[DESCRIPTION] FORM 10-KSB
<PAGE> 1
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-KSB
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 1997Commission 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: 619-297-8505
Securities registered pursuant to Section 12(b) of the Act:
None
Securities to be registered pursuant to Section 12(g) of the Act:
Common Stock, no par value
(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: $8,365,130
At March 31, 1999, there were 2,679,542 outstanding shares of registrant's
Common Stock held by non-affiliates, with an aggregate market value of
approximately $7,020,400, based on the closing Nasdaq price on that date.
At March 31, 1999, a total of 3,816,846 shares of registrant's Common Stock
were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE: None
Transitional Small Business Disclosure Format (check one): Yes ; No X
Exhibit Index appears on page 22.
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TABLE OF CONTENTS
PART I . . . . . . . . . . . . . . . . . . . . . . . . . . . .-1-
Item 1. Description of Business . . . . . . . . . . . .-1-
Item 2. Description of Property . . . . . . . . . . . .-4-
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 the Company's Common Stock
and Related Stockholder Matters . . . . . . . .-8-
Item 6. Management's Discussion and Analysis of
Financial Condition and Results of Operations .-9-
Item 7. Financial Statements and Supplementary Data . -13-
Item 8. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure. . . . -13-
PART III . . . . . . . . . . . . . . . . . . . . . . . . . . -13-
Item 9. Directors, Executive Officers, Promoters and
Control Persons, Compliance with Section 16(a)
of the Exchange Act . . . . . . . . . . . . . -13-
Item 10. Executive Compensation. . . . . . . . . . . . -16-
Item 11. Security Ownership of Certain Beneficial
Owners and Management. . . . . . . . . . . . .-18-
Item 12. Certain Relationships and Related Transactions-21-
Item 13. Exhibits, Lists, and Reports on Form 8-K. . . -22-
Signatures. . . . . . . . . . . . . . . . . . . . . . . -23-
FINANCIAL STATEMENTS . . . . . . . . . . . . . . . . . . . .-F-1-
ii
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ROYALE ENERGY, INC.
PART I
Item 1. Description of Business
Royale Energy, Inc. (the "Company"), is an independent oil and natural gas
producer. The Company'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 the Company. The
Company owns wells and leases in major geological basins located mainly in
California. The Company 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. The Company was
incorporated in California in 1986 and commenced operations in 1988. The
Company's Common Stock is traded on the Nasdaq National Market System (symbol
ROYL). On March 31, 1999, the Company had sixteen full time and two part time
employees.
During the fiscal year ended December 31, 1998, the Company continued its
exploration and development of natural gas properties in northern California.
The Company drilled eight wells in 1998, of which it elected to complete two
as commercially productive wells. Six wells drilled in 1998 were plugged and
abandoned as dry holes. The Company's estimated total natural gas reserves
declined from approximately 16.9 Bcf at January 1, 1998 to 15.2 Bcf at
December 31, 1998.
For the years ended December 31, 1998 and 1997, the Company reported gross
revenues in the amounts of $3,789,995 and $5,638,437, respectively, in
connection with the drilling of wells on a turnkey contract basis, which
represents 45.3% and 62.2% of the Company's total revenues for those years.
These amounts are offset by drilling expenses and development costs of
$1,541,624 and $3,163,945, respectively. The Company hires, in addition to
its own engineering staff, independent contractors to drill, test, complete
and equip the wells that it drills.
For the years ended December 31, 1998 and 1997, the Company had oil and
natural gas sales from production of its wells in the amounts of $4,101,553
and $2,992,679, respectively, which represents 43.8% and 33.0%, of the
Company's total revenues for those years.
Plan of Business
The Company is engaged in the acquisition of interests in oil and natural gas
reserves by sponsoring private joint ventures. Management believes that the
Company's shareholders are better served by diversification and limitation of
total exposure in individual drilling projects. Through its participation in
joint ventures, the Company can acquire interests and develop oil and natural
gas properties with limited expense and risk and still receive an interest in
the revenues and reserves produced from these properties.
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After acquiring the leases or lease participation, the Company drills or
participates in the drilling of development and exploratory oil and natural
gas wells on its property. To the extent that the Company retains all or any
portion of the working interest, the Company pays its proportionate share of
the actual cost of drilling, testing, and completing the project.
The Company may also elect to finance part of the drilling cost by selling
fractional interests in undeveloped wells. When the Company sells fractional
interests to raise capital to drill oil and natural gas wells, the Company
generally 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, the
Company recognized 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. The actual drilling and development costs may or may not be
greater than the gross revenue which is recognized by the Company for its
fractional interest sales.
When the Company receives funds from purchase of a turnkey drilling project
sold by it, a percentage of the purchasers' funds are used by the Company to
prepay lease costs, intangible drilling costs, and other costs as required to
allow the drilling project to proceed without delay. These funds are non-
refundable once the purchase has been made. The non-refundable portion of the
total turnkey drilling project is based on a percentage calculated by
estimating the pre-drilling costs as a percentage of total drilling costs for
a particular project. The Company recognizes the non-refundable portion of
the total purchase price as revenue and the related pre-drilling costs are
expensed. The Company records the remaining funds from the sale of working
interests as income at the commencement of drilling, and carries its
obligation to expend the remaining unexpended funds for drilling wells on
behalf of the purchasers as a current liability. See, Note 1 to the Company's
Financial Statements. The Company maintains internal records of the
expenditure of each investor's funds for drilling projects.
Wells completed by the Company are generally operated by the Company. As
operator, the Company receives fees set by industry standards from the owners
of fractional interests in the wells and expense reimbursements. For the
years ended December 31, 1998, and 1997, the Company earned gross revenues in
the amounts of $473,582 and $388,085, from operation of the wells, which
represent 5.7% and 4.3% of the Company's total revenues on a consolidated
basis for those years, respectively. As of December 31, 1998, the Company is
the operator of fifty-one natural gas wells on properties leased by the
Company in the Northern Sacramento Valley, Central Sacramento Valley, and Kern
County in California.
The Company's business is not dependent on a single customer or a few
customers and management does not believe it will be in the foreseeable
future. Oil and natural gas purchasers are readily available in today's
markets, and the Company does not believe that the loss of any customer would
have a material affect on the Company's business or ability to find ready
purchasers for its oil and gas production at current market prices.
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Prior to December 1996, the Company purchased natural gas on a spot basis from
wells operated by the Company and from unaffiliated producers and resold the
gas to consumers in the open market. The purchasers were mainly utilities and
manufacturers located in California. This was essentially a brokerage
operation which generates a large volume of sales revenue at small profit
margins. In December 1996, the Company's gas marketing operations were
discontinued.
Natural gas demand and the prices paid for gas have become seasonal, showing
decreases in the summer and fall. The oil business is not generally seasonal
in nature.
Affiliated Entities
On December 31, 1998, Royale Petroleum Corporation ("RPC") owned 27.4% of the
Company's Common Stock (excluding 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 the Company,
and Stephen Hosmer is chief financial officer and director of the Company.
Donald H. and Stephen M. Hosmer are sons of Harry E. Hosmer, chairman of the
Company's board of directors. See, Security Ownership of Certain Beneficial
Owners and Management. RPC is a predecessor and affiliate of the Company.
RPC is a Delaware corporation formed in 1985.
The Company had no subsidiaries at December 31, 1998.
Competition, Markets and Regulation
Competition
The exploration and production of oil and natural gas is an intensely
competitive industry. The sales of interests in oil and gas projects such as
those the Company sells is also very competitive. The Company 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, many
of which companies are substantially larger than the Company.
Markets
The quantities of, and price obtainable for, oil and natural gas production
from the Company's oil and natural gas properties, are affected by market
factors beyond the Company's control. 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
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including environmental, energy conservation, and tax laws or the imposition
of new regulatory requirements upon the oil and natural gas industry. There
can be no assurance that oil and natural gas prices will not increase or
decrease in the future, thereby increasing or decreasing the revenues that the
Company receives from its oil and natural gas sales.
Regulation
Production, transportation, and sale of oil and natural gas from the Company's
operations are affected to some degree by federal and state laws and
regulations. Many states in which the Company operates have statutory
provisions regulating the production and sale of oil and natural gas,
including provisions regarding deliverability. Such statutes, and the
regulations promulgated in connection therewith, are generally 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;
prohibition of drilling activities on certain lands lying within wilderness
areas or where pollution arises; and imposition of substantial liabilities for
pollution resulting from drilling operations, particularly operations in
offshore waters or on submerged lands. Compliance with such legislation and
regulations, together with any penalties resulting from noncompliance
therewith, may also increase the cost of oil and natural gas development and
production. Certain of these costs may ultimately be borne by the Company.
The Company does not presently anticipate that compliance with federal, state
and local environmental regulations will have a material adverse effect on
capital expenditures, earnings or the competitive position of the Company in
the oil and natural gas industry; however, since these laws and regulations
change frequently, the costs of the Company's compliance with existing and
future environmental regulations cannot be predicted.
The preceding discussion of regulation of the oil and natural gas industry is
not intended to constitute a complete discussion of the various statutes,
rules, regulations or governmental orders to which the Company's operations
may be subject.
Item 2. Description of Property
Since 1993, the Company has concentrated on development of properties in the
Sacramento Basin of Northern California. In 1998, the Company drilled two
commercially productive wells and six dry holes in Northern California. In
1997, the Company drilled nine commercially productive gas wells and four dry
holes in Northern California. The Company also owns other interests in
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<PAGE> 7
properties in Texas and Oklahoma in connection with joint ventures in which
the Company is a participant but is not the operator.
Following industry standards, the Company generally acquires oil and natural
gas acreage without warranty of title except as to claims made by, through, or
under the transferror. In these cases due diligence as to title is attempted
prior to acquisition, but there are no assurances that losses will not result
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 as are customary within the oil and natural gas industry.
The Company has available a $5,000,000 revolving credit line from a major
commercial bank for working capital purposes, acquisitions, and development of
oil and gas properties. At December 31, 1998, $5,000,000 in loans were
outstanding under this credit line. All of the Company's oil and gas
properties are pledged to secure this credit line.
The following is a discussion of the Company's significant oil and natural gas
properties. Reserves at December 31, 1998, for each property discussed below,
have been determined by WZI, Inc., registered professional petroleum
engineers, in accordance with its report dated March 1999 (the most recent
report available).
Northern California
The Company owns lease interests in 41,566.15 gross (29,120.51 net) acres in
15 gas fields with locations ranging from Tehama County in the north to Kern
County in the south, in the Sacramento and San Joaquin Basins in Northern
California. At December 31, 1998, the Company operated 51 wells in Northern
California, and its estimated total gas reserves in Northern California were
approximately 15.2 Bcf, according to the Company's independently prepared
reserve report.
Developed and Undeveloped Leasehold Acreage
As of December 31, 1998, the Company owned leasehold interests in the
following developed and undeveloped properties in both gross and net acreage.
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<TABLE>
<CAPTION>
Developed Undeveloped
Gross Net Gross Net
Acres Acres Acres Acres
----- ----- ----- -----
<S> <C> <C> <C> <C>
California 11,820.46 8,085.09 27,324.69 20,819.42
All other States 2,421.00 216.00 - -
--------- -------- --------- ---------
Total 14,241.46 8,301.09 27,324.69 20,819.42
</TABLE>
Drilling Activities
The following table sets forth the Company's drilling activities during the
years ended December 31, 1996, 1997, and 1998. All wells are located in the
Continental U.S., in California, Texas, and Oklahoma.
<TABLE>
<CAPTION>
Gross Wells (b) Net Wells
----------------------------- --------------------
Year Type of Well (a) Total Producing (c) Dry (d) Producing (c) Dry (d)
<S> <S> <C> <C> <C> <C> <C>
1996 Exploratory 1 - 1 - 0.3263
Developmental 8 5 3 1.2573 1.0383
1997 Exploratory 3 1 2 .4430 .6150
Developmental 10 8 2 3.1507 .7650
1998 Exploratory - - - - -
Developmental 8 2 6 .9727 2.9287
</TABLE>
(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 the Company
owns an interest. The Company'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.
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As of December 31, 1998, the Company had 51 gross (28.95 net) currently
producing natural gas wells.
Production
The following table summarizes, for the periods indicated, the Company'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 is
owned by the Company either directly or indirectly through partnership or
joint venture interests produced to its interest after deducting royalty,
limited partner or other similar interests. The Company 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.
<TABLE>
<CAPTION>
1998 1997 1996
<S> <C> <C> <C>
NET VOLUME
Oil (Bbl) 1,238 679 22
Gas (Mcf) 1,773,294 1,365,562 672,383
Mcfe 1,785,674 1,376,334 672,603
AVERAGE SALES PRICE
Oil (Bbl) $9.42 $14.42 $16.07
Gas (Mcf) $2.21 $2.26 $1.79
Net Production Costs & Taxes $708,137 $460,768 $260,789
Lifting Costs $0.39 $0.34 $0.37
</TABLE>
Net Proved Oil and Natural Gas Reserves
As of December 31, 1998, the Company had proved developed reserves of
10,386,000 Mcf and total proved reserves of 15,248,000 Mcf of natural gas on
all properties leased by the Company. Proved developed reserves are those
reserves which are expected to be recovered from already producing completion
intervals and are currently producing to a market. Total proved reserves
include proved developed reserves and those reserves that are estimated to be
recoverable from new wells on undrilled acreage or from existing wells where a
major capital expenditure is required for additional completion.
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Oil and gas reserve estimates and the discounted present value estimates
associated therewith are based on numerous engineering, geological and
operational assumptions that generally are derived from limited data. Common
assumptions include such matters as the areal extant and average thickness of
a particular reservoir, the average porosity and permeability of the
reservoir, the anticipated future production from existing and future wells,
future development and production costs and the ultimate hydrocarbon recovery
percentage. As a result, oil and gas reserve estimates and discounted present
value estimates are frequently revised in subsequent periods to reflect
production data obtained after the date of the original estimate. If the
reserve estimates are inaccurate, production rates may decline more rapidly
than anticipated, and future production revenues may be less than estimated.
Additional data relating to the Company's oil and natural gas properties is
disclosed in Supplemental Information About Oil and Gas Producing Activities
(Unaudited), attached to the Company's Financial Statements which are part of
this document. 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, 1998 and 1997, prepared by the Company's
independent reserve engineering consultants.
Item 3. Legal Proceedings
None.
Item 4. Submission of Matters to a Vote of Security Holders
During the fourth quarter of fiscal 1998, no matters were submitted to a vote
of the Company's security holders.
PART II
Item 5. Market Price of the Company's Common Stock and Related Stockholder
Matters
Since February 25, 1997, the Company's Common Stock has been traded on the
Nasdaq National Market System under the symbol "ROYL." From October 1994
until February 24, 1997, the Company's Common Stock was traded on the Nasdaq
Small Cap Market. The following table reflects high and low quarterly sales
prices from April 1997 through December 1998, and the high and low inter-dealer
bid price per share quotations in the Nasdaq Small Cap Market for the
first quarter of 1997.
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<TABLE>
<CAPTION>
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter
High Low High Low High Low High Low
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1997 6-3/8 4-1/16 5-7/8 4 5-1/8 3-7/16 5-1/4 3-5/8
1998 4-1/2 3-3/8 5-1/4 4 4-1/4 2-13/16 4-5/8 3
</TABLE>
Conversion of Preferred Stock to Common Stock
During the fourth quarter of 1998, 3,125 shares of the Company's Common Stock
were issued to one holder of the Company's previously issued Series AA Preferred
Convertible Stock, pursuant to the shareholder's exercise of his right to
convert his shares of Preferred Stock to Common Stock. The sole consideration
received by the Company was the Preferred Stock surrendered in the conversion.
Each outstanding share of Series AA Preferred Stock is convertible to Common
Stock at a ratio of one share of Common Stock for each of two shares of
Preferred. The Preferred Stock had originally been issued prior to 1993 in
private placements pursuant to Section 4(2) of the Securities Act of 1933, and
to the extent, if any, that the individual shareholder's conversion of his
Preferred shares to Common might be considered a sale of securities, the 1998
issuance of Common to the converting Preferred shareholder was also made
pursuant to Section 4(2) of the Securities Act of 1933.
Dividends
The Company has not declared or paid any cash dividends to its common
shareholders. The board has discussed whether it may wish to declare a dividend
in the future. The future determination as to the payment of dividends will
depend on the Company's financial condition and other factors deemed relevant by
the Company's board of directors.
Item 6. Management's Discussion and Analysis of Financial Condition and
Results of Operations
The following discussion should be read in conjunction with the Company's
Financial Statements and Notes thereto and other financial information relating
to the Company included elsewhere in this document.
For the past five years, the Company has primarily acquired and developed
producing and non-producing natural gas properties in Northern California. The
most significant factors affecting the Company's results of operations are (i)
changes in the sales price of natural gas, (ii) recording of turnkey drilling
revenues and the associated drilling expense, (iii) the containment of costs and
expenses on a company wide basis, and (iv) the change in natural gas reserves
owned by the Company.
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In its past drilling projects, the Company has sold geological and geophysical
data developed on the prospects to participants as part of the project costs.
The consideration received from these sales constituted an immaterial fraction
of the Company's revenues. The Company expects to continue to recover at least
part of the cost of its geological and geophysical library from participants in
future projects, and the Company may sell information from its library to third
party oil industry participants. Due to the increased cost associated with the
acquisition of three dimensional seismic data, and to the expected commencement
of sales of such data to unaffiliated industry members, the Company has chosen
to segregate these assets on its financial statements as Other Capitalized
Costs. See, Note 1 to the Company's Financial Statements for the Years Ended
December 31, 1998 and 1997 - Other Capitalized Costs.
Results of Operations for the Twelve Months Ended December 31, 1998, as Compared
to the Twelve Months Ended December 31, 1997
For the year ended December 31, 1998, the Company achieved a net profit of
$774,406, a $735,977 or 48.7% decrease from the net profit in 1997 of
$1,510,383. The Company's management attribute this decrease to lower revenues
from turnkey drilling and an increase in oil and gas property related expenses.
Total revenues for the year ended December 31, 1998 were $8,365,130, which was a
decrease of $700,996 or 7.7%, when compared to 1997. The decrease in total
revenues can be primarily attributed to the decrease in revenues from turnkey
drilling in 1998, compared to 1997.
Although the Company's net profit for 1998 was lower than in 1997, cash flows
from operating activities (before deducting non-cash items such as depreciation,
lease impairment, and deferred DWI revenues) increased to $3,239,819 in 1998,
from $2,998,779 in 1997, and increase of 8%.
Oil and gas revenues for the year ended December 31, 1998 were $4,101,553
compared to $2,992,679 for the same period in 1997, which represents a
$1,108,874 or 37.1% increase. This increase in revenues was mainly due to the
increase in natural gas production from Company owned wells. The net sales
volume for the year ended December 31, 1998, was 1,773,294 Mcf with an average
price of $2.21 per Mcf, versus 1,365,562 Mcf with an average price of $2.26 per
Mcf for 1997, which represents and increase in net sales volume of 407,732 Mcf
or 29.9%. The net sales volume for condensate (natural gas liquids) production
was 1,238 barrels with an average price of $9.42 per Bbl for the period ended
December 31, 1998, compared to 679 barrels at an average price of $14.42 per
Bbl for the same period in 1997, which represents an increase in net sales
volume of 559 barrels or 82.3%.
The Company's oil and gas lease operating expenses increased by $409,104, or
67%, to $1,020,541 for the year ended December 31, 1998, from $611,437 for the
same period in 1997. This increase in costs can be attributed to an increase in
the number of wells operated by the Company, along with workover costs on
several of the Company's wells. For 1998, the Company's gross margins on oil
and gas production (excluding drilling and development costs) were 75.1%,
compared to 79.6% in 1997. The decrease in gross margin was due to both the
decrease in the average price the Company received for its natural gas during
1998 and an increase in associated production costs.
For the year ended December 31, 1998, turnkey drilling revenues decreased
$1,848,442, to $3,789,995 in 1998 from $5,638,437 in 1997, or 32.8% for the
year. The Company also experienced
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a $1,622,321 or 51.3% decrease in drilling and development costs from $3,163,945
in 1997 to $1,541,624 in 1998. This decrease in turnkey revenues and expenses
was due to the Company's drilling of eight wells, two of which were commercially
productive, that were sold to outside parties in 1998, versus nine productive
wells and four dry holes in 1997. The Company's gross margins, or profits, on
drilling depend on the Company's ability to accurately estimate the costs
associated with the development of projects in which it sells working interests
to investors. Costs associated with contract drilling depend on location, well
depth, weather, and availability of drilling contractors and equipment. The
Company's gross margins on drilling were 59.3% and 43.9% for the years ended
December 31, 1998 and 1997, respectively.
During the first quarter of 1997, the Company recorded gas distribution revenue
from a brokered natural gas sale in the amount of $46,925, which was offset by
cost of sales of $23,741. There were no such sales of this type during 1998.
The 1997 sale was an isolated trade.
Our aggregate of supervisory fees and other income was $473,582 for the year
ended December 31, 1998, an increase of $85,497 (22%) from $388,085 during 1997.
Supervisory fees are charged in accordance with the Council for Petroleum
Accountants Societies (COPAS) policy for reimbursement of costs 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 $74,001 or 26.3%, from $281,564
in 1997 to $355,565 in 1998. This change can be attributed to the increased
number of wells that the Company operates.
Depreciation, depletion and amortization expense increased to $1,461,511 from
$665,694, an increase of $795,817 (119.6%) for 1998, compared to 1997. The
depletion rate is calculated using production as a percentage of reserves, and
the increase in depletion was mainly due to the increase in gas production
during 1998.
The Company periodically reviews its long-lived assets for impairment whenever
events or changes in circumstances indicate that the carrying amount of an asset
may not be recoverable, pursuant to SFAS No. 121. In addition, management also
periodically assesses the value of significant proved and unproved properties
and charges impairments of value to expense. In 1998, the Company changed the
method by which it assesses its proved properties from a field-by-field basis to
a region-by-region basis, to reflect a more consistent geological relationship
between the Company's assets and exploration activities. The 1998 review for
impairment under the former, field-by-field basis resulted in an impairment loss
of $1,659,048, compared to a 1997 impairment loss of $300,000. However, the
change to region-by-region review of proved properties resulted in a reduction
of the impairment loss by $1,193,528. This amount is recorded on the Company's
1998 Income Statement as a change in accounting principle for the cumulative
change in accounting for the impairment of long-lived assets. The difference of
$465,520, between $1,659,048 and $1,193,528, represents the total impairment
loss for 1998 after taking into account the accounting change. See, Note 1 to
the Company's Financial Statements for the Years Ended December 31, 1998 and
1997.
-11-
<PAGE> 14
The Company also reevaluated several of its geological lease and land costs,
which had been previously capitalized, in order to write off those prospects
which were no longer viable. As a result, $139,664 of previously capitalized
costs were written off and recorded as geological and geophysical expense during
1998.
General and administration expenses increased by $169,656, or 11.8%, from
$1,437,046 for the year ended December 31, 1997 to $1,606,702 for the same
period in 1998. Legal and accounting expense decreased to $544,228 for the
period, compared to $658,864 for 1997, a $114,636 (17.4%) decrease. The
decrease is due to lower litigation costs in 1998. Marketing expense for the
year ended December 31, 1998, decreased $21,047 or 4.74%, to $422,693,
compared to $443,740 for 1997. Marketing expense for the Company varies from
period to period according to the number of marketing conferences attended by
Company personnel and associated travel costs.
During the first half of 1997, the Company extended an existing credit line from
a major commercial bank, which it used to purchase the California assets of
Vernon E. Faulconer, Inc. Because of borrowings pursuant to this credit line,
interest expense increased to $335,373 for the year ended December 31, 1998 from
$149,725 for 1997.
Capital Resources and Liquidity
At December 31, 1998, the Company had current assets totaling $2,884,229 and
current liabilities totaling $4,084,103, a $1,199,874 working capital deficit.
The primary reason for this deficit is the Company's obligation to complete
wells on behalf of investors who bought fractional working interests from the
Company. The Company records these obligations as deferred revenue from
turnkey drilling until the drilling projects are completed. For the industry
as a whole, a working capital deficit is not uncommon. Management believes
that the Company has sufficient liquidity for the short term.
Operating Activities. For the year ended December 31, 1998, cash provided by
operating activities totaled $3,239,819 compared to $2,998,779 provided by
operations for 1997. This increase in cash provided in 1998 can be mainly
attributed to increased deferred revenues, due to the decrease in drilling in
1998.
Investing Activities. Net cash used by investing activities, primarily in
capital acquisitions of oil and gas properties, amounted to $4,942,652 for the
period, compared to $6,996,401 used by investing activities for 1997. The
decrease in cash used can be primarily attributed to the Company's acquisition,
during 1997, of the California assets of Vernon E. Faulconer, Inc. and to the
decrease in drilling during 1998.
Financing Activities. Net cash provided by financing activities for the year
ended December 31, 1998, was $687,138, compared to $3,434,179 provided by
financing activities for the same period in 1997. The primary reason for the
difference was the increase in long term debt due to the
-12-
<PAGE> 15
Faulconer property acquisition during the period in 1997. In April 1998, the
Company began repurchasing its own common stock in open market purchases, in
order to retire it. For all of 1998, the Company repurchased 77,150 shares for
$310,262 with an average share price of $4.02. In addition, the Company paid
$82,250 to two executive officers in 1998 to repurchase stock options. See,
Executive Compensation.
Year 2000
The Company believes that it is prepared for the challenges to management
information and other computer systems presented by Year 2000 ("Y2K"). In
general, Y2K issues relate to the way that many computer programs refer to
dates and their ability to recognize dates after the end of 1999. The
majority of the Company's computer software are "off-the-shelf" applications,
which have released updates to correct for the Y2K issue. The off-the-shelf
software updates have been implemented on or after their originally scheduled
update cycle, and therefore did not cause the Company any incremental expense.
The Company's major off-the-shelf systems include its accounting system and
its seismic, geologic, and engineering software.
Item 7. Financial Statements and Supplementary Data
See, pages F-1, et seq., included herein.
Item 8. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
PART III
Item 9. Directors, Executive Officers, Promoters and Control Persons,
Compliance with Section 16(a) of the Exchange Act
Listed below is certain information about the current directors and executive
officers of the Company. 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
the Company, its subsidiaries and affiliated companies.
-13-
<PAGE> 16
<TABLE>
<CAPTION>
First Became Director
Name Age or Executive Officer Positions Held
- ---- --- -------------------- --------------
<S> <C> <C> <C>
Harry E. Hosmer* 68 1987 Chairman of the Board.
Donald H. Hosmer 42 1987 President, Secretary and
Director. Chairman of the
Board and President of
Royale Petroleum
Corporation ("RPC").
Stephen M. Hosmer 32 1991 Chief Financial Officer and
Director. Secretary and
Director of RPC.
Oscar A.
Hildebrandt+ 63 1995 Director.
Gilbert C.L. Kemp 65 1998 Director.
Rodney Nahama 67 1994 Director.
George M. Watters*+ 79 1991 Director.
</TABLE>
* Member of the audit committee.
+ Member of the compensation committee.
The following summarizes the business experience of each director and executive
officer for the past five years.
HARRY E. HOSMER is the Chairman of the Board of the Company. He has served as
Chairman since the Company began operations in 1987, and from inception in 1987
until June 1995, he also served as President and Chief Executive Officer. In
October 1985, Mr. Hosmer and three of his sons founded Royale Petroleum
Corporation, an affiliate of the Company.
DONALD H. HOSMER is President, Chief Executive Officer, Secretary, and
Director of the Company. He has served as an executive officer and Director
of the Company 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 the Company. 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 the Company. Mr.
Hosmer joined the Company as the Management Information Systems Manager in May
1988, responsible for developing and maintaining the Company's computer
software. Mr. Hosmer developed programs and software systems used by the
Company. Mr. Hosmer graduated from Oral Roberts
-14-
<PAGE> 17
University in Tulsa, Oklahoma, in May 1988 with a Bachelor of Science in
Business Administration. Stephen M. Hosmer is the son of Harry E. Hosmer
and brother of Donald H. Hosmer.
OSCAR HILDEBRANDT, D.V.M., is a Director and is Chairman of the Company's
Compensation Committee. From 1994 to 1995 he served as an advisory member
of the Company'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 3D 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 the Company, 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 the Company.
Mr. Nahama holds a B.A. degree in geology from the University of California,
Los Angeles, and an M.A. degree in geology from the University of Southern
California. He was an independent exploration geologist from 1965 to 1971
and prior to that served as a geologist with Franco Western Oil Company
from 1963 to 1965. Between 1957 and 1963, Mr. Nahama worked as an
exploration geologist with Honolulu Oil Company, Getty Oil Company, and
Sunray Oil Company. Mr. Nahama is a member of the American Association
of Petroleum Geologists, the San Joaquin Geological Society, the California
Independent Petroleum Association and the Independent Petroleum Association
of America.
GEORGE M. WATTERS has been retired from full time employment during the
last five years. Mr. Watters retired from AMOCO Corporation in 1983 after
serving for 24 years in senior management positions with AMOCO Corporation
and its affiliates. From 1987 to the present Mr. Watters has managed his
personal investments. Mr. Watters received his Bachelor of Science degree
from Massachusetts Institute of Technology in 1942.
-15-
<PAGE> 18
Compliance with Section 16(a) of the Exchange Act
Section 16(a) of the Securities Exchange Act of 1934 and Securities and
Exchange Commission regulations require that the Company's directors,
certain officers, and greater than 10 percent shareholders are required to
file reports of ownership and changes in ownership with the SEC and the NASD
and to furnish the Company with copies of all such reports they file.
Directors Oscar A. Hildebrandt and Gilbert C. L. Kemp have each filed one
late report of purchases or sales of securities during 1998. Except for
these two reports, and based solely upon a review of the copies of the
forms furnished to the Company, or written representations from certain
reporting persons that no reports were required, the Company believes that
no other persons failed to file required reports on a timely basis during
or in respect of 1998.
Item 10. Executive Compensation
The following table summarizes the compensation of chief executive officer
and the other most highly compensated executive officers of the Company
and its subsidiaries during the past year.
<TABLE>
<CAPTION>
Annual Compensation
-------------------
(a) (b) (c) (d) (e) (f)
Other Annual All Other
Compensation Compensation
Name Year Salary Bonus (1) (2), (3)
- --------------- ---- ------- --------- ------------- -------------
<S> <C> <C> <C> <C> <C>
Donald H. Hosmer, 1998 $121,169 $10,000 $368 $53,350
President 1997 $103,974 $356
1996 $100,000 $703
Harry E. Hosmer, 1998 $130,000 $669
Chairman 1997 $110,000 $299
1996 $122,444 $882
Stephen M. Hosmer, 1998 $97,808 $10,000 $340 $37,269
Chief Financial 1997 $75,995 $361
Officer 1996 $73,385 $412
</TABLE>
(1) Under the terms of a plan adopted by the board of directors in 1989,
each of the listed executives have elected to participate in wells
drilled by the Company. See, Certain Relationships and Related
Transactions. 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
-16-
<PAGE> 19
by outside investors could be considered as additional compensation to
them. However, the Company's management does not believe that the amount
of such difference is significant. In addition, prior to June 1995,
the Company 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 Company's management
believe 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. The imputed interest rate used by the Company is
currently 7.5% simple interest per annum. In June 1995, the Company'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 the amount received upon resale of stock options to the Company
in September 1998 by Donald Hosmer ($51,750) and Stephen Hosmer ($34,400).
See, Aggregated 1998 Option Exercises and Year-End Values.
(3) Includes the Company's matching contribution for Donald Hosmer ($1,600)
and Stephen Hosmer ($2,769) to the Company's retirement savings plan
initiated in April 1998.
No Stock Options Were Granted in 1998
The Company did not grant any stock options or stock appreciation rights to its
officers or employees during 1998.
Aggregated 1998 Option Exercises and Year-End Values
None of the executive officers named in the Summary Compensation Table
exercised any stock options or stock appreciation rights in 1998, 1997, or
1996. The following table summarizes the number and value of all unexercised
stock options held by those executive officers at the end of 1998.
-17-
<PAGE> 20
<TABLE>
<CAPTION>
(a) (b) (c) (d) (e)
Number of
Securities Value of
Underlying Unexercised In-
Number of Unexercised the-Money
Securities Options/SARs Options/SARs at
Underlying at FY-End (#) FY-End ($) (1)
Options/
SARs Value Exercisable/ Exercisable/
Name Exercised Realized Unexercisable Unexercisable
- -----------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Harry E. Hosmer - - 45,000/0 $35,700/0
Donald H. Hosmer 30,000(2) $51,750 15,000/0 $ 900/0
Stephen M. Hosmer 20,000(2) $34,500 10,000/0 $ 600/0
</TABLE>
(1) Based on a fair market value of $3.06 per share, which was the closing bid
price of the Company's Common Stock in the Nasdaq National Market System on
December 31, 1998.
(2) On September 29, 1998, the noted officers exercised their rights to resell
previously granted stock options to the Company under a plan adopted by the
board of directors in July 1998, offering to repurchase officers' stock
options prior to September 30, 1998. Donald Hosmer and Stephen Hosmer sold
their stock options to the Company for $1.72 per share, which was the
difference between the exercise price of the stock options ($1.90 per
share)and the stock's closing market price on September 30, 1998 ($3.62
per share).
Compensation of Directors
Each director who is not an employee of the Company receives a quarterly fee for
their services, which in 1998 was set at $1,700 for the first quarter and
raised to $1,785 for each of the remaining three quarters, plus a fee of $250
for each Board or Board Committee meeting attended. In addition, the Company
reimburses directors for the expenses they incur for their service No
directors received any stock options or stock appreciation rights in 1998.
Item 11. Security Ownership of Certain Beneficial Owners and Management
The following tables set forth certain information regarding the ownership of
the Company's voting securities as of December 31, 1998, by: (i) each person
who is known by the Company to own beneficially more than 5% of the
outstanding shares of each class of equity securities, (ii) each director of
the Company, and (iii) all directors and officers of the Company 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.
-18-
<PAGE> 21
Common Stock
On December 31, 1998, 3,808,613 shares of the Company's Common Stock were
outstanding.
<TABLE>
<CAPTION>
Shares Owned (1)
----------------
Shareholder (2) Number Percent
- --------------- ------ --------
<S> <C> <C>
Royale Petroleum Corporation 1,274,076 (3), (4) 31.54%
Donald H. Hosmer 1,290,076 (3), (4) 31.96%
Harry E. Hosmer 45,000 (4) 1.17%
Oscar A. Hildebrandt 59,033 (5) 1.54%
Stephen M. Hosmer 1,285,236 (3), (4) 31.84%
Gilbert C. L. Kemp 5,000 Less than 1%
Owen LeTissier
St. Peter Port
Guernsey, Channel Islands 400,000 (6) 10.50%
Rodney Nahama 14,000 Less than 1%
George M. Watters 77,500 (7) 2.02%
All directors and officers as a
group (7 persons) 1,501,859 (3) 35.99%
</TABLE>
(1) Includes shares which the listed shareholder has the right to acquire
before March 1,1999, from options or warrants, as follows: Royale
Petroleum Corporation 230,555, Donald H. Hosmer 15,000, Harry E. Hosmer
45,000, Stephen M. Hosmer 10,000, Oscar Hildebrandt 20,000, Rodney Nahama
14,000, George M. Watters 30,000, and all officers and directors as a
group (excluding Royale Petroleum Corporation) 134,000.
(2) Unless otherwise indicated, the mailing address of each listed
shareholder is 7676 Hazard Center Drive, Suite 1500, San Diego, California
92108.
(3) Because Messrs. Donald and Stephen Hosmer are directors of Royale
Petroleum Corporation ("RPC") and have power to vote the shares of Common
Stock owned by RPC, pursuant to Rule 13d-3 promulgated under the
Securities Exchange Act of 1934, as amended, each of them may be deemed
to be the beneficial owner of all the Common Stock owned by RPC.
Accordingly, the 1,274,076 shares of the Company owned by RPC
-19-
<PAGE> 22
are included in the number of shares held by both Donald and Stephen
Hosmer 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 a family partnership of which Dr. Hildebrandt is
a 50% partner and shares held by a trust of which Dr. Hildebrandt is
trustee.
(6) The Company's transfer records reflect that Owen LeTissier holds 400,000
shares as the Trustee of two foreign charitable trusts.
(7) Includes Common Stock held by a trust of which Mr. Watters is the Trustee.
Preferred Stock
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, 1998, there were 9,375 shares of Series A
and 43,750 shares of Series AA Convertible Preferred Stock outstanding. The
shares of each series of Preferred shares is convertible into the Company'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 the
Company's knowledge, none of the Preferred shareholders would own more than
1% of the Company's Common Stock, if their Preferred shares were converted to
Common shares.
<TABLE>
<CAPTION>
Series A Series AA
-------- ---------
Shareholder Number % Number %
- ----------- ------ - ------ -
<S> <C> <C> <C> <C>
Richard G. and Margaret E. Algire 3,125 33.3%
Marjorie Carson 6,250 14.28%
June L. Ginnings 3,125 7.14%
Overland Bank 6,250 14.28%
Audrey Sanabria & B.G. Dienelt, Jr. 3,125 7.14%
George Singleton 6,250 14.28%
James S. Trowbridge 6,250 66.7%
William W. Well 6,250 14.28%
Jerome Winston 6,250 14.28%
-20-
<PAGE> 23
Series A Series AA
-------- ---------
Shareholder Number % Number %
- ----------- ------ - ------ -
Nim E. Wire 6,250 14.28%
All officers and directors as a
group (7 persons). 0 0.0% 0 0.0%
</TABLE>
Item 12. Certain Relationships and Related Transactions
In 1989, the board of directors adopted a policy (the "1989 policy") that
permits each director and officer of the Company to purchase from the Company,
at its cost, up to one percent (1%) fractional interest in any well to be
drilled by the Company. When an officer or director elects to make such a
purchase, the amount charged per each percentage working interest is equal
to the actual pro rata cost to the Company of drilling and completion costs,
rather than the higher amount that the Company 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 have at various times elected to purchase
interests in certain wells drilled by the Company under the 1989 policy.
Under the 1989 policy, officers and directors may elect to participate in
wells at any time up until drilling of the prospect commences. Participants
do not pay a set, turnkey price (as do outside investors who purchase
undivided working interests from the Company), but are liable for all direct
costs and expenses through completion of a well, whether or not the well
drilling and completion expenses exceed the Company's cost estimates. Thus,
they participate on terms much the same as would be afforded to other oil and
gas industry participants or joint venturers. Participants are invoiced for
their share of direct costs of drilling and completion as expenses are
incurred by the Company.
Officer and director participants under this program do not pay some expenses
paid by outside, retail investors in working interests, such as sales
commission, 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, the Company's
Management believes that the terms on which officers and directors participate
in wells under the Board of Directors' policy are being offered their
interests 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 the Company.
Donald and Stephen Hosmer have each individually participated in 32 wells
under the 1989 policy. Donald and Stephen Hosmer have also participated in
27 wells in the name of RPC, a
-21-
<PAGE> 24
corporation jointly owned by them, beginning in 1996. The Hosmer Trust, a
trust for the benefit of family members of Harry E. Hosmer, has participated
in 31 wells.
During 1998, Donald and Stephen Hosmer invested in one well under the 1989
policy in the name of RPC and was charged a total of $710 for its 0.25%
interest. Also in 1998, RPC was charged $3,592 for wells in which it
purchased interests in 1997, but which were not drilled until 1998.
Donald Hosmer's 1998 investments in wells under the 1989 policy totaled
$5,833 for 0.25% interests in seven wells. In 1998, Stephen Hosmer invested
purchased 0.25% interests in four wells and 0.125% interests in three wells
under the 1989 policy, for a total investment of $4,453.
The Hosmer Trust purchased 1.0% interests in seven wells during 1998 for a
total investment of $23,330.
Prior to June 1995, the Company had advanced to the participants under the 1989
policy, the funds with which to purchase their interests, with funds to be
repaid from future production from the working interests, with advances to be
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 the Company has a single
account to which all charges and income from all wells is credited. In June
1995, the Company's policy regarding the advancement of funds was changed.
Current policy requires that all such purchases of interests in wells must be
paid in cash. At December 31, 1998, the following executive officers and
their affiliates owed the following amounts on advances for well
participations: Donald Hosmer $5,720; Stephen Hosmer $4,578; RPC $526; the
Hosmer Trust $14,513.
Item 13. Exhibits, Lists, and Reports on Form 8-K
(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 the Company'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 the
Company's Form 8-K dated October 31, 1994.
3.3 Bylaws of Royale Energy, Inc., incorporated by reference to Exhibit 3.2
of the Company's Form 10-SB Registration Statement.
-22-
<PAGE> 25
4.1 Certificate of Determination of the Series A Convertible Preferred Stock,
incorporated by reference to Exhibit 4.1 of the Company'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 the Company's Form 10-SB
Registration Statement.
10.1 Wellbore Farmout Agreement between Royale Energy Funds, Inc., and
Pacific Gas & Electric Co., dated March 15, 1993, incorporated by
reference to Exhibit 10.2 of the Company's Form 10-SB Registration
Statement.
10.2 Form of Indemnification Agreement, incorporated by reference to Exhibit
10.3 of the Company's Form 10-SB Registration Statement.
(b) Reports on Form 8-K
The Company filed no Reports on Form 8-K during the last fiscal quarter of 1998.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
ROYALE ENERGY, INC.
Date: April 15, 1999 /s/ Donald H. Hosmer
----------------------------------
Donald H. Hosmer, President
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities indicated.
Date: April 15, 1999 /s/ Harry E. Hosmer
---------------------------------
Harry E. Hosmer, Chairman of the
Board
Date: April 15, 1999 /s/ Donald H. Hosmer
---------------------------------
Donald H. Hosmer, Chief Executive
Officer, President, Secretary, and Director
-23-
<PAGE> 26
Date: April 15, 1999 /s/ Stephen M. Hosmer
----------------------------------
Stephen M. Hosmer, Chief Financial
Officer and Director
Date: April 15, 1999 /s/ Oscar A. Hildebrandt
-----------------------------------
Oscar A. Hildebrandt, Director
Date: April 15, 1999 /s/ Gilbert C. L. Kemp
-----------------------------------
Gilbert C.L. Kemp, Director
Date: April 15, 1999 /s/ Rodney Nahama
-----------------------------------
Rodney Nahama, Director
Date:
--------------- -----------------------------------
George M. Watters, Director
<PAGE> 27
ROYALE ENERGY, INC.
INDEX TO FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA
Page
Index to Financial Statements. . . . . . . . . . . . . . . F-1
Report of Brown Armstrong Randall Reyes Paulden & McCown,
Independent Auditors. . . . . . . . . . . . . . . . . . F-2
Balance Sheets at December 31, 1998 and 1997 . . . . . . . F-3
Statements of Income for the Years Ended
December 31, 1998 and 1997. . . . . . . . . . . . . . . F-5
Statements of Stockholders' Equity for the
Years Ended December 31, 1998 and 1997. . . . . . . . . F-7
Statements of Cash Flows for the Years
Ended December 31, 1998 and 1997. . . . . . . . . . . . F-9
Notes to the Financial Statements. . . . . . . . . . . . . F-11
Supplemental Information About Oil and Gas Producing
Activities (Unaudited). . . . . . . . . . . . . . . . . F-26
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
<PAGE> 28
REPORT OF INDEPENDENT AUDITORS
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,
1998 and 1997, and the related statements of income,
stockholders' equity and cash flows for the years then
ended. These financial statements are the responsibility of
the Company's management. Our responsibility is to express
an opinion on these financial statements based on our audit.
We conducted our audits in accordance with generally
accepted auditing standards. 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, 1998 and
1997, and the results of their operations and their cash
flows for the years then ended in conformity with generally
accepted accounting principles.
As discussed in Note 1 to the financial statements, during
1998, the Company changed its method of evaluating its oil
and gas properties for impairment.
BROWN ARMSTRONG RANDALL
REYES PAULDEN & McCOWN
ACCOUNTANCY CORPORATION
Bakersfield, California
March 5, 1999
F-2
<PAGE> 29
ROYALE ENERGY, INC.
BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
December 31, December 31,
1998 1997
------------ -----------
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents $1,016,306 $2,032,001
Accounts receivable 1,531,259 1,823,388
Receivables from related parties 49,412 34,218
Note receivable 118,149 159,024
Other current assets 169,103 136,459
---------- ----------
Total Current Assets 2,884,229 4,185,090
---------- ----------
OIL AND GAS PROPERTIES (SUCCESSFUL EFFORTS
BASIS), EQUIPMENT AND FIXTURES, NET 11,597,827 9,288,487
---------- ----------
OTHER ASSETS
Other capitalized costs 927,208 220,927
Receivables from other related parties 7,151 9,652
---------- ----------
Total Other Assets 934,359 230,579
---------- ----------
$15,416,415 $13,704,156
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial
statements
F-3
<PAGE> 30
ROYALE ENERGY, INC.
BALANCE SHEETS
LIABILITIES AND STOCKHOLDERS' EQUITY
<BTB>
<TABLE>
<CAPTION>
December 31, December 31,
1998 1997
------------ ------------
<S> <C> <C>
CURRENT LIABILITIES
Accounts payable and accrued expenses $1,249,127 $2,112,756
Deferred revenue from turnkey
drilling 2,834,976 1,735,826
---------- ----------
Total Current Liabilities 4,084,103 3,848,582
---------- ----------
LONG-TERM DEBT, NET OF CURRENT PORTION 5,000,000 3,900,000
---------- ----------
REDEEMABLE PREFERRED STOCK
Series A, convertible preferred stock,
no par value, 59,250 shares authorized;
9,375 and 16,875 shares, respectively,
issued and outstanding 19,100 49,100
---------- ----------
STOCKHOLDERS' EQUITY
Common stock, no par value, 10,000,000
shares authorized; 3,808,613 and
3,864,300 shares, respectively,
issued and outstanding 8,240,605 8,676,273
Convertible preferred stock, Series AA,
no par value, 147,500 shares authorized;
43,750 and 50,000 shares, respectively,
issued and outstanding 175,000 200,000
Accumulated deficit (2,007,893) (2,782,299)
----------- -----------
Total paid in capital and
accumulated deficit 6,407,712 6,093,974
---------- ----------
Less cost of treasury stock 19,300
and 37,500 shares, respectively (94,500) (187,500)
----------- -----------
Total Stockholders' Equity 6,313,212 5,906,474
---------- ----------
$15,416,415 $13,704,156
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial
statements.
F-4
<PAGE> 31
ROYALE ENERGY, INC.
STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1998 AND 1997
<TABLE><CAPTION><BTB>
Year Ended Year Ended
December 31, December 31,
1998 1997
------------ ------------
<S> <C> <C>
REVENUES
Sale of oil and gas $ 4,101,553 $ 2,992,679
Gas distribution - 46,925
Turnkey drilling 3,789,995 5,638,437
Supervisory fees and other 473,582 388,085
----------- -----------
Total Revenues 8,365,130 9,066,126
----------- -----------
COSTS AND EXPENSES
Cost of gas distribution sales - 23,741
General and administrative 1,606,702 1,437,046
Geological and geophysical expense 139,664 -
Turnkey drilling and development 1,541,624 3,163,945
Lease operating 1,020,541 611,437
Lease impairment 1,659,048 300,000
Legal and accounting 544,228 658,864
Marketing 422,693 443,740
Depreciation, depletion and
amortization 1,461,511 665,694
----------- -----------
Total Costs and Expenses 8,396,011 7,304,467
----------- -----------
INCOME (LOSS) FROM OPERATIONS (30,881) 1,761,659
----------- -----------
OTHER (EXPENSE)
Interest (335,373) (149,725)
----------- -----------
INCOME (LOSS) BEFORE INCOME TAX EXPENSE
AND CHANGE IN ACCOUNTING PRINCIPLE (366,254) 1,611,934
----------- -----------
INCOME TAX EXPENSE 52,868 101,551
----------- -----------
NET INCOME (LOSS) BEFORE CHANGE IN
ACCOUNTING PRINCIPLE (419,122) 1,510,383
CHANGE IN ACCOUNTING PRINCIPLE - CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING FOR THE
IMPAIRMENT OF LONG-LIVED ASSETS 1,193,528 -
----------- -----------
NET INCOME $ 774,406 $ 1,510,383
=========== ===========
(Continued)
</TABLE>
The accompanying notes are an integral part of these financial
statements.
F-5
<PAGE> 32
ROYALE ENERGY, INC.
STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1998 AND 1997
<TABLE>
<CAPTION>
Year Ended Year Ended
December 31, December 31,
1998 1997
------------ ------------
<S> <C> <C>
BASIC EARNINGS (LOSS) PER COMMON SHARE
(See Note 1)
Net income (loss) before changes
in accounting principles $ (0.11) $ 0.39
=========== ===========
Changes in accounting principles
per common share $ 0.31 $ -
=========== ===========
Net income per common share $ 0.20 $ 0.39
=========== ===========
Diluted earnings per common share
(see Note 1) $ 0.19 $ 0.37
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial
statements.
F-6
<PAGE> 33
ROYALE ENERGY, INC.
STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1998 AND 1997
<TABLE>
<CAPTION>
Preferred Stock
Common Stock Series AA Treasury Stock
-------------------- ------------------ -----------------
Number Number
of Shares of Shares
Issued Issued Number
and Out- and Out- Accumulated of
standing Amount standing Amount Deficit shares Amount
--------- ---------- --------- -------- ------------ ------ --------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance,
January
1, 1997 3,834,049 $8,386,273 115,000 $460,000 $(4,292,682) 4,200 $ 21,000
Shares
issued
in
connection
with
preferred
stock
Series A
Conversion 3,750 30,000 - - - - -
Shares
issued in
in
connection
with
preferred
stock
Series AA
Conversion 32,501 260,000 - - - - -
Shares
Purchased - - - - - 33,000 166,500
Shares
redeemed
and
canceled (6,000) - (65,000) (260,000) - - -
Net Income - - - - 1,510,383 - -
--------- ---------- --------- --------- ----------- ------ --------
Balance,
December
31, 1997 3,864,300 $8,676,273 50,000 $200,000 $(2,782,299) 37,500 $187,500
========= ========== ======== ========= ============ ====== ========
</TABLE>
(Continued on next page)
F-7
<PAGE> 34
ROYALE ENERGY, INC.
STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1998 AND 1997
<TABLE>
<CAPTION>
Preferred Stock
Common Stock Series AA Treasury Stock
-------------------- ------------------ -----------------
Number Number
of Shares of Shares
Issued Issued Number
and Out- and Out- Accumulated of
standing Amount standing Amount Deficit shares Amount
--------- ---------- --------- -------- ------------ ------ --------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance,
January
1, 1998 3,864,300 $8,676,273 50,000 $200,000 $(2,782,299) 37,500 $187,500
New
Shares
Issued 18,060 - - - - - -
Shares
issued
in
connection
with
preferred
stock
Series A
Conversion 3,750 30,000 - - - - -
Shares
issued in
in
connection
with
preferred
stock
Series AA
Conversion 3,125 25,000 - - - - -
Stock
Options
Repurchased - (86,250) - - - - -
Shares
redeemed
and
canceled (80,622) (404,418) (6,250) (25,000) - (18,200) (93,000)
Net Income - - - - 774,406 - -
--------- ---------- --------- --------- ----------- ------ --------
Balance,
December
31, 1998 3,808,613 $8,240,605 43,750 $175,000 $(2,007,893) 19,300 $ 94,500
========= ========== ======== ========= ============ ====== ========
</TABLE>
The accompanying notes are an integral part of these financial
statements.
F-8
<PAGE> 35
ROYALE ENERGY, INC.
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1998 AND 1997
<TABLE>
<CAPTION>
Year Ended Year Ended
December 31, December 31,
1998 1997
------------ ------------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 774,406 $ 1,510,383
Adjustment to reconcile net income
to net cash provided by operating
activities: Depreciation,
depletion and amortization 1,461,511 665,694
Loss on lease impairment 465,520 300,000
(Increase) decrease in:
Accounts receivable 292,129 105,084
Receivable from related parties 2,501 (6,117)
Prepaid expenses and other assets (32,644) 54,076
Notes receivable 40,875 (27,177)
Increase(Decrease) in:
Accounts payable and accrued
expenses (863,629) 165,051
Deferred revenues - DWI 1,099,150 231,785
----------- -----------
Net Cash Provided by
Operating Activities 3,239,819 2,998,779
----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for oil and gas
properties (4,817,413) (6,929,049)
Proceeds from sale of oil and
gas properties - 7,307
Other capital expenditures (125,239) (74,659)
----------- -----------
Net Cash Used by Investing
Activities (4,942,652) (6,996,401)
----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES
(Increase) decrease in receivable from
related parties, net (15,194) 679
Proceeds from line of credit 1,100,000 3,900,000
Principal payments on notes payable - (300,000)
Common stock purchased and canceled (397,668) -
Treasury stock sold - (166,500)
----------- -----------
Net Cash Provided by Financing
Activities 687,138 3,434,179
----------- -----------
NET DECREASE IN CASH AND
CASH EQUIVALENTS (1,015,695) (563,443)
CASH AT BEGINNING OF YEAR 2,032,001 2,595,444
----------- -----------
CASH AT END OF YEAR $ 1,016,306 $ 2,032,001
=========== ===========
</TABLE>
(Continued on next page)
F-9
<PAGE> 36
ROYALE ENERGY FUNDS, INC.
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1998 AND 1997
<TABLE>
<CAPTION>
Year Ended Year Ended
December 31, December 31,
1998 1997
------------ ------------
<S> <C> <C>
SUPPLEMENTAL INFORMATION:
Cash paid for interest $ 335,373 $ 149,725
Cash paid for taxes 800 101,551
NONCASH TRANSACTIONS:
Series A preferred stock exchanged
for common stock 30,000 30,000
Series AA stock exchanged for
common stock 25,000 260,000
Treasury stock reclassed to
common stock 93,000 -
</TABLE>
The accompanying notes are an integral part of these financial
statements.
F-10
<PAGE> 37
ROYALE ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
This summary of significant accounting policies of Royale Energy, Inc.
(the "Company") is presented to assist in understanding the Company's
financial statements. The financial statements and notes are
representations of the Company's management, which is responsible for
their integrity and objectivity. These accounting policies conform to
generally accepted accounting principles and have been consistently
applied in the preparation of the financial statements.
Description of Business
The Company is an independent oil and gas producer which also has
operations in the area of turnkey drilling. The Company owns wells and
leases in major geological basins located in California. The Company
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 Company oil and gas reserves prepared
by an independent engineering consultant. Such estimates are subject to
numerous uncertainties inherent in the estimation of quantities of
proved reserves. Estimated reserves are used in the calculation of
depletion, depreciation and amortization as well as the Company's
assessment of proved oil and gas properties for impairment.
Revenue Recognition
The Company recognizes revenues from the sales of oil and gas in the
period of delivery.
The Company enters into turnkey drilling agreements with investors to
develop leasehold acreage acquired by the Company. The Company receives
funds from investors for the drilling and completion of oil and gas
wells. A percentage of total funds invested are used by the Company to
pay their share of the land costs and other costs as required to allow
the drilling projects to proceed without delay. These funds are non-refundable
once the investment has been made. The non-refundable portion
of the total Turnkey Drilling investment is based on a percentage
calculated by estimating the pre-drilling costs as a percentage of total
drilling costs for a particular investment. The non-refundable portion
of the total investment is recognized as revenue and the related pre-drilling
costs are expensed. If costs exceed revenues and the Company
participates as a working interest owner, the excess is capitalized as
the cost of the Company's working interest. If the Company 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 the Company, along with the investors, receive an
assignment of working interests. Included in cash and cash equivalents
are amounts for use in the completion of Turnkey drilling programs in
progress.
F-11
<PAGE> 38
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Oil and Gas Property and Equipment (Successful Efforts)
The Company 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 but is
subsequently expensed if proved reserves are not found. 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, the Company 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.
Prior to 1998, the Company performed the impairment review on a field by
field basis. In 1998, management decided to perform the impairment
review on a region by region basis. According to management, regional
aggregations of fields are more consistent with the company's operations
and identifiable sources of cash flows. Regional aggregations of fields
also correctly reflect geological relationships between proved reserves.
This change is reflected as a change in accounting principle on the
Company's income statement. The change does not have a material effect
on the prior period's net income.
In 1997, $300,000, was recorded as an impairment loss based on
management's assessment. Impairment loss for the year ended December
31, 1998 was $1,659,048 reduced by $1,193,528 as a result of the change
in accounting principle for a net expense of $465,520.
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. Upon
abandonment of properties, the reserves are deemed fully depleted and
any unamortized costs are recorded in the statement of operations under
loss on leases.
Other Capitalized Costs
Other capitalized costs are related to 3D seismic studies performed by
an outside Geophysical and Geological company on behalf of the Company.
The cost of this data is based on cost per square mile multiplied by the
number of squares analyzed. The data is used by the Company to enhance
or evaluate proposed developments of its proved and unproved fields, as
well as held for sale to outside parties. As the Company uses the data
for its exploratory and development projects, that portion of the
capitalized costs used will be reclassified as proved oil and gas
properties or expensed. The portion of the data library not used by the
Company for its projects will be amortized over a three year period
using the straight-line method.
As of the audit report date, the Company had not licensed and/or sold
seismic data to outside parties.
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.
F-12
<PAGE> 39
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
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.
Capitalization of Interest
Interest cost is capitalized on construction and development programs
until placed into operation.
Earnings (Loss) Per Share (SFAS 128)
In February 1997, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 128 (SFAS 128), "Earnings
Per Share", which was adopted by the Company for the year ended December
31, 1997. SFAS 128 replaces the presentation of primary earnings per
share with a presentation of basic earnings per share based upon the
weighted average number of common shares for the period. It also
requires dual presentation of basic and diluted earnings per share for
companies with complex structures.
Basic and diluted earnings (loss) per share are calculated as follows:
<TABLE>
<CAPTION>
For the Year Ended 1998
--------------------------------------
Income Shares Per-Share
(Numerator) (Denominator) Amount
------------ ------------- --------
<S> <C> <C> <C>
Basic Earnings (Loss) Per Share:
Net income (loss) available to
common stock before changes in
accounting principles $ (419,122) 3,839,127 $ (0.11)
Changes in accounting principles 1,193,528 0.31
----------- ----------- --------
Net income (loss) available
to common stock $ 774,406 $ 0.20
=========== =========== ========
Diluted Earnings (Loss) Per Share:
Net income (loss) available to
common stock before changes in
accounting principles $ (419,122) 3,839,127 $ (0.11)
Effect of dilutive securities
and stock options - 294,883 .01
----------- ---------- --------
Net income (loss) available to
common stock before changes in
accounting principles (419,122) 4,134,010 (0.10)
Changes in accounting principles 1,193,528 0.29
----------- ---------- --------
Net income (loss) available
to common stock $ 774,406 $ 0.19
=========== ========== ========
</TABLE>
F-13
<PAGE> 40
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Earnings (Loss) Per Share (SFAS 128) (Continued)
<BTB>
<TABLE>
<CAPTION>
For the Year Ended 1997
--------------------------------------
Income Shares Per-Share
(Numerator) (Denominator) Amount
------------ ------------- --------
<S> <C> <C> <C>
Basic Earnings Per Share:
Net income available to
common stock before changes in
accounting principles $ 1,510,383 3,861,589 $ 0.39
Changes in accounting principles - -
----------- ----------- --------
Net income available
to common stock $ 1,510,383 $ 0.39
=========== =========== ========
Diluted Earnings Per Share:
Net income available to
common stock before changes in
accounting principles $ 1,510,383 3,861,589 $ 0.39
Effect of dilutive securities
and stock options - 244,006 (.02)
----------- ---------- --------
Net income available to
common stock before changes
in accounting principles 1,510,383 4,105,595 0.37
Changes in accounting principles - -
----------- ---------- --------
Net income available
to common stock $ 1,510,383 $ 0.37
=========== ========== ========
</TABLE>
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.
The Company includes fair value in the notes to financial statements
when the fair value of its financial instruments is different from the
book value. The Company assumes that the book value of financial
instruments that are classified as current approximate fair value
because of the short maturity of these instruments. For noncurrent
financial instruments, the Company uses quoted market prices or, to the
extent that there are no available quoted market prices, market prices
for similar instruments.
Reclassification
Certain amounts in the financial statements have been reclassified to be
consistent and comparable from year-to-year.
F-14
<PAGE> 41
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
New Accounting Pronouncements
Effective January 1, 1998, the Company adopted Statement of Financial
Accounting Standards No. 130 (SFAS 130), Reporting Comprehensive Income.
This statement requires that all items that are required to be
recognized under accounting standards as components of comprehensive
income be reported in a financial statement that is displayed with the
same prominence as other financial statements. Comprehensive income is
the same as net income for all years presented.
Effective January 1, 1998, the Company adopted Statement of Accounting
Standards No. 131 (SFAS 131), Disclosures about Segments of an
Enterprise and Related Information. This statement requires the Company
to report income/loss, revenue, expense and assets by business segment
including information regarding the revenues derived from specific
products and services and about the countries in which the Company is
operating. The Statement also requires that the Company report
descriptive information about the way that operating segments were
determined, the products and services provided by the operating
segments, differences between the measurements used in reporting segment
information and those used in the Company's general-purpose financial
statements and changes in the measurement of segment amounts from period
to period. As noted above this statement establishes standards for
reporting and display and has no material effect on the Company's
financial condition or results of operations.
In February 1998, the FASB issued Statement of Financial Accounting
Standards No. 132 (SFAS 132), Employers' Disclosures about Pensions and
other Postretirement Benefits. This statement standardizes the
disclosure requirements for pension and other post retirement benefits.
The Company typically does not offer the types of benefit programs that
fall under the guidelines of this statement.
In June 1998, the FASB issued Statement of Financial Accounting
Standards No. 133 (SFAS 133), Accounting for Derivative Instruments and
Hedging Activities. This statement establishes accounting and reporting
standards for derivative instruments and requires recognition of all
derivatives as assets or liabilities in the statement of financial
position and measurement of those instruments at fair value. The
statement is effective for fiscal years beginning after June 15, 1999.
The Company does not have any derrvative instruments or hedging
activities. Management does not anticipate any impact to the Company's
financial statements as a result of the adoption of this statement.
NOTE 2 - NOTE RECEIVABLE
Notes receivable at December 31, 1998 consist of $103,116 note from an
individual secured by oil and natural gas interests bearing an interest
rate of prime plus 1.5%, and a note from a corporation in the amount of
$15,033 secured by Royale Covenant Security Corporation stock, bearing
an interest rate of prime plus 1.5%.
F-15
<PAGE> 42
NOTE 3 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES
Oil and gas properties, equipment and fixtures consist of the following
at December 31:
Oil and Gas
<TABLE>
<CAPTION>
1998 1997
------------ ------------
<S> <C> <C>
Producing properties, including
intangible drilling costs $ 9,180,297 $ 8,868,655
Undeveloped properties 1,444,942 295,022
Lease and well equipment 3,950,428 2,442,696
----------- -----------
14,575,667 11,606,373
Accumulated depletion, depreciation
and amortization (3,127,477) (1,717,620)
Reserve for lease impairment - (728,938)
----------- -----------
11,448,190 9,159,815
----------- -----------
Commercial and Other
Furniture and equipment 355,254 282,153
Accumulated depreciation (205,617) (153,481)
----------- -----------
149,637 128,672
----------- -----------
$11,597,827 $ 9,288,487
=========== ===========
</TABLE>
The following sets forth costs incurred for oil and gas property
acquisition and development activities, whether capitalized or expensed:
<TABLE>
<CAPTION>
1998 1997
------------ ------------
<S> <C> <C>
Acquisition $ 979,068 $ 3,999,087
Development $ 4,048,896 $ 5,150,617
</TABLE>
In July 1997, the Company acquired additional working interests in
producing wells and properties with development potential. In exchange
for these working interests and properties, the Company gave
consideration of cash by utilizing their credit line and cash in the
bank.
F-16
<PAGE> 43
NOTE 3 - OIL AND GAS PROPERTIES, EQUIPMENT AND FIXTURES (Continued)
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:
<TABLE>
<CAPTION>
1998 1997
------------ ------------
<S> <C> <C>
Oil and gas sales $ 4,101,553 $ 2,992,679
Production related costs (1,020,541) (611,437)
Geological and geophysical expense (139,664) -
Depreciation, depletion and
amortization (1,409,858) (631,133)
----------- -----------
Results of operations from producing
and exploration activities $ 1,531,490 $ 1,750,109
=========== ===========
</TABLE>
NOTE 4 - TURNKEY DRILLING CONTRACTS
The Company receives funds under turnkey drilling contracts which
requires the Company to drill oil and gas wells within a reasonable time
period from the date of receipt of the funds. As of December 31, 1998
and 1997, the Company had recorded deferred turnkey drilling revenue
associated with undrilled wells of $2,834,976 and $1,735,826,
respectively, as a current liability.
NOTE 5 - FINANCIAL INFORMATION RELATING TO INDUSTRY SEGMENTS
The Company adopted SFAS No. 131, Disclosure About Segments of an
Enterprise and Related Information SFAS 131" in 1998 which changes the
way the Company reports information about its operating segments.
The Company identifies reportable segments by product and country,
although the Company currently does not have foreign country segments.
The Company includes revenues from both external customers and revenues
from transactions with other operating segments in its measure of
segment profit or loss. The Company 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).
F-17
<PAGE> 44
NOTE 5 - FINANCIAL INFORMATION RELATING TO INDUSTRY SEGMENTS (Continued)
The Company's operations are classified into two principal industry
segments. Following is a summary of segmented information for 1998 and
1997:
<TABLE>
<CAPTION>
Oil and Gas
Producing Turnkey
and Drilling
Exploration Services Total
----------- ------------ ----------
<S> <C> <C> <C>
Year Ended December 31, 1998
Revenues from External
Customers $ 4,101,553 $ 3,789,995 $ 7,891,548
============ ============ ============
Interest Revenue $ 57,882 $ - $ 57,882
============ ============ ============
Interest Expense $ 335,373 $ - $ 335,373
============ ============ ============
Expenditures for Segment Assets $ 3,023,868 $ 1,541,624 $ 4,565,482
============ ============ ============
Depreciation, Depletion,
and Amortization $ 1,409,858 $ - $ 1,409,858
============ ============ ============
Lease Impairment $ 1,659,048 $ - $ 1,659,048
============ ============ ============
Total Assets $ 15,416,415 $ - $ 15,416,415
============ ============ ============
Income (Loss) Before Income
Tax and Change in
Accounting Principle $ (2,614,625 ) $ 2,248,371 $ (366,254)
Income Tax Expense - 52,868 52,868
------------ ------------ ------------
Net Income (Loss) Before Change
in Accounting Principle (2,614,625) 2,195,503 (419,122)
Changes in Accounting Principle -
Cumulative Effect of Change
in Accounting for the
Impairment of Long-Lived
Assets 1,193,528 - 1,193,528
------------ ------------ ------------
Net Income (Loss) $ (1,421,097) $ 2,195,503 $ 774,406
============ ============ ============
Year Ended December 31, 1997
Revenues from External
Customers $ 2,992,679 $ 5,638,437 $ 8,631,116
============ ============ ============
Interest Revenue $ 56,376 $ - $ 56,376
============ ============ ============
Interest Expense $ 149,725 $ - $ 149,725
============ ============ ============
Expenditures for Segment Assets $ 6,929,049 $ 611,437 $ 7,540,486
============ ============ ============
Depreciation, Depletion,
and Amortization $ 631,133 $ - $ 631,133
============ ============ ============
Lease Impairment $ 300,000 $ - $ 300,000
============ ============ ============
Total Assets $ 13,704,156 $ - $ 13,704,156
============ ============ ============
Income (Loss) Before Income
Tax and Change in
Accounting Principle $ (862,558) $ 2,474,492 $ 1,611,934
Income Tax Expense 101,551 - $ 101,551
------------ ------------ ------------
Net Income (Loss) Before Change
in Accounting Principle (964,109) $ 2,474,492 $ 1,510,383
Changes in Accounting Principle -
Cumulative Effect of Change
in Accounting for the
Impairment of Long-Lived
Assets - - -
----------- ------------ ------------
Net Income (Loss) $ (964,109) $ 2,474,492 $ 1,510,383
============ ============ ============
</TABLE>
F-18
<PAGE> 45
NOTE 6 - LONG-TERM DEBT
<TABLE>
<CAPTION>
1998 1997
----------- ----------
<S> <C> <C>
Revolving line of credit with a
maximum available of $5,000,000 for
working capital purposes, acquisitions,
and development of oil and gas
properties. Agreement was amended on
November 13, 1998. Interest at New York
prime plus 75.0 and 137.5 basis points,
resulting in rates of 8.5% and 9.875%
at December 31, 1998 and 1997,
respectively. Principal and interest
payable monthly, with the remaining
outstanding principal due at maturity
on January 31, 2000. Secured by
property and assignment of production. $ 5,000,000 $3,900,000
=========== ==========
</TABLE>
Maturities of long-term debt for years subsequent to December 31, 1998 are as
follows:
<TABLE>
<CAPTION>
December 31,
<C> <C>
2000 $ 5,000,000
===========
</TABLE>
The loan agreement for the revolving line of credit prohibits the purchase of
treasury stock; however, the lender has waived this requirement under
specific circumstances. The Company purchased treasury stock under this
waiver in 1997 and 1998.
NOTE 7 - INCOME TAXES
The provisions for income taxes for the years ended December 31, 1998 and 1997
represents minimum state taxes.
As of December 31, 1998, the Company had federal net operating loss
carryforwards as indicated:
<TABLE>
<CAPTION>
Year Year of Net Operating
Originated Expiration Loss
---------- ---------- --------------
<C> <C> <C>
1990 2006 $ 797,786
1991 2007 970,101
1992 2008 227,241
1993 2009 1,654,713
------------
$ 3,649,841
============
</TABLE>
F-19
<PAGE> 46
NOTE 7 - INCOME TAXES (Continued)
The components of the net deferred tax assets were as follows:
<TABLE>
<CAPTION>
1998 1997
------------ ------------
<S> <C> <C>
Deferred Tax Assets:
Net operating loss carryforwards $ 1,240,946 $ 1,314,318
Statutory depletion carryforwards 227,904 182,622
Accumulated depreciation 23,799 94,487
----------- -----------
Total Deferred Tax Assets 1,492,649 1,591,427
----------- -----------
Valuation Allowance (1,492,649) (1,591,427)
----------- -----------
Net Deferred Tax Assets $ - $ -
=========== ===========
</TABLE>
A full valuation allowance has been established for the deferred tax
assets generated by net operating loss carryforwards due to the
uncertainty of future utilization.
A reconciliation of the Company's provision for income taxes and the
amount computed by applying the U.S. statutory federal income tax rate
of 34% at December 31, 1998 and 1997, respectively, to pretax income is
as follows:
<TABLE>
<CAPTION>
1998 1997
------------ ------------
<S> <C> <C>
Tax computed at 34%, respectively $ 281,001 $ 513,533
Increase (decrease) in taxes
resulting from:
Net operating loss carryforwards (281,001) (513,533)
State taxes 52,868 101,551
----------- -----------
$ 52,868 $ 101,551
=========== ===========
Effective Tax Rate 6.8% 5.6%
==== ====
</TABLE>
NOTE 8 - REDEEMABLE PREFERRED STOCK
In 1993, the Company'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. The
Company 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.
There were no dividends declared and/or paid during 1998 or 1997.
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. The Company
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-20
<PAGE> 47
NOTE 8 - REDEEMABLE PREFERRED STOCK (Continued)
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 the Company 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, the Company'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, 1998,
224,875 shares of Series A Convertible Preferred Stock had been
converted to 198,625 shares of common stock.
NOTE 9 - SERIES AA PREFERRED STOCK
In April 1992, the Company'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, 1998 and 1997, there were
43,750 and 50,000 shares issued and outstanding, respectively. The
dividend has been paid on all shares outstanding at December 31, 1998.
NOTE 10 - COMMON STOCK
During 1998, 3,125 shares of common stock were issued for conversion of
6,250 Series AA Preferred Stock, and 3,750 common shares were issued for
conversion of 7,500 shares of Series A Preferred Stock. Also, in 1998,
12,200 shares were canceled. Additionally, 62,422 shares of the
Company's common stock were repurchased and canceled. The Company's
Board of Directors, at its December 1997 meeting, authorized the
repurchase and cancellation of up to 15% of the outstanding common stock
of the Company.
During 1997, 32,501 shares of common stock were issued for conversion of
65,000 Series AA Preferred Stock, and 3,750 common shares were issued
for conversion of 7,500 shares of Series A Preferred Stock. Also, in
1997, 6,000 shares were canceled as a result of a settlement agreement
executed in 1996. This settlement agreement was not material to the
Company as a whole.
NOTE 11 - STOCK WARRANTS
Changes in the Company's common stock warrants were as follows:
<TABLE>
<CAPTION>
Year Ended Year Ended
December 31, December 31,
1998 1997
------------ ------------
<S> <C> <C>
Outstanding warrants at beginning
of period 230,555 230,555
Additional warrants issued
- Exercise of stock warrants - -
- Warrants expired or ineligible - -
---------- ----------
Outstanding warrants at end of period 230,555 230,555
========== ==========
</TABLE>
F-21
<PAGE> 48
NOTE 11 - STOCK WARRANTS (Continued)
The Company's affiliate, RPC, acquired 111,111 shares of the Company'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 the Company'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 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
the Company'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.
NOTE 12 - OPERATING LEASES
The Company leases office space under a sixty month noncancellable
operating lease, which expires in July 2000. The lease calls for monthly
payments ranging from $10,875 to $12,325. Future minimum lease
obligations as of December 31, 1998 are as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
<C> <C>
1999 $ 145,359
2000 86,275
-----------
$ 231,634
===========
</TABLE>
Rental expense for the years ended December 31, 1998 and 1997, was
$146,397 and $138,664, respectively.
NOTE 13 - RELATED PARTY TRANSACTIONS
Significant Ownership Interests
On December 31, 1998, 27.40% of the Company'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, the Company's former president and former chief
executive officer, is principal adviser to trusts which own 10.50% of
the Company's common stock at December 31, 1998. 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 the Company.
Related Party Receivables
Amounts due from officers were $49,412 and $34,218 at December 31, 1998
and 1997, respectively. Receivables from other related parties amounted
to $7,151 and $9,652 on December 31, 1998 and 1997, respectively.
F-22
<PAGE> 49
NOTE 13 - RELATED PARTY TRANSACTIONS (Continued)
Stock Compensation Plan
On December 18, 1992, the Board of Directors granted the directors and
executive officers of the Company 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.
At the March 10, 1995 Board of Directors meeting, directors and
executive officers of the Company 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. The Company applies
APB Opinion 25 and related interpretations in accounting for its plans.
Accordingly, the Company recorded $48,150 as compensation expense for
the directors and officers in 1995. The Company did not grant stock
options during 1998 or 1997.
A summary of the status of the Company's stock option plan as of
December 31, 1998 and 1997, and changes during the years ending on those
dates is presented below:
<TABLE>
<CAPTION>
1998 1997
---------------------- ----------------------
Weighted- Weighted-
Average Average
Shares Exercise Price Shares Exercise Price
------ -------------- ------ --------------
<S> <C> <C> <C> <C>
Fixed Options
Outstanding at
beginning of year 184,000 $ 2.15 184,000 $ 2.86
Granted - -
Exercised 50,000 -
------- -------
Outstanding at end
of year 134,000 184,000
======= =======
Options exercisable
at year end 134,000 184,000
======= =======
Weighted-average fair
value of options
granted during
the year $ - $ -
</TABLE>
The following table summarizes information about fixed stock options
outstanding at December 31, 1998:
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
--------------------------------------- ---------------------------
Weighted- Weighted-
Number Average Weighted- Number Average
Range of Outstanding at Remaining Average Outstanding at Remaining
Exercise December 31, Contractual Exercise December 31, Contractual
Prices 1998 Life (Years) Price 1997 Life (Years)
- --------- ------------- ------------ --------- ------------- ------------
<C> <C> <C> <C> <C> <C>
$ 3.00 30,000 4.0 $ 3.00 30,000 5.0
$ 1.90 104,000 6.2 $ 1.90 154,000 7.2
------------- -------------
$ 1.90 to $ 1.90 to
$ 3.00 134,000 5.7 $ 3.00 184,000 6.6
============= =============
</TABLE>
F-23
<PAGE> 50
NOTE 13 - RELATED PARTY TRANSACTIONS (Continued)
The Board of Directors adopted a policy in 1989 that permits directors
and officers of the Company to purchase from the Company, at the
Company's actual cost, up to one percent of a fractional interest in any
well to be drilled by the Company. Current and former officers and
directors received as compensation or were billed $24,811 and $35,475
for their interests for the years ended December 31, 1998 and 1997,
respectively.
NOTE 14 - ENVIRONMENTAL MATTERS
The Company 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 the Company's business requires routine day-to-day
compliance with environmental laws and regulations. The Company incurred
no environmental investigation, compliance and remediation costs in 1998
or 1997.
The Company 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 the Company.
NOTE 15 - COMMITMENTS AND CONTINGENCIES
In 1996, the Company agreed to purchase 37,500 shares of its common
stock from an investor as part of a mediated settlement of litigation.
The stock was purchased at a total price of $187,500 with 4,200 shares
purchased in December of 1996 for $21,000 and the remaining 33,300
shares purchased for $166,500 during 1997. As of December 31, 1998, the
Company had satisfied their obligation under the agreement, however,
18,900 of the 37,500 shares had not been received by the Company from
the investor. Shares received by the Company as a result of this
settlement were canceled during 1998.
In October 1997, the Company settled its litigated issues with Stanley
L. Worthington. To avoid further litigation on this matter, the Company
agreed to re-purchase Mr. Worthington's oil and gas working interests.
The re-purchase amount, which is considered material to the financial
statements, was capitalized as an investment in the working interest
acquired.
In May 1998, the Company settled its litigated issues with Lucille F.
Biegel, et al. To avoid further litigation on this matter, the Company
agreed to re-purchase the claimants oil and gas working interests. The
re-purchase amount, which is considered material to the financial
statements, was capitalized as an investment in the working interest
acquired.
F-24
<PAGE> 51
NOTE 16 - QUARTERLY FINANCIAL DATA (UNAUDITED)
Operating revenues, operating income, net income, and earnings per
common share by quarters from 1998 and 1997 are shown below. The
Company, 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.
<TABLE>
<CAPTION>
Basic
Aggregate Earnings Weighted-
Effect of Change in Net Per Average
Total Gross Year-End Accounting Income Common Shares
Quarter Ended Revenues Profit Adjustment Principle (Loss) Shares Outstanding
- ------------- -------- ------ ---------- ---------- ------ -------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
December 31, 1998 $2,115,378 $ 817,637 $(254,987) $1,193,528 $(233,095) 0.00 3,839,127
1997 2,687,906 1,316,638 - - 471,094 0.12 3,861,589
September 30, 1998 $1,732,662 $1,122,345 $ - $ - $ 333,262 0.09 3,797,636
1997 2,314,392 1,366,755 - - 522,926 0.13 3,853,569
June 30, 1998 3,025,311 1,484,204 - - 567,944 0.15 3,832,629
1997 2,520,193 1,258,232 - - 448,332 0.12 3,845,062
March 31, 1998 1,491,779 917,268 - - 106,295 0.03 3,864,845
1997 1,543,635 659,684 - - 68,039 0.02 3,837,555
</TABLE>
F-25
<PAGE> 52
ROYALE ENERGY, INC.
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)
The following estimates of proved oil and gas reserves, both developed
and undeveloped, represent interests owned by the Company 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, 1998 and 1997. 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 the Company. 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.
F-26
<PAGE> 53
Changes in Estimated Reserve Quantities
The net interest in estimated quantities of proved developed reserves of
crude oil and natural gas at December 31, 1998 and 1997 and changes in
such quantities during each of the years then ended, were as follows:
<TABLE>
<CAPTION>
1998 1997
------------------- --------------------
Oil Gas Oil Gas
(BBL) (MCF) (BBL) (MCF)
------- --------- -------- --------
<S> <C> <C> <C> <C>
Proved developed and
undeveloped reserves:
Beginning of period 4,698 16,882,699 1,647 12,909,322
Revisions of previous
estimates (386) (2,153,290) 3,730 (5,522,625)
Production (4,312) (6,099,330) (679) (1,365,562)
Extensions, discoveries
and improved recovery - 5,003,000 - 8,087,987
Purchase of minerals
in place - 1,614,921 - 2,773,577
Sale of minerals
in place - - - -
------- ----------- ------ ----------
Proved reserves end
of period - 15,248,000 4,698 16,882,699
====== ========= ====== ==========
Gas equivalent reserve - 46,980
====== ======
Proved developed and undeveloped
reserves:
Beginning of period 4,698 16,882,699 1,647 12,909,322
====== ========== ====== ==========
End of period - 15,248,000 4,698 16,882,699
====== ========== ====== ==========
</TABLE>
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, 1998.
The future net cash inflows are developed as follows:
(1) Estimates are made of quantities of proved reserves and
the future periods during which they are expected to be
produced based on year-end economic conditions.
(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.
(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.
F-27
<PAGE> 54
<TABLE>
<CAPTION>
1998 1997
------------ ---------
<S> <C> <C>
Future cash inflows $36,230,000 $37,322,465
Future production costs (10,674,000) (8,721,586)
Future development costs (2,557,000) (2,706,685)
Future income tax expenses (6,899,700) (7,782,165)
----------- -----------
Future net cash flows 16,099,300 18,112,029
10% annual discount for estimated
timing of cash flows (6,028,407) (5,125,811)
----------- -----------
Standardized measure of discounted
future net cash flow $10,070,893 $12,986,218
=========== ===========
</TABLE>
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.
<TABLE>
<CAPTION>
1998 1997
------------ ------------
<S> <C> <C>
Standardized measure -
beginning of year $12,986,218 $12,021,253
----------- -----------
Sales of oil and gas produced,
net of production costs (6,824,289) (1,515,072)
Purchase of minerals in place 1,890,036 2,662,529
Revisions of estimates of reserves
provided in prior years:
Net changes in prices and production
costs (4,330,121) (9,799,460)
Extensions, discoveries and improved
recovery 5,057,000 10,422,897
Accretion of discount 42,624 (392,373)
Net change in income taxes 1,249,425 (413,556)
----------- -----------
Net increase (decrease) (2,915,325) 964,965
----------- -----------
Standardized measure - end of year $10,070,893 $12,986,218
=========== ===========
</TABLE>
F-28
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<CASH> 1,016,036
<SECURITIES> 0
<RECEIVABLES> 1,698,820
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 2,884,229
<PP&E> 14,930,921
<DEPRECIATION> 3,333,094
<TOTAL-ASSETS> 15,416,415
<CURRENT-LIABILITIES> 4,084,103
<BONDS> 0
19,100
175,000
<COMMON> 8,240,605
<OTHER-SE> 2,102,393
<TOTAL-LIABILITY-AND-EQUITY> 15,416,415
<SALES> 7,891,548
<TOTAL-REVENUES> 8,365,130
<CGS> 2,562,165
<TOTAL-COSTS> 8,396,011
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 335,373
<INCOME-PRETAX> (366,254)
<INCOME-TAX> 52,868
<INCOME-CONTINUING> (419,122)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 1,193,528
<NET-INCOME> 774,406
<EPS-PRIMARY> 0.20
<EPS-DILUTED> 0.19
