1
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001
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 $44,926,311
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 15, 2002.
The number of shares outstanding of the Registrant's Common Stock as of
March 15, 2002 was 17,397,049 of which 14,515,771 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................................................................................... 14
Item 3. Legal Proceedings............................................................................ 21
Item 4. Submission of Matters to a Vote of Security Holders.......................................... 21
PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters.................................................................. 22
Item 6. Selected Financial Data...................................................................... 22
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations........................................................................ 23
Item 7A. Quantitative and Qualitative Disclosures About Market Risk................................... 31
Item 8. Consolidated Financial Statements and Supplementary Data .................................... 32
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure......................................................................... 32
PART III
Item 10. Directors and Executive Officers of the Registrant........................................... 32
Item 11. Executive Compensation....................................................................... 34
Item 12. Security Ownership of Certain Beneficial Owners
and Management............................................................................... 36
Item 13. Certain Relationships and Related Transactions............................................... 38
PART IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K.......................................................................... 38
Signatures................................................................................................ 40
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 opportunities
arise, the Company may selectively participate 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 core area competencies 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 primarily through internally generated operating
cash flows, while combining debt financing, equity offerings or sale of
interests in properties when favorable terms or opportunities are available.
Prior to 1992, the Company's revenues were derived principally from the sale of
natural oil and gas production from working, royalty and mineral interests, as
well as sales of mineral interests acquired through leasing activities. From
1992 through 1996 the Company expanded its scope of 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 majority equity
interest spun-off via stock dividend to TXCO shareholders.
The continued availability of new equity and debt capital in 1998 through 2001,
combined with the re-investment of TXCO's growing positive cash provided from
operations, reaffirmed Management's ongoing strategy for improved shareholder
value by maintaining its focus on its core business of oil and gas exploration
and production. This strategy has allowed the Company to attract recognized
industry partners, expand its core area leasehold acreage, increase its 3-D
seismic database and interpretative skill set, and dramatically grow its reserve
base while maintaining a conservative debt profile and growing through its drill
bit success. Although measured progress was achieved during the year ended
December 31, 2001, TXCO experienced the same challenges as many U.S. based
exploration and production companies given the current industry conditions, the
continuing volatile commodity price environment and tragic world events. In
response to deteriorating market dynamics, prior to year-end 2001 the Company
curtailed its record level drilling activities, conserving liquidity while
awaiting meaningful improvements in industry conditions. Even though it
significantly reduced its discretionary cash expenditure levels during the last
quarter, the Company finished the year with a working capital deficit of over
$1,550,000 at December 31, 2001. The combination of price volatility in
commodity, exploration and operating costs together with slightly declining
production from its older, maturing gas wells resulted in marginally lower
operating revenues of $14,509,000 and a net loss of $50,283 for 2001 as compared
to revenues of $14,731,000 and net income of $6,761,000 in year 2000. While no
similar benefit was reflected in 2001 earnings, net income for 2000 included the
impact of a deferred federal income tax benefit of $5,232,700 reflecting the
cumulative future tax benefit of a portion of its net operating loss carry
forwards from past losses.
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The Company was otherwise successful in achieving significant progress and
record growth during 2001 in many key areas of operations. Record 2001 results
included a 339% reserve replacement, an increase of 9.06 Bcfe of gas reserve
additions from 73 drilled or re-entered wells with an 81% success rate, and
record positive cash provided from operations of $8,564,000. The following table
illustrates key features of the Company's continuous development over the 4
fiscal years presented.
Dec-2001 Dec-2000 Aug-1999 Aug-1998
-------- -------- -------- --------
No. of new gas wells added 54 6 6 4
No. of new oil wells added 9 3 2 2
Gas Production in Mcf 2,673,000 2,965,000 2,813,000 713,752
Gas Reserve Additions (Mcf) from drilling 8,664,000 2,126,000 2,803,000 4,541,500
Oil Production in Bbl 50,000 60,000 82,000 79,138
Oil Reserve Additions (Bbl) from drilling 66,000 5,000 32,000 70,700
Operating Revenues $14,509,487 $14,731,116 $7,497,375 $3,048,277
Net Income (Loss) $ (50,283) $ 6,761,935 $ 931,545 ($8,417,218)
Net cash provided (used) from operations $8,564,022 $ 6,529,838 $3,858,204 ($ 1,185,050)
Non-developed Texas acreage leased 372,000 365,000 95,000 56,000
Non-developed Williston Basin acreage leased 105,000 302,000 380,000 543,000
Over the last four years, TXCO has developed its natural gas production base
significantly. This overall growth is primarily attributable to ongoing drilling
activities and the acquisition of significant new non-developed leasehold
acreage in the 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 sales of 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 and 1998.
While the Company's production levels trended upward from 1998 to 2000,
operating profitability was finally established during 1999 for the first time
in TXCO's recent history, overcoming 1999's erratic commodity prices.
Improvements in gas prices during 2000 allowed TXCO to maintain its
profitability, providing record levels of cash from operations which were
further leveraged through drill bit success from growing exploration activities.
During 2001 realized gas prices ranged from over $10.50 per Mcf in January to a
low of $1.26 per Mcf in October. While profitability was not sustainable in 2001
due in large part to continued volatility in oil and gas prices, TXCO's
continued drill bit success added over 9.06 Bcfe of proved reserves and
established a record reserve replacement of 339%. The reserve additions far
exceeded the Company's 2001 production levels, and compared most favorably to
the recent domestic U.S. industry reserve replacement rate of 144%, as published
by the U.S. Department of Energy. Proved reserves increased 126% by year-end and
year over year equivalent gas production decreased by 11% in 2001. The decrease
is indicative of the maturing profile of the Company's existing Glen Rose reef
gas wells, the primary source of TXCO's historical gas production. In 2002, the
Company expects to significantly grow its production levels by exploiting the
record level of low risk, proved undeveloped locations contained in its growing
oil and gas reserve base.
TXCO's operating strategy includes the pursuit of multiple growth opportunities
begun in 2001 and carried over into 2002, based on diversification in
exploration targets within its core area of operations. By aggressively
expanding its surrounding lease holdings where geology indicates the likely
continuation of known or prospective oil and gas producing formations, TXCO is
well positioned to pursue new oil and gas reserves and expand its production
base. The Maverick Basin offers this diversity in its multiple hydrocarbon
bearing horizons. During 2001, the Company expanded its Maverick Basin lease
block to over 372,000 essentially contiguous acres and successfully completed a
record 54 new gas wells in diverse horizons including the Glen Rose, the Olmos
coals, the Escondido sands, the McKnight and the Georgetown intervals. An
additional 9 new oil wells were completed in varying horizons including the San
Miguel, the Austin Chalk and the Edwards formations.
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During 2001, the Company made significant strides in diversifying its oil and
gas exploration efforts by identifying and pursuing the exploration of at least
five new exploration targets in addition to targeting new Glen Rose reef-based
gas production. Following up on its 63 new oil and gas well completions in 2001,
new exploration targets for 2002, in descending depth order, are: first,
developing additional gas production from the Escondido sands; second,
accelerating Coal Bed Methane (CBM) gas production from dewatering Olmos coals;
third, expanding water flood oil production from the San Miguel interval;
fourth, continuing horizontal drilling for Glen Rose shoal gas production; and
fifth, increasing efforts to initiate drilling by operating partners in pursuit
of deep Jurassic formation gas. Each of these exploration targets has the
potential to establish meaningful additions to TXCO's oil and gas reserves and
significant numbers of new proved undeveloped and lower risk drilling locations.
The enhanced risk profile and growth potential of the Company's exploration and
development plans are evidenced by the robust 339% rate of reserve replacement
during 2001. The Company estimates it has at least 225 Bcfe of net unrisked
reserve potential to be developed on its existing acreage during the next three
years.
Should its exploration and development plans progress as intended, the Company
expects to continue the rapid growth of its oil and gas reserves in 2002 and to
attain meaningful growth in oil and gas production levels. Pending further
improvements in expected oil and gas prices going forward and the establishment
of meaningful new levels of oil and gas production from its 1st quarter 2002
drilling results, TXCO has designed a conservative capital expenditure budget of
$6.6 million for 2002. Initial plans target 19 new wells primarily aimed at
expanding production and proved gas reserves from the Glen Rose interval. This
level of expenditure is primarily dependent on TXCO maintaining sufficient
positive operating cash flow levels, and also relies on approximately 1/3 of the
expenditures to be funded from the Company's recently announced $25 million
revolving credit facility with Hibernia National Bank. The initial borrowing
base of $5 million is determined as a percentage of the discounted value of the
Company's oil and natural gas reserves. Based on TXCO's continuing drilling
success in 2002, the Company expects it will have sufficient working capital
available to minimize required borrowings, continue growing its oil and gas
reserve base and expects to return to profitability by year end. Although there
is no assurance the Company will be successful in maintaining its ongoing
drilling success at sufficient levels to return to profitability during 2002,
Management retains its ability to modify its capital expenditure program
consistent with its available liquidity in order to continue to meets its
ongoing operating and debt service obligations.
PRINCIPAL AREAS OF ACTIVITY
OIL AND GAS OPERATIONS
Throughout 2001, the Company has been actively developing its core mineral
interests in the Maverick Basin in South Texas, and re-evaluating its economic
alternatives related to its remaining properties in the Williston Basin of North
Dakota. These activities included the drilling or re-entry of 73 wells in South
Texas during 2001. 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. Marginally decreasing Maverick Basin gas production
during 2001 combined with historically high gas prices resulted in improved
positive cash flows for the first three quarters of the year. However, the
benefits were shortlived, as gas prices fell during the fourth quarter. 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
most of the Company's oil leases are located. The Company's strategy remains
focused on its core gas producing and higher margin exploration activities in
the Maverick Basin.
MAVERICK BASIN
The Company has owned at least a 50% leasehold interest in over 50,000
contiguous acres in Maverick County, Texas since 1989. These holdings have
increased to 372,000 acres through 2001. 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. Ten years ago, 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.
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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, while the shallower intervals
have provided alternative completion targets for these 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 100% 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. In 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 contiguous to 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 step-out 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.
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 through
December 31, 1999, TXCO initiated drilling on 3 gas prospects, one each on its
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. Expansion of the
Company's 3-D seismic database also progressed during this period, as TXCO
completed the acquisition of an additional 31,700 acres of seismic data over a
portion of newly leased acreage contiguous and north of the Paloma lease. At
January 1, 2000, leased acreage totaled approximately 115,000 acres. During the
transition period, TXCO also completed negotiations and entered 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.
TXCO participated in drilling a total of 25 new gas, oil or CBM prospects and 2
re-entries during 2000. Of the drilled wells, 5 were 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 2000.
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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. 1 Burr oil well and 1 Williston basin oil well were completed during
2001. The remaining 4 wells are in varying stages of completion at year end
2001and include 2 Paloma wells, and 1 well each on the Alkek and Wipff lease in
Texas.
CBM GAS PILOT PROGRAM
TXCO ended 2001 firmly entrenched at the forefront of Texas-based exploration
for CBM gas production. The United States Geological Survey (USGS) credited TXCO
with the establishment of the first CBM field in Texas, recognizing the
Company's Farias #5-110 well, completed in April 2001, as the discovery well.
The Texas Railroad Commission assigned the name "Sacatosa (CBM Olmos) Field" to
the extensive coal deposits which extend across approximately 250,000 acres of
TXCO's lease block under its Comanche and Chittim leases. Eager to encourage the
continuing development of this potential new source of CBM gas, the USGS formed
a cooperative research effort with TXCO to determine the gas in place, rank,
quality, extent and thickness of the Olmos coals in order to fully assess the
resource potential of the new CBM field. The USGS drilled two CBM wells on the
Comanche lease with TXCO under their agreement, collecting extensive amounts of
samples and data for further laboratory testing and evaluation. Extensive
desorption and adsorption tests on these wells as well as 10 additional core
tests confirmed the coals were gas-saturated. Published coal quality data
confirmed the Olmos coals are classified as having the favorable ranking of
high-volatile C bituminous coal, which is preferable for potential CBM
production. Additional measurements indicated samples of Olmos coal from the
Sacatosa (CBM Olmos) Field from varying depths contained quantities of CBM gas
ranging to as much as 350 standard cubic feet per ton of coal. Further study
confirmed the thickness, depth and gas content of the Olmos coals were similar
to coals in other established and commercially productive CBM basins such as the
Black Warrior in Alabama, the Cherokee Basin in Oklahoma and the Raton Basin in
New Mexico and Colorado.
Based on the encouraging results of its exploratory core and well drilling
program for CBM gas in 2000 and 2001, TXCO significantly expanded its CBM
activities in 2001 by drilling or re-entering 44 prospective CBM wells and
establishing 4 separate CBM pilot projects. TXCO is currently dewatering 34 of
the wells in its CBM pilot program targeting CBM gas production from the
multiple seams of high-volatile bituminous coal present under its leases.
Current CBM production from these pilot projects has reached as much as 175 Mcf
per day, with water production approaching 2000 barrels per day. Though
quantities of CBM gas are still increasing, the overall gas volumes currently
produced have not yet reached economic levels. Additionally, adsorption analysis
indicates that the reservoir pressure has not decreased below the level
necessary for the CBM gas to desorb from the coal. The Company expects to
establish economic production quantities of CBM gas during the second half of
2002.
SAN MIGUEL OIL WATER FLOOD PROJECTS
The large volume of water typically produced in the dewatering phase of CBM
production normally represents a significant component of the operating expense
in the production of CBM gas. However, in conjunction with its CBM dewatering
projects, TXCO has engineered a synergistic water disposal cost reduction
program to dispose of the CBM water into a neighboring formation. In September
2001, TXCO initiated a water flood injection pilot program targeting oil
production from the San Miguel formation, located about 400 feet below the base
of the Olmos coal interval. A proven San Miguel water flood oil-field directly
offsets the northern boundary of TXCO's Comanche lease. Conoco's Sacatosa (San
Miguel) Field has produced over 40 million barrels of oil and 19 Bcf of gas
since its discovery in 1956. Conoco began water flooding the San Miguel sand
interval in 1966 and continues to successfully operate the huge field. Initial
geologic and engineering studies indicate the San Miguel sand interval under the
Comanche lease is a look-alike structure in size and structural position
relative to Conoco's adjacent San Miguel water flood field. Using its increased
volumes of CBM water production, TXCO added a second San Miguel water flood
pilot subsequent to year-end 2001. Additional operating efficiencies were gained
by re-entering existing vertical well bores as prospective San Miguel oil
producers. Company engineers selected and re-entered existing horizontal well
bores in close proximity to the vertical wells in each of the pilots for
recompletion as water injection wells. To date, initial response from these
early stage water injection pilots has been very encouraging. TXCO hopes to add
significant additional proved oil reserves during 2002 from the planned
expansion of its new San Miguel water flood program.
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GLEN ROSE REEF OIL DISCOVERY
During 2001, the Company significantly advanced its joint venture with Saxet
Energy, Ltd. (Saxet), a privately held Houston exploration company, and Tom
Brown, Inc. (NasdaqNM: TMBR), a $1 billion Denver based independent covering
TXCO's 100,000 acre Comanche Ranch prospect. The Company sold a 50% working
interest (Saxet 20% and Tom Brown 30%) in its rights below the base of the San
Miguel formation. During 2001 the joint venture partners completed the
acquisition of a proprietary 100-square mile 3-D seismic survey covering the
western half of the Comanche Prospect, including Saxet's Cinco Ranch lease on
the western flank of the Comanche acreage. Based on early interpretation of the
western-most portion of the seismic survey, a well targeting the Glen Rose
formation was spudded in June 2001 on the Cinco Ranch portion of the prospect.
Unfortunately the reef was water bearing. Additional completion attempts in the
overlying Georgetown and Austin Chalk formations did not encounter economic
quantities of hydrocarbons. By year-end 2001, the partners completed the
acquisition and processing of the entire 3-D survey. An additional 30
seismically defined Glen Rose reefs were identified and a second well was
planned targeting a particularly attractive prospect on TXCO's Comanche lease
which contained evidence of multiple Glen Rose reefs stacked over a previously
unidentified structure.
Subsequent to the end of the year, Saxet spudded the Comanche 1-111 well in
February 2002, the first well to target a Glen Rose reef on the Comanche lease
since its acquisition. The well encountered significant oil flows from a depth
of approximately 6,500 feet. The well produced approximately 5,000 barrels of
light crude oil in a 24-hour period before the operator was able to stop the
flow. The well was subsequently completed and tested rates up to 3,600 BOPD on a
28/64" choke with tubing pressure of 495 psi before being curtailed due to a
lack of surface facilities to handle the large volume of oil. The well has been
continually flowed at a rate of 500 BOPD on a 10/64" choke with tubing pressure
of 735 psi over a week later. TXCO (50%WI) and its partner Saxet (50%) have
established the oil discovery is in a large reef complex approximately 850 acres
in size with 55 feet of net pay. Drilling on a delineation well commenced March
27, 2002. The Comanche 1-2 well was spudded approximately 4,500 feet northeast
of the Comanche 1-111 discovery well. The Company and its partner are in process
of filing an application for the establishment of new field discovery allowable
producing rules. The Company believes the Texas Railroad Commission will
establish an allowable rate of up to 1,000 barrels of oil per day on wells in
the new field. Although reserves have not been determined at this time, TXCO
expects that they will significantly impact the Company.
This discovery, while potentially very important by itself, may lead to
additional discoveries from other reefs situated similarly across the Comanche
lease. The Company is currently in process of modifying its original 2002
drilling schedule to accommodate additional Comanche lease Glen Rose wells
targeting oil bearing reefs. Due to the success of the Comanche 1-111 oil well,
TXCO expects to realize a material increase in its borrowing base under its
recently announced reserve backed Credit Facility with Hibernia National Bank.
This new component of TXCO's growing reserve base is another strong confirmation
of the multiple horizon/completion characteristic of the Company's lease block
in the Maverick Basin.
GLEN ROSE SHOAL HORIZONTAL GAS DISCOVERY
During the third quarter of 2001, TXCO announced the discovery of a horizontal
Glen Rose shoal gas play on a portion of its Chittim lease. Company geologists
had detected the presence of a large carbonate shoal (or carbonate "sand" bar)
located within the Glen Rose interval. The target area provided good well
control from nearby vertical producing wells which had logged or otherwise
penetrated the structure while attempting completions in other oil or
gas-bearing horizons. Based on their knowledge of the interval, Company
engineers designed a well with a horizontal displacement of 3,750 in a promising
and well-defined section of a large Glen Rose shoal at a vertical depth of 5,300
feet. The Chittim 1-141 gas well (48% WI) was completed in September 2001 with a
calculated absolute open flow rate (AOF) of 4,690 MMcfpd with flowing pressure
of 1,300 psi. The well was placed on production on October 2, 2001 at a rate of
2,042 MMcfpd with flowing pressure of 1,360 psi. Based on this discovery,
Company engineers identified 12 proved, undeveloped locations from the targeted
Glen Rose shoal. At December 31, 2001 the Company's independent engineering firm
estimated the proved undeveloped reserves represented by the 12 locations to be
5.3 Bcf of natural gas. TXCO plans for 2002 include drilling 6 low-risk
horizontal Glen Rose shoal wells commencing in February 2002.
9
Subsequent to the end of the year, TXCO spudded the Chittim 1-142 (48% WI) on
February 5, 2002. The well was drilled to a vertical depth of 5,350 feet with a
horizontal displacement of 3,650 feet and completed as a horizontal gas well in
March 2002 with a calculated AOF of 7.1 MMcfpd. The Company plans to drill at
least 5 additional horizontal Glen Rose shoal gas wells during the balance of
2002.
MAVERICK BASIN DRILLING ACTIVITY RECAP
TXCO participated in drilling a total of 73 new gas, oil or CBM prospects
including 25 drilling wells and 48 re-entries during 2001. Of the 25 drilling
wells, 11 were completed as producers, with 3 Paloma gas wells, 3 Burr gas
wells, 1 Chittim horizontal gas well, 1 Briscoe-Saner gas well, 1 Comanche gas
well, 1 Briscoe-Saner oil well and 1 marginal Wipff oil well, while 5 wells were
dry holes. A total of 9 drilling wells remained in progress at year-end. 40 of
the 48 re-entry attempts resulted in completions, including 30 CBM gas wells, 4
San Miguel oil wells, 1 Escondido gas well, 2 Burr gas wells, and 3 new water
disposal or injection wells. 1 re-entry remained in progress at year-end, while
7 were dry holes. At year-end, 34 CBM gas wells continued de-watering in the
ongoing CBM pilot program on the Comanche lease, while 8 San Miguel oil wells
were involved in the initial stages of the San Miguel water flood project.
At year-end December 2001, TXCO's net production reached 8.4 MMcf per day (gross
16.2 MMcf per day) from 72.47 net gas wells. At current gas prices, this
production level would not allow the Company to generate sufficient working
capital to entirely fund its 2002 capital expenditure program from internally
generated operating cash flow. The expanding geophysical database, historical
drilling results and the growing number of prospective formations targeted by
the Company and its partners reaffirmed the Company's longstanding belief that
it has significant exploration and development possibilities on its growing
Maverick Basin lease block. At year end 2001, the Company held leases totaling
over 372,000 acres and had accumulated 310 square miles of 3-D seismic data
covering most of its Maverick Basin lease block. Based on the newly completed 78
square mile 3-D seismic survey over the western half of the Comanche lease, 30
additional Glen Rose reefs were identified, increasing the number of TXCO's
fully 3-D imaged porosity-bearing Glen Rose patch reefs to 66 individual reefs
scattered across its extensive acreage position. The Company's Comanche lease
acquisition in 2000 included access to 70 miles of 2-D seismic data that
indicate the existence of an additional 15 Glen Rose Reef locations on the
eastern half of the 95,000 lease block. TXCO and its partners Saxet and Tom
Brown expect to commission a new 3-D seismic survey over the eastern half of the
Comanche lease prospect prior to the end of 2002. Based on current drilling
activity levels, the 81 seismically defined patch reefs represent a potential
four to five year drilling inventory.
JURASSIC FORMATION
Fiscal 1999 marked the year that the Company's concerted efforts resulted in a
new joint venture to explore the potential of the Jurassic formation under its
growing lease block. During 2000 and 2001 the Company, together with industry
partners, made significant progress in expanding its 3-D seismic database over a
much larger portion of the Maverick Basin.
Commencing in September 1999, Blue Star Oil and Gas, Ltd. (Blue Star), a Dallas
based privately held exploration company, designed a 3-D seismic acquisition
program over the 426 square mile area of the Maverick Basin targeted by the
joint venture. The initiation of field data acquisition work continued
throughout the year. The extensive data acquisition portion of the project was
completed late in the third quarter of 2000. In November 2000, pursuant to its
exploration joint venture with the Company, Blue Star confirmed that it had
completed the seismic data acquisition phase and began processing the seismic
data on the entire 426 square miles of 3-D seismic data, including 37,000 acres
of TXCO leases and Blue Star's 190,000 acre Chittim Ranch lease. By year end
2000, Blue Star had shared with TXCO's Jurassic project management team the
preliminary results from the data migration, processing and initial
interpretation of the seismic study.
10
Based on the preliminary interpretations of the 3-D seismic study, all
indications from Blue Star management confirmed they were preparing to drill the
initial Jurassic test well on TXCO's acreage early in 2001. In March 2001 Blue
Star contacted TXCO and announced Blue Star's decision to apply additional,
enhanced 3-D seismic processing techniques on their entire Jurassic seismic
database. Blue Star further advised that the prospective seismic processing
would likely take several months to finalize and could cost an additional $1
million. By year end 2001, Blue Star had completed its enhanced 3-D seismic
processing, had provided TXCO with a digitized seismic data set covering 164
square miles of the Maverick Basin and a proposed drilling location on the
Paloma lease. Drilling should commence in early 2002. 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
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 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 economics in
the region. The continued volatility or 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. The Company participated
in drilling 1 well (1.6% WI) in late 2000. The outside operated well was
proposed on a spacing unit in which TXCO owned a fractional interest which it
contributed to the unit. The well was completed as an oil well in 2001. Through
2001, 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. Consistent with Management's strategy to focus exploration
efforts and resources on the development of its core producing area in South
Texas, TXCO has maintained marketing efforts offering its remaining Williston
Basin holdings to other exploration companies with a focus on this area.
For the year ended December 31, 2001, the Company's interests produced an
average of 71 net barrels of crude oil per day from 4.26 net wells. At December
31, 2001 TXCO retained approximately 99,000 net acres of its original position.
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 2001, three purchasers of the Company's oil and gas production accounted
for 57%, 30% and <10%, 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.
11
EMPLOYEES
As of December 31, 2001, the Company employed 21 full-time employees including
management. The Company believes its relations with its employees are good. None
of the Company's employees are covered by union contracts.
GENERAL REGULATIONS
The extraction, production, transportation, and sale of oil, gas, and minerals
are regulated by both state and federal authorities. The executive and
legislative branches of government at both the state and federal levels have
periodically proposed and considered proposals for establishment of controls on
alternative fuels, energy conservation, environmental protection, taxation of
crude oil imports, limitation of crude oil imports, as well as various other
related programs. If any proposals relating to the above subjects were to be
enacted, the Company is unable to predict what effect, if any, implementation of
such proposals would have upon the Company's operations. A listing of the more
significant current state and federal statutory authority for regulation of the
Company's current operations and business are provided herein below.
FEDERAL REGULATORY CONTROLS
Historically, the transportation and sale for resale of natural gas in
interstate commerce have been regulated pursuant to the Natural Gas Act of 1938
(the "NGA"), the Natural Gas Policy Act of 1978 (the "NGPA") and the regulations
promulgated thereunder by the Federal Energy Regulatory Commission ("FERC").
Maximum selling prices of certain categories of natural gas sold in "first
sales," whether sold in interstate or intrastate commerce, were regulated
pursuant to the NGPA. On July 26, 1989, the Natural Gas Wellhead Decontrol Act
(the "Decontrol Act") was enacted, which removed, as of January 1, 1993, all
remaining federal price controls from natural gas sold in "first sales." The
FERC's jurisdiction over natural gas transportation was unaffected by the
Decontrol Act.
Commencing in April 1992, the FERC issued Order Nos. 636, 636-A and 636-B
(collectively "Order No. 636"), which required interstate pipelines to provide
transportation, separate or "unbundled," from the pipelines' sales of gas.
Although Order No. 636 did not directly regulate the Company's activities, it
fostered increased competition within all phases of the natural gas industry.
In December 1992, the FERC issued Order No. 547, governing the issuance of
blanket marketer sales certificates to all natural gas sellers other than
interstate pipelines. The order applies to non-first sales that remain subject
to the FERC's NGA jurisdiction. The FERC Order No. 547, in tandem with Order No.
636, has fostered a competitive market for natural gas by giving natural gas
purchasers access to multiple supply sources at market-driven prices. Order No.
547 has increased competition in markets in which the Company's natural gas is
sold. The natural gas industry historically has been very heavily regulated;
therefore, there is no assurance that the less stringent regulatory approach
pursued by the FERC and Congress will continue.
STATE REGULATORY CONTROLS
In each state where the Company conducts or contemplates conducting oil and gas
activities, such activities are subject to various state regulations. In
general, the regulations relate to the extraction, production, transportation
and sale of oil and natural gas, the issuance of drilling permits, the methods
of developing new production, the spacing and operation of wells, the
conservation of oil and natural gas reservoirs and other similar aspects of oil
and gas operations. In particular, the State of Texas (where the Company has
conducted the majority of its oil and gas operations to date) regulates the rate
of daily production allowable from both oil and gas wells on a market demand or
conservation basis. At the present time, no significant portion of the Company's
production has been curtailed due to reduced allowables. The Company knows of no
newly proposed regulations, which will significantly curtail its production.
12
ENVIRONMENTAL REGULATION
The Company's extraction, production and drilling operations are subject to
environmental protection regulations established by federal, state, and local
agencies. To the best of its knowledge, the Company believes that it is in
compliance with the applicable environmental regulations established by the
agencies with jurisdiction over its operations. The Company is acutely aware
that the applicable environmental regulations currently in effect could have a
material detrimental effect upon its earnings, capital expenditures, or
prospects for profitability. The Company's competitors are subject to the same
regulations and therefore, the existence of such regulations does not appear to
have any material effect upon the Company's position with respect to its
competitors. The Texas Legislature has mandated a regulatory program for the
management of hazardous wastes generated during crude oil and natural gas
exploration and production, gas processing, oil and gas waste reclamation and
transportation operations. The disposal of these wastes, as governed by the
Railroad Commission of Texas, is becoming an increasing burden on the industry.
The Company's operations in Montana, North Dakota and South Dakota are subject
to similar environmental regulations including archeological and botanical
surveys as some of its leases are on federal and state lands.
FEDERAL AND STATE TAX CONSIDERATIONS
Revenues from oil and gas production are subject to taxation by the state in
which the production occurred. In Texas, the state receives a severance tax of
4.6% for oil production and 7.5% for gas production. North Dakota production
taxes typically range from 9.0% to 11.5% while Montana's taxes range up to
17.2%. These high percentage state taxes can have a significant impact upon the
economic viability of marginal wells that the Company may produce and require
plugging of wells sooner than would be necessary in a less arduous taxing
environment. For Federal Income Tax purposes, the Company has net operating loss
carry forwards of $14,300,000 which are scheduled to expire in 2006 - 2019.
During 2000, the Company recognized a deferred federal income tax benefit of
$5,231,000 reflecting the cumulative estimated future tax benefit of a portion
of its net operating loss carry forwards from past losses. For 2001, this
benefit was unchanged. 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, 2001. The following table details the prices
used for these estimates for the respective dates presented:
12/31/01 12/31/00 2/31/99 8/31/99
-------- -------- ------- -------
Gas price per Mcf $ 2.72 $11.04 $1.99 $ 2.58
Oil price per Bbl $17.31 $25.67 $25.39 $19.03
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.
13
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.
NET INCOME OR LOSS FROM OPERATIONS
In its recent history, the Company has recorded both net income and net losses.
For the year ended December 31, 2001 the Company recorded a net loss of $50,283;
for the 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. The Company 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, By laws 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 non-cumulative
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. On May 25, 2001, a majority of the Company's shareholders approved an
amendment to its Certificate of Incorporation providing for the establishment of
a classified board of directors. The classified board provision established
three classes of directors, with each class to be elected for a three-year term
on a staggered basis. The classified board provision is intended to promote
management continuity and stability and to afford time and flexibility in
responding to unsolicited tender offers.
14
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 $12,119 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.
PROVED RESERVES, FUTURE NET REVENUE AND
PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES
The following unaudited information as of December 31, 2001, 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, 2001 and 2000 and August 31, 1999 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 and expenses 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
----------- ------------
2002 $ 3,052,900
2003 4,569,100
2004 2,633,300
2005 1,285,100
2006 706,200
Thereafter 1,735,900
--------------
Total $ 13,982,500
==============
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.
15
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.
YEARS ENDED 4 MONTHS ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31, AUGUST 31,
------------ ------------ ----------
2001 2000 1999 1999
---- ---- ---- ----
Oil:
Production in Barrels 50,000 60,000 24,000 82,000
Average sales price per Barrel $23.55 $27.85 $20.80 $12.27
Gas:
Production in Mcf 2,673,000 2,965,000 1,119,000 2,813,000
Average Sales Price per Mcf $4.56 $4.10 $2.75 $2.07
Average cost of production
per equivalent Mcf (1) $1.13 $.65 $.60 $.40
(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.
PRODUCING PROPERTIES - WELLS AND ACREAGE
The following table sets forth the Company's producing wells and developed
acreage assignable to such wells for the last three fiscal years:
PRODUCTIVE WELLS
----------------
DEVELOPED ACREAGE OIL GAS TOTAL
----------------- --- --- -----
PERIOD ENDED GROSS NET GROSS NET GROSS NET GROSS NET
------------ ----- --- ----- --- ----- --- ----- ---
Year Ended 12/31/01 19,870 11,140 53 39.12 96 72.47 149 111.59
Year Ended 12/31/00 15,920 8,257 28 15.63 47 25.49 75 41.12
Year Ended 12/31/99 11,720 5,185 18 6.29 29 12.56 47 18.85
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.
16
UNDEVELOPED ACREAGE
As of December 31, 2001, 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
FY2002
UNITED STATES GROSS ACRES NET ACRES DELAY RENTALS
------------- ----------- --------- -------------
Texas 372,000 329,000 $ 541,266
North Dakota 89,336 86,363 170,398
South Dakota 14,475 11,850 4,114
Montana 960 960 3,840
---------- --------- -------------
Totals 476,771 428,173 $ 719,618
======= ======= =========
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 2001, the Company's drilling activity increased to 73 wells
drilled or re-entered compared to 27 in calendar 2000. In addition, current year
activity included ongoing drilling operations on 16 wells that were in progress
at the end of calendar year 2000. The following table sets forth the Company's
drilling activity for the last three fiscal years:
DRILLING WELLS
2001 2000 1999
-------------------------- --------------------------- --------------------------
GROSS NET GROSS NET GROSS NET
PROD DRY PROD DRY PROD DRY PROD DRY PROD DRY PROD DRY
---- ---- ---- ---- ---- ---- ----- ---- ----- --- ---- ----
Oil Wells 5 1 3.70 0.63 2 1 .78 0.50 2 0 1.75 0.00
Gas Wells 18 5 15.53 4.37 6 6 3.76 2.13 6 0 3.78 0.00
-- - ----- ---- --- - ---- ---- - - ---- ----
Total Wells 23 6 19.23 5.00 8 7 4.54 2.63 8 0 5.53 0.00
== = ===== ==== = = ==== ==== = = ==== ====
The Exploration Company participated in the drilling of 25 wells (22.17 net)
during 2001. Of these, 22 wells (19.67 net) were operated by the Company. At
December 2001, 9 (9.0 net) of these wells remained in progress.
Included in the respective year 2001 columns are the results of the current
year's drilling activity involving the 16 wells spud in the prior fiscal year
and in progress at the beginning of 2001. These wells resulted in 9 producing
(8.17 net) gas wells and 3 producing (2.02 net) oil wells. In addition, 2 wells
resulted in 1 dry (0.88 net) gas well and 1 dry (1.0 net) oil well while 2 wells
(1.63 net) remained in progress at December, 2001.
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 spud 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
year 2000 drilling and 1 well (0.88 net) from the prior fiscal year.
17
RE-ENTRY WELLS
2001 2000 1999
-------------------------- ------------------------- --------------------------
GROSS NET GROSS NET GROSS NET
PROD DRY PROD DRY PROD DRY PROD DRY PROD DRY PROD DRY
---- ---- ---- ---- ---- --- ----- ---- ---- --- ---- ---
Oil Wells 4 1 4.00 1.00 1 0 .84 0.00 0 0 0.00 0.00
Gas Wells 36 7 36.00 7.00 0 0 0.00 0.00 0 0 0.00 0.00
-- - ----- ---- --- - ---- ---- - - ---- ----
Total Wells 40 8 40.00 8.00 1 0 0.84 0.00 0 0 0.00 0.00
== = ===== ==== = = ==== ==== = = ==== ====
During the year 2001 the Company re-entered 48 (48.0 net) existing wells, of
which 40 (40 net) wells are currently producing, while 1 well (1.0 net) remained
in progress at December 31, 2001. 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, 2000 and was dry in 2001.
TOTAL DRILLING AND RE-ENTRY WELLS
2001 2000 1999
----------------------- ---------------------------- -------------------------
GROSS NET GROSS NET GROSS NET
PROD DRY PROD DRY PROD DRY PROD DRY PROD DRY PROD DRY
---- ---- ---- ---- ---- --- ----- ---- ---- --- ---- ---
Oil Wells 9 2 7.70 1.63 3 1 1.62 0.50 2 0 1.75 0.00
Gas Wells 54 12 51.53 11.37 6 6 3.76 2.13 6 0 3.78 0.00
-- -- ----- ----- --- - ---- ---- - - ---- ----
Total Wells 63 14 59.23 13.00 9 7 5.38 2.63 8 0 5.53 0.00
== == ===== ===== = = ==== ==== = = ==== ====
The Company began year 2001 with 16 wells (13.70 net) in progress from year
2000. During year 2001, the Company initiated 73 (70.17 net) new drilling /
re-entry wells. These wells resulted in 54 gas (51.53 net) wells, 9 oil (7.70
net) wells, 14 dry (13.00 net) wells and 12 wells (11.64 net) were in progress
at December 31, 2001.
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 2001 and 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 acres 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 JOA dated May 1999 with Castle Exploration Company and is being
developed in conjunction with the JOA discussed below. Two wells were drilled
under the Picosa Creek JOA during 2000. Both were placed on production by
year-end 2000, one as a gas well, and the other as an oil producer.
18
In November 1998, the Company finalized a JOA with Ameritex Ventures, II Ltd.,
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, (NasdaqNM: 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
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.
Pursuant to the JOA and Castle's elections, Castle has a 50 % interest remaining
only in the undeveloped portion of the Burr lease,
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
acres tract out of the 190,000+ acres 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 an agreement 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. By 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. That
model supports the premise that structures that should contain significant
deposits of hydrocarbons are present in the Jurassic interval under its acreage
block. Based on these encouraging results, Blue Star indicated it anticipated
beginning preparations to drill the first Jurassic test well on TXCO's Maverick
Basin acreage in early part of 2001.
19
On March 13, 2001 Blue Star's Management advised TXCO of their decision to apply
enhanced 3-D seismic processing techniques on their seismic survey data. Blue
Star estimated the expanded seismic processing could cost an additional $1
million, would take months to finalize in order to better define their geologic
model of the interval and would likely preclude any drilling prior to the end of
2001. Blue Star hoped to enhance its process of selecting the initial drilling
locations to test the 18,000+ feet deep structure underlying the targeted
acreage block. TXCO believed that the results of the expanded processing will
reduce the initial drilling risk for the benefit of all its partners, enhancing
the overall success of the venture while potentially reducing exploration costs
in the long term.
While the advent of new, more advanced technology may 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. Throughout 2001, TXCO closely monitored Blue
Star's progress pursuant to their performance obligation under the agreement to
assure the project was not being unreasonably delayed or detrimental to the
ultimate development of the project. During the first quarter of 2002, Blue
Star's team of geoscientists met with TXCO's exploration team on several
occasions to include the Company's assistance in interpreting the final results
of the long awaited newly enhanced 3-D seismic processing. Blue Star also
requested TXCO's expertise in the identification and final ranking of multiple
proposed Jurassic drilling locations on TXCO's effected acreage. In March 2002,
Blue Star delivered a nearly final processed digital data set containing over 83
square miles of digitized seismic data for TXCO's ongoing review. As of the date
of this report, Blue Star confirms that it has received acceptable proposals
from several qualified drilling contractors and has conducted final inspections
and is obtaining current title opinions on all drilling locations. TXCO believes
drilling on its first Jurassic prospect will commence in the very near future.
In April 2000 the Company expanded its core Maverick Basin properties as it
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 of available seismic data indicated that multi-zone production
potential existed, including evidence of approximately 40 Glen Rose reefs and
indications of a deep Jurassic structure below 16,000 feet. Other progressively
deepening targets and intervals include CBM gas from the coalbeds in 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.
By the third quarter of 2001, the Company had also acquired over 100 previously
existing shut-in well bores from earlier operators on its new Comanche Ranch
Lease. To date, most of the well bores have been inspected and identified as
re-entry locations prospective for CBM production. Ongoing evaluation of
geologic and available historic well data indicated that approximately (93) of
the well bores appeared prospective for recompletion as CBM gas wells or San
Miguel oil wells, while the remaining well bores may be suitable for future
conversion to disposal or injection wells. The Company believes CBM production
will eventually make up a significant portion of the future gas production from
this acreage
During the first quarter of 2001, the Company entered into a joint venture with
Houston based Saxet and Denver based Tom Brown, Inc. (NasdaqNM: TMBR). The
Company sold a 50% working interest (Saxet 20% and Tom Brown 30%) in the
Comanche lease below the base of the San Miguel formation for cash, with Saxet
as the operator. By year-end 2001, the new partners had contracted Dawson
Geophysical (NasdaqNM: DWSN) and completed the acquisition of a proprietary,
100-square-mile 3-D survey including over 78 square miles of the Comanche Ranch
and 22 square miles of an adjoining property owned by Saxet. Based on early
interpretation of the first half of the seismic survey, a well targeting the
Glen Rose formation was spudded in June 2001. The Cinco B-1 gas prospect
encountered a reef that was found to contain water and was not economic. Further
drilling on the Comanche prospect in 2001 was curtailed pending the completion
of processing of the entire 3-D seismic survey. An additional 30 seismically
defined Glen Rose reefs were identified and a second well was planned after year
end, targeting a particularly attractive prospect on TXCO's Comanche lease which
contained evidence of multiple stacked Glen Rose reefs.
20
The Comanche 1-111 was spudded in February 2002, The well encountered
significant flows of oil while drilling, producing over 5,000 barrels in a 24
hour period. It was subsequently completed and tested rates as high as 3600 BOPD
and has been continually flowed at a rate of 500 BOPD over a week later. TXCO
(50%WI) and its partner Saxet (50%) have established the oil discovery is in a
large reef complex approximately 850 acres in size with 55 feet of net pay.
Drilling on the Comanche 1-2, the first delineation well, commenced on March 27,
2002 and located approximately 4,500 feet northeast of the Comanche 1-111 oil
discovery well. Pending further evaluation of the Comanche 1-111 discovery well
and results of the currently drilling delineation well, the Company anticipates
modifying its original 2002 drilling program to incorporate the expected
development of this newly discovered field.
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. Highly prospective for CBM gas production, the acreage is contiguous to
and between the Company's Paloma/Kincaid lease block to the northwest and its
Comanche Ranch lease to the south. With some exceptions, the Company controlled
drilling rights from the surface to the base of the San Miguel Formation ranging
from 300 to 2000 feet in depth. TXCO's average working interest on the Chittim
lease is 99.3%. 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 Maverick County. Within these holdings, the Company now
owns more than 250,000 acres of prospective CBM acreage covering portions of
three South Texas counties, including Maverick, Dimmit and Zavala Counties,
constituting what it believes to be the largest block of CBM gas prospective
acreage in the state of Texas.
At December 31, 2001, the Company's 3-D seismic database grew to approximately
310 square miles from 231 square miles in 2000. During 2001 the Company received
new high definition seismic data totaling approximately 84 square miles over a
large portion of Blue Star's Chittim Ranch lease, contiguous to TXCO's
Paloma/Kincaid lease block. Additionally, Blue Star also provided TXCO with
approximately 80 square miles of newly processed, higher definition, seismic
data covering most of the surface of the Company's Paloma and Kincaid leases.
Company geophysicists have updated their seismic model incorporating the new
seismic data providing TXCO with a much-enhanced overall image of the Jurassic
interval extending far beyond the area of its previously available data.
WILLISTON BASIN
TXCO was not active in the Williston Basin in 2001. 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. In 2000, 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 was completed as an oil
well in January 2002.
Throughout 2001, the Company continued to evaluate its existing operations in
the Williston Basin. Even with the higher oil prices during 2001, the Company's
producing 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 2001, Management identified one marginal Williston
Basin producing property whose capitalized costs were in excess of anticipated
future reserve potential and adjusted its remaining carrying basis to equal its
anticipated potential value with a charge to impairment in the amount of
$409,000. 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 2001, the Company charged a total of $808,200 to
abandonment expense, related to 40,052 acres which expired during the year.
21
Forward-looking statements in this 10-K are made pursuant to the safe harbor
provisions of the Private Securities Litigation Reform Act of 1995. Investors
are cautioned that all forward-looking statements involve risks and uncertainty,
including without limitation, the costs of exploring and developing new oil and
natural gas reserves, the price for which such reserves can be sold,
environmental concerns effecting the drilling of oil and natural gas wells, as
well as general market conditions, competition and pricing. Please refer to all
of TXCO's Securities and Exchange Commission filings, copies of which are
available from the Company without charge, for additional information.
ITEM 3. LEGAL PROCEEDINGS
The Company is not involved in any matters of litigation incidental to its
business of a significant nature.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of the security holders of the Company during
the 4th quarter of fiscal year 2001.
22
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 2001 $ 2.74 $ 1.95
September 2001 2.97 1.88
June 2001 4.03 1.90
March 2001 4.25 2.63
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 15, 2002, there were approximately 1,650 holders of record of the
Company's Common Stock. The transfer agent for the Company is EquiServe Trust
Company, 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.
4 MONTHS ENDED
YEAR ENDED DECEMBER 31 DECEMBER 31, YEAR ENDED AUGUST 31
---------------------- -------------------------------------
2001 2000 1999 1999 1998 1997
---- ---- ---- ---- ---- ----
Operating Revenues $14,509,487 $14,731,116 $ 3,852,089 $ 7,497,375 $ 3,048,277 $ 1,083,511
Income (Loss) from
continuing operations (50,283) 6,761,935 1,188,649 931,545 (8,417,218) (3,398,866)
Basic Income (Loss)
per common share from
continuing operations (0.003) 0.39 0.07 0.06 (0.55) (0.27)
Total Assets 29,843,432 29,205,641 18,647,878 17,553,815 16,264,632 21,652,726
Long-term obligations 862,177 1,195,191 1,679,936 3,094,809 4,823,927 4,995,000
Stockholders' equity $23,056,696 $23,321,736 $13,208,929 $12,020,280 $10,595,141 $14,770,770
Weighted average shares
outstanding - Basic 17,441,242 17,242,326 15,938,516 15,668,721 15,328,292 12,576,255
23
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The discussion and analysis of the Company's financial condition and results of
operations was based upon the consolidated financial statements, which have been
prepared in accordance with U.S. generally accepted accounting principles. The
preparation of these financial statements requires us to make estimates and
judgments that affect the reported amounts of assets, liabilities, revenues and
expenses. Our significant accounting policies are described in Note A to our
consolidated financial statements. In response to SEC Release No. 33-8040,
"Cautionary Advise Regarding Disclosure About Critical Accounting Policies," we
have identified certain of these policies as being of particular importance to
the portrayal of our financial position and results of operations and which
require the application of significant judgment by management. We analyze our
estimates, including those related to oil and gas revenues, oil and gas
properties, income taxes, contingencies and litigation, and base our estimates
on historical experience and various other assumptions that we believe to be
reasonable under the circumstances. Actual results may differ from these
estimates under different assumptions or conditions. We believe the following
critical accounting policies affect our more significant judgments and estimates
used in the preparation of the Company's financial statements:
SUCCESSFUL EFFORTS METHOD OF ACCOUNTING
The Company accounts for its natural gas and crude oil exploration and
development activities utilizing the successful efforts method of accounting.
Under this method, costs of productive exploratory wells, development dry holes
and productive wells, costs to acquire mineral interests and 3-D seismic costs
are capitalized. Exploration costs, including personnel costs, certain
geological and geophysical expenses including 2-D seismic costs and delay
rentals for oil and gas leases, are charged to expense as incurred. Exploratory
drilling costs are initially capitalized, but charged to expense if and when the
well is determined not to have found reserves in commercial quantities. The sale
of a partial interest in a proved property is accounted for as a cost recovery
and no gain or loss is recognized.
The application of the successful efforts method of accounting requires
managerial judgment to determine the proper classification of wells designated
as developmental or exploratory which will ultimately determine the proper
accounting treatment of the costs incurred. The results from a drilling
operation can take considerable time to analyze and the determination that
commercial reserves have been discovered requires both judgment and industry
experience. Wells may be completed that are assumed to be productive and
actually deliver oil and gas in quantities insufficient to be economic, which
may result in the abandonment of the wells at a later date. Wells are drilled
that have targeted geologic structures that are both developmental and
exploratory in nature and an allocation of costs is required to properly account
for the results. The evaluation of oil and gas leasehold acquisition costs
requires managerial judgment to estimate the fair value of these costs with
reference to drilling activity in a given area. Drilling activities in an area
by other companies may also effectively condemn leasehold positions.
The successful efforts method of accounting can have a significant impact on the
operational results reported when the Company is entering a new exploratory area
in hopes of finding a oil and gas field that will be the focus of future
development drilling activity. The initial exploratory wells may be unsuccessful
and will be expensed.
RESERVE ESTIMATES
The Company's estimates of oil and gas reserves, by necessity, are projections
based on geologic and engineering data, and there are uncertainties inherent in
the interpretation of such data as well as the projection of future rates of
production and the timing of development expenditures. Reserve engineering is a
subjective process of estimating underground accumulations of oil and gas that
are difficult to measure. The accuracy of any reserve estimate is a function of
the quality of available data, engineering and geological interpretation and
judgment. Estimates of economically recoverable oil and gas reserves and future
net cash flows necessarily depend upon a number of variable factors and
assumptions, such as historical production from the area compared with
production from other producing areas, the assumed effects of regulations by
governmental agencies and assumptions governing future oil and gas prices,
future operating costs, severance taxes, development costs and workover gas
costs, all of which may in fact vary considerably from actual results. The
future drilling costs associated with reserves assigned to proved undeveloped
locations may ultimately increase to an extent that these reserves may be later
determined to be uneconomic.
24
For these reasons, estimates of the economically recoverable quantities of oil
and gas attributable to any particular group of properties, classifications of
such reserves based on risk of recovery, and estimates of the future net cash
flows expected therefrom may vary substantially. Any significant variance in the
assumptions could materially affect the estimated quantity and value of the
reserves, which could affect the carrying value of the Company's oil and gas
properties and/or the rate of depletion of the oil and gas properties. Actual
production, revenues and expenditures with respect to the Company's reserves
will likely vary from estimates, and such variances may be material.
IMPAIRMENT OF OIL AND GAS PROPERTIES
The Company reviews its oil and gas properties for impairment at least annually
and whenever events and circumstances indicate a decline in the recoverability
of their carrying value. The Company estimates the expected future cash flows of
its oil and gas properties and compares such future cash flows to the carrying
amount of the properties to determine if the carrying amount is recoverable. If
the carrying amount exceeds the estimated undiscounted future cash flows, the
Company will adjust the carrying amount of the oil and gas properties to their
fair value. The factors used to determine fair value include, but are not
limited to, estimates of proved reserves, future commodity pricing, future
production estimates, anticipated capital expenditures, and a discount rate
commensurate with the risk associated with realizing the expected cash flows
projected.
Given the complexities associated with oil and gas reserve estimates and the
history of price volatility in the oil and gas markets, events may arise that
would require the Company to record an impairment of the recorded book values
associated with oil and gas properties. The Company has recognized impairments
in prior years and there can be no assurance that impairments will not be
required in the future.
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, 2001
During the year ended December 31, 2001, beginning cash reserves of $5,898,015
were increased by net cash provided from operating activities of $8,564,022
resulting in a total of $14,462,037 in internally generated working capital for
use in funding the ongoing expansion, development and exploration of the
Company's oil and gas properties. Additionally, cash of $2,005,133 was obtained
from the sale of oil and gas properties $153,231 was provided from debt
obligations, and $31,250 resulted from the exercise of an outstanding option for
the purchase of the Company's common stock. This resulted in total cash of
$16,651,651 available for use in meeting the Company's ongoing operational and
development needs.
The Company applied $13,360,347 of its working capital to fund the expansion and
ongoing development of its oil and gas properties. Included were drilling,
completion, seismic and leasehold acquisition costs totaling $13,255,071
primarily targeting TXCO's core area, the Maverick Basin. This represented
expenditures for the drilling, completion and re-entry of 73 oil and gas wells
and new Maverick Basin mineral lease purchases of approximately 158,000 acres.
Also included was $94,271 for the expansion of the Company's Paloma lease gas
gathering facilities.
The Company made timely payments of $486,244 on its long-term debt obligations
during 2001, while payments on interest totaled $128,373. Additionally, the
Company purchased 99,800 shares of its common stock for its treasury at a cost
of $246,007 under its common share buyback program approved by the Board of
Directors on June 27, 2001.
25
As a result of these activities, the Company ended the year 2001 with a negative
working capital of $1,554,454 and a current ratio of .73 to 1. This year-end
position compares to positive working capital of $6,349,625 and a current ratio
of 2.36 to 1 at December 31, 2000. The decrease in ending working capital is
attributable to the increased levels of development activities through the third
quarter coupled with the sharp decline in realized gas prices during the second
half of 2001.
BANK CREDIT FACILITY: TXCO had no bank debt at December 31, 2001. On March 4,
2002 the Company entered into a $25,000,000 oil and gas reserve based Revolving
Credit Facility (the Facility) with Hibernia National Bank providing a credit
line with an initial borrowing base set at $5 million. Interest is payable
monthly, with principal due at maturity in March 2005. Use of proceeds are for
the acquisition and development of oil and gas properties and general corporate
working capital purposes. The Facility provides the lender with semiannual
scheduled redeterminations, at mid-year and each subsequent anniversary date.
The Facility provides for two unscheduled redeterminations per year, at the
Company's discretion. Borrowings under the Facility are secured by a first
priority mortgage covering the Company's working and other interests in the
majority of its oil and gas leases. The interest rate under the facility will
initially be based on the Wall Street Journal Prime Rate plus applicable margin.
A Eurodollar Rate plus applicable margin may be utilized at the election of the
Company. The Facility contains certain financial covenants and other negative
restrictions common for financing of this type, to include but not limited to
the following: maintenance of a minimum Current Ratio of 1.00 to 1 from the date
of closing through June 30, 2002 and 1.25 to 1, thereafter; maintenance of a
Maximum Debt/Ebitdax ratio of 3.00 to 1 until maturity; a Minimum Interest
Coverage of 2.50 to 1 until maturity.
Although the Company had a working capital deficit at December 31, 2001,
Management is cautiously optimistic that with its new credit facility in place,
and with anticipated production increases from its successful first quarter 2002
drilling activities to date and going forward, the Company will be able meet its
ongoing operating cash requirements for 2002 and to complete its scheduled
exploration and development goals as targeted by its 2002 capital expenditure
program.
However, there is no assurance that the Company will reestablish profitability
in 2002 or that expected increases in new oil and gas production will be
realized, nor that sufficient debt capital will remain available from its new
borrowing Facility. Should these concerns be realized or should commodity prices
weaken significantly, the Company's financial condition could be adversely
effected, and could cause the Company to defer planned capital expenditures
consistent with its available capital resources.
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 common stock.
26
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 oil and gas wells
and 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 compared to positive working capital of $207,660 and
a current ratio of 1.04 to 1 at December 31, 1999. The dramatic increase in
working capital was 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.
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.
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 oil and gas 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.
27
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
oil and gas 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 was to 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
compared 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.
2002 CAPITAL REQUIREMENTS
The major components of the Company's plans, and the requirements for additional
capital for 2002, include the following:
MAVERICK BASIN ACTIVITY:
Initial capital expenditures planned for 2002 total over $6,597,000, are
presented net to the Company's interest, and target its Maverick Basin core
properties. The primary component of these expenditures is $6,215,000 for both
drilling and re-entry wells, while over $360,000 is earmarked for gas gathering
infrastructure expansion activities and other property and equipment purchases.
The Company's budgeted capital expenditures are intended to be flexible. Overall
budgeted capital outlays are subject to substantial increase should the
Company's key exploration targets, development activities or special situations
or opportunities warrant higher capital outlays than originally planned.
Management is particularly interested in accelerating the development of its CBM
pilot project, its San Miguel water flood pilot and its Glen Rose reef target
objectives as additional expenditures are warranted.
The Company initially plans to drill or re-enter a minimum of 19 wells,
including 9 Glen Rose reef prospects, 6 Glen Rose shoal horizontal prospects and
4 re-entries targeting San Miguel oil wells. The 9 Glen Rose reef wells are
targeted at prospects defined by TXCO's 3-D seismic database. 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. Glen Rose reef prospects
on the Comanche lease are expected to average $100,000 more than Paloma lease
wells, as the Glen Rose interval trends deeper down dip when encountered under
the Comanche lease. The typical horizontal Glen Rose shoal gas wells targeting
this newly identified horizontal gas play cost the Company approximately
$365,000 to complete or $210,000 as a dry hole, on a net basis. A typical San
Miguel re-entry well typically cost less that $50,000, on a net basis.
28
SUBSQUENT EVENT
Pending further evaluation of the Comanche 1-111 oil discovery well drilled in
February 2002 and results of the currently drilling Comanche 1-2 delineation
well, the Company anticipates modifying its original 2002 drilling program to
incorporate the expected development of this newly discovered oil field.
The Company continues to benefit from its 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%
to date by its partner and operator, Blue Star Oil and Gas, Ltd. No substantial
funding requirements are required of TXCO nor are any planned for 2002 for the
project.
Estimated expenditures required to maintain the Company's interest in all of its
remaining undeveloped South Texas leasehold acreage for fiscal 2002 are
approximately $540,000 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 2002 delay rentals of $179,000 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 coming year, there is no assurance that energy
prices or other market factors will continue to improve. Should prices weaken,
or should expected new oil and gas production levels from planned 2002 drilling
not be attained, the resulting reduction in projected revenues would cause the
Company to re-evaluate its expected sources of working capital and would
adversely effect the Company's ability to carry out its current operating plans.
SUBSEQUENT EVENT:
Subsequent to year-end, Management was actively involved in ongoing discussions
with various industry partners and domestic and foreign-based sources of debt,
project or equity financing. On March 4, 2002 the Company entered into a
$25,000,000 oil and gas reserve based Revolving Credit Facility with Hibernia
National Bank. The Facility provides a 3 year term revolving credit line with an
initial borrowing base set at $5 million, with interest due monthly and
principal due at maturity. Use of proceeds are for the acquisition and
development of oil and gas properties and general corporate working capital
purposes. Due to the success of its 1st quarter 2002 drilling activities,
including the Comanche 1-111 oil discovery well drilled in February 2002, TXCO
anticipates a material near term increase in the borrowing base under its new
Revolving Credit Facility.
The Company also expects it will have a continuing ability to further increase
its borrowing base commensurate with the expected additional growth of its
proved oil and gas reserves throughout the base term of the new Facility.
Management remains confident that financial resources will remain available,
enabling the Company to continue the rapid development of its oil and gas
properties and continue to meet its normal operational and debt service
obligations on a timely basis.
29
RESULTS OF OPERATIONS
CHANGE IN FISCAL YEAR
A Form 8-K was filed on December 29, 1999, reporting the decision of the Board
of Directors of the Company 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.
2001 COMPARED TO 2000
The Company reported a net loss of $50,283 or $0.003 per basic and diluted share
for the year ended December 31, 2001, compared to a net income of $6,761,935 or
$0.39 per basic and diluted share for the prior year. Net income in 2000
included a deferred tax benefit of $5,232,700 while no similar benefit was
recognized in 2001.
Although, 2001 revenues decreased by 1.5% compared to year 2000 levels, current
year oil and gas production declined by 9.8% and 17.5% respectively as compared
with prior year levels. The 17.5% decline in oil production primarily reflects
the advancing decline curve of maturing oil wells in the Williston Basin. In
addition, a 15.4 % decline in the average price of oil was offset somewhat by an
11% increase in the average price of gas as compared to prior year prices for
both commodities. The decline in 2001 gas production compared to the prior year
reflects the general production decline of the Company's existing mix of
maturing gas wells. This decline was partially offset by new gas production from
the 54 new gas wells drilled and completed during the year. Included in the
number of gas wells classified as producing at 2001 were 34 CBM gas wells which
are still in their initial dewatering stage, and are not yet contributing a
significant amount of new gas production. A significant contribution of new CBM
gas production is expected from these wells upon their reaching Phase 2 of the
dewatering process.
Average daily net gas production rates in 2001 decreased to 7,300 Mcf, an 11%
decline over the prior year, while average daily net oil production rates in
2001 decreased to 136 Bbls, a 26% decline over the prior year. The Company
expects to reverse these declining production rates based on its year 2002
drilling success to date and expected results from ongoing drilling projects.
Lease operations expense for year 2001 increased 108% compared to year 2000.
This increase is primarily due to the addition of 54 new gas wells and 9 new oil
wells during 2001. The increase reflects the incremental direct costs of
operating the new wells, including typical costs such as pumper, electricity,
water disposal, and other direct overhead charges, as added during 2001 to the
Company's existing lease operating expense levels. The 7 new Burr wells
increased overall annual lease operating costs by approximately $469,000 due to
the higher costs of chemical treatment for H2S removal and related costs of
operating an amine plant for these gas wells plus costs associated with salt
water disposal. The 34 newly connected CBM wells currently in the dewatering
pilot project added $419,000 in incremental operating costs in 2001 and reflect
the high operating costs associated with the de-watering phase of the CBM pilot
program initiated in the current year. Additionally, ad valorem taxes increased
approximately 30% in calendar 2001 compared to 2000 reflecting increased
appraised values for new oil and gas properties as well as increased valuations
of exiting wells due to higher oil and gas prices over the prior year.
Exploration expenses remained consistent with the 2000 level.
Pursuant to the successful efforts method of accounting for mineral properties,
the Company periodically assesses its producing and non-producing properties for
impairment. Impairment and abandonments decreased by 15% primarily due to lower
impairment rates on non-producing acreage in the Williston basin during 2001
versus 2000. This decrease was somewhat offset by an increase in impairments of
producing properties resulting from the lower oil and gas prices at year-end and
the resultant decreased property values in the year-end reserve report.
Depreciation, depletion and amortization increased by almost $500,000 or 18%
over calendar 2000 levels due primarily to the increased number of producing
wells being depleted and higher depletion rates for 2001 caused by lower
year-end reserve volumes as a result of lower oil and gas prices at December 31,
2001. The increase in depreciation was due to increased investments in other
equipment including the expansion of the Paloma lease gathering system
throughout the year. The increase in amortization was primarily due to the
additional amortization related to the 78-square mile 3-D seismic survey on the
Comanche Ranch acquired during 2001.
30
General and administrative costs increased 19% compared to 2000 levels
reflecting the higher sustained level of Company operations. 68% of the increase
was due primarily to increased salaries, wages and benefits associated with
staff increases including 2 engineering and administrative staff additions and 6
new field personnel during the current year. Also contributing to the increase
were higher costs for property and liability insurance, increased accounting and
auditing fees and increased state franchise tax expenses.
The 19% decrease in interest income reflects the declining cash levels in
interest bearing accounts and declining interest rates during 2001 versus 2000
levels. Interest expense decreased by $51,000 in 2001 from 2000 due to the
retirement of the Range debt during the second quarter of 2000. Income tax
expensed decreased by $5,216,800 due to the recognition of a deferred federal
tax benefit of $5,232,700 in 2000, while no similar benefit was recognized in
2001.
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 there 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 were 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.
31
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.
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 $ 1.3 million impact on the
Company's annual revenues and operating income.
INTEREST RATE RISK: The Company's exposure to interest rate risk was minimal at
December 31, 2001 as all of its existing debt was at fixed rates. Subsequent to
year-end, the Company has borrowed funds under a new revolving credit facility
with Hibernia National Bank, with interest tied to the Wall Street Journal Prime
rate. At March 28, 2002 the Company had $2.8 million in borrowings under the
Facility with interest at 4.75% per annum. Under terms of the Facility, the
Company has the option to lock in a fixed interest rate for a period of up to 6
months using LIBOR rates plus an applicable margin, which at March 25, 2002
totaled 5.04%. Should interest rates start to rise, the Company can convert its
outstanding loan balance to the LIBOR option rate within 3 days of its election.
An annualized 10% fluctuation in interest charged on the outstanding balance at
March 25, 2002 would have an approximate $13,000 impact on the Company's annual
net income.
32
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
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 15, 2002:
NAME CLASS POSITION AGE
---- ----- -------- ---
Stephen M. Gose, Jr. B Chairman of the Board of Directors 72
Member Compensation and Nominations Committees
Michael J. Pint C Director, Chairman Audit Committee 58
Member Compensation and Nominations Committees
Robert L. Foree, Jr. A Director, Chairman Nominations Committee 72
Member Audit and Compensation Committees
Alan L. Edgar B Director, Chairman Compensation Committee 56
Member Audit and Nominations Committees
James E. Sigmon C President and Director 53
Thomas H. Gose A Director and Assistant Secretary 46
Member Audit and Nominations Committee
Roberto R. Thomae Chief Financial Officer 51
Secretary/Treasurer, Vice President-Finance
Richard A. Sartor Controller 49
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 Compensation Committees
since June 1997 and served as its Chairman through April 1998. Mr. Gose was a
member of the Audit Committee From June 1997 through May 2001 and served as its
Chairman from June 1997 through April 1998. He has been a member of the
Nominations Committee since its inception in May 2001. Mr. Gose 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 46 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.
33
Michael J. Pint has served as a Director since May 1997. He has been a member of
the Audit Committee of the Board of Directors since June 1997 and has served as
its Chairman since April 1998. Mr. Pint has been a member of the Compensation
Committee since June 1997 and served as its Chairman from April 1998 through May
2001. He has been a member of the Nominations Committee since its inception in
May 2001. Mr. Pint has 36 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.
He has been a member of the Nominations Committee and served as its Chairman
since its inception in May 2001. A geologist by training, he has been active for
more than 46 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 served as the Chairman of the Compensation Committee since May
2001. Mr. Edgar has been a member of the Nominations Committee since its
inception in May 2001. He has been involved in energy related investment banking
and equity analysis for 30 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 31 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.
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 has been a member of the Audit and Nominations Committees since May
2001. Mr. Gose 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 Inc., 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.
34
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 Directors listed above has been elected by the shareholders to serve
until his successor is duly elected. In May 2001 the shareholders of the Company
approved the adoption of a classified board. The board is structured with three
classes of directors, Classes A, B and C, each having two directors with current
terms expiring in the years 2002, 2003 and 2004, respectively. Directors elected
at the May 2002 annual meeting and later meetings will serve full three-year
terms.
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 12/31/01 $201,250 $ 8,750 (1) $204,715 $592
President & CEO 12/31/00 175,000 14,583 (1) 174,181 402
12/31/99(2) 57,899 -0- (1) 52,600 -0-
8/31/99 150,000 -0- (1) 56,678 419
Roberto R Thomae 12/31/01 111,250 4,792 -0- 237
CFO & Secretary/ 12/31/00 100,000 8,333 -0- 161
Treasurer 12/31/99(2) 33,499 -0- -0- -0-
(1) Represents income from overriding royalty interests.
(2) Represents four month transition period for respective officer.
OPTION GRANTS IN LAST FISCAL YEAR
% OF TOTAL OPTIONS GRANT
# OPTIONS GRANTED TO EMPLOYEES EXERCISE PRICE EXPIRATION DATE
NAME GRANTED IN FISCAL YEAR PER SHARE DATE VALUE(1)
---- ------- -------------- --------- ---- -------
Roberto R. Thomae 50,000 24% $2.96 2011 $90,996
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.
35
AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR
NUMBER OF UNEXERCISED VALUE OF UNEXERCISED
# SHARES VALUE OPTIONS/SARS OPTIONS/SARS
NAME EXERCISED REALIZED EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE (1)
--------- ---------- -------- ----------------------------- ------------- ---------------
James E. Sigmon (2) - $ - 100,000 600,000 $ - $ -
Roberto R. Thomae - - 100,000 50,000 28,500 -
(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, 2001, 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.
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 an annual retainer of $5,000
per year upon election to the Board. Additionally, the outside directors 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 in equal annual increments 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
re-pricing 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 $210,000 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 Alan L. Edgar (Chairman),
Robert L. Foree, Jr., Michael J. Pint, and Stephen M. Gose, Jr. The principal
function of the Committee is to approve the compensation of all executive
officers of the Company, to recommend to the Board the terms of principal
compensation plans requiring stockholder approval and to direct the
administration of the Company's 1995 Flexible Incentive Plan.
36
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
17,397,049 shares outstanding and 20,567,478 fully diluted shares which includes
3,170,429 shares under options and warrants as of March 15, 2002. `
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
---------------- ------------------ -------------
Swisspartners Investment Network AG (1) 2,295,173 12.32%
Am Schanzengraben 23
Postfach 970
Switzerland
Stephen M. Gose, Jr. (2) 1,482,877 8.51%
HCR Box 1010 Hwy 212
Roberts, Montana 59070
Thomas H. Gose (2) 941,601 5.40%
517 Morningside
San Antonio, TX 78209
Tahoe Invest 1,200,000 6.90%
Innere Guterstrasse 4
6304 Zug
Switzerland
(1) The number of shares shown as being beneficially owned by Swisspartners
Investment Network AG include 1,057,077 shares issued in the names of three
different European banking institutions, and 1,238,096 shares reserved for
issuance under 5 year warrants, exercisable at $3.00 per share, granted in
February 2000 as part of a private equity funding. Based on currently
available information, the Company has concluded these holdings must be
aggregated for reporting purposes.
(2) Please see related footnotes for each respective beneficial owner presented
in the Security Ownership of Management table on the following page.
37
SECURITY OWNERSHIP OF MANAGEMENT
The following table sets forth the number of shares of common stock beneficially
owned as of March 15, 2002 by each director, each executive officer named in the
Summary Compensation Table and by all directors and executive officers as a
group. Information provided is based on 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) 1,482,877 8.51%
Thomas H. Gose (7) (8) 941,601 5.40%
James E. Sigmon (2) 750,000 4.14%
Michael Pint (4) 375,000 2.15%
Alan L. Edgar (5) 304,133 1.73%
Robert L. Foree, Jr. (4) 86,000 .49%
Roberto R. Thomae (6) 125,000 .71%
All Directors and Executive
Officers as a group 4,114,611 22.09%
(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. Stephen M. Gose, Jr. include
his 100% interest, shared equally with his spouse, in 1,457,877 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 300,000 and 11,000 respectively, of
directly owned shares.
(5) The number of shares beneficially owned by Mr. Edgar includes 145,800 shares
owned directly, 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 and 25,000 shares reserved for
issuance under non-qualified options issued to outside directors of the
Company exercisable at March 15, 2002.
(6) The number of shares beneficially owned by Mr. Thomae includes 125,000
shares of the Company's Common Stock reserved for issuance through options
issued under the Company's 1995 Flexible Incentive Plan.
(7) The number of shares beneficially owned by Mr. Stephen M. Gose, Jr. and Mr.
Thomas H. Gose each includes 25,000 shares of the Company's common stock
reserved for issuance under non-qualified options issued to outside
directors of the Company exercisable at March 15, 2001.
(8) The number of shares beneficially owned by Mr. Thomas Gose include 916,601
shares owned directly.
38
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.
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, 2001 and December 31, 2000.
Statements of Operations, Years Ended December 31, 2001 and
2000, August 31, 1999, and the Four Month
Transition Period Ended December 31, 1999.
Statements of Stockholders' Equity, Years Ended December 31,
2001 and 2000, August 31, 1999 , and the Four
Month Transition Period Ended December 31, 1999.
Statements of Cash Flows, Years Ended December 31, 2001 and
2000, August 31, 1999, 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 Sept1,1985.
** 3.6 Articles of Amendment to the Articles of
Incorporation of The Exploration Company
dated April 6, 1990.
** 10.2 Employment Agreement between the Registrant and
James E. Sigmon, dated October 1, 1984.
** 10.3 Registrant's Amended and Restated 1983 Incentive
Stock Option Plan filed as Exhibit A to registrant's
definitive Proxy Statement, dated February 20, 1985.
** 10.4 Registrant's 1995 Flexible Incentive Plan, filed as
Exhibit A to registrant's definitive Proxy Statement,
dated April 28, 1995.
** 10.5 Registrant's Form S-8 Registration Statement for its
1995 Flexible Incentive Plan, dated November 26,1996.
** 10.6 Registrant's Amendment to its 1995 Flexible
Incentive Plan, filed as Proposal II of the
registrants definitive Proxy Statement,Jan 12, 1999.
** 10.7 Registrant's Plan and Agreement of Merger of The
Exploration Company with and into The Exploration
Company of Delaware, Inc., filed as Appendix A of the
registrants definitive Proxy Statement, dated January
12, 1999.
39
**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
o f Designation of Series 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, 2001.
40
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 28, 2002 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 28, 2002
/s/ Thomas H. Gose
Thomas H. Gose Director and Assistant Secretary March 28, 2002
/s/ James E. Sigmon
James E. Sigmon President and Director
(Principal Executive Officer) March 28, 2002
/s/ Michael J. Pint
Michael J. Pint Director March 28, 2002
/s/ Robert L. Foree, Jr.
Robert L. Foree, Jr. Director March 28, 2002
/s/ Alan L. Edgar
Alan L. Edgar Director March 28, 2002
/s/ Roberto R. Thomae
Roberto R. Thomae Chief Financial Officer March 28, 2002
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, 2001 and 2000, and the related consolidated
statements of operations, stockholders' equity and cash flows for the years
ended December 31, 2001 and 2000, August 31, 1999, 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 U. S. 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, 2001 and 2000, and the results of its operations and
cash flows for the years ended December 31, 2001 and 2000, August 31, 1999, and
the four months ended December 31, 1999, in conformity with U. S. generally
accepted accounting principles.
We have also audited Schedule II of The Exploration Company for the years ended
December 31, 2001 and 2000, August 31, 1999 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 8, 2002, except Note B, to which the date
is March 28, 2002
F-2
THE EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
DEC. 31, DEC. 31,
2001 2000
---------------- ------------
>
ASSETS
Current Assets:
Cash and equivalents $ 2,019,164 $ 5,898,015
Accounts receivable:
Joint interest owners 472,146 571,255
Oil and gas production 1,470,497 2,833,411
Prepaid expenses and other 273,603 226,916
Deferred tax asset, current portion - 1,489,402
------------- --------------
Total current assets 4,235,410 11,018,999
Property and Equipment:
Oil and gas properties (successful efforts), less accumulated depreciation,
depletion and amortization of $10,849,797 and $7,792,062, and accumulated
impairment of $6,007,150
and $4,882,759 19,566,617 13,921,843
Other property and equipment, less accumulated
depreciation of $380,409 and $268,512 327,123 161,762
------------- -------------
Net property and equipment 19,893,740 14,083,605
Other Assets:
Deferred tax asset, net of current portion 5,232,718 3,743,316
Other 481,564 359,721
------------- -------------
Total other assets 5,714,282 4,103,037
------------- -------------
TOTAL ASSETS $ 29,843,432 $ 29,205,641
============= =============
SEE NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS.
F-3
THE EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
DEC. 31, DEC. 31,
2001 2000
----------------- -------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued expenses $ 4,122,669 $ 1,632,581
Due to joint interest owners 1,368,785 2,620,644
Current portion of long-term debt 298,410 416,149
------------ ------------
Total current liabilities 5,789,864 4,669,374
Long-term debt, net of current portion 563,767 779,042
Minority interest in consolidated subsidiaries 433,105 435,489
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
17,496,849 and 17,471,849 shares, outstanding
17,397,049 and 17,471,849 shares 174,968 174,718
Additional paid-in capital 44,017,983 43,986,983
Accumulated deficit (20,890,248) (20,839,965)
Less treasury stock, at cost, 99,800
and -0- shares (246,007) -
------------ -------------
Total stockholders' equity 23,056,696 23,321,736
------------ -------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 29,843,432 $ 29,205,641
============= =============
SEE NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS.
F-4
THE EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
YEAR YEAR FOUR MONTHS YEAR
ENDED ENDED ENDED ENDED
DEC. 31, DEC. 31, DEC. 31, AUG. 31,
2001 2000 1999 1999
---- ---- ---- ----
REVENUES
Gas and oil sales $ 13,350,699 $ 13,841,138 $ 3,580,765 $ 6,881,767
Other operating income 1,158,788 889,978 271,324 615,608
------------- ------------- ------------- -------------
14,509,487 14,731,116 3,852,089 7,497,375
COSTS AND EXPENSES
Lease operations 2,406,688 1,157,291 496,950 864,675
Production taxes 959,143 990,789 261,997 471,193
Exploration expenses 2,986,036 3,056,466 259,625 269,344
Impairment and abandonments 2,652,705 3,126,715 320,000 623,784
Depreciation, depletion and amortization 3,201,517 2,711,605 671,593 2,327,992
General and administrative 2,231,851 1,871,404 544,485 1,442,338
------------ ------------- ------------ ------------
Total costs and expenses 14,437,940 12,914,270 2,554,650 5,999,326
------------ ------------- ------------ ------------
Income from operations 71,547 1,816,846 1,297,439 1,498,049
Other Income (Expense)
Interest income 188,061 232,386 27,082 73,892
Interest expense (128,373) (179,036) (131,872) (628,396)
Loan fee amortization - (12,000) (4,000) (12,000)
------------ ------------- ------------ ------------
59,688 41,350 (108,790) (566,504)
------------ ------------- ------------ ------------
Income before income taxes
and minority interest 131,235 1,858,196 1,188,649 931,545
Minority interest in income of subsidiaries (106,518) (238,061) - -
------------ ------------- ------------ ------------
Income before income taxes 24,717 1,620,135 1,188,649 931,545
Income tax (expense) benefit, net (75,000) 5,141,800 - -
------------ ------------- ------------ ------------
NET INCOME (LOSS) $ (50,283) $ 6,761,935 $ 1,188,649 $ 931,545
============ ============= ============ ============
EARNINGS (LOSS) PER SHARE
Basic $ (.003) $ 0.39 $ 0.07 $ 0.06
Diluted (.003) 0.39 0.07 0.06
Weighted average number of common
shares outstanding:
Basic 17,441,242 17,242,326 15,938,516 15,668,721
Diluted 17,441,242 17,343,957 15,991,526 15,678,567
SEE NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS.
F-5
THE EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
COMMON STOCK ADDITIONAL
PAID-IN ACCUMULATED TREASURY
SHARES AMOUNT CAPITAL DEFICIT STOCK TOTAL
------ ------ ------- ------- ----- -----
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
Common stock options exercised 25,000 250 31,000 - - 31,250
Purchases of treasury stock, at cost - - - - (246,007) (246,007)
Net loss for the year - - - (50,283) - (50,283)
----------- -------- ----------- ----------- ----------- -----------
Balance at December 31, 2001 17,496,849 $ 174,968 $ 44,017,983 $ (20,890,248) $ (246,007) $ 23,056,696
=========== ========= ============ ============= ========== ============
SEE NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS.
F-6
THE EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR YEAR FOUR MONTHS YEAR
ENDED ENDED ENDED ENDED
DEC. 31, DEC. 31, DEC. 31, AUG. 31,
2001 2000 1999 1999
---- ---- ---- ----
OPERATING ACTIVITIES
Net income (loss) $ (50,283) $ 6,761,935 $ 1,188,649 $ 931,545
Adjustments to reconcile net income to
net cash provided by operating activities:
Deferred income taxes - (5,232,718) - -
Depreciation, depletion and amortization 3,201,517 2,711,605 671,593 2,327,992
Amortization of financing fees - - 4,000 12,000
Impairments and abandonments 2,652,705 3,126,715 320,000 623,784
Minority interest in income of subsidiaries 106,518 238,061 - -
Changes in operating assets and liabilities:
Receivables 1,462,023 (1,465,530) 314,213 (1,391,683)
Prepaid expenses and other (46,687) (104,441) 133,859 (238,596)
Accounts payable and accrued expenses 1,238,229 494,211 1,320,288 1,593,162
------------ ------------ ------------ -----------
Net cash provided by operating activities 8,564,022 6,529,838 3,952,602 3,858,204
INVESTING ACTIVITIES
Development of oil and gas properties (13,360,347) (6,290,260) (196,103) (3,448,320)
Proceeds from sale of oil and gas properties 2,005,133 - - -
Purchases of other property and equipment (314,980) (157,702) (3,349) (31,486)
Distributions to minority interests (108,902) - - -
Other changes (116,007) 8,843 75,000 (10,000)
------------- ------------- ------------ -----------
Net cash (used) by investing activities (11,895,103) (6,439,119) (124,452) (3,489,806)
FINANCING ACTIVITIES
Proceeds from long-term debt 153,231 1,173,642 20,131 900,000
Payments on long-term debt (486,244) (1,658,386) (1,435,004) (2,629,118)
Issuances of common stock, net of expenses 31,250 2,910,247 - -
Purchases of treasury stock (246,007) - - -
------------- ------------- -------------- -----------
Net cash provided (used) by financing activities (547,770) 2,425,503 (1,414,873) (1,729,118)
------------- ------------- -------------- -----------
CHANGE IN CASH AND EQUIVALENTS (3,878,851) 2,516,222 2,413,277 (1,360,720)
Cash and Equivalents at Beginning of Period 5,898,015 3,381,793 968,516 2,329,236
------------- ------------- --------------- -----------
CASH AND EQUIVALENTS AT END OF PERIOD $ 2,019,164 $ 5,898,015 $ 3,381,793 $ 968,516
============= ============= ============== ===========
SUPPLEMENTAL DISCLOSURES:
Cash paid for interest $ 128,373 $ 179,036 $ 131,872$ 721,292
Cash paid for income taxes 75,000 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 of Delaware, Inc., d.b.a.
The Exploration Company (TXCO or Company) is an independent energy company
engaged in the acquisition, exploration, development and production 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.
CONSOLIDATION: The financial statements include the accounts of the Company and
its majority-owned subsidiaries. The subsidiaries own and operate a gas
gathering system which is utilized by the Company for delivery of natural gas
from 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 year ended August 31, 1999 has not been
recast to conform to the new year end of December 31.
REVENUE RECOGNITION: The Company recognizes gas and oil revenue from its
interest in producing wells as the gas and oil 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,
3-D seismic costs, development wells, and costs to drill and equip exploratory
wells that find proved reserves are capitalized. Costs to drill exploratory
wells that do not find proved reserves, geological and geophysical costs, 2-D
seismic 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. Depletion of
coalbed methane properties begins following the dewatering phase of each coalbed
methane project. 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.
F-8
NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - CONTINUED
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.
EARNINGS (LOSS) PER SHARE: The Company applies Statement of Financial Accounting
Standards (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 places its temporary cash investments with major
financial institutions which, from time-to-time, may exceed federally insured
limits, and believes the risk of loss is minimal. 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
U.S. 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 used to calculate depreciation,
depletion and amortization, 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) Opinion No.
25, ACCOUNTING FOR STOCK ISSUED TO EMPLOYEES, and related interpretations in
accounting for all stock option plans. 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 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.
F-9
NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - CONTINUED
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 on its financial position or on the
reporting of its operations.
NOTE B - SUBSEQUENT DEBT FINANCING
On March 4, 2002, the Company entered into an agreement with Hibernia National
Bank providing a $25 million revolving credit line with an initial borrowing
base of $5 million, of which $2.8 million was drawn as of March 28, 2002. The
interest rate under the credit facility will initially be based on the prime
lending rate as posted in The Wall Street Journal. Interest on funds drawn will
be paid monthly, with the principle due March 2005. The line is collateralized
by accounts receivable and oil and gas properties.
NOTE C - LONG TERM DEBT
Long-term debt consists of the following at December 31:
2001 2000
---------------- ---------------
Note payable to financing companies, with interest at 12.61%, due in monthly
installments of $22,404, with final
payment in 2005, and collateralized by compressor equipment. $ 728,435 $ 893,866
Installment notes to insurance company, with interest from 8.25% to 9.25%,
due in current monthly installments of $17,025 with final
payment in 2002, and unsecured. 84,855 32,487
Note payable to financing companies, with interest at 22.96%, due in monthly
installments of $1,965, with final payment in 2002,
and collateralized by office equipment. 20,895 37,538
Note payable to financing companies, with interest at 11.85%, due in monthly
installments of $834, with final
payment in 2005, and collateralized by office equipment. 27,992 34,268
Note payable to vendors, with interest at 8% to 9.50%, due in monthly
installments of $40,000, with final payment in 2001, and collateralized
by certain oil and gas properties. - 197,032
------------- --------------
Total long-term debt 862,177 1,195,191
Less current portion (298,410) (416,149)
------------- --------------
Long-term portion of debt $ 563,767 $ 779,042
============= =============
The following is a schedule of maturities of long-term debt as of December 31,
2001:
YEAR ENDED DECEMBER 31, AMOUNT
----------------------- ------
2002 $ 298,410
2003 218,358
2004 247,484
2005 97,925
2006 -
------------
$ 862,177
============
F-10
NOTE D - STOCKHOLDERS' EQUITY
PREFERRED STOCK: The Company has authorized 10,000,000 shares of preferred
stock, none of which has been issued at December 31, 2001. 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. 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, 2001.
STOCK REPURCHASE: On June 27, 2001, the Company's Board of Directors approved a
common share buyback program to purchase up to $2 million of the Company's
common shares in open market or privately negotiated treasury purchases. The
timing and amount of these stock repurchases are determined at the discretion of
management. As of December 31, 2001, the Company has purchased 99,800 shares of
its common stock at a cost of $246,007 under this program.
STOCK OPTIONS: The Company grants options to its officers, directors, and key
employees under its 1995 Flexible Incentive Plan (The "Plan"), as amended. The
Plan was authorized to grant options to management, directors, and key employees
for up to 1,500,000 shares of the Company's common stock. In 2001, the Company's
shareholders approved a proposal to amend the Plan to increase by 200,000 the
maximum number of shares common stock that may be issued with respect to awards
under the plan. All options granted have ten year terms and vest and become
fully exercisable based on the specific terms imposed at the date of grant.
The Company has elected to follow APB No. 25 and related interpretations in
accounting for its employee stock options. Under APB No. 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.
Pro forma information regarding net income and earnings per share is required by
SFAS No. 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 YEAR FOUR MONTHS YEAR
ENDED ENDED ENDED ENDED
DEC. 31, DEC. 31, DEC. 31, AUG. 31,
2001 2000 1999 1999
---- ---- ---- ----
Risk-free interest rate 4.40% 5.11% 6.48% 5.0%
Dividend yield 0% 0% 0% 0%
Volatility of common stock .79 .67 1.21 .95
Weighted-average expected life of option 5 years 5 years 5 years 5 years
F-11
NOTE D - STOCKHOLDERS' EQUITY - CONTINUED
The Black-Scholes option valuation model was developed for use in estimating the
fair value of traded 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 YEAR FOUR MONTHS YEAR
ENDED ENDED ENDED ENDED
DEC. 31, DEC. 31, DEC. 31, AUG. 31,
2001 2000 1999 1999
---- ---- ---- ----
Pro forma earnings (loss) $ (357,803) $ 6,241,705 $ 1,122,238 $ 695,970
Pro forma earnings (loss) per common share:
Basic $ (0.02) $ 0.36 $ 0.07 $ .04
Diluted (0.02) 0.36 0.07 .04
A summary of the status of the Company's stock option activity and related
information is as follows:
WT.-AVG. EXERCISABLE WT.-AVG.
FAIR VALUE OF AT END EXERCISE
OPTIONS GRANTED OF PERIOD SHARES PRICE
--------------- --------- ------ -----
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
Granted $ 1.82 205,000 2.96
Exercised (25,000) 1.25
Forfeited (9,800) 3.91
-----------
Outstanding at December 31, 2001 649,000 1,604,000 2.43
===========
F-12
NOTE D - STOCKHOLDERS' EQUITY - CONTINUED
The following table summarizes information about the options outstanding at
December 31, 2001:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
--------------------------------------------- ----------------------------
Wt.-Avg.
REMAINING WT.-AVG WT.-AVG,
NUMBER CONTRACTUAL EXERCISE NUMBER EXERCISE
EXERCISE PRICE OUTSTANDING LIFE PRICE EXERCISABLE PRICE
-------------- ----------- ---- ----- ----------- -----
$ 0.98 25,000 6.83 years $ 0.98 25,000 $ 0.98
1.25 85,000 6.68 years 1.25 85,000 1.25
2.12 764,000 6.64 years 2.12 164,000 2.12
2.62 50,000 4.68 years 2.62 50,000 2.62
2.75 100,000 3.12 years 2.75 100,000 2.75
2.78 75,000 8.40 years 2.78 25,000 2.78
2.96 205,000 9.59 years 2.96 - 2.96
3.09 300,000 7.08 years 3.09 200,000 3.09
------- ------- -------
1,604,000 $ 2.43 649,000 $ 2.42
========= ==== ======= ====
STOCK WARRANTS: The following is a summary of warrants outstanding at December
31, 2001:
WT.-AVG.
WT.-AVG. REMAINING
NUMBER RANGE OF EXERCISE CONTRACUTAL
PURPOSE OF WARRANTS OF SHARES PRICES PRICE LIFE
------------------- --------- ------ ----- ----
Convertible notes and equity financing 1,566,429 $ 2.88 - $ 6.00 $ 3.06 3 years
(convertible notes subsequently paid
in full)
F-13
NOTE E - EARNINGS PER SHARE
The following is a reconciliation of the numerator and denominators of the basic
and diluted earnings per share computation:
INCOME PER SHARE
SHARES (LOSS) AMOUNT
------ ------ ------
YEAR ENDED DECEMBER 31, 2001:
Basic EPS:
Net income (loss) 17,441,242 $ (50,283) $ (0.003)
Effect of dilutive options - - -
----------- ------------ ---------
Dilutive EPS 17,441,242 $ (50,283) $ (0.003)
=========== ============ =========
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
=========== ============ =========
The 2001 loss per share does not include the effect of options and warrants as
their impact would be antidilutive.
F-14
NOTE F - OPERATING LEASES
The Company leases its primary office space through February 2005. The Company
incurred rent expense of $146,000, $133,000 and $95,000 for the years ended
December 31, 2001 and 2000 and August 31, 1999, and $33,000 for the four months
ended December 31, 1999. Future minimum rentals under all noncancelable leases
are as follows:
YEAR ENDED DECEMBER 31, AMOUNT
----------------------- ------
2002 $ 149,000
2003 153,000
2004 156,000
2005 26,000
NOTE G - INCOME TAXES
In years prior to 2000, 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.
The components of the Company's income taxes were as follows for the years ended
December 31:
2001 2000
Current federal tax expense $ 75,000 $ 90,918
Deferred federal tax (benefit) - (5,232,718)
---------- ----------
Income tax (benefit), net $ 75,000 $(5,141,800)
========== ===========
The following items give rise to the deferred tax assets and liabilities:
DEC, 31, DEC. 31,
2001 2000
------------ -------------
Deferred tax assets:
Tax net operating loss carryforwards $ 4,860,000 $ 5,480,000
Impairment of oil and gas and mineral properties 3,010,000 1,660,000
------------ -------------
Net deferred tax assets 7,870,000 7,140,000
Less valuation allowance (2,637,282) (1,907,282)
------------ -------------
Deferred income tax asset recorded $ 5,232,718 $ 5,232,718
============ =============
The Company's available net operating loss carryforwards of approximately
$14,300,000 ($4,860,000 tax benefit) at December 31, 2001, expire from 2006 to
2019.
F-15
NOTE G - INCOME TAXES - CONTINUED
The differences between the expected federal income taxes and the Company's
actual taxes are as follows:
FOUR MONTHS
YEAR ENDED YEAR ENDED ENDED YEAR ENDED
DEC. 31, DEC. 31, DEC. 31, AUG. 31,
2001 2000 1999 1999
------------- ------------ ----------- ------------
Expected federal taxes $ 3,700 $ 551,000 $ 404,000 $ 317,000
Change in valuation allowance 730,000 (6,388,718) (387,600) (1,072,020)
Other changes (658,700) 695,918 (16,400) 755,020
------------- ------------ ----------- ------------
Income tax expense (benefit) $ 75,000 $ (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 No.
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 changes during the last few
years. It has impaired or abandoned over $6.4 million on certain unproved
leasehold acreage during the last 4 years, minimizing its remaining exposure on
its unproved acreage positions. Although the Company's revenues dropped slightly
from 2000 to 2001, this was primarily attributable to the sudden decline in both
gas and oil prices commencing in the 2nd quarter of 2001 which affected the
entire industry. This return to extremely low pricing levels caused depletion
and amortization rates, and the related impairment of proved producing
properties, to increase significantly during the last half of 2001, particularly
in the 4th quarter when the full impact of these price declines was realized. In
addition, the reduction in natural gas prices from $11.04 per Mcf at year end
2000 to $2.72 per Mcf at year end 2001 reduced the Company's future cash inflows
as estimated by its independent petroleum engineering consultants. However, the
Company's equivalent gas proved reserves more than doubled during the same
period, from 4,532,000 Mcf to 10,976,000 Mcf.
Management believes it is more likely than not that a significant portion of its
deferred income tax asset will be realized. In 2000, the valuation allowance was
reduced and a deferred tax asset recognized for the amount expected to be
realized through taxable earnings. In 2001, this deferred tax asset recognized
was not changed, although the valuation allowance was increased for the net
change in the deferred tax components. In determining the valuation allowance,
the Company uses future income projections, reduced by graduating percentages to
compensate for uncertainties inherent in future years' projections. These
graduating percentages are changed periodically to compensate for the
fluctuations, both up and down, in natural gas and oil pricing. Regardless of
management's expectations, there can be no assurance that the Company will
generate any specific level of continuing earnings.
NOTE H - MAJOR CUSTOMERS
Sales to unrelated entities which individually comprised greater than 10% of
total oil and gas sales are as follows:
A B C
Year ended December 31, 2001 30% 57% <10%
Year ended December 31, 2000 28% 26% 18%
Four months ended December 31, 1999 28% <10% 57%
Year ended August 31, 1999 23% <10% 55%
NOTE I - 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).
F-16
NOTE J - OIL AND GAS PRODUCING ACTIVITIES AND PROPERTIES
CAPITALIZED COSTS AND COSTS INCURRED RELATING TO OIL AND GAS ACTIVITIES
The Company's investment in oil and gas properties is as follows at:
DEC. 31, DEC. 31,
2001 2000
-------------- --------------
Proved properties:
Conventional oil and gas properties $ 24,735,881 $ 17,161,948
Coalbed methane properties 5,962,313 1,081,460
-------------- --------------
Total proved property 30,698,194 18,243,408
Less reserve for impairment (5,145,837) (2,797,408)
Less accumulated depreciation,
depletion and amortization (10,849,797) (7,792,062)
-------------- --------------
Net proved properties 14,702,560 7,653,938
Unproved properties 5,725,370 8,353,256
Less reserve for impairment (861,313) (2,085,351)
-------------- --------------
Net unproved properties 4,864,057 6,267,905
-------------- --------------
Net capitalized cost $ 19,566,617 $ 13,921,843
============== ==============
Costs incurred, capitalized, and expensed in oil and gas producing activities
are as follows:
YEAR YEAR FOUR MONTHS YEAR
ENDED ENDED ENDED ENDED
DEC. 31, DEC. 31, DEC. 31, AUG. 31,
2001 2000 1999 1999
---- ---- ---- ----
Property acquisition costs, unproved $ 1,627,967 $ 2,319,285 $ 35,900 $ 890,418
Property development and exploration costs:
Conventional oil and gas properties 11,262,498 6,386,606 1,396,125 3,340,702
Coalbed methane properties 4,880,853 1,081,460 - -
Depreciation, depletion and amortization 3,040,932 2,625,924 654,592 2,281,758
Depletion per equivalent Mcf of production 1.02 .79 .52 .69
F-17
NOTE J - 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.
The Company has not yet established any reserves related to its coalbed methane
properties in the tables below. This project is still in the dewatering phase,
which must be completed before economic quantities of natural gas production may
be realized and reserves estimated. Changes in estimated net quantities of
conventional oil and gas reserves, all of which are located within the United
States, are as follows:
YEAR YEAR FOUR MONTHS YEAR
ENDED ENDED ENDED ENDED
DEC. 31, DEC. 31, AUG. 31, AUG. 31,
2001 2000 2000 1999
---- ---- ---- ----
C>
Proved developed and undeveloped reserves:
Natural gas (Mcf):
Beginning of period 4,532,000 5,823,000 6,263,000 6,101,700
Extensions and discoveries 8,664,000 2,126,000 461,000 2,803,000
Reserves purchased - - - 338,000
Production (2,673,000) (2,965,000) (1,119,000) (2,813,000)
Revisions of previous estimates 453,000 (452,000) 218,000 (166,700)
----------- ------------ ----------- -----------
End of period 10,976,000 4,532,000 5,823,000 6,263,000
=========== ============ =========== ===========
Crude Oil (Bbls):
Beginning of period 183,000 93,000 106,000 100,600
Extensions and discoveries 66,000 5,000 4,500 32,000
Reserves purchased - - - 1,600
Production (50,000) (60,000) (24,000) (82,000)
Revisions of previous estimates 95,000 145,000 6,500 53,800
----------- ------------ ----------- -----------
End of period 294,000 183,000 93,000 106,000
=========== ============ =========== ===========
Proved developed reserves:
Natural gas (Mcf):
Beginning of period 4,532,000 5,823,000 6,263,000 6,102,000
End of period 5,102,000 4,532,000 5,823,000 6,263,000
Crude Oil (Bbls):
Beginning of period 183,000 93,000 106,000 101,000
End of period 133,000 183,000 93,000 106,000
F-18
NOTE J - 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 $2.72, $11.04, $1.99 and $2.58 per Mcf of
gas and $17.70, $25.67, $25.39 and $19.03 per barrel of oil as of December 31,
2001, 2000 and 1999 and August 31, 1999. 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 YEAR FOUR MONTHS YEAR
ENDED ENDED ENDED ENDED
DEC. 31, DEC. 31, DEC. 31, AUG. 31,
2001 2000 1999 1999
---- ---- ---- ----
Future cash inflows $ 35,359,000 $ 54,747,000 $ 15,158,000 $ 17,370,000
Future production and development costs (16,331,000) (10,516,000) (2,411,000) (2,484,000)
------------- ------------- ------------- --------------
Future net cash inflows before income tax 19,028,000 44,231,000 12,747,000 14,886,000
Future income tax expense - (6,045,000) - -
------------- ------------- ------------- --------------
Future net cash flows 19,028,000 38,186,000 12,747,000 14,886,000
10% annual discount to reflect timing of
net cash flows (5,045,000) (6,226,000) (2,648,000) (2,441,000)
------------- ------------- ------------- --------------
Standardized measure of discounted future
net cash flows relating to proved reserves $ 13,983,000 $ 31,960,000 $ 10,099,000 $ 12,445,000
============ ============= ============= ===============
The principal factors comprising the changes in the standardized measure of
discounted future net cash flows is as follows:
YEAR YEAR FOUR MONTHS YEAR
ENDED ENDED ENDED ENDED
DEC. 31, DEC. 31, DEC. 31, AUG. 31,
2001 2000 1999 1999
---- ---- ---- ----
Standardized measure, beginning of period $ 31,960,000 $ 10,099,000 $ 12,445,000 $ 8,824,000
Extensions and discoveries 8,505,000 5,935,500 903,000 6,810,000
Reserves purchased - - - 350,000
Sales and transfers, net of production costs (9,984,868) (11,693,058) (2,821,818) (5,545,899)
Revisions in quantity and price estimates (15,881,132) 31,208,458 817,318 2,888,899
Net change in income taxes 2,580,000 (2,580,000) - -
Accretion of discount (3,196,000) (1,009,900) (1,244,500) (882,000)
------------ ------------ ------------- ------------
Standardized measure, end of period $ 13,983,000 $ 31,960,000 $ 10,099,000 $ 12,445,000
============ ============ ============ ============
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, 2001
Allowance for doubtful accounts,
trade accounts $ 27,000 $ - $ - $ 27,000
Impairment of oil and gas properties 4,882,759 2,627,705 (1,503,314) 6,007,150
Deferred tax asset valuation allowance 1,907,282 730,000 - 2,637,282
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