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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.
September 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 October 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 19
1
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS.
THE EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
Assets September 30, December 31,
2002 2001
- ------ ------------ ------------
Current Assets
Cash $ 2,524,579 $ 2,019,164
Accounts receivable, net 4,325,653 1,942,643
Prepaid expenses 682,635 273,603
------------ ------------
Total Current Assets 7,532,867 4,235,410
Property and Equipment
Oil and gas properties, net 36,933,433 19,566,617
Other property and equipment, net 758,254 327,123
------------ ------------
37,691,687 19,893,740
Other Assets
Deferred tax asset 5,232,718 5,232,718
Other assets 524,956 481,564
------------ ------------
5,757,674 5,714,282
------------ ------------
Total Assets $ 50,982,228 $ 29,843,432
============ ============
See notes to consolidated financial statements.
2
THE EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, December 31,
Liabilities and Stockholders' Equity 2002 2001
- ------------------------------------ ------------- ------------
Current Liabilities
Accounts payable and accrued expenses $ 4,379,261 $ 4,122,669
Due to joint interest owners 2,416,022 1,368,785
Current portion of long-term debt 550,734 298,410
------------ ------------
Total Current Liabilities 7,346,017 5,789,864
Long-term debt, net of current portion 4,201,148 563,767
Minority interest in consolidated subsidiaries 1,426,595 433,105
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 (20,131,874) (20,890,248)
Less treasury stock, at cost
99,800 shares (246,007) (246,007)
------------ ------------
Total Stockholders' Equity 38,008,468 23,056,696
------------ ------------
Total Liabilities and
Stockholders' Equity $ 50,982,228 $ 29,843,432
============ ============
See notes to consolidated financial statements.
3
THE EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
Three Months Ended
September 30
------------------------
2002 2001
---- ----
Revenues
Oil and gas sales $ 5,410,090 $ 2,348,855
Gas marketing revenues 424,257 -0-
Pipeline revenues 85,080 -0-
Other operating income 34,879 336,940
------------ ------------
5,954,306 2,685,795
Costs and Expenses
Lease operations 1,286,064 689,839
Production taxes 292,920 163,881
Exploration expenses 403,167 673,190
Impairment and abandonments 514,950 351,000
Gas marketing costs 347,920 -0-
Pipeline operating costs 110,418 -0-
Depreciation, depletion and amortization 1,487,466 690,231
General and administrative 507,434 560,518
------------ ------------
Total costs and expenses 4,950,339 3,128,659
------------ ------------
Income (loss) from Operations 1,003,967 (442,864)
Other Income (Expense)
Interest income 15,144 25,542
Gain on sale of assets -0- -0-
Interest expense (80,180) (28,773)
------------ -------------
(65,036) (3,231)
------------ -------------
Income (loss) before income taxes
and minority interest 938,931 (446,095)
Minority interest in income of subsidiaries (6,978) (17,068)
------------ -------------
Income (loss) before income taxes 931,953 (463,163)
Income tax benefit (expense) -0- (17,250)
------------ -------------
Net Income (Loss) $ 931,953 $ (480,413)
============ =============
Earnings (Loss) Per Share
Basic $ 0.05 $ (0.03)
============ =============
Diluted $ 0.04 $ (0.03)
============ =============
See notes to consolidated financial statements.
4
THE EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
Nine Months Ended
September 30
-----------------------
2002 2001
---- -----
Revenues
Oil and gas sales $ 10,978,399 $ 11,531,265
Gas marketing revenues 532,863 -0-
Pipeline revenues 127,687 -0-
Other operating income 561,287 900,082
------------ ------------
12,200,236 12,431,347
Costs and Expenses
Lease operations 2,832,034 1,731,510
Production taxes 654,041 829,360
Exploration expenses 985,468 2,510,602
Impairment and abandonments 1,257,850 1,315,000
Gas marketing costs 437,905 -0-
Pipeline operating costs 126,994 -0-
Depreciation, depletion and amortization 3,356,290 1,954,894
General and administrative 1,675,798 1,629,275
----------- ------------
Total costs and expenses 11,326,380 9,970,641
----------- ------------
Income from Operations 873,856 2,460,706
Other Income (Expense)
Interest income 36,818 175,463
Gain on sale of assets 95,434 -0-
Interest expense (193,297) (100,433)
----------- -------------
(61,045) 75,030
----------- -------------
Income before income taxes
and minority interest 812,811 2,535,736
Minority interest in income of subsidiaries (129,437) (95,803)
----------- -------------
Income before income taxes 683,374 2,439,933
Income tax benefit (expense) 75,000 (254,250)
----------- -------------
Net Income $ 758,374 $ 2,185,683
=========== =============
Earnings Per Share
Basic $ 0.04 $ 0.13
=========== =============
Diluted $ 0.04 $ 0.12
=========== =============
See notes to consolidated financial statements.
5
THE EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Ended
September 30
----------------------
2002 2001
---- ----
Operating Activities
Net income $ 758,374 $ 2,185,683
Adjustments to reconcile net income to net cash
provided by operating activities:
Deferred income taxes -0- 170,000
Depreciation, depletion and amortization 3,366,396 1,954,894
Impairment and abandonments 1,257,850 1,315,000
Minority interest in income of subsidiaries 129,437 95,803
Changes in operating assets and liabilities:
Receivables (2,383,010) 1,507,730
Prepaid expenses and other (409,882) 32,865
Accounts payable and accrued expenses 1,303,829 (201,145)
----------- ------------
Net cash provided in operating activities 4,022,994 7,060,830
Investing Activities
Development and purchases
of oil and gas properties (22,052,470) (11,627,829)
Purchase of other equipment (559,616) (310,304)
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 1,272,000 -0-
Distributions to minority interests (407,947) (100,718)
------------ ------------
Net cash (used) in investing activities (21,548,033) (10,024,725)
Financing Activities
Deferred financing fees (52,648) -0-
Proceeds from debt obligations 4,157,565 153,231
Payments on debt obligations (267,861) (385,682)
Issuance of common stock, net
of offering costs 14,193,398 31,250
Purchase of treasury stock -0- (246,007)
------------ ------------
Net cash provided (used) in financing activities 18,030,454 (447,208)
------------ ------------
Change in cash and equivalents 505,415 (3,411,103)
Cash and equivalents at beginning of period 2,019,164 5,898,015
------------ ------------
Cash and equivalents at end of period $ 2,524,579 $ 2,486,912
============ ============
See notes to consolidated financial statements
6
THE EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PERIODS ENDED SEPTEMBER 30, 2002 AND SEPTEMBER 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 September 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 Nine Months Ended
September 30, September 30,
------------------- -----------------
2002 2001 2002 2001
---- ---- ---- ----
Weighted average number of
shares outstanding-basic 19,984,716 17,411,309 18,776,297 17,455,973
Net number of shares issued
on the assumed exercise of
stock options and warrants 1,344,532 85,741 1,139,876 130,199
---------- ---------- ---------- ----------
Number of shares used in the
computation of diluted
earnings per share 21,329,248 17,497,050 19,916,173 17,586,172
========== ========== ========== ==========
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.
As a result of certain changes to the Corporate alternative minimum tax
provisions included in the Job Creation and Worker Assistance Act of 2002, as
signed into law on March 9, 2002, the Company expects to have no tax liability
for tax year 2002, has recouped the federal income taxes paid in tax year 2001,
and has recorded a current tax benefit of $75,000 in the quarter ended March 31,
2002.
7
4. LONG-TERM DEBT
On March 4, 2002, the Company established 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 on September 30 and March 31 through maturity. 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
the Company's 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 September 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 a financing of this type.
The Company is in compliance with all covenants. Subsequent to the end of the
third quarter, an additional $2,000,000 was drawn on the Credit Facility
bringing the outstanding balance to $5,800,000 at October 31, 2002.
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".
LIQUIDITY AND CAPITAL RESOURCES
Cash reserves of $2,019,164 at December 31, 2001 were increased by cash
provided from operating activities of $4,022,994 for the nine months ended
September 30, 2002. Also during the nine month period, cash of $200,000 was
obtained from the sale of oil and gas properties, $1,272,000 was provided by
contributions made by minority interests and proceeds from borrowings on the new
Credit Facility totaled $3,800,000. Additionally, cash of $357,565 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 $25,865,121 for use in meeting the Company's
ongoing operational and development needs.
During the first quarter, portions of this cash were used to fund principal
payments of $102,342 on debt, 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 second quarter, portions of this cash were used to fund
principal payments of $86,628 on debt, and related interest of $78,267. 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.
8
During the quarter ended September 30, 2002 additional amounts were used to
fund principal payments of $78,891 on debt and related interest of $80,180. In
addition the Company applied $6,682,916 to fund the acquisition, expansion and
ongoing development of its oil and gas properties which included the acquisition
of an additional leasehold block contiguous to its existing acreage in the
Maverick Basin. These expenditures included drilling and completion costs of
$5,304,000 for wells drilled or completed during the period, a four mile
extension of its Maverick-Dimmit pipeline for $287,000, costs associated with
the acquisition of 3-D seismic on the eastern half of the Comanche Ranch
Prospect of $410,000 and $232,000 for costs associated with the acquisition of
3-D seismic on its newly acquired Pena Creek prospect. Also included were
expenditures associated with the acquisition of a well service rig, winch truck
and a vacuum truck for $150,000 and $185,000 to upgrade the Company's
information systems and related infrastructure.
As a result of these activities, the Company's working capital position
improved from a negative working capital of $1,554,454 at December 31, 2001, to
a positive position of $186,850 with its current ratio improving from .73 to 1
to 1.03 to 1 at September 30, 2002. During this same period, cash flow from
operating activities decreased to $4,022,994 from $7,060,830 in the comparative
prior year period reflecting the decrease in gas commodity prices compared to
the prior year, though partially offset by the significant increase in oil sales
volumes during the current year. Current quarter net income was $931,953
compared to a loss of $480,413 for the same period of 2001. For the nine months
ended September 30, 2002, net income totaled $758,374 compared to net income of
$2,185,683 for the prior year period. The increase in current quarter net income
was primarily caused by the increase in oil production volume attributable to
the Comanche lease oil wells compared to the same quarter of the prior year. The
overall decrease for the nine month period was primarily caused by the decrease
in oil and gas commodity prices while partially offset by increased oil
production during the year compared to the prior year.
Earnings before interest expense, taxes, depreciation, depletion,
amortization, exploration expense, impairments and abandonments (EBITDA), was
$6,476,279 for the nine months ended September 30, 2002 as compared to
$8,320,862 for the comparative prior year period. The change reflects the
decreased revenues caused by lower oil and gas prices, somewhat offset by
increased oil production primarily from the Comanche lease oil wells during the
current year.
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 initial 80% interest ($3.9 million) was purchased through
its newly formed Maverick-Dimmit Pipeline, Ltd. partnership (the Partnership).
The remaining 20% of the Partnership was held by an unaffiliated private energy
concern. This acquisition was funded with proceeds from a $15 million private
placement also closed in May.
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
dehydrators which allow the system to have maximum deliverable capacity of 35
MMcfd of which 50 percent is currently utilized. Adding this system to TXCO's
Maverick Basin infrastructure gave the Company control of approximately 80 miles
of pipeline in the Basin.
9
In June, the Partnership acquired an additional 10 miles of pipeline from
TXCO's 62.5% owned subsidiary, the Paloma Pipeline L.P. for $1 million. During
the third quarter, the Partnership began construction of a 4 mile, $400,000
pipeline extension to connect the Company's growing Chittim lease production to
the pipeline system. This extension was placed in service early in the fourth
quarter.
Subsequent to the end of the third quarter, TXCO consolidated its position
by acquiring the outstanding 20% minority interest in Maverick-Dimmit Pipeline,
Ltd. at its book value of $1.3 million. The consolidation was funded through
TXCO's available Credit Facility.
PRODUCING PROPERTY ACQUISITION
Also in May 2002, the Company acquired the Pena Creek oil 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 270 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. Since acquisition, the
Company has been addressing deferred repair and maintenance work left by the
previous owner and is conducting engineering and geologic evaluations of the
property. The Company's engineers believe that additional proved undeveloped
reserves will be established within the field.
During the current quarter, TXCO, along with its partner, Saxet Energy,
initiated a 42 square mile 3-D seismic survey covering the Pena Creek field and
surrounding acreage. To date, data acquisition has been completed over
approximately 33 square miles, which included the Pena Creek field. The
remaining data acquisition is scheduled for early 2003. TXCO expects to exit
2002 with over 415 square miles of high definition 3-D seismic data in its
growing seismic data base. The data base includes most of TXCO's Maverick Basin
lease block.
CREDIT FACILITY
Due to the Company's drilling success during the first quarter, the Company
requested an unscheduled redetermination of the borrowing base as provided for
under its Credit Facility with Hibernia National Bank. As a result, the
Company's borrowing base increased to $10 million in April, 2002. The lender is
currently conducting its regularly scheduled midyear redetermination. The
Company expects this review will result in a measurable increase to its
borrowing base. At October 31, 2002, the Company's outstanding balance under the
Credit Facility was $5.8 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 has progressively 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 now increased its
estimated 2002 capital expenditure program to over $27 million. The increased
activities include $9.6 million for the two acquisitions discussed above, $7.3
million for 13 additional Glen Rose wells and oil pipeline/gathering system
infrastructure expansions on its Comanche lease, $1.7 million for other drilling
including 5 optimized coal bed methane (CBM) wells and 2 horizontal gas wells
plus $2.2 million for 3-D seismic and leasehold acquisitions. Through the nine
months ended September 30, 2002, the Company had expended approximately $22
million of its revised capital budget for the year.
Management believes 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 nine months of
the year: d) the stabilization of oil and gas prices: and e) the expected
incremental revenues from its acquisitions of Merit's Pena Creek property and
Aquila's 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.
10
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.
RESERVE GROWTH
The Company's proved oil & gas reserves were estimated as of June 30, 2002
and December 31, 2001 by Netherland Sewell & Associates, Inc., TXCO's
independent reserve engineering consultants. Using the SEC requirements of
constant prices with a 10% present value discount (PV-10) and on a pretax basis,
the Company's proved reserves were estimated at approximately $47 million at
June 30, 2002 and $14 million at December 31, 2001. The Company's next
independent reserve estimate is scheduled for December 31, 2002. Based on
drilling activity and operations during the third quarter, management estimates
its PV-10 reserves at September 30 are comparable to the latest independent
reserve estimate at June 30, 2002.
RESULTS OF OPERATIONS
Oil and gas revenues for the third quarter of 2002 increased 130% over the
third quarter of 2001 while year-to-date revenues decreased by 5% compared to
the respective period of the prior year. The quarterly increase is attributable
to increased oil sales volumes and the impact of slightly higher realized oil
and gas prices. The decrease for the current 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 oil and gas prices were 5% and 4% higher
respectively for the current quarter as compared to 2001, while year-to-date
prices for oil declined 4% and gas prices declined 43% from the comparable
period in 2001.
2002 2001
------------------- -------------------
Sales Average Sales Average
Volume Prices Volume Prices
------ ------ ------ ------
Three months ended Sept 30,
Gas (Mcf) 626,077 $ 3.39 623,856 $ 3.26
Oil (Bbls) 130,041 $ 25.27 13,171 $ 24.16
Nine months ended Sept 30,
Gas (Mcf) 1,915,356 $ 3.06 1,957,810 $ 5.40
Oil (Bbls) 212,402 $ 24.06 38,256 $ 25.19
On an equivalent unit basis, total production/sales volumes for the quarter
ended September 30, 2002 increased 100% over the year ago quarter and 37% over
the second quarter of 2002. Production/sales volumes for the current
year-to-date period increased 46% over the comparative prior year period. The
Company exited the third quarter of 2002 with overall net production rates of
approximately 1,500 barrels of oil per day and 7.2 million cubic feet of gas per
day.
Gas sales volumes decreased slightly due to the general production decline
of the Company's maturing gas wells but were mostly offset by sales volumes from
new wells placed on line subsequent to September 30, 2001. Oil sales volumes
increased 887% and 455% respectively, compared to the quarter and year-to-date
periods of the prior year, primarily reflecting production from new Comanche
lease oil wells, along with production from the May, 2002 acquisition of the
Pena Creek field.
Other operating income decreased by 90% and 38% for the current period and
year-to-date. These decreases reflect revised reporting of administrative
overhead charged to wells. Beginning with the third quarter, administrative
overhead charged to wells totaling $170,000 was recorded as a reduction to
general and administrative expenses. In prior periods, this item was included as
Other operating income. Comparative amounts included in Other operating income
in prior periods totalled $249,000 and $576,000 respectively for the third
quarter and year-to-date periods of the prior year and $353,000 for the current
year-to-date period. In addition, the current quarter includes $509,000 and
$660,500 of gas marketing and pipeline revenues generated from the operation of
the Company's recently acquired gas pipeline system.
11
Lease operating expenses (LOE) increased 86% and 64% for the quarter and
year-to-date periods ended September 30, 2002 as compared to the respective
prior year periods of 2001. The increase for the current quarter includes the
incremental LOE component associated with the newly acquired Pena Creek oil
field of $340,000 and the additional LOE associated with Saxet operated Comanche
lease oil wells placed on line during 2002 of $282,000. The year-to-date LOE
increase is due primarily to incremental LOE of $430,000 associated with the
recently acquired Pena Creek oil field and $319,000 associated with the Comanche
lease oil wells placed on line during 2002. Also included are increased LOE of
$282,000 associated with the CBM pilot projects and the San Miguel waterflood
pilot project, oil and gas wells placed online subsequent to September 30, 2001.
Production taxes increased 79% for the current quarter while decreasing 21%
year-to-date when compared to the respective prior year periods. These variances
are consistent with the changes in oil and gas revenues and also reflect the
changing mix of oil versus gas revenues.
Exploration expenses decreased by 40% and 61% 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 reflecting the Company's 96%
drilling success ratio through the nine months ended September 30, 2002. The
decreases in dry hole costs were partially offset by increases in current year
delay rental payments to maintain the Company's growing Maverick Basin acreage
block. Delay rentals increased $169,000 for the current quarter reflecting
minimum royalty payments on the Kincaid lease. Impairment expense increased by
47% for the current period while decreasing 4% for the nine months ended
September 30, 2002. The increase reflects a $120,000 charge related to obtaining
a new lease on an expiring 5,000 acre portion of the Company's Paloma lease. Gas
marketing and pipeline operating expenses totaling $458,000 represent the
initial quarter of operations of the Company's recently acquired and renamed
Maverick-Dimmit gas pipeline system.
Depreciation, depletion and amortization increased by 116% and 72% for the
current quarter and year-to-date periods over the comparable prior year periods.
The increase in depletion was due primarily to higher depletion rates on
maturing gas wells and additional depletable costs associated with new oil and
gas wells. The increase in depreciation was due to the increased depreciable
base resulting from the purchase and expansion of the Maverick-Dimmit gas
pipeline system. Amortization increased by $8,500 and $126,000 respectively over
the comparable prior periods due to amortization related to capitalized 3-D
seismic costs incurred subsequent to the first quarter of 2001.
General and administrative expense for the current quarter decreased by 9%
while the year-to-date period increased by 3% over the prior periods. The
decrease in the current quarter and the slight increase in the year-to-date
period reflect an offset to general and administrative expenses for
administrative overhead charged directly to existing wells. Beginning with the
current quarter, administrative overhead charged to wells totaling $170,000 is
included as a reduction to general and administrative expenses. In prior
periods, this item was recorded as Other operating income. Comparative amounts
included in prior periods are $249,000 and $576,000 respectively for the third
quarter and year-to-date 2001 periods and $353,000 for the current year-to-date
period. This reduction to general and administrative expense was offset by
higher sustained levels of the Company's existing operations along with all
newly acquired pipeline and producing properties. The higher levels of
operations are reflected in increased salaries, wages and benefits associated
with staff increases and higher insurance expense reflecting the increased
exposure and related costs for property and liability coverages.
Interest income decreased due to lower invested cash reserve levels during
2002 as compared to 2001. The increases in the gain on sale of assets and the
minority interest in income of subsidiaries primarily reflects the sale of
pipeline assets by the minority partners in TXCO's Paloma lease gathering
system. Interest expense increased $41,407 and $92,864 respectively, for the
third quarter and year-to-date period as compared to the same periods of the
prior year primarily reflecting borrowings under its Credit Facility.
DRILLING ACTIVITIES
During the nine months ended September 30, 2002, the Company participated
in 31 wells including 27 new drilling wells and four re-entry wells on its
382,000 acre lease block in the Maverick Basin. Fifteen of the new wells were
drilled during the third quarter, while all four of the re-entry wells were
completed during the first quarter of 2002.
At September 30, 2002, 19 of the 27 new drilling wells were producing, one
well was dry, and seven remained in progress. The producing wells consisted of
nine Comanche lease Glen Rose oil wells, five Glen Rose shoal horizontal gas
wells, one Glen Rose shoal vertical gas well, one Glen Rose reef gas well, one
Glen Rose reef oil well, one Georgetown oil well and one CBM gas well.
12
The first exploratory 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.
TXCO (50% WI) and its partner, Saxet Energy (50% WI) initially established
the oil discovery appeared to be associated with a large porosity complex of
approximately 850 acres in size with 55 feet of net pay. Pursuant to Texas
Railroad Commission guidelines, the operator initiated 30 days of testing to
establish the Maximum Effective Rate (MER) for the well, which was established
at 2,200 bopd as the initial well in the newly designated Comanche-Halsell
(6500) Field. Initially, the well produced no water; but after 60 days
production, the well began to produce some water. Subsequently, production rates
have been reduced. Currently, the well is producing about 400 bopd and 1,000
bwpd.
Between March and June, the partners drilled four additional exploratory
Comanche wells utilizing 3-D seismic to identify the locations for additional
drilling targets indicating the presence of a high porosity complex. The
Comanche 1-2, the 1-13, the 1-39 and the 1-112 wells (all 50% WI) were drilled
to depths ranging from 7,700 feet to 8,200 feet while production was established
from depths ranging from 6,500 feet to 6,700 feet. Initial oil production rates
ranged from 450 bopd to 1,000 bopd on the first three wells while only about 35
bopd on the fourth well. Initial water production rates ranged from two barrels
of water per day (bwpd) up to 250 bwpd.
Encouraged by the strong oil flows from four of the initial wells, the
operator mobilized a second drilling rig from mid June through July. Prior to
experiencing significant water production encountered in later wells, the
operator continued its initial completion procedure of drilling through the high
porosity interval to test the underlying formations for their hydrocarbon
potential. During July, completion procedures were modified to drill only to the
top of the targeted porosity zone. The modified completion procedure was applied
to all subsequent wells.
During the third quarter, the partners drilled nine additional Saxet
operated exploratory Comanche wells. July drilling included the Comanche 1-14,
the 1-116, the 1-44 and the 2-111 wells (all 50% WI). The wells were drilled to
depths ranging from 6,600 feet to 7,200 feet while production was established
from depths ranging from 6,340 feet to 7,180 feet. Initial oil production rates
ranged from 0 bopd on the first well versus 675 bopd to 1,000 bopd on the last
three wells. Initial water production rates ranged from 950 bwpd on the first
well versus 0 bwpd on the last three wells.
August drilling included the Comanche 2-116, the 2-2 and the 2-44 wells
(all 50% WI). The wells were drilled to depths ranging from 6,410 feet to 6,770
feet. The first well established production at a depth of 6,410 feet with
initial production rates of 220 bopd and 370 bwpd. The 2-2 well failed to locate
the high porosity interval while the 2-44 well encountered only minimal porosity
and failed to establish any production.
September drilling included the Comanche 1-118 and 2-13 wells (both 50%
WI). The wells were drilled to 6,400 feet and 6,600 feet, respectively. The
1-118 well encountered the porosity interval at a depth of 6,400 feet, tested no
oil and produced 120 bwpd. The 2-13 well failed to locate the high porosity
interval.
Subsequent to September 30, the Comanche 2-116 was shut in due to increased
water production. Current Comanche lease gross daily oil production from the
remaining eight producing wells has declined to about 2,500 barrels of oil per
day while water production has increased to about 3,400 barrels per day.
Cumulative gross oil production for the Comanche lease has climbed to more than
450,000 BO, while the water cut, the water to total production ratio, has
increased to 58%.
Currently, six wells are not producing and remain shut in. Two of these
wells failed to locate the targeted high porosity interval and are pending
further evaluation for additional completion techniques. The four remaining
wells that made mostly water await being reworked, sidetracked, drilled
horizontally or conversion for use as water disposal wells.
13
Initial interpretation of Comanche lease 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 to date has been ineffective in
isolating the water zones below the oil producing interval.
Even though the operator began drilling only into the top of the producing
interval to reduce potential water production, more recently drilled wells were
still encroached by the water. In spite of the fact that most wells are making
water, it remains unclear 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 14 exploratory Saxet operated Comanche wells have now been
drilled, and to date, eight producing wells are spread over an extensive area,
the productive and areal extent of the porosity interval is not yet fully
defined.Because the 40 degree gravity oil is consistent over the entire area and
contains no gas, the Company's engineers believe that all the productive wells
will eventually be determined to be in communication. Management believes 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 Comanche lease oil discovery.
Due to the annual operations moratorium during hunting season, running from
November to mid-January, additional drilling and completion activities on the
Comanche lease are currently suspended. While the Comanche oil production
remains profitable, increasing levels of associated water production are
expected to reduce future oil production levels until a field-wide development
plan to optimize oil production is established. Exploratory drilling on the
Comanche lease is expected to resume in early January 2003.
The Company and its partner have received the preliminary analysis of the
recently completed 3-D seismic survey covering the eastern half of the 95,000
acre Comanche lease in addition to a contiguous 27,000 acre area including the
Company's Pena Creek oil field to the east. Based on the initial data, TXCO's
exploration staff believes the oil producing high porosity interval will extend
into the eastern half of the Comanche lease providing numerous drilling
prospects for its 2003 drilling program.
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. The Company also
drilled the Chittim 2-143 (47% WI), spudded in May 2002, the Chittim 2-128 (47%
WI), spudded in June 2002 and the Chittim 1-127 (47% WI) and Chittim 3-128 (47%
WI), both spudded in August 2002. All five wells encountered natural gas from
the Glen Rose "C" interval around 5,300 to 5,500 feet. Horizontal displacements
of these wells range from approximately 2,670 feet to approximately 3,650 feet.
The six producing wells are currently producing a gross combined total of
approximately 6,500 mcfd. The Company plans to drill two additional horizontal
shoal wells during the remainder of 2002 and to date, has established 16
additional proved undeveloped horizontal drilling locations prospective for gas
production from Glen Rose shoals.
The Company drilled eight other wells through the third quarter of 2002.
The Paloma 1-82 (97.5% WI), spudded in March 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 is currently producing at a rate of 800 mcfd.
The Kincaid 1-166 (63% WI), spudded in March was drilled to a total depth of
5,200 feet also targeting a gas well completion in a Glen Rose reef. The reef
was wet and the Company then evaluated the Glen Rose shoal interval. Because the
shoal interval had low permeability, the Company is currently evaluating
reworking procedures for a potential horizontal completion in the McKnight
formation scheduled for early 2003. During April, 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 20 bopd.
14
During July, the Company spudded the Paloma 1-85 (100% WI), a Paloma Glen
Rose reef test targeting a depth of 5,600 feet. The target zone was not economic
and the well was plugged. Also during July, the Company drilled the Burr 4-31
(100% WI) targeting the Georgetown interval. This well is currently a marginal
oil producer. The Briscoe Saner 3-47 (100% WI) was spudded in September and
drilled to a depth of 5,400 feet targeting a Glen Rose reef. The targeted reef
proved to be wet and the well is awaiting completion in the Georgetown interval.
In October, the Company spudded the Paloma 2-72H (97.5% WI), targeting a
horizontal gas well completion in the McKnight formation. The well reached total
vertical depth of 3,400 feet with a horizontal displacement of 2,600 feet.
Absent further weather delays, the well is scheduled for completion in November,
2002.
COAL BED METHANE
The Company is accelerating the development of its coal bed methane (CBM)
project. During the current quarter, the Company spudded the Comanche 9-91,
the first of five new CBM locations planned before year-end. The remaining four
wells were drilled subsequent to the third quarter bringing the CBM pilot
project to a total of 39 wells. These latest wells were drilled using air
drilling and completion techniques designed to maximize response from coal
formations. Initial production levels to date confirm the optimized drilling and
completion configuration has effectively accelerated gas and water production
from the coal bearing zone. The five optimized wells are currently producing a
total of 30 mcfd and 755 bwpd. Notwithstanding the encouraging results of the
optimized new drilling, the Company's CBM pilot program remains in the
dewatering phase. During the current quarter and prior to the recent 5 well
addition, the Company's dewatering operations suffered repeated production
interruptions due to severe hurricane related weather. The storms disrupted the
pilot project's power supplies and flooding hampered repair and maintenance
activities. Current daily production from the initial 34 pilot program wells is
120 mcfd and 1,400 bwpd. However, once the weather related repairs are
completed, the Company expects to re-establish and subsequently exceed prior
production levels of approximately 175 mcfd.
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. The waterflood project is proceeding as planned. It is in
the first stage of development and has not yet shown a significant response to
the water injection.
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 affected acreage. In March, Blue Star delivered a nearly
final processed data set containing over 83 square miles of digitized seismic
data for TXCO's ongoing review. In August, Blue Star provided TXCO with a
comprehensive review of the latest seismic imagery resulting from recently
completed, state of the art, processing techniques. The findings confirm the
presence and ranking of numerous drilling locations on TXCO's acreage.
Blue Star had previously confirmed its receipt of acceptable proposals from
qualified drilling contractors, had conducted field inspections and had obtained
current title opinions on multiple drilling locations under evaluation. On
October 8, 2002, the partners signed an amendment, restatement and ratification
of the existing joint venture agreement committing Blue Star to begin drilling
the initial Jurassic test well on TXCO's Paloma or Kincaid lease no later than
March 31, 2003.
15
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.
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.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
There have been no material changes since December 31, 2001. See the
Company's Annual Report on Form 10-K, "Item 7A. Quantitative and
Qualitative Disclosures About Market Risk
ITEM 4. CONTROLS AND PROCEDURES.
a. The Company's Chief Executive Officer and the Chief Financial Officer
have carried out an evaluation of the effectiveness of the design and
operation of the Company's disclosure controls and procedures pursuant
to Exchange Act Rule 13a-14 and Rule 15d-14 as of September 30, 2002.
Based upon that evaluation, the Company's Chief Executive Officer
along with the Chief Financial Officer concluded that our disclosure
controls and procedures are effective in timely alerting them to
material information relating to the Company (including its
consolidated subsidiaries) required to be included in our periodic SEC
filings.
b. There have been no significant changes in the Company's internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of the above evaluation.
16
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
None
ITEM 5. OTHER INFORMATION
None
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a) Exhibits. The following are filed as exhibits to this form 10-Q:
99.1 Certification of Chief Executive Officer required pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002 filed
herewith.
99.2 Certification of Chief Financial Officer required pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002 filed
herewith.
b) Reports on Form 8-K:
None
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: November 13, 2002 chief accounting officer)
17
FORM OF SARBANES-OXLEY SECTION 302(A) CERTIFICATION
I, James E. Sigmon, certify that:
1. I have reviewed this quarterly report on Form 10-Q of The Exploration
Company of Delaware, Inc.;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present, in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
i) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
ii) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
iii) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent functions):
i) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
ii) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: November 13, 2002 /s/ James E. Sigmon
--------------------- -------------------------
James E. Sigmon
Chief Executive Officer
18
FORM OF SARBANES-OXLEY SECTION 302(A) CERTIFICATION
I, Roberto R. Thomae, certify that:
1. I have reviewed this quarterly report on Form 10-Q of The Exploration
Company of Delaware, Inc;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present, in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
i) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
ii) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
iii) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent functions):
i) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
ii) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: November 13, 2002 /s/ Roberto R. Thomae
--------------------- --------------------------
Roberto R. Thomae
Chief Financial Officer
19
EXHIBIT 99.1
CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of The Exploration Company of
Delaware, Inc. (the "Company") on Form 10-Q for the period ending September 30,
2002 as filed with the Securities and Exchange Commission on the date hereof
(the "Report"), I, James E. Sigmon, Chief Executive Officer of the Company,
hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, that:
1. The Report fully complies with the requirements of Section 13(a) or 15(d)
of the Securities Exchange Act of 1934; and
2. The information contained in the Report fairly presents, in all material
respects, the financial condition and results of operations of the Company.
/s/ James E. Sigmon
Name: James E. Sigmon
Title: Chief Executive Officer
Date: November 13, 2002
This certification is being furnished solely pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and
is not being filed as part of the Report or as a separate disclosure document.
EXHIBIT 99.2
CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of The Exploration Company of
Delaware, Inc. (the "Company") on Form 10-Q for the period ending September 30,
2002 as filed with the Securities and Exchange Commission on the date hereof
(the "Report"), I, Roberto R. Thomae, Chief Financial Officer of the Company,
hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, that:
1. The Report fully complies with the requirements of Section 13(a) or 15(d)
of the Securities Exchange Act of 1934; and
2. The information contained in the Report fairly presents, in all material
respects, the financial condition and results of operations of the Company.
/s/ Roberto R. Thomae
Name: Roberto R. Thomae
Title: Chief Financial Officer
Date: November 13, 2002
This certification is being furnished solely pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and
is not being filed as part of the Report or as a separate disclosure document.