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1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended: December 31, 1998
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: 0-02517
TOREADOR ROYALTY 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) 369-0080
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
PREFERRED STOCK PURCHASE RIGHTS 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 (Section 229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. [ ].
The aggregate market value of the voting stock of the registrant held by
non-affiliates, computed by reference to the closing sales price of such stock,
as of March 17, 1999 was $7,714,901. (For purposes of determination of the
foregoing amount, only directors, executive officers and 10% or greater
stockholders have been deemed affiliates.)
The number of shares outstanding of the registrant's Common Stock, par
value $.15625, as of March 17, 1999, was 5,205,671 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's Proxy Statement for the 1999 Annual Meeting
of Stockholders, expected to be filed on or prior to April 30, 1999, are
incorporated by reference into Part III of this Form 10-K.
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TABLE OF CONTENTS
Page
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PART I ...............................................................................................................-1-
ITEM 1. BUSINESS..............................................................................................-1-
ITEM 2. PROPERTIES...........................................................................................-11-
ITEM 3. LEGAL PROCEEDINGS....................................................................................-18-
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS..................................................-18-
PART II ..............................................................................................................-18-
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS..............................................................................................-18-
ITEM 6. SELECTED FINANCIAL DATA..............................................................................-19-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATION.................................................................................-21-
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK...........................................-25-
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA..........................................................-25-
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.................................................................................-26-
PART III ..............................................................................................................-27-
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. ..............................................-27-
ITEM 11. EXECUTIVE COMPENSATION. ..........................................................................-27-
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. ..................................-27-
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. ..................................................-27-
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. ..................................-28-
INDEX TO EXHIBITS......................................................................................................-28-
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PART I
FORWARD-LOOKING STATEMENTS
Before you invest in the Common Stock of Toreador Royalty 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. 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 results, 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 Royalty Corporation, a Delaware corporation, ("Toreador" or the
"Company") is an independent oil and gas 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 2,579,000 gross (1,356,000 net) acres. These
properties include 804,000 gross (480,000 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." For a more detailed description of these properties please see "Item
2. Properties."
We acquired the Southeastern States Holdings on December 16, 1998. These
new properties significantly increased our cash flow and added to our proven
reserve base. These properties are located in geologic provinces that are much
more likely to produce natural gas as opposed to oil. As a result, we were able
to improve our reserve mix to a point that is now approximately 60% natural gas
versus 40% oil. Our new holdings will provide us with growth potential, cash
flow and proved reserves that are more evenly balanced so as to enable us to
more successfully weather severe downturns in the price of crude oil. In
addition, by purchasing minerals located in every county of Alabama and
Mississippi, we have added both geological and geographical diversity to our
asset base.
See "Glossary of Selected Oil and Natural Gas Oil Terms" at the end of this
Item 1 for a definition of certain terms defined in this report.
HISTORY
Toreador Royalty Corporation was incorporated in 1951. The history of our
Texas Holdings dates back to the formation of the Matador Land & Cattle Company
in 1882. Scottish investors assembled approximately one million 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 assigned 50% of the mineral
rights under the ranch acreage. Later, we acquired an additional 25% of the
mineral rights under a number of the original ranch properties.
As of December 31, 1998, a total of 201 exploration and development wells
had been drilled on our Texas Holdings. Overall, well density is approximately
one well per 4,400 acres. In certain sections, well density is less than one
well per 20,000 acres.
BUSINESS STRATEGY
After a change in senior management in July 1998, our board of directors
joined with management in redefining our operating strategy. This shift in
strategic focus was made both as a response to the steep drop in crude oil
prices then underway and the desire to broaden the base of our operations. The
principal elements of our present strategic focus are as follows:
o Continue to promote exploration and development activity on our
Texas Holdings, but in doing so, limit the participation of our
Company to that of a mineral interest owner.
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o Expand the level of direct working interest participation as a
non-operator by our Company in exploration projects that provide
exposure in drilling opportunities for both multiple prospects
and multiple pay zones. We expect these to be generated by
experienced third party operators using current generation
three-dimensional ("3-D") seismic technology.
o Pursue opportunities to make high quality property acquisitions
that are often unique to depressed product price environments.
o Identify and dispose of non-strategic assets, focusing first on
those properties in our Texas Holdings.
DEVELOPMENTS DURING 1998
MANAGEMENT CHANGE
G. Thomas Graves III was elected President and Chief Executive Officer at
the conclusion of our annual shareholder meeting which was held on July 23,
1998. Other changes included the election of four new members of the board of
directors.
NEW PROJECTS
As part of our strategy to participate in third party generated and
operated 3-D seismic projects in geologic regions outside of our Texas
Holdings, our Company is engaged in two 3-D seismic projects that could add
significant gas reserves.
SOUTH ORANGE GROVE 3-D PROJECT. The Company has 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. 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 in the Miocene, Frio, Vicksburg and deeper Yegua horizons in and
around existing fields. These existing fields are older and contain relatively
few modern exploratory wells. The project is targeting gas reserves from depths
ranging from 800 feet to 8,100 feet. As of March 17, 1999, the operator, who has
had good exploration success in the same general area, had completed the
acquisition of 3-D seismic data and was in the processing phase of the project.
The interpretation phase is expected to be completed by May 1999 and, assuming
positive results from the interpretation of the data, drilling could commence as
early as the latter portion of the second quarter of 1999.
KIRBY HILLS 3-D PROJECT. The Company has 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. 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, range in depth from 1,500 feet to 5,400
feet. As of March 17, 1999, the operator's lease acquisition program was still
underway. Acquisition of seismic data is expected to begin May 1999. Processing
and interpretation should take approximately two months once data acquisition
is complete. Assuming positive results from the interpretation of the data,
drilling could begin as early as the third quarter of 1999.
ACQUISITIONS
As part of our strategy to actively pursue high quality property
acquisition opportunities, we reviewed a number of prospective candidates
during the third and fourth quarters of 1998.
HOWELL MINERAL ACQUISITION. On December 16, 1998, we purchased certain
oil, gas and other mineral and royalty interests located in Alabama, Louisiana
and Mississippi from Howell Petroleum Corporation. The purchase price before
final closing adjustments for these interests was $13.0 million. The purchase
price was funded with our cash ($4.4 million) and loans from Compass Bank,
Dallas ($8.6 million). The properties acquired consist of those previously
described as "Southeastern States Holdings." Non-producing acreage comprises
approximately 98% of the total properties acquired. The producing interests,
that make up the remaining 2% of the total, include interests in approximately
400 oil and gas wells. This acquisition had an effective date of November 1,
1998 and the acquired interests were estimated to contain 7.95 Bcfe of proved
reserves as of that date. During the evaluation of our total proved reserves as
of December 31, 1998, our outside consulting engineering, Harlan Consulting,
increased the original estimate of total proved reserves acquired to 9.56 Bcfe.
This latest evaluation shows the acquired reserves are a mix of approximately
71% gas and 29% oil.
FINANCING ACTIVITIES
A portion of the purchase price of the Howell property acquisition was
financed through a private placement of $4.0 million of the Company's Series
"A" Convertible Preferred Stock. This was sold pursuant to a securities
purchase agreement effective December 16, 1998 to various outside investors
that included four directors
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of the Company. These preferred shares were sold for a face value of $25.00.
The annual dividend paid is $2.25, which results in an annual yield of 9.0%. At
the option of the holder, a preferred share can be converted into shares of the
Company's common stock at a price of $4.00 per common share. For additional
information regarding the terms of the preferred stock, please see "Item 5.
Market for Registrant's Common Equity and Related Stockholder Matters."
MARKETS AND COMPETITION
Our oil and gas production is sold to various purchasers typically in the
areas where the oil or gas is produced. 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 Natural Gas Prices" for a
discussion of the risks of commodity price fluctuations.
The oil and natural 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 natural 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. We are unable to predict how
long current market conditions will continue.
Competition for attractive oil and natural 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 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 natural gas industry, changes in such laws
and changing administrative regulations affect our oil and natural 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 are of the opinion that price controls will not have a significant
impact on the prices received by us for natural gas produced in the near
future.
We review legislation affecting the oil and natural 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 natural 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,
nor whether amendments or additional regulations will be adopted, nor what
effect such interpretations and changes may have on our business or financial
conditions.
Matters subject to regulation include:
o discharge permits for drilling operations;
o drilling and abandonment bonds or other financial responsibility
requirements;
o reports concerning operations;
o the spacing of wells;
o unitization and pooling of properties; and
o taxation.
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Natural Gas Regulation and the Effect on Marketing
Historically, interstate pipeline companies generally acted as wholesale
merchants by purchasing natural gas from producers and reselling the natural
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 natural gas pipeline
operations, services, and rates, and thus have significantly altered the
marketing and price of natural 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 natural 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
natural 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 natural 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 for you 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 natural 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 natural gas through these facilities. We also transport a portion of our
natural 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 natural
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 a 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.
Several of these initiatives are intended to enhance competition in natural gas
markets, although some, 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
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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 Taxation
The federal government 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 natural 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;
o the Resource Conservation and Recovery Act;
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.
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 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 future amendments of the act,
if any.
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
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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 oil and gas exploration and production, and possibly other
activities, have been conducted at some of our properties by previous owners
and operators, 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.
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 natural 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
natural gas industry in general. Initiatives to further regulate the disposal
of crude oil and natural 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 natural
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 17, 1999, we employed seven 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
Effects of Indebtedness
At December 31, 1998, Toreador's debt to equity ratio was 102%. We may
incur additional indebtedness in the future as we execute our acquisition and
exploration strategy. See "-- Potential Need for Additional Financing for
Continued Growth."
Our ability to meet our debt service obligations will be dependent upon
our future performance, which will be subject to oil and natural 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 our future performance will not be
adversely affected by some or all of these factors. See "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operation
- -Liquidity and Capital Resources."
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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 businesses, 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."
Volatility of Oil and Natural Gas Prices
Our future financial condition and results of operations depend upon the
prices we receive for our oil and natural gas and the costs of acquiring,
developing and producing oil and natural gas. Currently, oil and natural gas
prices are depressed. Historically, oil and natural 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, without limitation:
o the level of domestic production;
o the availability of imported oil and natural gas;
o actions taken by foreign oil and natural gas producing nations;
o the availability of transportation systems with adequate capacity;
o the availability of competitive fuels;
o fluctuating and seasonal demand for natural gas;
o conservation and the extent of governmental regulation of production,
weather, foreign and domestic government relations;
o the price of domestic and imported oil and natural gas; and
o the overall economic environment.
A substantial or extended decline in oil and/or natural gas prices could have a
material adverse effect on the estimated value of our natural 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 natural gas prices.
Past Losses
We had net losses applicable to common shares of $261,746 and $51,366 for
the years ended December 31, 1998 and 1997, respectively. We may continue to
incur net losses and, to the extent that natural gas and crude oil prices are
low, such losses may be substantial.
Potential Inability to Develop Additional Reserves
Our future success as an oil and natural gas producer, as is generally the
case in the industry, depends upon our ability to find, develop and acquire
additional oil and natural 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.
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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 natural gas properties. Any future
acquisitions will require an assessment of recoverable reserves, future oil and
natural 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 Howell Mineral Acquisition represents a major step 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 can be effectively managed to realize the goals anticipated of the
property acquisitions.
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
natural gas properties and businesses. In addition, our pursuit of additional
capital could result in incurring addition indebtedness or potential dilutive
issuances of additional 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 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.
Drilling Risks
Our drilling involves numerous risks, including the risk that no
commercially productive oil or natural 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 natural gas
requires greater pre-drilling expenditures than traditional drilling
strategies. We cannot assure the success of our future drilling activities.
Nature of Property Interests
On the Southeastern States Holdings, we own interests in minerals that
include executive rights 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 portions of lease bonuses, delay
rentals and royalties, except, unlike our Southeastern States Holdings, we
generally do not own the executive rights -- the rights to sign leases -- 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 deciding 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.
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Estimates of Oil and Natural Gas Reserves
Numerous uncertainties are inherent in estimating quantities of proved oil
and natural gas reserves, including many factors beyond our control. This
report contains an estimate of our proved oil and natural gas reserves and the
estimated future net cash flows and revenue generated by the proved oil and
natural 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 natural 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 natural 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 natural 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 natural gas prices and other
factors.
Operating Hazards and Uninsured Risks
Our operations are subject to the risks inherent in the oil and natural
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, natural 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.
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 varies 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.
Stock Price Volatility
Because the volume of trades of shares of our Common Stock held by the
public 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
We have never paid cash dividends on our Common Stock and 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.
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Marketing Risks
The marketing of our oil and natural gas production principally depends
upon those facilities operated by others.
Control by Certain Stockholders
As of January 31, 1999, the current officers and directors of the Company
as a group held a beneficial interest in approximately 55% 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). In addition, certain officers and directors holding or
controlling an aggregate of 52% of the Common Stock have entered into a
Stockholder Voting Agreement whereby such persons have agreed to vote their
shares together or refrain from voting their shares under certain
circumstances, including the election of directors, merger transactions in
respect of the Company and other possible change of control events.
Consequently, these stockholders are in a position to effectively control the
affairs of the Company, including the election of all of the Company's
directors and the approval or prevention of certain corporate transactions
which require majority stockholder approval.
Key Personnel
We are substantially dependent upon G. Thomas Graves III, President, Chief
Executive Officer and Director, Edward C. Marhanka, Vice President, and other
key personnel, including Douglas W. Weir, Vice President - Finance and
Treasurer. Because we are engaged in a new business strategy, the loss of any
one of these individuals for any reason may have a material adverse impact upon
us.
GLOSSARY OF SELECTED OIL AND NATURAL GAS TERMS
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to crude oil or other liquid hydrocarbons.
Bcf. One billion cubic feet of 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.
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.
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.
"producing well" or "productive well." A well that is producing oil or
natural gas or that is capable of production.
"proved developed reserves" or "proved developed producing." Proved
developed reserves are 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
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should be included as "proved developed reserves" only after testing by a pilot
project or after the operation of an installed program has confirmed through
production response that increased recovery will be achieved.
"proved reserves." The estimated quantities of crude oil, 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." Reserves are 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 costs
of production.
"SEC PV-10." The present value of proved reserves is an estimate of the
discounted future net cash flows from each property at December 31, 1998, or as
otherwise indicated. Net cash flow is defined as net revenues less, after
deducting production and ad valorem taxes, future capital costs and operating
expenses, but before deducting federal income taxes. As required by rules of the
Securities and Exchange Commission, the future net cash flows have been
discounted at an annual rate of 10% to determine their "present value." The
present value is shown to indicate the effect of time on the value of the
revenue stream and should not be construed as being the fair market value of the
properties. In accordance with Securities and Exchange Commission rules,
estimates have been made using constant oil and natural gas prices and operating
costs, at December 31, 1998, or as otherwise indicated.
"Standardized Measure." Under the Standardized Measure, future cash flows
are estimated by applying year-end prices, adjusted for fixed and determinable
escalations, to the estimated future production of year-end proved reserves.
Future cash inflows are reduced by estimated future production and development
costs based on period-end costs to determine pretax cash inflows. Future income
taxes are computed by applying the statutory tax rate to the excess inflows
over the Company's tax basis in the associated properties. Tax credits, net
operating loss carryforwards, and permanent differences are also considered in
the future tax calculation. Future net cash inflows after income taxes are
discounted using a 10% annual discount rate to arrive at the Standardized
Measure.
"undeveloped acreage." Lease acreage on which wells have not been drilled
or completed to a point that would permit the production of commercial
quantities of oil and 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 costs of exploration to, development and operations and all risks in
connection therewith.
ITEM 2. PROPERTIES.
The Company owns perpetual oil and gas mineral and royalty interests
comprised of the Texas Holdings and the Southeastern States Holdings that total
approximately 2,579,000 gross acres.
TEXAS HOLDINGS
Our Texas Holdings are comprised of the Northern Ranch Minerals and the
Southern Ranch Minerals and equal approximately 804,000 gross acres.
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.
SOUTHERN DALHART BASIN. In January 1995, we leased approximately 13,000
acres on the Smith Ranch (formerly the Proctor Ranch) in Hartley County, Texas
with the intent of accelerating third party interest in various projects which
we generated. In January 1997, we entered into a farmout agreement with Corlena
Oil Company (the operator) covering approximately 1,900 acres of our leasehold.
In March 1997, we participated for a 25% working interest in drilling the first
well to test Pennsylvanian age Granite Wash reservoirs. This initial exploratory
well was plugged and
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abandoned after testing water and non-commercial quantities of oil. The
operator then conducted a 3-D seismic survey covering approximately 2,700 acres
of our 13,000 acre leasehold. In January 1998, the operator drilled a new oil
field discovery well, the #2-A Smith Ranch, to open the Pedarosa (Granite Wash)
Field at approximately 5,500 feet. In addition to our working interest, we have
a 15% net royalty interest. In March and April 1998 the Company participated in
the drilling of two wells, both of which were dry.
In January 1999, we sold approximately 66,300 gross (49,700 net) mineral
acres for $750,000. This acreage is commonly referred to as the Scharbauer
Ranch acreage in Oldham County, Texas. This sale was a result of our new
business strategy to divest the company's non-strategic assets. We plan to
continue this divestment strategy as long as we receive what we believe are
viable offers for our non-strategic minerals. See further discussion in Note 6
of the Notes to the Consolidated Financial Statements.
SOUTHERN RANCH MINERALS
The Company owns 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
in 1998.
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.
In January 1998, the Company participated in the testing and completion of
a well as an extension to an existing field. Upon completion, this well was
pumping at a daily rate of 36 Bbls of oil and three Bbls of water. Later in the
first quarter of 1998, the Company participated in drilling one exploration
well in the same field resulting in a dry well.
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 the first quarter of 1998, the Company participated in drilling seven
wells with the operator, resulting in two producing wells and five dry wells.
During the month of January 1999, these two producing wells combined pumped at
an average daily rate of 161 Bbls of oil.
SOUTHEASTERN STATES HOLDINGS
In December 1998, the Company acquired approximately 1,775,000 gross 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.
MISSISSIPPI
The Company owns perpetual mineral and royalty interests for oil, gas and
other minerals 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.
MISSISSIPPI SALT BASIN
Within the Mississippi Salt Basin, there are two major areas of activity
which are currently providing us with the opportunity to gain significant
reserve potential. They are in the areas of Piercement Salt Domes and Salt
Ridges.
PIERCEMENT SALT DOMES. The Piercement Salt Dome activity is currently
focused in the south-central portion of Mississippi in Jefferson Davis and
Covington 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 Paluxy formation at
approximately 12,000 feet. In Mississippi there are over five
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(5) dozen salt domes alone. The success of this activity to date is greatly
dependent and attributed to the advances of 3- D seismic technology.
In Jefferson Davis County, Mississippi, for instance, we are benefitting
directly from the use of the latest 3- D seismic technology to exploit this
activity. In June 1997, the Oakvale Dome Field was discovered in which the
initial well was completed in the Hosston "Harper" Sand and is currently flowing
for an average daily rate of approximately 10 MMcf of natural gas. In March
1999, a second well in the field was completed and recently tested at a daily
rate flowing as high as 20 MMcf of natural gas from the commingling of the
Hosston "Booth" Sand and the Hosston "H-1" and "H-2" Sands. Operations are
underway to increase pipeline capacity from the current daily rate of
approximately 15 MMcf of natural gas to a rate that allows the operator to
produce at a daily rate in excess of 30 MMcf of natural gas. We own a 3.125%
royalty interest in each of these wells and as a royalty owner do not bear the
burden of any expenses in developing these fields. In addition, the operator is
currently drilling its third well in the field and has permitted with the state
the location for a fourth well which the operator has indicated that it plans to
initiate drilling operations in the third quarter of 1999.
SALT RIDGES. Salt Ridge activity is currently underway in Wayne, Jones,
Perry and Greene Counties, Mississippi. The primary objectives are the Cotton
Valley, Smackover and Norphlet formations ranging from 12,000 feet to 18,000
feet. The use of 3-D seismic technology has been critical to the success of
this activity.
This activity was initiated by the discovery of the Crawford Creek Field
in Wayne County, Mississippi in 1994. As of December 1998 this field has
produced nearly 3 million barrels of oil and 1.5 Bcf of natural gas from 15
wells out of the Cotton Valley and Hosston Sands.
Some of our acreage is in a favorable position to be leased and included
in some units currently being formed by various operators which is near the
most recent discovery well that tested for a daily rate of approximately 3 MMcf
and 500 barrels of condensate.
DEEP KNOX GAS. Current activity is centered in Oktibbeha County,
Mississippi, adjacent to the Black Warrior Basin, where a 15,000 foot Knox Gas
well was completed in June 1998 and flowed for an average daily rate in January
1999 of six MMcf. We own a 0.35% royalty interest in this well. The operator is
currently drilling a delineation well where we will own a royalty interest of
approximately 2.9%.
Very few wells have been drilled to the Knox in this region near or in the
Black Warrior Basin, thus giving new promise to the area. With the use of 3-D
seismic technology, this well revitalizes the Maben Field which was originally
discovered in 1970.
ALABAMA
The Company owns perpetual oil and gas mineral and royalty interests in
approximately 622,000 gross acres in Alabama. Just as in Mississippi, we own a
mineral position in every county in Alabama.
The major producing property for the Company in Alabama is the North
Frisco City Fieldwide Unit located in the North Frisco City Field of Monroe
County, Alabama.
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 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 after production ceases for that period of 10 years.
TITLE TO OIL AND NATURAL GAS PROPERTIES
We have acquired interests in producing and non-producing acreage in the
form of working interests, 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 natural 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 natural gas. Once wells are drilled, a lease generally
continues so long as production of oil and natural 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 natural gas industry, and to
liens incident to operating
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agreements, liens relating to amounts owed to the operator, liens for current
taxes not yet due and other encumbrances. A substantial portion of our
exploration and production properties are pledged as collateral under our
credit facility, including a major portion of the Howell Mineral Acquisition.
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.
On the Southeastern States Holdings, we own interests in minerals that
include executive rights 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 portions of lease bonuses, delay rentals and
royalties, except, unlike our Southeastern States Holdings, we generally do not
own the executive rights -- the rights to sign leases -- 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 deciding 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. In situations where we acquire a working interest we do not seek to
become the operator. We currently operate and own a 100% working interest in one
oil well.
OIL AND GAS RESERVES
The following tables summarize certain information regarding our estimated
proved oil and gas reserves as of December 31, 1998, 1997, and 1996. All such
reserves are located in the United States. The estimates relating to our proved
oil and gas reserves and future net revenues of oil and gas reserves at
December 31, 1998 and December 31, 1996 are based upon reports prepared by
Harlan Consulting. The estimates at December 31, 1997 included in this report
are based upon reports prepared by another outside engineering firm. In
accordance with guidelines of the Securities and Exchange Commission, the
estimates of future net cash flows from proved reserves and their SEC PV-10 are
made using oil and gas sales prices in effect as of the dates of such estimates
and are held constant throughout the life of the properties. For the three
years ended December 31, our estimates of proved reserves, future net cash
flows and SEC PV-10 for the life of the properties were estimated using the
weighted average prices shown below for the life of the properties, before
deduction of production, severance and ad valorem taxes. Included in the table
is the percent change in the weighted-average price from the prior year.
DECEMBER 31,
------------------------------------------------------------------
% INCREASE % INCREASE
1998 (DECREASE) 1997 (DECREASE) 1996
----- ---------- ---- ----------- ------
Gas ($ per Mcf)...................... $1.86 (17) $ 2.25 (33) $ 3.34
Oil ($ per Bbl)...................... $9.74 (39) $15.87 (36) $24.62
Reserve estimates are imprecise and may be expected to change as
additional information becomes available. Furthermore, estimates of oil and gas
reserves, of necessity, are projections based on engineering data, and there
are uncertainties inherent in the interpretation of such data as well as the
projection of future rates of production and the timing of development
expenditures. Reservoir engineering is a subjective process of estimating
underground accumulations of oil and gas that cannot be measured in an exact
way, and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgement.
Reserve reports of other engineers might differ from the reports contained
herein. Results of drilling, testing, and production subsequent to the date of
the estimate may justify revision of such estimate. Future prices received for
the sale of oil and gas may be different from those used in preparing these
reports. The amounts and timing of future operating and development costs may
also differ from those used. Accordingly, there can be no assurance that the
reserves set forth herein will ultimately be produced nor can there be
assurance that the proved undeveloped reserves will be developed within the
periods anticipated. We emphasize with respect to the estimates prepared by
independent petroleum engineers that the discounted future net cash inflows
should not be construed as
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representative of the fair market value of the proved oil and gas properties
belonging to us, since discounted future net cash inflows are based upon
projected cash inflows which do not provide for changes in oil and gas prices
nor for escalation of expenses and capital costs. The meaningfulness of such
estimates is highly dependent upon the accuracy of the assumptions upon which
they were based.
All reserves are evaluated at contract temperature and pressure which can
affect the measurement of natural gas reserves. Operating costs, development
costs and certain production-related and ad valorem taxes were deducted in
arriving at the estimated future net cash flows. No provision was made for
income operating methods and existing conditions at the prices and operating
costs prevailing at the dates indicated above. The estimates of the SEC PV-10
from future net cash flows differ from the Standardized Measure set forth in
Note 17 of the Notes to the Consolidated Financial Statements of the Company,
which is calculated after provision for future income taxes. There can be no
assurance that these estimates are accurate predictions of future net cash
flows from oil and natural gas reserves or their present value.
For additional information concerning our oil and natural gas reserves and
estimates of future net revenues attributable thereto, see Note 17 of the Notes
to the Consolidated Financial Statements.
Company Reserves
The following tables set forth our proved reserves of oil and gas and the
SEC PV-10 thereof on an actual basis for each year in the three-year period
ended December 31, 1998.
PROVED OIL AND GAS RESERVES (1)
DECEMBER 31,
-----------------------------------------------------------------
% Increase % Increase
1998(1) (Decrease) 1997 (Decrease) 1996
----------- ---------- --------- --------- ---------
GAS RESERVES (MCF):
Proved Developed Producing Reserves.......... 8,500,655 242 2,487,574 (19) 3,052,940
Proved Developed Non-Producing Reserves...... 0 0 0 0 0
Proved Undeveloped Reserves.................. 1,289,785 1,576 76,966 N/A 0
----------- --------- --------- --------- ---------
Total Proved Reserves of gas............. 9,790,440 282 2,564,540 (16) 3,052,940
----------- --------- --------- --------- ---------
OIL RESERVES (BBL):
Proved Developed Producing Reserves.......... 1,094,454 143 450,646 (43) 791,272
Proved Developed Non-Producing Reserves...... 0 (100) 51,080 N/A 0
Proved Undeveloped Reserves.................. 19,051 (63) 51,452 N/A 0
----------- --------- --------- --------- ---------
Total Proved Reserves of oil............. 1,113,505 101 553,178 (30) 791,272
----------- --------- --------- --------- ---------
TOTAL PROVED RESERVES (MCFE)...................... 16,471,470 180 5,883,608 (25) 7,800,572
=========== ========= ========= ========= =========
- ----------
(1) Reflects the addition of reserves acquired in the Howell Mineral
Acquisition.
SEC PV-10 OF PROVED RESERVES
DECEMBER 31,
---------------------------------------------------------
% INCREASE % INCREASE
1998(2) (DECREASE) 1997 (DECREASE) 1996
-------- ---------- -------- ---------- --------
SEC PV-10 (thousands) (1):...................
Proved Developed Producing Reserves.......... $ 11,780 121 $ 5,342 (53) $ 11,345
Proved Developed Non-Producing Reserves.. 0 (100) 514 N/A 0
Proved Undeveloped Reserves.................. 1,454 380 303 N/A 0
-------- ---- -------- ---- --------
Total SEC PV-10.............................. $ 13,234 115 $ 6,159 (46) $ 11,345
======== ==== ======== ==== ========
- ----------
(1) SEC PV-10 differs from the Standardized Measure set forth in the Notes to
the Consolidated Financial Statements of the Company, which is calculated
after provision for future income taxes.
(2) Reflects the addition of reserves acquired in the Howell Mineral
Acquisition.
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Except for the effect of changes in oil and gas prices, no major discovery
or other favorable or adverse event is believed to have caused a significant
change in these estimates of our proved reserves since December 31, 1998.
VOLUMES, PRICES AND COSTS
The following table sets forth certain information regarding volumes of
our production of oil and natural gas, our average sales price per Bbl of crude
oil and average sales price per Mcf of natural gas, together with our average
production cost per BOE for each of the three years ended December 31, 1998 from
producing interests:
YEAR ENDED DECEMBER 31,
--------------------------------------------------------
% INCREASE % INCREASE
1998 (1) (DECREASE) 1997 (DECREASE) 1996
-------- ---------- ---- ---------- ----
Production
Oil (Bbls)................................. 90,097 29 69,903 2 68,318
Gas (Mcf).................................. 394,849 (7) 425,854 22 348,539
Oil equivalent (BOE)....................... 155,905 11 140,879 11 126,408
Average Sales Price
Oil ($/Bbl)................................ $ 13.48 (29) $ 19.04 (11) $ 21.51
Gas ($/Mcf)................................ 1.91 (18) 2.33 (3) 2.40
Oil equivalent ($/BOE)..................... 12.63 (23) 16.50 (10) 18.25
Average production cost (lifting cost) BOE...... $ 3.74 (24) $ 4.93 6 $ 4.63
- ----------
(1) The data presented for the year ended December 31, 1998 would include
only one-half month of production from the Howell Mineral Acquisition
since the closing date was December 16, 1998.
DRILLING ACTIVITY
All of the activity described below occurred on our Texas Holdings.
The Howell Mineral Acquisition was not completed until December 1998 and
therefore the Company did not include any drilling activity on these properties
prior to the date of the acquisition. The following table sets forth for each
of the last three years the number of net exploratory and development wells
drilled by us or on our behalf. An exploratory well is a well drilled to find
and produce oil or gas in an unproved area, to find a new reservoir in a field
previously found to be productive of oil or gas in another reservoir, or to
extend a known reservoir. A development well is a well drilled within the
proved area of an oil or gas reservoir to the depth of a stratigraphic horizon
known to be productive. The number of wells drilled refers to the number of
wells completed at any time during the respective year, regardless of when
drilling was initiated; and "completion" refers to the installation of
permanent equipment for the production of oil or gas, or, in the case of a dry
well, to the reporting of the plugging date to the appropriate state regulatory
agency.
NET EXPLORATORY WELLS
----------------------------------------
PRODUCTIVE (1) DRY (2)
------------------ ------------------
YEAR ENDED
DECEMBER 31,
1996........................... 0.50 0.98
1997........................... 0.57 (3) 0.46
1998........................... 0.00 0.57
NET EXPLORATORY WELLS
----------------------------------------
PRODUCTIVE (1) DRY (2)
------------------ ------------------
YEAR ENDED
DECEMBER 31,
1996........................... 0.03 0.00
1997........................... 0.55 (4) 0.11
1998........................... 0.22 0.90
- ----------
(1) A productive well is an exploratory or a development well that is not a
dry well.
(2) A dry well is an exploratory or development well found to be incapable of
producing either oil or gas in sufficient quantities to justify completion
as an oil or gas well.
-16-
19
(3) One (1) gross (0.25 net) exploratory well, which was a producer, was
drilled in December 1997 but completed in January 1998.
(4) One (1) gross (0.44 net) development well, which was a producer, was
drilled in December 1997 but completed in January 1998.
PRODUCING WELLS AND ACREAGE
The following table sets forth the gross and net producing oil and gas
wells in which we owned an interest and the developed and undeveloped gross and
net leasehold acreage held by us as of December 31, 1998. A "gross" well or
acre is a well or acre in which we have a working interest or royalty interest.
The number of gross wells is the total number of wells in which a working
interest or royalty interest is owned. A "net" well or acre is deemed to exist
when the sum of fractional ownership working interests and/or royalty interests
in a gross well or acre equals one. The number of net wells or acres is the sum
of the fractional working interests and/or royalty interests owned in gross
wells or acres expressed as whole numbers and fractions thereof.
YEAR ENDED DECEMBER 31, 1998 (1)
--------------------------------
Oil Wells (2)
Working Interest
Gross ............................................. 678
Net ............................................... 8.61
Average working interest (%) ...................... 1.27
Royalty Interest
Gross ............................................. 3,351
Net ............................................... 6.72
Average royalty interest (%) ...................... 0.20
Gas Wells (2)
Working Interest
Gross ............................................. 50
Net ............................................... 5.06
Average working interest (%) ...................... 10.11
Royalty Interest
Gross ............................................. 133
Net ............................................... 2.29
Average royalty interest (%) ...................... 1.73
Acreage (2)
Developed
Gross ............................................. 115,031
Net ............................................... 15,751
Undeveloped (3)
Gross ............................................. 149,468
Net ............................................... 122,316
- -------------
(1) Includes the properties from the Howell Mineral Acquisition. Does not
include wells that are considered to have a minor value on an
individual basis.
(2) Excludes wells or acres in which we own less than a 1% working or
royalty interest and are considered to have minor value.
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20
(3) Undeveloped acreage is considered to be only those leased acres on
which wells have not been drilled or completed to a point that would
permit the production of commercial quantities of oil and gas
regardless of whether or not the acreage contains proved reserves.
PRESENT ACTIVITIES
For the period January 1, 1999 through March 17, 1999, we participated in
drilling one gross (0.03 net) development well not on our mineral holdings and
it was successfully completed as a gas well.
OFFICE LEASE
We occupy approximately 2,500 square feet of office space at 4809 Cole
Avenue, Suite 108, Dallas, Texas 75205 under a sublease from Wilco Properties,
Inc.
ITEM 3. LEGAL PROCEEDINGS.
During 1998 we were not a party to any legal proceeding.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
During the last three months of the fiscal year ended December 31, 1998,
we did not submit any matter to a vote by our stockholders through the
solicitation of proxies or otherwise.
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.
1998 High Low
- -----------------------------------------------------------------------
First Quarter 4 1/2 2 15/16
Second Quarter 4 1/2 3 1/8
Third Quarter 3 3/8 2
Fourth Quarter 4 1/8 2
1997 High Low
- -----------------------------------------------------------------------
First Quarter 3 1/8 2 3/8
Second Quarter 3 1/2 2 1/4
Third Quarter 4 5/8 3
Fourth Quarter 4 13/16 4
HOLDERS AND CLOSING PRICE
As of March 17, 1999, there were 5,205,671 shares of Common Stock
outstanding held of record by 491 holders (inclusive of those brokerage firms,
clearing houses, banks and other nominee holders holding Common Stock for
clients, with all such nominees being considered as one holder).
The closing price of the Common Stock on the Nasdaq National Market System
on March 17, 1999 was $2.6875.
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. No cash dividends
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 credit facility
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 (other than dividends
payable in shares of Common Stock).
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21
SERIES A PREFERRED STOCK
A portion of the Howell Mineral Acquisition purchase price was financed
through a private placement of $4.0 million of Series A Preferred Stock, which
was sold pursuant to a securities purchase agreement effective December 16,
1998, between Toreador and certain individuals.
-19-
22
The Series A Preferred Stock is governed by a Certificate of Designation
as supplemented by a letter agreement with all of the holders of the Series A
Preferred Stock. The Series A Preferred Stock was sold for a face value of
$25.00 per share, and pays an annual cash dividend of $2.25 per share that
results in an annual yield of 9.0%. At the option of the holder, the Series A
Preferred Stock may be converted into common shares at a price of $4.00 per
common share. The Series A Preferred Stock is redeemable at our option, in
whole or in part, at any time on or after December 1, 2004. In connection with
the securities purchase agreement, the parties entered into a Registration
Rights Agreement effective December 16, 1998, among Toreador and the persons
party thereto which provides for certain demand and piggyback registration
rights in respect of the Common Stock issuable upon conversion of the Series A
Preferred Stock.
We have agreed to effect the registration of the Common Stock into which
the Series A Preferred Stock is convertible under the Securities Exchange Act
of 1933 (the "Securities Act"), as amended, upon the occurrence of certain
events set out in the Registration Rights Agreement. The sale of the Series A
Preferred Stock was effected in reliance upon the exemption from securities
registration afforded by the provisions of Section 4(2) of the Securities Act
and Regulation D as promulgated by the Securities and Exchange Commission under
the Securities Act.
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.
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------------------
1998 1997 1996 1995 1994
------------ ------------ ------------ ------------ ------------
INCOME STATEMENT DATA (1):
Revenues:
Oil and gas sales ........................ $ 1,968,638 $ 2,325,148 $ 2,306,791 $ 1,378,390 $ 1,323,129
Lease bonuses and rentals ................ 168,664 287,604 118,430 138,804 396,106
Interest and other income ................ 171,338 149,841 162,297 213,464 222,527
Gain on sale of marketable ............... -- 26,171 526,567 -- --
------------ ------------ ------------ ------------ ------------
securities and other assets
Total revenues ...................... 2,308,640 2,788,764 3,114,085 1,730,658 1,941,762
------------ ------------ ------------ ------------ ------------
Costs and Expenses:
Lease operating expense .................. 583,441 695,007 585,732 380,888 347,058
Dry holes and abandonments ............... 133,113 166,710 130,647 358,210 125,838
Depreciation, depletion and
amortization ........................... 514,071 539,346 273,026 233,709 247,654
Geological and geophysical ............... 517,870 546,634 227,744 297,047 235,719
General and administrative ............... 999,548 802,723 907,086 1,078,171 886,547
Loss on settlement of benefit plans ...... -- 173,971 -- -- --
Interest Expense ......................... 36,120 -- -- -- --
------------ ------------ ------------ ------------ ------------
Total costs and expenses ............ 2,784,163 2,924,391 2,124,235 2,348,025 1,842,816
------------ ------------ ------------ ------------ ------------
Income (loss) before federal
income taxes ........................... (475,523) (135,627) 989,850 (617,367) 98,946
Provision (benefit) for federal
income taxes ........................... (233,277) (84,261) 263,100 (206,936) (26,638)
------------ ------------ ------------ ------------ ------------
Net income (loss) ........................ $ (242,246) $ (51,366) $ 726,750 $ (410,431) $ 125,584
============ ============ ============ ============ ============
Dividend on preferred shares ............. 19,500 -- -- -- --
Income (loss) attributable to common shares .. $ (261,746) $ (51,366) $ 726,750 $ (410,431) $ 125,584
============ ============ ============ ============ ============
Basic income (loss) per common share ..... $ (0.05) $ (0.01) $ 0.14 $ (0.08) $ 0.02
Diluted income (loss) per common share ... $ (0.05) $ (0.01) $ 0.14 $ (0.08) $ 0.02
Weighted average shares outstanding
Basic ............................... 5,125,063 5,022,216 5,216,941 5,334,190 5,028,610
Diluted ............................. 5,125,603 5,022,216 5,216,941 5,334,190 5,064,258
CASH FLOW DATA:
Net cash provided (used) by
operating activities ................ $ 276,624 $ 830,643 $ 609,364 $ (10,963) $ 418,885
Capital expenditures for oil and gas
property and equipment ................. $(13,951,981) $ (717,481) $ (893,418) $ (1,048,757) $ (553,020)
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------------------
1998 1997 1996 1995 1994
------------ ------------ ------------ ------------ ------------
BALANCE SHEET DATA: (1)
Working capital .......................... $ 1,987,764 $ 3,007,121 $ 3,383,668 $ 3,538,206 $ 4,646,688
Oil and gas properties, net .............. 16,209,631 3,210,074 3,306,020 3,201,283 2,733,101
Total assets ............................. 19,782,262 6,526,785 7,008,924 7,051,052 7,649,904
Long-term debt ........................... 7,880,000 -- -- -- --
Stockholders' equity ..................... 10,594,508 6,217,195 6,624,180 6,810,485 7,261,761
- ----------
(1) The balance sheet data at December 31, 1998, reflects the completion of
the Howell Mineral Acquisition in December 1998. However, the income
statement data for the twelve months ended December 31, 1998, only
includes income and expense items from the closing date of the Howell
Mineral Acquisition which was December 16, 1998.
-20-
23
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 1998, 1997, and 1996.
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 1996 through 1998
and what we expect them to be in 1999,
o where cash will come from to pay for future capital expenditures, and
o what our progress is as to Year 2000 compliance.
As you read Management's Discussion and Analysis, it may be helpful to
refer to the Company's Consolidated Statements of Income on page F-4, which
present the results of our operations for 1998, 1997, and 1996. In Management's
Discussion and Analysis, we analyze and explain the annual changes in the
specific line items in the Consolidated Statements of Income. 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 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 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
impairment during 1998 in the amount of $19,649 primarily due to the decrease
in oil and gas prices. The impairment is included in the "Depreciation,
depletion and amortization" category of the consolidated statement 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.
-21-
24
While we continue to actively pursue exploration and development
opportunities on our own mineral acreage, the current depressed level of crude
oil prices is likely to reduce the number of third party proposals we receive
with regard to these properties. As a result, we will 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 or prospects which are within the capital exploration budget
approved by our board of directors.
Our 1999 capital and exploratory budget, excluding any acquisitions we may
make, could range from $700,000 to $1,000,000, 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 for reasons related to the negative impact of current crude oil
prices represent unique opportunities for us to add additional reserves to our
reserve base. Any such acquisitions will be financed using cash on hand, third
party sources, existing credit facilities or any combination thereof.
At the present time, the primary source of capital for financing our
operations is our cash flow from operations. During 1998 on a historical basis,
cash flow provided by operating activities totaled $276,624. We anticipate that
cash flow provided by operating activities for 1999 will be materially higher
reflecting the Howell Mineral Acquisition.
The Howell Mineral Acquisition was funded with proceeds from our revolving
credit facility, a $5.9 million term loan, and the issuance of $4.0 million of
our Series A Preferred Stock. For further details of the terms of the Series A
Preferred Stock, see "Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters - Series A Preferred Stock."
On November 13, 1997, we obtained a $10.0 million revolving credit
facility from Compass Bank. This credit facility has a current borrowing base
limitation of $2.7 million which was fully drawn as of December 31, 1998. The
borrowing base is determined by the lender based upon the oil and gas
properties pledged thereunder.
Under the terms of the revolving credit facility, as amended from time to
time, the interest rate is dependent on the Principal Debt (as defined) then
outstanding. For Principal Debt equal to or less than 80% of the Borrowing Base
then in effect, the unpaid principal balance of the Note is subject to a
fluctuating interest rate (per annum) equal to the fluctuating CBIR Rate (or
prime) less 0.5%. For Principal Debt greater than 80% of the Borrowing Base
then in effect, the unpaid principal balance of the Note is subject to a
fluctuating interest rate (per annum) equal to the fluctuating CBIR Rate.
Unpaid balances are paid quarterly commencing January 1, 1998. Borrowings up to
$1.5 million are unsecured. The revolving credit facility contains a Letter of
Credit subfeature which imposes a fee of 0.875% per annum on the face amount of
the Letter of Credit, with a minimum of $350. We are subject to an Unused
Commitment Fee computed at the rate of 0.375% per annum on the average daily
unused portion of the commitment. Such fee is payable quarterly in arrears
beginning January 1, 1998. This facility matures on October 1, 2000.
The revolving credit facility contains various affirmative and negative
covenants. These covenants, among other things, limit additional indebtedness,
the sale of assets and the payment of dividends, change of control and
management and require Tormin to meet certain financial tests. Tormin must
maintain a ratio of current assets to current liabilities of at least 1:1.
Tormin must also maintain a debt service coverage ratio of not less than 1.25:1.
The $5.9 million term loan arranged to fund the Howell Mineral Acquisition
matures on June 1, 2000 and bears fluctuating interest at prime plus .25%.
Tormin is required to pay to the lender monthly the greater of (i) 95% of the
net cash flow from the Howell Mineral Acquisition or (ii) $60,000 plus interest.
Aggregate principal reductions are $720,000 in 1999 and $7,880,000 in 2000.
We are currently negotiating to extend the payment terms of the term loan.
-22-
25
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
ourselves. 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 aforementioned credit 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 1999.
From October 10, 1995 through December 31, 1998 we have used $1,137,946 of
our cash reserves to purchase 432,700 shares of our Common Stock pursuant to
three share repurchase programs approved by the board of directors. On July
23, 1998, our board of directors suspended the policy of share repurchases for
the time being to instead use the Company's excess cash resources toward
funding our participation in third party operated 3-D projects or drilling
prospects and acquisition of producing oil and gas properties. On March 23,
1999, our board of directors reinstated the common stock repurchase program
enabling the Company to purchase the remaining 117,300 shares available under
the third stock repurchase plan from time to time and depending on market
conditions.
During 1998, we received a total of $790,266 as a result of the exercise
of stock options to purchase our Common Stock by two former employees and two
former consultants. Those options related to 200,000, 31,500, and 45,000 shares
of Common Stock with exercise prices of $3.00, $2.46875, and $2.50 per share,
respectively. As of December 31, 1998, only two of the former consultants held
the right to exercise options for additional shares of our Common Stock. Funds
received from the exercise of these stock options were added to our working
capital and used for general corporate purposes.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1998 VERSUS YEAR ENDED DECEMBER 31, 1997
Total revenues for 1998 were $2,308,640 compared with $2,788,764 in 1997.
Revenues from oil and gas sales decreased to $1,968,638 in 1998 from $2,325,148
in 1997. This 15.3% decrease reflects a 10.7% increase in volume on a BOE basis
(principally reflecting the benefit of nearly a full year of revenue from wells
completed in 1997 and early 1998) offset by a 23.5% decrease on a price per BOE
basis. Our net oil production increased 28.9% to 90,097 Bbls in 1998 from
69,903 Bbls in 1997. Net natural gas production decreased 7.3% to 394,849 Mcf
of natural gas in 1998 from 425,854 Mcf of natural gas in 1997. Lease bonuses
and rentals were $168,664 in 1998, down from $287,604 in 1997.
Interest and other income was $171,338 in 1998 versus $149,841 in 1997.
Total costs and expenses were $2,784,163 in 1998 as compared with
$2,924,391 in 1997 representing a 4.8% decrease. The largest decrease came from
lease operating expenses where expenses decreased 16.1% to $583,441 in 1998
versus $695,007 in 1997. This reflects the effort of operators to decrease
costs on wells due to lower oil and gas prices in 1998. Dry holes and
abandonments decreased 20.2% to $133,113 in 1998 from $166,710 in 1997, despite
our increased level of participation in drilling exploratory and development
wells on our mineral holdings in the first quarter of 1998 and early portions
of the second quarter of 1998. Depreciation, depletion and amortization
decreased 4.7% to $514,071 from $539,346 reflecting a downward revision to the
proved developed reserves created by lower oil and gas prices. Geological and
geophysical expenses decreased 5.3% to $517,870 in 1998 versus $546,634 in
1997. Our general and administrative expenses increased $196,825 or 24.5% to
$999,548 in 1998 from $802,723 in 1997, primarily resulting from increased
legal fees and other costs
-23-
26
related to the change in management. During 1998, we incurred interest expense
of $36,120 which was a result of debt incurred for the Howell Mineral
Acquisition.
Total net loss applicable to common shares for 1998 was $261,746 or $0.05
per share compared to a net loss of $51,366 or $0.01 per share.
YEAR ENDED DECEMBER 31, 1997 VERSUS YEAR ENDED DECEMBER 31, 1996
Total revenues for 1997 were $2,788,764 compared with $3,114,085 in 1996.
Revenues from oil and gas sales increased slightly to $2,325,148 in 1997 from
$2,306,791 in 1996. This 0.8% increase reflects an 11.4% increase in volume on
a BOE basis offset by a 9.6% decrease on a price per BOE basis. Our net oil
production increased 2.3% to 69,903 Bbls in 1997 from 68,318 Bbls in 1996. Net
natural gas production increased 22.2% to 425,854 Mcf in 1997 from 348,539 Mcf
in 1996. Lease bonuses and rentals were $287,604 in 1997, up from $118,430 in
1996.
Interest income was $147,237 in 1997 versus $138,720 in 1996. A gain
resulting from the sale of marketable securities decreased from $516,867 in
1996 to none in 1997. This reflects our sale of 100% of our units in the San
Juan Basin Royalty Trust which was completed in August 1996.
Total costs and expenses were $2,924,391 in 1997 as compared with
$2,124,235 in 1996 representing a 37.7% increase. The largest increase came from
geological and geophysical expenses where expenses increased 140% to $546,634 in
1997 versus $227,744 in 1996. This reflects our increased level of participation
in 3-D seismic surveys conducted on our mineral holdings in 1997. Depreciation,
depletion and amortization increased 97.5% to $539,346 from $273,026 reflecting
a downward revision to the proved developed reserves created by a combination of
some underperforming properties and lower oil and gas prices. Dry holes and
abandonments increased 27.6% to $166,710 in 1997 from $130,647 in 1996,
reflecting our increased level of participation in drilling exploratory and
development wells on our mineral holdings. Lease operating expenses increased
18.7% to $695,007 in 1997 versus $585,732 in 1996, as a result of our acquiring
more working interest properties in 1996 and 1997. Our general and
administrative expenses decreased $104,363 or 11.5% to $802,723 in 1997 from
$907,086 in 1996, of which $114,277 reflects a reduction in salary to our former
chairman and chief executive officer. During 1997, we incurred a loss of
$173,971 which has been recorded as a loss on settlement of benefit plans. This
loss consists of a 100% settlement of the pension benefit for $87,654 and a
payment of $88,617 for settlement of the supplemental executive retirement plan.
There were no losses on settlement of benefit plans in 1996.
Total net loss for 1997 was $51,366 or $0.01 per share compared to net
income of $726,750 or $0.14 per share in 1996. Included in 1996 total net
income is a $386,607 after tax gain from the sale of marketable securities and
other assets or $0.07 per share.
NEW ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities." This statement requires companies to record
derivatives on the balance sheet as assets and liabilities, measured at fair
value. Gains and losses resulting from changes in the values of those
derivatives would be accounted for depending on the use of the derivative and
whether it qualifies for hedge accounting. This statement is not expected to
have a material impact on our consolidated financial statements. This statement
is effective for all fiscal quarters of all fiscal years beginning after June
15, 1999, with earlier adoption encouraged.
YEAR 2000 COMPLIANCE
Project. Many computer software systems, as well as certain hardware and
equipment using date-sensitive data, were structured to use a two-digit field
meaning that they may not be able to properly recognize dates in the year 2000.
This problem would most typically be caused by erroneous data calculations,
which results from using two digits to signify a year (century implied),
handling leap years incorrectly or the use of "special" values that can be
confused with legitimate calendar dates. We have developed a plan to address
this issue and are taking steps to
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27
review various information technology systems, such as computer hardware and
software, as well as non-information technology systems, including computer
controlled equipment involved in processing and interpreting 3-D seismic data.
We have completed the initial phases of the plan by identifying all
computerized systems and completing an inventory of our equipment and component
parts. Both information technology and non-information technology systems may
contain embedded technology, which complicates our Year 2000 identification,
assessment, remediation and testing efforts. We are also currently reviewing all
of our systems to determine which are not Year 2000 compliant and will need to
be replaced or modified. This current phase includes comparisons of inventory to
manufacture's information and/or performance testing. If problems are
identified, we will undertake remediation, replacement or alternative procedures
for non-compliant equipment or facilities on a business priority basis. Our
identification and assessment efforts to date have not identified any computer
equipment or software currently being used which will require replacement or
modification. In addition, in the ordinary course of replacing computer
equipment and software, we intend to obtain replacements that are Year 2000
compliant. We currently anticipate that our identification, assessment,
remediation and testing efforts will continue and depending upon the results of
the assessment efforts, be completed by the end of the second quarter of 1999.
As of December 31, 1998, all costs incurred by us in connection with our
Year 2000 compliance efforts were included within our normal general and
administrative expenses. In 1998 those costs were approximately $12,000. We are
currently expensing, as incurred, all costs related to the assessment and
remediation of the Year 2000 issue and funding such expenses through operating
cash flow. However, in certain instances, we may determine that it would be
more practical to replace existing equipment. An accurate cost cannot be
determined prior to the completion of such testing, but we do not expect that
such costs will exceed $25,000.
The following table summarizes the current overall status of the project
with anticipated completion dates:
- ----------------------------------------------------------------------------------------
Phase
- ----------------------------------------------------------------------------------------
Component Inventory Assessment/Prioritization Remediation/Contingency
- ----------------------------------------------------------------------------------------
Software Complete Complete Complete
Hardware Complete Complete Complete
Business Partners Complete 4/30/99 6/30/99
Risks/Contingency. The failure to remediate critical systems (software,
hardware or embedded systems), or the failure of a material business partner to
resolve critical Year 2000 issues could have a serious adverse impact on our
ability to continue operations and meet obligations. Material contingencies
include the risk that gas pipelines to which our gas wells are connected
suspend operations due to Year 2000 problems or operations and other payors to
the Company are unable to calculate or make payment of our share of revenues
from production. However, until all assessment phases have been completed, it
is impossible to accurately identify the risks, quantify potential impacts or
establish a contingency plan. We have not yet clearly identified the most
likely worst case scenario if we and our material business partners do not
achieve Year 2000 compliance on a timely basis. We currently intend to complete
our contingency planning by June 30, 1999.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Not applicable.
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.
-25-
28
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
Not applicable.
-26-
29
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Information relating to our directors, nominees for directors and
executive officers will be set forth under the heading "Election of Directors"
in the Company's Proxy Statement relating to the Annual Meeting of Stockholders
to be held May 20, 1999, which will be filed with the Securities and Exchange
Commission on or prior to April 30, 1999, and which is incorporated herein by
reference.
ITEM 11. EXECUTIVE COMPENSATION.
Information relating to executive compensation will be set forth under the
heading "Executive Compensation and Other Transactions" in the Company's Proxy
Statement relating to the Annual Meeting of Stockholders to be held May 20,
1999, which will be filed with the Securities and Exchange Commission on or
prior to April 30, 1999, and which is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Information relating to security ownership of certain beneficial owners
and management will be set forth under the heading "Security Ownership of
Certain Beneficial Owners and Management" in the Company's Proxy Statement
relating to the Annual Meeting of Stockholders to be held May 20, 1999, which
will be filed with the Securities and Exchange Commission on or prior to April
30, 1999, and which is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Information relating to certain relationships and related transactions
will be set forth under the heading "Executive Compensation and Other
Transactions" in the Company's Proxy Statement relating to the Annual Meeting
of Stockholders to be held May 20, 1999, which will be filed with the
Securities and Exchange Commission on or prior to April 30, 1999, and which is
incorporated herein by reference.
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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 Accountants
Consolidated Balance Sheet as of December 31, 1998 and 1997
Consolidated Statement of Operations for the three years ended December
31, 1998 Consolidated Statement of Changes in Stockholders' Equity for the
three years ended December 31, 1998 Consolidated Statement of Cash
Flows for the three years ended December 31, 1998 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:
3.1* - Certificate of Incorporation, as amended, of Toreador Royalty
Corporation.
3.2* - Amended and Restated Bylaws, as amended, of Toreador Royalty
Corporation.
3.3 - Amendment to Bylaws of Toreador Royalty Corporation, dated April
21, 1997 (previously filed as Exhibit 3.7 to Toreador Royalty
Corporation Annual Report on Form 10-K for the year ended December
31, 1997, and incorporated herein by reference).
3.4 - Amendment to Bylaws of Toreador Royalty Corporation, dated June 25,
1998 (previously filed as Exhibit 3.1 to Toreador Royalty
Corporation Current Report on Form 8-K filed with the Securities
and Exchange Commission on July 1, 1998, and incorporated herein by
reference).
3.5 - Certificate of Designations of Series A Junior Participating
Preferred Stock of Toreador Royalty Corporation, dated April 3, 1995
(previously filed as Exhibit 3 to Toreador Royalty Corporation
Quarterly Report on Form 10-Q for the quarterly period ended June
30, 1995, and incorporated herein by reference).
3.6 - Certificate of Designation of Series A Convertible Preferred Stock
of Toreador Royalty Corporation, dated December 14, 1998 (previously
filed as Exhibit 10.3 to Toreador Royalty Corporation Current Report
on Form 8-K filed with the Securities and Exchange Commission on
December 31, 1998, and incorporated herein by reference).
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.
4.2 - Rights Agreement, dated as of April 3, 1995, between Toreador
Royalty Corporation and Continental Stock Transfer & Trust Company
(previously filed as Exhibit 1 to Toreador Royalty Corporation
Current Report on Form 8-K filed with the Securities and Exchange
Commission on April 3, 1995, and incorporated herein by reference).
4.3 - Amendment No. 1 to Rights Agreement, dated June 25, 1998, between
Toreador Royalty Corporation and Continental Stock Transfer & Trust
Company (previously filed as Exhibit 99.1 to Toreador Royalty
Corporation Registration on Form 8-A/A filed with the Securities and
Exchange Commission on July 1, 1998, and incorporated herein by
reference).
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31
4.4 - Registration Rights Agreement, effective December 16, 1998, among
Toreador Royalty Corporation and persons party thereto (previously
filed as Exhibit 10.2 to Toreador Royalty Corporation Current Report
on Form 8-K filed with the Securities and Exchange Commission on
December 31, 1998, and incorporated herein by reference).
4.5 - Settlement Agreement, dated June 25, 1998, among the Gralee
Persons, the Dane Falb Persons and Toreador Royalty Corporation
(previously filed as Exhibit 10.1 to Toreador Royalty Corporation
Current Report on Form 8-K filed with the Securities and Exchange
Commission on July 1, 1998, and incorporated herein by reference).
4.6 - Stockholder Voting Agreement, dated June 25, 1998, among the Gralee
Persons, the Dane Falb Persons and Current Management (previously
filed as Exhibit 10.2 to Toreador Royalty Corporation Current Report
on Form 8-K filed with the Securities and Exchange Commission on
July 1, 1998, and incorporated herein by reference).
10.1+ - Form of Stock Option Agreement, between Toreador Royalty
Corporation and Donald E. August, John V. Ballard, J. W. Bullion,
John Mark McLaughlin, and Jack L. Woods (previously filed as
Exhibit 4.6 to Toreador Royalty Corporation Form S-8
(No. 333-14145) filed with the Securities and Exchange Commission
on October 15, 1996, and incorporated herein by reference).
10.2+ - Stock Option Agreement, dated February 17, 1994, between Toreador
Royalty Corporation and Thomas P. Kellogg, Jr. (previously filed as
Exhibit 4.7 to Toreador Royalty Corporation Form S-8 (No. 333-14145)
filed with the Securities and Exchange Commission on October 15,
1996, and incorporated herein by reference).
10.3+ - Form of Stock Option Agreement, between Toreador Royalty
Corporation and Edward C. Marhanka and Earl V. Tessem, as amended
(previously filed as Exhibit 4.8 to Toreador Royalty Corporation
Form S-8 (No. 333-14145) filed with the Securities and Exchange
Commission on October 15, 1996, and incorporated herein by
reference).
10.4+ - Incentive Stock Option, dated as of May 15, 1997, between Toreador
Royalty Corporation and Edward C. Marhanka (previously filed as
Exhibit 10.4 to Toreador Royalty Corporation Quarterly Report on
Form 10-Q for the quarter ended June 30, 1997, and incorporated
herein by reference).
10.5+ - Employment Agreement, dated as of May 1, 1997, between Toreador
Royalty Corporation and Edward C. Marhanka (previously filed as
Exhibit 10.5 to Toreador Royalty Corporation Quarterly Report on
Form 10-Q for the quarter ended June 30, 1997, and incorporated
herein by reference).
10.6* - Joint Venture Agreement, dated March 1, 1989, among Toreador
Royalty Corporation, Bandera Petroleum, et al, as amended.
10.7+ - Toreador Royalty Corporation 1990 Stock Option Plan (previously
filed as Exhibit 10.7 to Toreador Royalty Corporation Annual Report
on Form 10-K for the year ended December 31, 1994, and incorporated
herein by reference).
10.8+ - Amendment to Toreador Royalty Corporation 1990 Stock Option Plan,
effective as of May 15, 1997 (previously filed as Exhibit 10.14 to
Toreador Royalty Corporation Annual Report on Form 10-K for the year
ended December 31, 1997, and incorporated herein by reference).
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32
10.9+ - Toreador Royalty Corporation 1994 Non-Employee Director Stock
Option Plan, as amended (previously filed as Exhibit 10.12 to
Toreador Royalty Corporation Annual Report on Form 10-K for the year
ended December 31, 1995, and incorporated herein by reference).
10.10+ - Toreador Royalty Corporation Amended and Restated 1990 Stock
Option Plan, effective as of September 24, 1998 (previously filed as
Exhibit A to Toreador Royalty Corporation Preliminary Proxy
Statement filed with the Securities and Exchange Commission on March
12, 1999, and incorporated herein by reference).
10.11 - Warrant for the Purchase of Shares of Common Stock issued to
Petrie Parkman & Co., dated May 23, 1994 (previously filed as
Exhibit 10.1 to Toreador Royalty Corporation Registration on Form
S-3, and incorporated herein by reference (No. 33-80572) filed with
the Securities and Exchange Commission on June 22, 1994, and
incorporated herein by reference).
10.12+ - Form of Indemnification Agreement, dated as of April 25, 1995,
between Toreador Royalty Corporation and each of the members of our
Board of Directors (previously filed as Exhibit 10 to Toreador
Royalty Corporation Quarterly Report on Form 10-Q for the quarterly
period ended June 30, 1995, and incorporated herein by reference).
10.13*+ - 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.
10.14*+ - 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.
10.15 - Securities Purchase Agreement, effective December 16, 1998, among
Toreador Royalty Corporation and the Purchasers party thereto
(previously filed as Exhibit 10.1 to Toreador Royalty Corporation
Current Report on Form 8-K filed with the Securities and Exchange
Commission on December 31, 1998, and incorporated herein by
reference).
10.16 - Purchase and Sale Agreement, effective November 1, 1998, between
Howell Petroleum Corporation and the J.T. Philip Company, as amended
(previously filed as Exhibit 10.4 to Toreador Royalty Corporation
Current Report on Form 8-K filed with the Securities and Exchange
Commission on December 31, 1998, and incorporated herein by
reference).
10.17* - Loan Agreement, effective November 13, 1997, between Toreador
Royalty Corporation and Toreador Exploration & Production Inc and
Compass Bank.
10.18* - First Amendment to Loan Agreement, dated September 22, 1998,
between Toreador Royalty Corporation and Toreador Exploration &
Production Inc and Compass Bank.
10.19* - Second Amendment to Loan Agreement, dated December 15, 1998,
between Toreador Royalty Corporation and Toreador Exploration &
Production Inc and Compass Bank.
10.20 - Credit Agreement, effective December 15, 1998, between Compass
Bank and Tormin, Inc. (previously filed as Exhibit 10.5 to Toreador
Royalty Corporation Current Report on Form 8- K filed with the
Securities and Exchange Commission on December 31, 1998, and
incorporated herein by reference).
21.1* - Subsidiaries of Toreador Royalty Corporation.
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33
23.1* - Consent of PricewaterhouseCoopers LLP.
23.2* - Consent of Harlan Consulting.
27.1* - Financial Data Schedule.
- --------------
* Filed herewith.
+ Management contract or compensatory plan
(b) Reports on Form 8-K:
During the last quarter of the fiscal year ended December 31, 1998, we
filed a Current Report on Form 8-K dated December 16, 1998, as amended by
Current Report on Form 8-K/A filed on March 1, 1999, with the Securities and
Exchange Commission to report the acquisition of certain oil, gas and other
mineral and royalty interests from Howell Petroleum Corporation under Items 2
and 7.
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34
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 ROYALTY CORPORATION
Date: April 14, 1999
By: /s/ G. THOMAS GRAVES III
-------------------------------------
G. Thomas Graves III, President,
Chief Executive Officer and Director
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 indicated.
SIGNATURE CAPACITY IN WHICH SIGNED DATE
--------- ------------------------ ----
/s/ G. THOMAS GRAVES III President, Chief Executive Officer and April 14, 1999
- -------------------------------- Director
G. Thomas Graves III
/s/ J.W. BULLION Secretary and Director April 14, 1999
- --------------------------------
J.W. Bullion
/s/ EDWARD NATHAN DANE Director April 14, 1999
- --------------------------------
Edward Nathan Dane
/s/ PETER L. FALB Director April 14, 1999
- --------------------------------
Peter L. Falb
/s/ THOMAS P. KELLOGG, JR Director April 14, 1999
- --------------------------------
Thomas P. Kellogg, Jr.
/s/ WILLIAM I. LEE Director April 14, 1999
- --------------------------------
William I. Lee
/s/ JOHN MARK McLAUGHLIN Chairman and Director April 14, 1999
- --------------------------------
John Mark McLaughlin
/s/ DOUGLAS WEIR Vice President - Finance and Treasurer April 14, 1999
- -------------------------------- (Principal Financial and Accounting Officer)
Douglas Weir
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35
TOREADOR ROYALTY CORPORATION
ITEM 14(a)(1) and (2)
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES
Page
----
Report of Independent Accountants..................................................................... F-2
Financial Statements: ................................................................................
Consolidated Balance Sheet as of December 31, 1998 and 1997.................................. F-3
Consolidated Statement of Operations for the three years ended December 31, 1998............. F-4
Consolidated Statement of Changes in Stockholders' Equity for the three years
ended December 31, 1998.................................................................. F-5
Consolidated Statement of Cash Flows for the three years ended December 31, 1998............. F-7
Notes to Consolidated Financial Statements................................................... F-8
All financial statement schedules have been omitted as all required information
has been included in the consolidated financial statements and notes thereto.
F-1
36
TOREADOR ROYALTY CORPORATION
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders
of Toreador Royalty Corporation
In our opinion, the consolidated financial statements listed in the index
appearing under Item 14(a)(1) and (2) on page F-1 present fairly, in all
material respects, the financial position of Toreador Royalty Corporation and
its subsidiaries at December 31, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.
These financial statements are the responsibility of the Company's management;
our responsibility is to express an opinion on these financial statements based
on our audits. We conducted our audits of these statements in accordance with
generally accepted auditing standards which 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, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for the
opinion expressed above.
PRICEWATERHOUSECOOPERS LLP
Dallas, Texas
April 9, 1999
F-2
37
TOREADOR ROYALTY CORPORATION
CONSOLIDATED BALANCE SHEET
December 31,
-----------------------------
1998 1997
------------ ------------
ASSETS
Current assets:
Cash and cash equivalents............................... $ 726,187 $ 2,876,652
Short term investments.................................. 1,218,291 --
Accounts receivable..................................... 517,442 334,851
Marketable securities................................... 374,915 --
Federal income tax receivable........................... 63,064 62,307
Assets held for sale.................................... 334,489 --
Deferred tax benefit.................................... -- 15,945
Other................................................... 61,130 26,956
------------ ------------
Total current assets.................................. 3,295,518 3,316,711
------------ ------------
Properties and equipment, less accumulated
depreciation, depletion and amortization............ 16,209,631 3,210,074
Other assets................................................ 78,873 --
Deferred tax benefit........................................ 198,240 --
------------ ------------
Total assets.......................................... $ 19,782,262 $ 6,526,785
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities................ $ 587,754 $ 309,590
Current portion of long term debt....................... 720,000 --
------------ ------------
Total current liabilities............................. 1,307,754 309,590
Long term debt.............................................. 7,880,000 --
------------ ------------
Total liabilities..................................... 9,187,754 309,590
------------ ------------
Stockholders' equity:
Preferred stock, $1.00 par value, 4,000,000
shares authorized; 160,000 and 0 issued............ 160,000 --
Common stock, $0.15625 par value, 10,000,000 shares
authorized; 5,644,071 and 5,367,571 shares issued... 881,886 838,683
Capital in excess of par value.......................... 8,202,862 3,646,834
Retained earnings....................................... 2,529,371 2,791,117
Accumulated other comprehensive income (loss)........... (24,922) --
------------ ------------
11,749,197 7,276,634
Treasury stock at cost:
438,400 and 408,400 shares.......................... (1,154,689) (1,059,439)
------------ ------------
Total stockholders' equity............................ 10,594,508 6,217,195
------------ ------------
Total liabilities and stockholders' equity............ $ 19,782,262 $ 6,526,785
============ ============
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
38
TOREADOR ROYALTY CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31,
----------------------------------------------
1998 1997 1996
------------ ------------ ------------
Revenues:
Oil and gas sales............................ $ 1,968,638 $ 2,325,148 $ 2,306,791
Lease bonuses and rentals.................... 168,664 287,604 118,430
Interest and other income.................... 171,338 149,841 162,297
Gain on sale of marketable securities
and other assets..................... -- 26,171 526,567
------------ ------------ ------------
Total revenues 2,308,640 2,788,764 3,114,085
------------ ------------ ------------
Costs and expenses:
Lease operating expense...................... 583,441 695,007 585,732
Dry holes and abandonments................... 133,113 166,710 130,647
Depreciation, depletion and amortization..... 514,071 539,346 273,026
Geological and geophysical................... 517,870 546,634 227,744
General and administrative................... 999,548 802,723 907,086
Loss on settlement of benefit plans.......... -- 173,971 --
Interest expense............................. 36,120 -- --
------------ ------------ ------------
Total costs and expenses................... 2,784,163 2,924,391 2,124,235
------------ ------------ ------------
Net income (loss) before federal income taxes.... (475,523) (135,627) 989,850
Provision (benefit) for federal income taxes..... (233,277) (84,261) 263,100
------------ ------------ ------------
Net income (loss)................................ (242,246) (51,366) 726,750
------------ ------------ ------------
Dividends on preferred shares.................... 19,500 -- --
------------ ------------ ------------
Net income (loss) applicable to common shares.... $ (261,746) $ (51,366) $ 726,750
============ ============ ============
Basic income (loss) per share.................... $ (0.05) $ (0.01) $ 0.14
============ ============ ============
Diluted income (loss) per share.................. $ (0.05) $ (0.01) $ 0.14
============ ============ ============
Weighted average shares outstanding
Basic............................................ 5,125,063 5,022,216 5,216,941
Diluted.......................................... 5,125,063 5,022,216 5,216,941
See accompanying notes to the consolidated financial statements.
F-4
39
TOREADOR ROYALTY CORPORATION
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
ACCUMULATED
CAPITAL IN OTHER
PREFERRED COMMON STOCK EXCESS OF RETAINED COMPREHENSIVE
STOCK SHARES AMOUNT PAR VALUE EARNINGS INCOME (LOSS)
--------- ----------- ----------- ---------- ----------- -----------
Balance at December 31, 1995 ............... $ -- 5,349,071 $ 835,792 $3,560,042 $ 2,115,733 $ 353,268
Issuance of common stock ................... -- 7,500 1,172 17,343 -- --
Purchase of treasury stock ................. -- -- -- -- -- --
Comprehensive income
Net income .............................. -- -- -- -- 726,750 --
Other comprehensive income, net of tax
Unrealized (losses) on securities ....
Minimum pension liability ............
Other comprehensive income .............. (441,811)
Comprehensive income .......................
--------- ----------- ----------- ---------- ----------- -----------
Balance at December 31, 1996 ............... -- 5,356,571 836,964 3,577,385 2,842,483 (88,543)
Issuance of common stock ................... -- 11,000 1,719 69,449 --
Purchase of treasury stock ................. -- -- -- -- --
Comprehensive income
Net loss ................................ -- -- -- -- (51,366) --
Other comprehensive income, net of tax
Minimum pension liability ............
Other comprehensive income .............. 88,543
Comprehensive income .......................
--------- ----------- ----------- ---------- ----------- -----------
Balance at December 31, 1997 ............... -- 5,367,571 838,683 3,646,834 2,791,117 --
Issuance of common stock ................... -- 276,500 43,203 766,809 --
Issuance of preferred stock ................ 160,000 -- -- 3,789,219 --
Dividends on preferred stock ............... -- -- -- -- (19,500)
Purchase of treasury stock ................. -- -- -- -- --
Comprehensive income (loss)
Net loss ................................ -- -- -- -- (242,246) --
Other comprehensive income (loss), net of tax
Unrealized (losses) on securities .... (24,922)
Other comprehensive income (loss)........
Comprehensive income (loss).................
--------- ----------- ----------- ---------- ----------- -----------
Balance at December 31, 1998 ............... $ 160,000 5,644,071 $ 881,886 $8,202,862 $ 2,529,371 $ (24,922)
========= =========== =========== ========== =========== ===========
TOTAL
COMPREHENSIVE TREASURY STOCKHOLDERS'
INCOME (LOSS) STOCK EQUITY
------------- ------------ -------------
Balance at December 31, 1995 ............... $ (54,350) 6,810,485
Issuance of common stock ................... -- -- 18,515
Purchase of treasury stock ................. -- (489,759) (489,759)
Comprehensive income
Net income .............................. $ 726,750 -- 726,750
-----------
Other comprehensive income, net of tax
Unrealized (losses) on securities .... (353,268) (353,268)
Minimum pension liability ............ (88,543) (88,543)
-----------
Other comprehensive income (loss) ....... (441,811)
-----------
Comprehensive income ....................... 284,939
===========
--------- -----------
Balance at December 31, 1996 ............... (544,109) 6,624,180
-----------
Issuance of common stock ................... -- 71,168
Purchase of treasury stock ................. -- (515,330) (515,330)
Comprehensive income (loss)
Net loss ................................ (51,366) -- (51,366)
-----------
Other comprehensive income, net of tax
Minimum pension liability ............ 88,543 88,543
-----------
Other comprehensive income (loss) ....... 88,543
-----------
Comprehensive income ....................... 37,177
===========
------------ -----------
Balance at December 31, 1997 ............... (1,059,439) 6,217,195
Issuance of common stock ................... -- 810,012
Issuance of preferred stock ................ -- -- 3,949,219
Dividends on preferred stock ............... -- -- (19,500)
Purchase of treasury stock ................. -- (95,250) (95,250)
Comprehensive income
Net loss ................................ (242,246) -- (242,246)
-----------
Other comprehensive income, net of tax
Unrealized (losses) on securities .... (24,922) (24,922)
-----------
Other comprehensive income ........... (24,922)
-----------
Comprehensive income ....................... (267,168)
===========
------------ -----------
Balance at December 31, 1998 ............... $ (1,154,689) $10,594,508
============ ===========
F-5
40
TOREADOR ROYALTY CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31,
------------------------------------------
1998 1997 1996
------------ ------------- ------------
Cash flows from operating activities:
Net income (loss) .............................................. $ (242,246) $ (51,366) $ 726,750
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, depletion and amortization ..................... 514,071 539,346 273,026
Dry holes and abandonments ................................... 133,113 166,710 130,647
Gain on sale of marketable securities and other assets ....... -- (26,171) (526,567)
Decrease (increase) in accounts receivable ................... (182,591) 173,942 (340,047)
Decrease (increase) in federal income tax receivable ........ (757) (7,408) 32,551
Decrease in pension obligation ............................... -- 88,543 29,782
Decrease (increase) in other current assets .................. (34,174) 38,145 (42,929)
Increase in accounts payable and accrued liabilities ......... 258,664 53,290 63,060
Increase (decrease) in federal income taxes payable .......... -- (62,938) 62,938
Deferred tax expense (benefit) ............................... (169,456) (81,453) 200,161
------------ ------------ ------------
Net cash provided by operating activities .................... 276,624 830,640 609,372
------------ ------------ ------------
Cash flows from investing activities:
Expenditures for oil and gas property and equipment ........... (797,438) (717,478) (893,426)
Acquisition of oil and gas properties ......................... (13,154,543) -- --
Proceeds from lease bonuses and rentals ....................... -- 77,583 415,074
Purchase of short term investments ............................ (1,218,291) -- --
Purchases of marketable securities ............................ (412,676) -- --
Proceeds from sale of marketable securities and other assets .. -- 56,065 652,826
Purchase of furniture and fixtures ............................ (29,249) (107) (30,066)
------------ ------------ ------------
Net cash provided (used) by investing activities .............. (15,612,197) (583,937) 144,408
------------ ------------ ------------
Cash flows from financing activities:
Payment for debt issue costs ................................... (78,873) -- --
Proceeds from issuance of common stock ......................... 810,012 71,168 18,515
Proceeds from issuance of preferred stock, net ................. 3,949,219 -- --
Proceeds from credit facilities ................................ 8,600,000 -- --
Purchase of treasury stock ..................................... (95,250) (515,330) (489,759)
------------ ------------ ------------
Net cash provided (used) by financing activities ............... 13,185,108 (444,162) (471,244)
------------ ------------ ------------
Net increase (decrease) in cash and cash equivalents ............... (2,150,465) (197,459) 282,536
Cash and cash equivalents, beginning of year ....................... 2,876,652 3,074,111 2,791,575
------------ ------------ ------------
Cash and cash equivalents, end of year ............................. $ 726,187 $ 2,876,652 $ 3,074,111
============ ============ ============
Supplemental schedule of cash flow information:
Cash paid (received) during the period for:
Income taxes .................................................... $ (63,064) $ 4,475 $ --
See accompanying notes to the consolidated financial statements.
F-6
41
TOREADOR ROYALTY CORPORATION
Notes to Consolidated Financial Statements
1. BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES
Toreador Royalty Corporation (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, Alabama, New Mexico,
Oklahoma, Louisiana and Arkansas. The Company's business activities
are with industry partners located within the United States.
PERVASIVENESS OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results
could differ from those estimates.
CONSOLIDATION
The consolidated financial statements include the accounts of
Toreador Royalty Corporation and its wholly-owned subsidiaries,
Toreador Exploration & Production Inc. and Tormin, Inc. All
intercompany accounts and transactions have been eliminated. Tormin,
Inc. was formed in 1998 and therefore has not been included in
previous periods' consolidated financial statements.
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.
SHORT TERM INVESTMENTS AND MARKETABLE SECURITIES
Short term investments include amounts held in managed funds which
invest in securities scheduled to mature within 12 months or less.
These investments are carried at cost which approximates fair value.
Marketable debt and equity securities are reported at fair value,
except for those debt securities that management has the intent and
ability to hold to maturity. 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. Trading
investments are classified as current assets and changes in fair value
are reported in the statement of operations.
F-7
42
TOREADOR ROYALTY CORPORATION
Notes to Consolidated Financial Statements
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 which do not
find proved reserves are expensed. Significant costs associated with
the acquisition of oil and gas properties are capitalized. Upon sale
or abandonment of units of property or the disposition of
miscellaneous equipment, the cost is removed from the asset account,
the related reserves relieved of the accumulated depreciation or
depletion and the gain or loss is credited to or charged against
operations. Maintenance and repairs are charged to expense;
betterments of property are capitalized and depreciated as described
below.
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 nonproducing 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 an impairment during 1998 on producing properties
in the amount of $19,649 primarily due to the decrease in oil and gas
prices. The impairment is included in the "Depreciation, depletion
and amortization" category of the consolidated statement of
operations.
REVENUE RECOGNITION
Oil and natural 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, 1998 and 1997, the imbalance and related value were
immaterial.
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).
F-8
43
TOREADOR ROYALTY CORPORATION
Notes to Consolidated Financial Statements
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, 1998 and 1997.
INCOME TAXES
Deferred tax assets and liabilities are recognized for the
anticipated future tax effects of temporary differences between the
financial statement basis and the tax basis of the Company's assets
and liabilities using enacted tax rates in effect at year end. A
valuation allowance for deferred tax assets is recorded when it is
more likely than not that the benefit from the deferred tax asset
will not be realized.
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 PER COMMON SHARE
Basic earnings (loss) per common share amounts were computed by
dividing net income (loss) after deduction of dividends on preference
shares by the weighted average number of common shares outstanding
during the period. Diluted earnings (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. There were no differences in the
weighted average common shares used in the basic and diluted earnings
per share computations due to antidilution.
2. ACQUISITION OF OIL AND GAS PROPERTIES
On December 16, 1998, Tormin, Inc., a wholly owned subsidiary of
Toreador Royalty Corporation purchased, effective November 1, 1998,
certain oil, gas and other mineral and royalty interests located in
Alabama, Louisiana and Mississippi (the "Properties") from Howell
Petroleum Corporation ("Howell"), a wholly owned subsidiary of Howell
Corporation, pursuant to a Purchase and Sale Agreement (the "Howell
Agreement") dated October 28, 1998 by and between Howell and J.T.
Philp Company ("JTP"). Tormin acquired JTP's rights under the Howell
Agreement through an assignment of JTP's rights and paid a transaction
fee of 1.5% of the purchase price of the Properties.
The purchase price for the Properties before adjustments was $13
million. The Properties are comprised of approximately 1,775,000 gross
(876,000 net) acres. Producing interests, which make up approximately
2% of the total net acres, are held in approximately 400 oil and gas
wells. The acquisition of the Properties was accounted for under the
purchase method and closed on December 16, 1998. The allocation of the
purchase price is presented below:
F-9
44
TOREADOR ROYALTY CORPORATION
Notes to Consolidated Financial Statements
Purchase Price..................................................... $ 13,000,000
Purchase price adjustments, including:
Distributions of cash flows generated from lease bonuses from
October 15, 1998 to the closing date, December 16, 1998........ (68,250)
Net oil and gas revenue earned from November 1, 1998 to the
closing date, December 16, 1998................................ (157,462)
Other acquisition costs........................................ 380,255
-------------
Total Purchase Price.... $ 13,154,543
=============
Purchase Allocation :
Producing royalty interests.................................... 5,883,911
Undeveloped mineral and royalty interests...................... 7,270,632
-------------
Total Purchase Price.... $ 13,154,543
=============
The purchase price was allocated to producing royalty interests and
undeveloped mineral and royalty interests based upon engineering
estimates.
The purchase price of the Properties was funded with proceeds received
from a private placement of $4 million of the Company's Series A 9%
Convertible Preferred Stock (the "Preferred Securities"), utilization of
Company's existing credit facility ($2.7 million), utilization of a
new term facility ($5.9 million), and cash on hand. See notes 13 and 15
for further discussion regarding these financial instruments.
The following summarized unaudited pro forma financial information assumes
the acquisition of the Properties occurred on January 1 of each year:
YEAR ENDED DECEMBER 31,
-------------------------
1998 1997
---- ----
Revenues................................... $4,093,757 $5,816,317
Net income................................. $ 231,982 $1,024,506
Net income applicable to common shares..... $ (128,018) $ 664,506
Net income per share - basic............... $ (.02) $ .13
Net income per share - diluted............. $ (.02) $ .13
The pro forma results do not necessarily represent results that would have
occurred if the transaction had taken place on the basis assumed above,
nor are they indicative of the results of future combined operations.
3. MARKETABLE SECURITIES
During 1996, the Company sold all shares in the San Juan Basin Royalty
Trust for proceeds of $643,125 resulting in a gain of $516,867.
Marketable securities at December 31,1998 consist of several issues of
preferred stock with a fair market value of $374,915 as of December 31,
1998. The net unrealized loss related to these securities before taxes is
$37,761 ($24,922 net of tax). The Company has designated these investments
as "securities available for sale" pursuant to Statement of Financial
Accounting Standards No. 115.
F-10
45
TOREADOR ROYALTY CORPORATION
Notes to Consolidated Financial Statements
4. ACCOUNTS RECEIVABLE
Accounts receivable consist of the following:
DECEMBER 31,
----------------------------
1998 1997
----------- -----------
Oil and gas............................... $ 417,442 $ 334,851
Receivable from preferred shareholders.... 100,000 --
----------- -----------
$ 517,442 $ 334,851
=========== ===========
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 receivable from preferred
shareholders was received in January 1999.
5. PROPERTIES AND EQUIPMENT
Properties and equipment consist of the following:
DECEMBER 31,
---------------------------
1998 1997
------------ ------------
Undeveloped mineral and royalty interests ............. $ 7,270,632 $ 334,489
Nonproducing leaseholds ............................... 122,267 26,911
Producing leaseholds .................................. 3,607,307 3,152,332
Producing royalty interests ........................... 7,306,423 1,422,512
Lease and well equipment .............................. 417,382 303,388
Furniture and fixtures and other assets ............... 108,268 79,019
------------ ------------
18,832,279 5,318,651
Accumulated depreciation, depletion and amortization .. (2,622,648) (2,108,577)
------------ ------------
$ 16,209,631 $ 3,210,074
============ ============
6. ASSETS HELD FOR SALE
Assets held for sale consist of undeveloped mineral and royalty interests
which the Company is currently marketing. In January 1999 the Company
sold a portion of the acreage for $750,000 resulting in a gain of $356,187
net of tax and closing costs.
F-11
46
TOREADOR ROYALTY CORPORATION
Notes to Consolidated Financial Statements
7. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
Accounts payable and accrued liabilities consist of the following:
DECEMBER 31,
-----------------------------
1998 1997
----------- -----------
Professional fees.......................................... $ 6,980 $ 3,251
Lease operating expense.................................... 94,290 92,430
Trade accounts payable..................................... 140,809 19,894
Brokerage fees............................................ 45,516 --
Drilling costs............................................. 40,130 194,015
Howell acquisition costs................................... 260,029 --
----------- -----------
$ 587,754 $ 309,590
=========== ===========
8. INTEREST AND OTHER INCOME
Interest and other income consists of:
YEAR ENDED DECEMBER 31,
---------------------------------------
1998 1997 1996
---------- ---------- ---------
Interest - Certificates of deposit
U.S. Treasury bills, and money market accounts....... $ 152,789 $ 147,237 $ 138,720
Distribution from San Juan Basin Royalty Trust................ -- -- 12,253
Dividends from marketable securities.......................... 7,720 -- --
Other......................................................... 10,829 2,604 11,324
---------- ---------- ---------
$ 171,338 $ 149,841 $ 162,297
========== ========== =========
9. GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative expenses incurred by the Company are as
follows:
YEAR ENDED DECEMBER 31,
----------------------------------------
1998 1997 1996
------------ ------------ ------------
Salaries .............................. $ 208,226 $ 213,000 $ 327,277
Professional fees ..................... 329,481 161,745 139,794
Insurance ............................. 49,338 57,730 57,005
Retirement expense .................... 9,992 69,188 69,050
Rent expense .......................... 43,676 34,297 30,913
Directors' fees and travel expenses ... 75,988 78,963 40,334
Shareholder relations ................. 122,688 53,126 77,166
Travel and entertainment .............. 8,613 21,800 52,726
Telephone and utilities ............... 19,755 16,588 19,908
Taxes, other than income .............. 35,268 37,747 38,285
Other ................................. 96,523 58,539 54,628
------------ ------------ ------------
$ 999,548 $ 802,723 $ 907,086
============ ============ ============
F-12
47
TOREADOR ROYALTY CORPORATION
Notes to Consolidated Financial Statements
10. INCOME TAXES
The Company's provision (benefit) for income taxes was comprised of the
following:
YEAR ENDED DECEMBER 31,
------------------------------------
1998 1997 1996
---------- ---------- ----------
Federal:
Current ....................... $ (63,821) $ (2,808) $ 62,939
Deferred ...................... (169,456) (81,453) 200,161
---------- ---------- ----------
Provision (benefit) for income taxes ... $ (233,277) $ (84,261) $ 263,100
========== ========== ==========
The primary reasons for the difference between tax expense at the
statutory federal income tax rate and the Company's provision for income
taxes were:
YEAR ENDED DECEMBER 31,
------------------------------------------
1998 1997 1996
------------ ------------ ------------
Theoretical tax at 34% ...................... $ (161,678) $ (46,113) $ 336,703
Surtax or rate difference ................... -- (958) (8,973)
Statutory depletion in excess of tax basis .. (69,979) (38,013) (64,317)
Other ....................................... (1,620) 823 (313)
------------ ------------ ------------
Provision (benefit) for income taxes ........ $ (233,277) $ (84,261) $ 263,100
============ ============ ============
Net operating loss generated in 1995 totaling $516,064 was carried
forward and used in 1996. In 1998, the net operating loss for tax
purposes totaled $641,176, of which $185,482 will be carried back to
be used against prior year taxable income. The remaining net operating
loss will be carried forward to be used against future taxable income.
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, 1998 and 1997 were as follows:
1998 1997
------------ ------------
Deferred tax liabilities:
Intangible drilling and development costs ......... $ (210,104) $ (117,774)
Lease and well equipment .......................... (13,949) (12,619)
Leasehold costs ................................... (2,260) (16,596)
------------ ------------
Gross deferred tax liabilities ........... (226,313) (146,989)
------------ ------------
Deferred tax assets:
Depletion carryforwards ........................... 115,172 49,528
Net operating tax loss carryforward ............... 154,936 --
Geological and geophysical costs
78,179 53,832
Alternative minimum tax credit carryforwards ...... 63,427 59,574
Unrealized loss on marketable securities .... 12,839 --
------------ ------------
Gross deferred tax assets................. 424,553 162,934
------------ ------------
Net deferred tax assets .................................... $ 198,240 $ 15,945
============ ============
F-13
48
TOREADOR ROYALTY CORPORATION
Notes to Consolidated Financial Statements
Of the change in deferred taxes, $12,839 was credited to net
unrealized loss on marketable securities in stockholders' equity for 1998.
The tax credit carryforwards and depletion carryforwards are available
indefinitely.
11. BENEFIT PLANS
The Company has a noncontributory defined benefit pension plan which
covers all Company employees. The benefits are based on years of service
and the employee's compensation. Contributions are intended to provide not
only for benefits attributed to service to date but also for those
expected to be earned in the future.
In 1996, the Company established a Supplemental Executive Retirement Plan
("SERP") covering certain key employees. The SERP provides for incremental
pension payments from the Company's funds so that retirement benefit
payments are equal to amounts that would have been payable from the
Company's principal pension plan if it were not for limitations on those
payments imposed by income tax regulations.
During 1997, the Company settled its benefit plan obligations with certain
employees resulting in a loss of $173,971 which has been recorded as a
loss on settlement of benefit plans in the consolidated statement of
operations. The loss consists of a 100% settlement of the pension benefit
for $87,654 and a payment of $88,617 for settlement of the SERP. The loss
is primarily attributable to the settlement of benefit plans upon the
resignation of the then Chairman and Chief Executive Officer of the
Company.
The status of the pension plan follows:
Change in benefit obligation:
1998 1997
------------ ------------
Benefit obligation at beginning of year........... $ 4,365 $ 463,933
Service cost...................................... 13,825 55,212
Interest on pension benefit obligation............ 306 15,401
Actuarial loss (gain)............................. 7,068 (42,340)
Benefits paid..................................... -- (487,841)
------------ ------------
Benefit obligation at end of year................. $ 25,564 $ 4,365
Change in plan assets:
Fair value of plan assets at beginning of year.... $ 5,020 $ 387,158
Actual return on plan assets...................... 1,477 25,777
Employer contributions............................ 27,750 79,927
Benefits paid..................................... -- (487,842)
------------ ------------
Fair value of plan assets at end of year.......... 34,247 5,020
------------ ------------
Funded status..................................... 8,683 655
Unrecognized net actuarial loss................... 6,914 104,902
------------ ------------
Prepaid pension cost.............................. $ 15,597 $ 105,557
============ ============
F-14
49
TOREADOR ROYALTY CORPORATION
Notes to Consolidated Financial Statements
Weighted average assumptions at measurement date:
1998 1997
---- ----
Discount rate 7% 7%
Expected long-term rate of return on assets 7% 7%
Rate of increase in compensation levels 3% 3.5%
The following table sets forth the net periodic costs for the plan as of
December 31, 1998, 1997 and 1996:
1998 1997 1996
------------ ------------ ------------
Service cost........................... $ 13,825 $ 55,212 $ 54,452
Interest cost.......................... 306 15,401 26,828
Expected return on assets.............. (1,323) (12,824) (25,899)
Amortization of transition (asset)..... -- (2,875) (2,874)
Recognized net actuarial loss (gain)... -- 8,129 8,211
------------ ------------ ------------
$ 12,808 $ 63,043 $ 60,718
============ ============ ============
12. LEASE AND OTHER COMMITMENTS
In November 1993, the Company signed a lease agreement to lease new office
space for a period of sixty-three months, beginning January 6, 1994 and
ending March 31, 1999. Rentals paid in 1999 through the termination of the
lease were $9,561.
13. LONG TERM DEBT
In November 1997, the Company obtained a $10,000,000 credit facility (the
"Facility"). In December 1998, the Company borrowed $2,700,000 against the
Facility which was used to finance the Howell Mineral Acquisition. The
Company obtained an additional $5,900,000 term loan (the "Loan") which was
used in this acquisition. As of December 31, 1998, the outstanding balance
of the facility and loan were $2,700,000 and $5,900,000, respectively.
The Facility is a revolving line of credit collateralized by various oil
and gas interests owned by the Company. The interest rate is equal to the
prime rate as long as the amount borrowed is greater than 80% of the
borrowing base as defined by the lender ($2,700,000 at December 31, 1998).
The rate will drop to prime less one-half percent if the amount borrowed
drops below 80% of the borrowing base. In addition the Facility has a
commitment fee of .375% per annum on unused amounts and a letter of credit
fee of .875% per annum. The interest rate on the Facility at December 31,
1998 was 7.5%, and the Company is currently not subject to any fees. The
maturity date is October 1, 2000.
The Facility contains various affirmative and negative covenants. These
covenants, among other things, limit additional indebtedness, the sale of
assets and the payment of dividends on common stock, change of control and
management and require us to meet certain financial requirements.
Specifically, the Company must maintain a current ratio of 1.00 to 1.00
and a debt service coverage ratio of not less than 1.25 to 1.00.
The Loan is a credit agreement collateralized by various oil and gas
interests owned by the Company. The interest rate is equal to the prime
rate plus one-quarter percent. The interest rate on the loan was 7.75% at
December 31,1998. The maturity date is June 1, 2000.
F-15
50
TOREADOR ROYALTY CORPORATION
Notes to Consolidated Financial Statements
The Loan contains various affirmative and negative covenants. These
covenants, among other things, limit additional indebtedness, the sale of
assets and the payment of dividends, change of control and management and
require Tormin to meet certain financial requirements. Specifically, Tormin
must maintain a current ratio of 1.25 to 1.00 after deducting the current
portion of the Loan and general and administrative costs are limited to
$50,000 per each calendar quarter. Tormin is committed to repay interest on
a monthly basis plus principal equal to the greater of 95% of net cash flow
or $60,000.
Each of the above described debt issues is controlled by its respective
borrowing bases. The amount of debt outstanding at any time is not allowed
to exceed the borrowing base as determined by the lender. The borrowing
base is subject to evaluation every six months and can be adjusted either
up or down. The Company and Tormin are required to repay any principal
which exceeds the revised borrowing base.
Aggregate principal reductions are as follows for each year ended December
31:
1999 ...............$ 720,000
2000 ............... 7,880,000
The Company is currently negotiating to extend the payment terms of the
Loan.
14. STOCK COMPENSATION PLANS
The Company has granted stock options to key employees, directors and
certain consultants of the Company which are 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 and subject to shareholder approval 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.
In September 1998, our board of directors authorized Toreador to enter into
stock option agreements with G. Thomas Graves III and John Mark McLaughlin
under the Amended and Restated Stock Option Plan, subject to stockholder
approval of the Amended and Restated Stock Option Plan, for options to
purchase 250,000 and 45,000 shares of common stock, respectively.
Pursuant to SFAS No. 123, the Company recorded an expense of $19,747 and
$44,011 during 1998 and 1997, respectively, for stock options granted to
certain consultants to the Company.
F-16
51
TOREADOR ROYALTY CORPORATION
Notes to Consolidated Financial Statements
A summary of stock option transactions are as follows:
1998 1997 1996
-------- ------- ---------
WEIGHTED- WEIGHTED- WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
-------- --------- ------- --------- --------- ---------
Outstanding at beginning of year .... 469,000 $ 2.97 452,500 $ 3.16 470,000 $ 3.15
Granted ............................. 340,000 4.38 117,500 2.50 -- --
Exercised ........................... (276,500) 2.86 (11,000) 2.47 (7,500) 2.47
Forfeited ........................... (70,000) 3.11 (90,000) 3.36 (10,000) 3.25
-------- --------- ------- --------- --------- ---------
Outstanding at end of year .......... 462,500 $ 4.05 469,000 $ 2.97 $ 452,500 $ 3.16
======== ========= ======= ========= ========= =========
Exercisable at end of year .......... 100,833 $ 3.28 411,500 $ 3.02 402,500 $ 3.13
======== ========= ======= ========= ========= =========
For stock options granted during 1998 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:
Option type Weighted- Weighted-Average
Average Fair
Exercise Price Value
-------------- -------------
Exercise price greater than market price.....$ 5.00 $ .35
Exercise price less than market price........ 2.75 1.11
Exercise price equal to market price......... 2.50 .92
The following table summarizes information about the fixed price stock options
outstanding at December 31, 1998:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------------------------- ----------------------------------------------------
WEIGHTED
AVERAGE WEIGHTED WEIGHTED
RANGE OF NUMBER REMAINING AVERAGE NUMBER AVERAGE
EXERCISE OUTSTANDING CONTRACTUAL EXERCISE EXERCISABLE EXERCISE
PRICES AT 12/31/98 LIFE PRICE AT 12/31/98 PRICE
--------------- ------------ ----------- ------------ ---------- ------------
$ 2.50 72,500 7.1 Years $ 2.50 20,833 $ 2.50
2.75 60,000 9.8 Years 2.75 0 0
3.25 - 3.50 50,000 5.7 Years 3.40 50,000 3.40
3.63 30,000 2.4 Years 3.63 30,000 3.63
5.00 250,000 9.8 Years 5.00 0 0
--------------- ------------ ----------- ------------ ---------- ------------
$ 2.50 - 5.00 462,500 8.4 Years $ 4.05 100,833 $ 3.28
=============== ============ =========== ============ ========== ============
At December 31, 1998, 202,500 shares were available for grant under the Plan
and 140,000 shares were available for grant as options under the Nonemployee
Director Plan.
F-17
52
TOREADOR ROYALTY CORPORATION
Notes to Consolidated Financial Statements
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:
1998 1997 1996
----------- ----------- ----------
Net income (loss) As reported $ (242,246) $ (51,366) $ 726,750
Pro forma $ (272,077) $ (82,515) $ 726,750
Basic earnings per share As reported $ (0.05) $ (0.01) $ 0.14
Pro forma $ (0.05) $ (0.02) $ 0.14
Diluted earnings per share As reported $ (0.05) $ (0.01) $ 0.14
Pro forma $ (0.05) $ (0.02) $ 0.14
There were no options granted during 1996. The fair value of each option
granted during 1997 is estimated on the date of grant using the
Black-Scholes Option-Pricing model with the following assumptions
respectively: dividend yield of $0/share; expected volatility of 39%;
risk-free interest rate of 6.4%; and expected lives of 5 years. The fair
value of each option granted during 1998 is estimated on the date of grant
using the Black-Scholes Option-Pricing model with the following
assumptions respectively: dividend yield of $0/; expected volatility of
27%; risk-free interest rate of 6.4%; and expected lives of 5 years.
15. 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.
The Company adopted a stockholder rights plan on April 3, 1995 designed to
assure that the Company's stockholders receive fair and equal treatment in
the event of any proposed takeover of the Company and to guard against
partial tender offers and other abusive takeover tactics to gain control
of the Company without paying all stockholders a fair price. Under the
rights plan, the Company declared a dividend of one right ("Right") on
each share of Company common stock. Each Right will entitle the holder to
purchase one one-hundredth of a share of a new Series A Junior
Participating Preferred Stock, par value $1.00 per share, at an exercise
price of $12.00. The Rights are not currently exercisable and will become
exercisable only in the event a person or group acquires beneficial
ownership of 20 percent or more of Toreador's outstanding common stock or
announces a tender offer or exchange offer to acquire such ownership
level. The Rights are subject to redemption by the Company for $.01 per
Right at any time prior to the tenth day after the first public
announcement of the acquisition by any person or group of beneficial
ownership of 20 percent or more of Company common stock. The dividend
distribution was made on April 13, 1995 to stockholders of record at the
close of business on that date. The rights will expire on April 13, 2005.
F-18
53
TOREADOR ROYALTY CORPORATION
Notes to Consolidated Financial Statements
In October 1995, the Company's Board of Directors authorized the repurchase
of up to 100,000 shares of the Company's common stock. This repurchase was
completed in April 1996. In April 1996, the Company's Board of Directors
authorized the repurchase of an additional 150,000 shares of the Company's
common stock. This repurchase was completed in April 1997.
In April 1997, the Company's board of directors authorized the repurchase
of an additional 300,000 shares of the Company's common stock. On July 23,
1998, the Company's board of directors suspended the policy of share
repurchases for the time being to instead use the Company's excess cash
resources toward funding the Company's participation in third party
operated 3-D projects or drilling prospects and acquisition of producing
oil and gas properties. On March 23, 1999, the Company's board of directors
reinstated the 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. As of
December 31, 1998, the Company had repurchased 182,700 shares of its common
stock under the third repurchase program. 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 for $4,000,000. 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 Howell mineral acquisition.
Under the original agreement, the Company was required to redeem all
outstanding Series A Preferred Stock on December 1, 2008. On March 15,
1999, the Company and the holders of the Series A Preferred Stock agreed to
remove the mandatory redemption feature in exchange for certain other
modifications. As a result, the Series A Preferred Stock has been
classified as a component of equity at December 31, 1998.
16. RELATED PARTY TRANSACTIONS
The Company entered into a technical services agreement with Wilco
Properties, Inc. ("Wilco") effective October 1, 1998 whereby Wilco
provides accounting and geological management services for a monthly fee
of $7,250. The Company cancelled the technical services agreement in
February 1999 and entered into a new technical services agreement whereby
the Company employed the Wilco personnel directly and agreed to provide
accounting and geological management services to Wilco for a monthly fee
of $7,250.
17. OIL AND GAS INFORMATION (UNAUDITED)
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:
1998 1997 1996
------------ ------------ ------------
Crude oil, condensate and natural gas ............ $ 1,968,638 $ 2,325,148 $ 2,306,791
Lease bonuses and delay rentals .................. 168,664 287,604 118,430
------------ ------------ ------------
Total revenues .......................... 2,137,302 2,612,752 2,425,221
------------ ------------ ------------
Costs and expenses:
Lease operating costs ................... 583,441 695,007 585,732
Exploration costs ....................... 650,983 713,344 358,391
Depreciation and depletion .............. 510,775 539,346 273,026
------------ ------------ ------------
Income before income taxes ....................... 392,103 665,055 1,208,072
Income tax expense ............................... 133,315 226,119 410,744
------------ ------------ ------------
Results of operations from producing activities
(excluding corporate overhead)........... $ 258,788 $ 438,936 $ 797,328
============ ============ ============
F-19
54
TOREADOR ROYALTY CORPORATION
Notes to Consolidated Financial Statements
CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES:
DECEMBER 31,
------------------------------------------
1998 1997 1996
------------ ------------ ------------
Unproved properties (a) ................ $ 7,727,388 $ 361,400 $ 457,861
Proved leaseholds ...................... 10,913,730 4,574,844 4,161,956
Lease and well equipment ............... 417,382 303,388 151,243
------------ ------------ ------------
19,058,500 5,239,632 4,771,060
------------ ------------ ------------
Less: Accumulated depreciation,
depletion and amortization ... (2,608,905) (2,036,912) (1,507,553)
------------ ------------ ------------
Capitalized costs ...................... $ 16,449,595 $ 3,202,720 $ 3,263,507
============ ============ ============
(a) Unproved properties for 1998 includes $334,489 classified as "Assets
held for sale".
COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION, AND
DEVELOPMENT ACTIVITIES:
1998 1997 1996
----------- ---------- ----------
Acquisition of properties
Proved...................................... $ 5,883,911 $ 192,670 $ 371,761
Unproved.................................... 7,365,988 56,245 69,838
Exploration costs............................... 133,113 166,710 130,647
Development costs............................... 568,969 301,853 321,180
----------- ---------- ----------
Costs incurred.................................. $13,951,981 $ 717,478 $ 893,426
=========== ========== ==========
OIL AND GAS RESERVES
The following table identifies the Company's net interest in estimated
quantities of proved oil and gas reserves and changes in such estimated
quantities. Reserve estimates were prepared by independent petroleum engineers
and such estimates were reviewed by Company management. 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, 1997 and 1996 are tabulated below. Crude oil includes
condensate and natural gas liquids and is stated in barrels (bbl). Natural gas
is stated in thousands of cubic feet (mcf).
F-20
55
TOREADOR ROYALTY CORPORATION
Notes to Consolidated Financial Statements
OIL(BBL) GAS(MCF)
------------ ------------
PROVED DEVELOPED AND UNDEVELOPED RESERVES
December 31, 1995 ................................ 569,281 2,607,436
Purchases of reserves in place ................... 219,268 266,899
Revisions of previous estimates .................. 35,082 372,202
Extensions, discoveries, and other additions ..... 35,959 154,942
Production ....................................... (68,318) (348,539)
------------ ------------
December 31, 1996 ................................ 791,272 3,052,940
Purchases of reserves in place ................... 5,410 265,316
Revisions of previous estimates .................. (317,393) (471,860)
Extensions, discoveries, and other additions ..... 143,792 143,998
Production ....................................... (69,903) (425,854)
------------ ------------
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
============ ============
PROVED DEVELOPED RESERVES
December 31, 1997 ................................ 501,726 2,487,574
============ ============
December 31, 1998 ................................ 1,095,798 8,631,968
============ ============
There were no proved undeveloped reserves at December 31, 1996 .
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS REVENUES
Pursuant to SFAS No. 69, the Company has developed the following information
titled "Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Quantities" (Standardized Measure). Accordingly, the
Standardized Measure has been prepared assuming year-end selling prices
adjusted for future fixed and determinable contractual price changes, year-end
development and production costs, year-end statutory tax rates adjusted for
future tax rates already legislated and a 10% annual discount rate. The
Standardized Measure does not purport to be an estimate of the fair market
value of the Company's reserves. An estimate of fair value would also have
taken into account, among other things, the expected recovery of reserves in
excess of proved reserves, anticipated changes in future prices and costs and a
discount factor representative of the time value of money and risks inherent in
producing oil and gas.
F-21
56
TOREADOR ROYALTY CORPORATION
Notes to Consolidated Financial Statements
1998 1997 1996
------------ ------------ ------------
Future cash inflows ........................................ $ 29,011,780 $ 14,558,500 $ 29,686,583
Future production costs .................................... 5,110,313 4,096,800 9,594,044
Future development costs ................................... 44,279 366,900 --
------------ ------------ ------------
Future net cash flows before income taxes .................. 23,857,188 10,094,800 20,092,539
Future income tax expense .................................. 5,375,278 2,628,421 6,001,855
------------ ------------ ------------
Future net cash flows ...................................... 18,481,910 7,466,379 14,090,684
10% annual discount for estimated timing of cash flows ..... 7,011,003 2,597,628 5,773,051
------------ ------------ ------------
Standardized measure of discounted future net cash
flows relating to proved oil and gas reserves ..... $ 11,470,907 $ 4,868,751 $ 8,317,633
============ ============ ============
The average oil and gas prices used to calculate future net cash inflows at
December 31, 1998 were $9.74 per barrel and $1.86 per mcf, respectively. At
December 31, 1998 and March 17, 1999, respectively, the NYMEX price for oil was
$12.05 per barrel and $15.24 per barrel and the NYMEX price for gas was $1.945
per MMBtu and $1.699 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:
1998 1997 1996
------------ ------------ ------------
Balance at January 1 ........................ $ 4,868,751 $ 8,317,633 $ 4,710,135
Sales of oil and gas produced, net .......... (1,385,196) (1,630,141) (1,721,059)
Net changes in prices and production costs .. (2,206,776) (2,968,223) 3,393,314
Extensions and discoveries .................. 181,087 1,432,864 884,206
Revisions of previous quantity estimates .... 1,813,841 (3,720,824) 719,335
Net change in income taxes .................. (473,300) 1,737,609 (1,726,595)
Accretion of discount ....................... 486,875 831,763 601,140
Purchases of reserves ....................... 8,304,398 494,526 371,761
Other ....................................... (118,773) 373,544 1,085,396
------------ ------------ ------------
Balance at December 31 ...................... $ 11,470,907 $ 4,868,751 $ 8,317,633
============ ============ ============
F-22
57
INDEX TO EXHIBITS
Exhibit No. Description
- ----------- -----------
3.1* - Certificate of Incorporation, as amended, of Toreador Royalty
Corporation.
3.2* - Amended and Restated Bylaws, as amended, of Toreador Royalty
Corporation.
3.3 - Amendment to Bylaws of Toreador Royalty Corporation, dated April
21, 1997 (previously filed as Exhibit 3.7 to Toreador Royalty
Corporation Annual Report on Form 10-K for the year ended December
31, 1997, and incorporated herein by reference).
3.4 - Amendment to Bylaws of Toreador Royalty Corporation, dated June
25, 1998 (previously filed as Exhibit 3.1 to Toreador Royalty
Corporation Current Report on Form 8-K filed with the Securities
and Exchange Commission on July 1, 1998, and incorporated herein
by reference).
3.5 - Certificate of Designations of Series A Junior Participating
Preferred Stock of Toreador Royalty Corporation, dated April 3,
1995 (previously filed as Exhibit 3 to Toreador Royalty
Corporation Quarterly Report on Form 10-Q for the quarterly
period ended June 30, 1995, and incorporated herein by
reference).
3.6 - Certificate of Designation of Series A Convertible Preferred Stock
of Toreador Royalty Corporation, dated December 14, 1998
(previously filed as Exhibit 10.3 to Toreador Royalty Corporation
Current Report on Form 8-K filed with the Securities and Exchange
Commission on December 31, 1998, and incorporated herein by
reference).
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.
4.2 - Rights Agreement, dated as of April 3, 1995, between Toreador
Royalty Corporation and Continental Stock Transfer & Trust
Company (previously filed as Exhibit 1 to Toreador Royalty
Corporation Current Report on Form 8-K filed with the Securities
and Exchange Commission on April 3, 1995, and incorporated herein
by reference).
4.3 - Amendment No. 1 to Rights Agreement, dated June 25, 1998, between
Toreador Royalty Corporation and Continental Stock Transfer &
Trust Company (previously filed as Exhibit 99.1 to Toreador
Royalty Corporation Registration on Form 8-A/A filed with the
Securities and Exchange Commission on July 1, 1998, and
incorporated herein by reference).
58
4.4 - Registration Rights Agreement, effective December 16, 1998, among
Toreador Royalty Corporation and persons party thereto
(previously filed as Exhibit 10.2 to Toreador Royalty Corporation
Current Report on Form 8-K filed with the Securities and Exchange
Commission on December 31, 1998, and incorporated herein by
reference).
4.5 - Settlement Agreement, dated June 25, 1998, among the Gralee
Persons, the Dane Falb Persons and Toreador Royalty Corporation
(previously filed as Exhibit 10.1 to Toreador Royalty Corporation
Current Report on Form 8-K filed with the Securities and Exchange
Commission on July 1, 1998, and incorporated herein by
reference).
4.6 - Stockholder Voting Agreement, dated June 25, 1998, among the
Gralee Persons, the Dane Falb Persons and Current Management
(previously filed as Exhibit 10.2 to Toreador Royalty Corporation
Current Report on Form 8-K filed with the Securities and Exchange
Commission on July 1, 1998, and incorporated herein by
reference).
10.1+ - Form of Stock Option Agreement, between Toreador Royalty
Corporation and Donald E. August, John V. Ballard, J. W. Bullion,
John Mark McLaughlin, and Jack L. Woods (previously filed as
Exhibit 4.6 to Toreador Royalty Corporation Form S-8 (No.
333-14145) filed with the Securities and Exchange Commission on
October 15, 1996, and incorporated herein by reference).
10.2+ - Stock Option Agreement, dated February 17, 1994, between Toreador
Royalty Corporation and Thomas P. Kellogg, Jr. (previously filed
as Exhibit 4.7 to Toreador Royalty Corporation Form S-8 (No.
333-14145) filed with the Securities and Exchange Commission on
October 15, 1996, and incorporated herein by reference).
10.3+ - Form of Stock Option Agreement, between Toreador Royalty
Corporation and Edward C. Marhanka and Earl V. Tessem, as amended
(previously filed as Exhibit 4.8 to Toreador Royalty Corporation
Form S-8 (No. 333-14145) filed with the Securities and Exchange
Commission on October 15, 1996, and incorporated herein by
reference).
10.4+ - Incentive Stock Option, dated as of May 15, 1997, between Toreador
Royalty Corporation and Edward C. Marhanka (previously filed as
Exhibit 10.4 to Toreador Royalty Corporation Quarterly Report on
Form 10-Q for the quarter ended June 30, 1997, and incorporated
herein by reference).
10.5+ - Employment Agreement, dated as of May 1, 1997, between Toreador
Royalty Corporation and Edward C. Marhanka (previously filed as
Exhibit 10.5 to Toreador Royalty Corporation Quarterly Report on
Form 10-Q for the quarter ended June 30, 1997, and incorporated
herein by reference).
10.6* - Joint Venture Agreement, dated March 1, 1989, among Toreador
Royalty Corporation, Bandera Petroleum, et al, as amended.
10.7+ - Toreador Royalty Corporation 1990 Stock Option Plan (previously
filed as Exhibit 10.7 to Toreador Royalty Corporation Annual
Report on Form 10-K for the year ended December 31, 1994, and
incorporated herein by reference).
10.8+ - Amendment to Toreador Royalty Corporation 1990 Stock Option Plan,
effective as of May 15, 1997 (previously filed as Exhibit 10.14
to Toreador Royalty Corporation Annual Report on Form 10-K for
the year ended December 31, 1997, and incorporated herein by
reference).
59
10.9+ - Toreador Royalty Corporation 1994 Non-Employee Director Stock
Option Plan, as amended (previously filed as Exhibit 10.12 to
Toreador Royalty Corporation Annual Report on Form 10-K for the
year ended December 31, 1995, and incorporated herein by
reference).
10.10+ - Toreador Royalty Corporation Amended and Restated 1990 Stock
Option Plan, effective as of September 24, 1998 (previously filed
as Exhibit A to Toreador Royalty Corporation Preliminary Proxy
Statement filed with the Securities and Exchange Commission on
March 12, 1999, and incorporated herein by reference).
10.11 - Warrant for the Purchase of Shares of Common Stock issued to
Petrie Parkman & Co., dated May 23, 1994 (previously filed as
Exhibit 10.1 to Toreador Royalty Corporation Registration on Form
S-3, and incorporated herein by reference (No. 33-80572) filed
with the Securities and Exchange Commission on June 22, 1994, and
incorporated herein by reference).
10.12+ - Form of Indemnification Agreement, dated as of April 25, 1995,
between Toreador Royalty Corporation and each of the members of
our Board of Directors (previously filed as Exhibit 10 to
Toreador Royalty Corporation Quarterly Report on Form 10-Q for
the quarterly period ended June 30, 1995, and incorporated herein
by reference).
10.13*+ - 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.
10.14*+ - 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.
10.15 - Securities Purchase Agreement, effective December 16, 1998, among
Toreador Royalty Corporation and the Purchasers party thereto
(previously filed as Exhibit 10.1 to Toreador Royalty Corporation
Current Report on Form 8-K filed with the Securities and Exchange
Commission on December 31, 1998, and incorporated herein by
reference).
10.16 - Purchase and Sale Agreement, effective November 1, 1998, between
Howell Petroleum Corporation and the J.T. Philip Company, as
amended (previously filed as Exhibit 10.4 to Toreador Royalty
Corporation Current Report on Form 8-K filed with the Securities
and Exchange Commission on December 31, 1998, and incorporated
herein by reference).
10.17* - Loan Agreement, effective November 13, 1997, between Toreador
Royalty Corporation and Toreador Exploration & Production Inc and
Compass Bank.
10.18* - First Amendment to Loan Agreement, dated September 22, 1998,
between Toreador Royalty Corporation and Toreador Exploration &
Production Inc and Compass Bank.
10.19* - Second Amendment to Loan Agreement, dated December 15, 1998,
between Toreador Royalty Corporation and Toreador Exploration &
Production Inc and Compass Bank.
10.20 - Credit Agreement, effective December 15, 1998, between Compass
Bank and Tormin, Inc. (previously filed as Exhibit 10.5 to
Toreador Royalty Corporation Current Report on Form 8- K filed
with the Securities and Exchange Commission on December 31, 1998,
and incorporated herein by reference).
21.1* - Subsidiaries of Toreador Royalty Corporation.
60
23.1* - Consent of PricewaterhouseCoopers LLP.
23.2* - Consent of Harlan Consulting.
27.1* - Financial Data Schedule.
- --------------
* Filed herewith.
+ Management contract or compensatory plan
(b) Reports on Form 8-K:
During the last quarter of the fiscal year ended December 31, 1998, we
filed a Current Report on Form 8-K dated December 16, 1998, as amended by
Current Report on Form 8-K/A filed on March 1, 1999, with the Securities and
Exchange Commission to report the acquisition of certain oil, gas and other
mineral and royalty interests from Howell Petroleum Corporation under Items 2
and 7.