UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.    20549

FORM 10-Q

[X]   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarter ended

Commission File No.

March 31, 2003

0-9120

THE EXPLORATION COMPANY OF DELAWARE, INC.

(Exact Name of Registrant as Specified in its Charter)

DELAWARE

84-0793089

(State or other jurisdiction of

(I.R.S. Employer I.D. No.)

incorporation or organization)

500 NORTH LOOP 1604 E.,  SUITE 250    SAN ANTONIO, TEXAS  78232

(Address of principal executive offices)

Registrant's telephone number, including area code:   (210) 496-5300

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

YES [X]  

   NO  [  ]

Indicate by check mark whether the Registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).

YES [X]  

   NO  [  ]

Indicate the number of shares outstanding of each of the issuer's classes of common stock as of May 9, 2003.

Common Stock $0.01 par value

20,009,716

(Class of Stock)

(Number of Shares)

For more information and a print friendly version of this document go to www.txco.com.

Total number of pages is 16

1

PART I - FINANCIAL INFORMATION

ITEM 1.     FINANCIAL STATEMENTS.

THE EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

March 31,
2003

December 31,
2002

Assets

Current Assets:

   Cash

$  2,693,560

$  2,333,688

   Accounts receivable, net

6,475,113

5,118,270

   Prepaid expenses

804,375

503,176

      Total Current Assets

9,973,048

7,955,134

Property and Equipment, net - successful efforts
   method of accounting for oil and gas properties

49,145,266

39,327,867

Other Assets:

   Deferred tax asset

5,232,718

5,232,718

   Other assets

515,904

520,600

      Total Other Assets

5,748,622

5,753,318

$64,866,936

$53,036,319

See notes to consolidated financial statements

2

THE EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

March 31,
2003

December 31,
2002

Liabilities and Stockholders' Equity

Current Liabilities:

   Accounts payable, trade

$7,018,267

$  3,684,550

   Other payables and accrued liabilities

4,912,275

3,187,174

   Undistributed revenue

2,038,953

1,894,144

   Current portion of long-term debt

1,615,937

1,073,773

      Total Current Liabilities

15,585,432

9,839,641

Long-term Liabilities:

   Long-term debt, net of current portion

10,133,020

6,143,458

   Asset retirement obligation

1,369,400

-       

Minority Interest in Consolidated Subsidiaries

84,175

82,846

Stockholders' Equity:

   Preferred stock, authorized 10,000,000 shares
      issued and outstanding -0- shares

   Common stock, par value $.01 per share; authorized
      50,000,000 shares; issued 20,109,516 shares,
      outstanding 20,009,716 shares

201,095

201,095

   Additional paid-in capital

58,216,504

58,216,504

   Accumulated deficit

(20,476,683

)

(21,201,218

)

   Less treasury stock, at cost, 99,800 shares

(246,007

)

(246,007

)

         Total Stockholders' Equity

37,694,909

36,970,374

      Total Liabilities and Stockholders' Equity

$64,866,936

$53,036,319

See notes to consolidated financial statements

3

THE EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

Three Months
Ended

Three Months
Ended

March 31, 2003

March 31, 2002

Revenues

   Oil and gas sales

$5,882,716

$1,818,778

   Gas gathering operations

3,208,385

-       

   Other operating income

(3,228

)

90,583

9,087,873

1,909,361

Costs and Expenses

   Lease operations

1,074,349

683,275

   Production taxes

368,404

125,480

   Exploration expenses

375,031

295,190

   Impairment and abandonments

339,075

363,700

   Gas gathering operations

3,597,236

-       

   Depreciation, depletion and amortization

1,673,319

782,202

   General and administrative

776,106

402,019

      Total costs and expenses

8,203,520

2,651,866

Income (Loss) from Operations

884,353

(742,505

)

Other Income (Expense)

   Interest income

4,605

5,666

   Interest expense

(110,842

)

(34,851

)

(106,237

)

(29,185

)

Income (loss) before income taxes, minority interest

   and cumulative effect of change in accounting principle

778,116

(771,690

)

Minority interest in income of subsidiaries

20,419

(19,536

)

Income (loss) before income taxes and cumulative effect of change in

   accounting principle

798,535

(791,226

)

Income tax benefit

-       

75,000

Cumulative effect of change in accounting principle, net of tax

(74,000

)

-      

Net Income (Loss)

$  724,535

$ (716,226

)

Earnings (Loss) Per Share

   Basic:

     Earnings (loss) before cumulative effect of change in

         accounting principle

$ 0.04

$ (0.04

)

     Cumulative effect of change in accounting principle

-   

-   

        Net Earnings (loss) per share

$ 0.04

$ (0.04

)

   Diluted:

     Earnings (loss) before cumulative effect of change in

         accounting principle

$ 0.04

$ (0.04

)

     Cumulative effect of change in accounting principle

-   

-   

        Net Earnings (loss) per share

$ 0.04

$ (0.04

)

See notes to consolidated financial statements

4

THE EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

Three Months
Ended

Three Months
Ended

March 31, 2003

March 31, 2002

Operating Activities

Net income (loss)

$     724,535

$  (716,226

)

Adjustments to reconcile net income to net cash
   provided (used) by operating activities:

   Depreciation, depletion and amortization

1,673,319

782,202

   Impairment and abandonments

339,075

363,700

   Minority interest in income of subsidiaries

(20,419

)

19,536

   Cumulative effect of change in accounting principle

74,000

-      

Changes in operating assets and liabilities:

   Receivables

(1,356,843

)

574,706

   Prepaid expenses and other

(296,797

)

(79,321

)

   Accounts payable and accrued expenses

5,203,627

(2,511,764

)

Net cash provided (used) in operating activities

6,340,497

(1,567,167

)

Investing Activities

   Development and purchases
      of oil and gas properties

(10,405,829

)

(2,243,350

)

   Purchase of other equipment

(128,271

)

(2,500

)

   Distributions to minority interests

21,748

(22,779

)

Net cash (used) in investing activities

(10,512,352

)

(2,268,629

)

Financing Activities

   Proceeds from debt obligations

2,700,000

2,800,000

   Proceeds from installment obligations

2,644,671

-      

   Deferred financing fees

-       

(48,437

)

   Payments on debt obligations

(812,944

)

(102,342

)

Net cash provided in financing activities

4,531,727

2,649,221

Change in Cash and Equivalents

359,872

(1,186,575

)

Cash and equivalents at beginning of period

2,333,688

2,019,164

Cash and Equivalents at End of Period

$  2,693,560

$   832,589

See notes to consolidated financial statements

5

THE EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PERIODS ENDED MARCH 31, 2003 AND MARCH 31, 2002 (Unaudited)

1.     Basis of Presentation

The accompanying unaudited consolidated financial statements of The Exploration Company (TXCO or the Company) have been prepared in accordance with U.S. generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. generally accepted accounting principles for complete financial statements. The accounting policies followed by the Company are set forth in Note A to the December 31, 2002 audited consolidated financial statements contained in the Company's annual report on Form 10-K.

In the opinion of management, all adjustments (consisting of normal recurring adjustments) considered necessary for a fair presentation have been included. Certain reclassifications have been made to the prior period to conform to current presentation. For further information, refer to the consolidated financial statements and footnotes thereto included in the Registrant Company's annual report on Form 10-K for the year ended December 31, 2002, which is incorporated herein by reference.

2.     Common Stock and Basic Income or Loss Per Share

As of March 31, 2003, the Company had outstanding and exercisable warrants and options to purchase 3,029,429 shares of common stock at prices ranging from $0.98 to $6.00 per share. The warrants and options expire at various dates through August 2011.

The following is a reconciliation of the numerator and denominator of the basic and diluted earnings per share computation:

Shares

Income
(Loss)

Per Share
Amount

Three Months Ended March 31, 2003

  Basic EPS:

    Net income before cumulative effect of
       change in accounting principle

20,009,716

$  798,535

$ .04

    Cumulative effect of change in accounting principle

-       

(74,000

) 

-   

    Net income

20,009,716

724,535

.04

    Effect of dilutive options

277,081

-       

-   

Dilutive EPS

20,286,797

$ 724,535

$ .04

Three Months Ended March 31, 2002

  Basic EPS:

    Net income

17,397,049

$(716,226

) 

$  (.04

)

    Effect of dilutive options

-       

-       

-   

Dilutive EPS

17,397,049

$(716,226

) 

$  (.04

)

6

3.     Income Taxes

The Company has recorded a deferred tax asset for the amount expected to be realized through taxable earnings. In determining taxable earnings, the Company uses income projections reduced by graduating percentages to compensate for uncertainties inherent in future years' projections. Total income tax expense is computed based on the Company's estimated annualized federal income tax for the year, considering the impact of any change in the amount of deferred tax asset. The Company does not expect to incur income tax for 2003 operations due to the availability of net operating loss carryforwards.

4.     Long-Term Debt

Bank Credit Facility: In March 2002 the Company entered into a $25 million oil and gas reserve based Revolving Credit Facility with Hibernia National Bank (the "Facility" or "Credit Facility") providing a credit line with an initial borrowing base set at $5 million. Through March 31, 2003, the borrowing base grew to $12 million with an outstanding balance of $8.5 million. The interest rate at March 31, 2003, was 4.25%, is payable monthly, with principal due at maturity in March 2005. More information on this Facility is available in the Company's "Annual Report on Form 10-K" for the year ended December 31, 2002.

The Facility contains certain financial covenants and other negative restrictions common for a financing of this type. As of March 31, 2003, the Company was not in compliance with the Current Ratio covenant. The Company has received a waiver relating to this covenant for the March 31, 2003 measurement period.

At the Company's request, the lender is currently conducting a discretionary redetermination of the Credit Facilities' oil and gas reserve backed borrowing base. This redetermination includes reserve additions through April 2003. The Company expects its borrowing base to increase significantly due to the ongoing addition of new oil and gas reserves from current drilling activities established since the previous redetermination.

Subsequent Borrowings: Additional borrowings by the Company, through May 5, 2003 totaled $3.5 million, increasing the outstanding balance under the Credit Facility to $12 million.

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. Future payments are due in two installments of $1.4 million each in January 2004 and 2005.

5.     Asset Retirement Costs and Obligations

The Company adopted the provisions of Statement of Financial Accounting Standards No. 143 "Accounting for Asset Retirement Obligations," on January 1, 2003. This statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. In addition, the associated asset retirement costs are required to be capitalized as part of the carrying amount of the long-lived asset.

Upon adoption of this statement, the Company recorded an asset retirement obligation of $1.3 million to reflect the Company's legal obligations related to future plugging and abandonment of its wells and gathering system. In addition, the Company recorded an increase to proved oil and gas properties of $1.2 million, and an expense of $74,000 constituting the cumulative effect of adoption. The new standard had no material impact on income before the cumulative effect of adoption in the first quarter of 2003, nor would it have had a material impact on the first quarter of 2002 assuming adoption on a pro-forma basis.

7

6.     Fair Value of Stock Options

At March 31, 2003, the Company has a stock-based employee compensation plan which is described more fully in Note D, "Stockholders' Equity," to the December 31, 2002 audited consolidated financial statements contained in the Company's annual report on Form 10-K. 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 three month periods ended March 31:

Three Months Ended March 31:

   2003  

  2002 

Net income (loss) as reported

$724,535

$(716,226

)

Deduct: Total stock-based compensation
  expense determined under the fair value based
  method for all awards, net of related tax effects

     -      

       -      

Pro forma earnings (loss)

$724,535

$(716,226

)

Earnings (loss) per common share:

  Basic, as reported

$   0.04

$   (0.04

)

  Basic, pro forma

0.04

(0.04

)

  Diluted, as reported

0.04

(0.04

)

  Diluted, pro forma

0.04

(0.04

)

ITEM 2.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
                 CONDITION AND RESULTS OF OPERATIONS

Certain statements in this report are not historical in nature, including statements of TXCO's and management's expectations, intentions, plans and beliefs, are inherently uncertain and are "forward-looking statements" within the meaning of Section 21E of the Securities and Exchange Act of 1934. The following discussion should be read in conjunction with the unaudited consolidated financial statements and notes thereto included in this Form 10-Q, and with the Company's latest audited consolidated financial statements and notes thereto, as reported in its Form 10-K for the year ended December 31, 2002. See "Disclosure Regarding Forward Looking Statements". Certain reclassifications have been made to the prior period to conform to current presentation.

Liquidity and Capital Resources

During the first quarter of 2003, cash reserves of $2.3 million at December 31, 2002 were increased by cash provided by operating activities of $6.3 million. In addition, proceeds from borrowings on the Credit Facility and installment obligations totaled $5.3 million, resulting in total cash available of $13.9 million for use in meeting the Company's ongoing operational and development needs.

Portions of this cash were used to fund payments on debt totaling $813,000 and related interest of $111,000. The Company applied $10.4 million to fund the expansion and ongoing development of its oil and gas producing properties. These expenditures included $6.2 million for drilling and completion costs for wells drilled, re-entered or completed during the period and approximately $4.2 million in additional leasehold acquisitions.

8

As a result of these activities, the Company ended the first quarter of 2003 with negative working capital of $5.6 million compared to negative working capital of $1.9 million at December 31, 2002, while its current ratio declined to .64 to 1 compared to .81 to 1 at year end. The Company exited the first quarter with an unused borrowing base of $3.5 million under its Credit Facility. Its ending working capital was significantly impacted by the high level of drilling and development activity expenditures during 2003 to date totaling $10.4 million, a 373% increase over the same period of the prior year. First quarter cash flow from operating activities increased to a positive $6.3 million from negative $1.6 million in the comparative prior year period reflecting the significant increase in oil production and realized oil and gas prices over the same quarter of the prior year.

Credit Facility - In March 2002 the Company entered into a $25 million oil and gas reserve based Revolving Credit Facility with Hibernia National Bank (the "Facility" or "Credit Facility" or "Lender"). At March 31, 2003 the borrowing base was $12 million with an outstanding balance of $8.5 million and an unused borrowing base of $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 purposes.

The interest rate is based on Wall Street Prime Rate and was 4.25% at March 31, 2003. The Facility contains certain financial covenants and other negative restrictions common for this type of financing. As of March 31, 2003 the Company was not in compliance with the current ratio covenant under the Facility. The Company has received a waiver for this covenant for the March 31, 2003 measurement period.

Management believes that the Credit 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 advance its scheduled exploration and development goals as targeted by its 2003 capital expenditure program.

Management is actively involved in ongoing discussions with various prospective industry partners and domestic and foreign based sources of debt and equity financing. These parties could provide favorably structured financing arrangements that, along with the Company's internally generated cash flow would provide funding as required to maintain or increase the Company's planned drilling activity during 2003 and future years. Management remains confident that these potential financial resources will remain available, further 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.

However, there is no assurance that the Company will maintain adequate levels of profitability and liquidity for the remainder of 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 existing Credit 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.

During February, the Company entered into a forward sale of 5,000 MMbtu per day, of gross natural gas production at a fixed price of $4.45 per MMbtu, or $5.13 per thousand cubic feet (Mcf), net of transportation expenses. This contract runs from February 1, 2003 through December 31, 2003. This volume includes approximately 2,300 MMbtu of TXCO's working interest partners' and royalty owners' gas. The net quantity represents approximately 30% of TXCO's daily net gas production rate at year end 2002. This contract locks in cash flow for a portion of our production and provides predictable cash flow to help fund our capital expenditures program. There is no derivative feature to this contract.

Significant Changes to Contractual Obligations - During the current quarter the Company increased borrowings under its Credit Facility to $8.5 million from $5.8 million at December 31, 2002.

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. Future payments are due in two installments of $1.4 million each in January 2004 and 2005.

9

As further discussed in Note 5 to the financial statements, the Company has recorded a long-term asset retirement obligation, which totaled $1.37 million at March 31, 2003, with its adoption of SFAS No. 143 effective January 1, 2003.

Management believes it will be able to meet its ongoing operating cash requirements for the current year as well as complete the scheduled exploration and development goals targeted by the growing 2003 capital expenditure program. However, if realized oil and gas prices, or if levels of its Maverick Basin production are substantially less than expected, or if prices or expenditures for goods and services used in the Company's exploration, development and operating activities rise significantly above budgeted levels, the Company's financial condition and liquidity could be adversely affected. Should this occur, Management retains the ability to extend the timing of its planned development and exploration activities to match available working capital, while maintaining its current operating activity levels and meeting its financial obligations on a timely basis.

Results of Operations

Oil and gas revenues totaled $5.88 million, an increase of 223% for the quarter ended March 31, 2003 versus the comparable prior year period. This increase is attributable to higher oil and gas prices realized during the period and significantly increased oil production volumes partially offset by a slight decline in gas production volumes. As reflected in the following table, average realized gas prices were 163% higher than the comparable period in 2002 while average oil prices increased 73% for the same periods. Oil sales volumes increased 356% reflecting production from the new Comanche lease oil wells along with production from the Pena Creek field acquired in May 2002. Gas sales volumes decreased slightly as the general production decline of the Company's maturing gas wells was not completely offset by increased production from new wells.

2003

2002

Sales
Volume

   Average
   Prices

Sales
Volume

Average
Prices

For the Three months ended March 31,

   Gas (Mcf)

551,319

$  6.04

650,868

$  2.30

   Oil  (Bbls)

81,109

$31.45

17,773

$18.21

During the quarter, the Company's gas gathering operations revenues totaled $3.2 million. Included were sales of third party natural gas of $2.5 million purchased for resale by the Company along its gathering system, sales of natural gas liquids extracted from that gas of $577,000 and transportation revenue of $104,000. Based on a total volume of 582,200 MMbtu, the Company's average sales price per MMbtu was $5.33 for the quarter.

Lease operating expenses (LOE) increased 57% for the first quarter of 2003 as compared to the same period of 2002. The increase primarily reflects the incremental LOE associated with operating the Pena Creek oil field acquired during the second quarter of 2002; nine new Saxet operated Comanche lease oil wells and 20 additional Maverick Basin oil and gas wells placed on production since March 31, 2002. During the current quarter production taxes fluctuated proportionately with the oil and gas revenues compared to the prior year quarter.

The Company's gas gathering system is generally operated on a break even basis. Natural gas pricing fluctuations are reflected at the wellhead for the Company's operated gas properties. Due to the acquisition of the Company's primary gas gathering assets during the second quarter of 2002, first quarter 2003 versus 2002 operations comparisons are not meaningful.

During the current quarter, the Company's gas gathering system expense totaled $3.6 million, including costs to purchase third party gas along the Company's gathering system of $3.4 million, associated transportation and marketing expenses required to market that gas of $78,000 and direct operating costs of the pipeline of $164,000. Sharply higher gas prices in late February 2003, combined with an erroneous gas nomination earlier that month, resulted in a one time trading loss of approximately $316,000 at March 31. Management has determined the trading loss was an isolated incident and has refined its internal procedures to prevent a similar reoccurrence.

10

Depreciation, depletion and amortization increased 114% over the comparable prior year period. The increase in depletion of $740,000 was due primarily to the increased number of producing wells being depleted for new wells added both through the drillbit and the Pena Creek acquisition, along with increased depletion rates due to the maturing profile of existing producing wells. Depreciation costs increased $124,000 due to the acquisition and expansion of the Company's gas gathering system and additional investments in well service equipment.

General and administrative expense increased 93% for the current period as compared to the same period in 2002. This increase reflects the higher sustained levels of Company operations and was due primarily to increased salaries, wages and benefits associated with staff increases. Staffing at March 31, 2003 included 37 full time employees, as compared to 22 in 2002. Also contributing to the increase for the quarter were higher costs for property and liability insurance and consulting fees associated with compliance reporting and investor relations activities. These increases are consistent with the expanded compliance burden mandated by the adoption of the Sarbanes Oxley Act in mid-2002.

Interest expense for the first quarter of 2003 increased by $76,000 over the same period of 2002 due to higher levels of debt.

The income tax benefit recorded in the first quarter of 2002 reflected a recoupment of taxes paid during 2001 due to changes in the Corporate alternative minimum tax included in the Job Creation and Worker Assistance Act of 2002. The Company does not expect to incur an income tax expense for 2003.

Drilling Activities

During the first quarter of 2003, the Company drilled or participated in the drilling of 24 wells on its 479,761 acre lease block in the Maverick Basin. Eleven of these wells are producing, six wells are in completion phase, four wells are shut in pending further evaluation, one well was temporarily abandoned pending sidetrack operations, while two wells remained drilling at March 31, 2003. By comparison, the Company participated in nine wells in the first quarter of 2002. The record number of first-quarter wells targeted multiple productive formations, including the Glen Rose, San Miguel, Georgetown and Jurassic intervals. The Company exited the first quarter of 2003 with total net daily production rates of 1,074 barrels of oil per day (BOPD) and 6.5 million cubic feet (MMcfd) of natural gas. By late April, net daily production rates increased to approximately 1,700 BOPD while gas increased to 6.7 MMcfd as additional new oil and gas wells were placed on line.

Glen Rose Oil - TXCO and its operating partner, Saxet Energy Ltd., drilled two new wells and re-entered and sidetracked one well during the first quarter. The Comanche #3-111, the first horizontal well targeting the Glen Rose porosity interval, was engineered to optimize oil production from numerous faults and fractures while minimizing associated water production. Completed in April 2003 it currently is flowing approximately 1,100 BOPD with 170 barrels of water per day (BWPD) after being drilled 4,000 feet horizontally across the top of the targeted porosity zone. TXCO and its partner believe developing the field with horizontal wells will allow more oil, with a better water cut, to be produced from the reservoir with fewer wells. This initial well appears to verify this technique.

A second well, the Comanche #1-659, located the targeted porosity interval but has been temporarily abandoned due to unstable hole conditions. The well was shut-in and is expected to be sidetracked at a later date. Saxet also re-entered and successfully sidetracked the Comanche #2-44. This well had been shut-in during 2002 after encountering poorer-than-normal porosity in the original wellbore. The new sidetrack well bore found good porosity within several hundred feet and is currently flowing approximately 40 BOPD and ten BWPD. The well remains on production and under engineering review to evaluate its current production profile prior to its possible horizontal extension.

11

Subsequent to March 31, two additional vertical wells and one horizontal well were spud targeting the porosity interval. The first well, the Comanche #1-46, was spud in mid-April and located the targeted porosity interval approximately five miles southeast of the Comanche #1-111 well, the original Comanche oil discovery well drilled in early 2002. This new vertical well was successfully drilled to the top of the Glen Rose porosity interval and has tested oil at rates of over 400 BOPD and 900 BWPD. The well confirms the continued presence of oil filled porosity, significantly expanding the aerial extent of the known Glen Rose porosity interval to the southeast, in a targeted area previously identified only by 3-D seismic imaging. The second vertical well and one horizontal well are currently drilling. Gross daily production from the Comanche Halsell (6500) Field was approximately 3,000 BOPD and 3,400 BWPD by late April.

Horizontal Glen Rose Shoal - During the first quarter, TXCO successfully completed three new horizontal Glen Rose shoal gas wells, two on the Chittim lease and one on the Paloma lease. At March 31 total horizontal Glen Rose shoal gas production reached a gross daily volume of approximately 6.8 MMcf.

The Company spudded a fourth Glen Rose shoal gas well near the end of the first quarter. The well was completed in late April. Subsequent to March 31, TXCO spudded the fifth Glen Rose shoal well, which is currently drilling. By late April, total horizontal Glen Rose shoal gas production reached a gross volume of approximately 8.3 MMcfd.

Georgetown Deviated Wells - TXCO engineers have employed directional drilling to enter the Georgetown formation at deviated angles, cutting through numerous, near-vertical faults. During the first quarter, TXCO drilled five new wells, re-entered two and participated in drilling one outside-operated prospect, all primarily employing the deviated technique. Three of the wells were completed in April and exhibited improved hydrocarbon recovery rates compared to similarly situated conventional wells. One well is pending completion, while the remaining four wells are shut in pending further evaluation.

Subsequent to the end of the current quarter, TXCO spudded one additional well and participated in drilling a second outside operated prospect. One of these wells is currently in progress while the other is awaiting completion. By late April, flowing Georgetown fault production reached a gross total of approximately 192 BOPD and 560 Mcfd, as compared to their initial flowing rates of 350 BOPD and 605 Mcfd earlier in April. The Company is in process of installing pumping equipment on selected wells and expects to reestablish higher production levels upon commencement of pumping activities.

San Miguel Waterflood - TXCO spudded eight infill wells during the first quarter of 2003. Five have been successfully fracture stimulated, completed and placed on production. The three remaining wells are currently in completion or are scheduled for fracture stimulation. Daily gross production rates from the Pena Creek field increased from 265 BOPD at year-end 2002 to approximately 350 BOPD at March 31. Subsequent to the end of the first quarter, TXCO spudded three additional infill wells, with two scheduled for fracture stimulation while one is still drilling. By late April production from the Pena Creek field further increased to approximately 400 BOPD.

Jurassic Formation - Blue Star Oil and Gas, Ltd. (Blue Star) began drilling the Taylor 1-132 well at the end of March 2003. The well is permitted to a depth of 18,500 feet, into the untested Jurassic formations of the basin under TXCO's Paloma lease. Drilling is ongoing at a current depth of approximately 6,900 feet. Because all other interior rift basins around the Gulf of Mexico have historically produced significant quantities of oil and gas from Jurassic intervals, TXCO believes the Jurassic in the Maverick Basin will also be productive.

Burr Lease - During the first quarter of 2003, TXCO acquired the 70,700-acre Burr Ranch lease. The acreage is contiguous to its existing acreage block and the Company felt it has excellent potential to establish production from the Glen Rose, Georgetown and Jurassic intervals. TXCO is now actively seeking a 50% partner in advance of a 3-D seismic shoot planned for the lease.

12

Coalbed Methane (CBM) - TXCO exited 2002 with 38 wells dewatering in its CBM pilot program targeting production from the multiple seams of high-volatile bituminous coal present under its leases. As of April 2003, the total CBM production rate was approximately 200 Mcfd with 2,000 barrels of water per day. 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 levels. 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 current 2003 CAPEX budget. The Company expects that this project will add significant reserves in the coming years.

Disclosure Regarding Forward Looking Statements

This Quarterly Report on Form 10-Q includes forward-looking statements which are not historical, including statements regarding TXCO's or management's intentions, hopes, beliefs, expectations, representations, projections, estimations, plans or predictions of the future, and which are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. 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 affecting the drilling of oil and natural gas wells, as well as general market conditions, competition and pricing. Please refer to all of TXCO's Securities and Exchange Commission filings, copies of which are available from the Company without charge, for additional information.

ITEM 3.     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

There have been no material changes in the reported market risks faced by the Company since December 31, 2002. See the Company's Annual Report on Form 10-K, "Item 7A. Quantitative and Qualitative Disclosures About Market Risk"

ITEM 4.     CONTROLS AND PROCEDURES.

a.      The Company's Chief Executive Officer and the Chief Financial Officer have carried out an evaluation of the effectiveness of the design and operation of the Company's disclosure controls and procedures pursuant to Exchange Act Rule 13a-14 and Rule 15d-14 as of March 31, 2003. Based upon that evaluation, the Company's Chief Executive Officer along with the Chief Financial Officer concluded that the disclosure controls and procedures are effective in timely alerting them to material information relating to the Company (including its consolidated subsidiaries) required to be included in our periodic SEC filings.

b.       There have been no significant changes in the Company's internal controls or in other factors that could significantly affect internal controls subsequent to the date of the above evaluation.

13

PART II - OTHER INFORMATION

ITEM 1.     LEGAL PROCEEDINGS

          None

ITEM 2.      CHANGES IN SECURITIES

          None

ITEM 3.      DEFAULTS UPON SENIOR SECURITIES

          None

ITEM 4.      SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

          None

ITEM 5.      OTHER INFORMATION

          None

ITEM 6.      EXHIBITS AND REPORTS ON FORM 8-K

a)      Exhibit 99.1   Certification of Chief Executive Officer required pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 filed herewith.

b)      Exhibit 99.2   Certification of Chief Financial Officer required pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 filed herewith.

c)      Form 8-K dated March 12, 2003, regarding the press release dated March 6, 2003 with respect to the Registrant's financial results for the year ended December 31, 2002.

d)     Form 8-K dated April 28, 2003, regarding the press release dated April 23, 2003 with respect to the Registrant's first quarter 2003 operation's update.

e)     Form 8-K dated May 2, 2003, regarding the press release dated April 28, 2003 with respect to the Registrant's webcast of its IPAA Oil and Gas Investment Symposium presentation.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

THE EXPLORATION COMPANY

(Registrant)

/s/ Roberto R. Thomae

Roberto R. Thomae,

Chief Financial Officer

Date:  May 15, 2003

14

Form of Sarbanes-Oxley Section 302(a) Certification

I, James E. Sigmon, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of The Exploration Company of Delaware, Inc.;

2.

Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3.

Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present, in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4.

The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a)

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b)

evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and

c)

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.

The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a)

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

b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.

The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date:

May 15, 2003

/s/ James E. Sigmon

James E. Sigmon

Chief Executive Officer

15

Form of Sarbanes-Oxley Section 302(a) Certification

I, Roberto R. Thomae, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of The Exploration Company of Delaware, Inc.;

2.

Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3.

Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present, in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4.

The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a)

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b)

evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and

c)

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.

The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a)

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

b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.

The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date:

May 15, 2003

/s/ Roberto R. Thomae

Roberto R. Thomae

Chief Financial Officer

16