EXPLORATION CO OF DELAWARE INC - 10-Q Quarterly Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarter ended		Commission File No.
June 30, 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 p

Indicate by check mark whether the Registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).
YES x		NO p

Indicate the number of shares outstanding of each of the issuer's classes of common stock as of August 7, 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 20







1


PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

THE EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

	June 30, 2003	December 31, 2002


Assets

Current Assets
Cash	$ 4,447,098	$ 2,333,688
Accounts receivable, net	6,746,634	5,118,270
Prepaid expenses	666,807	503,176

Total Current Assets	11,860,539	7,955,134

Property and Equipment, net - successful efforts method of accounting for oil and gas properties	54,543,202	39,327,867

Other Assets
Deferred tax asset	5,232,718	5,232,718
Other assets	511,504	520,600

Total Other Assets	5,744,222	5,753,318


Total Assets	$72,147,963	$53,036,319





















See notes to consolidated financial statements


2






THE EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

	June 30, 2003			December 31, 2002


Liabilities and Stockholders' Equity

Current Liabilities
Accounts payable, trade		$ 8,543,379		$ 3,684,550
Other payables and accrued liabilities		5,666,688		3,187,174
Undistributed revenue		1,511,492		1,894,144
Current portion of long-term debt		1,611,461		1,073,773

Total Current Liabilities		17,333,020		9,839,641

Long-term Liabilities
Long-term debt, net of current portion		15,554,353		6,143,458
Asset retirement obligation		1,435,800		-

Minority Interest in Consolidated Subsidiaries		102,417		82,846

Stockholders' Equity
Preferred stock - series A, 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		58,234,380		58,216,504
Accumulated deficit		(20,467,095	)	(21,201,218	)
Less treasury stock, at cost, 99,800 shares		(246,007	)	(246,007	)

Total Stockholders' Equity		37,722,373		36,970,374


Total Liabilities and Stockholders' Equity		$72,147,963		$53,036,319















See notes to consolidated financial statements


3





THE EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
	Three Months Ended			Three Months Ended
	June 30, 2003			June 30, 2002


Revenues
Oil and gas sales		$6,574,218			$3,749,531
Gas gathering operations		3,291,401			151,213
Other operating income		3,150			178,455

		9,868,769			4,079,199

Costs and Expenses
Lease operations		977,967			862,695
Production taxes		434,869			235,641
Exploration expenses		626,570			287,111
Impairment and abandonments		537,075			379,200
Gas gathering operations		3,417,324			106,561
Depreciation, depletion and amortization		2,821,148			1,086,622
General and administrative		854,798			413,541

Total costs and expenses		9,669,751			3,371,371


Income from Operations		199,018			707,828

Other Income (Expense)
Interest income		5,955			16,009
Interest expense		(161,240	)		(78,267	)

		(155,285	)		(62,258	)


Income before income taxes, minority interest
and cumulative effect of change in accounting principle		43,733			645,570

Minority interest in income of subsidiaries		15,855			(102,923	)


Income before income taxes and cumulative effect of change in
accounting principle		59,588			542,647
Income tax expense		(50,000	)
Cumulative effect of change in accounting principle, net of tax		-			-


Net Income		$ 9,588			$ 542,647


Earnings Per Share
Basic:
Earnings before cumulative effect of change in
accounting principle		$0.00			$0.03
Cumulative effect of change in accounting principle		-			-

Net earnings per share		$0.00			$0.03


Diluted:
Earnings before cumulative effect of change in
accounting principle		$0.00			$0.03
Cumulative effect of change in accounting principle		-			-

Net earnings per share		$0.00			$0.03




See notes to consolidated financial statements

4





THE EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
	Six Months Ended		Six Months Ended
	June 30, 2003		June 30, 2002


Revenues
Oil and gas sales	$12,456,934		$5,568,309
Gas gathering operations	6,499,786		151,213
Other operating income	(78	)	269,038

	18,956,642		5,988,560

Costs and Expenses
Lease operations	2,052,316		1,545,970
Production taxes	803,273		361,121
Exploration expenses	1,001,601		582,301
Impairment and abandonments	876,150		742,900
Gas gathering operations	7,014,560		106,561
Depreciation, depletion and amortization	4,494,468		1,868,824
General and administrative	1,630,903		815,560

Total costs and expenses	17,873,271		6,023,237


Income (Loss) from Operations	1,083,371		(34,677	)

Other Income (Expense)
Interest income	10,560		21,674
Interest expense	(272,082	)	(113,117	)

	(261,522	)	(91,443	)


Income (loss) before income taxes, minority interest
and cumulative effect of change in accounting principle	821,849		(126,120	)

Minority interest in income of subsidiaries	36,274		(122,459	)


Income (loss) before income taxes and cumulative effect of change in
accounting principle	858,123		(248,579	)
Income tax expense	(50,000	)	75,000
Cumulative effect of change in accounting principle, net of tax	(74,000	)	-


Net Income (Loss)	$ 734,123		$ (173,579	)


Earnings (Loss) Per Share
Basic:
Earnings (loss) before cumulative effect of change in
accounting principle	$0.04		$(0.01	)
Cumulative effect of change in accounting principle	-		-

Net earnings (loss) per share	$0.04		$(0.01	)


Diluted:
Earnings (loss) before cumulative effect of change in
accounting principle	$0.04		$(0.01	)
Cumulative effect of change in accounting principle	-		-

Net earnings (loss) per share	$0.04		$(0.01	)



See notes to consolidated financial statements

5





THE EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
	Six Months Ended			Six Months Ended
	June 30, 2003			June 30, 2002


Operating Activities
Net income (loss)		$ 734,123		$ (173,579	)
Adjustments to reconcile net income to net cash provided (used) by operating activities:
Depreciation, depletion and amortization		4,494,468		1,874,528
Impairment and abandonments		876,150		742,900
Minority interest in income of subsidiaries		(36,274	)	122,459
Cumulative effect of change in accounting principle		74,000		-
Changes in operating assets and liabilities:
Receivables		(1,628,364	)	(1,119,962	)
Prepaid expenses and other		(163,631	)	(8,108	)
Accounts payable and accrued expenses		6,955,691		571,921

Net cash provided in operating activities		11,306,163		2,010,159

Investing Activities
Development and purchases of oil and gas properties		(18,932,655	)	(15,369,554	)
Purchase of other equipment		(282,401	)	(95,227	)
Proceeds from sale of oil and gas properties		-		200,000
Contributions made by minority interests		55,844		1,200,000
Distributions to minority interests		-		(404,786	)

Net cash used in investing activities		(19,159,212	)	(14,469,567	)

Financing Activities
Issuance of common stock, net of offering costs		-		14,193,398
Proceeds from debt obligations		8,200,000		3,872,411
Proceeds from installment obligations		2,728,082		-
Deferred financing fees		17,876		(52,648	)
Payments on debt obligations		(979,499	)	(188,970	)

Net cash provided in financing activities		9,966,459		17,824,191


Change in Cash and Equivalents		2,113,410		5,364,783

Cash and equivalents at beginning of period		2,333,688		2,019,164


Cash and Equivalents at End of Period		$4,447,098		$7,383,947






See notes to consolidated financial statements



6


THE EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PERIODS ENDED JUNE 30, 2003 AND JUNE 30, 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 periods 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 June 30, 2003, the Company had outstanding warrants and options to purchase 3,174,429 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

Six Months Ended June 30, 2003
Basic EPS:
Net income before cumulative effect of change in accounting principle	20,009,716	$ 808,123		$0.04
Cumulative effect of change in accounting principle	-	(74,000	)	-

Net income	20,009,716	734,123		$0.04
Effect of dilutive options	420,709	-		-

Dilutive EPS	20,430,425	$ 734,123		$0.04


Three Months Ended June 30, 2003
Basic EPS:
Net income	20,009,716	$ 9,588		$0.00
Effect of dilutive options	562,757	-		-

Dilutive EPS	20,572,473	$ 9,588		$0.00


Six Months Ended June 30, 2002
Basic EPS:
Net income	18,172,088	$(173,579	)	$(0.01	)
Effect of dilutive options	992,530	-		-

Dilutive EPS	19,164,618	$(173,579	)	$(0.01	)


Three Months Ended June 30, 2002
Basic EPS:
Net income	18,947,126	$ 542,647		$0.03
Effect of dilutive options	1,455,960	-		-

Dilutive EPS	20,403,086	$ 542,647		$0.03


7

3. Income Taxes

The Company has recorded a deferred tax asset for the amount expected to be realized through taxable earnings. In determining taxable earnings, the Company uses income projections reduced by graduating percentages to compensate for uncertainties inherent in future years' projections. Total income tax expense is computed based on the Company's estimated annualized federal income tax for the year, considering the impact of any change in the amount of deferred tax asset. The Company does not expect to incur regular income tax for 2003 operations due to the availability of net operating loss carryforwards. However, corporate alternative minimum taxes are expected to be incurred, and for the six months ended June 30, 2003 totaled $50,000.

4. Long-Term Debt

Bank Credit Facility: The Company has a $25 million oil and gas reserve based Revolving Credit Facility with Hibernia National Bank (the "Facility" or "Credit Facility" or "Lender"). At June 30, 2003, the borrowing base was $14 million, all of which was utilized. The interest rate at June 30, 2003, was 4.00%, is payable monthly, with principal due at maturity in March 2005. Additional 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 and June 30, 2003, the Company was not in compliance with the Current Ratio covenant. The Company has received a permanent waiver relating to the March 31, 2003 covenant violation. On August 13, 2003, the Company and the Lender entered into an amendment to the Facility, which revised the current ratio covenant and waived the June 30, 2003 violation.

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 or second quarter of 2003, nor would it have had a material impact on the first or second quarter of 2002 assuming adoption on a pro-forma basis. This standard is not expected to have an additional material impact on the Company's financial position or operations in future periods.

6. Fair Value of Stock Options

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 Stoc k-Based Compensation," to stock-based employee compensation for the six and three month periods ended June 30:

Six Months Ended June 30:	2003	2002


Net income (loss) as reported	$734,123	$(173,579	)

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)	$734,123	$(173,579	)


Earnings (loss) per common share:
Basic, as reported	$0.04	$(0.01	)
Basic, pro forma	0.04	(0.01	)
Diluted, as reported	0.04	(0.01	)
Diluted, pro forma	0.04	(0.01	)

Three Months Ended June 30:	2003	2002


Net income (loss) as reported	$ 9,588	$ 542,647

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)	$ 9,588	$ 542,647


Earnings (loss) per common share:
Basic, as reported	$0.00	$0.03
Basic, pro forma	0.00	0.03
Diluted, as reported	0.00	0.03
Diluted, pro forma	0.00	0.03

7. Mandatorily Redeemable Preferred Stock - Subsequent Event

Subsequent to June 30, 2003, the Company entered into a private placement agreement to issue 16,000 shares, with a stated value of $1,000 each, of Series B Redeemable Preferred Stock ("Preferred"), and 2,133,333 shares of common stock, raising a total of approximately $15.1 million after offering costs. All of the common stock issued will be restricted from trading in a public transaction for one year from issuance, and the Company will have the option to repurchase up to one-half of the common stock at a purchase price of $6.00 per share for a period of two years from closing. The Preferred will be recorded as debt on the balance sheet.

The Preferred bears interest at 8.0 percent per annum, payable quarterly in cash, for the first three years, increasing to 10% per annum at that time. The Preferred must be redeemed at the end of six years, and is redeemable at the Company's option anytime after issuance at 100% of the stated value. The Preferred has a liquidation preference equal to the stated value, an aggregate of $16 million. The Preferred shares have certain rights such as information rights as well as representation on the TXCO Board of Directors. The board representation comes in the form of one director and one board observer.


9

8. Recent Accounting Pronouncements

In May 2003, the Financial Accounting Standards Board ("FASB") issued Statement of Accounting Standards No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" ("SFAS No. 150"). This statement requires that an issuer classify a financial instrument that is within its scope as a liability because the financial instrument embodies an obligation of the issuer. SFAS No. 150 is effective for all financial instruments entered into or modified after May 31, 2003 and requires reclassification of existing financial instruments in financial statements for the first interim period beginning after June 15, 2003. The mandatorily redeemable preferred stock discussed in Note 7 will be recorded as a liability as a result of this Statement.

The FASB and representatives of the accounting staff of the Securities and Exchange Commission are currently engaged in discussions regarding the application of certain provisions of SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets," to companies in the extractive industries, including oil and gas companies. The FASB and the SEC staff are considering whether the provisions of SFAS No. 141 and SFAS No.142 require registrants to classify costs associated with mineral rights, including both proved and unproved lease acquisition costs, as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures.

Historically, the Company has included oil and gas lease acquisition costs as a component of oil and gas properties. In the event the FASB and SEC staff determine that costs associated with mineral rights are required to be classified as intangible assets, a portion of the Company's oil and gas property acquisition costs may be required to be separately classified on its balance sheets as intangible assets or further described in footnote disclosures. However, the Company currently believes that its results of operations and financial condition would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with existing successful efforts accounting rules and impairment standards. The Company does not believe the classification of oil and gas lease acquisition costs as intangible assets would have any impact on the Company's compliance with covenants under its debt agreements.

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

Cash reserves of $2.3 million at December 31, 2002 were increased by cash provided by operating activities of $11.3 million for the six months ended June 30, 2003. Borrowing on the Credit Facility and installment obligations totaled $10.9 million, resulting in total cash available of $24.6 million for use in meeting the Company's ongoing operational and development needs.

During the first quarter, portions of this cash were used to fund payments on debt totaling $813,000 and related interest of $97,000. 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.

During the second quarter, payments on debt totaled $166,000 with $156,000 of related interest. The decrease in debt payments for the second quarter of 2003 reflects the retirement during the first quarter of debt related to last years' pipeline purchase, while the increase in interest payments reflects the higher balances on the Company's credit facility. The active drilling program accounted for expenditures of $8.5 million.

As a result of these activities, the Company ended the second quarter of 2003 with negative working capital of $5.5 million compared to negative working capital of $1.9 million at December 31, 2002, while its current ratio declined to .68 to 1 compared to .81 to 1 at year end. The Company exited the second quarter with no unused borrowing base 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 $18.9 million, a 23% increase over the same period of the prior year. Cash flow from operating activities for the six-month period increased to a positive $11.3 million from $2.0 million in the comparative prior year period reflecting the significant increase in oil production and realized oil and gas prices over the same period of the prior year.

Credit Facility - The Company has a $25 million oil and gas reserve based Revolving Credit Facility with Hibernia National Bank (the "Facility" or "Credit Facility" or "Lender"). At June 30, 2003 the borrowing base was $14 million, which was fully utilized. 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 4.00% at June 30, 2003. The Facility contains certain financial covenants and other negative restrictions common for this type of financing. As of June 30, 2003 the Company was not in compliance with the current ratio covenant under the Facility. The Company has received a permanent waiver for the covenant violation for the March 31 measurement period. On August 13, 2003, the Company and the Lender entered into an amendment to the Facility, which revised the current ratio covenant and waived the June 30, 2003 violation.

In 2003, the Company aggressively increased its CAPEX program on its projects in the Maverick Basin. To date the expenditures were funded through a combination of the Company's Credit Facility, positive cash flow resulting from existing and prospectively drilled wells, as well as, trade credit. In order for the Company to complete its CAPEX program for the balance of the year, the Company sought additional financing. The Company's new Preferred issuance is expected to allow for completion of the CAPEX program for the year along with the elimination of the Company's working capital deficit.

Management is continually 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.

Series B Redeemable Preferred Stock ("Preferred") -

Subsequent to June 30, 2003, the Company entered into a private placement agreement with Kayne Anderson Energy Fund II, L.P. and Gryphon Master Fund, L.P., to issue 16,000 shares, with a stated value of $1,000 each, of Series B Redeemable Preferred Stock ("Preferred"), and 2,133,333 shares of common stock, raising a total of approximately $15.1 million after offering costs. All of the common stock will be restricted from trading in a public transaction for one year from issuance, and the Company will have the option to repurchase up to one-half of the common stock at a purchase price of $6.00 per share for a period of two years from closing. The Preferred will be recorded as debt on the balance sheet.

The Preferred bears interest at 8.0 percent per annum, payable quarterly in cash, for the first three years, increasing to 10% per annum at that time. The Preferred must be redeemed at the end of six years, and are redeemable at the Company's option anytime after issuance at 100% of the stated value. The Preferred has a liquidation preference equal to the stated value, an aggregate of $16 million.

TXCO will use the proceeds to continue its active Maverick Basin drilling program and for general business purposes.

Significant Changes to Contractual Obligations - During the current year the Company increased borrowings under its Credit Facility to $14.0 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.

As further discussed in Note 5 to the financial statements, the Company has recorded a long-term asset retirement obligation, which totaled $1.4 million at June 30, 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.

Reserve Growth

As of June 30, 2003, the Company's estimated proved oil and gas reserves and the present value of the future net revenues using a 10% discount factor (PV-10 Value), as estimated by Netherland Sewell & Associates, Inc., a Dallas, Texas engineering firm, grew by 1.2 Bcfe as compared to December 31, 2002. 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.

June 30,
2003

December 31,
2002

Oil Reserves (MMBbl)

1.7

1.5

Gas Reserves (Bcf)

14.5

14.7

Total Reserves (Bcfe)

24.7

23.5

PV-10 Value (in thousands)

$51,422

$45,382

Results of Operations

Net income was $9,600 and $734,000 for the second quarter and year-to-date periods ended June 30, 3003. This compares with net income of $543,000 and a net loss of $174,000 for the second quarter and year to date periods ended June 30, 2002. High depletion and impairment charges in the second quarter of 2003 offset the significant increase in oil and gas revenues over the same period of the prior year.

Oil and gas revenues for the second quarter totaled $6.6 million, while year-to-date revenues were $12.5 million. This represents an increase of 75% and 124%, respectively, for the quarter and year-to-date periods ended June 30, 2003 versus the comparable prior year periods. These increases are attributable to higher oil and gas prices realized during 2003 and significantly increased oil production volumes partially offset by a decline in gas production volumes. As reflected in the following table, average realized gas prices were 62% and 102% higher than the comparable periods in 2002 while average oil prices increased 14% and 28%, respectively, for the same periods. Oil sales volumes increased 118% and 170%, respectively, for the quarter and year-to-date periods, 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 22% and 19%, respectively, over the same periods 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

Three months ended June 30,

Gas (Mcf)

495,794

$ 5.69

638,411

$ 3.52

Oil (Bbls)

141,062

$26.61

64,588

$23.25

Six months ended June 30,

Gas (Mcf)

1,047,113

$ 5.88

1,289,279

$ 2.90

Oil (Bbls)

222,171

$28.38

82,360

$22.16

On an equivalent unit basis, total sales volumes increased by 31% for the quarter ended June 30, 2003 over the prior year quarter and 29% over the first quarter of 2003, while increasing 33% for the six months ended June 30, 2003 over the same period for 2002.

During the second quarter and year-to-date periods, the Company's gas gathering operations revenues totaled $3.3 million and $6.5 million, respectively. Included for the six-month period were sales of third-party natural gas of $5.2 million purchased for resale by the Company along its gathering system, sales of natural gas liquids extracted from that gas of $1.1 million and transportation revenue of $173,000. Based on a total volume of 1,196,400 MMbtu, the Company's realized year-to-date average sales price per MMbtu was $5.28.

Lease operating expenses (LOE) increased 33% for the first six-month period of 2003 as compared to the same period of 2002 consistent with TXCO's expanded operating activities in the Maverick Basin. The increase primarily reflects the incremental LOE associated with operating the Pena Creek oil field acquired in May 2002, eight new Saxet-operated Comanche lease oil wells and 22 additional Maverick Basin oil and gas wells placed on production since June 30, 2002. During the current year periods, production taxes fluctuated proportionately with the oil and gas revenues compared to the prior year periods.

The Company's gas gathering system is generally operated on a break-even basis. The gas must be processed to remove liquids, as the Company's end market will not accept gas with a high liquid content. In processing, the Company incurs shrinkage of its gas being sold due to the removal of liquids and other products, which lowers the MMbtu content of the processed gas. 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 in May of 2002, 2003 versus 2002 operations comparisons are not meaningful.

During the current year, the Company's gas gathering system expense totaled $7.0 million, including costs to purchase third party gas along the Company's gathering system of $6.5 million, associated transportation and marketing expenses required to market that gas of $169,000 and direct operating costs of the pipeline of $253,000. 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.

Depreciation, depletion and amortization increased 141% for the six-month period ended June 30, 2003 over the comparable prior year period. The increase in depletion of $2.4 million was due primarily to the sharply increased production volumes and higher number of producing 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 $220,000 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 100% for the current six-month period as compared to the same period in 2002. This increase is consistent with the higher sustained levels of Company operations and was due primarily to increased salaries, wages, benefits and office overhead associated with staff increases. Staffing at June 30, 2003 included 41 full time employees, as compared to 26 in 2002. Also contributing to the increase were higher costs for property and liability insurance, and increased legal and consulting fees and expenses 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 six months of 2003 increased by $159,000 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 expects to incur Corporate alternative minimum tax expense for 2003.

See Notes 5 and 8 for a discussion of recent accounting pronouncements.

Drilling Activities

During the six months ended June 30, 2003, the Company drilled or participated in the drilling of 42 wells on its 479,761-acre lease block in the Maverick Basin. At June 30, 2003, 25 of these wells were producing, seven wells were in completion phase, four wells were shut-in pending further evaluation, one well was temporarily abandoned pending sidetrack operations, while five wells remained drilling. By comparison, the Company participated in 12 wells in the first half of 2002. The wells targeted multiple productive formations, including the Glen Rose, San Miguel, Georgetown and Jurassic intervals, which are discussed in more detail later in this section. The Company exited the first six months of 2003 with total net daily production rates of 1,886 barrels of oil per day (BOPD) and 6.6 million cubic feet (MMcfd) of natural gas. By July 31, net daily production rates decreased to approximately 1,400 BOPD, as increasing water production impacted the horizontal wells on the Comanche lease, while gas production declined below 6.5 MMcfd.

Glen Rose Oil - TXCO spudded five horizontal wells targeting the Glen Rose porosity interval in 2003 to date. The field's first horizontal well, the Comanche 3-111H, went on production in April and, at July 31, was producing approximately 330 BOPD and 600 BWPD. The Comanche 4-111H well was completed in mid June, the second horizontal well to the Glen Rose porosity interval. This well initially produced approximately 1,380 BOPD and no water to TXCO and its operating partner, Saxet Energy Ltd. (Saxet). Approximately 48,000 barrels of water were lost into the formation during drilling of a 4,300-foot lateral extension through the producing formation's oil-bearing zone. At July 31, the well was producing approximately 440 BOPD and 540 BWPD, while approximately 12,000 barrels of water had been recovered. Since this recovery is only approximately 25% of the water lost while drilling, it is too early to determine whether the well is producing formation water. The operator is conducting tests to determine the water's source. Since late June both wells have begun experiencing greater water production and reduced oil production.

Production began in mid-July on a third proposed horizontal well, the Comanche 1-117H, at approximately 100 BOPD and 190 BWPD. This well was not completed horizontally because it began flowing a significant volume of oil while drilling the curve for the planned lateral extension. Meanwhile, drilling began in late July on two additional horizontal wells targeting the porosity interval. During the first week of August one of these, the Comanche 2-112H, tested at flow rates as high as 2300 barrels per day of fluid, 95% of which was oil. After the test, the well was shut-in to remove the drilling rig and complete the well. Production from the Comanche Halsell (6500) Field averaged approximately 2,140 BOPD and 8,800 barrels of water per day (BWPD) from 14 producing wells with seven wells shut-in and under evaluation as horizontal recompletion candidates.

TXCO spudded five vertical delineation wells targeting the porosity interval in 2003 to date. Four of those wells were spudded since the end of March. At July 31, one well was producing, one was awaiting completion, and three were being evaluated for possible sidetrack operations. The Comanche 1-46 went on production in early May and at July 31 was producing approximately 80 BOPD and 1,600 BWPD.

Two of the vertical wells, approximately 14 miles east of the original discovery well (Pena Creek area), encountered water production when the Glen Rose porosity zone was drilled. The Myers 1-683 produced water in the open hole portion from fractures connecting the Glen Rose porosity zone with a water-bearing zone approximately 100 feet below as determined from a temperature survey. The water was more saline than water produced from other Comanche Glen Rose wells. Only ten feet of porosity zone were cut when water production commenced on the Vivian 1-687 well at rates of ten barrels per minute. The water exhibited chlorides similar to the Myers well. A temperature survey was not run on this well to determine the source of water due to the very limited amount of zone penetrated in the wellbore. The Vivian was plugged back and drilled horizontally in the Georgetown formation. The Myers well is shut-in pending completion of title work to allow a sidetrack lateral extensio n in the Glen Rose porosity zone.

Additionally, Saxet re-entered two existing wells during the first six months of 2003. The Comanche 2-44ST was sidetracked 300 feet laterally, encountered the porosity zone, was recently placed on pump and is producing 20 BOPD. The Comanche 2-2 was acid fractured without success and remains shut-in pending sidetrack operations.

In addition to potential oil production, the vertical delineation wells are intended to accelerate determination of the areal extent of the oil-bearing portion of the porosity interval, which was originally identified by 3-D seismic across approximately 20 square miles of TXCO's Maverick Basin lease block. Based on drilling results to date, TXCO expects to realize significant new Glen Rose oil reserve additions by year-end from its current exploration and development program with additional production history. Cumulative production from the Glen Rose porosity zone through July 31, 2003 was in excess of 1 MMBbl of oil.

Horizontal Glen Rose Shoal - During the first six months of 2003, TXCO successfully completed six new horizontal Glen Rose shoal gas wells, in addition to one in progress at year end 2002, including six wells on the Chittim lease and one on the Paloma lease. At June 30, total horizontal Glen Rose shoal gas production reached a gross daily volume of approximately 9.9 MMcf.

The Chittim 1-157H was spudded in late June and completed as a Glen Rose shoal gas well on August 1. Subsequent to June 30, TXCO spudded another Glen Rose shoal well, the Chittim 3-158H, which is currently drilling.

Georgetown Formation - TXCO has realized mixed success to date in tapping the Georgetown formation through use of deviated well techniques. The wells are engineered to cut across the formation's nearly vertical faults at deviated angles, targeting higher flow rates and production compared to similarly situated conventional wells. TXCO has spudded eight Georgetown deviated wells in 2003, including three new wells spudded since the end of March. Of these eight wells, three are producing oil, one is producing gas, two are awaiting completion and two are shut-in pending further geological and engineering evaluation. In addition, two existing wells were recompleted in the Georgetown formation. One well remains marginal and the second is shut-in pending further evaluation.

Drilling is expected to resume in August upon arrival of a new drilling rig that replaces a contractor released in June. Gross Georgetown production rates at June 30 were 210 BOPD and 770 Mcfd from fourteen producing wells, compared to the approximately 20 BOPD and 910 Mcfd at March 31. At July 31 production was 120 BOPD and 1,050 Mcfd from 18 producing wells.

San Miguel Waterflood - The Pena Creek Field remains a center of activity as TXCO continues its successful infill-drilling program to reach bypassed reserves in the San Miguel formation. Sixteen Pena Creek wells were spudded during the first six months of 2003, eight of those in the second quarter, all of which have been successfully fracture stimulated, completed and placed on production. Daily gross production rates from the Pena Creek field increased from 265 BOPD at year-end 2002 to approximately 450 at July 31. Subsequent to June 30, 2003, TXCO spudded three additional infill wells, all of which are awaiting completion.

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 below 15,000 feet and is predicted to reach total depth in the third quarter. 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 ultimately prove to 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 believes 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 during the third quarter.

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 mid-July 2003, 36 wells were producing 180 Mcfd and 2,150 BWPD, compared with 170 Mcfd and 2,325 BWPD at the end of March 2003. Two wells are temporarily shut-in for operational reasons. Three wells have achieved 50% to 100% increases in gas production since March 31, 2003. The Company believes this significant increase in gas production could signify the beginning of an important acceleration in the project's dewatering phase.

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 continues to pursue 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 June 30, 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.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

None

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS

Series B Preferred Stock Financing

On August 1, 2003 the Company entered into an agreement to sell 16,000 shares of mandatorily redeemable preferred stock and 2.13 million shares of common stock in a private placement of securities, raising a total of approximately $15.1 million after offering costs. The agreement is expected to close in late August. The preferred stock has a liquidation preference equal to the stated value for the shares, which was $1,000 per share. The Preferred shares have certain rights such as information rights as well as representation on the TXCO Board of Directors. The board representation comes in the form of one director and one board observer.

The net proceeds from the offering will be used to fund the Company's active drilling program in the Maverick Basin and for general corporate purposes.

The foregoing transactions were the result of arm's-length negotiations with accredited investors who were provided with our business and financial information, including copies of our periodic reports as filed with the Securities and Exchange Commission, and who were provided with the opportunity to ask questions directly of our executive officers. In each instance, the securities purchased will be restricted securities taken for investment. Certificates for all shares issued in such transactions will bear a restrictive legend conspicuously on their face and stop-transfer instructions will be noted respecting such certificates on our stock transfer records. Each of the foregoing transactions was effected in reliance on the exemption from registration provided in Section 4(2) of the Securities Act of 1933, as amended, as transactions not involving any public offering. The Company will file a registration statement within one year of closing for the 2.13 million shares of c ommon stock issued.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None

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

On May 30, 2003, the Company held the Annual Meeting of Shareholders at the Petroleum Club of San Antonio, pursuant to the notice mailed to shareholders of record on April 15, 2003. The following matters were submitted for approval by vote at the meeting. All matters were approved by the shareholders vote and the results of the voting is shown below for each matter.

1.	Election of two Class B Directors to serve for three-year terms expiring in 2006:

	Nominee	For	Against

	Stephen M. Gose, Jr.	16,353,758	381,841
	Alan L. Edgar	16,394,772	340,827

There were no changes in Directors of the Company.







18

2.	Proposal to amend the Company's 1995 Flexible Incentive Plan to increase by 300,900 the maximum number of shares of Common Stock that may be issued with respect to awards under the Plan.

	For	Against	Abstain

	8,498,256	2,541,899	157,926

3.	Proposal to amend the Company's 1995 Flexible Incentive Plan to provide for automatic adjustments to the number of shares authorized for issuance based upon the number of the then outstanding shares of the Company's stock.

	For	Against	Abstain

	8,462,888	2,585,440	149,753

4.	Proposal to ratify the appointment of Akin, Doherty, Klein & Feuge, P.C., certified public accountants, as independent auditors of the Company and its subsidiaries for the calendar year ending December 31, 2003.

	For	Against	Abstain

	16,538,316	102,215	95,068



ITEM 5. OTHER INFORMATION

None





























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ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

a) Exhibit 31.1 Certification of Chief Executive Officer required pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 filed herewith.

b) Exhibit 31.2 Certification of Chief Financial Officer required pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 filed herewith.

c) Exhibit 32.1 Certification of Chief Executive Officer required pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 filed herewith.

d) Exhibit 32.2 Certification of Chief Financial Officer required pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 filed herewith.

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

f) 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.

g) Form 8-K dated May 15, 2003, regarding the Registrant's financial results for the quarter ended March 31, 2003.

h) Form 8-K dated June 4, 2003, regarding the press release dated June 2, 2003 with respect to the review of active drilling program at the May 30, 2003 annual meeting of shareholders.

i) Form 8-K dated June 25, 2003, regarding the press release dated June 24, 2003 with respect to changes in the Registrant's management team.

j) Form 8-K dated, July 1, 2003, regarding the press release dated June 30, 2003 with respect to the Registrant's operations update.

k) Form 8-K dated, August 7, 2003, regarding the press releases dated August 4, 2003 with respect to the Registrant's second quarter earnings release and August 6, 2003 regarding the webcast of the Registrant's presentation to the 8th Oil and Gas Conference in Denver.


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/ P. Mark Stark

	P. Mark Stark,
	Chief Financial Officer

Date: August 14, 2003





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