.| ROYALE ENERGY, INC. | |||
| Date: December 11, 2003 | Stephen M. Hosmer
Stephen M. Hosmer, Executive Vice President and Chief Financial Officer |
-24-
| Index to Financial Statements | F-1 |
| Report of Brown Armstrong Paulden McCown Starbuck & Keeter, Independent Auditors | F-2 |
| Balance Sheets at December 31, 2001 and 2000 | F-3 |
| Statements of Income for the Years Ended December 31, 2001 and 2000 | F-4 |
| Statements of Stockholders' Equity for the Years Ended December 31, 2001 and 2000 | F-5 |
| Statements of Cash Flows for the Years Ended December 31, 2001 and 2000 | F-6 |
| Notes to the Financial Statements | F-7 |
| Supplemental Information About Oil and Gas Producing Activities (Unaudited) | F-21 |
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.
F-1
Shareholders and Board of
Directors
Royale Energy, Inc.
We have audited the accompanying balance sheets of Royale Energy, Inc. (a California corporation) as of December 31, 2001 and 2000, and the related statements of income, stockholders’ equity and cash flows for the years then ended. These financial statements are the responsibility of Royale Energy’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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, 2001 and 2000, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
BROWN
ARMSTRONG PAULDEN
McCOWN
STARBUCK & KEETER
ACCOUNTANCY
CORPORATION
Bakersfield, California
January 27, 2003
F-2
ASSETS
| 2001 |
2000 |
|||||||
|---|---|---|---|---|---|---|---|---|
| Current Assets | ||||||||
| Cash and cash equivalents | $ | 3,131,859 | $ | 2,106,841 | ||||
| Accounts receivable | 3,525,038 | 6,480,407 | ||||||
| Other current assets | 695,461 |
468,356 |
||||||
| Total Current Assets | 7,352,358 | 9,055,604 | ||||||
| Oil and Gas Properties (successful efforts basis), Equipment | ||||||||
| and Fixtures, net | 12,226,001 |
11,719,436 |
||||||
| $ | 19,578,359 |
$ | 20,778,040 |
|||||
| LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||||
| Current Liabilities | ||||||||
| Accounts payable and accrued expenses | $ | 3,543,001 | $ | 6,639,808 | ||||
| Deferred revenue from turnkey drilling | 2,740,991 |
1,635,300 |
||||||
| Total Current Liabilities | 6,283,992 |
8,275,108 |
||||||
| Long-Term Debt, net of current portion | 2,000,000 |
4,952,089 |
||||||
| Redeemable Preferred Stock | ||||||||
| Series A, convertible preferred stock, no par value, 59,250 shares | ||||||||
| authorized; 12,445 and 12,445 shares issued and outstanding | 30,140 |
30,140 |
||||||
| Stockholders' Equity | ||||||||
| Common stock, no par value, 10,000,000 shares authorized; | ||||||||
| 5,213,883 and 5,210,289 shares issued and outstanding, | ||||||||
| respectively | 17,687,905 | 17,662,905 | ||||||
| Convertible preferred stock, Series AA, no par value, 147,500 | ||||||||
| shares authorized; 51,409 and 58,596 shares issued and | 205,152 | 230,152 | ||||||
| outstanding | ||||||||
| Accumulated (deficit) | (6,501,524 |
) | (10,248,048 |
) | ||||
| Total paid in capital and accumulated deficit | 11,391,533 | 7,645,009 | ||||||
| Less cost of treasury stock, 26,000 shares | (127,306 |
) | (127,306 |
) | ||||
| Total Stockholders' Equity | 11,265,227 |
7,517,703 |
||||||
| $ | 19,578,359 |
$ | 20,775,040 |
|||||
F-3
The accompanying notes are an integral part of these financial statements.
| 2001 |
2000 As Restated |
|||||||
|---|---|---|---|---|---|---|---|---|
| Revenues | ||||||||
| Oil and gas production | $ | 8,452,282 | $ | 6,194,451 | ||||
| Turnkey drilling | 6,703,452 | 4,792,151 | ||||||
| Supervisory fees and other | 702,539 |
700,750 |
||||||
| Total Revenues | 15,858,273 |
11,687,352 |
||||||
| Costs and Expenses | ||||||||
| General and administrative | 2,245,781 | 1,737,201 | ||||||
| Geological and geophysical expense | 56,806 | 22,337 | ||||||
| Turnkey drilling and development | 3,065,747 | 1,975,242 | ||||||
| Lease operating | 1,266,245 | 936,841 | ||||||
| Lease impairment | 2,062,028 | 1,540,845 | ||||||
| Legal and accounting | 644,812 | 635,893 | ||||||
| Marketing | 1,062,700 | 686,193 | ||||||
| Depreciation, depletion and amortization | 1,282,640 |
895,976 |
||||||
| Total Costs and Expenses | 11,686,759 |
8,430,528 |
||||||
| Income from Operations | 4,171,514 | 3,256,824 | ||||||
| Other Expense | ||||||||
| Interest expense | 54,455 |
427,304 |
||||||
| Income Before Income Tax Expense | 4,117,059 | 2,829,520 | ||||||
| Income Tax Provision | 370,535 |
78,454 |
||||||
| Net Income | $ | 3,746,524 |
$ | 2,751,066 |
||||
| Basic Earnings Per Share | $ | 0.72 |
$ | 0.53 |
||||
| Diluted Earnings Per Share | $ | 0.68 |
$ | 0.50 |
||||
F-4
The accompanying notes are an integral part of these financial statements.
| Common Stock | Preferred Stock Series AA | Treasury Stock | |||||
|---|---|---|---|---|---|---|---|
| Shares Outstanding |
Amount | Shares Outstanding |
Amount | Accumulated Deficit |
Shares Outstanding |
Amount | |
| Balance at January 1, 2000, | |||||||
| as restated | 5,205,289 | $17,655,405 | 58,596 | $ 230,152 | $(12,999,114) | 26,000 | $(127,306) |
| Shares issued | 5,000 | 7,500 | |||||
| Net income for the year | -- | -- | -- | -- | 2,751,066 | -- | -- |
| Balance at December 31, 2000, as restated |
5,210,289 | 17,662,905 | 58,596 | 230,152 | (10,248,068) | 26,000 | (127,306) |
| Conversion of Preferred AA to | |||||||
| common stock | 3,594 | 25,000 | (7,187) | (25,000) | -- | -- | -- |
| Net income for the year | -- | -- | -- | -- | 3,746,524 | -- | -- |
| Balance at December 31, 2001 | 5,213,883 | $17,687,905 | 51,409 | $ 205,152 | $(6,501,524) | 26,000 | $(127,306) |
F-5
The accompanying notes are an integral part of these financial statements
| 2001 |
2000 As Restated |
|||||||
|---|---|---|---|---|---|---|---|---|
| CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||
| Net income | $ | 3,746,524 | $ | 2,751,066 | ||||
| Adjustment to reconcile net income to net cash | ||||||||
| provided by operating activities: | ||||||||
| Depreciation, depletion and amortization | 1,282,640 | 895,976 | ||||||
| Lease impairment | 2,062,028 | 1,540,845 | ||||||
| (Increase) decrease in: | ||||||||
| Accounts receivable | 2,955,369 | (4,650,337 | ) | |||||
| Prepaid expenses and other assets | (227,105 | ) | (78,766 | ) | ||||
| Increase (decrease) in: | ||||||||
| Accounts payable and accrued expenses | (3,096,807 | ) | 2,785,649 | |||||
| Deferred revenues - DWI | 1,105,691 |
170,685 |
||||||
| Net Cash Provided by Operating Activities | 7,828,340 |
3,415,118 |
||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||
| Expenditures for oil and gas properties | (3,267,284 | ) | (2,234,845 | ) | ||||
| Other capital expenditures | (583,949 |
) | -- |
|||||
| Net Cash Provided (Used) by Investing Activities | (3,851,233 |
) | (2,234,845 |
) | ||||
| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||
| Principal payments on long-term debt | (4,952,089 | ) | (5,050,000 | ) | ||||
| Proceeds from long-term debt | 2,000,000 | 4,952,089 | ||||||
| Common stock issued | -- |
7,500 |
||||||
| Net Cash Provided (Used) by Financing Activities | (2,952,089 |
) | (90,411 |
) | ||||
| Net Increase in Cash and Cash Equivalents | 1,025,018 | 1,089,862 | ||||||
| Cash at beginning of year | 2,106,841 |
1,016,979 |
||||||
| Cash at end of year | $ | 3,131,859 |
$ | 2,106,841 |
||||
| SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: | ||||||||
| Cash paid for interest | $ | 54,455 |
$ | 427,304 |
||||
| Cash paid for taxes | $ | 533,661 |
$ | 800 |
||||
F-6
The accompanying notes are an integral part of these financial statements.
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 in California. Royale Energy offers fractional working interests and seeks to minimize the risks of oil and gas drilling by selling multiple well drilling ventures which do not include the use of debt financing.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles 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 Royale Energy 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, 2001 and 2000, 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 30% in 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, Royale Energy receives management 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 acquired by Royale Energy. 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 enter a signed contract with Royale Energy. In this agreement, the investor agrees to share in the pre-drilling costs, which include lease costs, intangible drilling 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 the well is spudded (begun). If costs exceed revenues and Royale Energy participates as a working interest owner, Royale Energy’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. If the drilling effort is successful, each investor receives a working interest in the wells, and Royale Energy, along with the investors, receive an assignment
F-7
of working interests. 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. 121, “Accounting for the Impairment of Long-Lived Assets and/or Long-Lived Assets to be Disposed of”, 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. 121 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 an 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 $2,062,028 and $1,540,845 were recorded in 2001 and 2000, 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 are 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.
Accounts Receivable
Management believes that all accounts receivable as of December 31, 2001 and 2000, are fully collectible. Therefore, no allowance for doubtful accounts is recorded.
F-8
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:
| For the Year Ended 2001 |
|||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Income (Numerator) |
Shares (Denominator) |
Per-Share Amount |
|||||||||
| Basic Earnings Per Share: | |||||||||||
| Net income available to common stock | $ | 3,746,524 | 5,212,091 | $ | 0 | .72 | |||||
| Diluted Earnings Per Share: | |||||||||||
| Effect of dilutive securities and stock options | -- |
279,988 |
(0 |
.04) |
|||||||
| Net income available to common stock | $ | |
3,746,524 |
5,492,079 |
$ | 0 |
.68 |
||||
|
For the Year Ended 2000 |
|||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Income (Numerator) |
Shares (Denominator) |
Per-Share Amount |
|||||||||
| Basic Earnings Per Share: | |||||||||||
| Net income available to common stock | $ | 2,751,066 | 205,837 | $ | 0 | .53 | |||||
| Diluted Earnings Per Share: | |||||||||||
| Effect of dilutive securities and stock options | -- |
272,729 |
( |
.03) |
|||||||
| Net income available to common stock | $ | |
2,751,066 |
5,478,566 |
$ | 0 |
.50 |
||||
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
F-9
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.
New Accounting Standards
In April 2000, the FASB issued Financial Interpretation Number (FIN) 44, Accounting for Certain Transactions Involving Stock Compensation — an Interpretation of Accounting Principles Board No. 25. FIN 44 clarifies the application of Opinion No. 25. This Interpretation was effective immediately and all issues are to be handled prospectively. The adoption of FIN 44 did not have a material impact on Royale Energy’s financial position or results of operations.
In June 2001, the Financial Accounting Standards Board (“FASB”) issued Statements of Financial Accounting Standards No. 141 “Business Combinations” (“SFAS 141”) and No. 142 “Goodwill and Other Intangible Assets” (“SFAS 142”). SFAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for under the purchase method. For all business combinations for which the date of acquisition is after June 30, 2001, SFAS 141 also establishes specific criteria for the recognition of intangible assets separately from goodwill. SFAS 141 also requires unallocated negative goodwill (in a case where the purchase price is less than fair market value of the acquired assets) to be written off immediately as an extraordinary gain, rather than deferred and amortized. SFAS 142 changes the accounting for goodwill and other intangible assets after an acquisition. The most significant changes made by SFAS 142 are: 1) goodwill and intangible assets with indefinite lives will no longer be amortized; 2) goodwill and intangible assets with indefinite lives must be tested for impairment at least annually; and 3) the amortization period for intangible assets with finite lives will no longer be limited to 40 years.
Goodwill and intangible assets acquired in business combinations completed before July 1, 2001 will continue to be amortized prior to the adoption of Statement No. 142. Statement No. 141 will require, upon adoption of Statement No. 142, that an entity evaluate its existing intangible assets and goodwill that were acquired in a prior purchase business combination, and to make any necessary reclassifications in order to conform with the new criteria in Statement No. 141 for recognition apart from goodwill. The adoption of Statement No. 142, did not have a material impact on Royale Energy’s financial position or results of operations.
In June 2001, the FASB also 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. SFAS 143 guidance covers (1) the timing of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to expense, (4) subsequent measurement of the liability, and (5) financial statement disclosures. SFAS 143 requires that an asset retirement cost should be capitalized as part of the cost of the related long- lived asset and subsequently allocated to expense using a systematic and rational method. Royale Energy will adopt the statement effective no later than January 1, 2003, as required. The transition adjustment resulting from the adoption of SFAS 143 will be reported as a cumulative effect of a change in accounting principle. At this time, Royale Energy cannot reasonably estimate the effect of the adoption of this statement on its financial position, results of operations or cash flows.
In August 2001, the FASB also approved SFAS 144, “Accounting for the Impairment of Disposal of Long-Lived Assets” (“SFAS 144”). SFAS 144 replaces SFAS 121, “Accounting for the Impairment of Long-Lived Assets to Bed Disposed Of.” The new accounting model for long-lived assets to be disposed of by sale applies to all long-lived assets, including discontinued operations, and replaces the provisions of APB Opinion No. 30, “Reporting Results of Operations-Reporting the Effects of Disposal of a Segment of a Business,” for the disposal of segments of a business. SFAS 144 requires that those long-lived assets be measured at the lower of carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued operations. Therefore, discontinued operations will no longer be measured at net realizable value or include amounts for operating losses that have not yet occurred. SFAS 144 also broadens the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. The provisions of SFAS 144 are effective for financial statements issued for fiscal years beginning after December 15, 2001 and, generally are to be applied prospectively. At this time, Royale Energy cannot estimate the effect of this statement on its financial position, results of operations, or cash flows.
F-10
Reclassification
Certain amounts in the financial statements have been reclassified to be consistent and comparable from year-to-year.
Change in Method of Reviewing for Impairment
Company management continually reviews its use of generally accepted accounting principles, and occasionally adjusts their selection of accounting principles to more realistic, conservative methods.
Effective January 1, 1998, the Company reinstated its method of reviewing for impairment of its oil and gas properties from a region by region basis to a field by field basis. The Company believes that evaluating impairment on a field by field is a better measure of impairment than the region by region basis, and is consistent with the practice of the majority of oil and gas companies in industry for evaluating impairment. Before 1998, the Company had used a field cost center impairment measure, and changed to a regional method for 1998, 1999, and 2000, and throughout the first three quarters of 2001. Significant downward revisions to reserves were realized due to this change. All of these reporting periods have been restated.
Change in Accounting for Other Capitalized Costs
Effective December 31, 1998, the Company changed its method of accounting for the costs of 3D Seismic studies performed by independent Geophysical and Geological companies on its behalf. Previously, the Company capitalized these costs as inventoriable expenditures recoverable by sale or by development. Portions of the database used for Company projects have been capitalized as part of the carrying costs of proved properties. The Company has had prospective buyers of this data in the past, but to date has not sold any portions of the data to outside parties.
The Company has evaluated whether it is appropriate to report these costs as inventoriable expenditures and has determined that in the absence of sales, these costs are more appropriately reported as exploration geological and geophysical to be expensed when incurred. Accordingly, the Company has restated its financial statements to reflect the effect of expensing these costs in 1998 when the database was originally acquired.
Change in Accounting for Other Capitalized Costs
The following tables reconcile the effects of the restatements for the fiscal years ended December 31, 1998, 1999 and 2000:
| 1998 |
1999 |
2000 |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Income from operations as previously reported | $ | 1,162,647 | $ | 535,709 | $ | 3,498,299 | |||||
| Effect of change in method of reviewing for impairment | (1,149,310 | ) | (596,495 | ) | (550,544 | ) | |||||
| Effect of change in accounting for other capitalized costs | (927,208 | ) | 309,069 | 309,069 | |||||||
| Income (Loss) from operations as restated | (913,871 | ) | 248,283 | 3,256,824 | |||||||
| Net Income as previously reported | 774,406 | 149,903 | 2,990,995 | ||||||||
| Effect of change in method of reviewing for impairment | (1,120,233 | ) | (596,495 | ) | (556,104 | ) | |||||
| Effect of change in accounting for other capitalized costs | (903,417 | ) | 309,069 | 316,175 | |||||||
| Net Income (Loss) as restated | (1,249,244 | ) | (137,623 | ) | 2,751,066 | ||||||
| Net Income per share (basic) as previously reported | 0.20 | 0.04 | 0.71 | ||||||||
| Effect of change in method of reviewing for impairment | (0.29 | ) | (0.16 | ) | (0.11 | ) | |||||
| Effect of change in accounting for other capitalized costs | (0.24 | ) | 0.08 | 0.06 | |||||||
| Effect of increase in outstanding shares due to stock dividends | -- | -- | (0.13 | ) | |||||||
| Net Income (Loss) per share (basic) operations as restated | (0.33 | ) | (0.04 | ) | 0.53 | ||||||
F-11
| Net Income (Loss) per share (diluted) as previously reported | 0 | .19 | 0 | .04 | 0 | .67 | |||||
| Effect of change in method of reviewing for impairment | (0 | .27) | (0 | .16) | (0 | .11) | |||||
| Effect of change in accounting for other capitalized costs | (0 | .22) | 0 | .08 | 0 | .06 | |||||
| Effect of increase in outstanding shares due to stock dividends | -- | -- | (0 | .12) | |||||||
| Net Income (Loss) per share (diluted) as restated | (0 | .30) | (0 | .04) | 0 | .50 | |||||
Oil and gas properties, equipment and fixtures consist of the following at December 31:
| 2001 |
2000 |
|||||||
|---|---|---|---|---|---|---|---|---|
| Oil and Gas | ||||||||
| Producing properties, including intangible drilling costs | $ | 9,189,884 | $ | 8,732,387 | ||||
| Undeveloped properties | 1,939,338 | 1,648,374 | ||||||
| Lease and well equipment | 4,563,115 |
4,677,700 |
||||||
| 15,692,337 | 15,058,461 | |||||||
| Accumulated depletion, depreciation and amortization | (3,701,773 |
) | (3,461,085 |
) | ||||
| 11,990,564 |
11,597,376 |
|||||||
| Commercial and Other | ||||||||
| Furniture and equipment | 597,977 | 436,713 | ||||||
| Accumulated depreciation | (362,540 |
) | (314,653 |
) | ||||
| 235,437 |
122,060 |
|||||||
| $ | 12,226,001 |
$ | 11,719,436 |
|||||
F-12
The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed:
| 2001 | 2000 | 1999 | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Acquisition | $ | 94,174 | $ | 919,472 | $ | 55,290 | |||||
| Development | $ | 2,552,193 | $ | 1,950,428 | $ | 3,683,456 | |||||
| Exploration | $ | 221,207 | $ | 602,438 | $ | 928,539 | |||||
Results of Operations from Oil and Gas Producing and Exploration Activities
The results of operations from oil and gas producing and exploration activities (excluding corporate overhead and interest costs) for the two years ended December 31, are as follows:
| 2001 |
2000 |
|||||||
|---|---|---|---|---|---|---|---|---|
| Oil and gas sales | $ | 8,452,282 | $ | 6,194,451 | ||||
| Production related costs | (1,266,245 | ) | (936,841 | ) | ||||
| Geological and geophysical expense | (56,806 | ) | (22,337 | ) | ||||
| Depreciation, depletion and amortization | (1,282,640 |
) | (895,976 |
) | ||||
| Results of operations from producing and exploration activities | $ | 5,846,591 |
$ | 4,339,297 |
||||
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, 2001 and 2000, Royale Energy had recorded deferred turnkey drilling revenue associated with undrilled wells of $2,740,991 and $1,635,300, respectively, as a current liability.
Royale Energy adopted SFAS No. 131, Disclosure About Segments of an Enterprise and Related Information in 1998 which changes the way Royale Energy reports information about its operating 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 2001 and 2000:
| Oil and Gas Producing and Exploration |
Turnkey Drilling Services |
Total
|
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Year Ended December 31, 2001 | |||||||||||
| Revenues from External Customers | $ | 8,452,282 |
$ | 6,703,452 |
$ | 15,155,734 |
|||||
| Supervisory Fees | $ | 604,736 |
$ | -- |
$ | 604,736 |
|||||
| Interest Revenue | $ | 97,803 |
$ | -- |
$ | 97,803 |
|||||
| Interest Expense | $ | 27,228 |
$ | 27,227 |
$ | 54,455 |
|||||
| Expenditures for Segment Assets | $ | 3,030,565 |
$ | 5,311,526 |
$ | 8,342,091 |
|||||
| Depreciation, Depletion, and Amortization | $ | 1,223,588 |
$ | 59,052 |
$ | 1,282,640 |
|||||
F-13
| Lease Impairment | $ | 1,031,014 |
$ | 1,031,014 |
$ | 2,062,028 |
|||||
| Income Tax | $ | 185,268 |
$ | 185,267 |
$ | 370,535 |
|||||
| Total Assets | $ | 19,578,359 |
$ | -- |
$ | 19,578,359 |
|||||
| Net Income | $ | 3,657,158 |
$ | 89,366 |
$ | 3,746,524 |
|||||
| Year Ended December 31, 2000 | |||||||||||
| Revenues from External Customers | $ | 6,194,451 |
$ | 4,792,151 |
$ | 10,986,602 |
|||||
| Supervisory Fees | $ | 668,361 |
$ | -- |
$ | 668,361 |
|||||
| Interest Revenue | $ | 32,389 |
$ | -- |
$ | 32,389 |
|||||
| Interest Expense | $ | 213,652 |
$ | 213,652 |
$ | 427,304 |
|||||
| Expenditures for Segment Assets | $ | 2,264,380 |
$ | 3,729,327 |
$ | 5,993,707 |
|||||
| Depreciation, Depletion, and Amortization | $ | 846,050 |
$ | 49,926 |
$ | 895,976 |
|||||
| Lease Impairment $ | 1,129,077 |
$ | 411,768 |
$ | 1,540,845 |
||||||
| Income Tax | $ | 38,454 |
$ | 40,000 |
$ | 78,545 |
|||||
| Total Assets | $ | 20,775,040 |
$ | -- |
$ | 20,775,040 |
|||||
| Net Income | $ | 2,403,588 |
$ | 347,478 |
$ | 2,751,066 |
|||||
| 2001 | 2000 | ||||
| Revolving line of credit secured by oil and gas properties, with a | |||||
| maximum available of $6,000,000 issued by Bank One Service Corporation | |||||
| for the purposes of refinancing Royale Energy's existing debt and to | |||||
| fund development, exploration and acquisition activities as well as | |||||
| other general corporate purposes. Agreement was entered into on | |||||
| December 1, 2002, payable monthly with borrowing base reductions of | |||||
| $100,000 commencing on February 1, 2001. All Unpaid principal and | |||||
| interest is payable at maturity on December 21, 2003 | $2,000,000 |
$4,952,089 |
|||
| $2,000,000 |
$4,952,089 |
||||
Under the terms of the agreement, the Company is required to have a positive net worth not less than $6,086,850, debt service coverage not less than 1.25:1; current ratio not less than 1:1, debt and lien restrictions, no changes in management without bank consent, and dividend and distribution restrictions. The Company was in compliance with the terms of this agreement at December 31, 2001.
Maturities of long-term debt for years subsequent to December 31, 2001 are as follows:
| Year Ended | |||
| December 31, | |||
| 2003 |
$ 2,000,000 |
||
F-14
The components of the net deferred tax assets were as follows:
| 2001 | 2000 | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Deferred Tax Assets: | |||||||||||
| Net operating loss carryforwards | $ | -- | $ | 1,812,536 | |||||||
| Statutory depletion carryforwards | 342,000 | 355,502 | |||||||||
| Total Deferred Tax Assets | 342,000 | 2,168,038 | |||||||||
| Valuation Allowance | (342,000 | ) | (2,168,038 | ) | |||||||
| Net Deferred Tax Assets | $ | -- |
$ | -- |
|||||||
Royale Energy has approximately $1,500,000 of unused statutory percentage depletion, eligible to be used by Royale Energy in future years to reduce federal taxable income. This depletion has no expiration date. A full valuation allowance has been established for the deferred tax assets generated by this depletion carryforward due to the uncertainty of future utilization.
A reconciliation of Royale Energy’s provision for income taxes and the amount computed by applying the U.S. statutory federal income tax rate of 34% at December 31, 2001 and 2000, respectively, to pretax income is as follows:
| 2001 | 2000 | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Tax computed at 34%, respectively | $ | 1,399,800 | $ | 1,044,388 | |||||||
| Increase (decrease) in taxes resulting from: | |||||||||||
| Net operating loss carryforwards used | (932,118 | ) | (1,044,388 | ) | |||||||
| State tax | 244,553 | 78,454 | |||||||||
| Percentage depletion carryforwards used | (341,700 | ) | -- | ||||||||
| $ | 370,535 | $ | 78,454 | ||||||||
| Effective Tax Rate | 9.0% |
3.0% |
|||||||||
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 shareholders with a one time 10% dividend payable thirty days after the expiration of one year from the date of purchase. The dividend has been paid on all outstanding shares at December 31, 1994.
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).
F-15
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 shareholders 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 shareholders’ rights and incentives in the Royale Energy Income Trust. As of December 31, 2001 and 2000, 224,815 shares of Series A Convertible Preferred Stock had been converted to 198,625 shares of common 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 shareholders’ option. As of December 31, 2001 and 2000, there were 56,780 and 49,593 shares issued and outstanding. The dividend has been paid on all shares outstanding at December 31, 2001 and 2000.
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. In addition, on March 26, 2001, the Board of Directors authorized a 15% stock dividend to shareholders of record on May 25, 2001. The number of common shares increased by 555,838 shares. The effect of the stock dividend decreased retained earnings (deficit) by $3,925,606. The Board also authorized a 15% stock dividend to shareholders 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. A 3.75% stock dividend was paid on June 30, 2003, which increased common shares by 187,879, resulting in a $1,016,425 decrease to retained earnings.
The financial statements have been retroactively restated to reflect these dividends.
Changes in Royale Energy’s common stock warrants were as follows at December 31:
| 2001 |
2000 |
||||
|---|---|---|---|---|---|
| Outstanding warrants at beginning of period | 230,555 | 230,555 | |||
| 15% Stock dividend | 34,583 | -- | |||
| Additional warrants issued | -- | -- | |||
| Exercise of stock warrants | -- | -- | |||
| Warrants expired or ineligible | -- |
-- |
|||
| Outstanding warrants at end of period | 265,138 |
230,555 |
|||
Royale Energy’s affiliate, RPC, acquired 111,111 shares of Royale Energy’s common stock during the year ended December 31, 1993, at a purchase price of $333,333. This transaction was pursuant to the exercise of a stock purchase warrant granted to RPC by Royale Energy’s Board of Directors on December 18, 1992, to purchase a maximum of 166,666 shares at the minimum bid price on December 18, 1992 of $3.00 per share. The expiration
F-16
date to purchase the remaining 55,555 additional shares pursuant to this grant has been extended through December 31, 2002.
At the November 3, 1993 Board of Directors meeting, the Board of Directors granted RPC additional warrants to purchase 175,000 shares of Royale Energy’s common stock at prices ranging from $1.50 to $3.00 per share. The expiration date of this grant has been extended through December 31, 2002.
Due to the declaration of the 15% stock dividend the number of warrants increased by 34,583, with a corresponding decrease in prices ranging from $2.60 to $1.35 per share.
Royale Energy occupies office space under a sixty-month noncancellable lease, which expires in July 2005. The lease calls for monthly payments ranging from $16,675 to $17,762. Future minimum lease obligations as of December 31, 2001 is as follows:
| Year Ended
December 31, |
|||||
|---|---|---|---|---|---|
| 2002 | $ | 201,913 | |||
| 2003 | 206,763 | ||||
| 2004 | 210,613 | ||||
| 2005 | 124,338 |
||||
| $ | 743,627 |
||||
Rental expense for the years ended December 31, 2001 and 2000, was $186,474 and $177,257, respectively.
Significant Ownership Interests
On December 31, 2001, 27.53% of Royale Energy’s common stock was owned by Royale Petroleum Corporation (RPC). RPC is owned equally by Donald H. Hosmer and Stephen M. Hosmer.
Harry E. Hosmer, Royale Energy’s former president and former chief executive officer, owns 10.50% of Royale Energy’s 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.
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 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.
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.
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 2001 or 2000.
F-17
On March 26, 2001, the number of remaining options of 99,000 increased to 113,850 outstanding and the price decreased from $1.90 per share to $1.65 per share due to the declaration of the 15% stock dividend.
A summary of the status of Royale Energy’s stock option plan as of December 31, 2001 and 2000, and changes during the years ending on those dates follows
| 2001 |
2000 |
||||||||
|---|---|---|---|---|---|---|---|---|---|
| Shares | Weighted- Average Exercise Price |
Shares | Weighted- Average Exercise Price |
||||||
| Fixed Options | |||||||||
| Outstanding at beginning of year | $129,000 | $1.87 | 134,000 | $2.15 | |||||
| 15% of Stocks dividend | 19,350 | -- | |||||||
| Exercised | -- | 5,000 | |||||||
| Outstanding at end of year | 148,350 | 129,000 | |||||||
| Options exercisable at year end | 148,350 | 129,000 | |||||||
| Weighted-average fair value of options | |||||||||
| Granted during the year | $ -- | $ -- | |||||||
The following table summarizes information about fixed stock options outstanding at December 31, 2001 and 2000:
| Range of Exercise Prices |
Number
Outstanding at December 31, 2001 |
Weighted- Average Remaining Contractual Life (Years) |
Weighted- Average Exercise Price |
Number
Outstanding at December 31, 2000 |
Weighted- Average Remaining Contractual Life (Years) |
| $1.65 | 34,500 | 1.0 | $3.00 | 30,000 | 2.0 |
| $2.60 | 113,850 | 3.2 | $1.90 | 99,000 | 4.2 |
| $1.65 to $2.60 | 148,350 | 2.7 | $1.90 to $3.00 | 129,000 | 3.7 |
The Board of Directors adopted a policy in 1989 that permits directors and officers of Royale Energy to purchase from Royale Energy, at Royale Energy’s actual costs, up to one percent of a fractional interest in any well to be drilled by Royale Energy. Current and former officers and directors were billed $97,261 and $77,067 for their interests for the years ended December 31, 2001 and 2000, respectively.
In April 1998, Royale Energy established a Simple IRA pension plan covering all employees. Royale Energy 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, 2001 and 2000 were $34,606 and $23,035, respectively.
Royale Energy has established procedures for the on-going 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
F-18
environmental laws and regulations. Royale Energy incurred no material environmental investigation, compliance and remediation costs in 2000 or 1999.
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.
On December 10, 1999, a group of 16 investors in drilling projects sponsored by Royale Energy from 1994 to 1998 filed suit against Royale Energy and certain of its officers and former officers in U.S. District Court for the Northern District of California, alleging fraud, negligent misrepresentation, breach of fiduciary duties and other related claims in connection with the sales of working interests in those projects. Buck, et al., v. Royale Energy, et al., No. C 99 5236. The complaint generally states that the defendants failed to adequately disclose the company’s track record regarding previously drilled wells and makes other general statements about misconduct which are not in Royale Energy’s view supported by specific factual allegations. The suit seeks an unspecified amount of damages, restitution of amounts the plaintiffs invested, and punitive damages. In July 2000, the court granted Royale Energy’s motion to transfer the case to the US District Court for the Southern District of California. No discovery has been conducted in the case. No discovery has ever been conducted in the case since it was filed in December 1999. If the plaintiffs elect to pursue this case, Royale Energy will contend that the plaintiffs suffered no damages, that their claims are completely without merit and that the complaint fails to state a claim on which relief can be based.
On October 12, 2001, Blue Star Resources, Inc. and others filed suit against Royale Energy for declaratory relief, money damages, imposition of a constructive trust, and declaratory relief, seeking a working interest and drilling rights to certain properties covered by a joint operating agreement between plaintiffs and Royale Energy. The dispute is over whether plaintiffs failed to consent to drilling operations that resulted in a commercially productive well drilled by Royale Energy and thereby lost their rights to working interests in the well. The case is set for trial in July 2002. In March 2001, the court dismissed the plaintiff’s motion for partial summary judgment. Since the amount of the judgment against the Company, if any, cannot be reasonably determined at this time, no liability has been accrued in the financial statements.
In the normal course of business, Royale Energy occasionally becomes party to litigation. In the opinion of management, based on advice of legal counsel, pending and threatened litigation involving Royale Energy will not have a material adverse effect upon its financial condition or results of operations.
Operating revenues, operating income, net income, and earnings per common share by quarters from 2001 and 2000 are shown below. Royale Energy, in its opinion, has included all adjustments necessary for a fair presentation of the results of operations for the quarters. Due to the nature of Turnkey Drilling Revenues, which are recognized at specified times over program development on specified wells, annual amounts are not generated evenly by quarter during the year. Amounts for the four quarters and year ended December 31, 2000 have been restated (see note 2).
F-19
| Quarter Ended |
Total Revenues |
Gross Profit |
Net Income (Loss) |
Basic Earnings Per Common Share |
Weighted- Average Shares Outstanding |
||||||||||||
| December 31, 2001 | $ | 2,485,301 | $ | 323,262 | $ | (1,575,274 | ) | $ | (0.30) | 5,212,091 | |||||||
| 2000 | $ | 4,330,993 | $ | 3,525,104 | $ | 1,686,057 | $ | 0.32 | 5,205,837 | ||||||||
| September 30, 2001 | $ | 3,470,768 | $ | 1,659,976 | $ | 513,216 | $ | 0.10 | 5,212,091 | ||||||||
| 2000 | $ | 2,962,880 | $ | 1,604,364 | $ | 527,930 | $ | 0.10 | 5,205,289 | ||||||||
| June 30, 2001 | $ | 3,950,337 | $ | 3,005,045 | $ | 1,778,077 | $ | 0.34 | 5,210,289 | ||||||||
| 2000 | $ | 2,495,162 | $ | 1,224,745 | $ | 394,535 | $ | 0.08 | 5,205,289 | ||||||||
| March 31, 2001 | $ | 5,951,867 | $ | 4,459,575 | $ | 3,030,505 | $ | 0.58 | 5,210,289 | ||||||||
| 2000 | $ | 1,898,317 | $ | 1,026,910 | $ | 142,544 | $ | 0.03 | 5,205,289 | ||||||||
F-20
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, 2001 and 2000. 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, 2001 and 2000 and changes in such quantities during each of the years then ended, were as follows:
| 2001 |
2000 |
|
|
||||||||||
| Oil (BBL) |
Gas (MCF) |
Oil (BBL) |
Gas (MCF) |
||||||||||
| Proved developed and undeveloped reserves: | |||||||||||||
| Beginning of period | 3,000 | 16,651,010 | 80,000 | 15,842,000 | |||||||||
| Revisions of previous estimates | (2,000 | ) | (6,457,330 | ) | (76,404 | ) | 1,103,647 | ||||||
| Production | -- | (1,366,109 | ) | (596 | ) | (1,161,513 | ) | ||||||
| Extensions, discoveries and improved recovery | 7,000 | 4,333,429 | -- | 866,876 | |||||||||
| Purchase of minerals in place | -- |
-- |
-- |
-- |
|||||||||
| Proved reserves end of period | 8,000 |
13,161,000 |
3,000 |
16,651,010 |
|||||||||
| Proved developed reserves: | |||||||||||||
| Beginning of period | 3,000 |
12,672,000 |
80,000 |
10,401,000 |
|||||||||
| End of period | 8,000 |
11,245,000 |
3,000 |
12,672,000 |
|||||||||
These estimates were determined using gas prices at December 31, 2001 ranging from $2.41 per Mcf to $2.85 per Mcf as applied on a field-by-field basis.
F-21
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves
The standardized measure of discounted future net cash flows is presented below for the two years ended December 31, 2001.
The future net cash inflows are developed as follows:
(1) Estimates are made of quantities of proved reserves and the future periods which they are expected to be produced based on year-end economic conditions.
(2) The estimated future production of proved reserves is priced on the basis of year-end prices.
(3) 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 is as follows:
| 2002 | $ | 1,469,000 | |
| 2003 | 279,000 | ||
| 2004 | 5,000 | ||
| Thereafter | 190,000 |
||
| Total | $ | 1,943,000 | |
(4) 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.
| 2001 |
2000 |
|||||||
|---|---|---|---|---|---|---|---|---|
| Future cash inflows | $ | 34,888,000 | $ | 246,398,000 | ||||
| Future production costs | (11,830,000 | ) | (27,583,000 | ) | ||||
| Future development costs | (1,943,000 | ) | (2,286,000 | ) | ||||
| Future income tax expenses | (6,334,800 |
) | (64,959,000 |
) | ||||
| Future net cash flows | 14,780,200 | 151,570,000 | ||||||
| 10% annual discount for estimated timing of cash flows | (5,766,930 |
) | (68,515,413 |
) | ||||
| Standardized measure of discounted future net cash flows | $ | 9,013,270 |
$ | 83,054,587 |
||||
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.
F-22
| 2001 |
2000 |
|||||||
|---|---|---|---|---|---|---|---|---|
| Standardized measure - beginning of year | $ | 83,054,587 |
$ | 9,503,521 |
||||
| Sales of oil and gas produced, net of production costs | (1,819,352 | ) | (9,402,032 | ) | ||||
| Revisions of previous quantity estimates | (9,178,726 | ) | 11,829,749 | |||||
| Net changes in prices and production costs | (106,445,929 | ) | 101,776,580 | |||||
| Extensions, discoveries and improved recovery | 5,973,576 | 6,581,704 | ||||||
| Accretion of discount | 5,216,894 | (5,213,770 | ) | |||||
| Net change in income tax | 32,212,220 |
(32,021,165 |
) | |||||
| Net increase (decrease) | (74,041,317 |
) | 73,551,066 |
|||||
| Standardized measure - end of year | $ | 9,013,270 |
$ | 83,054,587 |
||||
F-23