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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended: December 31, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
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COMMISSION FILE NUMBER: 0-02517
TOREADOR RESOURCES CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 75-0991164
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
4809 COLE AVENUE
SUITE 108
DALLAS, TEXAS 75205
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (214) 559-3933
Securities registered pursuant to Section 12(b) of the Act:
NONE
Securities registered pursuant to Section 12(g) of the Act:
TITLE OF EACH CLASS: NAME OF EACH EXCHANGE ON WHICH REGISTERED:
------------------- -----------------------------------------
COMMON STOCK, PAR VALUE $.15625 PER SHARE NASDAQ NATIONAL MARKET SYSTEM
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Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 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
---
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ].
The aggregate market value of the voting stock of the registrant held
by non-affiliates, computed by reference to the closing sales price of such
stock, as of March 16, 2001 was $18,046,450. (For purposes of determination of
the foregoing amount, only directors, executive officers and 10% or greater
stockholders have been deemed affiliates.)
The number of shares outstanding of the registrant's Common Stock, par
value $.15625, as of March 16, 2001, was 6,270,944 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's Proxy Statement for the 2001 Annual
Meeting of Stockholders, expected to be filed on or prior to April 30, 2001, are
incorporated by reference into Part III of this Form 10-K.
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TABLE OF CONTENTS
Page
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PART I .............................................................................................1
ITEM 1. BUSINESS.....................................................................................1
ITEM 2. PROPERTIES..................................................................................14
ITEM 3. LEGAL PROCEEDINGS...........................................................................21
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS .......................................21
PART II ............................................................................................22
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS.........................................................................22
ITEM 6. SELECTED FINANCIAL DATA.....................................................................23
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATION........................................................................24
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK..................................28
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.................................................29
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE....................................................................29
PART III ............................................................................................30
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. ........................................30
ITEM 11. EXECUTIVE COMPENSATION......................................................................30
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT..................................................................................30
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS..............................................30
PART IV ............................................................................................30
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K............................30
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PART I
FORWARD-LOOKING STATEMENTS
Before you invest in the Common Stock of Toreador Resources
Corporation, you should be aware that there are various risks associated with an
investment, including the risks described below and risks that we highlighted in
other sections of this report, including "Item 1. Business - Risk Factors". You
should consider carefully these risk factors together with all of the other
information included in this report before you decide to purchase shares of our
Common Stock.
Some of the information in this report may contain forward-looking
statements. We use words such as "may," "will," "expect," "anticipate,"
"estimate," "believe," "continue," or other similar words to identify
forward-looking statements. You should read statements that contain these words
carefully because they (1) discuss future expectations; (2) contain projections
of our results of operations or of our financial conditions; or (3) state other
"forward-looking" information. We believe that it is important to communicate
our future expectations to our investors. However, there may be events in the
future that we are unable to accurately predict or over which we have no
control. When considering our forward-looking statements, you should keep in
mind the risk factors and other cautionary statements in this report. The risk
factors noted in this section and other factors noted throughout this report
provide example of risks, uncertainties and events that may cause our actual
results to differ materially from those contained in any forward-looking
statement.
ITEM 1. BUSINESS
GENERAL
Toreador Resources Corporation, a Delaware corporation ("Toreador" or
the "Company"), is an independent energy company engaged in oil and gas
exploration, development, production and acquisition activities. We principally
conduct our business through our ownership of perpetual mineral and royalty
interests in approximately 2,643,000 gross (1,368,000 net) acres. These
properties include 766,000 gross (461,000 net) acres located in the Texas
Panhandle and West Texas. Collectively we refer to these properties as the
"Texas Holdings." In Alabama, Mississippi and Louisiana, we own 1,775,000 gross
(876,000 net) acres that we collectively describe as the "Southeastern States
Holdings." We also own various royalty interests in Arkansas, California, Kansas
and Michigan covering 102,000 gross (31,000 net) acres. These properties are
collectively referred to as the "Four States Holdings". In addition to the
aforementioned holdings, we own various working interest properties in Texas,
Kansas, New Mexico and Oklahoma. We do not have any property interests anywhere
other than the United States. For a more detailed description of these
properties please see "Item 2. Properties."
See "Glossary of Selected Oil and Gas Oil Terms" at the end of this
Item 1 for a definition of certain terms defined in this report.
HISTORY
We were incorporated in 1951, and were formerly known as Toreador
Royalty Corporation. The history of our Texas Holdings dates back to the
formation of the Matador Land & Cattle Company in 1882. Scottish investors
assembled approximately 1,000,000 acres of land that was located in what is now
the Texas Panhandle and West Texas. When this property was sold in 1951,
Toreador was formed and was assigned 50% of the mineral rights under the ranch
acreage. In 1958 we acquired an additional 25% of the mineral rights under a
number of the original ranch properties.
As of December 31, 2000, a total of 187 exploration and development
wells had been drilled on our Texas Holdings since 1951. Overall, well density
is approximately one well per 3,700 acres. In certain sections, well density is
less than one well per 20,000 acres.
As a result of acquisitions in 1998 and 1999 and the lone merger in
2000, we now own more mineral, royalty and leasehold interests in addition to
our Texas Holdings. Please see "Item 1. Business -- Acquisitions & Mergers and
Item 2. Properties." for more detailed information.
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BUSINESS STRATEGY
Our strategic focus during 2000 centered on the pursuit of high quality
property acquisitions, participation in exploration projects as a non-operator
and the disposition of non-strategic assets. The principal elements of our
ongoing strategic focus are as follows:
o Pursue opportunities to make high quality property
acquisitions.
o Identify and dispose of non-strategic assets in all areas in
order to take advantage of favorable oil and gas prices. We
intend to use multiple avenues in this marketing effort,
including Internet based auctions held by EnergyNet.com, Inc.
o Expand our level of direct working interest participation as a
non-operator in exploration projects that provide exposure in
drilling opportunities for both multiple prospects and
multiple pay zones. We expect these opportunities to be
generated by experienced third party operators using current
generation three-dimensional ("3-D") seismic technology.
DEVELOPMENTS DURING 2000 AND 1999
ACQUISITIONS & MERGERS
As part of our strategy to actively pursue high quality property
acquisition and merger opportunities, we reviewed a number of prospective
candidates during 2000. We successfully closed one merger and one major equity
investment as a result of this process.
TEXONA PETROLEUM CORPORATION. On September 19, 2000, Toreador
Acquisition Corporation ("TAC"), a wholly owned subsidiary of the Company
completed a merger with Texona Petroleum Corporation ("Texona"), pursuant to a
Merger Agreement dated as of September 11, 2000. The terms of the Merger
Agreement called for Texona to be merged with TAC in a forward triangular
merger, thus leaving TAC as the surviving entity. The outstanding stock of
Texona was exchanged for a total of 1,115,000 common shares of Toreador, of
which 1,025,000 was issued to the Texona shareholders during 2000 and the
remaining shares ("Deferred Shares") will be issued no later then June 1, 2001,
subject to Toreador shareholder approval. The issuance of Toreador shares for
the Texona shares is hereinafter referred to as the "Merger".
In addition, the Company issued 143,040 of its stock options to certain
former employees and directors of Texona. The strike price of the options is
$3.12 per share, and they expire on September 19, 2010. On the Merger closing
date, the Company's stock was trading at $5.75 per share, and accordingly, the
fair value of the options was included in the purchase price allocated to the
assets acquired and liabilities assumed.
Immediately prior to the Merger, Texona owned an interest in close to
1,000 wells located in 12 states, primarily Oklahoma, Texas and Louisiana. The
estimated proved reserves for Texona totaled 6,806 MMcf and 449 MBbl for a total
of 9,502 MMcfe (equivalent MMcf on six Mcf per one barrel of oil basis).
Immediately after the Merger closing, TAC extinguished Texona's
outstanding bank debt of $2,449,223, utilizing its line from Compass Bank,
Dallas. In connection with the borrowing, Toreador, TAC, Toreador Exploration &
Production Company, a wholly owned subsidiary of the Company and Tormin, Inc., a
wholly owned subsidiary of the Company, entered into an amendment to their
existing Credit Agreement with Compass Bank, which Credit Agreement was
effective September 30,1999. The amendment to the Credit Agreement increased the
borrowing base to $17,000,000 from the previous borrowing base of $14,500,000.
The Merger is being accounted for under the purchase method of
accounting for business combinations. Under the purchase method, the combination
is recorded at cost, which in this case is based upon the fair market value of
Toreador common stock, options issued and direct costs incurred. Acquired assets
are recorded at their fair market value up to the purchase price. The Company's
results of operations for the year ended December 31, 2000 include the results
of operations from September 19, 2000 through December 31, 2000.
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ENERGYNET.COM, INC. On July 11, 2000, the Company acquired a 35.0%
interest in EnergyNet.com, Inc. ("EnergyNet"), an Internet based oil and gas
property auction company. The terms of the acquisition called for the Company to
issue 100,000 shares of common stock plus a $100,000 payment. We believe that
this investment in EnergyNet will provide the Company with a vehicle well
designed to facilitate the disposition of non-strategic assets by the Company.
FOUR STATES ACQUISITION. On September 30, 1999, we purchased certain
oil and gas royalty interests located in Arkansas, California, Kansas and
Michigan from Conoco, Inc. (the "Four States Property Acquisition"). The
Company's outside consulting engineering firm estimated total net proved
reserves at more than 2.6 Bcfe. Gas comprises approximately 57% of the total
reserves. The purchase price for these royalty interests was $3,215,000. The
effective date of the purchase was August 1, 1999.
LARIO PROPERTY ACQUISITION. On December 22, 1999, we purchased 50% of
Lario Oil and Gas Company's working interests in certain oil and gas leases and
properties located in Finney County, Kansas for a total purchase price of
$5,500,000 (the "Lario Property Acquisition"). This acquisition resulted in
reserve additions of over 1,000,000 BOE. The purchase had an effective date of
October 1, 1999.
DISPOSAL OF NON-STRATEGIC ASSETS
In 2000, we sold several non-strategic oil and gas assets for over
$900,000. Of that amount, thirty-nine percent (39%) of the funds received were
captured through the use of EnergyNet's auction web site (www.energynet.com).
The remaining funds were received through private negotiated sales.
We completed two major asset sales during 1999. In January we sold a
portion of our acreage in the Texas Panhandle for $750,000. In September we sold
a portion of our West Texas acreage for $300,000.
ONGOING 3-D PROJECTS
As part of our strategy to participate in third party generated and
operated 3-D seismic projects in geologic regions outside of our holdings, we
are currently engaged in several 3-D seismic projects that could add significant
oil and gas reserves.
KIRBY HILLS 3-D SEISMIC PROJECT. We acquired a 12.5% working interest
and an approximate 9.4% net revenue interest in a 20 square mile 3-D seismic
project in Solano County, California in 1999. This project, which is located in
the Sacramento Basin of northern California, is designed to identify structural
closures within in an established gas producing area. The objective formations,
the Wagenet, Domengine and Nortonville Sandstones, range in depth from 1,500
feet to 5,400 feet. As of March 16, 2001, the data acquisition and processing
phases are complete. Drilling, contingent upon rig availability, will commence
in the early part of the second quarter 2001. The operator of the project has
readily identified three drillable prospects and is working on six other
prospect leads. Drilling depths on the first three wells will be in the
3600-foot range. The drilling cost for each of the first three wells is
estimated to range from $315,000 to $400,000 gross ($39,000 to $50,000 net to
Toreador). A completed well (not including pipeline expenditures) will range
from $485,000 to $580,000 gross ($61,000 to $73,000 net to Toreador).
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SOUTH ORANGE GROVE 3-D SEISMIC PROJECT. We acquired a 12.5% working
interest and an approximate 9.5% net revenue interest in a 44 square mile 3-D
seismic project in Jim Wells County, Texas in 1999. This project, which is
located 35 miles west-northwest of Corpus Christi, Texas, is designed to
identify and test shallow, fault-bounded structural closures as well as
stratigraphic complexities targeting gas reserves in and around existing fields
from depths ranging from 800 feet to 8,100 feet. Generally, those horizons range
from the Miocene (~3,000 feet), Frio (~4,000 feet), Vicksburg (~5,000 feet) and
deeper Yegua horizons (~8,000 feet). The existing fields in this area are older
and contain relatively few modern exploratory wells. With the exception of
continued evaluation of identifying additional prospects, all acquisition,
processing and interpretation phases in the 3-D seismic project area are
complete. As of December 31, 2000, we have participated in seven exploratory
wells on the project. Of those, three gross (.38 net) new field discovery wells
have been completed. The four gross (.50 net) remaining wells are classified as
dry holes. Included in the dry hole count is one well that was initially
completed as a new field discovery, but was plugged and abandoned in January
2001 producing 25 MMcf before watering out. Gross reserves classified as proved
developed producing from each of the three wells range from 45 MMcf to 370 MMcf.
After the drilling of each well, future drilling projects are subject to change
based upon the gathering and evaluation of engineering and geological data and
refining the interpretation of the 3-D seismic data. We are currently reviewing
other prospects in the project area as the operator continues to evaluate and
recommend other prospective target zones.
EAST TEXAS 3-D SEISMIC PROJECT. We have an 18.5185% working interest
(13.6667 net revenue interest) in a gas play based upon 200 square miles of 3-D
seismic data. This prospect area is located adjacent to a prolific field in
which similar features in the project area have resulted in some wells that have
produced in excess of 15 Bcf per well. The Company has agreed to participate in
the leasing of seven prospects identified to date. Multiple producing horizons
are likely to be encountered, with the primary objective in this play targeted
at a depth of approximately 9,000 feet.
OTHER EXPLORATION PROJECTS
BELMONT LAKE PROSPECT. Toreador has a 25% working interest (18.75% net
revenue interest) in this Wilkinson County, Mississippi prospect that is
targeting potential producing zones in the Wilcox formation at depths ranging
from 7,900 feet to 8,400 feet. The No. 1 Rosenblatt "BL" was spudded in November
2000 and reached a total depth of approximately 8500 feet. Eighteen feet of pay
was encountered in the Wilcox Minter "B" sand. This sand was perforated in
February 2001 initially flow testing at a rate of 65 barrels of oil per day.
This well is located in the flood plain of the Mississippi River. As a result of
high water in the area, the Rosenblatt well has been shut-in pending
modifications to the surface facilities and the installation of pumping
equipment.
WEST SHULER PROSPECT. Toreador has a 20% working interest (15% net
revenue interest) in this Union County, Arkansas prospect that is to test the
Lower Cretaceous Hill sandstone at a depth of 3,100 feet. The new field
discovery well was spudded in October 2000 and reached a total depth of
approximately 3,600 feet. Sixteen feet of pay was encountered in the Hill sand
and is currently producing at the rate of 150 barrels of oil per day and no
water. The first of several planned offsets has been drilled and is currently
being completed.
BALDRIDGE CANYON DEVELOPMENT PROJECT. Toreador elected to participate
in drilling a 11,300 foot Morrow Sand development well proposed by a third party
operator in the Baldridge Canyon Field, Eddy County, New Mexico. The Company
participated with its 15.619% working interest in the No. 1 Baldridge Canyon "7"
State Com. well. Thirty-one feet of pay was encountered in the Morrow Sand and
is currently flowing at a daily rate of 1200 Mcf and eight to ten barrels of
condensate. Toreador has identified at least two additional well sites for
development drilling and is currently exploring various opportunities to develop
this area. This project is an exploitation opportunity that was created from an
acquisition that we made in 1993.
SHALLOW WATERS - GULF COAST REGION. We have entered into a joint
venture relationship to participate in exploration prospects in the shallow
waters of the Gulf of Mexico. We will have the option, but not the obligation,
to participate in selected prospects.
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MARKETS AND COMPETITION
Our oil and gas production is sold to various purchasers typically in
the areas where the oil or gas is produced. Revenues from the sale of oil and
gas production accounted for 94%, 76% and 85% of the Company's consolidated
revenues for the three years ended December 31, 2000, 1999 and 1998,
respectively. The Company does not receive a material amount of its revenues
from external customers domiciled in foreign countries. Generally, we do not
refine or process any of the oil and gas we produce. We are currently able to
sell, under contract or in the spot market through the operator, substantially
all of the oil and the gas we are capable of producing at current market prices.
Substantially all of our oil and gas is sold under short-term contracts or
contracts providing for periodic adjustments or in the spot market; therefore,
our revenue streams are highly sensitive to changes in current market prices.
Our gas markets are pipeline companies as opposed to end users. See "Item 1.
Business -- Risk Factors - Volatility of Oil and Gas Prices," for a discussion
of the risks of commodity price fluctuations.
The oil and gas industry is highly competitive. We encounter strong
competition from other independent operators and from major oil companies in
acquiring properties, in contracting for drilling equipment and in securing
trained personnel. Many of these competitors have financial and technical
resources and staffs substantially larger than those available to us. As a
result, our competitors may be able to pay more for desirable leases and they
may pay more to evaluate, bid for and purchase a greater number of properties or
prospects than our financial or personnel resources will permit us.
We are also affected by competition for drilling rigs and the
availability of tubular goods and certain other equipment. While the oil and gas
industry has experienced shortages of drilling rigs and equipment, pipe and
personnel in the past, we are not presently experiencing any shortages and do
not foresee any such shortages in the near future, however, we are unable to
predict how long current market conditions will continue.
Competition for attractive oil and gas producing properties,
undeveloped leases and drilling rights is also strong, and we cannot assure you
that we will be able to compete satisfactorily in acquiring properties. Many
major oil companies have publicly indicated their decisions to concentrate on
overseas activities and have been actively marketing certain producing
properties for sale to independent oil and gas producers. We cannot assure you
that we will be successful in acquiring any such properties.
REGULATION
GENERAL FEDERAL AND STATE REGULATION
From time to time political developments and federal and state laws and
regulations affect our operations in varying degrees. Price control, tax and
other laws relating to the oil and gas industry, changes in such laws and
changing administrative regulations affect our oil and gas production,
operations and economics. There are currently no price controls on oil,
condensate or natural gas liquids. To the extent price controls remain
applicable after the enactment of the Natural Gas Wellhead Decontrol Act of
1989, we believe that price controls will not have a significant impact on the
prices received by us for gas produced in the near future.
We review legislation affecting the oil and gas industry for amendment
or expansion. The legislative review frequently increases our regulatory burden.
Also, numerous departments and agencies, both federal and state, are authorized
by statute to issue and have issued rules and regulations binding on the oil and
gas industry and its individual members, compliance with which is often
difficult and costly and certain of which may carry substantial penalties if we
were to fail to comply. We cannot predict how existing regulations may be
interpreted by enforcement agencies or the courts, whether amendments or
additional regulations will be adopted, nor what effect such interpretations and
changes may have on our business or financial conditions.
Matters subject to regulation include:
o discharge permits for drilling operations;
o drilling and abandonment bonds or other financial
responsibility requirements;
o reports concerning operations;
o the spacing of wells;
o unitization and pooling of properties and
o taxation.
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GAS REGULATION AND THE EFFECT ON MARKETING
Historically, interstate pipeline companies generally acted as
wholesale merchants by purchasing gas from producers and reselling the gas to
local distribution companies and large end users. Commencing in late 1985, the
Federal Energy Regulatory Commission (the "FERC") issued a series of orders that
have had a major impact on interstate gas pipeline operations, services, and
rates, and thus have significantly altered the marketing and price of gas. The
FERC's key rule making action, Order No. 636, issued in April 1992, required
each interstate pipeline to, among other things, "unbundle" its traditional
bundled sales services and create and make available on an open and
nondiscriminatory basis numerous constituent services (such as gathering
services, storage services, firm and interruptible transportation services, and
standby sales and gas balancing services), and to adopt a new rate making
methodology to determine appropriate rates for those services. To the extent the
pipeline company or its sales affiliate makes gas sales as a merchant in the
future, it does so pursuant to private contracts in direct competition with all
other sellers, such as Toreador; however, pipeline companies and their
affiliates were not required to remain "merchants" of gas, and most of the
interstate pipeline companies have become "transporters only." In subsequent
orders, the FERC largely affirmed the major features of Order No. 636 and denied
a stay of the implementation of the new rules pending judicial review. By the
end of 1994, the FERC had concluded the Order No. 636 restructuring proceedings,
and, in general, accepted rate filings implementing Order No. 636 on every major
interstate pipeline. However, even through the implementation of Order No. 636
on individual interstate pipelines is essentially complete, many of the
individual pipeline restructuring proceedings, as well as orders on rehearing of
Order No. 636 itself and the regulations promulgated thereunder, are subject to
pending appellate review and could possibly be changed as a result of future
court orders. We cannot predict whether the FERC's orders will be affirmed on
appeal or what the effects will be on our business.
We own indirect interests in certain gas facilities that we believe
meet the traditional tests the FERC has used to establish a company's status as
a gatherer not subject to FERC jurisdiction under the Natural Gas Act of 1938.
Moreover, recent orders of the FERC have been more liberal in their reliance
upon or use of the traditional tests, such that in many instances, what was once
classified as "transmission" may now be classified as "gathering." We transport
our own gas through these facilities. We also transport a portion of our gas
through gathering facilities owned by others, including interstate pipelines,
and the cost and availability of that transportation also could be affected by
the developments referred to in the following paragraph.
In recent years the FERC also has pursued a number of other important
policy initiatives, which could significantly affect the marketing of gas. Some
of the more notable of these regulatory initiatives include:
o a series of orders in individual pipeline proceedings
articulating a policy of generally approving the voluntary
divestiture of interstate pipeline owned gathering facilities
by interstate pipelines to their affiliates (the so-called
"spin down" of previously regulated gathering facilities to
the pipeline's nonregulated affiliate) and to non-affiliates
(a so called "spin off"), a number of which have been approved
and implemented;
o the completion of rule making involving the regulation of
pipelines with marketing affiliates under Order No. 497;
o the FERC's ongoing efforts to promulgate standards for
pipeline electronic bulletin boards and electronic data
exchange;
o a generic inquiry into the pricing of interstate pipeline
capacity;
o efforts to refine the FERC's regulations controlling operation
of the secondary market for released pipeline capacity and
o a policy statement regarding market based rates and other
non-cost-based rates for interstate pipeline transmission and
storage capacity.
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Several of these initiatives are intended to enhance competition in gas
markets, although some of these initiatives, such as "spin downs", may have the
adverse effect of increasing the cost of doing business to some in the industry
if the new, unregulated owners of those facilities monopolize them. The FERC has
attempted to address some of these concerns in its orders authorizing such "spin
downs" by requiring nondiscriminatory access and prohibiting "tying" access to
pipeline transportation to other services of an affiliate, imposing certain
contract requirements, and retaining jurisdiction if an affiliate undermines
open and nondiscriminatory access to the interstate pipeline. The FERC also has
imposed additional requirements on interstate pipelines seeking to abandon
facilities certificated under the Natural Gas Act of 1938 and to terminate
service from both certificated and uncertificated activities. It remains to be
seen what effect these activities will have on access to markets and the cost of
doing business. Further, some of the orders and regulations of the FERC
establishing these initiatives and approving actions thereunder have been
appealed and remain subject to further action by an appellate court and the
FERC. We cannot predict what the ultimate effect of these and other orders of
the FERC will have on our production and marketing, or whether the FERC's orders
on these matters will be affirmed by an appellate court. As to all of these
recent FERC initiatives, the ongoing, or in some instances, preliminary evolving
nature of these regulatory initiatives also makes it impossible at this time for
us to predict their ultimate impact on our business.
FEDERAL AND STATE TAXATION
The federal and state governments may propose tax initiatives that
affect us. We are unable to determine what effect, if any, future proposals
would have on product demand or our results of operations.
STATE REGULATION
The various states in which we conduct activities regulate our
drilling, operation and production of oil and gas wells, including the method of
developing new fields, spacing of wells, the prevention and cleanup of
pollution, and maximum daily production allowables based on market demand and
conservation considerations.
ENVIRONMENTAL REGULATION
Exploration, development and production of oil and gas, including
operation of saltwater injection and disposal wells, are subject to various
federal, state and local environmental laws and regulations. Such laws and
regulations can increase the costs of planning, designing, installing and
operating oil and gas wells. Our domestic activities are subject to a variety of
environmental laws and regulations, including, but not limited to:
o the Oil Pollution Act of 1990;
o the Clean Water Act;
o the Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA");
o the Resource Conservation and Recovery Act ("RCRA");
o the Clean Air Act and
o the Safe Drinking Water Act,
as well as state regulations promulgated under comparable state statutes. These
laws and regulations:
o require the acquisition of a permit before drilling commences;
o restrict the types, quantities and concentration of various
substances that can be released into the environment in
connection with drilling and production activities;
o limit or prohibit drilling activities on certain lands lying
within wilderness, wetlands and other protected areas and
o impose substantial liabilities for pollution that might result
from our operations.
We also are subject to regulations governing the handling,
transportation, storage and disposal of naturally occurring radioactive
materials that are found in our oil and gas operations. Civil and criminal fines
and penalties may be imposed for non-compliance with these environmental laws
and regulations. Additionally, these laws and regulations require the
acquisition of permits or other governmental authorizations before undertaking
certain activities, limit or prohibit other activities because of protected
areas or species and impose substantial liabilities for cleanup of pollution.
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Under the Oil Pollution Act, a release of oil into water or other areas
designated by the statue could result in Toreador being held responsible for the
costs of remediating such a release, specified damages and natural resource
damages. The extent of that liability could be extensive, as set forth in the
statute, depending on the nature of the release. A release of oil in harmful
quantities or other materials into water or other specified areas could also
result in Toreador being held responsible under the Clear Water Act for the cost
of remediation, and for civil and criminal fines and penalties.
CERCLA and comparable state statutes, also known as "Superfund" laws,
can impose joint, several and retroactive liability, without regard to fault or
the legality of the original conduct, on certain classes of persons for the
release of a "hazardous substance" into the environment. In practice, cleanup
costs are usually allocated among various responsible parties. Potentially
liable parties include site owners or operators, past owners or operators under
certain conditions and entities that arrange for the disposal or treatment of,
or transport of hazardous substances found at the site. Although CERCLA, as
amended, currently exempts petroleum, including, but not limited to, crude oil,
gas and natural gas liquids from the definition of hazardous substance, our
operations may involve the use or handling of other materials that may be
classified as hazardous substances under CERCLA. Furthermore, there can be no
assurance that the exemption will be preserved in any future amendments to
CERCLA.
RCRA and comparable state and local requirements impose standards for
the management, including treatment, storage and disposal of both hazardous and
nonhazardous solid wastes. We generate hazardous and non-hazardous solid waste
in connection with our routine operations. From time to time, proposals have
been made that would reclassify certain oil and gas wastes, including wastes
generated during pipeline, drilling and production operations, as "hazardous
wastes" under RCRA which would make such solid wastes subject to much more
stringent handling, transportation, storage, disposal and clean-up requirements.
This development could have a significant impact on our operating costs. While
state laws vary on this issue, state initiatives to further regulate oil and gas
wastes could have a similar impact on our operations.
Because previous owners and operators have conducted oil and gas
exploration and production, and possibly other activities, at some of our
properties, materials from these operations remain on some of our properties and
in some instances require remediation. In addition, we have agreed to indemnify
the sellers of producing properties from whom we have acquired reserves against
certain liabilities for environmental claims associated with such properties.
While we do not believe the costs to be incurred by us for compliance and
remediating previously or currently owned or operated properties will be
material, we cannot guarantee that these potential costs will not result in
material expenditures.
Additionally, in the course of our routine oil and gas operations,
surface spills and leaks, including casing leaks, of oil or other materials
occur, and we may incur costs for waste handling and environmental compliance.
Notwithstanding our lack of control over wells controlled by others, the failure
of the operator to comply with applicable environmental regulations may, in
certain circumstances, be attributable to us.
It is not anticipated that we will be required in the near future to
expend amounts that are material in relation to our total capital expenditures
program by reason of environmental laws and regulations, but inasmuch as such
laws and regulations are frequently changed, we are unable to predict the
ultimate cost of compliance. There can be no assurance that more stringent laws
and regulations protecting the environment will not be adopted or that we will
not otherwise incur material expenses in connection with environmental laws and
regulations in the future.
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OTHER PROPOSED LEGISLATION
The recent trend toward stricter standards in environmental legislation
and regulation is likely to continue. For instance, legislation has been
proposed in Congress from time to time that would reclassify certain crude oil
and gas exploitation and production wastes as "hazardous wastes" which would
make the reclassified wastes subject to much more stringent handling, disposal
and clean-up requirements. If such legislation were to be enacted, it could have
a significant impact on our operating costs, as well as the oil and gas industry
in general. Initiatives to further regulate the disposal of crude oil and gas
wastes are also pending in certain states, and these various initiatives could
have a similar impact on us. We could incur substantial costs to comply with
environmental laws and regulations. In addition to compliance costs, government
entities and other third parties may assert substantial liabilities against
owners and operators of oil and gas properties for oil spills, discharge of
hazardous materials, remediation and clean-up costs and other environmental
damages, including damages caused by previous property owners. As a result,
substantial liabilities to third parties or governmental entities may be
incurred, the payment of which could reduce or eliminate the funds available for
project investment or result in loss of our properties. Although we maintain
insurance coverage we consider to be customary in the industry, we are not fully
insured against certain of these risks, either because such insurance is not
available or because of high premium costs. Accordingly, we may be subject to
liability or may lose substantial portions of properties due to hazards that
cannot be insured against or have not been insured against due to prohibitive
premium costs or for other reasons. The imposition of any such liabilities on us
could have a material adverse effect on our financial condition and results of
operations.
EMPLOYEES
As of March 16, 2001, we employed eleven full-time employees. None of
our employees are represented by unions or covered by collective bargaining
agreements. To date, we have not experienced any strikes or work stoppages due
to labor problems, and we consider our relations with our employees to be good.
As needed, we also utilize the services of independent consultants on a contract
basis.
RISK FACTORS
There are various risks involved in owning our Common Stock, including
those described below.
INDUSTRY RISKS
VOLATILITY OF OIL AND GAS PRICES
Our future financial condition and results of operations depend upon
the prices we receive for our oil and gas and the costs of acquiring, developing
and producing oil and gas. Currently, oil and gas prices are favorable.
Historically, oil and gas prices have been volatile and are subject to
fluctuations in response to changes in supply, market uncertainty and a variety
of additional factors that are also beyond our control. These factors include:
o the level of domestic production;
o the availability of imported oil and gas;
o actions taken by foreign oil and gas producing nations;
o the availability of transportation systems with adequate
capacity;
o the availability of competitive fuels;
o fluctuating and seasonal demand for gas;
o conservation and the extent of governmental regulation of
production;
o the effect of weather;
o foreign and domestic government relations;
o the price of domestic and imported oil and gas and
o the overall economic environment.
A substantial or extended decline in oil and/or gas prices could have a material
adverse effect on the estimated value of our gas and oil reserves, and on our
financial position, results of operations and access to capital. Our ability to
maintain or increase our borrowing capacity, to repay current or future
indebtedness and to obtain additional capital on attractive terms is
substantially dependent upon oil and gas prices.
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POTENTIAL INABILITY TO DEVELOP ADDITIONAL RESERVES
Our future success as an oil and gas producer, as is generally the case
in the industry, depends upon our ability to find, develop and acquire
additional oil and gas reserves that are profitable. If we are unable to conduct
successful development activities or acquire properties containing proved
reserves, our proved reserves will generally decline as reserves are produced.
We cannot assure you that we will be able to locate additional reserves or that
we will drill economically productive wells or acquire properties containing
proved reserves.
DRILLING RISKS
Our drilling involves numerous risks, including the risk that no
commercially productive oil or gas reservoirs will be encountered. We may incur
significant expenditures for the identification and acquisition of properties
and for the drilling and completion of wells. The cost of drilling, completing
and operating wells is often uncertain, and drilling operations may be
curtailed, delayed or canceled as a result of a variety of factors, including
unexpected drilling conditions, pressure or irregularities in formations,
equipment failures or accidents, weather conditions and shortages or delays in
the delivery of equipment. In addition, any use by us of 3-D seismic and other
advanced technology to explore for oil and gas requires greater pre-drilling
expenditures than traditional drilling strategies. We cannot assure the success
of our future drilling activities.
ESTIMATES OF OIL AND GAS RESERVES
Numerous uncertainties are inherent in estimating quantities of proved
oil and gas reserves, including many factors beyond our control. This report
contains an estimate of our proved oil and gas reserves and the estimated future
net cash flows and revenue generated by the proved oil and gas reserves based
upon reports of our independent petroleum engineers. Such reports rely upon
various assumptions, including assumptions required by the Securities and
Exchange Commission, as to constant oil and gas prices, drilling and operating
expenses, capital expenditures, taxes and availability of funds, and such
reports should not be construed as the current market value of the estimated
proved reserves. The process of estimating oil and gas reserves is complex,
requiring significant decisions and assumptions in the evaluation of available
geological, engineering and economic data for each property. As a result, such
estimates are inherently an imprecise evaluation of reserve quantities and
future net revenue. Our actual future production, revenue, taxes, development
expenditures, operating expenses and quantities of recoverable oil and gas
reserves may vary substantially from those we have assumed in the estimate. Any
significant variance in our assumptions could materially affect the estimated
quantity and value of reserves set forth in this report. In addition, our
reserves may be subject to downward or upward revision, based upon production
history, results of future exploitation and development, prevailing oil and gas
prices and other factors.
OPERATING HAZARDS AND UNINSURED RISKS
Our operations are subject to the risks inherent in the oil and gas
industry, including the risks of:
o fire, explosions, and blowouts;
o pipe failure;
o abnormally pressured formations and
o environmental accidents such as oil spills, gas leaks,
ruptures or discharges of toxic gases, brine or well fluids
into the environment (including groundwater contamination).
The occurrence of any of these events could result in substantial
losses to Toreador due to:
o injury or loss of life;
o severe damage to or destruction of property, resources and
equipment;
o pollution or other environmental damage;
o clean-up responsibilities;
o regulatory investigation and
o penalties and suspension of operations.
In accordance with customary industry practice, we maintain insurance
against some, but not all, of the risks described above. We cannot assure you
that any insurance maintained by us will be adequate to cover any such losses or
liabilities. Further, we cannot predict the continued availability of insurance,
or availability at commercially acceptable premium levels. We do not carry
business interruption insurance. Losses and liabilities arising from uninsured
or under-insured events could have a material adverse effect on our financial
condition and operations.
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From time to time, due primarily to contract terms, pipeline
interruptions or weather conditions, the producing wells in which we own an
interest have been subject to production curtailments. The curtailments range
from production being partially restricted to wells being completely shut-in.
The duration of curtailments may vary from a few days to several months. In most
cases we are provided only limited notice as to when production will be
curtailed and the duration of such curtailments. We are not currently
experiencing any material curtailment on our production.
COMPANY RISKS
CONTROL BY CERTAIN STOCKHOLDERS
As of January 31, 2001, the current officers and directors of the
Company as a group held a beneficial interest in approximately 52% of our Common
Stock (including shares issuable upon exercise of stock options for Common Stock
or conversion of the Company's Series A Preferred Stock held by affiliates of
certain directors).
EFFECTS OF INDEBTEDNESS
At December 31, 2000, Toreador's debt to equity ratio was 99%. We may
incur additional indebtedness in the future as we execute our acquisition and
exploration strategy. See section entitled "Potential Need for Additional
Financing for Continued Growth" below for more details.
Our ability to meet our debt service obligations will be dependent upon
our future performance, which will be subject to oil and gas prices, our level
of production, general economic conditions and to financial, business and other
factors affecting our operations, many of which are beyond our control. There
can be no assurance that some or all of these factors will not adversely affect
our future performance. See "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operation -- Liquidity and Capital
Resources."
Our level of indebtedness will have several important effects on our
future operations, including:
o a substantial portion of our cash flow from operations must be
dedicated to the payment of principal and interest on our
indebtedness and will not be available for other purposes;
o covenants contained in our debt obligations will require us to
meet certain financial tests, and other restrictions will
limit our ability to borrow additional funds or to dispose of
assets and may affect our flexibility in planning for, and
reacting to, changes in our business, including possible
acquisition activities and
o our ability to obtain additional financing in the future may
be impaired.
A default under our credit facility would permit the lender to accelerate
repayments of the loan and to foreclose on the collateral securing the loan,
including certain oil and gas properties. See "Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operation - Liquidity and
Capital Resources."
CAPABILITY TO IDENTIFY ALL ACQUISITION RISKS
Generally, it is not feasible for us to review in detail every
individual risk involved in an acquisition. Our business strategy includes
future acquisitions of producing oil and gas properties. Any future acquisitions
generally entail an assessment of recoverable reserves, future oil and gas
prices, operating costs, potential environmental and other liabilities and other
similar factors. Ordinarily, review efforts are focused on the higher-valued
properties. However, even a detailed review of certain properties and records
may not reveal existing or potential problems, nor will it permit us to become
sufficiently familiar with the properties to assess fully their deficiencies and
capabilities. Inspections are not always performed on every well, and potential
problems, such as mechanical integrity of equipment and environmental conditions
that may require significant remedial expenditures, are not necessarily
observable even when an inspection is undertaken. Even if we identify problems,
the seller may be unwilling or unable to provide effective contractual
protection against all or part of such problems.
The Texona Petroleum Corporation merger, Four States Property
Acquisition and the Lario Property Acquisition represent major steps in our
growth strategy. However, our increased size and scope of operations will
present us with significant challenges due to the increased time and resources
required in our management effort. Accordingly, there can be no assurance that
our future operations under present conditions can be effectively managed to
realize the goals set forth on future property acquisitions.
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POTENTIAL NEED FOR ADDITIONAL FINANCING FOR CONTINUED GROWTH
The growth of our business will require substantial capital on a
continuing basis. We may be unable to obtain additional capital on satisfactory
terms and conditions. Thus, we may lose opportunities to acquire oil and gas
properties and businesses. In addition, our pursuit of additional capital could
result in incurring additional indebtedness or issuing and adding potentially
dilutive equity securities. We also may utilize the capital currently expected
to be available for our present operations. The amount and timing of our future
capital requirements, if any, will depend upon a number of factors, including:
o drilling costs;
o transportation costs;
o equipment costs;
o marketing expenses;
o oil and gas prices;
o staffing levels and competitive conditions and
o any purchases or dispositions of assets.
Our failure to obtain any required additional financing could materially and
adversely affect our growth, cash flow and earnings.
NATURE OF PROPERTY INTERESTS
On the Southeastern States Holdings, we own interests in minerals that
include executive rights (the rights to sign leases) as well as rights to
receive portions of lease bonuses, delay rentals and royalties.
On the Texas Holdings, we own interests in minerals that include rights
to receive lease bonuses, delay rentals and royalties, except, unlike our
Southeastern States Holdings, we generally do not own the executive rights which
are typically held by surface owners. Therefore, we must rely on the owners of
the executive rights to execute leases of the acreage. In situations in which we
have acquired working interests in acreage where we have mineral rights, we have
acquired those interests through the signing of leases by holders of the
executive rights. While the majority of the owners holding those executive
rights have worked closely with us in the past, each acts independently of us in
their decisions to execute leases. In addition, since our interests are in the
form of mineral interests, royalty interests or non-operator working interests,
we do not have control over drilling or operating decisions on the properties in
which we have an interest.
MARKETING RISKS
The marketing of our oil and gas production principally depends upon
those facilities operated by others. The operations of those facilities may
change and have a material adverse effect on the marketing of our oil and gas
production.
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KEY PERSONNEL
We are substantially dependent upon G. Thomas Graves III, President,
Chief Executive Officer and Director, Edward C. Marhanka, Vice President -
Operations and Douglas W. Weir, Chief Financial Officer.
INVESTMENT RISKS
STOCK PRICE VOLATILITY
Because the volume of trading in shares of our Common Stock has been
low historically, the sale of a substantial number of shares of the Common Stock
in a short period of time could adversely affect the market price of the Common
Stock.
DIVIDENDS
From time to time the Company has paid cash dividends on its Common
Stock. However, we do not anticipate paying cash dividends on our Common Stock
in the foreseeable future. Our Common Stock is not a suitable investment for
persons requiring current income.
GLOSSARY OF SELECTED OIL AND GAS TERMS
BBL. One stock tank barrel, or 42 U.S. gallons liquid volume, used
herein in reference to crude oil or other liquid hydrocarbons.
BCF. One billion cubic feet of gas.
BCFE. One billion cubic feet of gas equivalents, converting one Bbl of
oil to six Mcf of gas.
BOE. Barrel of oil equivalent converting six Mcf of gas to one barrel
of oil.
"DEVELOPMENT WELL." A well drilled within the proved boundaries of an
oil or gas reservoir with the intention of completing the stratigraphic horizon
known to be productive.
"DRY WELL." A development or exploratory well found to be incapable of
producing either oil or gas in sufficient quantities to justify completion as an
oil or gas well.
"EXPLORATORY WELL." A well drilled to find and produce oil or gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir, or to extend a known reservoir.
"GROSS ACRES" or "GROSS WELLS." The total number of acres or wells, as
the case may be, in which a working or any type of royalty interest is owned.
MCF. One thousand cubic feet of gas.
MCFE. One thousand cubic feet of gas equivalents, converting one Bbl of
oil to six Mcf of gas.
MMCF. One million cubic feet of gas.
"NET ACRES" or "NET WELLS." The sum of the fractional working or any
type of royalty interests owned in gross acres or gross wells.
"PRODUCING WELL" or "PRODUCTIVE WELL." A well that is producing oil or
gas or that is capable of production.
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"PROVED DEVELOPED RESERVES". The oil and gas reserves that can be
expected to be recovered through existing wells with existing equipment and
operating methods. Additional oil and gas expected to be obtained through the
application of fluid injection or other improved recovery techniques for
supplementing the forces and mechanisms of primary recovery should be included
as "proved developed reserves" only after testing by a pilot project or after
the operation of an installed program has confirmed through production response
that increased recovery will be achieved.
"PROVED RESERVES." The estimated quantities of crude oil, gas and gas
liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions.
"PROVED UNDEVELOPED RESERVES." The oil and gas reserves that are
expected to be recovered from new wells on undrilled acreage, or from existing
wells where a relatively major expenditure is required for recompletion.
Reserves on undrilled acreage shall be limited to those drilling units
offsetting productive units that are reasonably certain of production when
drilled. Proved reserves for other undrilled units can be claimed only where it
can be demonstrated with certainty that there is continuity of production from
the existing productive formation. Under no circumstances should estimates for
proved undeveloped reserves be attributable to any acreage for which an
application of fluid injection or other improved recovery techniques is
contemplated, unless such techniques have been proved effective by actual tests
in the area and in the same reservoir.
"ROYALTY INTEREST." An interest in an oil and gas property entitling
the owner to a share of oil and gas production free of production costs.
"SEC PV-10." The present value of proved reserves is an estimate of the
discounted future net cash flows from each property at December 31, 2000, or as
otherwise indicated. Net cash flow is defined as net revenues less, after
deducting production and ad valorem taxes, future capital costs and operating
expenses, but before deducting federal income taxes. As required by rules of the
Securities and Exchange Commission, the future net cash flows have been
discounted at an annual rate of 10% to determine their "present value." The
present value is shown to indicate the effect of time on the value of the
revenue stream and should not be construed as being the fair market value of the
properties. In accordance with Securities and Exchange Commission rules,
estimates have been made using constant oil and gas prices and operating costs,
at December 31, 2000, or as otherwise indicated.
"STANDARDIZED MEASURE." Under the Standardized Measure, future cash
flows are estimated by applying year-end prices, adjusted for fixed and
determinable escalations, to the estimated future production of year-end proved
reserves. Future cash inflows are reduced by estimated future production and
development costs based on period-end costs to determine pretax cash inflows.
Future income taxes are computed by applying the statutory tax rate to the
excess inflows over the Company's tax basis in the associated properties. Tax
credits, net operating loss carryforwards, and permanent differences are also
considered in the future tax calculation. Future net cash inflows after income
taxes are discounted using a 10% annual discount rate to arrive at the
Standardized Measure.
"UNDEVELOPED ACREAGE." Lease acreage on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of oil and gas regardless of whether such acreage contains proved
reserves.
"WORKING INTEREST." The operating interest which gives the owner the
right to drill, produce and conduct operating activities on the property and a
share of production, subject to all royalties, overriding royalties and other
burdens and to all exploration, development and operational costs including all
risks in connection therewith.
ITEM 2. PROPERTIES.
We own perpetual oil and gas mineral and royalty interests comprised of
and commonly referred to as the Texas Holdings, the Southeastern States Holdings
and the Four States Property Holdings, all of which are equal to approximately
2,643,000 gross acres.
TEXAS HOLDINGS
Our Texas Holdings are comprised of the Northern Ranch Minerals and the
Southern Ranch Minerals and are equal to approximately 766,000 gross (461,000
net) acres.
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NORTHERN RANCH MINERALS
We own mineral interests under approximately 334,000 gross acres
located in Oldham and Hartley Counties, Texas. These minerals are all located in
the geologic province commonly known as the Southern Dalhart Basin.
No wells were drilled on the Northern Ranch Minerals in 2000. As of
March 16, 2001, no new wells have been drilled on this acreage. Inquiries by
third parties to evaluate the minerals in this area have diminished the past two
years mainly because the basin in which our minerals are located is considered
to be oil bearing and not gas bearing. We believe more independent oil and gas
producers are focusing their exploration efforts on gas projects while gas
prices remain at all time highs.
SOUTHERN RANCH MINERALS
We own mineral interests under an aggregate of approximately 470,000
gross acres located in three geologic provinces commonly known as the Palo Duro
Basin, the Matador Arch, and the Eastern Shelf.
PALO DURO BASIN - The Palo Duro Basin, where we own mineral interests
under approximately 195,000 gross acres located in Motley and Cottle Counties,
Texas, is a moderate depth depression between the Matador Arch on the south and
the Amarillo uplift complex to the north. There was no leasing or drilling
activity with respect to our mineral interests in this region in 2000.
MATADOR ARCH - The Matador Arch, where we own mineral interests under
approximately 90,000 gross acres, is a prominent east-west structural positive
traversing north Texas and southern Oklahoma. One gross (.15 net) well was
successfully drilled and completed in the Wolfcamp at approximately 3,300 feet,
pump testing at a daily rate of 50 barrels of oil per day extending the Matador
Field. Toreador owns a 15% net royalty interest in this well. That same operator
re-entered a drilled and abandoned well on the same lease, but it tested dry. In
February 2001, the operator drilled another dry hole on the same lease.
EASTERN SHELF - The Eastern Shelf of the Midland Basin, where we own
mineral interests under approximately 185,000 gross acres located primarily in
Dickens County, Texas, is prospective for shallow Permian age oil accumulations
in the Tannehill Sand and possible deeper objectives in the Pennsylvanian
section.
In 2000, there were four gross (.19 net) wells drilled on our Pitchfork
Ranch acreage. Two of the four wells are wells in which we participated for a
working interest in an attempt to extend the Silver Spur (Tannehill) Field. Two
other third party operators drilled two wells targeting the Tannehill in
different areas of the Pitchfork Ranch acreage. All of the wells were dry,
albeit that one of the wells offsetting the Silver Spur Field could have future
utility as a water injector.
SOUTHEASTERN STATES HOLDINGS
In December 1998, the Company acquired approximately 1,775,000 gross
(876,000 net) acres located in Mississippi, Alabama and Louisiana. Most of the
Company's activity is generated along the southern half of each of these three
states. Unlike our Texas Holdings, our mineral spread here is diversified over
several geologic provinces and not highly concentrated and dense in one specific
area. Conversely, we own a mineral position in every county in Mississippi and
Alabama. The majority of the leasing and exploration activity on our minerals is
in Mississippi.
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MISSISSIPPI
The Company owns perpetual mineral interests in approximately 1,137,000
gross acres in Mississippi. The largest concentration of activity for our
Southeastern States Holdings is in the geologic province commonly known as the
Mississippi Salt Basin. This province primarily stretches from northeastern
Louisiana across the southern half of Mississippi and just into the southwestern
portions of Alabama. In another province of more recent importance is the
development of a Deep Knox Gas discovery in northeastern Mississippi located
just southwest and adjacent to the Black Warrior Basin. This basin extends from
northeastern Mississippi into northwestern Alabama.
The majority of mineral leasing activity for the company occurs on the
Mississippi portion of our Southeastern States Holdings. In 2000, we received
approximately $475,000 in lease bonus and rental income from the leasing of
approximately 4,900 net mineral acres.
MISSISSIPPI SALT BASIN
The Mississippi Salt Basin contains two major areas of exploration
activity that currently provide us with the opportunity to gain significant
reserve additions. The two areas are the Piercement Salt Domes and the Salt
Ridges.
PIERCEMENT SALT DOMES - The Piercement Salt Dome activity is currently
focused in the south-central portion of Mississippi in Covington, Jefferson
Davis and Jones Counties, Mississippi. These geologic features have several
target pay zones ranging from primary objectives in several Hosston Sandstones
at depths of over 15,000 feet to secondary objectives in the Sligo and Paluxy
formations at approximately 14,000 feet and 12,000 feet, respectively. The
current success in this area is primarily attributed to the utilization of
modern 3-D seismic technology. As a royalty owner we do not bear the burden of
any expenses in exploring and developing any fields discovered.
SALT RIDGES - Salt Ridge exploration activity is resuming in Wayne
County, Mississippi. The primary objectives are the Cotton Valley, Smackover and
Norphlet formations ranging from 12,000 feet to 18,000 feet. The use of modern
3-D seismic technology has been critical to the success of this activity.
DEEP KNOX GAS
Current activity is centered in western Oktibbeha County, Mississippi,
adjacent to the Black Warrior Basin, where several 15,000-foot plus Knox test
wells have been completed since June 1998 as extensions of the Maben Field which
was originally discovered in 1970. The No. 1 Sanders, the very first Maben Field
extension well and one in which we own a .35% net royalty interest, flowed at a
daily average rate of 5.2 MMcf of gas in January 2001 and has produced in excess
of 4.2 Bcf. A year ago, this well flowed at a daily average rate of 5.8 MMcf.
The same operator drilled and completed a second exploratory well in the play to
the south, the #1 Georgia Pacific, which flowed at a marginal daily rate of
approximately 400 Mcf of gas in June 1999. In January 2001, this well flowed for
a daily average rate of 135 Mcf and has produced approximately 100 MMcf. We own
a 2.79% net royalty interest in this well. A third well, the No. 1 Love Heirs,
where we own a 1.4% net royalty interest, was drilled and completed by the same
operator in August 2000. This well flowed for a daily average rate of 8.4 MMcf
of gas in January 2001 and has produced approximately 1.0 Bcf in that short
time.
This area continues to be extremely promising since very few wells have
been drilled to the Knox formation in this region near or in the Black Warrior
Basin. The operator's continued success, aided by the use of modern 3-D seismic
technology, should fuel future drilling interest around the Maben Field area.
Additionally, other companies are in the process of funding a research team to
investigate the play into other regions inside and outside of Mississippi.
ALABAMA
The Company owns perpetual oil and gas mineral and royalty interests in
approximately 622,000 gross acres in Alabama. We own a mineral position in every
county in Alabama. Activity on our minerals in Alabama is not as significant as
it is in Mississippi.
LOUISIANA
The Company owns oil and gas mineral and royalty interests in
approximately 16,000 gross acres in Louisiana. Unlike the other states where we
own perpetual minerals, the laws in Louisiana are such that the minerals
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prescribe to the surface owner after 10 years have passed without any production
or drilling on said lands. Since we do not own the surface rights in any of the
properties that were acquired in December 1998, the consequences are that we do
not maintain many of our mineral rights if production ceases for a period of 10
years.
FOUR STATE PROPERTY HOLDINGS
In September 1999, the Company acquired certain oil and gas royalty
interests located in Arkansas, California, Kansas and Michigan. The holdings
include approximately 140 producing wells in addition to approximately 56,000
gross (18,000 net) undeveloped acres. While we have experienced limited leasing
activity on these holdings thus far, we continue to receive new revenues
generated from additional drilling development in Arkansas and secondary
recovery enhancements in California.
TEXONA PETROLEUM CORPORATION MERGER
In September 2000, the Company acquired an interest in close to 1,000
wells as a part of the Merger. While the wells are located in 12 states, the
primary value is concentrated in Oklahoma, Texas and Louisiana. Almost all of
the interests acquired were non-operated working interests. The estimated proved
reserves for Texona totaled 6,806 MMcf and 449 MBbl for a total of 9,502 MMcfe
(equivalent MMcf on six Mcf per one barrel of oil basis).
TITLE TO OIL AND GAS PROPERTIES
We have acquired interests in producing and non-producing acreage in
the form of working interests, fee mineral interests, royalty interests and
overriding royalty interests. Substantially all of our property interests are
leased to third parties. The leases grant the lessee the right to explore for
and extract oil and gas from specified areas. Consideration for a lease usually
consists of a lump sum payment (i.e., bonus) and a fixed annual charge (i.e.,
delay rental) prior to production (unless the lease is paid up) and, once
production has been established, a royalty based generally upon the proceeds
from the sale of oil and gas. Once wells are drilled, a lease generally
continues so long as production of oil and gas continues. In some cases, leases
may be acquired in exchange for a commitment to drill or finance the drilling of
a specified number of wells to predetermined depths. We receive annual delay
rentals from lessees of certain properties in order to prevent the leases from
terminating. Title to leasehold properties is subject to royalty, overriding
royalty, carried, net profits and other similar interests and contractual
arrangements customary in the oil and gas industry, and to liens incident to
operating agreements, liens relating to amounts owed to the operator, liens for
current taxes not yet due and other encumbrances. Substantial portions of our
exploration and production properties are pledged as collateral under our credit
facility, including a major portion of the Southeastern States Holdings.
As is common industry practice, we conduct little or no investigation
of title at the time we acquire undeveloped properties, other than a preliminary
review of local mineral records. However, we do conduct title investigations
and, in most cases, obtain a title opinion of local counsel before commencement
of drilling operations. We believe that the methods we utilize for investigating
title prior to acquiring any property is consistent with practices customary in
the oil and gas industry and that such practices are adequately designed to
enable us to acquire good title to such properties. Some title risks, however,
cannot be avoided, despite the use of customary industry practices.
Our properties are generally subject to:
o customary royalty and overriding royalty interests;
o liens incident to operating agreements and
o liens for current taxes and other burdens and minor
encumbrances, easements and restrictions.
We believe that none of these burdens either materially detract from
the value of our properties or materially interfere with their use in the
operation of our business. Substantially all of our properties are pledged as
collateral under our credit facility.
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OIL AND GAS RESERVES
The following tables summarize certain information regarding our
estimated proved oil and gas reserves as of December 31, 2000, 1999 and 1998.
All such reserves are located in the United States. The estimates relating to
our proved oil and gas reserves and future net revenues of oil and gas reserves
at December 31, 2000 and December 31, 1999 are based upon reports prepared by
LaRoche Petroleum Consultants. The estimates at December 31, 1998 included in
this report are based upon reports prepared by Harlan Consulting. In accordance
with the guidelines of the Securities and Exchange Commission, the estimates of
future net cash flows from proved reserves and their SEC PV-10 are made using
oil and gas sales prices in effect as of the dates of such estimates and are
held constant throughout the life of the properties. For the three years ended
December 31, our estimates of proved reserves, future net cash flows and SEC
PV-10 for the life of the properties were estimated using the weighted average
prices shown below for the life of the properties, before deduction of
production, severance and ad valorem taxes. Included in the table is the percent
change in the weighted-average price from the prior year.
DECEMBER 31,
------------------------------------------------------------
% INCREASE % INCREASE
2000 (DECREASE) 1999 (DECREASE) 1998
------- ---------- ------- ---------- ------
Gas ($ per Mcf).................... $ 9.21 311 $ 2.24 20 $ 1.86
Oil ($ per Bbl).................... $ 25.21 8 $ 23.42 140 $ 9.74
Reserve estimates are imprecise and may be expected to change as
additional information becomes available. Furthermore, estimates of oil and gas
reserves, of necessity, are projections based on engineering data, and there are
uncertainties inherent in the interpretation of such data as well as the
projection of future rates of production and the timing of development
expenditures. Reservoir engineering is a subjective process of estimating
underground accumulations of oil and gas that cannot be measured in an exact
way, and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgement.
Reserve reports of other engineers might differ from the reports contained
herein. Results of drilling, testing, and production subsequent to the date of
the estimate may justify revision of such estimate. Future prices received for
the sale of oil and gas may be different from those used in preparing these
reports. The amounts and timing of future operating and development costs may
also differ from those used. Accordingly, there can be no assurance that the
reserves set forth herein will ultimately be produced nor can there be assurance
that the proved undeveloped reserves will be developed within the periods
anticipated. We emphasize with respect to the estimates prepared by independent
petroleum engineers that the discounted future net cash inflows should not be
construed as representative of the fair market value of the proved oil and gas
properties belonging to us, since discounted future net cash inflows are based
upon projected cash inflows which do not provide for changes in oil and gas
prices nor for escalation of expenses and capital costs. The meaningfulness of
such estimates is highly dependent upon the accuracy of the assumptions upon
which they were based.
All reserves are evaluated at contract temperature and pressure that
can affect the measurement of gas reserves. Operating costs, development costs
and certain production-related and ad valorem taxes were deducted in arriving at
the estimated future net cash flows. No provision was made for income operating
methods and existing conditions at the prices and operating costs prevailing at
the dates indicated above. The estimates of the SEC PV-10 from future net cash
flows differ from the Standardized Measure set forth in Note 17 of the Notes to
the Consolidated Financial Statements of the Company, which is calculated after
provision for future income taxes. There can be no assurance that these
estimates are accurate predictions of future net cash flows from oil and gas
reserves or their present value.
For additional information concerning our oil and gas reserves and
estimates of future net revenues attributable thereto, see Note 17 of the Notes
to the Consolidated Financial Statements.
COMPANY RESERVES
The following tables set forth our proved reserves of oil and gas and
the SEC PV-10 thereof on an actual basis for each year in the three-year period
ended December 31, 2000.
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PROVED OIL AND GAS RESERVES (1)
DECEMBER 31,
------------------------------------------------------------------
% Increase % Increase
2000 (Decrease) 1999 (Decrease) 1998
------------ ----------- ----------- ---------- -----------
GAS RESERVES (MCF):
Proved Developed Producing Reserves .......... 13,299,946 67 7,987,551 (6) 8,500,655
Proved Developed Non-Producing Reserves ...... 366,330 341 82,982 N/A 0
Proved Undeveloped Reserves .................. 17,647 (87) 140,309 (89) 1,289,785
------------ ----------- -----------
Total Proved Reserves of Gas ................. 13,683,923 67 8,210,842 (16) 9,790,440
------------ ----------- -----------
OIL RESERVES (BBL):
Proved Developed Producing Reserves .......... 2,243,649 38 1,624,549 48 1,094,454
Proved Developed Non-Producing Reserves ...... 201,577 (46) 375,435 N/A 0
Proved Undeveloped Reserves .................. 77,642 (61) 196,682 932 19,051
------------ ----------- -----------
Total Proved Reserves of Oil ................. 2,522,868 15 2,196,666 97 1,113,505
------------ ----------- -----------
TOTAL PROVED RESERVES (MCFE) ...................... 28,821,131 35 21,390,838 30 16,471,470
============ =========== ===========
- ----------
SEC PV-10 OF PROVED RESERVES
DECEMBER 31,
---------------------------------------------------------
% INCREASE % INCREASE
2000 (DECREASE) 1999 (DECREASE) 1998
--------- ---------- --------- ---------- --------
SEC PV-10 (thousands) (1):
Proved Developed Producing Reserves........ $ 76,170 219 $ 23,863 103 $ 11,780
Proved Developed Non-Producing Reserves.... 4,372 (6) 4,646 N/A 0
Proved Undeveloped Reserves................ 1,108 (47) 2,072 43 1,454
--------- --------- --------
Total SEC PV-10............................ $ 81,650 167 $ 30,581 131 $ 13,234
========= ========= ========
- ----------
(1) SEC PV-10 differs from the Standardized Measure set forth in the Notes
to the Consolidated Financial Statements of the Company, which is
calculated after provision for future income taxes.
Except for the effect of changes in oil and gas prices, no major
discovery or other favorable or adverse event is believed to have caused a
significant change in these estimates of our proved reserves since December 31,
2000.
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VOLUMES, PRICES AND COSTS
The following table sets forth certain information regarding volumes of
our production of oil and gas, our average sales price per Bbl of crude oil and
average sales price per Mcf of gas, together with our average production cost
per BOE for each of the three years ended December 31, 2000 from producing
interests:
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------
% %
INCREASE INCREASE
2000 (DECREASE) 1999 (DECREASE) 1998
---------- ---------- ---------- ---------- --------
Production
Oil (Bbl)............................ 273,706 112 128,924 43 90,097
Gas (Mcf)............................. 1,318,714 44 918,986 133 394,849
Oil equivalent (BOE).................. 493,492 75 282,088 81 155,905
Average Sales Price
Oil ($/Bbl)........................... $ 28.45 66 $ 17.14 27 $ 13.48
Gas ($/Mcf)........................... 3.94 84 2.14 12 1.91
Oil equivalent ($/BOE)................ 26.67 80 14.81 17 12.63
Average production cost $/BOE............... $ 4.71 90 $ 2.48 $ (34) 3.74
- ----------
DRILLING ACTIVITY
The following table sets forth for each of the last three years the
number of net exploratory and development wells drilled by us or on our behalf.
An exploratory well is a well drilled to find and produce oil or gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir, or to extend a known reservoir. A
development well is a well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive. The
number of wells drilled refers to the number of wells completed at any time
during the respective year, regardless of when drilling was initiated; and
"completion" refers to the installation of permanent equipment for the
production of oil or gas, or, in the case of a dry well, to the reporting of the
plugging date to the appropriate state regulatory agency.
NET EXPLORATORY WELLS NET DEVELOPMENT WELLS
-------------------------------- --------------------------------
YEAR ENDED PRODUCTIVE(1) DRY(2) PRODUCTIVE(1) DRY(2)
DECEMBER 31, -------------- ------------- ------------- ------------
1998................ 0.00 0.57 0.22 0.90
1999................ 0.13 0.13 0.36 0.00
2000................ 0.83 0.45 0.29 0.19
- ----------
(1) A productive well is an exploratory or a development well that
is not a dry well.
(2) A dry well is an exploratory or development well found to be
incapable of producing either oil or gas in sufficient
quantities to justify completion as an oil or gas well.
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PRODUCING WELLS AND ACREAGE
The following table sets forth the gross and net producing oil and gas
wells in which we owned an interest and the developed and undeveloped gross and
net leasehold acreage held by us as of December 31, 2000. A "gross" well or acre
is a well or acre in which we have a working interest or royalty interest. The
number of gross wells is the total number of wells in which a working interest
or royalty interest is owned. A "net" well or acre is deemed to exist when the
sum of fractional ownership working interests and/or royalty interests in a
gross well or acre equals one. The number of net wells or acres is the sum of
the fractional working interests and/or royalty interests owned in gross wells
or acres expressed as whole numbers and fractions thereof.
YEAR ENDED
DECEMBER 31, 2000(1)
----------------------------
Wells OIL GAS
--------- -------
Working Interest
Gross..................................... 1,231.00 343.00
Net....................................... 34.12 24.39
Average working interest(%)............... 2.77 7.11
Royalty Interest
Gross..................................... 2,589.00 424.00
Net ...................................... 14.51 10.19
Average royalty interest(%) .............. 0.56 2.40
Acreage Developed Undeveloped(2)
--------- --------------
Developed
Gross..................................... 257,479 47,972
Net....................................... 36,702 22,950
- ----------
(1) Does not include wells that are considered to have a minor
value on an individual basis.
(2) Undeveloped acreage is considered to be only those leased
acres on which wells have not been drilled or completed to a
point that would permit the production of commercial
quantities of oil and gas regardless of whether or not the
acreage contains proved reserves.
PRESENT ACTIVITIES
For the period January 1, 2001 through March 16, 2001, we participated
in drilling three gross (0.32 net) development wells. Two of the wells were
successfully completed as oil wells, one of which is on our Texas Holdings where
we own a 9.38% net royalty interest. The third development well was successfully
drilled as a gas well.
OFFICE LEASE
We occupy approximately 5,277 square feet of office space at 4809 Cole
Avenue, Suite 108, Dallas, Texas 75205 under a lease from Chalk Stream
Properties, L.P. Total rental expense for 2000 was $85,983.
ITEM 3. LEGAL PROCEEDINGS.
During 2000, we were not a party to any legal proceeding.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
On December 7, 2000, we submitted a written consent solicitation
statement to the stockholders of the Company as of record date October 19, 2000.
The consent solicitation statement was furnished to the stockholders of the
Company in connection with the solicitation by the Company of the written
consents of the stockholders to the issuance of up to an additional 180,000
shares of our Common Stock (the "Deferred Shares"). The Deferred Shares will
have identical rights and preferences as the Company's currently outstanding
shares of common stock.
The purpose of the issuance of the Deferred Shares is to satisfy
certain obligations that are owed to certain stockholders of Texona pursuant to
the terms of the Merger Agreement, dated as of September 11, 2000, by and among
Texona, the Company, and Toreador Acquisition Corporation. Pursuant to the
Merger Agreement, the outstanding stock of Texona was exchanged for a total of
1,115,000 shares of common stock of the Company, of which 1,025,000 shares
(19.6% of the then outstanding shares) were issued to the Texona stockholders at
the closing of the merger on September 19, 2000.
We did not issue all 1,115,000 shares due to the rules of the National
Association of Securities Dealers Automated Quotation ("Nasdaq") requiring us to
obtain stockholder approval before the issuance of common stock
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constituting or having voting power equal to or greater than 20% of the
outstanding common stock. On September 19, 2000, 1,115,000 shares of common
stock constituted approximately 21% of the then outstanding shares. Therefore,
in order to comply with the applicable Nasdaq rules, we initially issued shares
of our common stock equal to 19.6% of the outstanding shares on September 19,
2000, and then were requesting stockholder approval for the issuance of the
Deferred Shares. Pursuant to the Merger Agreement, the Deferred Shares must be
issued no later than June 1, 2001.
The actual number of Deferred Shares to be issued will be between
90,000 and 180,000 based on a formula set forth in the Merger Agreement, subject
to adjustment prior to the issuance of the Deferred Shares of (i) the payment of
dividends on our currently issued common stock in shares of our common stock;
(ii) a stock split of our common stock; (iii) a reverse stock split of our
common stock; or (iv) other reclassifications or recapitalizations of our common
stock. Once issued, the Deferred Shares will be shares of our common stock
having identical rights and preferences as our currently outstanding shares of
common stock. If the issuance date were March 16, 2001, 90,000 Deferred Shares
would have been issued.
Except for the Texona stockholders that will receive the Deferred
Shares, the current stockholders of the Company's common stock will have their
percentage ownership of common stock diluted due to the issuance of the Deferred
Shares only to the Texona stockholders. This dilution is approximately 1.7% of
the common stock holdings of each such stockholder if 90,000 Deferred Shares are
issued and 3.4% of the common stock holdings of each such stockholder if 180,000
Deferred Shares are issued. The actual amount of dilution for each stockholder
will depend on the actual number of Deferred Shares issued.
The Board of Directors unanimously approved the issuance of the
additional shares of common stock as of August 1, 2000. Although approval by
stockholders of the Company of the issuance of common stock is not required
under governing Delaware law, such approval is required under the Nasdaq Rules
applicable to companies listed on the Nasdaq National Market. To assure
continued compliance with the listing rules of the Nasdaq National Market, the
terms of the Merger Agreement provide that the Deferred Shares can only be
issued if the stockholder approval is obtained. If the approval is not obtained,
Deferred Shares will not be issued and there will be no financial penalty.
Out of the 6,249,572 shares of our common stock issued and outstanding
as of October 19, 2000, we received 3,725,155 affirmative votes, 142,688 against
votes, 213,438 abstentions and 2,168,291 broker non-votes. Although majority
consent was received, the Deferred Shares were not issued. Nasdaq requested that
the Merger Agreement be amended to remove a certain clause calling for a penalty
payment to be made by Toreador to the Texona shareholders if the Deferred Shares
were not issued on or before June 1, 2001. The Merger Agreement was amended on
January 30, 2001 in order to comply with the request.
A revised written consent solicitation was submitted on February 22,
2001 to the stockholders of the Company as of record date February 5, 2001
reflecting the amendment to the Merger Agreement. The deadline for the responses
has been extended until April 2001.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
MARKET INFORMATION
Our shares of Common Stock, par value $.15625 per share are traded on
the Nasdaq National Market System under the trading symbol "TRGL." The following
table sets forth the high and low sale prices per share for the Common Stock for
each quarterly period during the past two fiscal years as reported by Nasdaq
based upon quotations which reflect inter-dealer prices, without retail mark-up,
mark-down or commission and may not represent actual transactions.
2000 High Low
- ------------------------------------- -------- ---------
First Quarter....................... 8 3 5/8
Second Quarter...................... 5 1/2 4 7/8
Third Quarter....................... 6 1/2 4 7/8
Fourth Quarter...................... 6 1/4 5 3/4
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25
1999 High Low
- ------------------------------------- -------- ---------
First Quarter....................... 3 3/4 2 1/4
Second Quarter...................... 3 3/8 2 3/8
Third Quarter....................... 3 9/16 2 15/16
Fourth Quarter...................... 4 3/4 3 7/16
HOLDERS AND CLOSING PRICE
As of March 16, 2001, there were 6,270,944 shares of Common Stock
outstanding held of record by 462 holders (inclusive of those brokerage firms,
clearing houses, banks and other nominee holders, holding Common Stock for
clients, with all such nominees being considered as one holder).
The closing price of the Common Stock on the Nasdaq National Market
System on March 16, 2001 was $5.50.
DIVIDENDS
Dividends on the Common Stock may be declared and paid out of funds
legally available when and as determined by our board of directors. Cash
dividends totaling $51,775 have been paid on our Common Stock to date. Our board
of directors plans to continue our policy of holding and investing corporate
funds on a conservative basis, and thus we do not anticipate paying cash
dividends on our Common Stock in the foreseeable future. In addition, under the
terms of the Facility (as defined below) described in "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operation --
Liquidity and Capital Resources," we are prohibited from paying dividends on the
Common Stock without prior consent from Bank of Texas, National Association
(other than dividends payable in shares of Common Stock).
Dividends on our Series A Preferred Stock are paid on a quarterly basis
per the terms of the Certificate of Designation, as amended. Cash dividends
totaling $360,000 were paid for the years ended December 31, 2000 and 1999 and
$19,500 was paid for the year ended December 31, 1998. Future dividends will be
paid in cash only at a rate of $90,000 per calendar quarter.
ITEM 6. SELECTED FINANCIAL DATA.
The following table summarizes certain selected financial data with
respect to our financial condition and results of operations for the periods
indicated. The selected financial data should be read in conjunction with the
financial statements and related notes set forth in "Item 8. Financial
Statements and Supplementary Data" of this Part II.
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YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------------
INCOME STATEMENT DATA: 2000(a) 1999(b) 1998 1997 1996
------------ ------------ ------------ ------------ ------------
Revenues:
Oil and gas sales ........................... $ 13,163,862 $ 4,259,040 $ 1,968,638 $ 2,325,148 $ 2,306,791
Lease bonuses and rentals ................... 472,845 463,083 168,664 287,604 118,430
Interest and other income ................... 70,702 109,035 171,338 149,841 162,297
Equity in earnings of unconsolidated
investments ............................... (53,977) -- -- -- --
Gain on sale of properties .................. 407,679 851,726 -- 26,171 --
Gain (loss) on sale of marketable
securities ................................ (54,076) (79,615) -- -- 526,567
------------ ------------ ------------ ------------ ------------
Total revenues .......................... 14,007,035 5,603,269 2,308,640 2,788,764 3,114,085
------------ ------------ ------------ ------------ ------------
Costs and Expenses:
Lease operating ............................. 2,324,603 699,278 583,441 695,007 585,732
Dry holes and abandonments .................. 50,642 9,933 133,113 166,710 130,647
Depreciation, depletion and amortization .... 2,439,368 1,276,268 514,071 539,346 273,026
Geological and geophysical .................. 258,345 394,496 517,870 546,634 227,744
General and administrative .................. 2,219,684 1,583,729 999,548 802,723 907,086
Other ....................................... 188,940 -- -- 173,971 --
Interest .................................... 1,408,807 794,627 36,120 -- --
------------ ------------ ------------ ------------ ------------
Total costs and expenses ................ 8,890,389 4,758,331 2,784,163 2,924,391 2,124,235
------------ ------------ ------------ ------------ ------------
Income (loss) before federal income taxes ........ 5,116,646 844,938 (475,523) (135,627) 989,850
Provision (benefit) for federal income taxes ..... 1,763,577 336,927 (233,277) (84,261) 263,100
------------ ------------ ------------ ------------ ------------
Net income (loss) ........................... $ 3,353,069 $ 508,011 $ (242,246) $ (51,366) $ 726,750
============ ============ ============ ============ ============
Dividend on preferred shares ................ 360,000 360,000 19,500 -- --
Income (loss) attributable to common shares ...... $ 2,993,069 $ 148,011 $ (261,746) $ (51,366) $ 726,750
============ ============ ============ ============ ============
Basic income (loss) per share ............... $ 0.54 $ 0.03 $ (0.05) $ (0.01) $ 0.14
Diluted income (loss) per share ............. $ 0.50 $ 0.03 $ (0.05) $ (0.01) $ 0.14
Weighted average shares outstanding
Basic ................................... 5,522,321 5,185,588 5,125,063 5,022,216 5,216,941
Diluted ................................. 6,691,361 5,250,862 5,125,603 5,022,216 5,216,941
CASH FLOW DATA:
Net cash provided by
operating activities .................... $ 6,046,146 $ 763,314 $ 276,624 $ 830,643 $ 609,364
Capital expenditures for oil and gas
property and equipment .................. $ (2,429,924) $ (9,208,348) $(13,951,981) $ (717,481) $ (893,418)
BALANCE SHEET DATA:
Working capital ............................. $ 3,177,683 $ 438,611 $ 1,987,764 $ 3,007,121 $ 3,383,668
Oil and gas properties, net ................. 34,629,513 24,423,537 16,209,631 3,210,074 3,306,020
Total assets ................................ 40,324,955 26,455,980 19,782,262 6,526,785 7,008,924
Long-term debt .............................. 15,244,223 14,666,500 7,880,000 -- --
Stockholders' equity ........................ 20,260,893 10,650,198 10,594,508 6,217,195 6,624,180
- ----------
(a) 2000 results contain results from the Texona acquisition from September 19,
2000 through December 31, 2000.
(b) 1999 results contain full year results from the Southeastern States
Acquisition and partial year results from the Four States Acquisition.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATION.
INTRODUCTION
In Management's Discussion and Analysis, we explain our general
financial condition and the results of operations including:
o what factors affect our business;
o what our earnings and costs were in 2000, 1999 and 1998;
o why those earnings and costs were different from the year
before;
o where our earnings came from;
o how all of this affects our overall financial condition;
o what our expenditures for capital projects were in 1998
through 2000 and what we expect them to be in 2001 and
o where cash will come from to pay for future capital
expenditures.
As you read Management's Discussion and Analysis, it may be helpful to
refer to the Company's Consolidated Statements of Operations on page F-4, which
present the results of our operations for 2000, 1999 and 1998. In Management's
Discussion and Analysis, we analyze and explain the annual changes in the
specific line items in the Consolidated Statements of Operations. Our analysis
may be important to you in making decisions about your investments in Toreador.
The Company follows the successful efforts method of accounting for oil
and gas exploration and development expenditures. Under this method, costs of
successful exploratory wells and all development wells are capitalized. Costs to
drill exploratory wells, which do not find proved reserves, are expensed.
Significant costs associated with the acquisition of oil and gas properties are
capitalized. Acquisition costs of mineral interests in oil and gas properties
remain capitalized until they are impaired or a determination has been made to
discontinue
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exploration of the lease, at which time all related costs are charged to
expense. Impairment of unproved properties is assessed and recorded on a
property-by-property basis. Upon sale or abandonment of units of property or the
disposition of miscellaneous equipment, the cost is removed from the asset
account, the related reserves relieved of the accumulated depreciation or
depletion and the gain or loss is credited to or charged against operations.
Maintenance and repairs are charged to expense; betterments of property are
capitalized as described below. The Company provides for depreciation, depletion
and amortization of its investment in producing oil and gas properties on the
units-of-production method, based upon independent reserve engineers' estimates
of recoverable oil and gas reserves from the property. Depreciation expense for
fixed assets is generally calculated on a straight-line basis based upon
estimated useful lives of five years.
The Company evaluates the carrying value of its long-lived assets,
consisting primarily of oil and gas properties, when events or changes in
circumstances indicate that the carrying value of such assets may be impaired.
The determination of impairment is based upon expectations of undiscounted
future cash flows of the related asset pursuant to Statement of Financial
Accounting Standard No. 121 (SFAS 121) "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed of." There was no
impairment in 2000. There was impairment during 1999 in the amount of $14,401,
primarily due to the decrease in oil and gas reserves for the affected producing
properties. There was impairment in 1998 of $19,649 resulting from the decrease
in oil and gas prices and there was no impairment during 1997. The impairments
are included in the "Depreciation, depletion and amortization" category of the
Consolidated Statements of Operations.
LIQUIDITY AND CAPITAL RESOURCES
Historically, most of the exploration activity on our acreage has been
funded and conducted by other oil companies. Exploration activity by third party
oil companies typically generates lease bonus and option income to us. If such
drilling is successful, we receive royalty income from the oil or gas production
but bear none of the capital or operating costs. Since the middle of 1996, we
have successfully accelerated the evaluation of several areas of our mineral
acreage as well as increased our ownership in any reserves that were discovered
by acquiring working interests of selected 3-D seismic projects and any wells
drilled as a result of such geological activity.
We will continue to actively pursue exploration and development
opportunities on our own mineral acreage in order to take advantage of the
current favorable level of crude oil prices. We will also expand our drilling
focus to geologic regions, particularly those areas with proven and attractive
gas reserves that can provide potentially better rates of return on our capital
resources. We also plan to evaluate 3-D seismic projects or drilling prospects,
generated by third party operators. If judged geologically and financially
attractive by our management, we will enter into joint ventures on those third
party projects subject to available room within the capital exploration budget
approved by our board of directors.
Our 2001 capital exploration budget, excluding any acquisitions we may
make, could range from $2,500,000 to $4,000,000, depending on the timing of any
new seismic surveys and drilling of exploratory and development wells in which
we may hold a working interest position.
We also intend to actively evaluate opportunities to acquire producing
properties that represent unique opportunities for us to add additional reserves
to our reserve base while not increasing general and administrative costs. Any
such acquisitions will be financed using cash on hand, third party sources,
existing credit facilities or any combination thereof.
At the present time, the primary source of capital for financing our
operations is our cash flow from operations. During 2000, cash flow provided by
operating activities was $6,046,146. We anticipate that cash flow provided by
operating activities for 2001 will be materially higher reflecting the higher
gas and crude oil prices and increased reserves from more recent acquisitions
and mergers.
On February 16, 2001, the Company entered into a $75 million credit
agreement (the "Facility") with Bank of Texas, National Association that matures
on February 16, 2006. The Facility replaced the Company's prior revolving credit
facility with Compass Bank that had a maturity date of October 1, 2002 (the
"Prior Credit Facility"). Outstanding borrowings under the Prior Credit Facility
totaled $15.2 million as of December 31, 2000. The interest rate on the Prior
Credit Facility at December 31, 2000 was 9.25%.
The Facility bears interest, at the option of the Company, based on (a)
a base rate equal to the higher of (i) the rate of interest per annum then most
recently published by The Wall Street Journal as the prime rate on corporate
loans for large U.S. commercial banks (9.50% at December 31, 2000) less 1.25%,
or (ii) the sum of the rate of interest, then most recently published by The
Wall Street Journal as the "federal funds" rate for reserves traded
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28
among commercial banks for overnight use, less three quarters of one percent
(0.75%), both as published in the Money Rates section of The Wall Street
Journal, or (b) the sum of the LIBOR Rate (6.40% at December 31, 2000) plus
1.75%. Additionally, the Facility calls for a commitment fee of 0.375% on the
unused portion.
The Facility imposes certain restrictive covenants on the Company,
including the maintenance of a Debt Service Coverage Ratio greater than or equal
to 1.25 to 1.00; maintenance of a Current Ratio greater than or equal to 1.00 to
1.00; and maintenance of a Tangible Net Worth of not less than the sum of (i)
$13.65 million, plus (ii) 50% of the Company's annual net income, plus (iii)
100% of all equity contributions. Although the Facility was not in place as of
December 31, 2000, the Company was in compliance with all covenants.
The Facility is controlled by the borrowing base. The amount of debt
outstanding at any time is not allowed to exceed the borrowing base as
determined by the lender. The borrowing base is subject to evaluation every six
months and can be adjusted either up or down. We are required to repay any
principal that exceeds the revised borrowing base. The borrowing base as of
March 16, 2001 was $20.00 million.
We may reinvest proceeds from option and lease bonuses by taking a
working interest in 3-D seismic projects or in wells. To the extent cash flow
from operations does not significantly increase and external sources of capital
are limited or unavailable, our ability to make the capital investment to
participate in 3-D seismic surveys and increase our interest in projects on our
acreage will be limited. Future funds are expected to be provided through
production from existing producing properties and new producing properties that
may be discovered through exploration of our acreage by third parties or by us.
Funds may also be provided through external financing in the form of debt or
equity. There can be no assurance as to the extent and availability of these
sources of funding.
We maintain our excess cash funds in interest-bearing deposits and in
marketable securities. In addition to the properties described above, we also
may acquire other producing oil and gas assets, which could require the use of
debt, including the Facility or other forms of financing.
Our management believes that sufficient funds are available from
internal sources and other third party sources to meet anticipated capital
requirements for fiscal 2001.
Through December 31, 2000 we have used $1,537,794 of our cash reserves
to purchase 527,000 shares of our Common Stock pursuant to four share repurchase
programs and discretionary repurchases of our stock subject to cash availability
as approved by the board of directors. On March 23, 1999, the Company's board of
directors reinstated the existing common stock repurchase program enabling the
Company to purchase the remaining 117,300 shares available under the April 1997
stock repurchase plan from time to time and depending on market conditions. On
October 18, 2000 the Company's board authorized the repurchase of up to 500,000
additional shares. As of December 31, 2000, the Company had repurchased 527,000
shares under all plans, leaving 528,700 shares remaining available for
repurchase. Management anticipates that any future repurchases of the Company's
Common Stock will be funded from the Company's cash flow from operations and
working capital.
Dividends on our Common Stock may be declared and paid out of funds
legally available when and as determined by our board of directors. Cash
dividends totaling $51,775 have been paid on our Common Stock to date. Our board
of directors plans to continue our policy of holding and investing corporate
funds on a conservative basis, and thus we do not anticipate paying cash
dividends on our Common Stock in the foreseeable future. In addition, under the
terms of the Facility we are prohibited from paying dividends on the Common
Stock without prior consent from Bank of Texas, National Association (other than
dividends payable in shares of Common Stock).
Dividends on our Series A Preferred Stock are paid on a quarterly basis
per the terms of the Certificate of Designation, as amended. Cash dividends
totaling $360,000 were paid for the years ended December 31, 2000 and 1999 and
$19,500 was paid for the year ended December 31, 1998. Future dividends will be
paid in cash only at a rate of $90,000 per calendar quarter.
During 2000, we received a total of $25,000 as a result of the exercise
of stock options to purchase our Common Stock by a former consultant. Those
options related to 10,000 shares of Common Stock with an exercise price of $2.50
per share.
26
29
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999
Total revenues for 2000 were $14,007,035 compared with $5,630,269 in
1999. Revenues from oil and gas sales increased to $13,163,862 in 2000 from
$4,259,040 in 1999. This 209.1% increase reflects a 74.9% increase in volume on
a BOE basis (principally reflecting the benefit of a full year of revenue from
properties acquired in the latter part of 1999, along with the Texona Merger in
September 2000) along with an 80.1% increase on a price per BOE basis. Average
oil prices increased 66.0% to $28.45 in 2000 from $17.14 in 1999. Average gas
prices increased 84% to $3.94 in 2000 from $2.14 in 1999. Our net oil production
increased 112.3% to 273,706 Bbls in 2000 from 128,924 Bbls in 1999. Net gas
production increased 43.5% to 1,318,714 Mcf of gas in 2000 from 918,986 Mcf of
gas in 1999. Lease bonuses and rentals were $472,845 in 2000, up from $463,083
in 1999.
Interest and other income were $70,702 in 2000 versus $109,035 in 1999.
This 35.2% decrease was due to the employment of short-term funds in the
acquisition of properties and repayment of debt rather than retaining such funds
in interest bearing accounts. Gain on sale of properties and other assets was
$407,679 in 2000, down from $851,726 in 1999. The 1999 sales were for two large
mineral acreage packages while the 2000 sales were for several producing
properties.
Total costs and expenses were $8,890,389 in 2000 as compared with
$4,758,331 in 1999 representing an 86.8% increase. The largest increases came
from lease operating expense and depreciation, depletion and amortization where
expenses increased 232.4% and 91.1% to $2,324,603 and $2,439,368 in 2000 versus
$699,278 and $1,276,268 in 1999, respectively. This major increase reflects the
property acquisitions we made during December of 1999 and during 2000, all of
which were working interest properties. Dry holes and abandonments increased to
$50,642 in 2000 from $9,933 in 1999, due to the increased drilling activity we
participated in during 2000. Geological and geophysical expenses decreased 34.5%
to $258,345 in 2000 versus $394,496 in 1999, reflecting the completion of our
two 3-D seismic projects that will generate future drilling sites. Our general
and administrative expenses increased $635,955 or 40.2% to $2,219,684 in 2000
from $1,583,729 in 1999, primarily resulting from the addition of staff. During
2000, we incurred interest expense of $1,408,807 as compared with $794,627 in
1999 as a result of debt incurred for the property acquisitions made from
December of 1999 through December of 2000. Other expense during 2000 totaled
$188,940 vs. zero in 1999, primarily resulting from the mark to market loss of
$135,300 on our derivative financial instruments. The provision for income taxes
increased to $1,763,577 in 2000 from $336,927 in 1999, due to the increased
income realized in 2000.
Total net income applicable to common shares for 2000 was $2,993,069 or
$0.54 per share compared to net income of $148,011 or $0.03 per share in 1999.
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Total revenues for 1999 were $5,603,269 compared with $2,308,640 in
1998. Revenues from oil and gas sales increased to $4,259,040 in 1999 from
$1,968,638 in 1998. This 116.3% increase reflects a 63.2% increase in volume on
a BOE basis (principally reflecting the benefit of a full year of revenue from
properties acquired in December of 1998) along with a 32.5% increase on a price
per BOE basis. Average oil prices increased 27.2% to $17.14 in 1999 from $13.48
in 1998. Average gas prices increased 12% to $2.14 in 1999 from $1.91 in 1998.
Our net oil production increased 28.1% to 128,924 Bbls in 1999 from 100,615 Bbls
in 1998. Net gas production increased 112.1% to 918,986 Mcf of gas in 1999 from
433,272 Mcf of gas in 1998. Lease bonuses and rentals were $463,083 in 1999, up
from $168,664 in 1998, an increase of 174.6% primarily as a result of leasing
activity on our Southeastern States Holdings.
Interest and other income were $109,035 in 1999 versus $171,338 in
1998. This 36.4% decrease was due to the employment of short-term funds in the
acquisition of properties rather than retaining such funds in interest bearing
accounts.
27
30
Total costs and expenses were $4,758,331 in 1999 as compared with
$2,784,163 in 1998 representing a 70.9% increase. The largest increase came from
depreciation, depletion and amortization where expenses increased 148.3% to
$1,276,268 in 1999 versus $514,071 in 1998. This major increase reflects the
property acquisitions we made during December of 1998 and during 1999. Dry holes
and abandonments decreased 92.5% to $9,933 in 1999 from $133,113 in 1998, due to
the decreased drilling activity we participated in during 1999. Geological and
geophysical expenses decreased 23.8% to $394,496 in 1999 versus $517,870 in
1998, reflecting the completion of our acquisition and processing phase of the
two 3-D seismic projects that will generate future drilling sites. Our general
and administrative expenses increased $584,181 or 58.4% to $1,583,729 in 1999
from $999,548 in 1998, primarily resulting from the addition of staff. During
1999, we incurred interest expense of $794,627 as compared with $36,120 in 1998
as a result of debt incurred for the property acquisitions made from December of
1998 through December of 1999.
Total net income applicable to common shares for 1999 was $148,011 or
$0.03 per share compared to a net loss of $261,746 or $0.05 per share in 1998.
NEW ACCOUNTING PRONOUNCEMENTS
The Company has not yet adopted Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities." This Statement will be adopted effective January 1, 2001. It
establishes accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts, and for
hedging activities. This Statement does not allow retroactive application to
financial statements of prior periods. The Company is accounting for its
financial instruments on a mark to market basis. For the year ended December 31,
2000, the Company recorded a loss, included in other expense, and an offsetting
accrued liability of $135,300. Accordingly, the result of the adoption of this
Statement will have no impact on future income. The Company intends continue to
account for the results of financial instruments on a mark to market basis.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The risk inherent in the Company's market risk sensitive instruments is
the potential loss arising from adverse changes in oil and gas commodity prices
and interest rates as discussed below. The sensitivity analysis does not,
however, consider the effects that such adverse changes may have on overall
economic activity nor do they consider additional actions the Company may take
to mitigate its exposure to such changes. Actual results may differ.
The following quantitative and qualitative information is provided
about financial instruments to which the Company is a party as of December 31,
2000, and from which the Company may incur future earnings gains or losses from
changes in commodity prices. The Company does not enter into derivative or other
financial instruments for trading purposes.
OIL AND GAS PRICES. The Company markets its oil and gas production
primarily on a spot market basis. As a result, the Company's earnings could be
affected by changes in the prices for these commodities, regulatory matters or
demand for the commodities. As market conditions dictate, the Company from time
to time will lock-in future oil and gas prices using various hedging techniques.
The Company does not use such financial instruments for trading purposes and is
not a party to any leveraged derivatives. Market risk is estimated as a 10%
decrease in the prices of oil and gas. Based on our projections for 2001 sales
volumes at fixed prices, such a decrease would result in a reduction to oil and
gas sales revenue of approximately $2.1 million before considering the effect of
the option agreements discussed below.
INTEREST RATES. The Company's earnings are affected by changes in
short-term interest rates related to its line of credit, discussed in Note 8 of
Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data". Market risk is estimated as a hypothetical
increase in short-term interest rates of 100 basis points. Based on our
projections of outstanding borrowings for fiscal 2001, such an increase could
result in an addition to interest expense of approximately $152,000.
DERIVATIVE FINANCIAL INSTRUMENTS. The Company has entered into
commodity price derivative contracts to hedge commodity price risks. The
Company's policy is not to enter into derivative contracts for trading purposes.
28
31
Gas hedge derivatives
The Company employs a policy of hedging a portion of its gas production
in order to mitigate the price risk between NYMEX prices and actual receipt
prices. As of December 31, 2000, the Company has hedged a portion of its gas
price risk with collar and non-collar contracts that provide a fixed floor price
but allow the Company to participate, within a contractual range, in index
prices if they close above the contractual floor price. The average gas prices
per Mcf that the Company reports includes the effects of Btu content, gathering
and transportation costs, gas processing and shrinkage and the net effect of the
gas hedges.
COMMODITY PRICE SENSITIVITY. The following table provides information
about the Company's derivative financial instruments that the Company is a party
to as of December 31, 2000 and that are sensitive to changes in gas commodity
prices. The Company has entered into collar contracts that provide a floor price
for the Company on a notional amount of sales volumes while allowing some
additional price participation for the Company if the relevant index prices
close above the floor price. See Note 7 of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data" for
a description of the accounting procedures followed by the Company relative to
hedge derivative financial instruments and for specific information regarding
the terms of the Company's derivative financial instruments that are sensitive
to changes in gas and crude oil commodity prices.
DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2000
2001
----------
Gas Hedge Derivatives:
Collar option contracts (average MMBtu per
month over contract life)............................. 35,000
Fair market value at December 31, 2000................. $ 173,000
Weighted average short call MMBtu ceiling price... $ 7.27
Weighted average long put MMBtu floor price....... $ 4.11
Non-collar option contracts (average MMBtu
per month over contract life)......................... 25,000
Weighted average long put MMBtu floor price....... $ 3.88
Fair market value at December 31, 2000................. $ 34,000
As of December 31, 2000, the Company's primary risk exposures
associated with financial instruments to which it is a party include gas price
volatility. The Company's primary risk exposures associated with financial
instruments have not changed significantly since December 31, 1999.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The Report of Independent Accountants and Consolidated Financial
Statements are set forth beginning on page F-1 of this Annual Report on Form
10-K and are incorporated herein.
The financial statement schedules have been omitted because they are
not applicable or the required information is shown in the Consolidated
Financial Statements or the Notes to the Consolidated Financial Statements.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
Please see Toreador Royalty Corporation Current Report on Form 8-K
regarding a change in accountants filed on June 30, 1999 with an effective date
of May 24, 1999.
On May 24, 1999, we dismissed PricewaterhouseCoopers LLP ("PWC") as our
independent accountant and on May 24, 1999, we retained Ernst & Young LLP
("E&Y") as our independent accountant.
PWC's reports on our financial statements for the fiscal year ended
December 31, 1998 did not contain an adverse opinion or disclaimer of opinion,
nor was it qualified or modified as to uncertainty, audit scope or accounting
principles.
29
32
The decision to engage E&Y as set forth above and to dismiss PWC was
approved by the audit committee and the board of directors of the Company. There
were no disagreements with PWC.
E&Y has audited our financial statements for the fiscal years ended
December 31, 2000, 1999, and 1998.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Information relating to our directors, nominees for directors and
executive officers will be set forth under the heading "Election of Directors"
in the Company's Proxy Statement relating to the Annual Meeting of Stockholders
to be held May 17, 2001, which will be filed with the Securities and Exchange
Commission on or prior to April 30, 2001, and which is incorporated herein by
reference.
ITEM 11. EXECUTIVE COMPENSATION.
Information relating to executive compensation will be set forth under
the heading "Executive Compensation and Other Transactions" in the Company's
Proxy Statement relating to the Annual Meeting of Stockholders to be held May
17, 2001, which will be filed with the Securities and Exchange Commission on or
prior to April 30, 2001, and which is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Information relating to security ownership of certain beneficial owners
and management will be set forth under the heading "Security Ownership of
Certain Beneficial Owners and Management" in the Company's Proxy Statement
relating to the Annual Meeting of Stockholders to be held May 17, 2001, which
will be filed with the Securities and Exchange Commission on or prior to April
30, 2001, and which is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Information relating to certain relationships and related transactions
will be set forth under the heading "Executive Compensation and Other
Transactions" in the Company's Proxy Statement relating to the Annual Meeting of
Stockholders to be held May 17, 2001, which will be filed with the Securities
and Exchange Commission on or prior to April 30, 2001, and which is incorporated
herein by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a) The following documents are filed as part of this report:
1. Index to Consolidated Financial Statements Report of
Independent Auditors, Consolidated Balance Sheets as
of December 31, 2000 and 1999, Consolidated
Statements of Operations for the three years ended
December 31, 2000, Consolidated Statements of Changes
in Stockholders' Equity for the three years ended
December 31, 2000, Consolidated Statements of Cash
Flows for the three years ended December 31, 2000 and
Notes to Consolidated Financial Statements
2. The financial statement schedules have been omitted
because they are not applicable or the required
information is shown in the Consolidated Financial
Statements or the Notes to Consolidated Financial
Statements.
3. Exhibits:
2.1 - Certificate of Ownership and Merger
merging Toreador Resources Corporation
into Toreador Royalty Corporation,
effective June 5, 2000 (previously
filed as Exhibit 2.1 to Toreador
Resources Corporation Current Report on
Form 8-K filed on June 5, 2000, and
incorporated herein by reference).
30
33
3.1 - Certificate of Incorporation, as
amended, of Toreador Royalty
Corporation (previously filed as
Exhibit 3.1 to Toreador Royalty
Corporation Annual Report on Form 10-K
for the year ended December 31, 1998,
and incorporated herein by reference).
3.2 - Amended and Restated Bylaws, as
amended, of Toreador Royalty
Corporation (previously filed as
Exhibit 3.2 to Toreador Royalty
Corporation Annual Report on Form 10-K
for the year ended December 31, 1998,
and incorporated herein by reference).
3.3 - Certificate of Designation of Series A
Convertible Preferred Stock of Toreador
Royalty Corporation, dated December 14,
1998 (previously filed as Exhibit 10.3
to Toreador Royalty Corporation Current
Report on Form 8-K filed with the
Securities and Exchange Commission on
December 31, 1998, and incorporated
herein by reference).
3.4* - Amendment to Certificate of Designation
of Series A Convertible Preferred Stock
of Toreador Resources Corporation,
dated December 31, 1998.
4.1 - Form of Letter Agreement regarding
Series A Convertible Preferred Stock,
dated as of March 15, 1999, between
Toreador Royalty Corporation and the
holders of Series A Convertible
Preferred Stock (previously filed as
Exhibit 4.1 to Toreador Royalty
Corporation Annual Report on Form 10-K
for the year ended December 31, 1998,
and incorporated herein by reference).
4.2 - Registration Rights Agreement,
effective December 16, 1998, among
Toreador Royalty Corporation and
persons party thereto (previously filed
as Exhibit 10.2 to Toreador Royalty
Corporation Current Report on Form 8-K
filed with the Securities and Exchange
Commission on December 31, 1998, and
incorporated herein by reference).
4.3 - Settlement Agreement, dated June 25,
1998, among the Gralee Persons, the
Dane Falb Persons and Toreador Royalty
Corporation (previously filed as
Exhibit 10.1 to Toreador Royalty
Corporation Current Report on Form 8-K
filed with the Securities and Exchange
Commission on July 1, 1998, and
incorporated herein by reference).
4.4 - Registration Rights Agreement,
effective July 31, 2000, among Toreador
Royalty Corporation and persons party
thereto (previously filed as Exhibit
4.5 to Toreador Resources Corporation
Registration Statement on Form S-3
filed with the Securities and Exchange
Commission on December 22, 2000, and
incorporated herein by reference).
4.5 - Registration Rights Agreement,
effective September 11, 2000, among
Toreador Resources Corporation and Earl
E. Rossman, Jr., Representative of the
Holders (previously filed as Exhibit
4.6 to Toreador Resources Corporation
Registration Statement on Form S-3
filed with the Securities and Exchange
Commission on December 22, 2000, and
incorporated herein by reference).
10.1+ - Employment Agreement, dated as of May
1, 1997, between Toreador Royalty
Corporation and Edward C. Marhanka
(previously filed as Exhibit 10.5 to
Toreador Royalty Corporation Quarterly
Report on Form 10-Q for the quarter
ended June 30, 1997, and incorporated
herein by reference).
31
34
10.2+ - Toreador Royalty Corporation 1990 Stock
Option Plan (previously filed as
Exhibit 10.7 to Toreador Royalty
Corporation Annual Report on Form 10-K
for the year ended December 31, 1994,
and incorporated herein by reference).
10.3+ - Amendment to Toreador Royalty
Corporation 1990 Stock Option Plan,
effective as of May 15, 1997
(previously filed as Exhibit 10.14 to
Toreador Royalty Corporation Annual
Report on Form 10-K for the year ended
December 31, 1997, and incorporated
herein by reference).
10.4+ - Toreador Royalty Corporation 1994
Non-Employee Director Stock Option
Plan, as amended (previously filed as
Exhibit 10.12 to Toreador Royalty
Corporation Annual Report on Form 10-K
for the year ended December 31, 1995,
and incorporated herein by reference).
10.5+ - Toreador Royalty Corporation Amended
and Restated 1990 Stock Option Plan,
effective as of September 24, 1998
(previously filed as Exhibit A to
Toreador Royalty Corporation
Preliminary Proxy Statement filed with
the Securities and Exchange Commission
on March 12, 1999, and incorporated
herein by reference).
10.6+ - Form of Indemnification Agreement,
dated as of April 25, 1995, between
Toreador Royalty Corporation and each
of the members of our Board of
Directors (previously filed as Exhibit
10 to Toreador Royalty Corporation
Quarterly Report on Form 10-Q for the
quarterly period ended June 30, 1995,
and incorporated herein by reference).
10.7+ - Toreador Royalty Corporation Amended
and Restated 1990 Stock Option Plan
Nonqualified Stock Option Agreement,
dated September 24, 1998, between
Toreador Royalty Corporation and G.
Thomas Graves III (previously filed as
Exhibit 10.13 to Toreador Royalty
Corporation Annual Report on Form 10-K
for the year ended December 31, 1998,
and incorporated herein by reference).
10.8+ - Toreador Royalty Corporation Amended
and Restated 1990 Stock Option Plan
Nonqualified Stock Option Agreement,
dated September 24, 1998, between
Toreador Royalty Corporation and John
Mark McLaughlin (previously filed as
Exhibit 10.14 to Toreador Royalty
Corporation Annual Report on Form 10-K
for the year ended December 31, 1998,
and incorporated herein by reference).
10.9* - Loan Agreement, effective February 16,
2001, between Toreador Resources
Corporation, Toreador Exploration &
Production Inc., Toreador Acquisition
Corporation and Tormin, Inc. and Bank
of Texas, National Association.
10.10 - Purchase and Sale Agreement, effective
November 24, 1999, between Lario Oil &
Gas Company and Toreador Exploration &
Production Inc. (previously filed as
Exhibit 10.1 to Toreador Royalty
Corporation Current Report on Form 8-K
filed on January 6, 2000, and
incorporated herein by reference).
10.11 - Merger Agreement, effective September
11, 2000, between Texona Petroleum
Corporation, Toreador Resources
Corporation and Toreador Acquisition
Corporation (previously filed as
Exhibit 10.1 to Toreador Resources
Corporation Current Report on Form 8-K
filed on October 2, 2000, and
incorporated herein by reference).
10.12* - First Amendment to Merger Agreement,
effective January 30, 2001, between
Texona Petroleum Corporation, Toreador
Resources Corporation and Toreador
Acquisition Corporation.
32
35
16.1 - Letter on Change in Certifying
Accountant from PricewaterhouseCoopers
LLP, dated June 30, 1999 (previously
filed as Exhibit 16 to Amendment No. 2
to Toreador Royalty Corporation Current
Report on Form 8-K/A filed on June 30,
1999, and incorporated herein by
reference).
21.1* - Subsidiaries of Toreador Resources
Corporation.
23.1* - Consent of Ernst & Young LLP.
23.2* - Consent of LaRoche Petroleum
Consultants, Ltd.
23.3* - Consent of Harlan Consulting.
- ----------
* Filed herewith.
+ Management contract or compensatory plan
(b) Reports on Form 8-K:
During the last quarter of the fiscal year ended
December 31, 2000, we filed a Current Report on Form 8-K dated October
2, 2000 with the Securities and Exchange Commission to report the
merger with Texona Petroleum Corporation under items 2 and 7.
33
36
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.
TOREADOR RESOURCES CORPORATION
Date: March 23, 2001
By: /s/ G. THOMAS GRAVES, III
--------------------------------------
G. Thomas Graves III, President and
Chief Executive Officer
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 and on the dates as indicated therein.
SIGNATURE CAPACITY IN WHICH SIGNED DATE
- ------------------------------------ ----------------------------------------------- --------------
/s/ G. THOMAS GRAVES, III President, Chief Executive Officer and Director March 23, 2001
- -----------------------------------
G. Thomas Graves III
/s/ J. W. BULLION Director March 23, 2001
- -----------------------------------
J. W. Bullion
/s/ EDWARD NATHAN DANE Director March 23, 2001
- -----------------------------------
Edward Nathan Dane
/s/ PETER L. FALB Director March 23, 2001
- -----------------------------------
Peter L. Falb
/s/ THOMAS P. KELLOGG, JR. Director March 23, 2001
- -----------------------------------
Thomas P. Kellogg, Jr.
/s/ WILLIAM I. LEE Director March 23, 2001
- -----------------------------------
William I. Lee
/s/ JOHN MARK MCLAUGHLIN Chairman and Director March 23, 2001
- -----------------------------------
John Mark McLaughlin
/s/ DOUGLAS W. WEIR Chief Financial Officer March 23, 2001
- ----------------------------------- (Principal Financial and Accounting Officer)
Douglas W. Weir
34
37
TOREADOR RESOURCES CORPORATION
ITEM 8
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES
Page
----
Report of Independent Auditors.................................................................................... F-2
Financial Statements:
Consolidated Balance Sheets as of December 31, 2000 and 1999................................................. F-3
Consolidated Statements of Operations for the three years ended December 31, 2000............................ F-4
Consolidated Statements of Changes in Stockholders' Equity for the three years ended December 31, 2000....... F-5
Consolidated Statements of Cash Flows for the three years ended December 31, 2000............................ F-6
Notes to Consolidated Financial Statements................................................................... F-7
F-1
38
TOREADOR RESOURCES CORPORATION
REPORT OF INDEPENDENT AUDITORS
The Board of Directors and Stockholders
Toreador Resources Corporation
We have audited the accompanying consolidated balance sheets of Toreador
Resources Corporation as of December 31, 2000 and 1999, and the related
consolidated statements of operations, stockholders' equity and cash flows for
each of the three years in the period ended December 31, 2000. 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 auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Toreador Resources
Corporation at December 31, 2000 and 1999, and the consolidated results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States.
Ernst & Young LLP
Dallas, Texas
March 9, 2001
F-2
39
TOREADOR RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31,
----------------------------
2000 1999
------------ ------------
ASSETS
Current assets:
Cash and cash equivalents $ 1,756,161 $ 341,463
Short-term investments -- 13,682
Accounts and notes receivable 2,678,020 1,112,502
Marketable securities 255,668 36,251
Other 103,057 73,995
------------ ------------
Total current assets 4,792,906 1,577,893
------------ ------------
Properties and equipment, less accumulated
depreciation, depletion and amortization 34,629,513 24,423,537
Equity in unconsolidated investments 715,974 114,241
Other assets 186,562 214,150
Deferred tax benefit -- 126,159
------------ ------------
Total assets $ 40,324,955 $ 26,455,980
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 1,348,620 $ 717,965
Federal income taxes payable 266,603 171,317
Current portion of long-term debt -- 250,000
------------ ------------
Total current liabilities 1,615,223 1,139,282
Long-term debt 15,244,223 14,666,500
Deferred tax liability 3,204,616 --
------------ ------------
Total liabilities 20,064,062 15,805,782
------------ ------------
Stockholders' equity:
Preferred stock, $1.00 par value, 4,000,000
shares authorized; 160,000 issued 160,000 160,000
Common stock, $0.15625 par value, 20,000,000
shares authorized; 6,786,571 and 5,651,571 shares issued 1,060,402 883,058
Capital in excess of par value 14,905,621 8,234,380
Retained earnings 5,618,676 2,677,382
Accumulated other comprehensive income (loss) 53,988 (35,530)
------------ ------------
21,798,687 11,919,290
Treasury stock at cost:
527,000 and 475,500 shares (1,537,794) (1,269,092)
------------ ------------
Total stockholders' equity 20,260,893 10,650,198
------------ ------------
Total liabilities and stockholders' equity $ 40,324,955 $ 26,455,980
============ ============
The Company uses the successful efforts method of accounting for its
oil and gas producing activities.
See accompanying notes to the consolidated financial statements.
F-3
40
TOREADOR RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
YEAR ENDED DECEMBER 31,
------------------------------------------------
2000 1999 1998
------------ ------------ ------------
Revenues:
Oil and gas sales $ 13,163,862 4,259,040 $ 1,968,638
Lease bonuses and rentals 472,845 463,083 168,664
Interest and other income 70,702 109,035 171,338
Equity in earnings of unconsolidated investments (53,977) -- --
Gain on sale of properties and other assets 407,679 851,726 --
Loss on sale of marketable securities (54,076) (79,615) --
------------ ------------ ------------
Total revenues 14,007,035 5,603,269 2,308,640
------------ ------------ ------------
Costs and expenses:
Lease operating 2,324,603 699,278 583,441
Dry holes and abandonments 50,642 9,933 133,113
Depreciation, depletion and amortization 2,439,368 1,276,268 514,071
Geological and geophysical 258,345 394,496 517,870
General and administrative 2,219,684 1,583,729 999,548
Other 188,940 -- --
Interest 1,408,807 794,627 36,120
------------ ------------ ------------
Total costs and expenses 8,890,389 4,758,331 2,784,163
------------ ------------ ------------
Income (loss) before income taxes 5,116,646 844,938 (475,523)
Provision (benefit) for income taxes 1,763,577 336,927 (233,277)
------------ ------------ ------------
Net income (loss) 3,353,069 508,011 (242,246)
Dividends on preferred shares 360,000 360,000 19,500
------------ ------------ ------------
Income (loss) applicable to common shares $ 2,993,069 $ 148,011 $ (261,746)
============ ============ ============
Basic income (loss) per share $ 0.54 $ 0.03 $ (0.05)
============ ============ ============
Diluted income (loss) per share $ 0.50 $ 0.03 $ (0.05)
============ ============ ============
Weighted average shares outstanding
Basic 5,522,321 5,185,588 5,125,063
Diluted 6,691,361 5,250,862 5,125,063
See accompanying notes to the consolidated financial statements.
F-4
41
TOREADOR RESOURCES CORPORATION
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
ACCUMULATED
CAPITAL IN OTHER
PREFERRED COMMON EXCESS OF RETAINED COMPREHENSIVE
STOCK STOCK PAR VALUE EARNINGS INCOME (LOSS)
------------ ------------ ------------ ------------ -------------
Balance at December 31, 1997 ......... $ -- $ 838,683 $ 3,646,834 $ 2,791,117 $ --
Issuance of common stock ............. -- 43,203 766,809 -- --
Issuance of preferred stock .......... 160,000 -- 3,789,219 -- --
Dividends declared on preferred
stock .............................. -- -- -- (19,500) --
Purchase of treasury stock ........... -- -- -- -- --
Comprehensive income
Net loss ............................. -- -- -- (242,246) --
Other comprehensive loss, net of
tax.................................
Unrealized loss on securities ........ -- -- -- -- (24,922)
Total comprehensive loss .............
------------ ------------ ------------ ------------ -------------
Balance at December 31, 1998 ......... 160,000 881,886 8,202,862 2,529,371 (24,922)
Issuance of common stock ............. -- 1,172 31,518 -- --
Dividends paid on preferred stock .... -- -- -- (360,000) --
Purchase of treasury stock ........... -- -- -- -- --
Comprehensive income
Net income ........................... -- -- -- 508,011 --
Other comprehensive loss, net of
tax.................................
Unrealized loss on securities ...... -- -- -- -- (10,608)
Less reclassification adjustment
for losses included in net income ..
Total comprehensive income ...........
------------ ------------ ------------ ------------ -------------
Balance at December 31, 1999 ......... 160,000 883,058 8,234,380 2,677,382 (35,530)
Issuance of common stock ............. -- 177,344 6,241,406 -- --
Issuance of stock options ............ -- 429,835 -- --
Dividends paid on preferred stock .... -- -- -- (360,000) --
Dividends paid on common stock ....... -- -- -- (51,775) --
Purchase of treasury stock ........... -- -- -- -- --
Comprehensive income
Net income ........................... -- -- -- 3,353,069 --
Other comprehensive loss, net of
tax.................................
Unrealized gain on securities ...... -- -- -- -- 89,518
Less reclassification adjustment
for losses included in net income ..
Total comprehensive income ...........
------------ ------------ ------------ ------------ -------------
Balance at December 31, 1999 ......... $ 160,000 $ 1,060,402 $ 14,905,621 $ 5,618,676 $ 53,988
============ ============ ============ ============ =============
TOTAL
TREASURY STOCKHOLDERS'
STOCK EQUITY
------------ -------------
Balance at December 31, 1997 ......... $ (1,059,439) $ 6,217,195
Issuance of common stock ............. -- 810,012
Issuance of preferred stock .......... -- 3,949,219
Dividends declared on preferred
stock .............................. -- (19,500)
Purchase of treasury stock ........... (95,250) (95,250)
Comprehensive income
Net loss ............................. -- (242,246)
Other comprehensive loss, net of
tax.................................
Unrealized loss on securities ........ -- (24,922)
-------------
Total comprehensive loss ............. (267,168)
------------ -------------
Balance at December 31, 1998 ......... (1,154,689) 10,594,508
Issuance of common stock ............. -- 32,690
Dividends paid on preferred stock .... -- (360,000)
Purchase of treasury stock ........... (114,403) (114,403)
Comprehensive income
Net income ........................... -- 508,011
Other comprehensive loss, net of
tax.................................
Unrealized loss on securities ...... -- (63,154)
Less reclassification adjustment
for losses included in net income .. 52,546
-------------
Total comprehensive income ........... 497,403
------------ -------------
Balance at December 31, 1999 ......... (1,269,092) 10,650,198
Issuance of common stock ............. -- 6,418,750
Issuance of stock options ............ -- 429,835
Dividends paid on preferred stock .... -- (360,000)
Dividends paid on common stock ....... -- (51,775)
Purchase of treasury stock ........... (268,702) (268,702)
Comprehensive income
Net income ........................... -- 3,353,069
Other comprehensive loss, net of
tax.................................
Unrealized gain on securities ...... -- 53,988
Less reclassification adjustment
for losses included in net income .. 35,530
-------------
Total comprehensive income ........... 3,442,587
------------ -------------
Balance at December 31, 2000 ......... $ (1,537,794) $ 20,260,893
============ =============
F-5
42
TOREADOR RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2000
------------------------------------------------
2000 1999 1998
------------ ------------ ------------
Cash flows from operating activities:
Net income (loss) $ 3,353,069 $ 508,011 $ (242,246)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, depletion and amortization 2,439,368 1,276,268 514,071
Dry holes and abandonments 50,642 9,933 133,113
Loss on sale of marketable securities 54,076 79,615 --
Gain on sale of properties (407,679) (851,726) --
Equity in earnings of unconsolidated investments 53,977 -- --
Changes in operating assets and liabilities:
Increase in accounts and notes receivable (1,053,486) (595,060) (182,591)
Decrease (increase) in federal income tax receivable -- 63,064 (757)
Increase in other current assets (24,134) (12,865) (34,174)
Increase in accounts payable and accrued liabilities 619,245 149,711 258,664
Increase in federal income taxes payable 95,286 171,317 --
Decrease (increase) in other assets 72,589 (112,500) --
Deferred tax expense (benefit) 793,193 77,546 (169,456)
------------ ------------ ------------
Net cash provided by operating activities 6,046,146 763,314 276,624
------------ ------------ ------------
Cash flows from investing activities:
Expenditures for oil and gas property and equipment (2,300,855) (486,275) (797,438)
Acquisition of oil and gas properties (129,069) (8,722,073) (13,154,543)
Proceeds from lease bonuses and rentals 42,877 27,407 --
Sale (purchase) of short-term investments 13,682 1,204,609 (1,218,291)
Purchase of marketable securities (173,868) (35,241) (412,676)
Proceeds from sale of marketable securities 36,009 278,217 --
Proceeds from sale of properties and other assets 901,039 1,024,676 --
Purchase of equity in unconsolidated investments (155,710) (114,241) --
Purchase of furniture and fixtures (52,215) (157,627) (29,249)
------------ ------------ ------------
Net cash used by investing activities (1,818,110) (6,980,548) (15,612,197)
------------ ------------ ------------
Cash flows from financing activities:
Payment for debt issue costs (45,001) (22,777) (78,873)
Proceeds from long-term debt 2,494,223 7,176,500 8,600,000
Payment of principal on long-term debt (4,660,723) (860,000) --
Proceeds from issuance of stock 25,000 32,690 810,012
Proceeds from issuance of preferred stock, net -- -- 3,949,219
Payment of preferred and common dividends (411,775) (379,500) --
Purchase of treasury stock (268,702) (114,403) (95,250)
Other 53,640 -- --
------------ ------------ ------------
Net cash provided (used) by financing activities (2,813,338) 5,832,510 13,185,108
------------ ------------ ------------
Net increase (decrease) in cash and cash equivalents 1,414,698 (384,724) (2,150,465)
Cash and cash equivalents, beginning of period 341,463 726,187 2,876,652
------------ ------------ ------------
Cash and cash equivalents, end of period $ 1,756,161 $ 341,463 $ 726,187
============ ============ ============
Supplemental schedule of cash flow information:
Cash paid during the period for:
Income taxes $ 875,098 $ -- $ (63,064)
Interest 1,234,985 620,106 --
See accompanying notes to the consolidated financial statements.
F-6
43
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES
Toreador Resources Corporation ("Toreador" or the "Company") is an
independent oil and gas company engaged in domestic oil and gas
exploration, development, production and acquisition activities. The
Company owns in excess of 1,300,000 net mineral acres located primarily
in Mississippi, Texas and Alabama. In addition, the Company owns
working or royalty interests in Mississippi, Texas, Kansas, Alabama,
California, Michigan, New Mexico, Oklahoma, Louisiana and Arkansas. The
Company's business activities are conducted primarily with industry
partners located within the United States.
PERVASIVENESS OF ESTIMATES
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States 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.
CONSOLIDATION
The consolidated financial statements include the accounts of Toreador
and its wholly owned subsidiaries, Toreador Exploration & Production
Inc. ("Toreador E&P"), Tormin, Inc. ("Tormin") and Toreador Acquisition
Corporation ("TAC"). All inter-company accounts and transactions have
been eliminated.
RECLASSIFICATIONS
Certain prior year amounts have been reclassified to conform to current
year presentation.
CASH AND CASH EQUIVALENTS
Cash and cash equivalents include cash on hand, amounts due from banks
and all highly liquid investments with original maturities of three
months or less. The Company maintains its cash in bank deposit
accounts, which, at times, may exceed federally insured limits. The
Company has not experienced any losses in such accounts and believes it
is not exposed to any significant risk on cash.
MARKETABLE SECURITIES
When securities are purchased they are designated as trading securities
or available for sale. Trading investments are classified as current
assets and changes in fair value are reported in the statement of
operations. Investments in available for sale securities are classified
based upon management's intent to sell the security and changes in fair
value are reported net of tax as a separate component of accumulated
other comprehensive income (loss).
FINANCIAL INSTRUMENTS
The carrying amounts of financial instruments including cash and cash
equivalents, short-term investments, accounts receivable, marketable
securities, accounts payable and accrued liabilities and long-term debt
approximate fair value, unless otherwise stated, as of December 31,
2000 and 1999.
F-7
44
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DERIVATIVE FINANCIAL INSTRUMENTS
The Company has only limited involvement with derivative financial
instruments. They are used to manage well-defined commodity price
risks. The Company is exposed to credit losses in the event of
nonperformance by the counterparty to its financial instruments. The
Company anticipates, however, that such counterparty will be able to
fully satisfy its obligations under the contracts. The Company does not
obtain collateral or other security to support financial instruments
subject to credit risk but monitors the credit standing of the
counterparty. The Company accounts for its derivative financial
instruments on a mark to market basis.
The Company utilizes various option contracts to (i) reduce the effect
of the volatility of price changes on the commodities the Company
produces and sells, (ii) support the Company's annual capital budgeting
and expenditure plans and (iii) lock in price ranges to protect the
economics related to certain capital projects.
OIL AND GAS PROPERTIES
The Company follows the successful efforts method of accounting for oil
and gas exploration and development expenditures. Under this method,
costs of successful exploratory wells and all development wells are
capitalized. Costs to drill exploratory wells that do not find proved
reserves are expensed. Significant costs associated with the
acquisition of oil and gas properties are capitalized. Upon sale or
abandonment of units of property or the disposition of miscellaneous
equipment, the cost is removed from the asset account, the related
reserves relieved of the accumulated depreciation or depletion and the
gain or loss is credited to or charged against operations.
Maintenance and repairs are charged to expense; betterments of property
are capitalized and depreciated as described below.
LEASE BONUSES
The Company defers bonuses received from leasing minerals in which
unrecovered costs remain by recording the bonuses as a reduction of the
unrecovered costs. Bonuses received from leasing mineral interests
previously expensed are taken into income. For federal income tax
purposes, lease bonuses are regarded as advance royalties (ordinary
income). Bonuses totaling $42,877, $27,407 and zero were recorded as
cost reductions for the years ending December 31, 2000, 1999 and 1998,
respectively.
DEPRECIATION, DEPLETION AND AMORTIZATION
The Company provides for depreciation, depletion and amortization of
its investment in producing oil and gas properties on the
unit-of-production method, based upon independent reserve engineers'
estimates of recoverable oil and gas reserves from the property.
Depreciation expense for fixed assets is generally calculated on a
straight-line basis based upon estimated useful lives of five years.
F-8
45
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
IMPAIRMENT OF ASSETS
Producing property costs are evaluated for impairment and reduced to
fair value if the sum of expected undiscounted future cash flows is
less than net book value pursuant to Statement of Financial Accounting
Standard No. 121 (SFAS 121) "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of."
Impairment of non-producing leasehold costs and undeveloped mineral and
royalty interests are assessed periodically on a property-by-property
basis, and any impairment in value is currently charged to expense.
There was no impairment loss during 2000. There was an impairment loss
during 1999 in the amount of $14,401 primarily due to the decrease in
oil and gas reserves for the affected producing properties. There was
an impairment loss in 1998 of $19,649 resulting from the decrease in
oil and gas prices. The impairments are included in the "Depreciation,
depletion and amortization" category of the consolidated statement of
operations.
REVENUE RECOGNITION
Oil and gas revenues are accounted for using the sales method. Under
this method, sales are recorded on all production sold by the Company
regardless of the Company's ownership interest in the respective
property. Imbalances result when sales differ from the seller's net
revenue interest in the particular property's reserves and are tracked
to reflect the Company's balancing position. At December 31, 2000 and
1999, the imbalance and related value were immaterial.
STOCK-BASED COMPENSATION
Statement of Financial Accounting Standards No. 123, ("SFAS 123")
"Accounting for Stock-Based Compensation," encourages, but does not
require, the adoption of a fair value-based method of accounting for
employee stock-based compensation transactions. The Company has elected
to apply the provisions of Accounting Principles Board Opinion No. 25
("Opinion 25"), "Accounting for Stock Issued to Employees," and related
interpretations, in accounting for its employee stock-based
compensation plans. Under Opinion 25, compensation cost is measured as
the excess, if any, of the quoted market price of the Company's stock
at the date of the grant above the amount an employee must pay to
acquire the stock.
NET INCOME (LOSS) PER COMMON SHARE
Basic income (loss) per common share amounts were computed by dividing
net income (loss) after deduction of dividends on preferred shares by
the weighted average number of common shares outstanding during the
period. Diluted income (loss) per common share assumes the conversion
of all securities that are exercisable or convertible into common
shares that would dilute the basic earnings per common share during the
period. The increase in potential shares used to determine dilutive
income per share for the year ended December 31, 2000 is attributable
to convertible preferred stock and dilutive stock options. Convertible
preferred stock was not considered in the diluted income (loss) per
share calculations for 1999 and 1998, as the effect would be
antidilutive. Stock options were not considered in the diluted loss per
share calculation for 1998, as the effect would be antidilutive.
F-9
46
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NEW ACCOUNTING PRONOUNCEMENTS
The Company has not yet adopted Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities." This Statement will be adopted effective January 1, 2001.
It establishes accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other
contracts, and for hedging activities. This Statement does not allow
retroactive application to financial statements of prior periods. The
Company is accounting for its financial instruments on a mark to market
basis. For the year ended December 31, 2000, the Company recorded a
loss, included in other expense, and an offsetting accrued liability of
$135,300. Accordingly, the result of the adoption of FAS No. 133 will
have no impact on future income. The Company intends continue to
account for the results of financial instruments on a mark to market
basis.
2. MARKETABLE SECURITIES
Marketable securities at December 31, 2000 and 1999 consist of several
issues of preferred stock with a fair market value of $255,668 and
$36,251, respectively. The Company has designated these investments as
"securities available for sale" pursuant to Statement of Financial
Accounting Standards No. 115. The net unrealized gain related to these
securities before taxes is $81,800 ($53,988 net of tax) at December 31,
2000 and the net unrealized loss was $53,834 ($35,530 net of tax) at
December 31, 1999, and is reflected as other comprehensive income
(loss). During 2000, a portion of the available-for-sale securities was
sold for $36,009 resulting in a net loss before taxes of $54,076
($34,068 net of tax) based upon historical cost.
3. ACCOUNTS RECEIVABLE
Accounts receivable consist of the following:
DECEMBER 31,
--------------------------
2000 1999
----------- -----------
Oil and gas................................ $ 2,581,872 $ 1,073,035
Note receivable............................ 30,000 30,000
Other receivables.......................... 66,148 9,467
----------- -----------
$ 2,678,020 $ 1,112,502
=========== ===========
Oil and gas receivables are due from companies engaged principally in
oil and gas activities, with payment terms on a short-term basis and in
accordance with industry standards. The note receivable is the current
amount due from the purchaser of non-strategic assets during 1999.
F-10
47
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. PROPERTIES AND EQUIPMENT
Properties and equipment consist of the following:
DECEMBER 31,
-------------------------------
2000 1999
-------------- --------------
Undeveloped mineral and royalty interests................. $ 7,361,174 $ 7,404,891
Non-producing leaseholds.................................. 765,472 408,899
Producing leaseholds...................................... 19,030,833 9,129,775
Producing royalty interests............................... 10,458,935 10,581,301
Lease and well equipment.................................. 2,774,873 523,374
Furniture and fixtures and other assets................... 330,069 265,895
-------------- --------------
40,721,356 28,314,135
Accumulated depreciation, depletion and amortization...... (6,091,843) (3,890,598)
-------------- --------------
$ 34,629,513 $ 24,423,537
============== ==============
During 2000 the Company sold various properties and equipment for
$901,039 (net of closing costs) resulting in a gain of $407,679 before
tax.
5. ACQUISITION OF OIL AND GAS PROPERTIES
On September 19, 2000, TAC completed a merger with Texona Petroleum
Corporation ("Texona"), pursuant to a Merger Agreement dated as of
September 11, 2000. The terms of the Merger Agreement called for Texona
to be merged with TAC in a forward triangular merger, thus leaving TAC
as the surviving entity. The outstanding stock of Texona was exchanged
for a total of 1,115,000 common shares of Toreador, of which 1,025,000
was issued to the Texona shareholders during 2000 and the remaining
shares ("Deferred Shares") will be issued no later then June 1, 2001,
subject to Toreador shareholder approval. If the approval is not
obtained, Deferred Shares will not be issued and there will be no
financial penalty. The value of the Deferred Shares will be added to
the value of oil and gas properties acquired upon issuance. The
issuance of Toreador shares for the Texona shares is hereinafter
referred to as the "Merger".
In addition, the Company issued 143,040 of its stock options to certain
former employees and directors of Texona. The strike price of the
options is $3.12 per share, and they expire on September 19, 2010. On
the Merger closing date, the Company's stock was trading at $5.75 per
share, and accordingly, the fair value of the options was included in
the purchase price allocated to the assets acquired and liabilities
assumed.
Immediately prior to the Merger, Texona owned an interest in close to
1,000 wells located in 12 states, primarily Oklahoma, Texas and
Louisiana. The estimated proved reserves for Texona totaled 6,806 MMcf
and 449 MBbl for a total of 9,502 MMcfe (equivalent MMcf on six Mcf per
one barrel of oil basis).
Immediately after the Merger closing, TAC extinguished Texona's
outstanding bank debt of $2,449,223, utilizing its line from Compass
Bank, Dallas. In connection with the borrowing, Toreador, TAC, Toreador
E&P and Tormin entered into an amendment to their existing Credit
Agreement with Compass Bank, which Credit Agreement was effective
September 30,1999. The amendment to the Credit Agreement increased the
borrowing base to $17,000,000 from the previous borrowing base of
$14,500,000.
The Merger is being accounted for under the purchase method of
accounting for business combinations. Under the purchase method, the
combination is recorded at cost, which in this case is based upon the
fair market value of Toreador common stock, options issued and direct
costs incurred. Acquired assets are recorded at their fair market value
up to the purchase price. The Company's results of operations for the
year ended December 31, 2000 include the results of operations from
September 19, 200 through December 31, 2000.
F-11
48
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Texona Merger
Fair market value of common stock and options..... $ 6,269,945
Other acquisition costs, net of cash acquired..... 765,472
--------------
Total consideration.................... $ 6,399,014
==============
Allocated as follows:
Assets acquired
Accounts receivable............................. $ 512,032
Other current assets............................ 4,928
Producing leaseholds............................ 10,867,193
Other assets.................................... 11,960
Liabilities assumed
Accounts payable................................ 11,410
Long-term debt.................................. 2,494,223
Deferred tax liabilities........................ 2,494,466
--------------
Net assets acquired.................... $ 6,399,014
==============
The following summarized unaudited pro forma financial information
assumes the Merger occurred on January 1 of each year:
YEAR ENDED DECEMBER 31,
---------------------------
2000 1999
------------ -----------
Revenues........................................ $ 16,323,259 $ 8,274,627
Net income (loss)............................... $ 3,854,326 $ 764,149
Net income (loss) applicable to common shares... $ 3,494,326 $ 404,149
Net income (loss) per share - basic............. $ .63 $ .08
Net income (loss) per share - diluted........... $ .52 $ .08
The pro forma results do not necessarily represent results that would
have occurred if the transactions had taken place on the basis assumed
above, nor are they indicative of the results of future combined
operations.
6. EQUITY IN UNCONSOLIDATED INVESTMENTS
On July 11, 2000, the Company acquired a 35.0% interest in
EnergyNet.com, Inc. ("EnergyNet"), an Internet based oil and gas
property auction company. The terms of the acquisition called for the
Company to issue 100,000 shares of common stock plus a $100,000
payment. The 100,000 shares were issued in August 2000.
The Company accounts for its 35% investment in EnergyNet and its 50%
investment in Capstone Royalty, LLP using the equity method of
accounting for investments. Equity in the pre-tax earnings of
unconsolidated investments included in the 2000 consolidated statements
of operations was $(53,977).
F-12
49
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. DERIVATIVE FINANCIAL INSTRUMENTS
During 2000 the Company sold call options to its counterparty for an
average volume of 35,000 MMBtu per month for at an average index price
of $7.27 per MMBtu. The Company purchased put options from its
counterparty for an average volume of 60,000 MMBtu per month at an
average index price of $4.01 per MMBtu. The periods covered by the
options began in March 2001 and end in October 2001.
The fair values of commodity price hedges outstanding at December 31,
2000 were obtained from quotes provided by the counterparty for each
agreement and represent the amount the Company would be able to receive
or be required to pay to liquidate the hedges as of December 31,2000.
The Company accounted for its derivative financial instruments on a
mark to market basis. Accordingly, for the year ended December 31,
2000, the Company recorded a loss, included in other expense, and an
offsetting accrued liability of $135,300.
8. LONG-TERM DEBT
On February 16, 2001, the Company entered into a $75 million credit
agreement (the "Facility") with Bank of Texas, National Association
that matures on February 16, 2006. The Facility replaced the Company's
prior revolving credit facility with Compass Bank that had a maturity
date of October 1, 2002 (the "Prior Credit Facility"). Outstanding
borrowings under the Prior Credit Facility totaled $15.2 million as of
December 31, 2000. The interest rate on the Prior Credit Facility at
December 31, 2000 was 9.25%. The majority of the Company's oil and gas
properties are pledged as collateral under the Facility.
The Facility bears interest, at the option of the Company, based on (a)
a base rate equal to the higher of (i) the rate of interest per annum
then most recently published by The Wall Street Journal as the prime
rate on corporate loans for large U.S. commercial banks (9.50% at
December 31, 2000) less 1.25%, or (ii) the sum of the rate of interest,
then most recently published by The Wall Street Journal as the "federal
funds" rate for reserves traded among commercial banks for overnight
use, less three quarters of one percent (0.75%), both as published in
the Money Rates section of The Wall Street Journal, or (b) the sum of
the LIBOR Rate (6.40% at December 31, 2000) plus 1.75%. Additionally,
the Facility calls for a commitment fee of 0.375% on the unused
portion.
The Facility imposes certain restrictive covenants on the Company,
including the maintenance of a Debt Service Coverage Ratio greater than
or equal to 1.25 to 1.00; maintenance of a Current Ratio greater than
or equal to 1.00 to 1.00; and, maintenance of a Tangible Net Worth of
not less than the sum of (i) $13.65 million, plus (ii) 50% of the
Company's annual net income, plus (iii) 100% of all equity
contributions. Although the Facility was not in place as of December
31, 2000, the Company was in compliance with all covenants.
9. CAPITAL
In connection with the private placement in 1994, the Company's
placement agent received a five-year warrant to purchase 106,867 shares
of common stock at a price of $4.375 per share and the right to
participate in registered offerings of common stock by the Company. The
Company paid $25,000 to the placement agent in December 1998 in order
to terminate the warrant and the related rights.
On March 23, 1999, the Company's board of directors reinstated an
existing common stock repurchase program enabling the Company to
purchase the remaining 117,300 shares available under the previously
authorized April 1997 stock repurchase plan from time to time and
depending on market conditions. On October 18, 2000 the Company's board
authorized the repurchase of up to 500,000 additional shares. As of
December 31, 2000, the Company had repurchased 527,000 shares under all
plans, leaving 528,700 shares remaining available for repurchase.
Management anticipates that any future repurchases of the Company's
common stock will be funded from the Company's cash flow from
operations and working capital.
F-13
50
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In December 1998, the Company sold 160,000 shares of Series A Preferred
Stock (convertible into 1,000,000 common shares) for net proceeds of
$3,949,219. The sale was made through a private placement. At the
option of the holder, the preferred stock may be converted into common
shares at a price of $4 per common share. The Company, at its option,
may redeem the preferred stock at its stated value of $25 per share on
or after December 1, 2004. The preferred stock accrues dividends at an
annual rate of $2.25 per share payable quarterly in cash. The proceeds
from the sale were used in part to finance the Southeastern States
Acquisition in December 1998.
In August 2000, the Company issued 100,000 shares of common stock as
part of the equity investment in EnergyNet. In September 2000, the
Company issued 1,025,000 shares of common stock as part of the Merger
with Texona.
10. EARNINGS PER SHARE
In accordance with the provisions of SFAS No. 128, "Earnings per
Share," basic earnings per share is computed on the basis of the
weighted-average number of common shares outstanding during the
periods. Diluted earnings per share is computed based upon the
weighted-average number of common shares plus the assumed issuance of
common shares for all potentially dilutive securities.
The computation of earnings per share for the years ended December 31,
2000, 1999 and 1998 is as follows:
YEAR ENDED DECEMBER 31,
----------------------------------------------
2000 1999 1998
------------ ------------ ------------
BASIC EPS
Income (loss) attributable to common shares ........ $ 2,993,069 $ 148,011 $ (261,746)
Average common shares outstanding applicable
to basic EPS ....................................... 5,522,321 5,185,588 5,125,063
Basic income (loss) per share ...................... $ 0.54 $ 0.03 $ (0.05)
------------ ------------ ------------
DILUTED EPS
Income (loss) attributable to common shares ........ $ 2,993,069 $ 148,011 $ (261,746)
Add: preferred dividends ........................... 360,000 -- --
------------ ------------ ------------
Income (loss) attributable to diluted shares ...... $ 3,353,069 $ 148,011 $ (261,746)
Average common shares outstanding applicable
to basic EPS ....................................... 5,522,321 5,185,588 5,125,063
Add: stock options ................................. 169,040 65,274 --
convertible preferred stock ............... 1,000,000 -- --
------------ ------------ ------------
Average common shares outstanding applicable
to diluted EPS ..................................... 6,691,361 5,250,862 5,125,063
Diluted income (loss) per share .................... $ 0.50 $ 0.03 $ (0.05)
------------ ------------ ------------
Convertible preferred stock was not included in the computation of
diluted earnings per share for the years ended December 31, 1999 and
1998 because their effect was antidilutive.
F-14
51
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. INCOME TAXES
The Company's provision (benefit) for income taxes was comprised of the
following:
YEAR ENDED DECEMBER 31,
----------------------------------------
2000 1999 1998
---------- ---------- ----------
Federal:
Current ........................... $ 874,481 $ 234,381 $ (63,821)
Deferred .......................... 728,880 77,546 (169,456)
State:
Current ........................... 95,903 25,000 --
Deferred .......................... 64,313 -- --
---------- ---------- ----------
Provision (benefit) for income taxes ... $1,763,577 $ 336,927 $ (233,277)
========== ========== ==========
The primary reasons for the difference between tax expense at the
statutory federal income tax rate and the Company's provision for
income taxes were:
YEAR ENDED DECEMBER 31,
------------------------------------------------
2000 1999 1998
------------ ------------ ------------
Statutory tax at 34% .......................... $ 1,739,660 $ 287,279 $ (161,678)
Statutory depletion in excess of tax basis .... (148,525) (4,838) (69,979)
State income tax .............................. 160,216 25,000 --
Other ......................................... 12,226 29,486 (1,620)
------------ ------------ ------------
Provision (benefit) for income taxes .......... $ 1,763,577 $ 336,927 $ (233,277)
============ ============ ============
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities as of
December 31, 2000 and 1999 were as follows:
2000 1999
------------ ------------
Deferred tax liabilities:
Leasehold costs .............................. $ (2,828,790) $ (54,298)
Intangible drilling and development costs .... (585,402) (194,184)
Lease and well equipment ..................... (94,759) (21,565)
Unrealized gain on marketable securities ..... (30,266) --
------------ ------------
Gross deferred tax liabilities ........... (3,539,217) (270,047)
------------ ------------
Deferred tax assets:
Depletion carryforwards ...................... -- 2,585
Geological and geophysical costs ............. 177,274 162,900
Net operating loss carryforward .............. 68,092 --
Tax credit carryforwards ..................... -- 212,417
Equity basis investments ..................... 19,327 --
Other ........................................ 69,908 --
Unrealized loss on marketable securities ..... -- 18,304
------------ ------------
Gross deferred tax assets ........... 334,601 396,206
------------ ------------
Net deferred tax (liabilities) assets ............. $ (3,204,616) $ 126,159
============ ============
The acquisition of Texona assets resulted in a $2,491,466 deferred tax
liability due to the difference between the book basis and the tax
basis of the assets acquired. Of the change in deferred taxes, $46,116
was charged to net unrealized gain on marketable securities in
stockholders' equity for 2000. The net operating loss carryforward
relates to the Texona acquisition and will be available to offset
future taxable income and income tax through 2018 and 2019.
F-15
52
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
12. BENEFIT PLANS
The Company had a noncontributory defined benefit pension plan that was
cancelled effective January 1, 2000. The benefits were based on years
of service and the employee's compensation. A full distribution was
made to each eligible employee during 2000. This plan was replaced with
a 401(k) plan.
13. STOCK COMPENSATION PLANS
The Company has granted stock options to key employees, directors and
certain consultants of the Company as described below.
In May 1990, the Company adopted the 1990 Stock Option Plan ("the
Plan"). The aggregate number of shares of common stock issuable under
the Plan as amended is 500,000. The Plan provides for the granting of
stock options at exercise prices equal to the market price of the stock
at the date of the grant.
In September 1994, the Company adopted the 1994 Nonemployee Director
Stock Option Plan ("Nonemployee Director Plan"). The number of shares
of common stock issuable under the Nonemployee Director Plan is 200,000
shares in the aggregate. The Nonemployee Director Plan provides for the
granting of stock options at exercise prices equal to the market price
of the stock at the grant date.
Options under the Plan and the Nonemployee Director Plan are granted
periodically throughout the year and are generally exercisable in equal
increments over a three-year period and have a maximum term of 10
years. From time to time the Company has issued stock options that did
not fall under any existing plan.
Pursuant to SFAS No. 123, the Company recorded an expense of zero,
$13,939 and $19,747 during 2000, 1999 and 1998, respectively, for stock
options granted to certain consultants to the Company.
A summary of stock option transactions is as follows:
2000 1999 1998
-------------------------- -------------------------- --------------------------
WEIGHTED- WEIGHTED- WEIGHTED-
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
---------- ---------- ---------- ---------- ---------- ----------
Outstanding at beginning of year 745,000 $ 4.24 462,500 $ 4.05 469,000 $ 2.97
Granted 277,540 4.27 290,000 4.50 340,000 4.38
Exercised (10,000) 2.50 (7,500) 2.50 (276,500) 2.86
Forfeited -- -- -- -- (70,000) 3.11
---------- ---------- ---------- ---------- ---------- ----------
Outstanding at end of year 1,012,540 $ 4.27 745,000 $ 4.24 462,500 $ 4.05
========== ========== ========== ========== ========== ==========
Exercisable at end of year 571,341 $ 3.88 216,658 $ 3.85 100,833 $ 3.28
========== ========== ========== ========== ========== ==========
F-16
53
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For stock options granted during 2000 the following represents the
weighted-average exercise prices and the weighted-average fair value
based upon whether or not the exercise price of the option was greater
than, less than or equal to the market price of the stock on the grant
date:
WEIGHTED-AVERAGE WEIGHTED-AVERAGE
OPTION TYPE EXERCISE PRICE FAIR VALUE
--------------------------------------------- ---------------- -----------------
Exercise price greater than market price.... $ 5.50 $ 3.13
Exercise price less than market price....... 3.12 3.59
The following table summarizes information about the fixed price stock
options outstanding at December 31, 2000:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
-------------------------------------------------------- ----------------------------------------
WEIGHTED WEIGHTED WEIGHTED
RANGE OF NUMBER AVERAGE AVERAGE NUMBER AVERAGE
EXERCISE OUTSTANDING AT REMAINING EXERCISE EXERCISABLE EXERCISE
PRICES 12/31/00 CONTRACTUAL LIFE PRICE AT 12/31/00 PRICE
----------- -------------- ---------------- ---------- ----------- ----------
$ 2.50 55,000 5.1 Years $ 2.50 44,998 $ 2.50
2.75 60,000 7.8 Years 2.75 39,996 2.75
3.00 30,000 8.5 Years 3.00 10,002 3.63
3.12 143,040 9.8 Years 3.12 143,040 3.12
3.25 - 3.50 50,000 3.7 Years 3.40 50,000 3.40
3.63 30,000 .4 Years 3.63 30,000 3.63
3.88 30,000 8.8 Years 3.88 10,002 3.63
4.00 50,000 8.8 Years 4.00 16,665 3.63
5.00 430,000 8.2 Years 5.00 226,644 5.00
5.50 134,500 9.7 Years 5.50 -- --
----------- ----------- ------------ ---------- ----------- ----------
$ 2.50-5.50 1,012,540 8.0 Years $ 3.88 571,347 $ 3.88
=========== =========== ============ ========== =========== ==========
At December 31, 2000, there were 292,460 shares available for grant
under existing plans.
Had compensation costs for employees under the Company's two
stock-based compensation plans been determined based on the fair value
at the grant dates under those plans consistent with the method
prescribed by SFAS No. 123, the Company's pro forma net income and
earnings per share would have been reduced to the pro forma amounts
listed below:
2000 1999 1998
------------- ------------- ------------
Net income (loss) As reported $ 2,993,069 $ 148,011 $ (261,746)
Pro forma $ 2,433,540 $ 101,973 $ (291,577)
Basic income (loss) per share As reported $ 0.54 $ 0.03 $ (0.05)
Pro forma $ 0.44 $ 0.02 $ (0.05)
Diluted income (loss) per share As reported $ 0.50 $ 0.03 $ (0.05)
Pro forma $ 0.42 $ 0.02 $ (0.05)
The fair value of each option granted is estimated on the date of grant
using the Black-Scholes option-pricing model with the following
assumptions:
F-17
54
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2000 1999 1998
---------- ---------- ----------
Dividend yield, per share -- -- --
Volatility 59% 59% 27%
Risk-free interest rate 5.9 - 6.6% 6.4% 6.4%
Expected lives 3-5 years 5 years 5 years
14. LEASE AND OTHER COMMITMENTS
The Company leases office space under a non-cancelable operating lease,
which expires on August 31, 2005. The Company subleases portions of the
leased space to one related party and one unrelated party under
non-cancelable sub-leases that expire on August 31, 2002. Minimum
annual rentals, net of sub-lease receipts, as of December 31, 2000 are
as follows:
2001 $ 115,069
2002 133,100
2003 170,608
2004 173,500
2005 115,667
-----------
Total 707,944
===========
Net rent expense totaled $85,983, $95,541 and $43,676 for the years
ended December 31, 2000, 1999 and 1998, respectively.
15. RELATED PARTY TRANSACTIONS
A director of the Company also owns Wilco Properties, Inc. The Company
entered into a technical services agreement with Wilco Properties, Inc.
("Wilco") effective February 1, 1999 whereby the Company provides
accounting and geological management services for a monthly fee of
$7,250. The Company has recorded to general and administrative expense
$87,000 and $79,750 related to this agreement for the years ended
December 31, 2000 and 1999, respectively. At December 31, 2000, $21,750
was receivable from Wilco under this agreement. The Company also
subleases office space to Wilco pursuant to a sub-lease agreement. The
Company has recorded reductions to rent expense totaling $15,080 and
$7,248 related to the sub-lease agreement discussed in Note 13 during
the years ended December 31, 2000 and 1999, respectively. Wilco and the
Company have an informal arrangement under which one of the two
companies incur, on behalf of the other, certain miscellaneous expenses
that are subsequently reimbursed by the other company. Transactions
under this arrangement resulted in net receipts from Wilco of $16,929
for the year ended December 31, 2000, and net payments to Wilco of
$118,938 for the year ended December 31, 1999. There were no amounts
due to or from Wilco as of December 31, 2000 or 1999 under this
arrangement.
The Company owns an equity investment in EnergyNet.com, Inc., an
Internet based oil and gas property auction company. The Company paid
commissions totaling approximately $25,000 to EnergyNet.com, Inc.
during 2000.
The Company entered into a consulting agreement with Earl Rossman, Jr.
effective October 1, 2000, whereby Mr. Rossman provides consulting
services for the Company for a monthly fee of $13,000. Mr. Rossman was
President of Texona Petroleum Corporation immediately prior to the
execution of the Merger Agreement. The consulting agreement expires on
September 30, 2001. The Company paid fees totaling $39,000 during 2000.
F-18
55
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
16. OIL AND GAS PRODUCING ACTIVITIES
The following information is presented pursuant to SFAS No. 69,
Disclosures about Oil and Gas Producing Activities:
RESULTS OF OPERATIONS
Results of operations from oil and gas producing activities were as
follows:
2000 1999 1998
------------- ------------- -------------
Crude oil, condensate and gas................. $ 13,163,862 $ 4,259,040 $ 1,968,638
Lease bonuses and delay rentals............... 472,845 463,083 168,664
------------- ------------- -------------
Total revenues........................... 13,636,707 4,722,123 2,137,302
Costs and expenses:
Lease operating costs.................... 2,324,603 699,278 583,441
Exploration costs........................ 308,987 404,429 650,983
Depreciation and depletion............... 2,389,109 1,247,278 510,775
------------- ------------- -------------
Income before income taxes.................... 8,614,008 2,371,138 392,103
Income tax expense............................ 3,187,183 806,187 133,315
------------- ------------- -------------
Results of operations from producing
activities (excluding corporate overhead)..... $ 5,426,825 $ 1,564,951 $ 258,788
============= ============= =============
CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES:
DECEMBER 31,
-----------------------------------------------------
2000 1999 1998
------------- ------------- -------------
Unproved properties (a)......................... $ 8,126,646 $ 7,813,790 $ 7,727,388
Proved leaseholds............................... 29,489,768 19,711,076 10,913,730
Lease and well equipment........................ 2,774,873 523,374 417,382
------------- ------------- -------------
40,391,287 28,048,240 19,058,500
Less: Accumulated depreciation, depletion
and amortization................... (5,937,634) (3,786,649) (2,608,905)
------------- ------------- -------------
Capitalized costs............................... $ 34,453,653 $ 24,261,591 $ 16,449,595
============= ============= =============
(a) Unproved properties for 1998 include $334,489 classified as "Assets
held for sale".
COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION,
EXPLORATION AND DEVELOPMENT ACTIVITIES:
2000 1999 1998
------------- ------------- -------------
Acquisition of properties
Proved..................................... $ 6,399,014 $ 8,722,073 $ 5,883,911
Unproved................................... -- 286,631 7,365,988
Exploration costs............................... 930,859 28,200 133,113
Development costs............................... 1,369,996 171,444 568,969
------------- ------------- -------------
Costs incurred.................................. $ 8,699,869 $ 9,208,348 $ 13,951,981
============= ============= =============
F-19
56
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
17. SUPPLEMENTAL OIL AND GAS RESERVES AND STANDARDIZED MEASURE INFORMATION
(UNAUDITED)
The following table identifies the Company's net interest in estimated
quantities of proved oil and gas reserves and changes in such estimated
quantities. Independent petroleum engineers prepared reserve estimates
and Company management reviewed such estimates. The Company emphasizes
that reserve estimates are inherently imprecise and that estimates of
new discoveries are more imprecise than those of producing oil and gas
properties. Accordingly, the estimates are expected to change as future
information becomes available. Estimated proved developed and
undeveloped oil and gas reserves at December 31, 2000, 1999 and 1998
are tabulated below. Crude oil includes condensate and natural gas
liquids and is stated in barrels (Bbl). Gas is stated in thousands of
cubic feet (Mcf).
OIL (BBL) GAS (MCF)
----------- -----------
PROVED DEVELOPED AND UNDEVELOPED RESERVES
December 31, 1997 ................................ 553,178 2,564,540
Purchases of reserves in place ................... 457,953 6,714,493
Revisions of previous estimates .................. 180,310 813,717
Extensions, discoveries, and other additions ..... 12,161 92,539
Production ....................................... (90,097) (394,849)
----------- -----------
December 31, 1998 ................................ 1,113,505 9,790,440
Purchases of reserves in place ................... 1,282,123 1,602,953
Revisions of previous estimates .................. (121,532) (2,640,742)
Extensions, discoveries, and other additions ..... 51,494 377,177
Production ....................................... (128,924) (918,986)
----------- -----------
December 31, 1999 ................................ 2,196,666 8,210,842
Purchases of reserves in place ................... 453,646 6,922,040
Revisions of previous estimates .................. 60,634 (1,204,842)
Extensions, discoveries, and other additions ..... 102,121 1,074,597
Sale of reserves ................................. (16,493) --
Production ....................................... (273,706) (1,318,714)
----------- -----------
December 31, 2000 ................................ 2,522,868 13,683,923
=========== ===========
PROVED DEVELOPED RESERVES
December 31, 1998 ................................ 1,094,454 8,500,655
=========== ===========
December 31, 1999 ................................ 1,999,984 8,070,533
=========== ===========
December 31, 2000 ................................ 2,445,226 13,666,276
=========== ===========
F-20
57
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO
PROVED OIL AND GAS RESERVES
Pursuant to SFAS No. 69, the Company has developed the following
information titled "Standardized Measure of Discounted Future Net Cash
Flows Relating to Proved Oil and Gas Quantities" (Standardized
Measure). Accordingly, the Standardized Measure has been prepared
assuming year-end selling prices adjusted for future fixed and
determinable contractual price changes, year-end development and
production costs, year-end statutory tax rates adjusted for future tax
rates already legislated and a 10% annual discount rate. The
Standardized Measure does not purport to be an estimate of the fair
market value of the Company's reserves. An estimate of fair value would
also have taken into account, among other things, the expected recovery
of reserves in excess of proved reserves, anticipated changes in future
prices and costs and a discount factor representative of the time value
of money and risks inherent in producing oil and gas.
2000 1999 1998
------------ ------------ ------------
Future cash inflows .............................................. $191,274,646 $ 69,816,041 $ 29,011,780
Future production costs .......................................... 38,244,222 14,567,866 5,110,313
Future development costs ......................................... 330,071 588,733 44,279
------------ ------------ ------------
Future net cash flows before income taxes ........................ 152,700,353 54,659,442 23,857,188
Future income tax expense ........................................ 50,283,397 13,259,925 5,375,278
------------ ------------ ------------
Future net cash flows ............................................ 102,416,956 41,399,517 18,481,910
10% annual discount for estimated timing of cash flows ........... 44,761,452 15,891,904 7,011,003
------------ ------------ ------------
Standardized measure of discounted future net cash flows relating
to proved oil and gas reserves ................................... $ 57,655,504 $ 25,507,613 $ 11,470,907
============ ============ ============
The average oil and gas prices used to calculate future net cash
inflows at December 31, 2000 were $25.21 per barrel and $9.21 per Mcf,
respectively. At December 31, 2000 the NYMEX price for oil was $26.80
per barrel and the NYMEX price for gas was $9.78 per MMBtu.
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH RELATING
TO PROVED OIL AND GAS RESERVES
The following are the principal sources of change in the standardized
measure:
2000 1999 1998
------------ ------------ ------------
Balance at January 1 .......................... $ 25,507,613 $ 11,470,907 $ 4,868,751
Sales of oil and gas, net ..................... (10,839,259) (3,559,762) (1,385,196)
Net changes in prices and production costs .... 23,723,370 6,760,297 (2,206,776)
Extensions and discoveries .................... 6,831,763 1,234,841 181,087
Revisions of previous quantity estimates ...... (683,786) (4,901,897) 1,813,841
Net change in income taxes .................... (18,921,740) (3,309,637) (473,300)
Accretion of discount ......................... 2,550,761 1,147,091 486,875
Purchases of reserves ......................... 28,597,160 14,706,892 8,304,398
Sale of reserves .............................. (206,536) -- --
Other ......................................... 1,096,158 1,958,881 (118,773)
------------ ------------ ------------
Balance at December 31 ........................ $ 57,655,504 $ 25,507,613 $ 11,470,907
============ ============ ============
F-21
58
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
------- -----------
2.1 - Certificate of Ownership and Merger merging Toreador
Resources Corporation into Toreador Royalty Corporation,
effective June 5, 2000 (previously filed as Exhibit 2.1
to Toreador Resources Corporation Current Report on Form
8-K filed on June 5, 2000, and incorporated herein by
reference).
3.1 - Certificate of Incorporation, as amended, of Toreador
Royalty Corporation (previously filed as Exhibit 3.1 to
Toreador Royalty Corporation Annual Report on Form 10-K
for the year ended December 31, 1998, and incorporated
herein by reference).
3.2 - Amended and Restated Bylaws, as amended, of Toreador
Royalty Corporation (previously filed as Exhibit 3.2 to
Toreador Royalty Corporation Annual Report on Form 10-K
for the year ended December 31, 1998, and incorporated
herein by reference).
3.3 - Certificate of Designation of Series A Convertible
Preferred Stock of Toreador Royalty Corporation, dated
December 14, 1998 (previously filed as Exhibit 10.3 to
Toreador Royalty Corporation Current Report on Form 8-K
filed with the Securities and Exchange Commission on
December 31, 1998, and incorporated herein by
reference).
3.4* - Amendment to Certificate of Designation of Series A
Convertible Preferred Stock of Toreador Resources
Corporation, dated December 31, 1998.
4.1 - Form of Letter Agreement regarding Series A Convertible
Preferred Stock, dated as of March 15, 1999, between
Toreador Royalty Corporation and the holders of Series A
Convertible Preferred Stock (previously filed as Exhibit
4.1 to Toreador Royalty Corporation Annual Report on
Form 10-K for the year ended December 31, 1998, and
incorporated herein by reference).
4.2 - Registration Rights Agreement, effective December 16,
1998, among Toreador Royalty Corporation and persons
party thereto (previously filed as Exhibit 10.2 to
Toreador Royalty Corporation Current Report on Form 8-K
filed with the Securities and Exchange Commission on
December 31, 1998, and incorporated herein by
reference).
4.3 - Settlement Agreement, dated June 25, 1998, among the
Gralee Persons, the Dane Falb Persons and Toreador
Royalty Corporation (previously filed as Exhibit 10.1 to
Toreador Royalty Corporation Current Report on Form 8-K
filed with the Securities and Exchange Commission on
July 1, 1998, and incorporated herein by reference).
4.4 - Registration Rights Agreement, effective July 31, 2000,
among Toreador Royalty Corporation and persons party
thereto (previously filed as Exhibit 4.5 to Toreador
Resources Corporation Registration Statement on Form S-3
filed with the Securities and Exchange Commission on
December 22, 2000, and incorporated herein by
reference).
59
4.5 - Registration Rights Agreement, effective September 11,
2000, among Toreador Resources Corporation and Earl E.
Rossman, Jr., Representative of the Holders (previously
filed as Exhibit 4.6 to Toreador Resources Corporation
Registration Statement on Form S-3 filed with the
Securities and Exchange Commission on December 22, 2000,
and incorporated herein by reference).
10.1+ - Employment Agreement, dated as of May 1, 1997, between
Toreador Royalty Corporation and Edward C. Marhanka
(previously filed as Exhibit 10.5 to Toreador Royalty
Corporation Quarterly Report on Form 10-Q for the
quarter ended June 30, 1997, and incorporated herein by
reference).
10.2+ - Toreador Royalty Corporation 1990 Stock Option Plan
(previously filed as Exhibit 10.7 to Toreador Royalty
Corporation Annual Report on Form 10-K for the year
ended December 31, 1994, and incorporated herein by
reference).
10.3+ - Amendment to Toreador Royalty Corporation 1990 Stock
Option Plan, effective as of May 15, 1997 (previously
filed as Exhibit 10.14 to Toreador Royalty Corporation
Annual Report on Form 10-K for the year ended December
31, 1997, and incorporated herein by reference).
10.4+ - Toreador Royalty Corporation 1994 Non-Employee Director
Stock Option Plan, as amended (previously filed as
Exhibit 10.12 to Toreador Royalty Corporation Annual
Report on Form 10-K for the year ended December 31,
1995, and incorporated herein by reference).
10.5+ - Toreador Royalty Corporation Amended and Restated 1990
Stock Option Plan, effective as of September 24, 1998
(previously filed as Exhibit A to Toreador Royalty
Corporation Preliminary Proxy Statement filed with the
Securities and Exchange Commission on March 12, 1999,
and incorporated herein by reference).
10.6+ - Form of Indemnification Agreement, dated as of April 25,
1995, between Toreador Royalty Corporation and each of
the members of our Board of Directors (previously filed
as Exhibit 10 to Toreador Royalty Corporation Quarterly
Report on Form 10-Q for the quarterly period ended June
30, 1995, and incorporated herein by reference).
10.7+ - Toreador Royalty Corporation Amended and Restated 1990
Stock Option Plan Nonqualified Stock Option Agreement,
dated September 24, 1998, between Toreador Royalty
Corporation and G. Thomas Graves III (previously filed
as Exhibit 10.13 to Toreador Royalty Corporation Annual
Report on Form 10-K for the year ended December 31,
1998, and incorporated herein by reference).
10.8+ - Toreador Royalty Corporation Amended and Restated 1990
Stock Option Plan Nonqualified Stock Option Agreement,
dated September 24, 1998, between Toreador Royalty
Corporation and John Mark McLaughlin (previously filed
as Exhibit 10.14 to Toreador Royalty Corporation Annual
Report on Form 10-K for the year ended December 31,
1998, and incorporated herein by reference).
10.9* - Loan Agreement, effective February 16, 2001, between
Toreador Resources Corporation, Toreador Exploration &
Production Inc., Toreador Acquisition Corporation and
Tormin, Inc. and Bank of Texas, National Association.
60
10.10 - Purchase and Sale Agreement, effective November 24,
1999, between Lario Oil & Gas Company and Toreador
Exploration & Production Inc. (previously filed as
Exhibit 10.1 to Toreador Royalty Corporation Current
Report on Form 8-K filed on January 6, 2000, and
incorporated herein by reference).
10.11 - Merger Agreement, effective September 11, 2000, between
Texona Petroleum Corporation, Toreador Resources
Corporation and Toreador Acquisition Corporation
(previously filed as Exhibit 10.1 to Toreador Resources
Corporation Current Report on Form 8-K filed on October
2, 2000, and incorporated herein by reference).
10.12* - First Amendment to Merger Agreement, effective January
30, 2001, between Texona Petroleum Corporation, Toreador
Resources Corporation and Toreador Acquisition
Corporation.
16.1 - Letter on Change in Certifying Accountant from
PricewaterhouseCoopers LLP, dated June 30, 1999
(previously filed as Exhibit 16 to Amendment No. 2 to
Toreador Royalty Corporation Current Report on Form
8-K/A filed on June 30, 1999, and incorporated herein by
reference).
21.1* - Subsidiaries of Toreador Resources Corporation.
23.1* - Consent of Ernst & Young LLP.
23.2* - Consent of LaRoche Petroleum Consultants, Ltd.
23.3* - Consent of Harlan Consulting.
- ----------
* Filed herewith.
+ Management contract or compensatory plan
(b) Reports on Form 8-K:
During the last quarter of the fiscal year ended December 31,
2000, we filed a Current Report on Form 8-K dated October 2,
2000 with the Securities and Exchange Commission to report the
merger with Texona Petroleum Corporation under items 2 and 7.