UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarter ended Commission File No.
June 30, 2002 0-9120
THE EXPLORATION COMPANY OF DELAWARE, INC.
(Exact Name of Registrant as Specified in its Charter)
DELAWARE 84-0793089
(State or other jurisdiction of (I.R.S. Employer I.D. No.)
incorporation or organization)
500 NORTH LOOP 1604 E., SUITE 250 SAN ANTONIO, TEXAS 78232
(Address of principal executive offices)
Registrant's telephone number, including area code: (210) 496-5300
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 the number of shares outstanding of each of the issuer's classes of
common stock as of July 31, 2002.
Common Stock $0.01 par value 19,984,716
(Class of Stock) (Number of Shares)
THIS DOCUMENT IS AVAILABLE ON THE INTERNET AT WWW.TXCO.COM
Total number of pages is 17
Page 1
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS.
THE EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
Assets June 30, 2002 December 31, 2001
- ------ ------------- -----------------
Current Assets
Cash $ 7,383,947 $ 2,019,164
Accounts receivable, net 3,062,605 1,942,643
Prepaid expenses 281,711 273,603
------------- -------------
Total Current Assets 10,728,263 4,235,410
Property and Equipment
Oil and gas properties, net 32,195,337 19,566,617
Other property and equipment, net 351,460 327,123
------------- ------------
32,546,797 19,893,740
Other Assets
Deferred tax asset 5,232,718 5,232,718
Other assets 528,508 481,564
------------- ------------
5,761,226 5,714,282
------------- -----------
Total Assets $ 49,036,286 $ 29,843,432
============= =============
See notes to consolidated financial statements.
Page 2
THE EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
Liabilities and Stockholders' Equity June 30, 2002 Dec 31, 2001
- ------------------------------------ ------------- -------------
Current Liabilities
Accounts payable and accrued expenses $ 4,004,059 $ 4,122,669
Due to joint interest owners 2,059,316 1,368,785
Current portion of long-term debt 288,558 298,410
------------ -----------
Total Current Liabilities 6,351,933 5,789,864
Long-term debt, net of current portion 4,257,060 563,767
Minority interest in
consolidated subsidiaries 1,350,778 433,105
Stockholders' Equity
Preferred stock, authorized
10,000,000 shares issued and
outstanding -0- shares
Common stock, par value $.01 per share;
authorized 50,000,000 shares; issued
20,084,516 and 17,496,849 shares,
outstanding 19,984,716 and
17,397,049 shares 200,845 174,968
Additional paid-in capital 58,185,504 44,017,983
Accumulated deficit (21,063,827) (20,890,248)
Less treasury stock, at cost
99,800 shares in 2002 and 2001 (246,007) (246,007)
------------- -------------
Total Stockholders' Equity 37,076,515 23,056,696
------------- -------------
Total Liabilities and
Stockholders' Equity $ 49,036,286 $ 29,843,432
============= =============
See notes to consolidated financial statements.
Page 3
THE EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
Three Months Three Months
Ended Ended
June 30, 2002 June 30, 2001
-------------- -------------
Revenues:
Oil and gas sales $ 3,749,531 $ 3,625,011
Gas marketing revenues 108,606 -0-
Pipeline revenues 42,607 -0-
Other operating income 257,108 306,104
------------ ------------
4,157,852 3,931,115
Costs and Expenses:
Lease operations 862,695 679,792
Production taxes 235,641 257,980
Exploration expenses 287,111 809,306
Impairment and abandonments 379,200 613,000
Gas marketing costs 89,985 -0-
Pipeline operating costs 16,576 -0-
Depreciation, depletion
and amortization 1,086,622 639,008
General and administrative 587,628 560,336
------------ -----------
Total costs and expenses 3,545,458 3,559,422
------------ -----------
Income from Operations 612,394 371,693
Other Income (Expense):
Interest income 16,009 69,022
Gain on sale of assets 95,434 -0-
Interest expense (78,267) (36,612)
------------ ------------
33,176 32,410
------------ ------------
Income before income taxes
and minority interest 645,570 404,103
Minority interest in income of subsidiaries (102,923) (30,401)
------------ ------------
Income before income taxes 542,647 373,702
Income tax benefit (expense) -0- (17,000)
------------ ------------
Net Income $ 542,647 $ 356,702
============ ============
Earnings Per Share:
Basic $ 0.03 $ 0.02
============= ============
Diluted $ 0.03 $ 0.02
============= ============
See notes to consolidated financial statements.
Page 4
THE EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
Six Months Six Months
Ended Ended
June 30, 2002 June 30, 2001
------------- -------------
Revenues:
Oil and gas sales $ 5,568,309 $ 9,182,410
Gas marketing revenues 108,606 -0-
Pipeline revenues 42,607 -0-
Other operating income 526,408 563,142
------------ ------------
6,245,930 9,745,552
Costs and Expenses:
Lease operations 1,545,970 1,041,671
Production taxes 361,121 665,478
Exploration expenses 582,301 1,837,413
Impairment and abandonments 742,900 964,000
Gas marketing costs 89,985 -0-
Pipeline operating costs 16,576 -0-
Depreciation, depletion and
amortization 1,868,824 1,264,663
General and administrative 1,168,364 1,068,757
------------ ------------
Total costs and expenses 6,376,041 6,841,982
------------ ------------
Income (Loss) from Operations (130,111) 2,903,570
Other Income (Expense):
Interest income 21,674 149,921
Gain on sale of assets 95,434 -0-
Interest expense (113,117) (71,660)
------------ ------------
3,991 78,261
------------ ------------
Income (loss) before income taxes
and minority interest (126,120) 2,981,831
Minority interest in income of subsidiaries (122,459) (78,735)
------------ ------------
Income (loss) before income taxes (248,579) 2,903,096
Income tax benefit (expense) 75,000 (237,000)
------------ ------------
Net Income (Loss) $ (173,579) $ 2,666,096
============ ============
Earnings (Loss) Per Share:
Basic $ (0.01) $ 0.15
============ ============
Diluted $ (0.01) $ 0.15
============ ============
See notes to consolidated financial statements.
Page 5
THE EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Six Months
Ended Ended
June 30, 2002 June 30, 2001
------------- -------------
Operating Activities:
Net income (loss) $ (173,579) $ 2,666,096
Adjustments to reconcile net income to net cash
provided (used) by operating activities:
Deferred income taxes -0- 170,000
Depreciation, depletion and amortization 1,874,528 1,264,663
Impairment and abandonments 742,900 964,000
Minority interest in income of subsidiaries 122,459 78,735
Changes in operating assets and liabilities:
Receivables (1,119,962) 382,076
Prepaid expenses and other (8,108) (113,376)
Accounts payable and accrued expenses 571,921 1,642,210
----------- -----------
Net cash provided in operating activities 2,010,159 7,054,404
Investing Activities:
Development and purchases
of oil and gas properties (15,369,554) (7,861,421)
Purchase of other equipment (95,227) (112,559)
Proceeds from the sale of
oil and gas properties 200,000 2,005,133
Proceeds from the sale of
other equipment -0- 8,993
Contributions made by minority interests 1,200,000 -0-
Distributions to minority interests (404,786) (100,355)
----------- -----------
Net cash (used) in investing activities (14,469,567) (6,060,209)
Financing Activities:
Deferred financing fees (52,648) -0-
Proceeds from debt obligations 3,872,411 51,893
Payments on debt obligations (188,970) (310,164)
Issuance of common stock, net
of offering costs 14,193,398 31,250
----------- -----------
Net cash provided (used) in financing activities 17,824,191 (227,021)
----------- -----------
Change in cash and equivalents 5,364,783 767,174
Cash and equivalents at beginning of period 2,019,164 5,898,015
----------- -----------
Cash and equivalents at end of period $ 7,383,947 $ 6,665,189
=========== ===========
See notes to consolidated financial statements
Page 6
THE EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PERIODS ENDED JUNE 30, 2002 AND JUNE 30, 2001 (Unaudited)
1. BASIS OF PRESENTATION
The accompanying unaudited consolidated financial statements of The Exploration
Company (TXCO or the Company) have been prepared in accordance with U.S.
generally accepted accounting principles for interim financial information and
with the instructions to Form 10-Q and Article 10 of Regulation S-X.
Accordingly, they do not include all of the information and footnotes required
by generally accepted accounting principles for complete financial statements.
The accounting policies followed by the Company are set forth in Note A to the
December 31, 2001 audited consolidated financial statements contained in the
Company's annual report on Form 10-K.
In the opinion of management, all adjustments (consisting of normal recurring
adjustments) considered necessary for a fair presentation have been included.
For further information, refer to the consolidated financial statements and
footnotes thereto included in the Registrant Company's annual report on Form
10-K for the year ended December 31, 2001, which is incorporated herein by
reference.
2. COMMON STOCK AND BASIC INCOME OR LOSS PER SHARE
As of June 30, 2002, the Company had outstanding and exercisable warrants and
options to purchase 3,056,429 shares of common stock at prices ranging from
$0.98 to $6.00 per share. The warrants and options expire at various dates
through August 2011.
The following table sets forth the determination of the number of shares
used in the earnings per share computations:
Three Months Ended Six Months Ended
June 30, June 30,
-------- --------
2002 2001 2002 2001
---- ---- ---- ----
Weighted average number of
shares outstanding-basic 18,947,126 17,484,761 18,172,088 17,478,305
Net number of shares issued
on the assumed exercise of
stock options and warrants 1,455,960 110,860 992,530 206,777
---------- ---------- ---------- ----------
Number of shares used in the
computation of diluted
earnings per share 20,403,086 17,595,621 19,164,618 17,685,082
========== ========== ========== ==========
Page 7
3. INCOME TAXES
The Company has recorded a deferred tax asset for the amount expected to be
realized through taxable earnings. In determining taxable earnings, the Company
uses income projections reduced by graduating percentages to compensate for
uncertainties inherent in future years' projections. Total income tax expense is
computed based on the Company's estimated annualized federal income tax for the
year, considering the impact of any change in the amount of deferred tax asset.
The Company recorded a current tax benefit of $75,000 in the quarter ended March
31, 2002 as a result of certain changes to the Corporate alternative minimum tax
included in the Job Creation and Worker Assistance Act of 2002 signed into law
on March 9, 2002.
4. LONG-TERM DEBT
On March 4, 2002, the Company entered into a $25,000,000 Revolving Credit
Facility (the Credit Facility) with Hibernia National Bank providing a credit
line with an initial borrowing base of $5,000,000. This borrowing base was
subsequently increased to $10,000,000 on April 12, 2002. The borrowing base is
determined based on the Company's proved oil and gas reserves. Interest is
payable monthly with principal due at maturity in March 2005. The Credit
Facility provides the lender with scheduled, semiannual borrowing base
redeterminations, at mid-year and each anniversary date. The Credit Facility
also provides for two unscheduled redeterminations per year at the Company's
discretion. Borrowings under the Credit Facility are secured by a first priority
mortgage covering working and other interests in the majority of its oil and gas
leases. The interest rate under the Credit Facility is initially based on the
prime rate as posted in the Wall Street Journal. The balance outstanding at June
30, 2002 was $3,800,000 with interest at 4.75% per annum. A Eurodollar Rate plus
applicable margin may be utilized at the election of the Company. The Credit
Facility contains certain financial covenants and other negative restrictions
common for financing of this type. The Company is in compliance with all
covenants.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Certain statements in this report are not historical in nature, including
statements of TXCO's and management's expectations, intentions, plans and
beliefs, are inherently uncertain and are "forward-looking statements" within
the meaning of Section 21E of the Securities and Exchange Act of 1934. The
following discussion should be read in conjunction with the unaudited
consolidated financial statements and notes thereto included in this Form 10-Q,
and with the Company's latest audited consolidated financial statements and
notes thereto, as reported in its Form 10-K for the year ended December 31,
2001. See "Disclosure Regarding Forward Looking Statements" on page 15.
LIQUIDITY AND CAPITAL RESOURCES
Cash reserves of $2,019,164 at December 31, 2001 were increased by cash provided
from operating activities of $2,010,159 for the six months ended June 30, 2002.
Also during the six month period, cash of $200,000 was obtained from the sale of
oil and gas properties, $1,200,000 was provided by contributions made by
minority interests and proceeds from borrowings on the new Credit Facility
totaled $3,800,000. Additionally, cash of $72,411 was provided by other debt
obligations, $14,051,892 was provided from the private placement of 2,499,667
shares of common stock and $141,506 was provided from the exercise of
outstanding options for the purchase of the Company's common stock. This
resulted in total cash available of $23,495,132 for use in meeting the Company's
ongoing operational and development needs.
Page 8
During the first quarter, portions of this cash were used to fund payments on
debt totaling $102,342, financing fees related to the Credit Facility of $48,437
and related interest of $34,851. The Company applied $2,243,350 to fund the
expansion and ongoing development of its oil and gas producing properties. These
expenditures included $2,164,000 for drilling and completion costs for wells
drilled, re-entered or completed during the period.
During the current quarter ended June 30, 2002, additional portions of this
capital were used to fund payment of debt, including principal payments of
$86,628 and related interest payments of $69,267. In addition, the Company
applied $13,126,204 to fund the acquisition, expansion and ongoing development
of its oil and gas properties. These expenditures included the purchase of a
69-mile gas pipeline system for $4,900,000, the acquisition of the Pena Creek
producing properties for $3,750,000, drilling and completion costs of $3,395,000
for wells drilled or completed during the period and $830,500 of costs
associated with the acquisition of 3-D seismic on the eastern half of the
Comanche Ranch Prospect.
As a result of these activities, the Company's working capital position
significantly improved from a negative working capital of $1,554,454 at December
31, 2001, to a positive position of $4,376,330 with its current ratio improving
to 1.69 to 1 compared to .73 to 1 for the previous period. During this same
period, cash flow from operating activities decreased to $2,010,159 from
$7,054,404 in the comparative prior year period reflecting the substantial
decrease in current gas commodity prices compared to the prior year. Current
quarter net income was $542,647 compared to $356,702 for the same period of
2001. However, for the six months ended June 30, 2002, the Company incurred a
net loss of $173,579 compared to a net income of $2,666,096 for the prior year
period. The increase for the current quarter was primarily caused by the
increase in oil production volume attributable to the Comanche Ranch oil wells
compared to the prior year quarter, while the overall decrease for the six month
period was primarily caused by the decrease in revenues attributable to lower
oil and gas prices for the current year compared to the prior year.
EBITDA, earnings before interest, taxes, depreciation, depletion, amortization
and exploration expense, was $3,058,563 for the six months ended June 30, 2002
as compared to $7,040,832 for the comparative prior year period also reflecting
the decreased revenues caused by lower oil and gas prices.
PRIVATE PLACEMENT
In May 2002, the Company closed the sale through a private placement of
2,499,667 shares of restricted common stock at a price of $6.00 per share to a
group of 10 institutional investors. The Company raised $14,051,892, net of
estimated offering costs of $946,000, to be used for acquisitions, to accelerate
the development of the Company's extensive Maverick Basin acreage holdings and
for general corporate purposes. Pursuant to the placement agreement, the Company
filed a Form S-3 Registration Statement dated June 6, 2002, covering the issued
shares on behalf of the investors.
PIPELINE ACQUISITION
In May 2002, the Company completed the acquisition of The Maverick Pipeline
System from Aquila Southwest Pipeline Corporation for a total purchase price of
$4.9 million. TXCO's 80% interest ($3.9 million) was purchased through its newly
formed Maverick-Dimmit Pipeline, Ltd. partnership. The remaining 20% of the
partnership is held by an unaffiliated private energy concern. This acquisition
was funded with cash available from the closing of its recent $15 million
private placement.
The assets include a 69-mile natural gas pipeline from approximately 12 miles
north of Eagle Pass, Texas in Maverick County to Carrizo Springs, Texas in
Dimmit County. The terminus is the El Paso Energy Field Services delivery point.
Also included were a compressor station with three compressors and three
Page 9
dehydrators which allow the system to have maximum deliverable capacity of 35
MMcf/d of which 50 percent is currently utilized. Adding this system to TXCO's
Maverick Basin infrastructure gives the Company control of approximately 80
miles of pipeline in the Basin.
PRODUCING PROPERTY ACQUISITION
Also in May 2002, the Company acquired the Pena Creek Field in Dimmit County,
Texas from Merit Energy Company for $3.75 million. The purchase was effective
April 1, 2002. Currently the field produces approximately 325 barrels of oil per
day from the San Miguel formation and contains an estimated 564,000 barrels of
proved developed producing reserves. The 10,000-acre lease is contiguous to the
Company's Comanche lease acreage block and contains potential for production
from the underlying Glen Rose formation. The Company intends to extend a 3-D
seismic survey over the new acreage during the third quarter of 2002.
CREDIT FACILITY
Due to the Company's drilling success during the first quarter, the Company
requested a redetermination of the borrowing base under its new Credit Facility
with Hibernia National Bank. As a result of this redetermination, the Company's
borrowing base increased to $10 million in April, 2002. At June 30, 2002, the
Company's outstanding balance under the Credit Facility was $3.8 million (see
Note 4-Long Term Debt).
Based on the proceeds from the private placement, the anticipated increase in
cash flow from ongoing operations resulting from production increases and the
increased Credit Facility borrowing base, the Company expanded its original 2002
capital expenditure program. Initially budgeted at $6.6 million the original
2002 capital expenditure program included 15 Glen Rose reef wells and four San
Miguel re-entry wells. The Company has increased its 2002 capital expenditure
program to $22.9 million. The increase includes $7.7 million for the two
acquisitions discussed above, $5 million for at least 10 additional Glen Rose
wells on its Comanche lease and $2 million for 3-D seismic and leasehold
acquisitions.
Management is confident it will be able to meet its ongoing operating cash
requirements for the current year as well as complete the scheduled exploration
and development goals targeted by the growing 2002 capital expenditure program.
The Company's available capital funding includes proceeds from: a) the May 2002
private placement of common stock: b) its expanding Credit Facility: c) the
increases in production from its drilling activity in the first six months of
the year: d) the stabilization of oil and gas prices: and e) the expected
incremental revenues from its acquisitions of the Pena Creek property and the
Aquila gas pipeline system. The Company also believes it will maintain
sufficient liquidity to take advantage of new acquisitions or growth
opportunities as identified during the balance of 2002.
However, if realized oil and gas prices, or if levels of its Maverick Basin or
Williston Basin production are substantially less than expected, or if prices
for goods and services used in the Company's exploration, development and
operating activities rise significantly above budgeted levels, the Company's
financial condition and liquidity could be adversely affected. Should this
occur, Management retains the ability to extend the timing of its planned
development and exploration activities to match available working capital, while
maintaining its current operating activity levels and meeting its financial
obligations on a timely basis.
Page 10
RESERVE GROWTH
The Company's estimated proved oil and gas reserves as of June 30, 2002 and the
present value of their future net revenues using a 10% discount factor (PV-10
Value), were estimated by Netherland Sewell & Associates, Inc., TXCO's
independent reserve engineering consultants. The estimates are presented below
along with the comparative information as of December 31, 2001. 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 pre-tax
basis, and is not intended to represent the current market value of the
estimated oil and natural gas reserves owned by the Company.
The following estimates of proved 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 judgement. 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 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. 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.
June 30, 2002 December 31, 2001 Increase
------------- ----------------- ------------
Oil Reserves (Bbl) 2,226,000 294,000 1,932,000
Gas Reserves (Mcf) 11,883,000 10,976,000 907,000
Total Equivalent
Reserves (Mcfe) 25,239,000 12,740,000 12,499,000
PV-10 Value $ 47,494,000 $ 13,983,000 $ 33,511,000
The reserves included above are estimates only and should not be construed as
exact quantities. A substantial portion of these reserve volumes are for proved
undeveloped locations, including approximately 36% of the oil reserves and 51%
of the gas reserves at June 30, 2002 compared to 55% and 54% of the respective
reserves at December 31, 2001. Therefore, these reserves are based on estimates
of reservoir volumes and recovery efficiencies along with analogies to similar
production, where available. As such reserve estimates are usually subject to
greater revision than those based on substantial production and pressure data,
it may be necessary to materially revise these estimates up or down in the
future as additional performance data becomes available. As of the June 30, 2002
reserve report, the wells included in the Comanche Halsel (6500) Field had
limited production history, with the oldest well having only three months
production. Management anticipates that the reserves for this field will change
substantially as additional data is obtained.
Page 11
RESULTS OF OPERATIONS
Oil and gas revenues for the second quarter of 2002 increased 3% over the second
quarter of 2001 while year to date revenues decreased by 39% compared to the
respective period of the prior year. The quarterly increase is attributable to
increased oil sales volumes offset by a slight decline in gas sales volumes and
the impact of lower realized oil and gas prices. The decrease for the
year-to-date period is attributable to lower realized oil and gas prices and a
slight decrease in gas sales volumes, offset by a significant increase in oil
sales volumes. As reflected in the following table, average realized gas prices
were 28% and 55% lower than the comparable periods in 2001 while average oil
prices declined 6% and 14% respectively.
2002 2001
---- ----
Sales Average Sales Average
Volume Prices Volume Prices
------ ------ ------ ------
Three months ended June 30,
Gas (Mcf) 638,411 $ 3.52 672,975 $ 4.91
Oil (Bbls) 64,588 $ 23.25 12,874 $ 24.85
Six months ended June 30,
Gas (Mcf) 1,289,279 $ 2.90 1,333,953 $ 6.40
Oil (Bbls) 82,360 $ 22.16 25,085 $ 25.73
On an equivalent unit basis, total production/sales volumes for the quarter
ended June 30, 2002 increased 37% over the year ago quarter and 35% over the
first quarter of 2002.
Gas sales volumes decreased slightly due to the general production decline of
the Company's maturing gas wells while offset by sales volumes from new wells
placed on line subsequent to June 30, 2001. Oil sales volumes increased 402% and
228% respectively, compared to the quarter and year to date periods of the prior
year, primarily reflecting production from its new Comanche lease oil wells,
along with production from its recent Pena Creek acquisition. In addition, the
current quarter includes $151,000 of gas marketing and pipeline revenues
generated from the operation of the Company's recently acquired gas pipeline
system.
Lease operating expenses (LOE) increased 27% and 48% for the quarter and year to
date periods ended June 30, 2002 as compared to the respective prior year
periods of 2001. The quarterly increase reflects the incremental LOE component
associated with the Pena Creek oil field acquisition and also includes increased
CBM pilot program operating costs. The year to date LOE increase is due
primarily to increased LOE costs associated with the CBM pilot projects and with
the San Miguel oil wells placed online subsequent to June 30, 2001. Production
taxes decreased 7% and 46% for the respective periods consistent with lower
sales revenues and the changing mix of oil versus gas revenues compared to the
prior periods.
Exploration expenses decreased 65% and 68% for the current quarter and year to
date periods as compared to the respective prior year periods. These decreases
are primarily due to lower dry hole costs while offset by increases in delay
rental payments to maintain the Company's extensive lease position in the
Maverick Basin. This decrease reflects the 100 per cent drilling success ratio
through the six months ended June 30, 2002. Delay rentals increased $184,000 for
the current six month period reflecting payments associated with new leases
acquired subsequent to the second quarter of 2001. Impairment expense decreased
by 38% and 23% respectively. These decreases are primarily attributable to a
$232,000 charge for marginal producing properties in the prior year periods
while no similar charges were required in the current year. During the current
quarter, gas marketing and pipeline operating expenses totaling $106,000 were
incurred in operating the Company's recently acquired gas pipeline.
Page 12
Deprecation, depletion and amortization increased by 70% and 48% for the current
quarter and year to date periods over the comparable prior year periods. The
increase in depletion was due primarily to higher estimated depletion rates on
maturing gas wells and higher depletable costs associated with new wells.
Amortization increased by $58,800 and $117,600 for the comparable periods due to
additional amortization related to new seismic costs incurred subsequent to the
first quarter of 2001.
General and administrative expense for the current quarter and the year to date
period increased by 5% and 9% respectively over the prior periods. These
increases reflect the higher sustained levels of the Company's existing
operations along with the newly acquired operations and is due primarily to
increased salaries, wages and benefits associated with staff increases. Interest
income decreased due to lower invested cash reserve levels during the first six
months of 2002 as compared to the same period in 2001. The increases in the gain
on sale of assets and the minority interest in income of subsidiaries primarily
reflect the sale of pipeline assets by the minority partners in TXCO's Paloma
lease gathering system. Interest expense increased $41,655 and $41,457
respectively, for the second quarter and year to date period as compared to the
same periods of the prior year primarily reflecting the cash advances drawn on
the Hibernia National Bank credit facility.
DRILLING ACTIVITIES
During the six months ended June 30, 2002, the Company drilled or participated
in the drilling of 12 new wells on its 382,000 acre lease block in the Maverick
Basin. Ten of these wells are producing while two remain in progress at June 30,
2002. The producing wells consist of four Comanche lease Glen Rose oil wells,
three Glen Rose shoal horizontal gas wells, one Glen Rose shoal vertical gas
well, one Glen Rose reef gas well and one Glen Rose reef oil well.
The first well to target a Glen Rose reef on the Company's Comanche lease since
its acquisition was the Comanche 1-111 (50% WI) and resulted in a significant
Glen Rose oil well. The well was spudded in February 2002. The well encountered
significant oil flows from a depth of approximately 6,500 feet and 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 barrels of oil per day (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 Company (50% WI) and its partner, Saxet Energy, Ltd. (Saxet) (50% WI), have
established that the oil discovery is associated with a large porosity complex
approximately 850 acres in size with 55 feet of net pay. The Company and Saxet
filed an application for the establishment of new field rules and allowable
producing rates. As part of this determination, the Texas Railroad Commission
required a Maximum Effective Rate or MER test on the well. During this 30 day
test, the well was produced at various rates to gather data regarding potential
deliverable flow rates. The Texas Railroad Commission established an allowable
rate of 2,200 bopd on this first well in the new Comanche-Halsell (6500) Field.
The Company's preliminary potential oil-in-place estimates for this discovery
ranged from 60 to 75 million barrels of oil in place. Initially the well
produced no water; but after 60 days production, the well began to produce some
water. Subsequently, production rates were reduced. Currently the well is
producing 900 bopd and 750 bwpd.
Page 13
The second well, the Comanche 1-2 well (50% WI), was spudded in March 2002
approximately 4,500 feet northeast of the Comanche 1-111 discovery well. The
well was drilled to a total depth of 8,100 feet, plugged back to 6,700 feet and
completed as an oil producer. Initial production rates of 1,000 bopd and 250
bwpd gradually declined to the current rate of 200 bopd and 600 bwpd. The
Comanche 1-13 (50% WI) was the third well drilled by TXCO and its partner,
Saxet. This well was spudded in May 2002 and tested a separate porosity complex
identified by the seismic survey to exist approximately two miles west of the
initial discovery well. The initial production rate of 700 bopd was gradually
reduced with the influx of water to the current rate of 325 bopd and 250 bwpd.
The Comanche 1-39 (50% WI), the fourth well drilled by TXCO and Saxet was
drilled as an offset in the initial porosity complex approximately 4,000 feet
southwest of the Comanche 1-111 in June 2002. The well has continued to produce
at a rate of 900 bopd and 10 bwpd since completion. The fifth well, the Comanche
1-112 (50% WI), also spudded in June, was completed approximately 9,500 feet
northeast of, but in the same porosity complex as the Comanche 1-13. The well's
latest production was 35 bopd and 440 bwpd and is currently shut-in waiting
to be reworked.
Subsequent to June 30, 2002, the sixth, seventh, eighth and ninth Glen Rose
interval wells were spudded. The Comanche 1-14 (50% WI) was drilled
approximately 4,700 feet northeast of the Comanche 1-13. The well is currently
being reworked as its initial production was 950 bwpd. The Comanche 1-116 (50%
WI) was drilled and completed in a third porosity complex approximately 5.5
miles west of the initial discovery well. It is currently producing 750 bopd and
no water. The Comanche 1-44 (50% WI) was drilled and completed 4,300 feet
southeast of the Comanche 1-13. It is currently producing 675 bopd with no
water. The ninth well, the Comanche 2-111, was spudded July 31 and is currently
drilling. Of the eight completed wells, seven have contained between 25 feet and
72 feet of pay in the Glen Rose interval around a depth of 6,600 feet. The
eighth well is the first well to be drilled only into the top 10 feet of the
targeted porosity zone.
Current gross daily production from six of the completed wells is approximately
3,750 barrels of oil and 1,600 barrels of water per day. The two remaining wells
that have made mostly water are in the process of or await being reworked. The
Company expects that upon final completion, water production will be reduced and
oil volumes will increase comparably to the other producing wells.
Initial interpretation of water production surveys indicates that the majority
of the water production is coming from zones encountered below the main oil
producing horizon. Because the oil zone has such high porosity and permeability,
it will not support a conventional 15.6 pound per gallon cement column.
Consequently, the operator has attempted to isolate the zone using a low-density
9.5 pound per gallon cement that appears to be ineffective in isolating the
water zones below the oil producing interval. The last well completed, the
Comanche 1-44, was not drilled deep enough to encounter the water zones and is
currently producing water-free. The partners are contemplating drilling only
into the top of the producing interval in future wells to reduce potential water
production. In spite of the fact that the wells are making water, it is too
early to determine whether the zone has a strong water drive since the
production surveys indicate the water may be coming from zones below the
producing interval. Although the currently producing wells are spread over an
area encompassing 6.5 miles by 2 miles, limits of the field have not been
established. Because the 40 degree gravity oil is consistent over the entire
area and contains no gas, the Company's engineers believe it is possible that
all the productive wells will eventually be determined to be in one field. The
partners plan to drill at least two additional wells before the end of the year
to more fully define the productive and areal extent of the porosity interval.
Management is confident that once the water production issue is resolved,
significant additional proved reserves will be established. Until such time that
water production issues are fully resolved for affected wells and adequate
production profiles are established for newly completed wells, the Company's
ongoing engineering estimates will be unable to reflect the full reserve
potential attributable to the expanding Comanche lease oil discovery
At year end 2001, the Company established multiple proved undeveloped horizontal
drilling locations prospective for gas production from Glen rose shoals
identified on its Chittim lease acreage. The Chittim 1-142 (47% WI), spudded in
February 2002 was the first Glen Rose shoal well to be drilled since the shoal
play was identified by the Company in late 2001. In addition, the Company has
drilled the Chittim 2-143 (47% WI), spudded in May 2002 and the Chittim 2-128
(47% WI), spudded in June 2002. All three wells encountered natural gas from the
Glen Rose "C" interval around 5,300 feet. Horizontal displacements of these
wells range from approximately 3,270 feet to approximately 3,650 feet. The three
wells are currently producing a gross combined total of approximately 5,500
mcfd. The Company plans to drill three additional horizontal shoal wells during
the remainder of 2002 and has another 16 potential locations to be drilled.
Page 14
The Company has drilled four other wells through the second quarter of 2002. The
Paloma 1-82 (97.5% WI), spudded in March 2002 was drilled to a total depth of
5,200 feet targeting a vertical gas well completion in a Glen Rose shoal. The
well was acidized and is currently a marginal producer and remains under
evaluation. The Briscoe Saner 1-46 (100% WI) was also spudded in March, drilled
to a total depth of 5,200 feet and produced at a rate of 1,000 mcfd. The Kincaid
1-166 (63% WI), spudded in March 2002 was drilled to a total depth of 5,200 feet
also targeting a gas well completion in a Glen Rose reef. Because the target
zone had low permeability, the Company is currently evaluating reworking
procedures for a potential horizontal completion in the McKnight formation
scheduled for the third quarter. During April 2002, the Briscoe Saner 1-45 (100%
WI) was drilled to a total depth of 5,200 feet targeting a Glen Rose reef, was
completed as an oil well and is currently producing 47 barrels of oil per day.
Subsequent to June 30, 2002, the Company spudded two additional wells. The
Paloma 1-85 (100% WI), a Paloma Glen Rose reef test reached target depth of
5,600 feet. The target zone was not economic and the well was plugged.
Additionally, the Company drilled the Burr 4-31 targeting the Georgetown
interval. This well is currently being completed.
RE-ENTRY ACTIVITIES
During the first quarter of 2002 the Company successfully re-entered four
existing well bores, completing the wells in the San Miguel formation. The wells
expanded the San Miguel water flood injection pilot program initiated by TXCO in
September 2001. This program is targeting oil production from the San Miguel
formation located about 400 feet below the base of the Olmos coal interval on
the Company's Comanche lease. The Company is now operating two water flood pilot
projects on the Comanche lease, using CBM pilot program water production to
flood the San Miguel formation. The Company has effectively reduced its CBM
water disposal costs, while initiating secondary oil production from the
underlying formation. To date, the pilot waterflood has not shown a significant
response to the water injection, which is not unexpected for a project such as
this at this early stage.
JURASSIC FORMATION
During the first quarter of 2002, Blue Star's team of geoscientists met with
TXCO's exploration team on several occasions to obtain the Company's expertise
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 data set containing over 83 square miles of digitized
seismic data for TXCO's ongoing review. Blue Star has confirmed it has received
acceptable proposals from several qualified drilling contractors, has conducted
field inspections and has obtained current title opinions on multiple drilling
locations under evaluation. Discussions are ongoing with Blue Star management to
establish a spud date for the first Jurassic test well. Blue Star, as the
operator, has reaffirmed its intention to spud the first well prior to the end
of 2002.
DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS
This Quarterly Report on Form 10-Q includes forward-looking statements which are
not historical, including statements regarding TXCO's or management's
intentions, hopes, beliefs, expectations, representations, projections,
estimations, plans or predictions of the future, and which are made pursuant to
the safe harbor provisions of the Private Securities Litigation Reform Act of
1995. Such statements include those relating to estimated or expected prices,
production volumes, reserve levels, number of drilling locations, expected
drilling results and sources, levels, timing and costs of financing. It is
important to note that actual results may differ materially from the results
predicted in any such forward-looking statements.
The Company undertakes no obligation to update any information contained in this
report or to publicly release the results of any revisions to any such
forward-looking statements that may be made to reflect events or circumstances
that occur, or which the Company becomes aware of, after the date hereof.
Investors are cautioned that all forward-looking statements involve risks and
uncertainty, including without limitation, the costs of exploring and developing
new natural oil and gas reserves, the price for which such reserves can be sold,
environmental concerns effecting the drilling of natural oil and gas wells, as
well as general market conditions, competition and pricing.
Page 15
More information about potential factors that could affect the Company's
operating and financial results is included in TXCO's annual report on Form 10-K
for the year ended December 31, 2001. This and all previously filed documents
are on file at the Securities and Exchange Commission and can be viewed on
TXCO's web site at www.txco.com. Copies are available without charge, upon
request from the Company.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
None
ITEM 2. CHANGES IN SECURITIES
None
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On May 31, 2002, the Company held the Annual Meeting of Shareholders
at the Petroleum Club of San Antonio, pursuant to the notice mailed to
shareholders of record on April 15, 2002. The following matters were
submitted for approval by vote at the meeting. All matters were
approved by the shareholders vote and the results of the voting is
shown below for each matter.
1. Election of two Class A Directors to serve for three-year terms
expiring in 2005:
Nominee For Withheld
------- --- --------
Robert L. Foree, Jr 14,413,823 264,389
Thomas H. Gose 14,371,611 306,601
There were no changes in Directors of the Company
2. Proposal to ratify the appointment of Akin, Doherty, Klein &
Feuge, P.C., as independent auditors of the Company and its
subsidiaries for the calendar year ending December 31, 2002.
For Against Abstain
--- ------- -------
14,362,375 297,717 18,120
ITEM 5. OTHER INFORMATION
None
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a) Exhibit 99.1 Certification of Chief Executive Officer required
pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002 filed herewith.
b) Exhibit 99.2 Certification of Chief Financial Officer required
pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002 filed herewith.
c) Form 8-K, dated May 30, 2002, regarding the acquisition of
the Maverick Pipeline System from Aquila Southwest Pipeline
Corporation.
Page 16
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
THE EXPLORATION COMPANY
(Registrant)
/s/ Roberto R. Thomae
Roberto R. Thomae,
Chief Financial Officer
(Signing on behalf of the Registrant and as
Date: August 14, 2002 chief accounting officer)
Page 17