W&T Offshore (WTI) 10-Q 2006 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 2006

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	77046-0905
(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.    Yes  x    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 filer  ¨    Non-accelerated filer  x

Indicate by check mark whether the registrant is a shell company.    Yes  ¨    No  x

As of November 14, 2006, there were 75,900,082 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, 2006 and December 31, 2005	1
	Condensed Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2006 and 2005	2
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2006 and 2005	3
	Notes to Condensed Consolidated Financial Statements	4
	Report of Independent Registered Public Accounting Firm	13
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	21
Item 4.	Controls and Procedures	22
PART II – OTHER INFORMATION
Item 6.	Exhibits	22
SIGNATURE		23
EXHIBIT INDEX		24

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.

This Quarterly Report on Form 10-Q 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 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, 2005 and may be discussed from time to time in our reports filed with the Securities and Exchange Commission subsequent to this report. We assume no obligation, nor do we intend, to update these forward-looking statements.

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

(Unaudited)

	September 30, 2006			December 31, 2005
Assets
Current assets:
Cash and cash equivalents	$	12,071		$	187,698
Receivables:
Oil and gas sales		78,491			43,892
Joint interest and other		29,481			33,097
Insurance receivables		51,579			6,634
Total receivables		159,551			83,623
Royalty deposits		8,073			5,166
Prepaid expenses and other assets		48,225			7,337
Total current assets		227,920			283,824
Property and equipment – at cost:
Oil and gas properties and equipment (full cost method, of which $395,886 at September 30, 2006 and $0 at December 31, 2005 were excluded from amortization)		3,068,714			1,479,832
Furniture, fixtures and other		13,738			7,033
Total property and equipment		3,082,452			1,486,865
Less accumulated depreciation, depletion and amortization		911,635			717,583
Net property and equipment		2,170,817			769,282
Restricted deposits for asset retirement obligations		10,629			10,348
Other assets		12,459			1,066
Total assets	$	2,421,825		$	1,064,520
Liabilities and Shareholders’ Equity
Current liabilities:
Current maturities of long-term debt – net of discount	$	354,640		$	—
Accounts payable		169,936			143,049
Undistributed oil and gas proceeds		16,985			11,667
Asset retirement obligations		43,760			39,653
Accrued liabilities		12,037			5,714
Income taxes		51,189			31,609
Total current liabilities		648,547			231,692
Long-term debt, less current maturities – net of discount		316,233			40,000
Asset retirement obligations, less current portion		243,858			112,621
Deferred income taxes		199,964			134,395
Other liabilities		4,398			2,429
Commitments and contingencies
Shareholders’ equity:
Common stock, $0.00001 par value; 118,330,000 shares authorized; issued and outstanding 75,900,082 and 65,979,875 shares at September 30, 2006 and December 31, 2005, respectively		1			1
Additional paid-in capital		361,489			52,332
Retained earnings		648,080			491,050
Accumulated other comprehensive loss		(745	)		—
Total shareholders’ equity		1,008,825			543,383
Total liabilities and shareholders’ equity	$	2,421,825		$	1,064,520

See accompanying notes.

1

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per share data)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Revenues:
Oil and natural gas revenues	$	213,393		$	153,355		$	535,960		$	431,744
Other		38			70			122			532
Total revenues		213,431			153,425			536,082			432,276
Operating costs and expenses:
Lease operating		34,427			18,226			66,491			52,253
Production taxes		369			184			546			631
Gathering and transportation		4,817			2,367			11,148			9,555
Depreciation, depletion and amortization		82,142			43,403			194,052			131,967
Asset retirement obligation accretion		3,324			2,203			7,840			6,829
General and administrative		9,645			6,524			30,377			19,187
Commodity derivative gain		(27,065	)		—			(21,793	)		—
Total costs and expenses		107,659			72,907			288,661			220,422
Operating income		105,772			80,518			247,421			211,854
Other income (expense):
Interest income		2,111			844			5,505			1,334
Interest expense		(9,876	)		(263	)		(10,514	)		(866	)
Interest capitalized		4,138			—			4,138			—
Total other income (expense)		(3,627	)		581			(871	)		468
Income before income taxes		102,145			81,099			246,550			212,322
Income taxes		35,444			27,997			85,553			74,156
Net income	$	66,701		$	53,102		$	160,997		$	138,166
Earnings per common share:
Basic	$	0.92		$	0.80		$	2.36		$	2.14
Diluted		0.91			0.80			2.35			2.09
Dividends declared per common share		—			0.02			0.06			0.06

See accompanying notes.

2

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Nine Months Ended September 30,
	2006			2005
Operating activities:
Net income	$	160,997		$	138,166
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		201,892			138,796
Amortization of debt issuance costs		1,097			262
Accretion of discount on long-term debt		2,141			—
Share-based compensation		2,177			390
Unrealized commodity derivative gain		(15,224	)		—
Deferred income taxes		65,977			32,517
Changes in operating assets and liabilities:
Oil and gas sales receivables		(34,599	)		18,110
Joint interest and other receivables		3,617			906
Insurance receivables		(36,449	)		—
Income taxes		19,575			23,669
Prepaid expenses, royalty deposits and other assets		(39,306	)		(523	)
Asset retirement obligations		(20,781	)		(13,573	)
Accounts payable and accrued liabilities		40,354			5,174
Net cash provided by operating activities		351,468			343,894
Investing activities:
Investment in oil and gas property and equipment, net		(1,449,095	)		(227,464	)
Investment in marketable securities		—			(1,822	)
Purchases of furniture, fixtures and other		(6,705	)		(358	)
Change in restricted deposits		(280	)		(187	)
Net cash used in investing activities		(1,456,080	)		(229,831	)
Financing activities:
Borrowings of long-term debt		819,732			2,550
Repayments of borrowings of long-term debt		(191,000	)		(37,550	)
Proceeds from equity offering, net of costs		306,980			—
Dividends to shareholders		(5,947	)		(2,639	)
Debt issuance costs		(780	)		(889	)
Net cash provided by (used in) financing activities		928,985			(38,528	)
(Decrease) increase in cash and cash equivalents		(175,627	)		75,535
Cash and cash equivalents, beginning of period		187,698			64,975
Cash and cash equivalents, end of period	$	12,071		$	140,510

See accompanying notes.

3

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

Operations. W&T Offshore, Inc., together with its wholly-owned subsidiaries (“W&T” or the “Company”), is an independent oil and natural gas acquisition, exploitation and exploration company primarily focused in the Gulf of Mexico.

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, 2005.

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 generally accepted accounting principles 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. Acquisition

On August 24, 2006, we completed the acquisition of a wholly-owned subsidiary of Kerr-McGee Oil & Gas Corporation (“Kerr-McGee”) by merger. We own the surviving entity, which is the successor to substantially all of Kerr-McGee’s Gulf of Mexico conventional shelf properties. The properties acquired include interests in approximately 100 fields on 242 offshore blocks (including 88 undeveloped blocks) spreading across the Western, Central and Eastern U.S. Gulf of Mexico, primarily in water depths of less than 1,000 feet. Based on our estimates, the total proved reserves of these properties approximated 280.5 Bcfe at June 30, 2006. This transaction was financed through a combination of cash on hand, additional debt and proceeds from the issuance of equity securities (see Notes 3 and 4).

This acquisition was accounted for as a purchase, and accordingly, the results of operations are included in our consolidated statements of income from the date of acquisition. The purchase price was allocated to the acquired assets and assumed liabilities based on their estimated fair value at the time of acquisition. We are in the process of finalizing the adjusted purchase price based on our review of results of operations of the properties from the effective date of the transaction to the closing date; therefore, the allocation of the purchase price as of September 30, 2006 is preliminary. The following summarizes the estimated fair values of assets acquired and liabilities assumed at closing (in thousands).

4

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Purchase price:
Cash paid, including transaction costs	$	1,061,769
Plus fair market value of liabilities assumed:
Asset retirement obligations		143,641
	$	1,205,410
Allocation of purchase price:
Proved oil and gas properties	$	813,670
Unproved oil and gas properties		391,740
	$	1,205,410

The following unaudited pro forma data illustrates the effect on our historical results of operations as if the merger transaction, an offering of the Company’s common stock to provide funds for the merger transaction and borrowings under the Company’s $1.3 billion senior credit facility to partially fund the merger had occurred at the beginning of each period presented. The pro forma data is a result of adjusting our statements of income for the three and nine months ended September 30, 2006 and 2005, respectively, for the pre-acquisition revenues and direct operating expenses of the Kerr-McGee acquired properties, increased depreciation, depletion, amortization and accretion resulting from the allocation of fair value to the oil and gas properties acquired and the asset retirement obligations assumed, increased general and administrative expenses due to the need for additional personnel to manage the Company after the acquisition and increased interest expense on acquisition debt. The pro forma adjustments include estimates and assumptions based on currently available information. The pro forma data does not necessarily reflect the actual operating results that would have occurred nor are they necessarily indicative of future results of operations (in thousands, except per share data).

	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
Revenues	$	329,839	$	281,151	$	883,071	$	875,087
Net income		79,041		78,835		212,731		221,310
Earnings per share:
Basic	$	1.04	$	1.10	$	2.81	$	2.97
Diluted	$	1.04	$	1.10	$	2.80	$	2.92

3. Long-Term Debt

On May 26, 2006, we entered into a credit agreement principally in connection with the funding of the Kerr-McGee transaction. Upon closing of the Kerr-McGee transaction in August 2006, our initial availability under the credit agreement was $987.5 million. The credit agreement provides for (1) a revolving loan with an initial availability of $300.0 million, (2) a Tranche A term loan in the amount of $387.5 million and (3) a Tranche B term loan in the amount of $300.0 million. The amount available under the revolving loan is subject to redetermination on March 1 and September 1 of each year commencing September 1, 2007. Additionally, the agreement provides for the availability of letters of credit for up to $90.0 million, provided however, that its usage is subject to availability under the revolving loan.

Interest accrues either (1) at the higher of the Prime Rate, or the Federal Funds Rate plus 0.50%, plus a margin which varies from 0.0% to 1.75% depending upon the loan or (2) to the extent any loan outstanding is designated as a Eurodollar loan, at the London Interbank Offered Rate plus a margin that varies from 1.25% to 2.75% depending upon the loan. The Tranche A and Tranche B term loans are payable in installments and mature fifteen months from initial funding and on the fourth anniversary of initial funding, respectively. The revolving loan matures on the third anniversary of initial funding. The interest rates on the Tranche A and Tranche B term loans were 8.15% and 7.65%, respectively, at September 30, 2006.

5

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The credit agreement contains covenants that restrict the payment of cash dividends to a maximum of $30.0 million per year, borrowings other than from the facilities, sales of assets, loans to others, investments, merger activity, hedging contracts, liens and certain other transactions without the prior consent of the lenders. We are required 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 loans at all times, as well as certain commodity derivatives. We are also subject to various financial covenants calculated as of the last day of each fiscal quarter, including a minimum current ratio beginning with the quarter ending on March 31, 2007, a minimum interest coverage ratio, a minimum asset coverage ratio and a maximum leverage ratio. We were in compliance with these covenants on September 30, 2006.

As of September 30, 2006 and December 31, 2005 our long-term debt was as follows (in thousands):

	September 30, 2006			December 31, 2005
Revolving loan facility	$	—		$	40,000
Tranche A term loan facility, net of unamortized discount of $8,662		378,838			—
Tranche B term loan facility, net of unamortized discount of $7,965		292,035			—
Total long-term debt		670,873			40,000
Current maturities of long-term debt		(354,640	)		—
Long-term debt, less current maturities	$	316,233		$	40,000

At September 30, 2006 we did not have any letters of credit outstanding. At December 31, 2005 we had $0.3 million of letters of credit outstanding.

4. Equity Offering

In July 2006 the Company completed an additional equity offering of 8,500,000 shares of its common stock at an offering price of $32.50 per share. The Underwriting Agreement also included a 30-day option to the underwriters to purchase up to an additional 1,275,000 shares at the offering price, less underwriting discounts and commissions. In August 2006 the over-allotment option was exercised in full. Net proceeds generated by the offering and the exercise of the over-allotment option were approximately $307.0 million after underwriting discounts and commissions of approximately $9.5 million and legal, accounting, printing and various other fees of approximately $1.2 million. The net proceeds from the equity offering and the exercise of the over-allotment option were used in connection with the funding of the Kerr-McGee transaction.

5. Derivative Financial Instruments

We account for our derivative contracts in accordance with Statement of Financial Accounting Standards (“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 transaction with 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 and nine months ended September 30, 2006, we recorded an unrealized gain of $22.7 million and $15.2 million related to our open derivative contracts, respectively. For the three and nine months ended September 30, 2006, we recorded a realized gain of $4.4 million and $6.6 million, respectively, related to settlements of our commodity derivatives. At September 30, 2006, we had a short term asset of $13.9 million included in prepaid expenses and other assets, a long term asset of $5.6 million included in other assets and a long term liability of $0.8 million included in other liabilities related to our open commodity derivatives.

6

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

As of September 30, 2006, our open commodity derivatives were as follows:

Collars
					NYMEX Contract Price
Type	Commodity	Effective Date	Termination Date	Notional Quantity	Floor		Ceiling
Zero Cost	Natural Gas	11/1/2006	12/31/2006	2,013,000 MMBtu	$	8.04	$	14.49
Funded	Natural Gas	1/1/2007	12/31/2007	8,760,000 MMBtu		7.76		16.80
Zero Cost	Oil	1/1/2007	12/31/2007	1,569,500 Bbls		61.68		76.40
Funded	Natural Gas	1/1/2008	12/31/2008	5,124,000 MMBtu		7.31		15.80
Zero Cost	Oil	1/1/2008	12/31/2008	1,024,800 Bbls		60.00		74.50

Swaps
Commodity	Effective Date	Termination Date	Notional Quantity	Price
Oil	10/1/2006	12/31/2006	248,400 Bbls	$69.85

Interest Rate Swaps. In connection with the Kerr-McGee merger transaction, our credit agreement required that we enter into interest rate swap contracts. In August 2006, we entered into two interest rate swaps, which serve as a hedge of the variable LIBOR rates used to reset the floating rates of our Tranche A and Tranche B term loans. These swaps have notional amounts that equate to 50% of the aggregate outstanding principal balance of the Tranche A and Tranche B term loans, and fix the rates at 5.41% and 5.16%, respectively. These swaps have been determined to be highly effective as it relates to the variability in the LIBOR interest rate and, therefore, qualify, and are designated by management, as cash flow hedges under SFAS No. 133.

At September 30, 2006, a $0.7 million, net of income tax, unrealized loss on hedging activity is included in accumulated other comprehensive loss resulting from the decrease in fair value of the interest rate swaps. Realized gains or losses on the swaps will be recorded to interest expense in future periods. The actual amounts that will be recorded to our consolidated statement of income could vary from this estimated amount as a result of future changes in interest rates. For the three and nine-month periods ended September 30, 2006, no amount was recognized in earnings due to ineffectiveness related to our interest rate swaps.

At September 30, 2006, we had a long term liability of $1.2 million included in other liabilities related to our interest rate swaps.

6. Comprehensive Income

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2006			2005		2006			2005
Net income	$	66,701		$	53,102	$	160,997		$	138,166
Change in the fair value of open interest rate swaps, net of income tax		(745	)		—		(745	)		—
Comprehensive income	$	65,956		$	53,102	$	160,252		$	138,166

7

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Accumulated Other Comprehensive Loss. Our accumulated other comprehensive loss for the period ended September 30, 2006 is as follows (in thousands):

Balance, December 31, 2005	$	—
Net change in unrealized losses on interest rate swaps		(745	)
Balance, September 30, 2006	$	(745	)

7. 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 since year-end December 31, 2005 is as follows (in thousands):

Balance, December 31, 2005	$	152,274
Liabilities settled		(20,781	)
Accretion of discount		7,840
Liabilities assumed through acquisition		143,641
Liabilities incurred		5,352
Revisions of estimated liabilities		(708	)
Balance, September 30, 2006		287,618
Less current portion		43,760
Long-term	$	243,858

8. Dividends

On August 1, 2006, we paid a cash dividend of $0.03 per common share to shareholders of record on July 14, 2006. On October 11, 2006, our board of directors declared a cash dividend of $0.03 per common share, which was paid on November 1, 2006 to shareholders of record on October 22, 2006.

9. Earnings Per Share

Basic earnings per share is 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 dilutive impact of preferred stock and nonvested restricted stock outstanding during the periods presented. In connection with our initial public offering in January 2005, all 2,000,000 shares of the Company’s preferred stock were converted into a total of 13,338,350 shares of common stock.

8

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,
	2006		2005		2006		2005
Net income (basic and diluted)	$	66,701	$	53,102	$	160,997	$	138,166
Weighted average number of common shares (basic)		72,882		65,970		68,300		64,649
Weighted average common shares assumed issued upon conversion of the preferred stock		—		—		—		1,319
Weighted average nonvested common shares		157		—		112		—
Weighted average number of common shares (diluted)		73,039		65,970		68,412		65,968
Earnings per share:
Basic	$	0.92	$	0.80	$	2.36	$	2.14
Diluted	$	0.91	$	0.80	$	2.35	$	2.09

10. Share-Based Compensation

Effective January 1, 2006, the Company adopted SFAS No. 123 (revised 2004) (“SFAS No. 123(R)”),Share-Based Payment, using the modified prospective transition method. SFAS No. 123(R) supersedes Accounting Principles Board Opinion No. 25,Accounting for Stock Issued to Employees, and revises guidance in SFAS No. 123,Accounting for Stock-Based Compensation. Under the modified prospective transition method, we are required to recognize compensation cost for share-based payments to employees over the period during which an employee is required to provide service in exchange for the award, based on the fair value of the equity instrument on the date of grant. Also, measurement and recognition of compensation cost for awards that were granted prior to, but not vested as of, the date of adoption should be based on their grant-date fair values. The new standard requires us to estimate forfeitures, resulting in the recognition of compensation cost only for those awards that actually vest. A cumulative effect of a change in accounting principle is required upon adoption to the extent that forfeitures were not estimated on share-based payments awarded prior to January 1, 2006 that were unvested on that date.

Historically, all of our share-based payments consisted of awards of unrestricted and restricted stock and were measured at their fair values on the dates of grant. As of January 1, 2006, the date we adopted SFAS No. 123(R), there were a total of 9,251 shares of restricted stock that had not vested and these shares were held by an executive officer of the Company. We estimated that the probability of forfeiture of these shares on the date of adopting SFAS No. 123(R) was remote; therefore, an adjustment to record a cumulative effect of a change in accounting principle was not required.

Shares of our common stock may be granted to employees and non-employee directors as restricted shares under our long-term incentive compensation plans. Restricted shares are subject to forfeiture restrictions and cannot be sold, transferred or disposed of during the restriction period. The holders of restricted shares generally have the same rights as a shareholder of the Company with respect to such shares, including the right to vote and receive dividends or other distributions paid with respect to the shares.

The Company generally issues new shares in connection with its share-based payment plans. During the quarter ended September 30, 2006, the Company did not issue any shares of common stock pursuant to its share-based payment plans. During the nine months ended September 30, 2006, a total of 161,784 restricted shares of our common stock were granted to employees pursuant to share-based payment plans. The restricted stock will vest in three equal increments on December 31, 2006, 2007 and 2008 and the associated compensation expense, less an allowance for estimated forfeitures, is being recognized over the requisite service period on a straight-line basis. In the second quarter of 2006, our non-employee directors were granted a total of 3,948 restricted shares of our common stock, with restrictions lapsing with respect to one-third of the shares on each of the first, second, and third anniversaries from the date of grant.

9

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

At September 30, 2006, there were 2,159,152 shares of common stock available for award under our share-based payment plans. A summary of restricted share activity for the nine months ended September 30, 2006, is as follows:

	Shares		Weighted Average Grant Date Fair Value
Nonvested at January 1, 2006	9,251		$	32.43
Granted	165,732		$	37.30
Vested	(2,087	)	$	37.17
Forfeited	(20,525	)	$	35.03
Nonvested at September 30, 2006	152,371		$	37.31

The grant date fair value of restricted shares granted during the nine months ended September 30, 2006 was $6.2 million. As of September 30, 2006, there was $3.1 million of total unrecognized compensation expense related to restricted shares, which is expected to be recognized through May 31, 2009. Total compensation expensed under share-based payment arrangements was $0.4 million and $2.0 million during the three and nine months ended September 30, 2006, respectively. For the nine months ended September 30, 2005, total compensation expensed under share-based payment arrangements was $0.5 million, substantially all of which was recorded in the first quarter of 2005.

11. Long-Term Incentive Compensation

2005 Bonus. In March 2006, our board of directors approved payment of a general bonus and an Extraordinary Performance Bonus under our long-term incentive compensation plan, as amended by the W&T Offshore, Inc. 2005 Annual Incentive Plan (the “2005 Plan”). The 2005 Plan includes all employees of the Company except those executive officers (including our Chief Executive Officer and our Secretary) who, by written agreement, have elected not to participate. The awards consist of cash and restricted stock payable from a bonus pool equating to a maximum value of five percent of adjusted pre-tax income for 2005. Payment of the Extraordinary Performance Bonus was contingent upon the Company achieving certain performance goals in 2005; however, such goals were subject to adjustment by the Compensation Committee of our board of directors for extraordinary or unusual items or events. Although not all of the performance measures for the Extraordinary Performance Bonus were met, our board determined that substantially all of the performance measures would have been met in 2005 if not for the effects of Hurricanes Katrina and Rita. As such, in March 2006, our board awarded a 2005 Extraordinary Performance Bonus with an aggregate value of $3.4 million to eligible employees.

Cash bonuses under the 2005 Plan (general bonus and Extraordinary Performance Bonus) were paid in March 2006 and totaled $4.2 million. Of this amount, $2.2 million was expensed in 2005, $1.7 million was expensed in the first quarter of 2006 and the remainder was billed to partners under joint operating agreements.

In March 2006, a total of 160,377 restricted shares of our common stock were issued as awards under the 2005 Plan to eligible employees. The restricted stock will vest in three equal increments on December 31, 2006, 2007 and 2008 and the associated compensation expense, less an allowance for estimated forfeitures, will be recognized over the requisite service period in accordance with SFAS No. 123(R) (see Note 10).

2006 Bonus. In accordance with the 2005 Plan, eligible employees will be entitled to receive cash bonuses and awards of restricted stock from a bonus pool generally limited to five percent of adjusted pre-tax income for 2006. Part of the bonus will be a general bonus, consisting of cash and restricted stock. An Extraordinary Performance Bonus, also consisting of cash and restricted stock, will be paid only if the Company achieves certain performance goals which may be adjusted by the Compensation Committee

10

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

for extraordinary or unusual items or events. Shares of restricted stock awarded as incentive compensation for performance in 2006 will vest in three equal annual installments on December 31, 2007, 2008 and 2009. During the three and nine months ended September 30, 2006, we expensed $1.4 million and $4.1 million, respectively, related to the 2006 bonus.

12. Income Taxes

The Katrina Emergency Tax Relief Act of 2005, signed on September 23, 2005, postponed tax deadlines with a due date falling on or after August 29, 2005 until February 28, 2006 for taxpayers affected by Hurricane Katrina. On February 17 and August 25, 2006, the Internal Revenue Service further postponed tax deadlines with a due date falling on or after August 29, 2005 until August 28 and October 16, 2006, respectively, for taxpayers affected by Hurricane Katrina. Consequently, our estimated federal income tax payments due in the third and fourth quarters of 2005 and the second and third quarters of 2006 were paid on October 16, 2006 and totaled $40.7 million.

13. Related Party Transactions

Virginia Boulet, who serves as special counsel to Adams and Reese LLP, was appointed to our board of directors on March 25, 2005. During the nine months ended September 30, 2006 and 2005, we paid approximately $0.3 million and $0.4 million, respectively, to Adams and Reese LLP for legal services.

Brooke Companies, Inc. provides personnel to fill temporary and permanent staffing needs of the Company from time to time. Susan Krohn, the wife of Tracy W. Krohn, owns 100% of Brooke Companies. Brooke Companies currently provides staffing services to our Company and we expect that it will continue to provide those services for the foreseeable future. During the nine months ended September 30, 2006 and 2005, the Company paid Brooke Companies approximately $0.4 million and $0.2 million, respectively.

The grandson of Jerome F. Freel, a director and our corporate Secretary, is employed by an insurance agency that arranges as a broker certain insurance coverage for the Company. We have been informed by Mr. Freel’s grandson that personal commissions earned by the grandson for arranging such coverage through his employer totaled approximately $0.1 million during the nine months ended September 30, 2006.

As part of our relocation program for employees moving from Louisiana to Texas, the Company agreed to purchase an employee’s home in Louisiana that has been actively marketed and has been for sale for a period greater than 90 days. The purchase price of the home is negotiable and is based on a reasonable appraised value. During the nine months ended September 30, 2006, the Company purchased homes from two of our vice presidents for a total of approximately $2.8 million pursuant to the relocation program, which is included in furniture, fixtures and other at September 30, 2006.

14. Insurance Receivables

As of September 30, 2006 we have incurred $12.1 million of development costs and $62.4 million of production costs (consisting primarily of repairs and maintenance and well control expenses), net to our interest, to remediate damage caused by Hurricanes Katrina and Rita that we believe are probable of reimbursement under our insurance policies. We reclassified these costs to insurance receivables and other assets and continue to process claims with our underwriters for reimbursement. As of September 30, 2006, we have received reimbursements of our claims totaling $17.2 million. Included in insurance receivables and other assets at September 30, 2006 is $45.7 million and $6.1 million, respectively, which represents the estimated reimbursable hurricane remediation costs incurred in excess of our deductibles. Any differences between our insurance recoveries and insurance receivables will be recorded as adjustments to development costs or production costs, depending on how the classification of the original cost was recorded. Our estimate of total development and production costs to remediate damage caused by hurricanes Katrina and Rita is between $90 million and $100 million.

11

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Also included in insurance receivables at September 30, 2006 is $5.9 million related to an insurance claim to recover estimated reimbursable drilling costs on a well that experienced uncontrollable water flow in the second quarter of 2006. We believe that this amount is probable of reimbursement under our insurance policies.

15. Recent Accounting Pronouncements

In July 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes – an interpretation of SFAS No. 109, (“FIN 48”), which clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109,Accounting for Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. It also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. Adoption of FIN 48 is not expected to have a material effect on our consolidated financial statements.

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.

In September 2006, the SEC Staff issued Staff Accounting Bulletin (“SAB”) No. 108,Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, in an effort to address diversity in practice of quantifying misstatements and the potential for improper amounts on the balance sheet. Prior to the issuance of SAB No. 108, the “roll-over” and “iron curtain” methods were used for quantifying the effects of financial statement errors. Under the “roll-over” method, the primary focus was the income statement, including reversing effects of prior year misstatements. By focusing on the income statement, misstatements could accumulate on the balance sheet. Under the “iron curtain” method, the focus was the ending balance sheet, with less importance on the reversing effects of prior year errors in the income statement. SAB No. 108 establishes a “dual approach,” which requires the quantification of the effect of financial statement errors on each financial statement, as well as related disclosures. Public companies are required to record the cumulative effect of initially adopting the “dual approach” method in the first fiscal year ending after November 16, 2006 by recording any necessary corrections to assets and liabilities with an offsetting adjustment to the opening balance of retained earnings. The use of this cumulative effect transition method also requires detailed disclosures of the nature and amount of each error being corrected and how and when they arose. We do not expect this bulletin to have an effect on our consolidated financial statements.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

W&T Offshore, Inc. and Subsidiaries:

We have reviewed the condensed consolidated balance sheet of W&T Offshore, Inc. and Subsidiaries as of September 30, 2006, and the related condensed consolidated statements of income for the three-month and nine-month periods ended September 30, 2006 and 2005, and the condensed consolidated statements of cash flows for the nine-month periods ended September 30, 2006 and 2005. These financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the condensed consolidated financial statements referred to above for them to be in conformity with U.S. generally accepted accounting principles.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of W&T Offshore, Inc. and Subsidiaries as of December 31, 2005, and the related consolidated statements of income, changes in shareholders’ equity and cash flows for the year then ended (not presented herein) and in our report dated March 30, 2006, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2005, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ ERNST & YOUNG LLP

Houston, Texas

November 13, 2006

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

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 includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements.

Overview

W&T is an independent oil and natural gas company primarily focused in the Gulf of Mexico, including exploration in the deepwater where we have developed significant technical expertise. W&T has grown through acquisitions, exploitation and exploration and currently holds working interests in over 200 fields in federal and state waters. The majority of our daily production is derived from wells we operate.

During the third quarter of 2006 –

• We completed our previously announced acquisition of a wholly-owned subsidiary of Kerr-McGee by merger. As a result of closing adjustments provided for under the Agreement and Plan of Merger effective as of October 1, 2005 (the “Merger Agreement”), the amount due at closing was approximately $1.0 billion. The final purchase price is subject to additional post-closing adjustments pursuant to and in accordance with the Merger Agreement. The properties acquired include interests in approximately 100 fields on 242 offshore blocks (including 88 undeveloped blocks) spreading across the Western, Central and Eastern U.S. Gulf of Mexico, primarily in water depths of less than 1,000 feet. Based on our estimates, the total proved reserves of these properties approximated 280.5 Bcfe at June 30, 2006.

• Net income increased 26% to $66.7 million as compared to the third quarter of 2005. Net income for the third quarter of 2006 includes an unrealized gain of $14.8 million (after taxes) related to our open commodity derivative contracts. Without the effect of the unrealized commodity derivative gain, net income for the third quarter of 2006 would have been $51.9 million or $0.71 per diluted share.

• We participated in drilling seven exploration wells, all of which were successful. Two of the exploration wells were on the conventional shelf, four were in the deep shelf and one was in the deepwater. We also participated in drilling one successful development well on the conventional shelf.

• On August 1, 2006, we paid a cash dividend of $0.03 per common share to shareholders of record on July 14, 2006.

14

Results of Operations

The following table sets forth selected 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,
	2006		2005		2006			2005
Net sales:
Natural gas (Bcf)		15.4		11.5		37.5			37.1
Oil (MMBbls)		1.8		1.0		4.3			3.4
Total natural gas and oil (Bcfe) (1)		26.2		17.5		63.3			57.4
Average daily equivalent sales (MMcfe/d)		285.1		189.7		232.0			210.3
Average realized sales prices (2):
Natural gas ($/Mcf)	$	6.58	$	8.64	$	7.35		$	7.31
Oil ($/Bbl)		62.08		54.39		60.48			47.38
Natural gas equivalent ($/Mcfe)		8.14		8.79		8.46	��		7.52
Average per Mcfe data ($/Mcfe):
Lease operating expenses	$	1.31	$	1.04	$	1.05		$	0.91
Gathering, transportation cost and production taxes		0.20		0.15		0.18			0.18
Depreciation, depletion, amortization and accretion		3.26		2.61		3.19			2.42
General and administrative expenses		0.37		0.37		0.48			0.33
Total number of wells drilled (gross)		8		5		28			19
Total number of productive wells drilled (gross)		8		5		24			16

(1) 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).

(2) Average realized prices exclude the effects of our derivative contracts that do not qualify for hedge accounting. Had we included the effect of these derivatives, our average realized sales price for natural gas would have been $6.87 per Mcf for the third quarter of 2006 and $7.54 per Mcf for the nine months ended September 30, 2006. Our average realized sales price for oil would have been $62.00 per barrel for the third quarter of 2006 and $60.33 per barrel for the nine months ended September 30, 2006. On a natural gas equivalent basis, our average realized sales price would have been $8.30 per Mcfe for the third quarter of 2006 and $8.57 per Mcfe for the nine months ended September 30, 2006. We did not have any derivative contracts in place during the periods ended in 2005.

Other Financial Information (in thousands)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
EBITDA	$	191,238	$	126,124	$	449,313	$	350,650
Adjusted EBITDA	$	168,524	$	126,124	$	434,089	$	350,650

We define EBITDA as net income plus income tax expense, net interest (income) expense, and depreciation, depletion, amortization and accretion. Adjusted EBITDA excludes 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 are relevant and useful because they help our investors understand our operating performance and make it easier to compare our results with those of other companies that have

15

different financing, capital or 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,
	2006			2005			2006			2005
Net income	$	66,701		$	53,102		$	160,997		$	138,166
Income taxes		35,444			27,997			85,553			74,156
Net interest expense (income)		3,627			(581	)		871			(468	)
Depreciation, depletion, amortization and accretion		85,466			45,606			201,892			138,796
EBITDA		191,238			126,124			449,313			350,650
Unrealized commodity derivative gain		(22,714	)		—			(15,224	)		—
Adjusted EBITDA	$	168,524		$	126,124		$	434,089		$	350,650

Three Months Ended September 30, 2006 Compared to the Three Months Ended September 30, 2005

Oil and natural gas revenues. Oil and natural gas revenues increased $60.0 million to $213.4 million for the three months ended September 30, 2006 as compared to the same period in 2005. Natural gas revenues increased $1.7 million and oil revenues increased $58.3 million. The natural gas revenue increase was primarily caused by a sales volume increase of 3.9 Bcf, which was partially offset by a 24% decrease in the average realized natural gas price from $8.64 per Mcf for the three months ended September 30, 2005 to $6.58 per Mcf for the same period in 2006. The natural gas volume increase is primarily attributable to our acquisition of a wholly-owned subsidiary of Kerr-McGee by merger in August 2006. The oil revenue increase was caused by a sales volume increase of 816 MBbls and a 14% increase in the average realized price, from $54.39 per barrel in the 2005 period to $62.08 per barrel in the 2006 period. The oil volume increase is primarily the result of successful drilling efforts and the Kerr-McGee merger transaction.

Lease operating expenses. Our lease operating expenses increased from $18.2 million in the quarter ended September 30, 2005 to $34.4 million in the same period of 2006. The increase is primarily attributable to the Kerr-McGee merger transaction and increases in insurance premiums as a result of last year’s hurricanes, hurricane repair costs, overall service costs and supply costs at our existing properties. On a per Mcfe basis, lease operating expenses increased 26%, from $1.04 per Mcfe in the 2005 period to $1.31 per Mcfe in 2006. Lease operating expenses for the quarter ended September 30, 2006 excludes $21.3 million of hurricane remediation costs reclassified to insurance receivables and other assets that we believe are reimbursable under our insurance policies.

Gathering and transportation costs and production taxes. Gathering and transportation costs increased from $2.4 million for the three months ended September 30, 2005 to $4.8 million for the same period in 2006, primarily due to higher throughput of natural gas and an increased ownership interest in 2006 at one of our processing facilities. Production taxes increased from $0.2 million for the three months ended September 30, 2005 to $0.4 million for the same period in 2006. Most of our production is from federal waters, where there are no production taxes.

Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion (“DD&A”) increased from $45.6 million for the quarter ended September 30, 2005 to $85.5 million for the same period in 2006. DD&A was higher in the 2006 period as a result of an increase in our total depletable costs due to the Kerr-McGee merger transaction and our drilling activities. On a per Mcfe basis, DD&A was $3.26 for the three months ended September 30, 2006, compared to $2.61 for the same period in 2005.

General and administrative expenses. General and administrative expenses (“G&A”) increased from $6.5 million for the three months ended September 30, 2005 to $9.6 million in the same period of 2006 primarily due to increased personnel and resources necessary to administer our growth and increased professional fees related to the requirement that the Company be able to provide management’s assessment of internal control over financial reporting as prescribed by Section 404 of the Sarbanes-Oxley Act of 2002 as of December 31, 2006.

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Commodity derivative gain.For the three months ended September 30, 2006, we recorded 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.

Interest income. Interest income increased from $0.8 million for the quarter ended September 30, 2005 to $2.1 million in the same period of 2006 primarily due to greater average daily balances of cash on hand in the 2006 period and higher yields on cash investments.

Interest expense. Interest expense, net of amounts capitalized, increased from $0.3 million for the quarter ended September 30, 2005 to $5.7 million in the same period of 2006 primarily due to higher average borrowings related to the Kerr-McGee merger transaction during the quarter ended in 2006. During the 2006 quarter, $4.1 million of interest was capitalized to unevaluated oil and gas properties acquired in the Kerr-McGee merger transaction.

Income tax expense. Income tax expense increased from $28.0 million for the quarter ended in 2005 to $35.4 million for the same period in 2006 primarily due to increased taxable income. Our effective tax rate for the three months ended September 30, 2006 and 2005 remained flat at approximately 35%.

Net income. Net income for the three months ended September 30, 2006 increased $13.6 million to $66.7 million compared to the same period in 2005. The primary reasons for this increase were as follows:

• higher volumes of natural gas sold during the quarter ended in 2006 of 15.4 Bcf, as compared to 11.5 Bcf during the same period in 2005;

• higher volumes of oil sold during the quarter ended in 2006 of 1.8 MMBbls, as compared to 1.0 MMBbls during the same period in 2005;

• higher average realized oil prices during the quarter ended in 2006 of $62.08 per barrel, as compared to $54.39 per barrel during the same period in 2005; and

• a commodity derivative gain of $27.1 million ($17.7 million after taxes) during the quarter ended in 2006.

Offsetting these favorable factors were lower average realized natural gas prices and increases in lease operating expenses, gathering and transportation costs, DD&A, G&A, interest expense and income taxes.

Nine Months Ended September 30, 2006 Compared to the Nine Months Ended September 30, 2005

Oil and natural gas revenues. Oil and natural gas revenues increased $104.2 million to $535.9 million for the nine months ended September 30, 2006 as compared to the same period in 2005. Natural gas revenues increased $3.8 million and oil revenues increased $100.4 million. The natural gas revenue increase was caused by a sales volume increase of 0.4 Bcf and a 1% increase in the average realized natural gas price from $7.31 per Mcf for the nine months ended September 30, 2005 to $7.35 per Mcf for the same period in 2006. The natural gas volume increase is primarily attributable the Kerr-McGee merger transaction, which was substantially offset by natural reservoir declines. The oil revenue increase was caused by a 28% increase in the average realized price, from $47.38 per barrel in the 2005 period to $60.48 per barrel in 2006 and a sales volume increase of 929 MBbls. The oil volume increase is primarily the result of successful drilling efforts and the Kerr-McGee merger transaction.

Lease operating expenses. Our lease operating expenses increased from $52.3 million in the nine months ended September 30, 2005 to $66.5 million in the same period of 2006. The increase is primarily attributable to the Kerr-McGee merger transaction and increases in insurance premiums as a result of last year’s hurricanes, hurricane repair costs, overall service costs and supply costs at our existing properties. On a per Mcfe basis, lease operating expenses increased from $0.91 per Mcfe in the 2005 period to $1.05 per Mcfe for the same period in 2006 as a result of higher costs in 2006. Lease operating expenses for the nine months ended September 30, 2006 excludes $53.9 million of hurricane remediation costs reclassified to insurance receivables and other assets that we believe are reimbursable under our insurance policies.

17

Gathering and transportation costs and production taxes. Gathering and transportation costs increased from $9.6 million for the nine months ended September 30, 2005 to $11.1 million for the same period in 2006, primarily due to higher throughput of natural gas and an increased ownership interest in 2006 at one of our processing facilities. Production taxes decreased from $0.6 million for the nine months ended September 30, 2005 to $0.5 million for the same period in 2006. Most of our production is from federal waters, where there are no production taxes.

Depreciation, depletion, amortization and accretion. DD&A increased from $138.8 million for the nine months ended September 30, 2005 to $201.9 million for the same period in 2006. DD&A increased as a result of an increase in our total depletable costs due to the Kerr-McGee merger transaction and our drilling activities. On a per Mcfe basis, DD&A was $3.19 for the nine months ended September 30, 2006, compared to $2.42 for the same period in 2005.

General and administrative expenses. G&A increased from $19.2 million for the nine months ended September 30, 2005 to $30.4 million in the same period of 2006 primarily due to increased personnel and resources necessary to administer our growth and increased professional fees related to the requirement that the Company be able to provide management’s assessment of internal control over financial reporting as prescribed by Section 404 of the Sarbanes-Oxley Act of 2002 as of December 31, 2006. Also included in G&A for the period ended in 2006 are expenses of $1.1 million related to the relocation of the majority of our employees to Houston, Texas and expenses of $0.4 million related to the temporary displacement of those employees due to damage caused by Hurricanes Katrina and Rita. Included in G&A for the nine months ended September 30, 2005 are expenses of $0.9 million related to our initial public offering in January 2005.

Commodity derivative gain.For the nine months ended September 30, 2006, we recorded 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.

Interest income. Interest income increased $4.2 million for the nine months ended September 30, 2006 as compared to the same period in 2005 primarily due to greater average daily balances of cash on hand in the 2006 period and higher yields on cash investments.

Interest expense. Interest expense, net of amounts capitalized, increased $5.5 million for the nine months ended September 30, 2006 as compared to the same period in 2005 primarily due to higher average borrowings related to the Kerr-McGee merger transaction during the period ended in 2006. During the 2006 period, $4.1 million of interest was capitalized to unevaluated oil and gas properties acquired in the Kerr-McGee merger transaction.

Income tax expense. Income tax expense increased from $74.2 million for the nine months ended in 2005 to $85.6 million for the same period in 2006 primarily due to increased taxable income. Our effective tax rate for the nine months ended September 30, 2006 and 2005 remained flat at approximately 35%.

Net income. Net income for the nine months ended September 30, 2006 increased $22.8 million to $161.0 million. The primary reasons for this increase were as follows:

• higher volumes of oil sold during the nine months ended in 2006 of 4.3 MMBbls, as compared to 3.4 MMBbls during the same period in 2005;

• higher average realized oil prices during the nine months ended in 2006 of $60.48 per barrel, as compared to $47.38 per barrel during the same period in 2005;

• a commodity derivative gain of $21.8 million ($14.2 million after taxes) during the nine months ended in 2006; and

• higher interest income for the nine months ended in 2006 as compared to the same period in 2005.

Offsetting these favorable factors were increases in lease operating expenses, gathering and transportation costs, DD&A, G&A, interest expense and income taxes.

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Liquidity and Capital Resources

Cash flow and working capital. Net cash flow provided by operating activities for the nine months ended September 30, 2006 was $351.5 million, compared to $343.9 million for the comparable period in 2005. Net cash flow used in investing activities totaled $1.5 billion and $229.8 million during the first nine months of 2006 and 2005, respectively, which primarily represents our investment in oil and gas properties. Included in the 2006 amount is approximately $1.1 billion, which primarily represents the adjusted purchase price of the Kerr-McGee transaction which was completed in August 2006. The final purchase price is subject to additional post-closing adjustments pursuant to and in accordance with the Merger Agreement. Net cash flow provided by financing activities was $929.0 million during the nine months ended September 30, 2006 while net cash flow used in financing activities for the same period in 2005 was $38.5 million. The amount for 2006 primarily represents borrowings on long-term debt, net of repayments, and proceeds from our equity offering which was completed in the third quarter. The balance of cash and cash equivalents decreased from $187.7 million as of December 31, 2005 to $12.1 million as of September 30, 2006 primarily due to the use of our excess cash to partially fund the Kerr-McGee transaction. Our future net cash flow provided by operating activities will depend on our ability to maintain and increase production through our operations, drilling and acquisition programs, as well as the prices of oil and gas.

In anticipation of the financing of the Kerr-McGee transaction, in January 2006 we entered into commodity swap and option contracts relating to approximately 14 Bcfe of our production in 2006, 18 Bcfe of our production in 2007 and 11 Bcfe of our production in 2008. In August 2006, we entered into two interest rate swaps as required by our credit agreement. The swaps have notional amounts that equate to 50% of the aggregate outstanding principal balance of the Tranche A and Tranche B term loans that effectively fix the interest rates on those loans at 5.41% and 5.16%, respectively. While these contracts are intended to reduce the effects of volatile oil and gas prices and interest rates, they may also have the effect of limiting our potential income and exposing us to potential financial losses. We may enter into additional derivative contracts as management deems appropriate based upon prevailing prices.

The Katrina Emergency Tax Relief Act of 2005, signed on September 23, 2005, postponed tax deadlines with a due date falling on or after August 29, 2005 until February 28, 2006 for taxpayers affected by Hurricane Katrina. On February 17 and August 25, 2006, the Internal Revenue Service further postponed tax deadlines with a due date falling on or after August 29, 2005 until August 28 and October 16, 2006, respectively, for taxpayers affected by Hurricane Katrina. Consequently, our estimated federal income tax payments due in the third and fourth quarters of 2005 and the second and third quarters of 2006 were paid on October 16, 2006 and totaled $40.7 million.

As of September 30, 2006, we had a working capital deficit of $420.6 million. Under the terms of our credit agreement, we will be subject to a minimum current ratio beginning with the quarter ending on March 31, 2007. We believe that our working capital balance should be viewed in conjunction with our cash provided by operations and the availability of borrowings under our credit facility when assessing liquidity.

Insurance receivables. As of September 30, 2006 we have incurred $12.1 million of development costs and $62.4 million of production costs (consisting primarily of repairs and maintenance and well control expenses), net to our interest, to remediate damage caused by Hurricanes Katrina and Rita that we believe are probable of reimbursement under our insurance policies. We reclassified these costs to insurance receivables and other assets and continue to process claims with our underwriters for reimbursement. As of September 30, 2006, we have received reimbursements of our claims totaling $17.2 million. Included in insurance receivables and other assets at September 30, 2006 is $45.7 million and $6.1 million, respectively, which represents the estimated reimbursable hurricane remediation costs incurred in excess of our deductibles. Any differences between our insurance recoveries and insurance receivables will be recorded as adjustments to development costs or production costs, depending on how the classification of the original cost was recorded. Our estimate of total development and production costs to remediate damage caused by hurricanes Katrina and Rita is between $90 million and $100 million. We believe that our insurance coverage is adequate to cover losses associated with Hurricanes Katrina and Rita. We expect that our available cash and cash equivalents, cash flow from operations and the availability of our revolving credit facility will be sufficient to meet any uninsured expenditures.

Also included in insurance receivables at September 30, 2006 is $5.9 million related to an insurance claim to recover estimated reimbursable drilling costs on a well that experienced uncontrollable water flow in the second quarter of 2006. We believe that this amount is probable of reimbursement under our insurance policies.

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Capital expenditures and other. 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, 2006, capital expenditures of $1.5 billion included $198.0 million for development activities, $167.7 million for exploration and $1.1 billion for acquisition and other leasehold activity. These expenditures do not include any amount of capitalized salaries, as we have elected not to capitalize such costs.

Of the drilling, completion and facilities expenditures for 2006, we spent $134.0 million in the deepwater, $61.1 million on the deep shelf and $170.6 million on the conventional shelf and other projects. These expenditures do not include hurricane remediation costs which totaled $56.2 million for the nine months ended September 30, 2006. Additionally, we spent $6.1 million on expensed workovers and major maintenance projects and $20.8 million for plugging and abandonment expenses. As a result of the exploration success the Company has experienced over the last twelve months, the Company’s capital spending on completion projects has exceeded earlier expectations and the Company has increased the original 2006 capital budget of $400 million by $150 million. We intend to fund our future exploration, exploitation and development expenditures through net cash flow from operating activities, cash on hand and long-term borrowings.

Long-term debt. On May 26, 2006, we entered into a credit agreement principally in connection with the funding of the Kerr-McGee transaction. Upon closing of the Kerr-McGee transaction in August 2006, our initial availability under the credit agreement was $987.5 million. The credit agreement provides for (1) a revolving loan with an initial availability of $300.0 million, (2) a Tranche A term loan in the amount of $387.5 million and (3) a Tranche B term loan in the amount of $300.0 million. The amount available under the revolving loan is subject to redetermination on March 1 and September 1 of each year commencing September 1, 2007. Additionally, the agreement provides for the availability of letters of credit for up to $90.0 million, provided however, that its usage is subject to availability under the revolving loan.

Interest accrues either (1) at the higher of the Prime Rate, or the Federal Funds Rate plus 0.50%, plus a margin which varies from 0.0% to 1.75% depending upon the loan or (2) to the extent any loan outstanding is designated as a Eurodollar loan, at the London Interbank Offered Rate plus a margin that varies from 1.25% to 2.75% depending upon the loan. The Tranche A and Tranche B term loans are payable in installments and mature fifteen months from initial funding and on the fourth anniversary of initial funding, respectively. The revolving loan matures on the third anniversary of initial funding.

The credit agreement contains covenants that restrict the payment of cash dividends to a maximum of $30.0 million per year, borrowings other than from the facilities, sales of assets, loans to others, investments, merger activity, hedging contracts, liens and certain other transactions without the prior consent of the lenders. We are required 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 loans at all times, as well as certain commodity derivatives. We are also subject to various financial covenants calculated as of the last day of each fiscal quarter, including a minimum current ratio beginning with the quarter ending on March 31, 2007, a minimum interest coverage ratio, a minimum asset coverage ratio and a maximum leverage ratio. We were in compliance with these covenants on September 30, 2006.

At September 30, 2006, we had no borrowings outstanding on the revolving loan, with $300.0 million of undrawn capacity. Also at September 30, 2006, borrowings outstanding on the Tranche A and Tranche B term loans totaled $670.9 million, net of unamortized discount of $16.6 million, of which $354.6 million is classified as current. The interest rates on the Tranche A and Tranche B term loans were 8.15% and 7.65%, respectively, at September 30, 2006.

Equity offering. In July 2006, the Company completed an additional equity offering of 8,500,000 shares of its common stock at an offering price of $32.50 per share. The Underwriting Agreement also included a 30-day option to the underwriters to purchase up to an additional 1,275,000 shares at the offering price, less underwriting discounts and commissions. In August 2006, the over-allotment option was exercised in full. Net proceeds generated by the offering and the exercise of the over-allotment option were approximately $307.0 million after underwriting discounts and commissions of approximately $9.5 million and legal, accounting, printing and various other fees of approximately $1.2 million. The net proceeds from the equity offering and the exercise of the over-allotment option were used in connection with the funding of the Kerr-McGee transaction.

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Critical Accounting Policies

Derivatives. We use derivative contracts to manage the variability in cash flows related to commodity price risks and interest rate risks and do not use them for trading purposes. We account for our derivative contracts in accordance with Statement of Financial Accounting Standards (“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 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.

Realized and unrealized gains and losses on derivatives that are not designated as hedges, as well as the ineffective portion of derivatives that qualify for hedge accounting treatment, are recorded as a derivative fair value gain or loss in the income statement. Unrealized gains and losses on effective cash flow derivatives that qualify for hedge accounting treatment, as well as any deferred gain or loss realized upon early termination of effective hedge derivatives, are recorded as a component of accumulated other comprehensive income (loss). When the hedged transaction occurs, the realized gain or loss, as well as any deferred gain or loss, on the hedge derivative is transferred from accumulated other comprehensive gain (loss) to the income statement and classified based on the hedged item. Realized and unrealized gains and losses on our commodity derivative contracts are recognized in income as commodity derivative gain (loss). Realized gains and losses on our interest rate swaps are recorded as adjustments to interest expense. Settlements of derivatives are included in cash flows from operating activities. See Note 5 of Notes to Condensed Consolidated Financial Statements included in this report for a discussion of our derivative contracts.

Other Accounting Policies. Our other 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, 2005. 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, seeItem 1. Financial Statements – Note 10 – Share-Based Compensationand Note 15 – Recent Accounting Pronouncements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Information about market risks for the periods ended September 30, 2006 does not differ materially from the disclosures in Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2005 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, 2005.

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 flow provided by operating activities and profitability. In connection with the anticipated financing of the transaction with Kerr-McGee, in January 2006 we entered into commodity swap and option contracts relating to approximately 14 Bcfe of our production in 2006, 18 Bcfe of our production in 2007 and 11 Bcfe of our production in 2008.

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As of September 30, 2006, our open commodity derivatives were as follows:

Collars
					NYMEX Contract Price
Type	Commodity	Effective Date	Termination Date	Notional Quantity	Floor		Ceiling
Zero Cost	Natural Gas	11/1/2006	12/31/2006	2,013,000 MMBtu	$	8.04	$	14.49
Funded	Natural Gas	1/1/2007	12/31/2007	8,760,000 MMBtu		7.76		16.80
Zero Cost	Oil	1/1/2007	12/31/2007	1,569,500 Bbls		61.68		76.40
Funded	Natural Gas	1/1/2008	12/31/2008	5,124,000 MMBtu		7.31		15.80
Zero Cost	Oil	1/1/2008	12/31/2008	1,024,800 Bbls		60.00		74.50

Swaps
Commodity	Effective Date	Termination Date	Notional Quantity	Price
Oil	10/1/2006	12/31/2006	248,400 Bbls	$69.85

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 derivative contracts, refer toItem 1. Financial Statements – Note 5 – Derivative Financial Instruments.

Interest Rate Risk. In connection with the Kerr-McGee merger transaction, our credit agreement required that we enter into interest rate swap contracts. In August 2006, we entered into two interest rate swaps, which serve as a hedge of the variable LIBOR rates used to reset the floating rates of our Tranche A and Tranche B term loans. These swaps have notional amounts that equate to 50% of the aggregate outstanding principal balance of the Tranche A and Tranche B term loans, and fix the rates at 5.41% and 5.16%, respectively.

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 interim 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 interim Chief Financial Officer have each concluded that as of September 30, 2006 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, 2006, 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 6. Exhibits

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

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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 14, 2006.

W&T OFFSHORE, INC.
By:	/s/ WILLIAM W. TALAFUSE
	William W. Talafuse
	Senior Vice President, interim Chief Financial
	Officer and Chief Accounting Officer

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EXHIBIT INDEX

Exhibit Number	Description
15.1*	Letter from Ernst & Young LLP regarding unaudited interim financial information.
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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