10-Q

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     June 30, 2006
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)
500 NORTH LOOP 1604 E.,  SUITE 250    SAN ANTONIO, TEXAS  78232
(Address of principal executive offices)
Registrant's telephone number, including area code:   (210) 496-5300
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes 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 August 4, 2006.
Common Stock $0.01 par value				32,930,815
(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.
1

PART I - FINANCIAL INFORMATION
ITEM 1.     FINANCIAL STATEMENTS.
THE EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
($ in thousands)	June 30, 2006		December 31, 2005
Assets
Current Assets
Cash and equivalents		$22,676	$6,083
Accounts receivable, net		8,789	9,344
Prepaid expenses and other		3,331	1,620
Total Current Assets		34,796	17,047
Property and Equipment, net - successful efforts    method of accounting for oil and gas properties		101,294	84,467
Other Assets
Deferred tax asset		7,998	7,242
Other assets		617	780
Total Other Assets		8,615	8,022
Total Assets		$144,705	$109,536
See notes to consolidated financial statements
2

THE EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
($ in thousands)	June 30, 2006			December 31, 2005
Liabilities and Stockholders' Equity
Current Liabilities
Accounts payable, trade		$8,814		$10,003
Undistributed revenue		1,782		2,479
Current income taxes payable		5,409		4,952
Other payables and accrued liabilities		3,985		4,297
Derivative settlements payable		324		151
Accrued derivative obligation - short-term		3,010		2,084
Long-term debt, current portion		228		262
Total Current Liabilities		23,552		24,228
Long-Term Liabilities
Long-term debt, net of current portion		1		1
Accrued derivative obligation - long-term		-		461
Asset retirement obligation		1,648		1,565
Total Long-Term Liabilities		1,649		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 33,030,615 and 29,479,697 shares,       outstanding 32,930,815 and 29,379,897 shares		330		295
Additional paid-in capital		121,188		89,680
Retained earnings / (accumulated deficit)		634		(4,622	)
Less treasury stock, at cost, 99,800 shares		(246	)	(246	)
Accumulated other comprehensive loss, net of tax		(2,402	)	(1,826	)
Total Stockholders' Equity		119,504		83,281
Total Liabilities and Stockholders' Equity		$144,705		$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)	June 30, 2006			June 30, 2005
Revenues
Oil and gas sales		$15,854		$8,877
Gas gathering operations		3,678		6,580
Other operating income		20		14
Total Revenues		19,552		15,471
Costs and Expenses
Lease operations		1,869		1,723
Production taxes		779		529
Exploration expenses		195		839
Impairment and abandonments		618		590
Gas gathering operations		3,625		6,250
Depreciation, depletion and amortization		3,627		3,628
General and administrative		1,888		1,344
Total Costs and Expenses		12,601		14,903
Income from Operations		6,951		568
Other Income (Expense)
Derivative mark-to-market gain (loss)		474		(336	)
Derivative settlements loss		(958	)	(285	)
Interest expense		(49	)	(932	)
Interest income		175		12
Loan fee amortization		(49	)	(20	)
Loss on sale of assets		(11	)	-
Total Other Income (Expense)		(418	)	(1,561	)
Income (loss) before income taxes		6,533		(993	)
Income tax expense		2,552		25
Net Income (Loss)		$3,981		$(1,018	)
Earnings (Loss) Per Share
Basic earnings (loss) per share		$0.12		$(0.04	)
Diluted earnings (loss) per share		$0.12		$(0.04	)
See notes to consolidated financial statements
4

THE EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
	Six Months Ended			Six Months Ended
(in thousands, except earnings per share data)	June 30, 2006			June 30, 2005
Revenues
Oil and gas sales		$26,323		$16,561
Gas gathering operations		9,218		13,507
Other operating income		35		20
Total Revenues		35,576		30,088
Costs and Expenses
Lease operations		3,512		3,408
Production taxes		1,290		991
Exploration expenses		640		1,351
Impairment and abandonments		1,094		1,155
Gas gathering operations		9,376		12,822
Depreciation, depletion and amortization		6,353		6,109
General and administrative		3,561		2,523
Total Costs and Expenses		25,826		28,359
Income from Operations		9,750		1,729
Other Income (Expense)
Derivative mark-to-market gain (loss)		468		(3,733	)
Derivative settlements loss		(1,591	)	(453	)
Interest expense		(136	)	(1,802	)
Interest income		213		24
Loan fee amortization		(122	)	(36	)
Loss on sale of assets		(11	)	-
Total Other Income (Expense)		(1,179	)	(6,000	)
Income (loss) before income taxes		8,571		(4,271	)
Income tax expense		3,315		50
Net Income (Loss)		$5,256		$(4,321	)
Earnings (Loss) Per Share
Basic earnings (loss) per share		$0.17		$(0.15	)
Diluted earnings (loss) per share		$0.16		$(0.15	)
See notes to consolidated financial statements
5

THE EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
	Six Months Ended			Six Months Ended
(in thousands)	June 30, 2006			June 30, 2005
Operating Activities
Net income (loss)		$5,256		$(4,321	)
Adjustments to reconcile net income (loss) to    net cash provided by operating activities:
Depreciation, depletion and amortization		6,475		6,145
Impairment and abandonments		1,094		1,155
Loss on sale of assets		11		-
Non-cash stock compensation expense		616		-
Non-cash derivative mark-to-market (gain) loss		(468	)	3,733
Non-cash interest expense and accretion of liability        - redeemable preferred stock		- -		530
Changes in operating assets and liabilities:
Receivables		555		62
Prepaid expenses and other		(1,670	)	(1,034	)
Accounts payable and accrued expenses		(1,569	)	3,338
Deferred tax asset		(400	)	-
Net cash provided by operating activities		9,900		9,608
Investing Activities
Development and purchases of oil and gas properties		(18,632	)	(17,924	)
Purchase of other equipment		(4,894	)	(19	)
Proceeds from sale of assets		19		-
Net cash (used) by investing activities		(23,507	)	(17,943	)
Financing Activities
Proceeds from issuance of common stock, net of expenses		30,233		1,296
Proceeds from long-term debt obligations		9,300		7,300
Payments on long-term debt obligations		(9,300	)	-
Proceeds from installment obligations		178		122
Payments on installment obligations		(211	)	(1,618	)
Net cash provided by financing activities		30,200		7,100
Change in Cash and Equivalents		16,593		(1,235	)
Cash and equivalents at beginning of period		6,083		3,118
Cash and Equivalents at End of Period		$22,676		$1,883
See notes to consolidated financial statements
6

THE EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PERIODS ENDED JUNE 30, 2006 AND JUNE 30, 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's Annual Report on Form 10-K for 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 Company's Annual Report on Form 10-K for the year ended December 31, 2005.
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, 2005. Total stock-based compensation expense recognized in the first six months of 2006 was $616,000, while the related tax benefit recognized was $228,000. No comparable expense was recognized in the prior year.
As of June 30, 2006, the Company had outstanding options to purchase 1,235,500 shares of common stock at prices ranging from $0.98 to $5.00 per share. Of these, 1,050,500 were exercisable at quarter end. The options expire at various dates through September 2014.
Additionally, at June 30, 2006, the Company had outstanding exercisable warrants to purchase 966,500 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 were granted in 2005 or 2006. The Board has moved to utilizing restricted stock grants in lieu of stock options.
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.
7
2.     Stock-based Compensation - continued
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 periods shown:
																																						Three													Six
Periods Ended June 30, 2005:																																						Months													Months
(in thousands, except per share data)
Net loss as reported																																						$(1,018										)			$(4,321									)
Deduct: Total stock-based compensation expense (benefit) determined under the fair    value based method for all awards, net of related tax effects																																						(124										)			(124									)
Pro forma loss																																						$(894										)			$(4,197									)
Loss per common share:
Basic, as reported																																						$(0.04										)			$(0.15									)
Basic, pro forma																																						(0.03										)			(0.15									)
Diluted, as reported																																						(0.04										)			(0.15									)
Diluted, pro forma																																						(0.03										)			(0.15									)
The Company adopted Statement of Financial Accounting Standards ("SFAS") No. 123 (revised 2004), "Share-Based Payment" ("SFAS No. 123R"), on January 1, 2006, using the modified-prospective transition method. SFAS No. 123R requires the measurement of compensation expense for the unvested portion of previously granted awards and any new awards using the grant date fair value and recording of such expense in the financial statements over the vesting period. The Company used the Black-Scholes option pricing model to compute the fair value which required the Company to make assumptions, as follows:
-   The risk-free interest rate was based on the five-year U.S. Treasury bond rate at the date of grant.    -   The dividend yield on the Company's common stock was assumed to be zero since the Company does not pay dividends and has no current plans to do so in the future.    -   The market price volatility is computed in accordance with SFAS No. 123R.    -   The term of the grants represents the weighted-average period that the stock options are expected to be outstanding.
For any future stock options awarded:    -   the market price volatility will be based on historical prices for a period equal to the grant term.    -   the grant term will be computed using the simplified method described in Staff Accounting Bulletin No. 107.
Compensation expense of $129,600 is being expensed over the first nine months of 2006, which represents the remaining vesting period, for the unvested portion of options outstanding at December 31, 2005.
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, 2005											1,254											$2.86										4.3																				$4,511
Granted											-											-
Exercised											13											4.91
Forfeited or Expired											5											5.00
Outstanding at June 30, 2006 **											1,236											$2.83										3.8																				$8,239
Exercisable at June 30, 2006											1,051											$2.72										3.6																				$7,119
*    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.
The total intrinsic value of options exercised during the six months ended June 30, 2006, was $78,600, and the Company received $65,000 in cash in connection with these exercises.
8
2.     Stock-based Compensation - continued
Restricted Stock: During the first quarter of 2006, the Company granted 349,000 shares of restricted stock as compensation to employees and non-employee directors under its 2005 Stock Incentive Plan. Of these, 42,000 shares with a fair value of $369,000 vest in one year, while 307,000 with a fair value of $2.7 million vest over a three-year period. The fair value is recognized as stock compensation expense 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, 2005																									-
Granted																									349											$9.00
Vested																									*											8.79
Forfeited																									6											8.79
Unvested restricted stock at June 30, 2006																									343											$9.00
*  500 shares vested upon the death of an employee.
Stock Used to Acquire Goods or Services: During the second quarter of 2006, the Company issued 61,335 shares of its common stock to buy out an overriding royalty interest in certain of its leases.
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:
								2006																							2005
(In thousands, except per share data)								Shares *							Income								Per Share Amount								Shares *													(Loss)											Per Share Amount
Three Months Ended June 30
Basic EPS:
Net income (loss)								32,921							$3,981								$0.12								28,365													$(1,018									)		$(0.04								)
Effect of dilutive options								1,170							-								-								n/a													-											-
Dilutive EPS								34,091							$3,981								$0.12								28,365													$(1,018									)		$(0.04								)
Six Months Ended June 30
Basic EPS:
Net income (loss)								31,340							$5,256								$0.17								28,271													$(4,321									)		$(0.15								)
Effect of dilutive options								2,279							-								0.01								n/a													-											-
Dilutive EPS								33,619							$5,256								$0.16								28,271													$(4,321									)		$(0.15								)
* Weighted average shares outstanding													n/a - not applicable due to net loss for the period.
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 37% and 0.0% for the three months ended June 30, 2006, and June 30, 2005, respectively.
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.
9
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.
The outstanding hedges at June 30, 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									June 30,														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									$(1,527												)		$(1,995													)
Derivatives treated as cash flow hedges:
06/05			Fixed Price			11/01/2006				04/30/2007								$56.70								13,000									(1,483												)		(550													)
Total fair value of derivative contracts																																			$(3,010												)		$(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- and six-month periods ended June 30, 2006, and 2005:
																			Three Month Period																				Six Month Period
(in thousands)																								2006						2005									2006													2005
Net income (loss)																								$3,981						$(1,018							)		$5,256													$(4,321							)
Other comprehensive income (loss):
Change in fair value of cash flow hedges																								(508				)		(417							)		(933											)		(416							)
Change in income tax benefit of cash flow hedges																								188						14									357													14
Total comprehensive income (loss)																								$3,661						$(1,421							)		$4,680													$(4,723							)
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.
10
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 June 30, 2006, the borrowing base, inclusive of tranche A and tranche B, was $29.0 million. At June 30, 2006, only $1,000 was outstanding at an interest rate of 8.25%. 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 interest rate at June 30, 2006, was 8.25% computed in accordance with (b) above.
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 June 30, 2006.
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, and Management's Discussion and Analysis, as reported in its Form 10-K for the year ended December 31, 2005. 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 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 MarketSM under the symbol "TXCO."
We currently have four drilling rigs under contract and in operation on our extensive 650,000-acre position in the Maverick Basin and one rig operating in the Marfa Basin. Our emphasis thus far this year has been on the Glen Rose, Georgetown and San Miguel formations. We began 32 new wells and six re-entries through July 2006, including 18 in the Glen Rose Porosity. We are beginning exploration activities in the Marfa Basin in the third quarter of 2006 with our partner for this project, Continental Resources, Inc., of Enid, Okla., targeting the Barnett and Woodford Shale formations. The drilling rig we purchased in March 2006 is currently undergoing refurbishment and is expected to be placed in service later in the third quarter. 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 improvem ents.
11
Due to the number of promising prospects on our Maverick Basin acreage, as well as higher oil and gas prices, drilling activity has remained high over 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, 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 recognition of reserves.
Net income was $4.0 million or $0.12 per diluted share for the quarter ended June 30, 2006, and $5.3 million or $0.16 per diluted share for the six months ended June 30, 2006. These compare with net losses of $1.0 million or $0.04 per diluted share for the prior-year quarter, and $4.3 million or $0.15 per diluted share for the six months ended June 30, 2005. Operating income increased by $6.4 million and $8.0 million for the quarter and year-to-date periods, as compared to the same periods in the prior year, due to increased volumes and product pricing. Net hedging losses decreased by $0.1 million and $3.1 million for the three- and six-month periods of 2006, from the prior-year periods, favorably impacting net income. Sales volumes were up 29.0% and 13.8% on a barrels of oil equivalent ("BOE") basis during second-quarter and first-half of 2006, as compared with the prior-year periods, despite the September 2005 sale of approximately 20% of then current total production. Lower interest ex pense also contributed to the improvement in net income. These factors are discussed in "Results of Operations."
SFAS No. 123(R) required the recording of non-cash compensation expense in 2006 for stock-based compensation that reduced earnings per diluted share by $0.01 for second-quarter 2006, and $0.02 for first-half 2006. No comparable expense was recognized during the 2005 periods.
Net cash provided by operating activities for first-half 2006 was $9.9 million, as compared to $9.6 million for first half 2005. Net cash provided by operating activities, excluding changes in operating assets and liabilities, was $13.0 million for the first six months of 2006, up from $7.2 million during the 2005 period.
														Second Quarter																						First Half
Operational Data														2006						2005							Change									2006										2005									Change
Oil  sales volumes (mBbls)														208						81							+	157.6					%			346										156									+		122.1				%
Gas sales volumes (MMcf)														293						710							-	58.7					%			586										1,404									-		58.3				%
Combined sales volumes (mBOE)														257						199							+	29.0					%			443										389									+		13.8				%
Net residue and NGL sales volumes (MMbtu)														394,671						754,860							-	47.7					%			1,046,705										1,562,559									-		33.0				%
Oil average realized sales price Bbl														$66.35						$49.79							+	33.3					%			$63.40										$47.86									+		32.5				%
Gas average realized sales price per Mcf														$7.03						$6.84							+	2.8					%			$7.54										$6.50									+		16.2				%
Residue & NGL average realized sales       price per MMbtu														$8.65						$8.51							+	1.7					%			$8.41										$8.45									- -		0.5				%
Oil  - average daily sales (BOPD)														2,284						887							+	157.6					%			1,909										859									+		122.1				%
Gas - average daily sales (Mcfd)														3,221						7,803							-	58.7					%			3,236										7,754									-		58.3				%
Combined average daily sales (BOED)														2,821						2,187							+	29.0					%			2,448										2,152									+		13.8				%
Subsequent Events: On August 1, 2006, the Nasdaq became operational as a national securities exchange. As a result of this change, our common stock is now registered under Section 12(b) of the Securities Exchange Act of 1934 instead of Section 12(g) of that Act. On August 2, 2006, we were notified that our application to move our listing from the Nasdaq Capital Market to the Nasdaq Global Select Market has been approved. This move will be effective upon payment of an additional entry fee, which we expect to remit during the third quarter of 2006.
12
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 our credit 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 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. 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 June 30, 2006, the borrowing base, inclusive of tranche A and tranche B, was $29.0 million. At June 30, 2006, only $1,000 was outstanding at an interest rate of 8.25%. 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.
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 June 30, 2006, we were in compliance with all covenants.
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 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 $29.8 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 in the Glen Rose Porosity, as well as other new projects. See "Part II, Item 2 - Unregistered Sales of Equity Securities and Use of Proceeds" in our Form 10-Q filed with the SEC on May 10, 2006, for additional information.
Outlook: We believe the Facility, 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 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.
13
Risk Management Activities -- Commodity Hedging Contracts: Due to the volatility of oil and natural gas prices and former requirements under our bank credit facility, we from time to time 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 af ter 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-half 2006, cash provided by operating activities was $9.9 million. In addition, net proceeds from the private placement of common stock of $29.8 million, borrowings under the Facility of $9.3 million, and proceeds from the exercise of options and warrants totaling $0.5 million, resulted in total cash available of $55.6 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.
During second-quarter 2006, payments on debt totaled $9.4 million in principal, with interest payments of $97,000. We applied $8.9 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 second quarter of 2006 with positive working capital of $14.6 million compared to negative working capital of $4.9 million at December 31, 2005. At June 30, 2006, with the same adjustment, our current ratio was 1.72 to 1 compared to 0.78 to 1 at year-end 2005. Including the $3.3 million of derivative current liabilities at June 30, 2006, positive working capital was $11.2 million with a current ratio of 1.48 to 1. At year-end 2005, including the $2.2 million of derivative current liabilities, negative working capital was $7.2 million, while the current ratio was 0.70 to 1.
We completed the second quarter of 2006 with an unused borrowing base of $29 million under our Facility. First-half 2006 cash provided by operating activities, including changes in operating assets and liabilities, was $9.9 million, compared to $9.6 million in the prior-year period. Before changes in operating assets and liabilities, first-half 2006 cash flow from operating activities was $13.0 million compared to $7.2 million for first-half 2005, a 80.6% increase. Changes in operating assets and liabilities include increases or decreases in receivables, accounts payable and prepaid expenses from the prior year-end balances.
14
Results of Operations
The following table highlights the change for 2006 from the comparable periods in 2005:
														Second Quarter																			First Six Months
Selected Income Statement Items:														$ thousands													%						$ thousands																							%
Oil and gas revenues														+		6,977									+		78.6						+										9,762									+				58.9
Lease operating expense														+		146									+		8.5						+										104									+				3.0
Depreciation, depletion & amortization														-		1									-		0.0						+										244									+				4.0
Income from operations														+		6,383									+		1,123.8						+										8,021									+				463.9
Derivative mark-to-market gain / loss														-		810											n/m						-										4,201													n/m
Derivative settlements loss														+		673									+		236.1						+										1,138									+				251.2
Net income														+		4,999											n/m						+										9,577													n/m
n/m - % change not meaningful due to move from loss to income/gain
The following table summarizes the change for 2006 from the comparable periods in 2005:
																	Second Quarter																					First Six Months
Change in Gas Gathering Results:																				$ thousands									%												$ thousands													%
Revenues:
Third-party natural gas sales																	-					2,124							-			41.7									-			2,860										-			27.2
Natural gas liquids sales																	-					885							-			66.4									-			1,549										-			57.6
Transportation and other revenue																	+					107							+			68.1									+			120										+			39.9
Total gas gathering revenues																	-					2,902							-			44.1									-			4,289										-			31.8
Expense:
Third-party gas purchases																	-					2,545							-			42.7									-			3,324										-			27.2
Transportation and marketing expenses																	-					49							-			68.2									-			103										-			68.4
Direct operating costs																	-					31							-			14.1									-			19										-			4.4
Total gas gathering operations expense																	-					2,625							-			42.0									-			3,446										-			26.9
Gross margin																	-					277							-			83.9									-			843										-			n/m
Operational data
Total sales volumes (MMBtu)																	-					360							-			47.7									-			516										-			33.0
Average sales price (per MMBtu)																	+					0.14							+			1.7									-			0.05										-			0.5
n/m - % change not meaningful due to move from income to loss
Three Months Ended June 30, 2006, Compared with Three Months Ended June 30, 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 157.6% primarily due to Glen Rose Porosity wells put on production since June 30, 2005. This increase was partially offset by 58.7% lower gas volumes, 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. In addition, due to our focus on drilling oil wells this year, we are not replacing gas-specific reserves at the present time. Sales volumes increased 29.0% on a BOE basis. Average realized sales prices for oil and natural gas were up 33.3% and 2.8%, respectively.
Lease Operations
The 8.5% increase in lease operating expenses primarily reflects costs related to new Maverick Basin oil and gas wells placed on production since June 30, 2005, and cost increases related to the high demand for services in field operations, partially offset by the elimination of costs related to wells sold to EnCana.
15
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 44.1% 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 and a partner's election to market their gas rather than sell it through TXCO.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization remained constant, as costs related to new wells placed on production were offset by the elimination of wells sold to EnCana.
General and Administrative ("G&A")
																	Second Quarter																				Change from prior
																							2006					2005												year period
Non-cash, stock compensation expense																							$363.6					$  -												+				$363.6								100.0						%
Other G&A expense																							1,524.7					1,344.3												+				180.4								13.4						%
Total G&A expense																							$1,888.3					$1,344.3												+				$544.1								40.5						%
G&A expense represents approximately 9.7% of total revenues. The increase was primarily due to non-cash stock compensation expense related to restricted stock grants during first-quarter 2006, and unvested stock options that are now required to be expensed by SFAS No. 123R. No comparable expenses were recorded during 2005. Excluding the stock compensation expense, G&A would have represented 7.8% of total revenues.
Salary-related costs were up $0.1 million related to four additional full-time employees hired since June 30, 2005, with associated salaries, wages and benefits, along with merit increases across the organization.
Derivative Gain / Loss
A non-cash, mark-to-market gain was accrued on hedges of future sales volumes. This is a $0.8 million change from the loss recorded in the prior-year period. This was due to the elimination of the natural gas hedges during October 2005, and the short remaining period on the oil hedge. Derivative settlement losses on the closed periods amounted to $1.0 million, up from $0.3 million, bringing the net pre-tax hedging loss to $0.5 million, as compared to $0.6 million in the prior-year quarter.
Interest Expense
Interest expense decreased by $0.9 million due to lower levels of borrowings under the Facility.
Six Months Ended June 30, 2006, Compared with Six Months Ended June 30, 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 122.1% primarily due to Glen Rose Porosity wells put on production since June 30, 2005. This increase was offset by 58.3% lower gas production, reflecting the sale of a portion of our gas production to EnCana in September 2005 and normal maturing gas well decline curves. In addition, due to our focus on drilling oil wells this year, we are not replacing gas-specific reserves at the present time. Sales volumes increased 13.8% on a BOE basis. Average realized sales prices for oil and natural gas were up 32.5% and 16.2%, respectively.
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Lease Operations
The 3.0% increase in lease operating expenses reflects costs related to new Maverick Basin oil and gas wells placed on production since June 30, 2005, and cost increases related to the high demand for services in field operations, partially offset by the elimination of costs related to wells sold to EnCana.
Gas Gathering
Gas gathering operations revenues decreased 31.8% 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 and a partner's election to market their gas rather than sell it through TXCO.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization increased 4.0%. The major component of this increase was higher depletion, up $0.5 million, which was offset by lower 3-D seismic amortization related to projects retired in conjunction with the sale of assets to EnCana. The increase in depletion 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 ("G&A")
																	First Six Months																					Change from prior
																								2006					2005											year period
Non-cash, stock compensation expense																								$616.0					$  -											+		$616.0									100.0						%
Other G&A expense																								2,944.9					2,523.5											+		421.4									16.7						%
Total G&A expense																								$3,560.9					$2,523.5											+		$1,037.4									41.1						%
G&A represents approximately 10.0% of total revenues. The increase was primarily due to non-cash stock compensation expense 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. Excluding the stock compensation expense, G&A would have represented 8.3% of total revenues.
Salary-related costs were up $0.3 million related to four additional full-time employees hired since June 30, 2005, with associated salaries, wages and benefits, along with merit increases throughout the organization.
Derivative Gain / Loss
A non-cash, mark-to-market gain of $0.5 million accrued on hedges of future sales volumes compares with a $3.7 million non-cash, mark-to-market loss in the prior-year period. The change is primarily due to the elimination of the natural gas hedges during October 2005 and lower remaining hedged oil volumes. Derivative settlement losses on the closed periods amounted to $1.6 million, up from $0.5 million, bringing the net pre-tax hedging loss to $1.1 million, as compared to $4.2 million in the prior-year period.
Interest Expense
Interest expense decreased by $1.6 million due to lower levels of borrowings under the Facility.
17
Drilling Activities
We drilled or participated in drilling 30 wells on our lease block in the Maverick Basin in first-half 2006, with 22 in the second quarter. At June 30, 2006, 11 of these wells were producing, 16 wells were in completion, and three wells remained drilling. Additionally, two wells that were in progress at year-end 2005 were placed on production in 2006. First-half 2006 wells focused primarily on the Glen Rose and San Miguel formations. By comparison, we participated in 28 wells during first-half 2005 targeting the Georgetown, San Miguel and Glen Rose intervals. The following table shows net daily sales for the periods presented:
												Second Quarter																							First Six Months
Average net daily sales volumes :												2006				2005								Change											2006							2005								Change
Oil, BOPD												2,284				887								+157.6%											1,909							859								+122.1%
Natural gas, Mcfd												3,221				7,803								-58.7%											3,236							7,754								-58.3%
Oil equivalent, BOED												2,821				2,187								+29.0%											2,448							2,152								+13.8%
In July 2006, TXCO spud six wells, four of which target the San Miguel formation, bringing total wells spud in 2006 to 36. At July 31, 2006, 14 of these wells were producing, 19 wells were in completion, and three wells remained drilling.
Our oil production continues to rise as the result of our successful drilling program in the Glen Rose Porosity. Porosity oil production temporarily outstripped available transportation facilities during first quarter 2006, creating an 11,100-barrel inventory at the end of that quarter. Inventories returned to a more typical level during second-quarter 2006. During the second quarter, we added tankage and arranged for increased transport services, which positively impacted sales levels.
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-half 2006, as only one new gas well was put on production to offset declines on maturing wells.
There are five 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 placed in service in the third quarter.
Glen Rose Porosity - During first-half 2006, we drilled 17 Porosity wells, up from four in first-half 2005. Currently of the 17 total wells, eight are producing, seven are in completion, and one continues drilling, while one well stopped prior to reaching its Porosity target after encountering gas in a shallower zone and was transferred to an operating partner. Glen Rose Porosity average daily sales for second-quarter 2006 were 2,019 BOPD, compared to 1,184 BOPD for the prior quarter and 335 BOPD for the prior-year quarter. Glen Rose Porosity average daily sales for first-half 2006 were 1,604 BOPD, compared with 308 BOPD for first-half 2005.
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 July 2006, we began drilling on one new porosity well.
Glen Rose Shoal/Reefs - During first-half 2006, we drilled one shoal and one reef well. Currently the shoal well is in completion, while the reef well is producing natural gas. One well targeting a Glen Rose Reef was started in first-half 2005 and was later completed in the Georgetown formation.
Glen Rose average daily sales for second-quarter 2006, excluding Porosity production, were 26 BOPD and 2.9 MMcfd, compared to 15 BOPD and 2.9 MMcfd for the prior quarter and 25 BOPD and 4.2 MMcfd for the prior-year quarter. First-half 2006 Glen Rose average daily sales, excluding Porosity production were 20 BOPD and 2.9 MMcfe, compared with 22 BOPD and 4.3 MMcfd for the prior-year period. We currently plan to drill four new shoal/reef wells during 2006.
18
Georgetown - We started two Georgetown wells during first-half 2006, down from 13 projects in the prior-year period. One of the 2006 wells is producing, while the other is in completion. We reentered one Georgetown well in July that is currently in completion. Our 2006 CAPEX budget includes 10 wells. Georgetown average daily sales for second-quarter 2006 were 40 BOPD and 0.2 MMcfd, compared to 58 BOPD and 0.2 MMcfd for the prior quarter, and 193 BOPD and 3.2 MMcfd for the prior-year quarter. First-half 2006 Georgetown average daily sales were 49 BOPD and 0.2 MMcfd, compared with 188 BOPD and 3.1 MMcfd for the prior-year period.
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 continue to hold a 100% working interest in the Georgetown formation across most of the northern portion of our leaseblock.
Pena Creek San Miguel - San Miguel average daily sales for second-quarter 2006 were 141 BOPD with no gas, compared to 204 BOPD with no gas for the prior quarter, and 241 BOPD with 11 Mcfd for the prior-year quarter. We started eight San Miguel wells during first-half 2006, compared with five during first-half 2005. During July 2006 we began four additional wells. Of the 12 total San Miguel wells started this year, currently four are producing, seven are in completion and one continues drilling. The decline in sales from the prior periods reflect the reservation of some oil production in preparation for fracturing wells in the play during the second quarter and third quarters of 2006, as well as the impact of wells that were off-line. Our CAPEX budget calls for 10 Pena Creek San Miguel wells in 2006.
San Miguel Tar Sand - We expect to begin development of the Tar Sand with our partner, Pearl Exploration and Production Ltd., in second-half 2006. Our CAPEX budget calls for 26 Tar Sand wells in 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 as operator. We currently expect a well targeting the Pearsall to begin drilling in August 2006. 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, 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. One re-entry and one new well are currently planned for 2006. We expect development of our new Marfa Basin acreage to begin in August with a re-entry of the El Paso Simpson 4 well bore.
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 our Form 10-K for the year ended December 31, 2005, and the additional risk factors 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.
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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 June 30, 2006, we had borrowings under our bank credit facility of $1,000. Assuming an increase in either the LIBOR or prime rate of interest of 100 basis points, interest expense would not increase materially.
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 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.
The following is a list of derivative contracts outstanding as of June 30, 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 June 30, 2006, the fair value of the outstanding hedges was a liability of approximately $3.3 million. A 10% change in the commodity price per unit would cause the fair value of the hedges to increase or decrease by approximately $330,000.
For additional information, see also our Annual 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.
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We have established disclosure controls and procedures to ensure that material information relating to us, including our consolidated subsidiaries, is made known 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 June 30, 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.
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 occurred.
ITEM 1A.     RISK FACTORS
Except as set forth below, there have been no material changes from the risk factors previously disclosed in our 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 pipelines and 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.
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-	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
Pursuant to agreements 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.
On April 7, 2006, we issued 61,335 shares of our common stock to purchase an overriding royalty interest in certain of our Marfa Basin oil and gas leases.
Both of the foregoing private placements were made in reliance on Section 4(2) of the Securities Act of 1933, as amended, and the rules and regulations promulgated thereunder, as the transactions did not involve a public offering and were sold to a limited group of investors.
ITEM 3.      DEFAULTS UPON SENIOR SECURITIES
None
ITEM 4.      SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On May 12, 2006, the Company held its Annual Meeting of Shareholders at the Petroleum Club of San Antonio, pursuant to the notice mailed to shareholders of record on April 3, 2006. The following matters were submitted for approval by vote at the meeting. All matters were approved by the shareholders' vote and the results of the voting are shown below for each matter.
1.		Election of two Class A Directors to serve for two-year terms expiring in 2008, and two Class B Directors to serve for three-year terms expiring in 2009:
		Nominee						For										Withheld
		Class A:
		Dennis B. Fitzpatrick						24,601,412										476,422
		Jon Michael Muckleroy						24,985,154										92,680
		Class B:
		Stephen M. Gose, Jr.						24,880,010										197,824
		Alan L. Edgar						24,987,329										90,505
There were no changes in Directors of the Company.
2.		Proposal to ratify the appointment of Akin, Doherty, Klein & Feuge, P.C., certified public accountants, as independent auditors of the Company and its subsidiaries for the calendar year ending December 31, 2006:
		For		Against			Abstain
		24,864,447		191,620			21,766
ITEM 5.      OTHER INFORMATION
None
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ITEM 6.      EXHIBITS
a)     Exhibit 10.1 Purchase Agreement between The Exploration Company of Delaware, Inc. and several investors, incorporated by reference to Exhibit 10.1 of our Form 8-K on April 5, 2006.
b)     Exhibit 10.2 Registration Rights Agreement between The Exploration Company of Delaware, Inc. and several investors, incorporated by reference to Exhibit 10.2 of our Form 8-K on April 5, 2006.
c)     Exhibit 31.1   Certification of Chief Executive Officer required pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended filed herewith.
d)     Exhibit 31.2   Certification of Chief Financial Officer required pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended filed herewith.
e)     Exhibit 32.1   Certification of Chief Executive Officer required pursuant to 18 U.S.C. Section 1350 as required by the Sarbanes-Oxley Act of 2002 filed herewith.
f)     Exhibit 32.2   Certification of Chief Financial Officer required pursuant to 18 U.S.C. Section 1350 as required by the Sarbanes-Oxley Act of 2002 filed herewith.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
																			THE EXPLORATION COMPANY
																			(Registrant)
																			/s/ P. Mark Stark
																			P. Mark Stark,
																			Chief Financial Officer
Date:  August 9, 2006
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EX-31

Exhibit 31.1
Certification
I, James E. Sigmon, certify that:
1.	I have reviewed this Quarterly Report on Form 10-Q of The Exploration Company of Delaware, Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b)  Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
	(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:	August 9, 2006
	/s/ James E. Sigmon
	James E. Sigmon President and Chief Executive Officer

EX-31

Exhibit 31.2
Certification
I, P. Mark Stark, certify that:
1.	I have reviewed this Quarterly Report on Form 10-Q of The Exploration Company of Delaware, Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b)  Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.	The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
	(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date:	August 9, 2006
	/s/ P. Mark Stark
	P. Mark Stark Vice President and Chief Financial Officer

EX-32

Exhibit 32.1
Certification
In connection with the Quarterly Report of The Exploration Company of Delaware, Inc. (the "Company") on Form 10-Q for the period ended June 30, 2006 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, James E. Sigmon, Chief Executive Officer of the Company, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
1.     The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2.     The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
	/s/  James E. Sigmon
	Name:  James E. Sigmon
	Title:    Chief Executive Officer
	Date:    August 9, 2006
The foregoing certification is being furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and is not being filed as part of the Report.
A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32

Exhibit 32.2
Certification
In connection with the Quarterly Report of The Exploration Company of Delaware, Inc. (the "Company") on Form 10-Q for the period ended June 30, 2006 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, P. Mark Stark, Chief Financial Officer of the Company, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
1.     The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2.      The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
	/s/ P. Mark Stark
	Name: P. Mark Stark
	Title:  Chief Financial Officer
	Date:   August 9, 2006
The foregoing certification is being furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and is not being filed as part of the Report.
A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.