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.
September 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 November 7, 2003.

Common Stock $0.01 par value		22,143,049
(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 19




1


PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

THE EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

	September 30, 2003		December 31, 2002


Assets

Current Assets
Cash		$ 5,455,899		$ 2,333,688
Accounts receivable, net		6,616,714		5,118,270
Prepaid expenses		1,010,363		503,176

Total Current Assets		13,082,976		7,955,134

Property and Equipment, net - successful efforts method of accounting for oil and gas properties		60,628,466		39,327,867

Other Assets
Deferred tax asset		5,232,718		5,232,718
Other assets		1,076,338		520,600

Total Other Assets		6,309,056		5,753,318


Total Assets		$80,020,498		$53,036,319






See notes to consolidated financial statements

2






THE EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

	September 30, 2003			December 31, 2002


Liabilities and Stockholders' Equity

Current Liabilities
Accounts payable, trade		$ 6,778,445		$ 3,684,550
Other payables and accrued liabilities		4,621,493		3,187,174
Undistributed revenue		1,332,312		1,894,144
Current portion of long-term debt		1,660,046		1,073,773

Total Current Liabilities		14,392,296		9,839,641

Long-Term Liabilities
Long-term debt, net of current portion		10,490,983		6,143,458
Redeemable preferred stock, Series B (redemption value $16 million)		9,928,149		-
Accrued dividends - preferred stock		17,733		-
Asset retirement obligation		1,502,200		-

Total Long-Term Liabilities		21,939,065		6,143,458

Minority Interest in Consolidated Subsidiaries		106,494		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 22,242,849 and 20,109,516 shares, outstanding 22,143,049 and 20,009,716 shares		222,428		201,095
Additional paid-in capital		64,014,851		58,216,504
Accumulated deficit		(20,408,629	)	(21,201,218	)
Less treasury stock, at cost, 99,800 shares		(246,007	)	(246,007	)

Total Stockholders' Equity		43,582,643		36,970,374


Total Liabilities and Stockholders' Equity		$80,020,498		$53,036,319






See notes to consolidated financial statements

3





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


Revenues
Oil and gas sales		$6,027,088			$5,410,090
Gas gathering operations		3,364,162			509,337
Other operating income		2,631			34,879

Total revenues		9,393,881			5,954,306

Costs and Expenses
Lease operations		1,158,760			1,166,427
Production taxes		348,225			292,920
Exploration expenses		292,928			403,167
Impairment and abandonments		641,725			514,950
Gas gathering operations		3,309,515			577,975
Depreciation, depletion and amortization		2,214,530			1,487,466
General and administrative		990,733			507,434

Total costs and expenses		8,956,416			4,950,339


Income from Operations		437,465			1,003,967

Other Income (Expense)
Interest income		10,754			15,144
Interest expense		(407,697	)		(80,180	)

Total other income (expense)		(396,943	)		(65,036	)


Income before income taxes, minority interest
and cumulative effect of change in accounting principle		40,522			938,931

Minority interest in income (loss) of subsidiaries		17,944			(6,978	)


Income before income taxes and cumulative effect of change in
accounting principle		58,466			931,953
Income tax expense		-			-
Cumulative effect of change in accounting principle, net of tax		-			-


Net Income		$ 58,466			$ 931,953


Earnings Per Share
Basic:
Earnings before cumulative effect of change in
accounting principle		$0.00			$0.05
Cumulative effect of change in accounting principle		-			-

Net earnings per share		$0.00			$0.05


Diluted:
Earnings before cumulative effect of change in
accounting principle		$0.00			$0.04
Cumulative effect of change in accounting principle		-			-

Net earnings per share		$0.00			$0.04




See notes to consolidated financial statements

4

THE EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

Nine Months
Ended

September 30, 2003

September 30, 2002

Revenues

Oil and gas sales

$18,484,022

$10,978,399

Gas gathering operations

9,863,948

660,550

Other operating income

2,553

303,917

Total revenues

28,350,523

11,942,866

Costs and Expenses

Lease operations

3,211,075

2,712,397

Production taxes

1,151,498

654,041

Exploration expenses

1,294,529

985,468

Impairment and abandonments

1,517,875

1,257,850

Gas gathering operations

10,324,076

684,536

Depreciation, depletion and amortization

6,708,998

3,356,290

General and administrative

2,621,636

1,322,994

Total costs and expenses

26,829,687

10,973,576

Income from Operations

1,520,836

969,290

Other Income (Expense)

Interest income

21,314

36,818

Interest expense

(679,779

)

(193,297

)

Total other income (expense)

(658,465

)

(156,479

)

Income before income taxes, minority interest

and cumulative effect of change in accounting principle

862,371

812,811

Minority interest in income (loss) of subsidiaries

54,218

(129,437

)

Income before income taxes and cumulative effect of change in

accounting principle

916,589

683,374

Income tax expense

(50,000

)

75,000

Cumulative effect of change in accounting principle, net of tax

(74,000

)

Net Income

$ 792,589

$ 758,374

Earnings Per Share

Basic:

Earnings before cumulative effect of change in

accounting principle

$0.04

$0.04

Cumulative effect of change in accounting principle

Net earnings per share

$0.04

$0.04

Diluted:

Earnings before cumulative effect of change in

accounting principle

$0.04

$0.04

Cumulative effect of change in accounting principle

Net earnings per share

$0.04

$0.04

See notes to consolidated financial statements





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


Operating Activities
Net income		$ 792,589			$ 758,374
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		6,708,998			3,366,396
Impairment and abandonments		1,517,875			1,257,850
Minority interest in (income) loss of subsidiaries		(54,218	)		129,437
Cumulative effect of change in accounting principle		74,000			-
Accrued interest expense and accretion of liability - preferred stock		255,594			-
Changes in operating assets and liabilities:
Receivables		(1,498,444	)		(2,383,010	)
Prepaid expenses and other		(507,187	)		(409,882	)
Accounts payable and accrued expenses		3,966,382			1,303,829

Net cash provided by operating activities		11,255,589			4,022,994

Investing Activities
Development and purchases of oil and gas properties		(27,781,230	)		(22,052,470	)
Purchase of other equipment		(354,122	)		(559,616	)
Proceeds from sale of oil and gas properties		-			200,000
Contributions made by minority interests		71,205			1,272,000
Distributions to minority interests		6,660			(407,947	)

Net cash used by investing activities		(28,057,487	)		(21,548,033	)

Financing Activities
Issuance of redeemable preferred stock, net of offering costs		9,170,632			-
Issuance of common stock, net of offering costs		5,819,679			14,193,398
Proceeds from debt obligations		8,200,000			4,157,565
Proceeds from installment obligations		2,797,078			-
Deferred financing fees		-			(52,648	)
Payments on debt obligations		(6,063,280	)		(267,861	)

Net cash provided by financing activities		19,924,109			18,030,454


Change in cash and equivalents		3,122,211			505,415

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


Cash and Equivalents at End of Period		$ 5,455,899			$ 2,524,579








See notes to consolidated financial statements

6

THE EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PERIODS ENDED SEPTEMBER 30, 2003 AND SEPTEMBER 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 Per Share

As of September 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 June 2013.

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

	Shares	Income		Per Share Amount

Nine Months Ended September 30, 2003
Basic EPS:
Net income before cumulative effect of change in accounting principle	20,322,292	$866,589		$0.04
Cumulative effect of change in accounting principle	-	(74,000	)	-

Net income	20,322,292	792,589		0.04
Effect of dilutive options	687,262	-		-

Dilutive EPS	21,009,554	$792,589		$0.04


Three Months Ended September 30, 2003
Basic EPS:
Net income	20,937,252	$58,466		$0.00
Effect of dilutive options	1,211,676	-		-

Dilutive EPS	22,148,928	$58,466		$0.00


Nine Months Ended September 30, 2002
Basic EPS:
Net income	18,776,297	$758,374		$0.04
Effect of dilutive options	1,139,876	-		-

Dilutive EPS	19,916,173	$758,374		$0.04


Three Months Ended September 30, 2002
Basic EPS:
Net income	19,984,716	$931,953		$0.05
Effect of dilutive options	1,344,532	-		(0.01	)

Dilutive EPS	21,329,248	$931,953		$0.04



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 nine months ended September 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 September 30, 2003, the borrowing base was $14 million, with an outstanding balance of $9 million. The interest rate at September 30, 2003, was 4.0%. Interest 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. At September 30, 2003, the Company is in compliance with all such covenants and restrictions. As of March 31, 2003 and June 30, 2003, the Company was not in compliance with the Current Ratio covenant. The Company 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. Redeemable Preferred Stock, Series B

Effective August 21, 2003, the Company authorized and issued 16,000 shares, with a stated value of $1,000 each, of Redeemable Preferred Stock, Series B ("Preferred"), and 2,133,333 shares of common stock, in a private placement, raising a total of approximately $15.0 million after offering costs. All of the common stock issued is restricted from trading in a public transaction for one year from issuance, and the Company has 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 has been recorded as debt on the balance sheet.

The Preferred bears interest at 8.0 % of stated value, payable quarterly in cash, for the first three years, increasing to 10% thereafter. The Preferred must be redeemed at the end of six years at its full stated value of $16.0 million, and is redeemable at any time at the Company's option at 100% of the stated value. The Preferred was initially recorded at its fair value of $9.8 million and will be accreted to its stated value of $16.0 million over the redemption period. The accretion will be recorded as interest expense. The Preferred shares have certain rights, such as information rights, as well as representation by one director and one board observer on the TXCO Board of Directors.

6. 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 2003, nor would it have had a material impact on 2002 assuming adoption on a pro-forma basis. This Statement is not expected to have an additional material impact on the Company's financial position or operations in future periods.

7. 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 nine and three month periods ended September 30:

Nine Months Ended September 30:

2003

2002

Net income as reported

$792,589

$758,374

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

124,361

124,361

Pro forma earnings

$668,228

$634,013

Earnings per common share:

Basic, as reported

$0.04

$0.04

Basic, pro forma

$0.03

$0.03

Diluted, as reported

$0.04

$0.04

Diluted, pro forma

$0.03

$0.03

Three Months Ended September 30:

Net income as reported

$58,466

$931,953

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

124,361

124,361

Pro forma earnings

$(65,895

)

$807,592

Earnings per common share:

Basic, as reported

$ 0.00

$0.05

Basic, pro forma

$(0.00

)

$0.04

Diluted, as reported

$ 0.00

$0.04

Diluted, pro forma

n/a

$0.04

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 5 has been 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 materially 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 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 nine months ended September 30, 2003. Borrowing on the Credit Facility and installment obligations totaled $11.0 million, together with net proceeds from the issuance of preferred and common stock of $15.0 million, resulted in total cash available of $39.6 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.

Third quarter payments on debt totaled $5.1 million with $210,000 of related interest. This reflects a $5.0 million payment on bank debt made out of the proceeds from the private placement of preferred and common stock. Approximately $8.8 million was invested in drilling activities during this period.

As a result of these activities, the Company ended the third quarter of 2003 with negative working capital of $1.3 million compared to negative working capital of $1.9 million at December 31, 2002, while its current ratio rose to .91 to 1 compared to .81 to 1 at year end. The Company exited the third quarter with an unused borrowing base of $5.0 million under its Credit Facility. The improved working capital position reflects $15.0 million net proceeds from the private placement of preferred and common stock, partially offset by $5.8 million higher payments on debt obligations, and $5.7 million higher drilling and development activity during 2003 as compared with the same period of 2002. Drilling and development activity expenditures for the nine month period totaled $27.8 million, a 26% increase over the same period of last year. Cash flow from operating activities for the nine-month period increased to $11.3 million from $4.0 million in the comparative prior year period, r eflecting 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 September 30, 2003, the borrowing base was $14.0 million with an outstanding balance of $9.0 million and an unused borrowing base of $5.0 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 4.00% at September 30, 2003. The Facility contains certain financial covenants and other negative restrictions common for this type of financing. As of September 30, 2003, the Company was in compliance with all such ratios. At June 30 and March 31, 2003, the Company was not in compliance with the current ratio covenant under the Facility. The Company 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 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 wells, trade credit, as well as the Company's Preferred issuance. Management believes that these sources, together with expected new cash flows from prospectively drilled wells, will be adequate to fund ongoing operating cash requirements for its capital expenditure program.

Forward Sales Contract - 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.

Redeemable Preferred Stock, Series B ("Preferred") - In August 2003, the Company entered into a private placement agreement with Kayne Anderson Energy Fund II, L.P. and Gryphon Master Fund, L.P., and issued 16,000 shares (16,000 shares authorized), with a stated value of $1,000 each, of Redeemable Preferred Stock, Series B, and 2,133,333 shares of common stock, raising a total of approximately $15.0 million after offering costs. All of the common stock is restricted from trading in a public transaction for one year from issuance, and the Company has the option to repurchase up to one-half of the common stock at a price of $6.00 per share for a period of two years from closing. The Preferred has been recorded as debt on the balance sheet.

While the Preferred is outstanding, holders have the right to elect one director and one board observer to the TXCO Board of Directors. Under certain conditions relating to the default on the Preferred or the deferral of dividend payments, holders of the Preferred may elect additional directors to the Board. At the closing on the sale of the Preferred, Charles W. Yates, III, of Kayne Anderson was elected to the Board to represent holders of the Preferred, and Michael Heinz was elected their Board observer.

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

Significant Changes to Contractual Obligations - 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 of 2004 and 2005.

Borrowings under the Company's Credit Facility total $9.0 million at September 30, 2003 compared to $5.8 million at December 31, 2002. As noted in the preceding section, the Company issued $16 million of preferred stock that is mandatorily redeemable in August 2009.

As further discussed in Note 6 to the financial statements, the Company has recorded a long-term asset retirement obligation, which totaled $1.5 million at September 30, 2003, as a result of its adoption of SFAS No. 143 effective January 1, 2003.

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.

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

Net income was $58,000 and $793,000 for the third quarter and year-to-date periods ended September 30, 2003. This compares with net income of $932,000 and $758,000 for the third quarter and year-to-date periods ended September 30, 2002. High depletion and impairment charges in the second and third quarters of 2003 offset the significant increase in oil and gas revenues over the prior-year periods.

Oil and gas revenues for the third quarter totaled $6.0 million, while year-to-date revenues were $18.5 million. This represents an increase of 11% and 68%, respectively, for the quarter and year-to-date periods ended September 30, 2003 versus the comparable prior year periods. The year-to-date increases are attributable to higher oil and gas prices realized during 2003 and increased oil production volumes, partially offset by a decline in gas production volumes. The increase for the third quarter reflects higher prices offset by lower production volumes for both oil and gas, when compared to the prior year quarter. Oil sales volumes reflect production from the new Comanche lease oil wells along with production from the Pena Creek field acquired in May 2002, offset for the quarter, by production declines from maturing oil wells. Gas sales volumes decreased over the same periods. Gas production from new wells was offset by general production declines of the Company's maturin g gas wells. The following table compares cumulative production volumes and average sales prices for the three- and nine-month periods ended September 30, 2003 and 2002.

Cumulative Production Volumes:

2003

2002

% Change

Three months ended September 30,

Gas (Mcf)

475,331

626,077

-24.1

Oil (Bbls)

125,778

130,041

-3.3

Natural Gas Equivalent (MMcfe)

1,230

1,406

-12.5

Oil Equivalent (BOE)

205,000

234,387

-12.5

Nine months ended September 30,

Gas (Mcf)

1,522,452

1,915,356

-20.5

Oil (Bbls)

347,951

212,402

+63.8

Natural Gas Equivalent (MMcfe)

3,610

3,190

+13.2

Oil Equivalent (BOE)

601,693

531,628

+13.2

Average Sales Prices:

2003

2002

% Change

Three months ended September 30,

Gas (Mcf)

$ 5.32

$ 3.39

+56.9

Oil (Bbls)

$27.83

$25.27

+10.1

Nine months ended September 30,

Gas (Mcf)

$ 5.70

$ 3.06

+86.3

Oil (Bbls)

$28.18

$24.06

+17.1

During the third quarter and year-to-date periods, the Company's gas gathering operations revenues totaled $3.4 million and $9.9 million, respectively. Included for the nine-month period were sales of third-party natural gas of $7.8 million purchased for resale by the Company along its gathering system, sales of natural gas liquids extracted from that gas of $1.8 million and transportation revenue of $264,000. Based on a total volume of 1,835,600 MMbtu, the Company's realized year-to-date average gas sales price per MMbtu was $5.22.

Lease operating expenses (LOE) increased 18% for the first nine-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, 13 new Saxet-operated Comanche lease oil wells and 45 additional Maverick Basin oil and gas wells placed on production since September 30, 2002. Production taxes for the current period fluctuated proportionately with the oil and gas revenues compared to the prior year period.

The Company's gas gathering system is generally expected to operate on a break-even basis. The gas must be processed to remove natural gas 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 natural gas liquids, 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, comparisons of 2003 operations to 2002 are not meaningful.

During the current year, the Company's gas gathering system expense totaled $10.3 million. This includes costs to purchase third-party gas along the Company's gathering system of $9.6 million, associated transportation and marketing expenses required to market that gas of $265,000 and direct operating costs of the pipeline of $488,000. 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 in the first quarter. 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 49% and 100% for the three- and nine-month periods ended September 30, 2003 over the comparable prior year periods. The increase in depletion of $660,000 and $3.0 million for the current quarter and nine months, respectively, as compared with the prior year periods 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 $347,000 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 95% and 98% for the current quarter and nine-month periods as compared to the same periods in 2002. General and administrative expenses were 9.3% and 11.1% of total revenues for the nine months ended September 30, 2003 and 2002, respectively. Staffing at September 30, 2003 included 44 full time employees, as compared to 32 in 2002. Technical and professional staffing levels and associated expenses increased in line with TXCO's higher drilling and operations levels. 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 nine months of 2003 increased by $486,000 over the same period of 2002 due to the new Preferred issuance and higher balances on the Credit Facility. 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 a minimal Corporate alternative minimum tax expense for 2003.

See Notes 6 and 8 for a discussion of recent accounting pronouncements.

Drilling Activities

During the nine months ended September 30, 2003, the Company drilled or participated in the drilling of 60 wells on its 480,000-acre lease block in the Maverick Basin. Status at September 30, 2003 for wells spud in 2003 was 38 producing, 17 in completion phase, two shut-in pending further evaluation, and one temporarily abandoned pending sidetrack operations, while two remained drilling. By comparison, the Company participated in 27 wells in the first nine months of 2002. The wells targeted multiple productive formations, including the Glen Rose, San Miguel, Georgetown, Escondido and Jurassic intervals, which are discussed in more detail later in this section. The Company exited the first nine months of 2003 with total net daily production rates of 1,299 barrels of oil per day (BOPD) and 6.1 million cubic feet (MMcfd) of natural gas. At October 31, 2003, total net daily production was 1,440 BOPD and 7.7 MMcfd of natural gas. At October 31, 2003, four rigs were drilling o n our Maverick Basin acreage.

Glen Rose Oil - TXCO and its operating partner, Saxet Energy Ltd. (Saxet) spudded six horizontal wells and seven vertical delineation wells targeting the Glen Rose porosity interval in the first nine months of 2003. Of these new wells, status at September 30, 2003 was six producing, five awaiting re-completion, one recompleted and producing in the Georgetown formation, and one shut-in.

Horizontal drilling has been used with varying degrees of success in an attempt to optimize oil production while minimizing associated water production. Horizontal wells drilled in the porosity zone have been much more successful than those drilled above the porosity zone. In addition to increasing overall Glen Rose oil production, the vertical delineation wells have been located to help determine the areal extent of the oil-bearing portion of the porosity interval. The target horizon covering more than 20 square miles was originally identified by 3-D seismic survey across TXCO's Maverick Basin lease block.

Gross production from the Comanche Halsell (6500) Field at September 30, 2003 was 1,946 BOPD and 9,546 barrels of water per day (BWPD) from 16 producing wells with seven wells shut-in and under evaluation as horizontal recompletion candidates. By early November cumulative production from the Glen Rose porosity zone was in excess of 1.3 MMBbl of oil since its initial discovery in March 2002.

During September a 760-foot lateral was drilled on the Comanche 2-2 using a new technique, which drills the horizontal lateral parallel to the faults within the porosity zone to avoid water production. The well went on production in October and has averaged over 750 BOPD with no water throughout October. During October, Saxet re-entered the Comanche 2-13, drilling a lateral that intersected faults and fractures above the porosity interval. The well tested at 100 BOPD with no water but stopped flowing and has been shut-in for further evaluation.

Based on drilling results to date, TXCO hopes to realize new Glen Rose oil reserve additions from its current exploration and development program with additional production history. An annual November-to-January hunting season drilling moratorium is now in effect on the Comanche Ranch, which includes the Glen Rose porosity prospects. TXCO expects to apply the new technique used on the Comanche 2-2 for future wells planned following the expiration of the annual hunting season drilling moratorium, as well as re-entries of many wells that have already been drilled.

Horizontal Glen Rose Shoal - During the first nine months of 2003, TXCO successfully completed eight new horizontal Glen Rose shoal gas wells, in addition to one in progress at year end 2002 (eight wells on the Chittim lease and one on the Paloma lease). At September 30, total horizontal Glen Rose shoal gas production reached a gross daily volume of approximately 9.6 MMcf.

Two additional wells were awaiting completion at September 30 and came on production in October. The Chittim 2-144 (47.3% WI) went on production at 1.3 MMcfd and 17 BOPD while the Chittim 4-143 (47.3% WI) flowed gas at the rate of 950 Mcfd and 10 BOPD. Subsequent to September 30, TXCO spudded another Glen Rose shoal well, the Chittim 2-157, which began producing in early November at rates of 1.6 MMcfd and 15 BOPD. TXCO has completed 12 consecutive successful shoal wells in 2003.

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 spudded eight Georgetown deviated wells in the first nine months of 2003. At the end of September, the status of these eight wells was three producing oil, two producing gas, two awaiting completion and one shut-in pending further geological and engineering evaluation. In addition, two existing wells were recompleted in the Georgetown formation. Both are currently shut-in pending further evaluation. Gross Georgetown production rates at September 30 were 76 BOPD and 961 Mcfd from 21 producing wells.

TXCO also placed the Vivian 1-687 (50% WI), on production flowing 3.5 MMcfd and 32 BOPD in October. This well was originally drilled vertically to test the eastern extent of the Glen Rose porosity zone and found water. The well was plugged back, sidetracked and completed horizontally in the overlying Georgetown formation. The well made use of new seismic processing techniques that appear to lessen the risk associated with predicting the formation's numerous faults and fractures. During the fourth quarter TXCO spudded two deviated Georgetown wells that were located using the same techniques.

San Miguel Waterflood - TXCO continues its infill-drilling program to reach bypassed San Miguel reserves. Twenty Pena Creek wells were spudded during the first nine months of 2003. Seventeen of those are on production, while two are awaiting completion and one is shut-in pending further evaluation. Daily gross production rates from the Pena Creek field increased from 265 BOPD at year-end 2002 to approximately 465 BOPD at September 30. Subsequent to September 30, 2003, TXCO spudded three additional infill wells, one of which is drilling ahead while the other two are awaiting completion.

The Company has drilled and completed 20 of 23 wells spudded this year. The Company expanded its Pena Creek infill-drilling program for this year to 23 wells from an initial 15-well target. TXCO hopes to realize significant new San Miguel oil reserve additions by year-end. Geological, seismic and engineering reviews of the field have identified more than 80 potential infill locations to date in the original producing sand alone.

TXCO's technical staff is studying the production potential of two overlying San Miguel sands. Whole coring and additional data gathering is currently under way to further identify the potential of these newly targeted, shallower sands. Recently, two wells have been recompleted in the second San Miguel sand, which overlays the predominate third San Miguel sand. The Myers #57 well is averaging approximately 5 BOPD and 60 BWPD. The J. A. Webb #500 was fractured and is currently producing 13 BOPD and 121 barrels of load water per day.

Jurassic Formation - Blue Star Oil and Gas, Ltd. began drilling the Taylor 1-132 well at the end of March 2003. The well was originally permitted to a depth of 18,500 feet targeting the untested Jurassic formations under TXCO's Paloma lease. The well was repermitted to 20,000 feet and reached a depth of 20,171 feet with logging completed in late October. Blue Star remains committed to further exploration of the sedimentary interval and has set 7 3/4-inch casing at 20,171 feet. Blue Star now plans to re-permit the well and continue drilling to a deeper depth in an attempt to further delineate the nature of the basin. Blue Star reports that Jurassic age sedimentary beds encountered thus far have been very encouraging and multiple, potentially productive intervals have been encountered and await testing and completion attempts once final total depth has been reached. Blue Star is carrying TXCO on all costs for the well, which to date total more than $9 million. If s uccessful, TXCO and its leasehold partners will receive the net revenue attributable to an 18.75% overriding royalty interest at no cost until payout on the well. Upon payout such overriding royalty interest shall convert to a 25% working interest in the well.

Burr Lease - TXCO simultaneously acquired three leases totaling 70,700-acres on the Burr Ranch in January 2003. The acreage is contiguous to its existing acreage block and the Company believes it has excellent potential to establish oil and gas production from the Glen Rose, Georgetown and Jurassic intervals. TXCO completed a 3-D seismic shoot on a portion of these leases during October and is currently waiting on processing of the data.

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 September 30, 2003, 35 wells were producing 185 Mcfd and 1,365 BWPD, compared with 180 Mcfd and 2,150 BWPD at June 30, and 170 Mcfd and 2,325 BWPD at the end of March 2003. Three wells are temporarily shut-in for operational reasons. The Company remains cautiously optimistic the CBM project will result in significant reserve and production growth in the future.

Escondido - TXCO has drilled five Escondido wells (100%WI) in 2003. Three of the wells were placed on production at the end of October, one remains shut in pending further evaluation and one has been abandoned. Well tests indicate initial production of approximately 200 Mcfd per well from the Escondido/Olmos sands at 800 to 1,000 feet. The low cost associated with drilling at these shallow depths provides attractive opportunities for further development of these shallow sands.

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 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 September 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

Preferred Stock Financing and Issuance of Common Stock

On August 21, 2003, the Company authorized and issued 16,000 shares of Redeemable Preferred Stock, series B, and 2.13 million shares of common stock in a private placement of securities, raising a total of approximately $15.0 million after offering costs. 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 by one director and one board observer on the TXCO Board of Directors.

The net proceeds from the offering are being 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 are restricted securities taken for investment. Certificates for all shares issued in such transactions 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 common sto ck issued.


ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None


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

	None.


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 Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.

b) Exhibit 31.2 Certification of Chief Financial Officer required pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.

c) Exhibit 32.1 Certification of Chief Executive Officer required pursuant to 18 U.S.C. Section 1350 as required by the Sarbanes-Oxley Act of 2002.

d) Exhibit 32.2 Certification of Chief Financial Officer required pursuant to 18 U.S.C. Section 1350 as required by the Sarbanes-Oxley Act of 2002.

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

f) 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 the signing of a private placement agreement, and August 6, 2003 regarding the webcast of the Registrant's presentation to the 8th Oil and Gas Conference in Denver.

g) Form 8-K dated August 26, 2003, regarding the closing and funding of a private placement of preferred and common stock.

h) Form 8-K dated September 5, 2003, regarding the press release dated September 4, 2003 with respect to the Registrant's operations update.

i) Form 8-K dated October 8, 2003, regarding the press release dated October 6, 2003 regarding the webcast of the Registrant's presentation to the IPAA Oil & Gas Investment Symposium West in San Francisco.

j) Form 8-K dated October 24, 2003, regarding the press release dated October 23, 2003 with respect to the Registrant's Maverick Basin operations update.

k) Form 8-K dated November 6, 2003, regarding the press release dated November 4, 2003 with respect to the Registrant's third quarter earnings.


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: November 13, 2003





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