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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark one)
|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2000
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 0-9120
THE EXPLORATION COMPANY OF DELAWARE, INC.
(Exact name of Registrant as specified in its charter)
DELAWARE 84-0793089
(State or other.jurisdiction of (I.RS. 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 $49,741,782
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 March 1, 2001.
The number of shares outstanding of the Registrant's Common Stock as of
March 15, 2001 was 17,471,849 of which 15,014,121 shares were held by
non-affiliates.
Documents Incorporated by Reference: None
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INDEX AND
CROSS REFERENCE SHEET
PART I Page
Item 1. Business..................................................................................... 3
Item 2. Properties................................................................................... 10
Item 3. Legal Proceedings............................................................................ 16
Item 4. Submission of Matters to a Vote of Security Holders.................................. 16
PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters.................................................................. 17
Item 6. Selected Financial Data...................................................................... 17
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations........................................................................ 18
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.............................. 24
Item 8. Consolidated Financial Statements and Supplementary Data....................... 24
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure......................................................................... 24
PART III
Item 10. Directors and Executive Officers of the Registrant................................ 25
Item 11. Executive Compensation....................................................................... 26
Item 12. Security Ownership of Certain Beneficial Owners
and Management............................................................................... 29
Item 13. Certain Relationships and Related Transactions............................................... 30
PART IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K.......................................................................... 31
Signatures................................................................................................ 33
Audited Consolidated Financial Statements of The Exploration Company................................... F-1
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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 and became publicly held through an
offering of its common stock in November, 1979. In May 1999, the Company changed
its state of incorporation from Colorado to Delaware, becoming The Exploration
Company of Delaware, Inc. The Company continues doing business as The
Exploration Company and its trading symbol on the Nasdaq Stock MarketSM remains
TXCO. Effective in January 2000, the Company changed its annual reporting period
from a fiscal year ending August 31 to a calendar year ending December 31.
Throughout its history, the Company's primary focus has been oil and gas
exploration and production. Its long term business strategy has been to acquire
undeveloped mineral interests and to develop a multi-year inventory of drilling
prospects internally through the application of state of the art technologies,
such as 3-D seismic and enhanced horizontal drilling techniques. The Company
strives to discover, develop and/or acquire more oil and gas reserves than it
produces each year from these internally-developed prospects, as well as
selectively participating with industry partners in prospects generated by TXCO
as well as by other parties. The Company also attempts to maximize the value of
its technical expertise by contributing its geological, geophysical and
operational knowledge base in its core areas through joint ventures or other
forms of strategic alliances with well capitalized industry partners in exchange
for carried interests in seismic acquisitions, leasehold purchases and/or wells
to be drilled. From time to time, the Company offers portions of its developed
and undeveloped mineral interests for sale. The Company finances its activities
through a combination of internally generated cash flow, debt financing, equity
offerings or sale of interests in properties.
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 mineral interests it acquired through its leasing
activities. From 1992 through 1996 the Company expanded its activities by
entering the then emerging alternative fuels vehicle conversion business through
the creation of its ExproFuels division. In 1996, Management redirected its
focus and resources to its core oil and gas exploration and production business.
Accordingly, the ExproFuels division was incorporated and a majority equity
interest spun-off via a stock dividend to TXCO shareholders.
The continued availability of new equity and debt capital in fiscal years 1997
through 2000 reaffirm Management's ongoing strategy for improved shareholder
value by maintaining its focus on its core business of gas and oil exploration
and production. This strategy has allowed the Company to attract
well-capitalized industry partners, expand its core area leasehold acreage,
increase its 3-D seismic database, dramatically grow its production base and
attain profitability by growing through its drill bit success. During the year
ended December 31, 2000, the Company realized the best operating results in its
21 year history, maintaining profitability throughout the year, and ending its
record breaking year 2000 with revenues of over $14,731,000 and net income of
$6,761,000. Net income for 2000 includes the impact of a deferred federal income
tax benefit of $5,231,000 reflecting the cumulative future tax benefit of a
portion of its net operating loss carry forwards from past losses.
The following table illustrates various aspects of the Company's growth over
the last 4 fiscal years ended:
Dec-2000 Aug-1999 Aug-1998 Aug-1997
-------- -------- -------- --------
No. of new gas wells added 6 6 4 4
Gas Production in Mcf 2,965,000 2,813,000 713,752 206,059
Gas Reserve Additions (Mcf) from drilling 2,126,000 2,803,000 4,541,500 1,147,345
Operating Revenues $14,731,116 $ 7,497,375 $ 3,048,277 $ 1,085,511
Net Income (Loss) $ 6,761,935 $ 931,545 ($ 8,417,218) ($ 3,398,866)
Net cash provided from operations $ 6,529,838 $ 3,858,204 ($ 1,185,050) ($ 378,270)
Non-dev Texas acreage leased 365,000 95,000 56,000 56,000
Non-dev-Williston Basin acreage leased 302,000 380,000 543,000 501,000
Over the last four years, TXCO has grown its natural gas production base
significantly. This overall growth is primarily attributable to ongoing drilling
activities and the acquisition of significant new leasehold acreage in the
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Company's core area of operations, the Maverick Basin of South Texas. The growth
is also reflected in the changed mix in leasehold: expansion in Texas acreage
acquisitions, versus reduction in the Williston acreage through expiration or
maturing leases. During the same periods, operating revenues were significantly
impacted by commodity price fluctuations, as the industry struggled to regain
its momentum after the crash in oil and gas prices in 1997. Average gas prices
per Mcf ranged from $2.65 in 1997, dropping steadily to $2.07 per Mcf in 1999,
before spiking to record levels, doubling to $4.10 for the current year average.
Success in growing the Company's production levels through drilling brought
operating profitability for the first time in TXCO's recent history, overcoming
1999's erratic commodity prices. The improvements in gas prices during 2000 and
the current winter grew its profitability and provided the Company with record
levels of cash flow from operations. While 1999 and 2000 drill bit reserve
replacement rates did not keep pace with the respective years' production
levels, they compared favorably to the 1999 domestic industry wide replacement
rate of 58% as published by the U.S. Department of Energy. The decline in
production was also indicative of the maturing profile of the Company's existing
Glen Rose reef gas wells, its primary source of gas production.
TXCO is pursuing multiple opportunities in 2001 to diversify its exploration
targets within its core area of operations by aggressively expanding its
surrounding lease holding where geology indicates the likely continuation of
known gas producing formations as well as the strong likelihood of establishing
new gas production from additional formations. The Maverick Basin offers this
diversity in its multiple hydrocarbon bearing formations. During 1999 and 2000,
the Company made significant strides in identifying and pursuing the exploration
of two new promising exploration targets, as well as continuing its exploration
for Glen Rose reef-based gas production. TXCO has succeeded in positioning
itself at the forefront of exploration for CBM (coal bed methane gas)
production, and believes it became the largest holder of CBM prospective acreage
in Texas by the end of 2000. An exploratory core and well drilling program for
CBM was initiated in 2000, with significant expansion plans for 2001, including
funding for at least 36 wells and a related gas gathering system targeting
multiple seams of high-volitile bituminous coal present under a 250,000 acres
portion of its leases.
The second diversification program targets the deep Jurassic interval located
under most of TXCO's 365,000 acreage block at the base of the Maverick Basin. A
new 3-D seismic acquisition program was completed at year end 2000 by TXCO's
operating partner, Blue Star Oil and Gas Ltd. (Blue Star), further delineating
the world class hydrocarbon potential of this under explored rift basin. The
Company cautiously expects significant progress towards the drilling of the
initial well on its Paloma lease to test this deep interval during the year
2001. In February 2001, the Company unveiled a new partnership restricted to the
deep rights below the San Miguel under its 100,000 acre Comanche prospect with
an additional set of industry partners, including Saxet Energy (20% WI) of
Houston and a large Denver-based publicly traded independent exploration company
(30% WI). The immediate focus of the venture is the ongoing acquisition of 3-D
seismic data across 78 square miles of the acreage. Drilling for significant
gas-bearing Glen Rose reefs should follow prior to year end. Should these
exploration and development plans progress as intended, The Exploration Company
expects these programs to cause it to resume its growth in gas reserves and
production levels, while insuring ongoing increases in revenues and
profitability.
PRINCIPAL AREAS OF ACTIVITY
OIL AND GAS OPERATIONS
Throughout the year, the Company has been actively developing its core mineral
interests in the Maverick Basin in South Texas, while evaluating its economic
alternatives related to its remaining properties in the Williston Basin in North
Dakota, South Dakota and Montana. These activities included participation in the
drilling or recompletion of 26 gas wells in South Texas during 2000 and 1 well
in the Williston Basin. The increase in Maverick Basin drilling activity
reflects the Company's continued ability to generate sufficient working capital
from profitable internal operations and from industry sources, allowing for
expansion of its Texas-based lease acreage holdings and natural gas exploration
and production activities. Stable Maverick Basin gas production during 2000
combined with dramatically increasing gas prices resulted in improved positive
cash flows for the year. Although crude oil prices also stabilized during the
year, industry activity or interest has not returned to pre-1998 levels in the
area of the Williston Basin where the Company's leases are located. The
Company's strategy remains focused on its core gas producing and exploration
activities in the Maverick Basin.
MAVERICK BASIN
The Company has owned at least a 50% leasehold interest in a minimum of 50,000
contiguous acres in Maverick County, Texas since 1989. These holdings have
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increased to 365,000 acres through 2000. Originally the lease block consisted of
two leases, the Paloma with 33,000 acres and the Kincaid with 17,000 acres. The
lease block is situated on the Chittim Anticline, a large regional structure,
under which hydrocarbons have been found in as many as seven separate horizons
dating back over 65 years. One of these zones is the Lower Glen Rose or Rodessa
interval. It is a carbonate formation that has produced billions of cubic feet
of natural gas from patch reefs within the zone. Past development in the area
was halted due to the inability of previous operators to accurately predict the
location of these porosity-bearing reefs. Utilizing new technological advances,
the Company applied an innovative processing method to the 2-D seismic available
in the area and confirmed a method of locating these porosity intervals.
Between 1993 and 1998, the Company expanded its in-house geophysical database to
include multiple 3-D seismic surveys totaling over 55 square miles, covering
approximately 36,000 acres of its Maverick Basin leases. Company geologists and
geophysicists conclusively identified and mapped numerous geological formations
at various depths on its leases. The mapping has provided numerous drilling
alternatives for future evaluation of the multiple horizons known to be
productive for oil and/or gas within and around its leases in the Maverick
Basin. Consistent with the capital resources available, the Company has been
selectively developing the Glen Rose interval. The shallower intervals provide
alternative completion targets while pursuing the underlying reefs.
From 1989 to 1998, TXCO participated in the drilling of 26 wells in the Maverick
Basin, with increasing degrees of drilling success. By the end of 1998, TXCO's
daily net gas production from its Maverick Basin properties reached 1.96 MMcf
(million cubic feet) from 16 gas wells. While successful in locating Glen Rose
patch reefs, the Company's geologists and geophysicists could not distinguish
between those containing hydrocarbons and those containing water. Management
continued to review technical data gained with the drilling of each well, to
modify its seismic interpretation model and improve its ability to distinguish
between water-filled reefs and gas-filled reefs in expanding the geologically
defined area known as the Prickly Pear Field. During 1998, 6 new gas well
discoveries in succession on the Paloma Lease extended the Prickly Pear Field by
several miles north and east of its previous recognized boundaries. The 6 wells
produced gross daily production volumes ranging from 1 MMcf to 4 MMcf per well.
Fiscal year 1999 brought a continuation of growth in new production and revenues
for the Company, as well as the expansion of TXCO's leasehold position over the
Maverick Basin. During 1999, the Company acquired interests in over 39,000 acres
of additional oil and gas leases in the immediate areas surrounding its Maverick
Basin production, bringing its total lease position to approximately 90,000
acres at year end. During the year, TXCO participated in drilling 10 gas
prospects, resulting in 5 new gas wells, further expanding the known producing
area of the Prickly Pear Field on the Company's Paloma lease. Four of the other
wells were drilled on leases acquired during fiscal 1999, while one was located
on the Company's Kincaid lease. All 5 of these stepout wells were at least 5 to
9 miles from the nearest Prickly Pear Field production. Their drilling resulted
in 2 completed oil wells and 1 completed gas well during 1999. Of the other 2
step out wells, one was completed as a marginal gas producer in 2000, while the
other completion was not economic and remains shut-in pending its conversion for
use as a salt water disposal well.
The turn of the century brought many changes for TXCO. Effective January 1, 2000
the Company adopted a calendar year end of December 31, leaving the fiscal year
end of August 31. During the 4 month transition period from August 31 thru
December 31, 1999, TXCO initiated drilling on 3 gas prospects, one each on the
Paloma, Chittim and Alkek leases. This drilling resulted in 1 new gas reef well
on the Paloma lease, 1 marginal gas well on the Chittim lease and 1 non-economic
well on the Alkek lease which was plugged and abandoned. 3-D seismic acquisition
also progressed during this period, as the Company completed the acquisition of
an additional 31,700 acres of seismic data over a portion of newly leased
acreage contiguous and north of its Paloma lease. At January 1, 2000, leased
acreage totaled approximately 115,000 acres. During the transition period, TXCO
also completed negotiations and entered into a joint operating agreement with
Blue Star Oil and Gas, Ltd., for the development of its deep Jurassic prospect
underlying its Paloma and Kincaid leases.
Calendar year 2000 marked a year of dramatic growth in numerous directions for
TXCO as leasehold acreage, operating revenues and operating profits all reached
record levels. During 2000, the Company's Maverick Basin core area lease block
grew to over 365,000 acres primarily due to two transactions. The Company
acquired lease interests consisting of all depths under 95,000 acres on the
Comanche Ranch in March plus an option to lease the shallow depths above the
base of the San Miguel formation on 150,000 acres on the adjoining Chittim Ranch
in June. Both leases are prospective for CBM production and various shallow oil
and gas bearing zones above the base of the San Miguel formation. In addition,
the Comanche lease covers all depths including the deep Jurassic interval. The
Chittim lease option was exercised in January, 2001.
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TXCO expanded its exploration efforts by participating in drilling a total of 25
new gas, oil or CBM prospects and 2 re-entries during the 2000. Of the drilling
wells, 5 have been completed as producers, with 2 Paloma gas wells, 1 marginal
Kincaid oil well, 1 marginal Chittim gas well and 1 marginal Chittim oil well.
Both of the re-entry attempts resulted in marginal completions, including 1
Chittim gas well and 1 Paloma oil well. A total of 14 wells remained in progress
at year end. Included were 7 new CBM wells involved in the initial stages of an
ongoing dewatering pilot program on the Comanche lease. Of the remaining 7
wells, 1 Burr gas well and 1 Burr oil well were completed during the first
quarter of 2001, while the remaining 5 wells are in varying stages of completion
and include 2 Paloma wells, and 1 well each on the Alkek and Wipff lease in
Texas and the Hutzenbiler lease in North Dakota.
At year end December 2000, TXCO's daily net gas production from its Maverick
Basin properties was 7.4 MMcf of the total gross operated production of 17.0
MMcf from 29 gas wells. At current gas prices, this production level should
allow the Company to internally generate sufficient working capital to fund its
fiscal year 2001 development plans. The expanding geophysical database,
historical drilling results and the evolving family of prospective formations
targeted by the Company and its partners continue to support the Company's
longstanding belief that it has significant exploration and development
possibilities remaining on its expanding Maverick Basin lease block. At year end
2000, the Company owned leases and options totaling over 365,000 acres. Included
in this total were options for 150,000 acres which were exercised in January
2001. Through 2000, the Company has accumulated 231 square miles of 3-D seismic
data over much of its Maverick Basin lease block, with evidence of 40 additional
porosity-bearing Glen Rose patch reefs scattered across its extensive acreage
position. The Company's Comanche Ranch acreage acquisition in the first quarter
of 2000 included access to 70 miles of 2-D seismic data that indicate the
existence of 45 additional Glen Rose Reef locations. Based on current drilling
activity rate, these 85 patch reefs represent a potential four to five year
drilling inventory of new gas well prospects .
JURASSIC FORMATION
Fiscal 1999 marked the year that the Company's concerted efforts resulted in a
new partnership to explore the potential of the Jurassic formation under its
lease block. Fiscal 2000 showed marked progress in expanding the 3-D seismic
database over a much larger portion of the Maverick Basin.
Commencing in September 1999, Blue Star designed the 3-D seismic acquisition
program over the 426 square mile area of the Maverick Basin targeted by the
venture. The initiation of field data acquisition work followed and continued
through the year. While interrupted by unseasonably wet conditions through part
of the year, the extensive data acquisition portion of the project was completed
late in the third quarter of 2000. In November, pursuant to its exploration
joint venture with the Company, Blue Star confirmed that it had completed its
seismic data acquisition phase and was performing the required seismic
processing on the entire 426 square miles of 3-D seismic data, including all of
the intended TXCO leases and Blue Star's Chittim Ranch lease. By year end, Blue
Star had also shared with TXCO's Jurassic project management team its
preliminary results from the data migration, processing and initial
interpretation of the new data. Based on the encouraging preliminary
interpretations of the 3-D seismic data available to it, Blue Star continued to
indicate it anticipated beginning preparations to drill the first Jurassic test
well on TXCO's Maverick Basin acreage during the first or second quarter of
2001. On March 13, 2001 Blue Star's senior executives contacted TXCO management
and announced they were applying enhanced 3-D seismic processing techniques on
the seismic field data. Blue Star further advised that the expanded seismic
processing would take several months to finalize and could cost them an
additional $1 million. See further discussion on the most recent developments
relating to the Jurassic Blue Star project as set forth in ITEM 2. PROPERTIES -
Drilling Activity - Maverick Basin.
WILLISTON BASIN
At August 31, 1999 TXCO retained approximately 263,000 net acres of its original
position in oil and gas leases in the Williston Basin in North Dakota, South
Dakota and Montana. The Company participated in drilling a total of 14 wells
during fiscal 1997 through 1998 in attempts to establish economic production and
develop oil and gas reserves in the Red River and Lodgepole formations. Drilling
activities were commenced prior to the collapse of oil and gas prices in late
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1997 and early 1998 and were suspended by the end of 1998. During this same
period, TXCO accumulated over 1,100 miles of 2-D seismic and approximately 64
square miles of 3-D seismic data covering approximately 40,800 acres of selected
portions of its acreage in the Williston Basin. No new drilling was conducted by
the Company in the Williston Basin during 1999 due to the continued unfavorable
economic climate in the region for the type of drilling prospects available to
the it. The weakness in crude oil prices rendered the production of marginal
levels of oil with high associated water production, as is typical of many wells
in the Basin, uneconomical for the Company to explore or produce.
The Company elected to participate in drilling 1 well (.015% WI) late in 2000.
The outside operated well was proposed on a spacing unit in which TXCO owned a
minor interest which it contributed to the unit. The well was still in progress
at year end. Throughout 2000, the Company continued to re-evaluate all of its
Williston Basin lease obligations, making lease extension payments on a
selective basis, emphasizing those leases with particular geologic attributes or
with adequate remaining primary lease terms. For the year ended December 31,
2000, the Company's interests produced a total daily average of 90 net barrels
of crude oil per day from 4.26 net wells.
At December 31, 2000, TXCO retained approximately 219,000 net acres of its
original position. The Company has established adequate provisions for
impairment allowances as required for expected year 2001 lease expirations.
Consistent with Management's decision to refocus its exploration efforts and
resources on the development of its core producing area in South Texas, TXCO has
initiated a focused marketing effort to present its remaining Williston Basin
holdings, complemented by an extensive seismic database, for sale to other
exploration companies with a focus on this area. With the recent improvement in
crude oil prices, reaching over $27.00 during the 1st quarter of 2001,
Management is cautiously optimistic that renewed industry interest in the area
will assist it in its efforts to monetize its remaining area holdings.
PRINCIPAL PRODUCTS AND COMPETITION
The Company's principal products are natural gas and crude oil. The production
and marketing of oil and gas are affected by a number of factors that are beyond
the Company's control, the effect of which cannot be accurately predicted. These
factors include crude oil imports, actions by foreign oil-producing nations, the
availability of adequate pipeline and other transportation facilities, the
marketing of competitive fuels and other matters affecting the availability of a
ready market, such as fluctuating supply and demand. The Company sells all of
its oil and gas under short-term contracts that can be terminated with 30 days
notice, or less. None of the Company's production is sold under long-term
contracts with specific purchasers. Consequently, the Company is able to market
its oil and gas production to the highest bidder each month. The Company
operates and directs the drilling of oil and gas wells. It contracts service
companies, such as drilling contractors, cementing contractors, etc., for
specific tasks. In some wells, the Company only participates as an overriding
royalty interest owner.
During 2000, three purchasers of the Company's oil and gas production accounted
for 28%, 26% and 18%, respectively, of total oil and gas sales. In the event any
of these major customers declined to purchase future production, the Company
believes that alternative purchasers could be found for such production at
comparable prices.
The oil and gas industry is highly competitive in the search for and development
of oil and gas reserves. The Company competes with a substantial number of major
integrated oil companies and other companies having materially greater financial
resources and manpower than the Company. These competitors, having greater
financial resources than the Company, have a greater ability to bear the
economic risks inherent in all phases of this industry. In addition, unlike the
Company, many competitors produce large volumes of crude oil that may be used in
connection with their operations. These companies also possess substantially
larger technical staffs, which puts the Company at a significant competitive
disadvantage compared to others in the industry.
EMPLOYEES
As of December 31, 2000, the Company employed 14 full-time employees including
management. The Company believes its relations with its employees are good. None
of the Company's employees are covered by union contracts.
GENERAL REGULATIONS
The extraction, production, transportation, and sale of oil, gas, and minerals
are regulated by both state and federal authorities. The executive and
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legislative branches of government at both the state and federal levels have
periodically proposed and considered proposals for establishment of controls on
alternative fuels, energy conservation, environmental protection, taxation of
crude oil imports, limitation of crude oil imports, as well as various other
related programs. If any proposals relating to the above subjects were to be
enacted, the Company is unable to predict what effect, if any, implementation of
such proposals would have upon the Company's operations. A listing of the more
significant current state and federal statutory authority for regulation of the
Company's current operations and business are provided herein below.
FEDERAL REGULATORY CONTROLS
Historically, the transportation and sale for resale of natural gas in
interstate commerce have been regulated pursuant to the Natural Gas Act of 1938
(the "NGA"), the Natural Gas Policy Act of 1978 (the "NGPA") and the regulations
promulgated thereunder by the Federal Energy Regulatory Commission ("FERC").
Maximum selling prices of certain categories of natural gas sold in "first
sales," whether sold in interstate or intrastate commerce, were regulated
pursuant to the NGPA. On July 26, 1989, the Natural Gas Wellhead Decontrol Act
(the "Decontrol Act") was enacted, which removed, as of January 1, 1993, all
remaining federal price controls from natural gas sold in "first sales." The
FERC's jurisdiction over natural gas transportation was unaffected by the
Decontrol Act.
Commencing in April 1992, the FERC issued Order Nos. 636, 636-A and 636-B
(collectively "Order No. 636"), which required interstate pipelines to provide
transportation, separate or "unbundled," from the pipelines' sales of gas.
Although Order No. 636 did not directly regulate the Company's activities, it
fostered increased competition within all phases of the natural gas industry.
In December 1992, the FERC issued Order No. 547, governing the issuance of
blanket marketer sales certificates to all natural gas sellers other than
interstate pipelines. The order applies to non-first sales that remain subject
to the FERC's NGA jurisdiction. The FERC Order No. 547, in tandem with Order No.
636, has fostered a competitive market for natural gas by giving natural gas
purchasers access to multiple supply sources at market-driven prices. Order No.
547 has increased competition in markets in which the Company's natural gas is
sold. The natural gas industry historically has been very heavily regulated;
therefore, there is no assurance that the less stringent regulatory approach
pursued by the FERC and Congress will continue.
STATE REGULATORY CONTROLS
In each state where the Company conducts or contemplates conducting oil and gas
activities, such activities are subject to various state regulations. In
general, the regulations relate to the extraction, production, transportation
and sale of oil and natural gas, the issuance of drilling permits, the methods
of developing new production, the spacing and operation of wells, the
conservation of oil and natural gas reservoirs and other similar aspects of oil
and gas operations. In particular, the State of Texas (where the Company has
conducted the majority of its oil and gas operations to date) regulates the rate
of daily production allowable from both oil and gas wells on a market demand or
conservation basis. At the present time, no significant portion of the Company's
production has been curtailed due to reduced allowables. The Company knows of no
newly proposed regulations, which will significantly curtail its production.
Environmental Regulation
The Company's extraction, production and drilling operations are subject to
environmental protection regulations established by federal, state, and local
agencies. To the best of its knowledge, the Company believes that it is in
compliance with the applicable environmental regulations established by the
agencies with jurisdiction over its operations. The Company is acutely aware
that the applicable environmental regulations currently in effect could have a
material detrimental effect upon its earnings, capital expenditures, or
prospects for profitability. The Company's competitors are subject to the same
regulations and therefore, the existence of such regulations does not appear to
have any material effect upon the Company's position with respect to its
competitors. The Texas Legislature has mandated a regulatory program for the
management of hazardous wastes generated during crude oil and natural gas
exploration and production, gas processing, oil and gas waste reclamation and
transportation operations. The disposal of these wastes, as governed by the
Railroad Commission of Texas, is becoming an increasing burden on the industry.
The Company's operations in Montana, North Dakota and South Dakota are subject
to similar environmental regulations including archeological and botanical
surveys as some of its leases are on federal and state lands.
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FEDERAL AND STATE TAX CONSIDERATIONS
Revenues from oil and gas production are subject to taxation by the state in
which the production occurred. In Texas, the state receives a severance tax of
4.6% for oil production and 7.5% for gas production. North Dakota production
taxes typically range from 9.0% to 11.5% while Montana's taxes range up to
17.2%. These high percentage state taxes can have a significant impact upon the
economic viability of marginal wells that the Company may produce and require
plugging of wells sooner than would be necessary in a less arduous taxing
environment. For Federal Income Tax purposes, the Company has net operating loss
carryforwards of $16,100,000 which are scheduled to expire in 2006 - 2015.
During 2000, the Company recognized a deferred federal income tax benefit of
$5,231,000 reflecting the cumulative future tax benefit of a portion of its net
operating loss carryforwards from past losses. See Notes to the Audited
Consolidated 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 constant based on
prices in effect at December 31, 2000. The following table details the prices
used for these estimates for the respective dates presented:
12/31/00 12/31/99 08/31/99 08/31/98
-------- -------- -------- --------
Gas price per Mcf $11.04 $ 1.99 $ 2.58 $ 1.84
Oil price per Bbl $25.67 $ 25.39 $ 19.03 $ 10.23
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 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 preliminary title investigation before acquiring undeveloped properties that
generally consists of obtaining a title report from outside counsel or due
diligence reviews by independent landmen. The Company believes that it has
satisfactory title to such properties in accordance with standards generally
accepted in the oil and gas industry. A title opinion from counsel is obtained
before the commencement of any drilling operations on such properties. The
Company's properties are subject to customary royalty interests, liens incident
to operating agreements, liens for current taxes and other burdens, none of
which the Company believes materially interferes with the use of, or affect the
value of, such properties.
-10-
NET INCOME OR LOSS FROM OPERATIONS
In its recent history, the Company has recorded both net income and net losses.
For the current year ended December 31, 2000 the Company recorded net income of
$6.76 million, for the transition period ended December 31, 1999, the Company
recorded net income of $1.19 million and for the fiscal year ended August 31,
1999, the Company recorded net income of $.93 million. However, the Company
recorded a net loss of $8.4 million in fiscal 1998 and experienced net losses
for all years previous. 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 exploration and production business
involves certain operating hazards such as crude oil and natural gas well
blowouts, explosions, formations with abnormal pressures, cratering and crude
oil spills and fires. Any of these could result in damage to or destruction of
crude oil and natural gas wells, destruction of producing facilities, damage to
life or property, suspension of operations, environmental damage and possible
liability to the Company. In accordance with customary industry practices, the
Company maintains insurance against some, but not all, of such risks and some,
but not all, of such losses. The occurrence of such an event not fully covered
by insurance could have a material adverse effect on the financial condition and
results of operations of the Company.
SUBSTANTIAL CAPITAL REQUIREMENTS
The Company makes, and will continue to make, substantial capital expenditures
for the acquisition, exploitation, development, exploration, and production of
crude oil and natural gas reserves. Historically, the Company has financed these
expenditures primarily from debt and equity offerings, supplemented by available
cash flow from operations and the sale of interests in its properties. The
Company is hopeful that it will continue to be able to obtain sufficient capital
to finance planned capital expenditures. However, if revenues decrease because
of lower crude oil and natural gas prices, operating difficulties or declines in
reserves, the Company may have limited ability to finance planned capital
expenditures in the future. Therefore, there can be no assurance that additional
debt or equity financing or cash generated by operations will be available to
meet its capital requirements.
CERTAIN CORPORATE DEFENSIVE MATTERS
The Company's Articles of Incorporation and Bylaws and Delaware law contain
provisions that may have the effect, together or separately, of delaying,
deferring, or preventing a change in control of the Company. In particular, the
Company may issue up to 10 million shares of preferred stock with rights and
privileges that could be senior to its outstanding common stock, without the
consent of the holders of the common stock. The Company's Certificate of
Incorporation and Bylaws provide, among other things, for advance notice of
stockholder's proposals and director nominations, and provide for noncumulative
voting in the election of Directors. On June 29, 2000, the Company's Board of
Directors adopted a Stockholder Rights Plan (Rights Plan) under which
uncertificated preferred stock purchase rights were distributed as a stock
dividend to its common shareholders at a rate of one right for each share of
common stock held of record as of July 19, 2000. Unless previously redeemed by
the Company, the rights will expire on June 29, 2010. The Rights Plan is
designed to enhance the Board's ability to prevent an acquirer from depriving
stockholders of the long-term value of their investment and to protect
shareholders against attempts to acquire the Company by means of unfair or
abusive takeover tactics that have been prevalent in many unsolicited takeover
attempts.
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 7,850
square feet, are leased through February 28, 2005 at $11,791 per month with
annual escalations each March 1.
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.
-11-
PROVED RESERVES, FUTURE NET REVENUE AND
PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES
The following unaudited information as of December 31, 2000, 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 (PV-10 Value), as estimated by Netherland Sewell &
Associates, Inc., a Dallas, Texas engineering firm. Estimates of proved
developed oil and gas reserves attributable to the Company's interest at
December 31, 2000 and August 31, 1999 and 1998 are set forth in Notes to the
Audited Financial Statements included in this Annual Report on Form 10-K. The
PV-10 Value was prepared in accordance with SEC requirements using constant
prices as of the calculation date, discounted at 10% per year on a pretax basis,
and is not intended to represent the current market value of the estimated oil
and natural gas reserves owned by the Company.
PV-10 Value of
Years Ending Estimated Future
December 31 Net Revenues
----------- --------------
2001 $ 20,370,000
2002 8,335,000
2003 3,795,000
2004 1,882,000
2005 983,000
Thereafter 1,670,000
--------------
TOTAL $ 37,035,000
==============
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas liquids and natural gas which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions. Proved developed
oil and gas reserves are reserves that can be expected to be recovered through
existing wells with existing equipment and operating methods. No reserve
estimates have been filed with or included in reports to any federal or foreign
government authority or agency, other than the Securities and Exchange
Commission, since the Company's latest Form 10-K filing.
PRODUCTION
The following table summarizes the Company's net oil and gas production, average
sales prices, and average production costs per unit of production for the
periods indicated. With respect to newly drilled wells, there can be no
assurance that current production levels can be sustained. Depending upon
reservoir characteristics, such levels of production could decline
significantly.
Year Ended 4 Months Ended Years Ended
December 31, December 31, August 31
2000 1999 1999 1998
------ ------ ------ ------
Oil:
Production in Barrels 60,000 24,000 82,000 79,138
Average sales price per Barrel $27.85 $20.80 $12.27 $15.78
Gas:
Production in Mcf 2,965,000 1,119,000 2,813,000 713,752
Average Sales Price per Mcf $4.10 $2.75 $2.07 $2.29
Average cost of production per equivalent Mcf (1) $.65 $.60 $.40 $.74
(1) Oil and gas were combined by converting oil to gas Mcf equivalent on the
basis of 1 barrel of oil = 6 Mcf of gas. Production costs include direct
lease operations and production taxes.
-12-
PRODUCING PROPERTIES - WELLS AND ACREAGE
The following table sets forth the Company's producing wells and developed
acreage assignable to such wells at December 31, 2000:
Productive Wells
----------------------------------------------------
Developed Acreage Oil Gas Total
----------------- --------------- -------------- -------------
Period Ended Gross Net Gross Net Gross Net Gross Net
- ------------ ----- --- ----- --- ----- --- ----- ---
Year Ended 12/31/00 15,920 8,257 28 15.63 47 25.49 75 41.12
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 December 31, 2000, the Company owned, by lease or in fee, the following
undeveloped acres, all of which are located in the Continental United States, as
follows:
Estimated
FY2001
United States Gross Acres Net Acres Delay Rentals
- ------------- ----------- --------- -------------
Texas 214,000 172,000 $ 281,000
North Dakota 277,000 201,000 125,000
South Dakota 15,000 12,000 4,000
Montana 10,000 6,000 1,000
--------- --------- ---------
Totals 516,000 391,000 $ 411,000
======== ======= =======
In addition, at December 31, 2000 the Company held under option 150,939 gross
and 131,716 net acres in Maverick and Zavala County in South Texas. In January
2001 the Company exercised this option and purchased a lease covering this
acreage.
Five large Texas leases totaling approximately 66,000 gross acres contain
varying requirements to drill a well every 90 to 150 days to keep the respective
lease in effect. The Company is presently drilling under the terms of the leases
and expects to keep the leases in force by continuous development during the
year.
DRILLING ACTIVITY
During calendar 2000, the Company's drilling activity increased to 27 wells
drilled or re-entered compared to 10 in fiscal 1999. In addition, current year
activity included ongoing drilling operations on 2 wells that were in progress
at the end of year 1999. The following table sets forth the Company's drilling
activity for the last three fiscal years:
-13-
Drilling Wells
2000 1999 1998
------------------------ -------------------------- -------------------------
Gross Net Gross Net Gross Net
---------- ----------- ----- ----- ----------- ---------- ----------
Prod Dry Prod Dry Prod Dry Prod Dry Prod Dry Prod Dry
---- --- ---- --- ---- --- ---- --- ---- --- ---- ---
Oil Wells 2 1 0.78 0.50 2 0 1.75 0.00 2 1 1.34 0.63
Gas Wells 6 6 3.76 2.13 6 0 3.78 0.00 4 0 2.50 0.00
- - ---- ---- --- - ---- ---- - - ---- ----
Total Wells 8 7 4.54 2.63 8 0 5.53 0.00 6 1 3.84 0.63
= = ==== ==== = = ==== ==== = = ==== ====
Included in the respective year 2000 columns were 2 producing (1.63 net) gas
wells and 1 (0.25 net) dry well drilled during the four month transition period
ended December 31, 1999, plus 1 producing (0.5 net) gas well spudded in the
prior fiscal year. In addition to the wells detailed in the table above, the
Company had an interest in 14 wells (11.81 net) in progress at December 31, 2000
from current year drilling and 1 well (0.88 net) from the prior fiscal year.
During the year 2000 the Company re-entered 2 (1.84 net) existing wells, of
which one well is currently producing, while the other well was in progress at
December 31. Re-entry wells are not classified as current year drilling wells
and accordingly are not included in the above table.
MAVERICK BASIN
Throughout the 1990's, the Company pursued a strategy to expand its core
Maverick Basin producing properties. In addition to using internally generated
working capital for exploration and development activities, TXCO accelerated its
growth, where possible, by entering into strategic joint ventures or operating
agreements targeted at leveraging the Company's increased leasehold values,
recognized technical abilities and exploration success in its core area of
interest. TXCO entered into several new joint venture or joint operating
agreements during 2000 while advancing on ventures entered into in past years,
whereby the Company successfully teamed with qualified industry partners who
contributed investment capital, mineral leases, 3-D seismic data and/or offered
the Company a carried interest in mineral leases, 3-D seismic acquisition
programs and wells to be drilled. These contributions were made in exchange for
TXCO's geophysical, geological and operational expertise, and in certain
instances, in exchange for an interest in a portion of the Company's
non-producing oil and gas lease interests .
During September 1998, the Company entered into two separate joint operating
agreements (JOA), one with Ashtola Exploration Company, Inc. and the second with
Picosa Creek Partnership. In the first, TXCO earned a 63% working interest in
Ashtola's 8,800 acre Alkek lease adjoining TXCO's Paloma lease, together with
rights to an existing 3-D seismic survey over the subject block. The acreage was
contributed to a new JOA dated May, 1999 with Castle Exploration Company and is
being developed in conjunction with the new JOA discussed below. Two wells were
drilled under the Picosa Creek JOA during 2000. Both were placed on production
by year end, one as a gas well, and the other as an oil producer.
In November 1998, the Company finalized a JOA with Ameritex Ventures, II Ltd., a
joint venture owned 85% by Enron Capital, allowing Ameritex and its partners to
earn a 50% interest in the shallow and intermediate depths in TXCO's existing
17,000 acre Kincaid lease by their funding 100% of a 27 square mile 3-D seismic
program over 17,000 acre in 1999. During 2000, three gas prospects were drilled
under the agreement resulting in one marginal oil completion and two
non-economic wells which were plugged and abandoned.
In May 1999, the Company finalized a JOA with Castle Exploration Company, a
subsidiary of Castle Energy Corporation, (Nasdaq:CECX) whereby Castle committed
up to $5,300,000 to fund 100% of the costs of purchasing leases, acquire 3-D
seismic and drill up to 12 Glen Rose reef wells on targeted acreage contiguous
to TXCO's productive Paloma lease. TXCO was named as operator, and contributed
its 8,800 acre Alkek lease in exchange for shared rights to all 3-D seismic
acquired, a 25% carried interest in the initial 12 wells, a 50% interest in
future lease acquisitions and up to a 50% interest in all wells to be drilled on
the leases. Pursuant to the agreement, Castle funded 100% of TXCO's costs to
lease 31,700 acres and complete a 3-D seismic acquisition program by November
-14-
1999. During 2000, the partners drilled two wells under the agreement. Neither
well encountered economic quantities of gas and both were plugged and abandoned.
Accordingly, Castle exercised its option under the agreement not to carry the
Company on subsequent wells. Under the current phase of the agreement, TXCO
retains its 50% interest in all acreage and 3-D seismic acquired and can
participate with a 50% interest in all future wells to be drilled on the leases.
In August 1999, the Company purchased from Peacock-Maverick Drilling and Peacock
Exploration their interests in producing wells and oil and gas leases covering
in aggregate 24,500 acres in exchange for 325,000 shares of TXCO common stock
valued at $493,594. The purchase included a 12.5 % working interest in a 12,800
acre tract out of the 190,000+ acre Chittim Ranch, including 6 producing gas
wells located thereon. The acreage is contiguous to the eastern flank of TXCO's
Paloma lease. In addition, the Company received a 100% working interest in the
Wipff/Shaw lease, totaling 11,700 acres located within 5 miles to the west of
TXCO's Paloma lease.
In September 1999, the Company finalized a JOA with Blue Star for an exploration
project targeting the deep Jurassic interval underlying TXCO's Maverick Basin
lease block. Blue Star paid TXCO a cash consideration upon closing and agreed to
fund 100% of a 426 square mile 3-D seismic acquisition program including over
37,000 acres of TXCO's Paloma and Kincaid leases. Blue Star was also obligated
to provide the Company approximately 50,000 acres of new 3-D seismic survey
data, of TXCO's selection from the completed 426 square mile survey. In
addition, Blue Star agreed to fund 100% of the costs of drilling 2 exploratory
wells to test the deep Jurassic interval. Should both wells be drilled timely,
Blue Star would earn a 50% interest in the deep rights in TXCO's Paloma and
Kincaid leases covering in aggregate 50,000 acres. TXCO and its partners would
keep a 50% working interest in future Jurassic wells drilled under the
agreement. According to the original agreement, should initial drilling not
occur within certain deadlines, Blue Star could be obligated to reimburse TXCO
up to $900,000 for certain expenditures in order for Blue Star to maintain its
rights under the agreement.
As of year end 2000, Blue Star had completed the acquisition of 3-D seismic data
over 426 square miles of the Maverick Basin, including TXCO's related 37,000
acres. Preliminary results of the initial processing and interpretation of the
Blue Star seismic data were extremely encouraging to the partners, and appear to
corroborate the geologic model defined in the original 3-D seismic study
completed by TXCO in 1999 which supports the premise that structures that could
contain hydrocarbons are present in the Jurassic interval under its acreage
block. Based on these encouraging results, Blue Star had continued to indicate
it anticipated beginning preparations to drill the first Jurassic test well on
TXCO's Maverick Basin acreage during the first or second quarter of 2001.
On March 13, 2001 Blue Star's senior executives contacted TXCO management and
stated they were applying enhanced 3-D seismic processing techniques on the
seismic field data. Blue Star advised that the expanded seismic processing could
cost an additional $1 million and would take several months to finalize in order
to better define their geologic model of the interval. Blue Star hopes to
enhance its process of selecting the initial drilling locations to test the
18,000+ feet deep structure underlying the targeted acreage block. They further
advised TXCO that the results of the expanded processing should reduce the
initial drilling risk for the benefit of all its partners, enhancing the overall
success of the venture while reducing exploration costs in the long term. Blue
Star also advised TXCO they may not be able to complete their interpretation of
the new processing and begin drilling activities before the end of 2001.
While the advent of new, more advanced technology may serve to reduce the
overall drilling risks involved in this highly technical drilling project, undue
delays in drilling the first well could cause the expiration of Blue Star's
original option to drill on TXCO's acreage. By early March, 2001 the parties
were pursuing discussions in an attempt to reach agreement on the status of Blue
Star's compliance with the terms and intent of the original agreement. While
discussions are continuing TXCO is reviewing it's options under the agreement in
order to confirm the project is not being unreasonably delayed and to further
assure the ultimate development of the project under Blue Stars' proposed new
timetable.
During 2000, the Company continued to expand its core Maverick Basin properties.
During the first quarter of 2000, the Company acquired a lease covering over
95,000 acres on the Comanche Ranch contiguous to the south of Blue Star's
Chittim Ranch Lease and southeast of TXCO's existing Maverick Basin acreage
block. The lease was granted by the Ewing Halsell Foundation giving the Company
a 100% leasehold interest to all depths not reserved under any existing leases
or held by production by other operators. There were no drilling obligations for
six years and initial geologic interpretation indicated that multi-zone
production potential existed, including a deep Jurassic structure below 16,000
-15-
feet. Other progressively deepening targets and intervals include CBM gas from
the shallow Olmos formation, oil from the San Miguel and Austin Chalk
formations, above 4,000 feet, and primarily natural gas from the mid-depth
Georgetown, Glen Rose, Pearsall, and Sligo formations above 8,000 feet.
Early in the fourth quarter of 2000, the Company acquired 42 shut-in well bores
from previous operators on its new Comanche Ranch Lease. Todate, 35 of these
well bores have been identified as locations for re-entry prospective for
coalbed methane (CBM) production. The Company believes CBM production will
eventually make up a significant portion of the future gas production from this
acreage.
Subsequent to year end, the Company sold 50% of its rights below the base of the
San Miguel formation to Saxet Energy, Ltd., a privately held exploration company
from Houston, Texas for a cash consideration. Saxet in turn later notified the
Company that it sold 30% of its interest to a large publicly-traded independent
energy company based in Denver. Saxet will be the operator of the new venture
with the remaining 20% working interest. By year end, the new partners hired
Dawson Geophysical (Nasdaq: DWSN) to acquire a proprietary, 100-square-mile 3-D
survey over 78 square miles of the Comanche Ranch and 22 square miles of an
adjoining property owned by Saxet.
In January 2001, the Company exercised its option to purchase a five-year oil
and gas mineral lease for the shallow rights above the base of the San Miguel
Formation on 150,000 acres of the Chittim Ranch acreage in Maverick County,
Texas. The acreage is contiguous to and between the Company's Paloma/Kincaid
lease block to the northwest and the Comanche Ranch Lease to the south. With
some exceptions, the Company controls drilling rights from the surface to the
base of the San Miguel Formation ranging from 2,700 to 3,500 feet in depth.
TXCO's average working interest on the new Chittim lease is 88.8 %. This
purchase increased the Company's leasehold position in the Maverick Basin to
over 365,000 acres, and established the largest single leasehold position in the
County. Within its holdings, the Company owns more than 250,000 acres of
prospective CBM acreage covering portions of three South Texas counties,
including Maverick, Dimmit and Zavala Counties, and believes this constitutes
the largest block of CBM prospective acreage in the state of Texas.
At December 31, 2000, the Company's 3-D seismic database grew to approximately
231 square miles as compared to the 148 square miles last reported in 1999.
During 2000, the Company received new seismic data totaling approximately 83
square miles over a portion of Blue Star's Chittim Ranch lease, contiguous to
TXCO's Paloma/Kincaid lease block. The Company has engaged two consulting
geophysicists to interpret the new data.
WILLISTON BASIN
TXCO was not active in the Williston Basin in 2000. While oil prices have
stabilized during the year, industry interest has not returned to the level it
reached prior to the price collapse of late 1997. No new drilling had been
pursued since exploration activities were suspended in 1998. The Company did
elect to participate in one outside operated drilling well proposed on a spacing
unit in which TXCO owned a minor interest which it contributed to the unit. This
was the only opportunity to contribute acreage to a drilling prospect identified
during the year. TXCO contributed 10 net acres contiguous to a neighboring
operator's prospect and joined in drilling the Hutzenbiler 1-19H. TXCO has a
1.60% working interest in this well which at December 31, 2000, was still in
progress.
Throughout calendar 2000, the Company continued to evaluate its existing
operations in the Williston Basin. Even with the higher oil prices during 2000,
the Company's properties were still faced with high unit production costs and
declining production volumes. The Company has continued to review the valuation
of its properties through out the year, with particular emphasis on their
continued economics. During the year, management identified one marginal
producing property for impairment whose capitalized costs were in excess of
anticipated future reserve potential. The Company also continued its selective
lease maintenance program targeting primarily those leases not covered under
existing 3-D seismic programs or otherwise not possessing known distinguishing
features of particular geologic significance. During 2000, the Company evaluated
the estimated fair value of the Williston Basin leases and after assessing the
likelihood of recovering its cost on expiring acreage, charged to impairment
expense a total of 123,400 acres whose lease terms are not expected to be
renewed and will expire through April 2001.
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.
-16-
ITEM 3. LEGAL PROCEEDINGS
The Company is not involved in any matters of litigation incidental to its
business of a significant nature.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of the security holders of the Company during
the 4th quarter of fiscal year 2000. During the 2nd quarter, on March 10, 2000,
the Company held its Annual Meeting of Shareholders. The following matters were
submitted for approval by vote at the meeting. All matters were approved by the
shareholders vote and the results of the voting is shown below for each matter.
1. Election of Directors:
For Against
-------- -------
Stephen M. Gose, Jr. 11,376,969 271,959
Thomas H. Gose 11,377,069 271,859
James E. Sigmon 11,381,069 267,859
Michael Pint 11,381,069 267,859
Robert L. Foree, Jr. 11,381,069 267,859
The members of the Board of Directors do not serve staggered terms of
office. There were no changes in Directors of the Company at the annual
meeting.
2. Proposal for ratification of the adoption of Akin, Doherty, Klein &
Feuge, P.C., as independent Auditors for the Company for the fiscal
year 2000.
For Against Abstain
--- ------- -------
11,634,939 1,332 12,657
-17-
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 presented based upon bid prices reported by the National
Association of Securities Dealers Quotations system under the call symbol
"TXCO":
Range of Bid Prices
Quarter Ended: High Low
-------------- ---- ---
December 2000 $ 3.53 $ 2.50
September 2000 3.19 2.38
June 2000 3.22 1.88
March 2000 3.88 1.78
December 1999
(Four month Transition Period) 3.06 1.53
August 1999 $ 2.94 $ 1.00
May 1999 1.41 .75
February 1999 1.50 .62
November 1998 1.41 .75
As of March 1, 2001, there were approximately 1,650 holders of record of the
Company's Common Stock. The transfer agent for the Company is EquiServe, Boston,
Massachusetts. The Company has not paid any cash dividends on its Common Stock
in past years 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 Audited Consolidated 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.
Year Ended August 31 _
Year Ended 4 Months Ended ------------------------------------------------------
December 31, December 31,
2000 1999 1999 1998 1997 1996
---- ---- ---- ---- ---- ----
Income (Loss) from
continuing operations 6,761,935 1,188,649 931,545 (8,417,218) (3,398,866) (1,880,389)
Basic Income (Loss)
per common share from
continuing operations 0.39 0.07 0.06 (0.55) (0.27) (0.31)
Total Assets 29,205,641 18,647,878 17,553,815 16,264,632 21,652,726 8,433,434
Long-term obligations 1,195,191 1,679,936 3,094,809 4,823,927 4,995,000 2,462,197
Shareholders' equity $23,321,736 $13,208,928 $12,020,280 $10,595,141 $14,770,770 $5,670,688
Weighted average shares
outstanding - Basic 17,242,326 15,938,516 15,668,721 15,328,292 12,576,255 6,140,176
-18-
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
CALENDAR YEAR ENDED DECEMBER 31, 2000
During the year ended December 31, 2000, beginning cash reserves of $3,381,793
were increased by net cash provided from operating activities of $6,529,838
resulting in a total of $9,911,631 in internally generated working capital for
use in funding the ongoing expansion, development and exploration of the
Company's oil and gas properties. Strengthening gas prices were reflected in
ongoing positive cash flow from operations in the latter half of the year and
contributed significantly to the Company's ability to expand its planned
activities. In February 2000, $2,810,248, net of offering costs, was provided
through a private placement of common stock with Swisspartners Investment
Network AG, a private investment firm based in Zurich, Switzerland. Proceeds
from the placement were for general corporate purposes, but the timing of its
receipt early in the year, allowed the Company to complete the acquisition of
significant additional acreage in its core Maverick Basin area. The funding also
provided additional flexibility to accelerate ongoing exploration activities. An
additional $1,173,642 was provided during the year from new equipment purchase
financing, while $100,000 was provided from the exercise of outstanding warrants
for the purchase of shares of the Company's commons stock.
The Company applied $6,290,260 of its working capital to fund the expansion and
ongoing development of its oil and gas properties. Included were drilling,
completion and leasehold acquisition costs totaling $4,865,807 primarily
targeting TXCO's core area, the Maverick Basin. Included in these costs were
expenditures for the drilling, completion and re-entry of 29 gas and oil wells,
new Maverick Basin mineral lease purchases of approximately 100,000 acres for
the year. Also included was $1,347,505 applied in the expansion of the Company's
Paloma lease gas gathering facilities, including the purchase of two new natural
gas compressors at a total cost of $1,012,404.
The Company made timely payments of $1,658,386 on its long term debt obligations
during 2000, while payments on interest totaled $179,036. These payments led to
the early retirement in May, 2000, of the then remaining $1,015,731 due under
the original 1998 financing agreement with Range Energy Finance Corporation
(NYSE:RRC).
As a result of these activities, the Company ended the year 2000 with a positive
working capital of $6,349,625 and a current ratio of 2.36 to 1. This greatly
improved year end position compares to positive working capital of $207,660 and
a current ratio of 1.04 at December 31, 1999. The dramatic increase in working
capital is attributable to the growth in operating cash flow from ongoing
operations, the Company's ability to raise equity capital and the improvements
in commodity prices throughout the year. Management is confident of the
Company's ability to continue to generate positive cash flow from operations and
to meet its ongoing operating cash requirements for 2001 and beyond..
FOUR MONTH TRANSITION PERIOD ENDED DECEMBER 31, 1999
The Company changed its fiscal year from August 31 to December 31, effective for
the calendar year beginning January 1, 2000. The four month transition period
from September 1 through December 31, 1999 preceded the start of the new
calendar year 2000 as presented above. The following discussion relates only to
this four month transition period.
Cash reserves of $968,516 at August 31, 1999 were increased by cash provided
from operating activities of $3,952,602 resulting in $4,921,118 in working
capital available for use in meeting the Company's ongoing operational and
development needs during the four month transition period ended December 31,
1999.
During this four month period, portions of this capital were used to fund
payments on debt of $1,435,004 and interest of $131,872. The Company applied
$196,103 to the expansion and ongoing development of its core oil and gas
properties. These costs included drilling and completion costs for wells drilled
or completed during the period and 3-D seismic acquisition and reprocessing
costs.
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As a result of these activities, working capital improved from a negative
$1,524,594 at August 31, 1999 to a positive $207,660 at December 31,1999. The
current ratio improved to a 1.04 to 1 compared to a current ratio of .70 to 1 at
the beginning of the period. The improvement in working capital and current
ratio levels were primarily due to sustained gas and oil production levels and
continued strength in these commodity prices.
FISCAL YEAR ENDED AUGUST 31, 1999
During the year ended August 31, 1999, beginning cash reserves of $2,329,236
were increased by net cash provided from operating activities of $3,858,204
resulting in a total of $6,187,440 in working capital available for use in
funding the Company's ongoing development and exploration of its oil and gas
properties. The ongoing positive cash flow from operations throughout the year
significantly improved the Company's ability to increase its core revenues from
oil and gas operations, thereby enhancing its ability to overcome the impact of
weak oil and gas prices through most of 1999. An additional $900,000 was
obtained during the year, under the existing financing agreement with Range
Energy Finance Corporation, bringing total borrowings from Range to $4,400,000.
The financing was specifically for ongoing development of the Company's natural
gas producing properties in Maverick County, Texas.
The Company applied $3,448,320 of its working capital to fund the expansion and
ongoing development of its oil and gas properties. Included were drilling and
completion costs of $2,791,544 for current year drilling of 10 Maverick Basin
gas and oil wells, plus costs associated with 2 wells drilled during the last
quarter of 1998. Also included were $211,101 in 3-D seismic acquisition and
reprocessing costs and $390,000 in lease extension payments to maintain
non-producing lease acreage in the Company's growing Maverick Basin lease block.
The Company made timely payments on long term debt of $2,629,118 during 1999,
including $1,966,956 paid on the Range financing agreement. Scheduled payments
totaling $662,162 were made on the Company's remaining long-term notes during
the remainder of the year.
During the 3rd quarter of 1999, TXCO successfully entered into a joint venture
agreement with Castle Exploration Company, (Castle) a wholly owned subsidiary of
Castle Energy Corporation (Nasdaq:CECX), whereby Castle agreed to fund up to
$5,300,000 for 100% of all costs to acquire approximately 25,000 acres of
additional leases, fund a 42 square mile 3-D seismic survey and drill up to 12
gas wells. In exchange, TXCO contributed its interest in an 8,800 lease to the
venture, was named operator and will be carried at no cost, for a 25% interest
in the first 12 wells drilled. Additionally, TXCO will be licensed to share in
all seismic data gathered and will earn a 50% working interest in all leases
acquired with the funds. At year end, all 3-D seismic acquisition and processing
had been completed, and Company geologists and geophysicists were in process of
interpreting and evaluating the new data.
During the 4th quarter of 1999, the Company successfully closed another non-cash
transaction to acquire various oil and gas mineral interests near or adjoining
TXCO's Maverick Basin leasehold. In exchange for 325,000 shares of its
restricted common stock valued at $493,594, the Company purchased a 12.5%
interest in 12,800 acres known as the Chittim Lease, including a 12.5% working
interest in 6 producing oil and gas wells and associated equipment. In addition,
TXCO also received a 100% working interest in two separate leases totaling
approximately 11,700 acres.
As a result of these activities, the Company ended fiscal year 1999 with
negative working capital of $1,525,594 and a current ratio of .70 to 1. This
compares to positive working capital of $516,693 and a current ratio of 1.19 to
1 at August 31, 1998. Working capital weakened during 1999 primarily due to cash
outlays for its aggressive ongoing development activities and due to timely
payments made under the terms of the Range financing agreement. Although the
Company had a working capital deficit at year end, included in current
liabilities is $2,110,620 estimated as the debt payment for fiscal 2000 under
the Range financing agreement. The Range debt payments are only due and payable
out of each future month's net cash flow from the collateralized producing
wells.
FISCAL YEAR ENDED AUGUST 31, 1998
During the year ended August 31, 1998, beginning cash reserves of $6,198,069
were reduced by net cash used in operating activities of $1,185,050 resulting in
a total of $5,013,019 in working capital available for use in funding the
Company's ongoing development and exploration of its oil and gas properties,
significantly improving the Company's potential to increase its core revenues
from oil and gas operations, and enhancing its ability to overcome the impact of
continued weakness in oil and gas prices.
-20-
Throughout fiscal 1998, the Company pursued opportunities to enhance its
liquidity by the conversion of existing short term trade payables to long-term
debt and the conversion of debentures into common stock. Management successfully
converted 4 separate accounts totaling $1,684,000 in current trade payables into
separate notes, with payment terms ranging from 12 to 36 months and interest
accruing at rates ranging from 8% to 14%. Further improvements to the Company's
debt structure were realized by Management's election to exercise the Company's
option to convert its outstanding $4,000,000 debentures to equity. Effective
January 1, 1998, the Company issued 844,318 shares of its common stock in
exchange for the outstanding debentures, including accrued interest of $221,590,
at the conversion price of $5.00 per share. In addition to the extremely
favorable conversion price for the new issuance, and the elimination of $240,000
in future annual interest expense, Management's elimination of its primary
long-term debt significantly enhanced the Company's ability to pursue additional
sources of equity or debt-based working capital.
Late in the final quarter of 1998, the Company entered into a financing
agreement with Range Energy Finance Corporation, a subsidiary of Range Resources
Corporation (NYSE:RRC), (formerly Domain Energy Corporation) to initially
establish a borrowing ceiling of $4,000,000. During fiscal year 1999 the
borrowing ceiling was increased to $4,400,000. The financing was specifically
for ongoing development of the Company's natural gas producing properties in
Maverick County, Texas. Funds were advanced in exchange for a limited term
overriding royalty interest tied to existing and future production from
specified depths underlying certain of the Company's oil and gas leases in
Maverick County. Terms provided for repayment of the funds, with interest at
18%, from a specified portion of sales proceeds from all existing and future
wells to be drilled on the Paloma lease. By August 31, 1998 the Company had
borrowed $3,500,000 under the agreement.
Throughout the year ended August 31, 1998, the Company applied $4,806,505 of its
available working capital to fund the ongoing development of its oil and gas
properties. This included drilling and completion costs of $3,385,720 associated
with the current year drilling of four new Maverick Basin gas wells, three new
Williston Basin oil wells and costs associated with 4 wells drilled prior to the
current fiscal year, plus $188,785 for completion of the newest segment of the
Company's new gas gathering system in Maverick County during 1998. Also included
were 1998 3-D seismic acquisitions totaling $711,294 over Company leases in
North Dakota and $153,845 on the Paloma lease in South Texas. Additional
investments in non-producing lease acreage totaled $366,861 for the year.
Additionally, the Company made payments on its long-term debt during the year of
$1,500,990. Included in the total was $940,481 paid during the first quarter, in
full prepayment of the Company's outstanding line of credit with Luzerner
Kantonalbank. Scheduled payments totaling $560,509 were made on the Company's
remaining long-term notes during the remainder of 1998.
As a result of these activities, the Company ended fiscal year 1998 with
positive working capital of $516,693 and a current ratio of 1.19 to 1. This
compared to positive working capital of $3,760,648 and a current ratio of 2.32
to 1 at August 31, 1997. While the Company's working capital position weakened
from the previous year, the results of the Company's dramatic 100% drilling
success ratio during 1998 for new Glen Rose wells became evident during the
first quarter of fiscal year 1999.
2001 CAPITAL REQUIREMENTS
The major components of the Company's plans, and the requirements for additional
capital for 2001 include the following:
MAVERICK BASIN ACTIVITY:
Initial capital expenditures planned for 2001 total over $11,100,000, are
presented net to the Company's interest, and are primarily on its Maverick Basin
core properties . Included is $1,000,000 for targeted lease acquisitions in
Maverick County during the first quarter of 2001. Additional 3-D seismic
acquisition plans total $900,000 and consist primarily of a 78 square mile
program commenced in February 2001 on the western most portion of the Comanche
lease. Gas gathering infrastructure expansion plan expenditures total $1,400,000
for the 2001, including $1,100,000 for the Company's shallow CBM project in the
Comanche lease, plus $300,000 for pipeline additions its Paloma lease pipeline
system.
-21-
The largest component of 2001 planned capital expenditures total $7,350,000 for
exploratory drilling wells and for an expanding number of re-entry targets
available to the company due to its October 2000 acquisition of 42 shallow
shut-in well bores prospective for CBM (coal bed methane) on the Comanche lease.
The Company plans to drill or re-enter a minimum of 51 wells, including 15 new
Glen Rose reef prospects and 36 CBM new or re-entry prospects. A total of
$3,750,000 is reserved for Glen Rose reef prospects, while $3,600,000 is planned
for CBM exploration. Three of the Glen Rose wells are planned on the Comanche
lease on a 50% WI basis under the Company's recently announced Comanche lease
operating agreement, with Saxet Energy as operator. Drilling is expected to
occur late in 2001, after 3-D seismic processing is completed on the ongoing
seismic data acquisition program currently underway on the Comanche lease. The
remaining 12 Glen Rose wells are targeted at reef prospects already defined by
existing 3-D seismic on the remaining portion of the Company's Maverick Basin
lease block. A typical Paloma lease Glen Rose reef well costs the Company
approximately $225,000 to 275,000 to complete or $160,000 as a dry hole, on a
net basis. Comanche lease Glen Rose prospects net drilling costs are expected to
average $50,000 more than Paloma lease wells, as the Glen Rose interval trends
deeper downdip when encountered under the Comanche lease.
The Company continues to benefit from its 25% carried interest in the ongoing
3-D seismic processing and interpretation activities continuing on its deep
Jurassic project under its Paloma/Kincaid lease block, as all costs have been
funded 100% todate by its partner and operator, Blue Star Oil and Gas, Ltd No
substantial funding requirements are required of TXCO nor are any planned for
2001for the project.
Estimated expenditures required to maintain the Company's interest in all of its
remaining undeveloped South Texas leasehold acreage for fiscal 2001 are
approximately $280,000 exclusive of required drilling obligations.
WILLISTON BASIN ACTIVITY:
The Company plans to maintain its existing producing properties and the payment
of delay rentals and lease extensions on selected undeveloped leases, with
scheduled 2001 delay rentals of $130,000 and will continue in its efforts to
offer remaining acreage, seismic data, and identified prospects to other
industry operators.
SUMMARY OF CAPITAL RESOURCES AND LIQUIDITY
While management is confident it has identified sufficient sources of working
capital to carry out its current exploration and development plans on its Texas
leaseholds, as well as to meet its obligations in the ordinary course of
business through the end of the new year, there is no assurance that energy
prices will continue to improve. Should prices weaken, the reduction in revenues
could cause the Company to re-evaluate its expected sources of working capital
and may cause the Company to reduce its current operating plans.
Management is actively involved in ongoing discussions with various industry
partners and domestic and foreign based sources of debt and equity financing.
These parties could provide favorably structured drilling arrangements that,
along with the Company's internally generated cash flow would provide funding as
required to increase the Company's planned drilling activity during year 2001.
Management remains confident that financial resources will remain available,
enabling the Company to continue the rapid development of its gas and oil
properties and continue to meet its normal operational and debt service
obligations.
CHANGE IN FISCAL YEAR
A Form 8-K was filed on December 29, 1999, in order to report that the Board of
Directors of the Company had elected to change its annual reporting period from
a fiscal year ending August 31 to a calendar year ending December 31 effective
for the calendar year beginning January 1, 2000. The transition period for this
change was reported on February 4, 2000, on the Company's Transition Report on
Form 10-Q for the four month period ended December 31, 1999.
-22-
RESULTS OF OPERATIONS
2000 COMPARED TO 1999
The Company reported net income of $6,761,935 or $0.39 per basic and diluted
share for the fiscal year ended December 31, 2000, compared to a net income of $
931,545 or $0.06 per basic and diluted share for the fiscal year ended August
31, 1999. The 626% increase included the result of recognition in the current
year of a deferred tax asset of $5,232,718. The deferred tax asset reflects the
cumulative future tax benefit of a portion of the Company's net operating loss
carryforwards. The deferred tax benefit was recognized by a reduction to the
valuation allowance established in prior years against the Company's deferred
tax assets. Management believes it is now more likely than not that a
significant portion of its deferred tax asset will be realized. Therefore, the
valuation allowance was reduced and a deferred tax asset recognized for the
amount expected to be realized through taxable earnings over the next three year
period. Additionally, revenues increased 96% over 1999 levels due primarily to
the substantial increase in prices received during the year. Average realized
prices for gas rose to $4.10 per Mcf, a 98% increase, while average realized
prices for oil rose to $27.85, a 127% increase. Total net gas production for the
year 2000 was 2,965,000 Mcf, an increase of 152,000 Mcf over 1999. This increase
resulted from 4 new gas wells being brought on line through the year, but was
partially offset by the general production decline of the existing older gas
wells. Total net oil production for the same periods decreased 12,000 Bbls to
60,000 Bbls in year 2000. This decline was primarily caused by the reduced
production in the Williston Basin attributable to increased water production.
Average daily net gas production in year 2000 increased 5% to 8,100 Mcf compared
to fiscal 1999, while average daily net oil production in year 2000 decreased to
164 Bbls, a 27% decline compared to fiscal 1999.
Exploration expenses increased $2,787,000 compared to 1999 levels primarily due
to the high dry hole expense resulting from accelerated exploration activities
initiated during the current year. Current year charge-offs included the costs
of 7 drilling wells to dry hole expense while the were no dry holes in the prior
year.
Pursuant to the Successful Efforts Method of accounting for mineral properties,
the Company periodically assesses its producing and non-producing properties for
impairment. Abandoned leases and equipment expense increased by 224% primarily
due to recognition of the expiration of 43,700 acres in the Williston Basin
during year 2000 versus much fewer incidents of acreage costs being charged off
during 1999. Similarly, impairment expense increased by 593% due to a 79,702
acres block of non-producing acreage in the Williston Basin expected to expire
in early 2001. Depreciation, depletion and amortization increased by 16% over
1999 levels due primarily to the higher depletion rate resulting from decreased
reserves for specific producing properties. The increase in depreciation was due
to investment in equipment expanding the Paloma Lease Gathering System completed
at mid-year.
General and administrative costs increased 30% compared to 1999 levels
reflecting the higher sustained level of Company operations. Increased salaries
and related costs due primarily to the addition of two employees and increased
compensation levels over the comparable period in 1999. An increase in investor
communications of $86,000 reflects the increased level of presentations and
associated print and electronic material design and preparation costs incurred
by the Company in conjunction with domestic and international investor and
industry conferences during 2000.
The 214% increase in interest income reflects the higher cash levels in interest
bearing accounts during 2000 versus 1999 levels. Interest expense decreased by
$449,000 in 2000 from 1999 due to the retirement of the Range debt during the
second quarter of 2000.
The minority interest in income of subsidiaries is a new line item resulting
from the consolidation of TXCO's majority-owned subsidiaries. There were no
consolidated subsidiaries in the prior year.
-23-
1999 COMPARED TO 1998
The Company reported net income of $931,545 or $0.06 per diluted share for the
year ended August 31, 1999, compared to a net loss of ($ 8,417,218) or ($0.55)
per diluted share for the same period in 1998. The attainment of profitability
was primarily the result of a 146% increase in revenues over 1998 levels due
primarily to significant new production from 9 new wells placed on line during
the year, including 2 gas wells completed late in the last quarter of the prior
year. While very positive, the increases were significantly offset by the
weakness in oil and gas prices through the first half of 1999. Gas sales volume
increases also reflect the impact of the first full year of operation of the
expanded gas gathering system completed during the latter part of 1998.
Exploration expenses decreased by 88% compared to 1998 levels due to the high
drilling success in the Maverick Basin compared to multiple Williston Basin dry
holes drilled or abandoned during the prior year. Abandoned leases and equipment
expense decreased by 78% primarily to the non-recurring nature of the one time
charge off of uneconomical producing properties during 1998 due to the oil and
gas price collapse during 1998. Impairment expense decreased by 92% also due to
the non-recurring nature of the initially large impairment provisions required
due to the oil price collapse in the prior year, while lower 1999 impairment
provisions proved adequate in light of the improvement in realized oil and gas
prices during the last half of the current year. Depreciation, depletion and
amortization increased by 61% over 1998 levels due primarily to an increase in
depletion. The change in depletion was due to the adverse impact on year end
reserve estimates caused by declining oil production and increasing water
disposal costs associated with Williston Basin production.
The decrease in loan fee amortization expense as compared to 1998, reflects the
non-recurring nature of the prior period's recognition of $180,000 in previously
capitalized prepaid loan fees due to the conversion of a $4,000,000 debenture in
January 1998. Fiscal 1998 loan fee amortization expense has been reclassified
for comparative purposes with current year expense. Interest expense increased
by 142% over 1998, reflecting a full year of interest charges on borrowings
under the Range financing agreement entered into during the last quarter of the
prior year.
1998 COMPARED TO 1997
Revenues from oil and gas sales increased 195% over 1997 as a result of
significant new production from the successful completion of the nine new wells
during the last part of the 1997, plus the additional production from 4 new gas
wells added during 1998. Lease operating expenses, related directly to the costs
of operating the newly producing Williston Basin oil wells with very high
production associated water disposal costs, increased by 297% over 1997. The
disproportionately higher increase in lease operating expense increases reflects
the difference in the Company's normal natural gas production expense level
versus the significantly higher per unit production cost associated with its
Williston Basin oil production.
Exploration expenses, including the costs of unsuccessful wells increased by 47%
due to the write-off of two high working interest dry holes during the year
compared to two very low working interest dry-holes in the previous year. The
40% fall of oil prices at mid-year rendered the completion of the wells
uneconomical. Abandoned leases and equipment increased to $1,451,880, reflecting
the ongoing impact of the 40% fall of oil prices during the year that rendered
marginal properties uneconomic to maintain or renew. Included in the non-cash
charge off for the current year are $608,573 in Williston Basin leases, $156,670
in Zavala County leases (South Texas), and $26,757 in Canadian Crown leases, all
determined to be uneconomic and expiring during the current year due to the
continued impact of low oil and gas prices. Also included in the 1998 non-cash
writeoff was the remaining capitalized costs $659,880 for the Kincaid #1-99, a
horizontal Georgetown test well drilled in Maverick County during the third
quarter of 1997 that failed to produce economic quantities of gas.
Pursuant to the Successful Efforts Method of accounting for mineral properties,
the Company periodically assesses its producing properties and non-producing
mineral leases for impairment. Based on the 40% fall in oil prices during the
year and the resulting impact on the updated reserve estimates at year end, the
Company identified certain producing properties which required impairment.
Additionally, non-producing leaseholds were reviewed for potential impairment.
Certain leases, with expiration dates through December 1999, were identified
which would not be renewed. Non-cash impairment charges totaling $3,655,342 were
recorded at year end including $1,580,820 of Williston Basin and Texas
non-producing leases set to expire through calendar year 1999. Additionally, a
$2,194,522 impairment was recorded reflecting the excess of unamortized book
value over the future realizable reserves primarily related to certain of its
Williston Basin wells. Additional expenses during the year include depreciation,
depletion and amortization of $1,446,726, plus current year exploration expenses
of $2,290,649.
-24-
Except for the statutory, intangible (non-cash) expenses required for compliance
reporting purposes described above and current year exploration expenses, actual
operating activities for the year ended August 31, 1998 resulted in positive
cash flow from producing operations of $989,484. This level of positive cash
flow, if sustained, is sufficient to provide for funding of the Company's
primary administrative operations. Management feels confident this source of
internally generated working capital will continue to grow as the Company's
Texas gas production levels expand through fiscal 1999 and beyond.
General and administrative costs increased to $1,278,270 from $938,000.
Increases in salaries totaling approximately $211,000 were due primarily to a
full twelve months of wages in 1998 for the increased number of new employee
positions required by the Company's expansion in operations as a result of the
Williston Basin lease acquisition versus only a partial year for the previous
year. The $184,692 decrease in interest income in 1998 reflects the lower cash
levels in interest bearing accounts during 1998 versus the prior year.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK
COMMODITY RISK. The Company's major market risk exposure is the commodity
pricing applicable to its oil and natural gas production. Realized commodity
prices received for such production are primarily driven by the prevailing
worldwide price for crude oil and spot prices applicable to natural gas. Prices
have fluctuated significantly over the last four years and such volatility is
expected to continue, and the range of such price movement is not predictable
with any degree of certainty. A 10% fluctuation in the price received for oil
and gas production would have an approximate $1.5 million impact on the
Company's annual revenues and operating income.
INTEREST RATE RISK. The Company's exposure to interest rate risk is minimal as
all of its debt at December 31, 2000 is at fixed rates.
FINANCIAL INSTRUMENTS: The Company's financial instruments consist of cash
equivalents and accounts receivable. Its cash equivalents are cash investment
funds which are placed with a major financial institution. Substantially all of
the Company's accounts receivable result from oil and gas sales or joint
interest billings to third parties in the oil and natural gas industry. This
concentration of customers and joint interest owners may impact the Company's
overall credit risk in that these entities may be similarly affected by changes
in economic and other conditions. Historically, the Company has not experienced
any significant credit losses on such receivables. See Certain Business Risks
section.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Consolidated 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
-25-
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 March 1, 2001:
Name Position Age
---- -------- ---
Stephen M. Gose, Jr. Chairman of the Board of Directors 71
Member Audit and Compensation Committees
Michael J. Pint Director, Chairman Audit and Compensation Committees 57
Robert L. Foree, Jr. Director, Member Audit and Compensation Committees 71
Alan L. Edgar Director, Member Audit and Compensation Committees 55
James E. Sigmon President and Director 52
Thomas H. Gose Director and Assistant Secretary 45
Roberto R. Thomae Chief Financial Officer 50
Secretary/Treasurer, Vice President-Finance
Richard A. Sartor Controller 48
Stephen M. Gose, Jr., has served as Chairman of the Board of Directors of the
Company since July 1984. He has been a member of the Audit and Compensation
Committees since June 1997 and served as their Chairman through April 1998. He
served as a Director of the Company's former subsidiary ExproFuels, Inc. from
1994 through 1999. A geologist by training, he has been active for more than 45
years in exploration and development of oil and gas properties, in real estate
development, and in ranching through the operations of Retamco Operating, Inc.,
its predecessors and affiliates.
Michael J. Pint has served as a Director since May, 1997. He has been a member
of the Audit and Compensation Committees of the Board of Directors since June,
1997 and has served as their Chairman since April, 1998. Mr. Pint has 35 years
banking experience, serving in the bank regulatory arena as well as in the
capacity of chairman, president and director of 38 different banks and bank
holding companies throughout the country. 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. A geologist by training, he has been active for more than 45 years in the
exploration and development of oil and gas properties. Since 1992, Mr. Foree has
served as President of Foree Oil Company, a privately held Dallas, Texas based
independent oil and gas exploration and production company.
Alan L. Edgar, has served as a Director of the Company since May 2000 and as a
member of the Audit and Compensation Committees of the Board of Directors since
that time. He has been involved in energy related investment banking and equity
analysis for over 28 years. Since 1998, Mr. Edgar has served as President of
Cochise Capital, Inc. a privately held Dallas, Texas based company specializing
in exploration and production related mergers and acquisitions advisory and
financing. Previous public company mergers and acquisitions, investment banking
and energy financing experience includes serving as Managing Director and
Co-Head of the Energy Group of Donaldson, Lufkin & Jenrette Securities, Inc.,
from 1990 to 1997, serving as Managing Director of the Energy Group of
Prudential-Bache Capital Funding from 1987 to 1990 and serving as Corporate and
Research Director of Schneider, Bernet & Hickman, Inc. (Thompson, McKinnon) from
1972 through 1986.
James E. Sigmon has served as the Company's President since February 1985. He
has been a Director of the Company since July 1984. He served as a Director of
ExproFuels, Inc. through November 1998. As an engineer, Mr. Sigmon has been
active for 30 years in the exploration and development of oil and gas
properties. Prior to joining the Company, Mr. Sigmon served in the management of
a private oil and gas exploration company active in drilling oil and gas wells
in South Texas.
-26-
Thomas H. Gose has served as a Director of the Company since February, 1989, as
Secretary from 1992 through March, 1997 and as Assistant Secretary since March,
1997. He served as President and Director of the Company's former subsidiary
ExproFuels, Inc. from 1994 through 1999. Since October, 2000 he has served as
President of NEOgas Ltd. a Houston based subsidiary of NEOppg International Ltd.
NEOgas develops and markets technologies to transport and deliver compressed
natural gas to markets with stranded gas production or stranded customer bases.
He formerly served as Director, CEO and President of Retamco Operating, Inc., (a
large shareholder of the Company) its predecessors and affiliates from 1987 to
1999. Thomas H. Gose is the son of Stephen M.
Gose, Jr.
Roberto R. Thomae has served as Chief Financial Officer and Vice
President-Finance of the Company since September 1996 and as Secretary/Treasurer
since March 1997. From September 1995 through September 1996 he was a consultant
to the Company in a financial management capacity. From 1989 through 1995 Mr.
Thomae was self- employed as a management consultant primarily involved in the
development of domestic and international oil and gas exploration projects and
the marketing of refined products.
Richard A. Sartor has served as Controller of the Company since April 1997. A
Certified Public Accountant since 1980, Mr. Sartor owned his own private
accounting practice from 1989 through March 1997.
Each of the aforementioned Executive Officers and/or Directors have been elected
by the shareholders to serve for one year or until his successor is duly elected
except for Mr. Edgar who was appointed by the Board in May 2000 to serve until
the next annual meeting of shareholders.
ITEM 11. EXECUTIVE COMPENSATION
Summary Compensation Information: The following table contains certain
information for each of the calendar and fiscal years and the 4 month transition
period ended as 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
Name and Other Annual All Other
Principal Position Year Salary Bonuses Compensation Compensation
- ------------------ ---- ------ ------- ------------ ------------
James E. Sigmon 12/31/00 $175,000 $14,583 (1) $174,181 $402
President & CEO 12/31/99(2) 57,899 -0- (1) 52,600 -0-
8/31/99 150,000 -0- (1) 56,678 419
8/31/98 132,000 -0- (1) 41,623 267
Roberto R Thomae 12/31/00 100,000 8,333 -0- 161
CFO & Secr/Treas 12/31/99(2) 33,499 -0- -0- -0-
(1) Amounts represent income from an overriding royalty interest.
(2) Represent four month transition period for respective officer.
-27-
OPTIONS/SAR GRANTS
% of Total Options Grant
# Options Granted to Employees Exercise Price Expiration Date
Name Granted in Fiscal Year per Share Date Value (1)
---- ------- -------------- --------- ---- -----
Fiscal Year Ended Dec 31, 2000:
None
4 Month Transition Period
Ended Dec 31, 1999:
Roberto R. Thomae 50,000 30% $2.125 2009 $60,762
CFO & Secr/Treas
(1) The fair value for all options granted, whether vested or not, was
estimated at the date of grant using the Black-Scholes option pricing model
with the following weighted-average assumption: risk-free interest rate of
6.48%; dividend yield of 0%; volatility factors of the expected market
price of the Company's common stock of 1.21 and a weighted-average expected
life of the option of five years.
AGGREGATED OPTION/SAR EXERCISES
Number of Unexercised Value of Unexercised
# Shares Value Options/SARs Options/SARs
Name Exercised Realized Exercisable Unexercisable Exercisable Unexercisable (1)
---- --------- -------- ----------- ------------- ----------- -------------
Year Ended Dec 31, 2000:
James E. Sigmon (2) - $ - 100,000 600,000 $ 18,800 $ 48,780
Roberto R. Thomae - - 100,000 25,000 85,175 20,325
Four Month Period Ended Dec 31, 1999:
James E. Sigmon (2) - - 100,000 600,000 - -
(1) Value of unexercised options calculated as the difference in the stock
price at period end and the option price.
(2) 100,000 of Mr. Sigmon's unexercised options were exercisable as of December
31, 2000, and the remaining 600,000 options vest and are exercisable in
specified amounts upon the Company's common stock attaining the following
price levels: 200,000 shares at $5.00; 100,000 shares at $7.50; 100,000
shares at $10.00; 100,000 shares at $12.50 and 100,000 shares at $15.00.
-28-
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 plus
reimbursement of related travel expenses for each board meeting physically
attended or $250 for telephonic attendance. Beginning in 1997, upon assuming
Director status, new outside directors have been awarded 10 year options (
Directors 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. During 2000, the Board of
Directors unanimously approved a two component strategy intended to re-align
long term incentives for all of its directors. This strategy was the result of
the expansion of the number of seats on the board by one and the election of a
sixth director in May 2000. The strategy provided for the issuance of Directors
Options to the two directors whose election to the Board predated the 1997 award
regimen thereby precluding their previous receipt of Directors Options. The
second component included a repricing of the exercise prices of existing
Directors Options (those issued to directors elected prior to 2000) equal to the
exercise prices as granted the newest outside director elected in May 2000.
EMPLOYMENT CONTRACTS
The Company has an employment agreement with its president, Mr. James E. Sigmon,
which sets his salary at a minimum of $175,000 annually, and includes the grant
of a proportionately reduced 1% overriding royalty interest under all leases the
Company has or acquires during his term as President. The agreement is
cancelable with 90 days notice by the Company.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
No Compensation Committee interlocks existed during the Company's last completed
year. The Compensation Committee of the Board of Directors of the Company was
established in June, 1997 and currently consists of Michael J. Pint (Chairman),
Robert L. Foree, Jr., Stephen M. Gose, Jr. and Alan L. Edgar, upon his election
in May 2000. 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.
-29-
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
17,471,849 shares outstanding and 20,472,078 fully diluted shares which includes
3,000,229 shares under options and warrants as of March 15,2001.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The following table sets forth information concerning all persons known to the
Company to beneficially own 5% or more if its common stock, including
information filed pursuant to Rule 13d filings made available to the company
during the year.
Name and Address of Number of Shares
Beneficial Owner Beneficially Owned Percent Owned
---------------- ------------------ -------------
Thomas H. Gose 916,601 5.25%
517 Morningside
San Antonio, TX 78209
Stephen M. Gose, Jr. 1,080,127 6.18%
HCR Box 1010 Hwy 212
Roberts, Montana 59070
Trianon Opus One, Inc. 1,350,500 7.73%
Fohrenstrasse 25
CH-8703 Erlenbach
Switzerland
Swisspartners Investment Network AG 1,333,333 7.63%
Am Schanzengraben 23
Postfach 970
Switzerland
Tahoe Invest 1,190,000 6.81%
Innere Guterstrasse 4
6304 Zug
Switzerland
-30-
SECURITY OWNERSHIP OF MANAGEMENT
The following table sets forth the number of shares of common stock beneficially
owned as of March 15, 2001by 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 Forms 3,4, 5, stock records of the
Company and the Company's transfer agent.
Number of Shares Percent
Name Beneficially Owned Owned(1)
---- ------------------ --------
Stephen M. Gose, Jr. (3)(7) 1,080,127 5.83%
James E. Sigmon (2) 750,000 4.13%
Thomas H. Gose (7) 916,601 5.25%
Michael Pint. (4) 350,000 1.99%
Alan L. Edgar (5) 258,333 1.47%
Robert L. Foree, Jr. (4) 86,000 .49%
Roberto R. Thomae (6) 100,000 .57%
All Directors and Executive
Officers as a group 3,578,561 18.21%
(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. Sigmon includes 50,000 shares
owned directly and 700,000 shares of the Company's Common Stock reserved for
issuance through options issued under the Company's 1995 Flexible Incentive
Plan.
(3) The number of shares beneficially owned by Mr. Gose, Jr. include 20,000
shares owned directly, plus his 100% interest, shared equally with his
spouse, in 1,060,127 shares owned by Retamco Operating, Inc.
(4) The number of shares beneficially owned by Mr. Pint and Mr. Foree each
includes 75,000 shares of the Company's Common Stock reserved for issuance
under non-qualified options issued to outside directors of the Company
exercisable at March 15, 2001 plus 275,000 and 11,000 respectively, of
directly owned shares.
(5) The number of shares beneficially owned by Mr. Edgar includes 125,000 shares
owned directly and 133,333 shares of the Company's Common Stock reserved for
issuance under 5 year warrants, granted in February 2000, for services
rendered prior to his election as a director.
(6) The number of shares beneficially owned by Mr. Thomae includes 100,000
shares of the Company's Common Stock reserved for issuance through options
issued under the Company's 1995 Flexible Incentive Plan exercisable at
March 15, 2001.
(7) None of the 75,000 shares reserved for issuance under non-qualified options
received respectively by Mr. Gose Jr. or Mr.Thomas Gose during the year
were vested at March 1, 2001 and accordingly are not included in their
beneficially owned share total above
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In December 1999, the Company retained the consulting advisory services of Mr.
Alan L. Edgar for the identification of and negotiation assistance with
potential sources of debt or equity capital investment in the Company. In
February 2000 the Company completed the private placement of 1,333,333 shares of
new common stock at a price of $2.25 per share, with Mr. Edgar's assistance.
Pursuant to the terms of his consulting agreement, upon closing, Mr. Edgar
received a 6% advisory fee totaling $180,000 and 5 year warrants, exercisable at
$3.00 per share, to purchase 133,333 shares of the Company's common stock. Mr.
Edgar was appointed to the Company's Board of Directors in May, 2000
-31-
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) Consolidated Financial Statements:
Independent Auditors' Reports. Balance Sheets, December 31, 2000 and
December 31, 1999. Statements of Operations, Years Ended December 31,
2000, August 31, 1999 and 1998, and the Four Month Transition Period
Ended December 31, 1999. Statements of Stockholders' Equity, Years
Ended December 31, 2000, August 31, 1999 and 1998, and the Four Month
Transition Period Ended December 31, 1999. Statements of Cash Flows,
Years Ended December 31, 2000, August 31, 1999 and 1998, and the Four
Month Transition Period Ended December 31, 1999. Notes to Audited
Consolidated Financial Statements.
(2) Financial Statement Schedules.
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 IncentiveStock
Option Plan filed as Exhibit A to registrant's
definitive Proxy Statement, dated February 20, 1985.
**10.4 Registrant's 1995 Flexible Incentive Plan, filed as
Exhibit A to registrant's definitive Proxy Statement,
dated April 28, 1995.
**10.5 Registrant's Form S-8 Registration Statement for its
1995 Flexible Incentive Plan, dated November 26,
1996.
**10.6 Registrant's Amendment to its 1995 Flexible Incentive
Plan, filed as Proposal II of the registrants
definitive Proxy Statement, dated January 12, 1999.
**10.7 Registrant's Plan and Agreement of Merger of The
Exploration Company with and into The Exploration
Company of Delaware, Inc., filed as Appendix A of the
registrants definitive Proxy Statement, dated January
12, 1999.
-32-
**10.8 Registrant's Certificate of Incorporation of The
Exploration Company of Delaware, Inc., filed
as Appendix B of the registrants definitive Proxy
Statement, dated January 12, 1999.
**10.9 Registrant's Certificate of Amendment of Certificate
of Incorporation of The Exploration Company of
Delaware, Inc., filed as Appendix C of the
registrants definitive Proxy Statement, dated January
12, 1999.
**10.10 Registrant's Bylaws of The Exploration Company of
Delaware, Inc., filed as Appendix D of the
registrants definitive Proxy Statement, dated January
12, 1999.
**10.11 Registrant's Rights Agreement, filed as Exhibit 4.1
of the registrants Form 8-K, dated June 29,2000 which
includes: as Exhibit A thereto, the Certificate of
Designation ofSeries A Junior Participating Preferred
Stock;as Exhibit B thereto,Form of Right Certificate;
as Exhibit C thereto, Summary of Rights to Purchase
Preferred Shares.
** Previously filed
(B) Reports on Form 8-K:
No reports on Form 8-K were filed during the quarter ended Dec. 31, 2000.
-33-
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this Report to be signed on
its behalf by the undersigned, thereunto duly authorized.
THE EXPLORATION COMPANY OF DELAWARE, INC.
Registrant
March 15, 2001 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.
Signatures Title Date
- ----------- ------------------- -------------
/s/ Stephen M. Gose, Jr.
- ------------------------
Stephen M. Gose, Jr. Chairman of the Board of Directors March 15, 2001
/s/ Thomas H. Gose
- ------------------
Thomas H. Gose Director and Assistant Secretary March 15, 2001
/s/ James E. Sigmon
- -------------------
James E. Sigmon President and Director
(Principal Executive Officer) March 15, 2001
/s/ Michael J. Pint
- -------------------
Michael J. Pint Director March 15, 2001
/s/ Robert L. Foree, Jr.
- ------------------------
Robert L. Foree, Jr. Director March 15, 2001
/s/ Alan L. Edgar
- -----------------
Alan L. Edgar Director March 15, 2001
/s/ Roberto R. Thomae
- ---------------------
Roberto R. Thomae Chief Financial Officer March 15, 2001
Vice-President-Finance
Secretary/Treasurer
(Principal Accounting Officer)
F-1
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
The Exploration Company of Delaware, Inc. and Subsidiaries
San Antonio, Texas
We have audited the consolidated balance sheets of The Exploration Company of
Delaware, Inc. and Subsidiaries (collectively referred to as "The Exploration
Company") as of December 31, 2000 and 1999, and the related consolidated
statements of operations, stockholders' equity and cash flows for the years
ended December 31, 2000, August 31, 1999 and 1998, and the four months ended
December 31, 1999. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of The Exploration
Company as of December 31, 2000 and 1999, and the results of its operations and
cash flows for the years ended December 31, 2000, August 31, 1999 and 1998, and
the four months ended December 31, 1999, in conformity with generally accepted
accounting principles.
We have also audited Schedule II of The Exploration Company for the years ended
December 31, 2000, August 31, 1999 and 1998, and the four months ended December
31, 1999. In our opinion, this schedule presents fairly, in all material
respects, the information required to be set forth therein.
AKIN, DOHERTY, KLEIN & FEUGE, P.C.
San Antonio, Texas
March 2, 2001
F-2
THE EXPLORATION COMPANY
Consolidated Balance Sheets
December 31, December 31,
2000 1999
----------- -----------
Assets
Current Assets:
Cash and equivalents $ 5,898,015 $ 3,381,793
Accounts receivable:
Joint interest owners 571,255 505,408
Oil and gas production 2,833,411 1,433,728
Prepaid expenses and other 226,916 122,475
Deferred tax asset, current portion 1,489,402 -
------------- -------------
Total current assets 11,018,999 5,443,404
Property and Equipment:
Oil and gas properties (successful efforts),
less accumulated depreciation,
depletion and amortization of $7,792,062 and $5,008,142,
and accumulated impairment of $4,882,759 and $2,805,061 13,921,843 12,760,449
Other property and equipment, less accumulated
depreciation of $268,512 and $196,211 161,762 75,461
------------- -------------
Net property and equipment 14,083,605 12,835,910
Other Assets:
Deferred tax asset, net of current portion 3,743,316 -
Other 359,721 368,564
------------- -------------
Total other assets 4,103,037 368,564
------------- -------------
Total Assets $ 29,205,641 $ 18,647,878
============= =============
See notes to audited consolidated financial statements.
F-3
THE EXPLORATION COMPANY
Consolidated Balance Sheets
December 31, December 31,
2000 1999
------------ ------------
Liabilities And Stockholders' Equity
Current Liabilities:
Accounts payable and accrued expenses $ 1,632,581 $ 1,279,238
Due to joint interest owners 2,620,644 2,479,776
Current portion of long-term debt 416,149 1,476,730
------------ ------------
Total current liabilities 4,669,374 5,235,744
Long-term debt, net of current portion 779,042 203,205
Minority interest in consolidated subsidiaries 435,489 -
Stockholders' Equity:
Preferred stock; authorized 10,000,000 shares,
issued and outstanding -0- shares - -
Common stock, par value $0.01 per share;
authorized 50,000,000 shares; issued and
outstanding 17,471,849 and 15,938,516 shares 174,718 159,385
Additional paid-in capital 43,986,983 40,651,444
Accumulated deficit (20,839,965) (27,601,900)
------------ ------------
Total stockholders' equity 23,321,736 13,208,929
------------ ------------
Total Liabilities and Stockholders' Equity $ 29,205,641 $ 18,647,878
============ ============
See notes to audited consolidated financial statements.
F-4
THE EXPLORATION COMPANY
Consolidated Statements of Operations
Year Four Months Year Year
Ended Ended Ended Ended
December 31, December 31, August 31, August 31,
2000 1999 1999 1998
----------- ------------ ---------- ---------
Revenues
Oil and gas sales $ 13,841,138 $ 3,580,765 $ 6,881,767 $ 2,886,676
Other operating income 889,978 271,324 615,608 161,601
----------- ----------- ------------ ------------
14,731,116 3,852,089 7,497,375 3,048,277
Costs and Expenses
Lease operations 1,157,291 496,950 864,675 700,381
Production taxes 990,789 261,997 471,193 178,912
Exploration expenses 3,056,466 259,625 269,344 2,290,649
Abandoned leases and equipment 1,049,017 - 323,784 1,451,880
Impairment of mineral properties 2,077,698 320,000 300,000 3,775,342
Depreciation, depletion and amortization 2,711,605 671,593 2,327,992 1,446,726
General and administrative 1,871,404 544,485 1,442,338 1,278,270
----------- ------------- ------------ ------------
Total costs and expenses 12,914,270 2,554,650 5,999,326 11,122,160
----------- ------------- ------------ ------------
Income (loss) from operations 1,816,846 1,297,439 1,498,049 (8,073,883)
Other Income (Expense):
Interest income 232,386 27,082 73,892 98,770
Interest expense (179,036) (131,872) (628,396) (260,105)
Loan fee amortization (12,000) (4,000) (12,000) (182,000)
----------- ------------ ------------ ------------
41,350 (108,790) (566,504) (343,335)
----------- ------------ ------------ ------------
Income (loss) before income
taxes and minority interest 1,858,196 1,188,649 931,545 (8,417,218)
Minority interest in income of subsidiaries (238,061) - - -
----------- ------------ ------------ ------------
Income (loss) before income taxes 1,620,135 1,188,649 931,545 (8,417,218)
Income tax benefit, net 5,141,800 - - -
----------- ------------ ------------ ------------
Net Income (Loss) $ 6,761,935 $ 1,188,649 $ 931,545 $ (8,417,218)
=========== ============ ============ ============
Earnings (Loss) Per Share
Basic $ 0.39 $ 0.07 $ 0.06 $ (0.55)
Diluted $ 0.39 $ 0.07 $ 0.06 $ (0.55)
Weighted average number of
common shares outstanding:
Basic 17,242,326 15,938,516 15,668,721 15,328,292
Diluted 17,343,957 15,991,526 15,678,567 15,328,292
See notes to audited consolidated financial statements.
F-5
THE EXPLORATION COMPANY
Consolidated Statements of Stockholders' Equity
Common Stock Additional
--------------------- Paid-in Accumulated
Shares Amount Capital Deficit Total
------ ------ ----------- ----------- -----
Balance at September 1, 1997 14,759,198 $ 147,592 $ 35,928,054 $ (21,304,876) $ 14,770,770
Conversion of debt to common stock 844,318 8,443 4,213,146 - 4,221,589
Common stock warrants exercised 10,000 100 19,900 20,000
Net loss for the year - - - (8,417,218) (8,417,218)
----------- -------- ----------- ------------ -----------
Balance at August 31, 1998 15,613,516 156,135 40,161,100 (29,722,094) 10,595,141
Issuance of common stock in
exchange for oil and gas properties 325,000 3,250 490,344 - 493,594
Net income for the year - - - 931,545 931,545
----------- -------- ----------- ------------ -----------
Balance at August 31, 1999 15,938,516 159,385 40,651,444 (28,790,549) 12,020,280
Net income for the period - - - 1,188,649 1,188,649
----------- -------- ----------- ------------ -----------
Balance at December 31, 1999 15,938,516 159,385 40,651,444 (27,601,900) 13,208,929
Issuance of common stock for cash,
net of expenses of $189,752 1,333,333 13,333 2,796,914 - 2,810,247
Issuance of common stock in
exchange for oil and gas properties 150,000 1,500 439,125 - 440,625
Common stock warrants exercised 50,000 500 99,500 - 100,000
Net income for the year - - - 6,761,935 6,761,935
----------- --------- ------------ ------------- ------------
Balance at December 31, 2000 17,471,849 $ 174,718 $ 43,986,983 $ (20,839,965) $ 23,321,736
=========== ========= ============ ============= ============
See notes to audited consolidated financial statements.
F-6
THE EXPLORATION COMPANY
Consolidated Statements of Cash Flows
Year Four Months Year Year
Ended Ended Ended Ended
December 31, December 31, August 31, August 31,
2000 1999 1999 1998
----------- ----------- --------- ---------
Operating Activities
Net income (loss) $ 6,761,935 $ 1,188,649 $ 931,545 $ (8,417,218)
Adjustments to reconcile net income(loss) to
net cash provided (used) in operating activities:
Deferred income taxes (5,232,718) - - -
Depreciation, depletion and amortization 2,711,605 671,593 2,327,992 1,446,726
Amortization of financing fees - 4,000 12,000 162,000
Abandoned leases and equipment 1,049,017 - 323,784 1,451,880
Impairment of properties 2,077,698 320,000 300,000 3,775,342
Minority interest in income of subsidiaries 238,061 - - -
Changes in operating assets and liabilities:
Receivables (1,465,530) 314,213 (1,391,683) (499,240)
Prepaid expenses and other (104,441) 133,859 (238,596) 31,346
Accounts payable and accrued expenses 494,211 1,320,288 1,593,162 864,114
------------ ----------- ------------ -----------
Net cash provided (used) in operating activities 6,529,838 3,952,602 3,858,204 (1,185,050)
Investing Activities
Development of oil and gas properties (6,290,260) (196,103) (3,448,320) (4,806,505)
Purchase of transportation and other equipment (157,702) (3,349) (31,486) (42,288)
Other assets 8,843 75,000 (10,000) -
----------- ----------- ------------ ----------
Net cash (used) in investing activities (6,439,119) (124,452) (3,489,806) (4,848,793)
Financing Activities
Proceeds from long-term debt 1,173,642 20,131 900,000 3,646,000
Payments on long-term debt (1,658,386) (1,435,004) (2,629,118) (1,500,990)
Issuances of common stock, net of expenses 2,910,247 - - 20,000
----------- ----------- ------------ ----------
Net cash provided (used) by financing activities 2,425,503 (1,414,873) (1,729,118) 2,165,010
----------- ----------- ------------ ----------
Change in Cash and Equivalents 2,516,222 2,413,277 (1,360,720) (3,868,833)
Cash and Equivalents at Beginning of Period 3,381,793 968,516 2,329,236 6,198,069
----------- ------------ ------------ ------------
Cash and Equivalents at End of Period $ 5,898,015 $ 3,381,793 $ 968,516 $ 2,329,236
=========== ============ ============ ============
Supplemental Disclosures:
Cash paid for interest $ 179,036 $ 131,872 $ 721,292 $ 82,295
Cash paid for income taxes 62,497 - - -
See notes to audited consolidated financial statements.
F-7
THE EXPLORATION COMPANY
Notes to Audited Consolidated Financial Statements
NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION AND OPERATIONS: The Exploration Company (TXCO or Company) is an
independent energy company engaged in the exploration, development, production
and acquisition of oil and gas properties. The Company's primary focus is on
developing gas reserves on properties located in Texas, and oil reserves on
properties located in South Dakota, North Dakota and Montana.
During 1999, the Company changed its State of Incorporation from Colorado to
Delaware and, as a result, changed its legal name to The Exploration Company of
Delaware, Inc. However, the Company continues to conduct all business under the
name The Exploration Company.
CONSOLIDATION: The financial statements include the accounts of the Company and
its majority-owned subsidiaries. The subsidiaries own and operate a gas pipeline
which is utilized by the Company for delivery of natural gas from some of its
Texas properties. All significant intercompany balances and transactions have
been eliminated in consolidation.
CHANGE IN FISCAL YEAR: The Company changed its fiscal year end from August 31 to
December 31, effective for the fiscal year beginning January 1, 2000. The
four-month transition period from September 1 through December 31, 1999 preceded
the start of the new year. The fiscal years ended August 31, 1999 and 1998 have
not been recast to conform to the new year end of December 31.
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.
CASH EQUIVALENTS: The Company considers all highly liquid investments with an
original maturity of three months or less to be cash equivalents.
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 is
computed using the unit-of-production method based upon recoverable reserves as
determined by the Company's independent reservoir engineers. Oil and gas
properties are periodically assessed for impairment. If the unamortized
capitalized costs of proved properties are in excess of the undiscounted future
cash flows before income taxes, the property is impaired. Future cash flows are
determined based on management's best estimate and may consider changes in
prices for the product as considered most likely to occur in future periods.
Unproved properties are also evaluated periodically and if the unamortized cost
is in excess of estimated fair value an impairment is recognized.
OTHER PROPERTY AND EQUIPMENT: Transportation and other equipment are recorded at
cost. Depreciation is computed using the straight-line method over the estimated
useful lives of the assets ranging from five to fifteen years. Major renewals
and betterments are capitalized while repairs are expensed as incurred.
FEDERAL INCOME TAXES: The Company follows the liability method of accounting for
income taxes under which deferred tax assets and liabilities are recognized for
the future tax consequences. Accordingly, deferred tax liabilities and assets
are determined based on the temporary differences between the financial
statement and tax bases of assets and liabilities, using enacted tax rates in
effect for the year in which the differences are expected to reverse.
F-8
NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - continued
EARNINGS (LOSS) PER COMMON SHARE: The Company applies SFAS No. 128, Earnings Per
Share, for calculation of "basic" and "diluted" earnings per share. Basic
earnings per share includes no dilution and is computed by dividing income
available to common stockholders by the weighted average number of common shares
outstanding for the period. Diluted earnings per share reflects the potential
dilution of securities that could share in the earnings of the Company.
FINANCIAL INSTRUMENTS: The Company's financial instruments that are exposed to
concentrations of credit risk consist primarily of cash equivalents and accounts
receivable. The Company's cash equivalents are cash investment funds which are
placed with a major financial institution. Substantially all of the Company's
accounts receivable result from oil and gas sales or joint interest billings to
third parties in the oil and natural gas industry. This concentration of
customers and joint interest owners may impact the Company's overall credit risk
in that these entities may be similarly affected by changes in economic and
other conditions. Historically, the Company has not experienced credit losses on
such receivables.
Unless otherwise specified, the Company believes the book value of the financial
instruments approximates their fair value.
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. Significant
estimates with regard to these financial statements include the estimate of
proved oil and gas reserve volumes and the related present value of estimated
future net cash flows, and the estimate of future years' earnings used as a
basis to record the deferred tax asset.
STOCK OPTIONS: The Company applies Accounting Principle Board (APB) No. 25,
Accounting for Stock Issued to Employees, and related interpretations in
accounting for all stock option plans. Statement of Financial Accounting
Standards (SFAS) No. 123, Accounting for Stock-Based Compensation, requires the
Company to provide pro forma information regarding net income as if compensation
cost for the Company's stock option plans had been determined in accordance with
the fair value based method prescribed in SFAS No. 123. To provide the required
pro forma information, the Company estimates the fair value of each stock option
at the grant date by using the Black-Scholes option-pricing model.
GOVERNMENT REGULATIONS: The Company's oil and gas operations 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 substantially comply with
applicable federal and state requirements.
RESTORATION, REMOVAL AND ENVIRONMENTAL MATTERS: The estimated costs of
restoration and removal of producing property well sites is generally less than
the estimated salvage value of the respective property; accordingly, the Company
has not provided for a liability accrual. The estimated future costs for known
environmental remediation requirements are accrued when it is probable that a
liability has been incurred and the amount of remediation costs can be
reasonably estimated. The Company is not aware of any such remediation
requirements material to its operations.
RECENT ACCOUNTING PRONOUNCEMENTS: The Financial Accounting Standards Board has
not issued any recent pronouncements not previously implemented by the Company
which would have a significant impact its financial position or on the reporting
of its operations.
F-9
NOTE B - LONG TERM DEBT
Long-term debt consists of the following at:
December 31, December 31,
2000 1999
----------- -----------
Note payable to Information Leasing Corporation, with interest at 12.61%, due in
monthly installments of $22,404, with final payment in 2005, and
collateralized by compressor equipment. $ 893,866 $ -
Note payable to Range Energy Finance Corporation, with interest at 18% and
payable from an overriding royalty interest (ORRI) granted to Range in
certain producing oil and gas properties on its Maverick County, Texas
leasehold acreage. The ORRI terminates upon final payment of the debt. - 1,015,731
Note payable to Continental Resources, Inc. with interest at 9.50%, due in
monthly installments of $30,000, with final payment in 2001, and
collateralized by certain oil and gas properties. 128,442 458,985
Note payable to Union Pacific Resources, with interest at 8%, due in monthly
installments of $10,000, with final payment in 2001, and collateralized by
certain oil and gas properties. 68,590 178,291
Installment notes with interest from 8.25% to 8.75%, due in current monthly
installments of $8,784, with final payment in 2001. 32,487 26,928
Note payable to First Federal Leasing, with interest at 22.96%, due in monthly
installments of $12,965, with final payment in 2002, and collateralized by
office equipment. 37,538 -
Note payable to DeLage Landen Financial Services, with interest at 11.85%, due
in monthly installments of $834, with final payment in 2005, and
collateralized by office equipment. 34,268 -
----------- -----------
Total long-term debt 1,195,191 1,679,935
Less current portion (416,149) (1,476,730)
----------- -----------
Long-term portion of debt $ 779,042 $ 203,205
=========== ===========
The following is a schedule of maturities of long-term debt as of December 31,
2000:
Year Ended December 31, Amount
----------------------- --------
2001 $ 416,149
2002 213,554
2003 218,358
2004 247,484
2005 99,646
-----------
$ 1,195,191
===========
F-10
NOTE C - STOCKHOLDERS' EQUITY
PREFERRED STOCK: The Company has authorized 10,000,000 shares of preferred
stock, none of which has been issued at December 31, 2000. Terms of the stock
have not been established by the Board of Directors.
STOCKHOLDER RIGHTS PLAN: On June 29, 2000, the Company adopted a Rights Plan
(the "Rights Plan") whereby a dividend of one preferred share purchase right (a
"Right") was paid for each outstanding share of TXCO common stock. The Rights
Plan is designed to enhance the Board's ability to prevent an acquirer from
depriving stockholders of the long-term value of their investment and to protect
shareholders against attempts to acquire the Company by means of unfair or
abusive takeover tactics that have been prevalent in many unsolicited takeover
attempts. The Rights will be exercisable only if a person acquires beneficial
ownership of 15% or more of TXCO common stock (an "Acquiring Person"), or
commences a tender offer which would result in beneficial ownership of 15% or
more of such stock. When they become exercisable, each Right entitles the
registered holder to purchase from TXCO .001 share of Series A Preferred Stock
("Series A Preferred Stock"), subject to adjustment under certain circumstances.
Upon the occurrence of certain events specified in the Rights Plan, each holder
of a Right (other than an Acquiring Person) may purchase, at the Right's then
current exercise price, shares of TXCO common stock having a value of twice the
Right's exercise price. In addition, if, after a person becomes an Acquiring
Person, TXCO is involved in a merger or other business combination transaction
with another person in which TXCO is not the surviving corporation, or under
certain other circumstances, each Right will entitle its holder to purchase, at
the Right's then current exercise price, shares of common stock of the other
person having a value of twice the Right's exercise price. The Rights Plan
generally may be amended by the Company without the approval of the holders of
the Rights prior to the public announcement by TXCO or an Acquiring Person that
a person has become an Acquiring Person.
Unless redeemed by TXCO earlier, the Rights will expire on June 29, 2010. The
Company will generally be entitled to redeem the Rights in whole, but not in
part, at $0.01 per Right, subject to adjustment. No Rights were exercisable
under the Rights Agreement at December 31, 2000.
STOCK OPTIONS: The Company grants options to its officers, directors, and key
employees under its 1995 Flexible Incentive Plan. In 1998, the Company also
issued options for the purchase of 600,000 shares of common stock under a
nonqualified plan. The Company has elected to follow Accounting Principles Board
Opinion No. 25, "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 employee stock options equals or exceeds the market price of the
underlying stock on the date of grant, no compensation expense is recognized.
The Company's 1995 Flexible Incentive Plan, as amended, was authorized to grant
options to management, directors, and key personnel for up to 1,500,000 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.
F-11
NOTE C - STOCKHOLDERS' EQUITY - continued
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 1994
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:
Year Four Months Year Year
Ended Ended Ended Ended
December 31, December 31, August 31, August 31,
2000 1999 1999 1998
----------- ----------- --------- ---------
Risk-free interest rate 5.11% 6.48% 5.0% 4.0%
Dividend yield 0% 0% 0% 0%
Volatility of common stock .67 1.21 .95 .69
Weighted-average expected life of option 5 years 5 years 5 years 5 years
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:
Year Four Months Year Year
Ended Ended Ended Ended
December 31, December 31, August 31, August 31,
2000 1999 1999 1998
----------- ----------- --------- ---------
Pro forma earnings (loss) $ 6,241,705 $ 1,122,238 $ 695,970 $ (8,608,865)
Pro forma earnings (loss) per common share:
Basic $ 0.36 $ 0.07 $ 0.04 $ (0.56)
Diluted 0.36 0.07 0.04 N/A
F-12
NOTE C - STOCKHOLDERS' EQUITY - continued
A summary of the status of the Company's stock option activity and related
information is as follows:
Weighted Weighted
Average Exercisable Average
Fair Value of at End Exercise
Options Granted of Period Shares Price
--------------- --------- ------ --------
Outstanding at August 31, 1997 439,800 $ 4.06
Granted $ 0.48 600,000 2.12
Exercised (10,000) 2.00
Forfeited - -
----------
Outstanding at August 31, 1998 379,800 1,029,800 2.95
Granted $ 0.95 139,000 1.20
Exercised - -
Forfeited (124,000) 2.70
----------
Outstanding at August 31, 1999 334,800 1,044,800 2.72
Granted $ 1.21 164,000 2.12
Exercised - -
Forfeited - -
----------
Outstanding at December 31, 1999 389,800 1,208,800 2.66
Granted $ 1.39 375,000 2.98
Exercised - -
Forfeited (150,000) 6.60
----------
Outstanding at December 31, 2000 526,800 1,433,800 2.33
==========
The following table summarizes information about the options outstanding at
December 31, 2000:
Options Outstanding Options Exercisable
------------------------------------------------------- -------------------------------
Weighted-Average
Number Remaining Weighted-Average Number Weighted-Average
Exercise Price Outstanding Contractual Life Exercise Price Exercisable Exercise Price
-------------- ----------- ---------------- -------------- ----------- --------------
$ 0.98 25,000 7.92 years $ 0.98 25,000 $ 0.98
1.25 110,000 7.67 years 1.25 110,000 1.25
2.125 764,000 7.92 years 2.12 82,000 2.12
2.62 50,000 5.67 years 2.62 50,000 2.62
2.75 100,000 4.08 years 2.75 100,000 2.75
2.78 75,000 9.42 years 2.78 - 2.78
3.03 300,000 4.33 years 3.03 150,000 3.03
3.91 9,800 1.00 year 3.91 9,800 3.91
---------- -----------
1,433,800 526,800
========== ===========
F-13
NOTE C - STOCKHOLDERS' EQUITY - continued
Stock Warrants: The following is a summary of warrants
outstanding at December 31, 2000:
Weighted Weighted
Number Range of Average Average
Purpose of Warrants of Shares Prices Exercise Price Contractual Life
-------------------------- --------- ------------- -------------- ----------------
Convertible notes and equity financing 1,566,429 $ 2.88 - $ 6.00 $ 3.06 4 years
NOTE D - EARNINGS PER SHARE
The following is a reconciliation of the numerator and denominators of the basic
and diluted earnings per share computation:
Per Share
Shares Income Amount
------ ------ --------
Year Ended December 31, 2000:
Basic EPS:
Net income 17,242,326 $ 6,761,935 $ 0.39
Effect of dilutive options 101,631 - -
----------- ----------- ------
Dilutive EPS 17,343,957 $ 6,761,935 $ 0.39
=========== =========== ======
Four Months Ended December 31, 1999:
Basic EPS:
Net income 15,938,516 $ 1,188,649 $ 0.07
Effect of dilutive options 53,010 - -
----------- ----------- ------
Dilutive EPS 15,991,526 $ 1,188,649 $ 0.07
=========== =========== ======
Year Ended August 31, 1999:
Basic EPS:
Net income 15,668,721 $ 931,545 $ 0.06
Effect of dilutive options 9,846 - -
----------- ----------- ------
Dilutive EPS 15,678,567 $ 931,545 $ 0.06
=========== =========== ======
Year Ended August 31, 1998:
Basic EPS:
Net income 15,328,292 $ (8,417,218) $ (0.55)
Effect of dilutive options - - -
----------- ------------- -------
Dilutive EPS 15,328,292 $ (8,417,218) $ (0.55)
=========== ============ =======
F-14
NOTE E - OPERATING LEASES
The Company leases its primary office space through February 2005. The Company
incurred rent expense of $133,000, $95,000 and $94,000 for the years ended
December 31, 2000 and August 31, 1999 and 1998, and $33,000 for the four months
ended December 31, 1999. Future minimum rentals under all noncancelable real
estate leases are as follows:
Year Ended December 31, Amount
----------------------- --------
2001 $ 145,000
2002 149,000
2003 153,000
2004 156,000
2005 26,000
NOTE F - INCOME TAXES
In prior years, the Company did not incur a federal or state income tax expense
due to the utilization of tax net operating losses, nor did it receive a tax
benefit as its deferred tax assets were fully reserved.
For the year ended December 31, 2000, the components of the Company's income
taxes were as follows:
Current federal tax expense $ 90,918
Deferred federal tax (benefit) (5,232,718)
------------
Income tax (benefit), net $ (5,141,800)
============
The following items give rise to the deferred tax assets and liabilities:
December 31, December 31,
2000 1999
----------- -----------
Deferred tax assets:
Tax net operating loss carryforwards $ 5,480,000 $ 7,310,000
Impairment of oil and gas and mineral properties 1,660,000 986,000
----------- -----------
Net deferred tax assets 7,140,000 8,296,000
Less valuation allowance (1,907,282) (8,296,000)
----------- -----------
Deferred income tax asset recorded $ 5,232,718 $ -
=========== ===========
F-15
NOTE F - INCOME TAXES - continued
The differences between the statutory federal income taxes and the Company's
effective taxes are as follows:
Four Months
Year Ended Ended Year Ended Year Ended
December 31, December 31, August 31, August 31,
2000 1999 1999 1998
---------- ----------- ---------- ----------
Statutory federal taxes $ 551,000 $ 404,000 $ 317,000 $ (2,862,000)
Change in valuation allowance (6,388,718) (387,600) (1,072,020) 3,275,140
Other changes 695,918 (16,400) 755,020 (413,140)
------------- ----------- ------------ ------------
Income tax expense (benefit) $ (5,141,800) $ - $ - $ -
============= =========== ============ ============
Prior to 2000, the Company provided a valuation allowance equal to its net
deferred tax asset, since it had a history of financial and tax losses. SFAS 109
required the valuation allowance since it was more likely than not such deferred
tax assets would not be realized.
However, the Company has undergone significant strategic changes during the last
few years. It has impaired or abandoned over $5.4 million on certain unproved
leasehold acreage during the past three and a half years, minimizing its
remaining exposure on its unproved acreage positions. At the same time, it has
significantly increased its revenues from its producing acreage. As a result,
the Company is now in position to take advantage of the economic recovery which
began in the oil and gas industry several years ago. The Company has
consistently increased income before income taxes for the last two and one-half
years and management now believes it is more likely than not that a significant
portion of its deferred income tax asset will be realized. Therefore, the
valuation allowance has been reduced and a deferred tax asset recognized for the
amount expected to be realized through taxable earnings. In determining the
valuation allowance, the Company uses three year income projections reduced by
graduating percentages to compensate for uncertainties inherent in future years'
projections. Regardless of management's expectations, there can be no assurance
that the Company will generate any specific level of continuing earnings.
The Company has available net operating loss carryforwards of approximately
$16,100,000 ($5,480,000 tax benefit) at December 31, 2000, which expire from
2006 to 2015.
NOTE G - MAJOR CUSTOMERS
Sales to unrelated entities which individually comprised greater than 10% of
total oil and gas sales as follows:
A B C D E
--- --- --- --- ---
Year ended December 31, 2000 28% 26% 18% <10% <10%
Four months ended December 31, 1999 28% <10% 57% <10% <10%
Year ended August 31, 1999 23% <10% 55% <10% <10%
Year ended August 31, 1998 20% <10% <10% 34% 28%
F-16
NOTE H - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
YEAR ENDED DECEMBER 31, 2000
The Company issued 150,000 shares of its common
stock for commissions it was charged related to the acquisition of
leasehold acreage.
YEAR ENDED AUGUST 31, 1999
The Company issued 325,000 shares of its common stock
in exchange for oil and gas properties (valued at the market price per
share for unregistered stock).
YEAR ENDED AUGUST 31, 1998
The Company converted $4,000,000 of convertible notes
payable and $221,590 of accrued interest into 844,318 shares of its common
stock.
The Company converted $1,684,000 of accounts payable into long-term debt.
NOTE I - 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:
December 31, December 31,
2000 1999
------------ ------------
Proved properties $ 18,243,408 $ 13,315,233
Less reserve for impairment (2,797,408) (2,323,584)
Less accumulated depreciation,
depletion and amortization (7,792,062) (5,008,142)
------------ ------------
Net proved properties 7,653,938 5,983,507
Unproved properties 8,353,256 7,258,419
Less reserve for impairment (2,085,351) (481,477)
------------ ------------
Net unproved properties 6,267,905 6,776,942
------------ ------------
Net capitalized cost $ 13,921,843 $ 12,760,449
============ ============
Costs incurred, capitalized, and expensed in oil and gas producing activities
are as follows:
Year Four Months Year Year
Ended Ended Ended Ended
December 31, December 31, August 31, August 31,
2000 1999 1999 1998
----------- ----------- --------- ---------
Property acquisition costs, unproved $ 2,319,285 $ 35,900 $ 890,418 $ 1,232,000
Property development and exploration costs 7,468,066 1,396,125 3,340,702 6,286,745
Depreciation, depletion and amortization 2,625,924 654,592 2,281,758 1,103,181
Depletion per equivalent Mcf of production .79 .52 .69 .93
F-17
NOTE I - OIL AND GAS PRODUCING ACTIVITIES AND PROPERTIES - continued
OIL AND GAS RESERVES (UNAUDITED)
The estimates of the Company's proved reserves and related future net cash flows
that are presented in the following tables are based upon estimates made by
independent petroleum engineering consultants.
The Company's reserve information was prepared as of each respective period end.
The Company cautions that there are many inherent uncertainties in estimating
proved reserve quantities, projecting future production rates, and timing of
development expenditures. Accordingly, these estimates are likely to change as
future information becomes available. Proved developed reserves are the
estimated quantities of crude oil, condensate, natural gas and natural gas
liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions.
Estimated quantities of proved developed reserves of oil and gas (all of which
are located within the United States) as well as the changes in proved reserves,
are as follows:
Oil Gas
(Barrels) (Mcf)
--------- -------
Reserves at August 31, 1997 ....................... 245,700 2,156,100
Discoveries ................................... 70,700 4,541,500
Revisions of previous estimates ............... (136,662) 117,852
Production .................................... (79,138) (713,752)
--------- ----------
Reserves at August 31, 1998 ....................... 100,600 6,101,700
Discoveries ................................... 32,000 2,803,000
Purchases of minerals in place ................ 1,600 338,000
Revisions of previous estimates ............... 53,800 (166,700)
Production .................................... (82,000) (2,813,000)
--------- ----------
Reserves at August 31, 1999 ....................... 106,000 6,263,000
Discoveries ................................... 4,500 461,000
Revision of previous estimates ................ 6,500 218,000
Production .................................... (24,000) (1,119,000)
--------- ----------
Reserves at December 31, 1999 ..................... 93,000 5,823,000
Discoveries ................................... 5,593 2,126,000
Revisions of previous estimates ............... 144,407 (452,000)
Production .................................... (60,000) (2,965,000)
--------- ----------
Reserves at December 31, 2000 ..................... 183,000 4,532,000
========= ==========
F-18
NOTE I - OIL AND GAS PRODUCING ACTIVITIES AND PROPERTIES - continued
The following table sets forth a standardized measure of the estimated
discounted future net cash flows attributable to the Company's proved developed
oil and gas reserves. Prices used to determine future cash inflows were based on
the respective year end weighted average sales prices utilized for the Company's
proved developed reserves which were $11.04, $1.99, $2.58 and $1.84 per Mcf of
gas and $25.67, $25.39, $19.03 and $10.23 per barrel of oil as of December 31,
2000 and 1999 and August 31, 1999 and 1998. The future production and
development costs represent the estimated future expenditures to be incurred in
developing and producing the proved reserves, assuming continuation of existing
economic conditions. Future income tax expense was computed by applying
statutory income tax rates to the difference between pretax net cash flows
relating to the Company's reserves and the tax basis of proved oil and gas
properties and available operating loss and temporary differences.
Year Four Months Year Year
Ended Ended Ended Ended
December 31, December 31, August 31, August 31,
2000 1999 1999 1998
------------ ------------ ------------ ------------
Future cash inflows $ 54,747,000 $ 15,158,000 $ 17,370,000 $ 11,872,000
Future production and development costs (10,516,000) (2,411,000) (2,484,000) (1,327,000)
------------ ------------ ------------ ------------
Future net cash inflows before income tax 44,231,000 12,747,000 14,886,000 10,545,000
Future income tax expense (6,045,000) - - -
------------ ------------ ------------ ------------
Future net cash flows 38,186,000 12,747,000 14,886,000 10,545,000
10% annual discount to reflect timing of
net cash flows (6,226,000) (2,648,000) (2,441,000) (1,721,000)
------------ ------------ ------------ ------------
Standardized Measure of discounted future
net cash flows relating to proved reserves $ 31,960,000 $ 10,099,000 $ 12,445,000 $ 8,824,000
============ ============ ============ ============
The principal factors comprising the changes in the standardized measure of
discounted future net cash flows is as follows:
Year Four Months Year Year
Ended Ended Ended Ended
December 31, December 31, August 31, August 31,
2000 1999 1999 1998
----------- ----------- --------- ---------
Standardized Measure, beginning of year $ 10,099,000 $ 12,445,000 $ 8,824,000 $ 4,732,000
Discoveries 5,935,500 903,000 6,810,000 7,683,000
Purchases of minerals in place - - 350,000 -
Sales and transfers, net of production costs (11,693,058) (2,821,818) (5,545,899) (2,007,383)
Revisions in quantity and price estimates 31,208,458 817,318 2,888,899 (1,110,417)
Net change in income taxes (2,580,000) - - -
Accretion of discount (1,009,900) (1,244,500) (882,000) (473,200)
------------ ------------ ------------ -----------
Standardized Measure, end of year $ 31,960,000 $ 10,099,000 $ 12,445,000 $ 8,824,000
============ ============ ============ ===========
F-19
THE EXPLORATION COMPANY
Schedule II - Valuation and Qualifying Reserves
Balance Charged to Balance
Beginning Costs and End of
of Period Expense Deductions Period
--------- --------- ---------- --------
Year Ended December 31, 2000
Allowance for doubtful accounts,
trade accounts $ 27,000 $ - $ - $ 27,000
Impairment of oil and gas properties 2,805,061 2,077,698 - 4,882,759
Deferred tax asset valuation allowance 8,296,000 - (6,388,718) 1,907,282
Four Months Ended December 31, 1999
Allowance for doubtful accounts,
trade accounts $ 27,000 $ - $ - $ 27,000
Impairment of oil and gas properties 2,485,061 320,000 - 2,805,061
Deferred tax asset valuation allowance 8,683,600 - (387,600) 8,296,000
Year Ended August 31, 1999
Allowance for doubtful accounts,
trade accounts $ 27,000 $ - $ - $ 27,000
Impairment of oil and gas properties 3,894,739 300,000 (1,709,678) 2,485,061
Deferred tax asset valuation allowance 9,755,620 - (1,072,020) 8,683,600
Year Ended August 31, 1998
Allowance for doubtful accounts,
trade accounts $ - $ 27,000 $ - $ 27,000
Impairment of loan to ExproFuels, Inc. 845,487 - (845,487) -
Impairment of oil and gas properties 119,397 3,775,342 - 3,894,739
Deferred tax asset valuation allowance 6,480,480 3,275,140 - 9,755,620