Txco Resources (TXCOQ) 10-Q 2007 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.    20549

FORM 10-Q

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

For the quarterly period ended    March 31, 2007    

OR

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

For the transition period from _____________ to _________________

Commission File No.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)

777 E. SONTERRA BLVD., SUITE 350    SAN ANTONIO, TEXAS  78258

(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 þ No  p

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.

Large accelerated filer p Accelerated filer þ Non-accelerated filer p

Indicate by check mark if the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes  p No þ

Indicate the number of shares outstanding of each of the issuer's classes of common stock as of May 4, 2007.

Common Stock $0.01 par value	33,705,625
(Class of Stock)	(Number of Shares)

For more information go to www.txco.com.

The information at www.txco.com is not incorporated into this report.

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PART I - FINANCIAL INFORMATION

ITEM 1.     FINANCIAL STATEMENTS

THE EXPLORATION COMPANY

Consolidated Balance Sheets

(Unaudited)

($ in thousands)		March 31, 2007		December 31, 2006
Assets
Current Assets
Cash and equivalents	$		3,668	$	3,882
Accounts receivable, net			9,725		9,132
Federal income tax receivable			9,734		4,468
Prepaid expenses and other			3,297		887
Total Current Assets			26,424		18,369
Property and Equipment, net - successful efforts method of accounting for oil and gas properties			136,876		119,574
Other Assets
Deferred tax asset			513		5,310
Other assets			2,539		548
Total Other Assets			3,052		5,858
Total Assets	$		166,352	$	$143,801

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THE EXPLORATION COMPANY

Consolidated Balance Sheets

(Unaudited)

($ in thousands)		March 31, 2007			December 31, 2006
Liabilities and Stockholders' Equity
Current Liabilities
Accounts payable, trade	$		10,611		$	7,969
Undistributed revenue			429			1,035
Notes payable			262			267
Derivative settlements payable			52			70
Accrued derivative obligation - short-term			125			321
Other payables and accrued liabilities			6,017			6,433
Total Current Liabilities			17,496			16,095
Long-Term Liabilities
Long-term debt			22,851			2,351
Asset retirement obligation			3,111			1,703
Total Long-Term Liabilities			25,962			4,054
Stockholders' Equity
Preferred stock, Series A & Series B; authorized 10,000,000 shares; issued and outstanding -0- shares			-			-
Common stock, par value $.01 per share; authorized 50,000,000 shares; issued 33,389,031 and 33,290,698 shares, outstanding 33,270,612 and 33,190,898 shares			334			333
Additional paid-in capital			122,618			122,108
Retained earnings			726			2,619
Accumulated other comprehensive loss, net of tax			(319	)		(1,162	)
Less treasury stock, at cost, 118,419 and 99,800 shares			(465	)		(246	)
Total Stockholders' Equity			122,894			123,652
Total Liabilities and Stockholders' Equity	$		166,352		$	143,801

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THE EXPLORATION COMPANY

Consolidated Statements Of Operations

(Unaudited)

		Three Months Ended			Three Months Ended
(in thousands, except earnings per share data)		March 31, 2007			March 31, 2006
Revenues
Oil and gas sales	$		8,725		$	10,469
Gas gathering operations			2,494			5,540
Other operating income			1			14
Total Revenues			11,220			16,023
Costs and Expenses
Lease operations			2,660			1,643
Production taxes			494			512
Exploration expenses, including dry hole costs			375			444
Impairment and abandonments			686			476
Gas gathering operations			2,881			5,751
Depreciation, depletion and amortization			4,916			2,726
General and administrative			1,804			1,672
Total Costs and Expenses			13,816			13,224
(Loss) Income from Operations			(2,596	)		2,799
Other Income (Expense)
Derivative mark-to-market loss			-			(6	)
Derivative settlements loss			-			(633	)
Interest expense			(277	)		(87	)
Interest income			26			38
Loan fee amortization			(10	)		(73	)
Total Other Income (Expense)			(261	)		(761	)
(Loss) income before income taxes			(2,857	)		2,038
Income tax (benefit) expense -- current			(5,266	)		763
deferred			4,301			-
Net (Loss) Income	$		(1,892	)	$	1,275
(Loss) Earnings Per Share
Basic (loss) earnings per share	$		(0.06	)	$	0.04
Diluted (loss) earnings per share	$		(0.06	)	$	0.04

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THE EXPLORATION COMPANY

Consolidated Statements Of Cash Flows

(Unaudited)

		Three Months Ended			Three Months Ended
(in thousands, except earnings per share data)		March 31, 2007			March 31, 2006
Operating Activities
Net (loss) income	$		(1,892	)	$	1,275
Adjustments to reconcile net income to    net cash provided by operating activities:
Depreciation, depletion and amortization			4,926			2,726
Impairment, abandonments and dry hole costs			965			476
Deferred tax expense			4,301			-
Non-cash stock compensation expense			226			252
Non-cash derivative mark-to-market loss			-			6
Non-cash change in components of Other Comprehensive Income			1,143			-
Changes in operating assets and liabilities:
Receivables			(594	)		1,771
Prepaid expenses and other			(4,410	)		(320	)
Accounts payable and accrued expenses			1,615			(4,485	)
Current income taxes (receivable) payable			(5,280	)		(2,104	)
Net cash provided (used) by operating activities			1,000			(403	)
Investing Activities
Development and purchases of oil and gas properties			(20,950	)		(9,776	)
Purchase of other equipment			(825	)		(4,055	)
Proceeds from sale of assets			-			3
Net cash used by investing activities			(21,775	)		(13,828	)
Financing Activities
Proceeds from issuance of common stock, net of expenses			284			382
Purchase of treasury shares			(219	)		-
Proceeds from bank credit facility			20,500			9,300
Proceeds from installment and other obligations			119			-
Payments on installment and other obligations			(123	)		(102	)
Net cash provided by financing activities			20,561			9,580
Change in Cash and Equivalents			(214	)		(4,651	)
Cash and equivalents at beginning of period			3,882			6,083
Cash and Equivalents at End of Period	$		3,668		$	1,432

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THE EXPLORATION COMPANY

Notes To Consolidated Financial Statements

Periods Ended March 31, 2007 and March 31, 2006(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's Annual Report on Form 10-K for the year ended December 31, 2006.

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 Company's Annual Report on Form 10-K for the year ended December 31, 2006.

2.Stock-based Compensation

The Company has stock-based employee compensation plans that are described more fully in Note F, "Stockholders' Equity," to the audited consolidated financial statements contained in the Company's Annual Report on Form 10-K for the year ended December 31, 2006. Total stock-based compensation expense recognized was $226,000 and $252,000, in the first three months of 2007 and 2006, respectively.

As of March 31, 2007, the Company had outstanding options to purchase 855,750 shares of common stock at prices ranging from $2.125 to $5.00 per share. The options expire at various dates through September 2014. Of these, 755,750 were exercisable at quarter end.

Additionally, at March 31, 2007, the Company had outstanding exercisable warrants to purchase 926,500 shares of common stock at $4.25 per share. The warrants, which expire in May 2008, were issued as part of the private placement of 4.3 million shares in May 2004. 

Stock Options: In prior years, the Company issued stock options as compensation to employees and non-employee directors. Generally, these options had a ten-year life and vested over two years for employees and three years for directors. Upon exercise, newly issued shares are utilized to fulfill the obligation. No options have been granted since 2004. The Board utilized restricted stock grants in lieu of stock options in 2006.

Prior to January 1, 2006, the Company accounted for the plans 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 was normally reflected in net income, as all options granted under the plans had an exercise price equal to, or greater than, the market value of the underlying common stock on the date of grant.

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2.Stock-based Compensation - continued

Stock Option Activity:	Number   Outstanding	Weighted Average  Exercise Price	Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value
1995 Flexible Incentive Plan:*	(in thousands)		(in years)	(in thousands)
Outstanding at December 31, 2006	956	$2.90	3.3	$9,974
Granted	-	-
Exercised	100	2.85
Forfeited or Expired	-	-
Outstanding at March 31, 2007 **	856	$2.91	3.1	$6,795
Exercisable at March 31, 2007	756	$3.01	3.3	$5,923

  *  There have been no options awarded under the 2005 Stock Incentive Plan.

  **100,000 shares become exercisable upon attaining a stock price target of $15.00.  

Restricted Stock: During the first-quarter of 2006, the Company granted restricted stock as compensation to employees and non-employee directors under its 2005 Stock Incentive Plan. Shares granted to continuing directors, with an aggregate fair value of $369,000, had a vesting term of one year, while shares granted to new directors and employees, with an aggregate fair value of $2.7 million, had a vesting term of three years ($0.9 million aggregate fair value per year). The fair value is recognized as stock compensation expense (included in general and administrative expense on the Consolidated Statements of Operations) over the vesting periods.

Restricted Stock Activity:	Shares	Weighted Average Grant Date Fair Value
2005 Stock Incentive Plan:	(in thousands)
Unvested restricted stock at December 31, 2006	330	$9.01
Granted	-	-
Vested	130	8.97
Forfeited	2	8.79
Unvested restricted stock at March 31, 2007	198	$9.03

Stock Used to Acquire Goods or Services: During April 2007, the Company issued 338,983 shares of its common stock in a private placement as partial payment for its acquisition of Output Exploration LLC, a privately held, Houston-based exploration and production firm. See Note 8 "Subsequent Events" for additional information regarding this transaction.

3.     Common Stock and Basic Income Per Share

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

	2007							2006
(In thousands, except per share data)	Shares *	Income			Per Share Amount			Shares *	Income		Per Share Amount
Three Months Ended March 31
Basic EPS:
Net (loss) income	32,985	$	(1,892	)	$	(0.06	)	29,738	$	1,275	$	0.04
Effect of dilutive options	n/a**		-			-		1,122		-		-
Dilutive EPS	32,985	$	(1,892	)	$	(0.06	)	30,860	$	1,275	$	0.04

* Weighted average shares outstanding

** not applicable due to net loss for the quarter

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4.     Income Taxes

The Company recognizes deferred tax assets on differences in its basis for book and tax purposes. The Company's effective tax rate was 33.8% and 37.4% for the three-month periods ended March 31, 2007, and 2006, respectively.

TXCO adopted the provisions of Financial Accounting Standards Board ("FASB") Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109" ("FIN 48"), on January 1, 2007. FIN 48 provides guidance for recognizing and measuring uncertain tax positions, as defined in SFAS 109, Accounting for Income Taxes. FIN 48 prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. Adoption of FIN 48 did not have a significant impact on the Company's financial statements.

5.     Commodity Hedging Contracts and Activity

Due to the volatility of oil and natural gas prices, the Company, from time to time, enters into price-risk management transactions (e.g., swaps, collars and floors) for a portion of its oil and natural gas production. In certain cases, this allows it 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, provide only partial price protection against declines in oil and natural gas prices, and may partially 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 Consolidated Balance Sheets at fair value. The Company has elected to account for certain of its derivative contracts as investments as set out under SFAS No. 133. Therefore, the changes in fair value in those contracts are recorded immediately as unrealized gains or losses on the Consolidated Statement of Operations. The change in fair value for the effective portion of contracts designated as cash flow hedges is reflected in Other Comprehensive Income (Loss) in the Stockholders' Equity section of the Consolidated Balance Sheets. The gain or loss in Other Comprehensive Income is being reported on the Consolidated 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 outstanding hedges at March 31, 2007, and December 31, 2006, impacting the balance sheet were as follows:

				Price	Barrels	Fair Value of Outstanding Derivative Contracts (1) at
Transaction				Per	Per	March 31,		December 31,
Date	Type	Beginning	Ending	Unit	Month	2007		2006
Crude oil (2):						(in thousands)
06/05	Fixed Price	11/01/2006	04/30/2007	$56.70	13,000	$      (125	)	$      (321	)

(1)The fair value of the Company's outstanding transactions is presented on the balance sheet by counterparty. Amounts in parentheses indicate liabilities.

(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. They were designated as cash flow hedges.

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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-month periods ended March 31, 2007, and 2006:

		First Quarter
(in thousands)		2007			2006
Net (loss) income	$	(1,892	)	$	1,275
Other comprehensive income (loss):
Deferred hedge gain (loss)		1,339			(425	)
Income tax (expense) benefit of cash flow hedges		(496	)		168
Total comprehensive (loss) income	$	(1,049	)	$	1,018

7.Long-Term Debt

Bank Credit Facility: At March 31, 2007, the Company had a $50 million senior secured revolving credit facility with Guaranty Bank (the "Facility"). The Facility was entered into in 2004 and would have expired in June 2008. See the "Subsequent Events" note that follows for discussion of the replacement of the Facility on April 2, 2007.

The Facility was 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 featured semi-annual redeterminations. At March 31, 2007, the borrowing base, inclusive of tranche A and tranche B, was $32.0 million. At March 31, 2007, $22.9 million was outstanding at an interest rate of 8.25% and the unused borrowing base was $9.1 million. Interest under the Facility was 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 Facility provided the lender a commitment fee equal to 0.5% per annum on the unused borrowing base. The interest rate at March 31, 2007, was 8.25% computed in accordance with (b) above.

The Facility contained additional terms and conditions consistent with similarly positioned companies. These conditions included 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, and prohibiting a change of control or incurring additional debt. The ratios used for determining compliance with the Facility were 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 March 31, 2007.

8.    Subsequent Events

Output Acquisition: On April 2, 2007, TXCO's acquisition of Output Exploration, LLC, a Delaware limited liability company ("Output"), was closed and became effective. Pursuant to the terms of the Agreement and Plan of Merger, dated as of February 20, 2007, as amended (the "Merger Agreement"), by and among TXCO, Output Acquisition Corp., a Texas corporation and wholly-owned subsidiary of TXCO ("Merger Sub"), and Output, Output merged with and into Merger Sub (the "Merger"), with Merger Sub continuing as the surviving corporation and a wholly-owned subsidiary of TXCO.

In connection with the Merger, TXCO paid to the holders of Output equity interests an aggregate of approximately $95.6 million, consisting of $91.6 million in cash and approximately 339,000 shares of TXCO common stock (the "Reserve Shares"). The Reserve Shares will be held by an escrow agent and released to TXCO to the extent necessary to satisfy indemnity claims made by TXCO under the Merger Agreement during the one-year period following the Merger. Any Reserve Shares not released to TXCO will be liquidated by the escrow agent and the net proceeds paid to the holders of Output equity interests converted in the Merger.

Concurrent with the closing, TXCO elected to terminate all hedges assumed in the acquisition with a payment of $4.8 million.

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BMO Capital Markets served as financial advisor to TXCO. The Merger was funded through borrowings under a new Senior Credit Agreement and Term Loan Agreement described in Item 1.01 of the Current Report on Form 8-K, that was filed with the SEC on April 5, 2007, and summarized below.

Senior Credit Agreement: On April 2, 2007, TXCO entered into a four-year amended and restated credit agreement (the "Senior Credit Agreement") with Bank of Montreal, a Canadian chartered bank acting through certain of its United States branches and agencies.

The Senior Credit Agreement provides for revolving credit loans to be made to TXCO from time to time and letters of credit to be issued from time to time for the account of TXCO or any of its subsidiaries. The aggregate principal amount of the commitments of the lenders under the Senior Credit Agreement is $125,000,000. The initial borrowing base is $60,000,000. The borrowing base is redetermined semi-annually and upon requested special redeterminations.

The Senior Credit Agreement matures on April 2, 2011. TXCO's obligations under the Senior Credit Agreement are secured by a first-priority security interest in TXCO's and certain of its subsidiaries' proved oil and natural gas reserves and in the equity interests of such subsidiaries. In addition, TXCO’s obligations under the Senior Credit Agreement are guaranteed by such subsidiaries.

Loans under the Senior Credit Agreement are subject to floating rates of interest based on (1) the total amount outstanding under the Senior Credit Agreement in relation to the borrowing base and (2) whether the loan is a LIBOR loan or a base rate loan. LIBOR loans bear interest at the LIBOR rate plus the applicable margin, and base rate loans bear interest at the base rate plus the applicable margin. The applicable margin varies with the ratio of total outstanding to the borrowing base. For base rate loans it ranges from zero to 100 basis points and for LIBOR rate loans it ranges from 150 to 250 basis points.

Under the Senior Credit Agreement, TXCO will also be required to pay a commitment fee on the difference between amounts available under the borrowing base and amounts actually borrowed. The commitment fee shall be (1) 0.375%, so long as the ratio of amounts outstanding under the Senior Credit Agreement to the borrowing base is less than 30%, and (2) 0.50%, in the event such ratio is 30% or greater.

As of April 30, 2007, the balance outstanding under the Senior Credit Agreement was $44.0 million at an average interest rate of 7.44% per annum. Borrowings under the Senior Credit Agreement may be repaid and reborrowed from time to time without penalty.

Second Lien Term Loan Agreement: On April 2, 2007, TXCO entered into a five-year term loan agreement (the "Term Loan Agreement") with Bank of Montreal and certain other financial institutions party thereto. The Term Loan Agreement provides for term loans to be made to TXCO in a single draw in an aggregate principal amount not to exceed $80,000,000.

The Term Loan Agreement matures on April 2, 2012. TXCO's obligations under the Term Loan Agreement are secured by a second-priority security interest in TXCO’s and certain of its subsidiaries' proved oil and natural gas reserves and in the equity interests of such subsidiaries. In addition, TXCO's obligations under the Term Loan Agreement are guaranteed by such subsidiaries.

Loans under the Term Loan Agreement are subject to floating rates of interest equal to, at TXCO’s option, the LIBOR rate plus 4.50% or the base rate plus 3.50%. The "LIBOR rate" and the base rate are calculated in the same manner as under the Senior Credit Agreement.

As of April 30, 2007, the balance outstanding under the Term Loan Agreement was $80,000,000 with an interest rate of 9.875%. Borrowings under the Term Loan Agreement may be repaid (but not reborrowed) subject to a prepayment premium equal to (i) 1.0%, if prepaid prior to April 2, 2008 and (ii) 0.0%, thereafter. Additionally, no prepayments are permitted if the ratio of the total amount outstanding under the Senior Credit Agreement to the borrowing base thereunder exceeds 75% or if any default exists under the Senior Credit Agreement.

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Both the Senior Credit Agreement and the Term Loan Agreement contain certain restrictive covenants which, among other things, limit the incurrence of additional debt, investments, liens, dividends, redemptions of capital stock, prepayments of indebtedness, asset dispositions, mergers and consolidations, transactions with affiliates, derivative contracts, sale leasebacks and other matters customarily restricted in such agreements. The Agreements will require TXCO and its subsidiaries to meet a maximum consolidated leverage ratio of 3.00 to 1.00, a minimum current assets to current liabilities ratio of 1.00 to 1.00, a minimum interest coverage ratio of 2.00 to 1.00 and a minimum net present value to consolidated total debt ratio of 1.50 to 1.00. Both agreements also contain customary events of default. The ratios are calculated on a quarterly basis. If an event of default occurs and is continuing, lenders with a majority of the aggregate outstanding term loans may require Bank of Montreal to declare all amounts outstanding under the agreements to be immediately due and payable.

ITEM 2.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL

CONDITION AND RESULTS OF OPERATIONS

Certain statements in this report that 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, and Management's Discussion and Analysis, as reported in its Form 10-K for the year ended December 31, 2006. See the "Disclosure Regarding Forward Looking Statements" section at the end of this Item 2.

Overview

Unless the context requires otherwise, when we refer to "TXCO", "the Company", "we", "us" or "our", we are describing The Exploration Company of Delaware, Inc. The following discussion of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and the notes thereto included in this Form 10-Q.

We are an independent oil and gas enterprise with interests primarily in the Maverick Basin, the onshore Gulf Coast region, the Marfa Basin of Texas and the Midcontinent region of western Oklahoma. We have a consistent record of long-term growth in proved oil and gas reserves, leasehold acreage position, production and cash flow through our established exploration, exploitation and development programs. Our 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. We account for our oil and gas operations under the successful efforts method of accounting and trade our common stock on Nasdaq's Global Select Market under the symbol "TXCO."

We currently have six drilling rigs under contract and in operation on our Maverick Basin acreage, and we expect to add two additional rigs in the near future. Our emphasis thus far this year has been on the Glen Rose and San Miguel formations. We began 19 new wells and six re-entries in Texas through May 4, including 11 in the Glen Rose Porosity. We participated in one new well and two re-entries in the Williston Basin. The drilling rig we purchased in March 2006 was put into service in January 2007. Our revised 2007 capital expenditures budget ("CAPEX") includes funds for the drilling or re-entry of more than 90 wells (more than 30 in the Glen Rose Porosity), as well as funds for completion of a number of wells in progress at year-end 2006 and for infrastructure improvements. On April 2, 2007, we closed on the acquisition of Output Exploration, LLC -- see the "Subsequent Events" and "New Credit Facilities" sections later in this Item.

Due to the number of promising prospects on our Maverick Basin acreage, as well as high oil and gas prices, drilling activity has remained high during the last several years. (For further discussion of this activity, see "Principal Areas of Activity" and "Drilling Activity" in Item 1 of our Annual Report on Form 10-K for the year ended December 31, 2006). The resulting increased expenditures continue to translate into increased reserves as we establish adequate production history. Recognition of additional reserves on newly drilled wells requires a period of sustained production, causing a delay between the expenditures and the recognition of reserves.

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Oil and gas sales revenues declined by $1.7 million when compared to the prior year quarter. Sales volumes were up 1% on a billion cubic feet equivalent ("bcfe") basis in spite of our seasonal slowdown in the Glen Rose Porosity. Average realized prices were down $3.96 per barrel of oil ("BO") and $0.80 per thousand cubic feet of natural gas ("mcf") compared to this quarter a year ago. Gas gathering revenues declined by $3.0 million due to lower gas volumes for third party gas and lower commodity prices compared to a year ago. Total costs and expenses increased by $0.6 million or 4.5%. Lease operating expenses increased by $1.0 million from a year ago. Depreciation, depletion and amortization increased by $2.2 million while gas gathering expenses declined by $2.9 million. These factors contributed to the net loss of $1.9 million, or $0.06 per basic share, for the quarter ended March 31, 2007. In the prior year quarter, we recorded net income of $1.3 million, or $0.04 per basic and diluted share.

Net cash provided by operating activities for first-quarter 2007 was $1.0 million, as compared to net cash used by operating activities of $0.4 million for the same period in 2006. Net cash provided by operating activities, excluding changes in operating assets and liabilities, was $9.7 million for first-quarter 2007, up from $4.7 million during the comparable 2006 period. In spite of higher non-cash charges in this quarter when compared with the comparable period from the prior year, we had higher cash flows than we did a year ago.

	First Quarter
Operational Data	2007	2006	% Change
Oil sales volumes (mBbls)	151	138	+	10
Gas sales volumes (mmcf)	221	293	-	24
Combined sales volumes (mmcfe)	1,130	1,118	+	1
Net residue and NGL sales volumes (mmBtu)	267	652	-	59
Oil average realized sales price Bbl	$54.98	$58.94	-	7
Gas average realized sales price per mcf	$7.26	$8.06	-	10
Residue & NGL average realized sales       price per mmBtu	$8.33	$8.26	+	1
Oil - average daily sales (BOPD)	1,683	1,529	+	10
Gas - average daily sales (mcfd)	2,454	3,250	-	24
Combined average daily sales (mmcfed)	12,551	12,425	+	1

Subsequent Events: We closed on our acquisition of Output Exploration Company, LLC on April 2, 2007, effectively doubling our proved reserves and increasing our sales volumes by more than 60%. The consideration for the purchase was $91.6 million in cash, subject to certain adjustments, and $4.0 million of our common stock. Concurrent with the closing, we elected to terminate all hedges assumed in the acquisition with a payment of $4.8 million. BMO Capital Markets served as financial advisor to TXCO. See the "New Credit Facilities" section below for discussion of the related financing.

The core of the Output holdings is in the East Texas Fort Trinidad Field and is prospective for the Glen Rose, Buda, Austin Chalk and Eagleford/Woodbine formations. Other Output holdings acquired include acreage in the Midcontinent and Gulf Coast regions and shallow Gulf Coast waters.

Liquidity and Capital Resources

Liquidity is a measure of ability to access cash. Our primary needs for cash are for exploration, exploitation, development and acquisition of oil and gas properties, repayment of contractual obligations and working capital funding. We have historically addressed our long-term liquidity requirements through cash provided by operating activities, the issuance of debt and equity securities when market conditions permit, sale of non-strategic assets, and more recently through our credit facilities. The prices for future oil and natural gas production and the level of production have significant impacts on operating cash flows and cannot be predicted with any degree of certainty. We continue to examine alternative sources of long-term capital, including bank borrowings, the issuance of debt instruments, the sale of common stock, the sales of strategic and non-strategic assets, and joint-venture financing. Availability of these sources of capital and, therefore, our ability to execute our operating strategy will depend upon a number of factors, some of which are beyond our control.

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Bank Credit Facility: At March 31, 2007, we had a $50 million senior secured revolving credit facility with Guaranty Bank (the "Facility"). The Facility was entered into in 2004 and would have expired in June 2008. See the discussion below regarding the replacement of the Facility on April 2, 2007.

The Facility was collateralized by all of our proven oil and gas properties, with the borrowing base established on current levels of our oil and gas reserves, and featured semi-annual redeterminations. At March 31, 2007, the borrowing base, inclusive of tranche A and tranche B, was $32.0 million. At March 31, 2007, $22.9 million was outstanding at an interest rate of 8.25% and the unused borrowing base was $9.1 million. Interest under the Facility was based on, at our 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 Facility provided the lender a commitment fee equal to 0.5% per annum on the unused borrowing base. The interest rate at March 31, 2007, was 8.25% computed in accordance with (b) above.

The Facility contained additional terms and conditions consistent with similarly positioned companies. These conditions included 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, and prohibiting a change of control or incurring additional debt. The ratios used for determining compliance with the Facility were defined within the Facility and may not be equivalent to other uses of those terms. We were in compliance with all such covenants at March 31, 2007.

New Credit Facilities: On April 2, 2007, we entered into a new Senior Credit Agreement and a Second Lien Term Loan Agreement (the "New Facilities"). The New Facilities replaced the Facility with Guaranty Bank and provided funding for our acquisition of Output Exploration, LLC. At April 30, 2007, the combined balance outstanding under the New Facilities was $124.0 million at a weighted average interest rate of 9.0%. The New Facilities are discussed in more detail in Note 8 to the consolidated financial statements.

Outlook:We believe the New Facilities, along with our current working capital and positive cash flow from existing production and anticipated production increases from new drilling, will provide adequate capital to fund operating cash requirements and complete our scheduled exploration and development goals for 2007. We expect to further increase our borrowing base commensurate with the expected growth of our proved oil and gas reserves throughout the base term of the new facilities. Should product prices weaken, or expected new oil and gas production levels not be attained, the resulting reduction in projected revenues would cause us to re-evaluate our working capital options and would adversely affect our ability to carry out our current operating plans.

Risk Management Activities -- Commodity Hedging Contracts: Due to the volatility of oil and natural gas prices and initial requirements under our former bank credit facility, we periodically enter into price-risk management transactions (e.g., swaps, collars and floors) for a portion of our oil and natural gas production. In certain cases, this allows us to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations.  These arrangements apply to only a portion of our production, and provide only partial price protection against declines in oil and natural gas prices, and may partially limit our potential gains from future increases in prices.  None of these instruments are used for trading purposes. On a quarterly basis, management sets all of our 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 the Board of Directors.  Our Board of Directors monitors our price-risk management policies and trades.

All of our 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 our 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. We have elected to account for certain of our derivative contracts as investments as set out under SFAS No. 133. Therefore, the changes in fair value in those contracts are recorded immediately as unrealized gains or losses on the Consolidated Statement of Operations. The change in fair value for the effective portion of contracts designated as cash flow hedges is recognized as Other Comprehensive Income (Loss) as a component in the Stockholders' 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.

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Sources and Uses of Cash: At December 31, 2006, our cash reserves were $3.9 million.  During first-quarter 2007, cash provided by operating activities was $1.0 million. In addition, borrowings under the Facility of $20.5 million, proceeds from installment obligations of $0.1 million, and proceeds from the exercise of options totaling $0.3 million, resulted in total cash available of $21.9 million for use in meeting our ongoing operational and development needs.

Payments on installment debt during first-quarter 2007 totaled $0.1 million in principal, while interest payments on debt were also $0.1 million. There were no federal income taxes paid during the quarter. We applied $21.0 million to fund the ongoing development of our oil and gas producing properties.

Adjusted for the impact of the derivative liabilities on current liabilities, we ended first-quarter 2007 with positive working capital of $9.1 million compared to $2.7 million at December 31, 2006. At March 31, 2007, with the same adjustment, our current ratio was 1.53 to 1 compared to 1.17 to 1 at year-end 2006. Including the $0.2 million of derivative current liabilities at March 31, 2007, positive working capital was $8.9 million with a current ratio of 1.51 to 1. At year-end 2006, including the $0.4 million of derivative current liabilities, working capital was $2.3 million, while the current ratio was 1.14 to 1.

We completed first-quarter 2007 with an unused borrowing base of $9.1 million under the Facility. First-quarter 2007 net cash provided by operating activities was $1.0 million, compared to net cash used by operating activities of $0.4 million in first-quarter 2006. Before changes in operating assets and liabilities, first-quarter 2007 net cash provided by operating activities was $9.7 million compared to $4.7 million for the same 2006 period. Changes in operating assets and liabilities include increases or decreases in current receivables, payables and prepaid expenses from the prior year-end balances.

Results of Operations

The following table highlights the change for 2007 from the comparable periods in 2006:

	First Quarter
Selected Income Statement Items:	$ thousands			%
Oil and gas revenues	-	1,744	-	17
Lease operating expense	+	1,017	+	62
Depreciation, depletion & amortization	+	2,190	+	80
Income from operations	-	5,395	-	193
Net income	-	3,167	-	248

The following table summarizes the change for 2007 from the comparable period in 2006:

	First Quarter
Change in Gas Gathering Results:	$ thousands		%
Revenues:
Third-party natural gas sales	-	2,882	-	61
Natural gas liquids sales	-	276	-	40
Transportation and other revenue	+	112	+	72
Total gas gathering revenues	-	3,046	-	55
Expense:
Third-party gas purchases	-	2,973	-	54
Transportation and marketing expenses	-	4	-	14
Direct operating costs	+	107	+	48
Total gas gathering operations expense	-	2,870	-	50
Gross margin	-	176	-	84
Operational data:
Total sales volumes (mmBtu)	-	385	-	59
Average sales price (per mmBtu)	+	0.08	+	1

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Three Months Ended March 31, 2007, Compared with Three Months Ended March 31, 2006:

Revenues

The decrease in oil and gas revenue is primarily due to non-cash losses on derivatives designated as cash flow hedges, along with lower average realized prices and a decline in gas sales volumes. These decreases were partially offset by higher oil sales volumes. Sales volumes increased 1.0% on a mcfe basis. Oil sales volumes increased 10.1% primarily due to Glen Rose Porosity wells put on production since March 31, 2006. This increase was largely offset by 24.5% lower gas volumes, reflecting normal maturing gas well decline curves. Additionally, due to our current focus on drilling oil wells, we are not replacing gas-specific reserves at the present time. Excluding the impact of hedging, average realized sales prices for oil were down 6.7%, while those for natural gas were down 9.9%. Derivative losses of a non-cash nature reduced revenues by $1.2 million for first-quarter 2007, of which $1.1 million was a non-cash charge allocating the cost of the 2005 termination of gas hedges for transactions in this period. Prior year revenues were not impacted by hedging, since the hedges in place for transaction in that time period were mark-to-market hedges.

Lease Operations

The 61.9% increase reflects costs related to 42 oil wells and one gas well placed on production since March 31, 2006, and increasing costs due to greater demand for third-party services in the field.

Exploration expenses

The 15.4% decrease primarily reflects lower delay rentals partially offset by higher dry hole costs.

Gas Gathering

Our gas gathering system transports our natural gas production to various markets. It also transports production for other owners at a set rate per million British thermal units ("mmBtu"). Gas gathering operations revenues decreased 55.0% due to lower volumes for third-party natural gas sales and natural gas liquids sales. The impact was partially offset by higher realized prices on natural gas liquids sales. Lower third-party natural gas sales volumes are coming through the system due to declining production on area leases and a partner's election to market its gas rather than sell it through TXCO.

Impairment

Impairment accruals increased 44.2% primarily due to impairment recorded on certain in-progress wells from prior periods.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization increased 80.3%, due to higher finding costs, depletion rates and costs related to new wells placed on production over the last year.

General and Administrative ("G&A")

The $0.1 million increase was primarily due to higher salaries. G&A expense as a percentage of revenue increased to approximately 16.1%, from 10.4% last year. The increase in the percentage of revenues was also impacted by the reduction in revenues previously discussed.

Salary-related costs were up $0.4 million related to accrual of year-end bonus, merit increases across the organization and a one-time adjustment upon the conversion to a bi-weekly payroll schedule.

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Derivative Gain / Loss

No mark-to-market ("MTM") or settlement gains or losses were recorded in first-quarter 2007 as the remaining hedges are designated as cash flow hedges. Settlements on cash flow hedges are reflected in revenues. Our remaining hedges expire on April 30, 2007. For the MTM hedges in the prior year quarter -- a pre-tax hedging loss of $0.6 million was recorded, primarily reflecting settlement costs.

Interest Expense

The $0.2 million increase was due to higher levels of borrowings under the Facility.

Drilling Activities

We drilled or participated in drilling 17 wells in the first three months of 2007. Of these wells, 15 were in the Maverick Basin and two were in the Williston Basin. At April 30, 2007, eight of these wells were on production, seven wells were in completion or being evaluated for recompletion, and one well remained drilling, while one well was plugged and abandoned. Additionally, two wells that were in progress at year-end 2006 were placed on production in first-quarter 2007. We focused primarily on the Glen Rose formation thus far in 2007. By comparison, we participated in eight wells during first-quarter 2006. The following table shows net daily sales for the periods presented:

	Quarter Ended			% Change from
Average net daily sales volumes :	March 31, 2007	December 31, 2006	March 31, 2006	4th Qtr 2006	1st Qtr 2006
Oil, BOPD	1,683	2,214	1,529	-24.0	+10.1
Natural gas, Mcfd	2,454	2,603	3,250	-5.7	-24.5
Oil equivalent, BOED	2,092	2,648	2,071	-21.0	+1.0

 Through May 4, 2007, TXCO spud or re-entered 11 wells in the second quarter, of which seven target the Glen Rose formation, bringing total wells spud in 2007 to 28. As of May 4, 2007, six of the second quarter spuds continued drilling, one was producing and four were in the completion phase.

Normal production declines were experienced on natural gas wells in first-quarter 2007, and no new gas wells were put on production to offset declines on maturing wells. One gas well was placed on production in April. Oil sales during first-quarter 2007 did not reach their potential for three major reasons:

·   impact of fourth-quarter 2006 drilling technique issues,

·   seasonal drilling slowdown (November through January), and

·   unscheduled third-party oil pipeline repairs.

There are six rigs under contract to facilitate drilling or re-entry of over 90 wells on our Maverick Basin acreage during 2007. The drilling rig we purchased in March 2006 was placed in service in January of this year and is being used primarily on wells in which TXCO has a 100% WI.

Glen Rose Porosity - During first-quarter 2007, we drilled or re-entered six Porosity wells, up from five in the same period of 2006. Five additional Porosity wells were begun in the second quarter through May 4, 2007. Currently, of the 11 total 2007 Porosity wells, five are on production, two are in completion, and four continue drilling. Glen Rose Porosity average daily sales for first-quarter 2007 were 1,370 BOPD, compared to 1,931 BOPD for the prior quarter and 1,184 BOPD for the comparable prior-year quarter. See the discussion above for causes of the decline in oil production.

Glen Rose Porosity targets represent more than half of our 2007 CAPEX budget. We currently plan to drill or re-enter over 35 wells in the Porosity during 2007.

Glen Rose Shoal/Reefs - During first-quarter 2007, we drilled two shoal and two reef wells. Additionally, we participated in two shoal wells in April. Currently of the six total shoal/reef wells: one is producing natural gas, two are in completion, two are being evaluated for re-completion and one remains drilling. Two wells targeting a Glen Rose reef or shoal were started in first-quarter 2006.

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Glen Rose average daily sales for first-quarter 2007, excluding Porosity production, were 13 BOPD and 2.2 mmcfd, compared to 9 BOPD and 2.3 mmcfd for the prior quarter and 15 BOPD and 2.9 mmcfd for the prior-year quarter. We currently plan to drill 12 shoal/reef wells during 2007.

Georgetown - We started one Georgetown well during first-quarter 2007, which is producing oil. Our 2007 CAPEX budget includes five wells. Georgetown average daily sales for first-quarter 2007 were 21.9 BOPD and 111 mcfd, compared to 16.5 BOPD and 134 mcfd for the prior quarter, and 57.8 BOPD and 155 mcfd for the prior-year quarter.

San Miguel - San Miguel average daily sales for first-quarter 2007 were 215 BOPD, compared to 211 BOPD for the prior quarter, and 203 BOPD for the prior-year quarter. We started two San Miguel wells during first-quarter 2007. Three wells were spud during April. Three of the five wells spud thus far in 2007 are in completion at April 30, 2007, one continues drilling and one was plugged and abandoned. None were begun in the prior year quarter. Our CAPEX budget calls for 11 San Miguel wells in 2007.

San Miguel Oil Sands - The two-well pilot test of the Oil Sands formation with our partner, Pearl Exploration and Production Ltd., involves a steam injection, soak and production cyclical process designed to heat the oil (0 degree API gravity) and allow it to be produced. Both of the pilot wells have completed the second injection cycle, which raised the bottom hole temperature ("BHT") to over 300 degrees around each well. Oil from the project has been shipped to laboratories for analysis and pricing. We anticipate that it will receive a discount to West Texas Intermediate prices. Our CAPEX budget calls for 21 Oil Sands wells in 2007. We acquired over 30,000 additional acres over the tar sand body during the first quarter, bringing our total to over 77,000 acres.

Heavy Oil - We are conducting a project to test the feasibility of extracting heavy oil (12- to 14-degree API gravity) from shallow sands on certain portions of our acreage (100% WI) using a series of horizontal well bores to inject steam and heat the formation. This first phase of this project includes two horizontal wells and five shallow monitor wells that will be converted to producing wells when the BHT has increased sufficiently.

This oil sand is relatively small (20 to 30 foot thick) and covers only about 6,000 acres. It is close to the surface and should be inexpensive to develop. Costs incurred to date on this project are about $0.5 million.

Pearsall - No wells have been spud thus far in 2007 targeting the Pearsall formation. We expect our partner, EnCana Oil & Gas (USA) Inc., to spud our first horizontal well targeting this formation in late May, or early June, 2007. Our first vertical well targeting this formation, spud during third-quarter 2006, is producing gas. Our CAPEX budget calls for up to three Pearsall wells to be drilled in 2007. The timing and number of these wells is under the control of EnCana as operator. For further discussion see "Part I, Item I - Business -Maverick Basin Plays" in our Annual Report on Form 10-K for the year ended December 31, 2006.

Marfa Basin - We expect the Simpson 1 well, re-entered during third-quarter 2006, to be fracture stimulated during 2007. Continental Resources Inc., our 50% partner in this acreage, serves as operator for the lease block.

Output Properties - Operations are ongoing on former Output Exploration properties in Texas and Oklahoma. We currently are assimilating new staff, CAPEX budget and related operations. We expect to drill more than 30 wells this year on prospects acquired through Output.

We are now preparing locations to submit to our partners to drill horizontally in the undeveloped Glen Rose shoals that we have identified in the Fort Trinidad field. We believe there are four shoals that can be drilled horizontally covering several thousand acres each. We are also encouraged by recent activity to both the east and west of our 20,000 acre block targeting the expanding downdip Bossier play.

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Disclosure Regarding Forward Looking Statements

Statements in this 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 forwarding-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 estimated financial results, or expected prices, production volumes, reserve levels and number of drilling locations, expected drilling plans, including the 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. These risks and uncertainties include: the costs and accidental risks inherent in exploring and developing new oil and natural gas reserves, the price for which such reserves and production can be sold, environmental concerns affecting the drilling of oil and natural gas wells, impairment of oil and gas properties due to depletion or other causes, the uncertainties inherent in estimating quantities of proved reserves and cash flows, as well as general market conditions, competition and pricing. Please refer to the "Risk Factors" section of our Form 10-K for the year ended December 31, 2006. This and all our previously filed documents are on file at the Securities and Exchange Commission and can be viewed on our Web site at www.txco.com. Copies of the filings are available from our Corporate Secretary 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 due to adverse changes in financial market prices, including interest rate risk, and other relevant market rate or price increases.

We are exposed to market risk through interest rates related to our credit facility borrowing. Our credit facility borrowings are based on the LIBOR or prime rate plus an applicable margin and are used to assist in meeting our working capital needs. As of March 31, 2007, we had borrowings under our bank credit facility of $22.9 million. Assuming an increase in either the LIBOR or prime rate of interest of 100 basis points, interest expense would increase by approximately $229,000 per year. The interest rate variability on all other debt would not have a material adverse effect on our financial position. As discussed in Note 8 to our consolidated financial statements in Part I, Item 1 of this Form 10-Q, we replaced the foregoing facility with the New Facilities in April 2007. At April 30, 2007, we had a combined balance outstanding under the New Facilities of $124.0 million, at a weighted average interest rate of 9.0% per annum. At the current borrowing level, interest expense will increase by approximately $11.2 million per year.

Our major market-risk exposure is the commodity pricing applicable to our oil and natural gas production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. Prices have fluctuated significantly during the last five years and such volatility is expected to continue, and the range of such price movement is not predictable with any degree of certainty. In the normal course of business we periodically enter into hedging transactions, 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, we put in place natural gas and crude oil swaps for a portion of our 2005 through 2007 production. Please refer to Note 5 to the consolidated financial statements included herein for additional information. 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.  Our remaining hedges expired on April 30, 2007.

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The following is a list of derivative contracts outstanding as of March 31, 2007:

				Price	Volumes
Transaction				Per	Per
Date	Type	Beginning	Ending	Unit	Month
Crude oil (1):
06/05	Fixed Price	11/01/2006	04/30/2007	$56.70	13,000

(1)   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. They were designated as cash flow hedges.

At March 31, 2007, the fair value of the outstanding hedges was a liability of approximately $0.1 million. A 10% change in the commodity price per unit would cause the fair value of the hedges to increase or decrease by approximately $13,000.

For additional information, see also our Annual Report on Form 10-K for the year ended December 31, 2006, "Item 7A. Quantitative and Qualitative Disclosures About Market Risk."

ITEM 4.     CONTROLS AND PROCEDURES

The SEC has adopted rules requiring reporting companies to maintain disclosure controls and procedures to provide reasonable assurance that a registrant is able to record, process, summarize and report the information required in the registrant's quarterly and annual reports under the Securities Exchange Act of 1934 (the "Exchange Act"). While we believe that our existing disclosure controls and procedures have been effective to accomplish these objectives, we intend to continue to examine, refine and formalize our disclosure controls and procedures and to monitor ongoing developments in this area.

Based on their evaluation as of March 31, 2007, our chief executive officer and chief financial officer have concluded that our disclosure controls and procedures (as defined in Rule 13a-15(e) or 15d-15(e) under the Exchange Act) are effective to ensure that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is: (1) recorded, processed, summarized and reported within the time periods as specified in the SEC's rules and forms, and (2) accumulated and communicated to our management, including our chief executive and chief financial officers, to allow timely decisions regarding required disclosure.

There have not been any changes in our internal control over financial reporting (as such term is defined in Rule 13a-15(f) or 15d-15(f) under the Exchange Act) during the fiscal quarter to which this report relates that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1.     LEGAL PROCEEDINGS

From time to time, we are involved in litigation arising out of our operations in the ordinary course of business. We maintain liability insurance, including product liability coverage, in amounts deemed adequate by management. To date, aggregate costs to us for claims, including product liability actions, have not been material. However, an uninsured or partially insured claim, or claim for which indemnification is not available, could have a material adverse effect on our financial condition or results of operations. We believe that there are no claims or litigation pending, the outcome of which could have a material adverse effect on our financial position or results of operations. However, due to the inherent uncertainty of litigation, there can be no assurance that the resolution of any particular claim or proceeding will not have a material adverse effect on our results of operations for the fiscal period in which such resolution occurs.

ITEM 1A.     RISK FACTORS

Please see the risk factors previously disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2006.

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ITEM 2.      UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

There were no unregistered sales by TXCO of its equity securities during first-quarter 2007. However on April 2, 2007, approximately 339,000 shares were issued in a private placement as part of the acquisition of Output Acquisition. See Note 8 to the financial statements included in this Form 10-Q for further information.

ITEM 3.      DEFAULTS UPON SENIOR SECURITIES

          None

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

          None

ITEM 5.      OTHER INFORMATION

          None

ITEM 6.      EXHIBITS

a)      Exhibit 3.1  Amended and Restated Bylaws, filed herewith.

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

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

d)     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.

e)     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:  May 10, 2007

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