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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended: December 31, 1999
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) 559-3933
Securities registered pursuant to Section 12(b) of the Act:
NONE
Securities registered pursuant to Section 12(g) of the Act:
TITLE OF EACH CLASS: NAME OF EACH EXCHANGE ON WHICH REGISTERED:
------------------- -----------------------------------------
COMMON STOCK, PAR VALUE $.15625 PER SHARE NASDAQ NATIONAL MARKET SYSTEM
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, 2000 was $18,046,450. (For purposes of determination of
the foregoing amount, only directors, executive officers and 10% or greater
stockholders have been deemed affiliates.)
The number of shares outstanding of the registrant's Common Stock, par
value $.15625, as of March 17, 2000, was 5,172,371 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's Proxy Statement for the 2000 Annual
Meeting of Stockholders, expected to be filed on or prior to April 30, 2000, are
incorporated by reference into Part III of this Form 10-K.
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TABLE OF CONTENTS
Page
PART I .............................................................................................1
ITEM 1. BUSINESS.....................................................................................1
ITEM 2. PROPERTIES..................................................................................13
ITEM 3. LEGAL PROCEEDINGS...........................................................................20
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS .......................................20
PART II ............................................................................................20
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS.........................................................................20
ITEM 6. SELECTED FINANCIAL DATA.....................................................................21
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATION........................................................................22
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 ............................................................................................26
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. ........................................26
ITEM 11. EXECUTIVE COMPENSATION......................................................................26
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT..................................................................................26
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS..............................................26
PART IV ............................................................................................26
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K............................26
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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 our results of operations or of our financial conditions; or (3) state other
"forward-looking" information. We believe that it is important to communicate
our future expectations to our investors. However, there may be events in the
future that we are unable to accurately predict or over which we have no
control. When considering our forward-looking statements, you should keep in
mind the risk factors and other cautionary statements in this report. The risk
factors noted in this section and other factors noted throughout this report
provide example of risks, uncertainties and events that may cause our actual
results to differ materially from those contained in any forward-looking
statement.
ITEM 1. BUSINESS
GENERAL
Toreador Royalty Corporation, a Delaware corporation ("Toreador" or the
"Company"), is an independent energy company engaged in oil and gas exploration,
development, production and acquisition activities. We principally conduct our
business through our ownership of perpetual mineral and royalty interests in
approximately 2,643,000 gross (1,368,000 net) acres. These properties include
766,000 gross (461,000 net) acres located in the Texas Panhandle and West Texas.
Collectively we refer to these properties as the "Texas Holdings." In Alabama,
Mississippi and Louisiana, we own 1,775,000 gross (876,000 net) acres that we
collectively describe as the "Southeastern States Holdings." We also own various
royalty interests in Arkansas, California, Kansas and Michigan covering 102,000
gross (31,000 net) acres. These properties are collectively referred to as the
"Four States Holdings". In addition to the aforementioned holdings we own
various working interest properties in Texas, Kansas, New Mexico and Oklahoma.
We do not have any property interests anywhere other than the United States. For
a more detailed description of these properties please see "Item 2. Properties."
See "Glossary of Selected Oil and 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 was assigned 50% of the
mineral rights under the ranch acreage. In 1958 we acquired an additional 25% of
the mineral rights under a number of the original ranch properties.
As of December 31, 1999, 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.
As a result of acquisitions in 1998 and 1999, we now own more mineral
and royalty interests in addition to our Texas Holdings. Please see "ITEM 1.
Business -- Acquisitions and ITEM 2. Properties." For more detailed information.
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BUSINESS STRATEGY
Our strategic focus during 1999 centered on the pursuit of high quality
property acquisitions, participation in exploration projects as a non-operator
and the disposition of non-strategic assets. As a result of the current
favorable oil and gas prices being realized we have adjusted our objectives
accordingly. The principal elements of our present strategic focus are as
follows:
o Pursue opportunities to make high quality property
acquisitions.
o Identify and dispose of non-strategic assets in all areas in
order to take advantage of favorable oil and gas prices. We
intend to use multiple avenues in this marketing effort,
including internet on-line auctions.
o Expand our level of direct working interest participation as a
non-operator in exploration projects that provide exposure in
drilling opportunities for both multiple prospects and
multiple pay zones. We expect these opportunities to be
generated by experienced third party operators using current
generation three-dimensional ("3-D") seismic technology.
DEVELOPMENTS DURING 1999
ACQUISITIONS
As part of our strategy to actively pursue high quality property
acquisition opportunities, we reviewed a number of prospective candidates during
1999. We successfully closed two acquisitions as a result of this process.
FOUR STATES ACQUISITION. On September 30, 1999, we purchased certain
oil and gas royalty interests located in Arkansas, California, Kansas and
Michigan from Conoco, Inc. (the "Four States Property Acquisition"). The
Company's outside consulting engineering firm estimated total net proved
reserves at more than 2.6 Bcfe. Natural gas comprises approximately 57% of the
total reserves. The purchase price for these royalty interests was $3,215,000.
The effective date of the purchase was August 1, 1999.
LARIO PROPERTY ACQUISITION. On December 22, 1999, we purchased 50% of
Lario Oil and Gas Company's working interests in certain oil and gas leases and
properties located in Finney County, Kansas for a total purchase price of
$5,500,000 (the "Lario Property Acquisition"). This acquisition resulted in
reserve additions of over 1,000,000 BOE. The purchase had an effective date of
October 1, 1999.
DISPOSAL OF NON-STRATEGIC ASSETS
As part of our strategy to identify and dispose of non-strategic
assets, we completed two major asset sales during 1999. In January we sold a
portion of our acreage in the Texas Panhandle for $750,000. In September we sold
a portion of our West Texas acreage for $300,000.
ONGOING PROJECTS
As part of our strategy to participate in third party generated and
operated 3-D seismic projects in geologic regions outside of our holdings, we
are currently engaged in two 3-D seismic projects that could add significant gas
reserves.
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SOUTH ORANGE GROVE 3-D SEISMIC PROJECT. We have 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 targeting gas reserves in and around existing fields
from depths ranging from 800 feet to 8,100 feet. Generally, those horizons range
from the Miocene (~3,000 feet), Frio (~4,000 feet), Vicksburg (~5,000 feet) and
deeper Yegua horizons (~8,000 feet). The existing fields in this area are older
and contain relatively few modern exploratory wells. As of December 31, 1999,
after completing the acquisition, processing and interpretation phases in the
3-D seismic project area the operator proposed six wells and drilled two
exploratory wells. Of those, one was successfully completed as a Miocene
producer and the other was a dry hole. As of March 17, 2000, three additional
exploratory wells have been drilled resulting in one Vicksburg producer, one
well currently being completed as a potential Yegua producer and the other was a
dry hole. After the drilling of each well, future drilling projects are subject
to change based upon the gathering and evaluation of engineering and geological
data and refining the interpretation of the 3-D seismic data.
KIRBY HILLS 3-D SEISMIC PROJECT. We have 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 Sandstones, range in depth from 1,500
feet to 5,400 feet. As of March 17, 2000, the data acquisition phase is
complete; the data processing phase of the project is still underway. Assuming
positive results from the interpretation of the data, drilling could begin as
early as the end of the second quarter of 2000.
MARKETS AND COMPETITION
Our oil and gas production is sold to various purchasers typically in
the areas where the oil or gas is produced. Revenues from the sale of oil and
gas production accounted for 76%, 85% and 83% of the Company's consolidated
revenues for the three years ended December 31, 1999, 1998 and 1997,
respectively. The Company does not receive a material amount of its revenues
from external customers domiciled in foreign countries. Generally, we do not
refine or process any of the oil and gas we produce. We are currently able to
sell, under contract or in the spot market through the operator, substantially
all of the oil and the gas we are capable of producing at current market prices.
Substantially all of our oil and gas is sold under short term contracts or
contracts providing for periodic adjustments or in the spot market; therefore,
our revenue streams are highly sensitive to changes in current market prices.
Our gas markets are pipeline companies as opposed to end users. See "Item 1.
Business -- Risk Factors -- Volatility of Oil and 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, however, 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.
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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 believe 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,
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.
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
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.
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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 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 of these initiatives, such as "spin downs", may have the
adverse effect of increasing the cost of doing business to some in the industry
if the new, unregulated owners of those facilities monopolize them. The FERC has
attempted to address some of these concerns in its orders authorizing such "spin
downs" by requiring nondiscriminatory access and prohibiting "tying" access to
pipeline transportation to other services of an affiliate, imposing certain
contract requirements, and retaining jurisdiction if an affiliate undermines
open and nondiscriminatory access to the interstate pipeline. The FERC also has
imposed additional requirements on interstate pipelines seeking to abandon
facilities certificated under the Natural Gas Act of 1938 and to terminate
service from both certificated and uncertificated activities. It remains to be
seen what effect these activities will have on access to markets and the cost of
doing business. Further, some of the orders and regulations of the FERC
establishing these initiatives and approving actions thereunder have been
appealed and remain subject to further action by an appellate court and the
FERC. We cannot predict what the ultimate effect of these and other orders of
the FERC will have on our production and marketing, or whether the FERC's orders
on these matters will be affirmed by an appellate court. As to all of these
recent FERC initiatives, the ongoing, or in some instances, preliminary evolving
nature of these regulatory initiatives also makes it impossible at this time for
us to predict their ultimate impact on our business.
FEDERAL 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.
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ENVIRONMENTAL REGULATION
Exploration, development and production of oil and gas, including
operation of saltwater injection and disposal wells, are subject to various
federal, state and local environmental laws and regulations. Such laws and
regulations can increase the costs of planning, designing, installing and
operating oil and gas wells. Our domestic activities are subject to a variety of
environmental laws and regulations, including, but not limited to:
o the Oil Pollution Act of 1990;
o the Clean Water Act;
o the Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA");
o the Resource Conservation and Recovery Act ("RCRA");
o the Clean Air Act and
o the Safe Drinking Water Act,
as well as state regulations promulgated under comparable state statutes. These
laws and regulations:
o require the acquisition of a permit before drilling commences;
o restrict the types, quantities and concentration of various
substances that can be released into the environment in
connection with drilling and production activities;
o limit or prohibit drilling activities on certain lands lying
within wilderness, wetlands and other protected areas and
o impose substantial liabilities for pollution that might result
from our operations.
We also are subject to regulations governing the handling, transportation,
storage and disposal of naturally occurring radioactive materials that are found
in our oil and gas operations. Civil and criminal fines and penalties may be
imposed for non-compliance with these environmental laws and regulations.
Additionally, these laws and regulations require the acquisition of permits or
other governmental authorizations before undertaking certain activities, limit
or prohibit other activities because of protected areas or species and impose
substantial liabilities for cleanup of pollution.
Under the Oil Pollution Act, a release of oil into water or other areas
designated by the statue could result in Toreador being held responsible for the
costs of remediating such a release, specified damages and natural resource
damages. The extent of that liability could be extensive, as set forth in the
statute, depending on the nature of the release. A release of oil in harmful
quantities or other materials into water or other specified areas could also
result in Toreador being held responsible under the Clear Water Act for the cost
of remediation, and for civil and criminal fines and penalties.
CERCLA and comparable state statutes, also known as "Superfund" laws,
can impose joint, several and retroactive liability, without regard to fault or
the legality of the original conduct, on certain classes of persons for the
release of a "hazardous substance" into the environment. In practice, cleanup
costs are usually allocated among various responsible parties. Potentially
liable parties include site owners or operators, past owners or operators under
certain conditions and entities that arrange for the disposal or treatment of,
or transport of hazardous substances found at the site. Although CERCLA, as
amended, currently exempts petroleum, including, but not limited to, crude oil,
gas and natural gas liquids from the definition of hazardous substance, our
operations may involve the use or handling of other materials that may be
classified as hazardous substances under CERCLA. Furthermore, there can be no
assurance that the exemption will be preserved in any future amendments to
CERCLA.
RCRA and comparable state and local requirements impose standards for
the management, including treatment, storage and disposal of both hazardous and
nonhazardous solid wastes. We generate hazardous and non-hazardous solid waste
in connection with our routine operations. From time to time, proposals have
been made that would reclassify certain oil and gas wastes, including wastes
generated during pipeline, drilling and production operations, as "hazardous
wastes" under RCRA which would make such solid wastes subject to much more
stringent handling, transportation, storage, disposal and clean-up requirements.
This development could have a significant impact on our operating costs. While
state laws vary on this issue, state initiatives to further regulate oil and gas
wastes could have a similar impact on our operations.
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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, 2000, we employed nine 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, 1999, Toreador's debt to equity ratio was 149%. 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" section below.
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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."
Our level of indebtedness will have several important effects on our future
operations, including:
o a substantial portion of our cash flow from operations must be
dedicated to the payment of principal and interest on our
indebtedness and will not be available for other purposes;
o covenants contained in our debt obligations will require us to
meet certain financial tests, and other restrictions will
limit our ability to borrow additional funds or to dispose of
assets and may affect our flexibility in planning for, and
reacting to, changes in our business, including possible
acquisition activities and
o our ability to obtain additional financing in the future may
be impaired.
A default under our credit facility would permit the lender to accelerate
repayments of the loan and to foreclose on the collateral securing the loan,
including certain oil and natural 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 favorable. 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:
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; the effect of 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.
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 generally entail 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 Four States Property Acquisition and the Lario Property Acquisition
represent major steps in our growth strategy. However, our increased size and
scope of operations will present us with significant challenges due to the
increased time and resources required in our management effort. Accordingly,
there can be no assurance that our future operations under present conditions
can be effectively managed to realize the goals set forth on future property
acquisitions.
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 additional indebtedness or our issuing potentially
dilutive 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 (the rights to sign leases) as well as rights to
receive portions of lease bonuses, delay rentals and royalties.
On the Texas Holdings, we own interests in minerals that include rights
to receive portions of lease bonuses, delay rentals and royalties, except,
unlike our Southeastern States Holdings, we generally do not own the executive
rights which are typically held by surface owners. Therefore, we must rely on
the owners of the executive rights to execute leases of the acreage. In
situations in which we have acquired working interests in acreage where we have
mineral rights,
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we have acquired those interests through the signing of leases by holders of
the executive rights. While the majority of the owners holding those executive
rights have worked closely with us in the past, each acts independently of us in
their decisions to execute leases. In addition, since our interests are in the
form of mineral interests, royalty interests or non-operator working interests,
we do not have control over drilling or operating decisions on the properties in
which we have an interest.
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 may vary from a few days to several months. In most
cases we are provided only limited notice as to when production will be
curtailed and the duration of such curtailments. We are not currently
experiencing any material curtailment on our production.
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STOCK PRICE VOLATILITY
Because the volume of trading in shares of our Common Stock has been
low historically, the sale of a substantial number of shares of the Common Stock
in a short period of time could adversely affect the market price of the Common
Stock.
DIVIDENDS
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.
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, 2000, the current officers and directors of the
Company as a group held a beneficial interest in approximately 53% 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 53% 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 -
Operations and 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.
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"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." The oil
and natural gas reserves that can be expected to be recovered through existing
wells with existing equipment and operating methods. Additional oil and natural
gas expected to be obtained through the application of fluid injection or other
improved recovery techniques for supplementing the natural forces and mechanisms
of primary recovery should be included as "proved developed reserves" only after
testing by a pilot project or after the operation of an installed program has
confirmed through production response that increased recovery will be achieved.
"PROVED RESERVES." The estimated quantities of crude oil, natural gas
and natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
"PROVED UNDEVELOPED RESERVES." The oil and natural gas reserves that
are expected to be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required for
recompletion. Reserves on undrilled acreage shall be limited to those drilling
units offsetting productive units that are reasonably certain of production when
drilled. Proved reserves for other undrilled units can be claimed only where it
can be demonstrated with certainty that there is continuity of production from
the existing productive formation. Under no circumstances should estimates for
proved undeveloped reserves be attributable to any acreage for which an
application of fluid injection or other improved recovery techniques is
contemplated, unless such techniques have been proved effective by actual tests
in the area and in the same reservoir.
"ROYALTY INTEREST." An interest in an oil and natural gas property
entitling the owner to a share of oil and natural gas production free of
production costs.
"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, 1999, 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, 1999, 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.
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"WORKING INTEREST." The operating interest which gives the owner the
right to drill, produce and conduct operating activities on the property and a
share of production, subject to all royalties, overriding royalties and other
burdens and to all exploration, development and operational costs including all
risks in connection therewith.
ITEM 2. PROPERTIES.
We own perpetual oil and gas mineral and royalty interests comprised of
and commonly referred to as the Texas Holdings, the Southeastern States Holdings
and the Four States Property Holdings, all of which are equal to approximately
2,643,000 gross acres.
TEXAS HOLDINGS
Our Texas Holdings are comprised of the Northern Ranch Minerals and the
Southern Ranch Minerals and are equal to approximately 766,000 gross (461,000
net) acres.
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.
In January 1999, we sold approximately 66,300 gross (49,700 net)
mineral acres for $750,000. This particular acreage is commonly referred to as
the Scharbauer Ranch acreage in Oldham County, Texas.
Both of these sales are 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 consider to be viable offers for our non-strategic
minerals.
No wells were drilled on the Northern Ranch Minerals in 1999. As of
March 17, 2000, no wells have been drilled on this acreage. We continue to
receive inquiries by third parties to evaluate the existing 2-D seismic database
and possibly implementing the latest 3-D seismic technology to evaluate the
potential of the minerals.
SOUTHERN RANCH MINERALS
We own mineral interests under an aggregate of approximately 470,000
gross acres located in three geologic provinces commonly known as the Palo Duro
Basin, the Matador Arch, and the Eastern Shelf.
PALO DURO BASIN - The Palo Duro Basin, where we own mineral interests
under approximately 195,000 gross acres located in Motley and Cottle Counties,
Texas, is a moderate depth depression between the Matador Arch on the south and
the Amarillo uplift complex to the north. There was no leasing or drilling
activity with respect to our mineral interests in this region in 1999. In August
1999, we sold approximately 38,000 gross (19,000 net) mineral acres for
$300,000. This acreage is commonly referred to as the Bird acreage in Cottle and
Motley Counties, Texas.
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.
We leased approximately 1,800 gross (1,400 net) acres to two separate
third parties in 1999. One of the operators leased some of our acreage
contiguous with acreage owned by others. Two wells were drilled and tested dry
on the outside acreage. As of December 31, 1999, there were no wells drilled
with respect to our mineral interests in this region. As of March 17, 2000, the
other third party re-entered and pipe tested a previously plugged and abandoned
well near the Matador Field as a marginal oil producer pumping less than five
barrels of oil per day. We own a 15.0% net royalty interest in this 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.
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In 1999, we leased a total of approximately 2,300 gross (1,100 net)
acres under two separate agreements. As of December 31, 1999, there had not been
any wells drilled on our acreage under these agreements. As of March 17, 2000,
one exploratory well had been drilled to test the Tannehill Sand as an extension
to the Silver Spur Field resulting in a dry hole. We participated with a 9.375%
working interest.
SOUTHEASTERN STATES HOLDINGS
In December 1998, the Company acquired approximately 1,775,000 gross
(876,000 net) acres located in Mississippi, Alabama and Louisiana. Most of the
Company's activity is generated along the southern half of each of these three
states. Unlike our Texas Holdings, our mineral spread here is diversified over
several geologic provinces and not highly concentrated and dense in one specific
area. Conversely, we own a mineral position in every county in Mississippi and
Alabama.
MISSISSIPPI
The Company owns perpetual mineral interests in approximately 1,137,000
gross acres in Mississippi. The largest concentration of activity for our
Southeastern States Holdings is in the geologic province commonly known as the
Mississippi Salt Basin. This province primarily stretches from northeastern
Louisiana across the southern half of Mississippi and just into the southwestern
portions of Alabama. In another province of more recent importance is the
development of a Deep Knox Gas discovery in northeastern Mississippi located
just southwest and adjacent to the Black Warrior Basin. This basin extends from
northeastern Mississippi into northwestern Alabama.
MISSISSIPPI SALT BASIN
The Mississippi Salt Basin contains two major areas of exploration
activity that currently provide us with the opportunity to gain significant
reserve additions. The two areas are the Piercement Salt Domes and the Salt
Ridges.
PIERCEMENT SALT DOMES - The Piercement Salt Dome activity is currently
focused in the south-central portion of Mississippi in Covington, Jefferson
Davis and Jones Counties, Mississippi. These geologic features have several
target pay zones ranging from primary objectives in several Hosston Sandstones
at depths of over 15,000 feet to secondary objectives in the Sligo and Paluxy
formations at approximately 14,000 feet and 12,000 feet, respectively. The
current success in this area is primarily attributed to the utilization of
modern 3-D seismic technology. As a royalty owner we do not bear the burden of
any expenses in exploring and developing any fields discovered.
The Kola Dome feature is the latest salt dome exploration project to
utilize modern 3-D seismic technology. In Covington County, Mississippi, the
#1 Miller-Langston well reached a total depth of over 16,000 feet and was
completed in the Sligo formation during February of 2000, testing at daily rates
in excess of 9.1 MMcf of natural gas and 450 barrels of condensate without any
form of stimulation. We own a 5.89% net royalty interest in this well. In
addition, we hold a 50% mineral interest in 3,000 acres within a two-mile radius
of the newly completed well, some of which is contiguous to the new field
discovery.
In Jefferson Davis County, Mississippi, we are also incurring benefits
from the use of modern 3-D seismic technology. In June 1997, the Oakvale Dome
Field was discovered. The discovery well has produced at daily rates in excess
of 10 MMcf of natural gas and 35 barrels of condensate. As of March 17, 2000,
there are three wells producing from several Hosston formations in the field for
a combined daily rate of 15.8 MMcf and 35 barrels of condensate. We own a 3.125%
net royalty interest in two of the three wells and a 0.78% in the third and
least productive of the three wells. As of March 17, 2000, the operator is in
the process of drilling its fourth well in the field. We will own a 1.97% net
royalty interest if the well is successfully completed as a producer. A fifth
location near this field has been permitted with the State of Mississippi, but
no definitive date has been announced as to when drilling will commence.
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Near the Moselle Dome in Jones County, Mississippi, we own a 4.17% net
royalty interest in the #1 Frost 5-11 well in the Parker Creek Field which is
identified geologically as a fault-bounded structural feature adjacent to a salt
dome. This well was completed in the Hosston at a daily rate in excess of 700
barrels of oil in November 1999. As of March 17, 2000, the operator is drilling
the #1 Allar Company well in a northern extension to the field. If successfully
completed as a producer, we will own a 2.93% net royalty interest. Currently,
the operator is drilling below the intermediate casing which was set through the
Hosston formation. The Hosston section had good oil shows and is
stratigraphically equivalent to the zone completed in the #1 Frost 5-11 well.
SALT RIDGES - Salt Ridge exploration activity is resuming in Wayne
County, Mississippi. The primary objectives are the Cotton Valley, Smackover and
Norphlet formations ranging from 12,000 feet to 18,000 feet. The use of modern
3-D seismic technology has been critical to the success of this activity.
This activity was initiated as a result of the discovery of the
Crawford Creek Field in Wayne County, Mississippi in 1994. As of December 1999,
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. As of
March 17, 2000, we are in the process of negotiating several leases with a
number of operators.
DEEP KNOX GAS
Current activity is centered in western Oktibbeha County, Mississippi,
adjacent to the Black Warrior Basin, where the 15,000-foot Knox test well, the
#1 Sanders, was completed in June 1998 as an extension of the Maben Field which
was originally discovered in 1970. The newly discovered well flowed for an
average daily rate of 5.8 MMcf in January of 2000. It produced nearly 3.0 Bcf of
natural gas since gas sales began in September 1998. We own a 0.35% net royalty
interest in this well. The operator drilled and completed a second exploratory
well in the play, the #1 Georgia Pacific, which flowed at a daily rate of
approximately 400 Mcf in June 1999. We own a 2.79% net royalty interest in this
well. A third well, where we do not own a royalty interest, was drilled and
completed by the same operator in February 2000 and tested at a daily rate of
5.2 MMcf.
This area is considered to be extremely promising since very few wells
have been drilled to the Knox formation in this region near or in the Black
Warrior Basin. The operator's continued success, aided by the use of modern 3-D
seismic technology, will fuel future drilling interest around the Maben Field
area. Additionally, other companies are in the process of funding a research
team to investigate the play into other regions including and outside of
Mississippi.
ALABAMA
The Company owns perpetual oil and gas mineral and royalty interests in
approximately 622,000 gross acres in Alabama. We own a mineral position in every
county in Alabama. Activity on our minerals in Alabama is not as significant as
it is in Mississippi.
LOUISIANA
The Company owns oil and gas mineral and royalty interests in
approximately 16,000 gross acres in Louisiana. Unlike the other states where we
own perpetual minerals, the laws in Louisiana are such that the minerals
prescribe to the surface owner after 10 years have passed without any production
or drilling on said lands. Since we do not own the surface rights in any of the
properties that were acquired in December 1998, the consequences are that we do
not maintain many of our mineral rights if production ceases for a period of 10
years.
FOUR STATE PROPERTY HOLDINGS
In September 1999, the Company acquired certain oil and gas royalty
interests located in Arkansas, California, Kansas and Michigan. The holdings
include approximately 140 producing wells in addition to approximately 56,000
gross (18,000 net) undeveloped acres. The Company's outside engineering firm
estimated total net proved reserves at 2.6 Bcfe. Natural gas comprises
approximately 57% of the total reserves.
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TITLE TO OIL AND NATURAL GAS PROPERTIES
We have acquired interests in producing and non-producing acreage in
the form of working interests, fee mineral interests, royalty interests and
overriding royalty interests. Substantially all of our property interests are
leased to third parties. The leases grant the lessee the right to explore for
and extract oil and 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 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
Southeastern States Holdings.
As is common industry practice, we conduct little or no investigation
of title at the time we acquire undeveloped properties, other than a preliminary
review of local mineral records. However, we do conduct title investigations
and, in most cases, obtain a title opinion of local counsel before commencement
of drilling operations. We believe that the methods we utilize for investigating
title prior to acquiring any property is consistent with practices customary in
the oil and gas industry and that such practices are adequately designed to
enable us to acquire good title to such properties. Some title risks, however,
cannot be avoided, despite the use of customary industry practices.
Our properties are generally subject to:
o customary royalty and overriding royalty interests;
o liens incident to operating agreements and
o liens for current taxes and other burdens and minor
encumbrances, easements and restrictions.
We believe that none of these burdens either materially detract from the value
of our properties or materially interfere with their use in the operation of our
business. Substantially all of our properties are pledged as collateral under
our credit facility.
OIL AND GAS RESERVES
The following tables summarize certain information regarding our
estimated proved oil and gas reserves as of December 31, 1999, 1998 and 1997.
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, 1999 are based upon reports prepared by LaRoche Petroleum
Consultants. The estimates at December 31, 1998 and December 31, 1997 included
in this report are based upon reports prepared by other outside engineering
firms. In accordance with the guidelines of the Securities and Exchange
Commission, the estimates of future net cash flows from proved reserves and
their SEC PV-10 are made using oil and gas sales prices in effect as of the
dates of such estimates and are held constant throughout the life of the
properties. For the three years ended December 31, our estimates of proved
reserves, future net cash flows and SEC PV-10 for the life of the properties
were estimated using the weighted average prices shown below for the life of the
properties, before deduction of production, severance and ad valorem taxes.
Included in the table is the percent change in the weighted-average price from
the prior year.
DECEMBER 31,
---------------------------------------------------
% INCREASE % INCREASE
1999 (DECREASE) 1998 (DECREASE) 1997
------ ---------- ------ ---------- ------
Gas ($ per Mcf) ......... $ 2.24 20 $ 1.86 (17) $ 2.25
Oil ($ per Bbl) ......... $23.42 140 $ 9.74 (39) $15.87
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Reserve estimates are imprecise and may be expected to change as
additional information becomes available. Furthermore, estimates of oil and gas
reserves, of necessity, are projections based on engineering data, and there are
uncertainties inherent in the interpretation of such data as well as the
projection of future rates of production and the timing of development
expenditures. Reservoir engineering is a subjective process of estimating
underground accumulations of oil and gas that cannot be measured in an exact
way, and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgement.
Reserve reports of other engineers might differ from the reports contained
herein. Results of drilling, testing, and production subsequent to the date of
the estimate may justify revision of such estimate. Future prices received for
the sale of oil and gas may be different from those used in preparing these
reports. The amounts and timing of future operating and development costs may
also differ from those used. Accordingly, there can be no assurance that the
reserves set forth herein will ultimately be produced nor can there be assurance
that the proved undeveloped reserves will be developed within the periods
anticipated. We emphasize with respect to the estimates prepared by independent
petroleum engineers that the discounted future net cash inflows should not be
construed as representative of the fair market value of the proved oil and gas
properties belonging to us, since discounted future net cash inflows are based
upon projected cash inflows which do not provide for changes in oil and gas
prices nor for escalation of expenses and capital costs. The meaningfulness of
such estimates is highly dependent upon the accuracy of the assumptions upon
which they were based.
All reserves are evaluated at contract temperature and pressure 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 14 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 14 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, 1999.
PROVED OIL AND GAS RESERVES (1)
DECEMBER 31,
------------------------------------------------------------------------
% Increase % Increase
1999 (Decrease) 1998 (Decrease) 1997
---------- ---------- ---------- ---------- ----------
GAS RESERVES (MCF):
Proved Developed Producing Reserves ......... 7,987,551 (6) 8,500,655 242 2,487,574
Proved Developed Non-Producing Reserves ..... 82,982 N/A 0 0 0
Proved Undeveloped Reserves ................. 140,309 (89) 1,289,785 1,576 76,966
---------- ---------- ----------
Total Proved Reserves of gas ................ 8,210,842 (16) 9,790,440 282 2,564,540
---------- ---------- ----------
OIL RESERVES (BBL):
Proved Developed Producing Reserves ......... 1,624,549 48 1,094,454 143 450,646
Proved Developed Non-Producing Reserves ..... 375,435 N/A 0 (100) 51,080
Proved Undeveloped Reserves ................. 196,682 932 19,051 (63) 51,452
---------- ---------- ----------
Total Proved Reserves of oil ................ 2,196,666 97 1,113,505 101 553,178
---------- ---------- ----------
TOTAL PROVED RESERVES (MCFE) ..................... 21,390,838 30 16,471,470 180 5,883,608
========== ========== ==========
- ----------
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SEC PV-10 OF PROVED RESERVES
DECEMBER 31,
-------------------------------------------------------------
% INCREASE % INCREASE
1999 (DECREASE) 1998 (DECREASE) 1997
-------- ---------- -------- ---------- --------
SEC PV-10 (thousands) (1):
Proved Developed Producing Reserves ......... $ 23,863 103 $ 11,780 121 $ 5,342
Proved Developed Non-Producing Reserves ..... 4,646 N/A 0 (100) 514
Proved Undeveloped Reserves ................. 2,072 43 1,454 380 303
-------- -------- --------
Total SEC PV-10 ............................. $ 30,581 131 $ 13,234 115 $ 6,159
======== ======== ========
- ----------
(1) SEC PV-10 differs from the Standardized Measure set forth in the Notes
to the Consolidated Financial Statements of the Company, which is
calculated after provision for future income taxes.
Except for the effect of changes in oil and gas prices, no major
discovery or other favorable or adverse event is believed to have caused a
significant change in these estimates of our proved reserves since December 31,
1999.
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, 1999 from
producing interests:
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------
% %
INCREASE INCREASE
1999 (DECREASE) 1998 (DECREASE) 1997
---------- ---------- ---------- ---------- ----------
Production
Oil (Bbl) .................. 128,924 43 90,097 29 69,903
Gas (Mcf) ................... 918,986 133 394,849 (7) 425,854
Oil equivalent (BOE) ........ 282,088 81 155,905 11 140,879
Average Sales Price
Oil ($/Bbl) ................. $ 17.14 27 $ 13.48 (29) $ 19.04
Gas ($/Mcf) ................. 2.14 12 1.91 (18) 2.33
Oil equivalent ($/BOE) ...... 14.81 17 12.63 (23) 16.50
Average production cost $/BOE ..... $ 2.48 (34) $ 3.74 (24) $ 4.93
- ----------
DRILLING ACTIVITY
The following table sets forth for each of the last three years the
number of net exploratory and development wells drilled by us or on our behalf.
An exploratory well is a well drilled to find and produce oil or gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir, or to extend a known reservoir. A
development well is a well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive. The
number of wells drilled refers to the number of wells completed at any time
during the respective year, regardless of when drilling was initiated; and
"completion" refers to the installation of permanent equipment for the
production of oil or gas, or, in the case of a dry well, to the reporting of the
plugging date to the appropriate state regulatory agency.
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NET EXPLORATORY WELLS NET DEVELOPMENT WELLS
-------------------------------- -------------------------------
PRODUCTIVE (1) DRY (2) PRODUCTIVE (1) DRY (2)
-------------- ------------- -------------- ----------
YEAR ENDED
DECEMBER 31,
1997................. (3) 0.57 0.46 (4) 0.55 0.11
1998................. 0.00 0.57 0.22 0.90
1999................. 0.13 0.13 0.36 0.00
- ----------
(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.
(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, 1999. 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, 1999 (1)
------------------------
Oil Wells OIL GAS
--- ---
Working Interest
Gross..................................... 705 54
Net....................................... 19.09 5.47
Average working interest (%).............. 2.71 10.13
Royalty Interest
Gross..................................... 3,432 243
Net ...................................... 9.80 6.78
Average royalty interest (%) ............. 0.29 2.79
Acreage Developed Undeveloped (2)
--------- ---------------
Developed
Gross..................................... 164,484 36,714
Net....................................... 30,767 18,540
- ----------
(1) Does not include wells that are considered to have a minor value on an
individual basis.
(2) Undeveloped acreage is considered to be only those leased acres on
which wells have not been drilled or completed to a point that would
permit the production of commercial quantities of oil and gas
regardless of whether or not the acreage contains proved reserves.
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PRESENT ACTIVITIES
For the period January 1, 2000 through March 17, 2000, we participated
in drilling five gross (0.47 net) exploratory wells: one of the wells was on our
mineral holdings, two of the wells were successfully completed as a gas wells,
one of the wells was dry and one of the wells is in progress.
OFFICE LEASE
We occupy approximately 5,277 square feet of office space at 4809 Cole
Avenue, Suite 108, Dallas, Texas 75205 under a lease from Chalk Stream
Properties, L.P. Total rental expense for 1999 was $95,541.
ITEM 3. LEGAL PROCEEDINGS.
During 1999 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,
1999, 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.
1999 High Low
- ------------------------------------ --------------- -----------
First Quarter....................... 3 3/4 2 1/4
Second Quarter...................... 3 3/8 2 3/8
Third Quarter....................... 3 9/16 2 15/16
Fourth Quarter...................... 4 3/4 3 7/16
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
HOLDERS AND CLOSING PRICE
As of March 17, 2000, there were 5,172,371 shares of Common Stock
outstanding held of record by 463 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, 2000 was $5.75.
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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).
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,
----------------------------------------------------------------------------
1999 (a) 1998 1997 1996 1995
------------ ------------ ------------ ------------ ------------
INCOME STATEMENT DATA:
Revenues:
Oil and gas sales ........................... $ 4,259,040 $ 1,968,638 $ 2,325,148 $ 2,306,791 $ 1,378,390
Lease bonuses and rentals ................... 463,083 168,664 287,604 118,430 138,804
Interest and other income ................... 109,035 171,338 149,841 162,297 213,464
Gain on sale of properties................... 851,726 -- 26,171 -- --
Gain on sale of marketable securities........ (79,615) -- -- 526,567 --
------------ ------------ ------------ ------------ ------------
Total revenues .......................... 5,603,269 2,308,640 2,788,764 3,114,085 1,730,658
------------ ------------ ------------ ------------ ------------
Costs and Expenses:
Lease operating ............................. 699,278 583,441 695,007 585,732 380,888
Dry holes and abandonments .................. 9,933 133,113 166,710 130,647 358,210
Depreciation, depletion and
amortization ........................... 1,276,268 514,071 539,346 273,026 233,709
Geological and geophysical .................. 394,496 517,870 546,634 227,744 297,047
General and administrative .................. 1,583,729 999,548 802,723 907,086 1,078,171
Loss on settlement of benefit plans ......... -- -- 173,971 -- --
Interest .................................... 794,627 36,120 -- -- --
------------ ------------ ------------ ------------ ------------
Total costs and expenses ................ 4,758,331 2,784,163 2,924,391 2,124,235 2,348,025
------------ ------------ ------------ ------------ ------------
Income (loss) before federal income taxes ........ 844,938 (475,523) (135,627) 989,850 (617,367)
Provision (benefit) for federal income taxes ..... 336,927 (233,277) (84,261) 263,100 (206,936)
------------ ------------ ------------ ------------ ------------
Net income (loss) ........................... $ 508,011 $ (242,246) $ (51,366) $ 726,750 $ (410,431)
============ ============ ============ ============ ============
Dividend on preferred shares ................ 360,000 19,500 -- -- --
Income (loss) attributable to common shares ...... $ 148,011 $ (261,746) $ (51,366) $ 726,750 $ (410,431)
============ ============ ============ ============ ============
Basic and diluted income (loss) per share ... $ 0.03 $ (0.05) $ (0.01) $ 0.14 $ (0.08)
Weighted average shares outstanding
Basic ................................... 5,185,588 5,125,063 5,022,216 5,216,941 5,334,190
Diluted ................................. 5,250,862 5,125,603 5,022,216 5,216,941 5,334,190
CASH FLOW DATA:
Net cash provided (used) by
operating activities .................... $ 763,314 $ 276,624 $ 830,643 $ 609,364 $ (10,963)
Capital expenditures for oil and gas
property and equipment .................. $ (9,208,348) $(13,951,981) $ (717,481) $ (893,418) $ (1,048,757)
BALANCE SHEET DATA: (1)
Working capital ............................. $ 438,611 $ 1,987,764 $ 3,007,121 $ 3,383,668 $ 3,538,206
Oil and gas properties, net ................. 24,423,537 16,209,631 3,210,074 3,306,020 3,201,283
Total assets ................................ 26,455,980 19,782,262 6,526,785 7,008,924 7,051,052
Long-term debt .............................. 14,666,500 7,880,000 -- -- --
Stockholders' equity ........................ 10,650,198 10,594,508 6,217,195 6,624,180 6,810,485
- ------------
(a) 1999 results contain full year results from the Southeastern States
Acquisition and partial year results from the Four States Acquisition.
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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 1999, 1998, and 1997;
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 1997
through 1999 and what we expect them to be in 2000 and
o where cash will come from to pay for future capital
expenditures.
As you read Management's Discussion and Analysis, it may be helpful to
refer to the Company's Consolidated Statements of Operations on page F-5, which
present the results of our operations for 1999, 1998, and 1997. In Management's
Discussion and Analysis, we analyze and explain the annual changes in the
specific line items in the Consolidated Statements of Operations. Our analysis
may be important to you in making decisions about your investments in Toreador.
The Company follows the successful efforts method of accounting for oil
and gas exploration and development expenditures. Under this method, costs of
successful exploratory wells and all development wells are capitalized. Costs to
drill exploratory wells which do not find proved reserves are expensed.
Significant costs associated with the acquisition of oil and gas properties are
capitalized. Acquisition costs of mineral interests in oil and gas properties
remain capitalized until they are impaired or a determination has been made to
discontinue 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 1999 in the amount of $14,401, primarily due to the decrease
in oil and gas reserves for the affected producing properties. There was an
impairment in 1998 of $19,649 resulting from the decrease in oil and gas prices
and there was no impairment during 1997. The impairments are included in the
"Depreciation, depletion and amortization" category of the Consolidated
Statements of Operations.
LIQUIDITY AND CAPITAL RESOURCES
Historically, most of the exploration activity on our acreage has been
funded and conducted by other oil companies. Exploration activity by third party
oil companies typically generates lease bonus and option income to us. If such
drilling is successful, we receive royalty income from the oil or gas production
but bear none of the capital or operating costs. Since the middle of 1996, we
have successfully accelerated the evaluation of several areas of our mineral
acreage as well as increased our ownership in any reserves that were discovered
by acquiring working interests of selected 3-D seismic projects and any wells
drilled as a result of such geological activity.
22
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We will continue to actively pursue exploration and development
opportunities on our own mineral acreage in order to take advantage of the
current favorable level of crude oil prices. We will also expand our drilling
focus to geologic regions, particularly those areas with proven and attractive
gas reserves, that can provide potentially better rates of return on our capital
resources. We also plan to evaluate 3-D seismic projects or drilling prospects,
generated by third party operators. If judged geologically and financially
attractive by our management, we will enter into joint ventures on those third
party projects subject to available room within the capital exploration budget
approved by our board of directors.
Our 2000 capital exploration budget, excluding any acquisitions we may
make, could range from $1,000,000 to $1,500,000, depending on the timing of any
new seismic surveys and drilling of exploratory and development wells in which
we may hold a working interest position.
We also intend to actively evaluate opportunities to acquire producing
properties that represent unique opportunities for us to add additional reserves
to our reserve base while not increasing general and administrative costs. Any
such acquisitions will be financed using cash on hand, third party sources,
existing credit facilities or any combination thereof.
At the present time, the primary source of capital for financing our
operations is our cash flow from operations. During 1999, on a historical basis,
cash flow provided by operating activities was $763,314. We anticipate that cash
flow provided by operating activities for 2000 will be materially higher
reflecting the higher crude oil prices and increased reserves from acquisitions.
In November 1997, we obtained a $10,000,000 credit facility (as
amended, the "Facility"). In December 1998, we borrowed $2,700,000 against the
Facility which was used to finance the Howell Mineral Acquisition. We obtained
an additional $5,900,000 term loan (the "Loan") which was used in this
acquisition.
A new credit agreement was entered into as of September 30, 1999 with
Compass Bank that amended the Facility and terminated the Loan with proceeds
from the Facility. The amendment increased the line of credit under the Facility
up to $25,000,000 subject to the underlying collateral value. The Facility is a
revolving line of credit collateralized by various oil and gas interests owned
by us. The interest rate is equal to the prime rate less one-quarter as long as
the amount borrowed is greater than 80% of the borrowing base as defined by the
lender ($12,500,000 at December 31, 1999). The rate will drop an additional
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 of the
Facility at December 31, 1999 was 8.25%, and we are currently not subject to any
fees. The maturity date of the Facility is October 1, 2002. As of December 31,
1999, the outstanding balance of the Facility was $12,416,500.
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, we 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.
We obtained a term promissory note of $2,000,000 (the "Note" as
amended) in December of 1999. The interest rate is equal to the prime rate. The
interest rate on the loan was 8.5% at December 31, 1999. On March 1, 2000 the
maturity date was extended to April 1, 2001.
Each of the above described debt issues is controlled by the borrowing
base. The amount of debt outstanding at any time is not allowed to exceed the
borrowing base as determined by the lender. The borrowing base is subject to
evaluation every six months and can be adjusted either up or down. We are
required to repay any principal which exceeds the revised borrowing base.
On December 22, 1999, we purchased 50% of the oil and gas working
interests of Lario Oil & Gas Company located in Finney County, Kansas, pursuant
to a Purchase and Sale Agreement dated as of November 24, 1999, between Lario
and Toreador. The purchase price for the interests was $5,500,000, consisting of
$5,000,000 cash and an agreement to pay the amount of $500,000 on an installment
basis. Half of this amount ($250,000) is to be repaid by Toreador on a monthly
basis, plus interest at prime plus 1%, amortized over 13 months beginning
January, 2000. The remaining $250,000 plus interest at prime plus 1% (which is
currently 9.5% per annum) is to be repaid by Toreador on January 23, 2001.
23
26
We may reinvest proceeds from option and lease bonuses by taking a
working interest in 3-D seismic projects or in wells. To the extent cash flow
from operations does not significantly increase and external sources of capital
are limited or unavailable, our ability to make the capital investment to
participate in 3-D seismic surveys and increase our interest in projects on our
acreage will be limited. Future funds are expected to be provided through
production from existing producing properties and new producing properties that
may be discovered through exploration of our acreage by third parties or by us.
Funds may also be provided through external financing in the form of debt or
equity. There can be no assurance as to the extent and availability of these
sources of funding.
We maintain our excess cash funds in interest-bearing deposits and in
marketable securities. In addition to the properties described above, we also
may acquire other producing oil and gas assets, which could require the use of
debt, including the Facility or other forms of financing.
Our management believes that sufficient funds are available from
internal sources and other third party sources to meet anticipated capital
requirements for fiscal 2000.
Through December 31, 1999 we have used $1,269,092 of our cash reserves
to purchase 475,500 shares of our Common Stock pursuant to three share
repurchase programs and discretionary repurchases of our stock subject to cash
availability as approved by the board of directors. On July 23, 1998, our board
of directors temporarily suspended the policy of share repurchases 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. There are 76,500 shares
available for repurchase under the program as of March 17, 2000.
During 1999, we received a total of $18,750 as a result of the exercise
of stock options to purchase our Common Stock by one former employee. Those
options related to 7,500 shares of Common Stock with an exercise price of $2.50
per share. In addition, we recognized compensation expense of $13,940 related to
stock options granted to former consultants that is reflected as a component of
Capital in excess of par value in the Consolidated Balance Sheets as of December
31, 1999.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Total revenues for 1999 were $5,603,269 compared with $2,308,640 in
1998. Revenues from oil and gas sales increased to $4,259,040 in 1999 from
$1,968,638 in 1998. This 116.3% increase reflects a 63.2% increase in volume on
a BOE basis (principally reflecting the benefit of a full year of revenue from
properties acquired in December of 1998) along with a 32.5% increase on a price
per BOE basis. Average oil prices increased 27.2% to $17.14 in 1999 from $13.48
in 1998. Average gas prices increased 12% to $2.14 in 1999 from $1.91 in 1998.
Our net oil production increased 28.1% to 128,924 Bbls in 1999 from 100,615 Bbls
in 1998. Net natural gas production increased 112.1% to 918,986 Mcf of natural
gas in 1999 from 433,272 Mcf of natural gas in 1998. Lease bonuses and rentals
were $463,083 in 1999, up from $168,664 in 1997, an increase of 174.6% primarily
as a result of leasing activity on our Southeastern States Holdings.
Interest and other income were $109,035 in 1999 versus $171,338 in
1998. This 36.4% decrease was due to the employment of short-term funds in the
acquisition of properties rather than retaining such funds in interest bearing
accounts.
Total costs and expenses were $4,758,331 in 1999 as compared with
$2,784,163 in 1998 representing a 70.9% increase. The largest increase came from
depreciation, depletion and amortization where expenses increased 148.3% to
$1,276,268 in 1999 versus $514,071 in 1998. This major increase reflects the
property acquisitions we made during December of 1998 and during 1999. Dry holes
and abandonments decreased 92.5% to $9,933 in 1999 from $133,113 in 1998, due to
the decreased drilling activity we participated in during 1999. Geological and
geophysical expenses decreased 23.8% to $394,496 in 1999 versus $517,870 in
1998, reflecting the completion of our acquisition and processing phase of the
two 3-D seismic projects that will generate future drilling sites. Our general
and administrative expenses increased $584,181 or 58.4% to $1,583,729 in 1999
from $999,548 in 1998, primarily resulting from the addition of staff. During
1999, we incurred interest expense of $794,627 as compared
24
27
with $36,120 in 1998 as a result of debt incurred for the property acquisitions
made from December of 1998 through December of 1999.
Total net income applicable to common shares for 1999 was $148,011 or
$0.03 per share compared to a net loss of $261,746 or $0.05 per share in 1998.
YEAR ENDED DECEMBER 31, 1998 COMPARED TO 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 43.9% to 100,615 Bbls in
1998 from 69,903 Bbls in 1997. Net natural gas production increased 1.74% to
433,272 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 were $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
related to the change in management. During 1998, we incurred interest expense
of $36,120 that 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.
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 as we do not
currently have any derivative or hedging instruments. This statement is
effective for all fiscal quarters of all fiscal years beginning after June 15,
2000.
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.
Please see Toreador Royalty Corporation Current Report on form 8-K
regarding a change in accountants filed on June 30, 1999 with an effective date
of May 24, 1999.
On May 24, 1999, we dismissed PricewaterhouseCoopers LLP ("PWC") as our
independent accountant and on May 24, 1999, we retained Ernst & Young LLP
("E&Y") as our independent accountant.
PWC's reports on our financial statements for the fiscal years ended
December 31, 1998 and 1997 did not contain an adverse opinion or disclaimer of
opinion, nor were they qualified or modified as to uncertainty, audit scope or
accounting principles.
The decision to engage E&Y as set forth above and to dismiss PWC was
approved by the audit committee and the board of directors of the Company. There
were no disagreements with PWC.
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 18, 2000, which will be filed with the Securities and Exchange
Commission on or prior to April 30, 2000, 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
18, 2000, which will be filed with the Securities and Exchange Commission on or
prior to April 30, 2000, 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 18, 2000, which
will be filed with the Securities and Exchange Commission on or prior to April
30, 2000, 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 18, 2000, which will be filed with the Securities
and Exchange Commission on or prior to April 30, 2000, and which is incorporated
herein by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a) The following documents are filed as part of this report:
1. Index to Consolidated Financial Statements Report of
Independent Accountants Consolidated Balance Sheet as
of December 31, 1999 and 1998 Consolidated Statement
of Operations for the three years ended December 31,
1999 Consolidated Statement of Changes in
Stockholders' Equity for the three years ended
December 31, 1999 Consolidated Statement of Cash
Flows for the three years ended December 31, 1999
Notes to Consolidated Financial Statements
26
29
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 (previously filed as Exhibit 3.1 to Toreador Royalty
Corporation Annual Report on Form 10-K for the year ended December 31,
1998, and incorporated herein by reference).
3.2 - Amended and Restated Bylaws, as amended, of Toreador Royalty Corporation
(previously filed as Exhibit 3.2 to Toreador Royalty Corporation Annual
Report on Form 10-K for the year ended December 31, 1998, and
incorporated herein by reference).
3.3 - 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 (previously filed as
Exhibit 4.1 to Toreador Royalty Corporation Annual Report on Form 10-K
for the year ended December 31, 1998, and incorporated herein by
reference).
4.2 - 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).
27
30
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(previously filed as
Exhibit 10.6 to Toreador Royalty Corporation Annual Report on Form 10-K
for the year ended December 31, 1998, and incorporated herein by
reference).
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).
28
31
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).
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 (previously filed
as Exhibit 10.13 to Toreador Royalty Corporation Annual Report on Form
10-K for the year ended December 31, 1998, and incorporated herein by
reference).
10.14+ - 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 (previously filed
as Exhibit 10.14 to Toreador Royalty Corporation Annual Report on Form
10-K for the year ended December 31, 1998, and incorporated herein by
reference).
10.15 - 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. Philp 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
(previously filed as Exhibit 10.17 to Toreador Royalty Corporation
29
32
Annual Report on Form 10-K for the year ended December 31, 1998, and
incorporated herein by reference).
10.18 - First Amendment to Loan Agreement, dated September 22, 1998, between
Toreador Royalty Corporation and Toreador Exploration & Production Inc
and Compass Bank (previously filed as Exhibit 10.18 to Toreador Royalty
Corporation Annual Report on Form 10-K for the year ended December 31,
1998, and incorporated herein by reference).
10.19 - Second Amendment to Loan Agreement, dated December 15, 1998, between
Toreador Royalty Corporation and Toreador Exploration & Production Inc
and Compass Bank (previously filed as Exhibit 10.19 to Toreador Royalty
Corporation Annual Report on Form 10-K for the year ended December 31,
1998, and incorporated herein by reference).
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).
10.21 - Amended and Restated Credit Agreement, dated April 16, 1999, between
Toreador Royalty Corporation and Toreador Exploration & Production Inc
and Compass Bank (previously filed as Exhibit 10.1 to Toreador Royalty
Corporation Quarterly Report on Form 10-Q for the quarter ended June 30,
1999, and incorporated herein by reference).
10.22 - Credit Agreement, effective September 30, 1999, between Compass Bank, as
Lender, Toreador Royalty Corporation, Toreador Exploration & Production
Inc, and Tormin, Inc., as Borrowers, and Toreador Acquisition
Corporation, as Guarantor (previously filed as Exhibit 10.1 to Toreador
Royalty Corporation Current Report on Form 8- K, filed on October 27,
1999, and incorporated herein by reference).
10.23 - Purchase and Sale Agreement, effective November 24, 1999, between Lario
Oil & Gas Company and Toreador Exploration & Production Inc. (previously
filed as Exhibit 10.1 to Toreador Royalty Corporation Current Report on
Form 8-K filed on January 6, 2000, and incorporated herein by reference).
10.24 - First Amendment to Loan Agreement, dated December 17, 1999, between
Compass Bank, as Lender, and Toreador Royalty Corporation, Toreador
Exploration & Production Inc. and Tormin, Inc., as Borrowers, and
Toreador Acquisition Corporation, as Guarantor (previously filed as
Exhibit 10.2 to Toreador Royalty Corporation Current Report on Form 8-K
filed on January 6, 2000, and incorporated herein by reference).
10.25 - Term Promissory Note, effective December 17, 1999, between Compass Bank,
as Lender, and Toreador Royalty Corporation, Toreador Exploration &
Production Inc. and Tormin, Inc., as Borrowers, and Toreador Acquisition
Corporation, as Guarantor (previously filed as Exhibit 10.3 to Toreador
Royalty Corporation Current Report on Form 8-K filed on January 6, 2000,
and incorporated herein by reference).
16.1 - Letter on Change in Certifying Accountant from PricewaterhouseCoopers
LLP, dated June 30, 1999 (previously filed as Exhibit 16 to Amendment No. 2
to Toreador Royalty Corporation Current Report on Form 8-K/A filed on
June 30, 1999, and incorporated herein by reference).
21.1* - Subsidiaries of Toreador Royalty Corporation.
30
33
23.1* - Consent of Ernst & Young LLP.
23.2* - Consent of PricewaterhouseCoopers LLP.
23.3* - Consent of LaRoche Petroleum Consultants, Ltd.
23.4* - Consent of Harlan Consulting.
27.1* - Financial Data Schedule.
- -------------------------
* Filed herewith.
+ Management contract or compensatory plan
(b) Reports on Form 8-K:
None.
31
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: March 21, 2000
By: /s/ G. THOMAS GRAVES III
------------------------------------
G. Thomas Graves III, President and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated.
SIGNATURE CAPACITY IN WHICH SIGNED DATE
--------- ------------------------ ----
/s/ G. THOMAS GRAVES III President, Chief Executive Officer and Director March 21, 2000
- -----------------------------------
G. Thomas Graves
/s/ J.W. BULLION Secretary and Director March 21, 2000
- -----------------------------------
J.W. Bullion
/s/ EDWARD NATHAN DANE Director March 21, 2000
- -----------------------------------
Edward Nathan Dane
/s/ PETER L. FALB Director March 21, 2000
- -----------------------------------
Peter L. Falb
/s/ THOMAS P. KELLOGG, JR Director March 21, 2000
- -----------------------------------
Thomas P. Kellogg, Jr.
/s/ WILLIAM I. LEE Director March 21, 2000
- -----------------------------------
William I. Lee
/s/ JOHN MARK McLAUGHLIN Chairman and Director March 21, 2000
- -----------------------------------
John Mark McLaughlin
/s/ DOUGLAS W. WEIR Vice President - Finance and Treasurer March 21, 2000
- ----------------------------------- (Principal Financial and Accounting Officer)
Douglas W. Weir
32
35
TOREADOR ROYALTY CORPORATION
ITEM 8
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES
PAGE
Reports of Independent Accountants................................................................................ F-2
Financial Statements:
Consolidated Balance Sheets as of December 31, 1999 and 1998................................................. F-4
Consolidated Statements of Operations for the three years ended December 31, 1999............................ F-5
Consolidated Statements of Changes in Stockholders' Equity for the three years ended December 31, 1999....... F-6
Consolidated Statements of Cash Flows for the three years ended December 31, 1999............................ F-7
Notes to Consolidated Financial Statements................................................................... F-8
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.
F-1
36
TOREADOR ROYALTY CORPORATION
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders
of Toreador Royalty Corporation
We have audited the accompanying consolidated balance sheet of Toreador
Royalty Corporation of December 31, 1999, and the related consolidated
statements of operations, shareholders' equity and cash flows for the year then
ended. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audit.
We conducted our audit in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audit provides a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the consolidated financial position of
Toreador Royalty Corporation at December 31, 1999, and the consolidated results
of their operations and their cash flows for the year then ended in conformity
with accounting principles generally accepted in the United States.
Ernst & Young LLP
Dallas, Texas
March 3, 2000
F-2
37
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 the results of their operations and
their cash flows for each of the two 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-3
38
TOREADOR ROYALTY CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31,
----------------------------
1999 1998
------------ ------------
ASSETS
Current assets:
Cash and cash equivalents $ 341,463 $ 726,187
Short-term investments 13,682 1,218,291
Accounts and notes receivable 1,112,502 517,442
Marketable securities 36,251 374,915
Federal income tax receivable -- 63,064
Assets held for sale -- 334,489
Other 73,995 61,130
------------ ------------
Total current assets 1,577,893 3,295,518
------------ ------------
Properties and equipment, less accumulated
depreciation, depletion and amortization 24,423,537 16,209,631
Other assets 328,391 78,873
Deferred tax benefit 126,159 198,240
------------ ------------
Total assets $ 26,455,980 $ 19,782,262
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 717,965 $ 587,754
Federal income taxes payable 171,317 --
Current portion of long-term debt 250,000 720,000
------------ ------------
Total current liabilities 1,139,282 1,307,754
Long-term debt 14,666,500 7,880,000
------------ ------------
Total liabilities 15,805,782 9,187,754
------------ ------------
Commitments and Contingencies (Note 11)
Stockholders' equity:
Preferred stock, $1.00 par value, 4,000,000
shares authorized; 160,000 issued 160,000 160,000
Common stock, $0.15625 par value, 20,000,000 and 10,000,000
shares authorized; 5,651,571 and 5,644,071 shares issued 883,058 881,886
Capital in excess of par value 8,234,380 8,202,862
Retained earnings 2,677,382 2,529,371
Accumulated other comprehensive loss (35,530) (24,922)
------------ ------------
11,919,290 11,749,197
Treasury stock at cost:
475,500 and 438,400 shares at December 31, 1999 and 1998 (1,269,092) (1,154,689)
------------ ------------
Total stockholders' equity 10,650,198 10,594,508
------------ ------------
Total liabilities and stockholders' equity $ 26,455,980 $ 19,782,262
============ ============
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-4
39
TOREADOR ROYALTY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
YEAR ENDED DECEMBER 31,
--------------------------------------------
1999 1998 1997
------------ ------------ ------------
Revenues:
Oil and gas sales $ 4,259,040 $ 1,968,638 $ 2,325,148
Lease bonuses and rentals 463,083 168,664 287,604
Interest and other income 109,035 171,338 149,841
Gain on sale of properties 851,726 -- 26,171
Loss on sale of marketable securities (79,615) -- --
------------ ------------ ------------
Total revenues 5,603,269 2,308,640 2,788,764
------------ ------------ ------------
Costs and expenses:
Lease operating 699,278 583,441 695,007
Dry holes and abandonments 9,933 133,113 166,710
Depreciation, depletion and amortization 1,276,268 514,071 539,346
Geological and geophysical 394,496 517,870 546,634
General and administrative 1,583,729 999,548 802,723
Loss on settlement of benefit plans -- -- 173,971
Interest 794,627 36,120 --
------------ ------------ ------------
Total costs and expenses 4,758,331 2,784,163 2,924,391
------------ ------------ ------------
Income (loss) before federal income taxes 844,938 (475,523) (135,627)
Provision (benefit) for federal income taxes 336,927 (233,277) (84,261)
------------ ------------ ------------
Net income (loss) 508,011 $ (242,246) $ (51,366)
------------ ------------ ------------
Dividends on preferred shares 360,000 19,500 --
------------ ------------ ------------
Income (loss) applicable to common shares $ 148,011 $ (261,746) $ (51,366)
============ ============ ============
Basic and diluted income (loss) per share $ 0.03 $ (0.05) $ (0.01)
============ ============ ============
Weighted average shares outstanding
Basic 5,185,588 5,125,063 5,022,216
Diluted 5,250,862 5,125,063 5,022,216
See accompanying notes to the consolidated financial statements.
F-5
40
TOREADOR ROYALTY CORPORATION
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
ACCUMULATED
CAPITAL IN OTHER
PREFERRED COMMON EXCESS OF RETAINED COMPREHENSIVE TREASURY
STOCK STOCK PAR VALUE EARNINGS INCOME STOCK
---------- ---------- ----------- ----------- ------------ ----------
Balance at December 31, 1996 ............. $ -- $ 836,964 $ 3,577,385 $ 2,842,483 $ (88,543) $ (544,109)
Issuance of common stock ................. -- 1,719 69,449 --
Purchase of treasury stock ............... -- -- -- -- (515,330)
Comprehensive income
Net loss ............................... -- -- -- (51,366) -- --
Other comprehensive income, net of tax
Minimum pension liability............ 88,543
Total comprehensive income ...............
----------- ----------- ----------- ----------- ----------- -----------
Balance at December 31, 1997 ............. -- 838,683 3,646,834 2,791,117 -- (1,059,439)
Issuance of common stock ................. -- 43,203 766,809 --
Issuance of preferred stock .............. 160,000 -- 3,789,219 -- --
Dividends declared on preferred stock .... -- -- -- (19,500) --
Purchase of treasury stock ............... -- -- -- -- (95,250)
Comprehensive income
Net loss ............................... -- -- -- (242,246) -- --
Other comprehensive income, net of tax
Unrealized loss on securities ........ (24,922)
Total comprehensive loss .................
----------- ----------- ----------- ----------- ----------- -----------
Balance at December 31, 1998 ............. 160,000 881,886 8,202,862 2,529,371 (24,922) (1,154,689)
Issuance of common stock ................. -- 1,172 31,518 --
Dividends declared on preferred stock .... -- -- -- (360,000) --
Purchase of treasury stock ............... -- -- -- -- (114,403)
Comprehensive income
Net income ............................. -- -- -- 508,011 -- --
Other comprehensive loss, net of tax
Unrealized loss on securities ........ (63,154)
Less reclassification adjustment for
losses included in net income ........ 52,546
Total comprehensive income ...............
----------- ----------- ----------- ----------- ----------- -----------
Balance at December 31, 1999 ............. $ 160,000 $ 883,058 $ 8,234,380 $ 2,677,382 $ (35,530) $(1,269,092)
=========== =========== =========== =========== =========== ===========
TOTAL
STOCKHOLDERS'
EQUITY
--------------
Balance at December 31, 1996 ............. $ 6,624,180
Issuance of common stock ................. 71,168
Purchase of treasury stock ............... (515,330)
Comprehensive income
Net loss ............................... (51,366)
Other comprehensive income, net of tax
Minimum pension liability ............ 88,543
-----------
Total comprehensive income 37,177
-----------
Balance at December 31, 1997 ............. 6,217,195
Issuance of common stock ................. 810,012
Issuance of preferred stock .............. 3,949,219
Dividends declared on preferred stock .... (19,500)
Purchase of treasury stock ............... (95,250)
Comprehensive income
Net loss ............................... (242,246)
Other comprehensive income, net of tax
Unrealized loss on securities ........ (24,922
-----------
Total comprehensive loss ................. (267,168)
-----------
Balance at December 31, 1998 ............. 10,594,508
Issuance of common stock ................. 32,690
Dividends declared on preferred stock .... (360,000)
Purchase of treasury stock ............... (114,403)
Comprehensive income
Net income ............................. 508,011
Other comprehensive loss, net of tax
Unrealized loss on securities ........ (63,154)
Less reclassification adjustment for
losses included in net income ........ 52,546
-----------
Total comprehensive income ............... 497,403
-----------
Balance at December 31, 1999 ............. $10,650,198
===========
F-6
41
TOREADOR ROYALTY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31,
------------------------------------------------
1999 1998 1997
------------ ------------ ------------
Cash flows from operating activities:
Net income (loss) $ 508,011 $ (242,246) $ (51,366)
Adjustments to reconcile net income (loss) to
net cash provided (used) by operating activities:
Depreciation, depletion and amortization 1,276,268 514,071 539,346
Dry holes and abandonments 9,933 133,113 166,710
Loss on sale of marketable securities 79,615 -- --
Gain on sale of properties (851,726) -- (26,171)
Decrease (increase) in accounts and notes receivable (595,060) (182,591) 173,942
Decrease (increase) in federal income tax receivable 63,064 (757) (7,408)
Decrease in pension obligation -- -- 88,543
Decrease (increase) in other current assets (12,865) (34,174) 38,145
Increase in accounts payable and accrued liabilities 149,711 258,664 53,290
Increase (decrease) in federal income taxes payable 171,317 -- (62,938)
Increase in other assets (112,500) -- --
Deferred tax expense (benefit) 77,546 (169,456) (81,453)
------------ ------------ ------------
Net cash provided by operating activities 763,314 276,624 830,640
------------ ------------ ------------
Cash flows from investing activities:
Expenditures for oil and gas property and equipment (486,275) (797,438) (717,478)
Acquisition of oil and gas properties (8,722,073) (13,154,543) --
Proceeds from lease bonuses and rentals 27,407 -- 77,583
Sale (purchase) of short-term investments 1,204,609 (1,218,291) --
Purchase of marketable securities (35,241) (412,676) --
Proceeds from sale of marketable securities 278,217 -- --
Proceeds from sale of properties and other assets 1,024,676 -- 56,065
Purchase of partnership interest (114,241) -- --
Purchase of furniture and fixtures (157,627) (29,249) (107)
------------ ------------ ------------
Net cash used by investing activities (6,980,548) (15,612,197) (583,937)
------------ ------------ ------------
Cash flows from financing activities:
Payment for debt issue costs (22,777) (78,873) --
Proceeds from issuance of common stock 32,690 810,012 71,168
Proceeds from issuance of preferred stock, net -- 3,949,219
Decrease in current portion of long-term debt (470,000) -- --
Proceeds from long-term debt 6,786,500 8,600,000 --
Payment of preferred dividends (379,500) -- --
Purchase of treasury stock (114,403) (95,250) (515,330)
------------ ------------ ------------
Net cash provided (used) by financing activities 5,832,510 13,185,108 (444,162)
------------ ------------ ------------
Net decrease in cash and cash equivalents (384,724) (2,150,465) (197,459)
Cash and cash equivalents, beginning of year 726,187 2,876,652 3,074,111
------------ ------------ ------------
Cash and cash equivalents, end of period $ 341,463 $ 726,187 $ 2,876,652
============ ============ ============
Supplemental schedule of cash flow information:
Cash paid (received) during the period for:
Income taxes $ -- $ (63,064) $ 4,475
Interest expense $ 620,106 $ -- $ --
See accompanying notes to the consolidated financial statements.
F-7
42
TOREADOR ROYALTY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES
Toreador Royalty Corporation ("Toreador" or the "Company") is an
independent oil and gas company engaged in domestic oil and gas
exploration, development, production and acquisition activities. The
Company owns in excess of 1,300,000 net mineral acres located primarily
in Mississippi, Texas and Alabama. In addition, the Company owns
working or royalty interests in Mississippi, Texas, Kansas, Alabama,
California, Michigan, New Mexico, Oklahoma, Louisiana and Arkansas. The
Company's business activities are conducted primarily with industry
partners located within the United States.
PERVASIVENESS OF ESTIMATES
The preparation of financial statements in conformity with 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
and its wholly-owned subsidiaries, Toreador Exploration & Production
Inc. ("Toreador E&P") and Tormin, Inc. ("Tormin"). All intercompany
accounts and transactions have been eliminated.
CASH AND CASH EQUIVALENTS
Cash and cash equivalents include cash on hand, amounts due from banks
and all highly liquid investments with original maturities of three
months or less. The Company maintains its cash in bank deposit accounts
which, at times, may exceed federally insured limits. The Company has
not experienced any losses in such accounts and believes it is not
exposed to any significant risk on cash.
MARKETABLE SECURITIES
When securities are purchased they are designated as trading securities
or available for sale. Trading investments are classified as current
assets and changes in fair value are reported in the statement of
operations. Investments in available for sale securities are classified
based upon management's intent to sell the security and changes in fair
value are reported net of tax as a separate component of accumulated
other comprehensive income (loss).
FINANCIAL INSTRUMENTS
The carrying amounts of financial instruments including cash and cash
equivalents, short-term investments, accounts receivable, marketable
securities, accounts payable and accrued liabilities and long-term debt
approximate fair value, unless otherwise stated, as of December 31,
1999 and 1998.
F-8
43
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 that do not find proved
reserves are expensed. Significant costs associated with the
acquisition of oil and gas properties are capitalized. Upon sale or
abandonment of units of property or the disposition of miscellaneous
equipment, the cost is removed from the asset account, the related
reserves relieved of the accumulated depreciation or depletion and the
gain or loss is credited to or charged against operations.
Maintenance and repairs are charged to expense; betterments of property
are capitalized and depreciated as described below.
LEASE BONUSES
The Company defers bonuses received from leasing minerals in which
unrecovered costs remain by recording the bonuses as a reduction of the
unrecovered costs. Bonuses received from leasing mineral interests
previously expensed are taken into income. For federal income tax
purposes, lease bonuses are regarded as advance royalties (ordinary
income). Bonuses totaling $27,407, zero and $77,583 were recorded as
cost reductions for the years ending December 31, 1999, 1998 and 1997,
respectively.
DEPRECIATION, DEPLETION AND AMORTIZATION
The Company provides for depreciation, depletion and amortization of
its investment in producing oil and gas properties on the
unit-of-production method, based upon independent reserve engineers'
estimates of recoverable oil and gas reserves from the property.
Depreciation expense for fixed assets is generally calculated on a
straight-line basis based upon estimated useful lives of five years.
IMPAIRMENT OF ASSETS
Producing property costs are evaluated for impairment and reduced to
fair value if the sum of expected undiscounted future cash flows is
less than net book value pursuant to Statement of Financial Accounting
Standard No. 121 (SFAS 121) "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of."
Impairment of non-producing leasehold costs and undeveloped mineral and
royalty interests are assessed periodically on a property by property
basis, and any impairment in value is currently charged to expense.
There was an impairment loss during 1999 in the amount of $14,401
primarily due to the decrease in oil and gas reserves for the affected
producing properties. There was an impairment in 1998 of $19,649
resulting from the decrease in oil and gas prices and there was no
impairment during 1997. The impairments are included in the
"Depreciation, depletion and amortization" category of the consolidated
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, 1999 and 1998, the imbalance and related value were immaterial.
F-9
44
TOREADOR ROYALTY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 (LOSS) PER COMMON SHARE
Basic earnings (loss) per common share amounts were computed by
dividing net income (loss) after deduction of dividends on preferred
shares by the weighted average number of common shares outstanding
during the period. Diluted 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. The increase in potential shares used to determine
dilutive income per share for the year ended December 31, 1999 is
attributable to dilutive stock options. Stock options were not
considered in the diluted loss per share calculations for 1998 and 1997
as the effect would be antidilutive.
2. MARKETABLE SECURITIES
Marketable securities at December 31,1999 and 1998 consist of several
issues of preferred stock with a fair market value of $36,251 and
$374,915, respectively. The Company has designated these investments as
"securities available for sale" pursuant to Statement of Financial
Accounting Standards No. 115. The net unrealized loss related to these
securities before taxes is $16,073 ($10,608 net of tax) and $37,761
($24,922 net of tax) for the same respective periods and is reflected
as a component of other comprehensive income (loss). During 1999, a
portion of the available-for-sale securities was sold for $278,217
resulting in a net loss before taxes of $79,615 ($52,546 net of tax)
based upon historical cost.
3. ACCOUNTS RECEIVABLE
Accounts receivable consist of the following:
DECEMBER 31,
-----------------------
1999 1998
---------- ----------
Oil and gas ............. $1,073,035 $ 417,442
Note receivable ......... 30,000 --
Other receivables ....... 9,467 100,000
---------- ----------
$1,112,502 $ 517,442
========== ==========
Oil and gas receivables are due from companies engaged principally in
oil and gas activities, with payment terms on a short-term basis and in
accordance with industry standards. The note receivable is the current
amount due from the purchaser of non-strategic assets during 1999.
F-10
45
TOREADOR ROYALTY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. PROPERTIES AND EQUIPMENT
Properties and equipment consist of the following:
DECEMBER 31,
----------------------------
1999 1998
------------ ------------
Undeveloped mineral and royalty interests .................. $ 7,404,891 $ 7,270,632
Non-producing leaseholds ................................... 408,899 122,267
Producing leaseholds ....................................... 9,129,775 3,607,307
Producing royalty interests ................................ 10,581,301 7,306,423
Lease and well equipment ................................... 523,374 417,382
Furniture and fixtures and other assets .................... 265,895 108,268
------------ ------------
28,314,135 18,832,279
Accumulated depreciation, depletion and amortization ....... (3,890,598) (2,622,648)
------------ ------------
$ 24,423,537 $ 16,209,631
============ ============
During 1999 the Company sold various properties and equipment for
$1,024,676 (net of closing costs) resulting in a gain of $851,726
before tax. Of this total, undeveloped royalty interest acreage in West
Texas was sold for $997,500 (net of closing costs) and various
producing leaseholds were sold for $27,176 resulting in gains before
tax of $851,600 and $126, respectively.
5. ACQUISITION OF OIL AND GAS PROPERTIES
On September 30, 1999, Toreador purchased certain oil and gas royalty
interests located in Arkansas, California, Kansas and Michigan (the
"Properties") from Conoco, Inc. ("Conoco"), pursuant to a written offer
by Toreador and a letter of acceptance from Conoco. The purchase price
for the Properties was $3,215,000 before adjustments. The adjusted
purchase price was $3,274,878. The effective date of the purchase was
August 1, 1999.
The purchase price for the Properties was funded with the Company's
available cash ($600,000) and a loan from Compass Bank, Dallas
($2,615,000). The acquisition was accounted for under the purchase
method of accounting.
On December 22, 1999, Toreador E&P purchased from Lario Oil & Gas
Company ("Lario") 50% of their oil and gas working interests in
designated oil and gas leases and properties located in Finney County,
Kansas (the "Assets"), pursuant to a Purchase and Sale Agreement dated
as of November 24, 1999, between Lario and Toreador E&P (the "Lario
Agreement"). The purchase price for the Assets before adjustments was
$5,500,000, consisting of $5,000,000 cash and an agreement to pay the
amount of $500,000 on an installment basis. Half of this amount
($250,000) is to be repaid by Toreador on a monthly basis, plus
interest at prime plus 1%, amortized over 13 months. The remaining
$250,000 plus interest at prime plus 1% (which is currently 9.5% per
annum) is to be repaid by Toreador on January 23, 2001. The adjusted
purchase price was $5,447,195.
The purchase price for the Assets was funded with Toreador's available
cash ($1,000,000), a loan from Compass Bank, Dallas ($4,000,000) and
the $500,000 to be paid by Toreador to Lario on an installment basis.
In connection with the borrowings to finance the acquisition of the
Assets, Toreador, Toreador E&P and Tormin entered into an amendment to
its existing Credit Agreement with Compass Bank, which Credit Agreement
was effective September 30, 1999. The amendment to the Credit Agreement
increased the borrowing base to $12,500,000 from the previous borrowing
base of $10,500,000, and provided $2,000,000 of the acquisition price
of the Assets.
Toreador, Toreador E&P and Tormin also executed a Term Promissory Note
(the "Note") with Compass Bank, which provided an additional $2,000,000
of the cash portion of the purchase price for the Assets. The Note
bears interest equal to the variable prime rate published in The Wall
Street Journal's "Money Rates" table (the "Prime Rate"), which is
currently 8.5% per annum. The amendment to the Credit Agreement and the
Note are secured by a pledge of Toreador's assets, including all of the
properties within the Assets. The Note maturity has been extended to
April 1, 2001 from the original date of March 1, 2000.
F-11
46
TOREADOR ROYALTY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following summarized unaudited pro forma financial information
assumes the acquisition of the Properties and the Assets occurred on
January 1 of each year:
YEAR ENDED DECEMBER 31,
---------------------------
1999 1998
------------ ------------
Revenues ................................... $ 7,401,661 $ 3,742,544
Net income (loss) .......................... $ 491,208 $ (491,602)
Net income (loss) applicable to common
shares ................................... $ 131,208 $ (511,102)
Net income (loss) per share - basic ........ $ .03 $ (.10)
Net income (loss) per share - diluted ...... $ .02 $ (.10)
The pro forma results do not necessarily represent results that would
have occurred if the transactions had taken place on the basis assumed
above, nor are they indicative of the results of future combined
operations.
6. LONG-TERM DEBT
In November 1997, the Company obtained a $10,000,000 credit facility
from Compass Bank (the "Facility" as amended). In December 1998, the
Company borrowed $2,700,000 against the Facility which was used to
finance the Southeastern States Mineral Acquisition (the "Southeastern
States 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 the loan
were $2,700,000 and $5,900,000, respectively.
A new credit agreement was entered into as of September 30, 1999 with
Compass Bank that amended the Facility and terminated the loan with
proceeds from the Facility. The Facility was increased to a limit of
$25,000,000 subject to the underlying collateral value. The amount
outstanding at December 31, 1999 was $12,416,500. 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 less one-quarter as long as the amount borrowed is greater than
80% of the borrowing base as defined by the lender ($12,500,000 at
December 31, 1999). The rate will drop an additional 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, 1999 was 8.25%, and the Company is
currently not subject to any fees. The maturity date is October 1,
2002.
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 Company was in compliance with all covenants as of
December 31, 1999.
The Company obtained a term promissory note (the "Note" as amended) in
December, 1999. The interest rate is equal to the prime rate. The
interest rate on the loan was 8.5% at December 31,1999. The maturity
date is April 1, 2001. The outstanding balance of the Note was
$2,000,000 as of December 31, 1999.
Each of the above described debt issues is controlled by the borrowing
base. The amount of debt outstanding at any time is not allowed to
exceed the borrowing base as determined by the lender. The borrowing
base is subject to evaluation every six months and can be adjusted
either up or down. The Company is required to repay any principal which
exceeds the revised borrowing base.
As per the terms of the Lario Agreement, the Company agreed to pay a
portion of the purchase price ($500,000) on an installment basis. Half
of this amount ($250,000) is to be repaid by the Company on a monthly
basis, plus interest at prime plus 1%, amortized over 13 months
beginning January, 2000. The remaining $250,000 plus interest at prime
plus 1% (which is currently 9.5% per annum) is to be repaid by the
Company on January 23, 2001.
F-12
47
TOREADOR ROYALTY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Aggregate principal reductions are as follows for each year ended
December 31:
2000................... $ 250,000
2001................... 2,250,000
2002................... 12,416,500
7. CAPITAL
In connection with the private placement in 1994, the Company's
placement agent received a five-year warrant to purchase 106,867 shares
of common stock at a price of $4.375 per share and the right to
participate in registered offerings of common stock by the Company. The
Company paid $25,000 to the placement agent in December 1998 in order
to terminate the warrant and the related rights.
The Company adopted a stockholder rights plan on April 3, 1995. 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 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.
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, 1999, the Company had repurchased 219,800 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.
F-13
48
TOREADOR ROYALTY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In December 1998, the Company sold 160,000 shares of Series A Preferred
Stock for net proceeds of $3,949,219. The sale was made through a
private placement. At the option of the holder, the preferred stock may
be converted into common shares at a price of $4 per common share. The
Company, at its option, may redeem the preferred stock at its stated
value of $25 per share on or after December 1, 2004. The preferred
stock accrues dividends at an annual rate of $2.25 per share payable
quarterly in cash. The proceeds from the sale were used in part to
finance the Southeastern States mineral acquisition.
8. INCOME TAXES
The Company's provision (benefit) for income taxes was comprised of the
following:
YEAR ENDED DECEMBER 31,
----------------------------------------------
1999 1998 1997
----------- ----------- -----------
Federal:
Current.......................... $ 259,381 $ (63,821) $ (2,808)
Deferred......................... 77,546 (169,456) (81,453)
----------- ----------- -----------
Provision (benefit) for income taxes.. $ 336,927 $ (233,277) $ (84,261)
=========== =========== ===========
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,
--------------------------------------
1999 1998 1997
---------- ---------- ----------
Statutory tax at 34% ......................... $ 287,279 $ (161,678) $ (46,113)
Surtax or rate difference .................... -- -- (958)
Statutory depletion in excess of tax basis ... (4,838) (69,979) (38,013)
State income tax ............................. 25,000
Other ........................................ 29,486 (1,620) 823
---------- ---------- ----------
Provision (benefit) for income taxes ......... $ 336,927 $ (233,277) $ (84,261)
========== ========== ==========
At December 31, 1998, the net operating loss for tax purposes totaled
$641,176, of which approximately $185,000 will be carried back to
offset prior year(s) taxable income. The remaining net operating loss
was carried forward and utilized against 1999 current 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, 1999 and 1998 were as follows:
1999 1998
---------- ----------
Deferred tax liabilities:
Intangible drilling and development costs ........... $ (194,184) $ (210,104)
Lease and well equipment ............................ (21,565) (13,949)
Leasehold costs ..................................... (54,298) (2,260)
---------- ----------
Gross deferred tax liabilities .................. (270,047) (226,313)
---------- ----------
Deferred tax assets:
Depletion carryforwards ............................. 2,585 115,172
Net operating tax loss carryforward ................. -- 154,936
Geological and geophysical costs .................... 162,900 78,179
Tax credit carryforwards ............................ 212,417 63,427
Unrealized loss on marketable securities ............ 18,304 12,839
---------- ----------
Gross deferred tax assets .................. 396,206 424,553
---------- ----------
Net deferred tax assets .................................. $ 126,159 $ 198,240
========== ==========
F-14
49
TOREADOR ROYALTY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Of the change in deferred taxes, $5,465 was credited to net unrealized
loss on marketable securities in stockholders' equity for 1999. The tax
credit carryforwards and depletion carryforwards are available
indefinitely.
9. BENEFIT PLANS
The Company had a noncontributory defined benefit pension plan which
was cancelled effective January 1, 1999. The benefits were based on
years of service and the employee's compensation. Upon final
dissolution of the plan a full distribution will be made to each
eligible employee. This plan was replaced with a 401-K plan.
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 all of its benefit plan obligations
with certain employees resulting in a charge to operations 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:
1999 1998
-------- --------
Benefit obligation at beginning of year .......... $ 25,564 $ 4,365
Service cost ..................................... 14,613 13,825
Interest on pension benefit obligation ........... 1,789 306
Actuarial loss (gain) ............................ 717 7,068
Benefits paid .................................... -- --
-------- --------
Benefit obligation at end of year ................ 42,683 25,564
======== ========
Change in plan assets:
Fair value of plan assets at beginning of year ... 34,247 5,020
Actual return on plan assets ..................... 2,654 1,477
Employer contributions ........................... -- 27,750
Benefits paid .................................... -- --
-------- --------
Fair value of plan assets at end of year ......... 36,901 34,247
-------- --------
Funded status (excess / (shortage)) .............. (5,782) 8,683
Unrecognized net actuarial loss .................. -- 6,914
-------- --------
Prepaid pension cost ............................. $ (5,782) $ 15,597
======== ========
Weighted average assumptions at measurement date:
1999 1998
------ ------
Discount rate 7% 7%
Expected long-term rate of return on assets 7% 7%
Rate of increase in compensation levels 0% 3.0%
F-15
50
TOREADOR ROYALTY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table sets forth the net periodic costs for the plan as of
December 31, 1999, 1998 and 1997:
1999 1998 1997
---------- ---------- ----------
Service cost........................... $ 14,613 $ 13,825 $ 55,212
Interest cost.......................... 1,789 306 15,401
Expected return on assets.............. (2,397) (1,323) (12,824)
Amortization of transition (asset)..... -- -- (2,875)
Recognized net actuarial loss (gain)... 205 -- 8,129
----------- ----------- -----------
$ 14,210 $ 12,808 $ 63,043
=========== =========== ===========
10. 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 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, for
options to purchase 250,000 and 45,000 shares of common stock,
respectively.
From time to time the Company has issued stock options which did not
fall under any existing plan.
Pursuant to SFAS No. 123, the Company recorded an expense of $13,939,
$19,747 and $44,011 during 1999, 1998 and 1997, respectively, for stock
options granted to certain consultants to the Company.
A summary of stock option transactions are as follows:
1999 1998 1997
--------------------- --------------------- ---------------------
WEIGHTED- WEIGHTED- WEIGHTED-
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
-------- -------- -------- -------- -------- --------
Outstanding at beginning of year 462,500 $ 4.05 469,000 $ 2.97 452,500 $ 3.16
Granted 180,000 5.00 340,000 4.38 117,500 2.50
Exercised (7,500) 2.50 (276,500) 2.86 (11,000) 2.47
Forfeited -- -- (70,000) 3.11 (90,000) 3.36
-------- -------- -------- -------- -------- --------
Outstanding at end of year 635,000 $ 4.34 462,500 $ 4.05 469,000 $ 2.97
======== ======== ======== ======== ======== ========
Exercisable at end of year 216,658 $ 3.85 100,833 $ 3.28 411,500 $ 3.02
======== ======== ======== ======== ======== ========
F-16
51
TOREADOR ROYALTY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For stock options granted during 1999 the following represents the
weighted-average exercise prices and the weighted-average fair value
based upon whether or not the exercise price of the option was greater
than, less than or equal to the market price of the stock on the grant
date:
WEIGHTED- WEIGHTED-
AVERAGE EXERCISE AVERAGE
OPTION TYPE PRICE FAIR VALUE
--------------------------------------------- ---------------- ----------
Exercise price greater than market price..... $ 5.00 $ 1.07
The following table summarizes information about the fixed price stock
options outstanding at December 31, 1999:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------------------------- ---------------------------------------------
WEIGHTED WEIGHTED WEIGHTED
NUMBER AVERAGE AVERAGE NUMBER AVERAGE
RANGE OF OUTSTANDING AT REMAINING EXERCISE EXERCISABLE EXERCISE
EXERCISE PRICES 12/31/99 CONTRACTUAL LIFE PRICE AT 12/31/99 PRICE
--------------- -------------- ---------------- ---------- ----------- ----------
$ 2.50 65,000 6.1 Years $ 2.50 33,333 $ 2.50
2.75 60,000 8.8 Years 2.75 20,000 2.75
3.25 - 3.50 50,000 4.7 Years 3.40 50,000 3.40
3.63 30,000 1.4 Years 3.63 30,000 3.63
5.00 430,000 9.2 Years 5.00 83,325 5.00
------------ ----------- ----------- ---------- ----------- ----------
$2.50 - 5.00 635,000 8.1 Years $ 4.05 216,658 $ 3.85
============ =========== =========== ========== =========== ==========
At December 31, 1999, 30,000 shares were available for grant under the
Plan and 140,000 shares were available for grant as options under the
Nonemployee Director Plan.
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:
1999 1998 1997
------------- ------------ ------------
Net income (loss) As reported $ 148,011 $ (261,746) $ (51,366)
Pro forma $ 114,820 $ (291,577) $ (82,515)
Basic income (loss) per share As reported $ 0.03 $ (0.05) $ (0.01)
Pro forma $ 0.02 $ (0.05) $ (0.02)
Diluted income (loss) per share As reported $ 0.03 $ (0.05) $ (0.01)
Pro forma $ 0.02 $ (0.05) $ (0.02)
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/share; expected volatility of 27%; risk-free
interest rate of 6.4% and expected lives of 5 years. The fair value of
each option granted during 1999 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 59%;
risk-free interest rate of 6.63% and expected lives of 5 years.
F-17
52
TOREADOR ROYALTY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. LEASE AND OTHER COMMITMENTS
The Company has entered into non-cancelable operating leases for office
space and a vehicle used in its operation. The remaining lease terms
are for periods of thirty-two months and fifty-one months for the
office space and the vehicle, respectively. Minimum annual rentals at
December 31, 1999 are as follows:
2000 $ 93,118
2001 99,311
2002 70,177
2003 11,909
2004 1,985
12. RELATED PARTY TRANSACTIONS
A director of the Company also owns Wilco Properties, Inc. The Company
entered into a technical services agreement with Wilco Properties, Inc.
("Wilco") effective February 1, 1999 whereby the Company provides
accounting and geological management services for a monthly fee of
$7,250. The Company also subleases office space to Wilco pursuant to a
sub-lease agreement.
During the first nine months of 1999 Wilco subleased to the Company and
then took over the lease and subleased space back to Wilco. The Company
received payments totaling $108,696 from Wilco and made payments
totaling $140,636 to Wilco during 1999.
13. OIL AND GAS PRODUCING ACTIVITIES
The following information is presented pursuant to SFAS No. 69,
Disclosures about Oil and Gas Producing Activities:
RESULTS OF OPERATIONS
Results of operations from oil and gas producing activities were as
follows:
1999 1998 1997
---------- ---------- ----------
Crude oil, condensate and natural gas ................ $4,259,040 $1,968,638 $2,325,148
Lease bonuses and delay rentals ...................... 463,083 168,664 287,604
---------- ---------- ----------
Total revenues .................................. 4,722,123 2,137,302 2,612,752
========== ========== ==========
Costs and expenses:
Lease operating costs ........................... 699,278 583,441 695,007
Exploration costs ............................... 404,429 650,983 713,344
Depreciation and depletion ...................... 1,247,278 510,775 539,346
---------- ---------- ----------
Income before income taxes ........................... 2,371,138 392,103 665,055
Income tax expense ................................... 806,187 133,315 226,119
---------- ---------- ----------
Results of operations from producing activities
(excluding corporate overhead) ....................... $1,564,951 $ 258,788 $ 438,936
========== ========== ==========
CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES:
DECEMBER 31,
------------------------------------------------
1999 1998 1997
------------ ------------ ------------
Unproved properties(a) ..................... $ 7,813,790 $ 7,727,388 $ 361,400
Proved leaseholds .......................... 19,711,076 10,913,730 4,574,844
Lease and well equipment ................... 523,374 417,382 303,388
------------ ------------ ------------
28,048,240 19,058,500 5,239,632
Less: Accumulated depreciation,
depletion and amortization ..... (3,786,649) (2,608,905) (2,036,912)
------------ ------------ ------------
Capitalized costs .......................... $ 24,261,591 $ 16,449,595 $ 3,202,720
============ ============ ============
F-18
53
TOREADOR ROYALTY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(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:
1999 1998 1997
------------- ------------- -------------
Acquisition of properties
Proved..................................... $ 8,722,073 $ 5,883,911 $ 192,670
Unproved................................... 286,631 7,365,988 56,245
Exploration costs............................... 28,200 133,113 166,710
Development costs............................... 171,444 568,969 301,853
------------- ------------- -------------
Costs incurred.................................. $ 9,208,348 $ 13,951,981 $ 717,478
============= ============= =============
14. SUPPLEMENTAL OIL AND GAS RESERVES AND STANDARDIZED MEASURE INFORMATION
(UNAUDITED)
The following table identifies the Company's net interest in estimated
quantities of proved oil and gas reserves and changes in such estimated
quantities. 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,
1999, 1998 and 1997 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).
OIL(BBL) GAS(MCF)
---------- ----------
PROVED DEVELOPED AND UNDEVELOPED RESERVES
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
Purchases of reserves in place ................... 1,282,123 1,602,953
Revisions of previous estimates .................. (121,532) (2,640,742)
Extensions, discoveries, and other additions ..... 51,494 377,177
Production ....................................... (128,924) (918,986)
---------- ----------
December 31, 1999 ................................ 2,196,666 8,210,842
========== ==========
PROVED DEVELOPED RESERVES
December 31, 1997 ................................ 501,726 2,487,574
========== ==========
December 31, 1998 ................................ 1,094,454 8,500,655
========== ==========
December 31, 1999 ................................ 1,999,984 8,070,533
========== ==========
F-19
54
TOREADOR ROYALTY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
1999 1998 1997
------------ ------------ ------------
Future cash inflows ........................................ $ 69,816,041 $ 29,011,780 $ 14,558,500
Future production costs .................................... 14,567,866 5,110,313 4,096,800
Future development costs ................................... 588,733 44,279 366,900
------------ ------------ ------------
Future net cash flows before income taxes .................. 54,659,442 23,857,188 10,094,800
Future income tax expense .................................. 13,259,925 5,375,278 2,628,421
------------ ------------ ------------
Future net cash flows ...................................... 41,399,517 18,481,910 7,466,379
10% annual discount for estimated timing of cash flows ..... 15,891,904 7,011,003 2,597,628
------------ ------------ ------------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves .................... $ 25,507,613 $ 11,470,907 $ 4,868,751
============ ============ ============
The average oil and gas prices used to calculate future net cash
inflows at December 31, 1999 were $23.42 per barrel and $2.24 per mcf,
respectively. At December 31, 1999 and March 17, 2000, respectively,
the NYMEX price for oil was $25.60 per barrel and $30.91 per barrel and
the NYMEX price for gas was $2.43 per MMBtu and $2.785 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:
1999 1998 1997
------------ ------------ ------------
Balance at January 1 ............................. $ 11,470,907 $ 4,868,751 $ 8,317,633
Sales of oil and gas produced, net ............... (3,559,762) (1,385,196) (1,630,141)
Net changes in prices and production costs ....... 6,760,297 (2,206,776) (2,968,223)
Extensions and discoveries ....................... 1,234,841 181,087 1,432,864
Revisions of previous quantity estimates ......... (4,901,897) 1,813,841 (3,720,824)
Net change in income taxes ....................... (3,309,637) (473,300) 1,737,609
Accretion of discount ............................ 1,147,091 486,875 831,763
Purchases of reserves ............................ 14,706,892 8,304,398 494,526
Other ............................................ 1,958,881 (118,773) 373,544
------------ ------------ ------------
Balance at December 31 ........................... $ 25,507,613 $ 11,470,907 $ 4,868,751
============ ============ ============
F-20
55
INDEX TO EXHIBITS
Exhibit
Number Exhibits
- ------- ------------------------------------------------------------------------------------------------
3.1 - Certificate of Incorporation, as amended, of Toreador Royalty Corporation (previously filed
as Exhibit 3.1 to Toreador Royalty Corporation Annual Report on Form 10-K for the year ended
December 31, 1998, and incorporated herein by reference).
3.2 - Amended and Restated Bylaws, as amended, of Toreador Royalty Corporation (previously filed as
Exhibit 3.2 to Toreador Royalty Corporation Annual Report on Form 10-K for the year ended
December 31, 1998, and incorporated herein by reference).
3.3 - 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 (previously filed as Exhibit 4.1 to Toreador Royalty Corporation Annual
Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by
reference).
4.2 - 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
56
Exhibit
Number Exhibits
- ------- ------------------------------------------------------------------------------------------------
(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).
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(previously filed as Exhibit 10.6 to Toreador Royalty Corporation
Annual Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by
reference).
57
Exhibit
Number Exhibits
- ------- ------------------------------------------------------------------------------------------------
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).
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 (previously filed as Exhibit 10.13 to Toreador Royalty Corporation Annual
Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by
reference).
10.14+ - 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 (previously filed as Exhibit 10.14 to Toreador Royalty Corporation Annual
Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by
reference).
10.15 - 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. Philp Company, as amended
58
Exhibit
Number Exhibits
- ------- ------------------------------------------------------------------------------------------------
(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 (previously filed as Exhibit 10.17 to
Toreador Royalty Corporation Annual Report on Form 10-K for the year ended December 31, 1998,
and incorporated herein by reference).
10.18 - First Amendment to Loan Agreement, dated September 22, 1998, between Toreador Royalty
Corporation and Toreador Exploration & Production Inc and Compass Bank (previously filed as
Exhibit 10.18 to Toreador Royalty Corporation Annual Report on Form 10-K for the year ended
December 31, 1998, and incorporated herein by reference).
10.19 - Second Amendment to Loan Agreement, dated December 15, 1998, between Toreador Royalty
Corporation and Toreador Exploration & Production Inc and Compass Bank (previously filed as
Exhibit 10.19 to Toreador Royalty Corporation Annual Report on Form 10-K for the year ended
December 31, 1998, and incorporated herein by reference).
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).
10.21 - Amended and Restated Credit Agreement, dated April 16, 1999, between Toreador Royalty
Corporation and Toreador Exploration & Production Inc and Compass Bank (previously filed as
Exhibit 10.1 to Toreador Royalty Corporation Quarterly Report on Form 10-Q for the quarter
ended June 30, 1999, and incorporated herein by reference).
10.22 - Credit Agreement, effective September 30, 1999, between Compass Bank, as Lender, Toreador
Royalty Corporation, Toreador Exploration & Production Inc, and Tormin, Inc., as Borrowers,
and Toreador Acquisition Corporation, as Guarantor (previously filed as Exhibit 10.1 to
Toreador Royalty Corporation Current Report on Form 8- K, filed on October 27, 1999, and
incorporated herein by reference).
10.23 - Purchase and Sale Agreement, effective November 24, 1999, between Lario Oil & Gas Company and
Toreador Exploration & Production Inc. (previously filed as Exhibit 10.1 to Toreador Royalty
Corporation Current Report on Form 8-K filed on January 6, 2000, and incorporated herein by
reference).
10.24 - First Amendment to Loan Agreement, dated December 17, 1999, between Compass Bank, as Lender,
and Toreador Royalty Corporation, Toreador Exploration & Production Inc. and Tormin, Inc., as
Borrowers, and Toreador Acquisition Corporation, as Guarantor (previously filed as Exhibit
10.2 to Toreador Royalty Corporation Current Report on Form 8-K filed on January 6, 2000, and
incorporated herein by reference).
10.25 - Term Promissory Note, effective December 17, 1999, between Compass Bank, as Lender, and
Toreador Royalty Corporation, Toreador Exploration & Production Inc. and Tormin, Inc., as
Borrowers, and Toreador Acquisition
59
Exhibit
Number Exhibits
- ------- ------------------------------------------------------------------------------------------------
Corporation, as Guarantor (previously filed as Exhibit 10.3 to Toreador Royalty
Corporation Current Report on Form 8-K filed on January 6, 2000, and incorporated
herein by reference).
16.1 - Letter on Change in Certifying Accountant from PricewaterhouseCoopers LLP, dated June 30,
1999 (previously filed as Exhibit 16 to Amendment No. 2 to Toreador Royalty Corporation
Current Report on Form 8-K/A filed on June 30, 1999, and incorporated herein by reference).
21.1* - Subsidiaries of Toreador Royalty Corporation.
23.1* - Consent of Ernst & Young LLP.
23.2* - Consent of PricewaterhouseCoopers LLP.
23.3* - Consent of LaRoche Petroleum Consultants, Ltd.
23.4* - Consent of Harlan Consulting.
27.1* - Financial Data Schedule.
- ---------------------
* Filed herewith.
+ Management contract or compensatory plan
(b) Reports on Form 8-K:
None.