10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2002
Commission File Number 0-9120
THE EXPLORATION COMPANY OF DELAWARE, INC.
(Exact name of Registrant as specified in its charter)
Delaware				84-0793089
(State or other jurisdiction of				(I.RS. Employer
incorporation or organization)				Identification No.)
500 North Loop 1604 East, Suite 250, San Antonio, Texas 78232
(Address of principal executive offices)
Registrant's telephone number, including area code:    (210) 496-5300
Securities registered pursuant to Section 12(b) of the Act:    None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, par value $0.01 per share
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes		[X]	No		[   ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X].
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the act). Yes [X]
The aggregate market value of the voting stock (which consists solely of shares of Common Stock) held by non-affiliates of the registrant was $116.5 million based upon the closing price of $6.77 per share of such stock as reported by the NASDAQ Small-Cap Market under the symbol TXCO on June 28, 2002.
The number of shares outstanding of the Registrant's Common Stock as of March 24, 2003 was 20,009,716 of which 17,323,638 shares were held by non-affiliates.
Documents Incorporated by Reference:   None
For more information and a print friendly version of this document go to www.txco.com.

INDEX AND CROSS REFERENCE SHEET
	PART I	Page
Item 1.	Business	3
Item 2.	Properties	14
Item 3.	Legal Proceedings	19
Item 4.	Submission of Matters to a Vote of Security Holders	19
	PART II
Item 5.	Market for Registrant's Common Equity and Related Stockholder Matters	19
Item 6.	Selected Financial Data	20
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	20
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	29
Item 8.	Consolidated Financial Statements and Supplementary Data	29
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	29
	PART III
Item 10.	Directors and Executive Officers of the Registrant	30
Item 11.	Executive Compensation	32
Item 12.	Security Ownership of Certain Beneficial Owners and Management	33
Item 13.	Certain Relationships and Related Transactions	35
Item 14.	Controls and Procedures	35
	PART IV
Item 15.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K	35
	Signatures	37
	Audited Consolidated Financial Statements of The Exploration Company	F-1

PART I

ITEM 1. BUSINESS

GENERAL DEVELOPMENT OF BUSINESS

The Exploration Company (the "Company" or "TXCO") was incorporated in the State of Colorado on May 16, 1979, for the purpose of engaging in oil and gas exploration, development and production and became publicly held through an offering of its common stock in November 1979. In May 1999, the Company changed its state of incorporation from Colorado to Delaware, becoming The Exploration Company of Delaware, Inc. The Company continues doing business as The Exploration Company and its trading symbol on the Nasdaq Stock Market^SM remains TXCO. Effective in January 2000, the Company changed its annual reporting period from a fiscal year ending August 31 to a calendar year ending December 31.

Throughout its history, the Company's primary focus has been oil and gas exploration and production. Its long-term business strategy has been to acquire undeveloped mineral interests and to develop a multi-year inventory of drilling prospects internally through the application of state-of-the-art technologies, such as 3-D seismic and enhanced horizontal drilling techniques. The Company strives to discover, develop and/or acquire more oil and gas reserves than it produces each year from these internally developed prospects. As opportunities arise, the Company may selectively participate with industry partners in prospects generated by TXCO as well as by other parties. The Company also attempts to maximize the value of its technical expertise by contributing its geological, geophysical and operational core area competencies through joint ventures or other forms of strategic alliances with well capitalized industry partners in exchange for carried interests in seismic acquisit ions, leasehold purchases and/or wells to be drilled. From time to time, the Company offers portions of its developed and undeveloped mineral interests for sale. The Company finances its activities primarily through internally generated operating cash flows, while combining debt financing, equity offerings or sale of interests in properties when favorable terms or opportunities are available.

Prior to 1992, the Company's revenues were derived principally from the sale of oil and natural gas production from working, royalty and mineral interests, as well as sales of mineral interests acquired through leasing activities. From 1992 through 1996 the Company expanded its scope of activities by entering the then emerging alternative fuels vehicle conversion business through the creation of its ExproFuels division. In 1996, Management redirected its focus and resources to its core oil and gas exploration and production business. Accordingly, the ExproFuels division was incorporated and majority equity interest spun-off via a stock dividend to TXCO shareholders.

The continued availability of new equity and debt capital in 1998 through 2002, combined with the re-investment of TXCO's growing positive cash flow provided from operations, reaffirmed Management's ongoing strategy for improved shareholder value by maintaining its focus on its core business of oil and gas exploration and production. This strategy has allowed the Company to attract recognized industry partners, expand its core area leasehold acreage, increase its 3-D seismic database and interpretative skill set, and dramatically grow its reserve base while maintaining a conservative debt profile and growing through its drill bit success. In March 2002 TXCO's marked growth was further affirmed by a new $25 million reserve based credit facility. The credit facility was established to compliment the Company's expansive drilling program. The Company has remained focused on the Maverick Basin for 14 years and has successfully established a multi-year portfolio of geologic plays within its core area.

TXCO achieved significant progress and record growth during 2002 in many key areas of operations. Current year results include a 255% drill bit reserve replacement rate and an 8.7 Bcfe increase in reserves. Including an acquisition of 4 Bcfe reserves, TXCO's all sources reserve replacement was a record 347%. To support its growing asset base in the Maverick Basin, the Company acquired a 69 mile pipeline gathering system. The pipeline acquisition enables TXCO to realize higher prices for its natural gas and better share in proceeds from extraction of natural gas liquids. Positive cash flow provided from operations totaled $7.4 million. The following table illustrates key features of the Company's continuous development over the four fiscal years presented.

	Dec-2002		Dec-2001		Dec-2000	Aug-1999
No. of new gas wells completed	16		54		6	6
No. of new oil wells completed	14		9		3	2
No. of new gas wells purchased	-		-		-	6
No. of new oil wells purchased	94		-		-	-
Gas production (Mcf)	2,487,000		2,673,000		2,965,000	2,813,000
Gas reserve additions from drilling (Mcf)	5,103,000		8,664,000		2,126,000	2,803,000
Oil production (Bbl)	314,000		50,000		60,000	82,000
Oil reserves additions from drilling (Bbl)	600,000		66,000		5,000	32,000
Gas equivalent production (Bcfe)	4.37		2.97		3.33	3.30
Reserve additions (Bcfe)
Drilling	8.70		9.06		2.16	3.00
Revisions of previous estimates	2.44		1.02		.41	.15
Purchased	4.04		-		-	.35
Total reserves added (Bcfe)(2)	15.18		10.08		2.57	3.50
Reserve replacement rate
Drill bit	255%		339%		77%	95%
Drill bit plus purchases (all sources)	347%		339%		77%	106%
Operating revenues	$18,958,364		$13,758,920		$14,361,357	$7,235,391
Net Income (Loss)	$    (310,970	)	$      (50,283	)	$  6,761,935	$   931,545
Net cash provided from operations	$  7,389,430		$  8,564,022		$  6,529,838	$3,858,204
Non-developed Texas acreage leased (1)	408,992		372,000		365,000	95,000
Non-developed Williston Basin acreage leased	91,804		105,000		302,000	380,000
(1) 479,761 acres as of January 2003
(2) Reserve make-up at year end 2002: 62% gas, 52% proved developed
Over the last four years, TXCO has developed its natural gas production base significantly. This overall growth is primarily attributable to ongoing drilling activities and the acquisition of new non-developed leasehold acreage as well as the acquisition of a producing field with significant undeveloped potential in the Company's core area of operations, the Maverick Basin of South Texas. The growth is also reflected in the changed mix in leasehold: expansion in Texas acreage acquisitions, versus reduction in the Williston Basin acreage primarily in North Dakota through expiration or sales of maturing leases. During the same periods, operating revenues were significantly impacted by commodity price fluctuations.
TXCO's established operating strategy includes the pursuit of multiple growth opportunities, accelerated in 2001, based on diversification in exploration targets within its core area of operations. By aggressively expanding its surrounding lease holdings where geology indicates the likely continuation of known or prospective oil and gas producing formations, TXCO is well positioned to pursue new oil and gas reserves and expand its production base. The Maverick Basin offers this diversity in its multiple hydrocarbon bearing horizons. During 2002, the Company expanded its Maverick Basin lease block to 408,992 essentially contiguous acres and successfully completed 16 new gas wells in diverse horizons including the Glen Rose, the Olmos coals, the Escondido sands, the McKnight and the Georgetown intervals. Additionally, 14 new oil wells were completed in varying horizons including the Glen Rose, Georgetown, and the San Miguel formations. In January 2003 TXCO acquired an additi onal 70,769-acre lease in the Maverick Basin, contiguous to its existing acreage, bringing its overall position to almost 480,000 acres in the basin.
During 2002, the Company made significant strides in diversifying its oil and gas exploration efforts by identifying and pursuing the exploration of at least 6 new exploration targets in addition to targeting new Glen Rose oil production on the Company's Comanche lease. The Comanche oil discovery alone produced over 600,000 gross barrels of oil by year-end, largely responsible for the 83% increase in ending reserves. The Company believes that the Comanche lease will contribute significant new oil reserves in 2003 and future years. Following up on its 30 new oil and gas well completions in 2002, new exploration targets for 2003, in descending depth order, are: first, developing additional gas production from the Escondido sands; second, accelerating Coalbed Methane (CBM) gas production from dewatering Olmos coals; third, expanding waterflood oil production from the San Miguel interval; fourth, Georgetown deviated wells; fifth, continuing horizontal drilling for Glen Rose sho al gas production; sixth, Comanche lease oil wells targeting the high porosity complex; and seventh, consulting with operating partners in pursuit of deep Jurassic formation gas. As 2002 results confirmed, each of these high impact exploration targets has the potential to establish meaningful additions to TXCO's oil and gas reserves and significant numbers of new proved undeveloped and lower risk drilling locations. The enhanced risk profile and growth potential of the Company's exploration and development plans are evidenced by two years of record back to back reserve replacement rates.
Should its exploration and development plans progress as intended, the Company expects to continue the rapid growth of its oil and gas reserves in 2003 and to attain meaningful growth in oil and gas production levels. As the Company expected, at year-end 2002 and in early 2003, there has been significant improvements in oil and gas prices. Subject to prices remaining above 2002 levels and the establishment of meaningful new levels of oil and gas production from its 1st and 2nd quarter 2003 drilling results, TXCO has designed a capital expenditure budget ("CAPEX budget") of $27.4 million for 2003. The budget calls for drilling 93 new wells primarily aimed at expanding production and proved gas reserves from the newly discovered Comanche oil field, as well as the Georgetown, San Miguel and Glen Rose intervals. This level of expenditure is dependent on TXCO maintaining sufficient positive operating cash flow levels, and also relies on funding from the Co mpany's $25 million revolving credit facility with Hibernia National Bank (the "Credit Facility"). The borrowing base, initially established at $5 million and increased to $12 million by year end, is determined as a percentage of the discounted value of the Company's oil and natural gas reserves. Based on TXCO's continuing drilling success in 2003, the Company expects it will have sufficient working capital available to minimize required borrowings, continue growing its oil and gas reserve base and expects to be profitable in 2003. Although there is no assurance the Company will be successful in maintaining its ongoing drilling success at sufficient levels to fund its capital needs during 2003, Management retains its ability to modify its capital expenditure program consistent with its available liquidity in order to continue to meet its ongoing operating and debt service obligations.
PRINCIPAL AREAS OF ACTIVITY
Oil and Gas Operations
Throughout 2002, the Company actively developed its core mineral interests in the Maverick Basin in South Texas, and re-evaluated its economic alternatives related to its remaining properties in the Williston Basin, primarily in North Dakota. These activities included the drilling or re-entry of 41 wells in South Texas during 2002, as compared to 73 in 2001. The 73 wells in the prior year included 44 re-entered coalbed methane (CBM) wells, and 29 non-CBM wells. There were 36 non-CBM wells drilled or re-entered in 2002, a 24% increase over the prior year. The increase in Maverick Basin drilling activity reflects the Company's continued ability to generate sufficient working capital from profitable internal operations and from industry sources, allowing for expansion of its Texas-based lease acreage holdings and natural gas exploration and production activities. Marginally decreasing Maverick Basin gas production during 2002, combined with lower natural gas prices, resulted in a decrease in net cash provided by operating activities from $8.6 million in 2001 to $7.4 million in 2002. Approximately 46% of the $7.4 million in cash flow was realized during the fourth quarter of 2002, reflecting higher oil and natural gas prices.
Although crude oil and natural gas prices have increased significantly during the fourth quarter of 2002 and the first quarter of 2003, industry activity or interest has not returned to pre-1998 levels in the Williston Basin, which is the only significant interest the Company has outside the Maverick Basin. The Company's strategy remains focused on its core oil and natural gas producing wells and higher margin exploration activities in the Maverick Basin. TXCO has continued efforts to either locate a suitable joint venture partner, farmout, or sell its interest in the Williston Basin.

Maverick Basin
The Company has owned a 50% or greater leasehold interest in at least 50,000 contiguous acres in the Maverick Basin, Texas, since 1989. These holdings have increased to 408,992 acres through 2002, and to 479,761 in January 2003 when the Company leased the remaining portion of the Burr Ranch. The contiguous lease block is situated on the Chittim Anticline, a large regional structure, under which hydrocarbons have been found in as many as seven separate horizons dating back over 65 years. One of these zones is the Lower Glen Rose or Rodessa interval. It is a carbonate formation that has produced billions of cubic feet of natural gas from patch reefs within the zone. Past development in the area was halted due to the inability of previous operators to accurately predict the location of these porosity-bearing reefs. Ten years ago, utilizing new technological advances, the Company applied an innovative processing method to the 2-D seismic available in the area and confirmed a method of locating these porosity intervals.
Company geologists and geophysicists conclusively identified and mapped numerous geological formations at various depths on its leases. The mapping provided numerous drilling alternatives for future evaluation of the multiple horizons known to be productive for oil and/or gas within and around its leases in the Maverick Basin. Consistent with the capital resources available, the Company has been selectively developing the Glen Rose interval, while the shallower intervals have provided alternative completion targets for these underlying reefs. While 100% successful in locating Glen Rose patch reefs, the Company's geologists and geophysicists can not distinguish between those containing hydrocarbons and those containing water. Management continues to review technical data gained with the drilling of each well, to modify its seismic interpretation model and improve its ability to distinguish between water-filled reefs and gas-filled reefs in expanding the geologically defined a rea known as the Prickly Pear Field.
Maverick Basin 2002 Drilling Activity Summary
TXCO participated in drilling a total of 37 gross wells and 4 re-entries during 2002. Of the 41 drilled wells, 29 were successfully completed, one was a dry hole and 11 remained in progress at year end. Completed wells include 7 Comanche oil wells, 6 Chittim horizontal gas wells, 5 CBM wells, 2 Briscoe-Saner gas wells, 2 Burr lease oil wells, 1 Paloma gas well, 1 Briscoe-Saner oil well and 1 Alkek gas well, while 1 well was dry. A total of 22 drilling wells remained in progress at year-end. All 4 re-entry attempts resulted in San Miguel oil well completions. At year-end, 38 CBM gas wells continued de-watering in the ongoing CBM pilot program on the Comanche lease, while 10 San Miguel oil wells were involved in the initial stages of the Comanche San Miguel water flood project.
TXCO's approximate working interest ownership in some of its Maverick Basin projects are detailed below by formation in descending depth order:
		Working Interest Range
1	Escondido - Gas	100	%
2	Olmos - CBM Gas	100	%
3	San Miguel - Oil Waterflood	100	%
4	Georgetown - Gas	2% to 100	%
5	Glen Rose - Oil Porosity Zone	50	%
6	Glen Rose - Gas Shoal Horizontal	48% to 100	%
7	Jurassic - Gas	2% to 100	%
At year-end 2002 TXCO's net production reached 7.8 MMcf per day (gross 18.8 MMcf per day) from 83 net gas wells plus 1,000 barrels of oil per day (gross 5,800 barrels of oil per day) from 149 net oil wells. At current gas prices, this production level would not allow the Company to generate sufficient working capital to entirely fund its 2003 capital expenditure program from internally generated operating cash flow alone. The Company expects to have adequate capital available through its Credit Facility, and from new production from successful current year drilling activities. The expanding geophysical database, historical drilling results and the growing number of prospective formations targeted by the Company and its partners reaffirmed the Company's longstanding belief that it has very significant exploration and development possibilities on its growing Maverick Basin lease block.
At year-end 2002 the Company had accumulated 455 square miles of 3-D seismic data covering most of its Maverick Basin lease block. This represents an increase of 145 square miles of 3-D data over year end 2001, all of which is attributable to the eastern portion of its 95,000 acre Comanche lease plus the Pena Creek field, which is an eastern extension to the Comanche data set.
During the fourth quarter, TXCO made its initial interpretation of the 145 square mile data set. To date, interpretation of the eastern data set has yielded over 50 additional drillable locations in the highly productive Comanche Glen Rose porosity zone. The 3-D data set shows that the porosity zone overlays a layer of numerous identified Glen Rose reefs that have yet to be quantified, and that there are multiple layers of these reefs. The oil bearing porosity zone extends over a 20 square mile area of the Comanche and Pena Creek lease block. A portion of these locations has been included in the 2003 capital expenditure budget. The 3-D data set also shows that the Jurassic interval extends to this large, southern portion of TXCO's Maverick Basin acreage.

CBM Gas Pilot Program

At year end 2002 TXCO remained firmly entrenched at the forefront of Texas-based exploration for CBM gas production. The United States Geological Survey (USGS) credited TXCO with the establishment of the first CBM field in Texas, recognizing the Company's Farias #5-110 well, completed in April 2001, as the discovery well. The Texas Railroad Commission assigned the name "Sacatosa (CBM Olmos) Field" to the extensive coal deposits which extend across approximately 250,000 acres of TXCO's lease block under its Comanche and Chittim leases. Eager to encourage the continuing development of this potential new source of CBM gas, the USGS formed a cooperative research effort with TXCO to determine the gas in place, rank, quality, extent and thickness of the Olmos coals in order to fully assess the resource potential of the new CBM field. The USGS drilled two CBM wells on the Comanche lease with TXCO under their agreement, collecting extensive amounts of samples and data for further laboratory testing and evaluation. Extensive desorption and adsorption tests on these wells as well as 10 additional core tests confirmed the coals were gas-saturated. Published coal quality data confirmed the Olmos coals are classified as having the favorable ranking of high-volatile C bituminous coal, which is preferable for potential CBM production. Additional measurements indicated samples of Olmos coal from the Sacatosa (CBM Olmos) Field from varying depths contained quantities of CBM gas ranging to as much as 350 standard cubic feet per ton of coal. Further study confirmed the thickness, depth and gas content of the Olmos coals were similar to coals in other established and commercially productive CBM basins such as the Black Warrior in Alabama, the Cherokee Basin in Oklahoma and the Raton Basin in New Mexico and Colorado.

Through 2001, TXCO drilled or re-entered, and successfully completed, 34 wells on its Comanche lease. Based on the encouraging results of its exploratory core and well drilling program for CBM gas, TXCO significantly expanded its CBM activities in 2002 by advancing the project into its preliminary development stage, justifying the costs of drilling optimized wells. Optimized wells are wells drilled using air-drilling techniques and completed selectively with advanced fracture stimulation techniques designed to maximize coal formation response. Additionally, the wells are completed with larger-diameter tubulars, allowing for more rapid dewatering. During the last half of 2002, the Company drilled 5 optimized wells. After fracture stimulating 2 of the 5 wells, production from the new wells increased over 40% to 57 Mcfd with a corresponding drop in water production. While the actual CBM producing amounts are not significant in themselves, the marked increase in post-fracture v olumes is encouraging in confirming the applicability of the optimized drilling technique.

TXCO exited 2002 with 38 wells in its CBM pilot program targeting production from the multiple seams of high-volatile bituminous coal present under its leases. As of February 2003, the total CBM production rate was 200 Mcfd with 2,200 BWD. The Company believes that the next phase of this project will require 25 to 50 wells initially, during which the Company expects to establish economic production quantities. The Company is in the process of arranging project type financing, which it believes is more suitable for this project due to its cash flow profile, as well as complimenting the Company's existing capital structure. There are no CBM wells included in the 2003 CAPEX budget. The Company expects that this project will add significant reserves in the coming years.

San Miguel Oil Waterflood Projects

Comanche Lease: The large volume of water typically produced in the dewatering phase of CBM production normally represents a significant component of the operating expense in the production of CBM gas. In conjunction with its CBM dewatering projects, TXCO has engineered a synergistic water disposal cost reduction program to dispose of the CBM water into a neighboring formation. In 2001, TXCO initiated a waterflood injection pilot program targeting oil production from the San Miguel formation, located about 400 feet below the base of the Olmos coal interval. A proven San Miguel waterflood oil-field directly offsets the northern boundary of TXCO's Comanche lease. Conoco's Sacatosa (San Miguel) Field has produced over 40 million barrels of oil and 19 Bcf of gas since its discovery in 1956. Conoco began waterflooding the San Miguel sand interval in 1966 and continues to successfully operate the huge field. Initial geologic and engineering studies indicate the San Miguel sand interval under the Comanche lease is a look-a-like structure in size and structural position relative to Conoco's adjacent San Miguel waterflood field. Using its growing volume of CBM water production, TXCO added a second San Miguel waterflood pilot in 2002. Additional operating efficiencies were gained by re-entering existing vertical well bores acquired from previous operators. Company engineers selected and re-entered existing horizontal well bores in close proximity to the vertical wells in each of the pilots for recompletion as water injection wells. To date, initial response from these early stage water injection pilots has been very encouraging. The development of this project is pending expansion of the CBM project that would provide injection water.

Pena Creek: In May 2002, the Company acquired the Pena Creek oil field in Dimmit County, Texas. The purchase was effective April 1, 2002, and consisted of 94 producing oil wells, 94 injection wells and 28 shut-in wells. At year end 2002 the field was producing approximately 265 barrels of oil per day from the San Miguel formation, and contains an estimated 674,000 barrels of proved reserves, net to the Company on an SEC PV-10 basis. The 10,000 acre lease is contiguous to the Company's Comanche lease acreage block and contains potential for oil and natural gas 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 conducting engineering and geologic evaluations of the property.

During the last half of 2002, TXCO, along with its partner, Saxet Energy, completed a 3-D seismic survey covering the Pena Creek field and surrounding acreage. The Company has completed geologic interpretation of some of the 3-D seismic and the extensive historic well data acquired. These evaluations have yielded numerous drillable Glen Rose locations, as well as identified bypassed infill reserves that are not presently included in the Company's reserve base. In January 2003 the Company spudded the first of 15 infill, San Miguel wells targeting bypassed reserves. This first well was completed in February after it was successfully fracture stimulated, resulting in initial production of 60 barrels of oil per day. It is currently producing 30 barrels per day and the decline has appeared to have flattened. A second well was recently put on production at an initial rate of 120 barrels of oil per day. Both wells are still returning the load water injected into the wells during frac ture stimulation. Subsequently, TXCO has drilled four additional San Miguel wells, which are in various stages of completion. The Company's 2003 CAPEX budget includes $2.6 million for San Miguel development.

Georgetown Deviated Wells

During the fourth quarter, TXCO engineers designed a drilling and completion technique that has proved well suited for the Georgetown interval. The target intervals underlie most of TXCO's Maverick Basin lease block. The faults, which are nearly vertical, can be mapped by 3-D seismic. To increase drilling success, TXCO has employed directional drilling to enter the Georgetown at deviated angles, cutting through the targeted faults at an optimized position. During 2002, wells drilled with this method have much-improved hydrocarbon recovery, allowing an entire fault or reservoir to be drained. Previously, the Georgetown had been typically a secondary target when lower zones proved unproductive. The three wells currently produce a combined 1.5 MMcfe per day. TXCO sees this as an economically attractive way to add to production and has proposed 25 additional wells in this year's drilling program. During the first quarter of 2003, the Company spudded three deviated wells, one we ll being completed while two are drilling. The 2003 CAPEX budget includes $6.9 million for this project.

Glen Rose Porosity Zone

During 2002, the Company significantly advanced its joint venture with Saxet Energy, Ltd. (Saxet), a privately held Houston exploration company, and Tom Brown, Inc. (Nasdaq: TMBR), a large Denver based independent, covering TXCO's 100,000 acre Comanche prospect. In 2001 the Company sold a 50% working interest (Saxet 20% and Tom Brown 30%) in its rights below the base of the San Miguel formation. Also in 2001 the joint venture partners completed the acquisition of a proprietary, 100-square mile, 3-D seismic survey covering the western half of the Comanche prospect, including Saxet's Cinco Ranch lease on the western flank of the Comanche acreage. Based on early interpretation of the western-most portion of the seismic survey, a well targeting the Glen Rose formation was spudded in June 2001 on the Cinco Ranch portion of the prospect. Unfortunately the reef was water bearing. By year-end 2002, the partners completed the acquisition and processing of the entire 3-D survey. An additional 30 seismically defined Glen Rose reefs were identified and a second well was planned targeting a particularly attractive prospect on TXCO's Comanche lease, which contained evidence of multiple Glen Rose reefs stacked over a previously unidentified structure.

The first exploratory well to target a Glen Rose reef on the Company's Comanche lease since its acquisition was the Comanche 1-111 and resulted in a significant Glen Rose oil well. The well spudded in February 2002 and 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. 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. After 60 days of oil production, the well began to produce some water. Subsequently, oil production rates have been reduced. Currently, the well is producing about 200 bopd and 970 bwpd.

From March through September 2002, the partners drilled 13 additional exploratory Comanche wells utilizing 3-D seismic to identify the presence of a high porosity complex. These wells were drilled to depths ranging from 6,600 feet to 8,200 feet. Initial oil production rates ranged from zero to 1,000 bopd. Initial water production rates ranged from zero up to 250 barrels of water per day (bwpd).

Prior to experiencing significant water production encountered in later wells, Saxet, as 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.

Current Comanche lease gross daily oil production from the seven currently producing wells has declined to about 1,300 barrels of oil per day while water production has increased to about 3,500 barrels per day. Cumulative gross oil production for the Comanche lease has climbed to over 716,000 BO through mid-March 2003, while the water cut, the water to total production ratio, has increased to 72%.

At year end seven wells were not producing and remained shut in. Two of these wells failed to locate the targeted high porosity interval and were pending further evaluation for additional completion techniques. In March 2003, one of these wells was successfully sidetracked, encountering the adjacent porosity interval with an initial production rate of 60 Bopd, and no significant water production. In addition, the 3-111H is currently being drilled as a horizontal well. The four remaining wells that made mostly water await being reworked, sidetracked, drilled horizontally or conversion for use as water disposal wells. The Company has obtained a surface discharge permit that allows it to dispose of the water production at relatively low cost. Initial interpretation of Comanche lease water production surveys indicates that the majority of the water production comes from zones encountered below the main oil producing horizon.

Although 14 exploratory Saxet operated Comanche wells have now been drilled, and to date, seven producing wells are spread over a six-mile 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 one field. The partners' engineering staffs have completed extensive reviews of the porosity intervals and its oil and water production profiles. Additionally, extensive seismic has been integrated with the Comanche Halsell field production profile. Management believes that 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 un able to reflect the full reserve potential attributable to the Comanche lease oil discovery.

The Company and its partner have received the 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 data, TXCO's exploration staff believes the oil producing high porosity interval appears to extend as much as 14 miles into the eastern half of the Comanche and Pena Creek leases providing numerous additional drilling prospects for its 2003 drilling program. The Company's 2003 CAPEX budget includes a total of 26 Comanche wells, 13 exploratory and 13 developmental, at a total cost of $7.8 million to this growing project.

Horizontal Glen Rose Shoal Gas Wells

In late 2001, TXCO announced the discovery of a horizontal Glen Rose shoal gas play on a portion of its Chittim lease. Company geologists detected the presence of a large carbonate shoal (or carbonate "sand" bar) located within the Glen Rose interval. The target area provided good well control from nearby vertical producing wells which had logged or otherwise penetrated the structure while attempting completions in other oil or gas-bearing horizons. Based on their knowledge of the interval, Company engineers designed a well with a horizontal displacement of 3,750 feet in a promising and well-defined section of a large Glen Rose shoal at a vertical depth of 5,300 feet. The Chittim 1-141 gas well (48% WI) was completed in September 2001 with a calculated absolute open flow rate (AOF) of 4,690 MMcfpd with flowing pressure of 1,300 psi. The well was placed on production on October 2, 2001 at a rate of 2,042 MMcfpd with flowing pressure of 1, 360 psi.

Based on drilling results thus far, Company engineers identified 17 proved, undeveloped locations from the targeted Glen Rose shoal. At December 31, 2002 the Company's independent engineering firm estimated the proved undeveloped reserves represented by the 17 locations to be 7.9 Bcf of natural gas, net to TXCO. This represents an increase over the prior year's estimated reserves of 5.3 Bcf from 12 locations.

Plans for 2003 include drilling 17 low-risk horizontal Glen Rose shoal wells at a total cost of $6.1 million, net to TXCO. Subsequent to year end, 3 of the 17 wells have been spudded. The initial production rate on the first well is 1.3 MMcf of natural gas and 15 barrels of oil per day. The second well is waiting on a pipeline connection, and the third well is currently drilling.

Jurassic Formation

Fiscal 1999 marked the year that the Company's concerted efforts resulted in a new joint venture to explore the potential of the Jurassic formation under its growing lease block. During the 2000-2002 period, the Company, together with industry partners, made significant progress in expanding its 3-D seismic database over a much larger portion of the Maverick Basin.

Commencing in September 1999, Blue Star Oil and Gas, Ltd. (Blue Star), a Dallas based privately held exploration company, designed a 3-D seismic acquisition program over the 426 square mile area of the Maverick Basin targeted by the joint venture. The initiation of field data acquisition work continued throughout the year. The extensive data acquisition portion of the project was completed late in the third quarter of 2000. In November 2000, pursuant to its exploration joint venture with the Company, Blue Star confirmed that it had completed the seismic data acquisition phase and began processing the seismic data on the entire 426 square miles of 3-D seismic data, including 37,000 acres of TXCO leases and Blue Star's 190,000 acre Chittim lease. By year-end 2000, Blue Star had shared with TXCO's Jurassic project management team the preliminary results from the data migration, processing and initial interpretation of the seismic study. In March 2001 Blue Star contacted TXCO and announced Blue Star's decision to apply additional, enhanced 3-D seismic processing techniques on their entire Jurassic seismic database. Blue Star further advised that the prospective seismic processing would likely take several months to finalize and could cost an additional $1 million. By year end 2001, Blue Star had completed its enhanced 3-D seismic processing, had provided TXCO with a digitized seismic data set covering 164 square miles of the Maverick Basin and a proposed drilling location on the Paloma lease.

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 80 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 confirmed the presence and ranking of numerous drilling locations on TXCO's acreage.

Through year-end 2002, Blue Star continued its efforts to obtain proposals from qualified drilling contractors, conducted field inspections and 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.

On March 27, 2003, Blue Star spudded the Taylor 132-1, on TXCO's Paloma lease. The well, targeting natural gas, is permitted to a depth of 18,500' and is expected to take from 90 to 120 days to reach total depth. A second well on the Paloma lease, the McKinney 106-1, has been staked and permitted to a depth of 20,200'. Under the terms of the agreement, TXCO (62.5%) and its partners (37.5%) will share an 18.75% overriding royalty interest in any production associated with the well, reverting to a shared 25% working interest upon payout. In exchange for the carried interest in the Taylor well, Blue Star will earn a 25% working interest in the deep rights below the Silgo formation in the 50,000 acres under the Paloma and Kincaid leases. Blue Star retains the right to carry TXCO for an identical interest in a second well to earn an additional 25% under the two leases.

Williston Basin

Through 2002, the Company continued to re-evaluate all of its Williston Basin lease obligations, making lease extension payments on a selective basis, emphasizing those leases with particular geologic attributes or with adequate remaining primary lease terms. Consistent with Management's strategy to focus exploration efforts and resources on the development of its core producing area in South Texas, TXCO has maintained marketing efforts offering its remaining Williston Basin holdings to other exploration companies with a focus on this area.

For the year ended December 31, 2002, the Company's interests produced an average of 68 net barrels of crude oil per day from 5.2 net wells. At December 31, 2002 TXCO retained approximately 87,000 net acres of its original position.

PRINCIPAL PRODUCTS AND COMPETITION

The Company's principal products are natural gas and crude oil. The production and marketing of oil and gas are affected by a number of factors that are beyond the Company's control, the effects of which cannot be accurately predicted. These factors include crude oil imports, actions by foreign oil-producing nations, the availability of adequate pipeline and other transportation facilities, the marketing of competitive fuels and other matters affecting the availability of a ready market, such as fluctuating supply and demand. During 2002 the Company sold all of its oil and gas under short-term contracts that can be terminated with 30 days notice, or less. None of the Company's production was sold under long-term contracts with specific purchasers. Consequently, the Company was able to market its oil and gas production to the highest bidder each month. As discussed in Item 7, Contractual Obligations and Contin gent Liabilities and Commitments, in January 2003 the Company entered into a fixed price contract for approximately 30% of the its net gas production rate at year-end 2002. As a forward sale of part of its physical production, the Company was able to lock-in relatively high, by historical standards, prices without being subject to risks associated with derivative instruments.

The Company operates and directs the drilling of oil and gas wells and participates in non-operated wells. As operator, it contracts service companies, such as drilling contractors, cementing contractors, etc., for specific tasks. In other wells, the Company only participates as an overriding royalty interest owner.

During 2002, four purchasers of the Company's oil and gas production accounted for 42%, 25%, 18% and 11% of total oil and gas sales. In the event any of these major customers declined to purchase future production, the Company believes that alternative purchasers could be found for such production at comparable prices.

The oil and gas industry is highly competitive in the search for and development of oil and gas reserves. The Company competes with a substantial number of major integrated oil companies and other companies having materially greater financial resources and manpower than the Company. These competitors, having greater financial resources than the Company, have a greater ability to bear the economic risks inherent in all phases of this industry. In addition, unlike the Company, many competitors produce large volumes of crude oil that may be used in connection with their operations. These companies also possess substantially larger technical staffs, which puts the Company at a significant competitive disadvantage compared to others in the industry.

EMPLOYEES

As of December 31, 2002, the Company employed 35 full-time employees including management. The Company believes its relations with its employees are good. None of the Company's employees are covered by union contracts.

GENERAL REGULATIONS

The extraction, production, transportation, and sale of oil, gas, and minerals are regulated by both state and federal authorities. The executive and legislative branches of government at both the state and federal levels have periodically proposed and considered proposals for establishment of controls on alternative fuels, energy conservation, environmental protection, taxation of crude oil imports, limitation of crude oil imports, as well as various other related programs. If any proposals relating to the above subjects were to be enacted, the Company is unable to predict what effect, if any, implementation of such proposals would have upon the Company's operations. A listing of the more significant current state and federal statutory authority for regulation of the Company's current operations and business are provided herein below.

Federal Regulatory Controls

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938 (the "NGA"), the Natural Gas Policy Act of 1978 (the "NGPA") and the regulations promulgated thereunder by the Federal Energy Regulatory Commission ("FERC"). Maximum selling prices of certain categories of natural gas sold in "first sales," whether sold in interstate or intrastate commerce, were regulated pursuant to the NGPA. On July 26, 1989, the Natural Gas Wellhead Decontrol Act (the "Decontrol Act") was enacted, which removed, as of January 1, 1993, all remaining federal price controls from natural gas sold in "first sales." The FERC's jurisdiction over natural gas transportation was unaffected by the Decontrol Act.

Commencing in April 1992, the FERC issued Order Nos. 636, 636-A and 636-B (collectively "Order No. 636"), which required interstate pipelines to provide transportation, separate or "unbundled," from the pipelines' sales of gas. Although Order No. 636 did not directly regulate the Company's activities, it fostered increased competition within all phases of the natural gas industry.

In December 1992, the FERC issued Order No. 547, governing the issuance of blanket marketer sales certificates to all natural gas sellers other than interstate pipelines. The order applies to non-first sales that remain subject to the FERC's NGA jurisdiction. The FERC Order No. 547, in tandem with Order No. 636, has fostered a competitive market for natural gas by giving natural gas purchasers access to multiple supply sources at market-driven prices. Order No. 547 has increased competition in markets in which the Company's natural gas is sold. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach pursued by the FERC and Congress will continue.

State Regulatory Controls

In each state where the Company conducts or contemplates conducting oil and gas activities, such activities are subject to various state regulations. In general, the regulations relate to the extraction, production, transportation and sale of oil and natural gas, the issuance of drilling permits, the methods of developing new production, the spacing and operation of wells, the conservation of oil and natural gas reservoirs and other similar aspects of oil and gas operations. In particular, the State of Texas (where the Company has conducted the majority of its oil and gas operations to date) regulates the rate of daily production allowable from both oil and gas wells on a market demand or conservation basis. At the present time, no significant portion of the Company's production has been curtailed due to reduced allowables. The Company knows of no newly proposed regulations, which will significantly curtail its production.

Environmental Regulation

The Company's extraction, production and drilling operations are subject to environmental protection regulations established by federal, state, and local agencies. To the best of its knowledge, the Company believes that it is in compliance with the applicable environmental regulations established by the agencies with jurisdiction over its operations. The Company is acutely aware that the applicable environmental regulations currently in effect could have a material detrimental effect upon its earnings, capital expenditures, or prospects for profitability. The Company's competitors are subject to the same regulations and therefore, the existence of such regulations does not appear to have any material effect upon the Company's position with respect to its competitors. The Texas Legislature has mandated a regulatory program for the management of hazardous wastes generated during crude oil and natural gas exploration and production, gas processing, oil and gas waste reclamati on and transportation operations. The disposal of these wastes, as governed by the Railroad Commission of Texas, is becoming an increasing burden on the industry. The Company's leases in Montana, North Dakota and South Dakota are subject to similar environmental regulations including archeological and botanical surveys as most of the leases are on federal and state lands.

Federal and State Tax Considerations

Revenues from oil and gas production are subject to taxation by the state in which the production occurred. In Texas, the state receives a severance tax of 4.6% for oil production and 7.5% for gas production. North Dakota production taxes typically range from 9.0% to 11.5% while Montana's taxes range up to 17.2%. These high percentage state taxes can have a significant impact upon the economic viability of marginal wells that the Company may produce and require plugging of wells sooner than would be necessary in a less arduous taxing environment. For Federal Income Tax purposes, the Company has net operating loss carry forwards of $13,600,000 which are scheduled to expire from 2008 to 2019. During 2000, the Company recognized a deferred federal income tax benefit of $5,231,000 reflecting the cumulative estimated future tax benefit of a portion of its net operating loss carry forwards from past losses. For 2001and 2002, this benefit was unchanged. See Notes to the Audited Consolidated Financial Statements.

CERTAIN BUSINESS RISKS
Reliance on Estimates of Proved Reserves and Future Net Revenues: Depletion of Reserves
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and the timing of development expenditures, including many factors beyond the control of the Company. The reserve data set forth in this report represent only estimates. In addition, the estimates of future net revenues from proved reserves of the Company and the present value thereof are based on certain assumptions about future production levels, prices and costs that may not prove to be correct over time. In particular, estimates of crude oil and natural gas reserves, future net revenue from proved reserves and the present value of proved reserves for the crude oil and natural gas properties described in this report are based on the assumption that future crude oil and natural gas prices remain constant based on prices in effect at December 31, 2002. The following table details the prices used for these estimates for the respective dates pre sented:
	12/31/02	12/31/01	12/31/00	12/31/99
Gas price per Mcf	$  4.90	$  2.72	$11.04	$  1.99
Oil price per Bbl	$28.71	$17.31	$25.67	$25.39
Any significant variance in these assumptions could materially affect the estimated quantity and value of reserves set forth herein. See "Management's Discussion and Analysis of Financial Condition and Results of Operation - Liquidity and Capital Resources" and "Properties".
Depletion of Reserves
The rate of production from crude oil and natural gas properties declines as reserves are depleted. Except to the extent the Company acquires additional properties containing proved reserves, conducts successful exploration and development activities or through engineering studies identifies additional behind-pipe zones or secondary recovery reserves, the proven reserves of the Company will decline as reserves are produced. Future crude oil and natural gas production is highly dependent upon the Company's level of success in acquiring or finding additional reserves.
Title to Properties
As is customary in the crude oil and natural gas industry, the Company performs a preliminary title investigation before acquiring undeveloped properties that generally consists of obtaining a title report from outside counsel or due diligence reviews by independent landmen. The Company believes that it has satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. A title opinion from counsel is obtained before the commencement of any drilling operations on such properties. The Company's properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, none of which the Company believes materially interferes with the use of, or affect the value of, such properties.
Net Income or Loss from Operations
In its recent history, the Company has recorded both net income and net losses. For the year ended December 31, 2002 the Company recorded a net loss of $310,970; for the year ended December 31, 2001 the Company recorded a net loss of $50,283; for the year ended December 31, 2000, the Company recorded net income of $6.76 million. There can be no assurance that the Company will not experience operating losses in the future.
Operating Hazards; Uninsured Risks
The nature of the crude oil and natural gas exploration and production business involves certain operating hazards such as crude oil and natural gas well blowouts, explosions, formations with abnormal pressures, cratering and crude oil spills and fires. Any of these could result in damage to or destruction of crude oil and natural gas wells, destruction of producing facilities, damage to life or property, suspension of operations, environmental damage and possible liability to the Company. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of such risks and some, but not all, of such losses. The occurrence of such an event not fully covered by insurance could have a material adverse effect on the financial condition and results of operations of the Company.
Substantial Capital Requirements
The Company makes, and will continue to make, substantial capital expenditures for the acquisition, exploitation, development, exploration, and production of crude oil and natural gas reserves. Historically, the Company has financed these expenditures primarily from debt and equity offerings, supplemented by available cash flow from operations and the sale of interests in its properties. The Company is hopeful that it will continue to be able to obtain sufficient capital to finance planned capital expenditures. However, if revenues decrease because of lower crude oil and natural gas prices, operating difficulties or declines in reserves, the Company may have limited ability to finance planned capital expenditures in the future. Therefore, there can be no assurance that additional debt or equity financing or cash generated by operations will be available to meet its capital requirements.
Certain Corporate Defensive Matters
The Company's Articles of Incorporation, Bylaws and Delaware law contain provisions that may have the effect, together or separately, of delaying, deferring, or preventing a change in control of the Company. In particular, the Company may issue up to 10 million shares of preferred stock with rights and privileges that could be senior to its outstanding common stock, without the consent of the holders of the common stock. The Company's Certificate of Incorporation and Bylaws provide, among other things, for advance notice of stockholder's proposals and director nominations, and provide for non-cumulative voting in the election of Directors. On June 29, 2000, the Company's Board of Directors adopted a Stockholder Rights Plan (Rights Plan) under which uncertificated preferred stock purchase rights were distributed as a stock dividend to its common shareholders at a rate of one right for each share of common stock held of record as of July 19, 2000. Unless previously redeemed b y the Company, the rights will expire on June 29, 2010. The Rights Plan is designed to enhance the Board's ability to prevent an acquirer from depriving stockholders of the long-term value of their investment and to protect shareholders against attempts to acquire the Company by means of unfair or abusive takeover tactics that have been prevalent in many unsolicited takeover attempts. On May 25, 2001, a majority of the Company's shareholders approved an amendment to its Certificate of Incorporation providing for the establishment of a classified board of directors. The classified board provision established three classes of directors, with each class to be elected for a three-year term on a staggered basis. The classified board provision is intended to promote management continuity and stability and to afford time and flexibility in responding to unsolicited tender offers.
Available Information
The Company files annual, quarterly and current reports, proxy statements and other information with the Commission. These filings are available free of charge through our internet website at www.txco.com as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Commission.
ITEM 2. PROPERTIES
PHYSICAL PROPERTIES
The Company's administrative offices are located at 500 North Loop 1604 East, Suite 250, San Antonio, Texas. These offices, consisting of approximately 13,500 square feet, are leased through August 2007 at $21,300 per month with annual escalations each February 1.
All the Company's oil and gas properties, reserves, and activities are located onshore in the continental United States. There are no quantities of oil or gas subject to long-term supply or similar agreements with foreign government authorities.

Proved Reserves, Future Net Revenue and
Present Value of Estimated Future Net Revenues
The following unaudited information as of December 31, 2002, relates to the Company's estimated proved oil and gas reserves, estimated future net revenues attributable to such reserves and the present value of such future net revenues using a 10% discount factor (PV-10 Value), as estimated by Netherland Sewell & Associates, Inc., a Dallas, Texas engineering firm. Estimates of proved developed oil and gas reserves attributable to the Company's interest at December 31, 2002, 2001 and 2000 are set forth in Notes to the Audited Financial Statements included in this Annual Report on Form 10-K. The PV-10 Value was prepared in accordance with SEC requirements using constant prices and expenses as of the calculation date, discounted at 10% per year on a pretax basis, and is not intended to represent the current market value of the estimated oil and natural gas reserves owned by the Company.
Years Ending December 31,			PV-10 Value of Estimated Future Net Revenues
2003				$10,321,200
2004				14,120,800
2005				6,455,900
2006				3,828,700
2007				2,606,700
Thereafter				8,048,500
Total				$45,381,800
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas liquids and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. No reserve estimates have been filed with or included in reports to any federal or foreign government authority or agency, other than the Securities and Exchange Commission, since the Company's latest Form 10-K filing.
TXCO's continued drill bit success in 2002 added over 8.7 Bcfe of proved reserves and, combined with the acquisition of the Pena Creek field (4.04 Bcfe) and revisions of previous estimates (2.44 Bcfe), established a record all sources reserve replacement of 347%. Reserve additions far exceeded the Company's 2002 production levels for the second year in a row resulting in an 83% increase in year-end proved reserves over the prior year. 2001 reserves increased 126% over 2000. The following table shows TXCO's year-end reserves for the past three years.
SEC PV-10 Reserves at December 31,
	2002				2001		2000
	Volumes	Share *			Volumes	Share *	Volumes	Share *
Natural gas (Bcf)	14.7	63%			11.0	87%	4.5	80%
Oil (MMBbls)	1.5	37%			.3	13%	.2	20%
Natural gas equivalent (Bcfe) *	23.5	100%			12.7	100%	5.6	100%
*  For percent change and natural gas equivalent calculations, one barrel of oil is approximately equivalent to six Mcf    of natural gas.

Production
The following table summarizes the Company's net oil and gas production, average sales prices, and average production costs per unit of production for the periods indicated. With respect to newly drilled wells, there can be no assurance that current production levels can be sustained. Depending upon reservoir characteristics, such levels of production could decline significantly.
				Years Ended December 31,
				2002			2001			2000
Oil:
Production (Bbl)				314,000			50,000			60,000
Average sales price per Barrel				$24.56			$23.55			$27.85
Gas:
Production (Mcf)				2,487,000			2,673,000			2,965,000
Average price per Mcf				$3.35			$4.56			$4.10
Average cost of production per     equivalent Mcf (1)				$1.19			$1.13			$0.65
(1)  Oil and gas were combined by converting oil to gas Mcf equivalent on the basis of 1 barrel of oil = 6 Mcf of gas. Production costs include direct lease operations and production taxes.
Producing Properties - Wells and Acreage
The following table sets forth the Company's producing wells and developed acreage assignable to such wells for the last three fiscal years:
			Productive Wells
	Developed      Acreage		Oil			Gas			Total
Year Ended	Gross	Net	Gross		Net	Gross		Net	Gross		Net
12/31/02	25,350	14,526	168		148.66	112		83.45	280		232.11
12/31/01	19,870	11,140	53		39.12	96		72.47	149		111.59
12/31/00	15,920	8,257	28		15.63	47		25.49	75		41.12
Productive wells consist of producing wells and wells capable of production, including shut-in wells and wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.
A "gross well" or "gross acre" is a well or acre in which a working interest is held. The number of gross wells or gross acres is the total number of wells or acres in which working interests are owned. A "net well" or "net acre" is deemed to exist when the sum of fractional ownership interest in gross wells or gross acres equals one. The number of net wells or net acres is the sum of fractional working interests owned in gross wells or gross acres expressed as whole numbers and fractions thereof.

Undeveloped Acreage
As of December 31, 2002, the Company owned, by lease or in fee, the following undeveloped acres, all of which are located in the Continental United States, as follows:
											Estimated
											2003
United States			Gross Acres					Net Acres			Delay Rentals
Texas					408,992			349,579			$		267,410
North Dakota					88,207			84,244					171,836
South Dakota					2,637			2,130					4,114
Montana					960			960					3,840
Total					500,796			436,913			$		447,200
Six large Texas leases totaling approximately 83,460 gross acres contain varying requirements to drill a well every 90 to 180 days to keep the respective lease in effect. The Company is presently drilling under the terms of the leases and expects to keep the leases in force by continuous development during the year. In January 2003 TXCO acquired a 70,700-acre lease in Texas, increasing total gross Texas acres to approximately 480,000.
Gathering System
During 2002 the Company acquired 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 MMcf/d of which one-third 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.
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 last half of 2002, the Partnership constructed a 3 mile, $300,000 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.
Also during the fourth quarter 2002, 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.
Drilling Activity
During calendar 2002, the Company drilled or re-entered 41 wells compared to 73 in 2001. The 73 wells in the prior year include 44, mostly re-entered, coalbed methane (CBM) wells, and 29 non-CBM wells. There were 36 non-CBM wells drilled or re-entered in 2002, a 24% increase over the prior year. In addition, current year activity included ongoing drilling operations on 12 wells that were in progress at the end of calendar year 2001. The following table sets forth the Company's drilling activity for the last three years:
Drilling Wells
	2002						2001							2000
	Gross			Net			Gross			Net				Gross		Net
	Prod.	Dry		Prod.		Dry	Prod.		Dry	Prod.		Dry		Prod.	Dry	Prod.	Dry
Oil Wells	10	0		5.53		0	5		1	3.70		0.63		2	1	.78	0.50
Gas Wells	15	1		11.48		.63	18		5	15.53		4.37		6	6	3.76	2.13
Total Wells	25	1		17.01		.63	23		6	19.23		5.00		8	7	4.54	2.63

The Exploration Company participated in the drilling of 37 wells (23.24 net) during 2002. Of these, 21 wells (16.18 net) were operated by the Company. At December 31, 2002, 3 (2.08 net) of these wells remained in progress.
Not reflected in the respective 2002 columns are 11 wells (10.63 net) spud in the prior year. All 11 wells remained in progress at December 31, 2002. Of the 11 wells, 9 are CBM project wells and completion of these wells is pending development of the coal field. These wells were drilled beyond the limits of existing gathering facilities to test the extent of the field. The remaining two wells are being considered for completion in the Georgetown.
Included in the respective year 2001 columns are the results of the drilling activity involving 16 wells spud in the prior year and in progress at the beginning of 2001. These wells resulted in 9 producing (8.17 net) gas wells and 3 producing (2.02 net) oil wells. In addition, 2 wells resulted in 1 dry (0.88 net) gas well and 1 dry (1.0 net) oil well while 2 wells (1.63 net) remained in progress at December 31, 2001.
Included in the respective year 2000 columns were 2 producing (1.63 net) gas wells and 1 (0.25 net) dry well drilled during the four month transition period ended December 31, 1999, plus 1 producing (0.5 net) gas well spud in the prior fiscal year. In addition to the wells detailed in the table above, the Company had an interest in 14 wells (11.81 net) in progress at December 31, 2000 from year 2000 drilling and 1 well (0.88 net) from the prior fiscal year.
Re-entry Wells
	2002							2001								2000
	Gross			Net				Gross				Net				Gross				Net
	Prod.		Dry	Prod.		Dry		Prod.		Dry		Prod.		Dry		Prod.		Dry		Prod.		Dry
Oil Wells	4		0	4		0		4		1		4		1		1		0		0.84		0.00
Gas Wells	1		0	1		0		36		7		36		7		0		0		0.00		0.00
Total Wells	5		0	5		0		40		8		40		8		1		0		0.84		0.00
During 2002 the Company re-entered 4 (4 net) existing wells, of which all are currently producing. Included in 2002 re-entry activity is 1 CBM gas well that was in progress at year end 2001. During 2001 the Company re-entered 48 (48.0 net) existing wells, of which 40 (40 net) wells are currently producing, while 1 well (1.0 net) remained in progress at December 31, 2001, and, as mentioned above, was completed in 2002. During 2000 the Company re-entered 2 (1.84 net) existing wells, of which one well is currently producing, while the other well was in progress at December 31, 2000, and was dry in 2001.
Total Drilling and Re-entry Wells
	2002								2001								2000
	Gross				Net				Gross				Net				Gross				Net
	Prod.	Dry			Prod.		Dry		Prod.		Dry		Prod.		Dry		Prod.		Dry		Prod.		Dry
Oil Wells	14	0			9.53		0		9		2		7.70		1.63		3		1		1.62		0.50
Gas Wells	16	1			12.48		.63		54		12		51.53		11.37		6		6		3.76		2.13
Total Wells	30	1			22.01		.63		63		14		59.23		13.00		9		7		5.38		2.63
The Company began 2002 with 12 wells (11.64 net) in progress from 2001. During 2002, the Company initiated 41 (27.24 net) new drilling / re-entry wells. These wells resulted in 16 gas (12.48 net) wells, 14 oil (9.53 net) wells, 1 dry (.63 net) wells and 22 wells (16.23 net) were in progress at December 31, 2002.

Maverick Basin
Throughout the 1990's, the Company pursued a strategy to expand its core Maverick Basin producing properties. In addition to using internally generated working capital for exploration and development activities, TXCO accelerated its growth, where possible, by entering into strategic joint ventures or operating agreements targeted at leveraging the Company's increased leasehold values, recognized technical abilities and exploration success in its core area of interest. Throughout its history TXCO has entered into joint venture or joint operating agreements, under which the Company teamed with qualified industry partners who contributed investment capital, mineral leases, 3-D seismic data and/or offered the Company a carried interest in mineral leases, 3-D seismic acquisition programs and wells to be drilled. These contributions were made in exchange for TXCO's geophysical, geological and operational expertise, and in certain instances, in exchange for an interest in a portio n of the Company's non-producing oil and gas lease interests.
Additional information regarding the Company's properties is contained in Item 1 of this Form 10-K and in the Consolidated Financial Statements and Notes thereto under Item 8 of this Form 10-K.
ITEM 3. LEGAL PROCEEDINGS
The Company is not involved in any matters of litigation incidental to its business of a significant nature.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of the security holders of the Company during the 4th quarter of fiscal year 2002.
PART II
ITEM 5.  MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The following is a range of high and low bid prices for the Company's common stock for each quarter presented based upon bid prices reported by the National Association of Securities Dealers Quotations system under the call symbol "TXCO":
	Range of Bid Prices
Quarter Ended:	High		Low
December 2002	$	5.23	$	2.73
September 2002		6.89		4.62
June 2002		8.74		4.05
March 2002		4.61		1.90
December 2001		2.74		1.95
September 2001		2.97		1.88
June 2001		4.03		1.90
March 2001		4.25		2.63
As of March 14, 2003, there were approximately 1,138 holders of record of the Company's Common Stock. The transfer agent for the Company is the American Stock Transfer & Trust Company, 59 Maiden Lane, New York, New York 10038. The Company has not paid any cash dividends on its Common Stock in past years and does not expect to do so in the foreseeable future.

ITEM 6. SELECTED FINANCIAL DATA
The following selected financial information is derived from and qualified in its entirety by the Audited Consolidated Financial Statements of the Company and the Notes thereto as set forth in this Annual Report on Form 10-K commencing on page F-1.
							4 Months
							Ended
	Year Ended December 31						December 31		Year Ended August 31
	2002		2001		2000		1999		1999		1998
Operating revenues	$	18,958,364	$	13,758,920	$	14,361,357	$	3,768,667	$	7,235,391	$	2,862,416
Income (loss) from   continuing operations		(310,970	)	(50,283	)	6,761,935		1,188,649		931,545		(8,417,218	)
Basic income (loss) per   common share from   continuing operations		(0.016	)	(0.003	)	0.39		0.07		0.06		(0.55	)
Total Assets		53,036,319		29,843,432		29,205,641		18,647,878		17,553,815		16,264,632
Long-term obligations		7,217,231		862,177		1,195,191		1,679,936		3,094,809		4,823,927
Stockholders' Equity	$	36,970,374	$	23,056,696	$	23,321,736	$	13,208,929	$	12,020,280	$	10,595,141
Weighted averages shares   outstanding - Basic		19,080,847		17,441,242		17,242,326		15,938,516		15,668,721		15,328,292
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Forward-looking Statements: Statements in this Form 10-K 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, are forwarding-looking statements and are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Investors are cautioned that all forward-looking statements involve risks and uncertainty, including without limitation, the costs of exploring and developing new oil and natural gas reserves, the price for which such reserves can be sold, environmental concerns effecting the drilling of oil and natural gas wells, as well as general market conditions, competition and pricing. Please refer to all of TXCO's Securities and Exchange Commission filings, copies of which are available from the Company without charge, for additional information.
GENERAL
The following is a discussion of the Company's financial condition and results of operations. This discussion should be read in conjunction with the Financial Statements of the Company and Notes thereto.
The Exploration Company is an independent oil and gas enterprise with interests primarily in the Maverick Basin in Southwest Texas. Its long-term business strategy is to acquire undeveloped mineral interests and internally develop a multi-year drilling inventory through the use of advanced technologies, such as 3-D seismic and horizontal drilling. The Company accounts for its oil and gas operations under the successful efforts method of accounting and trades its common stock on the Nasdaq Stock Market(sm) under the symbol "TXCO." The Company currently has six drilling rigs under operation on its extensive 480,000 acreage block in the Maverick Basin, targeting at least seven separate formations for the production of oil and natural gas.

CAPITAL RESOURCES AND LIQUIDITY
Year Ended December 31, 2002
During 2002 beginning cash reserves of $2 million were increased by net cash provided from operating activities of $7.4 million resulting in a total of $9.4 million in internally generated working capital for use in funding ongoing expansion, development and exploration of the Company's oil and gas properties. Additionally, cash of $21 million from other sources listed below resulted in total cash of $31.3 million available for use in meeting the Company's ongoing operational and development needs. Included in the $21 million cash received from other sources, is approximately $14.1 million from 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 amount raised, net of offering costs of $0.9 million, was 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.
2002 Cash Available to the Company
Beginning cash reserves, January 1, 2002					$	2,019,164
Net cash provided by operating activities						7,389,430
Sub-total						9,408,594
Private placement of 2,499,667 shares of      common stock	$		14,051,893
Borrowings on the new Credit Facility			5,800,000
Other debt obligations			1,639,915
Exercise of outstanding options for the Company's      common stock			172,755
Proceeds from sale of oil and gas properties			200,000
Total other sources of cash					$	21,864,563
2002 Cash Available					$	31,273,157
The Company applied $27.4 million of its working capital to fund the expansion and ongoing development of its oil and gas properties. Included were drilling, completion, seismic and acquisition costs totaling $17.4 million, primarily targeting TXCO's core area, the Maverick Basin. This represented expenditures for the drilling, completion and re-entry of 41 oil and gas wells and the acquisition of Maverick Basin mineral leases. In addition, the Company acquired a 69-mile pipeline system. The pipeline system has and continues to gather most of the Company's natural gas in the Maverick Basin. The following table summarizes uses of cash during 2002.
2002 Uses of Cash
Drilling and completion costs, 3-D seismic, and      leasehold acquisitions		$		17,410,942
Natural gas pipeline and facilities				5,767,291
Pena Creek acquisition and improvements				3,681,902
Well service equipment				183,145
Upgrade information system and related   infrastructure				337,967
Other				39,036
Sub-total				27,420,283
Net distributions to minority interests				434,325
Debt principal payments				1,084,861
		$		28,939,469
The Company made timely payments of $1,084,861 on its long-term debt obligations during 2002, while payments on interest totaled $273,213.

Acquisition - Pipelines: 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.

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 3 mile, $300,000 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.

During the fourth quarter 2002, 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.

Acquisition - Pena Creek: 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. The acquisition consisted of 94 producing oil wells, 94 injection wells and 28 shut-in wells.

As a result of these activities, the Company ended the year 2002 with a negative working capital of $1,884,507 and a current ratio of .81 to 1. This year-end position compares to negative working capital of $1,554,454 and a current ratio of .73 to 1 at December 31, 2001. The Company ended 2002 with an unused borrowing base of $6.2 million. The Company's ending working capital for years ended 2002 and 2001 was significantly impacted by the high level of drilling activity during the two year period.

Bank Credit Facility: On March 4, 2002 the Company entered into a $25 million oil and gas reserve based Revolving Credit Facility with Hibernia National Bank providing a credit line with an initial borrowing base set at $5 million. The borrowing base was subsequently increased to $13 million as of September 30, 2002, with quarterly reductions of $1 million. At December 31, 2002, the borrowing base was $12 million with an outstanding balance of $5.8 million, resulting in an unused borrowing base of $6.2 million. The unused borrowing base at March 17, 2003, was $3.5 million. Interest is payable monthly, with principal due at maturity in March 2005. Uses of proceeds are for the acquisition and development of oil and gas properties and general corporate working capital purposes. The Facility provides the lender with semiannual scheduled redeterminations, at mid-year and each subsequent anniversary date, while providing for two unscheduled redeterminations per year, at the Company's discretion. Borrowings under the Facility are secured by a first priority mortgage covering the Company's working and other interests in the majority of its oil and gas leases. The interest rate under the facility will initially be based on the Wall Street Journal Prime Rate plus applicable margin. A Eurodollar Rate plus applicable margin may be utilized at the election of the Company. The interest rate at December 31, 2002, was 4.25%, and the rate was unchanged at March 10, 2003. The Facility also provides the lender with a commitment fee equal to 0.5%, per annum on the unused borrowing base. The Facility contains certain financial covenants and other negative restrictions common for a financing of this type. Any unused borrowing base is a net increase to working capital for purposes of the Current Ratio covenant.

Management believes that the Facility, along with the Company's positive cash flow from existing production and anticipated production increases from new drilling, will provide adequate capital to fund ongoing operating cash requirements for 2003 and to complete its scheduled exploration and development goals as targeted by its 2003 capital expenditure program.

However, there is no assurance that the Company will re-establish profitability in 2003 nor that expected increases in new oil and natural gas production will be realized, nor that sufficient debt capital will remain available from its new borrowing Facility. Should these concerns be realized or should commodity prices weaken significantly, the Company's financial condition could be adversely affected and could cause the Company to defer planned capital expenditures consistent with its available capital resources.

Year Ended December 31, 2001
During 2001 beginning cash reserves were increased by net cash provided from operating activities resulting in a total of $14.5 million in internally generated working capital, and $2.2 million from other sources, listed below, for a total of $16.7 million in cash available for use in funding the ongoing expansion, development and exploration of the Company's oil and gas properties.
2001 Cash Available to the Company
Beginning cash reserves, January 1, 2001				$	5,898,015
Net cash provided by operating activities					8,564,022
Sub-total					14,462,037
Other debt obligations	$	153,231
Exercise of outstanding options for the    Company's common stock		31,250
Sale of oil and gas properties		2,005,133
Total other sources of cash					2,189,614
2001 Cash Available				$	16,651,651
The Company applied $13.8 million of its working capital to fund the expansion and ongoing development of its oil and gas properties. Included were drilling, completions, seismic and leasehold acquisition costs totaling $13.4 million primarily targeting TXCO's core area, the Maverick Basin. This represented expenditures for the drilling, completion and re-entry of 73 oil and gas wells and new Maverick Basin mineral lease purchases of approximately 158,000 acres. Also included were expenditures for the expansion of the Company's Paloma lease gas gathering facilities and for vehicles and other equipment used in the field.
2001 Uses of Cash
Drilling and completion costs, 3-D seismic, and    leasehold acquisitions	$		13,360,347
Expansion of natural gas gathering facilities			94,271
Other property and equipment			220,709
Other			116,007
Sub-total			13,791,334
Purchase of 99,800 shares of treasury stock			246,007
Debt principal payments			486,244
Net distributions to minority interests			108,902
	$		14,632,487
The Company made timely payments of $486,244 on its long-term debt obligations during 2001, while payments on interest totaled $128,373. Additionally, the Company purchased 99,800 shares of its common stock for its treasury at a cost of $246,007 under its common share buyback program approved by the Board of Directors on June 27, 2001.
As a result of these activities, the Company ended the year 2001 with a negative working capital of $1,554,454 and a current ratio of .73 to 1. This year-end position compares to positive working capital of $6,349,625 and a current ratio of 2.36 to 1 at December 31, 2000. The decrease in ending working capital was attributable to the increased levels of development activities through the third quarter coupled with the sharp decline in realized gas prices during the second half of 2001.

2003 Capital Requirements

The major components of the Company's plans, and the requirements for additional capital for 2003, include the following:

Maverick Basin Activity:

Initial capital expenditures planned for 2003 total over $27.4 million and target the Company's Maverick Basin core properties. The primary component of these expenditures is $24.9 million for drilling wells, while over $2.5 million is earmarked for seismic and leasehold and gas gathering system enhancements and other infrastructure expansion activities. The Company's budgeted capital expenditures are intended to be flexible. Overall budgeted capital outlays are subject to substantial increase should the Company's key exploration targets, development activities or special situations or opportunities warrant higher capital outlays than originally planned.

The Company initially plans to drill 93 wells, including 26 Glen Rose porosity zone oil wells, 17 Glen Rose shoal horizontal gas wells, 25 Georgetown gas wells, 15 San Miguel waterflood oil wells in the Pena Creek field, and 10 shallow Escondido gas wells. Some of these wells will be operated by other companies and, therefore, TXCO does not have direct control over when they will be drilled or what final costs will actually be incurred. The following table details typical gross well costs for 2003 budgeted wells.

Typical Gross Well Costs

Dry Hole

Completed

Glen Rose oil porosity zone well

$500,000

$750,000

Glen Rose shoal gas well

500,000

650,000

Georgetown gas well

150,000

275,000

San Miguel waterflood oil well

100,000

175,000

Escondido gas well

100,000

150,000

Williston Basin Activity:

The Company plans to maintain its existing producing properties and the payment of delay rentals and lease extensions on selected undeveloped leases, with scheduled 2003 delay rentals of $180,000 and will continue in its efforts to offer remaining acreage, seismic data, and identified prospects to other industry operators.

Summary of Capital Resources and Liquidity

The Company expects it will have a continuing ability to further increase its borrowing base commensurate with the expected additional growth of its proved oil and gas reserves throughout the base term of the new Facility. Management remains confident that financial resources will remain available, enabling the Company to continue the rapid development of its oil and gas properties and continue to meet its normal operational and debt service obligations on a timely basis.

While management is confident it has identified sufficient sources of working capital to carry out its current exploration and development plans on its Texas leaseholds, as well as to meet its obligations in the ordinary course of business through the end of the coming year, there is no assurance that energy prices or other market factors will continue to improve. Should prices weaken, or should expected new oil and gas production levels from planned 2003 drilling not be attained, the resulting reduction in projected revenues would cause the Company to re-evaluate its expected sources of working capital and would adversely affect the Company's ability to carry out its current operating plans.

RESULTS OF OPERATIONS

2002 Compared to 2001

The Company reported a net loss of $310,970 or $0.016 per basic and diluted share for the year ended December 31, 2002, compared to a net loss of $50,283 or $0.003 per basic and diluted share for the prior year.

Revenues for 2002 increased by 38% compared to 2001. Oil production increased by 528% while natural gas production declined by 7% as compared with the prior year. The increase in oil production is due to the new Comanche lease oil wells, along with production from the May 2002 acquisition of the Pena Creek field. The decline in 2002 gas production compared to the prior year reflects the general production decline of the Company's existing mix of maturing gas wells. This decline was partially offset by new gas production from the 16 new gas wells drilled and completed during the year. Included in the number of gas wells classified as producing at December 31, 2002, were 38 CBM gas wells, which are still in their initial dewatering stage, and are not yet contributing a significant amount of new gas production. On an equivalent unit basis, prices averaged 18% lower in 2002 as compared to 2001. Crude oil prices averaged 4% higher while natural gas prices fell 27%. Average lowe r prices for 2002, as compared to 2001, had a $3.6 million negative impact on revenues in 2002. Commodity prices have been and continue to be volatile. During 2001, realized gas prices ranged from over $10.50 per Mcf in January to a low of $1.26 per Mcf in October. During 2002 realized natural gas prices ranged from over $4.71 per Mcf in November to a low of $1.75 in February. During the first three months of 2003 crude oil and natural gas prices have increased significantly.

Average daily net gas production rates in 2002 decreased to 6.8 MMcf, a 7% decline from the prior year, while average daily net oil production rates in 2002 increased to 860 Bbls, a 528% over the prior year. The Company expects to reverse the declining natural gas production rates based on its year 2003 drilling success to date and expected results from ongoing drilling projects.

Lease operating expense for 2002 increased $1.8 million, from $2.4 million in 2001 to $4.2 million in 2002, a 76% increase. This increase is primarily due to the addition of 16 new natural gas wells and 14 new oil wells during 2002 and the acquisition of 188 active Pena Creek wells. The increase reflects the incremental direct costs of operating the new wells, including typical costs such as pumper, electricity, water disposal, and other direct overhead charges, as added during 2002 to the Company's existing lease operating expense levels. Operating expense per Mcfe increased $0.06, from $1.13 in 2001 to $1.19 in 2002. The increase in the rate is due to the Pena Creek field, which consists of three waterflood units. Typically, waterfloods incur higher costs of operations. Excluding the Pena Creek field, operating expense per Mcfe for 2002 is $1.07, a decrease of $0.06 from the prior year. Also, included in operating costs is the cost of operating the CBM wells. These costs to taled $583,852 in 2002 and $446,006 in 2001. The CBM wells are in the dewatering phase and therefore have little production relative to their operating costs. Operating cost per Mcfe excluding the CBM wells and Pena Creek averaged $0.93 in 2002 and $0.99 in 2001.

Pursuant to the successful efforts method of accounting for mineral properties, the Company periodically assesses its producing and non-producing properties for impairment. Impairment and abandonments decreased by 53% primarily due to lower impairment rates on non-producing acreage in the Williston Basin during 2002 versus 2001. Depreciation, depletion and amortization increased by almost $2.9 million, or 123%, over 2001 due primarily to the increased number of producing wells being depleted for wells added through the drill bit and the Pena Creek acquisition. The increase in depreciation was due to increased investments in other equipment including the pipeline and well service equipment acquisitions. The increase in amortization was primarily due to the full year amortization related to the 3-D seismic survey on the Comanche lease acquired during 2001.

General and administrative costs increased 37% compared to 2001 reflecting the higher sustained level of Company operations. The increase is due primarily to increased salaries, wages and benefits associated with staff increases including 6 engineering and administrative staff additions and 8 new field personnel during 2002. Also contributing to the increase were higher costs for property and liability insurance and increased investor relations expenses.

The 75% decrease in interest income reflects the declining cash levels in interest bearing accounts and declining interest rates during 2002 versus 2001. Interest expense increased by $144,840 in 2002 from 2001 due to higher debt levels.

2001 Compared to 2000

The Company reported a net loss of $50,283 or $0.003 per basic and diluted share for the year ended December 31, 2001, compared to net income of $6,761,935 or $0.39 per basic and diluted share for the prior year. Net income in 2000 included a deferred tax benefit of $5,232,700 while no similar benefit was recognized in 2001.

Although, 2001 revenues decreased by 1.5% compared to year 2000 levels, 2001 oil and gas production declined by 9.8% and 17.5% respectively as compared with 2000. The 17.5% decline in oil production primarily reflects the advancing decline curve of maturing oil wells in the Williston Basin. In addition, a 15.4 % decline in the average price of oil was offset somewhat by an 11% increase in the average price of gas as compared to 2000 prices for both commodities. The decline in 2001 gas production compared to the prior year reflects the general production decline of the Company's existing mix of maturing gas wells. This decline was partially offset by new gas production from the 54 new gas wells drilled and completed during 2001. Included in the number of gas wells classified as producing in 2001 were 34 CBM gas wells, which were still in their initial dewatering stage and not yet contributing a significant amount of new gas production. A significant contribution of new CBM gas production is expected from these wells upon their reaching Phase 2 of the dewatering process.

Average daily net gas production rates in 2001 decreased to 7.3 MMcf, an 11% decline over the prior year, while average daily net oil production rates in 2001 decreased to 136 Bbls, a 26% decline over the prior year.

Lease operations expense for 2001 increased 108% compared to 2000. This increase was primarily due to the addition of 54 new gas wells and 9 new oil wells during 2001. The increase reflects the incremental direct costs of operating the new wells, including typical costs such as pumper, electricity, water disposal, and other direct overhead charges, as added during 2001 to the Company's existing lease operating expense levels. The 7 new Burr wells increased overall annual lease operating costs by approximately $469,000 due to the higher costs of chemical treatment for H2S removal and related costs of operating an amine plant for these gas wells plus costs associated with salt water disposal. The 34 newly connected CBM wells in the dewatering pilot project added $419,000 in incremental operating costs in 2001 and reflect the high operating costs associated with the de-watering phase of the CBM pilot program initiated in 2001. Addit ionally, ad valorem taxes increased approximately 30% in 2001 compared to 2000 reflecting increased appraised values for new oil and gas properties as well as increased valuations of exiting wells due to higher oil and gas prices over the prior year. Exploration expenses remained consistent with 2000.

Pursuant to the successful efforts method of accounting for mineral properties, the Company periodically assesses its producing and non-producing properties for impairment. Impairment and abandonment decreased by 15% primarily due to lower impairment rates on non-producing acreage in the Williston Basin during 2001 versus 2000. This decrease was somewhat offset by an increase in impairments of producing properties resulting from lower oil and gas prices at year end and the resultant decreased property values in the year-end reserve report. Depreciation, depletion and amortization increased by almost $500,000 or 18% over calendar 2000 levels due primarily to the increased number of producing wells being depleted and higher depletion rates for 2001 caused by lower year-end reserve volumes as a result of lower oil and gas prices at December 31, 2001. The increase in depreciation was due to increased investments in other equipment including the expansion of the Paloma lease ga thering system throughout the year. The increase in amortization was primarily due to the additional amortization related to the 78-square mile 3-D seismic survey on the Comanche lease acquired during 2001.

General and administrative costs increased 19% compared to 2000 reflecting the higher sustained level of Company operations. 68% of the increase was due primarily to increased salaries, wages and benefits associated with staff increases including 2 engineering and administrative staff additions and 6 new field personnel during 2001. Also contributing to the increase were higher costs for property and liability insurance, increased accounting and auditing fees and increased state franchise tax expenses.

The 19% decrease in interest income reflects the declining cash levels in interest bearing accounts and declining interest rates during 2001 versus 2000. Interest expense decreased by $51,000 in 2001 from 2000 due to the retirement of the Range debt during the second quarter of 2000. Income tax expensed decreased by $5,216,800 due to the recognition of a deferred federal tax benefit of $5,232,700 in 2000, while no similar benefit was recognized in 2001.

CONTRACTUAL OBLIGATIONS AND CONTINGENT LIABILITIES AND COMMITMENTS

The following is a summary of the Company's future payments on obligations as of December 31, 2002.

Payments Due by Period

2-3

4-5

After 5

Contractual Obligations

1 Year

Years

Years

Years

Total

Long-term debt

$

1,073,773

$

6,143,458

$

-

-

$

7,217,231

Operating lease obligations

300,000

610,000

486,000

-

1,396,000

Total Contractual Cash       Obligations

$

1,373,773

$

6,753,458

$

486,000

-

$

8,613,231

In addition to the above, in January 2003 the Company entered into a $2.8 million unsecured installment obligation. Imputed interest due on the obligation is 4.25% per annum. Payments are due in two equal installments: $1.4 million in January 2004 and January 2005.

In January 2003 the Company entered into a contract to deliver natural gas at a fixed price. The volumes to be delivered under the contract are as follows:

Commitment by Period

2-3

4-5

After 5

Fixed Price Contract

1 Year

Years

Years

Years

Total

Natural Gas

Volume, MMBtu *

901,800

-

-

-

901,800

Fixed price per MMBtu**

$

4.45

-

-

-

$

4.45

*   Approximately 2,700 MMBtu per day for the period February 1, 2003 through December 31, 2003.

** Net of transportation and marketing costs.

The volumes to be delivered under the contract represented approximately 30% of the Company's natural gas production rate at December 31, 2002. The Company expects to be able to delivery the committed volumes from its Maverick Basin production.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The discussion and analysis of the Company's financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note A to our consolidated financial statements. In response to SEC Release No. 33-8040, "Cautionary Advice Regarding Disclosure About Critical Accounting Policies," we have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. We analyze our estimates, including those related to oil and gas revenues, oil and gas properties, income taxes, contingencies and litigation, an d base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of the Company's financial statements:

Successful Efforts Method of Accounting

The Company accounts for its natural gas and crude oil exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells, costs to acquire mineral interests and 3-D seismic costs are capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses including 2-D seismic costs and delay rentals for oil and gas leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature and an allocation of costs is required to properly account for the results. The evaluation of oil and gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with referenc e to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

The successful efforts method of accounting can have a significant impact on the operational results reported when the Company is entering a new exploratory area in hopes of finding an oil and gas field that will be the focus of future development drilling activity. The initial exploratory wells may be unsuccessful and will be expensed.

Reserve Estimates

The Company's estimates of oil and gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future oil and gas prices, future operating costs, severance taxes, development costs and w orkover gas costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to an extent that these reserves may be later

determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of oil and gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company's oil and gas properties and/or the rate of depletion of the oil and gas properties. Actual production, revenues and expenditures, with respect to the Company's reserves, will likely vary from estimates and such variances may be material.

Impairment of Oil and Gas Properties

The Company reviews its oil and gas properties for impairment at least annually and whenever events and circumstances indicate a decline in the recoverability of their carrying value. The Company estimates the expected future cash flows of its oil and gas properties and compares such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to their fair value. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected.

Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that would require the Company to record an impairment of the recorded book values associated with oil and gas properties. The Company has recognized impairments in prior years and there can be no assurance that impairments will not be required in the future.

New Accounting Standards

In April 2002, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 145, "Revision of FASB Statements No. 4, 44 and 64, and Amendment of FASB Statement No. 13 and Technical Corrections". This Statement changes the presentation and reporting of extinguishments of debt on the Statement of Operations. The required adoption of this Statement in 2003 by the Company is not expected to have a material impact on its operating results or financial position.

In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities". SFAS No. 146 requires that a liability for costs associated with an exit or disposal activity be recognized and measured initially at fair value and only when the liability is incurred. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002. The Company does not expect the adoption of SFAS 146 to have a material impact on its operating results or financial position.

In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure - an Amendment of FASB Statement No. 123". This Statement provides guidance and transition rules for those companies electing to change their method of accounting for stock-based compensation. However, the statement does not require the change in accounting, and TXCO has elected to continue reporting stock-based compensation following SFAS No. 123 and Accounting Principles Board Opinion No. 25. SFAS No. 148 also requires certain enhanced disclosures regarding stock-based compensation, and such disclosures have been included in these footnotes to the financial statements.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Risk: The Company's major market risk exposure is the commodity pricing applicable to its oil and natural gas production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. Prices have fluctuated significantly over the last five years and such volatility is expected to continue, and the range of such price movement is not predictable with any degree of certainty. During January 2003 the Company entered into a forward sale of approximately 2,700 MMBtu per day of its natural gas production from February 1, 2003, through December 31, 2003, at a fixed price of $4.45 per MMBtu. This represents approximately 30% of the Company's net natural gas sales as of year-end 2002. A 10% fluctuation in the price received for oil and gas production would have an approximate $1.6 million impact on the Company's annual revenues based on 2002 sales volumes; and a $1.3 million impact had the 2,700 MMBtu per day forward sales been in effect for the entire year of 2002.

Interest Rate Risk: The Company has borrowed funds under a new revolving credit facility with Hibernia National Bank, with interest tied to the Wall Street Journal Prime rate. At March 24, 2003 the Company had $8.5 million in borrowings under the Facility with interest at 4.25% per annum. Under terms of the Facility, the Company has the option to lock in a fixed interest rate for a period of up to 6 months using LIBOR rates plus an applicable margin. Should interest rates start to rise, the Company can convert its outstanding loan balance to the LIBOR option rate within 3 days of its election. An annualized 10% fluctuation in interest charged on the outstanding balance at March 24, 2003 would have an approximate $34,000 impact on the Company's annual net income.

Financial Instruments: The Company's financial instruments consist of cash equivalents and accounts receivable. Its cash equivalents are cash investment funds which are placed with a major financial institution. Substantially all of the Company's accounts receivable result from oil and gas sales or joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, the Company has not experienced any significant credit losses on such receivables. See Certain Business Risks section.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The Consolidated Financial Statements and Notes thereto are set out in this Form 10-K commencing on page F-1.

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND

           FINANCIAL DISCLOSURES

None

PART III
ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information regarding the directors and executive officers of the Company, as of March 24, 2003:
Name	Class	Position	Age
Stephen M. Gose, Jr.	B	Chairman of the Board of Directors Member Compensation and Nominations Committees	73
Michael J. Pint	C	Director, Chairman Audit Committee Member Compensation and Nominations Committees	59
Robert L. Foree, Jr.	A	Director, Chairman Nominations Committee Member Audit and Compensation Committees	73
Alan L. Edgar	B	Director, Chairman Compensation Committee Member Audit and Nominations Committees	57
James E. Sigmon	C	President and Director	54
Thomas H. Gose	A	Director and Assistant Secretary Member Nominations Committee	47
Roberto R. Thomae		Chief Financial Officer Secretary/Treasurer, Vice President-Finance	52
Richard A. Sartor		Controller	50
Stephen M. Gose, Jr., has served as Chairman of the Board of Directors of the Company since July 1984. He has been a member of the Compensation Committees since June 1997 and served as its Chairman through April 1998. Mr. Gose was a member of the Audit Committee from June 1997 through May 2001 and served as its Chairman from June 1997 through April 1998. He has been a member of the Nominations Committee since its inception in May 2001. Mr. Gose served as a Director of the Company's former subsidiary, ExproFuels, Inc. from 1994 through 1999. A geologist by training, he has been active for more than 46 years in exploration and development of oil and gas properties, in real estate development, and in ranching through the operations of Retamco Operating, Inc., its predecessors and affiliates.
Michael J. Pint has served as a Director since May 1997. He has been a member of the Audit Committee of the Board of Directors since June 1997 and has served as its Chairman since April 1998. Mr. Pint has been a member of the Compensation Committee since June 1997 and served as its Chairman from April 1998 through May 2001. He has been a member of the Nominations Committee since its inception in May 2001. Mr. Pint has 36 years banking experience, serving in the bank regulatory arena as well as in the capacity of chairman, president and director of 38 different banks and bank holding companies throughout the country. Since 1995, Mr. Pint has served as a Director of Valley Bancorp, Inc. and Valley Bank of Arizona, Inc. of Phoenix, Arizona. Previous bank regulatory and management positions include a four-year term as Commissioner of Banks and Chairman of the Minnesota Commerce Commis sion from 1979 to 1983 and Senior Vice-President and Chief Financial Officer of the Federal Reserve Bank of Minneapolis, Minnesota through 1983.
Robert L. Foree, Jr. has served as a Director since May 1997 and as a member of the Audit and Compensation Committees of the Board of Directors since June 1997. He has been a member of the Nominations Committee and served as its Chairman since its inception in May 2001. A geologist by training, he has been active for more than 46 years in the exploration and development of oil and gas properties. Since 1992, Mr. Foree has served as President of Foree Oil Company, a privately held Dallas, Texas based independent oil and gas exploration and production company.
Alan L. Edgar has served as a Director of the Company since May 2000 and as a member of the Audit and Compensation Committees of the Board of Directors since that time. He has served as the Chairman of the Compensation Committee since May 2001. Mr. Edgar has been a member of the Nominations Committee since its inception in May 2001. He has been involved in energy related investment banking and equity analysis for 30 years. Since 1998, Mr. Edgar has served as President of Cochise Capital, Inc. a privately held Dallas, Texas based company specializing in exploration and production related mergers and acquisitions advisory and financing. Previous public company mergers and acquisitions, investment banking and energy financing experience includes serving as Managing Director and Co-Head of the Energy Group of Donaldson, Lufkin & Jenrette Securities, Inc., from 1990 to 1997, serving as Managing Director of the Energy Group of Prudential-Bache Capital Funding from 1987 to 1 990 and serving as Corporate and Research Director of Schneider, Bernet & Hickman, Inc. (Thompson, McKinnon) from 1972 through 1986.
James E. Sigmon has served as the Company's President since February 1985. He has been a Director of the Company since July 1984. He served as a Director of ExproFuels, Inc. through November 1998. As an engineer, Mr. Sigmon has been active for 31 years in the exploration and development of oil and gas properties. Prior to joining the Company, Mr. Sigmon served in the management of a private oil and gas exploration company active in drilling oil and gas wells in South Texas.
Thomas H. Gose has served as a Director of the Company since February 1989, as Secretary from 1992 through March 1997 and as Assistant Secretary since March 1997. He had been a member of the Audit and Nominations Committees since May 2001. During 2002 Mr. Gose resigned from the Audit Committee. Mr. Gose served as President and Director of the Company's former subsidiary ExproFuels, Inc. from 1994 through 1999. Since October 2000 he has served as President of NEOgas Inc., a Houston based subsidiary of NEOppg International Ltd. NEOgas develops and markets technologies to transport and deliver compressed natural gas to markets with stranded gas production or stranded customer bases. He formerly served as Director, CEO and President of Retamco Operating, Inc., (a large shareholder of the Company) its predecessors and affiliates from 1987 to 1999. Thomas H. Gose is the son of Stephen M. Gose, Jr.
Roberto R. Thomae has served as Chief Financial Officer and Vice President-Finance of the Company since September 1996 and as Secretary/Treasurer since March 1997. From September 1995 through September 1996 he was a consultant to the Company in a financial management capacity. From 1989 through 1995 Mr. Thomae was self-employed as a management consultant primarily involved in the development of domestic and international oil and gas exploration projects and the marketing of refined products.
Richard A. Sartor has served as Controller of the Company since April 1997. A Certified Public Accountant since 1980, Mr. Sartor owned his own private accounting practice from 1989 through March 1997.
Each of the Directors listed above has been elected by the shareholders to serve until his successor is duly elected. In May 2001 the shareholders of the Company approved the adoption of a classified board. The board is structured with three classes of directors, Classes A, B and C, each having two directors with current terms expiring in the years 2005, 2003 and 2004, respectively. Directors elected at the May 2002 annual meeting and later meetings serve full three-year terms.

ITEM 11.  EXECUTIVE COMPENSATION

Summary Compensation Information: The following table contains certain information for the past three years with respect to the chief executive officer and those executive officers of the Company with total annual salary and bonuses exceeding $100,000:

SUMMARY COMPENSATION TABLE

Other Annual

All Other

Salary

Bonus

Compensation

Compensation

James E. Sigmon

12/31/02

$204,697

$  8,750

(1)

$265,354

$393

President & CEO

12/31/01

201,250

8,750

(1)

210,099

592

12/31/00

175,000

14,583

(1)

179,374

402

Roberto R. Thomae

12/31/02

126,669

5,625

-0-

177

CFO & Secretary/

12/31/01

111,250

4,792

-0-

237

Treasurer

12/31/00

100,000

8,333

-0-

161

(1)   Represents income from overriding royalty interests

OPTION GRANTS IN LAST FISCAL YEAR

% of Total Options

Granted to

Exercise

# Options

Employees

Price

Expiration

Grant Date

Name

Granted

In Fiscal Year

per share

Date

Value(1)

James E. Sigmon

None

N/A

N/A

N/A

N/A

President & CEO

Roberto R. Thomae

None

N/A

N/A

N/A

N/A

CFO & Secretary/

Treasurer

AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR

Number of

Value of

# Shares

Value

Unexercised Options/SARs

Unexercised Options/SARs

Name

Exercised

Realized

Exercisable

Unexercisable

Exercisable

Unexercisable (1)

James E. Sigmon(2)

N/A

N/A

400,000

300,000

$279,500

$256,500

Roberto R. Thomae

N/A

N/A

150,000

25,000

111,250

500

(1)

Value of unexercised options calculated as the difference in the stock price at period end and the option price.

(2)

400,000 of Mr. Sigmon's unexercised options were exercisable as of December 31, 2002, and the remaining 300,000 options vest and are exercisable in specified amounts upon the Company's common stock attaining the following price levels: 100,000 shares at $10.00; 100,000 shares at $12.50 and 100,000 shares at $15.00.

COMPENSATION OF DIRECTORS

Members of the Board of Directors who serve as Executive Officers of the Company are not compensated for any services provided as a Director. Outside (non-employee) directors of the Company are paid an annual retainer of $10,000 per year upon election to the Board. Additionally, the outside directors are paid a fee of $1,000 plus reimbursement of related travel expenses for each board meeting attended. Beginning in 1997, upon assuming Director status, new outside directors have been awarded 10 year options (Directors Options) for the purchase of 75,000 shares of Company common stock at 110% of the stock's market value on the date of grant, with such options vesting in equal annual increments over their first three years of service.

EMPLOYMENT CONTRACTS
The Company has an employment agreement with its president, Mr. James E. Sigmon, which sets his salary at a minimum of $210,000 annually, and includes the grant of an overriding royalty interest equal to 1% of the Company's net revenue interest under all leases the Company has or acquires during his term as President. The agreement is cancelable with 90 days notice by the Company.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
No Compensation Committee interlocks existed during the Company's last completed year. The Compensation Committee of the Board of Directors of the Company was established in June 1997 and currently consists of Alan L. Edgar (Chairman), Robert L. Foree, Jr., Michael J. Pint, and Stephen M. Gose, Jr. The principal function of the Committee is to approve the compensation of all executive officers of the Company, to recommend to the Board the terms of principal compensation plans requiring stockholder approval and to direct the administration of the Company's 1995 Flexible Incentive Plan.
ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following tables set forth beneficial ownership of the Company's common stock, its only class of equity security. The percent owned is based on 20,009,716 shares outstanding and 23,039,145 fully diluted shares which includes 3,029,429 shares under options and warrants as of March 24, 2003.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The following table sets forth information concerning all persons known to the Company to beneficially own 5% or more if its common stock, including information filed pursuant to Rule 13d filings made available to the Company during the year.
	Name and Address of			Number of Shares
	Beneficial Owner			Beneficially Owned	Percent Owned
	Stephen M. Gose, Jr.		(1)	1,517,877	7.57%
	HCR Box 1010 Hwy 212
	Roberts, Montana 59070
	Thomas H. Gose		(1)	824,601	4.11%
	517 Morningside
	San Antonio, TX 78209
	Tahoe Invest			1,200,000	6.00%
	Innere Guterstrasse 4
	6304 Zug
	Switzerland
(1)		Please see related footnotes for each respective beneficial owner presented in the Security Ownership of Management table on the following page.

SECURITY OWNERSHIP OF MANAGEMENT
The following table sets forth the number of shares of common stock beneficially owned as of March 24, 2003 by each director, each executive officer named in the Summary Compensation Table and by all directors and executive officers as a group. Information provided is based on Forms 3, 4, 5, stock records of the Company and the Company's transfer agent.
			Number of Shares	Percent
	Name		Beneficially Owned	Owned
				(1)
	Stephen M. Gose, Jr.	(3) (7)	1,517,877	7.57	%
	Thomas H. Gose	(7) (8)	824,601	4.11	%
	James E. Sigmon	(2)	774,400	3.74	%
	Michael Pint	(4)	325,000	1.62	%
	Alan L. Edgar	(5)	278,433	1.38	%
	Robert L. Foree, Jr.	(4)	99,100	.49	%
	Roberto R. Thomae	(6)	150,000	.74	%
	All Directors and Executive
	Officers as a group		4,006,911	18.78	%
(1)	Except as otherwise noted, the Company believes that each named individual has sole voting and investment power over the shares beneficially owned.
(2)	The number of shares beneficially owned by Mr. Sigmon includes 74,400 shares owned directly and 700,000 shares of the Company's Common Stock reserved for issuance through options issued under the Company's 1995 Flexible Incentive Plan.
(3)	The number of shares beneficially owned by Mr. Stephen M. Gose, Jr. include his 100% interest, shared equally with his spouse, in 1,467,877 shares owned by Retamco Operating, Inc.
(4)	The number of shares beneficially owned by Mr. Pint and Mr. Foree each includes 75,000 shares of the Company's Common Stock reserved for issuance under non-qualified options issued to outside directors of the Company exercisable at March 24, 2003 plus 250,000 and 24,100 respectively, of directly owned shares.
(5)	The number of shares beneficially owned by Mr. Edgar includes 95,100 shares owned directly, 133,333 shares of the Company's Common Stock reserved for issuance under 5 year warrants granted in February 2000, for services rendered prior to his election as a director and 50,000 shares reserved for issuance under non-qualified options issued to outside directors of the Company exercisable at March 24, 2003.
(6)	The number of shares beneficially owned by Mr. Thomae includes 150,000 shares of the Company's Common Stock reserved for issuance through options issued under the Company's 1995 Flexible Incentive Plan.
(7)	The number of shares beneficially owned by Mr. Stephen M. Gose, Jr. and Mr. Thomas H. Gose each includes 50,000 shares of the Company's common stock reserved for issuance under non-qualified options issued to outside directors of the Company exercisable at March 24, 2003.
(8)	The number of shares beneficially owned by Mr. Thomas Gose include 774,601 shares owned directly.

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
Plan Category		Number of Securities to be Issued Upon Exercise of Outstanding Options,   Warrants and Rights	Weighted-average Exercise Price of Outstanding Options, Warrants      and Rights		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (excluding securities    reflected in column (a)
		(a)	(b)		(c)
Equity compensation plans    approved by security holders		1,463,000	$	2.49	139,000
Equity compensation plans not    approved by security holders		N/A		N/A	N/A
Total		1,463,000	$	2.49	139,000
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
ITEM 14. CONTROLS AND PROCEDURES
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. Based upon that evaluation, which took place as of a date within 90 days of the filing of this report, the Company's Chief Executive Officer along with the Chief Financial Officer concluded that the Company's 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 reports it files with the SEC.
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.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(A)     The following documents are being filed as part of this annual report on Form 10-K after the signature page, commencing on page F-1.
(1)	Consolidated Financial Statements:
	Independent Auditors' Reports.
	Balance Sheets, December 31, 2002 and December 31, 2001.
	Statements of Operations, Years Ended December 31, 2002, 2001 and 2000.
	Statements of Stockholders' Equity, Years Ended December 31, 2002, 2001 and 2000.
	Statements of Cash Flows, Years Ended December 31, 2002, 2001 and 2000.
	Notes to Audited Consolidated Financial Statements.
(2)	Financial Statement Schedules.
	Schedule II - Valuation and Qualifying Reserves.
	All other schedules for which provision is made in the applicable accounting regulations of the Securities and Exchange Commission are omitted as the required information is inapplicable or the information is presented in the Consolidated Financial Statements or Notes thereto.

(3)	Exhibits:
**  3.1		Articles of Incorporation of the Registrant filed as Exhibit 3(B) to the registration statement on Form S-1; Reg. No. 2-65661.
**  3.2		Articles of Amendment to Articles of Incorporation of The Exploration Company, dated July 27, 1984, filed as Exhibit 3.2 to Registrant's Annual report on Form 10-K, dated February 4, 1985.
**  3.3		Articles of Amendment to the Articles of Incorporation of the Exploration Company dated April 2, 1985.
**  3.4		By-Laws of the Registrant filed as Exhibit 5(A) to the Registration Statement on Form S-1; Reg. 2-65661.
**  3.5		Amendment to By-Laws of registrant, dated September 1, 1985.
**  3.6		Articles of Amendment to the Articles of Incorporation of The Exploration Company dated April 6, 1990.
** 10.2		Employment Agreement between the Registrant and James E. Sigmon, dated October 1, 1984.
** 10.3		Registrant's Amended and Restated 1983 Incentive Stock Option Plan filed as Exhibit A to registrant's definitive Proxy Statement, dated February 20, 1985.
** 10.4		Registrant's 1995 Flexible Incentive Plan, filed as Exhibit A to registrant's definitive Proxy Statement, dated April 28, 1995.
** 10.5		Registrant's Form S-8 Registration Statement for its 1995 Flexible Incentive Plan, dated November 26, 1996.
** 10.6		Registrant's Amendment to its 1995 Flexible Incentive Plan, filed as Proposal II of the registrants definitive Proxy Statement, dated January 12, 1999.
** 10.7		Registrant's Plan and Agreement of Merger of The Exploration Company with and into The Exploration Company of Delaware, Inc., filed as Appendix A of the registrants definitive Proxy Statement, dated January 12, 1999.
** 10.8		Registrant's Certificate of Incorporation of The Exploration Company of Delaware, Inc., filed as Appendix B of the registrant's definitive Proxy Statement, dated January 12, 1999.
** 10.9		Registrant's Certificate of Amendment of Certificate of Incorporation of The Exploration Company of Delaware, Inc., filed as Appendix C of the registrant's definitive Proxy Statement, dated January 12, 1999.
** 10.10		Registrant's Bylaws of The Exploration Company of Delaware, Inc., filed as Appendix D of the registrant's definitive Proxy Statement, dated January 12, 1999.
** 10.11		Registrant's Rights Agreement, filed as Exhibit 4.1 of the registrants Form 8-K, dated June 29, 2000 which includes: as Exhibit A thereto, the Certificate of Designation of Series A Junior Participating Preferred Stock; as Exhibit B thereto, Form of Right Certificate; as Exhibit C thereto, Summary of Rights to Purchase Preferred Shares.
10.12		Loan Agreement dated March 4, 2002, between The Exploration Company and Hibernia National Bank filed herewith.
10.13		First Amendment to Loan Agreement dated December 13, 2002 between The Exploration Company and Hibernia National Bank filed herewith.
** 10.14		Registrant's Certificate of Amendment of Certificate of Incorporation of The Exploration Company of Delaware, Inc., filed as Appendix B of the registrant's definitive Proxy Statement, dated May 25, 2001.
** 10.15		Registrant's Amendment to its Flexible Incentive Plan, filed as Proposal IV of the registrants definitive Proxy Statement, dated May 25, 2001.
** 10.16		Registrant's Audit Committee Charter filed as Appendix A of the registrant's definitive Proxy Statement, dated May 25, 2001.
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.
**		Previously filed
(B)      Reports on Form 8-K:
No reports on Form 8-K were filed during the quarter ended Dec. 31, 2002.

SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
THE EXPLORATION COMPANY OF DELAWARE, INC.
Registrant
March 28, 2003		By: /s/ James E. Sigmon
		James E. Sigmon, President
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signatures	Title		Date
/s/ Stephen M. Gose, Jr	Chairman of the Board of Directors		March 28, 2003
Stephen M. Gose, Jr.
/s/ Thomas H. Gose	Director and Assistant Secretary		March 28, 2003
Thomas H. Gose
/s/ James E. Sigmon	President and Director		March 28, 2003
James E. Sigmon	(Principal Executive Officer)
/s/ Michael J. Pint	Director		March 28, 2003
Michael J. Pint
/s/ Robert L. Foree, Jr	Director		March 28, 2003
Robert L. Foree, Jr.
/s/ Alan L. Edgar	Director		March 28, 2003
Alan L. Edgar
/s/ Roberto R. Thomae	Chief Financial Officer		March 28, 2003
Roberto R. Thomae	Vice-President-Finance
	Secretary/Treasurer
	(Principal Accounting Officer)

Form of Sarbanes-Oxley Section 302(a) Certification
I, James E. Sigmon, certify that:
1.	I have reviewed this annual report on Form 10-K of The Exploration Company of Delaware, Inc.;
2.	Based on my knowledge, this annual 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 annual report;
3.	Based on my knowledge, the financial statements, and other financial information included in this annual 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 annual 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 annual 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 annual report (the "Evaluation Date"); and
	iii)	presented in this annual 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 annual 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:	March 28, 2003		/s/ James E. Sigmon
			James E. Sigmon
			Chief Executive Officer

Form of Sarbanes-Oxley Section 302(a) Certification
I, Roberto R. Thomae, certify that:
1.	I have reviewed this annual report on Form 10-K of The Exploration Company of Delaware, Inc.;
2.	Based on my knowledge, this annual 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 annual report;
3.	Based on my knowledge, the financial statements, and other financial information included in this annual 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 annual 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 annual 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 annual report (the "Evaluation Date"); and
	iii)	presented in this annual 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 annual 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:	March 28, 2003		/s/ Roberto R. Thomae
			Roberto R. Thomae
			Chief Financial Officer

INDEPENDENT AUDITORS' REPORT

The Board of Directors and Stockholders

The Exploration Company of Delaware, Inc. and Subsidiaries

San Antonio, Texas

We have audited the consolidated balance sheets of The Exploration Company of Delaware, Inc. and Subsidiaries (collectively referred to as "The Exploration Company" or "Company") as of December 31, 2002 and 2001, and the related consolidated statements of operations, stockholders' equity and cash flows for the years ended December 31, 2002, 2001 and 2000. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with U. S. generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of The Exploration Company as of December 31, 2002 and 2001, and the results of its operations and cash flows for the years ended December 31, 2002, 2001 and 2000, in conformity with U. S. generally accepted accounting principles.

We have also audited Schedule II of The Exploration Company for the years ended December 31, 2002, 2001 and 2000. In our opinion, this schedule presents fairly, in all material respects, the information required to be set forth therein.

AKIN, DOHERTY, KLEIN & FEUGE, P.C.

San Antonio, Texas

March 4, 2003

THE EXPLORATION COMPANY Consolidated Balance Sheets	December 31
	2002	2001
Assets
Current Assets:
Cash and equivalents	$ 2,333,688	$ 2,019,164
Accounts receivable:
Joint interest owners	744,395	472,146
Oil and gas production	4,373,875	1,470,497
Prepaid expenses and other	503,176	273,603
Total current assets	7,955,134	4,235,410
Property and Equipment, net - successful efforts   method of accounting for oil and gas properties	39,327,867	19,893,740
Other Assets:
Deferred tax asset	5,232,718	5,232,718
Other	520,600	481,564
Total other assets	5,753,318	5,714,282
Total Assets	$53,036,319	$29,843,432
See notes to audited consolidated financial statements.

THE EXPLORATION COMPANY Consolidated Balance Sheets	December 31
	2002		2001
Liabilities And Stockholders' Equity
Current Liabilities:
Accounts payable and accrued expenses	$ 6,871,724		$ 4,122,669
Due to joint interest owners	1,894,144		1,368,785
Current portion of long-term debt	1,073,773		298,410
Total current liabilities	9,839,641		5,789,864
Long-term debt, net of current portion	6,143,458		563,767
Minority interest in consolidated subsidiaries	82,846		433,105
Stockholders' Equity:
Preferred stock; authorized 10,000,000 shares,     issued and outstanding -0- shares Deferred tax asset
Common stock, par value $0.01 per share;     authorized 50,000,000 shares; issued     20,109,516 and 17,496,849 shares, outstanding     20,009,716 and 17,397,049	201,095		174,968
Additional paid-in capital	58,216,504		44,017,983
Accumulated deficit	(21,201,218	)	(20,890,248	)
Less treasury stock, at cost, 99,800 shares	(246,007	)	(246,007	)
Total stockholders' equity	36,970,374		23,056,696
Total Liabilities and Stockholders' Equity	$53,036,319		$29,843,432
See notes to audited consolidated financial statements.

THE EXPLORATION COMPANY Consolidated Statements of Operations
	Years Ended December 31
	2002		2001		2000
Revenues
Oil and gas sales	$16,049,798		$13,350,699		$13,841,138
Pipeline operations	2,596,955		-		-
Other operating income	311,611		408,221		520,219
	18,958,364		13,758,920		14,361,357
Costs and Expenses
Lease operations	4,238,921		2,406,688		1,157,291
Production taxes	973,078		959,143		990,789
Exploration expenses	1,567,098		2,986,036		3,056,466
Impairment and abandonments	1,246,495		2,652,705		3,126,715
Pipeline operations	2,467,554		-		-
Depreciation, depletion and amortization	6,500,625		3,201,517		2,711,605
General and administrative	2,025,440		1,481,284		1,501,645
Total costs and expenses	19,019,211		13,687,373		12,544,511
Income (loss) from operations	(60,847	)	71,547		1,816,846
Other Income (Expense)
Interest income	46,663		188,061		232,386
Interest expense	(273,213	)	(128,373	)	(179,036	)
Loan fee amortization	(14,507	)	-		(12,000	)
	(241,057	)	59,688		41,350
Income (loss) before income taxes   and minority interest	(301,904	)	131,235		1,858,196
Minority interest in income of subsidiaries	(84,066	)	(106,518	)	(238,061	)
Income (loss) before income taxes	(385,970	)	24,717		1,620,135
Income tax benefit (expense), net	75,000		(75,000	)	5,141,800
Net Income (Loss)	$    (310,970	)	$      (50,283	)	$  6,761,935
Earnings (Loss) Per Share
Basic	$        (0.016	)	$        (0.003	)	$          0.392
Diluted	(0.016	)	(0.003	)	0.390
Weighted average number of common   shares outstanding:
Basic	19,080,847		17,441,242		17,242,326
Diluted	19,080,847		17,441,242		17,343,957
See notes to audited consolidated financial statements.

THE EXPLORATION COMPANY Consolidated Statements of Stockholders' Equity
			Additional
	Common Stock		Paid-in	Accumulated		Treasury
	Shares	Amount	Capital	Deficit		Stock		Total
Balance at December 31, 1999	15,938,516	$159,385	$40,651,444	$(27,601,900	)	$     -		$13,208,929
Issuance of common stock   for cash, net of expenses     of $189,752	1,333,333	13,333	2,796,914	- -		- -		2,810,247
Issuance of common stock in   exchange for oil and     gas properties	150,000	1,500	439,125	- -		- -		440,625
Common stock warrants exercised	50,000	500	99,500	-		-		100,000
Net income for the year	-	-	-	6,761,935		-		6,761,935
Balance at December 31, 2000	17,471,849	174,718	43,986,983	(20,839,965	)	-		23,321,736
Common stock options exercised	25,000	250	31,000	-		-		31,250
Purchases of treasury stock, at cost						(246,007	)	(246,007	)
Net loss for the year	-	-	-	(50,283	)	-		(50,283	)
Balance at December 31, 2001	17,496,849	174,968	44,017,983	(20,890,248	)	(246,007	)	23,056,696
Common stock options exercised	113,000	1,130	171,625	-		-		172,755
Issuance of common stock for cash,   -net of expenses of $946,112	2,499,667	24,997	14,026,896	- -		- -		14,051,893
Net loss for the year	-	-	-	(310,970	)	-		(310,970	)
Balance at December 31, 2002	20,109,516	$201,095	$58,216,504	$(21,201,218	)	$(246,007	)	$36,970,374
See notes to audited consolidated financial statements.

THE EXPLORATION COMPANY Consolidated Statements of Cash Flows
	Years Ended December 31
	2002		2001		2000
Operating Activities
Net income (loss)	$   (310,970	)	$     (50,283	)	$6,761,935
Adjustments to reconcile net income (loss) to     net cash provided by operating activities:
Deferred income taxes	-		-		(5,232,718	)
Depreciation, depletion and amortization	6,500,625		3,201,517		2,711,605
Impairments and abandonments	1,246,495		2,652,705		3,126,715
Minority interest in income of subsidiaries	84,066		106,518		238,061
Changes in operating assets and liabilities:
Receivables	(3,175,627	)	1,462,023		(1,465,530	)
Prepaid expenses and other	(229,573	)	(46,687	)	(104,441	)
Accounts payable and accrued expenses	3,274,414		1,238,229		494,211
Net cash provided by operating activities	7,389,430		8,564,022		6,529,838
Investing Activities
Purchases of property and equipment	(27,381,247	)	(13,675,327	)	(6,447,962	)
Proceeds from sale of oil and gas properties	200,000		2,005,133		-
Changes in minority interests	(434,325	)	(108,902	)	-
Other changes	(39,036	)	(116,007	)	8,843
Net cash (used) by investing activities	(27,654,608	)	(11,895,103	)	(6,439,119	)
Financing Activities
Proceeds from long-term debt	7,439,915		153,231		1,173,642
Payments on long-term debt	(1,084,861	)	(486,244	)	(1,658,386	)
Issuances of common stock, net of expenses	14,224,648		31,250		2,910,247
Purchases of treasury stock	-		(246,007	)	-
Net cash provided (used) by financing activities	20,579,702		(547,770	)	2,425,503
Change in Cash and Equivalents	314,524		(3,878,851	)	2,516,222
Cash and Equivalents at Beginning of Year	2,019,164		5,898,015		3,381,793
Cash and Equivalents at End of Year	$2,333,688		$2,019,164		$5,898,015
Supplemental Disclosures:
Cash paid for interest	$  273,213		$  128,373		$  179,036
Cash paid for income taxes	-		75,000		62,497
Common stock issued for leasehold acquisition	-		-		440,625
See notes to audited consolidated financial statements.

THE EXPLORATION COMPANY

Notes to Audited Consolidated Financial Statements

Years Ended December 31, 2002, 2001 and 2000

NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Operations: The Exploration Company of Delaware, Inc., d.b.a. The Exploration Company ("TXCO" or "Company") is an independent energy company engaged in the acquisition, exploration, development and production of oil and gas properties. The Company's primary focus is on developing oil and gas reserves on properties located in Texas. The Company also owns properties in South Dakota, North Dakota and Montana.

Consolidation: The financial statements include the accounts of the Company and its majority-owned subsidiaries. The subsidiaries own and operate a gas gathering system which is utilized by the Company for delivery of natural gas from its Texas properties. All significant intercompany balances and transactions have been eliminated in consolidation.

Revenue Recognition: The Company recognizes oil and gas revenue from its interest in producing wells as the oil and gas is sold to third parties. Pipeline revenues are recognized upon delivery of the product to third parties.

Cash and Equivalents: The Company considers all highly liquid investments with an original maturity of three months or less to be cash and equivalents.

Accounts Receivable: Accounts receivable are reported at outstanding principal net of an allowance for doubtful accounts of approximately $27,000 at December 31, 2002 and December 31, 2001. The Company normally does not charge interest on accounts receivable. The allowance for doubtful accounts is generally determined based on the Company's historical losses, as well as a review of certain accounts. Accounts are charged off when collection efforts have failed and the account is deemed uncollectible.

Oil and Gas Properties: The Company uses the successful efforts method of accounting for its oil and gas activities. Costs to acquire mineral interests, 3-D seismic costs, development wells, and costs to drill and equip exploratory wells that find proved reserves are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, 2-D seismic costs, and costs of carrying and retaining unproved properties are expensed as incurred.

Depreciation, depletion and amortization ("DD&A") of oil and gas properties is computed using the unit-of-production method based upon recoverable reserves as determined by the Company's independent reservoir engineers. Depletion of coalbed methane properties begins following the dewatering phase of each coalbed methane project. Oil and gas properties are periodically assessed for impairment. If the unamortized capitalized costs of proved properties are in excess of the undiscounted future cash flows before income taxes, the property is impaired. Future cash flows are determined based on management's best estimate and may consider changes in prices for the product as considered most likely to occur in future periods. Unproved properties are also evaluated periodically and if the unamortized cost is in excess of estimated fair value an impairment is recognized.

Other Property and Equipment: Transportation and other equipment are recorded at cost. Depreciation is computed using the straight-line method over the estimated useful lives of the assets ranging from five to fifteen years. Major renewals and betterments are capitalized while repairs are expensed as incurred.

Federal Income Taxes: The Company follows the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences. Accordingly, deferred tax assets and liabilities are determined based on the temporary differences between the financial statement and tax basis of assets and liabilities, using enacted tax rates in effect for the year in which the differences are expected to reverse.

THE EXPLORATION COMPANY
Notes to Audited Consolidated Financial Statements
Years Ended December 31, 2002, 2001 and 2000
NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - continued
Earnings (Loss) Per Share: Basic earnings per common share is computed by dividing net income by the weighted average number of common shares outstanding during each year. The diluted earnings per share calculation adds to the weighted average number of common shares outstanding the incremental shares that would have been outstanding assuming the exercise of dilutive stock options.
Financial Instruments: The Company's financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents and accounts receivable. The Company places its temporary cash investments with major financial institutions which, from time-to-time, may exceed federally insured limits, and believes the risk of loss is minimal. Substantially all of the Company's accounts receivable result from oil and gas sales or joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, the Company has not experienced credit losses on such receivables. Unless otherwise specified, the Company believes the book value of the financial instruments approximates their fair value.
Use of Estimates: The preparation of financial statements in conformity with U. S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve volumes used to calculate depreciation, depletion and amortization and the related present value of estimated future net cash flows used to review for impairment of proved oil and gas properties similarly, evaluations for impairment of unproved oil and gas properties are subject to numerous uncertainties including estimates of future recoverable reserves and commodity price outlooks.
Accounting for Stock Based Compensation: At December 31, 2002, the Company has a stock-based employee compensation plan which is described more fully in the Stockholders' Equity footnote. The Company accounts for this plan under the recognition and measurement principles of APB Opinion No. 25, "Accounting for Stock Issued to Employees," and related Interpretations. No stock-based employee compensation cost related to stock options is reflected in net income, as all options granted under the plan had an exercise price equal to, or greater than, the market value of the underlying common stock on the date of grant. The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS No. 123, "Accounting for Stock-Based Compensation," to stock-based employee compensation for the year ended December 31:
	2002		2001		2000
Net income (loss) as reported	$(310,970	)	$(50,283	)	$6,761,935
Deduct: Total stock-based compensation   expense determined under the fair value based   method for all awards, net of related tax effects	(241,109	)	(307,520	)	(520,230	)
Pro forma earnings (loss)	$(552,079	)	$(357,803	)	$6,241,705
Earnings (loss) per common share:
Basic, as reported	$   (0.016	)	$   (0.003	)	$    0.392
Basic, pro forma	(0.029	)	(0.021	)	0.362
Diluted, as reported	(0.016	)	(0.003	)	0.390
Diluted, pro forma	(0.029	)	(0.021	)	0.360

THE EXPLORATION COMPANY
Notes to Audited Consolidated Financial Statements
Years Ended December 31, 2002, 2001 and 2000
NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - continued
Government Regulations: The Company's oil and gas operations are subject to federal, state and local provisions regulating the discharge of materials into the environment. Management believes that its current practices and procedures for the control and disposition of such wastes substantially comply with applicable federal and state requirements.
Restoration, Removal and Environmental Matters: The estimated costs of restoration and removal of producing property well sites is generally less than the estimated salvage value of the respective property; accordingly, the Company has not provided for a liability accrual. The estimated future costs for known environmental remediation requirements are accrued when it is probable that a liability has been incurred and the amount of remediation costs can be reasonably estimated. The Company is not aware of any such remediation requirements material to its operations.
Recent Accounting Pronouncements: In April 2002, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 145, "Revision of FASB Statements No. 4, 44 and 64, and Amendment of FASB Statement No. 13 and Technical Corrections". This Statement changes the presentation and reporting of extinguishments of debt on the Statement of Operations. The required adoption of this Statement in 2003 by the Company is not expected to have a material impact on its operating results or financial position.
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities". SFAS No. 146 requires that a liability for costs associated with an exit or disposal activity be recognized and measured initially at fair value and only when the liability is incurred. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002. The Company does not expect the adoption of SFAS 146 to have a material impact on its operating results or financial position.
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure - an Amendment of FASB Statement No. 123". This Statement provides guidance and transition rules for those companies electing to change their method of accounting for stock-based compensation. However, the statement does not require the change in accounting, and TXCO has elected to continue reporting stock-based compensation following SFAS No. 123 and Accounting Principles Board Opinion No. 25. SFAS No. 148 also requires certain enhanced disclosures regarding stock-based compensation, and such disclosures have been included in these footnotes to the financial statements.
Reclassifications: Certain amounts for 2001 and 2000 have been reclassified to conform to the 2002 presentation.
NOTE B - PROPERTY AND EQUIPMENT
Property and equipment consists of the following at December 31:
	2002		2001
Oil and gas properties	$56,994,583		$31,277,727
Other property and equipment	1,407,171		707,532
Total Property and Equipment	58,401,754		31,985,259
Accumulated depreciation, depletion and amortization	(17,585,395	)	(11,230,206	)
Reserve for impairment on unproved properties	(1,488,492	)	(861,313	)
Net Property and Equipment	$39,327,867		$19,893,740

THE EXPLORATION COMPANY
Notes to Audited Consolidated Financial Statements
Years Ended December 31, 2002, 2001 and 2000
NOTE C - LONG-TERM DEBT
Long-term debt consists of the following at December 31:
	2002		2001
Note payable to a financial institution under Bank Credit Facility   (see below), with interest at prime, monthly payments of interest   only, with final payment due in 2005, and collateralized by accounts   receivable and certain oil and gas properties.	$5,800,000		$       -
Note payable to financing companies, with interest   at 12.61%, due in monthly installments of $22,404, with final   payment in 2005, and collateralized by compressor equipment	540,885		728,435
Note payable to financing companies, with interest   at 11.85%, due in monthly installments of $834, with final   payment in 2005, and collateralized by office equipment.	20,931		27,992
Installment notes to insurance company, with interest from 5.25%   to 8.75%, due in current monthly installments of $17,025 with final   payment in 2003, and unsecured.	214,240		84,855
Note payable to a vendor, due in monthly installments of   $320,588, with final payment in 2003.	641,175		-
Note payable to financing companies, with interest at 22.96%, due   in monthly installments of $1,965, with final payment in 2002,   and collateralized by office equipment.	-		20,895
Total long-term debt	7,217,231		862,177
Less current portion	(1,073,773	)	(298,410	)
Long-term portion of debt	$6,143,458		$ 563,767
The following is a schedule of principal maturities of long-term debt as of December 31, 2002:
Year Ended December 31,	Amount
2003	$1,073,773
2004	247,484
2005	5,895,974
	$7,217,231

THE EXPLORATION COMPANY

Notes to Audited Consolidated Financial Statements

Years Ended December 31, 2002, 2001 and 2000

NOTE C - LONG-TERM DEBT - continued

Bank Credit Facility: On March 4, 2002 the Company entered into a $25 million oil and gas reserve based Revolving Credit Facility (the Facility) with Hibernia National Bank providing a credit line with an initial borrowing base set at $5 million. The borrowing base was subsequently increased to $13 million as of September 30, 2002, with quarterly reductions of $1 million. At December 31, 2002, the borrowing base was $12 million with an outstanding balance of $5.8 million, resulting in an unused borrowing base of $6.2 million. Interest is payable monthly, with principal due at maturity in March 2005. Uses of proceeds are for the acquisition and development of oil and gas properties and general corporate working capital purposes. The Facility provides the lender with semiannual scheduled redeterminations at mid-year and each subsequent anniversary date. The facility provides for two unscheduled redeterminations per year at the Company's discretion. Borrowin gs under the Facility are secured by a first priority mortgage covering the Company's working and other interests in the majority of its oil and gas leases. The interest rate under the facility will initially be based on the Wall Street Journal Prime Rate plus applicable margin. A Eurodollar Rate plus applicable margin may be utilized at the election of the Company. The interest rate at December 31, 2002, is 4.25%. The Facility also provides the lender with a commitment fee equal to 0.5% per annum on the unused borrowing base. The Facility contains certain financial covenants and other negative restrictions, which are customary for similar credit facilities. The Company is in compliance with all such covenants and negative restrictions.

Subsequent Installment Obligation: In January, 2003, the Company entered into an unsecured installment obligation related to additions to its oil and gas properties. Imputed interest due on the obligation is 4.25% per annum. Payments are due in two installments of $1,406,421 each in January 2004 and 2005.

NOTE D - STOCKHOLDERS' EQUITY

Preferred Stock: The Company has authorized 10,000,000 shares of preferred stock, none of which has been issued at December 31, 2002. Terms of the stock have not been established by the Board of Directors.

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 $14,051,893, net of offering costs of $946,112, to be used for oil and gas property acquisition and development, 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.

Stockholder Rights Plan: On June 29, 2000, the Company adopted a Rights Plan (the "Rights Plan") whereby a dividend of one preferred share purchase right (a "Right") was paid for each outstanding share of TXCO common stock. The Rights Plan is designed to enhance the Board's ability to prevent an acquirer from depriving stockholders of the long-term value of their investment and to protect shareholders against attempts to acquire the Company by means of unfair or abusive takeover tactics. The Rights will be exercisable only if a person acquires beneficial ownership of 15% or more of TXCO common stock (an "Acquiring Person"), or commences a tender offer which would result in beneficial ownership of 15% or more of such stock. When they become exercisable, each Right entitles the registered holder to purchase from TXCO .001 share of Series A Preferred Stock ("Series A Preferred Stock"), subject to adjustment under certain circumstances.

THE EXPLORATION COMPANY
Notes to Audited Consolidated Financial Statements
Years Ended December 31, 2002, 2001 and 2000
NOTE D - STOCKHOLDERS' EQUITY-continued
Upon the occurrence of certain events specified in the Rights Plan, each holder of a Right (other than an Acquiring Person) may purchase, at the Right's then current exercise price, shares of TXCO common stock having a value of twice the Right's exercise price. In addition, if, after a person becomes an Acquiring Person, TXCO is involved in a merger or other business combination transaction with another person in which TXCO is not the surviving corporation, or under certain other circumstances, each Right will entitle its holder to purchase, at the Right's then current exercise price, shares of common stock of the other person having a value of twice the Right's exercise price. The Rights Plan generally may be amended by the Company without the approval of the holders of the Rights prior to the public announcement by TXCO or an Acquiring Person that a person has become an Acquiring Person.
Unless redeemed by TXCO earlier, the Rights will expire on June 29, 2010. The Company will generally be entitled to redeem the Rights in whole, but not in part, at $0.01 per Right, subject to adjustment. No Rights were exercisable under the Rights Agreement at December 31, 2002.
Stock Repurchase: On June 27, 2001, the Company's Board of Directors approved a common share buyback program to purchase up to $2 million of the Company's common shares in the open market or privately negotiated treasury purchases. The timing and amount of these stock repurchases are determined at the discretion of management. During 2001, the Company purchased 99,800 shares of its common stock at a cost of $246,007 under this program. The Company did not purchase any common stock under this program during 2002.
Stock Based Employee Compensation Plan: The Company grants options to its officers, directors, and key employees under its 1995 Flexible Incentive Plan (The "Plan"), as amended. The Plan, as amended, is authorized to grant options to management, directors, and key employees for up to 1,700,000 shares of the Company's common stock. All options granted have ten year terms that vest and become fully exercisable based on the specific terms imposed at the date of grant.
Pro forma information included in Note A regarding net income and earnings per share as required by SFAS No. 123 is computed using a Black-Scholes option pricing model. The fair value for these options was estimated at the date of grant with the following weighted-average assumptions as of the year ended December 31:
	2002	2001	2000
Risk-free interest rate	3.12%	4.40%	5.11%
Expected dividend yield	0%	0%	0%
Expected volatility of common stock	.90	.79	.67
Expected weighted-average life of option	4 years	5 years	5 years
The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company's employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its employee stock options.

THE EXPLORATION COMPANY
Notes to Audited Consolidated Financial Statements
Years Ended December 31, 2002, 2001 and 2000
NOTE D - STOCKHOLDERS' EQUITY-continued
A summary of the status of the Company's stock option activity and related information is as follows:
	Shares		Wt.-Avg. Exercise Price	Wt.-Avg.           Fair Value of       Options Granted	Exercisable at End     of Period
Outstanding at December 31, 1999	1,208,800		2.66		389,800
Granted	375,000		2.98	$1.39
Exercised	-
Forfeited	(150,000	)	6.60
Outstanding at December 31, 2000	1,433,800		2.33		526,800
Granted	205,000		2.96	$1.82
Exercised	(25,000	)	1.25
Forfeited	(9,800	)	3.91
Outstanding at December 31, 2001	1,604,000		2.43		649,000
Granted	-		-	N/A
Exercised	(113,000	)	1.53
Forfeited	(28,000	)	2.96
Outstanding at December 31, 2002	1,463,000		2.49		999,500
The following table summarizes information about the options outstanding at December 31, 2002:

	Options Outstanding			Options Exercisable
Exercise Price	Number Outstanding	Wt.-Avg. Remaining Contractual Life	Wt.-Avg. Exercise Price	Number Exercisable	Wt.-Avg. Exercisable Price
$0.98	25,000	5.83 years	$0.98	25,000	$0.98
1.25	8,000	5.68 years	1.25	8,000	1.25
2.12	728,000	5.64 years	2.12	428,000	2.12
2.62	50,000	3.68 years	2.62	50,000	2.62
2.75	100,000	2.12 years	2.75	100,000	2.75
2.78	75,000	7.40 years	2.78	50,000	2.78
2.96	177,000	8.59 years	2.96	88,500	2.96
3.09	300,000	6.08 years	3.09	250,000	3.09
	1,463,000		$2.49	999,500	$2.53

THE EXPLORATION COMPANY
Notes to Audited Consolidated Financial Statements
Years Ended December 31, 2002, 2001 and 2000
NOTE D - STOCKHOLDERS' EQUITY-continued
Stock Warrants: The following is a summary of warrants outstanding at December 31, 2002:
Purpose of Warrants	Number   of Shares	Range of     Prices	Wt.-Avg.   Exercise   Price	Wt.-Avg.   Remaining   Contracutal   Life
Convertible notes and equity financing   (convertible notes subsequently paid     in full)	1,566,429	$2.88 - $6.00	$3.06	2 years
NOTE E - EARNINGS PER SHARE
The following is a reconciliation of the numerator and denominator of the basic and diluted earnings per share computation:
			Income	Per Share
		Shares	(Loss)	Amount
Year Ended December 31, 2002:
Basic EPS:
Net income		19,080,847	$ (310,970)	$(0.016)
Effect of dilutive options		-	-	-
Dilutive EPS		19,080,847	$ (310,970)	$(0.016)
Year Ended December 31, 2001:
Basic EPS:
Net income		17,441,242	$  (50,283)	$(0.003)
Effect of dilutive options		-	-	-
Dilutive EPS		17,441,242	$  (50,283)	$(0.003)
Year Ended December 31, 2000:
Basic EPS:
Net income		17,242,326	$6,761,935	$  0.392
Effect of dilutive options		101,631	-	(0.002)
Dilutive EPS		17,343,957	$6,761,935	$  0.390
The 2002 and 2001 loss per share does not include the effect of options and warrants as their impact would be antidilutive.

THE EXPLORATION COMPANY
Notes to Audited Consolidated Financial Statements
Years Ended December 31, 2002, 2001 and 2000
NOTE F - OPERATING LEASES
The Company leases its primary office space through August, 2007 and certain oil field equipment through November, 2006. The Company incurred rent expense of $170,000 in 2002, $146,000 in 2001 and $133,000 in 2000. Future minimum rentals under all noncancelable leases are as follows:
	Year Ended December 31,			Amount
	2003	$300,000
	2004	303,000
	2005	307,000
	2006	307,000
	2007	179,000
NOTE G - INCOME TAXES
The tax benefit in 2002 resulted from a reversal of the current expense recorded in 2001 due to certain changes in the federal income tax regulations enacted in March, 2002. The components of the Company's income taxes were as follows for the years ended December 31:
			2002			2001		2000
Current federal tax benefit (expense)			$75,000			$(75,000	)	$   (90,918	)
Deferred federal tax benefit (expense)			-			-		5,232,718
Income tax benefit (expense)			$75,000			$(75,000	)	$5,141,800
The following items give rise to the deferred tax assets and liabilities:
			2002			2001
Deferred tax assets:
Tax net operating loss carryforwards			$4,600,000			$4,860,000
Impairment of oil and gas properties			3,400,000			3,010,000
Net deferred tax assets			8,000,000			7,870,000
Less valuation allowance			(2,767,282		)	(2,637,282	)
Deferred income tax asset recorded			$5,232,718			$5,232,718

THE EXPLORATION COMPANY
Notes to Audited Consolidated Financial Statements
Years Ended December 31, 2002, 2001 and 2000
NOTE G - INCOME TAXES - continued
The Company's available net operating loss carryforwards ("NOLs") of approximately $13,600,000 ($4,600,000 tax benefit) at December 31, 2002, expire from 2008 to 2019. Realization of deferred tax assets associated with the NOLs is dependent upon generating sufficient taxable income prior to their expiration. The Company believes that there is a risk that certain of these NOLs may expire unused and, accordingly, has a valuation allowance of $2,761,282 against the carryforwards at December 31, 2002. Although realization is not assured for the remaining deferred tax asset, the Company believes it is more likely than not that they will be realized through future taxable earnings. However, the net deferred tax assets could be reduced further if the Company's estimate of taxable income in future periods is significantly reduced.
The differences between the expected federal income taxes and the Company's actual taxes are as follows:
		2002				2001			2000
Expected federal tax benefit (expense)		$131,000				$   (3,700		)	$ (551,000		)
Change in valuation allowance		-				(730,000		)	6,388,718
Other changes		(56,000		)		658,700			(695,918		)
Net tax benefit (expense)		$  75,000				$  (75,000		)	$5,141,800
NOTE H - MAJOR CUSTOMERS
Sales to unrelated entities which individually comprised greater than 10% of total oil and gas sales are as follows:
	A		B		C		D			E
Year ended December 31, 2002	42%		18%		25%		11%			-
Year ended December 31, 2001	-		30%		57%		-			< 10%
Year ended December 31, 2000	-		28%		26%		-			18%

THE EXPLORATION COMPANY
Notes to Audited Consolidated Financial Statements
Years Ended December 31, 2002, 2001 and 2000
NOTE I - OIL AND GAS PRODUCING ACTIVITIES AND PROPERTIES
Capitalized Costs and Costs Incurred Relating to Oil and Gas Activities
The Company's investment in oil and gas properties is as follows at December 31:
		2002				2001
Proved properties		$38,733,563				$18,730,849
Less accumulated depreciation,     depletion and amortization		(17,025,745		)		(10,849,797	)
Net proved properties		21,707,818				7,881,052
Unproved properties:
Coalbed methane properties		7,009,569				5,962,313
Drilling in-progress		4,298,087				859,195
Oil and gas leasehold acreage		6,953,364				5,725,370
Total unproved properties		18,261,020				12,546,878
Less reserve for impairment		(1,488,492		)		(861,313	)
Net unproved properties		16,772,528				11,685,565
Net capitalized cost		$38,480,346				$19,566,617
A reserve for impairment on the Company's proved properties, previously reported as separate line item on the above schedule, has been reclassified in 2001 to adjust the proved property cost to its new basis after consideration of the impairment.
Costs incurred, capitalized, and expensed in oil and gas producing activities are as follows for the years ended December 31:
	2002		2001		2000
Property acquisition costs, unproved	$ 5,866,791		$ 1,627,967		$ 2,319,285
Property development and exploration costs:
Conventional oil and gas properties	14,117,482		11,168,228		5,039,101
Coalbed methane properties	1,047,256		4,880,853		1,081,460
Gathering system	5,649,181		94,270		1,347,505
Depreciation, depletion and amortization	6,306,511		3,040,932		2,625,924
Depletion per equivalent Mcf of production	1.44		1.02		.79

THE EXPLORATION COMPANY
Notes to Audited Consolidated Financial Statements
Years Ended December 31, 2002, 2001 and 2000
NOTE I - OIL AND GAS PRODUCING ACTIVITIES AND PROPERTIES - continued
Oil and Gas Reserves (Unaudited)
The estimates of the Company's proved reserves and related future net cash flows that are presented in the following tables are based upon estimates made by independent petroleum engineering consultants.
The Company's reserve information was prepared as of each respective period end. The Company cautions that there are many inherent uncertainties in estimating proved reserve quantities, projecting future production rates, and timing of development expenditures. Accordingly, these estimates are likely to change, as future information becomes available. Proved developed reserves are the estimated quantities of crude oil, condensate, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
The Company has not yet established any reserves related to its coalbed methane properties in the tables below. This project is still in the dewatering phase, which must be completed before economic quantities of natural gas production may be realized and reserves estimated. Changes in estimated net quantities of conventional oil and gas reserves, all of which are located within the United States, are as follows for the years ended December 31:
	2002		2001		2000
Proved developed and undeveloped reserves:
Natural gas (Mcf):
Beginning of year	10,976,000		4,532,000		5,823,000
Extensions and discoveries	5,103,000		8,664,000		2,126,000
Reserves purchased	-		-		-
Production	(2,487,000	)	(2,673,000	)	(2,965,000	)
Revisions of previous estimates	1,083,000		453,000		(452,000	)
End of year	14,675,000		10,976,000		4,532,000
Crude Oil (Bbls):
Beginning of year	294,000		183,000		93,000
Extensions and discoveries	600,000		66,000		5,000
Reserves purchased	674,000		-		-
Production	(314,000	)	(50,000	)	(60,000	)
Revisions of previous estimates	225,000		95,000		145,000
End of year	1,479,000		294,000		183,000
Proved developed reserves
Natural gas (Mcf):
Beginning of year	5,102,000		4,532,000		5,823,000
End of year	6,213,000		5,102,000		4,532,000
Crude Oil (Bbls):
Beginning of year	133,000		183,000		93,000
End of year	988,000		133,000		183,000

THE EXPLORATION COMPANY
Notes to Audited Consolidated Financial Statements
Years Ended December 31, 2002, 2001 and 2000
NOTE I - OIL AND GAS PRODUCING ACTIVITIES AND PROPERTIES - continued
The following table sets forth a standardized measure of the estimated discounted future net cash flows attributable to the Company's proved developed and undeveloped oil and gas reserves. Prices used to determine future cash inflows were based on the respective year end weighted average sales prices utilized for the Company's proved developed reserves which were $4.90, $2.72 and $11.04 per Mcf of gas and $28.71, $17.70 and $25.67 per barrel of oil as of December 31, 2002, 2001 and 2000. The future production and development costs represent the estimated future expenditures to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expense was computed by applying statutory income tax rates to the difference between pretax net cash flows relating to the Company's reserves and the tax basis of proved oil and gas properties and available operating losses and temporary differences. The standard meas ure is as follows for the years ended December 31:
	2002			2001		2000
Future cash inflows	$114,337,000			$35,359,000		$54,747,000
Future production and development costs	(49,207,000		)	(16,331,000		(10,516,000	)
Future net cash inflows before income tax	65,130,000			19,028,000		44,231,000
Future income tax expense	(10,400,000		)	-		(6,045,000	)
Future net cash flows	54,730,000			19,028,000		38,186,000
10% annual discount to reflect timing of     net cash flows	(16,583,000		)	(5,045,000	)	(6,226,000	)
Standardized measure of discounted future     net cash flows relating to proved reserves	$  38,147,000			$13,983,000		$31,960,000
The principal factors comprising the changes in the standardized measure of discounted future net cash flows is as follows for the years ended December 31:
		2002		2001		2000
Standardized measure, beginning of year		$13,983,000		$31,960,000		$10,099,000
Extensions and discoveries		27,024,000		8,505,000		5,936,000
Reserves purchased		4,645,000		-		-
Sales and transfers, net of production costs		(10,838,000	)	(9,985,000	)	(11,693,000	)
Revisions in quantity and price estimates		11,966,000		(15,881,000	)	31,208,000
Net change in income taxes		(7,235,000	)	2,580,000		(2,580,000	)
Accretion of discount		(1,398,000	)	(3,196,000	)	(1,010,000	)
Standardized measure, end of year		$38,147,000		$13,983,000		$31,960,000

THE EXPLORATION COMPANY
Schedule II - Valuation and Qualifying Reserves
	Balance  Beginning of Period	Charged to Costs and  Expense	Deductions		Balance  End of   of Period
Year Ended December 31, 2002
Allowance for doubtful accounts,     trade accounts	$    27,000	$       -	$       -		$    27,000
Impairment of oil and gas properties	861,313	627,179	-		1,488,492
Deferred tax asset valuation allowance	2,637,282	130,000	-		2,767,282
Year Ended December 31, 2001
Allowance for doubtful accounts,     trade accounts	$    27,000	$       -	$       -		$    27,000
Impairment of oil and gas properties	2,085,351	2,627,705	(3,851,743	)	861,313
Deferred tax asset valuation allowance	1,907,282	730,000	-		2,637,282
Year Ended December 31, 2000
Allowance for doubtful accounts,     trade accounts	$    27,000	$       -	$       -		$    27,000
Impairment of oil and gas properties	481,477	1,603,874	-		2,085,351
Deferred tax asset valuation allowance	8,296,000	-	(6,388,718	)	1,907,282

EX-10

Exhibit 10.12

LOAN AGREEMENT (LINE OF CREDIT)

THIS LOAN AGREEMENT ("Agreement"), dated as of March 4, 2002, is made between THE EXPLORATION COMPANY OF DELAWARE, INC., a Delaware corporation ("Borrower"), and HIBERNIA NATIONAL BANK, a national banking association ("Lender"), who agree as follows:

ARTICLE 1

GENERAL TERMS

Section 1.1  Terms Defined Above. As used in this Agreement, the terms "Agreement", "Borrower", and "Lender", shall have the meanings indicated above.

Section 1.2  Certain Definitions. As used in this Agreement, the following terms shall have the meanings indicated (and as provided in Section 9.14), unless the context otherwise requires:

"Advances" shall mean the borrowings on the Closing Date under the Loan and all or any portion of such borrowings and other or subsequent reborrowings under the Loan so long as same remain outstanding and unpaid.

"Amount" shall mean five million ($5,000,000.00) dollars. Although the face amount of the initial Note under this Agreement is twenty five million ($25,000,000.00) dollars, the Amount (and hence the Commitment Limit) is acknowledged by Borrower to be a lesser number, subject to one or more future increases by the Lender in its sole discretion in conjunction with any future increases in the Borrowing Base and further bank management approvals.

"Base Rate" shall mean, for any day, an interest rate per annum equal to the Prime Rate in effect on such day plus the Applicable Prime Rate Margin (as defined below). The "Applicable Prime Rate Margin" shall mean the following per annum interest rate from time to time, determined for each fiscal quarter by reference to the Percentage Outstanding for the immediately prior fiscal quarter, in accordance with the following schedule:

Percentage Outstanding	Applicable Prime Rate Margin
less than 1/3	0%
1/3 to 2/3	0%
above 2/3	0.25%
The Applicable Prime Rate Margin shall remain fixed during each fiscal quarter of the Borrower's fiscal year, determined on the first day of each fiscal quarter depending upon the Percentage Outstanding for the immediately prior quarter. (During the first partial quarter of this Agreement, commencing on the Closing Date, the Applicable Prime Rate Margin shall be zero (0%) percent). Without notice to the Borrower, the Base Rate shall change automatically from time to time as and in the amount by which the Prime Rate shall fluctuate, with each such change in the Base Rate to be effective as of the date of each change in the Prime Rate, adjusted daily.

"Borrowing Base" shall mean, at any time, the dollar amount calculated as the maximum loan value of the Collateral as determined by the Lender in its sole discretion, but based upon the Lender's customary standards and practices from time to time in effect with respect to secured oil and gas property lines of credit in determining the discounted present value of the Collateral's production and the Borrower's cash flows. Any good faith determination by the Lender of the Borrowing Base shall be final and conclusive. The Borrowing Base may be revised by Lender at any time to reflect changes in the Collateral or the occurrence of events or economic conditions or otherwise pursuant to Lender's customary standards and practices as such exist at that particular time, and further will be subject to scheduled semi-annual redeterminations during the term of this Loan. Additionally, the Borrower may request twice per any twelve month period (commencing 90 days after the Closing Date) that an unscheduled redetermi nation be done by Lender, subject to Borrower's payment to Lender of a fee in accordance with the then applicable fee schedule established by Lender from time to time in its sole discretion. The Lender shall notify the Borrower of the result of each Borrowing Base redetermination by the Lender at least fifteen (15) days before its effective date. Each determination of the Borrowing Base shall be effective until redetermined by the Lender in accordance with this Agreement. Such redetermination by the Lender may lead to increased or decreased credit availability to the Borrower under the revised Borrowing Base schedule. Without limiting the foregoing, the Lender may exclude, in its sole and

absolute discretion, any property or portion of production therefrom from the Borrowing Base, at any time, because title information on, or the status of title to, such property is not reasonably satisfactory to Lender, such property is not Collateral, the Lender's Lien therein is not first and prior to all others, such property is subject to contractual agreements or commitments not reasonably satisfactory to Lender, or such property is not assignable. On the Closing Date, the Borrowing Base is $5,000,000.00.

"Business Day" shall mean (a) for all purposes other than as covered by clause (b) of this definition, a day other than a Saturday, Sunday or legal holiday for commercial banks in either New Orleans, Louisiana, or New York, New York, and (b) with respect to all requests, notices and determinations in connection with LIBO Rate Loans, a day which is a Business Day described in clause (a) of this definition and which is a day for trading by and between banks for dollar deposits in the London interbank market.

"Closing Date" shall mean the date on which the Note is executed and delivered by the Borrower to the Lender.

"Code" shall mean the Internal Revenue Code of 1986, as amended.

"Collateral" shall mean the properties and property rights described in the Collateral Documents described in Section 3.1 as primary security for the Indebtedness.

"Collateral Documents" shall mean collectively the documents from time to time required by the Lender to obtain the security interest in the Collateral, or otherwise guarantee or secure the Indebtedness, such documents which exist on the Closing Date being described in Article 3 hereof, as all such documents are amended, restated or renewed from time to time.

"Commitment Limit" shall mean, at any particular date, the lesser of (x) the Amount or (b) the Borrowing Base as most recently determined and in effect.

"Contracts" shall mean those agreements, contracts and other instruments to which the Borrower's interest in the oil, gas and mineral leases comprising the Collateral are subject.

"Debt" shall mean any and all amounts and/or liabilities owing from time to time by the Borrower to any Person, including the Lender, direct or indirect, liquidated or contingent, now existing or hereafter arising, including without limitation (i) indebtedness for

borrowed money or the deferred purchase price of property; (ii) unfunded portions of commitments for money to be borrowed; (iii) the amounts of all standby and commercial letters of credit and bankers acceptances, matured or unmatured, issued on behalf of the Borrower, and (without duplication) all drafts drawn thereon; (iv) guaranties of the obligations of any other Person, whether direct or indirect, whether by agreement to purchase the indebtedness of any other Person or by agreement for the furnishing of funds to any other Person through the purchase or lease of goods, supplies or services (or by way of stock purchase, capital contribution, advance or loan) for the purpose of paying or discharging the indebtedness of any other Person, or otherwise; (v) indebtedness of the types described above secured by any Lien on any property owned by the Borrower, to the extent attributable to the Borrower's interest in such property, even though the Borrower has not assumed or become liable for the payment thereo f personally; (vi) the present value of all obligations for the payment of rent or hire of property of any kind (real or personal) under leases or lease agreements required to be capitalized under generally accepted accounting principles, (vii) trade payables and operating leases incurred in the ordinary course of business or otherwise; and (viii) Hedging Obligations.

"Default" shall mean the occurrence of any of the events specified in Article 8 hereof, whether or not any requirement for notice or lapse of time or other condition precedent has been satisfied.

"Default Rate" shall mean, on any particular date, the Prime Rate plus five (5%) percent per annum.

"ERISA" shall mean the Employee Retirement Income Security Act of 1974, as amended.

"Event of Default" shall mean the occurrence of any of the events specified in Article 8 hereof, provided that any requirement for notice or lapse of time or any other condition precedent has been satisfied.

"Hedge Agreement" means any agreement or arrangement providing for payments which are related to, or the value of which is dependent upon, fluctuations of interest rates, currency exchange rates or forward rates, or fluctuations of commodity prices, including without limitation any swap agreement, cap, collar, floor, exchange transaction, forward agreement or exchange or protection agreement or similar futures contract or swap or other derivative agreement related to interest rates, currency exchange rates or

hydrocarbons or other commodities, or any option with respect to such transaction.

"Hedging Obligations" of a Person means any and all obligations of such Person, whether absolute or contingent and howsoever and whensoever created, arising or evidenced (including all renewals, extensions and modifications thereof and substitutions therefor), under any and all Hedge Agreements and any and all cancellations, buybacks, reversals, terminations or assignments of any Hedge Agreement.

"Indebtedness" shall mean any and all amounts, liabilities or obligations owing from time to time by the Borrower to the Lender (or any transferee of the Loan), including without limitation any such amounts, liabilities or obligations pursuant to this Agreement, the Note and the Collateral Documents (including attorneys' fees incurred in connection with the execution, enforcement or collection of the Borrower's obligations hereunder or thereunder or any part thereof) or any Hedging Obligations, and whether such amounts, liabilities or obligations be liquidated or unliquidated, now existing or hereafter arising.

"LIBO Rate" shall mean, during any Interest Period (as defined below) for any Advance, an interest rate per annum equal to the Reserve Adjusted LIBO Rate (as defined below) plus the Applicable LIBO Rate Margin (as defined below). "Reserve Adjusted LIBO Rate" shall mean with respect to each Interest Period for a LIBO Rate Advance, an interest rate per annum equal to the quotient (converted to a percentage, rounded upward to the nearest whole multiple of 1/100 of 1% per annum) of (i) the rate per annum as determined by the Lender at or about 10:00 a.m. Central Time (or as soon thereafter as practicable) on the second Business Day prior to the first day of each Interest Period, to be the annual rate of interest for deposits in United States dollars for the selected Interest Period as shown on the Dow Jones Telerate Matrix page for British Bankers Association Interest Settlement Rates as of two Business Days prior to the first day of such Interest Period, divided by (ii) the remainder of 1.00 minus the LIBOR Reserve Requirement (as defined below), expressed as a decimal, for such Interest Period. "LIBOR Reserve Requirement" shall mean for any day during an Interest Period for any LIBO Rate Advance, that percentage which is specified by the Board of Governors of the Federal Reserve System (or any successor) for determining the maximum reserve requirement (including, but not limited to, any marginal reserve requirement) for the Lender with respect to liabilities consisting of or including "Eurocurrency

liabilities" (as defined in Regulation D of the Board of Governors of the Federal Reserve System) with a maturity equal to such Interest Period. In determining this percentage, the Lender may use any reasonable averaging and attribution method. "Interest Period" shall mean the period between the Business Day on which the LIBO Rate shall begin and the day on which the LIBO Rate shall end. The duration of each Interest Period for a LIBO Rate Advance shall be one (1) month, two (2) months, three (3) months or six (6) months, at the Borrower's election, subject to the following: (i) no Interest Period shall extend past the Maturity Date; (ii) whenever the last day of any Interest Period would otherwise occur on a day other than a Business Day, the last day of such Interest Period shall be extended to occur on the next succeeding Business Day, except that if the next succeeding Business Day would occur in the next following calendar month, the last day of such Interest Period shall be shortened to occur on the next preceding Business Day; (iii) whenever the first day of any Interest Period occurs on a day of an initial calendar month for which there is no numerically corresponding day in the calendar month that succeeds such initial calendar month by the number of months in such Interest Period, such Interest Period shall end on the last Business Day of such succeeding calendar month; and (iv) if the Borrower fails to designate an Interest Period, the Interest Period for a LIBO Rate Advance (recognizing that under Subsection 2.1(b) below the Lender is not obligated to make such a LIBO Rate Advance in the absence of such designation by the Borrower) shall be deemed to be one month until a different designation is made for a subsequent Interest Period. No Interest Period for a LIBO Rate Advance shall have a duration of less than one month, and if any such Interest Period would otherwise be a shorter period, the relevant Advance shall be a Base Rate Advance during such period. The "Applicable LIBO Rate Margin" shall mean the following per annum interest rate from time to time, determined for each fiscal quarter by reference to the Percentage Outstanding for the immediately prior fiscal quarter, in accordance with the following schedule:

Percentage Outstanding	Applicable LIBO Rate Margin
less than 1/3	2.75%
1/3 to 2/3	3.00%
above 2/3	3.25%
The Applicable LIBO Rate Margin shall remain fixed during each fiscal quarter of the Borrower's fiscal year, determined on the first day of each fiscal quarter depending upon the Percentage
Outstanding for the immediately prior quarter. (During the first partial quarter of this Agreement, commencing on the Closing Date, the Applicable LIBO Rate Margin shall be three (3%) percent.) No more than four (4) LIBO Rate tranches at any one time are permitted for the Note. The Borrower will comply with the provisions of Addendum I hereto, relating to the LIBO Rate, which is an integral part of this Agreement. The LIBO Rate shall remain fixed for the duration of the LIBO Rate Interest Period selected. The Borrower shall not have the right to voluntarily prepay Advances outstanding at the LIBO Rate prior to the end of the applicable LIBO Rate Interest Period.
"Lien" shall mean any interest in property securing an obligation owed to, or a claim by, a Person other than the owner of the property, whether such interest is based on jurisprudence, statute or contract, and including but not limited to the lien or security interest arising from a mortgage, encumbrance, pledge, security agreement, production payment, conditional sale or trust receipt or a lease, consignment or bailment for security purposes. The term "Lien" shall include reservations, exceptions, encroachments, easements, servitudes, usufructs, rights-of-way, covenants, conditions, restrictions, leases, and other title exceptions and encumbrances affecting property. For the purposes of this Agreement, the Borrower shall be deemed to be the owner of any property which it has accrued or holds subject to a conditional sale agreement, financing lease or other arrangement pursuant to which title to the property has been retained by or vested in some other Person for security purposes.
"Loan" shall mean the line of credit as described in Article 2
hereof.
"Loan Excess" shall mean, at any point in time, the amount, if any, by which the outstanding principal balance of the Advances plus the face amount of all outstanding standby letters of credit issued pursuant to this Agreement exceeds the Commitment Limit then in effect.
"Maturity Date" shall mean the third anniversary of the Closing Date, or such earlier date on which the Loan is accelerated pursuant to Section 8.2 hereof.
"Note" shall mean the note described in Section 2.1(a) hereof.
"Paloma Pipeline" shall mean Paloma Pipeline, L.P., a Texas limited partnership.
"PPL Operating" shall mean PPL Operating, Inc., a Texas corporation.
"Percentage Outstanding" shall mean, for any fiscal quarter (or lesser time period as applicable), the fraction obtained by dividing (x) the average unpaid and outstanding principal balance of the Advances under the Note during such quarter, by (y) the average of the Commitment Limit for such quarter.
"Permitted Hedge Agreement" shall mean any Hedge Agreement related to either (i) Borrower's production and sale of its hydrocarbons or (ii) interest rates pertaining to the Loan, in each case which the Borrower enters into (x) in the ordinary course of business as part of its normal business operations with the purpose and effect of fixing prices or hedging variable interest rates as a risk-management strategy, and not for purposes of speculation and
not intended primarily as a borrowing of funds, and (y) with any Person reasonably acceptable to the Lender.

"Person" shall mean any individual, corporation, limited liability company, partnership, joint venture, association, joint stock company, trust, unincorporated organization, government or any agency or political subdivision thereof, or any other form of entity.

"Plan" shall mean any plan subject to Title IV of ERISA and maintained by the Borrower, or any such plan to which the Borrower is required to contribute on behalf of its employees.

"Prime Rate" shall mean, at any particular date, the prime or base rate as reflected in The Wall Street Journal (or if such rate is not published or is no longer available, such other index satisfactory to Lender). Without notice to the Borrower, the Prime Rate shall change automatically from time to time as and in the amount by which said index rate shall fluctuate, with each such change in the Prime Rate to be effective as of the date of each change in such index rate. The Wall Street Journal index rate is a reference rate and does not necessarily represent the lowest or best rate actually charged to any customer by Lender (or by such institutions comprising said index).

"Subsidiary" shall mean each corporation of which the Borrower owns, directly or indirectly, fifty percent or more of the outstanding capital stock, and each partnership, limited liability company or other Person of which the Borrower owns, direct or indirect, fifty percent (50%) or more of the outstanding partnership, membership or other ownership or voting interest.

Section 1.3  Accounting Terms. Unless otherwise specified herein, all accounting terms used herein shall be interpreted, all accounting determinations hereunder shall be made, and all financial statements required to be delivered hereunder shall be prepared in accordance with generally accepted accounting principles as in effect from time to time on a basis consistent (except for changes in accounting principles or practice approved by independent public accountants for the Borrower) with the most recent financial statements of the Borrower.

ARTICLE 2

THE CREDIT

Section 2.1  Line of Credit and Letters of Credit. (a) Line of Credit. Subject to and upon the terms and conditions contained in this Agreement, and relying on the representations and warranties contained in this Agreement, on the Closing Date the Lender agrees to make a revolving line of credit available to the Borrower, including the face amount of all standby letters of credit permitted to be issued under this Agreement, in the maximum aggregate principal amount equal to the Commitment Limit. The line of credit is represented by a promissory note in the principal amount of the twenty five million ($25,000,000.00), payable to the order of the Lender. Principal and all accrued and unpaid interest on the line of credit shall be payable in full on the Maturity Date, after which no further Advances will be made. Payments may be debited from the Borrower's accounts at the Lender as provided in this Agreement.

(b)  Interest. The interest rate applicable to each Loan Advance beginning on the date such Advance is made shall be either (i) the Base Rate, adjusted daily, or (ii) the LIBO Rate, adjusted on the first day of each LIBO Rate Interest Period and remaining fixed for the duration of the LIBO Rate Interest Period, selected at the Borrower's option by written notice to Lender in accordance with the terms hereof. Effective on the first day following the end of any LIBO Rate Interest Period, the Borrower may from time to time change the interest rate which is to apply to the Advances or a portion thereof (including any yet to be made Advance which is

made on the effective date of the interest rate change) by notifying the Lender of the Borrower's desire to change the interest rate not less than three (3) Business Days prior to the date on which such change shall be effective. No more than four (4) LIBO Rate tranches and one Base Rate tranche (all Base Rate Advances constituting one tranche) shall be permitted for the Note at any one time. In the absence of any timely specific interest rate election by the Borrower (as provided above in this Subsection 2.1(b) and in the definition of LIBO Rate), unless otherwise agreed by the Lender, an Advance (if outstanding as a LIBO Rate Advance) will be automatically converted into a Base Rate Advance on the last day of the then current LIBO Rate Interest Period for such Advance or (if not then outstanding) an Advance shall bear interest at the Base Rate. The Borrower further will comply with the provisions of Addendum I hereto, relating to the LIBO Rate, which is an integral part of this Agree ment. Interest on the Note shall be payable (x) on Advances bearing interest at the Base Rate monthly in arrears on the last day of each month, and (y) on LIBO Rate Advances monthly in arrears on the last day of each month (notwithstanding the applicable LIBO Rate Interest Period for each LIBO Rate Advance). Interest on (i) Base Rate Advances and all other Indebtedness except for LIBO Rate Advances shall be calculated on the basis of a 365 (or in a leap year 366) day year and the actual number of days elapsed, and (ii) on LIBO Rate Advances shall be calculated on the basis of a 360-day year by applying the ratio of the annual interest rate over a year of 360 days, times the applicable principal balance, times the actual number of days such applicable principal balance is outstanding. Payments may be debited from the Borrower's accounts at the Lender as provided in this Agreement.

(c)  Draw Requests. In accordance with the provisions in this Section, the Lender will make Advances to the Borrower from time to time on any Business Day on and after the Closing Date until and including the last Business Day before the Maturity Date in such amounts as the Borrower may request, up to the Commitment Limit, and the Borrower may make borrowings, repayments and reborrowings in respect thereof. Requests for Advances must be made by written notice from the Borrower sent to the Lender by mail, courier or facsimile in accordance with Section 9.1, specifying the amount of the Advance. A request shall be fully authorized by the Borrower if made by any one of the Persons hereby designated by the Borrower as an authorized person in accordance with resolutions of the Board of Directors of the Borrower certified to the Lender. The Lender may rely fully and completely upon the authority of the signatory of such request or confirmation unless such authority is terminated by written notice to the Lender, and any such termination shall be effective only prospectively. The request for any Advance by the Borrower shall constitute a certification by the Borrower that all of the representations and warranties contained in Article 4 (other than those representations and warranties, if any, that are by their specific terms limited in application to a specific date) are true and correct as of the date of such request and also as of the date of the Advance.

(d)  Timing After the Lender's receipt of an authorized request for Advance, the Lender will make such Advance for the benefit of the Borrower in same day funds as provided below upon fulfillment of the applicable conditions set forth in this Agreement. Requests for Advances at the Base Rate shall be made on written notice from the Borrower to the Lender, received by the Lender no later than 11:00 a.m. (Central Time) on the first Business Day before such Base Rate Advance specifying the amount thereof. Request for Advances at the LIBO Rate shall be made on written notice from the Borrower to the Lender received by the Lender no later than 11:00 a.m. (Central Time) on the third (3rd) Business Day before such LIBO Rate Advance, specifying the amount thereof (including the amount of each tranche, if more than one) and the LIBO Rate Interest Period (or Interest Periods, if more than one tranche). Each such written notice by the Borrower shall be irrevocable by the Borrower. Not l ater than 3:00 p.m. (Central Time) on the date properly and timely requested for the Advance and upon fulfillment of the applicable conditions set forth in Article 7 of this Agreement, the Lender will make such Advance available to the Borrower in same day funds in the disbursement deposit account maintained by the Borrower with the Lender. The Borrower irrevocably agrees in favor of the Lender that the deposit of the proceeds of any Advance in any account of Borrower with the Lender shall be deemed prima facie evidence of the Borrower's Indebtedness to the Lender under the Loan.

(e)  Minimum. Notwithstanding anything in this Agreement to the contrary, the aggregate principal amount of all LIBO Rate Advances having the same LIBO Rate Interest Period shall be at least equal to $100,000.00; and if any LIBO Rate tranche would otherwise be in a lesser principal amount for any period, such tranche shall bear interest at the Base Rate during such period.

(f)  Letters of Credit. As a portion of the line of credit availability (and subject to the Commitment Limit and the other terms and conditions of this Agreement), the Lender will issue standby letters of credit for the account of the Borrower. The expiration of such letters of credit shall not extend beyond the Maturity Date of the line of credit. The fee for a standby letter of credit shall be at the per annum rate equal to the Applicable LIBO Rate Margin then in effect on the face amount of the letter of credit for the period from the letter of credit's issuance to the expiration date, paid quarterly in arrears on each September 30, December 31, March 31 and June 30, plus additional amounts customarily charged by the Lender for the issuance and processing of letters of credit. The Borrower shall submit an application for each letter of credit on the Lender's standard form. Such letters of credit will be documented on the Lender's standard form. No letter of credit will be issued if the face amount thereof plus the aggregate of all Advances then outstanding plus the face amount of all standby letters of credit then outstanding would exceed the Commitment Amount. Payment by the Lender of a draw on a standby letter of credit shall be an Advance as part of the Loan bearing interest from the date of such draw, notwithstanding the Commitment Limit.

Section 2.2  Business Days. If the date for any payment, prepayment or fee payment hereunder falls on a day which is not a Business Day, then for all purposes of this Agreement (unless otherwise provided herein) the same shall be deemed to have fallen on the next following Business Day, and such extension of time shall in such case be included in the computation of payments of interest.

Section 2.3  Payments. The Borrower shall make each payment hereunder and under the Note and any Collateral Documents in lawful money of the United States of America in same day funds to the Lender at its main office in New Orleans, Louisiana, not later than 11:00 a.m. (Central Time) on the day when due, or such other place in the United States as designated in writing by the Lender. The Borrower hereby authorizes the Lender to charge from time to time against the Borrower's deposit accounts with the Lender any amount which is then so due, and acknowledges that such accounts will be established for that purpose (among other purposes) under Section 5.16 and may be so used even in the absence of an Event of Default.

Section 2.4   Prepayment. (a) Voluntary. The Borrower may prepay the Loan in full or in part at any time without payment of premium or penalty; provided, however, that (i) the Borrower shall give the Lender notice of each such prepayment of all or any portion of a LIBO Rate Advance no less than three (3) Business Days prior to prepayment, (ii) any LIBO Rate Advance may be prepaid only on the last day of the Interest Period for such LIBO Rate Advance, (iii) the Borrower shall give the Lender notice of each such prepayment of all or any portion of a Base Rate Advance no less than one (1) Business Day prior to prepayment, (iv) the Borrower shall pay all accrued and unpaid interest on the amounts prepaid, and (v) no such prepayment shall serve to postpone the repayment when due of any other Indebtedness.

(b)  Mandatory. The Lender shall notify the Borrower of the result of each Borrowing Base redetermination by the Lender. If at any time the Lender determines that a Loan Excess exists, then within thirty (30) days of receipt by the Borrower of notice of such Loan Excess the Borrower shall (x) prepay the Advances (together with accrued interest on the amount to be prepaid to the date of payment) in an amount sufficient to reduce the Advances plus the face amount of all standby letters of credit then outstanding to the then Commitment Limit, and/or (y) execute, deliver and record or cause to be executed and delivered such additional Collateral Documents pursuant to Section 2.1, sufficient to induce the Lender to make an increased redetermination of the Borrowing Base to an amount not less than the outstanding principal balance of the Advances plus the face amount of all standby letters of credit then outstanding. The Borrower specifically acknowledges that no additional grace pe riod (beyond the period stated in the preceding sentence) is applicable under this Agreement to any failure to make such mandatory prepayment before such failure is an Event of Default hereunder.

Section 2.5  Fees. (a) The Borrower shall pay the Lender a commitment fee in the amount equal to $25,000.00 (0.50% of the Amount of $5,000,000.00) in two equal installments. The first payment of $12,500.00 shall be paid on or before the Closing Date upon acceptance of the commitment letter for this Loan, and the second payment of $12,500.00 shall be paid by the Borrower to the Lender on the Closing Date.

(b)  The Borrower shall pay the Lender an unused facility fee quarterly in arrears beginning March 31, 2002 (for the period from the Closing Date through such date) and on the last day of each succeeding June, September, December and March and on the Maturity Date of the Loan, in an amount equal to one-half of one percent (0.50%) per annum on (x) the Amount less (y) the average outstanding principal balance of the Advances under the Note plus the face amount of all standby letters of credit then outstanding during such quarter (or lesser time period, as applicable.)

(c)  The Borrower agrees to reimburse Lender quarterly in arrears on the last day of each fiscal quarter for Lender's actual costs, if any, incurred during that quarter for Lender's compliance with its environmental verification process in obtaining environmental status reports or similar information from governmental agencies.

(d)  Letter of Credit fees are owed and paid as provided in Subsection 2.1(f).

(e)  Borrowing Base redetermination fees for Borrower requested unscheduled redeterminations are owed and paid as provided in the definition of "Borrowing Base" in Section 1.2.

Section 2.6  Use of Proceeds. The Borrower shall use the proceeds of the Loan in connection with the acquisition and development of oil and gas properties as well as general working capital purposes (including letters of credit hereunder). In particular, the Borrower shall use the proceeds of the initial Advance under the Loan to pay in full its older accounts payable and its property taxes as required by Section 5.18.

Section 2.7  Default Rate. Anything in the Note or in any other agreement, document or instrument to the contrary notwithstanding, effective upon an Event of Default or upon the Maturity Date, the Lender shall have the right to prospectively increase the interest rate under the Note to the Default Rate until the Note is paid in full. Upon the acceleration of the principal amount of the Indebtedness represented by the Note, the accelerated principal balance of the Loan shall bear interest from the date of acceleration up to the actual payment (as well after as before judgment) at the Default Rate. All such interest at the Default Rate shall be payable upon demand.

Section 2.8  Additional Regulatory Costs. If any governmental authority, central bank, or other comparable authority shall at any time impose, modify or deem applicable any reserve (including without limitation any imposed by the Board of Governors of the Federal Reserve System), special deposit or similar requirement against assets of, deposits with or for the account of, or credit extended by, the Lender, or shall impose on the Lender any other condition affecting an Advance or the obligation of the Lender to make an Advance; and the result of any of the foregoing is to increase the cost to the Lender of making or maintaining the Advances to the Borrower, or to reduce the amount of any sum received or receivable by the Lender under this Agreement or under the Note by an amount deemed by the Lender to be material, then, within sixty (60) days after demand by the Lender, the Borrower shall pay to the Lender such additional amount or amounts as will compensate the Lender for such increased cost or reduction. The Lender will promptly notify the Borrower of any event of which it has knowledge, occurring after the date hereof, which will entitle the Lender to compensation pursuant to this Section. A certificate of the Lender claiming compensation under this Section and setting forth the additional amount or amounts to be paid to it hereunder shall be conclusive in the absence of manifest error.

Section 2.9  Hedge Agreement Quotes. Upon the Borrower's request from time to time, the Lender will provide to Borrower interest rate swap quotes for interest rate Hedge Agreements pertaining to the Loan, not to exceed the Amount or the Maturity Date.

ARTICLE 3

SECURITY FOR THE OBLIGATIONS

Section 3.1  Security. The Loan shall be primarily secured by the following:

(i)  Mortgage, Deed of Trust, Assignment, Security Agreement and Financing Statement executed by the Borrower, granting a first priority mortgage, security interest and assignment of production in the Borrower's interests in various oil and gas properties in the State of Texas (and after the Closing Date in future locations as Borrower and Lender may agree from time to time) and collateral relating thereto.

(ii)  Pledge executed by the Borrower, granting a first priority security interest in the Borrower's stock in PPL Operating.

ARTICLE 4

REPRESENTATIONS AND WARRANTIES

In order to induce the Lender to enter into this Agreement, the Borrower represents and warrants to the Lender (which representations and warranties will survive the extensions of credit under this Agreement) that:

Section 4.1  Existence. (a) The Borrower is a corporation duly organized, legally existing and in good standing under the laws of its state of incorporation (Delaware) and is duly qualified as foreign corporation in Texas and all other jurisdictions wherein the property it owns or the business it transacts make such qualification necessary and the failure to so qualify would have a material adverse effect on its financial condition, business or operations.

(b)  Paloma Pipeline is a limited partnership duly organized and legally existing under the laws of its state of formation (Texas).

(c)  PPL Operating is a corporation duly organized, legally existing and in good standing under the laws of its state of incorporation (Texas).

Section 4.2  Names, Numbers and Offices of Borrower. (a) The Borrower is not doing business under any name (including trade names) other than the name of the Borrower set forth above and its d/b/a name "The Exploration Company" (for which appropriate assumed name filings have been made in all appropriate jurisdictions), and has never done business previously under any other names except the name "Colorado Exploration Company" (which is a dormant Subsidiary) and its former corporate name "The Exploration Company", and "ExproFuels" which was the name of a former division (which name Borrower has not used after 1997). (The Borrower's Subsidiaries do business under their names as provided in this Agreement.)

(b)  The Borrower's federal employer identification number and secretary of state registration number and locations of its state of incorporation and chief executive office are accurately set forth in the Collateral Documents. The Borrower's chief executive office has been continuously located in the State of Texas on and after January 1, 1996.

Section 4.3  Borrower's Power and Authorization. The Borrower is duly authorized and empowered to execute, deliver and perform this Agreement, the Note and the Collateral Documents executed by it. All corporate action on the part of the Borrower (including all shareholder action) requisite for the due creation and execution of the Loan and this Agreement, the Note and Collateral Documents have been duly and effectively taken.

Section 4.4  Review of Documents; Binding Obligations. The Borrower has reviewed this Agreement, the Note and the Collateral Documents with counsel for the Borrower and has had the opportunity to discuss the provisions thereof with the Lender prior to execution. This Agreement, the Note and the Collateral Documents constitute valid and binding obligations of the Borrower, enforceable in accordance with their terms (except that enforcement may be subject to any applicable bankruptcy, insolvency or similar laws generally affecting the enforcement of creditors' rights).

Section 4.5  No Legal Bar or Resultant Lien. This Agreement, the Note and the Collateral Documents do not and will not violate any provisions of the Borrower's articles of incorporation or bylaws or Paloma Pipeline's articles of partnership, will not violate any contract, agreement, law, regulation, order, injunction, judgment, decree or writ to which the Borrower is subject, and will not result in the creation or imposition of any Lien upon any property of the Borrower other than as contemplated by this Agreement.

Section 4.6  No Consent. The Borrower's execution, delivery and performance of this Agreement, the Note and the Collateral Documents do not require the consent or approval of any other Person, including without limitation any regulatory authority or governmental body of the United States or any state thereof or any political subdivision of the United States or any state thereof, except that the foreclosure sale of the Borrower's interest as lessee in the Chittim Ranch Lease dated December 16, 1996, from Jack Robert Chittim, et al., as lessor, requires the lessors' consent, not to be unreasonably withheld, to such assignment..

Section 4.7  Financial Condition. All financial statements of the Borrower and any affiliates delivered to Lender fairly and accurately present the financial condition of the parties for whom such statements are submitted and the financial statements of the Borrower and any affiliates have been prepared in accordance with generally accepted accounting principles consistently applied throughout the periods involved, and there are no contingent liabilities not disclosed thereby which would adversely affect the financial condition of Borrower or any affiliates. Since the close of the period covered by the latest financial statement delivered to Lender with respect to Borrower and any affiliates, there has been no material adverse change in the assets, liabilities, or financial condition of Borrower or any affiliates. No event has occurred (including, without limitation, any litigation or administrative proceedings) and no condition exists or, to the knowledge of Borrower, is thre atened, which (i) might render Borrower unable to perform its obligations under this Agreement, the Note or the Collateral Documents, or (ii)

would constitute a Default hereunder, or (iii) might adversely affect the financial condition of the Borrower or any affiliates or the validity or priority of the Lien of the Collateral Documents. Each of the Borrower, Paloma Pipeline and PPL Operating is solvent and has the ability to pay its Debts when and as due.

Section 4.8  Taxes and Governmental Charges. The Borrower has filed all tax returns and reports required to be filed and have paid all taxes, assessments, fees and other governmental charges levied upon it or upon its property or income which are due and payable, including interest and penalties, or is contesting the same in good faith by appropriate proceedings and has provided adequate reserves for the payment thereof, except for property taxes to be paid on or immediately following the Closing Date.

Section 4.9  Defaults. The Borrower is not in default under any indenture, mortgage, deed of trust, agreement or other instrument to which the Borrower is a party or by which it or any of its property is bound.

Section 4.10  Liabilities and Litigation. Except for liabilities incurred in the normal course of business, the Borrower and its Subsidiaries have no material (individually or in the aggregate) liabilities, direct or contingent, except as disclosed in the most recent financial statements furnished to the Lender. Except as disclosed in the most recent financial statements furnished to the Lender, there is no litigation, legal or administrative proceeding, investigation or other action of any nature pending or, to the knowledge of Borrower, threatened against or affecting the Borrower or its Subsidiaries which involves the possibility of any judgment or liability not fully covered by insurance which may materially and adversely affect the business or the property of the Borrower or such Subsidiary or its respective ability to carry on business as now conducted. Without limiting the foregoing, on the Closing Date there is no litigation, legal or administrative proceeding, investi gation or other action pending or, to the knowledge of Borrower, threatened against or affecting the Borrower or any Subsidiary involving non-compliance by the Borrower or any Subsidiary or its respective properties with any Applicable Environmental Laws (as defined in Section 4.17).

Section 4.11  Margin Stock. None of the Loan proceeds will be used for the purpose of, and the Borrower is not engaged in the business of extending credit for the purpose of, purchasing or carrying any "margin stock" as defined in Regulation U of the Board of Governors of the Federal Reserve System (12 C.F.R. Part 221), or for the purpose of reducing or retiring any indebtedness which was originally incurred to purchase or carry a margin stock or for any other purpose which might constitute this transaction a "purpose credit" within the meaning of said Regulation U. The Borrower is not engaged principally, or as one of the Borrower's important activities, in the business of extending credit for the purpose of purchasing or carrying margin stocks. Neither the Borrower nor any Person acting on behalf of the Borrower has taken or will take any action which might cause this Agreement to violate Regulation U or any other regulation of the Board of Governors of the Federal Reserve S ystem or to violate the Securities Exchange Act of 1934 or any rule or regulation thereunder, in each case as now in effect or as the same may hereinafter be in effect.

Section 4.12  Utility or Investment Company. The Borrower is not engaged in the generation, transmission, or distribution and sale of electric power; operation of a local distribution system for the sale of natural or other gas for domestic, commercial, industrial, or other use; ownership or operation of a pipeline for the transmission or sale of natural or other gas, crude oil or petroleum products (except for ownership of interests in gathering line systems); provision of telephone or telegraph service to others; production, transmission, or distribution and sale of steam or water; operation of a railroad; or provision of sewer service to others; or any other activity which cause the Borrower to be subject to regulation as a utility. The Borrower is not an "investment company" within the meaning of the Investment Company Act of l940, as amended.

Section 4.13 Compliance with the Law. The Borrower (i) is not in violation of any law, judgment, decree, order, ordinance, or governmental rule or regulation to which the Borrower or any of its property is subject; and (ii) has not failed to obtain any license, permit, franchise or other governmental authorization necessary to the ownership of any of its property or the conduct of its business; in each case, which violation or failure could reasonably be anticipated to materially and adversely affect the business, prospects, profits, property or condition (financial or otherwise) of the Borrower.

Section 4.14 ERISA. The Borrower is in compliance in all material respects with the applicable provisions of ERISA, and no "reportable event", as such term is defined in Section 4043 of ERISA, has occurred with respect to any Plan of the Borrower.

Section 4.15 Other Information. All information, reports, papers and data given to the Lender by the Borrower pursuant to this Agreement and in connection with the Borrower's application for the Loan and the Lender's commitment letter are accurate and correct in all material respects, and together constitute a complete and accurate presentation of all facts material thereto. All financial projections given to the Lender were prepared in good faith based on facts and circumstances existing at the time of preparation and were believed by the Borrower to be accurate in all material respects. No information, exhibit or report furnished by the Borrower to the Lender in connection with the negotiation of this Agreement contains any material misstatement of fact or fails to state a material fact or any fact necessary to make the statement contained therein not materially misleading.

Section 4.16 Title to Collateral. (a) The Borrower has good and marketable title to the Collateral, and the Collateral Documents constitute the legal, valid and perfected Liens on the Collateral, free of all Liens except those permitted by this Agreement in Section 6.2.

(b)  The Borrower has, with respect to the Collateral, the working interests and net revenue interests therein as reported to the Lender in connection with the negotiation of this Agreement. Except as otherwise specifically disclosed to the Lender in writing with respect to any particular part of the Borrower's properties, (i) the Borrower is not obligated, whether by virtue of any payment under any contract providing for the sale by the Borrower of hydrocarbons which contains a "take or pay" clause or under any similar arrangement or by virtue of any production payment or otherwise, to deliver hydrocarbons produced or to be produced from the Borrower's properties at any time after the Closing Date without then or thereafter receiving full payment therefor, except for Permitted Hedge Agreements; (ii) none of the Borrower's properties is subject to any contractual or other arrangement whereby payment for production is to be deferred for a substantial period after the month in whi ch such production is delivered; (iii) none of the Borrower's properties is subject to an arrangement or agreement under which any purchaser or other Person is currently entitled to "make-up" or otherwise receive material deliveries of hydrocarbons at any time after the Closing Date without paying at such time the full contract price therefor; and (iv) except for routine imbalances occurring from time to time on the Aquila transmission system, no Person is currently entitled to receive any material portion of the interest of the Borrower in any hydrocarbons or to receive cash or other payments from the Borrower to "balance" any disproportionate allocation of hydrocarbons under any operating agreement, cash balancing and storage agreement, gas processing or dehydration agreement, or other similar agreements. For purposes of this paragraph, "material" shall mean ten thousand ($10,000.00) dollars (or more) or an amount of property with an equivalent value.

(c)  As of the Closing Date, none of the Collateral is subject to any calls on production of hydrocarbons or any gathering or transportation dedications or commitments of any kind.

(d)  Paloma Pipeline has good and marketable title to the gas gathering system servicing the Collateral.

Section 4.17 Environmental Matters. No friable asbestos, or any substance containing asbestos deemed hazardous by federal or state regulations on the date of this Agreement, has been installed in any Collateral constituting real property. Such real property and the Borrower are not in violation of or subject to any existing, pending, or threatened investigation or inquiry by any governmental authority or to any remedial obligations under any applicable laws pertaining to health or the environment (hereinafter sometimes collectively called "Applicable Environmental Laws"), including without limitation the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended by the Superfund Amendments and Reauthorization Act of 1986 (as amended, hereinafter called "CERCLA"), the Resource Conservation and Recovery Act of 1976, as amended by the Used Oil Recycling Act of 1980, the Solid Waste Disposal Act Amendments of 1980, and the Hazardous and Solid Waste Amendments o f 1984 (as amended, hereinafter called "RCRA"), and this representation and warranty would continue to be true and correct following disclosure to the applicable governmental authorities of all relevant facts, conditions and circumstances, if any, pertaining to such property and known to the Borrower. No hazardous substances or solid wastes have been disposed of or otherwise released on or to such property. The terms "hazardous substance" and "release" as used in this Agreement shall have the meanings specified in CERCLA, and the terms "solid waste" and "disposal" (or "disposed") shall have the meanings specified in RCRA; provided, in the event that the laws of any applicable state establish a

meaning for "hazardous substance," "release," "solid waste," or "disposal" which is broader than that specified in either CERCLA or RCRA, such broader meaning shall apply.

Section 4.18 Governmental Requirements. Any Collateral constituting real (immovable) property is in compliance with all current governmental requirements affecting such property, including, without limitation, all current coastal zone protection, zoning and land use regulations, building codes and all restrictions and requirements imposed by applicable governmental authorities with respect to the construction of any improvements on such property and the contemplated use of such property.

Section 4.19 Contracts. The Contracts when considered as a whole do not materially affect the rights, benefits or security of the Lender under the Collateral Documents and the Contracts do not contain any provision which would prevent the Lender's practical realization of the benefits of the Collateral Documents as to the Collateral. After giving effect to the Contracts, the net revenue interests of the Borrower in the Collateral are not less than those set forth in the Collateral Documents.

Section 4.20 Affiliates. (a) The Borrower has no Subsidiaries, except for PPL Operating, Paloma Pipeline and Colorado Exploration Company. The Borrower has no ownership (direct or beneficial) interest in any other Person (whether stock, partnership interest, membership interest or otherwise). The Borrower has furnished to the Lender true, accurate and complete copies of the agreement of limited partnership of Paloma Pipeline and of the articles of incorporation and bylaws of PPL Operating. On the Closing Date, the Borrower owns and controls 100% of the ownership and voting rights in PPL Operating. On the Closing Date, PPL Operating is the sole general partner of Paloma Pipeline, and the Borrower and PPL Operating together own and control at least sixty two (62%) percent of the ownership and voting rights in Paloma Pipeline.

(b)  None of the Collateral is owned by, or has record title to it in the name of, another company than Borrower.

(c)  PPL Operating is engaged in no business activities other than being the sole corporate general partner of Paloma Pipeline.

(d)  Colorado Exploration Company is not engaged in business activities.

Section 4.21 Debt and Preferred Stock. (a) On the Closing Date, the Borrower has no Debt for borrowed money from any financial institution (other than this new Loan), except under certain capital lease agreements disclosed in the Borrower's financial statements provided to the Lender.

(b)  On the Closing Date, the Borrower has no preferred stock issued or outstanding.

Section 4.23 Continuing Accuracy. All of the representations and warranties contained in this Article or elsewhere in this Agreement shall be true through and until the date on which all obligations of Borrower under this Agreement, the Note and the Collateral Documents and any other documents executed in connection therewith are fully satisfied, and Borrower shall promptly notify Lender of any event which would render any of said representations and warranties untrue or misleading.

ARTICLE 5

AFFIRMATIVE COVENANTS

Unless the Lender's prior written consent to the contrary is obtained, the Borrower will at all times comply with the covenants contained in this Article 5, from the date hereof and for so long as any part of the Indebtedness is outstanding.

Section 5.1 Performance of Obligations. The Borrower will repay the Indebtedness according to the reading, tenor and effect of the Note and this Agreement. The Borrower will do and perform every act required of it by this Agreement, the Note or in the Collateral Documents at the time or times and in the manner specified.

Section 5.2 Financial Statements and Reports. The Borrower will furnish or cause to be furnished to the Lender from time to time:

(a)  Borrower's Annual Reports - as soon as available and in any event within 110 days after the close of each fiscal year of the Borrower, the audited balance sheet of the Borrower as of the end of such year, the audited statement of income of the Borrower for such year, the audited statement of shareholder equity of the Borrower for such year, and the audited statement of cash flow of Borrower for such year, setting forth in each case in comparative form the corresponding figures for the preceding fiscal year, accompanied by the unqualified opinions of an independent certified public accountant acceptable to the Lender.

(b)  Borrower's Quarterly Reports - as soon as available and in any event within 60 days after the end of each fiscal quarter in each fiscal year of the Borrower, the unaudited balance sheet of the Borrower as of the end of such fiscal quarter, the unaudited statement of income of the Borrower for the period from the beginning of the fiscal year to the close of such fiscal quarter, the unaudited statement of shareholder equity of the Borrower for the period from the beginning of the fiscal year to the close of such fiscal quarter, and the unaudited statement of cash flow of Borrower for such fiscal quarter and for the period from the beginning of the fiscal year to the close of such fiscal quarter, setting forth in each case in comparative form the corresponding figures for the corresponding period of the preceding fiscal year (and showing without limitation any over or under produced imbalances of production). Such internally prepared quarterly reports shall be accompanied by t he certificates of compliance required by Section

5.3.

(c)  Annual Engineering Report - as soon as available and in any event by March 31 of each year, an annual independent third party engineering report covering the Borrowing Base properties, with an effective date of January 1 of the current year, in form and substance acceptable to the Lender prepared by an independent firm acceptable to the Lender. Without limiting the foregoing sentence, such reports shall include a discussion of assumptions as to engineering, pricing and expenses, and an economic evaluation together with the reserve value of each well of each property in the Borrowing Base, and (except for the initial report delivered on or about the Closing Date) further categorized as Collateral or non-Collateral and as Proved Developed Producing Reserves, Proved Developed Non-Producing Reserves, or Proved Undeveloped Reserves. (The Borrower acknowledges that the Lender reserves the right to determine the Borrowing Base based on the provisions hereof and Lender's own evalu ations of rates, volumes, prices, assumptions and other factors regardless of this outside engineering data or then market prices.)

(d)  Semi-Annual Engineering - as soon as available and in any event by September 30 of each year, a semi-annual engineering update report covering the Borrower Base properties, either from an independent third party or an internal report with technical review.

(e)  Monthly Reports - within 60 days after the end of each month, a monthly production tracking report pertaining to the Borrowing Base properties on a well by well basis in form acceptable to the Lender's Oil and Gas Appraisal Department, including production volumes and revenue and expense statements.

(f)  Title Information - promptly upon the Lender's request, detailed information concerning any and all requirements or exceptions set forth in any title opinions concerning any of the Collateral.

(g)  Environmental - (I) promptly upon receipt thereof, complete documentation pertaining to any fines levied during the prior year against the Borrower, or to the extent known and available to the Borrower against an operator of any Collateral, for non-compliance with all applicable federal, state and local environmental laws and regulations; and (II) promptly upon learning thereof, notice of Borrower's acquisition of actual knowledge of the presence of any hazardous materials or solid waste (as defined elsewhere in this Agreement) on or under any Collateral; and (III) the report required by Section 5.19.

(h)  Notices - when required by the terms thereof, the notices required under Section 5.11.

(i)  Audit Reports - promptly upon receipt thereof, one copy of each report submitted to the Borrower by independent accountants in connection with any annual, interim or special audit made by them of the books of the Borrower.

(j)  Insurance Report - within 30 days after the end of each fiscal year of the Borrower, an annual insurance coverage report detailing Borrower's insurance program.

(k)  S.E.C. Reports - promptly upon becoming available, copies of all (i) regular, periodic or special reports, schedules and other material which the Borrower may be required to file with or deliver to any securities exchange or the Securities and Exchange Commission (or any other governmental authority succeeding to the functions thereof) and (ii) material news releases and annual reports relating to the Borrower.

(l)  Other Information - promptly upon the request of the Lender, all regular budgets and such other financial, technical or other information regarding the business and affairs and financial condition of the Borrower as the Lender may reasonably request.

All balance sheets and other financial reports referred to above shall be in such detail as the Lender may reasonably request and shall conform to the standards described in Section 1.3.

Section 5.3 Certificates of Compliance. Concurrently with the furnishing of the annual and quarterly financial statements described above, the Borrower will furnish to the Lender a certificate signed by the principal financial officer of the Borrower, stating either that no Default occurred during such quarter (or if it did but no longer exists, the nature and duration thereof) and that no Default then exists, or if a Default exists, the nature, period of existence and status thereof, and specifically setting forth the calculations showing the Borrower's compliance with the financial covenants in Section 5.15.

Section 5.4 Taxes and Other Liens. The Borrower will file all tax returns and reports required to be filed and pay (or cause to be paid) and discharge promptly when due all taxes, assessments and governmental charges or levies imposed upon it or upon income or upon any of its property, or upon Paloma Pipeline or upon any of its properties, (including production, severance, windfall profit, excise and other taxes assessed against or measured by the production of, or the value or proceeds of production of, the Collateral) as well as all claims of any kind (including claims for labor, materials, supplies and rent) which, if unpaid, might become a Lien upon any or all of its property or Paloma Pipeline's property; provided, however, the Borrower shall not be required to pay or cause to be paid any such tax, assessment, charge, levy or claim if the amount, applicability or validity thereof shall currently be contested in good faith by appropriate proceedings diligently conducted and if the co ntesting party shall have set up reserves therefor adequate under generally accepted accounting principles (provided that such reserves may be set up under generally accepted accounting principles) and so long as the payment of same is not a condition to be met in order to maintain an oil, gas or mineral lease in force.

Section 5.5 Maintenance and Compliance. The Borrower will, and will cause each Subsidiary to, (i) maintain its corporate or partnership existence and rights and its current business operations; (ii) observe and comply (to the extent necessary so that any failure will not materially and adversely affect the business of such Person) with all valid existing and future laws, statutes, codes, acts, ordinances, orders, judgments, decrees, injunctions, rules, regulations, certificates, franchises, permits, licenses, authorizations, directions and requirements (including without limitation applicable statutes, regulations, orders and restrictions relating to environmental standards or controls or to energy regulations) of all federal, state, county, municipal and other governments, departments, commissions, boards, courts, authorities, officials and officers, domestic or foreign; and (iii) maintain its properties (and any property

leased by or consigned to it or held under title retention or conditional sales contracts) in generally good and workable condition at all times and make all repairs, replacements, additions, betterments and improvements to its properties to the extent necessary so that any failure will not materially and adversely affect the business of such Person.

Section 5.6 Further Assurances. The Borrower at its expense will promptly (and in no event later than 30 days after written notice from the Lender is received) cure any defects, errors or omissions in the creation, execution, delivery or contents of this Agreement, the Note or the Collateral Documents, and execute and deliver to the Lender upon request all such other and further documents, agreements and instruments in compliance with or accomplishment of the covenants and agreements of the Borrower in this Agreement, the Note or in the Collateral Documents or to further evidence and more fully describe the Collateral (including without limitation any renewals, additions, substitutions, replacements or accessions to the Collateral), or to correct any omissions in the Collateral Documents, or more fully state the security obligations set out herein or in any of the Collateral Documents, or to perfect, protect or preserve any Liens and the priority thereof created pursuant to any of the Co llateral Documents, or to make any recordings, to file any notices, or obtain any consents as may be necessary or appropriate in connection with the transactions contemplated by this Agreement.

Section 5.7 Reimbursement of Expenses. The Borrower will pay all reasonable legal fees and expenses incurred by the Lender in connection with the preparation of this Agreement, the Note and the Collateral Documents. The Borrower will, upon request promptly reimburse the Lender for all amounts expended, advanced or incurred by the Lender to satisfy any obligation of the Borrower under this Agreement, or to protect the property or business of the Borrower or to collect the Indebtedness, or to enforce the rights of the Lender under this Agreement or the Note or the Collateral Documents, which amounts will include all court costs, attorneys' fees and expenses, fees and expenses of engineers, auditors and accountants, travel expenses and investigation expenses reasonably incurred by the Lender in connection with any such matters, together with interest at the Default Rate on each such amount from the date that the same is expended, advanced or incurred by the Lender until the date of reimbur sement to the Lender. The Borrower also agrees to pay, and to hold the Lender harmless from any failure or delay in paying, all recording taxes, documentary stamp taxes or other similar taxes, if any, which may be payable or determined to be payable in connection with the execution and delivery of this Agreement, the Note, the Collateral Documents, or any modification or supplement thereof or thereto.

Section 5.8 Insurance. The Borrower will maintain with financially sound and reputable insurers, insurance with respect to its properties and businesses against such liabilities, casualties, risks and contingencies and in such types and amounts as are reasonably satisfactory to the Lender and customary in accordance with standard industry practice or as more specifically provided in the Collateral Documents. Upon request of the Lender, the Borrower will furnish or cause to be furnished to the Lender from time to time a summary of the insurance coverage of the Borrower in form and substance satisfactory to the Lender and if requested will furnish the Lender original certificates of insurance and/or copies of the applicable policies.

Section 5.9 Accounts and Records. The Borrower will keep books of record and accounts in which true and correct entries will be made as to all material matters of all dealings or transactions in relation to its business and activities.

Section 5.10 Right of Inspection. The Borrower will permit any officer, employee or agent of the Lender at their risk to visit and inspect any of the property of the Borrower, examine the books of record and accounts of the Borrower, take copies and extracts therefrom, and discuss the affairs, finances and accounts of the Borrower with the Borrower's officers, accountants and auditors, and the Borrower will furnish information concerning the Collateral, including schedules of all internal and third party information identifying the Collateral (such as, for example, lease and well names and numbers assigned by the Borrower or the operator of any mineral properties, division orders and payment names and numbers assigned by purchasers of the hydrocarbons, and internal identification names and numbers used by the Borrower in accounting for revenues, costs and joint interest transactions attributable to the mineral properties), all on reasonable notice, at such reasonable times without hindra nce or delay and as often as the Lender may reasonably desire. The Borrower will furnish to the Lender promptly upon request and in the form and content specified by the Lender lists of purchasers of hydrocarbons and other account debtors, schedules of equipment and other data concerning the Collateral as the Lender may from time to time specify.

Section 5.11 Notice of Certain Events. (a) The Borrower shall promptly notify the Lender if the Borrower learns of the occurrence of any event which constitutes a Default, together with a detailed statement by a responsible officer of the Borrower of the steps being taken to cure the effect of such Default.

(b)  The Borrower shall promptly notify the Lender of any change in location of the Borrower's principal place of business or the office where it keeps its records concerning accounts and contract rights or a change in its name, state of organization, federal taxpayer identification number or organizational status.

(c)  The Borrower shall promptly notify the Lender of the arising of any litigation or dispute threatened against or affecting the Borrower or any Subsidiary which, if adversely determined, would have a material adverse effect upon the financial condition or business of the Borrower or such Subsidiary. In the event of such litigation, the Borrower will cause such proceedings to be vigorously contested in good faith and, in the event of any adverse ruling or decision, the Borrower shall prosecute all allowable appeals. The Lender may (but shall not be obligated to), without prior notice to Borrower, commence, appear in, or defend any action or proceeding purporting to affect the Loan, or the respective rights and obligations of Lender and Borrower pursuant to this Agreement. The Lender may (but shall not be obligated to) pay all necessary expenses, including reasonable attorneys' fees and expenses incurred in connection with such proceedings or actions, which Borrower agrees to repay to Lender upon demand.

(d)  The Borrower shall promptly notify the Lender of the occurrence of any material adverse change in the value of any oil or gas property which is included in the Borrowing Base, or from which the Borrower otherwise derives material revenue. Without limiting the foregoing, the Borrower shall promptly notify the Lender of any notice of default or cancellation from any lessor of any mineral lease in the Collateral.

(e)  The Borrower shall promptly notify the Lender of the creation, incurrence, assumption, existence or filing of any Lien on any Borrowing Base property now owned or hereafter acquired, or the property of Paloma Pipeline, except for Liens permitted under Section 6.2.

(f)  The Borrower shall promptly notify the Lender of each creation, acquisition, disposition, dissolution, merger or other change in the status of or addition or removal of any Subsidiary.

The foregoing requirements of notice shall not be construed to imply permission or consent by the Lender as to such events or to waive any representations, covenants and defaults set forth in this Agreement.

Section 5.12 ERISA Information and Compliance. The Borrower will promptly furnish to the Lender (i) promptly after the filing thereof with the United States Secretary of Labor or the Pension Benefit Guaranty Corporation, copies of each annual and other report with respect to each Plan or any trust created by the Borrower, and (ii) immediately upon becoming aware of the occurrence of any "reportable event," as such term is defined in Section 4043 of ERISA, or of any "prohibited transaction," as such term is defined in Section 4975 of the Code, in connection with any Plan or any trust created by the Borrower, a written notice signed by the president or the principal financial officer of the Borrower specifying the nature thereof, what action the Borrower is taking or proposes to take with respect thereto, and, when known, any action taken by the Internal Revenue Service with respect thereto. The Borrower will comply with all of the applicable funding and other requirements of ERISA as su ch requirements relate to the Plans of the Borrower.

Section 5.13 Indemnification. (a) The Borrower will indemnify the Lender and hold the Lender harmless from claims of brokers with whom the Borrower has contracted in the execution hereof or the consummation of the transactions contemplated hereby. The Lender will indemnify the Borrower from claims of brokers with whom the Lender has contracted in connection with the transactions contemplated hereby.

(b)  The Borrower will indemnify the Lender and hold the Lender harmless from any and all liabilities, obligations, losses, damages, penalties, claims, actions, suits, costs and expenses of whatever kind or nature which may be imposed on, incurred by or asserted at any time against the Lender in any way relating to, or arising in connection with, the use or occupancy of any of the Collateral or any breach of any representation, warranty or covenant under the terms of this Agreement or the Collateral Documents.

Section 5.14 Environmental Indemnity. The Borrower shall defend, indemnify and hold Lender and its directors, officers, agents and employees harmless from and against all claims, demands, causes of action, liabilities, losses, costs and expenses (including, without limitation, costs of suit, reasonable attorneys' fees and fees of expert witnesses) arising from or in connection with (i) the presence on or under all Collateral constituting immovable (real) property of any hazardous substances or solid wastes (as defined elsewhere in this Agreement), or any releases or discharges of any hazardous substances or solid wastes on, under or from such property, or (ii) any activity carried on or undertaken on or off such property, whether prior to or during the term of this Agreement, and whether by Borrower or any predecessor in title or any officers, employees, agents, contractors or subcontractors of Borrower or any predecessor in title, or any third persons at any time occupying or present on such property, in connection with the handling, use, generation, manufacture, treatment, removal, storage, decontamination, clean-up, transport or disposal of any hazardous substances or solid wastes at any time located or present on or under such property. The foregoing indemnity shall further apply to any residual contamination on or under such property, or affecting any natural resources, and to any contamination of any property or natural resources arising in connection with the generation, use, handling, storage, transport or disposal of any such hazardous substances or solid wastes, and irrespective of whether any of such activities were or will be undertaken in accordance with applicable laws, regulations, codes and ordinances. Without prejudice to the survival of any other agreements of the Borrower hereunder, the provisions of this Section shall survive the final payment of all Indebtedness and the termination of this Agreement and shall continue thereafter in full force and effect.

Section 5.15 Financial Covenants. The Borrower shall comply with the following financial covenants (determined in accordance with Section 1.3), except as specifically stated otherwise:

(a)  Minimum Current Ratio. The Borrower shall maintain, on a quarterly basis as of the last day of each fiscal quarter, a current ratio in an amount not less than 1.00 to 1.00 through June 30, 2002, and of not less than 1.25 to 1.00 thereafter. For purposes of this Section, "current ratio" shall mean the ratio of (x) current assets to (y) current liabilities.

(b)  Maximum Debt to EBITDAX. The Borrower shall maintain, on a quarterly basis as of the last day of each fiscal quarter, a ratio (on a rolling four fiscal quarter basis) of funded debt to EBITDAX (as defined in Subsection 5.15(d) below) during the four preceding fiscal quarters of no more than 3.00 to 1.00. For purposes of this Subsection, "debt" shall mean all debt for borrowed money and capitalized leases (whether short or long term) (and for this purpose debt does not mean "Debt" as otherwise defined in this Agreement).

(c)  Minimum EBITDAX to Interest Expense. The Borrower shall maintain, on a quarterly basis as of the last day of each fiscal quarter, a ratio (on a rolling four fiscal quarter basis) of EBITDAX to interest expense during the four preceding fiscal quarters of not less than 2.50 to 1.00. For purposes of this Subsection, interest expense shall mean, for each period,

the sum of all interest, fees, charges and related expenses payable (without duplication) for that period to a lender in connection with borrowed money or the deferred purchase price of assets that are considered "interest expense" under generally accepted accounting principles, plus the portion of rent paid or payable (without duplication) for that period under capital lease obligations that should be treated as interest in accordance with Financial Accounting Standards Board Statement No. 13.

(d)  EBITDAX and EBITDA. "EBITDAX" shall be calculated for purposes of this Section as EBITDA, but adjusted as if the Borrower were to use the full cost method of accounting (under which all exploration expenses are capitalized) to capitalize exploration and dry hole costs rather than the Borrower's successful efforts accounting method of expensing intangible drilling costs (such as seismic and geological expenses), dry hole costs and other costs. For purposes of this Section, "EBITDA" shall mean, for each period of four preceding fiscal quarters, the sum of the Borrower's (i) net income for that period, plus (ii) any extraordinary loss and other expenses not considered to be operating in nature reflected in such net income, minus (iii) any extraordinary gain, interest income and other income not considered operating in nature reflected in such net income, plus (iv) depreciation, depletion, amortization and all other non-cash expenses for that period, plus (v) all interest, fee s, charges and related expenses paid or payable (without duplication) for that period to a lender in connection with borrowed money or the deferred purchase price of assets that are considered "interest expense" under generally accepted accounting principles, together with the portion of rent paid or payable (without duplication) for that period under capital lease obligations that should be treated as interest in accordance with Financial Accounting Standards Board Statement No. 13, plus (vi) the aggregate amount of federal and state taxes on or measured by income for that period (whether or not payable during that period).

Section 5.16 Bank Accounts. (a) The Borrower shall maintain its primary operating, clearing, collection and disbursement accounts pertaining to the Collateral at the Lender, including without limitation as provided in Section 5.17.

(b)  The Borrower hereby grants to the Lender a continuing security interest in all of Borrower's deposit accounts now existing or hereafter maintained at Lender as security for the Indebtedness, and all funds, investment property and proceeds pertaining thereto.

Section 5.17 Revenue Clearing Account. (a) The Borrower agrees to immediately deposit in a revenue clearing account at Lender, daily, all amounts received by Borrower on any accounts and sales of hydrocarbons. All such deposits shall be made no later than the first Business Day after collection by the Borrower. Without limiting the foregoing, the Borrower shall use its best efforts to cause all purchasers from or agents of Borrower which make payments for oil or natural gas purchases by electronic transfer payments to change such electronic payments to be made directly to Borrower's accounts at the Lender. If no Default has

occurred and is continuing, proceeds in the revenue clearing account exceeding the next monthly payment amount may be transferred and withdrawn by the Borrower.

(b)  The Borrower and the Lender acknowledge that Collateral is comprised in part of the Borrower's undivided interests in mineral properties for which the Borrower is operator, and accordingly a portion of the payments made to the Borrower from the sale of hydrocarbons from such properties may be owed by the Borrower to the non-operator working interest owners. In the event that revenues of another Person attributable to such other Person's working interest ("Other Revenues") are deposited into the revenue clearing account at Lender, then the Lender agrees that such Other Revenues will be released by the Lender to such Persons (even if an Event of Default has occurred and is continuing) upon the receipt by the Lender of appropriate evidence that such funds are Other Revenues (i.e., are not the Borrower's funds). The Lender shall not be liable, however, for any actions by Lender which are taken in compliance with the terms of this Agreement and the Collateral Documents with res pect to funds in the revenue clearing account that are Other Revenues and which are taken before Lender received such evidence that such funds are Other Revenues.

(c)  Upon the occurrence of any Event of Default, the Borrower shall upon Lender's request execute such division orders, transfer orders or letters in lieu thereof as are necessary to direct that all payments of mineral production due to the Borrower from its properties are paid directly to the Lender, including as further provided in the mortgage by Borrower to Lender (Section 3.1).

Section 5.18 Payment of Payables. The Borrower shall promptly pay in full from the initial Advance under this Loan (i) all of its accounts payable owing by Borrower on the Closing Date which are more than sixty (60) days old and (ii) all of its unpaid property taxes.

Section 5.19 Initial Environmental Report. The Borrower will cause to be furnished to the Lender within ninety (90) days after the Closing Date an environmental assessment report acceptable to Lender's Energy Technical Services.

ARTICLE 6

NEGATIVE COVENANTS

Unless the Lender's prior written consent to the contrary is obtained, the Borrower will at all times comply with the covenants contained in this Article 6, from the date hereof and for so long as any part of the Indebtedness is outstanding.

Section 6.1 Debts, Guaranties and Other Obligations. The Borrower will not incur, create, assume or in any manner become or be liable in respect of any Debt direct or contingent, except for:

(a)  The Indebtedness to the Lender.

(b)  Customary trade payables or operating leases from time to time incurred in the ordinary course of business.

(c)  Debt under operating agreements, unitization and pooling agreements and orders, farmout agreements and gas balancing agreements, in each case that are customary in the oil, gas and mineral production business and that are entered into in the ordinary course of business.

(d)  Taxes, assessments or other government charges which are not yet due or are being contested in good faith by appropriate action promptly initiated and diligently conducted, if such reserve as shall be required by generally accepted accounting principles shall have been made therefor.

(e)  Obligations incurred in the ordinary course of business under Permitted Hedge Agreements.

(f)  Debt fully subordinated to the Indebtedness, entered into after Lender's prior written consent, and with a subordination in favor of Lender of such Debt on terms and conditions satisfactory to Lender in its sole discretion.

(g)  Debt under capital leases existing on the Closing Date, as shown on the Borrower's balance sheet as of the Closing Date.

Section 6.2 Liens. The Borrower will not, and will not allow or suffer Paloma Pipeline or PPL Operating to, create, incur, assume or permit to exist any Lien on any of its property now owned or hereafter acquired, except for:

(a)  Liens for taxes, assessments, or other governmental charges not yet due or which are being contested in good faith by appropriate action promptly initiated and diligently conducted, if such reserve as shall be required by generally accepted accounting principles shall have been made therefor, and so long as the payment of same is not a condition to be met in order to maintain in force such Person's interest in such property or (if applicable) the Lender's first Lien therein.

(b)  Liens of landlords, vendors, carriers, warehousemen, mechanics, laborers and materialmen arising by law in the ordinary course of business for sums either not more than 90 days past due or being contested in good faith by appropriate action promptly initiated and diligently conducted, if such reserve as shall be required by generally accepted accounting principles shall have been made therefor, and so long as the payment of same is not a condition to be met in order to maintain in force the Borrower's interest in such property or the Lender's first Lien therein.

(c)  Inchoate liens arising under ERISA to secure the contingent liability of the Borrower permitted by this Agreement.

(d)  The pledge of the Collateral and any other liens in favor of the Lender to secure the Indebtedness of the Borrower to the Lender.

(e)  Minor imperfections of title or non-monetary Liens that do not materially impair the development, operation or value of property in its intended use or the title thereto and which are of a nature commonly existing with respect to properties of a similar character as the Collateral.

(f)  Royalties, overriding royalties, net profits interests, production payments, reversionary interests, calls on production, preferential purchase rights and other burdens on or deductions from the proceeds of production, that do not secure Debt for borrowed money and that are taken into account in computing the net revenue interests and working interests of the Borrower warranted in the Collateral Documents.

(g)  Operating agreements, unitization and pooling agreements and orders, farmout agreements, gas balancing agreements and other agreements, in each case that are customary in the oil, gas and mineral production business and that are entered into in the ordinary course of business.

(h)  Liens fully subordinated to Lender's Liens, securing subordinated Debt permitted by Section 6.1(f), granted after Lender's prior written consent, and with a subordination in favor of Lender of such Liens on terms and conditions satisfactory to Lender in its sole discretion.

(i)  Liens under the Borrower's capital leases existing on the Closing Date.

(j)  Lien in favor of the lessor under the Comanche/Farias Ranch Lease dated March 8, 2000, from The Halsell Foundation as lessor, which security interest covers all of the Borrower's hydrocarbons from said lease but which is subordinated by its express terms as to Borrower's full lessee interest thereunder to any mortgage loan made to Borrower.

The inclusion of this Section 6.2 shall not constitute in any way an acknowledgment by the Lender of the validity, legality, enforceability or binding effect on the Lender of such Liens, the sole purpose of this provision being to provide that the existence of any such permitted Liens shall not in and of itself constitute an Event of Default under this Agreement.

Section 6.3 Investments, Loans and Advances. The Borrower will not (directly or indirectly through any Subsidiary), and will not allow or suffer any Subsidiary to, make or permit to remain outstanding any loans or advances to or investments in or acquisitions of capital stock or ownership (direct or beneficial) interests or obligations of any Person (including without limitation any Subsidiary), except for:

(a)  Investments in direct obligations of the United States of America or any agency thereof.

(b)  Investments in either certificates of deposit of maturities less than one year issued by the Lender, or, if the Lender is not substantially competitive (in terms of its certificate of deposit interest rate for comparable amounts) with other banks (having a credit rating equal or better than the Lender's), certificates of deposit of maturities less than one year issued by one or more of such other banks.

(c)  Investments in commercial paper of maturities less than one year with the best rating by Standard & Poors, Moody's Investors Service, Inc., or any other rating agency satisfactory to the Lender.

(d)  Routine advances to employees made in the ordinary course of business, and that do not exceed historical levels in a material manner.

(e)  Advances pursuant to operating agreements, unitization and pooling agreements and orders, farmout agreements and gas balancing agreements, in each case that are customary in the oil, gas and mineral production business and that are entered into in the ordinary course of business.

(f)  Ownership of equity interests in PPL Operating and Paloma Pipeline.

(g)  Loans and advances made by the Borrower to Paloma Pipeline in the ordinary course of business to be used in the normal business operations of Paloma Pipeline.

(h)  Acquisitions of the capital stock of the Borrower up to and not to exceed, in any one fiscal year period, twenty (20%) percent of the Borrower's net worth at the prior fiscal year end.

Section 6.4 Nature of Business. The Borrower will not permit any material change to be made in the character of its business or the business of PPL Operating or Paloma Pipeline as carried on at the date hereof.

Section 6.5 Mergers and Consolidations. The Borrower will not, and will not allow or suffer any Subsidiary to, acquire, merge with or consolidate with any Person (whether or not such acquisition, merger or consolidation requires any capital expenditures on the part of the Borrower), without in each case the prior written consent of Lender, which shall not be unreasonably withheld.

Section 6.6 ERISA Compliance. The Borrower will not at any time permit any Plan maintained by it to engage in any "prohibited transaction" as such term is defined in Section 4975 of the Code; incur any "accumulated funding deficiency" as such term is defined in Section 302 of ERISA; or terminate any such Plan in a manner which could result in the imposition of a Lien on the property of the Borrower pursuant to Section 4068 of ERISA.

Section 6.7 Changes. The Borrower will not without 30 days prior notice to the Lender change the location of any of its Collateral, or change the location of its state of organization or chief executive office or change its name or taxpayer identification number.

Section 6.8 Sales. The Borrower will not, and will not allow or suffer any Subsidiary to, sell, assign, lease or otherwise dispose of (whether in one transaction or in a series of transactions) all or substantially all of its property (whether now owned or hereafter acquired) to any Person. The Borrower will not, and will not allow or suffer any Subsidiary to, sell, lease or otherwise dispose of any of its Collateral or any material portion of its other property, except for sales of production, collection of its accounts, and sales of items of equipment which are obsolete or otherwise no longer useful for such Person's operations, in each case in the ordinary course of business.

Section 6.9 Agreements. The Borrower will not enter into or be a party to any contract or agreement for the purchase of materials, supplies or other property or services if such contract or agreement shall require that the Borrower make payment for such materials, supplies or other property irrespective of whether delivery thereof is made or whether such services are rendered. Except in the ordinary course of business, the Borrower will not enter into any arrangement with any gas pipeline company or any other purchaser of hydrocarbons regarding the Collateral whereby the Borrower agrees that said gas pipeline company or purchaser may set off any claim against the Borrower by withholding payment for any hydrocarbons actually delivered.

Section 6.10 Dividends or Redemption of Shares. The Borrower will not (i) pay or declare any dividend on any class of its stock (other than stock dividends), (ii) make any other distribution or other shareholder expenditure on account of any class of its stock, nor set aside any funds for such purpose, nor (iii) otherwise make or agree to pay for or make, directly or indirectly, any other distribution with respect to any shares of any class of its stock, or any payment (whether in cash, securities or other property), including any sinking fund or similar deposit, on account of the purchase, redemption, retirement, acquisition, cancellation or termination of any such shares or any option, warrants or other right to acquire any such shares, except that (x) dividends may be declared and paid limited in an amount not to exceed fifty (50%) percent of the Borrower's prior year's fiscal year end net income on an annual basis and (y) the Borrower may make, and agree to make, acquisitions of its capital stock as permitted by Section 6.3(h).

Section 6.11 Compensation. The Borrower will not pay compensation to its employees, officers or directors in excess of reasonable salaries, bonuses and other benefits that are incurred in the ordinary course of business and do not exceed historical levels in a material manner (and, without limiting the foregoing, are not paid with the purpose or effect of avoiding the limitation established in Section 6.10 above).

Section 6.12 Management. The Borrower will not permit or suffer a change in the key management of the Borrower to occur. For purposes of this Section, key management shall mean the continued active employment of each of James Sigmon and Roberto Thomae; provided, however, that the cessation of employment of one such officer shall not be a Default hereunder so long as the Borrower hires or promotes a replacement officer with experience and qualifications reasonably acceptable to the Lender within six (6) months of the former officer's termination of employment .

Section 6.13 Change of Ownership or Control. (a) No Person or group (as defined in Section 13(d)(3) of the Securities Exchange Act of 1934), other than existing management and owners of capital stock of Borrower as of the Closing Date, shall become the beneficial owner of more than 33% of the total voting power of the capital stock of the Borrower then outstanding.

(b)  A majority of the members of the Board of Directors of the Borrower shall not cease to be Continuing Directors. For purposes of this Section, the term "Continuing Directors" of a Person means any member of such Person's Board of Directors who: (x) was a member of such Person's Board of Directors on the Closing Date; or (y) was nominated for election or elected with the approval of a majority of the Continuing Directors who were then members of such Person's Board of Directors (but excluding any such individual whose initial assumption of office occurs as a result of either an actual or threatened election contest or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Continuing Directors).

Section 6.14 Transactions with Affiliates. The Borrower will not sell, transfer, lease or otherwise dispose of (including pursuant to any merger) any property or assets to, or purchase, lease or otherwise acquire (including pursuant to a merger) any property or assets from, or otherwise engage in any other transactions with, any affiliates, except in the ordinary course of business at prices and on terms and conditions not less favorable to the Borrower as could be obtained on an arms-length basis from unrelated third persons in a comparable transaction.

Section 6.15 Subsidiaries. (a) The Borrower will not allow or suffer any changes to be made in the ownership structure of PPL Operating, and shall not own and control less than one hundred (100%) percent of the ownership and voting rights in PPL Operating. The Borrower will not create, incur, assume or permit to exist any Lien on its equity interest in PPL Operating, other than in favor of the Lender.

(b)  The Borrower will not allow or suffer any change or combination of changes in the ownership or voting rights in Paloma Pipeline to occur such that the Borrower (directly or indirectly) owns and controls less than sixty (60%) percent of the limited partners' ownership and voting rights in Paloma Pipeline. The Borrower shall not allow or suffer PPL Operating to cease to be the sole general partner of Paloma Pipeline. The Borrower will not create, incur, allow or suffer any Lien to exist on any partnership interest in Paloma Pipeline held by the Borrower or PPL Operating. The Borrower will not allow or suffer any amendment or other change in the articles of partnership of Paloma Pipeline.

ARTICLE 7

CONDITIONS OF LENDING

Section 7.1 Conditions of Lending. The obligation of the Lender to make the Loan (or issue a standby letter of credit) is subject to the accuracy of each and every representation and warranty of the Borrower contained in this Agreement, the absence of a Default or an Event of Default, and to the receipt of the following on or before the Closing Date:

(a)  Agreement. A duly executed counterpart of this Agreement signed by all the parties hereto.

(b)  Note. The duly executed Note signed by the Borrower.

(c)  Good Standing. Certificates of good standing of the Borrower issued by the Secretaries of State of Delaware and Texas.

(d)  Corporate Certificate. A certificate of the secretary of the Borrower (i) setting forth resolutions of its board of directors in form and substance satisfactory to the Lender with respect to the unanimous authorization of this Agreement, the Note and the Collateral Documents, (ii) attaching the articles of incorporation and bylaws of the Borrower, (iii) stating its Federal tax identification number and Delaware corporate registration number, and (iv) setting forth the officers authorized to sign such instruments.

(e)  Fee. The second installment of the commitment fee required by Section 2.5.

(f)  Collateral Documents. Duly executed and recorded mortgages or deeds of trust, and executed pledges, and filed financing statements covering the Collateral.

(g)  Lien Searches. UCC lien searches satisfactory to the Lender from Delaware and Texas pertaining to the Borrower.

(h)  Title Opinions. Preliminary title opinions with respect to the Collateral, with a recent effective date and otherwise in form, scope and substance satisfactory to the Lender and Lender's counsel, which indicate that the Borrower has good and marketable title to the interests in the Collateral in amounts not less than those specified in the Collateral Documents or otherwise represented to Lender, subject to no Liens other than the Collateral Documents and those accepted by the Lender in writing.

(i)  Legal Opinion. Legal opinion in form, scope and substance satisfactory to the Lender and Lender's counsel.

(j)  Insurance. Satisfactory evidence of all insurance coverages relating to the Collateral and the Borrower.

(k)  Environmental. Complete documentation pertaining to any previous fines levied against the

Borrower or any current operator of the Collateral for non-compliance with applicable federal, state and local environmental laws and regulations.

(l)  Subsidiaries. Copies of the articles of partnership of Paloma Pipeline and the articles of incorporation and bylaws of PPL Operating.

(m)  Stock. The original stock certificate held by Borrower for its shares in PPL Operating, duly indorsed to the Lender.

In the event that the Lender in its sole and absolute discretion waives the receipt of any items set forth above, the Borrower agrees that it nonetheless will promptly deliver such item to the Lender upon request within the time period reasonably specified by the Lender.

Section 7.2 Certification. The obligation of the Lender to make the Loan is further subject to the certification by the Borrower, which the Borrower hereby makes, that no Default or Event of Default exists, and that no material adverse change (in the Lender's sole determination) in the Collateral or other assets, liabilities, financial condition, business operations, affairs or circumstances of the Borrower or other facts, circumstances or conditions (financial or otherwise) upon which Lender has relied or utilized in making its decision to make this Loan have occurred from those reflected in the most recent financial statements furnished to the Lender prior to the Closing Date or otherwise existing at the time of the issuance of Lender's commitment letter.

Section 7.3  Post-Closing Items. (a) The Borrower will furnish the Lender with updated title opinions by May 3, 2002, on the Collateral updating title through and confirming the recordation of the Lender's Collateral Documents and the Lender's first priority Lien.

(b)  Certain properties included within the Borrowing Base from time to time at zero or low value may not be covered by title opinions at the time of their inclusion in the Borrowing Base. The Borrower acknowledges and agrees that the Lender has the right under the terms of this Agreement to require title opinions on such Borrowing Base properties in the future, whether at the time of an increase in the value attributed to such property in the Borrowing Base or otherwise, and Borrower agrees promptly to deliver such title opinions and acknowledges that in the absence thereof such properties may be excluded by the Lender from the Borrowing Base (as provided in the definition of Borrowing Base).

Section 7.4 Each Additional Advance. The obligation of the Lender to make additional Advances on the line of credit or issue standby letters of credit is subject to the satisfaction of each of the following conditions:

(a)  Each of the representations and warranties of the Borrower contained in this Agreement shall be true and correct on and as of the date of each subsequent Advance, except as such representations and warranties relate to matters that are permitted by this Agreement.

(b)  At the time of such Advance, no Default shall have occurred and be continuing.

(c)  There shall have occurred no material adverse change (in the Lender's sole determination), either individually or in the aggregate, in the assets,

liabilities, financial condition, business operations, affairs or circumstances of the Borrower, from those reflected in the most recent financial statements furnished to the Lender prior to the Closing Date, except to the extent that such changes are permitted by this Agreement.

(d)  If reasonably required by Lender, a bringdown title search in the appropriate states, confirming the absence of Lien filings against the Borrower since the effective date of the preceding bringdown search.

Section 7.5 Title Opinions. It is expressly acknowledged by the Borrower that the waiver by the Borrower (on the basis of the Borrower's business judgment) of any title requirements contained in any title opinions delivered to the Lender from time to time in connection with this Agreement, and funding by the Lender of Advances, shall not constitute a waiver by the Lender of any of the representations or warranties of the Borrower contained herein.

ARTICLE 8

DEFAULT

Section 8.1 Events of Default. Any of the following events shall be considered an "Event of Default" as that term is used herein:

(a)  Principal and Interest Payments. The Borrower fails to make payment (x) when due of any principal or interest installment on the Note, any unused facility fee, any commitment fee, engineering fee or any other Indebtedness incurred pursuant to this Agreement to the Lender, and such failure continues unremedied for a period of five (5) Business Days after the earlier of (i) notice thereof being given by the Lender to the Borrower or (ii) such default otherwise becoming known to the president or chief financial officer of the Borrower or (y) when due of any mandatory prepayment under Subsection 2.4(b).

(b)  Representations and Warranties. Any representation or warranty made by or on behalf of the Borrower contained in this Agreement, the Note or any of the Collateral Documents proves to have been incorrect in any material respect as of the date thereof; or any representation, statement (including financial statements), certificate or data furnished or made to the Lender by any Person under this Agreement, the Note or any of the Collateral Documents proves to have been untrue in any material adverse respect as of the date as of which the facts therein set forth were stated or certified.

(c)  Specific Covenants. The Borrower fails to observe or perform at any time any covenant or agreement contained in Section 5.6, Section 5.8, Section 5.15, or Article 6 of this Agreement.

(d)  Covenants. The Borrower or other Person (other than the Lender) defaults in the observance or performance of any of the covenants or agreements contained in this Agreement, the Note or any of the Collateral Documents to be kept or performed by the Borrower or such Person (other than a default under Subsections (a) through (c) hereof), and such default continues unremedied for a period of 30 days after the earlier of (i) notice thereof being given by the Lender to the Borrower or such Person, as applicable, or (ii) such default (and the fact that it is a default) otherwise becoming known to the president or chief financial officer of the Borrower or other Person, as applicable.

(e)  Other Debt to Lender. The Borrower defaults in the payment of any amounts due to the Lender or in the observance or performance of any of the covenants, or agreements contained in any loan agreements, notes, leases, collateral or other documents relating to any Debt of the Borrower to the Lender other than the Indebtedness, and any grace period applicable to such default has elapsed.

(f)  Other Debt to Other Lenders. The Borrower defaults in the payment of any amounts due to any Person (other than the Lender) or in the observance or performance of any of the covenants or agreements contained in any credit agreements, notes, leases, collateral or other documents relating to any Debt of the Borrower to any Person (other than the Lender) in excess of $500,000.00, and any grace period applicable to such default has elapsed.

(g)  Involuntary Bankruptcy or Receivership Proceedings. A receiver, conservator, liquidator or trustee of the Borrower, or of any of its property, is appointed by order or decree of any court or agency or supervisory authority having jurisdiction; or an order for relief is entered against the Borrower under the Federal Bankruptcy Code; or the Borrower is adjudicated bankrupt or insolvent; or any material portion of the property of the Borrower is sequestered by court order and such order remains in effect for more than 30 days after such party obtains knowledge thereof; or a petition is filed against the Borrower under any reorganization, arrangement, insolvency, readjustment of debt, dissolution, liquidation or receivership law of any jurisdiction, whether now or hereafter in effect, and such petition is not dismissed within 60 days.

(h)  Voluntary Petitions. The Borrower files a case under the Federal Bankruptcy Code or seeking relief under any provision of any bankruptcy, reorganization, arrangement, insolvency, readjustment of debt, dissolution or liquidation law of any jurisdiction, whether now or hereafter in effect, or consents to the filing of any case or petition against it under any such law.

(i)  Assignments for Benefit of Creditors. The Borrower makes an assignment for the benefit of its creditors, or admits in writing its inability to pay its debts generally as they become due, or consents to the appointment of a receiver, trustee or liquidator of the Borrower or of all or any part of its property.

(j)  Undischarged Judgments. Judgment for the payment of money in excess of $20,000.00 (which is not covered by insurance) is rendered by any court or other governmental body against the Borrower, and the Borrower does not discharge the same or provide for its discharge in accordance with its terms, or procure a stay of execution thereof within 30 days from the date of entry thereof, and within said 30-day period or such longer period during which execution of such judgment shall have been stayed, appeal therefrom and cause the execution thereof to be stayed during such appeal while providing such reserves therefor as may be required under generally accepted accounting principles.

(k)  Attachment. A writ or warrant of attachment or any similar process shall be issued by any court against all or any material portion of the property of the Borrower, and such writ or warrant of attachment or any similar process is not released or bonded within 30 days after its entry.

(l)  Invalidity. The Borrower shall assert in writing that any material provision of this Agreement, the Note or any of the Collateral Documents shall for any reason be or cease to be valid and binding on the Borrower after the Closing Date.

Section 8.2 Remedies. (a) Upon the happening of any Event of Default specified in the preceding Section (other than Subsections (g) or (h) thereof), (i) all obligations, if any, of the Lender to make Advances to the Borrower shall immediately cease and terminate, and (ii) the Lender may by written notice to the Borrower declare the entire principal amount of all Indebtedness then outstanding including interest accrued thereon to be immediately due and payable without presentment, demand, protest, notice of protest or dishonor or other notice of default of any kind, all of which are hereby expressly waived by the Borrower.

(b) Upon the happening of any Event of Default specified in Subsections (g) or (h) of the preceding Section, (i) all obligations, if any, of the Lender to make Advances to the Borrower shall immediately cease and terminate, and (ii) the entire principal amount of all obligations then outstanding including interest accrued thereon shall, without notice or action by the Lender, be immediately due and payable without presentment, demand, protest, notice of protest or dishonor or other notice of default of any kind, all of which are hereby expressly waived by the Borrower.

(c)  In addition to the foregoing, the Lender may exercise any of the rights and remedies established in the Collateral Documents or avail itself of any other rights and remedies provided by applicable law.

(d)  In furtherance of the foregoing, to the extent that any standby letters of credit are outstanding upon the occurrence of any Event of Default, the Lender may be written notice to the Borrower require the Borrower to pay to the Lender immediately on such demand the full face amount of such letters of credit to be held by the Lender as collateral for the payment of such letters of credit.

Section 8.3 Set-Off. Upon the occurrence of any Event of Default, the Lender shall have the right to set-off any funds of the Borrower in the possession of the Lender (including without limitation funds in the accounts provided for in Article 5) against any amounts then due by the Borrower to the Lender pursuant to the Agreement (but the Borrower acknowledges that the Lender may apply funds in such accounts against any interest, fee or mandatory principal prepayment amounts then due and payable by the Borrower even without the occurrence of an Event of Default). The Borrower agrees that any holder of a participation in the Note may exercise any and all rights of counter-claim, set-off, banker's lien and other liens with respect to any and all monies owing by Borrower to such holder as fully as if such holder of a participation were a holder of a note in the amount of such participation.

Section 8.4 Marshaling. The Borrower shall not in any time hereafter assert any right under any law pertaining to marshaling (whether of assets or liens) and the Borrower expressly agrees that the Lender may execute or foreclose upon the Collateral Documents in such order and manner as the Lender, in its sole discretion, deems appropriate.

ARTICLE 9

MISCELLANEOUS

Section 9.1 Notices. Any notice or demand which, by provision of this Agreement, is required or permitted to be given by one party to the other party hereunder shall be given by (i) deposit, postage prepaid, in the mail, registered or certified mail, or (ii) delivery to a recognized express courier service, or (iii) delivery by hand, or (iv) by facsimile, in each case addressed (until another address or addresses is given in writing by such party to the other party) as follows:

If to Borrower:  The Exploration Company of Delaware, Inc.

500 North Loop 1604 East, Suite 250

San Antonio, Texas 78232

Attention: Chief Financial Officer

Facsimile Number: (210) 496-3232

If to Lender:  Hibernia National Bank

P. O. Box 61540

New Orleans, Louisiana 70161

or

313 Carondelet Street

New Orleans, Louisiana 70130

Attention: Manager

Energy/Maritime Department

Facsimile Number: (504) 533-5434

All notices sent by facsimile transmission shall be deemed received by the addressee upon the transmitter's receipt of acknowledgment of receipt from the offices of such addresses (if before 5:00 p.m. on a Business Day; if later, than on the next Business Day).

Section 9.2 Entire Agreement. This Agreement, the Note and the Collateral Documents set forth the entire agreement of the Lender and the Borrower with respect to the Indebtedness, and supersede all prior written or oral understandings with respect thereto; provided, however, that all written representations, warranties and certifications made by the Borrower to the Lender with respect to the Indebtedness and the security therefor shall survive

the execution of this Agreement. The Borrower is not relying on any representation by the Lender, and no representation has been made, that the Lender will, at the time of a Default or at any other time, waive, negotiate, discuss, or take or refrain from taking any action with respect to such Default.

Section 9.3 Renewal, Extension or Rearrangement. All provisions of this Agreement relating to the Note shall apply with equal force and effect to each and all promissory notes or security instruments hereinafter executed which in whole or in part represent a renewal, extension for any period, increase or rearrangement of any part of the Note.

Section 9.4 Amendment. Neither this Agreement nor any provisions hereof may be changed, waived, discharged or terminated orally or in any manner other than by an instrument in writing signed by the party against whom enforcement of the change, waiver, discharge or termination is sought.

Section 9.5 Invalidity. In the event that any one or more of the provisions contained in this Agreement, the Note, or the Collateral Documents shall, for any reason, be held invalid, illegal or unenforceable in any respect, such invalidity, illegality or unenforceability shall not affect any other provision of this Agreement, the Note or the Collateral Documents.

Section 9.6 Survival of Agreements. All representations and warranties of the Borrower herein, and all covenants and agreements herein not fully performed before the effective date of this Agreement, shall survive such date.

Section 9.7 Waivers. No course of dealing on the part of the Lender, its officers, employees, consultants or agents, nor any failure or delay by the Lender with respect to exercising any of its rights, powers or privileges under this Agreement, the Note or the Collateral Documents, shall operate as a waiver thereof.

Section 9.8 Cumulative Rights. The rights and remedies of the Lender under this Agreement, the Note and the Collateral Documents shall be cumulative, and the exercise or partial exercise of any such right or remedy shall not preclude the exercise of any other right or remedy.

Section 9.9 Time of the Essence. Time shall be deemed of the essence with respect to the performance of all of the terms, provisions and conditions on the part of the Borrower and the Lender to be performed hereunder.

Section 9.10 Successors and Assigns; Participants. (a) All covenants and agreements made by or on behalf of the Borrower in this Agreement, the Note and the Collateral Documents shall bind its successors and assigns and shall inure to the benefit of the Lender and its successors and assigns. The Borrower may not assign its rights or obligations under this Agreement.

(b)  This Agreement is for the benefit of the Lender and for such other Person or Persons as may from time to time become or be the holders of any of the Indebtedness, and this Agreement shall be transferrable and negotiable, with the same force and effect and to the same extent as the Indebtedness may be transferrable, it being understood that, upon the transfer or assignment by the Lender of any of the Indebtedness, the legal holder of such Indebtedness shall have all of the rights granted to the Lender under this Agreement.

(c)  The Borrower hereby recognizes and agrees that the Lender may, from time to time, one or more times, transfer all or any portion of the Indebtedness to one or more third parties. Such transfers may include, but are not limited to, sales of participation interests in such Indebtedness in favor of one or more third party lenders. Borrower specifically (i) consents to all such transfers and assignments, waives any subsequent notice of and right to consent to any such transfers and assignments as may be provided under applicable Louisiana law; (ii) agrees that the purchaser of a participation interest in the Indebtedness will be considered as the absolute owner of a percentage interest of such Indebtedness and that such a purchaser will have all of the rights granted to the purchaser under any participation agreement governing the sale of such a participation interest; (iii) waives any right of offset that Borrower may have against the Lender, and/or any purchaser of such a pa rticipation interest in the Indebtedness, and unconditionally agrees that either the Lender or such a purchaser may enforce Borrower's Indebtedness under this Agreement, irrespective of the failure or insolvency of the Lender or any such purchaser; (iv) agrees that any purchaser of a participation interest in the Indebtedness may exercise any and all rights of counter-claim, set-off, banker's lien and other liens with respect to any and all monies owing to the Borrower; and (v) agrees that, upon any transfer of all or any portion of the Indebtedness, the Lender may transfer and deliver any and all collateral securing repayment of such Indebtedness to the transferee of such Indebtedness and such collateral shall secure any and all of the Indebtedness in favor of such a transferee, and after any such transfer has taken place, the Lender shall be fully discharged from any and all future liability and responsibility to Borrower with respect to such collateral, and the transferee thereafter shall be vested with a ll the powers, rights and duties with respect to such collateral.

Section 9.11 Relationship Between the Parties. The relationship between the Lender and the Borrower shall be solely that of lender and borrower, and such relationship shall not, under any circumstances whatsoever, be construed to be a joint venture, joint adventure, or partnership. The Lender has no fiduciary obligation to the Borrower with respect to this Agreement or the transactions contemplated hereby.

Section 9.12 Limitation of Liability. This Agreement, the Note and the Collateral Documents are executed by an officer of the Lender, and by acceptance of the Loan, the Borrower agrees that for the payment of any claim or the performance of any obligations hereunder resulting from any default by the Lender, resort shall be had solely to the assets and property of the Lender, and no shareholder, officer, employee or agent of the Lender shall be personally liable therefor.

Section 9.13 Titles of Articles, Sections and Subsections. All titles or headings to articles, sections, subsections or other divisions of this Agreement or the exhibits hereto are only for the convenience of the parties and shall not be construed to have any effect or meaning with respect to the other content of such articles, sections, subsections or other divisions, such other content being controlling as to the agreement between the parties hereto.

Section 9.14 Singular and Plural. Words used herein in the singular, where the context so permits, shall be deemed to include the plural and vice versa. The definitions of words in the singular herein shall apply to such words when used in the plural where the context so permits and vice versa.

SECTION 9.15 GOVERNING LAW. THIS AGREEMENT IS, AND THE NOTE WILL BE, CONTRACTS MADE UNDER AND SHALL BE CONSTRUED IN ACCORDANCE WITH AND GOVERNED BY THE LAWS OF THE UNITED STATES OF AMERICA AND THE STATE OF LOUISIANA.

Section 9.16 Counterparts. This Agreement may be executed in two or more counterparts, and it shall not be necessary that the signatures of all parties hereto be contained on any one counterpart hereof; each counterpart shall be deemed an original, but all of which together shall constitute one and the same instrument.

SECTION 9.17 WAIVER OF JURY TRIAL; SUBMISSION TO JURISDICTION. (a) THE BORROWER AND THE LENDER HEREBY WAIVE TRIAL BY JURY IN ANY ACTION OR PROCEEDING TO WHICH THE BORROWER AND THE LENDER MAY BE PARTIES, ARISING OUT OF OR IN ANY WAY PERTAINING TO (i) THE NOTE, (ii) THIS AGREEMENT, (iii) THE COLLATERAL DOCUMENTS OR (iv) THE COLLATERAL. IT IS AGREED AND UNDERSTOOD THAT THIS WAIVER CONSTITUTES A WAIVER OF TRIAL BY JURY OF ALL CLAIMS AGAINST ALL PARTIES TO SUCH ACTIONS OR PROCEEDINGS, INCLUDING CLAIMS AGAINST PARTIES WHO ARE NOT PARTIES TO THIS AGREEMENT. THIS WAIVER IS KNOWINGLY, WILLINGLY AND VOLUNTARILY MADE BY THE BORROWER AND THE LENDER, AND THE BORROWER AND THE LENDER HEREBY REPRESENT THAT NO REPRESENTATIONS OF FACT OR OPINION HAVE BEEN MADE BY ANY INDIVIDUAL TO INDUCE THIS WAIVER OF TRIAL BY JURY OR TO IN ANY WAY MODIFY OR NULLIFY ITS EFFECT. THE BORROWER AND THE LENDER FURTHER REPRESENT THAT IT HAS BEEN REPRESENTED IN THE SIGNING OF THIS AGREEMENT AND IN THE MAKING OF THIS WAIVER B Y INDEPENDENT LEGAL COUNSEL, SELECTED OF ITS OWN FREE WILL, AND THAT IT HAD THE OPPORTUNITY TO DISCUSS THIS WAIVER WITH COUNSEL.

(b)  THE BORROWER HEREBY IRREVOCABLY CONSENTS TO THE NON-EXCLUSIVE JURISDICTION OF THE STATE COURTS OF LOUISIANA AND THE FEDERAL EASTERN DISTRICT COURT IN LOUISIANA, AND AGREES THAT ANY ACTION OR PROCEEDING ARISING OUT OF OR BROUGHT TO ENFORCE THE PROVISIONS OF THE NOTE, THIS AGREEMENT AND/OR THE COLLATERAL DOCUMENTS MAY BE BROUGHT IN ANY COURT HAVING SUBJECT MATTER JURISDICTION. THE BORROWER HEREBY IRREVOCABLY WAIVES ANY OBJECTIONS THAT IT MAY NOW OR HEREAFTER HAVE TO THE VENUE OF ANY SUCH ACTION OR PROCEEDING IN ANY SUCH COURT OR THAT ANY SUCH ACTION OR PROCEEDING WAS BROUGHT IN AN INCONVENIENT COURT AND AGREES NOT TO PLEAD OR CLAIM THE SAME. THE BORROWER AGREES THAT NOTHING HEREIN SHALL LIMIT THE LENDER'S RIGHT TO SUE IN ANY OTHER JURISDICTION.

(c)  THE BORROWER HEREBY AGREES THAT SERVICE OF PROCESS IN ANY SUCH ACTION OR PROCEEDING MAY BE EFFECTED BY MAILING A COPY BY REGISTERED OR CERTIFIED MAIL (OR ANY SUBSTANTIALLY SIMILAR FORM OF MAIL) POSTAGE PREPAID, TO THE BORROWER AT ITS ADDRESS SET FORTH IN SECTION 9.1 OR AT SUCH OTHER ADDRESS AS TO WHICH THE LENDER SHALL HAVE BEEN NOTIFIED PURSUANT THERETO. THE BORROWER AGREES THAT NOTHING HEREIN SHALL AFFECT THE RIGHT TO EFFECT SERVICE OF PROCESS IN ANY OTHER MANNER PERMITTED BY LAW.

SECTION 9.18 AGREEMENT SUPERCEDES ALL PRIOR AGREEMENTS. THIS AGREEMENT, TOGETHER WITH THE NOTE, THE COLLATERAL DOCUMENTS, AND ANY OTHER WRITTEN INSTRUMENTS EXECUTED PURSUANT TO THIS AGREEMENT REPRESENT, COLLECTIVELY, THE FINAL AGREEMENT BETWEEN THE PARTIES HERETO WITH RESPECT TO THE SUBJECT HEREOF AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES AND SHALL SUPERSEDE ANY PRIOR AGREEMENT BETWEEN THE PARTIES HEREOF, WHETHER WRITTEN OR ORAL, RELATING TO THE SUBJECT HEREOF. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

IN WITNESS WHEREOF, the parties hereto have caused this instrument to be duly executed as of the date first above written.

BORROWER:            THE EXPLORATION COMPANY OF DELAWARE, INC.

By:    /s/ James E. Sigmon 

Name:    James E. Sigmon

Title:     President

LENDER:                  HIBERNIA NATIONAL BANK

By: /s/ Nancy Moragas

Name: Nancy Moragas

Title:  Vice President

ADDENDUM I

LIBO RATE PROVISIONS

1.  The Lender shall determine the interest rate applicable to LIBO Rate Advances, and its determination shall be conclusive in the absence of manifest error. The Lender shall endeavor to notify the Borrower prior to the date on which an interest payment is due, provided that the failure of the Lender to provide such notice shall not affect the Borrower's obligation to pay interest on such date.

2.  If any applicable law or regulation, or the action of any applicable regulatory requirement increases the reserves or capital required to be maintained by the Lender with respect to the Loan (including unfunded commitments and obligations on letter of credit), the Lender shall promptly deliver a certificate to the Borrower specifying the additional amount as will compensate the Lender for the additional costs, which certificate shall be conclusive in the absence of manifest error. The Borrower shall pay the amount specified in such certificate promptly upon receipt.

3.  If the Lender gives notice to the Borrower that no LIBO bid rate is quoted to the Lender (or otherwise that adequate and reasonable methods do not exist for ascertaining the LIBO Rate) for the applicable Interest Period or in the applicable amounts (which notice shall be conclusive and binding on the Borrower absent manifest error), then (A) the obligation of the Lender to make a LIBO Rate Advance and the ability of the Borrower to select the LIBO Rate for an Advance shall be suspended, and (B) the Borrower shall either prepay all LIBO Rate Advances for which an interest rate is to be determined on such date or the Loan shall thereafter bear interest at the Base Rate.

4.  If any applicable domestic or foreign law, treaty, rule or regulation (whether now in effect or hereinafter enacted or promulgated, including Regulation D of the Board of Governors of the Federal Reserve System) or any interpretation or administration thereof by any governmental authority charged with the interpretation or administration thereof (whether or not having the force of law):

(i)  changes the basis of taxation of payments to the Lender or any principal, interest, or other amounts attributable to any LIBO Rate Advance (other than taxes imposed on the overall net income of the Lender);

(ii)  changes, imposes, modifies, applies or deems applicable any reserve, special deposit or similar requirements in respect of any such LIBO Rate Advance (excluding those for which the Lender is fully compensated pursuant to adjustments made in the definition of LIBO Rate) or against assets of, deposits with or for the account of, or credit extended by, the Lender; or

(iii)  imposes on the Lender or the interbank eurocurrency deposit and transfer market any other condition or requirement affecting any such LIBO Rate Advance,

and the result of any of the foregoing is to increase the cost to the Lender of funding or maintaining any such LIBO Rate Advance (other than costs for which the Lender is fully compensated pursuant to adjustments made in the definition of LIBO Rate) or to reduce the amount of any sum receivable by the Lender in respect of any such LIBO Rate advance by an amount deemed by the Lender to be material, then or the Lender shall promptly notify the Borrower in writing of the happening of such event and (1) Borrower shall upon demand pay to the Lender such additional amount or amounts as will compensate the Lender for such additional cost or reduction and (2) Borrower may elect, by giving to the Lender not less than three Business Days' notice, to change the interest rate applicable to such Advance, and any other portion of the Loan bearing interest at the LIBO Rate, to the Base Rate.

5.  Notwithstanding any other provision hereof, if any change in applicable laws, treaties, rules or regulations or in the interpretation or administration thereof of or in any jurisdiction whatsoever, domestic or foreign, shall make it unlawful or impracticable for the Lender to maintain Advances bearing interest at the LIBO Rate, or shall materially restrict the authority of the Lender to purchase, sell or take certificates of deposit or offshore deposits of dollars, then, upon notice by the Lender to Borrower, the Lender's portion of all LIBO Rate Advances which are then outstanding and which cannot lawfully or practicably be maintained shall immediately cease to bear interest at the LIBO Rate and shall commence to bear interest at the Base Rate. The Borrower agrees to indemnify the Lender and hold it harmless against all costs, expenses, claims, penalties, liabilities and damages which may result from any such change in law, treaty, rule, regulation, interpretation or admini stration. The Borrower hereby agrees promptly to pay the Lender, upon demand by the Lender, any additional amounts necessary to compensate the Lender for any costs incurred by the Lender in making any conversation in accordance with this Paragraph, including any interest or fees payable by the Lender to lenders of funds obtained by it in order to make or maintain hereunder its portion of the Loan accruing interest based on the LIBO Rate.

6.  The Borrower will indemnify the Lender against, and reimburse the Lender on demand for, any loss or expense incurred or sustained by the Lender (including without limitation, any loss or expense incurred by reason of the liquidation or reemployment of deposits or other funds acquired by the Lender to fund or maintain LIBO Rate Advances) as a result of (i) any payment or prepayment (whether authorized or required hereunder or otherwise, including without limitation a mandatory prepayment when required under Section 2.4(b) of the Agreement) of all or a portion of any LIBO Rate Advance on a day other than the day on which the applicable Interest Period ends, (ii) any payment or prepayment, whether required hereunder or otherwise, of the LIBO Rate Advances made after the delivery, but before the effective date, of an election to have the LIBO Rate apply to LIBO Rate Advance, if such payment or prepayment prevents such election from becoming fully effective, or (iii) the failure o f any LIBO Rate Advance to be made by the Lender or of any such election to become effective due to any condition precedent to a LIBO Rate Advance not being satisfied or due to any other action or

inaction of Borrower. For purposes of this section, funding losses arising by reason of liquidation or reemployment of deposits or other funds acquired by the Lender to fund or maintain LIBO Rate Advances shall be calculated as the remainder obtained by subtracting: (1) the yield (reflecting both stated interest rate and discount, if any) to maturity of obligations of the United States Treasury as determined by the Lender in an amount equal or comparable to such advance for the period of time commencing on the date of the payment, prepayment or change of rate as provided above and ending on the last day of the subject Interest Period, from (2) the LIBO Rate of the subject Interest Period, times the number of days from the date of payment, prepayment or change of rate to the last day of the subject Interest Period, divided by 360. Any payment due under this paragraph will be paid to the Lender within five days after demand therefor by the Lender.

7.  The Borrower covenants and agrees that

(i) The Borrower will pay, within five days after notice thereof from Lender and on an after-tax basis, all present and future income, stamp and other taxes, levies, costs and charges whatsoever imposed, assessed, levied or collected on or in respect of any LIBO Rate Advance whether or not legally or correctly imposed, assessed, levied or collected (excluding taxes, levies, costs or charges imposed on or measured by the overall net income of the Lender) (all such non-excluded taxes, levies, costs and charges being collectively called "Reimbursable Taxes"). Promptly after the date on which payment of any Reimbursable Taxes is due pursuant to applicable law, the Borrower will, at the request of the Lender, furnish to the Lender evidence in form and substance satisfactory to the Lender that Borrower has met its obligation under this paragraph.

(ii) The Borrower will indemnify the Lender against, and reimburse the Lender on demand for, any Reimbursable Taxes paid by the Lender and any loss, liability, claim or expense, including interest, penalties and legal fees, that the Lender may incur at any time arising out of or in connection with the failure of Borrower to make any payment of Reimbursable Taxes when due, unless such failure is due to the Lender's failure to give notice to Borrower of Borrower's obligation to pay such Reimbursable Taxes at least five days prior to the date when they are due. Any payment due under this subsection will be paid to the Lender within five days after demand therefor by the Lender.

(iii) All payments on account of the principal of, and interest on, LIBO Rate Advances and all other amounts payable by Borrower to the Lender hereunder shall be made free and clear of and without reduction by reason of any Reimbursable Taxes.

(iv) If Borrower is ever required to pay any Reimbursable Taxes with respect to any LIBO Rate Advance, Borrower may elect, by giving to the Lender not less than three (3) Business Days' notice, to change the interest rate applicable to any such advance from the LIBO Rate to the Base Rate, but such election shall not diminish Borrower's obligation to pay all Reimbursable Taxes therefore imposed, assessed, levied or collected.

EX-10

EXHIBIT 10.13

FIRST AMENDMENT

TO LOAN AGREEMENT

THIS FIRST AMENDMENT TO LOAN AGREEMENT (this "Amendment") dated as of December 13, 2002, is made between THE EXPLORATION COMPANY OF DELAWARE, INC., a Delaware corporation ("Borrower"), and HIBERNIA NATIONAL BANK, a national banking association ("Lender") who agree as follows:

RECITALS

A.  The Borrower and the Lender entered into that certain Loan Agreement dated as of March 4, 2002 (the "Loan Agreement"). Unless otherwise specified herein, capitalized terms used in this Amendment shall have the meanings indicated in the Loan Agreement.

B.  The Borrower and the Lender desire to alter the Borrowing Base of the Loan, and otherwise to provide with respect to the Loan.

AGREEMENT

NOW, THEREFORE, in consideration of the terms and conditions contained herein, and the loans and extensions of credit heretofore, now or hereafter made to the Borrower by the Lender, the parties hereto hereby agree as follows:

ARTICLE 1.

AMENDMENTS

1.1  The Borrower and the Lender hereby amend Section 2.4 (Prepayment) of the Loan Agreement by adding a new Subsection 2.4(c), to read in its entirety as follows:

(c)

As part of a Borrowing Base redetermination, the Lender may include as part of the Borrowing Base an automatic reduction schedule, monthly or quarterly, in an amount determined by the Lender in its sole discretion, but based upon the Lender's customary standards and practices from time to time in effect with respect to secured oil and gas property lines of credit. Such automatic reductions, each in the amounts so determined and so scheduled (each a "Periodic Reduction"), shall cause an automatic reduction to the Borrowing Base on the dates set in the schedule so determined by the Lender. Each reduction to the Borrowing Base by a Periodic Reduction shall be permanent, subject to any increase agreed to as part of a subsequent Borrowing Base redetermination. As part of the notification by the Lender to the Borrower of the result of a Borrowing Base redetermination, the Lender shall notify the Borrower of the terms and schedule of any Periodic Reductions included therein. Notwithstanding t he foregoing provisions of Subsection 2.4(b), the Borrower shall pay the amount of any Loan Excess that results from the application of each Periodic Reduction to the Borrowing Base on the day that such Periodic Reduction takes effect. The Borrowers specifically acknowledges that the thirty (30) day grace period set forth in Subsection 2.4(b) pertaining to a Loan Excess resulting from a Borrowing Base redetermination is not applicable to any failure to make such mandatory prepayment triggered by a Loan Excess due to a Periodic Reduction as provided in this Subsection 2.4(c).

1.2  The Borrower and the Lender hereby amend Subsection 8.1(a) of the Loan Agreement, by adding the words "or Subsection 2.4(c)" to the end of clause (y) of Subsection 8.1(a).

1.3  The Borrower and the Lender acknowledge and agree that in accordance with the Loan Agreement, periodic changes in the Borrowing Base and the Amount (and hence the Commitment Limit) may be made, without need of formal amendment to the Loan Agreement (but nonetheless evidenced in writing). For the avoidance of doubt, the Borrower and the Lender agree that as of the time of this Amendment, the Amount has been increased to thirteen million ($13,000,000.00) dollars (having been previously increased from the Amount on the Closing Date of $5,000,000.00 to $10,000,000.00 previously). Furthermore, as of the time of this Amendment, the Borrowing Base has been increased to thirteen million ($13,000,000.00) dollars. As part of that increase to and redetermination of the Borrowing Base, the Borrower acknowledges and agrees that the Lender has established Periodic Reductions to the Borrowing Base in the amounts of $1,000,000.00 on December 31, 2002, and $1,000,000.00 on March 31, 2003.

ARTICLE 2.

ACKNOWLEDGMENT OF COLLATERAL

2.1  The Borrower hereby specifically reaffirms all of the Collateral Documents.

ARTICLE 3.

MISCELLANEOUS

3.1  The Borrower represents and warrants to the Lender (which representations and warranties will survive the execution of this Amendment) that (i) all representations and warranties contained in the Loan Agreement and the Collateral Documents are true and correct on and as of the date hereof as though made on and as of such date, (ii) no event has occurred and is continuing as of the date hereof which constitutes a Default or Event of Default, (iii) there has not occurred any material adverse change in the Collateral or other assets, liabilities, financial condition, business operations, affairs or circumstances of the Borrower or any other facts, circumstances or conditions (financial or otherwise) upon which the Lender has relied or utilized in making its decision to enter into this Amendment, and (iv) there is no defense, offset, compensation, counterclaim or reconventional demand with respect to amounts due under, or performance of, the terms of the Note. To the extent any such defense, offset, compensation, counterclaim or reconventional demand or other causes of action by the Borrower against the Lender might exist, whether known or unknown, such items are hereby waived by the Borrower.

3.2  Subject to the specific amendment set forth in paragraphs 1.1 and 1.2 of this Amendment and the other provisions contained in this Amendment, all terms and provisions of the Loan Agreement and of the Note are hereby ratified and confirmed, and shall be and remain in full force and effect, enforceable in accordance with their terms.

3.3  The Borrower agrees to pay on demand all reasonable expenses of Lender in connection with the preparation, reproduction, execution and delivery of this Amendment and the other instruments and documents to be delivered hereunder (including the reasonable fees and expenses of counsel for Lender). In addition, the Borrower shall pay any and all stamp or other taxes, recordation fees and other fees payable in connection with the execution, delivery, filing or recording of this Amendment and the other instruments and documents to be delivered hereunder and agrees to hold the Lender harmless from and against any and all liabilities with respect to or resulting from any delay or omission in paying such taxes or fees.

3.4  THIS AMENDMENT, AND THE NOTE AS AMENDED, ARE CONTRACTS MADE UNDER AND SHALL BE CONSTRUED IN ACCORDANCE WITH AND GOVERNED BY THE LAWS OF THE UNITED STATES OF AMERICA AND THE STATE OF LOUISIANA.

3.5  The Borrower and the Lender agree that this Amendment may be executed in multiple separate counterparts, and each party's signature may appear on a separate counterpart, but all such counterparts taken together shall constitute one and the same instrument. The parties specifically confirm their intent to be bound by delivery of such signed counterparts by telecopier.

IN WITNESS WHEREOF, the parties hereto have caused this instrument to be duly executed as of the date first above written.

BORROWER:           THE EXPLORATION COMPANY OF DELAWARE, INC.

By:   /s/ Roberto R. Thomae         

    Name:     Roberto R. Thomae

    Title:      Chief Financial Officer

LENDER:                      HIBERNIA NATIONAL BANK

By:   /s/ Nancy G. Moragas       

    Name:     Nancy G. Moragas

    Title:      Vice President

EX-99

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 Annual Report of The Exploration Company of Delaware, Inc. (the "Company") on Form 10-K for the year ended December 31, 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:   March 28, 2003
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.

EX-99

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 Annual Report of The Exploration Company of Delaware, Inc. (the "Company") on Form 10-K for the period ending December 31, 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:  March 28, 2003
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.