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1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark one)
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended August 31, 1999
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 0-9120
THE EXPLORATION COMPANY OF DELAWARE, INC.
(Exact name of Registrant as specified in its charter)
Delaware 84-0793089
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
500 North Loop 1604 East, Suite 250,
San Antonio, Texas 78232
(Address of principal executive offices)
Registrant's telephone number, including area code: (210) 496-5300
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, par value $0.01 per share
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
The aggregate market value of the voting stock (which consists solely of
shares of Common Stock) held by non-affiliates of the registrant is $24,261,231
based upon the average of the high and low bid price of such stock as reported
by the NASDAQ Small-Cap Market under the symbol TXCO on November 1, 1999.
The number of shares outstanding of the Registrant's Common Stock as of
November 1, 1999 was 15,938,516 of which 13,381,815 shares were held by
non-affiliates.
Documents Incorporated by Reference: None
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2
INDEX AND
CROSS REFERENCE SHEET
<TABLE>
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PART I Page
<S> <C>
Item 1. Business..................................................................................... 3
Item 2. Properties................................................................................... 9
Item 3. Legal Proceedings............................................................................ 14
Item 4. Submission of Matters to a Vote of Security Holders.......................................... 14
PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters.................................................................. 15
Item 6. Selected Financial Data...................................................................... 15
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations........................................................................ 16
Item 7A. Quantitative and Qualitative Disclosures About Market Risk................................... 21
Item 8. Financial Statements and Supplementary Data ................................................. 21
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure......................................................................... 21
PART III
Item 10. Directors and Executive Officers of the Registrant........................................... 22
Item 11. Executive Compensation....................................................................... 23
Item 12. Security Ownership of Certain Beneficial Owners
and Management............................................................................... 25
Item 13. Certain Relationships and Related Transactions............................................... 26
PART IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K.......................................................................... 26
Signatures................................................................................................ 28
Audited Financial Statements of The Exploration Company.................................................. F-1
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3
PART I
ITEM 1. BUSINESS
GENERAL DEVELOPMENT OF BUSINESS
The Exploration Company (the "Company" or "TXCO") was incorporated in the State
of Colorado on May 16, 1979, for the purpose of engaging in oil and gas
exploration, development and production and became publicly held through an
offering of its common stock in November, 1979. In May 1999, the Company changed
its state of incorporation from Colorado to Delaware, becoming The Exploration
Company of Delaware, Inc. The Company continues doing business as The
Exploration Company and its trading symbol on the Nasdaq Stock MarketSM remains
TXCO.
Throughout its history, the Company's primary focus has been oil and gas
exploration and production. Its long term business strategy has been to acquire
undeveloped mineral interests and to develop a multi-year inventory of drilling
prospects internally through the application of state of the art technologies,
such as 3-D seismic and enhanced horizontal drilling techniques. The Company
strives to discover, develop and/or acquire more oil and gas reserves than it
produces each year from these internally-developed prospects, as well as
selectively participating with industry partners in prospects generated by TXCO
as well as by other parties. The Company also attempts to maximize the value of
its technical expertise by contributing its geological, geophysical and
operational knowledge base in its core area through joint ventures or forms of
strategic alliances with well capitalized industry partners in exchange for
carried interests in seismic acquisitions, leasehold purchases and/or wells to
be drilled. From time to time, the Company offers portions of its developed and
undeveloped mineral interests for sale. The Company finances its activities
through a combination of debt financing, equity offerings and internally
generated cash flow. When appropriate, the Company may also use its equity
securities as all or part of the consideration for operating investments.
Prior to 1992, the Company's revenues were derived principally from the sale of
natural gas and oil production from working, royalty and mineral interests, as
well as the sale of the mineral interests it acquired through its leasing
activities. From 1992 through 1996 the Company expanded its activities by
entering the then emerging alternative fuels vehicle conversion business through
the creation of its ExproFuels division. In 1996, management redirected its
focus and resources to its core oil and gas exploration and production business.
Accordingly, the ExproFuels division was incorporated and a majority equity
interest spun-off via a stock dividend to TXCO shareholders.
The continuing availability of new equity and debt capital to The Exploration
Company during fiscal years 1997, 1998 and 1999 reaffirmed Management's
expectations for improved shareholder value by focusing on its core business of
oil and gas exploration and production. Although profitability was not attained
through fiscal year 1998, operating results included a 195% increase in oil and
gas revenues and a 183% increase in proved oil and gas reserves over 1997 levels
while establishing positive cashflow from operations. Earnings before interest,
taxes, depreciation, depletion, amortization, impairment and exploration
expenses (EBIDAX) increased to $989,484.
Based on the growth of its operations in the prior two years, TXCO started 1999
with great expectations. We have not been disappointed. Although not reflected
in its stock trading levels, for the year ended August 31, 1999, the Company
realized the best operating results in its 20 year history, reaching
profitability during the 1st quarter and ending its record breaking 1999 fiscal
year with revenues of over $7,497,000 and net income of $931,000. In addition to
reaching book profitability, EBIDAX surged to an all time high of $4,793,000.
TXCO overcame the weakness in oil and gas prices during the first half of fiscal
1999, extending its strong growth trend through its drilling success and
operational efficiencies. The Company realized a 146% increase in gross
operating revenues, a 246% increase in production volumes and a 70% increase in
oil and gas leasehold acreage in its core producing area. New reserve additions
from 1999 drilling discoveries effectively replaced the record volume of gas and
oil produced for the year, and together with improving oil and gas prices during
the last half of the year, resulted in a 41% increase in the discounted present
value (PV-10) of proved producing oil and gas reserves for the year.
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TXCO has succeeded in leveraging its current success, positioning itself to
further accelerate growth in fiscal years 2000 and 2001. In addition to planned
new drilling in fiscal 2000 utilizing internally generated working capital, two
new strategic alliances were initiated near year end which together are expected
to provide TXCO with a substantial benefit from upwards of $17,000,000 in
mineral leasing, 3-D seismic acquisition and exploration drilling expenditures
over a 2 year period. The expenditures are targeted to develop and drill at
least 12 additional Glen Rose patch reef drilling prospects in fiscal 2000 and
to expand and update TXCO's 3-D seismic database to further define and then
drill on a deep Jurassic Formation prospect before the end of 2000. The
potential natural gas reserves of the deep Jurassic Formation could increase the
Company's existing proved producing reserve base significantly. Should these
exploration and development plans progress as intended, The Exploration Company
expects to continue its strong growth in gas reserves, revenues and
profitability well into the new millenium.
PRINCIPAL AREAS OF ACTIVITY
Oil and Gas Operations
Throughout the year, the Company has been actively developing its core mineral
interests in the Maverick Basin in South Texas, while evaluating its economic
alternatives related to its remaining properties in North Dakota, South Dakota
and Montana. These activities included participation in the drilling of 10 gas
wells in South Texas during 1999. The increase in Maverick Basin drilling
activity reflects the Company's continued ability to generate sufficient working
capital from profitable internal operations and from industry sources, allowing
for expansion of its Texas-based lease acreage holdings and natural gas
exploration and production activities. Increased Maverick Basin gas production
during 1999 resulted in improved positive cash flows, more than offsetting the
effects of weak natural gas prices for the first half of 1999. The ongoing
reduction in Williston Basin activity reflects the lingering impact of low crude
oil prices realized by TXCO through the first half of 1999, and is consistent
with Company strategy to focus on its core gas producing and exploration
activities.
Maverick Basin
The Company has owned at least a 50% leasehold interest in approximately 50,000
contiguous acres in Maverick County, Texas since 1989. Originally the lease
block consisted of two leases, the Paloma with 33,000 acres and the Kincaid with
17,000 acres. The lease block is situated on the Chittim Anticline, a large
regional structure, under which hydrocarbons have been found in as many as seven
separate horizons dating back over 65 years. One of these zones is the Lower
Glen Rose or Rodessa interval. It is a carbonate formation that has produced
billions of cubic feet of natural gas from patch reefs within the zone on or
near the anticline. Past development in the area was halted due to the inability
of previous operators to accurately predict the location of these
porosity-bearing reefs. Utilizing new technological advances, the Company
applied an innovative processing method to the 2-D seismic available in the area
and confirmed a method of determining the location of these porosity intervals.
Between 1993 and 1998, the Company expanded its in-house geophysical database to
include multiple 3-D seismic surveys totaling over 55 square miles, covering
approximately 36,000 acres of its Maverick Basin leases. Company scientists
conclusively identified and mapped numerous geological formations at various
depths on its leases. The mapping has provided numerous drilling alternatives
for future evaluation of the multiple horizons known to be productive for oil
and/or gas within and around its leases in the Maverick Basin. Consistent with
the capital resources available, the Company has been selectively developing the
Glen Rose interval. The shallower intervals provided alternative completion
targets while pursuing the underlying reefs.
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5
From 1989 to 1998, TXCO participated in the drilling of 26 wells in the
Maverick Basin, with increasing degrees of drilling success. By the end of 1998,
TXCO's daily net gas production from its Maverick Basin properties reached 1.96
MMcfd (million cubic feet of natural gas per day) from 16 gas wells. While
successful in locating Glen Rose patch reefs, Management continued to review
technical data gained with the drilling of each well, modifying its seismic
interpretation model, improving its ability to distinguish between water-filled
reefs and gas-filled reefs as well as expanding the geologically defined area
known as the Prickly Pear Field.
During fiscal year 1998, 6 new gas well discoveries in succession on the Paloma
Lease extended the Prickly Pear Field by several miles north and east of its
previous recognized boundaries. The 6 wells produced gross daily production
volumes ranging from 1 MMcfd to 4 MMcfd per well.
Fiscal year 1999 brought a continuation of growth in new production and revenues
for the Company, as well as the expansion of TXCO's leasehold position over the
Maverick Basin. During 1999, the Company acquired interests in over 39,000 acres
of additional oil and gas leases in the immediate areas surrounding its Maverick
Basin production, bringing its total lease position to approximately 90,000
acres at year end. TXCO participated in drilling 10 gas prospects, resulting in
5 new gas wells, further expanding the known producing area of the Prickly Pear
Field on the Company's Paloma lease. Four of the other wells were drilled on
leases acquired during fiscal 1999, while one was located on the Company's
Kincaid lease. All 5 of these stepout wells were at least 5 to 9 miles from the
nearest Prickly Pear Field production. Their drilling resulted in 2 completed
oil wells and one completed gas well. The 2 other step out wells are being
evaluated for various completion alternatives in shallower geologic formations
overlying the Glen Rose patch reef interval, including the upper Glen Rose,
lower and upper Georgetown, Eagleford, Austin Chalk and Buda formations .
At year end August 1999, TXCO's daily net gas production from its Maverick Basin
properties reached 9.10 MMcfd from 28 gas wells. Ongoing production increases
are a direct result of the application of advances totaling $4,400,000 under the
existing financing agreement with Range Energy Finance Corporation. The newly
attained production levels and resultant positive cash flow will allow the
Company to internally generate sufficient working capital to fund its current
fiscal year 2000 development plans. The successful drilling results of fiscal
year 1998 and 1999 dramatically reaffirm the Company's longstanding belief that
it has significant development possibilities on its expanding Maverick Basin
lease block. At year end, Maverick Basin leases totaled over 90,000 acres with
an additional 25,000 acres reserved under seismic options which were exercised
during the 1st quarter of fiscal 2000. Through 1999, the Company has accumulated
148 square miles (93,000 acres) of 3-D seismic data over most of its Maverick
Basin lease block, with evidence of from 30 to 40 additional porosity-bearing
Glen Rose patch reefs scattered across its extensive acreage position. Based on
current drilling activity, these patch reefs represent a potential three to four
year drilling inventory of new gas well prospects .
Jurassic Formations: The Company's geophysicists and geologists have established
that the 148 square miles of 3-D seismic shot through November 1999 across its
115,000 acre lease block in Maverick County indicates a significant potential
for development of the deep Jurassic interval. Fiscal 1999 marked the year that
the Company's concerted efforts resulted in a new partnership to develop the
potential Jurassic reserves.
In September 1999, the Company completed negotiations and entered into a joint
operating agreement with Blue Star Oil and Gas, Ltd., a Dallas based private
partnership, for an extensive exploration project targeting the deep Jurassic
interval underlying TXCO's Maverick Basin lease block. Under its terms, Blue
Star paid TXCO a cash consideration upon closing and will initially fund 100% of
the costs of a 58 square mile 3-D seismic acquisition program covering over
37,000 acres of TXCO's Paloma and Kincaid leases. In addition, Blue Star will
fund 100% of the costs of drilling 2 exploratory wells to test the underlying
deep Jurassic interval, carrying TXCO and its partners for a 25% working
interest. Blue Star is also obligated to provide a similar amount of new 3-D
seismic survey data, of TXCO's selection, which Blue Star is in process of
acquiring on its 191,000 acre Chittim Ranch Lease which lies adjacent to TXCO's
Paloma lease. Should both wells be drilled in a timely fashion, Blue Star will
earn a 50% interest in the deep rights in both leases totaling 50,000 gross
acres. TXCO will keep a 15% to 50% working interest in future Jurassic wells
drilled under the agreement, depending on the location of future wells. Should
initial drilling not occur within certain deadlines ending in fiscal year 2000,
Blue Star will be obligated to pay $900,000 to TXCO to maintain its rights under
the agreement. At year end, acquisition of seismic field data was underway on
various portions of the Company's acreage block.
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6
Williston Basin
During 1996 and 1997, the Company acquired a 50% interest in approximately
320,000 acres of oil and gas leases in the Williston Basin in North Dakota,
South Dakota and Montana. The Company participated in the drilling of 11 wells
in fiscal 1997 and 3 in fiscal 1998 in attempts to establish economic production
and develop oil and gas reserves in the Red River and Lodgepole formations.
During this same period, TXCO accumulated over 1,100 miles of 2-D seismic and
approximately 64 square miles of 3-D seismic data covering over 40,800 acres of
selected portions of its acreage in the Williston Basin. No new drilling was
conducted on the Company's leases in the Williston Basin during 1999. The
Company's interests produced an average of 122 net barrels of crude oil per day
from 4.32 net wells. Industry wide exploration efforts in the Williston Basin
have remained at historically low levels during the current year, with crude oil
prices reaching a low of nearly $8.25 per barrel in December 1998. The weakness
in crude oil prices rendered the production of marginal levels of oil with high
associated water production, as is typical of many wells in the Basin,
uneconomical for the Company to explore or produce. Current development plans,
pending continuing recent crude oil price improvements, are limited to potential
recompletions in behind pipe zones on existing wells, where electric logs
indicate the presence of hydrocarbons during original drilling.
Throughout 1999, the Company continued to re-evaluate all of its Williston Basin
lease obligations, making lease extension payments on a selective basis,
emphasizing those leases with particular geologic attributes or with adequate
remaining primary lease terms. At August 31, 1999, TXCO retained approximately
263,900 net acres of its original position. The Company has established adequate
provisions for impairment allowances as required for expected fiscal year 2000
lease expirations. Consistent with Management's decision to refocus its
exploration efforts and resources on continuing development of its core
producing area in South Texas, TXCO initiated a focused marketing effort to
present its remaining Williston Basin holdings, complemented by an extensive
seismic database, for sale to other exploration companies with a focus on this
area. Proceeds from such sales would be primarily redirected into the Company's
South Texas development activities after making provisions for any remaining
lease obligations. With the recent improvement in crude oil prices, reaching
$18.74 at year end and over $24.00 during the 1st quarter of fiscal year 2000,
Management is cautiously optimistic that renewed industry interest in the area
will assist it in its efforts to monetize its remaining area holdings.
PRINCIPAL PRODUCTS AND COMPETITION
The Company's principal products are natural gas and crude oil. The production
and marketing of oil and gas are affected by a number of factors that are beyond
the Company's control, the effect of which cannot be accurately predicted. These
factors include crude oil imports, actions by foreign oil-producing nations, the
availability of adequate pipeline and other transportation facilities, the
marketing of competitive fuels and other matters affecting the availability of a
ready market, such as fluctuating supply and demand. The Company sells all of
its oil and gas under short-term contracts that can be terminated with 30 days
notice, or less. None of the Company's production is sold under long-term
contracts with specific purchasers. Consequently, the Company is able to market
its oil and gas production to the highest bidder each month. The Company
operates and directs the drilling of oil and gas wells. It contracts service
companies, such as drilling contractors, cementing contractors, etc., for
specific tasks. In some wells, the Company only participates as an overriding
royalty interest owner.
During 1999, three purchasers of the Company's oil and gas production accounted
for 55%, 24% and 7%, respectively of total oil and gas sales. In the event any
of these major customers declined to purchase future production, the Company
believes that alternative purchasers could be found for such production at
comparable prices.
The oil and gas industry is highly competitive in the search for and development
of oil and gas reserves. The Company competes with a substantial number of major
integrated oil companies and other companies having materially greater financial
resources and manpower than the Company. These competitors, having greater
financial resources than the Company, have a greater ability to bear the
economic risks inherent in all phases of this industry. In addition, unlike the
Company, many competitors produce large volumes of crude oil that may be used in
connection with their operations. These companies also possess substantially
larger technical staffs, which puts the Company at a significant competitive
disadvantage compared to others in the industry.
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7
EMPLOYEES
As of August 31, 1999, the Company employed 12 full-time employees including
management. The Company believes its relations with its employees are good. None
of the Company's employees are covered by union contracts.
GENERAL REGULATIONS
The extraction, production, transportation, and sale of oil, gas, and minerals
are regulated by both state and federal authorities. The executive and
legislative branches of government at both the state and federal levels, have
periodically proposed and considered proposals for establishment of controls on
alternative fuels, energy conservation, environmental protection, taxation of
crude oil imports, limitation of crude oil imports, as well as various other
related programs. If any proposals relating to the above subjects were to be
enacted, the Company is unable to predict what effect, if any, implementation of
such proposals would have upon the Company's operations. A listing of the more
significant current state and federal statutory authority for regulation of the
Company's current operations and business are provided herein below.
Federal Regulatory Controls
Historically, the transportation and sale for resale of natural gas in
interstate commerce have been regulated pursuant to the Natural Gas Act of 1938
(the "NGA"), the Natural Gas Policy Act of 1978 (the "NGPA") and the regulations
promulgated thereunder by the Federal Energy Regulatory Commission ("FERC").
Maximum selling prices of certain categories of natural gas sold in "first
sales," whether sold in interstate or intrastate commerce, were regulated
pursuant to the NGPA. On July 26, 1989, the Natural Gas Wellhead Decontrol Act
(the "Decontrol Act") was enacted, which removed, as of January 1, 1993, all
remaining federal price controls from natural gas sold in "first sales." The
FERC's jurisdiction over natural gas transportation was unaffected by the
Decontrol Act.
Commencing in April 1992, the FERC issued Order Nos. 636, 636-A and 636-B
(collectively "Order No. 636"), which required interstate pipelines to provide
transportation, separate or "unbundled," from the pipelines' sales of gas.
Although Order No. 636 did not directly regulate the Company's activities, it
fostered increased competition within all phases of the natural gas industry.
In December 1992, the FERC issued Order No. 547, governing the issuance of
blanket marketer sales certificates to all natural gas sellers other than
interstate pipelines. The order applies to non-first sales that remain subject
to the FERC's NGA jurisdiction. The FERC Order No. 547, in tandem with Order No.
636, has fostered a competitive market for natural gas by giving natural gas
purchasers access to multiple supply sources at market-driven prices. Order No.
547 has increased competition in markets in which the Company's natural gas is
sold. The natural gas industry historically has been very heavily regulated;
therefore, there is no assurance that the less stringent regulatory approach
pursued by the FERC and Congress will continue.
State Regulatory Controls
In each state where the Company conducts or contemplates conducting oil and gas
activities, such activities are subject to various state regulations. In
general, the regulations relate to the extraction, production, transportation
and sale of oil and natural gas, the issuance of drilling permits, the methods
of developing new production, the spacing and operation of wells, the
conservation of oil and natural gas reservoirs and other similar aspects of oil
and gas operations. In particular, the State of Texas (where the Company has
conducted the majority of its oil and gas operations to date) regulates the rate
of daily production allowable from both oil and gas wells on a market demand or
conservation basis. At the present time, no significant portion of the Company's
production has been curtailed due to reduced allowables. The Company knows of no
newly proposed regulations, which will significantly curtail its production.
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Environmental Regulation
The Company's extraction, production and drilling operations are subject to
environmental protection regulations established by federal, state, and local
agencies. To the best of its knowledge, the Company believes that it is in
compliance with the applicable environmental regulations established by the
agencies with jurisdiction over its operations. The Company is acutely aware
that the applicable environmental regulations currently in effect could have a
material detrimental effect upon its earnings, capital expenditures, or
prospects for profitability. The Company's competitors are subject to the same
regulations and therefore, the existence of such regulations does not appear to
have any material effect upon the Company's position with respect to its
competitors. The Texas Legislature has mandated a regulatory program for the
management of hazardous wastes generated during crude oil and natural gas
exploration and production, gas processing, oil and gas waste reclamation and
transportation operations. The disposal of these wastes, as governed by the
Railroad Commission of Texas, is becoming an increasing burden on the industry.
The Company's operations in Montana, North Dakota and South Dakota are subject
to similar environmental regulations including archeological and botanical
surveys as some of its leases are on federal and state lands.
Federal and State Tax Considerations
Revenues from oil and gas production are subject to taxation by the state in
which the production occurred. In Texas, the state receives a severance tax of
4.6% for oil production and 7.5% for gas production. North Dakota production
taxes typically range from 9.0% to 11.5% while Montana's taxes range up to
17.2%. These high percentage state taxes can have a significant impact upon the
economic viability of marginal wells that the Company may produce and require
plugging of wells sooner than would be necessary in a less arduous taxing
environment. Although the Company is subject to federal income taxes on the oil
and gas produced, its tax net operating loss carry forward should be sufficient
to shelter a substantial amount of production. See Notes to the audited
financial statements.
CERTAIN BUSINESS RISKS
Reliance on Estimates of Proved Reserves and Future Net Revenues: Depletion of
Reserves
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and the timing of
development expenditures, including many factors beyond the control of the
Company. The reserve data set forth in this report represents only estimates. In
addition, the estimates of future net revenues from proved reserves of the
Company and the present value thereof are based on certain assumptions about
future production levels, prices and costs that may not prove to be correct over
time. In particular, estimates of crude oil and natural gas reserves, future net
revenue from proved reserves and the present value of proved reserves for the
crude oil and natural gas properties described in this report are based on the
assumption that future crude oil and natural gas prices remain the same as crude
oil and natural gas prices as of August 31, 1999. The average sales prices as of
such dates used for purposes of these estimates were $18.68 per barrel of crude
oil and $2.59 per mcf of natural gas, representing an increase of 70% and 42%,
respectively, from the prior year sales prices. Any significant variance in
these assumptions could materially affect the estimated quantity and value of
reserves set forth herein. See "Management's Discussion and Analysis of
Financial Condition and Results of Operation - Liquidity and Capital Resources"
and "Properties "
Depletion of Reserves
The rate of production from crude oil and natural gas properties declines as
reserves are depleted. Except to the extent the Company acquires additional
properties containing proved reserves, conducts successful exploration and
development activities or through engineering studies identifies additional
behind-pipe zones or secondary recovery reserves, the proven reserves of the
Company will decline as reserves are produced. Future crude oil and natural gas
production is therefore highly dependent upon the Company's level of success in
acquiring or finding additional reserves.
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9
Title to Properties
As is customary in the crude oil and natural gas industry, the Company performs
a preliminary title investigation before acquiring undeveloped properties that
generally consists of obtaining a title report from outside counsel or due
diligence reviews by independent landmen. The Company believes that it has
satisfactory title to such properties in accordance with standards generally
accepted in the oil and gas industry. A title opinion from counsel is obtained
before the commencement of any drilling operations on such properties. The
Company's properties are subject to customary royalty interests, liens incident
to operating agreements, liens for current taxes and other burdens, none of
which the Company believes materially interferes with the use of, or affect the
value of, such properties.
Losses from Operations
For the current year the Company recorded net income of $.93 million. However,
in prior years the Company recorded net losses of $8.4 million in fiscal 1998
and $3.4 million in fiscal 1997. There can be no assurance that the Company will
not experience operating losses in the future.
Operating Hazards; Uninsured Risks
The nature of the crude oil and natural gas business involves certain operating
hazards such as crude oil and natural gas well blowouts, explosions, formations
with abnormal pressures, cratering and crude oil spills and fires. Any of these
could result in damage to or destruction of crude oil and natural gas wells,
destruction of producing facilities, damage to life or property, suspension of
operations, environmental damage and possible liability to the Company. In
accordance with customary industry practices, the Company maintains insurance
against some, but not all, of such risks and some, but not all, of such losses.
The occurrence of such an event not fully covered by insurance could have a
material adverse effect on the financial condition and results of operations of
the Company.
Substantial Capital Requirements
The Company makes, and will continue to make, substantial capital expenditures
for the acquisition, exploitation, development, exploration, and production of
crude oil and natural gas reserves. Historically, the Company has financed these
expenditures primarily from debt and equity offerings, supplemented by available
cash flow from operations. The Company is hopeful that it will continue to be
able to obtain sufficient capital to finance planned capital expenditures.
However, if revenues decrease because of lower crude oil and natural gas prices,
operating difficulties or declines in reserves, the Company may have limited
ability to finance planned capital expenditures in the future. Therefore, there
can be no assurance that additional debt or equity financing or cash generated
by operations will be available to meet its capital requirements.
ITEM 2. PROPERTIES
PHYSICAL PROPERTIES
The Company's administrative offices are located at 500 North Loop 1604 East,
Suite 250, San Antonio, Texas. These offices, consisting of approximately 5,700
square feet, are leased through February 28, 2000 at $7,676 per month.
All the Company's oil and gas properties, reserves, and activities are located
onshore in the continental United States. There are no quantities of oil or gas
subject to long-term supply or similar agreements with foreign government
authorities.
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10
Proved Reserves, Future Net Revenue and
Present Value of Estimated Future Net Revenues
The following unaudited information as of August 31, 1999, relates to the
Company's estimated proved oil and gas reserves, estimated future net revenues
attributable to such reserves and the present value of such future net revenues
using a 10% discount factor, as estimated by Pollard, Gore and Harrison, an
Austin, Texas engineering firm. Estimates of proved developed oil and gas
reserves attributable to the Company's interest at August 31, 1999, 1998 and
1997 are set forth in Notes to the Audited Financial Statements included in this
Annual Report on Form 10-K. Present Value of Estimated Future Net Revenues from
proved developed oil and gas reserves as of August 31, 1999, are as follows:
10% Present Value of
Years Ending Estimated Future
August 31 Net Revenues
---------- ------------
2000 5,751,000
2001 3,580,000
2002 1,473,000
2003 719,000
2004 364,000
Thereafter 558,000
-----------
TOTAL $ 12,445,000
===========
The present value of estimated future net revenues is computed in accordance
with SEC requirements. These amounts were computed by applying current prices
for oil and gas, giving effect only to those escalations in prices of gas which
are currently contractually defined, deducting estimated future expenditures to
develop and produce the proved reserves and applying a discount factor of 10%.
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas liquids and natural gas 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 developed
oil and gas reserves are reserves that can be expected to be recovered through
existing wells with existing equipment and operating methods. No reserve
estimates have been filed with or included in reports to any federal or foreign
government authority or agency, other than the Securities and Exchange
Commission, since the Company's latest Form 10-K filing.
Production
The following table summarizes the Company's net oil and gas production, average
sales prices, and average production costs per unit of production for the
periods indicated. With respect to newly drilled wells, there can be no
assurance that current production levels can be sustained. Depending upon
reservoir characteristics, such levels of production could decline
significantly.
<TABLE>
<CAPTION>
Years Ended August 31
-------------------------------------
1999 1998 1997
---- ----- ----
<S> <C> <C> <C>
Oil:
Production in Barrels 82,000 79,138 23,086
Average sales price per Barrel $12.27 $15.78 $18.64
Gas:
Production in MCF 2,813,000 713,752 206,059
Average Sales Price per MCF $2.07 $2.29 $ $2.65
Average cost of production per equivalent MCF (1) $.40 $.74 $.72
</TABLE>
(1) Oil and gas were combined by converting oil to gas mcf equivalent on the
basis of 1 barrel of oil = 6 MCF of gas. Production costs include direct
lease operations and production taxes.
<PAGE>
11
Producing Properties - Wells and Acreage
The following table sets forth the Company's producing wells and developed
acreage assignable to such wells at August 31, for the last three fiscal years:
<TABLE>
<CAPTION>
Productive Wells
Fiscal ----------------------------------------------------------
Year Developed Acreage Oil Gas Total
- ----- ------------------- -------------- ---------------- ---------------
Gross Net Gross Net Gross Net Gross Net
----- --- ----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1999 11,720 5,185 18 6.29 29 12.56 47 18.85
1998 8,920 3,894 16 5.26 17 8.05 33 13.31
1997 6,040 2,479 10 3.77 13 5.55 23 9.32
</TABLE>
Productive wells consist of producing wells and wells capable of production,
including shut-in wells and wells awaiting pipeline connections to commence
deliveries and oil wells awaiting connection to production facilities.
A "gross well" or "gross acre" is a well or acre in which a working interest is
held. The number of gross wells or gross acres is the total number of wells or
acres in which working interests are owned. A "net well" or "net acre" is deemed
to exist when the sum of fractional ownership interest in gross wells or gross
acres equals one. The number of net wells or net acres is the sum of fractional
working interests owned in gross wells or gross acres expressed as whole numbers
and fractions thereof.
Undeveloped Acreage
As of August 31, 1999, the Company owned, by lease or in fee, the following
undeveloped acres, all of which are located in the Continental United States, as
follows:
Estimated
FY 2000
United States Gross Acres Net Acres Delay Rentals
- ------------- ----------- --------- -------------
Texas 95,155 64,631 $ 81,726
North Dakota 323,294 226,904 130,405
South Dakota 32,244 20,281 3,085
Montana 25,163 15,759 1,440
----------- --------- -------------
Totals 475,856 327,575 $ 216,656
========== ========= =============
Five Texas leases totaling approximately 66,000 gross acres contain varying
requirements to drill a well every 90 to 150 days to keep the respective lease
in effect. The Company is presently drilling under the terms of the leases and
expects to keep the leases in force by continuous development during the year.
<PAGE>
12
Drilling Activity
During fiscal 1999, the Company's drilling activity increased to 10 wells
compared to 7 in 1998. The following table sets forth the Company's drilling
activity for the last three fiscal years:
<TABLE>
<CAPTION>
Drilling Wells
1999 1998 1997
----------------------- -------------------------- ------------------------
Gross Net Gross Net Gross Net
Prod Dry Prod Dry Prod Dry Prod Dry Prod Dry Prod Dry
---- ---- ---- ---- ---- --- ----- ---- ---- --- ---- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Oil Wells 2 0 1.75 0 2 1 1.34 .63 9 2 3.73 <.01
Gas Wells 6 0 3.78 0 4 0 2.50 .00 4 0 2.80 .00
- - ---- - - - ---- --- - - ---- ---
Total Wells 8 0 5.53 0 6 1 3.84 .63 13 2 6.53 <.01
= = ==== = = = ==== === == = ==== ===
</TABLE>
The Company had an interest in 2 wells (1.38 net) in progress at August 31,
1999. Fiscal years 1998 and 1997 well totals include completed or dry wells
commenced in the respective prior year.
Maverick Basin
Throughout 1999, the Company has pursued its strategy to expand its core
Maverick Basin producing properties. In addition to using its internally
generated working capital for exploration and development activities, TXCO has
accelerated its growth by entering into strategic joint ventures or operating
agreements targeted at leveraging the Company's increased leasehold values,
recognized technical abilities and exploration success in its core area of
interest. TXCO entered into several new joint venture or joint operating
agreements during the year whereby the Company successfully teamed with
qualified industry partners who contributed investment capital, mineral leases,
3-D seismic data and/or offered the Company a carried interest in mineral
leases, 3-D seismic acquisition programs and wells to be drilled. These
contributions were made in exchange for TXCO's geophysical, geological and
operational expertise, and in certain instances, in exchange for a portion of
the Company's non-producing oil and gas lease interests .
During September 1998, the Company entered into a joint operating agreement (JOA
) with Ashtolla Exploration Company, Inc., whereby TXCO earned a 63% working
interest in Ashtolla's 8,800 acre Alkek lease adjoining TXCO's Paloma lease,
together with rights to an existing 3-D seismic survey over the subject block.
In exchange, TXCO agreed to drill a well to test the Glen Rose interval,
allowing the previous operator to meet the operational requirements under the
terms of the original lease agreement. Two wells were drilled under this JOA
during the year resulting in 1 marginal gas well completion, while the second
well was awaiting completion at year end.
Also in September 1998, the Company entered into a JOA with the Picosa Creek
Partnership, whereby TXCO was given access to an existing 3-D seismic survey
over the 12,800 acre Chittim lease which adjoins its Paloma lease. The Company
earns a 25% interest in any Glen Rose reef wells it proposes and drills after
reprocessing and interpreting the new 3-D seismic data. One well was drilled and
completed as an oil producer under this JOA during the year, while a 2nd well
was drilled and is being completed as a gas well in November 1999 .
In November 1998, the Company finalized a JOA with Ameritex Ventures, II Ltd., a
joint venture owned 85% by Enron Capital, allowing Ameritex and its partners to
earn up to a 50% interest in TXCO's existing 17,000 acre Kincaid lease in
exchange for their funding 100% of the costs of and commencement of a 27 square
mile 3-D seismic program on parameters established by TXCO over the entire
17,000 acre tract. While the terms reduced the Company's remaining interest in
the non-producing lease to 50% in shallow zones, it provided for TXCO to keep
100% of its deeper rights, including the deep Jurassic interval. Upon completion
of the 3-D seismic acquisition program, 1 well was drilled and was being
completed at year end.
<PAGE>
13
In May 1999, the Company finalized a JOA with Castle Exploration Company, a
wholly owned subsidiary of Castle Energy Corporation, (Nasdaq:CECX) whereby
Castle committed to provide TXCO with up to $5,3000,000 to fund 100% of the
initial costs to purchase leases, acquire 3-D seismic and drill up to 12 Glen
Rose reef wells on targeted acreage contiguous to TXCO's productive Paloma
lease. TXCO was named as operator, and contributed its interest in its 8,800
acre Alkek lease in exchange for shared rights to all 3-D seismic acquired, a
25% carried interest in the initial 12 wells drilled, a 50% interest in initial
lease acquisitions, and the right to participate with up to a 50% interest in
all future wells to be drilled on the leases. By year end, TXCO had leased or
held options totaling 31,700 acres adjoining it's Paloma lease acreage. Through
November 1999, all 3-D seismic acquisition work was completed over most of the
acreage tract. Initial review of the completed data set by TXCO's exploration
team confirmed the presence of Glen Rose patch reefs scattered across the block.
Management expects to propose its initial selection of drilling locations
utilizing the new seismic data during the second quarter of fiscal 2000, with
drilling to commence immediately thereafter. In October 1999, TXCO drilled the
first well under the terms of the JOA. The well did not encounter sufficient
quantities of gas, so Castle elected not to complete the well.
In August 1999, the Company closed an agreement with Peacock-Maverick Drilling
and Peacock Exploration to purchase their interests in producing wells and oil
and gas leases totaling 24,500 acres in exchange for 325,000 shares of TXCO
common stock valued at $493,594. The purchase included a 12.5 % working interest
in the 12,800 acre Chittim lease, including a similar working interest in 6
producing oil and gas wells located thereon. The acreage is contiguous to TXCO's
Paloma lease. In addition, the Company received a 100% working interest in two
leases totaling 11,700 acres located within 5 miles of the other tracts.
In September 1999, the Company completed negotiations and entered into a JOA
with Blue Star Oil and Gas, Ltd., for an extensive exploration project targeting
the deep Jurassic interval underlying TXCO's Maverick Basin lease block. Under
its terms, Blue Star paid TXCO a cash consideration upon closing and will
initially fund 100% of the costs of a 58 square mile 3-D seismic acquisition
program covering over 37,000 acres of TXCO's Paloma and Kincaid leases. In
addition, Blue Star will fund 100% of the costs of drilling 2 exploratory wells
to test the underlying deep Jurassic interval. Blue Star is also obligated to
provide, at TXCO's selection, a similar amount of new 3-D seismic survey data
which Blue Star is in process of acquiring on its 191,000 acre Chittim Ranch
Lease which lies adjacent to TXCO's Paloma lease. Should both wells be drilled
timely, Blue Star will earn a 50% interest in the deep rights in both leases
totaling 50,000 acres. TXCO will keep a working interest in future Jurassic
wells drilled under the agreement varying between 15% to 50%, depending on the
location of future wells. Should initial drilling not occur within certain
deadlines ending in fiscal year 2000, Blue Star will be obligated to pay
$900,000 to TXCO to maintain its rights under the agreement.
By the end of fiscal year 1999, the Company had extended its 3-D seismic
database over an expanded area of its core producing leases by 68,000 acres,
more than doubling the size of its existing seismic database at the end of the
previous year. By the end of the 1st quarter of fiscal 2000, that number grew to
over 93,800 acres or over 148 square miles. The Company currently has two
consulting geophysicists engaged in interpretation of the new data. Management
expects to identity a significant number of new 3-D defined drilling prospects
in numerous horizons throughout its Maverick Basin leases further adding to its
multiyear drilling prospect inventory.
Williston Basin
The Company did not participate in drilling any Williston Basin wells during
1999. While the depressed oil and gas price environment in fiscal year 1998 and
1999 have impacted all of the Company's operations, the Williston Basin
operations were impacted the most. Realized prices for the Company's North
Dakota crude oil dropped from its high of $22.52 in November 1997 to a low of
$8.30 in December 1998 and back up to $18.22 in August 1999. These lower prices,
combined with high unit production costs at current production levels, have
resulted in failed economics on several of the Company's Williston Basin
producing properties. The Company curtailed its capital spending program in the
area during midyear 1998 and has continued implementing its cost reduction plan
through all of 1999. Curtailed current period expenses included non-payment of
lease renewals or expired leases totaling over 110,000 acres of leases in
Montana, North and South Dakota, targeting primarily those leases not covered
under existing 3-D seismic programs or otherwise not possessing known
distinguishing features of particular significance.
<PAGE>
14
At year end, the Company continued its evaluation of all operations in the
Williston Basin, with particular emphasis on their continued economics resulting
from the instability in oil prices. The review also identified oil leases
targeted for impairment, totaling over 34,800 net acres in North and South
Dakota, with primary expirations prior to August 31, 2000. The Company
determined it was reasonable and conservative to charge future monthly period
earnings with a ratably computed impairment for the lease acreage which is
expected to expire during the upcoming year.
Forward-looking statements in this 10-K are made pursuant to the safe harbor
provisions of the Private Securities Litigation Reform Act of 1995. Investors
are cautioned that all forward-looking statements involve risks and uncertainty,
including without limitation, the costs of exploring and developing new oil and
natural gas reserves, the price for which such reserves can be sold,
environmental concerns effecting the drilling of oil and natural gas wells, as
well as general market conditions, competition and pricing. Please refer to all
of TXCO's Securities and Exchange Commission filings, copies of which are
available from the Company without charge, for additional information.
ITEM 3. LEGAL PROCEEDINGS
The Company is not involved in any matters of litigation incidental to its
business of a significant nature.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of the security holders of the Company during
the 4th quarter of fiscal year 1999. During the 2nd quarter, on February 26,
1999, the Company held its Annual Meeting of Shareholders. The following matters
were submitted for approval by vote at the meeting. All matters were approved by
the shareholders vote and the results of the voting is shown below for each
matter.
1. Election of Directors:
For Against
Stephen M. Gose, Jr. 14,060,208 93,637
Thomas H. Gose 14,060,143 93,702
James E. Sigmon 14,060,208 93,637
Michael Pint 14,060,208 93,637
Robert L. Foree, Jr. 14,059,698 94,147
The members of the Board of Directors do not serve staggered terms of
office. There were no changes in Directors of the Company
2. Proposal for an amendment of the Company's 1995 Flexible Incentive Plan:
For Against Abstain Non-Voted
7,890,220 804,415 109,465 5,349,745
3. Proposal for the re-incorporation of the Company by changing state of
incorporation of the Company from Colorado to Delaware.
For Against Abstain Non-Voted
8,665,755 252,566 9,798 5,225,726
4. Proposal for ratification of the adoption of Akin, Doherty, Klein & Feuge,
P.C., as independent Auditors for the Company for the fiscal year 1999.
For Against Abstain
14,111,145 34,530 8,170
<PAGE>
15
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The following is a range of high and low bid prices for the Company's common
stock for each quarter of the last two years based upon bid prices reported by
the National Association of Securities Dealers Quotations system under the call
symbol "TXCO":
Range of Bid Prices
Quarter ended: High Low
August 1999 $ 2.94 $ 1.00
May 1999 1.41 .75
February 1999 1.50 .62
November 1998 1.41 .75
August 1998 $ 1.94 $ 1.16
May 1998 2.81 1.69
February 1998 3.50 1.63
November 1997 8.44 2.50
As of November 1, 1999, there were approximately 1,697 holders of record of the
Company's Common Stock. The transfer agent for the Company is EquiServe, Boston,
Massachusetts. The Company has not paid any cash dividends on its Common Stock
and does not expect to do so in the foreseeable future.
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial information is derived from and qualified in
its entirety by the Financial Statements of the Company and the Notes thereto as
set forth in this Annual Report on Form 10-K commencing on page F-1.
<TABLE>
<CAPTION>
Years Ended August 31
------------------------------------------------------------------
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Operating Revenues $7,497,375 3,048,277 $1,083,511 $ 521,593 $ 331,253
Income (Loss) from
continuing operations 931,545 (8,417,218) (3,398,866) (1,880,389) (2,153,365)
Basic Income (Loss) per common share
from continuing operations 0.06 (0.55) (0.27) (0.31) (0.44)
Total Assets(1) 17,553,815 16,264,632 21,652,726 8,433,434 4,111,980
Long-term obligations(1) 3,094,809 4,823,927 4,995,000 2,462,197 2,429,697
Shareholders' equity 12,020,280 10,595,141 14,770,770 5,670,688 1,377,747
Weighted average shares
outstanding (1) 15,668,721 15,328,292 12,576,255 6,140,176 4,863,961
</TABLE>
(1) Amounts reflect adjustments in 1995 for the reclassification of ExproFuels
as an equity investment due to its spin-off in 1996.
<PAGE>
16
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following is a discussion of the Company's financial condition and results
of operations. This discussion should be read in conjunction with the Financial
Statements of the Company and Notes thereto.
CAPITAL RESOURCES AND LIQUIDITY
1999
- ----
During the year ended August 31, 1999, beginning cash reserves of $2,329,236
were increased by net cash provided from operating activities of $3,858,204
resulting in a total of $6,187,440 in working capital available for use in
funding the Company's ongoing development and exploration of its oil and gas
properties. The ongoing positive cash flow from operations throughout the year
significantly improved the Company's ability to increase its core revenues from
oil and gas operations, thereby enhancing its ability to overcome the impact of
weak oil and gas prices through most of 1999. An additional $900,000 was
obtained during the year, under the existing financing agreement with Range
Energy Finance Corporation, bringing total borrowings from Range to $4,400,000.
The financing was specifically for ongoing development of the Company's natural
gas producing properties in Maverick County, Texas.
The Company applied $3,448,320 of its working capital to fund the expansion and
ongoing development of its oil and gas properties. Included were drilling and
completion costs of $2,791,544 for current year drilling of 10 Maverick Basin
gas and oil wells, plus costs associated with 2 wells drilled during the last
quarter of 1998. Also included were $211,101 in 3-D seismic acquisition and
reprocessing costs and $390,000 in lease extension payments to maintain
non-producing lease acreage in the Company's growing Maverick Basin lease block.
The Company made timely payments on long term debt of $2,629,118 during 1999,
including $1,966,956 paid on the Range financing agreement. Scheduled payments
totaling $662,162 were made on the Company's remaining long-term notes during
the remainder of the year.
During the 3rd quarter of 1999, TXCO successfully entered into a joint venture
agreement with Castle Exploration Company, (Castle) a wholly owned subsidiary of
Castle Energy Corporation (Nasdaq:CECX), whereby Castle agreed to fund up to
$5,300,000 for 100% of all costs to acquire approximately 25,000 acres of
additional leases, fund a 42 square mile 3-D seismic survey and drill up to 12
gas wells. In exchange, TXCO contributed its interest in an 8,800 lease to the
venture, was named operater and will be carried at no cost, for a 25% interest
in the first 12 wells drilled. Additionally, TXCO will be licensed to share in
all seismic data gathered and will earn a 50% working interest in all leases
acquired with the funds. At year end, all 3-D seismic acquisition and processing
had been completed, and Company geologists and geophysicists were in process of
interpreting and evaluating the new data.
During the 4th quarter of 1999, the Company successfully closed another non-cash
transaction to acquire various oil and gas mineral interests near or adjoining
TXCO's Maverick Basin leasehold. In exchange for 325,000 shares of its
restricted common stock valued at $493,594, the Company purchased a 12.5%
interest in 12,800 acres known as the Chittim Lease, including a 12.5% working
interest in 6 producing oil and gas wells and associated equipment. In addition,
TXCO also received a 100% working interest in two separate leases totaling
approximately 11,700 acres.
As a result of these activities, the Company ended fiscal year 1999 with
negative working capital of $1,525,594 and a current ratio of .70 to 1. This
compares to positive working capital of $516,693 and a current ratio of 1.19 to
1 at August 31, 1998. Working capital weakened during 1999 primarily due to cash
outlays for its aggressive ongoing development activities and due to timely
payments made under the terms of the Range financing agreement. Although the
Company had a working capital deficit at year end, included in current
liabilities is $2,110,620 estimated as the debt payment for fiscal 2000 under
the Range financing agreement. The Range debt payments are only due and payable
out of each future month's net cash flow from the collateralized producing
wells. Should producing well cash flows be less than estimated, the debt
repayment will be less, while the reverse is true should cash flows be greater.
Due to the Company's drilling success in 1998 and 1999, it expects substantially
all of the Range debt to be repaid during fiscal year 2000. Management is
confident of the Company's ability to continue to generate positive cash flow
from operations, and in its ability to meet its ongoing operating cash
requirements.
<PAGE>
17
1998
- ----
During the year ended August 31, 1998, beginning cash reserves of $6,198,069
were reduced by net cash used in operating activities of $1,185,050 resulting in
a total of $5,013,019 in working capital available used in funding the Company's
ongoing development and exploration of its oil and gas properties, significantly
improving the Company's potential to increase its core revenues from oil and gas
operations, and enhancing its ability to overcome the impact of continued
weakness in oil and gas prices.
Throughout fiscal 1998, the Company pursued opportunities to enhance its
liquidity by the conversion of existing short term trade payables to long-term
debt and the conversion of debentures into common stock. Management successfully
converted 4 separate accounts totaling $1,684,000 in current trade payables into
separate notes, with payment terms ranging from 12 to 36 months and interest
accruing at rates ranging from 8% to 14%. Further improvements to the Company's
debt structure were realized by Management's election to exercise the Company's
option to convert its outstanding $4,000,000 debentures to equity. Effective
January 1, 1998, the Company issued 844,318 shares of its common stock in
exchange for the outstanding debentures, including accrued interest of $221,590,
at the conversion price of $5.00 per share. In addition to the extremely
favorable conversion price for the new issuance, and the elimination of $240,000
in future annual interest expense, Management's elimination of its primary
long-term debt significantly enhanced the Company's ability to pursue additional
sources of equity or debt-based working capital.
Late in the final quarter of 1998, the Company entered into a financing
agreement with Range Energy Finance Corporation, a subsidiary of Range Resources
Corporation (NYSE:RRC), (formerly Domain Energy Corporation) to initially
establish a borrowing ceiling of $4,000,000. During fiscal year 1999 the
borrowing ceiling was increasd to $4,400,000. The financing was specifically for
ongoing development of the Company's natural gas producing properties in
Maverick County, Texas. Funds were advanced in exchange for a limited term
overriding royalty interest tied to existing and future production from
specified depths underlying certain of the Company's oil and gas leases in
Maverick County. Terms provided for repayment of the funds, with interest at
18%, from a specified portion of sales proceeds from all existing and future
wells to be drilled on the Paloma lease. By August 31, 1998 the Company had
borrowed $3,500,000 under the agreement.
Throughout the year ended August 31, 1998, the Company applied $4,806,505 of its
available working capital to fund the ongoing development of its oil and gas
properties. This included drilling and completion costs of $3,385,720 associated
with the current year drilling of four new Maverick Basin gas wells, three new
Williston Basin oil wells and costs associated with 4 wells drilled prior to the
current fiscal year, plus $188,785 for completion of the newest segment of the
Company's new gas gathering system in Maverick County during 1998. Also included
were 1998 3-D seismic acquisitions totaling $711,294 over Company leases in
North Dakota and $153,845 on the Paloma lease in South Texas. Additional
investments in non-producing lease acreage totaled $366,861 for the year.
Additionally, the Company made payments on its long-term debt during the year of
$1,500,990. Included in the total was $940,481 paid during the first quarter, in
full prepayment of the Company's outstanding line of credit with Luzerner
Kantonalbank. Scheduled payments totaling $560,509 were made on the Company's
remaining long-term notes during the remainder of 1998.
As a result of these activities, the Company ended fiscal year 1998 with
positive working capital of $516,693 and a current ratio of 1.19 to 1. This
compares to positive working capital of $3,760,648 and a current ratio of 2.32
to 1 at August 31, 1997. While the Company's working capital position weakened
from the previous year, the results of the Company's dramatic 100% drilling
success ratio during 1998 for new Glen Rose wells became evident during the
first quarter of fiscal year 1999. As new wells were placed on production,
Management was assured in its confidence of continuing significant improvements
in the Company's ability to meet its ongoing operating cash requirements.
<PAGE>
18
1997
- ----
During the first quarter of 1997, the Company converted $933,485 of its debt
into 340,060 shares of common stock and raised an additional $525,000 cash
through the exercise of common stock warrants and sales of common stock.
During the second quarter of fiscal 1997, the Company successfully closed a
large transaction that resulted in its acquiring an additional 220,000 net acres
of undeveloped oil and gas acreage in the Williston Basin of North and South
Dakota and Montana for $22,000,000 cash and the issuance of 1,000,000 shares of
restricted common stock. Simultaneous with the acquisition, the Company sold a
42.5% net profits interest in future wells on the acreage for $17,000,000 cash.
Concurrent with the acquisition of undeveloped acreage and sale of the net
profits interest, the Company received from the same acquiring parties
$4,000,000 cash for a debenture convertible into the Company's common stock at
$5.00 per share. During the same quarter, the Company completed an offering
under Regulation S by successfully selling 2,800,000 shares of its common stock
for $14,000,000 and also converted $1,331,212 in previously issued convertible
debentures into 532,488 shares of common stock. The result of the above
transactions was to significantly enhance the Company's operating position by
giving it additional acreage to develop as well as the working capital with
which to drill.
For the entire year, the Company raised $15,007,400, net of expenses, through
common stock sales and converted $2,264,702 of convertible debentures into
common stock (and thereby eliminating an on-going cash outlay for interest as
well as the future repayment of the debt). The Company also raised $17,000,000
through the sale of the net profits interest in future Williston basin wells to
be drilled and raised an additional $5,000,000 through new debt financing, which
included proceeds from the sale of $4,000,000 in convertible debentures plus
proceeds from its existing $1,000,000 line of credit. A portion of this new
capital was used to finance the second quarter acquisition of the Company's
additional 220,000 net acres of Williston Basin oil leases purchased for
$22,000,000 cash plus 1,000,000 shares of the Company's common stock. Proceeds
were also used to fund the Company's loss for the year of $3,398,866, including
the payment of interest of $236,000, payments on current portion of debt and
capital leases of $210,000 and for capital and investment expenditures of
$14,196,000. Capital expenditures included approximately $115,000 in equipment,
$125,000 in drilling bonds and deposits, $200,000 in prepaid loan fees and
cumulative advances to ExproFuels totaling $826,000. Most significantly,
$12,924,000 was invested in the development of the Company's oil and gas
properties, including the drilling of four Maverick Basin wells in Texas, 11
Williston Basin wells in North Dakota, the acquisition of $780,000 of 3-D
seismic data and $279,000 for expansion of the Company's Maverick County natural
gas pipeline infrastructure.
At August 31, 1997, the Company had cash of $6,198,069 and working capital of
$3,760,648, on current assets of $6,609,579 and current liabilities of
$2,848,931. This compared to a cash position of $967,838 and a working capital
deficit of $33,624 at August 31, 1996.
2000 Capital Requirements
- -------------------------
The major components of the Company's plans, and the requirements for additional
capital at August 31, 1999, include the following:
Maverick Basin Activity: During fiscal 2000, the Company's plans to drill a
minimum of 9 additional wells, in keeping with lease renewal minimum
requirements, with a total drilling budget of $2,000,000. Two of these wells are
scheduled to be drilled under and funded by the Castle project at no cost to
TXCO. The remaining 7 wells are targeted as Glen Rose reef prospects, each
costing approximately $225,000 to 275,000 to complete or $160,000 as a dry hole.
Company engineers are planning to test other formations with horizontal drilling
techniques with the hope of unlocking additional reserves not previously
productive from vertical drilling, due to the formations' low permeability. The
horizontal drilling increases the typical gross completion cost of a well by
$150,000 to $300,000, with the Company's share being approximately $90,000 to
$180,000. In the event of continuing improvements in realized oil and gas
prices, the Company can accelerate its drilling program as additional internally
generated working capital becomes available during the year. It can also
accelerate the Castle program as directed by the funding partner during the
year. Estimated expenditures required to maintain the Company's interest in its
remaining undeveloped South Texas leasehold acreage for fiscal 2000 are
$269,000.
<PAGE>
19
The Company has effectively layed off a significant portion of the capital
requirements for which it would have otherwise had to provide funding for during
fiscal 2000 and 2001. This capital outlay reduction was made possible by the
carried interest feature included in two key strategic joint ventures it entered
in during 1999. TXCO will be carried for a 25% interest in the next 11 wells
proposed to be drilled under its joint operating agreement with Castle
Exploration Company. Upon completion of the new 3-D seismic data set's
interpretation, the results from the new 31,700 acre 3-D seismic survey should
generate a number of new drillable Glen Rose reef prospects in excess of TXCO's
internal drilling program. In addition, all of TXCO's currently remaining 3-D
seismic expenditures for both the Castle project and the Blue Star Jurassic
project are covered entirely by its partners.
Williston Basin Activity: Due to the continuing uncertainty in crude oil prices
and unattractive economics for continued exploration, the Company has deferred
further expenditures in the Williston Basin, except for maintaining existing
producing properties and the payment of delay rentals and lease extensions on
selected leases. Management will continue its efforts to offer its remaining
prospects to other industry operators. Delay rentals required to maintain the
Company's interest in its remaining undeveloped Williston Basin leasehold
acreage for fiscal 2000 are $135,000.
Summary of Capital Resources and Liquidity
Subsequent to the end of fiscal 1999, the Company successfully drilled two
wells, completing one as a Georgetown formation gas well in October 1999.
Drilling on the second well was completed in November 1999, with electric logs
indicating the well encountered a 55 foot section of Glen Rose reef which
appears to be gas productive. The Company's net revenues from both wells should
increase by $500,000 to $750,000 per year.
While management is confident it has identified sufficient sources of working
capital to carry out its current exploration and development plans on its Texas
leaseholds, as well as to meet its obligations in the ordinary course of
business through the end of the new fiscal year, there is no assurance that
energy prices will either continue to improve or return to their weakened
positions as they were during the first half of 1999. Should prices weaken, the
reduction in revenues could cause the Company to re-evaluate its expected
sources of working capital and reduce its current operating plans. Management is
actively involved in ongoing discussions with various domestic and foreign based
sources of debt and equity financing that could provide favorably structured
funding as required to increase the Company's planned drilling activity during
fiscal year 2000. Management remains confident that financial resources will
remain available, enabling the Company to continue the rapid development of its
oil and gas properties and continue to meet its normal operational and debt
service obligations.
Year 2000
Over the last three years the Company has replaced or upgraded most of the core
management information systems used in the Company's business. The Company has
conducted a review of these systems to verify their compliance with Year 2000
date codes. In addition, the Company has conducted an inventory, review and
assessment of its desktop computers, networks and servers, software applications
and packages, and products and services provided by third parties for internal
operations to determine whether or not they support Year 2000 date codes. The
Company believes it has successfully completed required modifications to all
mission critical applications included in its internal systems. In addition, the
Company has contacted its major gas purchasers, gas pipeline carriers, stock
transfer agent and banking institutions and received written assurances and/or
viewed assurances on their websites that they have no material Year 2000
problems. The Company does not believe the Year 2000 issue will materially
affect its ability to pay its vendors and suppliers, track its assets in the
custody of financial institutions or otherwise prevent it from conducting its
business on an ongoing basis.
RESULTS OF OPERATIONS
1999 Compared to 1998
The Company reported net income of $931,545 or $0.06 per diluted share for the
year ended August 31, 1999, compared to a net loss of ($ 8,417,218) or ($0.55)
per diluted share for the same period in 1998. The attainment of profitability
was primarily the result of a 146% increase in revenues over 1998 levels due
primarily to significant new production from 9 new wells placed on line during
the year, including 2 gas wells completed late in the last quarter of the prior
year. While very positive, the increases were significantly offset by the
weakness in oil and gas prices through the first half of 1999. Gas sales volume
increases also reflect the impact of the first full year of operation of the
expanded gas gathering system completed during the latter part of 1998.
<PAGE>
20
Exploration expenses decreased by 88% compared to 1998 levels due to the high
drilling success in the Maverick Basin compared to multiple Williston Basin dry
holes drilled or abandoned during the prior year. Abandoned leases and equipment
expense decreased by 78% primarily to the non-recurring nature of the one time
charge off of uneconomical producing properties during 1998 due to the oil and
gas price collapse during 1998. Impairment expense decreased by 92% also due to
the non-recurring nature of the initially large impairment provisions required
due to the oil price collapse in the prior year, while lower 1999 impairment
provisions proved adequate in light of the improvement in realized oil and gas
prices during the last half of the current year. Depreciation, depletion and
amortization increased by 61% over 1998 levels due primarily to an increase in
depletion. The change in depletion was due to the adverse impact on year end
reserve estimates caused by declining oil production and increasing water
disposal costs associated with Williston Basin production.
The decrease in loan fee amortization expense as compared to 1998, reflects the
non-recurring nature of the prior period's recognition of $180,000 in previously
capitalized prepaid loan fees due to the conversion of a $4,000,000 debenture in
January 1998. Fiscal 1998 loan fee amortization expense has been reclassified
for comparative purposes with current year expense. Interest expense increased
by 142% over 1998, reflecting a full year of interest charges on borrowings
under the Range financing agreement entered into during the last quarter of the
prior year.
1998 Compared to 1997
Revenues from oil and gas sales increased 195% over 1997 as a result of
significant new production from the successful completion of the nine new wells
during the last part of the 1997, plus the additional production from 4 new gas
wells added during 1998. Lease operating expenses, related directly to the costs
of operating the newly producing Williston Basin oil wells with very high
production associated water disposal costs, increased by 297% over 1997. The
disproportionately higher increase in lease operating expense increases reflects
the difference in the Company's normal natural gas production expense level
versus the significantly higher per unit production cost associated with its
Williston Basin oil production.
Exploration expenses, including the costs of unsuccessful wells increased by 47%
due to the write-off of two high working interest dry holes during the year
compared to two very low working interest dry-holes in the previous year. The
40% fall of oil prices at mid-year rendered the completion of the wells
uneconomical. Abandoned leases and equipment increased to $1,451,880, reflecting
the ongoing impact of the 40% fall of oil prices during the year that rendered
marginal properties uneconomic to maintain or renew. Included in the non-cash
charge off for the current year are $608,573 in Williston Basin leases, $156,670
in Zavala County leases (South Texas), and $26,757 in Canadian Crown leases, all
determined to be uneconomic and expiring during the current year due to the
continued impact of low oil and gas prices. Also included in the 1998 non-cash
writeoff was the remaining capitalized costs $659,880 for the Kincaid #1-99, a
horizontal Georgetown test well drilled in Maverick County during the third
quarter of 1997 that failed to produce economic quantities of gas.
Pursuant to the Successful Efforts Method of accounting for mineral properties,
the Company periodically assesses its producing properties and non-producing
mineral leases for impairment. Based on the 40% fall in oil prices during the
year and the resulting impact on the updated reserve estimates at year end, the
Company identified certain producing properties which required impairment.
Additionally, non-producing leaseholds were reviewed for potential impairment.
Certain leases, with expiration dates through December 1999, were identified
which will not be renewed. Non-cash impairment charges totaling $3,655,342 were
recorded at year end including $1,580,820 of Williston Basin and Texas
non-producing leases set to expire through calendar year 1999. Additionally, a
$2,194,522 impairment was recorded reflecting the excess of unamortized book
value over the future realizable reserves primarily related to certain of its
Williston Basin wells. Additional expenses during the year include depreciation,
depletion and amortization of 1,446,726, plus current year exploration expenses
of $2,290,649.
Except for the statutory, intangible (non-cash) expenses required for compliance
reporting purposes described above and current year exploration expenses, actual
operating activities for the year ended August 31, 1998 resulted in positive
cash flow from producing operations of $989,484. This level of positive cash
flow, if sustained, is sufficient to provide for funding of the Company's
primary administrative operations. Management feels confident this source of
internally generated working capital will continue to grow as the Company's
Texas gas production levels expand through fiscal 1999 and beyond.
<PAGE>
21
General and administrative costs increased to $1,278,270 from $938,000.
Increases in salaries totaling approximately $211,000 were due primarily to a
full twelve months of wages in 1998 for the increased number of new employee
positions required by the Company's expansion in operations as a result of the
Williston Basin lease acquisition versus only a partial year for the previous
year. The $184,692 decrease in interest income in 1998 reflects the lower cash
levels in interest bearing accounts during 1998 versus the prior year.
1997 Compared to 1996
Revenues from oil and gas sales increased 115% over 1996, to $976,000 from
$455,000, as a result of significant new production from the successful
completion of the nine new wells during the last part of the year. Lease
operating expenses, related directly to the costs of operating the producing
wells, accordingly increased to $176,000 from $75,000 in 1996. Exploration
expenses, which includes the costs of unsuccessful wells, increased by 129% to
$1,549,000 from $677,170, with $965,000 in dry hole costs related to the James
#1-9F. The well was in the process of drilling at August 31, 1997, but
subsequently did not produce sufficient hydrocarbons to be economically viable.
Although the Company may re-enter the well and drill another lateral in a
different direction, all costs related to the James #1-9F were accrued and
included in fiscal 1997 operations as a loss, in accordance with generally
accepted accounting principles.
Other costs included non-cash expenses of $153,000 in abandoned leases,
primarily represented by certain expired acreage in Canada, as well as depletion
and depreciation of $293,000. General and administrative costs increased to
$938,000 from $513,000 due primarily to increased salaries for new employee
positions required by the Company's expansion in operations as a result of the
Williston Basin lease acquisition. Although interest expense decreased by
$141,500, this was almost all offset by the write-off of deferred financing fees
on debt converted during the year.
In total, revenues increased $561,000 or 108%, to $1,083,000 in 1997 from
$521,000 in 1996. Cost of sales, including exploration expenses, general and
administrative expenses, and abandoned leases, increased 119%, to $3,210,000 in
1997 from $1,465,000 in 1996, resulting in an increase in the Company's loss
from its oil and gas operations to $2,127,000 in 1997 from $943,000 in 1996. The
Company also incurred a loss on its investment in ExproFuels of $1,215,000
compared to $680,000 in 1996. However, since this investment has been written
down to zero dollars, and no additional cash advances are expected after
December 31, 1997, (advances committed to ExproFuels of $265,000 for September
1, 1997 to December 31, 1997 were accrued at August 31, 1997) operations should
not suffer from this investment in future periods. As a result of the above,
loss from operations increased to ($3,342,000) in 1997 from ($1,624,000) in
1996.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
None - See additional comments pertaining to certain business risk on page 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Financial Statements and Notes thereto are set out in this Form 10-K
commencing on page F-1.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES
None
<PAGE>
22
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information regarding the directors and
executive officers of the Company, as of November 10, 1999:
<TABLE>
<CAPTION>
Name Position Age
---- -------- ---
<S> <C> <C>
Stephen M. Gose, Jr. Chairman of the Board of Directors 69
Member Audit and Compensation Committees
Michael Pint Director, Chairman Audit and Compensation Committees 56
Robert L. Foree, Jr. Director, Member Audit and Compensation Committees 70
Thomas H. Gose Director and Assistant Secretary 44
James E. Sigmon President and Director 51
Roberto R. Thomae Chief Financial Officer 48
Secretary/Treasurer, Vice President-Finance
Richard A. Sartor Controller 47
</TABLE>
Stephen M. Gose, Jr., has served as Chairman of the Board of Directors of the
Company since July 1984. He has been a member of the Audit and Compensation
Committees since June 1997 and served as their Chairman through April 1998. He
has been active for more than 45 years in exploration and development of oil and
gas properties, in real estate development, and in ranching through the
operations of Retamco Operating, Inc., its predecessors and affiliates. Mr. Gose
also serves as Chairman of the Board of Directors of ExproFuels, Inc.
Michael Pint has served as a Director since May, 1997. He has been a member of
the Audit and Compensation Committees of the Board of Directors since June, 1997
and has served as their Chairman since April, 1998. Since 1995, Mr. Pint has
served as a Director of Valley Bancorp, Inc. and Valley Bank of Arizona, Inc. of
Phoenix, Arizona and Midway National Bank of St. Paul, Minnesota. Previous bank
regulatory and management positions include a four year term as Commissioner of
Banks and Chairman of the Minnesota Commerce Commission from 1979 to 1983 and
Senior Vice-President and Chief Financial Officer of the Federal Reserve Bank of
Minneapolis, Minnesota through 1983.
Robert L. Foree, Jr. has served as a Director since May, 1997 and as a member of
the Audit and Compensation Committees of the Board of Directors since June,
1997. Since 1992, Mr. Foree has served as President of Foree and Company, a
Dallas, Texas based independent oil and gas exploration and production company.
Thomas H. Gose has served as a Director of the Company since February, 1989, as
Secretary from 1992 through May, 1997 and as Assistant Secretary since May,
1997. He formerly served as Director, CEO and President of Retamco Operating,
Inc., (a large shareholder of the Company) its predecessors and affiliates,
since 1987. He also serves as President and Director of ExproFuels, Inc. Thomas
H. Gose is the son of Stephen M. Gose, Jr.
James E. Sigmon has served as the Company's President since February 1985. He
has been a Director of the Company since July 1984. He served as a Director of
ExproFuels, Inc. through November 1998. Prior to joining the Company, Mr. Sigmon
served in the management of a private oil and gas exploration company active in
drilling oil and gas wells in South Texas.
Roberto R. Thomae has served as Chief Financial Officer and Vice
President-Finance of the Company since September 1996 and as Secretary/Treasurer
since March 1997. From September 1995 through September 1996 he was a consultant
to the Company in a financial management capacity. From 1989 through 1995 Mr.
Thomae was self- employed as a management consultant primarily involved in the
development of domestic and international oil and gas exploration projects and
the marketing of refined products.
<PAGE>
23
Richard A. Sartor has served as Controller of the Company since April 1997. A
Certified Public Accountant since 1980, Mr. Sartor owned his own private
accounting practice from 1989 through March 1997.
Each of the aforementioned Executive Officers and/or Directors have been elected
to serve for one year or until his successor is duly elected.
ITEM 11. EXECUTIVE COMPENSATION
Summary Compensation Information: The following table contains certain
information for each of the fiscal years indicated with respect to the chief
executive officer and those executive officers of the Company as to whom the
total annual salary and bonuses exceed $100,000:
<TABLE>
<CAPTION>
SUMMARY COMPENSATION TABLE
Name and Other Annual Long-term All other
Principal Position Year Salary Bonuses Compensation Compensation Compensation
- ------------------ ---- ------ ------- ------------ ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
James E. Sigmon 1999 $ 150,000 $ 0 (1) $56,678 $ 0 $ 0
President & CEO 1998 132,000 0 (1) 41,623 0 0
1997 120,000 0 (1) 20,827 0 0
</TABLE>
(1) Amounts represent income from an overriding royalty interest.
<TABLE>
<CAPTION>
OPTIONS/SAR GRANTS IN LAST FISCAL YEAR
% of Total Options Grant
# Options Granted to Employees Exercise Price Expiration Date
Name Granted in Fiscal Year per Share Date Value (1)
- ----------------- ------- ------------------- ------------- ----------- ------------
<S> <C> <C> <C> <C> <C>
Roberto R. Thomae 25,000 18% $0.98 2008 $23,750
CFO & Secr/Treas
</TABLE>
(1) The fair value for all options granted, whether vested or not, was
estimated at the date of grant using the Black-Scholes option pricing model
with the following weighted-average assumption: risk-free interest rate of
5.0%; dividend yield of 0%; volatility factors of the expected market price
of the Company's common stock of .95 and a weighted-average expected life
of the option of five years.
<PAGE>
24
AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR
AND FISCAL YEAR END OPTION/SAR VALUES
<TABLE>
<CAPTION>
Number of Unexercised Value of Unexercised
# Shares Value Options/SARs Options/SARs
Name Exercised Realized August 31, 1999 August 31, 1999 (1)
--------- --------- -------- ----------------------- -------------------
<S> <C> <C> <C> <C>
James E. Sigmon (2) - - 700,000 $ 0
Michael Pint (3) - - 75,000 0
Robert L. Foree, Jr .(3) - - 75,000 0
Roberto R. Thomae (4) - - 75,000 $30,200
</TABLE>
(1) Value of unexercised options calculated as the difference in the stock
price at August 31,1999 and the option price. None of these unexercised
options were "in the money" at August 31, 1999 and/or were not vested;
accordingly the options are valued at $0 at year end.
(2) 100,000 of Mr. Sigmon's unexercised options were exercisable as of August
31, 1999, and the remaining 600,000 options vest and are exercisable in
specified amounts upon the Company's common stock attaining the following
price levels: 200,000 shares at $5.00, 100,000 shares at $7.50, 100,000
shares at $10.00, 100,000 shares at $12.50 and 100,000 shares at $15.00.
(3) 50,000 of Mr. Pint and Mr. Foree's options, respectively, were exercisable
as of August 31, 1999.
(4) 50,000 of Mr. Thomae's options were exercisable at August 31, 1999.
COMPENSATION OF DIRECTORS
Members of the Board of Directors who serve as Executive Officers of the Company
are not compensated for any services provided as a Director. Outside
(non-employee) Directors of the Company are paid a fee of $1,000 for each board
meeting physically attended or $250 for telephonic attendance plus reimbursement
of related travel expenses. Additionally, upon assuming Director status, the two
outside directors were awarded 10 year options for the purchase of 75,000 shares
of Company common stock at 110% of the stock's market value on the date of
grant, with such options vesting equally over their first three years of
service.
EMPLOYMENT CONTRACTS
The Company has an employment agreement with its president, Mr. James E. Sigmon,
which sets his salary at a minimum of $150,000 annually, and includes the grant
of a proportionately reduced 1% overriding royalty interest under all leases the
Company has or acquires during his term as President. The agreement is
cancelable with 90 days notice by the Company.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
No Compensation Committee interlocks existed during the Company's last completed
fiscal year. The Compensation Committee of the Board of Directors of the Company
was established in June, 1997 and consists of Michael Pint (Chairman), Robert L.
Foree, Jr. and. Stephen M. Gose, Jr. The principal function of the Committee is
to approve the compensation of all executive officers of the Company, to
recommend to the Board the terms of principal compensation plans requiring
stockholder approval and to direct the administration of the Company's 1995
Flexible Incentive Plan.
<PAGE>
25
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following tables set forth beneficial ownership of the Company's common
stock, its only class of equity security. The percent owned is based on
15,938,516 shares outstanding and 17,490,816 fully diluted shares which includes
1,552,300 shares under options and warrants as of November 1, 1999.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The following table sets forth information concerning all persons known to the
Company to beneficially own 5% or more if its common stock, including
information filed pursuant to Rule 13d filings made available to the company
during the year.
Percent Owned
Name and Address of Number of Shares Primary Shares
Beneficial Owner Beneficially Owned Outstanding
------------------------------------------ ------------------ -----------
Thomas H. Gose ............................ 1,094,101 6.86%
500 North Loop 1604 East
Suite 250
San Antonio, TX 78232
Stephen M. Gose, Jr ....................... 1,176,600 7.38%
HCR Box 1010 Hwy 212
Roberts, Montana 59070
Trianon Opus One, Inc. .................... 1,400,000 8.78%
Fohrenstrasse 25
CH-8703 Erlenbach
Switzerland
Pensionskasse der F. Hoffman La Roche A.G . 1,074,600 6.74%
Funds I & II
Grenzacherstrasse 124
4070 Basel
Switzerland
SECURITY OWNERSHIP OF DIRECTORS AND EXECUTIVE OFFICERS
The following table sets forth the number of shares of common stock beneficially
owned as of November 1, 1999 by each director, each executive officer named in
the Summary Compensation Table and by all directors and executive officers as a
group. Information provided is based on the Form 4's, stock records of the
Company and the Company's transfer agent.
Number of Shares Percent
Name Beneficially Owned Owned (1)
-------------------------- ------------------ ---------
Stephen M. Gose, Jr. ....... (3) 1,176,600 7.38%
Thomas H. Gose .............. 1,094,101 6.86%
James E. Sigmon ............. (2) 750,000 4.51%
Michael Pint ................ (4) 275,000 1.72%
Robert L. Foree, Jr ......... (4) 61,000 .38%
All Directors and Executive
Officers as a group ........... 3,431,701 20.35%
<PAGE>
26
(1) Except as otherwise noted, the Company believes that each named individual
has sole voting and investment power over the shares beneficially owned.
(2) The number of shares beneficially owned by Mr. James E. Sigmon includes
50,000 shares owned directly and 700,000 shares of the Company's Common
Stock reserved for issuance through options issued under the Company's 1995
Flexible Incentive Plan.
(3) The number of shares beneficially owned by Mr. Stephen M. Gose, Jr. include
30,000 shares owned directly, plus his 100% interest, shared equally with
his spouse, in 1,146,600 shares owned by Retamco Operating, Inc.
(4) The number of shares beneficially owned by Mr. Pint and Mr. Foree each
includes 50,000 shares of the Company's Common Stock reserved for issuance
under non-qualified options issued to outside directors of the Company
exercisable at August 31, 1998 plus 225,000 and 11,000 respectively, of
directly owned shares.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
During 1997, the Company purchased undeveloped oil and gas leases covering
approximately 220,000 net acres for exploration in the Williston Basin of North
and South Dakota and Montana. The acquisition was paid for with $22,000,000 cash
and the issuance of 1,000,000 shares of common stock valued at $5 per share. A
67% interest in the leases was acquired from Retamco Operating, Inc., a company
affiliated with two directors of the Company. Concurrently with the acquisition,
the Company sold to third parties a 42.5% net profits interest in wells to be
drilled on the oil and gas leases for $17,000,000 cash. The oil and gas leases
acquired have been reported at the affiliates cost basis, which resulted in a
reduction to the basis in the properties of $9,773,154 and a charge for the same
amount to additional paid-in capital.
The Company's ExproFuels division was spun off from The Exploration Company on
September 3, 1996 with a 40% equity ownership being retained. During 1997 the
Company's net investment in ExproFuels, Inc. was reduced to $0 by recognition of
a $1,215,259 charge to operations. ExproFuels has no remaining assets and no
current operations.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(A) The following documents are being filed as part of this annual report
on Form 10-K after the signature page, commencing on page F-1.
(1) Financial Statements:
Independent Auditors' Reports.
Balance Sheets, August 31, 1999 and 1998
Statements of Operations, Years Ended August 31, 1999, 1998 and
1997. Statements of Stockholders' Equity, Years Ended August 31,
1999, 1998 and 1997. Statements of Cash Flows, Years Ended August
31, 1999, 1998 and 1997.
Notes to Financial Statements.
(2) Financial Statement Schedule for the years ended August 31, 1999,
1998 and 1997:
Schedule II - Valuation and Qualifying Reserves.
All other schedules for which provision is made in the applicable
accounting regulations of the Securities and Exchange Commission
are omitted as the required information is inapplicable or the
information is presented in the Consolidated Financial Statements
or Notes thereto.
<PAGE>
27
(3) Exhibits:
** 3.1 Articles of Incorporation of the Registrant filed
as Exhibit 3(B) to the registration statement on Form
S-1; Reg. No. 2-65661.
** 3.2 Articles of Amendment to Articles of Incorporation
of The Exploration Company, dated July 27, 1984, filed
as Exhibit 3.2 to Registrant's Annual report on Form
10-K, dated February 4, 1985.
** 3.3 Articles of Amendment to the Articles of Incorporation
of the Exploration Company dated April 2, 1985.
** 3.4 By-Laws of the Registrant filed as Exhibit 5(A) to the
Registration Statement on Form S-1; Reg. 2-65661.
** 3.5 Amendment to By-Laws of registrant, dated Sept 1, 1985.
** 3.6 Articles of Amendment to the Articles of Incorporation
of The Exploration Company dated April 6, 1990.
**10.2 Employment Agreement between the Registrant and James
E. Sigmon, dated October 1, 1984.
**10.3 Registrant's Amended and Restated 1983 Incentive
Stock Option Plan filed as Exhibit A to registrant's
definitive Proxy Statement, dated February 20, 1985.
**10.4 Registrant's 1995 Flexible Incentive Plan, filed as
Exhibit A to registrant's definitive Proxy Statement,
dated April 28, 1995.
**10.5 Registrant's Form S-8 Registration Statement for its
1995 Flexible Incentive Plan, dated November 26, 1996.
**10.6 Registrant's Amendment to its 1995 Flexible
Incentive Plan, filed as Proposal II of the
registrants definitive Proxy Statement, dated
Jan 12,1999.
**10.7 Registrant's Plan and Agreement of Merger of The
Exploration Company with and into The Exploration
Company of Delaware, Inc., filed as Appendix A of the
registrants definitive Proxy Statement, dated January
12, 1999.
**10.8 Registrant's Certificate of Incorporation of The
Exploration Company of Delaware, Inc., filed as
Appendix B of the registrants definitive Proxy
Statement, dated January 12, 1999.
**10.9 Registrant's Certificate of Amendment of Certificate of
Incorporation of The Exploration Company of Delaware,
Inc., filed as Appendix C of the registrants definitive
Proxy Statement, dated January 12, 1999.
**10.10 Registrant's Bylaws of The Exploration Company of
Delaware, Inc., filed as Appendix D of the registrants
definitive Proxy Statement, dated January 12, 1999.
27.1 Financial Data Schedule
** Previously filed
(B) Reports on Form 8-K:
None Filed
<PAGE>
28
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.
THE EXPLORATION COMPANY OF DELAWARE, INC.
Registrant
November 23, 1999 By: /s/ James E. Sigmon
---------------------------------
James E. Sigmon, President
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
<TABLE>
<CAPTION>
Signatures Title Date
- ----------- ----------------------------------- -----------
<S> <C> <C>
/s/ Stephen M. Gose, Jr.
- -----------------------------
Stephen M. Gose, Jr. Chairman of the Board of Directors November 23, 1999
/s/ Thomas H. Gose
- ----------------------------
Thomas H. Gose Director and Assistant Secretary November 23, 1999
/s/ James E. Sigmon
- ----------------------------
James E. Sigmon President and Director
(Principal Executive Officer) November 23, 1999
/s/ Michael Pint
- ----------------------------
Michael Pint Director November 23, 1999
/s/ Robert L. Foree, Jr.
- ----------------------------
Robert L. Foree, Jr. Director November 23, 1999
/s/ Roberto R. Thomae
- ----------------------------
Roberto R. Thomae Chief Financial Officer November 23, 1999
Secretary/Treasurer
(Principal Accounting Officer)
</TABLE>
F-1
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
The Exploration Company
San Antonio, Texas
We have audited the balance sheets of The Exploration Company of Delaware, Inc.
(hereinafter referred to as "The Exploration Company") as of August 31, 1999 and
1998, and the related statements of operations, stockholders' equity and cash
flows for each of the three years in the period ended August 31, 1999. 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 in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of The Exploration Company as of
August 31, 1999 and 1998, and the results of its operations and cash flows for
each of the three years in the period ended August 31, 1999, in conformity with
generally accepted accounting principles.
We have also audited Schedule II of The Exploration Company for each of the
three years in the period ended August 31, 1999. In our opinion, this schedule
presents fairly, in all material respects, the information required to be set
forth therein.
AKIN, DOHERTY, KLEIN & FEUGE, P.C.
San Antonio, Texas
November 12, 1999
<PAGE>
F-2
THE EXPLORATION COMPANY
Balance Sheets
August 31, 1999 and 1998
<TABLE>
<CAPTION>
1999 1998
---------- ----------
Assets
<S> <C> <C>
Current Assets:
Cash and equivalents $ 968,516 $ 2,329,236
Accounts receivable:
Joint interest owners 583,985 293,931
Oil and gas production 1,669,364 567,735
Prepaid expenses and other 256,334 17,738
------------ ------------
Total current assets 3,478,199 3,208,640
Property and Equipment:
Oil and gas properties (successful efforts),
less accumulated depreciation,
depletion and amortization of $4,353,550 and $2,073,491,
and accumulated impairment of $2,323,584
and $3,894,739 13,538,938 12,502,566
Other property and equipment:
Transportation and other equipment, less accumulated
depreciation of $179,211 and $132,977 89,114 103,862
------------ ------------
Net property and equipment 13,628,052 12,606,428
Other Assets 447,564 449,564
------------ ------------
Total Assets $ 17,553,815 $ 16,264,632
============ ============
</TABLE>
See notes to audited financial statements.
<PAGE>
F-3
THE EXPLORATION COMPANY
Balance Sheets
August 31, 1999 and 1998
<TABLE>
<CAPTION>
1999 1998
---------- ----------
Liabilities And Stockholders' Equity
<S> <C> <C>
Current Liabilities:
Accounts payable and accrued expenses $ 678,478 $ 737,157
Due to joint interest owners 1,760,248 108,407
Current portion of long-term debt 2,565,067 1,846,383
------------ ------------
Total current liabilities 5,003,793 2,691,947
Long-Term Debt, net of current portion 529,742 2,977,544
Stockholders' Equity:
Preferred stock; authorized 10,000,000 shares,
issued and outstanding -0- shares - -
Common stock, par value $ .01 per share;
authorized 50,000,000 shares; issued and
outstanding 15,938,516 and 15,613,516 shares 159,385 156,135
Additional paid-in capital 40,651,444 40,161,100
Accumulated deficit (28,790,549) (29,722,094)
------------ ------------
Total stockholders' equity 12,020,280 10,595,141
------------ ------------
Total Liabilities and Stockholders' Equity $ 17,553,815 $ 16,264,632
============ ============
</TABLE>
See notes to audited financial statements.
<PAGE>
F-4
THE EXPLORATION COMPANY
Statements of Operations
Years Ended August 31, 1999, 1998 and 1997
<TABLE>
<CAPTION>
1999 1998 1997
---------- ---------- ----------
<S> <C> <C> <C>
Revenues:
Oil and gas sales $ 6,881,767 $ 2,886,676 $ 976,882
Other operating income 615,608 161,601 106,629
------------ ------------ ------------
7,497,375 3,048,277 1,083,511
Costs and Expenses:
Lease operations 864,675 700,381 176,019
Production taxes 471,193 178,912 71,954
Exploration expenses 269,344 2,290,649 1,549,095
Abandoned leases and equipment 323,784 1,451,880 153,066
Impairment of mineral properties 300,000 3,775,342 28,400
Depreciation, depletion and amortization 2,327,992 1,446,726 293,527
General and administrative 1,442,338 1,278,270 938,638
Net loss from ExproFuels equity ownership - - 1,215,259
------------ ------------ ------------
Total costs and expenses 5,999,326 11,122,160 4,425,958
Income (loss) from operations 1,498,049 (8,073,883) (3,342,447)
Other Income (Expense):
Interest income 73,892 98,770 283,462
Interest expense (628,396) (260,105) (236,494)
Loan fee amortization (12,000) (182,000) (103,387)
------------ ------------ ------------
(566,504) (343,335) (56,419)
------------ ------------ ------------
Net Income (Loss) $ 931,545 $ (8,417,218) $ (3,398,866)
============ ============ ============
Amounts Per Common Share:
Basic income (loss) $ 0.06 $ (0.55) $ (0.27)
============ ============ ============
Diluted income (loss) $ 0.06 $ (0.55) $ (0.27)
============ ============ ============
Weighted average number of common shares outstanding:
Basic 15,668,721 15,328,292 12,576,255
============ ============ ============
Diluted 15,678,567 15,328,292 12,576,255
============ ============ ============
</TABLE>
See notes to audited financial statements.
<PAGE>
F-5
THE EXPLORATION COMPANY
Statements of Stockholders' Equity
Years Ended August 31, 1999, 1998, and 1997
<TABLE>
<CAPTION>
Additional
Common Stock Paid-in Accumulated
Shares Amount Capital Deficit Total
------ ------ ------- ------- -----
<S> <C> <C> <C> <C> <C>
Balance at September 1, 1996 9,426,650 $ 94,266 $ 23,482,432 $ (17,906,010) $ 5,670,688
Issuance of common stock
for cash 3,280,000 32,800 14,492,200 - 14,525,000
Issuance of common stock in
exchange for oil and gas properties 1,000,000 10,000 4,990,000 - 5,000,000
Adjustment of oil and gas properties
to affiliates historical cost basis - - (9,773,154) - (9,773,154)
Common stock warrants exercised 180,000 1,800 480,600 - 482,400
Conversion of debt to common stock 872,548 8,726 2,255,976 - 2,264,702
Net loss for the year - - - (3,398,866) (3,398,866)
----------- --------- ----------- ------------ -----------
Balance at August 31, 1997 14,759,198 147,592 35,928,054 (21,304,876) 14,770,770
Conversion of debt to common stock 844,318 8,443 4,213,146 - 4,221,589
Common stock warrants exercised 10,000 100 19,900 20,000
Net loss for the year - - - (8,417,218) (8,417,218)
----------- --------- ----------- ------------ -----------
Balance at August 31, 1998 15,613,516 156,135 40,161,100 (29,722,094) 10,595,141
Issuance of common stock in
exchange for oil and gas properties 325,000 3,250 490,344 - 493,594
Net income for the year - - - 931,545 931,545
------------ --------- ------------ ------------- ------------
Balance at August 31, 1999 $ 15,938,516 $ 159,385 $ 40,651,444 $ (28,790,549) $ 12,020,280
============ ========= ============ ============= ============
</TABLE>
See notes to audited financial statements.
<PAGE>
F-6
THE EXPLORATION COMPANY
Statements of Cash Flows
Years Ended August 31, 1999, 1998, and 1997
<TABLE>
<CAPTION>
1999 1998 1997
---------- ----------- -----------
<S> <C> <C> <C>
Operating Activities:
Net income (loss) $ 931,545 $ (8,417,218) $ (3,398,866)
Adjustments to reconcile net income (loss) to
net cash provided (used) in operating activities:
Depreciation, depletion and amortization 2,327,992 1,446,726 293,527
Amortization of financing fees 12,000 162,000 83,887
Abandoned leases, equipment and other 323,784 1,451,880 153,066
Impairment of properties 300,000 3,775,342 28,400
ExproFuels operations and loan loss reserve - 1,215,259
Changes in operating assets and liabilities:
Receivables (1,391,683) (499,240) (290,839)
Prepaid expenses and other (238,596) 31,346 (49,084)
Accounts payable and accrued expenses 1,593,162 864,114 1,586,380
------------ ----------- -----------
Net cash provided (used) in operating activities 3,858,204 (1,185,050) (378,270)
Investing Activities:
Development of oil and gas properties (3,448,320) (4,806,505) (12,924,068)
Purchase of transportation and other equipment (31,486) (42,288) (115,071)
Investments in and advances to ExproFuels - - (826,224)
Other assets (10,000) - (331,036)
------------ ----------- -----------
Net cash (used) in investing activities (3,489,806) (4,848,793) (14,196,399)
Financing Activities:
Proceeds from long-term debt 900,000 3,646,000 5,008,140
Payments on long-term debt (2,629,118) (1,500,990) (210,640)
Issuance of common stock, net of expenses - 20,000 15,007,400
------------ ----------- -----------
Net cash provided (used) by financing activities (1,729,118) 2,165,010 19,804,900
------------ ----------- -----------
Change in Cash and Equivalents (1,360,720) (3,868,833) 5,230,231
Cash and Equivalents at Beginning of Year 2,329,236 6,198,069 967,838
------------ ----------- -----------
Cash and Equivalents at End of Year $ 968,516 $ 2,329,236 $ 6,198,069
============ =========== ===========
Supplemental Disclosures:
Cash paid for interest $ 721,292 $ 82,295 $ 151,955
Cash paid for income taxes - - -
</TABLE>
See notes to audited financial statements.
<PAGE>
F-7
THE EXPLORATION COMPANY
Notes to Audited Financial Statements
August 31, 1999, 1998 and 1997
NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and Operations: The financial statements include the accounts of
The Exploration Company (the Company) which is engaged in the business of
acquiring, exploring and developing oil and gas properties. The Company=s oil
and gas operations are located primarily in Texas, North Dakota and Montana.
During 1999, the Company changed its State of Incorporation from Colorado to
Delaware and, as a result, changed its legal name to The Exploration Company of
Delaware, Inc. However, the Company continues to conduct all business under the
name The Exploration Company.
From 1993 through 1996, the Company operated in the alternative fuels industry
through a division called ExproFuels.
Cash and Equivalents: Cash and equivalents consist of all demand deposits and
funds invested in short-term investments with original maturities of three
months or less. All of the Company's cash and money market accounts are
maintained with Frost National Bank and AIM Institutional Fund Services, Inc. At
year end, the Company did not have any cash equivalents in excess of insured
limits.
Oil and Gas Properties: The Company uses the successful efforts method of
accounting for its oil and gas activities. Costs to acquire mineral interests in
oil and gas properties, to drill and equip exploratory wells that find proved
reserves, and to drill and equip development wells are capitalized. Costs to
drill exploratory wells that do not find proved reserves, geological and
geophysical costs, and costs of carrying and retaining unproved properties are
expensed as incurred.
Depreciation, depletion and amortization (DD&A) of oil and gas properties are
computed using the unit-of-production method based upon recoverable reserves as
determined by Company engineers. Oil and gas properties are periodically
assessed for impairment, and if the unamortized capitalized costs of proved
properties are in excess of the discounted present value of future cash flows
relating to proved reserves, an impairment charge is recorded. Unproved
properties are also evaluated periodically and if the unamortized cost is in
excess of estimated fair value an impairment is recognized.
Other Property and Equipment: Transportation and other equipment are recorded at
cost. Depreciation is computed using the straight-line method over the estimated
useful lives of the assets ranging from five to fifteen years. Major renewals
and betterments are capitalized while repairs are expensed as incurred. Included
in other property and equipment are an insignificant amount of assets under
capital lease. Amortization related to capital lease obligations is included in
the Statement of Operations under depreciation, depletion and amortization.
Federal Income Taxes: Deferred tax assets and liabilities are determined based
on differences between financial reporting and tax basis of assets and
liabilities, and are measured using the enacted tax rates and laws that will be
in effect when the differences are expected to reverse. A valuation allowance is
provided against net deferred assets for which realization is doubtful.
Income (Loss) Per Common Share: Income (loss) per common share is calculated in
accordance with Financial Accounting Standards Board Statement No. 128. Basic
income (loss) per share considers as outstanding only common stock, without
giving any effect to options or warrants. Diluted income per share gives effect
to options and warrants using the treasury stock method.
<PAGE>
F-8
NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - continued
Comprehensive Income: During 1998, the Company adopted Statement No. 130,
Reporting Comprehensive Income. Statement No. 130 establishes new rules for the
reporting and display of comprehensive income and its components; however, the
adoption of this Statement had no impact on the Company's net income or
stockholders' equity as previously reported or in the current year.
Concentrations of Credit Risk: Financial instruments that potentially expose the
Company to credit risk consist principally of accounts receivable. Accounts
receivable, net of allowance of $27,026 at August 31, 1999, are generally from
companies with significant oil and gas marketing activities. The Company
performs ongoing credit evaluations and generally requires no collateral from
customers.
Use of Estimates: The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements, and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates. Management
believes that it is reasonably possible that estimates of proved crude oil and
natural gas reserves could significantly change in the future.
Stock-Based Compensation: Statement of Financial Accounting Standards No. 123,
"Accounting for Stock-Based Compensation," encourages, but does not require,
companies to record compensation cost for stock-based employee compensation
plans at fair value. The Company has chosen to continue to account for
stock-based compensation using the intrinsic value method prescribed in
Accounting Principles Board Opinion No. 25 "Accounting for Stock Issued to
Employees," and related interpretations. Accordingly, compensation cost for
stock options is measured as the excess, if any, of the quoted market price of
the Company's stock at the date of the grant over the amount an employee must
pay to acquire the stock.
Government Regulations: Substantially all of the Company's producing oil and gas
properties are subject to Federal, state and local provisions regulating the
discharge of materials into the environment. Management believes that its
current practices and procedures for the control and disposition of such wastes
comply with applicable federal and state requirements.
Restoration, Removal and Environmental Matters: The estimated costs of
restoration and removal of producing property well sites is generally less than
the estimated salvage value of the respective property and, accordingly, the
Company has not provided for a liability accrual. The estimated future costs for
known environmental remediation requirements are accrued when it is probable
that a liability has been incurred and the amount of remediation costs can be
reasonably estimated. The Company is not aware of any such remediation
requirements material to its operations.
Fair Value of Financial Instruments: The only financial instruments of the
Company are cash and equivalents, trade accounts receivable and payable, and
long-term debt. In all cases the carrying amount of financial instrument
approximates fair value.
Revenue Recognition: The Company recognizes oil and gas revenue from its
interest in producing wells as the oil and gas is sold from the wells.
<PAGE>
F-9
NOTE B - LONG TERM DEBT
Long-term debt consists of the following at August 31:
<TABLE>
<CAPTION>
1999 1998
---------- -----------
<S> <C> <C>
Note payable to Range Energy Finance Corporation, with interest at 18% and
payable from an overriding royalty interest (ORRI) granted to Range in
certain oil and gas properties currently producing, as well as those
completed and to be drilled on its Maverick County, Texas leasehold acreage
subsequent to June 1, 1998. The ORRI terminates
upon final payment of the debt. $ 2,279,669 $ 3,346,625
Note payable to Continental Resources, Inc. with interest at
9.50%, due in monthly installments of $30,000, with final
payment in 2001, and collateralized by certain oil and
gas properties. 562,396 847,053
Note payable to Union Pacific Resources, with interest at 8%, due in monthly
installments of $10,000, with final payment
in 2001, and collateralized by certain oil and gas properties. 212,957 318,672
Note payable to Caza Drilling with interest at 14%, due in monthly installments
of $35,000 with final payment
in December 1998, unsecured. - 165,503
Note payable to Quantum Geophysical, with interest at 12%, due in monthly
installments of $15,940, with final
payment in 1999, and unsecured. - 77,367
Installment notes with interest from 8.5% to 22.64%, due
in current monthly installments of $5,631. 39,787 68,707
------------ ------------
Total long-term debt 3,094,809 4,823,927
Less current portion (2,565,067) (1,846,383)
------------ ------------
Long-term portion of debt $ 529,742 $ 2,977,544
============ ============
</TABLE>
<PAGE>
F-10
NOTE B - LONG TERM DEBT - continued
The following is a schedule of maturities of long-term debt as of August 31,
1999:
Fiscal Year Ended
August 31 Amount
2000 $ 2,565,067
2001 529,742
-----------
$ 3,094,809
===========
NOTE C - STOCKHOLDERS' EQUITY
Preferred Stock: The Company has authorized 10,000,000 shares of preferred
stock, none of which has been issued at August 31, 1999. Terms of the stock have
not been established by the Board of Directors.
Stock Options: The Company grants options to its officers, directors, and key
employees under its 1995 Flexible Incentive Plan. In 1998, the Company also
issued options for the purchase of 600,000 shares of common stock under a
nonqualified plan. The Company has elected to follow Accounting Principles Board
Opinion No. 25, AAccounting for Stock Issued to Employees,@ (APB 25) and related
Interpretations in accounting for its employee stock options because, as
discussed below, the alternative fair value accounting provided for under FASB
Statement No. 123, AAccounting for Stock-Based Compensation,@ (FASB 123)
requires use of option valuation models that were not developed for use in
valuing employee stock options. Under APB 25, because the exercise price of the
Company=s stock options equals or exceeds the market price of the underlying
stock on the date of grant, no compensation expense is recognized.
The Company's 1995 Flexible Incentive Plan was authorized to grant options to
management, directors, and key personnel for up to 400,000 shares of the
Company's common stock. During 1999, the Plan was amended to increase the number
of options to allow for the purchase of up to 1,500,000 common stock shares. All
options granted have ten year terms and vest and become fully exercisable based
on the specific terms imposed at the date of grant.
Pro forma information regarding net income and earnings per share is required by
FASB 123, which also requires that the information be determined as if the
Company has accounted for its employee stock options granted subsequent to
August 31, 1995 under the fair value method of that Statement. The fair value
for these options was estimated at the date of grant using a Black-Scholes
option pricing model with the following weighted-average assumptions for 1999,
1998 and 1997, respectively: risk-free interest rates of 5.0%, 4.0%, and 6.25%;
dividend yields of -0-%; volatility factors of the expected market price of the
Company's common stock of .95, .69, and .33; and a weighted-average expected
life of the option of five years.
<PAGE>
F-11
NOTE C - STOCKHOLDERS' EQUITY - continued
The Black-Scholes option valuation model was developed for use in estimating the
fair value of trade options which have no vesting restrictions and are fully
transferable. In addition, option valuation models require the input of highly
subjective assumptions including the expected stock price volatility. Because
the Company's employee stock options have characteristics significantly
different from those of traded options, and because changes in the subjective
input assumptions can materially affect the fair value estimate, in management's
opinion, the existing models do not necessarily provide a reliable single
measure of the fair value of its employee stock options.
For purposes of pro forma disclosures, the estimated fair value of the options
is amortized to expense over the options' vesting period. The Company's pro
forma information is as follows for the years ended August 31:
<TABLE>
<CAPTION>
1999 1998 1997
---------- ---------- ----------
<S> <C> <C> <C>
Pro forma net income (loss) $ 695,970 $ (8,608,865) $ (3,539,881)
Pro forma net (income) loss per common share:
Basic $ 0.04 $ (0.56) $ (0.28)
Diluted 0.04 N/A N/A
</TABLE>
A summary of the status of the Company's stock option activity and related
information for the years ended August 31, is as follows:
<TABLE>
<CAPTION>
1999 1998
---------------------------- -----------------------------
Weighted-Average Weighted-Average
Shares Exercise Price Shares Exercise Price
---------- --------------- ---------- ----------------
<S> <C> <C> <C> <C>
Outstanding options at beginning of year 1,029,800 $ 2.95 439,800 $ 4.06
Granted 139,000 1.20 600,000 2.12
Exercised - - (10,000) 2.00
Forfeited (124,000) 2.70 - -
---------- ------ ---------- --------
Outstanding options at end of year 1,044,800 $ 2.72 1,029,800 $ 2.95
========== ====== ========== ======
Exercisable at end of year 334,800 $ 4.32 379,800 $ 3.78
========== ====== ========== ======
Weighted-average fair value of
options granted during the year $ 0.95 $ 0.48
====== ======
</TABLE>
<PAGE>
F-12
NOTE C - STOCKHOLDERS' EQUITY - continued
The following table summarizes information about the options outstanding at
August 31, 1999:
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
------------------------------------------------- -----------------------------
Weighted-Average
Number Remaining Weighted-Average Number Weighted-Average
Exercise Price Outstanding Contractual Life Exercise Price Exercisable Exercise Price
--------------- ----------- ---------------- ---------------- ----------- ---------------
<S> <C> <C> <C> <C> <C>
$ 0.98 25,000 10.0 years $ 25,000 $ 0.98
1.25 110,000 10.0 years 1.25 - 1.25
2.125 600,000 8.6 years 2.12 - 2.12
2.62 50,000 7.0 years 2.62 50,000 2.62
2.75 100,000 6.5 years 2.75 100,000 2.75
3.91 9,800 2.3 years 3.91 9,800 3.91
6.60 150,000 7.6 years 6.60 150,000 6.60
---------- ----------- ------ --------- ------
1,044,800 8.2 years $ 2.72 334,800 $ 3.78
========== =========== ====== ========= ======
</TABLE>
Stock Warrants: The following is a summary of warrants outstanding at
August 31, 1999:
<TABLE>
<CAPTION>
Weighted Weighted
Average Average
Number Range of Exercise Contractual
Purpose of Warrants Outstanding Prices Price Life
------------------- ----------- ------ ----- ----
<S> <C> <C> <C> <C>
Convertible notes and equity financing 457,500 $ 2.00 - $ 6.00 $ 3.31 3 years
Services rendered 50,000 $ 2.18 2.18 1 year
</TABLE>
<PAGE>
F-13
NOTE D - EARNINGS PER SHARE
The following is a reconciliation of the numerators and denominators of the
basic and diluted earnings per share (EPS) computation for the year ended August
31, 1999:
<TABLE>
<CAPTION>
Per Share
Income Shares Amount
------ ------ ------
<S> <C> <C> <C>
Basic EPS:
Net income $ 931,545 15,668,721 $ 0.06
Effect of dilutive options 9,846
--------- ----------- ------
Dilutive EPS $ 931,545 15,678,567 $ 0.06
========= =========== ======
</TABLE>
Options and warrants exercisable to purchase 813,300 shares of common stock were
outstanding at August 31, 1999 but were not included in the computation of
diluted EPS because the exercise price was greater than the average market price
of the common shares.
The 1998 and 1997 loss per share does not include the effect of options and
warrants as their impact would be antidilutive given the Company's loss position
in those years.
NOTE E - OPERATING LEASES
The Company leases its primary office space for $7,676 per month through
February 2000.
For the years ended August 31, 1999, 1998, and 1997, the Company incurred rent
expense of approximately $95,000, $94,000, and $92,000, respectively. Future
minimum rentals under all noncancellable real estate leases are as follows:
Fiscal Year Ended
August 30 Amount
------------ ---------
2000 $ 46,057
<PAGE>
F-14
NOTE F - FEDERAL INCOME TAXES
The Company has incurred losses for both financial statement and income tax
purposes in prior years. A valuation allowance equal to the net deferred tax
asset has been recorded due to the uncertainty of the realization of the asset.
The following items give rise to the deferred tax assets and liabilities at
August 31:
1999 1998
---------- ------------
Deferred tax assets:
Tax net operating loss carryforwards ........... $ 23,055,000 $ 24,575,000
Impairment of oil and gas and mineral properties 2,485,000 4,118,000
------------ -----------
Gross deferred tax assets ........................ 25,540,000 28,693,000
Statutory tax rate ............................... 34% 34%
------------ -----------
Net deferred tax assets .......................... 8,683,600 9,755,620
Less valuation allowance ......................... (8,683,600) (9,755,620)
------------ ----------
Deferred income tax asset recorded ............... $ -- $ --
============ ==========
The net operating loss carryforwards available at August 31, 1999, and the
related expiration dates are as follows:
Expires
August 31 Amount
--------- -------------
2000 $ 480,000
2001 1,200,000
2002 1,960,000
2003 708,000
2004 168,000
2005 to 2009 5,850,000
2010 to 2014 12,689,000
-------------
$ 23,055,000
=============
<PAGE>
F-15
NOTE G - RELATED PARTY TRANSACTIONS
During 1997, the Company purchased undeveloped oil and gas leases covering
approximately 222,000 net acres for exploration in the Williston Basin of North
and South Dakota and Montana. The acquisition was paid for with $22,000,000 cash
and the issuance of 1,000,000 shares of common stock valued at $5 per share. 67%
of the acquisition was from a company affiliated with two directors of the
Company. Concurrently with the acquisition, the Company sold to third parties a
42.5% net profits interest in wells to be drilled on the oil and gas leases for
$17,000,000 cash. The oil and gas leases acquired were reported at the
affiliates historical cost basis, which resulted in a reduction to the basis in
the properties of $9,773,154, and a charge for the same amount to additional
paid-in capital.
The Company's ExproFuels division was spun off from The Exploration Company on
September 3, 1996, with a 40% equity ownership being retained. During 1997, the
Company's net assets in ExproFuels, Inc. was reduced to $0 by recognition of a
$1,215,259 charge to operations. ExproFuels, Inc. has no remaining assets and no
current operations.
NOTE H - SEGMENT INFORMATION AND MAJOR CUSTOMERS
The Company operates only in the oil and gas industry. The Company's oil and gas
sales include amounts sold to major purchasers in the three years ended August
31, as follows:
Purchaser 1999 1998 1997
- --------- --------- --------- ---------
A . $ 3,800,000 $ -- $ --
B . 150,000 985,000 --
C . 480,000 810,000 732,000
D . 1,630,000 595,000 --
E . -- 122,000
NOTE I - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Year Ended August 31, 1999
The Company issued 325,000 shares of its common stock in exchange for oil and
gas properties (valued at the market price per share for unregistered stock).
Year Ended August 31, 1998
The Company converted $4,000,000 of convertible notes payable and $221,590
of accrued interest into 844,318 shares of its common stock.
The Company converted $1,684,000 of accounts payable into long-term debt.
Year Ended August 31, 1997
The Company issued 1,000,000 shares of its common stock in exchange for oil and
gas properties (valued at the market price per share for unregistered stock).
The Company converted $2,264,702 of debentures into 872,548 shares of its common
stock.
<PAGE>
F-16
NOTE J - OIL AND GAS PRODUCING ACTIVITIES AND PROPERTIES
Capitalized Costs and Costs Incurred Relating to Oil and Gas Activities
The Company's investment in oil and gas properties is as follows at August 31:
1999 1998
------------ ------------
Proved properties ............ $ 12,948,366 $ 9,098,623
Less reserve for impairment .. (2,323,584) (2,314,592)
Less accumulated depreciation,
depletion and amortization . (4,353,550) (2,073,491)
------------ ------------
Net proved properties ... 6,271,232 4,710,540
Unproved properties .......... 7,429,182 9,372,026
Less reserve for impairment .. (161,476) (1,580,000)
------------ ------------
Net unproved properties . 7,267,706 7,792,026
------------ ------------
Net capitalized cost ......... $ 13,538,938 $ 12,502,566
============ ============
Costs incurred, capitalized, and expensed in oil and gas producing activities
are as follows:
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Property acquisition costs, unproved $ 890,418 $ 1,232,000 $ 13,517,743
Property development and exploration costs 3,340,702 6,286,745 4,024,922
Depreciation, depletion and amortization 2,281,758 1,103,181 258,000
Depletion per equivalent MCF of production .69 .93 .75
</TABLE>
<PAGE>
F-17
NOTE J - OIL AND GAS PRODUCING ACTIVITIES AND PROPERTIES - continued
Estimated Quantities of Proved Oil and Gas Reserves (Unaudited)
The following estimates of proved developed and undeveloped reserve quantities
and related standardized measure of discounted net cash flow are estimates only,
and do not purport to reflect realizable values or fair market values of the
Company's reserves. The Company emphasizes that reserve estimates are inherently
imprecise and that estimates of new discoveries are more imprecise than those of
currently producing oil and gas properties. Accordingly, these estimates are
expected to change as future information becomes available.
Proved reserves are estimates of crude oil (including condensate and natural gas
liquids) and natural gas that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions. Proved developed reserves are
those expected to be recovered through existing well, equipment and operating
methods. The estimates have been prepared by an independent reservoir
engineering firm.
Oil Gas
(Barrels) (MCF)
Reserves at August 31, 1996 ...................... 20,570 1,893,490
Discoveries .................................. 289,770 1,147,345
Revisions of previous estimates .............. (41,554) (678,676)
Production ................................... (23,086) (206,059)
---------- ----------
Reserves at August 31, 1997 ...................... 245,700 2,156,100
Discoveries .................................. 70,700 4,541,500
Revisions of previous estimates .............. (136,662) 117,852
Production ................................... (79,138) (713,752)
---------- ----------
Reserves at August 31, 1998 ...................... 100,600 6,101,700
Discoveries .................................. 32,000 2,803,000
Purchases of minerals in place ............... 1,600 338,000
Revisions of previous estimates .............. 53,800 (166,700)
Production ................................... (82,000) (2,813,000)
---------- ----------
Reserves at August 31, 1999 ...................... 106,000 6,263,000
========== ==========
Substantially all of the Company's proved reserves are developed and are located
in the continental United States.
<PAGE>
F-18
NOTE J - OIL AND GAS PRODUCING ACTIVITIES AND PROPERTIES - continued
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves (Unaudited)
The "Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Gas Reserves" (Standardized Measure) presented below is computed in
accordance with SFAS No. 69. The Standardized Measure does not purport to
present the fair market value of a company's proved oil and gas reserves. This
would require consideration of expected future economic and operating
conditions, which are not taken into account in calculating the Standardized
Measure.
Under the Standardized Measure, future cash inflows were estimated by applying
year-end prices, adjusted for fixed determinable escalations, to the estimated
future production and development costs based on year-end costs to determine
pre-tax cash inflows. Future income taxes were computed by applying the
statutory tax rate to the excess of pre-tax cash inflows over the company's
basis in the associated proved oil and gas properties. Tax credits, permanent
differences and net operating loss carryforwards were also considered in the
future income tax calculations, thereby reducing the expected tax expense to
zero.
Set forth below is the Standardized Measure relating to proved oil and gas
reserves at August 31:
<TABLE>
<CAPTION>
1999 1998 1997
-------------- ------------ ------------
<S> <C> <C> <C>
Future cash inflows $ 17,370,000 $ 11,872,000 $ 8,814,000
Future production and development costs (2,484,000) (1,327,000) (1,919,000)
------------ ------------- -----------
Future net cash inflows before income tax 14,886,000 10,545,000 6,895,000
Future income tax expense - - -
------------ ------------- -----------
Future net cash flows 14,886,000 10,545,000 6,895,000
10% annual discount to reflect timing of net cash flows (2,441,000) (1,721,000) (2,163,000)
------------ ------------- -----------
Standardized Measure of discounted future
net cash flows relating to proved reserves $ 12,445,000 $ 8,824,000 $ 4,732,000
============ ============= ============
</TABLE>
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Reserves (Unaudited)
The following is an analysis of the changes in the Standardized Measure:
<TABLE>
<CAPTION>
1999 1998 1997
------------ ------------ -----------
<S> <C> <C> <C>
Standardized Measure, beginning of year $ 8,824,000 $ 4,732,000 $ 2,199,740
Discoveries 6,810,000 7,683,000 5,741,710
Purchases of minerals in place 350,000 - -
Sales and transfers, net of production costs (5,545,899) (2,007,383) (728,909)
Revisions in quantity and price estimates 2,888,899 (1,110,417) (2,260,567)
Accretion of discount (882,000) (473,200) (219,974)
------------ ----------- -----------
Standardized Measure, end of year $ 12,445,000 $ 8,824,000 $ 4,732,000
============ =========== ===========
</TABLE>
<PAGE>
F-19
NOTE K - YEAR 2000
Over the last three years the Company has replaced or upgraded most of the core
management information systems used in the Company's business. The Company has
conducted a review of these systems to verify their compliance with Year 2000
date codes. In addition, the Company has conducted an inventory, review and
assessment of its desktop computers, networks and servers, software applications
and packages, and products and services provided by third parties for internal
operations to determine whether or not they support Year 2000 date codes. The
Company believes it has successfully completed required modifications to all
mission critical applications included in its internal systems. In addition, the
Company has contacted its major gas purchasers, gas pipeline carriers, stock
transfer agent and banking institutions and received written assurances and/or
viewed assurances on their websites that they have no material Year 2000
problems. The Company does not believe the Year 2000 issue will materially
affect its ability to pay its vendors and suppliers, track its assets in the
custody of financial institutions or otherwise prevent it from conducting its
business on an ongoing basis.
<PAGE>
F-20
THE EXPLORATION COMPANY
Schedule II - Valuation and Qualifying Reserves
For the Three Years Ended August 31, 1999
<TABLE>
<CAPTION>
Balance . Charges to Balance
Beginning Costs and End of
of Period Expense Write-offs Period
--------- ------- ---------- ------
<S> <C> <C> <C> <C>
Year ended August 31, 1999
Allowance for doubtful accounts - trade accounts ........... $ 27,000 $ -- $ -- $ 27,000
Impairment of oil and gas properties ....................... 3,894,739 147,369 (1,718,524) 2,323,584
Year ended August 31, 1998
Allowance for doubtful accounts - trade accounts .......... $ -- $ 27,000 $ -- $ 27,000
Impairment of loan to ExproFuels, Inc. ..................... 845,487 -- (845,487) --
Impairment of oil and gas properties ....................... 119,397 3,775,342 -- 3,894,739
Year ended August 31, 1997
Allowance for doubtful accounts - trade accounts .......... $ 9,973 $ -- $ (9,973) $ --
Impairment of loan to ExproFuels, Inc. ..................... -- 845,487 -- 845,487
Impairment of oil and gas properties ...................... 90,997 28,400 -- 119,397
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
EXPLORATION COMPANY AUDITED FINANCIAL STATEMENTS FOR THE YEAR ENDED AUGUST 31,
1999 AND IS QUALIFED IN ITS ENTIRETY BY REFERENCE TO SUCH.
</LEGEND>
<CIK> 0000313395
<NAME> THE EXPLORATION COMPANY
<MULTIPLIER> 1
<CURRENCY> US DOLLAR
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> AUG-31-1999
<PERIOD-START> SEP-01-1998
<PERIOD-END> AUG-31-1999
<EXCHANGE-RATE> 1
<CASH> 968516
<SECURITIES> 0
<RECEIVABLES> 2253349
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 3478199
<PP&E> 20484397
<DEPRECIATION> 6856345
<TOTAL-ASSETS> 17553815
<CURRENT-LIABILITIES> 5003793
<BONDS> 529742
0
0
<COMMON> 159385
<OTHER-SE> 11860895
<TOTAL-LIABILITY-AND-EQUITY> 17553815
<SALES> 7497375
<TOTAL-REVENUES> 7497375
<CGS> 4556988
<TOTAL-COSTS> 5999326
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 640396
<INCOME-PRETAX> 931545
<INCOME-TAX> 0
<INCOME-CONTINUING> 931545
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 931545
<EPS-BASIC> .06
<EPS-DILUTED> .06
</TABLE>
