W&T Offshore (WTI) 10-Q 2007 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2007

OR

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

For the transition period from                        to                        

Commission File Number 1-32414

W&T OFFSHORE, INC.

(Exact name of registrant as specified in its charter)

Texas	72-1121985
(State of incorporation)	(IRS Employer Identification Number)
Nine Greenway Plaza, Suite 300
Houston, Texas	77046-0908
(Address of principal executive offices)	(Zip Code)

(713) 626-8525

(Registrant’s telephone number, including area code)

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¨

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¨                          Accelerated filerþ                             Non-accelerated filer¨

Indicate by check mark whether the registrant is a shell company.      Yes¨ Noþ

As of November 8, 2007, there were 76,227,604 shares outstanding of the registrant’s common stock, par value $0.00001.

W&T OFFSHORE, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets as of September 30, 2007 and December 31, 2006	1
	Condensed Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2007 and 2006	2
	Condensed Consolidated Statement of Changes in Shareholders’ Equity for the Nine Months Ended September 30, 2007	3
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2007 and 2006	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	19
Item 4.	Controls and Procedures	20
PART II—OTHER INFORMATION
Item 1A.	Risk Factors	20
Item 6.	Exhibits	22
SIGNATURE		23
EXHIBIT INDEX		24

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30, 2007			December 31, 2006
	(In thousands, except share data)
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	187,807		$	39,235
Receivables:
Oil and gas sales		77,933			98,362
Joint interest and other		57,560			50,681
Insurance		—			75,151
Income taxes		—			15,705
Total receivables		135,493			239,899
Prepaid expenses and other assets		42,594			49,559
Total current assets		365,894			328,693
Property and equipment—at cost:
Oil and gas property and equipment (full cost method, of which $286,535 at September 30, 2007 and $308,231 at December 31, 2006 were excluded from amortization)		3,575,536			3,297,153
Furniture, fixtures and other		10,711			10,948
Total property and equipment		3,586,247			3,308,101
Less accumulated depreciation, depletion and amortization		1,399,196			1,042,315
Net property and equipment		2,187,051			2,265,786
Restricted deposits for asset retirement obligations		10,463			10,680
Other assets		6,290			4,526
Total assets	$	2,569,698		$	2,609,685
Liabilities and Shareholders’ Equity
Current liabilities:
Current maturities of long-term debt	$	3,000		$	271,380
Accounts payable		123,566			247,324
Undistributed oil and gas proceeds		51,829			46,933
Asset retirement obligations—current portion		24,762			41,718
Accrued liabilities		27,364			28,825
Income taxes		22,164			—
Deferred income taxes—current portion		—			7,896
Total current liabilities		252,685			644,076
Long-term debt, less current maturities—net of discount		652,160			413,617
Asset retirement obligations, less current portion		281,632			272,350
Deferred income taxes, less current portion		242,579			232,835
Other liabilities		5,553			3,890
Commitments and contingencies
Shareholders’ equity:
Common stock, $0.00001 par value; 118,330,000 shares authorized; issued and outstanding 76,227,713 and 75,900,082 shares at September 30, 2007 and December 31, 2006, respectively		1			1
Additional paid-in capital		366,219			361,855
Retained earnings		769,670			681,634
Accumulated other comprehensive loss		(801	)		(573	)
Total shareholders’ equity		1,135,089			1,042,917
Total liabilities and shareholders’ equity	$	2,569,698		$	2,609,685

See Notes to Condensed Consolidated Financial Statements.

1

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
	(In thousands, except per share data)
	(Unaudited)
Revenues	$	255,191		$	213,431		$	774,293		$	536,082
						��
Operating costs and expenses:
Lease operating expenses		51,627			35,227			169,154			68,704
Production taxes		1,263			369			3,857			546
Gathering and transportation		4,520			4,817			10,769			11,148
Depreciation, depletion and amortization		117,539			82,142			356,881			194,052
Asset retirement obligation accretion		5,574			3,324			16,477			7,840
General and administrative expenses		9,952			8,845			29,240			28,164
Derivative loss (gain)		2,809			(27,065	)		15,082			(21,793	)
Total costs and expenses		193,284			107,659			601,460			288,661
Operating income		61,907			105,772			172,833			247,421
Interest expense:
Incurred		14,332			9,876			47,774			10,514
Capitalized		(6,024	)		(4,138	)		(19,117	)		(4,138	)
Loss on extinguishment of debt		—			—			2,806			—
Other income		1,567			2,111			2,508			5,505
Income before income taxes		55,166			102,145			143,878			246,550
Income taxes		18,826			35,444			48,988			85,553
Net income	$	36,340		$	66,701		$	94,890		$	160,997
Earnings per common share:
Basic	$	0.48		$	0.92		$	1.25		$	2.36
Diluted		0.48			0.91			1.25			2.35
Dividends declared per common share		0.03			—			0.09			0.06

See Notes to Condensed Consolidated Financial Statements.

2

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

	Common				Additional Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Loss			Total Shareholders’ Equity
	Shares		Value
	(In thousands)
	(Unaudited)
Balances at December 31, 2006	75,900		$	1	$	361,855		$	681,634		$	(573	)	$	1,042,917
Cash dividends	—			—		—			(6,854	)		—			(6,854	)
Share-based compensation	—			—		2,491			—			—			2,491
Restricted stock issued, net of forfeitures	339			—		2,229			—			—			2,229
Shares surrendered for payroll taxes	(11	)		—		(356	)		—			—			(356	)
Net income	—			—		—			94,890			—			94,890
Other comprehensive income, net of tax	—			—		—			—			(228	)		(228	)
Balances at September 30, 2007	76,228		$	1	$	366,219		$	769,670		$	(801	)	$	1,135,089

See Notes to Condensed Consolidated Financial Statements.

3

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine Months Ended September 30,
	2007			2006
	(In thousands)
	(Unaudited)
Operating activities:
Net income	$	94,890		$	160,997
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		373,358			201,892
Amortization of debt issuance costs and discount on indebtedness		5,840			3,238
Loss on extinguishment of debt		2,806			—
Share-based compensation related to restricted stock issuances		2,491			2,177
Unrealized derivative loss (gain)		21,360			(15,224	)
Deferred income taxes		92			65,977
Other		746			—
Changes in operating assets and liabilities:
Oil and gas receivables		20,429			(34,599	)
Joint interest and other receivables		(7,240	)		3,617
Insurance receivables		75,151			(36,449	)
Income taxes		37,869			19,575
Prepaid expenses and other assets		(1,199	)		(39,306	)
Asset retirement obligations		(28,890	)		(20,781	)
Accounts payable and accrued liabilities		(125,024	)		40,354
Other liabilities		(11	)		—
Net cash provided by operating activities		472,668			351,468
Investing activities:
Acquisition of Kerr-McGee properties		—			(1,061,769	)
Investment in oil and gas property and equipment, net		(273,638	)		(387,326	)
Purchases of furniture, fixtures and other, net		(348	)		(6,985	)
Net cash used in investing activities		(273,986	)		(1,456,080	)
Financing activities:
Issuance of Senior Notes		450,000			—
Borrowings of other long-term debt		458,000			819,732
Repayments of long-term debt		(945,750	)		(191,000	)
Proceeds from equity offering, net of costs		—			306,980
Dividends to shareholders		(6,850	)		(5,947	)
Debt issuance costs and other		(5,510	)		(780	)
Net cash (used in) provided by financing activities		(50,110	)		928,985
Increase (decrease) in cash and cash equivalents		148,572			(175,627	)
Cash and cash equivalents, beginning of period		39,235			187,698
Cash and cash equivalents, end of period	$	187,807		$	12,071

See Notes to Condensed Consolidated Financial Statements.

4

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

Operations. W&T Offshore, Inc. and subsidiaries, referred to herein as “W&T” or the “Company,” is an independent producer, active in the acquisition, exploitation, exploration and development of oil and natural gas properties in the Gulf of Mexico area.

Interim Financial Statements. The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, the condensed consolidated financial statements do not include all of the information and footnote disclosures required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for interim periods are not necessarily indicative of the results that may be expected for the entire year. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the Company’s annual report on Form 10-K for the year ended December 31, 2006.

Reclassifications. Certain reclassifications have been made to prior periods’ financial statements to conform to the current presentation.

Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

2. Recent Accounting Pronouncements

In June 2007, the Financial Accounting Standards Board (“FASB”) ratified Emerging Issues Task Force (“EITF”) Issue No. 06-11 (“EITF No. 06-11”),Accounting for the Income Tax Benefits of Dividends on Share-Based Payment Awards, which requires that tax benefits associated with dividends on share-based payment awards be recorded as a component of additional paid-in capital. EITF No. 06-11 is effective, on a prospective basis, for fiscal years beginning after December 15, 2007. The adoption of EITF No. 06-11 is not expected to have a material impact on the Company’s financial statements.

In February 2007, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 159,The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115. This statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. The objective of this statement is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. At the present time, the Company does not expect to apply the provisions of SFAS No. 159.

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements, which defines fair value as that term is used in many accounting pronouncements, establishes a framework for measuring the fair value of assets and liabilities as already required by generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We are currently evaluating the impact that SFAS No. 157 may have on our consolidated financial statements.

5

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

3. Asset Retirement Obligations

Our asset retirement obligations primarily represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives in accordance with applicable laws. Revisions of estimated liabilities include, among other things, revisions due to timing of settling certain asset retirement obligations. A summary of our asset retirement obligations is as follows (in thousands):

Balance, December 31, 2006	$	314,068
Liabilities settled		(28,890	)
Accretion of discount		16,477
Liabilities incurred, net of sales		3,721
Revisions of estimated liabilities		1,018
Balance, September 30, 2007		306,394
Less current portion		24,762
Long-term	$	281,632

4. Long-Term Debt

As of September 30, 2007 and December 31, 2006, our long-term debt was as follows (in thousands):

	September 30, 2007			December 31, 2006
Revolving loan facility, due August 2009	$	—		$	122,000
Tranche A term loan facility, net of unamortized discount of $4,583 at December 31, 2006		—			270,417
Tranche B term loan facility, net of unamortized discount of $4,090 at September 30, 2007 and $7,420 at December 31, 2006, due August 2010		205,160			292,580
8.25% Senior notes, due June 2014		450,000			—
Total long-term debt		655,160			684,997
Current maturities of long-term debt		(3,000	)		(271,380	)
Long-term debt, less current maturities	$	652,160		$	413,617

Aggregate maturities of long-term debt for the periods ended December 31 are as follows (in millions): 2007–$0.8; 2008–$3.0; 2009–$3.0; 2010–$202.5; 2011–$0.0; thereafter–$450.0.

Private Offering of 8.25% Senior Notes due 2014. In June 2007, the Company sold and issued to eligible investors $450 million aggregate principal amount of 8.25% senior notes due 2014 (the “Notes”) pursuant to Rule 144A under the Securities Act of 1933, as amended. Net proceeds generated by the offering were approximately $444.7 million after underwriting fees of $4.1 million and legal, accounting, printing and various other fees of approximately $1.2 million. The Company used substantially all of the net proceeds from the private placement of the Notes to repay a portion of the outstanding borrowings under its Third Amended and Restated Credit Agreement (the “Credit Agreement”).

The Notes are unsecured senior obligations of the Company, rank senior in right of payment to any future subordinated indebtedness, rank equally in right of payment with the Company’s existing and any future unsecured senior indebtedness and are effectively subordinated in right of payment to any secured indebtedness, including obligations under the Credit Agreement, to the extent of the collateral securing such indebtedness.

6

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

The Notes are jointly and severally guaranteed on a senior unsecured basis by the Company’s existing subsidiaries (other than certain minor non-guarantor subsidiaries) and any future domestic subsidiaries that (a) have indebtedness outstanding in excess of $5.0 million, or (b) guaranty any other indebtedness of the Company or of another guarantor in excess of $5.0 million. In the future, the guarantees may be released or terminated under certain circumstances. Each subsidiary guarantee ranks senior in right of payment to any future subordinated indebtedness of that guarantor, ranks equally in right of payment to any future senior indebtedness of that guarantor, and is subordinate in right of payment to any secured indebtedness of that guarantor, including indebtedness under the Credit Agreement, to the extent of the collateral securing such indebtedness.

The Notes bear interest at a fixed rate of 8.25%, with interest payable semi-annually in arrears on June 15 and December 15, commencing on December 15, 2007. The Notes mature on June 15, 2014. The Company is not required to make sinking fund payments with respect to the Notes. The estimated annual effective interest rate on the Notes is 8.4%.

The Company may redeem the Notes, in whole or in part, at any time prior to June 15, 2011, at a redemption price equal to 100% of the aggregate principal amount redeemed plus a make-whole premium and accrued and unpaid interest. Beginning on June 15 of the years indicated below, the Company may redeem the Notes from time to time, in whole or in part, at the prices set forth below (expressed as percentages of the principal amount redeemed) plus accrued and unpaid interest:

	% of Principal
Year	Amount
2011	104.125	%
2012	102.063	%
2013 and thereafter	100.000	%

In addition, prior to June 15, 2010, the Company may redeem up to 35% of the aggregate principal amount of the Notes with the net cash proceeds of one or more equity offerings, at a price equal to 108.25% of the principal amount of the Notes redeemed, plus accrued and unpaid interest. If the Company experiences a change of control (as defined in the indenture governing the Notes), subject to certain exceptions, each holder of the Notes will have the right to require the Company to repurchase all or any part of that holder’s Notes in an amount equal to 101% of the aggregate principal amount of Notes repurchased plus accrued and unpaid interest.

The Company and its restricted subsidiaries are subject to certain covenants under the indenture governing the Notes which limit the Company’s and each of its restricted subsidiaries’ ability to, among other things, make investments, incur additional indebtedness or issue preferred stock, sell assets, consolidate, merge or transfer all or substantially all of its assets, engage in transactions with affiliates, pay dividends or make other distributions on capital stock or subordinated indebtedness and create unrestricted subsidiaries.

Credit Agreement. The Credit Agreement was amended in June 2007 whereby the amount of senior unsecured indebtedness the Company may incur was increased to $500 million to allow for the issuance of the Notes, provided that the proceeds from the Notes would be used to prepay the Tranche A term loan facility in full. Consequently, in June 2007, the Company paid in full the Tranche A term loan facility outstanding balance of $50.0 million plus accrued and unpaid interest of $0.2 million. The Company also used proceeds from the Notes to make a payment of $90.0 million on the Tranche B term loan facility balance outstanding plus accrued and unpaid interest of $1.5 million, and to pay in full the revolving loan facility outstanding balance of $271.0 million. At September 30, 2007, we had $300.0 million of undrawn capacity available under our revolving loan facility. During the nine months ended September 30, 2007, we recorded a loss of $2.8 million related to the write-off of all the deferred financing costs related to the Tranche A term loan facility and a pro-rata portion of the deferred financing costs related to the Tranche B term loan facility. On November 6, 2007, the Credit Agreement was amended to provide for, among other things, an increase in the capacity available under our revolving loan facility to $500.0 million from $300.0 million.

7

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

Borrowings under the revolving loan facility prior to November 6, 2007 bore interest at either (1) the higher of the Prime Rate, or the Federal Funds Rate plus 0.50%, plus a margin equal to 1.5% or (2) to the extent the loan outstanding was designated as a Eurodollar loan, at the London Interbank Offered Rate (“LIBOR”) plus a margin equal to 2.5%. The Credit Agreement also bore an unused commitment fee of 0.50% depending on the level of total borrowings then outstanding under the revolving loan facility. The effective interest rate on the revolving loan facility, including unused commitment fees, was 10.7% during the nine months ended September 30, 2007. Subsequent to November 6, 2007, borrowings under the revolving loan facility will bear interest at either (1) the higher of the Prime Rate, or the Federal Funds Rate plus 0.50%, plus a margin which varies from 0.0% to 0.625% depending on the level of total borrowings under the Credit Agreement or (2) to the extent the loan outstanding is designated as a Eurodollar loan, at the LIBOR plus a margin that varies from 1.25% to 1.875% depending on the level of total borrowings under the Credit Agreement. The unused commitment fee will range from 0.30% to 0.50% depending on the level of total borrowings outstanding under the revolving loan facility.

Borrowings under the Tranche B term loan facility bear interest at either (1) the higher of the Prime Rate, or the Federal Funds Rate plus 0.50%, plus a margin equal to 1.25% or (2) to the extent the loan outstanding is designated as a Eurodollar loan, at the LIBOR plus a margin equal to 2.25%. The effective interest rate, including amortization of the discount, on the Tranche B term loan facility was 8.4% during the nine months ended September 30, 2007.

The Credit Agreement was also amended to eliminate the requirement to maintain interest rate hedging contracts with respect to at least 50% of the aggregate principal amount outstanding of the Tranche A and Tranche B term loan facilities. In June 2007, we terminated the interest rate swap contract associated with our Tranche A term loan facility (see Note 5).

We are subject to various financial covenants calculated as of the last day of each fiscal quarter, including a current ratio, interest coverage ratio, asset coverage ratio and a leverage ratio. We were in compliance with all applicable covenants of the Credit Agreement as of September 30, 2007.

5. Derivative Financial Instruments

We account for our derivative contracts in accordance with SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities. SFAS No. 133, as amended, requires each derivative to be recorded on the balance sheet as an asset or a liability at its fair value. Additionally, the statement requires that changes in a derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met at the time the derivative contract is entered into. Counterparties to our derivative contracts expose the Company to credit loss in the event of nonperformance; however, we do not anticipate nonperformance by the counterparties.

Commodity Derivatives. In January 2006, we entered into commodity swap and option contracts in connection with the anticipated financing related to the acquisition by merger of a wholly-owned subsidiary of Kerr-McGee Oil & Gas Corporation (“Kerr-McGee”). While these contracts are intended to reduce the effects of volatile oil and natural gas prices, they may also limit future income from favorable price movements. Changes in the fair value of our commodity derivative contracts are recognized currently in earnings.

During the three months ended September 30, 2007 and 2006, we recorded an unrealized loss of $5.5 million and an unrealized gain of $22.7 million, respectively, related to our open commodity derivative contracts, and we recorded realized gains of $3.6 million and $4.4 million, respectively, related to settlements of our commodity derivatives.

During the nine months ended September 30, 2007 and 2006, we recorded an unrealized loss of $20.3 million and an unrealized gain of $15.2 million, respectively, related to our open commodity derivative contracts, and we recorded realized gains of $6.3 million and $6.6 million, respectively, related to settlements of our commodity derivatives.

At September 30, 2007, $3.5 million was included in prepaid expenses and other assets, $0.7 million was included in other assets, $6.3 million was included in accrued liabilities and $1.2 million was included in other liabilities related to our open commodity derivatives.

8

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

As of September 30, 2007, our open commodity derivatives were as follows:

Collars
Type	Commodity	Effective Date	Termination Date	Notional Quantity	NYMEX Contract Price				Fair Value Gain (Loss) (in thousands)
					Floor		Ceiling
Funded	Natural Gas	11/1/2007	12/31/2007	1,464,000 MMBtu	$	7.76	$	16.80	$	1,212
Zero Cost	Oil	10/1/2007	12/31/2007	395,600 Bbls		61.68		76.40		(2,007	)
Funded	Natural Gas	1/1/2008	12/31/2008	5,124,000 MMBtu		7.31		15.80		2,972
Zero Cost	Oil	1/1/2008	12/31/2008	1,024,800 Bbls		60.00		74.50		(5,487	)
									$	(3,310	)

As of December 31, 2006, our open commodity derivatives were as follows:

Collars
Type	Commodity	Effective Date	Termination Date	Notional Quantity	NYMEX Contract Price				Fair Value Gain (in thousands)
					Floor		Ceiling
Funded	Natural Gas	2/1/2007	12/31/2007	8,016,000 MMBtu	$	7.76	$	16.80	$	10,950
Zero Cost	Oil	1/1/2007	12/31/2007	1,569,500 Bbls		61.68		76.40		2,511
Funded	Natural Gas	1/1/2008	12/31/2008	5,124,000 MMBtu		7.31		15.80		3,413
Zero Cost	Oil	1/1/2008	12/31/2008	1,024,800 Bbls		60.00		74.50		73
									$	16,947

Interest Rate Swaps. The Credit Agreement required that we enter into interest rate hedging contracts with respect to at least 50% of the aggregate principal amount outstanding of our Tranche A and Tranche B term loan facilities. In June 2007, we amended the Credit Agreement to eliminate the requirement to maintain interest rate hedging contracts with respect to the Tranche A and Tranche B term loan facilities. Subsequently, we paid our Tranche A term loan facility in full and terminated the interest rate swap associated with the Tranche A term loan facility.

In June 2007, we made a payment of $90.0 million on the outstanding balance of the Tranche B term loan facility. In connection with this payment, we de-designated as a cash flow hedge 30% of the notional amount of the interest rate swap associated with the Tranche B term loan facility. As of the date of de-designation (June 14, 2007), the fair value of the de-designated portion of the swap was approximately $0.3 million (net of income tax), which was recorded in accumulated other comprehensive income and is being recognized in earnings through interest expense over the remaining term of the interest rate swap. From the date of de-designation, subsequent changes in the fair value of the de-designated portion of the interest rate swap have been and will continue to be immediately recognized in earnings. During the three and nine months ended September 30, 2007, we recorded an unrealized loss of $0.9 million and $1.1 million, respectively, related to the portion of our interest rate swap that is no longer designated as a cash flow hedge. The remaining 70% of the notional amount continues to be designated as a cash flow hedge under SFAS No. 133 and represents 50% of the principal amount outstanding on the Tranche B term loan facility as of September 30, 2007.

At September 30, 2007, $1.0 million, net of income tax, of the unrealized loss in accumulated other comprehensive loss relates to the fair value of the portion of the interest rate swap that continues to be designated as a cash flow hedge. The swap has been determined to be highly effective as it relates to the variability in the LIBOR and therefore qualifies, and is designated by management, as a cash flow hedge under SFAS No. 133. Gains or losses on this portion of the swap are recorded to interest expense when realized and could vary from the unrealized amount shown above as a result of future changes in interest rates. For the three and nine months ended September 30, 2007, no amount was recognized in earnings due to ineffectiveness related to our interest rate swap.

9

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

All interest rate swap payments are made quarterly and the LIBOR is determined in advance of each interest period. The fixed interest rate of the swap related to the Tranche B term loan facility is 5.16%. The effective interest rate, including amortization of the discount, on the Tranche B term loan facility was 8.4% during the nine months ended September 30, 2007.

6. Income Taxes

We adopted FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes—an interpretation of SFAS No. 109, (“FIN 48”), effective January 1, 2007. The adoption of FIN 48 did not have an effect on our consolidated financial statements.

As of September 30, 2007, we do not have any accrued interest or penalties related to uncertain tax positions; however, when applicable, we will recognize interest and penalties related to uncertain tax positions in income tax expense. The tax years from 2004 through 2006 remain open to examination by the tax jurisdictions to which we are subject.

Our effective tax rate for the nine months ended September 30, 2007 was approximately 34% and reflects the utilization of the deduction attributable to qualified domestic production activities under Section 199 of the Internal Revenue Code. Our effective tax rate for the nine months ended September 30, 2006 was approximately 35%.

7. Insurance Receivables

In March 2007, we entered into agreements with our insurance underwriters to settle all claims related to Hurricanes Katrina and Rita, as well as a claim to recover drilling costs on a well at Green Canyon 82 that experienced uncontrollable water flow in the second quarter of 2006. After adjustments for applicable deductibles and reimbursements of $21.9 million received in 2006 and $4.8 million received in February 2007, the Company received proceeds of $73.3 million in March 2007. Total reimbursements of $78.1 million received in the first quarter of 2007 exceeded our insurance receivables at December 31, 2006 by $2.9 million. Such amount was used to offset a portion of our hurricane remediation costs incurred in 2007 which totaled $21.5 million through September 30, 2007. In the third quarter of 2007 we recovered $3.8 million under the insurance policy of one of our partners, which also offset a portion of our hurricane remediation costs incurred in 2007. Included in lease operating expenses for the three and nine months ended September 30, 2007 is $1.8 million and $14.8 million, respectively, for hurricane remediation expenses that were not covered by insurance. We anticipate incurring additional costs to repair damage to our facilities caused by Hurricanes Katrina and Rita during the remainder of 2007, none of which is expected to be covered by insurance. During the nine months ended September 30, 2007, uninsured expenditures were classified as lease operating expenses and any such future expenditures are expected to be classified similarly. The timing of future repairs will be affected by equipment availability, design and remediation planning and permitting.

8. Long-Term Incentive Compensation

2006 Bonus. In March 2007, our board of directors approved payment of a general bonus and an extraordinary performance bonus to our employees for 2006 in accordance with the W&T Offshore, Inc. 2005 Annual Incentive Plan (the “2005 Plan”). Each type of bonus includes a cash component and a restricted stock component.

Cash bonuses for 2006 (general bonus and extraordinary performance bonus) were paid in March 2007 and totaled $6.4 million, of which $4.7 million was expensed in 2006, $1.3 million was expensed in the first quarter of 2007 and the remainder was billed to partners under joint operating agreements.

The restricted stock portion of the 2006 bonus (general bonus and extraordinary performance bonus) was granted in March 2007 by the issuance of 329,813 restricted shares of our common stock with a fair value of approximately $9.0 million. The associated compensation expense, less an allowance for estimated forfeitures, is being recognized over the requisite service period of four years

10

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

beginning on the first day of 2006. Accrued liability amounts of approximately $2.2 million ($1.9 million in 2006) related to the recognition of compensation expense during the service period prior to the issuance of the restricted shares were reclassified to additional paid-in capital upon issuance of the restricted shares in March 2007 (see Note 9).

2007 Bonus. Eligible employees will be entitled to receive a general bonus and an extraordinary performance bonus for 2007 in accordance with the 2005 Plan, consisting of cash and restricted stock. Shares of restricted stock to be awarded as a bonus for 2007 will be issued in 2008 and have a four year requisite service period and will vest in three equal installments on December 31, 2008, 2009 and 2010. The cash bonus for 2007 will be paid in 2008. During the three months ended September 30, 2007, we expensed $1.6 million related to the general bonus for 2007, of which $0.4 million will ultimately be settled in restricted shares. During the nine months ended September 30, 2007, we expensed $3.6 million related to the general bonus for 2007, of which $1.0 million will ultimately be settled in restricted shares (see Note 9).

9. Share-Based Compensation

We recognize compensation cost for share-based payments to employees and non-employee directors over the period during which the recipient is required to provide service in exchange for the award, based on the fair value of the equity instrument on the date of grant. At September 30, 2007, there were 1,831,521 shares of common stock available for award under our share-based payment plans. A summary of share activity pursuant to our share-based payment plans for the nine months ended September 30, 2007, is as follows:

	Restricted Shares		Weighted Average Grant Date Price Per Share
Nonvested at December 31, 2006	102,860		$	37.35
Granted	348,675			27.39
Vested	(1,316	)		40.55
Forfeited	(9,458	)		31.01
Nonvested at September 30, 2007	440,761			29.59

Restricted shares generally vest in three equal installments with the first such installment vesting on December 31 of the year in which the shares are granted and annually thereafter. The weighted average grant date fair value of restricted shares granted during the nine months ended September 30, 2007 and 2006 was $9.5 million and $6.2 million, respectively.

During the three months ended September 30, 2007 and 2006, total compensation expense under share-based payment arrangements was $1.3 million and $0.9 million, respectively, of which $0.9 million and $0.4 million, respectively, was credited to additional paid-in capital. During the nine months ended September 30, 2007 and 2006, total compensation expense under share-based payment arrangements was $3.7 million and $3.3 million, respectively, of which $2.7 million and $2.0 million, respectively, was credited to additional paid-in capital. Prior to the granting of the restricted shares, the associated compensation expense is recorded as an accrued liability. As of September 30, 2007, there was $6.4 million of total unrecognized share-based compensation expense related to restricted shares issued, which is expected to be recognized between October 2007 and April 2010.

10. Earnings Per Share

Basic earnings per share was calculated by dividing net income applicable to common shares by the weighted average number of common shares outstanding during the periods presented. Diluted earnings per share incorporates the potential dilutive impact of nonvested restricted stock outstanding during the periods presented.

11

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

The reconciliation of basic and diluted weighted average shares outstanding and earnings per share is as follows (in thousands, except per share amounts):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
Net income applicable to common shares	$	36,340	$	66,701	$	94,890	$	160,997
Weighted average number of common shares (basic)		75,787		72,882		75,787		68,300
Weighted average nonvested common shares		162		157		127		112
Weighted average number of common shares (diluted)		75,949		73,039		75,914		68,412
Earnings per share:
Basic	$	0.48	$	0.92	$	1.25	$	2.36
Diluted		0.48		0.91		1.25		2.35

11. Comprehensive Income

Our comprehensive income for the periods indicated is as follows (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Net income	$	36,340		$	66,701		$	94,890		$	160,997
Amounts reclassified to income, net of income tax		(50	)		—			(146	)		—
Change in the fair value of interest rate swaps, net of income tax		(1,269	)		(745	)		(82	)		(745	)
Comprehensive income	$	35,021		$	65,956		$	94,662		$	160,252

12. Dividends

On August 1, 2007, we paid a cash dividend of $0.03 per common share to shareholders of record on July 13, 2007. On August 31, 2007, our board of directors declared a cash dividend of $0.03 per common share, which was paid on November 1, 2007 to shareholders of record on October 15, 2007.

13. Contingencies

The Company is a party to various pending or threatened claims and complaints seeking damages or other remedies concerning its commercial operations and other matters in the ordinary course of its business. Some of these claims relate to matters occurring prior to its acquisition of properties and some relate to properties it has sold. In certain cases, the Company is entitled to indemnification from the sellers of properties and in other cases, it has indemnified the buyers of properties from it. Although the Company can give no assurance about the outcome of pending legal and administrative proceedings and the effect such outcomes may have on it, management believes that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on its consolidated financial position, results of operations or liquidity.

12

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements

The following discussion and analysis should be read in conjunction with our accompanying unaudited condensed consolidated financial statements and the notes to those financial statements included elsewhere in this quarterly report. The following discussion contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act and Section 21E of the Securities and Exchange Act that involve risks, uncertainties and assumptions. If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions. All statements other than statements of historical fact are statements that could be deemed forward-looking statements, such as those statements that address activities, events or developments that we expect, believe or anticipate will or may occur in the future. These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. Certain factors that may affect our financial condition and results of operations are discussed in Item 1A “Risk Factors” and Item 7A “Quantitative and Qualitative Disclosures About Market Risk” of our Annual Report on Form 10-K for the year ended December 31, 2006 and may be discussed or updated from time to time in subsequent reports filed with the Securities and Exchange Commission. We assume no obligation, nor do we intend, to update these forward-looking statements. Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q to “W&T,” “we,” “us,” “our” and the “Company” refer to W&T Offshore, Inc. and its subsidiaries.

Overview

W&T is an independent oil and natural gas producer focused in the Gulf of Mexico area. W&T has grown through acquisitions, exploitation and exploration and currently holds working interests in over 150 producing fields in federal and state waters. The majority of our daily production is derived from wells we operate.

Results of Operations

The following tables set forth selected financial and operating data for the periods indicated (all values are net to our interest unless indicated otherwise):

	Three Months Ended September 30,										Nine Months Ended September 30,
	2007		2006			Change			%		2007		2006			Change			%
	(In thousands, except per share data)
Financial:
Revenues:
Oil	$	147,054	$	112,296		$	34,758		31.0	%	$	376,048	$	260,504		$	115,544		44.4	%
Natural gas		108,134		101,097			7,037		7.0	%		398,172		275,456			122,716		44.6	%
Other		3		38			(35	)	(92.1	%)		73		122			(49	)	(40.2	%)
Total revenues		255,191		213,431			41,760		19.6	%		774,293		536,082			238,211		44.4	%
Operating costs and expenses:
Lease operating expenses (1)		51,627		35,227			16,400		46.6	%		169,154		68,704			100,450		146.2	%
Gathering and transportation costs and production taxes		5,783		5,186			597		11.5	%		14,626		11,694			2,932		25.1	%
Depreciation, depletion, amortization and accretion		123,113		85,466			37,647		44.0	%		373,358		201,892			171,466		84.9	%
General and administrative expenses (1)		9,952		8,845			1,107		12.5	%		29,240		28,164			1,076		3.8	%
Derivative loss (gain)		2,809		(27,065	)		29,874		110.4	%		15,082		(21,793	)		36,875		169.2	%
Total costs and expenses		193,284		107,659			85,625		79.5	%		601,460		288,661			312,799		108.4	%
Operating income		61,907		105,772			(43,865	)	(41.5	%)		172,833		247,421			(74,588	)	(30.1	%)
Interest expense, net of amounts capitalized		8,308		5,738			2,570		44.8	%		28,657		6,376			22,281		349.5	%
Loss on extinguishment of debt		—		—			—		—			2,806		—			2,806		—
Other income		1,567		2,111			(544	)	(25.8	%)		2,508		5,505			(2,997	)	(54.4	%)
Income before income taxes		55,166		102,145			(46,979	)	(46.0	%)		143,878		246,550			(102,672	)	(41.6	%)
Income taxes		18,826		35,444			(16,618	)	(46.9	%)		48,988		85,553			(36,565	)	(42.7	%)
Net income	$	36,340	$	66,701		$	(30,361	)	(45.5	%)	$	94,890	$	160,997		$	(66,107	)	(41.1	%)
Earnings per common share – diluted	$	0.48	$	0.91		$	(0.43	)	(47.3	%)	$	1.25	$	2.35		$	(1.10	)	(46.8	%)
EBITDA (2)	$	185,020	$	191,238		$	(6,218	)	(3.3	%)	$	543,385	$	449,313		$	94,072		20.9	%
Adjusted EBITDA (2)	$	191,389	$	168,524		$	22,865		13.6	%	$	567,551	$	434,089		$	133,462		30.7	%

See footnotes beginning on page 14.

13

	Three Months Ended September 30,									Nine Months Ended September 30,
	2007		2006		Change			%		2007			2006		Change			%
Operating:
Net sales:
Natural gas (Bcf)		16.8		15.4		1.4		9.1	%		55.5			37.5		18.0		48.0	%
Oil (MMBbls)		2.0		1.8		0.2		11.1	%		6.1			4.3		1.8		41.9	%
Total natural gas and oil (Bcfe) (3)		28.9		26.2		2.7		10.3	%		92.2			63.3		28.9		45.7	%
Average daily equivalent sales (MMcfe/d)		314.0		285.1		28.9		10.1	%		337.7			232.0		105.7		45.6	%
Average realized sales prices (4):
Natural gas ($/Mcf)	$	6.45	$	6.58	$	(0.13	)	(2.0	%)	$	7.17		$	7.35	$	(0.18	)	(2.4	%)
Oil ($/Bbl)		72.72		62.08		10.64		17.1	%		61.49			60.48		1.01		1.7	%
Natural gas equivalent ($/Mcfe)		8.83		8.14		0.69		8.5	%		8.40			8.46		(0.06	)	(0.7	%)
Average per Mcfe ($/Mcfe):
Lease operating expenses (1)	$	1.79	$	1.34	$	0.45		33.6	%	$	1.83		$	1.08	$	0.75		69.4	%
Gathering and transportation costs and production taxes		0.20		0.20		—		—			0.16	��		0.18		(0.02	)	(11.1	%)
Depreciation, depletion, amortization and accretion		4.26		3.26		1.00		30.7	%		4.05			3.19		0.86		27.0	%
General and administrative expenses (1)		0.34		0.34		—		—			0.32			0.44		(0.12	)	(27.3	%)
	$	6.59	$	5.14	$	1.45		28.2	%	$	6.36		$	4.89	$	1.47		30.1	%
Total number of wells drilled (gross) (5)(7)		1		8		(7	)	NM			5			30		(25	)	NM
Total number of productive wells drilled (gross) (6)(7)		1		8		(7	)	NM			5			26		(21	)	NM

(1) Certain industry related reimbursements for overhead expenses from joint interest owners have been reclassified from lease operating expenses to general and administrative expenses in order to better match the underlying reimbursement with the actual cost recorded. All prior year amounts have been reclassified to conform with the 2007 presentation. The effect of these reclassifications had no impact on net income.

(2) We define EBITDA as net income plus income tax expense, net interest expense, and depreciation, depletion, amortization and accretion. Adjusted EBITDA excludes the loss on extinguishment of debt and the unrealized gain or loss related to our open derivative contracts. Although not prescribed under generally accepted accounting principles, we believe the presentation of EBITDA and Adjusted EBITDA provide useful information regarding our ability to service debt and fund capital expenditures and they help our investors understand our operating performance and make it easier to compare our results with those of other companies that have different financing, capital and tax structures. EBITDA and Adjusted EBITDA should not be considered in isolation from or as a substitute for net income, as an indication of operating performance or cash flows from operating activities or as a measure of liquidity. EBITDA and Adjusted EBITDA, as we calculate them, may not be comparable to EBITDA and Adjusted EBITDA measures reported by other companies. In addition, EBITDA and Adjusted EBITDA do not represent funds available for discretionary use. A reconciliation of our consolidated net income to EBITDA and Adjusted EBITDA is as follows (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2007		2006			2007		2006
Net income	$	36,340	$	66,701		$	94,890	$	160,997
Income taxes		18,826		35,444			48,988		85,553
Net interest expense		6,741		3,627			26,149		871
Depreciation, depletion, amortization and accretion		123,113		85,466			373,358		201,892
EBITDA		185,020		191,238			543,385		449,313
Loss on extinguishment of debt		—		—			2,806		—
Unrealized derivative loss (gain)		6,369		(22,714	)		21,360		(15,224	)
Adjusted EBITDA	$	191,389	$	168,524		$	567,551	$	434,089

(3) One billion cubic feet equivalent (Bcfe), one million cubic feet equivalent (MMcfe) and one thousand cubic feet equivalent (Mcfe) are determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids (totals may not add due to rounding).

14

(4) Average realized prices exclude the effects of our commodity derivative contracts that do not qualify for hedge accounting. Had we included the effects of these derivatives, our average realized sales prices for natural gas would have been $6.69 per Mcf and $6.87 per Mcf for the third quarter of 2007 and 2006, respectively, and $7.27 per Mcf and $7.54 per Mcf for the nine months ended September 30, 2007 and 2006, respectively. Our average realized sales prices for oil would have been $72.52 per barrel and $62.00 per barrel for the third quarter of 2007 and 2006, respectively, and $61.64 per barrel and $60.33 per barrel for the nine months ended September 30, 2007 and 2006, respectively. On a natural gas equivalent basis, our average realized sales prices would have been $8.96 per Mcfe and $8.30 per Mcfe for the third quarter of 2007 and 2006, respectively, and $8.47 per Mcfe and $8.57 per Mcfe for the nine months ended September 30, 2007 and 2006, respectively.

(5) Data for the nine months ended September 30, 2006 reflects three wells drilled between the effective date and the closing date of the Kerr-McGee transaction on properties acquired by merger in that transaction, which was completed in August 2006.

(6) Data for the nine months ended September 30, 2006 reflects two productive wells drilled between the effective date and the closing date of the Kerr-McGee transaction on properties acquired by merger in that transaction.

(7) Percentage change not meaningful (“NM”).

Three Months Ended September 30, 2007 Compared to the Three Months Ended September 30, 2006

Revenues. Revenues increased $41.8 million or 20% to $255.2 million for the three months ended September 30, 2007 as compared to the same period in 2006. Natural gas revenues increased $7.0 million and oil revenues increased $34.8 million. The natural gas revenue increase was attributable to a sales volume increase of 1.4 Bcf, which was partially offset by a 2% decrease in the average realized price to $6.45 per Mcf for the three months ended September 30, 2007 from $6.58 per Mcf for the same period in 2006. The oil revenue increase was attributable to a sales volume increase of 0.2 MMBbls and a 17% increase in the average realized price to $72.72 per barrel in the 2007 period from $62.08 in the 2006 period. The volume increases for natural gas and oil are primarily attributable to properties acquired by merger in the Kerr-McGee transaction, resumed production from properties that underwent hurricane repairs and increased production from our successful drilling and development efforts, partially offset by properties that experienced natural reservoir declines.

Lease operating expenses. Lease operating expenses increased to $1.79 per Mcfe in the third quarter of 2007 from $1.34 per Mcfe in the third quarter of 2006, despite higher total sales volumes in the 2007 period. On a nominal basis, lease operating expenses increased to $51.6 million in the third quarter of 2007 from $35.2 million in the third quarter of 2006. The increase of $16.4 million is attributable to increases in operating costs of $13.2 million, major maintenance expenses of $2.5 million ($1.8 million of which is hurricane remediation costs) and $1.4 million in higher insurance premiums, partially offset by a decrease in workover expenditures of $0.7 million. Approximately $7.8 million of the increase in operating costs is associated with properties acquired by merger in the Kerr-McGee transaction. We believe the incurrence of such costs following a large acquisition of properties is not unusual, and the magnitude and timing of additional workover and maintenance expenditures on the properties acquired by merger in the Kerr-McGee transaction may fluctuate as integration of the properties continues. The remainder of the increase in operating costs is primarily attributable to new production and increases in service costs. The $1.8 million of hurricane remediation costs referred to above was not covered by insurance. Amounts spent in 2006 related to hurricane remediation efforts were covered by insurance (after applicable deductibles) and therefore were not included in lease operating expenses.

Gathering and transportation costs and production taxes. Gathering and transportation costs and production taxes increased to $5.8 million for the three months ended September 30, 2007 from $5.2 million for the same period in 2006 primarily due to the acquisition of a field in Louisiana state waters that was part of the properties acquired by merger in the Kerr-McGee transaction. Most of our production is from federal waters, where there are no production taxes.

15

Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion (“DD&A”) increased to $123.1 million for the quarter ended September 30, 2007 from $85.5 million for the same period in 2006. The increase primarily reflects increases in finding and development costs and volumes of oil and natural gas sold in 2007. On a per Mcfe basis, DD&A was $4.26 for the quarter ended September 30, 2007, compared to $3.26 for the quarter ended September 30, 2006.

General and administrative expenses. General and administrative expenses (“G&A”) increased to $9.9 million for the three months ended September 30, 2007 from $8.8 million for the same period in 2006 primarily due to increases in the number of employees (and therefore greater compensation and benefits costs), legal and professional fees and a termination benefit under an employment contract in 2007. As a percentage of revenues, G&A decreased to 3.9% for the three months ended September 30, 2007, compared to 4.1% for the same period in 2006.

Derivative loss/gain. For the quarter ended September 30, 2007, our derivative loss of $2.8 million consisted of an unrealized loss of $5.5 million related to our open commodity derivative contracts offset by a realized gain of $3.6 million related to settlements of our commodity derivative contracts. Also included in 2007 is an unrealized loss of $0.9 million related to the portion of our open interest rate swap that was de-designated as a cash flow hedge. For the quarter ended September 30, 2006, our derivative gain of $27.1 million consisted of an unrealized gain of $22.7 million related to our open commodity derivative contracts and a realized gain of $4.4 million related to settlements of our commodity derivative contracts. For additional details about our derivatives, refer to Item 1.Financial Statements – Note 5 – Derivative Financial Instruments.

Interest expense. Interest expense incurred increased to $14.3 million for the quarter ended September 30, 2007 from $9.9 million for the quarter ended September 30, 2006 primarily due to debt incurred in August 2006 to finance a portion of the purchase price of properties acquired by merger in the Kerr-McGee transaction. During the quarters ended September 30, 2007 and 2006, $6.0 million and $4.1 million of interest was capitalized to unevaluated oil and gas properties, respectively.

Other income. Other income, consisting of interest income, decreased to $1.6 million for the quarter ended September 30, 2007 from $2.1 million in the same period of 2006 mainly due to lower average daily balances of cash on hand in 2007.

Income tax expense. Income tax expense decreased to $18.8 million for the quarter ended September 30, 2007 from $35.4 million for the same period in 2006 primarily due to decreased taxable income. Our effective tax rate for the three months ended September 30, 2007 was approximately 34% and reflects the utilization of the deduction attributable to qualified domestic production activities under Section 199 of the Internal Revenue Code. Our effective tax rate for the three months ended September 30, 2006 was approximately 35%.

Nine Months Ended September 30, 2007 Compared to the Nine Months Ended September 30, 2006

Revenues. Revenues increased $238.2 million or 44% to $774.3 million for the nine months ended September 30, 2007 as compared to the same period in 2006. Natural gas revenues increased $122.7 million and oil revenues increased $115.5 million. The natural gas revenue increase was attributable to a sales volume increase of 18.0 Bcf, which was partially offset by a 2% decrease in the average realized price to $7.17 per Mcf for the nine months ended September 30, 2007 from $7.35 per Mcf for the same period in 2006. The oil revenue increase was attributable to a sales volume increase of 1.8 MMBbls and a 2% increase in the average realized price to $61.49 per barrel in the 2007 period from $60.48 in the 2006 period. The volume increases for natural gas and oil are primarily attributable to properties acquired by merger in the Kerr-McGee transaction, resumed production from properties that underwent hurricane repairs and increased production from our successful drilling and development efforts, partially offset by properties that experienced natural reservoir declines.

Lease operating expenses. Lease operating expenses increased to $1.83 per Mcfe for the nine months ended September 30, 2007 from $1.08 per Mcfe for the same period of 2006, despite higher total sales volumes in the 2007 period. On a nominal basis, lease operating expenses increased to $169.2 million for the nine months ended September 30, 2007 from $68.7 million for the same period of 2006. The increase of $100.5 million is attributable to increases in operating costs of $53.2 million, workover expenditures of $7.3 million, major maintenance expenses of $23.9 million ($14.8 million of which is hurricane remediation costs) and $16.1 million in higher insurance

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premiums. Approximately $38.5 million of the increases in operating costs and workovers are associated with properties acquired by merger in the Kerr-McGee transaction. We believe the incurrence of such costs following a large acquisition of properties is not unusual, and the magnitude and timing of additional workover and maintenance expenditures on the properties acquired by merger in the Kerr-McGee transaction may fluctuate as integration of the properties continues. The remainder of the increase in operating costs is primarily attributable to new production and increases in service costs. The $14.8 million of hurricane remediation costs referred to above was not covered by insurance. Amounts spent in 2006 related to hurricane remediation efforts were covered by insurance (after applicable deductibles) and therefore were not included in lease operating expenses.

Gathering and transportation costs and production taxes. Gathering and transportation costs and production taxes increased to $14.6 million for the nine months ended September 30, 2007 from $11.7 million for the same period in 2006 primarily due to the acquisition of a field in Louisiana state waters that was part of the properties acquired by merger in the Kerr-McGee transaction. Most of our production is from federal waters, where there are no production taxes.

Depreciation, depletion, amortization and accretion. DD&A increased to $373.4 million for the nine months ended September 30, 2007 from $201.9 million for the same period in 2006. The increase primarily reflects increases in finding and development costs and volumes of oil and natural gas sold in 2007. On a per Mcfe basis, DD&A was $4.05 for the nine months ended September 30, 2007, compared to $3.19 for the nine months ended September 30, 2006.

General and administrative expenses. G&A increased to $29.2 million for the nine months ended September 30, 2007 from $28.2 million for the same period in 2006 primarily due to increases in the number of employees (and therefore greater compensation and benefits costs), legal and professional fees and a termination benefit under an employment contract in 2007. As a percentage of revenues, G&A decreased to 3.8% for the nine months ended September 30, 2007, compared to 5.3% for the same period in 2006.

Derivative loss/gain. For the nine months ended September 30, 2007, our derivative loss of $15.1 million consisted of an unrealized loss of $20.3 million related to our open commodity derivative contracts offset by a realized gain of $6.3 million related to settlements of our commodity derivative contracts. Also included in 2007 is an unrealized loss of $1.1 million related to the portion of our open interest rate swap that was de-designated as a cash flow hedge. For the nine months ended September 30, 2006, our derivative gain of $21.8 million consisted of an unrealized gain of $15.2 million related to our open commodity derivative contracts and a realized gain of $6.6 million related to settlements of our commodity derivative contracts. For additional details about our derivatives, refer to Item 1.Financial Statements – Note 5 – Derivative Financial Instruments.

Interest expense. Interest expense incurred increased to $47.8 million for the nine months ended September 30, 2007 from $10.5 million for the nine months ended September 30, 2006 primarily due to debt incurred in August 2006 to finance a portion of the purchase price of properties acquired by merger in the Kerr-McGee transaction. During the nine months ended September 30, 2007 and 2006, $19.1 million and $4.1 million of interest was capitalized to unevaluated oil and gas properties, respectively.

Loss on extinguishment of debt. In June 2007, the Company used a portion of the proceeds from its private offering of 8.25% senior unsecured notes (the “Notes”) to prepay the balance outstanding on its Tranche A term loan facility and make a $90.0 million principal payment on its Tranche B term loan facility. For the nine months ended September 30, 2007, a loss of $2.8 million was incurred related to the write-off of all the deferred financing costs related to the Tranche A term loan facility and a pro-rata portion of the deferred financing costs related to the Tranche B term loan facility.

Other income. Other income, consisting of interest income, decreased to $2.5 million for the nine months ended September 30, 2007 from $5.5 million in the same period of 2006 mainly due to lower average daily balances of cash on hand in 2007.

Income tax expense. Income tax expense decreased to $49.0 million for the nine months ended September 30, 2007 from $85.6 million for the same period in 2006 primarily due to decreased taxable income. Our effective tax rate for the nine months ended September 30, 2007 was approximately 34% and reflects the utilization of the deduction attributable to qualified domestic production activities under Section 199 of the Internal Revenue Code. Our effective tax rate for the nine months ended September 30, 2006 was approximately 35%.

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Liquidity and Capital Resources

Cash flow and working capital. Net cash provided by operating activities for the nine months ended September 30, 2007 was $472.7 million, compared to $351.5 million for the comparable period in 2006. Net cash used in investing activities totaled $274.0 million and $1.5 billion during the first nine months of 2007 and 2006, respectively, which primarily represents our investment in oil and gas properties. Included in the 2006 amount is approximately $1.1 billion, which represents the adjusted purchase price of properties acquired by merger in the Kerr-McGee transaction which was completed in August 2006. During the first nine months of 2007, the Company reduced debt by $37.8 million and increased cash by $148.6 million. Cash provided by operations, borrowings available under our revolving loan facility and other external sources of liquidity should be sufficient to fund our ongoing cash requirements. At September 30, 2007, we had $300.0 million of undrawn capacity available under the revolving portion of the Third Amended and Restated Credit Agreement (the “Credit Agreement”). On November 6, 2007, the Credit Agreement was amended to provide for, among other things, an increase in the capacity available under our revolving loan facility to $500.0 million from $300.0 million. For a discussion of our debt offering and payments made under the Credit Agreement, seeLong-term debt below. Under the terms of the Credit Agreement, we are subject to various financial covenants calculated as of the last day of each fiscal quarter. As of September 30, 2007, we were in compliance with such financial covenants and we expect to be in compliance with such covenants throughout the remainder of 2007.

In January 2006, we entered into commodity swap and option contracts (as required by the Credit Agreement) relating to approximately 14 Bcfe, or 14%, of our production in 2006, 18 Bcfe of our anticipated production in 2007 and 11 Bcfe of our anticipated production in 2008. In August 2006, we entered into two interest rate swaps (as required by the Credit Agreement) to hedge the risk associated with the variable LIBOR used to reset the floating rates of our Tranche A and Tranche B term loans. For additional details about our derivatives, refer to Item 1.Financial Statements – Note 5 – Derivative Financial Instruments.

Insurance receivables. In March 2007, we entered into agreements with our insurance underwriters to settle all claims related to Hurricanes Katrina and Rita, as well as a claim to recover drilling costs on a well at Green Canyon 82 that experienced uncontrollable water flow in the second quarter of 2006. After adjustments for applicable deductibles and reimbursements of $21.9 million received in 2006 and $4.8 million received in February 2007, the Company received proceeds of $73.3 million in March 2007. Total reimbursements of $78.1 million received in the first quarter of 2007 exceeded our insurance receivables at December 31, 2006 by $2.9 million. Such amount was used to offset a portion of our hurricane remediation costs incurred in 2007 which totaled $21.5 million through September 30, 2007. In the third quarter of 2007 we recovered $3.8 million under the insurance policy of one of our partners, which also offset a portion of our hurricane remediation costs incurred in 2007. Included in lease operating expenses for the three and nine months ended September 30, 2007 is $1.8 million and $14.8 million, respectively, for hurricane remediation expenses that were not covered by insurance. We estimate that we could spend an additional $4 million to $6 million to repair damage to our facilities caused by Hurricanes Katrina and Rita during the remainder of 2007, none of which is expected to be covered by insurance. During the nine months ended September 30, 2007, uninsured expenditures were classified as lease operating expenses and any such future expenditures are expected to be classified similarly. The timing of future repairs will be affected by equipment availability, design and remediation planning and permitting.

Capital expenditures. The level of our investment in oil and gas properties changes from time to time, depending on numerous factors, including the price of oil and gas, acquisition opportunities and the results of our exploration and development activities. For the nine months ended September 30, 2007, capital expenditures for oil and gas properties of $277.3 million (before dispositions of $3.7 million) included $162.3 million for development activities, $71.6 million for exploration and $43.4 million for acquisition and other leasehold costs. Our capital expenditures for the nine months ended September 30, 2007 were financed by net cash from operating activities.

During the nine months ended September 30, 2007, our development and exploration capital expenditures consisted of $98.7 million in the deepwater, $34.5 million on the deep shelf and $100.7 million on the conventional shelf and other projects.

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In August 2007, our Board of Directors approved an increase of $100 million in the Company’s capital and major expenditures budget. The Company expects to be able to fund such increase from cash flow from operating activities and, to the extent needed, borrowings under its bank credit facilities.

Long-term debt. In June 2007, the Company issued $450 million of Notes. The Credit Agreement was amended in June 2007 whereby the amount of senior unsecured indebtedness the Company may incur was increased to $500 million to allow for the issuance of the Notes, provided that the proceeds from the Notes would be used to prepay the Tranche A term loan facility in full. Consequently, in June 2007, the Company paid in full the Tranche A term loan facility outstanding balance of $50.0 million plus accrued and unpaid interest of $0.2 million. The Company also used proceeds from the Notes to make a payment of $90.0 million on the Tranche B term loan facility balance outstanding plus accrued and unpaid interest of $1.5 million, and to pay in full the revolving loan facility outstanding balance of $271.0 million. During the nine months ended September 30, 2007, we recorded a loss of $2.8 million related to the write-off of all the deferred financing costs related to the Tranche A term loan facility and a pro-rata portion of the deferred financing costs related to the Tranche B term loan facility. For additional details about our long term debt, refer to Item 1.Financial Statements – Note 4 – Long Term Debt.

Contractual obligations. Except as described inLong-term debt above, information about contractual obligations for the nine months ended September 30, 2007, did not change materially from the disclosures in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2006.

Critical Accounting Policies

Our significant accounting policies are summarized in Note 1 of Notes to Consolidated Financial Statements included in our Annual Report on Form 10-K for the year ended December 31, 2006. Also refer to the Notes to Condensed Consolidated Financial Statements included in Part 1, Item 1 of this report.

Recent Accounting Pronouncements

For a description of recent accounting pronouncements, see Item 1. Financial Statements – Note 2 – Recent Accounting Pronouncementsand Note 6 – Income Taxes.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Information about market risks for the three and nine months ended September 30, 2007, did not change materially from the disclosures in Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2006 except as noted below. As such, the information contained herein should be read in conjunction with the related disclosures in our Annual Report on Form 10-K for the year ended December 31, 2006.

Commodity Price Risk. Our revenues, profitability and future rate of growth substantially depend upon market prices of oil and natural gas, which fluctuate widely. Oil and natural gas price declines and volatility could adversely affect our revenues, net cash provided by operating activities and profitability. In January 2006, we entered into commodity swap and option contracts. While these contracts are intended to reduce the effects of volatile oil and natural gas prices, they may also limit future income if oil and natural gas prices were to rise substantially over the price established by the hedge. We do not enter into derivative contracts for trading purposes. For additional details about our commodity derivatives, refer to Item 1.Financial Statements – Note 5 – Derivative Financial Instruments.

Interest Rate Risk. In June 2007, we amended the Credit Agreement to eliminate the requirement to maintain interest rate hedging contracts with respect to our Tranche A and Tranche B term loan facilities. Subsequently, we paid the Tranche A term loan facility in full and terminated the interest rate swap associated with the Tranche A term loan facility. We also made a payment of $90.0 million on the outstanding balance of the Tranche B term loan facility. In connection with the payment on the Tranche B term loan facility, we de-designated as a cash flow hedge 30% of the notional amount of the interest rate swap associated with the Tranche B term loan facility. For additional details about our interest rate swaps, refer to Item 1.Financial Statements – Note 5 – Derivative Financial Instruments.

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Item 4. Controls and Procedures

We performed an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have each concluded that as of September 30, 2007 our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports filed or submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

During the quarter ended September 30, 2007, there was no change in our internal control over financial reporting that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1A. Risk Factors

Our Annual Report on Form 10-K for the year ended December 31, 2006 includes a detailed discussion of our risk factors. There have been no material changes to the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2006, except for the following related to the offering of the Notes, which were included in our Form 10-Q for the period ended June 30, 2007. The information presented below updates and should be read in conjunction with the risk factors and information disclosed in our Annual Report on Form 10-K for the year ended December 31, 2006.

Risks Relating to the Notes

We may not be able to generate enough cash flow to meet our debt obligations.

We expect our earnings and cash flow to vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. In addition, our future cash flow may be insufficient to meet our debt obligations and commitments, including the Notes. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt, including the Notes. Many of these factors, such as oil and gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.

If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

• refinancing or restructuring our debt;

• selling assets;

• reducing or delaying capital investments; or

• seeking to raise additional capital.

However, any alternative financing plans that we undertake, if necessary, may not allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations, including our obligations under the Notes, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.

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Our debt could have important consequences. For example, it could:

• increase our vulnerability to general adverse economic and industry conditions;

• limit our ability to fund future working capital and capital expenditures, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets;

• limit our opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments of interest and principal on our debt or to comply with any restrictive terms of our debt;

• limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

• impair our ability to obtain additional financing in the future; and

• place us at a competitive disadvantage compared to our competitors that have less debt.

In addition, if we fail to comply with the covenants or other terms of any agreements governing our debt, our lenders will have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. Realization of any of these factors could adversely affect our financial condition.

We may be able to incur substantially more debt. This could exacerbate the risks associated with our indebtedness.

The Company may be able to incur substantial additional indebtedness in the future. The terms of our indenture governing the Notes do not prohibit us or our subsidiaries from doing so as long as we meet the debt incurrence tests provided in the indenture. As of September 30, 2007, we had $300.0 million of undrawn capacity available under the revolving portion of the Credit Agreement.

These borrowings would be secured, and as a result, effectively senior to the Notes and the guarantees of the Notes by our subsidiary guarantors, to the extent of the value of the collateral securing that indebtedness. If we incur any additional indebtedness that ranks equally with the Notes, the holders of that debt will be entitled to share ratably with the holders of the Notes in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding-up of us. This may have the effect of reducing the amount of proceeds paid to noteholders.

If new debt is added to our current debt levels, the related risks that we and our subsidiaries now face could intensify. Our level of indebtedness may prevent us from engaging in certain transactions that might otherwise be beneficial to us by limiting our ability to obtain additional financing, limiting our flexibility in operating our business or otherwise. In addition, we could be at a competitive disadvantage against other less leveraged competitors that have more cash flow to devote to their business. Any of these factors could result in a material adverse effect on our business, financial condition, results of operations, business prospects and ability to satisfy our obligations under the Notes.

Restrictions in our existing and future debt agreements could limit our growth and our ability to respond to changing conditions.

The indenture governing the Notes, the Credit Agreement and agreements governing our other indebtedness contain a number of significant covenants in addition to covenants restricting the incurrence of additional debt. These covenants limit our ability and the ability of our restricted subsidiaries, among other things, to:

• pay dividends or distributions on our capital stock or to repurchase our capital stock;

• repurchase subordinated debt;

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• make certain investments;

• create certain liens on our assets to secure debt;

• merge or to enter into other business combination transactions;

• issue and sell capital stock of our subsidiaries;

• enter into certain transactions with affiliates; and

• transfer and sell assets.

Our Credit Agreement requires us, among other things, to maintain certain financial ratios, satisfy certain financial condition tests or reduce our debt. These restrictions may also limit our ability to obtain future financings, withstand a future downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under the indenture governing the Notes and our existing indentures and Credit Agreement impose on us.

A breach of a covenant contained in the indenture governing the Notes, the Credit Agreement or any agreement governing our other indebtedness would result in a default under that agreement after any applicable grace periods. A default, if not waived, could result in acceleration of the debt outstanding under such agreement and in a default with respect to, and acceleration of, the debt outstanding under any other debt agreements. The accelerated debt would become immediately due and payable. If that should occur, we may not be able to make all of the required payments or borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us.

We may not be able to repurchase the Notes upon a change of control.

If we experience certain kinds of changes of control, we must give holders of the Notes the opportunity to sell us their Notes at 101% of their principal amount, plus accrued and unpaid interest. However, in such an event, we might not be able to pay noteholders the required repurchase price for the Notes presented to us because we might not have sufficient funds available at that time, or the terms of our Credit Agreement or other agreements we may enter into in the future may prevent us from applying funds to repurchase the Notes. The source of funds for any repurchase required as a result of a change of control will be our available cash or cash generated from our oil and gas operations or other sources, including:

• borrowings under our Credit Agreement or other sources;

• sales of assets; or

• sales of equity.

Sufficient funds may not be available at the time of any change of control to repurchase the Notes after first repaying any of our senior secured debt that may exist at the time. In addition, restrictions under our Credit Agreement do not, and any future credit facilities may not, allow such repurchases. A “change of control” (as defined in the indenture for the Notes) will also be an event of default under the Credit Agreement that would permit the lenders to accelerate the debt outstanding under the Credit Agreement. Finally, using available cash to fund the potential consequences of a change of control may impair our ability to obtain additional financing in the future, which could negatively impact our ability to conduct our business operations.

Item 6. Exhibits

The exhibits to this report are listed in the Exhibit Index appearing on page 24.

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SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) 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, on November 8, 2007.

W&T OFFSHORE, INC.
By:	/S/ JOHN D. GIBBONS
	John D. Gibbons Senior Vice President, Chief Financial Officer and Chief Accounting Officer

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EXHIBIT INDEX

Exhibit Number		Description
10.1		Waiver and Fourth Amendment to Third Amended and Restated Credit Agreement, as amended (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on November 7, 2007)
31.1	*	Section 302 Certification of Chief Executive Officer
31.2	*	Section 302 Certification of Chief Financial Officer
32.1	*	Section 906 Certification of Chief Executive Officer and Chief Financial Officer

* Filed or furnished herewith.

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