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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, 1997
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 0-9120
THE EXPLORATION COMPANY
(Exact name of Registrant as specified in its charter)
COLORADO 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. [X]
The aggregate market value of the voting stock (which consists solely of
shares of Common Stock) held by non-affiliates of the registrant is $33,926,841
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 11, 1997.
The number of shares outstanding of the Registrant's Common Stock as of
November 14, 1997, was 14,759,198 of which 12,565,497 shares were held by
non-affiliates.
Documents Incorporated by Reference: None
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INDEX AND
CROSS REFERENCE SHEET
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PART I
Page
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Item 1. Business..................................................................................... 3
Item 2. Properties................................................................................... 10
Item 3. Legal Proceedings............................................................................ 14
Item 4. Submission of Matters to a Vote of Security Holders.......................................... 15
PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters.................................................................. 16
Item 6. Selected Financial Data...................................................................... 16
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations........................................................................ 17
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.......................................................................... 27
Signatures................................................................................................ 28
Audited Financial Statements of The Exploration Company.................................................. F-0
Audited Financial Statements of ExproFuels, Inc. ......................................................... S-0
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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. The Company became publicly held
through an offering of its common stock in November, 1979. During 1984 the
corporate office of the Company relocated to San Antonio, Texas.
Throughout its history, the Company's primary focus has been oil and gas and
mineral exploration and production. Its business strategy has been to acquire
undeveloped mineral interests, develop drilling prospects internally and to
selectively participate with industry partners in prospects generated by other
parties in their exploration activities, and, from time to time, to offer
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. The Company also may use its
equity securities as all or part of the consideration for the operating
investments it may make.
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 acquires through its leasing
activities. In order to provide the Company downstream opportunities,
management entered the alternative fuels vehicle (AFV) conversion business
through the creation of its own alternative fuels division, ExproFuels, in late
1992. The alternative fuels division's focus included the conversion of
internal combustion engines to run alternately on Liquefied Petroleum Gas
(LPG), Compressed Natural Gas (CNG) or Liquefied Natural Gas (LNG), and the
design, installation and operation of alternate fuel refueling stations. The
ExproFuels division initiated ongoing operations in Texas and Arizona, while
actively pursuing international opportunities in Europe, Asia and Latin
America. From 1994 through 1996, gross revenues from the ExproFuels division
surpassed gross revenues from oil and gas operations, although profitable
operating levels were not attained.
In late 1996, management determined that it was in the Company's best interest
to refocus its resources in its core oil and gas business. Accordingly, the
ExproFuels division was incorporated in August, 1996, and spun-off in early
September, 1996, with the Company retaining approximately a 40% interest. The
Common Stock of the new corporation, ExproFuels, Inc., was registered with the
Securities and Exchange Commission (SEC) by the filing of an Information
Statement on February 28, 1997. Following amendment, the Information Statement
was distributed to the shareholders of TXCO, along with the newly issued shares
of Common Stock in ExproFuels, Inc. on August 29, 1997, effectively completing
the spin-off.
The distribution of ExproFuels, Inc. to the TXCO shareholders was designed to
separate two types of business with distinct financial, investment and
operating characteristics so that each could adopt strategies and pursue
objectives appropriate to its specific needs. The distribution has enabled
management to concentrate its attention and financial resources on its core
business and has permitted investors to make more focused investment decisions
based on the attributes of the oil and gas exploration, development and
production aspects of the Company. The significant inflows to The Exploration
Company of new equity and debt capital realized during 1997 confirmed
Management's expectations of the benefits of the distribution for the
shareholders of the Company. During fiscal 1997, the Company concentrated on
oil and gas exploration and development, and in February 1997, completed a
significant acquisition of undeveloped acreage in the Williston Basin area of
North Dakota, South Dakota and Montana.
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PRINCIPAL AREAS OF ACTIVITY
OIL AND GAS OPERATIONS
The Company has been actively evaluating mineral interests in major oil and gas
producing basins in South Texas, North Dakota, South Dakota and Montana,
acquiring leasehold acreage for its ongoing exploration programs and
participating in the drilling of oil and gas wells.
Maverick Basin
Glen Rose/Rodessa Formation: The Company has owned at least a fifty percent
leasehold interest in approximately 50,000 contiguous acres in Maverick County,
Texas since 1989. The property is on the Chittim Anticline, a large regional
structure, under which hydrocarbons have been found in as many as seven
separate horizons. 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 of the field was halted because of the inability of operators to
accurately predict the location of these porosity-bearing reefs. The Company
applied a different processing method to the seismic available in the area and
discovered what appeared to be a method of determining the location of these
porosity intervals. Further investigation revealed that every well drilled in
the vicinity of existing seismic lines with a good porosity zone had a certain
signature pattern on the seismic processing while every well which lacked the
porosity zone did not have this pattern.
Through 1993, the Company participated in the drilling of five wells to test
theories of being able to locate the patch reef using 2-D seismic. In all cases
the Company was successful in predicting the presence of, or absence of,
porosity-bearing patch reefs using the new seismic interpretation methods.
Although only one of the wells, the Paloma #1-84, was a successful gas
producer, the Company used the information gained from each well to refine its
interpretation and model of the patch reefs' depositional environment.
In 1993 and again in 1997, the Company ran two contiguous 3-D seismic surveys
over a total of 43 square miles (approximately 26,000 acres) of the Company's
lease position. The new seismic grid has now been processed and reviewed by the
Company. Seismic analysis of the combined surveys has identified numerous patch
reefs on the 26,000 acres that represent only one-half of the potentially
productive 50,000 acres.
Using this newly acquired 3-D seismic information, the Company has drilled
several Glen Rose reef wells. The Paloma #1-107 which was drilled in the third
quarter of 1994, had nearly 50 feet of gas-bearing porosity, tested at rates in
excess of two million cubic feet per day and had an absolute open flow
potential of 44,000 mcfd (thousands of cubic feet per day). It was followed by
two additional wells, the Paloma #1-133 and Paloma #1-89, in 1995 that had
excellent reef intervals but contained water and not gas. After modifying its
interpretation of the seismic data, the Company drilled the Paloma #2-112 in
early 1996 and once again encountered a gas-bearing reef. This well was
produced at rates of 2,500 mcfd and had a calculated absolute open flow
potential of 20,000 mcfd. This well was again followed by another well that
encountered excellent reef but contained water and was plugged and abandoned.
After further modification of the geophysical interpretation in 1997, the
Company drilled the Paloma #2-108, the Paloma #1-106, the Paloma #2-106 and the
Paloma #2-83. Three of the four wells were excellent Glen Rose reef producers.
While the Company's engineers and geologists have been 100% successful in
locating Glen Rose patch reefs, Management continues to review technical data
gained with the drilling of each well to improve its ability to distinguish
between water-filled reefs versus gas-filled reefs. Although the Company's
success ratio has improved from its early start of 33% successful wells from
its first six Glen Rose wells to its current 75% successful ratio on its last
four wells, Management hopes that it will be able to improve the ratio even
more. The Company continues to believe it has significant development
possibilities on its 50,000 acres because it has successfully demonstrated that
the new 3-D seismic modeling can accurately predict the presence of porosity
and gas bearing zones within the Lower Glen Rose formation. Based upon the
extensive seismic data gathered to date, the Company has over twenty additional
porosity-bearing patch reefs scattered across its extensive acreage position.
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In addition to locating patch reefs, investment in the 3-D seismic data
acquisition has proved to be valuable to the Company in locating faults and
fractures associated with production from the six other potentially productive
zones under the Maverick County leases. From its review of the data from other
strata, the Company has identified numerous drill sites targeting various
productive horizons. The Austin Chalk, Georgetown and Pearsall intervals all
produce on the lease from faults and fractures which have been further defined
using the comprehensive seismic data.
Georgetown Formation: Three porosity intervals of approximately 15 feet each
are situated approximately 100 feet below the top of the Georgetown and contain
hydrocarbons at depths of only 2500 to 3500 feet. The zones have been
encountered in each of the seventeen wells that the Company has drilled on the
block. The zones appears to contain gas across the entire 50,000 acres but have
extremely low permeability. The Company has made completion attempts in five
wells to test the Georgetown formation since 1995. Two wells were drilled
vertically and acidized with relatively small volumes of hydrochloric acid. A
small fracturing treatment was attempted on another vertical producer. Two
horizontal wells were drilled with laterals of 1500 feet and 3000 feet in the
uppermost porosity interval. All five wells had initial production increases of
natural gas that did not continue at the initial high rates after several
months production. The Company is continuing with its efforts to stimulate the
low permeability of the Georgetown to obtain a sustainable increase in the
productivity of the zone. Shortly after the year end, Management has scheduled
a massive fracturing treatment on one of the wells it has already drilled and
is hopeful that this method will be successful in improving the Georgetown's
deliverability.
Jurassic Formations: The Company's geophysicists believe that the 43 square
miles of 3-D seismic that has been shot across the 50,000 acres in Maverick
County indicates a potential for development of the deep Jurassic interval.
Only three wells have attempted to discover Jurassic reserves in the area and
they were drilled by Shell, Exxon and Conoco twenty to thirty years ago. Upon
acquiring magnetic surveys that were flown across the region approximately ten
years ago, the Company discovered that the Shell and Exxon wells were not
drilled within what is believed to be the limits of the Maverick Basin. The
Company's 3-D seismic shows that although the Conoco well was drilled within
the basin, it was not drilled deep enough to reach the Jurassic interval. The
Jurassic zones are prolific producers in all known Jurassic basins along the
Gulf Coast except for the Maverick Basin which has not had a well drilled of
sufficient depth to test the Jurassic interval. The Company is searching for an
industry partner who will drill an exploratory well on its block to test the
Jurassic formations.
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 acquired some of the leases with its
common stock, but the majority interest was acquired by selling a Swiss
institutional investor a 50% net profits interest in the entire 320,000 acres
for cash which was used to purchase the leases in February 1997. Subsequent to
acquiring the leases, the Company has participated in the drilling of several
wells to develop oil and gas reserves in the Red River and Lodgepole
formations.
Red River Formation: The Red River "B" is a fractured carbonate reservoir with
porosity development giving it the storage capacity to hold large volumes of
oil. The reservoir lends itself to horizontal drilling since it is fractured
and is trapped stratigraphically. Over 500 wells have been permitted to be
drilled horizontally in the area during the last three years. Published
information reveals that to date over 220 of these horizontal wells have been
drilled in Bowman and Slope Counties of North Dakota, Harding County of South
Dakota and Fallon County of Montana where the Company's lease position is
concentrated. Many producing wells have initial production rates varying from
100 to over 500 barrels of oil per day. Available data indicates that the wells
can have reserves of 500,000 barrels to 600,000 barrels each. The Red River "C"
and "D" zones are approximately 100 to 200 feet below the Red River "B"
interval and are known to be prolific producers in some wells. A few wells in
the area have produced between 750,000 and 1,000,000 barrels from vertical
wells in the "C" and "D". However, there can be no assurance that wells drilled
by the Company or on the Company's leases will have similar results.
The Company has entered into several joint venture agreements with industry
partners to help develop its acres quickly. The Company entered into a Joint
Operating Agreement with Continental Resources, Inc. ("CRI") and Union Pacific
Resources Company ("UPRC") wherein the Company has contributed approximately
7,800 acres,
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CRI contributed 10,000 acres and UPRC contributed 7,800 acres in
an area covering portions of North Dakota and South Dakota. Under the
agreement, CRI will operate, while the Company will participate with a 30%
interest in wells to be drilled in the combined 25,600 acres area. The Company
also entered into another Joint Operating Agreement with UPRC covering
additional leases on the North Dakota and South Dakota border. Under the
agreement, UPRC contributed 22,000 acres and the Company contributed 22,000
acres giving the Company a 50% interest in any wells drilled on the 44,000
acres block. UPRC has been designated as operator under this agreement.
Additionally, the Company entered into a Joint Operating Agreement with CRI
covering leases in Harding County, South Dakota. Under the agreement, CRI
contributed 4,350 acres and the Company contributed 4,350 acres, giving the
Company a 50% interest in any wells drilled on the entire block. CRI has been
designated as operator under this agreement. The Company finalized yet another
Joint Operating Agreement with Eagle Oil & Gas Company ("Eagle") wherein the
Company has contributed approximately 27,000 acres and Eagle has contributed
27,000 acres in Slope and Golden Valley Counties of North Dakota. The Company
has a 50% interest in the entire area and has been designated operator for
approximately one-half of the block while Eagle will operate wells drilled in
the remaining half.
The Company, through its joint venture partners, began drilling horizontally in
the Red River "B" interval in January of 1997. Its partners, CRI and UPRC,
chose to drill without the benefit of 2-D or 3-D seismic because initial wells
drilled on the Cedar Creek Anticline were successfully drilled horizontally
without seismic. The Company, on the other hand, desired to maximize its
drilling dollar by producing both "C" and "D" vertical wells in the same
wellbore that would produce from a lateral in the "B". CRI, which has drilled
or participated in over 120 horizontal wells in the area, has drilled three
horizontal wells in the "B" interval with the Company as a partner without the
benefit of seismic data. One of the three wells has not been completed but had
good shows of oil and gas while drilling. Although one of the other two wells
had an initial production rate in excess of 100 barrels of oil per day (bopd),
it also produced over 300 barrels of water per day (bwpd). The other well
produced only a minimal amount of oil and over 11,000 barrels of water. UPRC,
which is generally recognized as the world's leader in horizontal drilling
activity, drilled another horizontal well with the Company in the "B" interval.
Once again, this well did not have the benefit of seismic and the results were
comparable to those of CRI's wells. UPRC had trouble staying in the "B"
interval and drilled five laterals before finishing the well. It is the
Company's opinion that the well produces over 350 bwpd because so much of the
well was drilled out of the oil-bearing interval in the "B". The Company
believes that both the CRI well and the UPRC well can be re-entered to
establish commercial production by either redrilling the "B" interval using
seismic or cementing casing to isolate the water intervals from the oil
producing portions of the laterals. However, Management elected to impair the
entire cost of the James #1-9 at the end of the year because seismic that would
conclusively verify that a higher ridge can be reached from the existing
wellbore had not been reviewed.
The Company has now supervised the drilling of three wells in Bowman County,
North Dakota. The Company has used 2-D and 3-D seismic exclusively to locate
its wells on structural features that might have the potential to produce
vertically from the "C" and "D" intervals as well as horizontally in the "B".
The Company's first well had an initial production rate of 260 bopd from the
"D" interval and the second had an initial rate of 125 bopd and 125 bwpd from
the "C". Both of these wells will eventually be drilled horizontally in the "B"
thereby maximizing the productivity of each well. The third well is currently
being completed as a horizontal "B" well since neither the "C" nor the "D"
appeared to be productive on the structure.
Initially, the Company's geologic model of the area indicated that the "B"
would produce horizontally wherever it was drilled, and the "C" and "D" would
produce vertically on structures. After analyzing the drilling results of the
Company and its partners along with the available 2-D and 3-D seismic,
Management has modified its Red River geologic model. The Company now believes
that all three intervals, "B", "C", and "D", should be drilled on structures.
Basically, the oil is accumulating on the high points and water in the lower
portions. Wells that are drilled irrespective of structure have a much higher
incidence of high water production. The Company plans to continue drilling on
the structures to encounter "C" and "D" production but will also drill shorter
horizontal laterals in accordance with seismic interpretation of local
structures in the "B" intervals to stay on top of the structural features. In
some cases the Company plans to drill two 2,000 feet laterals in the "B" on top
of ridges or structures rather than one long 4,000 feet lateral that might
encounter the "valley" between structures.
The Company currently has over 1100 miles of 2-D seismic and 32 square miles of
3-D seismic in its library. Additionally, the Company is currently shooting
another 20 square miles of 3-D seismic. The Company still believes that it has
numerous locations on its lease block but intends to
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develop these leases using seismic data in conjunction with horizontal drilling.
Lodgepole Formation: Wells capable of producing rates in excess of 5,000 bopd
have been drilled by several operators in the Lodgepole formation in the
Williston Basin. Ongoing area discoveries by major and independent oil
exploration companies have supported testimony before the North Dakota
Industrial Commission of flow rates in excess of 8,000 bopd from the reef-like
mounds near Dickinson, North Dakota. The Company has participated as a result
of its leasehold position in the drilling of four producing Lodgepole wells to
date. The Company has minor interests of 0.1% to 3.0% in these wells in the
Stadium Field south of Dickinson. Reservoir estimates of 14 - 20,000,000
barrels of recoverable oil have been reported to the North Dakota Industrial
Commission for Stadium Field. Production rates for each well have been held at
a maximum of 500 bopd until unitization of the entire field has taken place so
that production from it can be maximized through pressure maintenance of the
reservoir. Additional wells have been permitted farther from the original
discoveries and closer to the Company's larger lease position, but the wells
drilled outside the Dickinson area have encountered poor results. Although the
Company's 2-D seismic indicates potentially productive mounds may be present in
many areas where the Company holds oil and gas leases, the Company believes
that the risks in drilling these wells are still high as geophysicists have not
yet perfected their interpretations sufficiently to adequately predict where
productive reefs are located. Significantly more geological and geophysical
analysis needs to be applied to the current information before the Company will
feel comfortable in drilling potential locations. Management is reducing its
risk in searching for productive reefs by farming-out the initial wells on
prospects to other operators and keeping smaller interests in the exploratory
well. The Company would then be able to increase its interest in the subsequent
wells in a discovered field. Management continues to believe that the Lodgepole
production can have a significant and positive impact on the Company's value.
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 less than 30 days notice. 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 1997, one purchaser of the Company's oil and gas production accounted
for 75% of total oil and gas sales. In the event this major customer 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.
EMPLOYEES
As of August 31, 1997, the Company employed 11 full-time employees including
management. The Company believes its relations with its employees are good.
None of the Company's employees is covered by union contracts.
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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
in the past and, it appears, will continue to periodically propose and consider
proposals for establishment of controls on the development and use of
alternative fuels, energy conservation, environmental protection, taxation upon
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
recently 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 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, only a small portion of the Company's
production has been curtailed due to reduced allowables. The production from
the Stadium Field in Stark County, North Dakota has been reduced to 500 bopd
per well until unitization of the entire field has been completed which is
anticipated in the second quarter of 1997. The Company knows of no newly
proposed regulations, which will significantly curtail its production. The
Company is continuing to expand its operations to the states of North Dakota,
South Dakota and Montana.
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
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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 is 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 carryforward 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 at August 31, 1997. The average
sales prices as of such dates used for purposes of said estimates were $17.74
per barrel of crude oil and $2.25 per mcf of natural gas. 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.
Title to Properties
As is customary in the crude oil and natural gas industry, the Company performs
a title investigation before acquiring undeveloped properties, which generally
consists of obtaining a title report from counsel and due diligence reviews by
independent or the Company's landmen of the remaining properties. The Company
believes that it has satisfactory title to such properties in accordance with
standards generally accepted in the crude oil and natural 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
9
<PAGE> 10
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
The Company has experienced recurring losses. For the years ended August 31,
1997, 1996 and 1995, the Company recorded net losses of $3.3 million, $1.9
million and $2.2 million, respectively. 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 which
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 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 $7,548 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.
Proved Reserves, Future Net Revenue and
Present Value of Estimated Future Net Revenues
The following unaudited information as of August 31, 1997, 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. Estimates of proved developed oil and gas reserves
attributable to the Company's interest at August 31, 1997, 1996 and 1995 are
set forth in Notes to the audited financial statements included in this Annual
Report on Form 10-K.
10
<PAGE> 11
Present Value of Estimated Future Net Revenues from proved developed oil and
gas reserves as of August 31, 1997, are as follows:
<TABLE>
<CAPTION>
Present Value of
Years Ending Estimated Future
August 31 Net Revenues
------------ ----------------
<S> <C> <C>
1998 $ 1,258,000
1999 918,000
2000 660,000
2001 483,000
2002 357,000
Thereafter 1,056,000
----------------
TOTAL $ 4,732,000
================
</TABLE>
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 (2).
<TABLE>
<CAPTION>
Years Ended August 31
1997 1996 1995
---- ----- ----
<S> <C> <C> <C>
Oil:
Production in Barrels 23,086 2,862 2,598
Average sales price per Barrel $18.64 $18.03 $16.89
Gas:
Production in MCF 206,059 215,274 177,238
Average Sales Price per MCF $2.65 $1.79 $ 1.62
Average cost of production per equivalent Barrel (1) $4.31 $2.68 $ 1.94
</TABLE>
(1) Oil and gas were combined by converting gas to barrel equivalent
on the basis of 6 MCF of gas = 1 barrel of oil. Production
costs include direct lease operations and production taxes.
(2) With respect to newly drilled wells, there can be no assurance
that current production levels can be sustained. Depending on
reservoir characteristics, such levels of production could decline
significantly.
11
<PAGE> 12
'
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, 1997:
<TABLE>
<CAPTION>
Productive Wells
-------------------------------------------------------------------------
Developed Acreage Oil Gas Total
----------------- ------------------ ----------------- ------------------
Gross Net Gross Net Gross Net Gross Net
----- --- ----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C> <C>
6,040 2,479 10 3.77 13 5.55 23 9.33
</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, 1997, the Company owned, by lease or in fee, the following
undeveloped acres, all of which are located in the Continental United States,
as follows:
<TABLE>
<CAPTION>
Est. FY 1998
United States Gross Acres Net Acres Delay Rentals
------------- ----------- --------- -------------
<S> <C> <C> <C>
Texas 56,401 43,668 $ 121,204
North Dakota 393,788 255,570 126,561
South Dakota 74,637 62,673 11,000
Montana 32,668 22,880 440
----------- --------- -------------
Totals 557,494 384,791 $ 259,205
=========== ========= =============
</TABLE>
A Texas lease containing approximately 33,000 acres also has a requirement to
drill a well every 90 days to keep the lease in effect since the primary term
of the lease has expired. The Company is presently drilling under the terms of
the lease and expects to keep the lease in force by continuous development
during the year.
Drilling Activity
During 1997, the Company's drilling activity increased significantly from its
usual 4-5 wells per year to 15 wells. The Company participated in the drilling
of eleven wells in the Williston Basin and four wells in the Maverick Basin.
With respect to newly drilled wells, there can be no assurance that current
production levels can be sustained. Depending on reservoir characteristics,
such levels of production could decline significantly.
Maverick Basin
During the year, the Company drilled three Glen Rose reef wells in Maverick
County, Texas. The Paloma #2-108 had over 130 feet of porosity-bearing reef but
only the top ten feet was gas-bearing. The well was completed as a Glen Rose
reef producer of 200 mcfd (thousands of cubic feet of gas per day). The Paloma
#1-106 was drilled and completed in the Glen Rose reef and tested at 1,645 mcfd
and 3.3 bcpd (barrels of condensate per day). It was followed by the Paloma
#2-106 which had only six feet of low permeability reef present. It produced
less than 50 mcfd from the Glen Rose. Management anticipates recompleting the
#2-106 into the Edwards section shortly during fiscal 1998. The Company also
completed a new 3-D seismic program covering nearly 13,000 additional acres of
the Paloma Ranch during the fourth quarter. Interpretation of the processed
data indicates numerous patch reefs in
12
<PAGE> 13
the Glen Rose interval as well as the anticipated fracturing and faulting in
the Georgetown interval. The Paloma #2-83 was drilled using this data after the
fiscal year end and appears that it will be an excellent well in the Glen Rose
interval.
During the fourth quarter, the Company also drilled a horizontal Georgetown
well, the Kincaid #1-199, on the Kincaid Ranch in Maverick County, Texas. The
Kincaid Ranch lease is comprised of 17,000 acres contiguous with the 33,000
acre Paloma Ranch lease. The Georgetown is a carbonate formation with low
permeability that appears to contain hydrocarbons under the entire 50,000 acre
block at depths of only 2,500 to 3,500 feet. The well was successfully drilled
3,350 feet horizontally in the upper porosity lobe of the Georgetown interval
and was tested at rates of up to 400 mcfd. Unfortunately, sustained
deliverability from the well has only been 50 mcfd. Management is continuing to
pursue economic methods to produce the potential reserves under its leases in
the Georgetown formation and is planning a massive fracturing treatment in the
formation during 1998.
The Company is the general partner in a limited partnership that began
construction of 6.5 miles of six inch pipeline to gather gas on the Maverick
Basin properties during the last quarter of 1997 and the first quarter of 1998.
Due to previous pipeline constraints, the Company and its partners' production
had been limited to only 2,400 mcfd. After completing new pipeline subsequent
to the end of the year, the daily production from the lease has increased by
over fifty percent to 3,800 mcfd. The Company expects these rates to increase
even more with the drilling of additional wells using the new 3-D seismic.
Williston Basin
During the current year, the Company completed its acquisition of 320,000 net
acres in the Williston Basin and participated in drilling eleven wells in the
basin. In order to expedite the development of the Company's large acreage
position in the Williston Basin, the Company entered into several Joint
Operating Agreements with other operators. One such agreement is with
Continental Resources, Inc. ("CRI") and Union Pacific Resources Company
("UPRC") wherein the Company has contributed approximately 7,800 acres, CRI has
contributed 10,000 acres and UPRC has contributed 7,800 acres in an area
covering portions of North Dakota and South Dakota. Under the agreement, CRI
will operate wells to be drilled, while the Company will participate with a 30%
interest in the wells in the combined 25,600 acre area. The Company also
entered into an agreement with UPRC alone covering additional leases on the
North Dakota and South Dakota borders. Under this agreement, UPRC contributed
22,000 acres and the Company contributed 22,000 acres giving the Company a 50%
interest in any wells drilled on the entire block. UPRC has been designated as
operator under the agreement. The Company entered into an additional agreement
with CRI covering another group of leases in Harding County, South Dakota.
Under the agreement, CRI contributed 4,350 acres and the Company contributed
4,350 acres giving the Company a 50% interest in any wells drilled on the
entire block. CRI has been designated as operator under the agreement. Yet
another agreement has been reached with Eagle Oil & Gas Company ("Eagle")
wherein the Company has contributed approximately 27,000 acres and Eagle has
contributed 27,000 acres in Slope and Golden Valley Counties of North Dakota.
The Company has a 50% interest in the entire area and has been designated
operator for approximately one-half of the block while Eagle will operate wells
drilled in the remaining half.
The Company owns a small interest in several successful Lodgepole wells that
were drilled during fiscal 1997 in the Stadium Field in Stark County, North
Dakota. The Company has a 1.5% interest in TransTexas Gas Corporation's
Dinsdale #2-4, which tested at 5,500 bopd (barrels oil per day) and a 3.0%
interest in the Dinsdale #1-3, which tested at 5,100 bopd. The Company also has
a 0.40% interest in Duncan Oil Company's Heart River #1-9, another Lodgepole
well which tested at 1,000 bopd as well as a 0.20% interest in Duncan Oil
Company's Dinsdale #1-10 that was tested at 450 bopd. During the year, the
operators of the various wells began attempts to unitize the Stadium Field to
begin pressure maintenance operations. If successful, the Company will gain an
interest in all production from the field. While attempts to unitize the field
are underway, the North Dakota Industrial Commission has voted to regulate
field production limits at 500 bopd per well. Once unitization is complete,
which is anticipated to be during the first quarter of 1998, the production
limits will be removed, allowing overall production from the field to increase
significantly.
During the year, the Company also participated in the drilling of two
unsuccessful Lodgepole reef wells in Stark County, North Dakota. The Company
had a 0.1% interest in Conoco, Inc.'s Kostelecky #33-2 which was plugged and
abandoned after drilling through the Lodgepole interval. The Company also had a
0.05% interest in Duncan Oil
13
<PAGE> 14
Company's Heart River #2-9 that was also plugged and abandoned after drilling
the Lodgepole interval. Because the Lodgepole reefs are difficult to identify
using 2-D and 3-D seismic, Management has elected to limit its exposure in the
wells by farming-out some of its leases to other operators who will drill the
first wells on a prospect and carry the Company for small back-in interest. The
Company has retained the right to participate in subsequent wells at an
increased interest if the initial well is successful.
The Company has participated in the drilling of five Red River wells since the
Williston Basin leases were acquired at the end of January 1997. The Company
has operated two Red River wells that were drilled using 2-D and 3-D seismic to
locate the wells on structures that might contain production in the Red River
"C" and "D" intervals as well as the Red River "B". The first operated well,
the Sherry #1-16 in Bowman County, North Dakota, was completed in the Red River
"D" interval in the vertical wellbore. The initial production rate was 263 bopd
with no water production. During the year, water production has increased to
approximately 75 bwpd (barrels water per day) and the oil production has
decreased slowly to approximately 100 bopd. The Company's engineers plan to
drill the Red River "B" zone horizontally at a later date after the production
from the Red River "D" zone depletes. The second operated well, the Martha
#1-36 in Bowman County, North Dakota, was also positioned in such a manner to
allow one well to test the Red River "C" and "D" reservoirs in the vertical
section prior to drilling horizontally in the Red River "B". This time the well
was completed as a vertical producer in the Red River "C" initially; however,
the Company intends to drill it horizontally in the Red River "B" and "C" at a
later date. The well initially produced at rates of approximately 125 bopd and
125 bwpd. Its production has continued to decrease. The well has been scheduled
by the Company to be re-entered and drilled horizontally during 1998.
During the year, the Company also participated in the drilling of three
horizontal Red River wells in Bowman County, North Dakota, with CRI and UPRC
wherein no seismic data was utilized to locate the wells. CRI drilled the
Barbara #1-15 and the James #1-9. Although both wells were drilled horizontally
approximately 5,000 feet in the Red River "B" interval, neither was located
using seismic to assure that the "B" interval would be encountered in a
structurally high position. The Barbara #1-15 initially produced at rates of
approximately 100 bopd and 300 bwpd that has slowly decreased during the year
to 65 bopd and 325 bwpd, while the James #1-9 produced at rates of
approximately 30 bopd and 400 bwpd. UPRC also drilled the Abrahamson #41-33H
without the benefit of seismic; consequently, UPRC had difficulties staying in
the Red River "B" oil zone. Four laterals were drilled below the oil zone while
the fifth lateral appeared to be in zone for the final 2,500 feet.
Unfortunately, the well has produced over 11,000 barrels of water with no oil
production. The Company believes that isolation of the four out-of-zone
laterals and the first 2,000 feet of the fifth lateral that are probably
producing water with a cemented liner may allow the wellbore to produce the oil
encountered in the final 2,500 feet of the well.
Based upon its drilling results with CRI and UPRC, the Company has concluded
that all its Red River "B" wells should be drilled utilizing 2-D or 3-D seismic
to insure that the wells are drilled on structures to minimize water production
and maximize oil production. Subsequent to the end of the year, the Company
participated in one final well with CRI without seismic but is waiting on
production results. Because management believes strongly that all future
horizontal Red River wells should be located utilizing seismic data, the
Company acquired over 1100 miles of 2-D seismic and over 32 square miles of 3-D
seismic during 1997. Additionally, the Company began the acquisition of another
20 square miles subsequent to the end of the 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 except for the following:
Disputes between the Company's former subsidiary, ExproFuels and CNG
International (CNG), American Engineering Inc. (AEI) and American Technical
Institute (ATI) have resulted in the filing of two lawsuits in July, 1997, one
by
14
<PAGE> 15
ExproFuels in federal court in San Antonio, Texas, and the other by ATI and
AEI in state court in Memphis, Tennessee. In its lawsuit, ExproFuels claims
breach of contract and is seeking among other things, (1) damages in the amount
of ExproFuels' investment in CNG (approximately $381,000), ExproFuels'
unreimbursed expenses advanced to CNG (approximately $239,000) and ExproFuels'
lost profits or (2) recision of ExproFuels' arrangement with CNG and a refund
of all moneys invested in or advanced to CNG. ATI and AEI, in their lawsuit,
have sued ExproFuels and The Exploration Company for, among other things,
breach of contract and defamation of character, and are seeking a declaratory
judgment that ExproFuels' interest in CNG is null and void and unspecified
compensatory exemplary damages. The Company, through its ownership interest in
ExproFuels, intends to pursue its claims and vigorously defend itself against
ATI's and AEI's claims. To date, both suits are in the preliminary stages. No
formal discovery has been submitted or completed, no scheduling orders have
been entered nor have any trial dates been set. While the Company and its
counsel remain optimistic they will ultimately prevail in the matter, and
remain confident that any material unfavorable outcome is extremely unlikely,
it is difficult to predict with any certainty the likelihood of an unfavorable
outcome of such litigation as of the date of this writing.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of security holders of the Company during the
fourth quarter of the fiscal year ended August 31, 1997.
15
<PAGE> 16
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":
<TABLE>
<CAPTION>
Range of Bid Prices
-------------------
Quarter ended: High Low
-------------- ------ ------
<S> <C> <C>
August 1997 $ 8.44 $ 5.44
May 1997 6.44 5.44
February 1997 6.81 2.94
November 1996 3.38 2.25
August 1996 $ 2.63 $ 1.86
May 1996 2.38 1.56
February 1996 2.63 1.63
November 1995 2.88 2.06
</TABLE>
As of November 14, 1997, there were approximately 1,740 holders of record of
the Company's Common Stock. The transfer agent for the Company is Boston
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
---------------------------------------------------------------------
1997 1996 1995 1994 1993
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Operating Revenues $1,083,511 $ 521,593 $ 331,253 $ 236,440 $ 116,716
Loss from continuing operations (3,398,866) (1,880,389) (2,153,365) (1,550,953) (2,277,144)
Loss per common share from
continuing operations (2) (0.27) (0.31) (0.44) (0.36) (0.64)
Total Assets(1) 21,652,726 8,433,434 4,111,980 2,262,283 2,447,785
Long-term obligations(1) 4,995,000 2,462,197 2,429,697 630,111 632,442
Shareholders' equity 14,770,770 5,670,688 1,377,747 1,613,121 1,214,297
Weighted average shares
outstanding (1) 12,576,255 6,140,176 4,863,961 4,267,363 3,533,973
</TABLE>
(1) Amounts reflect adjustments in 1995, 1994, and 1993 for the
reclassification of ExproFuels as an equity investment due to its
spin-off in 1996.
(2) Amounts reflect 1 for 50 reverse common stock split as of March 29, 1993.
16
<PAGE> 17
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
1997
Fiscal year 1997 was a very favorable year for the Company with respect to
raising equity and debt financing, acquiring undeveloped acreage for future
development and exploration and positioning the Company to significantly
increase its revenues from oil and gas operations.
During the second quarter of fiscal 1997, the Company successfully closed a
large transaction which 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.
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.
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 a 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,
eleven 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.
1996
In fiscal year 1996, the Company successfully raised funds under an agreement
with Comstar BioCapital, Inc., a foreign entity, through an offering of the
Company's common stock to foreign investors. The Company raised $2,100,000 in
exchange for 1,175,000 shares of the Company's common stock pursuant to
Regulation S of the
17
<PAGE> 18
Securities Act of 1933, as amended. The Company also realized $602,000 from the
payment of an outstanding note receivable, received $55,000 due to the
expiration of a drilling option and obtained $132,500 as proceeds from
long-term borrowings during the year. Proceeds were utilized to fund the
Company's cash loss from operations of $1,375,000, including the payment of
interest of $378,000, payments on current portion of debt and capital leases of
$40,100 and for capital expenditures of $182,000. The capital expenditures
included approximately $55,000 to develop oil and gas properties, $80,000 for
equipment purchases for use in U.S. operations of ExproFuels, and $41,000 for
purchases of other assets. Additional capital investments and advances totaling
$442,000 were made by ExproFuels in CNG International, LLC.
At August 31, 1996, the Company had current assets of $1,039,425 and current
liabilities of $1,073,049. However, its current assets included $967,838 in
cash, and its current liabilities included a $500,000 convertible note payable
not due until May, 1997. This compared to a cash position of only $78,655 at
August 31, 1995.
1995(1)
In fiscal year 1995, the Company successfully raised funds under a convertible
note payable and indenture of trust agreement which was initially started in
the 4th quarter of fiscal 1994. During fiscal 1995, the Company raised
$1,689,697 in funds under this long-term debt agreement, increasing to
$1,764,697 the total amount raised under this agreement. Although the
debentures offering raised a significant amount of needed capital for the
Company, the funds were not received as timely as was projected. The delay in
obtaining the funds reduced management's ability to initiate its intended
development activities as planned. The Company also raised $508,000 from sales
of Common Stock in fiscal 1995 and $261,000 from the sale of oil and gas
properties. Proceeds were utilized to fund the Company's cash loss from
operations of $2,030,000, payment of interest of $180,000, payments on current
portion of debt and capital leases of $142,000 and for capital expenditures of
$545,000. The capital expenditures included approximately $290,000 to develop
oil and gas properties in Maverick County, $105,000 for equipment purchases for
use in the U.S. operations of ExproFuels, and $150,000 for ExproFuels growing
participation in international operations through its joint venture investment
in CNG, International, LLC.
At August 31, 1995, the Company had current assets of $841,024 and current
liabilities of $469,545, resulting in $371,479 in working capital, as compared
to a working capital deficit of $360,000 at August 31, 1994. However, the
Company had a deficit of "quick" assets (cash and receivables) to current
liabilities of $266,392 at year end 1995 compared to a deficit of $554,000 at
year-end 1994.
(1)Amounts for 1995 have been adjusted for reclassifications of ExproFuels
division as an equity investment due to its spin-off in 1996.
1998 Capital Requirements
The major components of the Company's plans, and the requirements for
additional capital at August 31, 1997, include the following:
Maverick Basin Activity: During fiscal 1998, the Company plans to drill a
minimum of 3 additional wells, in keeping with lease renewal minimum
requirements, with the first well, the Paloma #2-83 having been spudded early
in the first quarter of fiscal 1998. Current drilling results indicate the well
will be completed as a gas well producing from a patch reef in the Glen Rose
formation. Based on interpretation of the Company's extensive 3-D seismic
database, over 20 potentially drillable patch reef prospects have been
identified on the Kincaid and Paloma Ranch leases, targeting the deeper Glen
Rose formation, while also providing an alternative completion target by
testing the overlaying Georgetown formation. The Company's share of the cost of
each Glen Rose or Georgetown well is approximately $260,000 for a completed
well and $160,000 for a dry hole. Company engineers are planning to test the
Georgetown formation with a new massive fracturing treatment with the hope of
unlocking additional reserves not previously productive due to the formation's
low permeability. The fracturing treatment increases the typical gross
completion cost of a Georgetown test well by $150,000 to $300,000, with the
Company's share being approximately $150,000 to $180,000.
Williston Basin Activity: At the end of fiscal 1997 the Company had 8 pending
permits to drill horizontal wells in the Red River "B" formation in the
Williston Basin on portions of its 320,000 acre leasehold in which it holds a
50%
18
<PAGE> 19
interest. All permits were for North Dakota leases and none of the locations
were selected with the assistance of 3-D seismic data. The Company's share of
the cost of each horizontal well is approximately $500,000 to $600,000 for a
completed well, while vertical completions can cost 25% to 50% less. Based on
its drilling experience gained by participating in the drilling of 11 wells in
the region during 1997, Company engineers and geologists have determined that
selection of drilling sites must incorporate 2-D, and preferably 3-D, seismic
evaluation in order to pinpoint the structural highs of the Red River
formation. Remaining structurally high dramatically improves the probability of
oil production, while deviation below this drilling model seemingly assures
prolific water production. The Company is currently shooting a 3-D seismic
survey over 20 square miles containing portions of its Williston basin acreage
at a cost of $600,000. Company management intends to postpone further location
selection and new drilling operations until 3-D seismic data confirms the
specific location of structurally high positions under any prospective drilling
location, if at all possible. Company engineers are also planning to drill
additional horizontal laterals during fiscal 1998 on several of the
non-economic wells it participated in during 1997 in the hope of recompleting
them in the known oil producing zones, while averting the water bearing strata.
The Company's share of the cost of additional horizontal laterals is
approximately $100,000 to $200,000 per well, depending on the number and length
of laterals drilled.
While the Company intends to proceed with its drilling activities cautiously,
the extensive acreage position it holds in the Williston Basin requires a high
level of drilling activity that comprises a formidable challenge to the Company
with limited access to exploration funds. Delay rentals required to maintain
the Company's interest in all of its undeveloped leasehold acreage are
approximately $260,000 for 1998, with the Williston Basin lease delay rentals
totaling over $137,000. Due to the Company's limited financial resources,
Management continues to seek, review, and negotiate for acceptable
opportunities to participate in drilling Red River and Lodgepole wells on its
acreage under farmout agreements or other acceptable terms with industry
operators experienced in the area.
Summary of Capital Resources and Liquidity
Management is endeavoring to identify additional sources that will provide the
funds required to meet its current obligations during fiscal year 1998.
Increases in oil and gas production in North Dakota and Texas from its 7 new
oil wells and 5 new gas wells coming on line during the last two quarters of
1997 and the first quarter 1998 have more than tripled monthly oil and gas
sales revenues compared to prior levels, from approximately $50,000 in March,
1997 to approximately $150,000 in September, 1997. Another 25% to 50% increase
in monthly revenues is expected during the 2nd quarter of 1998 due to
completion and commencement of operations of the new six inch gas pipeline in
Maverick County, plus incremental 2nd quarter sales revenues from new
production from wells completed late in the first quarter of 1998. The new gas
pipeline will allow the Company to increase revenues by removing a historical
restriction on its Maverick basin production caused by a lack of available
pipeline capacity or alternative sales outlets. Management continues to pursue
additional sources of debt and equity financing, and remains hopeful that
financial resources will remain available, enabling the Company to continue the
measured development of its oil and gas properties and meet its normal
operational and debt service obligations.
Management also believes that the completion of the spin-off of its former
subsidiary, ExproFuels, and the complete write-off of its investment and
advances to it at August 1997 will reduce the need for ongoing cash advances or
credit extensions and should further allow the Company's to achieve net income
from operations, before non-cash expenses, during the first quarter of 1998. In
addition, Management is confident oil and gas revenues should continue to
increase in light of current drilling plans and the expected continued
stability or moderate strengthening of domestic crude oil and natural gas
prices in fiscal 1998.
RESULTS OF OPERATIONS
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
19
<PAGE> 20
$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 has not produced 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 have been accrued
and included in fiscal 1997 operations as a loss, in accordance with generally
accepted accounting principles.
Other costs included noncash 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.
1996 Compared to 1995
Revenues from oil and gas sales increased by 50% in 1996 to $455,000 from
$304,000 in 1995, primarily as a result of higher gas sales due to the
successful completion of the Paloma "B" #2-112 during 1996 and the first full
year of production from the Paloma #1-107 and the Paloma "A"#83-1H.
Additionally, gas prices increased an average of 10% during 1996 over 1995
levels. Lease operating expenses for 1996 increased to $75,000 from $41,000 in
1995 reflecting a higher number of operated properties and overall higher costs
in operating certain producing wells. Exploration expenses increased by
$526,000 due to the drilling of two dry holes during the year, the Paloma
"C"#1-108 and the Paloma "D"#1-73. Additionally, during 1996, the Company
expensed the costs incurred in 1995 in drilling the Paloma #1-89, which
remained shut in at the end of 1995 pending its final evaluation. Depletion per
equivalent barrel of production increased to $4.12 in 1996 from $3.17 in 1995,
resulting in an overall increase of $58,000 depletion expense for the year.
Other costs included an increase in interest expense to $378,000 from $285,000
in 1995 attributable to interest accruing for a full year in 1996 versus a
partial year in 1995 on the Company's primary convertible note payable which
had an outstanding balance of $1,764,000 at August 31, 1996.
In total, revenues increased $463,000 or 42%, from $1,065,000 in 1995 to
$1,568,000 in 1996. Costs of sales, including general and administrative,
depreciation, depletion and amortization, increased only $207,000, thereby
resulting in a net decrease to prior year losses from operations of $255,000.
Other income and expense, in total, decreased by $17,000, with an increase in
interest expense of $93,000 being partially offset by an increase in interest
income of $58,000 and an increase in sublease income of $52,000. As a result,
the Company's net loss decreased to ($1,880,000) in 1996 from ($2,153,000) in
1995.
1995 Compared to 1994
Revenues from oil and gas sales in 1995 increased to $304,000 from $209,000 in
1994, primarily as a result of the Paloma #1-107 gas well having production for
a full year. Exploration expenses increased by $93,000 from 1994 to 1995 due to
the drilling of one dry hole during the year, the Paloma #1-133, plus the write
off of the portion of the drilling cost of the Paloma #1-89 below its final
completion horizon in the Upper Georgetown interval. Depletion increased by
$52,000 from 1994 to 1995 due to increased production volumes from the first
full year of the Paloma # 1-107, as mentioned above. Depletion per equivalent
barrel of production remained almost unchanged, increasing to $3.17 per barrel
in 1995 from $3.14 per barrel in 1994. The Company recognized an impairment of
$171,505 on its Holmgreen Ranch mineral interest.
20
<PAGE> 21
General and administrative costs increased by $288,000 from 1994 to 1995. The
significant components of the increase included a $200,000 one time charge in
1995 for marketing services, and increases in public expense of $26,000 and
consulting fees expense of $31,000.
In total, revenues from operations increased by $46,000 from 1994 to 1995. This
slight revenue increase was significantly offset by the increase in total costs
and expenses of $544,000 from 1994 to 1995 resulting in the overall increase in
loss from operation of $460,000 for the year.
Other non-operating expense changes consisted primarily of an increase in
interest expense of $154,000 from 1994 to 1995 due directly to the completion
during the year of borrowings under the convertible note payable and indenture
of trust; such borrowings increased by $1,690,000 from 1994 to 1995. As a
result of the above, net losses from continuing operations increased by
$603,000 for the year ended August 31, 1995 from the similar period in 1994.
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
21
<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 15, 1997:
<TABLE>
<CAPTION>
Name Position Age
---- -------- ---
<S> <C> <C>
Stephen M. Gose, Jr. Chairman of the Board of Directors 67
and of Audit and Compensation Committees
Thomas H. Gose Director and Assistant Secretary 42
James E. Sigmon President and Director 49
Michael Pint Director, Audit and Compensation Committees 54
Robert L. Foree, Jr. Director, Audit and Compensation Committees 68
Roberto R. Thomae Chief Financial Officer 46
Secretary/Treasurer, Vice President-Finance
Richard A. Sartor Controller 45
</TABLE>
Stephen M. Gose, Jr., has served as Chairman of the Board of Directors of the
Company since July, 1984, and as Chairman of the Audit and Compensation
Committees of the Board of Directors since May, 1997. He has been active for
more than thirty-five years in exploration and development of oil and gas
properties, in real estate development, and in ranching through the operations
of Cibolo Properties, Inc., its predecessors and affiliates.
Mr. Gose also serves as Chairman of the Board of Directors of ExproFuels, Inc.
Thomas H. Gose is the sole Director, CEO and President of Cibolo Properties,
Inc. and Retamco Operating, Inc. He formerly served as President of Spectrum
Resources, Inc. (a majority shareholder of the Company) since 1987. He has also
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 is the
President and a 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. and is also a Director of
ExproFuels, Inc.
Michael Pint 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 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.
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.
Richard A. Sartor has served as Controller of the Company since April 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.
22
<PAGE> 23
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:
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
Name and Other Annual Long-term All other
Principal Position Year Salary Bonuses Compensation Compensation Compensation
- ------------------ ---- ------ ------- ------------ ------------ ------------
<S> <C> <C> <C> <C> <C> <C> <C>
James E. Sigmon 1997 $ 120,000 $ 0 (1) $20,827 $ 0 $ 0
President & CEO 1996 72,000 0 (1) 12,498 0 7,500
1995 72,000 0 0 0 0
</TABLE>
(1) Amounts represents income from 1% overriding royalty interest.
OPTIONS/SAR GRANTS IN LAST FISCAL YEAR
<TABLE>
<CAPTION>
% of Total Options Grant
# Options Granted to Employees Exercise Price Expiration Date
Name Granted(3) in Fiscal Year per Share Date Value
--------- ---------- ----------------- ------------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Michael Pint 75,000(1) 35.7% $ 6.60 2007 $ 141,497
Robert L. Foree, Jr. 75,000(1) 35.7% 6.60 2007 141,497
Roberto R. Thomae 50,000(2) 23.8% 2.62 2006 38,420
Frank A. Alderman 10,000(2) 4.8% 2.62 2006 8,624
--------- ------- ----------
Totals 210,000 100% $ 330,038
========= ======= ==========
</TABLE>
(1) Director's ten year non-qualified options to purchase shares at 110% of
current market price at date of grant, vesting ratably at 25,000 shares per
year over next three years from date of grant. Options to purchase 25,000
shares were exercisable at August 31, 1997.
(2) Employee's ten year qualified options granted under the registrant's 1995
Flexible Incentive Plan to purchase shares at 110% of current market price
at date of grant, vesting 50% after one year and 100% after two years from
the date of grant, and continuing employee status. None were exercisable at
August 31, 1997.
(3) 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
6.25%; dividend yield of 0%; volatility factors of the expected market price
of the Company's common stock of .300; and a weighted-average expected life
of the option of five years.
23
<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, 1997 August 31, 1997 *
--------- --------- -------- ----------------------- --------------------
<S> <C> <C> <C> <C>
James E. Sigmon(1)(2) -- -- 150,000 $ 855,000
Michael Pint(3) -- -- 75,000 $ 0
Robert L. Foree, Jr.(3) -- -- 75,000 $ 0
Roberto R. Thomae(4) -- -- 50,000 $ 0
Frank A. Alderman(4) -- -- 10,000 $ 0
</TABLE>
(1) Value of unexercised options calculated as the difference in the stock
price at August 31,1997 and the option price.
(2) All of Mr. Sigmon's unexercised options were exercisable as of August
31, 1997.
(3) Mr. Pint and Mr. Foree's options were not "in the money" at August 31,
1997; accordingly the options are valued at $0 at year end.
(4) None of Mr. Thomae's or Mr. Alderman's options were exercisable at August
31, 1997; accordingly the options are valued at $0 at year end.
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 new 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 $120,000 annually, and includes
the grant of a 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 Stephen M. Gose, Jr.
(Chairman), Robert L. Foree, Jr. and Michael Pint. 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.
24
<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
14,759,198 shares outstanding and 16,079,604 fully diluted shares which
includes 1,320,406 shares under options and warrants as of November 14, 1997.
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.
<TABLE>
<CAPTION>
Percent Owned
Name and Address of Number of Shares Primary Shares
Beneficial Owner Beneficially Owned Outstanding
------------------- ------------------ --------------
<S> <C> <C>
Thomas H. Gose 2,193,701 14.86%
500 North Loop 1604 East
Suite 250
San Antonio, TX 78232
Trianon Opus One, Inc. 1,100,000 7.45%
Fohrenstrasse 25
CH-8703 Erlenbach
Switzerland
</TABLE>
SECURITY OWNERSHIP OF DIRECTORS AND EXECUTIVE OFFICERS
The following table sets forth the number of shares of common stock
beneficially owned as of November 19, 1997 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.
<TABLE>
<CAPTION>
Number of Shares Percent
Name Beneficially Owned Owned
---- ------------------ -------
(1)
<S> <C> <C>
Thomas H. Gose (3) 2,193,701 14.86%
James E. Sigmon (2) 200,000 1.36%
Stephen M. Gose, Jr. 100,000 .68%
Michael Pint. (4) 125,000 .85%
Robert L. Foree, Jr. (4) 35,000 .24%
----------- --------
All Directors and Executive
Officers as a group 2,713,701 18.39%
</TABLE>
(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 150,000 shares of the Company's Common
Stock reserved for issuance under options issued under the Company's 1995
Flexible Incentive Plan.
(3) The number of shares beneficially owned by Mr. Thomas H. Gose include
20,500 shares owned directly, 930,070 shares owned by Spectrum Resources,
Inc., 1,189,631 owned by Retamco Operating, Inc., 20,000 shares owned by
Spectrum Holdings, and 33,500 shares owned by Retamco Properties, Inc.
(4) The number of shares beneficially owned by Mr. Pint and Mr. Foree each
includes 25,000 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, 1997 and 100,000 and 10,000 respectively owned
directly.
25
<PAGE> 26
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED 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. Sixty-seven percent of the acquisition was 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, resulting
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.
During 1997, the Company advanced ExproFuels, its former wholly-owned
subsidiary, $561,224 under a formal credit arrangement, and committed to
advance an additional $265,000 through December 31, 1997. Interest is at 8% and
the entire amount of principal and interest is due December 31, 1998. However,
due to the financial condition of ExproFuels, a provision for loan loss of the
outstanding balance, accrued interest and commitment in the total amount of
$845,487 has been recorded at August 31, 1997.
In August, 1996, 10% of the outstanding common stock of ExproFuels, Inc.,
previously a wholly-owned subsidiary, was given as consideration to the
Directors of ExproFuels, Inc. for services rendered.
During 1996, the Company exchanged 2,637,736 shares of its unregistered common
stock for 131,860 gross acres (32,965 net acres) of undeveloped oil and gas
properties with several parties brought to it by its investment banker.
In December, 1995, the Company exchanged with its Chairman a 32.5% mineral
property interest for certain unproved oil and gas leasehold acreage valued at
$225,000, a $100,000 note payable and certain other assets valued at $73,403.
26
<PAGE> 27
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, 1997 and 1996
Statements of Operations, Years Ended August 31, 1997, 1996 and
1995. Statements of Stockholders' Equity, Years Ended August 31,
1997, 1996 and 1995. Statements of Cash Flows, Years Ended August
31, 1997, 1996 and 1995.
Notes to Financial Statements.
(2) Financial Statement Schedule for the years ended August 31, 1997,
1996 and 1995:
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.
(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 September
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
21.1 Financial Statements of ExproFuels, Inc. (beginning on
page S-1)
27.1 Financial Data Schedule
** Previously filed
(B) Reports on Form 8-K:
None Filed
27
<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
Registrant
November 26, 1997 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 26, 1997
/s/ Thomas H. Gose
- -------------------------
Thomas H. Gose Director and Assistant Secretary November 26, 1997
/s/ James E. Sigmon
- -------------------------
James E. Sigmon President and Director
(Principal Executive Officer) November 26, 1997
/s/ Michael Pint
- -------------------------
Michael Pint Director November 26, 1997
/s/ Robert L. Foree, Jr.
- -------------------------
Robert L. Foree, Jr. Director November 26, 1997
/s/ Roberto R. Thomae
- -------------------------
Roberto R. Thomae Chief Financial Officer November 26, 1997
Secretary/Treasurer
(Principal Accounting Officer)
</TABLE>
28
<PAGE> 29
THE EXPLORATION COMPANY
INDEX TO FINANCIAL STATEMENTS
AUGUST 31, 1997 AND 1996
<TABLE>
<CAPTION>
AUDITED FINANCIAL STATEMENTS Page
----
<S> <C>
Independent Auditors' Report F-1
Balance Sheets F-2
Statements of Operations F-4
Statements of Stockholders' Equity F-5
Statements of Cash Flows F-6
Notes to Financial Statements F-7
SUPPORTING SCHEDULE
Schedule II - Valuation and Qualifying Reserves F-19
</TABLE>
F-0
<PAGE> 30
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
The Exploration Company
We have audited the balance sheets of The Exploration Company as of August 31,
1997 and 1996, and the related statements of operations, stockholders' equity
and cash flows for each of the three years in the period ended August 31, 1997.
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, 1997 and 1996, and the results of its operations and cash flows for
each of the three years in the period ended August 31, 1997, 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, 1997. 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 14, 1997
F-1
<PAGE> 31
THE EXPLORATION COMPANY
BALANCE SHEETS
AUGUST 31, 1997 AND 1996
<TABLE>
<CAPTION>
1997 1996
------------ ------------
ASSETS
<S> <C> <C>
Current Assets:
Cash and equivalents $ 6,198,069 $ 967,838
Accounts receivable, less allowance for doubtful accounts of
$9,973 in 1996:
Joint interest owners 127,602 11,587
Oil and gas production 234,824 60,000
Prepaid expenses and other 49,084 --
------------ ------------
Total current assets 6,609,579 1,039,425
Property and Equipment:
Oil and gas properties (successful efforts),
less accumulated depreciation, depletion and
amortization of $680,240 in 1997 and $422,240 in 1996 14,311,450 6,599,996
Other property and equipment:
Transportation and other equipment 194,550 79,453
Less accumulated depreciation and amortization (74,418) (38,891)
------------ ------------
Net property and equipment 14,431,582 6,640,558
Other Assets:
Net assets of ExproFuels -- 363,271
Deferred financing fees, net of amortization of $20,000 180,000 --
Other assets 431,565 390,180
------------ ------------
611,565 753,451
------------ ------------
Total Assets $ 21,652,726 $ 8,433,434
============ ============
</TABLE>
See notes to financial statements.
F-2
<PAGE> 32
THE EXPLORATION COMPANY
BALANCE SHEETS
AUGUST 31, 1997 AND 1996
<TABLE>
<CAPTION>
1997 1996
------------ ------------
LIABILITIES AND STOCKHOLDERS' EQUITY
<S> <C> <C>
Current Liabilities:
Accounts payable and accrued expenses $ 1,832,037 $ 264,018
Due to joint interest owners 8,513 12,224
Accrued payroll and taxes 46,406 24,307
Current portion of long-term debt 944,013 772,500
Current portion of capital lease obligations 17,962 --
------------ ------------
Total current liabilities 2,848,931 1,073,049
Long-term Liabilities:
Long-term debt 4,000,000 1,689,697
Capital lease obligations 33,025 --
------------ ------------
Total long-term liabilities 4,033,025 1,689,697
Stockholders' Equity:
Common stock, par value $ .01 per share; authorized 200,000,000 shares;
issued and outstanding 14,759,198 and 9,426,650 shares
at August 31, 1997 and 1996 147,592 94,266
Additional paid-in capital 35,928,054 23,482,432
Accumulated deficit (21,304,876) (17,906,010)
------------ ------------
Total stockholders' equity 14,770,770 5,670,688
------------ ------------
Total Liabilities and Stockholders' Equity $ 21,652,726 $ 8,433,434
============ ============
</TABLE>
See notes to financial statements.
F-3
<PAGE> 33
THE EXPLORATION COMPANY
STATEMENTS OF OPERATIONS
YEARS ENDED AUGUST 31, 1997, 1996 AND 1995
<TABLE>
<CAPTION>
1997 1996 1995
------------ ------------ ------------
<S> <C> <C> <C>
REVENUES:
Oil and gas sales $ 976,882 $ 455,221 $ 304,342
Other operating income 106,629 66,372 26,911
------------ ------------ ------------
1,083,511 521,593 331,253
COSTS AND EXPENSES:
Lease operations 176,019 75,634 41,225
Production taxes 71,954 28,357 21,312
Exploration expenses 1,549,095 677,170 151,142
Abandoned leases and equipment 153,066 -- 21,000
Impairment of mineral properties 28,400 -- 171,505
Depreciation, depletion and amortization 293,527 170,525 106,200
General and administrative 938,638 513,896 730,711
------------ ------------ ------------
Total costs and expenses 3,210,699 1,465,582 1,243,095
------------ ------------ ------------
(2,127,188) (943,989) (911,842)
Net loss from ExproFuels equity ownership (1,215,259) (680,825) (968,889)
------------ ------------ ------------
Loss from operations (3,342,447) (1,624,814) (1,880,731)
Other Income (Expense):
Interest income 283,462 122,428 13,098
Interest expense (236,494) (294,003) (201,732)
Loan fee amortization (103,387) (84,000) (84,000)
------------ ------------ ------------
(56,419) (255,575) (272,634)
------------ ------------ ------------
NET LOSS $ (3,398,866) $ (1,880,389) $ (2,153,365)
============ ============ ============
AMOUNTS PER COMMON SHARE:
Net loss per common share $ (0.27) $ (0.31) $ (0.44)
============ ============ ============
Weighted average number of common
shares outstanding 12,576,255 6,140,176 4,863,961
============ ============ ============
</TABLE>
See notes to financial statements.
F-4
<PAGE> 34
THE EXPLORATION COMPANY
STATEMENTS OF STOCKHOLDERS' EQUITY
YEARS ENDED AUGUST 31, 1997, 1996 AND 1995
<TABLE>
<CAPTION>
Common Stock Additional
--------------------------- Paid-in Accumulated
Shares Amount Capital Deficit Total
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
Balance at September 1, 1994 4,591,087 $ 45,912 $ 15,439,465 $(13,872,256) $ 1,613,121
Issuance of common stock
for cash 299,056 2,990 504,937 -- 507,927
Issuance of common stock
in exchange for oil and
gas properties 350,227 3,502 710,240 -- 713,742
Conversion of debt to
common stock 267,600 2,676 599,852 -- 602,528
Issuance of common stock
warrants with convertible stock -- -- 33,794 -- 33,794
Common stock warrants exercised 20,000 200 59,800 -- 60,000
Net loss for the year -- -- -- (2,153,365) (2,153,365)
------------ ------------ ------------ ------------ ------------
BALANCE AT AUGUST 31, 1995 5,527,970 55,280 17,348,088 (16,025,621) 1,377,747
Issuance of common stock
for cash 1,175,000 11,750 2,088,250 -- 2,100,000
Issuance of common stock
in exchange for oil and
gas properties 2,723,680 27,236 4,578,502 -- 4,605,738
Issuance of common stock
warrants -- -- 12,500 -- 12,500
Spin-off of ExproFuels, Inc. -- -- (544,908) -- (544,908)
Net loss for the year -- -- -- (1,880,389) (1,880,389)
------------ ------------ ------------ ------------ ------------
BALANCE AT AUGUST 31, 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
============ ============ ============ ============ ============
</TABLE>
See notes to financial statements.
F-5
<PAGE> 35
THE EXPLORATION COMPANY
STATEMENTS OF CASH FLOWS
YEARS ENDED AUGUST 31, 1997, 1996 AND 1995
<TABLE>
<CAPTION>
1997 1996 1995
------------ ------------ ------------
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net loss $ (3,398,866) $ (1,880,389) $ (2,153,365)
Adjustments to reconcile net loss to net cash
used in operating activities:
Depreciation, depletion and amortization 293,527 170,525 106,200
Amortization of financing fees 83,887 86,105 92,302
Abandoned leases, equipment and other 153,066 220,805 21,000
Impairment of properties 28,400 -- 171,505
ExproFuels operations and loan loss reserve 1,215,259 (80,284) (121,330)
Changes in operating assets and liabilities:
Receivables (290,839) 52,911 (98,246)
Prepaid expenses and other (49,084) 35,343 27,043
Accounts payable and accrued expenses 1,586,380 19,417 (78,284)
------------ ------------ ------------
Net cash (used) in operating activities (378,270) (1,375,567) (2,033,175)
INVESTING ACTIVITIES:
Development of oil and gas properties (12,924,068) (55,484) (289,980)
Purchase of transportation and other equipment (115,071) (86,277) (104,644)
Proceeds from sale of oil and gas properties -- -- 261,242
Increase in note receivable -- -- (602,528)
Proceeds from note receivable -- 602,528 --
Investments in and advances to ExproFuels (826,224) (442,426) (150,000)
Other assets (331,036) 41,509 (98,304)
------------ ------------ ------------
Net cash provided (used) in investing activities (14,196,399) 59,850 (984,214)
FINANCING ACTIVITIES:
Issuance of common stock, net of expenses 15,007,400 2,112,500 1,204,249
Proceeds from long-term debt 5,008,140 132,500 1,935,664
Payments on long-term debt (210,640) (40,100) (142,914)
------------ ------------ ------------
Net cash provided by financing activities 19,804,900 2,204,900 2,996,999
------------ ------------ ------------
INCREASE (DECREASE) IN CASH AND EQUIVALENTS 5,230,231 889,183 (20,390)
Cash and equivalents at beginning of year 967,838 78,655 99,045
------------ ------------ ------------
CASH AND EQUIVALENTS AT END OF YEAR $ 6,198,069 $ 967,838 $ 78,655
============ ============ ============
SUPPLEMENTAL DISCLOSURES
Cash paid for interest $ 151,955 $ 295,360 $ 179,635
Cash paid for income taxes -- -- --
</TABLE>
See notes to financial statements.
F-6
<PAGE> 36
THE EXPLORATION COMPANY
NOTES TO FINANCIAL STATEMENTS
AUGUST 31, 1997, 1996 AND 1995
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.
In 1993, the Company commenced operations in the alternative fuels industry
through a division called ExproFuels. ExproFuels converted vehicle engines that
use gasoline for combustion to propane or natural gas, supplies alternative
fuels to customers and constructs alternative fuels refueling facilities.
Customers are primarily located in Texas and Arizona. The ExproFuels division
was incorporated in August, 1996, and was spun off from The Exploration Company
on September 3, 1996, with an approximate 40% equity ownership being retained.
At August 31, 1996, financial position and results of operations of ExproFuels,
Inc. were reported for all years presented in accordance with disposal of a line
of business with a significant retained interest. The Company's net assets in
ExproFuels, Inc. was reduced to $0 in 1997 by recognition of its equity
ownership in losses.
Cash and Equivalents: Cash and cash equivalents consist of all demand deposits
and funds invested in short-term investments with original maturities of three
months or less.
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 are in excess
of the discounted present value of future cash flows relating to proved
reserves, an impairment charge is recorded.
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 at August 31, 1997 are assets under capital
lease of $51,302, net of accumulated depreciation of $12,825. 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.
Net Loss Per Share: Net loss per common share is computed by dividing net loss
by the weighted average number of shares of common stock outstanding during the
period. Common stock equivalents are not considered in the computation of net
loss per common share as their effect is anti-dilutive.
F-7
<PAGE> 37
THE EXPLORATION COMPANY
NOTES TO FINANCIAL STATEMENTS
AUGUST 31, 1997, 1996 AND 1995
NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - CONTINUED
Financial Instruments with Off-Balance-Sheet Risk: Financial instruments that
potentially subject the Company to concentrations of credit risk consist
principally accounts receivables. Accounts receivable 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.
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 and Removal Liabilities: The estimated costs of restoration and
removal of producing property well sites is generally less than the estimated
salvage value of the respective property. Accordingly, the Company has not
provided for an additional liability accrual.
Fair Value of Financial Instruments: The only financial instruments of the
Company at August 31, 1997 and 1996, 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.
Reclassifications: Certain amounts for 1996 and 1995 have been reclassified for
comparative purposes to 1997.
NOTE B - LONG TERM DEBT
Long-term debt and capitalized lease obligations consist of the following at
August 31:
<TABLE>
<CAPTION>
1997 1996
-------------- ---------
<S> <C> <C>
Convertible notes payable with interest at 6%,
interest due at maturity and principal due in full
on December 31, 2001 ($3,800,000) and
January 27, 2002 ($200,000). See below. $ 4,000,000 $ --
Note payable under $1,000,000 line of credit with Kantonalbank, Luzern
Switzerland, with interest floating at the bank's market rate (3.30% at August
31, 1997), unsecured and
due on demand 940,481 --
Installment note due financing company, with
interest rate at 11.90%, due in monthly installments
of $401 and secured by vehicle. 3,532 --
</TABLE>
F-8
<PAGE> 38
THE EXPLORATION COMPANY
NOTES TO FINANCIAL STATEMENTS
AUGUST 31, 1997, 1996 AND 1995
NOTE B - LONG TERM DEBT - CONTINUED
<TABLE>
<CAPTION>
1997 1996
----------- ----------
<S> <C> <C>
Capital lease obligations, with imputed interest rates from 21.33% to 22.64%,
due in monthly installments
of $2,296 and secured by related equipment. 50,987 --
Convertible note payable to Trust, with interest
at 11.50%, and principal due beginning August 1997;
secured by certain oil and gas properties. See below. -- 1,764,697
Convertible note payable to partnership, with interest
at 10%, and principal due in May 1997. See below. -- 500,000
Notes payable to individual, with interest at 12%, due
currently, and secured by certain common stock of the Company. -- 197,500
----------- -----------
Total long-term debt and capitalized lease obligations 4,995,000 2,462,197
Less current portion (961,975) (772,500)
----------- -----------
Long-term portion of debt and capitalized lease obligations $ 4,033,025 $ 1,689,697
=========== ===========
</TABLE>
Convertible $4,000,000 Notes Payable: During the current year the Company issued
two separate convertible debentures, both with identical terms, except for the
due date. Each debentures accrues interest at 6% until maturity, and are
convertible at the payees option, in total amount only, into common stock of the
Company at the conversion rate of $5 per share of common stock. The Company has
the right to force conversion after its common stock has been trading at $7.50
for ten consecutive days. Conversion may not occur prior to January 1, 1998, and
if converted, the stock issued by the Company must be without restrictive
legend.
Convertible $1,764,697 Notes Payable: On August 2, 1994, the Company entered
into a master note payable and indenture of trust agreement for up to $2,000,000
principal amount, secured by certain oil and gas properties. The notes includes
interest at 11.50%, payable semi-annually on January 1 and July 1, and a
conversion option at $2.50 per common share of stock. The Company may force the
conversion at the same price per share in the event the closing bid price of the
Company's common stock has closed at $6.00 per share for fifteen consecutive
days. During 1997, the notes were converted into 705,882 shares of the Company's
common stock.
Convertible $500,000 Note Payable: On May 25, 1994, the Company issued a
$500,000, three year, convertible promissory note payable to a partnership. The
terms of the note include interest at 10% per annum, payable quarterly, and a
conversion option at $3.00 per common share of stock. The note was callable at
the option of the Company in the event the closing bid price of the Company's
common stock averaged $7.00 for a period of forty-five days. During 1997, the
note was converted into $166,666 shares of the Company's common stock.
F-9
<PAGE> 39
THE EXPLORATION COMPANY
NOTES TO FINANCIAL STATEMENTS
AUGUST 31, 1997, 1996 AND 1995
NOTE B - LONG TERM DEBT - CONTINUED
The following is a schedule of principal maturities of long-term debt and
capital lease obligation as of August 31, 1997:
<TABLE>
<CAPTION>
Fiscal Year Ended
August 31 Debt Leases Total
------------- ---------- ---------- ----------
<S> <C> <C> <C>
1998 $ 944,013 $ 17,962 $ 961,975
1999 -- 22,304 22,304
2000 -- 10,721 10,721
2001 4,000,000 -- 4,000,000
---------- ---------- ----------
$4,944,013 $ 50,987 $4,995,000
========== ========== ==========
</TABLE>
Future minimum rentals under all capital leases are as follows:
<TABLE>
<S> <C>
1998 $ 27,552
1999 27,552
2000 4,608
--------
Total minimum rentals 59,712
Less amount representing interest,
executory costs and profit 8,725
--------
Present value of capital lease obligations $ 50,987
========
</TABLE>
NOTE C - STOCKHOLDERS' EQUITY
Stock Options: The Company grants options to its officers, directors, and key
employees under its 1995 Flexible Incentive Plan. The Company has elected to
follow Accounting Principles Board Opinion No. 25, "Accounting 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, "Accounting 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 stock option plan has authorized the grant of options to
management, directors, and key personnel for up to 400,000 shares of the
Company's common stock. All options granted have ten year terms and vest and
become fully exercisable based on the specific terms imposed at the date of
grant, generally ranging up to three years.
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 1997
and 1996, respectively: risk-free interest rates of 6.25% and 6.25%; dividend
yields of -0-% and -0-%; volatility factors of the expected market price of the
Company's common stock of .300 and .300; and a weighted-average expected life of
the option of five years.
F-10
<PAGE> 40
THE EXPLORATION COMPANY
NOTES TO FINANCIAL STATEMENTS
AUGUST 31, 1997, 1996 AND 1995
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>
1997 1996
------------- ------------
<S> <C> <C>
Pro forma net (loss) $ (3,539,881) $ (1,800,389)
Pro forma net loss per common share $ (0.28) $ (0.31)
</TABLE>
A summary of the status of the Company's stock options as of August 31, 1997 and
1996, and changes during the fiscal years then ended, is presented below:
<TABLE>
<CAPTION>
1997 1996
--------------------------- ---------------------------
Weighted-Average Weighted-Average
Shares Exercised Price Shares Exercise Price
------ --------------- ------ --------------
<S> <C> <C> <C> <C>
Outstanding options at beginning of year 229,800 $ 2.77 279,800 $ 2.72
Granted 210,000 5.46 - -
Exercised - - - -
Forfeited - - (50,000) 2.50
------- ------ ------- ------
Outstanding options at end of year 439,800 $ 4.06 229,800 $ 2.77
======= ====== ======= ======
Options exercisable at end of year 339,800 $ 3.32 229,800 $ 2.77
======= ====== ======= ======
Weighted-average fair value of
options granted during the year $ 1.57 $ -
====== ======
</TABLE>
F-11
<PAGE> 41
THE EXPLORATION COMPANY
NOTES TO FINANCIAL STATEMENTS
AUGUST 31, 1997, 1996 AND 1995
NOTE C - STOCKHOLDERS' EQUITY - CONTINUED
The following table summarizes information about the options outstanding at
August 31, 1997:
<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>
$ 2.00 10,000 5.3 years $ 2.00 10,000 $ 2.00
2.34 50,000 1.8 years 2.34 50,000 2.34
2.75 100,000 7.5 years 2.75 100,000 2.75
2.62 60,000 9.0 years 2.62 60,000 2.62
3.13 60,000 1.8 years 3.13 60,000 3.13
3.91 9,800 4.3 years 3.91 9,800 3.91
6.60 150,000 9.6 years 6.60 50,000 6.60
-------- --------- ------ ------- ------
439,800 6.9 years $ 4.06 339,800 $ 3.32
======== ========= ====== ======= ======
</TABLE>
Stock Warrants: The following is a summary of warrants outstanding at August 31,
1997:
<TABLE>
<CAPTION>
Weighted Weighted
Average Average
Range of Exercise Contractual
Purpose Number Prices Price Life
- -------------------------------------- ------ -------- -------- -----------
<S> <C> <C> <C> <C>
Convertible notes and equity financing 830,606 $ 2.00 - $6.00 $ 3.26 3.1 years
Services rendered 150,000 2.18 - 2.68 2.52 9.5 years
</TABLE>
NOTE D - OPERATING LEASES
The Company leases its primary office space for $7,420 per month through
February 29, 1998. The Company is also contingently liable on leases of
ExproFuels, Inc. in an amount of approximately $57,300 at August 31, 1997.
For the years ended August 31, 1997, 1996 and 1995, the Company incurred rent
expense of $91,639, $91,144 and $90,420, respectively. Future minimum rentals
under all noncancellable real estate leases are as follows:
<TABLE>
<CAPTION>
Fiscal Year Ended
August 31 Amount
----------------- ----------
<S> <C>
1998 $ 90,580
1999 92,115
2000 46,057
---------
Future minimum rentals $ 228,752
=========
</TABLE>
F-12
<PAGE> 42
THE EXPLORATION COMPANY
NOTES TO FINANCIAL STATEMENTS
AUGUST 31, 1997, 1996 AND 1995
NOTE E - FEDERAL INCOME TAXES
The Company has incurred losses for both financial statement and income tax
purposes. 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:
<TABLE>
<CAPTION>
1997 1996
------------ ------------
<S> <C> <C>
Deferred tax assets:
Tax net operating loss carryforwards $ 17,664,000 $ 16,321,000
Provision for loan losses 845,000 --
Impairment of oil and gas and mineral properties 460,000 434,000
Other temporary differences - net 3,000 3,000
------------ ------------
Gross deferred tax assets 18,972,000 16,758,000
Statutory tax rate 34% 34%
------------ ------------
6,450,480 5,697,720
Unused general business credits 30,000 30,000
------------ ------------
Net deferred tax assets 6,480,480 5,727,720
Less valuation allowance (6,480,480) (5,727,720)
------------ ------------
Deferred income tax asset recorded $ -0- $ -0-
============ ============
</TABLE>
The net operating loss carryforwards available at August 31, 1997, and the
related expiration dates are as follows:
<TABLE>
<CAPTION>
Expires
August 31 Amount
--------- -------------
<S> <C>
1998 $ 443,000
1999 131,000
2000 480,000
2001 1,200,000
2002 1,960,000
2003 to 2007 3,261,000
2008 to 2012 10,189,000
------------
$ 17,664,000
============
</TABLE>
NOTE F - 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
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 have been reported at the
affiliates historical cost basis, resulting 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.
F-13
<PAGE> 43
THE EXPLORATION COMPANY
NOTES TO FINANCIAL STATEMENTS
AUGUST 31, 1997, 1996 AND 1995
NOTE F - RELATED PARTY TRANSACTIONS - CONTINUED
During 1997, the Company advanced ExproFuels $561,224 under a formal credit
arrangement, and committed to advance an additional $265,000 through December
31, 1997. Interest is at 8% and the entire amount of principal and interest is
due December 31, 1998. However, due to the financial condition of ExproFuels, a
provision for loan loss of the outstanding balance, accrued interest and
commitment in the total amount of $845,487 has been recorded at August 31, 1997.
The average balance outstanding on the loan during the current fiscal year was
$191,690.
In August, 1996, 10% of the outstanding common stock of ExproFuels, Inc.,
previously a wholly-owned subsidiary, was given to the Directors of ExproFuels,
Inc. as consideration for services rendered.
During 1996, the Company exchanged 2,637,736 shares of its unregistered common
stock for 131,860 gross acres (32,965 net acres) of undeveloped oil and gas
properties with several parties brought to the Company by its investment banker.
In December, 1995, the Company exchanged with its Chairman a 32.5% mineral
property interest for certain unproved oil and gas leasehold acreage valued at
$225,000, a $100,000 note and certain other assets valued at $73,403.
In August, 1995, an affiliated company loaned the Company $50,000. The loan was
repaid in full on August 31, 1995.
During 1995, the Company acquired from an affiliate unproved oil and gas
leasehold acreage with a basis of $300,000, for 186,731 shares of the Company's
common stock.
NOTE G - 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:
<TABLE>
<CAPTION>
1997 1996
------------ ------------
<S> <C> <C>
Proved properties $ 4,961,616 $ 936,694
Less reserve for impairment (119,250) (90,850)
------------ ------------
Net proved properties 4,842,366 845,844
Unproved properties 10,149,324 6,176,392
------------ ------------
Total oil and gas properties 14,991,690 7,022,236
Less accumulated depreciation,
depletion and amortization (680,240) (422,240)
------------ ------------
Net capitalized cost $ 14,311,450 $ 6,599,996
============ ============
</TABLE>
F-14
<PAGE> 44
THE EXPLORATION COMPANY
NOTES TO FINANCIAL STATEMENTS
AUGUST 31, 1997, 1996 AND 1995
NOTE G - OIL AND GAS PRODUCING ACTIVITIES AND PROPERTIES - CONTINUED
Costs incurred, capitalized, and expensed in oil and gas producing activities
are as follows:
<TABLE>
<CAPTION>
1997 1996 1995
-------- -------- ------
<S> <C> <C> <C>
Property acquisition costs, unproved $ 13,517,743 $ 4,951,598 $ 748,321
Property development and exploration costs 4,024,922 732,654 511,944
Depreciation, depletion and amortization 258,000 160,000 102,000
Depletion per equivalent barrel of production 4.50 4.12 3.17
</TABLE>
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.
<TABLE>
<CAPTION>
Oil Gas
(Barrels) (MCF)
---------- ----------
<S> <C> <C>
Reserves at August 31, 1994 8,294 969,018
Discoveries -- 55,709
Revisions of previous estimates 8,428 495,027
Production (2,598) (177,238)
---------- ----------
Reserves at August 31, 1995 14,124 1,342,516
Discoveries 5,710 525,000
Revisions of previous estimates 3,598 241,248
Production (2,862) (215,274)
---------- ----------
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
========== ==========
</TABLE>
All of the Company's proved reserves are developed and are located in the
continental United States.
F-15
<PAGE> 45
THE EXPLORATION COMPANY
NOTES TO FINANCIAL STATEMENTS
AUGUST 31, 1997, 1996 AND 1995
NOTE G- 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>
1997 1996 1995
----------- ----------- -----------
<S> <C> <C> <C>
Future cash inflows $ 8,814,000 $ 4,658,670 $ 2,144,655
Future production and development costs (1,919,000) (680,120) (250,943)
----------- ----------- -----------
Future net cash inflows before income tax 6,895,000 3,978,550 1,893,712
Future income tax expense -- -- --
----------- ----------- -----------
Future net cash flows 6,895,000 3,978,550 1,893,712
10% annual discount to reflect
timing of net cash flows (2,163,000) (1,778,810) (671,672)
----------- ----------- -----------
Standardized Measure of discounted future
net cash flows relating to proved reserves $ 4,732,000 $ 2,199,740 $ 1,222,040
=========== =========== ===========
</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>
1997 1996 1995
----------- ----------- -----------
<S> <C> <C> <C>
Standardized Measure, beginning of year $ 2,199,740 $ 1,222,040 $ 1,049,458
Discoveries 5,741,710 613,500 36,106
Sales and transfers, net of production costs (728,909) (362,947) (261,805)
Revisions in quantity and price estimates (2,260,567) 849,351 503,227
Accretion of discount (219,974) (122,204) (104,946)
----------- ----------- -----------
Standardized Measure, end of period $ 4,732,000 $ 2,199,740 $ 1,222,040
=========== =========== ===========
</TABLE>
F-16
<PAGE> 46
THE EXPLORATION COMPANY
NOTES TO FINANCIAL STATEMENTS
AUGUST 31, 1997, 1996 AND 1995
NOTE H - SEGMENT INFORMATION AND MAJOR CUSTOMERS
In 1997, the Company operated only in the oil and gas exploration industry. In
1996 and 1995, the Company also operated in the alternative fuels industry.
Operations in the oil and gas industry consist of acquiring, exploring and
developing oil and gas properties. Operations in the alternative fuels industry
were conducted through the Company's ExproFuels division, (see Notes A and I)
and are reported as a separate line item on the balance sheet and statement of
operations.
The Company's oil and gas sales include amounts sold to two major purchasers in
the three years ended August 31, as follows:
<TABLE>
<CAPTION>
Purchaser 1997 1996 1995
------------- --------- --------- ---------
<S> <C> <C> <C>
A $ 732,000 $ 371,000 $ 192,000
B 122,000 31,000 30,000
</TABLE>
NOTE I - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
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.
Year Ended August 31, 1996
The Company issued 2,723,680 shares of its common stock in exchange for oil and
gas properties (valued at the market price per share for unregistered stock).
The Company exchanged a 32.5% mineral property interest for certain oil and gas
properties valued at $225,000, a $100,000 note and certain other assets valued
at $73,403.
Year Ended August 31, 1995
The Company issued 186,731 shares of its common stock to an affiliate in
exchange for $300,000 of oil and gas properties (valued at the historical cost
basis of the common-control affiliate for unregistered stock).
The Company issued 163,496 shares of its common stock in exchange for $413,743
of oil and gas properties (valued at the market price per share for unregistered
stock).
The Company issued 61,212 shares of its common stock to a Director for cash of
$85,731 and a receivable for $72,196. The receivable was fully collected on
November 8, 1995.
F-17
<PAGE> 47
THE EXPLORATION COMPANY
NOTES TO FINANCIAL STATEMENTS
AUGUST 31, 1997, 1996 AND 1995
NOTE J - FOURTH QUARTER ADJUSTMENT (UNAUDITED)
During the fourth quarter of the fiscal year ended August 31, 1997, the Company
made a provision for loan loss of the outstanding balance, accrued interest and
its loan commitment with ExproFuels in the total amount of $845,487. See Note F.
F-18
<PAGE> 48
THE EXPLORATION COMPANY
SCHEDULE II - VALUATION AND QUALIFYING RESERVES
FOR THE THREE YEARS ENDED AUGUST 31, 1997
<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, 1997
Allowance for doubtful accounts -
trade accounts $ 9,973 $ -- $ (9,973) $ --
========== ============ ========== ========
Impairment of loan to ExproFuels, Inc. $ -- $ 845,487 $ -- $845,487
========== ============ ========== ========
YEAR ENDED AUGUST 31, 1996
Allowance for doubtful accounts -
trade accounts $ 9,973 $ -- $ -- $ 9,973
========== ============ ========== ========
YEAR ENDED AUGUST 31, 1995
Allowance for doubtful accounts -
trade accounts $ 9,973 $ -- $ -- $ 9,973
========== ============ ========== ========
</TABLE>
F-19
<PAGE> 49
EXPROFUELS, INC.
CONTENTS
AUGUST 31, 1997
<TABLE>
<CAPTION>
Page
----
<S> <C>
AUDITED FINANCIAL STATEMENTS
Independent Auditors' Report S-1
Balance Sheet S-2
Statements of Operations S-4
Statements of Stockholders' Equity (Deficit) S-5
Statements of Cash Flows S-6
Notes to Financial Statements S-7
</TABLE>
S-0
<PAGE> 50
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
ExproFuels, Inc.
We have audited the balance sheet of ExproFuels, Inc. as of August 31, 1997,
and the related statements of operations, stockholders' equity (deficit) and
cash flows for each of the two years in the period ended August 31, 1997. 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 ExproFuels, Inc. as of August
31, 1997, and the results of its operations and its cash flows for each of the
two years in the period ended August 31, 1997, in conformity with generally
accepted accounting principles.
The financial statements have been prepared assuming that the Company will
continue as a going concern. As discussed in Note B to the financial
statements, the Company has suffered recurring losses from operations since
inception, has a deficiency of current assets to current liabilities of
$478,623, an accumulated deficit in retained earnings of $4,238,600, and a
deficiency in stockholders' equity of $712,464 at August 31, 1997, all of which
raise substantial doubt about the Company's ability to continue as a going
concern. Management's plans concerning these matters are also discussed in Note
B. The financial statements do not include any adjustments that might result
from the outcome of this uncertainty.
AKIN, DOHERTY, KLEIN & FEUGE, P.C.
San Antonio, Texas
November 14, 1997
S-1
<PAGE> 51
SEE NOTES TO FINANCIAL STATEMENTS.
EXPROFUELS, INC.
BALANCE SHEET
AUGUST 31, 1997
<TABLE>
<CAPTION>
<S> <C>
ASSETS
Current Assets:
Cash and equivalents $ 31,647
Accounts receivable, less allowance for doubtful
accounts of $10,000 141,754
Inventories 400,517
Prepaid expenses and other 34,159
----------
Total current assets 608,077
Property and Equipment:
Transportation and other equipment 133,883
Equipment under capital leases 93,326
Fuel stations 280,889
----------
Total property and equipment 508,098
Less accumulated depreciation and amortization (270,436)
----------
Net property and equipment 237,662
Other Assets:
Investments in and advances to CNG, net of provision
for impairment and allowance of $620,658 --
Other assets 45,099
----------
45,099
----------
Total Assets $ 890,838
==========
</TABLE>
S-2
<PAGE> 52
SEE NOTES TO FINANCIAL STATEMENTS.
EXPROFUELS, INC.
BALANCE SHEET
AUGUST 31, 1997
<TABLE>
<CAPTION>
<S> <C>
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Current Liabilities:
Accounts payable and accrued expenses $ 495,468
Current portion of long-term debt-nonaffiliates 8,945
Current portion of long-term debt-affiliates 561,225
Current portion of capital lease obligations 21,062
-----------
Total current liabilities 1,086,700
Long-term Liabilities:
Long-term debt-nonaffiliates 107,946
Long-term debt-affiliates 400,000
Capital lease obligations 8,656
-----------
Total long-term liabilities 516,602
Stockholders' Equity (Deficit):
Common stock, par value $ .01 per share; authorized 50,000,000
shares; issued and outstanding 4,000,000 shares 40,000
Additional paid-in capital 3,486,136
Accumulated deficit (4,238,600)
-----------
Total stockholders' equity (deficit) (712,464)
Total Liabilities and Stockholders' Equity (Deficit) $ 890,838
===========
</TABLE>
S-3
<PAGE> 53
EXPROFUELS, INC.
STATEMENTS OF OPERATIONS
YEARS ENDED AUGUST 31, 1997 AND 1996
<TABLE>
<CAPTION>
1997 1996
------------ -----------
<S> <C> <C>
REVENUES:
Conversion sales $ 643,607 $ 557,641
Fuel station construction sale 148,453 301,115
Alternative fuel sales 333,950 187,645
------------ -----------
1,126,010 1,046,401
COSTS AND EXPENSES:
Cost of sales 1,004,613 752,024
Shop general and administrative 420,983 484,920
Depreciation and amortization 88,654 85,574
General and administrative 583,320 404,708
Impairment of investment in CNG 620,658 --
------------ -----------
Total costs and expenses 2,718,228 1,727,226
------------ -----------
LOSS FROM OPERATIONS (1,592,218) (680,825)
Other Income (Expense):
Sublease rental income 13,500 58,500
Interest income 730 959
Other income 9,667 --
Interest expense (52,321) (23,648)
------------ -----------
(28,424) 35,811
NET LOSS $ (1,620,642) $ (645,014)
============ ===========
PER SHARE DATA:
Net loss per common share $ (.41) $ (.16)
============ ===========
Weighted average number of
common and common equivalent
shares outstanding 4,000,000 4,000,000
============ ===========
</TABLE>
SEE NOTES TO FINANCIAL STATEMENTS.
S-4
<PAGE> 54
EXPROFUELS, INC.
STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)
YEARS ENDED AUGUST 31, 1997 AND 1996
<TABLE>
<CAPTION>
Common Stock Additional
------------------------------- Paid-in Accumulated
Shares Amount Capital Deficit Total
----------- ---------- ----------- ------------ -------------
<S> <C> <C> <C> <C> <C>
BALANCE AT SEPTEMBER 1, 1995 -- $ -- $ -- $ (1,972,944) $ (1,972,944)
Issuance of common stock 4,000,000 40,000 (40,000) -- --
Contribution of capital by
parent -- -- 3,526,136 -- 3,526,136
Net loss for the year -- -- -- (645,014) (645,014)
----------- ---------- ----------- ------------ ------------
BALANCE AT AUGUST 31, 1996 4,000,000 40,000 3,486,136 (2,617,958) 908,178
Net loss for the year -- -- -- (1,620,642) (1,620,642)
----------- ---------- ----------- ------------ ------------
BALANCE AT AUGUST 31, 1997 4,000,000 $ 40,000 $ 3,486,136 $ (4,238,600) $ (712,464)
=========== ========== =========== ============ ============
</TABLE>
SEE NOTES TO FINANCIAL STATEMENTS.
S-5
<PAGE> 55
EXPROFUELS, INC.
STATEMENTS OF CASH FLOWS
YEARS ENDED AUGUST 31, 1997 AND 1996
<TABLE>
<CAPTION>
1997 1996
------------ ----------
<S> <C> <C>
OPERATING ACTIVITIES:
Net loss $ (1,620,642) $ (645,014)
Adjustments to reconcile net loss to net cash
used in operating activities:
Change in allowance for doubtful accounts (25,000) --
Proceeds from sale of equipment 5,816 --
Reserve for impairment and allowance on CNG 620,658 --
Depreciation 80,320 85,574
Amortization 8,334 --
Changes in operating assets and liabilities:
Receivables 37,947 66,775
Inventory (256,550) (40,011)
Prepaid expenses and other (14,813) 6,025
Accounts payable and accrued expenses 239,284 (99,465)
------------ ----------
Net cash (used) in operating activities (924,646) (626,116)
INVESTING ACTIVITIES:
Purchase of property and equipment (48,904) (79,946)
Investments in and advances to CNG (28,232) (442,426)
Other assets (10,112) 10,097
------------ ----------
Net cash (used) in investing activities (87,248) (512,275)
FINANCING ACTIVITIES:
Advances from affiliate 561,225 1,192,095
Proceeds from long-term debt 500,000 --
Payments on long-term debt (38,555) (40,096)
------------ ----------
Net cash provided by financing activities 1,022,670 1,151,999
------------ ----------
INCREASE IN CASH AND EQUIVALENTS 10,776 13,608
Cash and equivalents at beginning of year 20,871 7,263
------------ ----------
CASH AND EQUIVALENTS AT END OF YEAR $ 31,647 $ 20,871
============ ==========
SUPPLEMENTAL DISCLOSURES:
Cash paid for interest $ 27,532 $ 22,636
Cash paid for income taxes -- --
</TABLE>
See notes to financial statements.
S-6
<PAGE> 56
EXPROFUELS, INC.
NOTES TO FINANCIAL STATEMENTS
YEARS ENDED AUGUST 31, 1997 AND 1996
NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and Operations: ExproFuels, Inc. (the Company), formerly a
division of The Exploration Company (TXCO), began operating as a wholly-owned
subsidiary of TXCO August 15, 1996, following the issuance of 4,000,000 shares
of its common stock. The Company converts vehicle engines that use gasoline for
combustion to propane or natural gas, supplies alternative fuels to customers,
and constructs alternative fuels refueling facilities. Customers are primarily
located in Texas and Arizona.
On August 30, 1996, TXCO distributed to it's Directors 400,000 common stock
shares it owned in ExproFuels, Inc. for services rendered, thereby reducing
TXCO's ownership interest from 100% to 90%.
On August 29, 1997, TXCO distributed 1,910,000 common stock it owned in
ExproFuels, Inc. to TXCO stockholders of record as of September 13, 1997. The
effect of the distribution was to reduce TXCO's ownership in ExproFuels, Inc.
to approximately 42%.
The Statement of Operations for the year ended August 31, 1996 includes the
accounts of ExproFuels while operated as a division of TXCO (September 1, 1995
through August 14, 1996) and as a subsidiary of TXCO (August 15, 1996 through
August 31, 1996).
Cash and Equivalents: Cash and cash equivalents consist of all demand deposits
and funds invested in short-term investments with original maturities of three
months or less.
Inventories: Inventories, consisting principally of finished goods (parts), are
valued at the lower of cost or market using the first-in, first-out method of
accounting.
Property and Equipment: Transportation and other equipment, equipment reported
under capitalized leases and fuel stations are recorded at cost. Depreciation
is computed using the straight-line method over the estimated useful lives of
the assets ranging from five to seven years. Major renewals and betterments are
capitalized while repairs are expensed as incurred.
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.
Financial Instruments with Off-Balance-Sheet Risk: Financial instruments that
potentially subject the Company to concentrations of credit risk consist
principally of temporary cash investments and accounts receivables. The Company
places its temporary cash investments with financial institutions and limits
the amount of credit exposure to any one financial institution. The Company's
raw materials are readily available and the Company is not dependent on a
single supplier or a few suppliers. The Company generally requires no
collateral from its customers.
Corporate Expenses: The Company shares office space, office equipment and
certain personnel with TXCO. The Statements of Operations for the years ended
August 31, 1997 and 1996 include all direct and indirect costs of the Company,
incurred either by it or on its behalf by TXCO. The most significant common
expenses have been allocated to the Company generally as follows: a) payroll
and related costs have been allocated on a pro-rata basis using an estimate of
the percentage of time devoted by the personnel (those personnel with
responsibilities for both companies) to TXCO and ExproFuels; b) office costs,
including rents, corporate depreciation and similar charges have been allocated
pro-rata based on a determination of the corporate office square footage used
by each Company's direct personnel to total office square footage. Other
general and administrative charges are not significant, but have generally been
allocated based on a combination of a) and b).
S-7
<PAGE> 57
EXPROFUELS, INC.
NOTES TO FINANCIAL STATEMENTS
YEARS ENDED AUGUST 31, 1997 AND 1996
NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - CONTINUED
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.
Net Loss Per Share: Loss per common and common equivalent share are computed by
dividing net loss by the weighted average number of shares outstanding during
the period. Common stock issued in connection with the Company's incorporation
on August 15, 1996 has been assumed to be outstanding for all periods
presented.
Government Regulations: Substantially all of the Company's facilities 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.
Fair Value of Financial Instruments: The only financial instruments of the
Company at August 31, 1997 and 1996, are cash and equivalents, trade accounts
receivable and payable, and long-term debt. In all cases the carrying amount of
the financial instruments approximates fair value.
Revenue Recognition: The Company recognizes conversion sales and fuel station
construction sales upon completion of the work. Fuel sales are recognized at
the time of the sale.
NOTE B - GOING CONCERN UNCERTAINTY
The accompanying financial statements have been prepared on a going concern
basis, which contemplates the realization of assets and the satisfaction of
liabilities in the normal course of business. Since its inception, the Company
has been substantially reliant on The Exploration Company to fund its cash
requirements. As shown in the financial statements, the Company has suffered
recurring losses, has a deficiency of current assets to current liabilities of
$478,623, an accumulated deficit in retained earnings of $4,238,600 at August
31, 1997, and a deficiency in stockholders' equity of $712,464. These factors,
among others, raise substantial doubt about the Company's ability to continue
as a going concern. The financial statements do not include any adjustments
relating to the recoverability and classification of recorded asset amounts or
the amounts and classification of liabilities that might be necessary should
the Company be unable to continue as going concern.
Management is seeking alternatives, including raising additional debt or equity
financing. See Note D. The Company's ability to continue to operate is
dependent upon successfully accomplishing some or all of these or other
alternatives, and ultimately to attain profitable operations.
NOTE C - INVESTMENTS IN AND ADVANCES TO CNG INTERNATIONAL
The Company has invested $620,658 at August 31, 1997 in CNG International,
L.L.C., a Tennessee company formed for the purpose of converting motor vehicles
to operate on alternative fuels, manufacturing and selling of related component
equipment and to develop the necessary infrastructure to support operation of
motor vehicles on alternative fuels primarily in Uzbekistan, a former Soviet
Republic. The total investment of $620,658 is composed of an equity investment
of $381,123 and accounts receivable of $239,535. At August 31, 1997,
ExproFuels, Inc. owned an 11% interest in CNG International and accounted for
its ownership interest using the cost method of accounting.
S-8
<PAGE> 58
EXPROFUELS, INC.
NOTES TO FINANCIAL STATEMENTS
YEARS ENDED AUGUST 31, 1997 AND 1996
NOTE C - INVESTMENTS IN AND ADVANCES TO CNG INTERNATIONAL - CONTINUED
In July, 1997, management became aware that its relationship with the majority
owners of CNG International had deteriorated to the level whereby the Company
filed suit in federal court to force payment of its accounts receivable of
$239,535. The majority owners of CNG International in turn countersued
ExproFuels, Inc. claiming, among other things, breach of contracts. The Company
is vigorously contesting the countersuit, and management believes it will
ultimately be successful in the legal claims. However, management has concluded
its investment in CNG International of $381,123 is at risk, and timely or
ultimate collection of its account receivable of $239,535 is doubtful.
Accordingly, at August 31, 1997 the Company has fully impaired its investment
of $381,123 and allowed for its accounts receivable of $239,535.
NOTE D - LONG TERM DEBT
Long-term debt and capitalized lease obligations consist of the following at
August 31, 1997:
<TABLE>
<S> <C>
Notes payable to financial institutions, with interest rates from 8.50% to
12%,due in monthly installments of $901
and secured by certain vehicles. $ 16,891
Capital lease obligations, with imputed interest rates from 16.21% to
19.82%, due in monthly installments of $2,349
and secured by related leased equipment. 29,718
Convertible notes payable with interest at 6%, interest due quarterly and
principal due from July, 1999 to February,
2000. See below. 500,000
Notes payable to affiliate with interest at 8%, due on demand
and unsecured. See below. 561,225
----------
Total long-term debt and capitalized lease obligations 1,107,834
Less current portion 591,232
----------
Long-term portion of debt and capitalized lease obligations $ 516,602
==========
</TABLE>
Convertible Notes Payable: During the current year, the Company issued four
separate unsecured convertible debentures, all with identical terms, except for
the due date, if not converted. Each debenture requires quarterly interest
payments computed at 6%, and are convertible at the payee's option into common
stock of the Company at the rate of $1 of debt to 1 share of common stock. The
Company has the right to force conversion if it attains $2,000,000 in total
assets. The convertible debentures were issued to parties related to the
Company ($400,000) and to an unrelated third party ($100,000), and, if not
converted, are due from September 18, 1999 to April 11, 2000.
Notes Payable to Affiliate: During the current year the Company's former
parent, TXCO, made advances to it under a note agreement in the total amount of
$561,225. The debt accrues interest at 8% and is due in full on December 31,
1998, but may be demanded by TXCO at any time.
S-9
<PAGE> 59
EXPROFUELS, INC.
NOTES TO FINANCIAL STATEMENTS
YEARS ENDED AUGUST 31, 1997 AND 1996
NOTE D - LONG TERM DEBT - CONTINUED
The following is a schedule of principal maturities of long-term debt and
capital lease obligations as of August 31, 1997:
<TABLE>
<CAPTION>
Fiscal Year Ended
August 31 Debt Leases Total
--------------------- ------------ ----------- -----------
<S> <C> <C> <C> <C>
1998 $ 570,170 $ 21,062 $ 591,232
1999 205,839 8,656 214,495
2000 302,107 -- 302,107
------------ ----------- -----------
$ 1,078,116 $ 29,718 $ 1,107,834
============ =========== ===========
Future minimum rentals under all capital leases are as follows:
1998 $ 28,212
1999 7,615
-----------
Total minimum rentals 35,827
Less amount representing interest,
executory costs and profit 6,109
Present value of capital lease obligations $ 29,718
===========
</TABLE>
NOTE E - STOCKHOLDERS' EQUITY
Preferred Stock: The Company has authorized 10,000,000 shares of preferred
stock, none of which is issued. Terms and rights 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 1996 Flexible Incentive Plan. The Company has elected to
follow Accounting Principles Board Opinion No. 25, "Accounting 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, "Accounting 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 stock option plans have authorized the grant of options to
management, directors, and key personnel for up to 400,000 shares of the
Company's common stock. All options granted have ten year terms and vest and
become fully exercisable based on the specific terms imposed at the date of
grant, generally ranging up to three years from the date of the 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 1997
and 1996, respectively: risk-free interest rates of 6.25% and 6.25%; dividend
yields of -0-% and -0-%; volatility factors of the expected market price of the
Company's common stock of .300 and .300; and a weighted-average expected life
of the option of five years.
S-10
<PAGE> 60
EXPROFUELS, INC.
NOTES TO FINANCIAL STATEMENTS
YEARS ENDED AUGUST 31, 1997 AND 1996
NOTE E - 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>
1997 1996
------------ ----------
<S> <C> <C>
Pro forma net (loss) $ (1,620,642) $ (645,014)
Pro forma net loss per common share $ (0.41) $ (0.16)
</TABLE>
A summary of the status of the Company's stock option plan as of August 31,
1997 and 1996, and changes during the fiscal years then ending, is presented
below:
<TABLE>
<CAPTION>
1997 1996
------------------------------- ------------------------------
Weighted-Average Weighted-Average
Shares Exercise Price Shares Exercise Price
---------- ---------------- --------- ----------------
<S> <C> <C> <C> <C>
Outstanding options at beginning of year -- $ -- $ --
Granted 300,000 0.15 -- --
Exercised -- -- -- --
Forfeited -- -- -- --
---------- ---------- --------- --------
Outstanding options at end of year 300,000 $ 0.15 -- $ --
========== ========== ========= ========
Options exercisable at end of year 0 N/A -- $ --
========== ========== ========= ========
Weighted-average fair value of
options granted during the year* $ -- $ --
========== ========
</TABLE>
* Due to the Company's financial condition at date of grant and August 31,
1997, the options granted have a determined fair value of $0.
The following table summarizes information about the options outstanding at
August 31, 1997:
<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>
$ 0.15 300,000 9 years $ 0.15 0 N/A
</TABLE>
S-11
<PAGE> 61
EXPROFUELS, INC.
NOTES TO FINANCIAL STATEMENTS
YEARS ENDED AUGUST 31, 1997 AND 1996
NOTE F - OPERATING LEASES
The Company shares office space with TXCO and pays to them $4,725 per month for
the use of office space and equipment. In addition, the Company leases from
nonaffiliates its conversion facilities and a fuel station location under
noncancellable leases with terms from one to three years.
For the years ended August 31, 1997 and 1996, the Company incurred rent expense
of $120,925 and $141,996, respectively and received sublease rental income of
$13,500 in 1997 and $58,500 in 1996. Future minimum rentals under all
noncancellable operating leases are as follows at August 31, 1997:
<TABLE>
<S> <C>
1998 $ 34,800
1999 22,500
---------
Net future minimum rentals $ 57,300
=========
</TABLE>
NOTE G - FEDERAL INCOME TAXES
The Company began operating as a corporation on August 15, 1996; accordingly,
its tax attributes began on that date.
Deferred taxes are as follows at August 31, 1997:
<TABLE>
<S> <C>
Deferred tax assets:
Net operating loss carryforwards $ 1,650,000
Statutory tax rate 34%
---------------
Net deferred tax asset 561,000
Less valuation allowance (561,000)
Deferred income tax asset recorded $ --
===============
</TABLE>
The net operating loss carryforwards expire $27,000 in 2011 and $1,623,000 in
2012.
NOTE H - RELATED PARTY TRANSACTIONS
On August 31, 1996, 10% of the outstanding common stock of the Company
previously held by TXCO was given as consideration for services rendered to the
Directors of ExproFuels, Inc.
During fiscal year 1997, TXCO advanced the Company $561,225 under a note
agreement. See Note D.
During fiscal year 1997, related parties advanced the Company $400,000 under
convertible debenture agreements. See Note D.
S-12
<PAGE> 62
EXPROFUELS, INC.
NOTES TO FINANCIAL STATEMENTS
YEARS ENDED AUGUST 31, 1997 AND 1996
NOTE I - MAJOR CUSTOMERS
Sales to major customers are as follows for the years ended August 31:
<TABLE>
<CAPTION>
Customer 1997 1996
------------ ------------ ---------
<S> <C> <C>
A $ 176,235 $ --
B 119,181 --
C 108,425 83,663
D 20,302 259,438
E -- 86,110
</TABLE>
S-13
<PAGE> 63
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
Exhibit Number Description
- -------------- -----------
<S> <C>
27.1 Financial Data Schedule
</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,
1997, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH THE EXPLORATION
COMPANY FORM 10-K FOR THE YEAR ENDED AUGUST 31, 1997.
</LEGEND>
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> AUG-31-1997
<PERIOD-START> SEP-01-1996
<PERIOD-END> AUG-31-1997
<CASH> 6,198,069
<SECURITIES> 0
<RECEIVABLES> 362,426
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 6,609,579
<PP&E> 15,186,240
<DEPRECIATION> 754,658
<TOTAL-ASSETS> 21,652,726
<CURRENT-LIABILITIES> 2,848,931
<BONDS> 4,033,025
0
0
<COMMON> 147,592
<OTHER-SE> 14,623,178
<TOTAL-LIABILITY-AND-EQUITY> 21,652,726
<SALES> 1,083,511
<TOTAL-REVENUES> 1,083,511
<CGS> 2,272,061
<TOTAL-COSTS> 3,210,699
<OTHER-EXPENSES> 1,215,259
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 339,881
<INCOME-PRETAX> (3,398,866)
<INCOME-TAX> 0
<INCOME-CONTINUING> (3,398,866)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (3,398,866)
<EPS-PRIMARY> (.27)
<EPS-DILUTED> 0
</TABLE>
