Txco Resources (TXCOQ) 10-Q 2006 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 Quarter ended				Commission File No.
March 31, 2006				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.
Yesþ				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 filerp	Accelerated filerþ					Non-accelerated filerp
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 April 28, 2006.
Common Stock $0.01 par value				32,923,565
(Class of Stock)				(Number of Shares)
For more information go to www.txco.com
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PART I - FINANCIAL INFORMATION
ITEM 1.     FINANCIAL STATEMENTS.
THE EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
($ in thousands)	March 31, 2006	December 31, 2005
Assets
Current Assets
Cash and equivalents	$1,432	$6,083
Accounts receivable, net	7,573	9,344
Prepaid expenses and other	2,059	1,620
Total Current Assets	11,064	17,047
Property and Equipment,net - successful efforts    method of accounting for oil and gas properties	95,124	84,467
Other Assets
Deferred tax asset	7,410	7,242
Other assets	661	780
Total Other Assets	8,071	8,022
Total Assets	$114,259	$109,536
See notes to consolidated financial statements
2

THE EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
($ in thousands)	March 31, 2006			December 31, 2005
Liabilities and Stockholders' Equity
Current Liabilities
Accounts payable, trade		$6,412		$10,003
Undistributed revenue		1,966		2,479
Current income taxes payable		2,848		4,952
Other payables and accrued liabilities		3,864		4,297
Derivative settlements payable		203		151
Accrued derivative obligation - short-term		2,815		2,084
Long-term debt, current portion		159		262
Total Current Liabilities		18,267		24,228
Long-term Liabilities
Long-term debt, net of current portion		9,301		1
Accrued derivative obligation - long-term		161		461
Asset retirement obligation		1,597		1,565
Total Long-Term Liabilities		11,059		2,027
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 32,962,030 and 29,479,697 shares,       outstanding 32,862,230 and 29,379,897 shares		330		295
Additional paid-in capital		120,155		89,680
Accumulated deficit		(3,348	)	(4,622	)
Less stock subscription receivable, 3,000,000 shares, net of costs		(29,875	)	-
Less treasury stock, at cost, 99,800 shares		(246	)	(246	)
Accumulated other comprehensive loss, net of tax		(2,083	)	(1,826	)
Total Stockholders' Equity		84,933		83,281
Total Liabilities and Stockholders' Equity		$114,259		$109,536
See notes to consolidated financial statements
3

THE EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
	Three Months Ended			Three Months Ended
(in thousands, except earnings per share data)	March 31, 2006			March 31, 2005
Revenues
Oil and gas sales		$10,469			$ 7,684
Gas gathering operations		5,540			6,927
Other operating income		14			6
Total Revenues		16,023			14,617
Costs and Expenses
Lease operations		1,643			1,686
Production taxes		512			462
Exploration expenses		444			512
Impairment and abandonments		476			564
Gas gathering operations		5,751			6,572
Depreciation, depletion and amortization		2,726			2,481
General and administrative		1,420			1,179
Stock compensation expense		252			-
Total Costs and Expenses		13,224			13,456
Income from Operations		2,799			1,161
Other Income (Expense)
Derivative mark-to-market loss		(6	)		(3,396	)
Derivative settlements loss		(633	)		(168	)
Interest expense		(87	)		(870	)
Interest income		38			12
Loan fee amortization		(73	)		(16	)
Total Other Income (Expense)		(761	)		(4,438	)
Income before income taxes		2,038			(3,277	)
Income tax expense		763			25
Net Income (Loss)		$1,275			$(3,302	)
Earnings (Loss) Per Share
Basic earnings (loss) per share		$0.04			$(0.12	)
Diluted earnings (loss) per share		$0.04			$(0.12	)
See notes to consolidated financial statements
4

THE EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
	Three Months Ended			Three Months Ended
(in thousands)	March 31, 2006			March 31, 2005
Operating Activities
Net income (loss)		$1,275		$(3,302	)
Adjustments to reconcile net income (loss) to    net cash provided by operating activities:
Depreciation, depletion and amortization		2,726		2,481
Impairment and abandonments		476		564
Non-cash compensation expense related to stock options and warrants		252		-
Non-cash derivative mark-to-market loss		6		3,396
Non-cash interest expense and accretion of liability        - redeemable preferred stock		- -		265
Changes in operating assets and liabilities:
Receivables		1,771		1,690
Prepaid expenses and other		(320	)	(813	)
Accounts payable and accrued expenses		(6,589	)	(1,821	)
Net cash (used) provided by operating activities		(403	)	2,460
Investing Activities
Development and purchases of oil and gas properties		(9,776	)	(7,112	)
Purchase of other equipment		(4,055	)	(15	)
Proceeds from sale of assets		3		-
Net cash (used) by investing activities		(13,828	)	(7,127	)
Financing Activities
Proceeds from issuance of common stock, net of expenses		382		1,296
Proceeds from long-term debt obligations		9,300		3,300
Payments on installment obligations		(102	)	(1,532	)
Net cash provided by financing activities		9,580		3,064
Change in Cash and Equivalents		(4,651	)	(1,603	)
Cash and equivalents at beginning of period		6,083		3,118
Cash and Equivalents at End of Period		$1,432		$ 1,515
See notes to consolidated financial statements
5

THE EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PERIODS ENDED MARCH 31, 2006 AND MARCH 31, 2005 (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, 2005.
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, 2005.
2.     Fair Value of Stock Options
At March 31, 2006, the Company has a stock-based employee compensation plan which is described more fully in Note F, "Stockholders' Equity," to the December 31, 2005, audited consolidated financial statements contained in theCompany'sAnnual Report on Form 10-K. The Company adopted SFAS No. 123R, "Accounting for Stock-Based Compensation," on January 1, 2006, using the modified-prospective transition method. Compensation expense, for the unvested portion of options outstanding at December 31, 2005, is being expensed over the remaining life of those awards. No options have been granted in fiscal 2006.
Prior to the adoption of SFAS No. 123R, the Company accounted 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 was 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 to stock-based employee compensation for the period presented:
Three Months Ended March 31:	2005
(in thousands, except per share data)
Net loss as reported	$(3,302	)
Deduct: Total stock-based compensation expense determined under the fair value based    method for all awards, net of related tax effects	1
Pro forma loss	$(3,303	)
Loss per common share:
Basic, as reported	$(0.12	)
Basic, pro forma	(0.12	)
Diluted, as reported	(0.12	)
Diluted, pro forma	(0.12	)
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3.     Common Stock and Basic Income Per Share
On March 30, 2006, our Board of Directors approved a private placement of our common stock to a group of institutional investors. On March 31, 2006, related stock subscriptions for three million shares of our common stock were received via the placement agents. On April 4, 2006, the transaction was closed and funded, providing approximately $29.9 million to supplement our capital resources. These new funds allow the expansion of the capital expenditure budget for 2006 in order to accelerate the development on the Glen Rose Porosity as well as other new projects.
As of March 31, 2006, the Company had outstanding warrants and options to purchase 2,220,250 shares of common stock at prices ranging from $0.98 to $5.00 per share. Of these, warrants and options to purchase 1,830,250 shares were exercisable at quarter end. The warrants and options expire at various dates through September 2014. The Company granted 349,000 shares of restricted stock as compensation to employees and directors during the first quarter of 2006.
The following is a reconciliation of the numerator and denominator of the basic and diluted earnings per share computation:
			2006						2005
Three Months Ended March 31			Wt.-Avg. Shares Outstanding		Income		Per Share Amount		Wt.-Avg. Shares Outstanding			(Loss)						Per Share Amount
(In thousands, except per share data)
Basic EPS:
Net income (loss)			29,738		$1,275		$0.04		28,176			$(3,302					)	$(0.12		)
Effect of dilutive options			1,122		-		-		n/a			-						-
Dilutive EPS			30,860		$1,275		$0.04		28,176			$(3,302					)	$(0.12		)
n/a - not applicable due to net loss for the period.							Wt.-Avg. - weighted average
4.     Income Taxes
The Company recognizes deferred tax assets on its differences in basis for book and tax purposes. The Company's effective tax rate was 37% and 0.8% for the three months ended March 31, 2006, and March 31, 2005, respectively.
5.     Commodity Hedging Contracts and Activity
Due to the volatility of oil and natural gas prices, 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. 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 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 Balanc e Sheets. The gain or loss in Other Comprehensive Income will be 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.
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5.     Commodity Hedging Contracts and Activity - continued
The outstanding hedges at March 31, 2006, and December 31, 2005, impacting the balance sheet were as follows:
						Price		Volumes		Fair Value of Outstanding     Derivative Contracts (1) as of
Transaction		Beginning		Ending		Per		Per		March 31,						December 31,
Date	Type					Unit		Month		2006						2005
Crude oil (2):										(in thousands)
Derivatives treated as investments:
03/05	Fixed Price	11/01/2005		10/31/2006		$49.40		15,000		$(2,001				)		$(1,995				)
Derivatives treated as cash flow hedges:
06/05	Fixed Price	11/01/2006		04/30/2007		$56.70		13,000		(975				)		(550				)
Total fair value of derivative contracts										$(2,976				)		$(2,545				)
(1)   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.
(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.
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 months ended March 31, 2006, and 2005:
											Three Month Period
(in thousands)											2006				2005
Net income (loss)											$1,275				$(3,302				)
Other comprehensive income (loss):
Change in fair value of cash flow hedges											(425		)		-
Change in income tax benefit of cash flow hedges											168				-
Total comprehensive income (loss)											$1,018				$(3,302				)
7.     Long-Term Debt
Bank Credit Facility:The Company has a $50 million senior secured revolving credit facility with Guaranty Bank ("Facility"). The Facility was entered into in 2004 and expires in June 2008.
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 semi-annual redeterminations. At March 31, 2006, the borrowing base, inclusive of traunche A and traunche B, was $29.0 million. The unused borrowing base at March 31, 2006, was $19.7 million with $9.3 million outstanding at a weighted average interest rate of 7.27%. Interest under the Facility is based on, at TXCO's option, (a) the London Interbank Offered Rate ("LIBOR") plus an applicable margin ranging from 2.00% to 2.50% or (b) prime plus an applicable margin ranging from 0.00% to 0.25% ("floating rate"). The Facility provides the lender a commitment fee equal to 0.5% per annum on the unused borrowing base.
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, and prohibiting a change of control or incurring additional debt. 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 March 31, 2006.
8

ITEM 2.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
                   CONDITION AND RESULTS OF OPERATIONS

Certain statements in this report are not historical in nature, including statements of TXCO's and management's expectations, intentions, plans and beliefs, are inherently uncertain and are "forward-looking statements" within the meaning of Section 21E of the Securities Exchange Act of 1934. The following discussion should be read in conjunction with the unaudited consolidated financial statements and notes thereto included in this Form 10-Q, and with the Company's latest audited consolidated financial statements and notes thereto, as reported inits Form 10-K for the year ended December 31, 2005. See"Disclosure Regarding Forward Looking Statements".

Overview

Unless the context requires otherwise, when we refer to "TXCO", "the Company", "we", "us" and "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 in Southwest Texas and the Marfa Basin of West Texas, with a consistent record of long-term growth in proved oil and gas reserves, leasehold acreage position, production and cash flow through our established exploration 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 the Nasdaq Capital Market^SM under the symbol "TXCO."

We currently have six drilling rigs under contract and in operation on our extensive 656,000-acre position in the Maverick Basin. Our current emphasis is on the Glen Rose, Georgetown and San Miguel formations. Our updated 2006 capital expenditures budget (CAPEX) includes funds for the drilling or re-entry of over 90 wells (over 30 in the Glen Rose Porosity), as well as funds for completion of a number of wells in progress at year-end 2005 and for infrastructure improvements. We began 13 new wells and one re-entry through late April 2006, including nine in the Glen Rose Porosity. We expect to begin exploration activities in the Marfa Basin in the third quarter of 2006 with our recently announced partner for this project, Continental Resources, Inc., of Enid, Okla. The drilling rig we purchased in March 2006 is currently undergoing refurbishment and is expected to be in service in the third quarter.

Due to the number of promising prospects on our Maverick Basin acreage, as well as higher oil and gas prices, drilling activity remained high over the last several years. (For further discussion of this activity, see "Principal Areas of Activity" and "Drilling Activity" in Item 1 ofour Annual Report on Form 10-K for the year ended December 31, 2005). The resulting increased expenditures should continue to translate into increased reserves as an adequate 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.

Net income was $1.3 million or $0.04 per basic share for the quarter ended March 31, 2006, compared to a net loss of $3.3 million or $0.12 per basic and diluted share for the prior-year period. The increase resulted from substantially lower derivative mark-to-market losses and higher oil and gas sales revenues. Excluding the hedging losses net of tax impact, net income would have been $1.7 million for first-quarter 2006 as compared to $0.3 million for the prior-year period. Oil and gas revenues were up 36.3% for first-quarter 2006 over first-quarter 2005 due to higher oil volumes sold at a higher average realized price, partially offset by lower natural gas volumes at a higher average realized price. Sales volumes were down 2.0% on a billion cubic feet equivalent (Bcfe) basis during first-quarter 2006, as compared with the prior-year period. Lower combined and natural gas sales reflect the September 2005 sale of approximately 20% of then current total production. The gross loss on gas ga thering operations, along with higher depreciation, depletion and amortization and general and administrative costs were partially offset by lower lease operating costs, impairment charges, and interest expense. These factors are discussed in "Results of Operations."

9

							First Quarter
Operational Data							2006		2005					Change
Oil  sales volumes (Bbls)							137,617		74,837					+						83.9		%
Gas sales volumes (Mcf)							292,506		693,476					-						57.8		%
Combined sales volumes (MMcfe)							1,118		1,142					-						2.1		%
Net residue and NGL sales volumes (MMbtu)							652,034		807,699					-						19.3		%
Gas average realized sales price per Mcf							$8.06		$6.14					+						31.3		%
Oil average realized sales price per Bbl							$58.94		$45.78					+						28.8		%
Residue & NGL average realized sales price per MMbtu							$8.26		$8.40					-						1.7		%
Gas - average daily sales (MMcfd)							3.3		7.7					-						57.8		%
Oil  - average daily sales (BOPD)							1,529		832					+						83.9		%
Combined average daily sales (MMcfed)							12.4		12.7					-						2.1		%
Subsequent Events:In addition to the new Marfa Basin partner, mentioned earlier in this section and in the Drilling Activities section, we signed a lease on May 8, 2006 for new office space. The lease has a term of seven and one-half years.
Liquidity and Capital Resources
Liquidity is a measure of ability to access cash. Our primary needs for cash are for exploration, development and acquisitions 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 ourcredit facility. 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 non-strategic assets, and joint venture financing. Availability of these sources of capital and, therefore, our ability to execute our operating strateg y will depend upon a number of factors, some of which are beyond our control. We believe that projected operating cash flows, cash on hand, and borrowings under our credit facility, will be sufficient to meet the requirements of our business. However, future cash flows are subject to a number of variables including the level of production 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 our planned levels of capital expenditures or that we will not increase capital expenditures. 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: We have a $50 million senior secured revolving credit facility with Guaranty Bank (the "Facility" or "credit facility"). The Facility was entered into in 2004 and expires in June 2008.
The Facility is 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 features semi-annual redeterminations. At March 31, 2006, the borrowing base, inclusive of traunche A and traunche B, was $29.0 million. The unused borrowing base at March 31, 2006, was $19.7 million with $9.3 million outstanding at a weighted average interest rate of 7.27%. Interest under the Facility is 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 provides the lender a commitment fee equal to 0.5% per annum on the unused borrowing base. At April 30, 2006, all but $1,000 had been repaid.
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. The Facility's original requirement for hedging a percentage of production, under certain circumstances, was removed during 2005. At March 31, 2006, we were in compliance with all covenants.
10
Private Placement of Common Stock: On March 30, 2006, our Board of Directors approved a private placement of our common stock to a group of accredited investors. On March 31, 2006, related stock subscriptions for three million shares of our common stock were received via the placement agents. On April 4, 2006, the transaction was closed and funded, providing approximately $29.9 million to supplement our capital resources. These new funds allow the expansion of our capital expenditure budget for 2006 in order to accelerate our development on the Glen Rose Porosity, as well as other new projects. See "Part II, Item 2 - Unregistered Sales of Equity Securities and Use of Proceeds" for additional information.
Outlook:We believe the Facility, along with our positive cash flow from existing production and anticipated production increases from new drilling and the proceeds from the private placement, will provide adequate capital to fund operating cash requirements and complete our scheduled exploration and development goals for 2006. 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 Facility. 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 requirements under our 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. 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 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.
Sources and Uses of Cash: At December 31, 2005, our cash reserves were $6.1 million. During first-quarter 2006, we used $0.4 million in cash for operating activities. In addition, borrowings under the Facility totaled $9.3 million and proceeds from the exercise of warrants totaled $0.4 million, resulting in total cash available of $15.4 million for use in meeting our ongoing operational and development needs.
Payments on installment debt during first-quarter 2006 totaled $0.1 million in principal, with interest payments of $27,000. We applied $9.8 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 the first quarter of 2006 with negative working capital of $4.2 million compared to negative working capital of $4.9 million at December 31, 2005. At March 31, 2006, with the same adjustment, our current ratio was 0.73 to 1 compared to 0.78 to 1 at year-end 2005. Including the $3.0 million of derivative current liabilities at March 31, 2006, negative working capital was $7.2 million with a current ratio of 0.61 to 1. At year-end 2005, including the $2.2 million of derivative current liabilities, negative working capital was also $7.2 million, while the current ratio was 0.70 to 1.
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We completed the first quarter of 2006 with an unused borrowing base of $19.7 million under our Facility. First-quarter 2006 cash used by operating activities, including changes in operating assets and liabilities, was $0.4 million, compared to cash provided of $2.5 million in the prior-year period, primarily due to reduced accounts payable balances. Before changes in operating assets and liabilities, first-quarter 2006 cash flow from operating activities was $4.7 million in 2006 compared to $3.4 million for first-quarter 2005, a 39.1% increase. Changes in operating assets and liabilities include increases or decreases in receivables, accounts payable and prepaid expenses from the prior year-end balances.
Results of Operations
The following table highlights the change from first-quarter 2005to first-quarter 2006:
Selected Income Statement Items:						$ thousands													%
Oil and gas revenues						+						2,785			+				36.3
Lease operating expense						-						43			-				2.5
Depreciation, depletion & amortization						+						245			+				9.9
Income from operations						+						1,638			+				141.1
Derivative mark-to-market loss						-						3,390			-				99.8
Derivative settlements loss						+						465			+				275.4
Net income						+						4,577			+				n/m
n/m - % change not meaningful due to move from loss to income
The following table summarizes the change from first-quarter 2005 to first-quarter 2006:
Change in Gas Gathering Results:								$ thousands										%
Revenues:
Third-party natural gas sales											-		736				-				13.6
Natural gas liquids sales											-		664				-				48.9
Transportation and other revenue											+		13				+				9.0
Total gas gathering revenues											-		1,387				-				20.0
Expense:
Third-party gas purchases											-		778.8				-				12.4
Transportation and marketing expenses											-		54.6				-				68.5
Direct operating costs											+		12.2				+				5.9
Total gas gathering operations expense											-		821				-				12.5
Gross margin											-		566				-				n/m
Operational data
Total sales volumes (MMBtu)											-		155,665				-				19.3
Average sales price (per MMBtu)											-		0.14				-				1.7
n/m - % change not meaningful due to move from income to loss
Three Months Ended March 31, 2006, Compared with March 31, 2005:
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 production. Oil sales volumes increased 83.9% primarily due to Glen Rose Porosity wells put on production since March 31, 2005. This increase was offset by 57.8% lower gas production, reflecting the sale of a portion of our gas production to EnCana Oil & Gas (USA) Inc. ("EnCana") in September 2005 and normal maturing gas well decline curves. Sales volumes decreased slightly on a Mcfe basis. Average realized sales prices for oil and natural gas were up 28.8% and 31.3%, respectively.
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Lease Operations
The 2.5% decrease in lease operating expenses primarily reflects the elimination of costs related to wells sold to EnCana, partially offset by costs related to new Maverick Basin oil and gas wells placed on production since March 31, 2005, and cost increases related to the high demand for services in field operations.
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). It sells gas at several points along the system with a significant portion being delivered to purchasers through the Enterprise/Gulf Terra Pipeline System or to purchasers behind the Duke Three Rivers processing plant. The gas is processed and the natural gas liquids are removed. The residue gas is then sold to various purchasers. We receive a share of the liquids revenues. Natural gas pricing fluctuations are reflected at the wellhead for our operated gas properties.
Gas gathering operations revenues decreased 20.0% due to lower volumes for third-party natural gas sales and natural gas liquids sales. The impact was partially offset by higher realized prices. 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 9.9%. The major component of this increase was higher depletion, up $388,000. The increase was consistent with the increased number of producing wells subject to depletion and reflects increasing depletion rates due to the maturing profile of existing producing wells.
General and Administrative
General and administrative expense increased 20.4%, and represents approximately 8.8% of total revenues. The increase was primarily due to salary-related costs for four additional full-time employees hired since March 31, 2005, with associated salaries, wages, benefits and office-related expenses, along with merit increases across the organization. Higher costs for franchise taxes, related to increased commodity price levels, was largely offset by lower costs for independent engineer fees and internal control project costs.
Stock Compensation
The stock compensation expense was related to restricted stock grants during first-quarter 2006, and unvested stock options that are now required to be expensed under SFAS No. 123R. No comparable expenses were recorded during 2005.
Derivative Losses
Non-cash mark-to-market losses accrued on hedges of future sales volumes declined $3.4 million, primarily due to the elimination of the natural gas hedges during October 2005. Derivative losses on the closed periods amounted to $633,000, up from $168,000, bringing the total hedging loss to $639,000, as compared to $3.6 million in the prior year.
Interest Expense
Interest expense decreased by $0.8 million due to lower levels of borrowings under the Facility.
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Drilling Activities
We drilled or participated in drilling eight new wells on our lease block in the Maverick Basin in the first quarter of 2006. At March 31, 2006, two of these wells were producing, three wells were in completion, and three wells remained drilling. The first-quarter 2006 wells focused primarily on the Glen Rose formation. By comparison, we participated in nine new wells and three re-entries during first-quarter 2005 targeting the Glen Rose and Georgetown intervals. For first-quarter 2006, we had net daily sales of approximately 1,529 barrels of oil per day (BOPD) and 3.3 million cubic feet per day (MMcfd) of natural gas, a combined rate of approximately 12.4 million cubic feet equivalent per day (MMcfed). The comparable figures for fourth quarter 2005 were 1,427 BOPD and 3.5 MMcfd, or 12.0 MMcfed, while first-quarter 2005 sales were 832 BOPD and 7.7 MMcfd, or 12.7 MMcfed. In April 2006, TXCO spud five new wells and one re-entry. Four of the new wells target the Glen Rose Porosity.
Our oil production continues to rise as the result of our successful drilling program in the Glen Rose Porosity. Porosity oil production has begun to temporarily outstrip available transportation facilities, creating an 11,100-barrel inventory at the end of the quarter, compared to a typical level of approximately 1,100 barrels. We are currently adding tankage and arranging for increased transport services, which is expected to positively impact sales levels during the second quarter and going forward.
In September 2005, approximately 20% of then current total production, primarily from gas properties, was sold to EnCana. Normal production declines were experienced on natural gas wells in first-quarter 2006, as no new gas wells were put on production to offset declines on maturing wells. One oil and one natural gas well were put on production during April 2006.
There are six rigs under contract for our, or a partner's, account to facilitate drilling or re-entry of over 90 wells, during 2006. The drilling rig we purchased in March 2006 is currently undergoing refurbishment and is expected to be in service around the end of the second quarter.
Glen Rose Porosity- During first-quarter 2006, we drilled five Porosity wells, up from one in first-quarter 2005. Since quarter end, we started four additional Porosity projects. Currently of the nine total wells, two are producing, two are in completion, four continue drilling, and one awaits re-completion due to water encroachment. Glen Rose Porosity average daily sales for first-quarter 2006 were 1,184 BOPD, compared to 1,047 BOPD for the prior quarter and 281 BOPD for the prior-year period.
Glen Rose Porosity targets represent the largest portion of our 2006 CAPEX budget. We currently plan to drill or re-enter over 30 new wells in the Porosity during 2006. In April 2006, we began drilling on four new porosity wells.
Glen Rose Shoal/Reefs- During first-quarter 2006, we drilled one shoal and one reef well. Currently the shoal well is in completion, while the reef well is producing. No shoal or reef wells were started in first-quarter 2005.
Glen Rose average daily sales for first-quarter 2006, excluding Porosity production, were 15 BOPD and 2.9 MMcfd, compared to 14 BOPD and 3.1 MMcfd for the prior quarter and 19 BOPD and 4.4 MMcfd for the prior-year period. We currently plan to drill four new shoal/reef wells during 2006.
Georgetown- We started one Georgetown well during first-quarter 2006, down from ten projects in the prior-year period. The well has been placed on production. Our 2006 CAPEX budget includes 10 wells. Georgetown average daily sales for first-quarter 2006 were 0.2 MMcfd and 58 BOPD, compared to 58 BOPD and 0.1 MMcfd for the prior quarter and 3.0 MMcfd and 184 BOPD for the prior-year period. In late April 2006, we began a re-entry on a Georgetown well.
The drop in Georgetown production from the prior-year period, and the reduced Georgetown activity, reflects the sale of our interest in this formation on certain properties to EnCana in September 2005. We hold a 100% working interest in the Georgetown formation across most of the northern portion of our leaseblock.
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San Miguel Plays- San Miguel average daily sales for first-quarter 2006 were 204 BOPD with no gas, compared to 231 BOPD and 56 Mcfd for the prior quarter and 231 BOPD and 36 Mcfd for the prior-year period. No San Miguel wells were drilled in first-quarter 2005 or 2006. The decline in sales from the prior quarter reflects the reservation of some oil production in preparation for fracturing wells in the play during the second quarter. Our CAPEX budget calls for 36 San Miguel wells, including 26 Tar Sand and 10 Pena Creek wells, in 2006. One Pena Creek San Miguel well was spud in April 2006 with a second starting on May 1, 2006. We expect to begin development of the Tar Sand with our partner, Pearl Exploration and Production Ltd., in second-half 2006.
Pearsall- No Pearsall wells were drilled in 2005 or thus far in 2006. Our current CAPEX budget projects up to eight Pearsall wells to be drilled with our operating partner, EnCana. The timing and number of these wells is under the control of EnCana. For further discussion see Part I, Item I - Business -Maverick Basin Plays in ourAnnual Report on Form 10-Kfor the year ended December 31, 2005.
Marfa Basin - In April 2006, we sold a 50% working interest in our Marfa Basin acreage block to Continental Resources Inc., of Enid, Okla., which will serve as operator for the lease block. We expect to begin development of our new Marfa Basin acreage in the second half of 2006. One re-entry and one new well are currently planned for 2006.
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 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 ourForm 10-K for the year ended December 31, 2005, and the additional risk factor included in Part II, Item 1A of this Form 10-Q. 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. The 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, 2006, we had borrowings under our bank credit facility of $9.3 million. Assuming an increase in either the LIBOR or prime rate of interest of 100 basis points, interest expense could increase by approximately $93,000 per year.
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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 over 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 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 and 2006 production. Please refer toNote 5 to the consolidated financial statements included herein for addi tional 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.
The following is a list of derivative contracts outstanding as of March 31, 2006:
										Price						Volumes
Transaction										Per						Per
Date		Type	Beginning	Ending						Unit						Month
Crude oil (1):
Derivatives treated as investments:
03/05		Fixed Price	11/01/2005	10/31/2006						$49.40						15,000
Derivatives treated as cash flow hedges:
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.
At March 31, 2006, the fair value of the outstanding hedges was a liability of approximately $3.0 million. A 10% change in the commodity price per unit would cause the fair value of the hedges to increase or decrease by approximately $300,000.
For additional information, see alsoourAnnual Report on Form 10-K for the year ended December 31, 2005, "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. 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.
We have established disclosure controls and procedures to ensure that material information relating to us, including our consolidated subsidiaries, is made know to the officers who certify our financial reports and to other members of senior management and the Board of Directors.
Based on their evaluation as of March 31, 2006, 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.
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PART II - OTHER INFORMATION
ITEM 1.     LEGAL PROCEEDINGS
None
ITEM 1A.     RISK FACTORS
Except as set forth below, there have been no material changes from the risk factors previously disclosed inour Annual Report on Form 10-K for the fiscal year ended December 31, 2005.
The marketability of our production may be dependent upon transportation facilities over which we have no control.
	The marketability of our production depends in part upon the availability, proximity, and capacity of oil and gas pipelines, crude oil trucking, natural gas gathering systems and processing facilities. Any significant change in market factors affecting these infrastructure facilities could harm our business. We transport our crude oil through trucks that we do not own, and we deliver some of our natural gas through gathering systems and pipelines that we do not own. These facilities may not be available to us in the future or may become inadequate for oil and gas volumes produced.
Instituted in 1999, our Rights Plan and certain provisions in our Restated Certificate of Incorporation may inhibit a takeover of the Company regardless of whether such takeover is in the best interest of our stockholders.
-	Our Rights Plan and certain provisions in our Restated Certificate of Incorporation could have the effect of discouraging a third party from making a tender offer or otherwise attempting to obtain control of the Company even though such a transaction could be beneficial to our stockholders:
-	Our Rights Plan, commonly referred to as a "poison pill", provides that when any person or group acquires beneficial ownership of 15% or more of Company common stock, or commences a tender offer which would result in beneficial ownership of 15% or more of such stock, holders of rights under the Rights Plan will be entitled to purchase, at the Right's then current exercise price, shares of our common stock having a value of twice the Right's exercise price.
-	Pursuant to our Restated Certificate of Incorporation, our Board of Directors has the authority to issue preferred stock with voting or other rights or preferences that could impede the success of any attempt to effect a change in control or takeover of the Company.
-	Our Restated Certificate of Incorporation provides that our Board of Directors will be divided into three classes of approximately equal numbers of directors, with the term of office of one class expiring each year over a three-year period. Classification of directors has the effect of making it more difficult for stockholders to change the composition of our Board. At least two annual meetings of stockholders, instead of one, will generally be required to effect a change in the majority of the Board.
ITEM 2.      UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
During the first quarter of 2006, an investor exercised a warrant to purchase 133,333 shares of our common stock at $3.00 per share, resulting in cash proceeds of approximately $0.4 million. Proceeds from the exercise were used in the ordinary course of business. The warrant was issued in a private placement in 2000. The underlying shares were registered with the S-1 registration filing on April 28, 2006.
Pursuant to an agreement signed on March 30-31, 2006, we sold three million shares of common stock in a private placement for $10.50 per share. We received the cash proceeds on April 4, 2006. A related Form S-1 was filed with the SEC on April 28, 2006. The net proceeds of approximately $29.9 million will be used to increase drilling and development of the Glen Rose Porosity and San Miguel tar sand plays on our Maverick Basin acreage, drilling on our Marfa Basin acreage and fund our recent acquisition of a drilling rig. The related agreements were provided to the SEC with our Current Reports on Form 8-K filed on April 5 and 6, 2006.
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On April 7, 2006, we issued 61,335 shares of our common stock along with a cash payment to purchase an overriding royalty interest in our Marfa Basin oil and gas leases covering approximately 140,000 gross acres (135,000 net) located in Presidio and Brewster Counties.
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 10.1  * Sample of Restricted Stock Award issued to all employees during the first quarter of 2006, filed herewith.
b)     Exhibit 10.2  * Compensation arrangement for General Counsel, filed February 10, 2006 on Form 8-K as Item 5.02.
c)     Exhibit 31.1   Certification of Chief Executive Officer required pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended filed herewith.
d)     Exhibit 31.2   Certification of Chief Financial Officer required pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended filed herewith.
e)     Exhibit 32.1   Certification of Chief Executive Officer required pursuant to 18 U.S.C. Section 1350 as required by the Sarbanes-Oxley Act of 2002 filed herewith.
f)     Exhibit 32.2   Certification of Chief Financial Officer required pursuant to 18 U.S.C. Section 1350 as required by the Sarbanes-Oxley Act of 2002 filed herewith.
*   Compensatory arrangement.
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, 2006
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