Txco Resources (TXCOQ) 10-Q 2004 Q3 Quarterly report

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, 2004		0-9120
THE EXPLORATION COMPANY OF DELAWARE, INC.
(Exact Name of Registrant as Specified in its Charter)
DELAWARE		84-0793089
(State or other jurisdiction of		(I.R.S. Employer I.D. No.)
incorporation or organization)
500 NORTH LOOP 1604 E.,  SUITE 250    SAN ANTONIO, TEXAS  78232
(Address of principal executive offices)
Registrant's telephone number, including area code:   (210) 496-5300
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
YES [X]		NO  [  ]
Indicate by check mark whether the Registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).
YES [X]		NO  [  ]
Indicate the number of shares outstanding of each of the issuer's classes of common stock as of October 31, 2004.
Common Stock $0.01 par value		27,974,063
(Class of Stock)		(Number of Shares)
For more information and aprint friendly version of this document go towww.txco.com.
Total number of pages is 18
1

PART I - FINANCIAL INFORMATION
ITEM 1.     FINANCIAL STATEMENTS.
THE EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
	September 30, 2004		December 31, 2003
Assets
Current Assets
Cash and equivalents	$    4,841,420		$  6,180,560
Accounts receivable, net	6,733,357		4,837,965
Prepaid expenses	1,518,055		718,853
Total Current Assets	13,092,832		11,737,378
Property and Equipment,net - successful efforts    method of accounting for oil and gas properties	86,559,878		66,155,827
Other Assets
Deferred tax asset	5,232,718		5,232,718
Other assets	1,102,242		1,080,290
Total Other Assets	6,334,960		6,313,008
Total Assets	$105,987,670		$84,206,213
See notes to consolidated financial statements
2
THE EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
	September 30, 2004		December 31, 2003
Liabilities and Stockholders' Equity
Current Liabilities
Accounts payable, trade	$  13,237,844		$  8,186,705
Other payables and accrued liabilities	4,903,512		3,709,016
Undistributed revenue	1,298,208		416,399
Current portion of long-term debt	1,604,340		1,752,286
Total Current Liabilities	21,043,904		14,064,406
Long-term Liabilities
Long-term debt, net of current portion	8,561,276		15,425,598
Redeemable preferred stock, Series B       (redemption value - $16 million)	10,766,056		10,135,335
Accrued dividends - preferred stock	177,729		57,732
Asset retirement obligation	1,648,600		1,537,600
Total Long-Term Liabilities	21,153,661		27,156,265
Minority Interest in Consolidated Subsidiaries	-		193,441
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 28,073,863 and 22,242,849 shares,       outstanding 27,974,063 and 22,143,049 shares	280,738		222,428
Additional paid-in capital	83,874,670		63,976,021
Accumulated deficit	(20,119,296	)	(21,160,341	)
Less treasury stock, at cost, 99,800 shares	(246,007	)	(246,007	)
Total Stockholders' Equity	63,790,105		42,792,101
Total Liabilities and Stockholders' Equity	$105,987,670		$84,206,213
See notes to consolidated financial statements
3

THE EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
	Three Months Ended				Three Months Ended
		September 30, 2004			September 30, 2003
Revenues
Oil and gas sales			$  7,846,365		$6,027,088
Gas gathering operations			7,464,545		3,364,162
Other operating income			6,120		2,631
Total Revenues			15,317,030		9,393,881
Costs and Expenses
Lease operations			1,242,615		1,158,760
Production taxes			446,183		348,225
Exploration expenses			696,430		292,928
Impairment and abandonments			579,968		641,725
Gas gathering operations			7,030,025		3,309,515
Depreciation, depletion and amortization			2,562,483		2,214,530
General and administrative			1,429,527		990,733
Total Costs and Expenses			13,987,231		8,956,416
Income from Operations			1,329,799		437,465
Other Income (Expense)
Interest income			8,313		10,754
Interest expense			(679,010	)	(403,296	)
Loan fee amortization			(9,486	)	(4,401	)
Total Other Income (Expense)			(680,183	)	(396,943	)
Income before income taxes and minority interest			649,616		40,522
Minority interest in income of subsidiaries			(3,094	)	17,944
Income before income taxes			646,522		58,466
Income tax expense			(46,702	)	-
Net Income			$     599,820		$     58,466
Earnings Per Share
Basic earnings per share			$0.022		$0.003
Diluted earnings per share			$0.021		$0.003
See notes to consolidated financial statements
4

THE EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
	Nine Months Ended					Nine Months   Ended
	September 30, 2004					September 30, 2003
Revenues
Oil and gas sales	$20,957,990					$18,484,022
Gas gathering operations	20,340,020					9,863,948
Other operating income	10,926					2,553
Total Revenues	41,308,936					28,350,523
Costs and Expenses
Lease operations	3,918,242					3,211,075
Production taxes	1,288,423					1,151,498
Exploration expenses	1,446,212					1,294,529
Impairment and abandonments	1,613,768					1,517,875
Gas gathering operations	18,964,695					10,324,076
Depreciation, depletion and amortization	7,334,923					6,708,998
General and administrative	3,462,188					2,621,636
Total Costs and Expenses	38,028,451					26,829,687
Income from Operations	3,280,485					1,520,836
Other Income (Expense)
Interest income	27,724					21,314
Interest expense	(2,136,913			)		(666,576		)
Loan fee amortization	(68,437			)		(13,203		)
Total Other Income (Expense)	(2,177,626			)		(658,465		)
Income before income taxes, minority interest and    cumulative effect of change in accounting principle	1,102,859					862,371
Minority interest in income of subsidiaries	34,889					54,218
Income before income taxes and cumulative effect of change    in accounting principle	1,137,748					916,589
Income tax expense	(96,702			)		(50,000		)
Cumulative effect of change in accounting principle, net of tax	-					(74,000		)
Net Income	$  1,041,046					$    792,589
Earnings Per Share
Basic earnings before cumulative effect of change          in accounting principle	$0.041					$0.043
Cumulative effect of change in accounting principle	-					(0.004		)
Basic earnings per share	$0.041					$0.039
Diluted earnings before cumulative effect of change          in accounting principle	$0.040					$0.041
Cumulative effect of change in accounting principle	-					(0.003		)
Diluted earnings per share	$0.040					$0.038
See notes to consolidated financial statements
5
THE EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
		Nine Months Ended					Nine Months Ended
		September 30, 2004					September 30, 2003
Operating Activities
Net income			$1,041,046				$    792,589
Adjustments to reconcile net income to    net cash provided by operating activities:
Depreciation, depletion and amortization			7,334,923				6,708,998
Impairment and abandonments			1,613,768				1,517,875
Minority interest in income of subsidiaries			(34,889		)		(54,218	)
Cumulative effect of change in accounting principle			-				74,000
Non-cash compensation expense on stock options and warrants			237,333				-
Non-cash interest expense and accretion of liability        - redeemable preferred stock			750,722				255,594
Net cash provided by operating activities,                before changes in operating assets and liabilities			10,942,903				9,294,838
Changes in operating assets and liabilities:
Receivables			(1,895,392		)		(1,498,444	)
Prepaid expenses and other			(799,202		)		(507,187	)
Accounts payable and accrued expenses			7,127,440				3,966,382
Net cash provided by operating activities			15,375,749				11,255,589
Investing Activities
Development and purchases of oil and gas properties			(27,807,179		)		(27,781,230	)
Purchase of other equipment			(220,890		)		(354,122	)
Net changes in minority interests			(158,552		)		77,865
Net cash used by investing activities			(28,186,621		)		(28,057,487	)
Financing Activities
Issuance of redeemable preferred stock, net of offering costs			-				9,170,632
Proceeds from issuance of common stock, net of expenses			18,484,000				5,819,679
Proceeds from long-term debt obligations			116,739				5,997,078
Payments on long-term debt obligations			(7,129,007		)		(1,063,280	)
Net cash provided by financing activities			11,471,732				19,924,109
Change in Cash and Equivalents			(1,339,140		)		3,122,211
Cash and equivalents at beginning of period			6,180,560				2,333,688
Cash and Equivalents at End of Period			$4,841,420				$ 5,455,899
See notes to consolidated financial statements
6

THE EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PERIODS ENDED SEPTEMBER 30, 2004 AND SEPTEMBER 30, 2003 (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 audited consolidated financial statements contained in the Company'sannual report on Form 10-Kfor the year ended December 31, 2003.
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 prior periods to conform to the current presentation. For further information, refer to the consolidated financial statements and footnotes thereto included in the Registrant Company'sannual report on Form 10-K for the year ended December 31, 2003, which is incorporated herein by reference.
2.     Fair Value of Stock Options
At September 30, 2004, the Company had a stock-based employee compensation plan which is described more fully in Note F, "Stockholders' Equity," to the audited consolidated financial statements contained in theCompany'sannual report on Form 10-K for the year ended December 31, 2003. 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 compensation cost related to grants of 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. Non-cash compensation expense of $237,333 was recognized in the third quarter of 2004 on one-year extensions of the expiration date for a non-qualifi ed option and for a warrant. The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS No. 123, "Accounting for Stock-Based Compensation," to stock-based employee compensation for the periods ended September 30:
Three Months Ended September 30:	2004	2003
Net income as reported	$599,820	$  58,466
Deduct: Total stock-based compensation expense determined under the fair value    based method for all awards, net of related tax effects	57,087	124,361
Pro forma earnings (loss)	$542,733	$ (65,895	)
Earnings per common share:
Basic, as reported	$0.022	$ 0.003
Basic, pro forma	$0.019	$(0.003	)
Diluted, as reported	$0.021	$0.003
Diluted, pro forma	$0.019	n/a
7

Nine Months Ended September 30:		2004		2003
Net income as reported		$1,041,046		$792,589
Deduct: Total stock-based compensation expense determined under the fair value    based method for all awards, net of related tax effects		163,094		124,361
Pro forma earnings		$  877,952		$668,228
Earnings per common share:
Basic, as reported		$0.041		$0.039
Basic, pro forma		$0.035		$0.033
Diluted, as reported		$0.040		$0.038
Diluted, pro forma		$0.034		$0.032
3.     Common Stock and Basic Income Per Share
As of September 30, 2004, the Company had outstanding warrants and options to purchase 3,458,833 shares of common stock at prices ranging from $0.98 to $6.00 per share. Of these, warrants and options to purchase 1,566,333 shares were exercisable at quarter end. The warrants and options expire at various dates through August 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
Three Months Ended September 30, 2004
Basic EPS:
Net income	27,962,487	$599,820			$0.022
Effect of dilutive options	634,740	-			(0.001	)
Dilutive EPS	28,597,227	$599,820			$0.021
Nine Months Ended September 30, 2004
Basic EPS:
Net income	25,421,169	$1,041,046			$0.041
Effect of dilutive options	770,993	-			(0.001	)
Dilutive EPS	26,192,162	$1,041,046			$0.040
Three Months Ended September 30, 2003
Basic EPS:
Net income	20,937,252	$58,466			$0.003
Effect of dilutive options	1,211,676	-			-
Dilutive EPS	22,148,928	$58,466			$0.003
Nine Months Ended September 30, 2003
Basic EPS:
Net income before cumulative effect of        change in accounting principle	20,322,292	$866,589			$0.043
Cumulative effect of change in accounting principle	-	(74,000	)		(0.004	)
Net income	20,322,292	792,589			$0.039
Effect of dilutive options	687,262	-			(0.001	)
Dilutive EPS	21,009,554	$792,589			$0.038
8

4.     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. TXCO computes total income tax expense 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 expects its current income tax to be minimized through utilization of net operating loss carryforwards. A current charge of $96,702 has been recorded for its corporate alternative minimum tax for the nine months ended September 30, 2004.

5.     Long-Term Debt

Bank Credit Facility: The Company has a $50 million senior secured revolving credit facility with Guaranty Bank (Facility), which has a three-year term expiring in 2007.

The credit facility is collateralized by all of the Company's proven oil and gas properties, with the borrowing base established on current levels of TXCO's oil and gas reserves, and features bi-annual redeterminations. Interest under the Facility is based on, at TXCO's option, (a) the London Interbank Offered Rate (LIBOR) plus an applicable margin ranging from 2.00% to 2.50% or (b) prime plus an applicable margin ranging from 0.00% to 0.25% (floating rate). The borrowing base was $12,300,000 at September 30, 2004, and was increased to $20,750,000 in October. At September 30, 2004, the Company had outstanding $8.6 million with a weighted average interest rate of 4.22%.

When borrowing under the agreement exceeds 50% of the borrowing base, the Company is required to hedge a portion of its production. The Company entered into financial price hedges on October 1, 2004. The Facility contains additional terms and conditions consistent with similarly positioned companies. These conditions include various restrictive covenants such as minimum levels of interest coverage, tangible net worth and current ratio, a maximum debt to EBITDAX ratio, restricting the payment of dividends other than the dividends payable under the redeemable preferred stock, and prohibiting a change of control or incurring additional debt. EBITDAX is earnings before income taxes, interest, depreciation, depletion, amortization, impairment, abandonment and exploration expense. The ratios used for determining compliance with the Facility are defined within that Facility and may not be equivalent to other uses of those terms. At September 30, 2004, the Company was not in techni cal compliance with the Current Ratio covenant, as the borrowing base redetermination was expected during the month of September. This timing issue was resolved by the increased borrowing base in October and a one-time waiver that was received from Guaranty Bank.

6.     New Accounting Pronouncements

On January 1, 2004, the Company adopted Financial Accounting Standards Board (FASB) Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46). This interpretation addresses consolidation of business enterprises of variable interest. The adoption of FIN 46 did not have a material impact on the Company's financial position or results of operations.

On October 13, 2004, the FASB concluded that proposed Statement 123R, "Share-Based Payment," which would require all companies to measure compensation cost for all share-based payments (including employee stock options) at fair value, would be effective for public companies for interim or annual periods beginning after June 15, 2005. The expected impact to the Company for options and warrants currently granted is not significant.

9

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 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 inits Form 10-K for the year ended December 31, 2003. See"Disclosure Regarding Forward Looking Statements."

Overview

The Exploration Company is an independent oil and gas enterprise with interests primarily in the Maverick Basin in Southwest Texas. The Company has a consistent record of long-term growth in its proved oil and gas reserves, leasehold acreage position, production and cash flow through its established exploration and development programs. Its business strategy is to build shareholder value by acquiring undeveloped mineral interests and internally developing a multi-year drilling inventory through the use of advanced technologies, such as 3-D seismic and horizontal drilling. The Company accounts for its oil and gas operations under the successful efforts method of accounting and trades its common stock on the Nasdaq Stock MarketSM under the symbol "TXCO."

At October 31, 2004, the Company had four rigs in operation on its extensive 554,000-acre position in the Maverick Basin, targeting at least seven separate formations for the production of oil and natural gas. Through the first nine months of 2004, drilling operations emphasized the Georgetown and Glen Rose formations. The 2004 CAPEX budget, revised in May 2004, totals just over $33 million and targets 66 new wells, including 27 Glen Rose wells and 28 Georgetown wells, as well as funding completion of a number of wells in progress at year-end 2003 and infrastructure improvements. The 2004 CAPEX is the second-largest drilling program in the Company's history.

TXCO reported net income of $600,000 and $1.0 million for the quarter and nine-month periods ended September 30, 2004, compared to $58,000 and $793,000 for the prior-year periods, respectively. While production remained relatively constant on a thousand cubic feet of gas equivalent (Mcfe) basis, oil and gas revenues were up 30.2% and 13.4% as compared to the third-quarter and nine-month periods of 2003, respectively, due to higher commodity price realizations. The increase in net income for the first nine months of 2004 compared to the 2003 period reflects a $2.5 million increase in oil and gas revenues and $1.8 million in higher margins on gas gathering operations. These revenue increases were offset by an increase of $1.5 million in interest expense from redeemable preferred stock debt and $707,000 higher lease operation expenses due to its growing number of producing wells. These factors are discussed in theResults of Operationssection.

The following table highlights certain operational data for the periods presented:

Third Quarter

Nine Month Period

Operational Data

2004

2003

Change

2004

2003

Change

Gas production (Mcf)

806,895

475,331

+69.8

%

2,228,471

1,522,452

+46.4

%

Oil  production (Bbls)

81,602

125,778

-35.1

%

228,751

347,951

-34.3

%

Combined production (Mcfe)

1,296,507

1,229,999

+5.4

%

3,600,977

3,610,158

-0.3

%

Net residue and NGL sales (MMbtu)

752,117

639,246

+17.7

%

2,737,265

1,835,626

+49.1

%

Gas sales price per Mcf

$5.62

$5.32

+5.7

%

$5.73

$5.70

+0.5

%

Oil sales price per Bbl

$40.61

$27.83

+45.9

%

$35.84

$28.18

+27.2

%

Residue & NGL sales price per MMbtu

$6.93

$5.11

+35.7

%

$6.59

$5.22

+26.2

%

Gas - daily exit rate (MMcf)

9.6

6.1

+57.4

%

9.6

6.1

+57.4

%

Oil  - daily exit rate (Bbls)

1,296

1,299

-0.2

%

1,296

1,299

-0.2

%

Combined daily exit rate (MMcfe)

17.4

13.9

+25.2

%

17.4

13.9

+25.2

%

10

On October 1, 2004, the Company entered into financial price hedges with Macquarie Bank Ltd. for 15,000 barrels of oil (BO) and 140,000 million British thermal units (MMBtu) of gas, each on a monthly basis for the next 12 months. These hedges are in the form of ratio swaps (the Swaps) and provide floor prices of $39.10 per BO and $5.37 per MMBtu on a basis adjusted to Houston Ship Channel prices for approximately 40% of its then current production levels. The Swaps also allow the Company to participate in 75% of potential upside price movement above the floor levels. For more information see theForm 8-K filed with the Securities and Exchange Commission on October 6, 2004.

Liquidity and Capital Resources

Liquidity is a measure of ability to access cash. The Company's primary needs for cash are for acquisitions, exploration and development of oil and gas properties, repayment of contractual obligations and working capital requirements. TXCO has historically addressed its long-term liquidity requirements through cash provided by operating activities, issuance of equity securities when market conditions permit, and sale of non-strategic assets. More recently, TXCO has used borrowings under its Credit Facility and cash proceeds from the issuance of its stock to supplement its historical sources of liquidity. The prices for future oil and natural gas production and the level of production have significant impacts on operating cash flows and are difficult to predict with a high degree of certainty. Management continues to examine alternative sources of long-term capital, including bank borrowings, issuance of debt instruments, issuance of stock, sales of non-strategic assets, and j oint-venture financing. Availability of these sources of capital and, therefore, TXCO's ability  to  execute  its  operating strategy  will  depend  upon a  number of  factors, some of  which are beyond its control. Management believes projected operating cash flows, cash on hand, and borrowings under the Credit Facility, will be sufficient to meet the requirements of TXCO's business. However, because future cash flows are subject to a number of variables, no assurances can be made that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures. Conversely, with increased levels of production and prices, capital expenditures could be raised over levels currently budgeted.

Private Placement: In May 2004, TXCO closed on a private placement of 4,266,668 shares of its common stock at a purchase price of $3.75 per share for net proceeds of $15.0 million. Included are warrants for an additional 1,280,000 common shares exercisable at $4.25 per share. The warrants become exercisable in November 2004 and expire in May 2008. Purchasers were primarily private, U.S.-based investment funds. Proceeds from the private placement were used to expand the Company's capital expenditure program, restore balance sheet liquidity, complement on-going operations and provide for general corporate purposes.

Bank Credit Facility: The Company has a $50 million senior secured revolving credit facility with Guaranty Bank (Facility), which has a three-year term expiring in 2007.

The credit facility is collateralized by all of the Company's proven oil and gas properties, with the borrowing base established on current levels of TXCO's oil and gas reserves, and features biannual redeterminations. Interest under the Facility is based on, at TXCO's option, (a) the London Interbank Offered Rate (LIBOR) plus an applicable margin ranging from 2.00% to 2.50% or (b) prime plus an applicable margin ranging from 0.00% to 0.25% (floating rate). The borrowing base was $12,300,000 at September 30, 2004, and was increased to $20,750,000 in October. At September 30, 2004, the Company had outstanding $8.6 million with a weighted average interest rate of 4.22%.

On October 1, 2004, TXCO entered intofinancial price hedges for a portion of its production in compliance with provisions of the Facility requiring hedging when borrowings exceed 50% of the borrowing base. The next semi-annual borrowing base review is currently scheduled for February 2005. At October 31, 2004, total borrowings under this agreement were $10.6 million, up $2.0 million from the quarter end balance of $8.6 million, with an unused borrowing base of $10.2 million available for future capital needs.

11

The Facility contains additional terms and conditions consistent with similarly positioned companies. These conditions include various restrictive covenants such as minimum levels of interest coverage, tangible net worth and current ratio, a maximum debt to EBITDAX ratio, restricting the payment of dividends other than the dividends payable under the redeemable preferred stock, and prohibiting a change of control or incurring additional debt. EBITDAX is defined as earnings before income taxes, interest, depreciation, depletion, amortization, impairment, abandonment and exploration expense. The ratios used for determining compliance with the Facility are defined within that Facility and may not be equivalent to other uses of those terms. At September 30, 2004, the Company was not in technical compliance with the Current Ratio covenant, as the borrowing base redetermination was expected during the month of September. This timing issue was resolved by the increased borrowing b ase in October and a one-time waiver that was received from Guaranty Bank.

Management believes the Facility, along with the Company's positive cash flow from existing production and anticipated production increases from new drilling, will provide adequate capital to fund operating cash requirements and complete its scheduled exploration and development goals for 2004. TXCO expects to further increase its borrowing base commensurate with the expected growth of its proved oil and gas reserves throughout the base term of the Facility.

Subsequent Events: In connection with theSwaps discussed in the Overview section, the Company entered into a one-year Letter of Credit Agreement (L/C) with Guaranty Bank. This agreement provided for the issuance of a Standby Letter of Credit representing a Hedge Commodity Agreement or Rate Management Transaction issued outside of the original borrowing base as stated in the Facility dated June 30, 2004. The agreement requires the payment of an administrative fee ranging from 2.0% to 2.5% per annum of the face amount of the L/C. The initial L/C amount was set at $1 million and subsequently increased to $2 million. No drafts or advances have been made against these L/C's through October 31, 2004.

In late October, TXCO entered into an agreement effective on September 1, 2004, to purchase a 6.1-mile portion of an existing, privately owned pipeline to serve the northwest portion of TXCO's lease block at a net price of $207,000. This purchase, and an associated five-year lease on an additional 1.7-mile segment of existing pipeline effective on November 1, 2004, expands our pipeline infrastructure to bring new Burr lease gas production to the market.

Sources and Uses of Cash: During the first nine months of 2004, TXCO increased cash reserves from $6.2 million at December 31, 2003, through cash provided by operating activities of $15.4 million. In addition, proceeds from a private placement of common stock, approximately $15.0 million net of expenses, along with net proceeds totaling $3.5 million from the exercise of warrants (purchasing 1,238,096 shares of common stock), resulted in total cash available of $40.1 million for use in meeting the Company's ongoing operational and development needs.

During the first quarter of 2004, TXCO used portions of the available cash to fund payments on debt totaling $2.5 million and related interest of $784,000. The Company applied $6.1 million to fund the ongoing development of its oil and gas producing properties.

During the second quarter, payments on debt totaled $7.0 million with $956,000 of related interest. This reflects a $6.8 million payment on bank debt made out of the proceeds from the private placement of common stock and warrants in May. In addition, approximately $6.9 million was invested in drilling activities during this period.

During the third quarter, net borrowings on debt totaled $2.4 million and payments for related interest were $609,000. Additionally, during this period, approximately $14.9 million was invested in drilling activities.

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As a result of theincreased drilling in the third quarter, the Company ended the period with negative working capital of $8.0 million, compared to negative $2.3 million at December 31, 2003, while its current ratio declined to 0.63 to 1 compared to 0.83 to 1 at year end. The Company exited the third quarter with an unused borrowing base of $3.7 million available under its new credit facility. After the October increase in borrowing base, and a $2.0 million draw in mid-October, the unused portion is now $10.2 million. Ending working capital was impacted by increases in current liabilities, partially offset by higher accounts receivable and prepaid account balances. Cash flow from operating activities for the first nine months of 2004 increased to $15.4 million from $11.3 million in the comparative prior-year period, reflecting the impact of the working capital changes, higher non-cash expenses and increased net income. Adjusting for changes in operating assets and liabilities, cash flow from operating activities for the first nine months of 2004 was $10.9 million in 2004 compared to $9.3 million for the first nine months of 2003, a 17.7% increase over the same period a year ago. Changes in operating assets include increases or decreases in accounts receivable, accounts payable and prepaid expenses from the prior year-ends.

Results of Operations

The following table highlights the change from comparable periods in 2003:

Third Quarter

Nine Month Period

Change in Selected Income Statement Items

$thousands

%

$thousands

%

Oil and gas revenues

+1,819

+30.2

+2,474

+13.4

Lease operations

+84

+7.2

+707

+22.0

Impairment & abandonments

-62

-9.6

+96

+6.3

Depreciation, depletion & amortization (DD&A)

+348

+15.7

+626

+9.3

Income from operations

+892

+204.0

+1,760

+115.7

Net income

+541

+925.9

+248

+31.3

The increases in oil and gas revenues for both 2004 periods presented as compared to the same periods of 2003 are attributable to higher gas production along with higher oil and natural gas prices, partially offset by a decline in oil production. Gas sales volumes increased 69.8% and 46.4% for the third quarter and first nine months of 2004, respectively, primarily due to Georgetown and Glen Rose shoal wells put on production since September 30, 2003. This increase was offset by lower oil production, primarily related to fewer wells drilled with our operating partner on the Comanche lease, compared to  the same 2003 periods. Production gains of 5.4% on a Mcfe basis in the 2004 third quarter, over the same 2003 period, offset lower operating levels in the first half of 2004 resulting in essentially flat overall production levels for the nine month periods. While average gas sales prices are up 5.7% for the third quarter of 2004 over 2003, year-to-date averages are flat with those for the first nine months of 2003 due to lower prices in the first quarter of 2004.

The increase in lease operating expenses for the first nine months of 2004 over the prior period primarily reflects costs related to 48 additional Maverick Basin oil and gas wells placed on production since September 30, 2003. Lease operation expenses were impacted by approximately $94,000 in non-recurring charges for repairs related to severe weather and flooding on the southern portion of our lease block in the first half of 2004.

The Company's gas gathering system transports its production to various markets. It also transports production for other owners at a set rate per MMbtu. It sells gas at several points along the system with a significant portion being delivered to purchasers through the Enterprise/Gulf Terra Pipeline System (Enterprise). Enterprise processes gas delivered through it to remove natural gas liquids, which it markets separately. The Company receives a share of the revenues for these liquids. Natural gas pricing fluctuations are reflected at the wellhead for the Company's operated gas properties.

During the third quarter and first nine months of 2004, gas gathering operations revenues increased 121.9% and 106.2%, respectively, due to higher sales volumes and prices for both residue gas and natural gas liquids, when compared to the same periods of 2003. The increase is consistent with the increased number of gas wells connected to the gathering system compared to the prior period.

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The following table summarizes the change from comparable periods in 2003:

Third Quarter

Nine Month Period

Change in Gas Gathering Results:

$thousands

%

$thousands

%

Revenues:

Third-party natural gas sales

+2,779

+106.2

+7,786

+99.8

Natural gas liquids sales

+1,322

+204.0

+2,705

+151.6

Transportation and other revenue

-1

-0.6

-15

-5.4

Total gas gathering revenues

+4,100

+121.9

+10,476

+106.2

Expense:

Third-party gas purchases

+3,598

+118.3

+8,333

+87.1

Transportation and marketing expenses

+61

+63.3

+146

+55.1

Direct operating costs

+62

+35.9

+162

+33.2

Total gas gathering operations expense

+3,721

+112.4

+8,641

+83.7

Gross margin

+379

+689.1

+1,835

+398.9

Operational data

Total sales volumes (MMbtu)

+112,871

+17.7

+901,639

+2.1

Average sales price (per MMbtu)

+$1.82

+35.7

+$1.37

+26.2

The increases in DD&A for the three and nine month periods of 2004 over the comparable prior-year periods resulted primarily from higher depletion, up $318,000 and $525,000, respectively, consistent with the growing number of producing wells subject to depletion and with increased depletion rates due to the maturing profile of existing producing wells.

In the third quarter of 2004, the Company recorded $237,000 in non-cash compensation charges relating to the one-year extensions on the expiration date for a non-qualified option and warrant. Excluding this compensation charge, General and administrative expense (G&A) would have been $3.2 million representing 7.8% of revenues for the nine months ended September 20, 2004, and up 23% from $2.6 million for the same period in 2003. Including the charge, G&A increased 32.1% over the prior year period and represented 8.4% of total revenues. G&A for the same period in 2003 was 9.2% of revenues. Other increases in G&A included higher compensation related expense for two additional employees hired since September 30, 2003, with their associated salaries, wages, benefits and office-related expenses, and a full-year of expense related to staff additions during 2003. Staffing at September 30, 2004, was 47, as compared with 44 at September 30, 2003, and 35 at December 31, 2002. In addition, increased activity levels resulted in higher costs for independent engineer's services, franchise taxes and investor communications. Higher costs for information systems reflect a full nine months of the new systems implemented during 2003. Partially offsetting these higher costs were lower consulting costs, down $59,000, primarily due to bringing in-house certain functions previously performed by consultants. The majority of the increases in general and administrative costs are consistent with the expanded compliance burden mandated by the Sarbanes-Oxley Act (SOA). For the first nine months of 2004, management estimates its total costs associated with SOA compliance to be approximately $131,000 including consulting, software and internal payroll-related costs. Management also anticipates these costs to increase in the final quarter of 2004 in conjunction with continuing costs for SOA section 404 compliance.

Interest expense for the first nine months of 2004 increased by $1,470,000 over the same period of 2003 primarily due to the issuance of $16 million in redeemable preferred stock debt in August 2003. Of this, $592,000 reflects non-cash charges for accretion of the debt to its full redemption value by August of 2009 and amortization of related issue costs. For the third quarter of 2004, interest on the preferred was $597,000, of which $136,000 represented non-cash charges. The income tax expense recorded in the first nine months of 2004 reflects corporate alternative minimum taxes expected to be incurred for 2004.

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Drilling Activities

Activity increased in the third quarter of 2004 with 23 wells spudded, up from 17 and 11 in the second and first quarters, respectively. The Company drilled or participated in drilling 51 new wells on its lease block in the Maverick Basin in the first nine months of 2004. At September 30, 2004, 32 of these wells were producing, 13 wells were in completion, two wells were awaiting pipeline connection, two wells remained drilling and two wells were shut in pending further evaluation. By comparison, the Company drilled 60 wells during the first nine months of 2003. TXCO also participated in one new well and two re-entries on its Williston Basin acreage, all of which are producing oil.

The Company had as many as seven rigs drilling on our Maverick Basin leases during the third quarter of 2004. There were as few as two rigs running during portions of the first half of 2004. A combination of poor weather and corporate restructuring by one of our operating partners reduced drilling activity during the first six months of this year. TXCO also saw an increase in wells put on production in the third quarter, with 20 wells coming on production compared with 14 during the first half of 2004 including one reentry in each period. During October 2004, TXCO drilled or participated in six new wells.

The Company exited the third quarter of 2004 with total net daily production of 1,296 barrels of oil per day (BOPD) and 9.6 million cubic feet per day (MMcfd) of natural gas, a combined 17.4 million cubic feet equivalent per day (MMcfed). Six completed wells were curtailed or waiting on pipeline connections at September 30, 2004, that could have added additional production. At October 31, 2004, total net daily production increased to 19.9 MMcfed as wells completed in the third quarter were placed on production. The comparable daily production rates at year-end 2003 were 1,200 BOPD and 8.9 MMcfd, equal to 2,674 BOE or 16.0 MMcfed.

Glen Rose- Through September 30, TXCO has spudded 17 Glen Rose wells, with 10 producing, one awaiting a pipeline connection, and three awaiting completion. The wells spudded include nine targeting shoals, seven targeting reefs and one targeting the porosity zone. All of the shoal wells, and the porosity well, were producing at October 31, 2004. For the reef wells at October 31, 2004, two were producing, two await completion, and three had been recompleted to and were producing from the Georgetown formation. Net Glen Rose production at September 30, 2004, was 427 BOPD and 5.4 MMcfd. At October 31, net Glen Rose production had risen to 629 BOPD and 6.0 MMcfd.

In the Glen Rose porosity play, a second well, the Comanche 2-14H (50% WI), was drilled and went on production in late October, flowing approximately 500 BOPD and no water. Meanwhile, the Comanche 2-39H (50% WI) continued to flow 370 BOPD in late October and has produced water-free oil since it began production in August. Both wells were drilled using a new technique in which the horizontal wellbore parallels fractures within the formation, minimizing water intrusion from a separate, lower zone.

In the Glen Rose reef play, TXCO placed the Burr C 1-56 (100% WI) on production in late October flowing 1.2 MMcfd. Weather and pipeline construction delays postponed the start of production since the well's completion in the third quarter. Meanwhile, three wells originally targeting Glen Rose reefs, which proved wet, have been successfully completed as horizontal Georgetown wells. In the Glen Rose shoal play, the Chittim 1-131H, (52% WI) went on production in late October at 825 Mcfd. One additional Glen Rose shoal well was spudded in late October.

Georgetown- The Company spudded six new Georgetown wells in the third quarter, bringing total wells spudded to 20 of the 28 new Georgetown wells planned for this year in addition to the three Georgetown completions originally targeting Glen Rose reefs. Three additional Georgetown wells were spudded in October 2004, with two awaiting completion and one drilling at month end. Net Georgetown production at September 30, 2004, was 3.7 MMcfd and 319 BOPD, and at October 31, 2004 was 5.1 MMcfd and 254 BOPD.

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Fifteen Georgetown wells were drilled on the southern portion of TXCO's acreage block in the first nine months of 2004, including five spudded in the third quarter. Of these, through October 31, 2004, nine have been placed on production, five are in progress or awaiting completion while one had a mechanical failure. The Comanche W 1-2H (50% WI) flow tested from the Georgetown formation at rates as high as 1.4 MMcfd and 15 BOPD. The well went on production in late October at 1.0 MMcfd. On tests in early November, the Gary 1H well flowed at 240 BOPD and 611 Mcfd.

On the northern portion of the Company's acreage block, five Georgetown wells were drilled through September 30, 2004, including one spudded in the third quarter. Three additional wells were spudded in October. Of these eight wells, one is producing, two await completion, and one is drilling while four are shut in pending further evaluation as of October 31, 2004. The Burr A 1-16H tested at a rate of 384 BOPD in early November.

As to the three former Glen Rose reef wells, the Burr C 1-231.5H (100% WI) tested at 1.5 MMcfd and was placed on production in October flowing 860 thousand cubic feet per day (Mcfd). The Burr C 1-53H, (100% WI) went on production in early October pumping 157 BOPD. The Burr C 1-60 (100% WI) was placed on production in October at 117 BOPD.

San Miguel Waterflood- TXCO spudded 13 San Miguel oil wells this year, including 10 budgeted for its Pena Creek project (100% WI). At September 30, 2004, all 10 Pena Creek wells were on production. San Miguel oil production at September 30, 2004, was 371 BOPD. In the third quarter of 2004, TXCO spudded two wells to begin testing a new San Miguel sand on the west end of the Comanche Ranch. One additional San Miguel well was spudded in mid-October and was awaiting completion at month end. San Miguel production at October 31, 2004, included 344 BOPD and 146 Mcfd. This is a temporary decline in production due to construction of a new tank battery on the northern portion of the Pena Creek lease.

To date, 11 water injection well workovers have been completed as part of a program to enhance water injection efficiency and increase oil output in the Pena Creek Unit.

Pearsall- The Taylor 132-1 (97.5% WI) is producing gas through temporary production facilities from Pearsall perforations following fracture stimulation. This lower Cretaceous interval lies below the Glen Rose formation and above 7,500 feet. The well was producing approximately 200 Mcfe at October 31. Further testing continues.

Jurassic -Blue Star Oil and Gas, Ltd., Dallas, the Company's operating partner in the Jurassic play, has reaffirmed plans to drill a second Jurassic wildcat in the Maverick Basin utilizing formation data gained from the Taylor wildcat to select a location. TXCO's 2004 drilling budget currently includes no provision for a second Jurassic well as Blue Star would pay 100 percent of drilling costs while carrying TXCO for a 25 percent working interest if a second well is drilled on TXCO's lease block.

Coalbed Methane - The Company'shorizontal re-entryattempts on two existing coalbed methane (CBM) dewatering wells (100% WI), using new multiple short-radius lateral (MSRL) technology, were delayed by mechanical difficulties. Design engineers are working to refine the MSRL tool design. If successful, the MSRL technique could significantly increase dewatering volumes and associated CBM gas production going forward.

TXCO exited 2003 with 36 wells dewatering in its CBM pilot program targeting production from the multiple seams of high-volatile bituminous coal present under its leases. At September 30, 2004, the net CBM production rate was approximately 120 Mcfd with 1,389 barrels of water per day after being shut down for some time due to flooding and related electricity interruptions. The Company believes the next phase of this project will require 25 to 50 wells initially, during which the Company expects to establish economic production quantities.  The Company may seek an industry partner or project-type financing,  which it believes is more suitable for this project due to its cash flow profile, as well as complementing the Company's existing capital structure. The Company may sell an interest in the CBM project to an industry partner with CBM expertise. To date, several potential industry partners have expressed an interest in TXCO's project. There are no new CBM wells i ncluded in the 2004 CAPEX budget. The Company continues to believe this project will add significant reserves in the coming years.

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Red River B Zone- The Company participated in the drilling of one new well (0.58% WI) and two re-entries (30.0% and 0.58% WI), all horizontal laterals, in the Williston Basin with its operating partner Luff Exploration Company. All three wells are currently producing oil. Net Williston Basin production at September 30, 2004, was 150 BOPD and 154 Mcfd.

Disclosure Regarding Forward Looking Statements

Statements in this Quarterly Report on Form 10-Q which are not historical, including statements regarding TXCO's or management's intentions, hopes, beliefs, expectations, representations, projections, estimations, plans or predictions of the future, are forward-looking statements and are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Such statements include those relating to expected drilling plans, including timing, category, number, depth, cost and/or success of wells to be drilled, expected geological formations or the availability of specific services or technologies. It is important to note that actual results may differ materially from the results predicted in any such forward-looking statements. 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 rese rves 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 TXCO's Securities and Exchange Commission filings for additional information. This and all TXCO's previously filed documents are on file at the Securities and Exchange Commission and can be viewed on TXCO's website atwww.txco.com. Copies of which are available from the Company without charge.

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, 2003. See the Company'sAnnual 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, 2004. 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

None

ITEM 3.      DEFAULTS UPON SENIOR SECURITIES

None

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

None

ITEM 5.      OTHER INFORMATION

None

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ITEM 6.      EXHIBITS

a)     Exhibit 10.1   Energy Option Transaction Confirmation dated October 5, 2004, between the registrant and Macquarie Bank Limited - OBU.

b)     Exhibit 10.2   Letter of Credit Agreement dated October 7, 2004, between the registrant and Guaranty Bank.

c)     Exhibit 31.1   Certification of Chief Executive Officer required pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended filed herewith.

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

e)     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 filed herewith.

f)     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 filed herewith.

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 9, 2004

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