Txco Resources (TXCOQ) 10-Q 2005 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, 2005		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 by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
YES [  ]		NO  [X]
Indicate the number of shares outstanding of each of the issuer's classes of common stock as of October 31, 2005.
Common Stock $0.01 par value		28,872,563
(Class of Stock)		(Number of Shares)
For more information go to www.txco.com.
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Total number of pages is 24.
1

PART I - FINANCIAL INFORMATION
ITEM 1.     FINANCIAL STATEMENTS.
THE EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
		September 30, 2005	December 31, 2004
Assets
Current Assets
Cash and equivalents	$24,729,505		$3,118,328
Accounts receivable, net	13,068,050		8,985,373
Prepaid expenses and other	1,404,047		800,045
Accrued derivative asset - current	-		133,971
Total Current Assets	39,201,602		13,037,717
Property and Equipment,net - successful efforts    method of accounting for oil and gas properties	69,186,543		94,836,476
Other Assets
Deferred tax asset	7,580,129		5,232,718
Other assets	909,233		1,130,413
Total Other Assets	8,489,362		6,363,131
Total Assets	$116,877,507		$114,237,324
See notes to consolidated financial statements
2

THE EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
	September 30, 2005			December 31, 2004
Liabilities and Stockholders' Equity
Current Liabilities
Accounts payable, trade		$12,447,059		$10,339,934
Accrued income taxes payable		3,002,930		15,000
Other payables and accrued liabilities		7,039,670		5,434,553
Derivative settlements payable		340,176		49,185
Accrued derivative obligation - current		9,584,233		-
Undistributed revenue		2,326,258		1,062,000
Current portion of long-term debt		91,933		1,666,466
Total Current Liabilities		34,832,259		18,567,138
Long-Term Liabilities
Long-term debt, net of current portion		100,000		17,099,237
Accrued derivative obligation - long-term		4,219,479		-
Redeemable preferred stock, Series B       (redemption value - $16 million)		- -		10,991,308
Accrued dividends - preferred stock		-		217,728
Asset retirement obligation		1,545,330		1,679,600
Total Long-Term Liabilities		5,864,809		29,987,873
Stockholders' Equity
Preferred stock, authorized 10,000,000 shares      Series A, -0- shares issued and outstanding     Series B, -0- and 16,000 shares issued and outstanding		- -		- -
Common stock, par value $.01 per share; authorized       50,000,000 shares; issued 28,510,363 and 28,110,363 shares,       outstanding 28,410,563 and 28,010,563 shares		285,103		281,103
Additional paid-in capital		85,493,605		84,010,730
Accumulated deficit		(7,395,705	)	(18,363,513	)
Less treasury stock, at cost, 99,800 shares		(246,007	)	(246,007	)
Accumulated other comprehensive loss, net of tax		(1,956,557	)	-
Total Stockholders' Equity		76,180,439		65,682,313
Total Liabilities and Stockholders' Equity		$116,877,507		$114,237,324
See notes to consolidated financial statements
3

THE EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
	Three Months Ended			Three Months Ended
	September 30, 2005			September 30, 2004
Revenues
Oil and gas sales		$10,950,024			$7,846,365
Gas gathering operations		6,176,109			7,464,545
Other operating income		9,797			6,120
Total Revenues		17,135,930			15,317,030
Costs and Expenses
Lease operations		1,612,796			1,242,615
Production taxes		608,320			446,183
Exploration expenses		476,281			696,430
Impairment and abandonments		780,403			579,968
Gas gathering operations		6,254,427			7,030,025
Depreciation, depletion and amortization		4,370,231			2,562,483
General and administrative		1,602,770			1,429,527
Total Costs and Expenses		15,705,228			13,987,231
Income from Operations		1,430,702			1,329,799
Other Income (Expense)
Derivative settlements loss		(546,820	)		-
Derivative mark-to-market loss		(7,099,264	)		-
Interest income		10,706			8,313
Interest expense		(1,076,355	)		(679,010	)
Loan fee amortization		(31,536	)		(9,486	)
Gain on sale of assets		24,541,042			-
Total Other Income (Expense)		15,797,773			(680,183	)
Income before income taxes and minority interest		17,228,475			649,616
Minority interest in income of subsidiaries		-			(3,094	)
Income before income taxes		17,228,475			646,522
Income tax expense		(1,939,928	)		(46,702	)
Net Income		$15,288,547			$599,820
Earnings Per Share
Basic earnings per share		$0.54			$0.02
Diluted earnings per share		$0.53			$0.02
See notes to consolidated financial statements
4

THE EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
	Nine Months Ended			Nine Months Ended
	September 30, 2005			September 30, 2004
Revenues
Oil and gas sales		$27,510,788			$20,957,990
Gas gathering operations		19,683,100			20,340,020
Other operating income		30,293			10,926
Total Revenues		47,224,181			41,308,936
Costs and Expenses
Lease operations		5,021,141			3,918,242
Production taxes		1,599,058			1,288,423
Exploration expenses		1,827,312			1,446,212
Impairment and abandonments		1,935,229			1,613,768
Gas gathering operations		19,076,333			18,964,695
Depreciation, depletion and amortization		10,479,151			7,334,923
General and administrative		4,126,240			3,462,188
Total Costs and Expenses		44,064,464			38,028,451
Income from Operations		3,159,717			3,280,485
Other Income (Expense)
Derivative settlements loss		(999,935	)		-
Derivative mark-to-market loss		(10,832,036	)		-
Interest income		34,673			27,724
Interest expense		(2,878,173	)		(2,136,913	)
Loan fee amortization		(67,594	)		(68,437	)
Gain on sale of assets		24,541,082			-
Total Other Income (Expense)		9,798,017			(2,177,626	)
Income before income taxes and minority interest		12,957,734			1,102,859
Minority interest in income of subsidiaries		-			34,889
Income before income taxes		12,957,734			1,137,748
Income tax expense		(1,989,926	)		(96,702	)
Net Income		$10,967,808			$1,041,046
Earnings Per Share
Basic earnings per share		$0.39			$0.04
Diluted earnings per share		$0.38			$0.04
See notes to consolidated financial statements
5

THE EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
	Nine Months Ended			Nine Months Ended
	September 30, 2005			September 30, 2004
Operating Activities
Net income		$10,967,808		$1,041,046
Adjustments to reconcile net income to    net cash provided by operating activities:
Depreciation, depletion and amortization		10,479,151		7,334,923
Impairment and abandonments		1,935,229		1,613,768
Minority interest in income of subsidiaries		-		(34,889	)
Gain on sale of assets		(24,541,082	)	-
Deferred income taxes		(1,198,321	)	-
Non-cash compensation expense on stock options and warrants		-		237,333
Non-cash derivative mark-to-market loss		10,832,036		-
Non-cash interest expense and/or accretion of liability        - redeemable preferred stock		684,190		750,722
Changes in operating assets and liabilities:
Receivables		(4,707,677	)	(1,895,392	)
Prepaid expenses and other		(382,823	)	(799,202	)
Accounts payable and accrued expenses		8,255,421		7,127,440
Net cash provided by operating activities		12,323,932		15,375,749
Investing Activities
Proceeds from the sale of oil and gas properties		78,000,131		-
Development and purchases of oil and gas properties		(35,605,590	)	(27,807,179	)
Purchase of other equipment		(20,401	)	(220,890	)
Changes in minority interests		-		(158,552	)
Net cash provided (used) by investing activities		42,374,140		(28,186,621	)
Financing Activities
Proceeds from issuance of common stock, net of expenses		1,486,875		18,484,000
Proceeds from long-term debt obligations		15,000,764		10,599,237
Payments on long-term debt obligations		(32,000,000	)	(16,000,000	)
Payments on installment obligations		(1,696,997	)	(1,728,244	)
Proceeds from installment obligations		122,463		116,739
Redemption of preferred stock		(16,000,000	)	-
Net cash provided (used) by financing activities		(33,086,895	)	11,471,732
Change in Cash and Equivalents		21,611,177		(1,339,140	)
Cash and equivalents at beginning of period		3,118,328		6,180,560
Cash and Equivalents at End of Period		$24,729,505		$4,841,420
See notes to consolidated financial statements
6

THE EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PERIODS ENDEDSEPTEMBER 30, 2005 ANDSEPTEMBER 30, 2004 (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, 2004.
In the opinion of management, all adjustments (consisting of normal recurring adjustments) considered necessary for a fair presentation have been included. Certain reclassifications have been made to the prior period to conform to current presentation. For further information, refer to the consolidated financial statements and footnotes thereto included in the RegistrantCompany's Annual Report on Form 10-K for the year ended December 31, 2004, which is incorporated herein by reference.
2.     Fair Value of Stock Options
The Company has a stock-based employee compensation plan which is described more fully in Note F, "Stockholders' Equity," to the December 31, 2004, audited consolidated financial statements contained in theCompany'sAnnual 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 normally reflected in net income, as all options granted under the plan had an exercise price equal to, or greater than, the market value of the underlying common stock on the date of grant. The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS No. 123, "Accounting for Stock-Based C ompensation," to stock-based employee compensation for the three and nine month periods endedSeptember 30:
Three Months Ended September 30:	2005		2004
Net income as reported	$15,288,547		$599,820
Deduct: Total stock-based compensation expense determined under the fair value    based method for all awards, net of related tax effects	(493,677	)	(57,087	)
Pro forma earnings	$14,794,870		$542,733
Earnings per common share:
Basic, as reported	$0.54		$0.02
Basic, pro forma	0.52		0.02
Diluted, as reported	0.53		0.02
Diluted, pro forma	0.51		0.02
7

2.     Fair Value of Stock Options - continued
Nine Months Ended September 30:				2005					2004
Net income as reported				$10,967,808					$1,041,046
Deduct: Total stock-based compensation expense determined under the fair value    based method for all awards, net of related tax effects				(370,035			)		(163,094		)
Pro forma earnings				$10,597,773					$877,952
Earnings per common share:
Basic, as reported				$0.39					$0.04
Basic, pro forma				0.37					0.04
Diluted, as reported				0.38					0.04
Diluted, pro forma				0.37					0.03
The Financial Accounting Standards Board ("FASB") issued Statement No. 123R in December 2004, requiring the expensing of the fair value of unvested options for periods beginning after June 15, 2005. The SEC further delayed the effective date of this FASB Statement. For the Company, FASB Statement No. 123R will be effective beginning January 1, 2006.
3.     Common Stock and Basic Income Per Share
As of September 30, 2005, the Company had outstanding warrants and options to purchase 2,959,833 shares of common stock at prices ranging from $0.98 to $5.17 per share. Of these, warrants and options to purchase 2,544,833 shares were exercisable at quarter-end. The warrants and options expire at various dates through September 2014.
The following is a reconciliation of the numerator and denominator of the basic and diluted earnings per share computation:
	2005					2004
(In thousands, except per share amounts)	Shares	Income	Per Share Amount			Shares		Income		Per Share Amount
Three Months Ended September 30:
Basic EPS:
Net income	28,367	$15,288	$0.54			27,962		$600		$0.02
Effect of dilutive options	608	-	(0.01		)	635		-		-
Dilutive EPS	28,975	$15,288	$0.53			28,597		$600		$0.02
Nine Months Ended September 30:
Basic EPS:
Net income	28,303	$10,967	$0.39			25,421		$1,041		$0.04
Effect of dilutive options	205	-	(0.01		)	771		-		-
Dilutive EPS	28,508	$10,967	$0.38			26,192		$1,041		$0.04
8

4.     Income Taxes

The Company recognizes deferred tax assets on its differences in basis for book and tax purposes. In prior periods, the Company has recorded a valuation allowance against its available tax net operating loss carryforwards. During the current period, this valuation allowance of $1,642,286 was reduced to $0 as the Company expects it will fully utilize the tax net operating loss carryforwards in the current year. The Company will also currently utilize $328,424 in available alternative minimum tax credit carryforwards from amounts paid in previous years, and has reported $1,043,498 as a charge netted against its accumulated other comprehensive loss. The realization of these carryforwards and charges has resulted in the Company's effective tax rate being 11.2% and 15.4% for the three- and nine-month periods ended September 30, 2005, respectively.

The Company's deferred tax asset at September 30, 2005, relates primarily to impairment charges and similar allowances that will be deducted for tax purposes in future periods as the amounts are realized.

5.     Derivative Instruments and Hedging Activity

Due to the volatility of oil and natural gas prices and requirements under TXCO's bank credit facility, the Company periodically enters into price-risk management transactions (e.g., swaps, collars and floors) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations.  These arrangements apply to only a portion of the Company's production, and provide only partial price protection against declines in oil and natural gas prices, and limit the Company's potential gains from future increases in prices.  None of these instruments are used for trading purposes. On a quarterly basis, the Company's management sets all of the Company's price-risk management policies, including volumes, types of instruments and counterparties.

All of these price-risk management transactions are considered derivative instruments and accounted for in accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." These derivative instruments are intended to hedge the Company's price risk and may be considered hedges for economic purposes, but certain of these transactions may or may not qualify for cash flow hedge accounting. All derivative instrument contracts are recorded on the balance sheet at fair value. The Company has elected to account for certain of its derivative contracts as investments as set out under FAS 133. Therefore, the changes in fair value in those contracts are recorded immediately as unrealized gains or losses on the Statement of Operations. For contracts designated as cash flow hedges, the change in fair value for the effective portion is reflected in Other Comprehensive Income (Loss) in the Equity section of the Consolidated Balance Sheets and will be reporte d on the Statement of Operations as the hedged transactions occur (November 2006 through April 2007). The hedges are highly effective, and therefore, no hedge ineffectiveness was recorded.

The Company entered into monthly Basis Swaps (mBS), for two months in the third quarter of 2005, to cover price exposure for certain new physical purchase contracts that used an average daily gas price rather than the first of the month index prices. The mBS agreements were established at the beginning of each month for a volume that was expected to be purchased at the daily gas price for that month. The receivable or payable for the settlement of that month's contract is reflected in Current Assets or Current Liabilities, as appropriate, on the Consolidated Balance Sheets. The gain or loss on the contract is reflected in Gas Gathering Operations expense on the Consolidated Statements of Operations. Effective October 1, 2005, TXCO amended the contract to use first of the month index prices, therefore TXCO no longer uses mBS contracts.

Subsequent to September 30, 2005, management terminated its derivative contracts for natural gas sales for the period beginning November 2005 and ending April 2007. The termination required a cash payment of approximately $9.9 million, which partially offsets the derivative obligations shown on the balance sheet. In accordance with FAS 133 guidance, the other comprehensive loss related to the derivatives will remain in the contra-equity account and be applied against revenue when the hedged transactions occur.

9

5.     Derivative Instruments and Hedging Activity - continued
					Price			Volumes		Fair Value of Outstanding     Derivative Contracts as of
Transaction		Beginning	Ending		Per			Per		September 30,			December 31,
Date	Type				Unit			Month		2005 (4)			2004(4)
Derivatives treated as investments:										(in thousands)
Natural gas (1):
10/04	Ratio Swap	11/01/2004	10/31/2005		$5.37			140,000		$(193	)		$53
03/05   (5)	Fixed Price	11/01/2005	10/31/2006		$6.83			140,000		(7,388	)		-
Crude oil (2):
10/04	Ratio Swap	11/01/2004	10/31/2005		$39.10			15,000		(101	)		81
03/05	Fixed Price	11/01/2005	10/31/2006		$49.40			15,000		(3,054	)		-
Fair value of derivatives not designated as hedges										(10,736	)		134
Derivatives treated as cash flow hedges:
Natural gas (3):
06/05   (5)	Fixed Price	11/01/2006	04/30/2007		$7.86			130,000		(2,400	)		-
Crude oil (2):
06/05	Fixed Price	11/01/2006	04/30/2007		$56.70			13,000		(668	)		-
Fair value of derivatives designated as cash flow hedges										(3,068	)		-
Total fair value of derivative contracts										$(13,804	)		$134
(1)   These natural gas hedges were entered into on a per MMBtu delivered price basis, using the Houston Ship Channel Index, with settlement for each calendar month occurring following the expiration date, as determined by the contracts.
(2)   These crude oil hedges were entered into on a per barrel delivered price basis, using the West Texas Intermediate Index, with settlement for each calendar month occurring following the expiration date, as determined by the contracts.
(3)   These natural gas hedges were entered into on a per MMBtu delivered price basis, using the Henry Hub Index, with settlement for each calendar month occurring following the expiration date, as determined by the contracts.
(4)   The fair value of the Company's outstanding transactions is presented on the balance sheet by counterparty. The balance is shown as current or long-term based on our estimate of the amounts that will be due in the relevant time periods at currently predicted price levels. Amounts in parentheses indicate liabilities.
(5)   The Company terminated these natural gas hedges in October 2005 with a total cash payment of approximately $9.9 million.
6.     Comprehensive Income
Comprehensive income includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. The components of comprehensive income are as follows for the three and nine months ended September 30, 2005, and 2004:
				Three Month Period					Nine Month Period
				2005			2004		2005					2004
Net income				$15,288,547			$599,820		$10,967,808					$1,041,046
Other comprehensive income (loss):
Change in fair value of derivatives				(2,689,224		)	-		(3,105,647			)		-
Income tax benefit of derivatives				1,134,932			-		1,149,090					-
Total comprehensive income				$13,734,255			$599,820		$9,011,251					$1,041,046
10

7.     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 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"). At September 30, 2005, the Company repaid $32.0 million of its outstanding principal balance to Guaranty Bank using a portion of the proceeds from the EnCana sale (see Item 2, Overview for a further description). This left the Company with an outstanding balance of $100,000 with a weighted average interest rate of 7.0%, and the unused borrowing ba se was $33.4 million.
When borrowing under the Facility exceeds 50% of the borrowing base, the Company is required to hedge a portion of its production. As a result, TXCO entered into financial price hedges beginning in October 2004. During first-quarter 2005, the Facility's definition of the current ratio was amended to exclude all current assets and liabilities generated by derivative transactions. The repayment of substantially all of the outstanding borrowings at quarter-end eliminated the hedging requirement. In early October, management terminated its natural gas hedges, which required a cash payment of approximately $9.9 million. As a result of the removal of these hedges, the borrowing base was reduced to $29.5 million.
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. The Company was in compliance with all such covenants at September 30, 2005, except for the hedging cap. The lender waived the hedging cap violation and the condition was cured by the termination of certain hedges during October.
Letter of Credit Agreement:In connection with the financial price hedges, the Company entered into a Letter of Credit Agreement (L/C) with Guaranty Bank in October 2004. This agreement provides for the issuance of a Standby Letter of Credit (SLC) representing a Hedge Commodity Agreement or Rate Management Transaction issued outside of the original borrowing base as stated in the Facility. The agreement requires the payment of administrative fees ranging from 2.0% to 2.5% per annum of the face amount of the outstanding SLCs. The initial SLC amount was set at $1 million. Subsequently, additional SLC's were required in conjunction with the Company's derivatives such that the total of SLC's outstanding at September 30, 2005 was $9.4 million. During October 2005, certain SLC's were cancelled leaving outstanding SLC's of $2.6 million. No drafts or advances have been made against the L/C through November 9, 2005.
11
ITEM 2.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL                    CONDITION AND RESULTS OF OPERATIONS
Certain statements in this report are not historical in nature, including statements of TXCO's and management's expectations, intentions, plans and beliefs; are inherently uncertain and are "forward-looking statements" within the meaning of Section 21E of the Securities and Exchange Act of 1934. The following discussion should be read in conjunction with the unaudited consolidated financial statements and notes thereto included in this Form 10-Q, and with the Company's latest audited consolidated financial statements and notes thereto, as reported inits Form 10-K for the year ended December 31, 2004. See"Disclosure Regarding Forward Looking Statements."
Overview
The following is a discussion of the Company's financial condition and results of operations. This discussion should be read in conjunction with the Financial Statements of the Company and Notes thereto.
The Exploration Company is an independent oil and gas enterprise operating primarily in the Maverick Basin in Southwest Texas. Its long-term 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 Capital MarketSM under the symbol "TXCO." The Company currently has two drilling rigs in operation on its extensive 664,000-gross acre block in the Maverick Basin, targeting multiple formations for the production of oil and natural gas. The emphasis in 2005 has shifted from the Georgetown formation in the first several months of the year to the Glen Rose formation more recently. The updated 2005 capital expenditures budget (CAPEX) includes funds for the d rilling or re-entry of approximately 50 wells, as well as funds for completion of a number of wells in progress at year-end 2004 and for infrastructure improvements.
In December 2004, TXCO retained Raymond James & Associates ("RJA") to assist in actively pursuing strategic alternatives designed to enhance shareholder value, including a merger or sale of the Company. As a direct result of this review, the Company entered into a purchase and sale agreement with EnCana Oil & Gas (USA) Inc. ("EnCana") to sell selected interests in TXCO's Maverick Basin interest effective September 1, 2005, for $80 million. EnCana acquired interests in approximately 300,000 gross acres across the southern portion of TXCO's Maverick Basin acreage, excluding the Glen Rose formation under the entire block and the San Miguel formation in the Pena Creek field. EnCana also received a 50% interest in approximately 220,000 gross acres across the northern portion of TXCO's Maverick Basin acreage below the Glen Rose formation, including the Pearsall and Jurassic formations. Approximately three percent of TXCO's proved reserves and 19% of its existing producti on at September 1, 2005, were transferred in this sale. At closing, TXCO increased its future working interest (WI) in the oil and gas rights attributable to the Glen Rose formation to 100% across the acreage block acquired in the asset exchange with Arrow River Energy LP and CMR Energy LP in February 2005, and to 75.5% on the Comanche Ranch leaseblock. TXCO retained its 100% WI in the San Miguel formation on its Pena Creek field, as well as its extensive gas gathering and transmission pipeline assets. A gain of $24.5 million was recognized on this transaction in the third quarter. Proceeds from the transaction were used to redeem Preferred Stock and pay down $32 million on the Credit Facility effective September 30, 2005. Additionally, funds were used in early October to terminate derivative contracts on natural gas for November 2005 through April 2007, requiring a cash payment of approximately $9.9 million that substantially offsets the accrued derivative obligations recorded in the first three quarte rs of 2005. Additionally, funds were used to acquire leasehold interests in the Marfa Basin of West Texas.
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For third-quarter 2005, TXCO reported a net income of $15.3 million ($0.53 per diluted share), up $14.7 million ($0.51 per diluted share), from $600,000 ($0.02 per diluted share) for the prior-year period. The primary factor for the improved income is the $24.5 million gain on sale of assets, reduced by a derivative mark-to-market loss of $7.1 million. Realized prices for oil and natural gas were significantly higher than during third-quarter 2004, as shown in the "Operation Data" table later in this section. Oil and gas revenues were up 39.6% over the 2004 period, while sales volumes were down 10.4% for the third quarter of 2005, on a million cubic feet equivalent (MMcfe) basis, primarily due to producing wells sold to EnCana. Partially offsetting higher revenues were non-cash expenses, such as derivative mark-to-market losses and higher depletion costs. The derivative losses were largely non-cash mark-to-market adjustments tha t did not impact cash flow from operations in the quarter. The Company was not involved in derivatives during third-quarter 2004. Additionally higher lease operating costs, impairment and depletion charges, interest expense and the loss on gas gathering operations reduced income for the quarter.
For the first nine months of 2005, TXCO reported a net income of $11.0 million, or $0.38 per diluted share, compared to $1.0 million or $0.04 per diluted share for the prior-year period. The primary factor for the improved income is the $24.5 million gain on sale of assets. Realized prices for oil and natural gas were significantly higher than during the first nine months of 2005. Sales volumes were down 2.9% for the first nine months of 2005, on a MMcfe basis, and oil and gas revenues were up 31.3% over the 2004 period. Partially offsetting these improvements were non-cash expenses, such as derivative mark-to-market losses and higher depletion costs. The derivative losses were largely non-cash mark-to-market adjustments that did not impact cash flow from operations during the nine-month period. The Company was not involved in derivatives during the first nine months of 2004. Additionally higher lease operating costs, impairment and depletion charges, interest expense and l ower gross margin on gas gathering operations were experienced in the 2005 period when compared with the same period of 2004. These factors are discussed in theResults of Operations section.
Net cash provided by operating activities for the first nine months of 2005 was $12.3 million, as compared to $15.4 million in the same period of 2004. Net cash provided by operating activities, excluding changes in operating assets and liabilities, was $9.2 million for the year-to-date period ended September 30, 2005, down from $10.9 million during the 2004 period. Cash interest expense increased due to higher average balances at higher average interest rates, as well as the payment of interest that was being accreted on the redeemable preferred stock.
	Third Quarter					First Nine Months
Operational Data	2005	2004	Change			2005	2004	Change
Gas sales volumes(Mcf)	498,842	806,895	-	38.2	%	1,902,342	2,228,471	-	14.6	%
Oil sales volumes(Bbls)	110,418	81,602	+	35.3	%	265,971	228,751	+	16.3	%
Combined sales volumes(MMcfe)	1,161,350	1,296,507	-	10.4	%	3,498,168	3,600,977	-	2.9	%
Net residue and NGL sales volumes(MMBtu)	757,759	1,062,619	-	28.7	%	2,320,318	3,047,767	-	23.9	%
Gas average realized sales price per Mcf	$8.62	$5.62	+	53.4	%	$7.05	$5.73	+	23.2	%
Oil average realized sales price per Bbl	$60.23	$40.61	+	48.3	%	$53.00	$35.84	+	47.9	%
Residue & NGL average realized sales       price per MMBtu	$7.97	$6.93	+	14.9	%	$8.29	$6.59	+	25.9	%
Gas - average daily sales(MMcfd)	5,422	8,771	-	38.2	%	6,968	8,133	-	14.6	%
Oil  - average daily sales(BOPD)	1,200	887	+	35.3	%	974	835	+	16.3	%
Combined average daily sales(MMcfed)	12,623	14,092	-	10.4	%	12,814	13,142	-	2.9	%
Due to the availability of many promising prospects on our Maverick Basin acreage, and higher oil and gas prices, drilling activity has remained brisk over the last three years. (For further discussion of this activity, see the "Principal Areas of Activity" and "Drilling Activity" sections ofTXCO's Annual Report on Form 10-K). The resulting increased expenditures should continue to translate into increased reserves as an adequate sales and production history is established. Recognition of additional reserves on newly drilled wells requires a period of sustained production, causing a delay between the expenditures and the recording of reserves.
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Liquidity and Capital Resources
Liquidity is a measure of ability to access cash. The Company's primary needs for cash are for exploration, development and acquisition of oil and gas properties, repayment of contractual obligations and working capital funding. TXCO has historically addressed its long-term liquidity requirements through cash provided by operating activities, the issuance of equity securities when market conditions permit, sale of assets, and through theCredit Facility and issuance of redeemable preferred stock. Management regularly examines alternative sources of long-term capital, including bank borrowings, the issuance of debt instruments, the sale of common stock, the sales of non-strategic assets, and joint 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 that 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, future cash flows are subject to a number of variables including the level of sales volumes and oil and natural gas prices. No assurances can be made that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures or that increased capital expenditures will not be undertaken. Actual levels of capital expenditures may vary significantly due to a variety of factors, including but not limited to drilling results, product pricing and future acquisition and divestitures of properties.
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 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"). On September 30, 2005, the Company repaid $32.0 million of its outstanding principal balance to Guaranty Bank using a portion of the proceeds from the EnCana sale (see Item 2, Overview for a further description). This left the Company with an outstanding balance of $100,000 with a weighted average interest rate of 7.0%, and the unused borrowing ba se was $33.4 million.
When borrowing under the Facility exceeds 50% of the borrowing base, the Company is required to hedge a portion of its production. As a result, TXCO entered into financial price hedges beginning in October 2004. During first-quarter 2005, the Facility's definition of the current ratio was amended to exclude all current assets and liabilities generated by derivative transactions. The repayment of substantially all of the outstanding borrowings at quarter-end eliminated the hedging requirement. In early October, management terminated its natural gas hedges. As a result of the removal of these hedges, the borrowing base was reduced to $29.5 million.
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. The Company was in compliance with all such covenants at September 30, 2005, except for the hedging cap. The lender waived the hedging cap violation and the condition was cured by the termination of certain hedges during October.
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Management believes that cash on hand from the recent sale of assets, 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 the remainder of 2005 and into 2006, minimizing the need for borrowings under the Facility. TXCO expects to further increase its borrowing base as growth of its proved oil and gas reserves continues throughout the base term of the Facility. Should product prices materially weaken, or expected new oil and gas production levels not be attained, the resulting reduction in projected revenues would cause the Company to re-evaluate its working capital options and would adversely affect the Company's ability to carry out its current operating plans.
Letter of Credit Agreement:In connection with the financial price hedges, the Company entered into a Letter of Credit Agreement (L/C) with Guaranty Bank in October 2004. This agreement provides for the issuance of a Standby Letter of Credit (SLC) representing a Hedge Commodity Agreement or Rate Management Transaction issued outside of the original borrowing base as stated in the Facility. The agreement requires the payment of administrative fees ranging from 2.0% to 2.5% per annum of the face amount of the outstanding SLCs. The initial SLC amount was set at $1 million. Subsequently, changes to SLC's were required in conjunction with the Company's derivatives such that the total of SLC's currently outstanding is $2.6 million. No drafts or advances have been made against these SLC's through November 9, 2005.
Risk Management Activities -- Derivatives and Hedging:Due to the instability of oil and natural gas prices and requirements under TXCO's bank credit facility, the Company enters into, from time to time, price-risk management transactions for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from commodity price fluctuations.These arrangements apply to only a portion of the Company's production, provide only partial price protection against declines in oil and natural gas prices and limit potential gains from future increases in prices. None of these instruments are used for trading purposes. On a quarterly basis, management sets all price-risk management policies, including volumes, types of instruments and counterparties. These policies are implemented by management through the execution of trades by the Chief Financial Officer after consultation with and concurrence by the President and th e Board of Directors.  TXCO's Board of Directors monitors the Company's price-risk management policies and trades.
The Company entered into derivative transactions beginning in October 2004. The Company elected to account for its earlier contracts as investments as set out under FAS 133. Therefore, the changes in fair value in those contracts are recorded immediately as unrealized gains or losses on the Statement of Operations. Management designated the contracts established in June 2005 as cash flow hedges. As a result, the changes in fair value for the effective portion of those contracts are reflected in Other Comprehensive Income (Loss) in the Equity section of the Consolidated Balance Sheets and will be reclassified to income as the hedged transactions occur (November 2006 through April 2007). The hedges are highly effective, and therefore, no hedge ineffectiveness was recorded.
Sources and Uses of Cash: During the first nine months of 2005, beginning cash reserves of $3.1 million were increased by cash provided by operating activities of $12.3 million. In addition, net proceeds from the sale of assets totaled $78.0 million and proceeds from the exercise of warrants totaled $1.5 million, resulting in total cash available of $94.9 million for use in meeting the Company's ongoing operational and development needs.
During the first quarter of 2005, borrowings under the Facility totaled $3.3 million and proceeds from the exercise of warrants totaled $1.3 million. Payments on installment debt totaled $1.5 million in principal, with interest payments of $613,000, while the Company applied $7.1 million to fund the ongoing development of its oil and gas producing properties.
During the second quarter of 2005, borrowings under the Facility totaled $4.0 million, while payments of interest on long-term debt totaled $908,000 and TXCO invested $10.8 million in drilling activities.
TXCO repaid $24.3 million, net of new borrowings, under the Facility during the third quarter of 2005, while payments of interest on long-term debt totaled $1.5 million and TXCO invested $17.7 million in drilling activities.
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Adjusted for the impact of the derivative liabilities on current liabilities, the Company ended the first nine months of 2005 with working capital of $14.3 million compared to negative working capital of $5.5 million at December 31, 2004. At September 30, 2005, with the same adjustment, TXCO's current ratio was 1.57 to 1 compared to 0.70 to 1 at year-end. Including the estimated $9.9 million current liability for derivative losses at September 30, 2005, working capital was $4.4 million, with a current ratio of 1.13 to 1. The ending working capital was impacted by higher cash balances held, partially offset by short-term accrued derivative mark-to-market obligations related to hedges entered into in connection with the Facility, and increased payables to joint interest owners due to higher commodity prices.
The Company exited the first nine months of 2005 with an unused borrowing base of $33.4 million under its Credit Facility. Year-to-date cash flow from operating activities decreased to $12.3 million from $15.4 million in the comparative prior-year period. Before changes in operating assets and liabilities, cash flow from operating activities for the first nine months of 2005 was $9.2 million compared to $10.9 million at September 30, 2004, a 16.3% decrease over the same period a year ago. This difference primarily relates to federal income taxes incurred as a result of the sale of assets to EnCana, as well as settlement amounts paid for derivatives during the period. Changes in operating assets and liabilities include increases or decreases in receivables, accounts payable and prepaid expenses from the prior-year ending balances.
Results of Operations
The following table highlights the change from comparable periods in 2004:
	Third Quarter								First Nine Months
Selected Income Statement Items:		$ thousands				%						$ thousands				%
Oil and gas revenues	+	3,104			+	39.6			+			6,553		+		31.3
Lease operating expense	+	370			+	29.8			+			1,103		+		28.1
Depreciation, depletion & amortization	+	1,808			+	70.5			+			3,144		+		42.9
Income from operations	+	101			+	7.6			-			121		-		3.7
Derivative mark-to-market loss	+	7,099			+	100.0			+			10,832		+		100.0
Derivative settlements loss	+	547			+	100.0			+			1,000		+		100.0
Gain on sale of assets	+	24,541			+	100.0			+			24,541		+		100.0
Net income (loss)	+	15,289			+	2,448.9			+			9,927		+		953.5
The following table summarizes the change for 2005 from comparable periods in 2004:
			Third Quarter							First Nine Months
Change in Gas Gathering Results:			$ thousands					%			$ thousands						%
Revenues:
Third-party natural gas sales			-	570			-	10.6			-		243		-		1.6
Natural gas liquids sales			-	760			-	38.6			-		588		-		13.1
Transportation and other revenue			+	42			+	42.0			+		174		+		65.6
Total gas gathering revenues			-	1,288			-	17.3			-		657		-		3.2
Expense:
Third-party gas purchases			-	688			-	10.4			+		289		+		1.6
Transportation and marketing expenses			-	58			-	36.6			-		161		-		39.1
Direct operating costs			-	30			-	12.7			-		16		-		2.5
Total gas gathering operations expense			-	776			-	11.0			+		112		+		0.6
Gross margin			-	512			-	118.0			-		769		-		55.9
Operational data
Total residue gas & NGL sales volumes (MMBtu)			-	304,860			-	28.7			-		727		-		23.9
Average realized sales price (per MMBtu)			+	1.03			+	14.9			+		1.71		+		25.9
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Three Months Ended September 30, 2005, Compared with September 30, 2004

Revenues

The increase in oil and gas revenue is attributable to higher oil sales volumes along with higher oil and natural gas prices, partially offset by a decline in gas sales volumes. Sales volumes declined 10.4% on an equivalent basis. Oil sales volumes increased 35.3%, primarily due to Glen Rose Porosity oil wells put on production since September 30, 2004. This increase was offset by 38.2% lower gas sales volumes. This was due to producing wells sold to EnCana, effective September 1, 2005, as well as normal declines in maturing gas wells. These reductions were partially offset by production from new wells. The overall average realized sales price for oil and natural gas was up 55.8%.

Lease Operations

The 29.8% increase in lease operating expenses ("LOE") primarily reflects increased costs experienced due to high demand for services in field operations in 2005, as well as costs related to 43 additional Maverick Basin oil and gas wells placed on production since September 30, 2004.

Gas Gathering

The Company's gas gathering system transports its natural gas production to various markets. It also transports production for other owners at a set rate per million British thermal units (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.

Gas gathering revenues decreased 17.3% due to lower volumes for third-party natural gas sales and natural gas liquids sales. The impact was partially offset by higher realized prices. Lower third-party natural gas sales volumes are coming through the system due to declining production on area leases.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization increased 70.5%. The major component of this increase was higher depletion, up $1.8 million. The increase was consistent with the increased number of producing wells subject to depletion, and reflects the acceleration of increasing depletion rates due to the maturing profile of existing producing wells.

General and Administrative

General and administrative expense (G&A) increased 12.1%, representing 9.4% of total revenues as compared to 9.3% in the prior-year period. A number of general and administrative related expenses associated with the strategic alternatives review and ultimately the EnCana sale were incurred that are non-recurring in nature. Legal, accounting and consulting expenses, combined, were $86,000 higher for third-quarter 2005 due to expanded compliance requirements under the Sarbanes-Oxley Act of 2002 and the strategic alternatives review begun in December 2004. Salaries and related costs were up 4.7% from 2004.

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Derivative Losses

Non-cash mark-to-market losses accrued on derivatives that hedge future oil and gas sales volumes, which were treated as investments for accounting purposes, were $7.1 million. Derivative losses on the closed periods amounted to $547,000, bringing the total recognized hedging loss to $7.6 million. Additionally, in accordance with FAS 133, an additional unrecognized hedging loss of $2.7 million, related to agreements for which hedge accounting was elected, was recorded in other comprehensive income (OCI) in the equity section of the balance sheet. The balance in OCI will offset revenues during November 2006 through April 2007, the periods that the hedged transactions occur, assuming that the current price levels continue. No derivative contracts were in place during the 2004 period.

Interest Expense

Interest expense for third-quarter 2005 increased by $397,000 due to higher levels of borrowings under the Credit Facility and higher average interest rates. A non-cash accrual reflecting the accretion of the liability on the redeemable preferred stock to its full redemption value accounts for 14.3% of the interest expense in 2005. The comparable percentage for 2004 was 31.7%. These costs will be reduced significantly for the near future due to the repayment of essentially all borrowings at September 30, 2005. The non-cash interest became a cash item upon the redemption of the preferred stock.

Gain on Sale of Assets

The Company recognized a gain of $24.5 million on the sale of certain assets to EnCana. The transaction, which closed on September 30, 2005, is discussed in theOverview section of Management's Discussion and Analysis.

Nine Months Ended September 30, 2005, Compared with September 30, 2004

Revenues

The increase in oil and gas revenue is attributable to higher oil sales volumes along with higher oil and natural gas prices, partially offset by a decline in gas sales volumes. Oil sales volumes increased 16.3%, primarily due to Glen Rose Porosity oil wells put on production since September 30, 2004. This increase was offset by 14.6% lower gas sales volumes. This was due to producing wells sold to EnCana, effective September 1, 2005, as well as normal declines in maturing gas wells. These reductions were partially offset by production from new wells. Average realized sales prices for oil and natural gas were up 35.1%.

Lease Operations

The 28.1% increase in lease operating costs primarily reflects increased costs experienced due to high demand for services in field operations in 2005, as well as costs related to 43 additional Maverick Basin oil and gas wells placed on production since September 30, 2004.

Gas Gathering

Gas gathering operations revenues decreased 3.2% due to lower third-party natural gas sales and natural gas liquids sales partially offset by higher transportation income. The impact was partially offset by higher realized prices. Lower third-party natural gas sales volumes are coming through the system due to declining production on area leases.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization increased 42.9%. The major component of this increase was higher depletion, up $3.1 million. The increase was consistent with the increased number of producing wells subject to depletion, and reflects the acceleration of increasing depletion rates due to the maturing profile of existing producing wells.

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General and Administrative

General and administrative expense increased 19.2%, while representing 8.7% of total revenues as compared to 8.4% in the prior-year period. A number of general and administrative related expenses associated with the strategic alternatives review and ultimately the EnCana sale were incurred that are non-recurring in nature. A 10% increase in salaries and benefits, related to accrual of year-end bonuses in 2005, higher directors' fees, higher 401k plan matching and merit increases, contributed to the overall G&A increase. Consulting service charges related to completion of the initial internal control certifications amortized during the period were up $92,000. Higher costs for independent engineer's services and franchise taxes were related to increased activity levels. Legal and accounting expenses were also up due to the strategic alternatives review begun in December 2004 and expanded compliance requirements under the Sarbanes-Oxley Act of 2002.

Derivative Losses

Non-cash mark-to-market losses accrued on derivatives that hedge future oil and gas sales volumes, which were treated as investments for accounting purposes, were $10.8 million. Derivative losses on the closed periods amounted to $1.0 million, bringing the total recognized hedging loss to $11.8 million. Additionally, in accordance with FAS 133, an additional unrecognized hedging loss of $3.1 million, related to agreements for which hedge accounting was elected, was recorded in other comprehensive income (OCI) on the balance sheet. The balance in OCI will offset revenues during November 2006 through April 2007, the periods that the hedged transactions occur, assuming that the current price levels continue. No derivatives were in place during the 2004 period.

Interest Expense

Interest expense increased by $741,000 due to higher levels of borrowings under the Credit Facility and higher average interest rates. A non-cash accrual reflecting the accretion of the liability on the redeemable preferred stock to its full redemption value accounts for 23.8% of the interest expense in 2005. The comparable percentage for 2004 was 35.1%. These costs will be reduced significantly for the near future due to the repayment of essentially all borrowings at September 30, 2005. The non-cash interest became a cash item upon the redemption of the preferred.

Gain on Sale of Assets

The Company recognized a gain of $24.5 million on the sale of certain assets to EnCana. The transaction, which closed on September 30, 2005, is discussed in theOverview section of Management's Discussion and Analysis.

Drilling Activities

The Company drilled or participated in drilling 38 new wells and four re-entries on its lease block in the Maverick Basin in the first nine months of 2005, with 13 of the new wells drilled in the third quarter. Thirteen of the wells drilled this year were assigned to EnCana, effective September 1, 2005, following the asset salediscussed in the Overview section. Of the 25 remaining new wells, 20 wells were placed on production, and five wells were in various completion stages at October 31, 2005. Through October 31, 2005, TXCO successfully placed on production wells from the Georgetown, Glen Rose, San Miguel, Edwards, and Austin Chalk formations. By comparison, the Company participated in 51 new wells and nine re-entries during first nine months of 2004 primarily targeting the Glen Rose, Georgetown and San Miguel intervals. TXCO spud four new wells in October 2005, targeting the Glen Rose and Lower San Miguel formations, with one i n completion while three continued drilling at October 31, 2005. TXCO has also participated in one well on its Williston Basin acreage this year, which is producing oil. There are two rigs under contract for TXCO or its partner's account to facilitate drilling or re-entering over 50 wells during 2005.

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For third-quarter 2005, the Company had net daily sales of 1,200 barrels of oil per day (BOPD) and 5.4 million cubic feet per day (MMcfd) of natural gas, a combined rate of approximately 12.6 million cubic feet equivalent per day (MMcfed). The comparable figures for second-quarter 2005 were 887 BOPD and 7.8 MMcfd, or 13.1 MMcfed, while the third quarter of 2004 was 887 BOPD and 8.8 MMcfd, or 14.1 MMcfed. For the nine months ended September 30, 2005, net daily sales averaged 974 BOPD and 7.0 MMcfd, or 12.8 MMcfed, as compared with 835 BOPD, 8.1 MMcfd and 13.1 MMcfed for the same period in 2004. Normal natural gas production declines were experienced in the third quarter and first nine months of 2005, as new wells put on production did not fully replace declines on maturing wells. Sales volumes were also effected by the sale of certain producing wells to EnCana effective on September 1, 2005, representing approximately 20% of TXCO's production.

Glen Rose- The Company spud nine new Glen Rose wells during third-quarter 2005, bringing total Glen Rose wells to 14 for the nine months ended September 30, 2005. At October 31, 2005, 10 of the 14 wells were producing oil, while three wells await completion and one was recompleted to, and is producing from, the Georgetown formation. Three wells spud in October continue drilling. Glen Rose targets represent the largest portion of the Company's revised 2005 CAPEX budget.

Third-quarter 2005 Glen Rose oil and gas sales were approximately 854 BOPD and 3.6 MMcfd, compared to 360 BOPD and 4.2 MMcfd in second-quarter 2005, and 317 BOPD and 5.5 MMcfd in third-quarter 2004.

Georgetown- The Company started 15 Georgetown drilling projects during the first nine months of 2005. Ten of these wells were assigned to EnCana in the asset sale effective September 1, 2005. At October 31, 2005, four of the remaining five wells had been placed on production, while one was awaiting completion. Third-quarter 2005 Georgetown oil and gas sales were approximately 113 BOPD and 1.7 MMcfd, compared to 193 BOPD and 3.2 MMcfd in second-quarter 2005, and 133 BOPD and 2.9 MMcfd in third-quarter 2004.

Since the Georgetown is a fractured reservoir, it is difficult to predict the type and quantity of ultimate reserves for each well as such reservoirs typically have high initial production rates that rapidly fall to lower sustained rates. In better wells, first year declines typically range from 35% to 70%, while less-productive wells may experience a first year decline of approximately 90%.

Other Plays- TXCO continued its Pena Creek San Miguel oil play, in which it has a 100% working interest (WI), by spudding six infill wells this year. At October 31, 2005, five of these wells were producing and one awaited completion. TXCO's revised CAPEX budget calls for six San Miguel wells this year. Third-quarter 2005 San Miguel oil and gas sales were approximately 158 BOPD, compared to 241 BOPD in the second quarter 2005, and 288 BOPD in third-quarter 2004.

The Company spud four wells targeting the oil-prone Austin Chalk this year. Three of the four wells were assigned to EnCana as part of the asset sale. The remaining Austin Chalk well is producing oil. TXCO has drilled one well to the Edwards formation, which is producing oil. TXCO has three wells awaiting completion that target other Maverick Basin zones. Two wells are testing a separate, lower San Miguel zone with tar and heavy oil in place, while the third well, the first joint TXCO/EnCana well in the Maverick Basin, targets the James Lime gas play.

Red River B Zone- The Company participated in drilling one new well (3.1% working interest) in the Williston basin with its operating partner Luff Exploration Company during the first half of 2005. The well is producing oil.

Coalbed Methane (CBM) - All of the Company's CBM wells were transferred as part of the EnCana transaction effective September 1, 2005. Much of TXCO's remaining acreage has potential for CBM development.

Marfa Basin - The Company has acquired a 100 percent working interest in oil and gas leases covering approximately 134,000 gross acres in the Marfa Basin of Presidio and Brewster counties in West Texas. The acreage block is located approximately 250 miles northwest of TXCO's Maverick Basin lease block and is prospective for the Barnett Shale, Woodford Shale and other plays.

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Disclosure Regarding Forward Looking Statements
Statements in this Quarterly Report on Form 10-Q that 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 reser ves 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 Web site at www.txco.com. Copies are available from the Company without charge.
ITEM 3.     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Market risk represents the risk of loss that may impact the financial position, results of operations, or cash flows of the Company due to adverse changes in financial market prices, including interest rate risk, and other relevant market rate or price increases.
The Company is exposed to market risk through interest rates related to its bank credit facility borrowing. The credit facility borrowings are based on the LIBOR or prime rate plus an applicable margin and are used to assist in meeting working capital needs. As of September 30, 2005, the Company had borrowings under its bank credit facility of $100,000. Assuming an increase in either the LIBOR or prime interest rates of 100 basis points, interest expense could increase by approximately $1,000 per year. The interest rate variability on all debt would not have a material adverse effect on the Company's financial position.
The Company enters into hedging transactions in the normal course of business, including fixed price and ratio swaps to mitigate exposure to commodity price movements, but not for trading or speculative purposes.   During 2004 and 2005, due to the instability of prices and to achieve a more predictable cash flow, TXCO put in place natural gas and crude oil swaps for a portion of its production for 2005 through April 2007. Please refer to Note 5 to the consolidated financial statements. While the use of these arrangements limits the benefit of increases in the price of oil and natural gas, it also limits the downside risk of adverse price movements.  The following table lists contracts outstanding as of September 30, 2005.
Derivative Contracts at Period End:				Price	Volumes Per
Transaction Date	Transaction Type	Beginning	Ending	Per Unit	Per Month
Natural Gas  (3):
10/04   (1)	Ratio Swap	11/01/2004	10/31/2005	$5.37	140,000 MMBtu
03/05   (1) (4)	Fixed Price Swap	11/01/2005	10/31/2006	$6.83	140,000 MMBtu
06/05   (2) (4)	Fixed Price Swap	11/01/2006	04/30/2007	$7.86	130,000 MMBtu
Crude Oil   (3):
10/04	Ratio Swap	11/01/2004	10/31/2005	$39.10	15,000 Bbl
03/05	Fixed Price Swap	11/01/2005	10/31/2006	$49.40	15,000 Bbl
06/05	Fixed Price Swap	11/01/2006	04/30/2007	$56.70	13,000 Bbl
(1)   These natural gas hedges were entered into on a per MMBtu delivered price basis, using the Houston Ship Channel Index, with settlement for each calendar month occurring following the expiration date, as determined by the contracts.
(2)   These natural gas hedges were entered into on a per MMBtu delivered price basis, using the Henry Hub Index, with settlement for each calendar month occurring following the expiration date, as determined by the contracts.
(3)   The fair value of the Company's outstanding transactions is presented on the balance sheet by counterparty. The balance is shown as current or long-term based on management's estimate of the amounts that will be due in the relevant time periods at currently predicted price levels
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(4)   The Company terminated these natural gas hedges in October 2005 with a total cash payment of approximately $9.9 million.
At September 30, 2005, the fair value of the outstanding hedges was a liability of approximately $13.8 million. A 10% change in the commodity price per unit would have caused the fair value of the hedges to increase or decrease by approximately $1.4 million. However subsequent to quarter-end, the natural gas derivatives for November 2005 through April 2007 were canceled. The balance at September 30, 2005 related to the crude oil derivatives was approximately $3.7 million. A 10% change in the crude oil price per barrel would cause the fair value of the remaining derivatives to increase or decrease by approximately $370,000.
The Company entered into monthly Basis Swaps (mBS), for two months in the third quarter of 2005, to cover price exposure for certain new physical purchase contracts that used an average daily gas price rather than the first of the month index prices. The mBS agreements were established at the beginning of each month for a volume that was expected to be purchased at the daily gas price for that month. The receivable or payable for the settlement of that month's contract is reflected in Current Assets or Current Liabilities, as appropriate, on the Consolidated Balance Sheets. The gain or loss on the contract is reflected in Gas Gathering Operations expense on the Consolidated Statements of Operations. Effective October 1, 2005, TXCO amended the contract to use first of the month index prices, therefore TXCO no longer uses mBS contracts.
See also theCompany'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, 2005. 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 the Company's periodic SEC filings.
b.      There have been no changes in the Company's internal controls that have materially affected, or are reasonably likely to materially affect, the Company's internal controls over financial reporting subsequent to the date of the above evaluation. There were no material weaknesses identified in the course of such review and evaluation and, therefore, no corrective measures were required.
PART II - OTHER INFORMATION
ITEM 1.     LEGAL PROCEEDINGS
None
ITEM 2.      UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Subsequent to quarter-end, 450,000 shares of TXCO's common stock were issued in connection with the acquisition of leasehold interests in the Marfa Basin of West Texas.
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 4.1 Waiver and Second Amendment to Credit Agreement, effective August 23, 2005, filed herewith.

b)     Exhibit 10.1 Purchase and Sale Agreement by and between Registrant and EnCana Oil & Gas (USA) Inc. effective September 1, 2005, filed herewith.

c)     Exhibit 10.2 Assignment of Bill of Sale and Conveyance - Southern Lands between Registrant and EnCana Oil & Gas (USA) Inc. effective September 1, 2005, filed herewith.

d)     Exhibit 10.3 Partial Assignment of Oil, Gas and Mineral Leases - Northern Lands between Registrant and EnCana Oil & Gas (USA) Inc. effective September 1, 2005, filed herewith.

e)     Exhibit 10.4 Assignment - Comanche Ranch between Registrant and CMR Energy, L. P. effective September 1, 2005, filed herewith.

f)     Exhibit 10.5 Assignment - Glen Rose Rights between Registrant and CMR Energy, L. P. effective September 1, 2005, filed herewith.

g)     Exhibit 10.6 Affidavit of Non-Foreign Status between Registrant and EnCana Oil & Gas (USA) Inc. effective September 1, 2005, filed herewith.

h)     Exhibit 10.7 Seismic Data License Agreement between Registrant and EnCana Oil & Gas (USA) Inc. effective September 1, 2005, filed herewith.

i)     Exhibit 10.8 Transition Services Agreement between Registrant and EnCana Oil & Gas (USA) Inc. effective September 1, 2005, filed herewith.

j)     Exhibit 10.9 Partial Release of Liens and Security Interests between Registrant and EnCana Oil & Gas (USA) Inc. effective September 1, 2005, filed herewith.

k)     Exhibit 10.10 Operating Agreement between Registrant and EnCana Oil & Gas (USA) Inc. effective September 1, 2005, filed herewith.

l)     Exhibit 10.11 Release and Reassignment of Net Profits Interest between Registrant and Arrow River Energy L. P. effective September 1, 2005, filed herewith.

m)     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.

n)     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.

o)     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.

p)     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.

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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, 2005
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