UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K/A
(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
------------ ------------
COMMISSION FILE NUMBER: 0-2517
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
----------
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 November 29, 2001 was $13,742,351. (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 November 29, 2001, was 6,296,944 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's Proxy Statement for the 2001 Annual
Meeting of Stockholders, filed on April 23, 2001, are incorporated by reference
into Part III of this Form 10-K.
Toreador Resources Corporation hereby amends and restates its Annual
Report on Form 10-K for the year ended December 31, 2000, to read in its
entirety as follows:
TABLE OF CONTENTS
Page
----
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
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.
1
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.
2
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).
3
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.
4
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.
5
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.
6
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.
7
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.
8
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.
9
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.
10
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.
11
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.
12
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 OIL AND GAS TERMS
The following are certain defined terms used in this prospectus:
"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 natural gas.
"Bcfe." One billion cubic feet of natural gas equivalents, converting one
Bbl of oil to six Mcf of natural gas.
"BOE." Barrel of oil equivalent converting six Mcf of natural gas to one
barrel of oil.
"DEVELOPMENT WELL." A well drilled within the proved boundaries of an oil
or natural 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 natural gas in sufficient quantities to justify
completion as an oil or natural gas well.
"EXPLORATORY WELL." A well drilled to find and produce oil or natural gas
in an unproved area, to find a new reservoir in a field previously found to be
productive of oil or natural 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.
"MBbl." One thousand Bbls.
"MBOE." One thousand BOE.
"Mcf." One thousand cubic feet of natural gas.
"Mcfe." One thousand cubic feet of natural gas equivalents, converting one
Bbl of oil to six Mcf of natural gas.
"MMBl." One million Bbls of oil and other liquid hydrocarbons.
"MMBOE." One million BOE.
"MMcf." One million cubic feet of natural 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.
"NPV-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. 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 natural gas prices and operating
costs, at December 31, 2000, or as otherwise indicated.
"PRODUCING WELL" or "PRODUCTIVE WELL." A well that is producing oil or
natural gas or that is capable of production.
"PROVED DEVELOPED RESERVES." The oil and natural gas reserves that can be
expected to be recovered through existing wells with existing equipment and
operating methods. Additional oil and natural gas expected to be obtained
through the application of fluid injection or other improved recovery techniques
for supplementing the natural 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.
13
"PROVED RESERVES." The estimated quantities of crude oil, natural gas and
natural 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 natural 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 natural gas property
entitling the owner to a share of oil and natural gas production free of
production costs.
"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
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 natural 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.
14
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.
15
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
16
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.
17
OIL AND GAS RESERVES
The following table sets forth information about the Company's estimated
net proved reserves at December 31, 2000 and 1999. LaRoche Petroleum
Consultants, Ltd., an independent petroleum engineering firm of Dallas, Texas,
prepared these estimates.
<Table>
<Caption>
DECEMBER 31,
-----------------
2000 1999
------- -------
Proved developed:
Oil (MBbls)............................................... 2,445 2,000
Gas (MMcf)................................................ 13,666 8,070
Total (MBOE)........................................... 4,723 3,345
Proved undeveloped:
Oil (MBbls)............................................... 78 197
Gas (MMcf)................................................ 18 140
Total (MBOE)........................................... 81 220
Discounted present value (PRETAX) (in thousands)............ $81,650 $30,581
Standardized measure of proved reserves (in thousands)...... $57,656 $25,508
</Table>
Reserves were estimated using oil and gas and production and development
costs in effect on December 31 of 2000 and 1999, without escalation. The
reserves were determined using both volumetric and production performance
methods. Proved reserves are those estimated quantities of crude oil, natural
gas, and natural 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. THE VALUES REPORTED
MAY NOT NECESSARILY BE THE FAIR MARKET VALUE OF THE RESERVES.
PRODUCTIVE WELLS
The following table sets forth the Company's gross and net interests in
productive oil and gas wells as of December 31, 2000. Productive wells are
producing wells and wells capable of production.
<Table>
<Caption>
GROSS(1) NET(2)
--------- -------
Gas
Working Interest.......................................... 343 24.39
Royalty Interest.......................................... 424 10.19
Oil
Working Interest.......................................... 1,231 34.12
Royalty Interest.......................................... 2,589 14.51
</Table>
- ---------------
(1) "Gross" refers to all wells in which the Company has a working interest.
(2) "Net" refers to the aggregate of the percentage working interest of the
Company in the wells before royalties and on a pay-out basis unless the
wells have already paid out.
18
ACREAGE
The following table sets forth developed and undeveloped acreage owned by
us attributable to our ownership as of December 31, 2000 all of which is located
in the United States.
<Table>
<Caption>
DEVELOPED UNDEVELOPED TOTAL
ACREAGE ACREAGE ACREAGE
---------------- --------------- ----------------
GROSS NET GROSS NET GROSS NET
------- ------ ------ ------ ------- ------
257,479 36,702 47,972 22,950 305,451 84,674
</Table>
DRILLING ACTIVITIES
The development wells we drilled during the periods indicated are
summarized in the following table and all such wells were drilled in the United
States.
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
-------------------------------------
2000 1999
----------------- -----------------
GROSS(1) NET(2) GROSS(1) NET(2)
-------- ------ -------- ------
Development:
Gas(3).......................................... 5 0.29 7 0.36
Oil(4).......................................... -- -- -- --
Abandoned(5).................................... 2 0.19 -- --
--- ---- --- ----
Totals....................................... 7 0.48 7 0.36
=== ==== === ====
Exploratory:
Gas(3).......................................... 3 0.38 1 0.13
Oil(4).......................................... 2 0.45 -- --
Abandoned(5).................................... 3 0.45 1 0.13
--- ---- --- ----
Totals....................................... 8 1.28 2 0.26
=== ==== === ====
</Table>
- ---------------
(1) "Gross" means the number of wells in which we have a working interest.
(2) "Net" means the aggregate of the numbers obtained by multiplying each gross
well by our after pay-out percentage working interest therein.
(3) "Gas" means gas wells which are either currently producing or are capable of
production.
(4) "Oil" means producing oil wells.
(5) "Abandoned" means wells that were dry when drilled and were abandoned
without production casing being run.
NET PRODUCTION, UNIT PRICES AND COSTS
The following table summarizes our oil, natural gas and natural gas liquids
production, net of royalties, for the periods indicated.
<Table>
<Caption>
YEARS ENDED DECEMBER 31,
-----------------------------
2000 1999 1998
--------- ------- -------
Net Production:
Oil (Bbls).............................. 273,706 128,924 90,097
Daily average (Bbls/day)................ 750 353 247
Natural gas (Mcf)....................... 1,318,714 918,986 394,849
Daily average (Mcf/day)................. 3,613 2,518 1,082
Daily average (BOE/day)................. 1,352 773 427
</Table>
19
<Table>
<Caption>
YEARS ENDED DECEMBER 31,
-----------------------------
2000 1999 1998
--------- ------- -------
Unit Prices:
Average oil price ($/Bbl)............... $ 28.45 $ 17.14 $ 13.48
Average natural gas price ($/Mcf)....... 3.94 2.14 1.91
--------- ------- -------
Average equivalent price ($/BOE)........ $ 26.67 $ 14.81 $ 12.63
========= ======= =======
Unit Costs ($/BOE):
Lease operating......................... $ 4.71 $ 2.48 $ 3.74
Exploration and acquisition............. 0.63 1.44 4.18
Depreciation, depletion and
amortization......................... 4.94 4.52 3.30
General and administrative.............. 4.61 5.62 6.41
Interest................................ 2.86 2.81 0.23
--------- ------- -------
Total................................ $ 17.75 $ 16.87 $ 17.86
========= ======= =======
</Table>
TITLE TO PROPERTIES
We 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 its 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 it acquires 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 are 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:
- customary royalty and overriding royalty interests;
- liens incident to operating agreements; and
- 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 its properties or materially interfere with their use in the operation
of our business. Substantially all of our properties are pledged as collateral
under its credit facility.
20
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
21
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
22
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 November 29, 2001, there were 6,296,944 shares of Common Stock
outstanding held of record by approximately 455 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 November 29, 2001 was $4.04.
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.
23
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
---------------------------------------------
1996 1997 1998 1999(2) 2000(1)
------ ------ -------- ------- -------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
INCOME STATEMENT DATA:
Revenues:
Oil and gas sales.................... $2,307 $2,325 $ 1,969 $4,259 $13,164
Gain (loss) on commodity
derivatives........................ -- -- -- -- (135)
Lease bonuses and rentals............ 118 288 168 463 472
------ ------ -------- ------ -------
Total revenues..................... 2,425 2,613 2,137 4,722 13,501
Costs and expenses:
Lease operating...................... 716 862 583 699 2,325
Exploration and acquisition.......... 228 546 651 405 309
Depreciation, depletion and
amortization....................... 273 539 514 1,276 2,439
General and administrative........... 907 803 1,000 1,584 2,273
------ ------ -------- ------ -------
Total costs and expenses........... 2,124 2,750 2,748 3,964 7,346
------ ------ -------- ------ -------
Operating income (loss)................ 301 (137) (611) 758 6,155
Other income (expense) Equity in
earnings of unconsolidated
Investments.......................... -- -- -- -- (54)
Gain on sale of properties and other
assets............................. -- 26 -- 852 408
Gain (loss) on sale of marketable
securities......................... 527 -- -- (80) (54)
Interest and other income............ 162 (24) 171 109 71
Interest expense..................... -- -- (36) (794) (1,409)
------ ------ -------- ------ -------
Total other income (expense)....... 689 2 135 87 (1,038)
------ ------ -------- ------ -------
Income (loss) before federal income
taxes................................ 990 (135) (476) 845 5,117
Provision (benefit) for federal income
taxes................................ 263 (84) (234) 337 1,764
------ ------ -------- ------ -------
Net income (loss)...................... 727 (51) (242) 508 3,353
Dividend on preferred shares........... -- -- 20 360 360
------ ------ -------- ------ -------
Income (loss) attributable to common
shares............................... $ 727 $ (51) $ (262) $ 148 $ 2,993
====== ====== ======== ====== =======
Basic income (loss) per share.......... $ 0.14 $(0.01) $ 0.05) $ 0.03 $ 0.54
Diluted income (loss) per share........ $ 0.14 $(0.01) $ (0.05) $ 0.03 $ 0.50
Weighted average shares outstanding
Basic................................ 5,217 5,022 5,125 5,186 5,522
Diluted................................ 5,217 5,022 5,125 5,251 6,691
CASH FLOW DATA:
Net cash provided by operating
activities......................... $ 609 $ 831 $ 277 $ 763 $ 6,046
Capital expenditures for oil and gas
property and equipment............. (893) (717) (13,952) (9,208) (2,430)
BALANCE SHEET DATA:
Working capital...................... 3,384 3,007 1,988 439 3,178
Oil and gas properties, net.......... 3,306 3,210 16,210 24,424 34,630
Total assets......................... 7,009 6,527 19,782 26,456 40,325
Long-term debt....................... -- -- 7,880 14,667 15,244
Stockholders' equity................. 6,624 6,217 10,595 10,650 20,261
</Table>
- ----------
(1) 2000 results contain results from the Texona acquisition from September 19,
2000 through December 31, 2000.
(2) 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
24
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 March 16, 2001, 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
25
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
RESULTS OF OPERATIONS
COMPARISON OF YEARS ENDED DECEMBER 31, 2000 AND 1999
Revenues. Total revenues for 2000 were $13,501,407 compared with
$4,722,123 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.
Expenses. Total costs and expenses were $7,346,282 in 2000 as compared
with $3,963,704 in 1999 representing an 85.3% 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. Exploration and acquisition
costs decreased to $308,987 in 2000 from $404,429 in 1999, due to the completion
of our two 3-D seismic projects that will generate future drilling sites. Our
general and administrative expenses increased $689,595 or 43.5% to $2,273,324 in
2000 from $1,583,729 in 1999, primarily resulting from the addition of staff.
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. 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.
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.
Net Income. 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.
COMPARISON OF YEARS ENDED DECEMBER 31, 1999 AND 1998
Revenues. Total revenues for 1999 were $4,722,123 compared with $2,137,302
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.
Expenses. Total costs and expenses were $3,963,704 in 1999 as compared
with $2,784,043 in 1998 representing a 42.4% 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.
Exploration and acquisition expense decreased 37.9% to $404,429 in 1999 from
$650,983 in 1998, due to the decreased drilling activity we participated in
during 1999. 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.
Gain on sale of properties and other assets was $851,726 in 2000 vs. zero
in 1999. The 1999 sales were for two large mineral acreage packages. 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.
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.
Net Income. 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.
27
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
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
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
held May 17, 2001, filed with the Securities and Exchange Commission on April
23, 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 held May 17,
2001, which will be filed with the Securities and Exchange Commission on April
23, 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 held May 17, 2001, which will be
filed with the Securities and Exchange Commission on April 23, 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 held May 17, 2001, which will be filed with the Securities and
Exchange Commission on April 23, 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, File
No. 0-2517, and incorporated herein by
reference).
30
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,
File No. 0-2517, 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,
File No. 0-2517, 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, File No. 0-2517, 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
(previously filed as Exhibit 3.4 to the
Toreador Resources Corporation Annual
Report on Form 10-K for the year ended
December 31, 2000, File No. 0-2517, and
incorporated herein by reference).
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,
File No. 0-2517, 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, File
No. 0-2517, 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, File No.
0-2517, 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, No.
333-52522, 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, No.
333-52522, 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, File No. 0-2517,
and incorporated herein by reference).
31
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,
File No. 0-2517, 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, File No. 0-2517, 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,
File No. 0-2517, 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, File No. 0-2517, 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,
File No. 0-2517, 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,
File No. 0-2517, 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,
File No. 0-2517, 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
(previously filed as Exhibit 10.9 to
the Toreador Resources Corporation
Annual Report on Form 10-K for the year
ended December 31, 2000, File No.
0-2517, and incorporated herein by
reference).
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, File No.
0-2517, 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, File No.
0-2517, 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 (previously
filed as Exhibit 10.12 to the Toreador
Resources Corporation on Form 10-K for
the year ended December 31, 2000, File
No. 0-2517, and incorporated herein by
reference.
32
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 (previously filed as
Exhibit 21.1 to the Toreador Resources
Corporation Annual Report on Form 10-K
for the year ended December 31, 2000,
File No. 0-2517, and incorporated
herein by reference).
23.1* - Consent of Ernst & Young LLP.
23.2* - Consent of LaRoche Petroleum
Consultants, Ltd.
23.3* - Consent of Harlan Consulting.
24.1 - Power of attorney (previously filed as
Exhibit 24.1 to Toreador Resources
Corporation Registration Statement on
Form S-4, No. 333-72314, filed with the
Securities and Exchange Commission on
October 26, 2001, and incorporated
herein by reference).
- ----------
* 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
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: November 30, 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 November 30, 2001
- -----------------------------------
G. Thomas Graves III
/s/ J. W. BULLION* Director November 30, 2001
- -----------------------------------
J. W. Bullion
/s/ EDWARD NATHAN DANE* Director November 30, 2001
- -----------------------------------
Edward Nathan Dane
/s/ PETER L. FALB* Director November 30, 2001
- -----------------------------------
Peter L. Falb
/s/ THOMAS P. KELLOGG, JR.* Director November 30, 2001
- -----------------------------------
Thomas P. Kellogg, Jr.
/s/ WILLIAM I. LEE* Director November 30, 2001
- -----------------------------------
William I. Lee
/s/ JOHN MARK MCLAUGHLIN* Chairman and Director November 30, 2001
- -----------------------------------
John Mark McLaughlin
/s/ DOUGLAS W. WEIR Chief Financial Officer November 30, 2001
- ----------------------------------- (Principal Financial and Accounting Officer)
Douglas W. Weir
/s/ G. THOMAS GRAVES III
- -----------------------------------
G. Thomas Graves III*
* Pursuant to power of attorney
previously filed with the
Securities and Exchange Commission
34
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<Table>
<Caption>
PAGE
----
TOREADOR RESOURCES CORPORATION
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
</Table>
F-1
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.
/s/ ERNST & YOUNG LLP
Dallas, Texas
March 9, 2001
F-2
TOREADOR RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
<Table>
<Caption>
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 at December 31, 2000 and 1999,
respectively..................................... 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 at December 31,
2000 and 1999, respectively.................... (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
=========== ===========
</Table>
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
TOREADOR RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
-------------------------------------
2000 1999 1998
----------- ---------- ----------
Revenues:
Oil and gas sales................ $13,163,862 4,259,040 $1,968,638
Gain (loss) on commodity
derivatives................... (135,300) -- --
Lease bonuses and rentals........ 472,845 463,083 168,664
----------- ---------- ----------
Total revenues................ 13,501,407 4,722,123 2,137,302
Costs and expenses:
Lease operating.................. 2,324,603 699,278 583,441
Exploration and acquisition
expense....................... 308,987 404,429 650,983
Depreciation, depletion and
amortization.................. 2,439,368 1,276,268 514,071
General and administrative....... 2,273,324 1,583,729 999,548
----------- ---------- ----------
Total costs and expenses...... 7,346,282 3,963,704 2,748,043
----------- ---------- ----------
Operating income (loss)............ 6,155,125 758,419 (610,741)
Other income (expense)
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) --
Interest and other income........ 70,702 109,035 171,338
Interest expense................. (1,408,807) (794,627) (36,120)
----------- ---------- ----------
Total other income
(expense)................... (1,038,479) 86,519 135,218
----------- ---------- ----------
Net 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
</Table>
See accompanying notes to the consolidated financial statements.
F-4
TOREADOR RESOURCES CORPORATION
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
<Table>
<Caption>
ACCUMULATED
OTHER
CAPITAL IN COMPREHENSIVE TOTAL
PREFERRED COMMON EXCESS OF RETAINED INCOME TREASURY STOCKHOLDERS'
STOCK STOCK PAR VALUE EARNINGS (LOSS) STOCK EQUITY
--------- ---------- ----------- ---------- ------------- ----------- -------------
Balance at December 31, 1997.... $ -- $ 838,683 $ 3,646,834 $2,791,117 $ -- $(1,059,439) $ 6,217,195
Issuance of common stock........ -- 43,203 766,809 -- -- -- 810,012
Issuance of preferred stock..... 160,000 -- 3,789,219 -- -- -- 3,949,219
Dividends declared on preferred
stock......................... -- -- -- (19,500) -- -- (19,500)
Purchase of treasury stock...... -- -- -- -- -- (95,250) (95,250)
Comprehensive income
Net loss...................... -- -- -- (242,246) -- -- (242,246)
Other comprehensive loss, net
of tax
Unrealized loss on
securities.................. -- -- -- -- (24,922) -- (24,922)
-----------
Total comprehensive loss........ (267,168)
-------- ---------- ----------- ---------- -------- ----------- -----------
Balance at December 31, 1998.... 160,000 881,886 8,202,862 2,529,371 (24,922) (1,154,689) 10,594,508
Issuance of common stock........ -- 1,172 31,518 -- -- -- 32,690
Dividends paid on preferred
stock......................... -- -- -- (360,000) -- -- (360,000)
Purchase of treasury stock...... -- -- -- -- -- (114,403) (114,403)
Comprehensive income
Net income.................... -- -- -- 508,011 -- -- 508,011
Other comprehensive loss, net
of tax
Unrealized loss on
securities.................. -- -- -- -- (10,608) -- (63,154)
Less reclassification
adjustment for losses
included in net income...... 52,546
-----------
Total comprehensive income...... 497,403
-------- ---------- ----------- ---------- -------- ----------- -----------
Balance at December 31, 1999.... 160,000 883,058 8,234,380 2,677,382 (35,530) (1,269,092) 10,650,198
Issuance of common stock........ -- 177,344 6,241,406 -- -- -- 6,418,750
Issuance of stock options....... -- 429,835 -- -- -- 429,835
Dividends paid on preferred
stock......................... -- -- -- (360,000) -- -- (360,000)
Dividends paid on common
stock......................... -- -- -- (51,775) -- -- (51,775)
Purchase of treasury stock...... -- -- -- -- -- (268,702) (268,702)
Comprehensive income
Net income.................... -- -- -- 3,353,069 -- -- 3,353,069
Other comprehensive loss, net
of tax......................
Unrealized gain on
securities.................. -- -- -- -- 89,518 -- 53,988
Less reclassification
adjustment for losses
included in net income...... 35,530
-----------
Total comprehensive income...... 3,442,587
-------- ---------- ----------- ---------- -------- ----------- -----------
Balance at December 31, 2000.... 160,000 1,060,402 14,905,621 5,618,676 53,988 (1,537,794) 20,260,893
======== ========== =========== ========== ======== =========== ===========
</Table>
F-5
TOREADOR RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
----------------------------------------
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
(Gain) 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 (decrease) 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)
Other....................................... -- -- --
----------- ----------- ------------
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 --
Investment in EnergyNet.com, Inc. .............. (155,710)
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................................... -- (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 --
</Table>
See accompanying notes to the consolidated financial statements.
F-6
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.
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
F-7
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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. In the
absence of a determination as to whether the reserves that have been found can
be classified as proved, the Company carries the costs of drilling such an
exploratory well as an asset for no more than one year following completion of
drilling. If, after that year has passed, a determination that proved reserves
have been found cannot be made, Toreador assumes that the well is impaired, and
charges its costs to expense. 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.
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
F-8
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
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 to continue to account for the
results of financial instruments on a mark to market basis.
F-9
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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:
<Table>
<Caption>
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
========== ==========
</Table>
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.
4. PROPERTIES AND EQUIPMENT
Properties and equipment consist of the following:
<Table>
<Caption>
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
=========== ===========
</Table>
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
F-10
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
1,025,000 was issued to the Texona shareholders during 2000 and the remaining
shares ("Deferred Shares") will be issued no later than June 1, 2001. The value
of the Deferred Shares will be added to the value of oil and gas properties
acquired. 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 9,500 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, 2000 through December 31, 2000.
TEXONA MERGER
<Table>
Fair market value of common stock and options............... $6,269,945
Other acquisition costs, net of cash acquired............... 129,069
----------
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.................................. 2,491,466
----------
Net assets acquired......................................... $6,399,014
==========
</Table>
F-11
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following summarized unaudited pro forma financial information assumes
the Merger occurred on January 1 of each year:
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
------------------------
2000 1999
----------- ----------
Revenues.................................................... $16,323,259 $8,274,627
Net income.................................................. $ 3,854,326 $ 764,149
Net income applicable to common shares...................... $ 3,494,326 $ 404,149
Net income per share -- basic............................... $ .63 $ .08
Net income per share -- diluted............................. $ .52 .08
</Table>
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% 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).
7. DERIVATIVE FINANCIAL INSTRUMENTS
During 2000 the Company sold call options to its counterparty for an
average volume of 35,000 MMBtu per month 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
F-12
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
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.
F-13
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The computations of earnings per share for the years ended December 31,
2000, 1999, and 1998, are as follows:
<Table>
<Caption>
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 N/A N/A
---------- ---------- ----------
Income (loss) attributable to
diluted shares............................ $3,353,069 $ 508,011 $ (242,246)
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)
---------- ---------- ----------
</Table>
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.
11. INCOME TAXES
The Company's provision (benefit) for income taxes was comprised of the
following:
<Table>
<Caption>
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)
========== ======== =========
</Table>
F-14
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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:
<Table>
<Caption>
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)
========== ======== =========
</Table>
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:
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
------------------------
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
=========== ========
</Table>
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.
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. At the time of the cancellation of the defined benefit
plan, Toreador established a 401(k) retirement savings plan. Employees are
eligible to defer portions of their salaries, limited by Internal Revenue
Service regulations. Employer matches are discretionary, and are
F-15
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
determined annually by the board of directors. Such discretionary matches
amounted to $14,717 in 2000. In January 2001, Toreador provided an employer
match of $25,156.
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:
<Table>
<Caption>
2000 1999 1998
---------------------------- --------------------------- ---------------------------
WEIGHTED-AVERAGE WEIGHTED-AVERAGE WEIGHTED-AVERAGE
SHARES EXERCISE PRICE SHARES EXERCISE PRICE SHARES EXERCISE 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
========= ===== ======== ===== ======== =====
</Table>
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:
<Table>
<Caption>
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
</Table>
F-16
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table summarizes information about the fixed price stock
options outstanding at December 31, 2000:
<Table>
<Caption>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------------------------------- ---------------------------------
WEIGHTED WEIGHTED NUMBER WEIGHTED
NUMBER AVERAGE AVERAGE EXERCISABLE AVERAGE
RANGE OF OUTSTANDING AT REMAINING EXERCISE AT EXERCISE
EXERCISE PRICES 12/31/00 CONTRACTUAL LIFE PRICE 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
========= ========= ===== ======= =====
</Table>
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:
<Table>
<Caption>
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 $ (0.06)
Diluted income (loss) per share....... As reported $ 0.50 $ 0.03 $ (0.05)
Pro forma $ 0.42 $ 0.02 $ (0.06)
</Table>
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:
<Table>
<Caption>
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
</Table>
14. LEASE AND OTHER COMMITMENTS
The Company leases office space under a non-cancelable operating lease,
which expires on June 30, 2006. The Company subleases portions of the leased
space to one related party and two unrelated parties under non-cancelable
sub-leases that expire on June 30, 2006. The following is a schedule of minimum
future rentals
F-17
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
under the Company's non-cancelable operating lease, giving effect to the
non-cancelable sub-leases, as of December 31, 2000:
<Table>
2001........................................................ $ 144,439
2002........................................................ 152,680
2003........................................................ 170,608
2004........................................................ 173,500
2005........................................................ 115,667
----------
Total....................................................... 756,894
Less: minimum rents from subleases.......................... 48,950
----------
Total....................................................... $ 707,944
==========
</Table>
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
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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:
<Table>
<Caption>
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
=========== ========== ==========
</Table>
CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES:
<Table>
<Caption>
DECEMBER 31,
---------------------------------------
2000 1999 1998
----------- ----------- -----------
Unproved properties(1)........................ $ 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
=========== =========== ===========
</Table>
- ---------------
(1) 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:
<Table>
<Caption>
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
========== ========== ===========
</Table>
F-19
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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,
1998, 1999 and 2000 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).
<Table>
<Caption>
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
========= ==========
</Table>
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
F-20
TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
<Table>
<Caption>
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 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
============ =========== ===========
</Table>
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:
<Table>
<Caption>
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)(2) (4,901,897)(1) 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
============ =========== ===========
</Table>
- ---------------
(1) The most significant downward revision in gas reserves was related to one
field where Toreador owns a royalty interest in three producing wells and
one proved undeveloped location. Initial reserve projections were based
primarily on material balance or volumetric calculations, and very limited,
but flat, gas production history and offset field analogy, if any. As more
production history became available, engineering projections shifted towards
decline curve analysis and were less dependent on volumetric calculations.
Consequently, while these particular wells exhibited very strong gas
deliverability for a period of time, additional production history and
decline curve analysis has proven that the drainage area is not as large as
originally estimated.
(2) The most significant of the downward revisions involved additional downward
revisions to the field mentioned in footnote 1 including the write-off of
reserves on the proved undeveloped location, which was drilled as a dry
hole. Also, Toreador lost significant reserves when a royalty interest well
in another field encountered mechanical problems and the operator was unable
to restore production.
F-21
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, File No. 0-2517, 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, File No. 0-2517,
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, File No. 0-2517,
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, File No. 0-2517, 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 (previously filed
as Exhibit 3.4 to the Toreador Resources Corporation
Annual Report on Form 10-K for the year ended December
31, 2000, File No. 0-2517, and incorporated herein by
reference).
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, File
No. 0-2517, 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, File No. 0-2517, 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, File No. 0-2517, 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, No. 333-52522, 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, No. 333-52522, 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, File No. 0-2517, 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, File No. 0-2517, 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, File No. 0-2517, 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, File No. 0-2517, 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,
File No. 0-2517, 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, File No. 0-2517, 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, File No. 0-2517, 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, File No. 0-2517, 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
(previously filed as Exhibit 10.9 to the Toreador
Resources Corporation Annual Report on Form 10-K for the
year ended December 31, 2000, File No. 0-2517, and
incorporated herein by reference).
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, File
No. 0-2517, 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, File No. 0-2517, 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 (previously filed as Exhibit 10.12 to the
Toreador Resources Corporation on Form 10-K for the year
ended December 31, 2000, File No. 0-2517, and
incorporated herein by reference.
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
(previously filed as Exhibit 21.1 to the Toreador
Resources Corporation Annual Report on Form 10-K for the
year ended December 31, 2000, file No. 0-2517, and
incorporated herein by reference).
23.1* - Consent of Ernst & Young LLP.
23.2* - Consent of LaRoche Petroleum Consultants, Ltd.
23.3* - Consent of Harlan Consulting.
24.1 - Power of attorney (previously filed as Exhibit 24.1 to
Toreador Resources Corporation Registration Statement
on Form S-4, No. 333-72314, filed with the Securities
and Exchange Commission on October 26, 2001, and
incorporated herein by reference).
- ----------
* Filed herewith.
+ Management contract or compensatory plan