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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, 2010

¨	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. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

As of November 5, 2010, there were 74,627,502 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, 2010 and December 31, 2009		1
	Condensed Consolidated Statements of Income (Loss) for the Three and Nine Months Ended September 30, 2010 and 2009		2
	Condensed Consolidated Statement of Changes in Shareholders’ Equity for the Nine Months Ended September 30, 2010		3
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2010 and 2009		4
	Notes to Condensed Consolidated Financial Statements		5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		19

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		30

Item 4.	Controls and Procedures		31

PART II – OTHER INFORMATION

Item 1A.	Risk Factors		31

Item 5.	Other Information		33

Item 6.	Exhibits		33

SIGNATURE			34

EXHIBIT INDEX			35

PART I – FINANCIAL INFORMATION

Item 1.

Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30, 2010			December 31, 2009
	(In thousands, except share data)
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	180,511		$	38,187
Receivables:
Oil and natural gas sales		51,348			54,978
Joint interest and other		21,770			51,312
Insurance		11,482			30,543
Income taxes		1,305			85,457

Total receivables		85,905			222,290
Prepaid expenses and other assets		31,337			28,777

Total current assets		297,753			289,254
Property and equipment – at cost:
Oil and natural gas properties and equipment (full cost method, of which $65,950 at September 30, 2010 and $77,301 at December 31, 2009 were excluded from amortization)		5,027,907			4,732,696
Furniture, fixtures and other		15,485			15,080

Total property and equipment		5,043,392			4,747,776
Less accumulated depreciation, depletion and amortization		3,954,851			3,752,980

Net property and equipment		1,088,541			994,796
Restricted deposits for asset retirement obligations		30,633			30,614
Deferred income taxes		—			5,117
Other assets		6,476			7,052

Total assets	$	1,423,403		$	1,326,833


Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	75,854		$	115,683
Undistributed oil and natural gas proceeds		24,410			32,216
Asset retirement obligations		95,970			117,421
Accrued liabilities		22,314			13,509
Deferred income taxes		3,542			5,117

Total current liabilities		222,090			283,946
Long-term debt		450,000			450,000
Asset retirement obligations, less current portion		279,117			231,379
Other liabilities		19,759			2,558
Commitments and contingencies
Shareholders’ equity:
Common stock, $0.00001 par value; 118,330,000 shares authorized; 77,507,618 issued and 74,638,445 outstanding at September 30, 2010; 77,579,968 issued and 74,710,795 outstanding at December 31, 2009		1			1
Additional paid-in capital		376,626			373,050
Retained earnings		99,977			10,066
Treasury stock, at cost		(24,167	)		(24,167	)

Total shareholders’ equity		452,437			358,950

Total liabilities and shareholders’ equity	$	1,423,403		$	1,326,833

See Notes to Condensed Consolidated Financial Statements.

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
	(In thousands, except per share data)
	(Unaudited)
Revenues	$	169,575		$	167,042		$	518,827		$	434,896


Operating costs and expenses:
Lease operating expenses		34,371			53,820			122,194			158,131
Production taxes		276			174			788			1,464
Gathering and transportation		4,607			4,050			12,920			10,400
Depreciation, depletion and amortization		69,051			80,139			201,870			235,442
Asset retirement obligation accretion		6,264			7,934			18,676			28,761
Impairment of oil and natural gas properties		—			—			—			218,871
General and administrative expenses		13,389			9,758			38,143			31,925
Derivative loss (gain)		4,770			3,845			(8,500	)		4,697

Total costs and expenses		132,728			159,720			386,091			689,691

Operating income (loss)		36,847			7,322			132,736			(254,795	)
Interest expense:
Incurred		10,485			11,096			32,319			35,345
Capitalized		(1,345	)		(1,874	)		(4,090	)		(5,378	)
Loss on extinguishment of debt		—			—			—			2,926
Other income		150			39			632			762

Income (loss) before income tax expense (benefit)		27,857			(1,861	)		105,139			(286,926	)
Income tax expense (benefit)		669			(539	)		7,766			(35,052	)

Net income (loss)	$	27,188		$	(1,322	)	$	97,373		$	(251,874	)

Basic and diluted earnings (loss) per common share	$	0.36		$	(0.02	)	$	1.30		$	(3.35	)
Dividends declared per common share	$	0.04		$	0.03		$	0.10		$	0.09

See Notes to Condensed Consolidated Financial Statements.

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY


	Common Stock Outstanding					Additional Paid-In Capital		Retained Earnings			Treasury Stock					Total Shareholders’ Equity
	Shares			Value		Additional Paid-In Capital		Retained Earnings			Shares		Value			Total Shareholders’ Equity
	(In thousands)
	(Unaudited)
Balances at December 31, 2009		74,711		$	1	$	373,050	$	10,066			2,869	$	(24,167	)	$	358,950
Cash dividends		—			—		—		(7,462	)		—		—			(7,462	)
Share-based compensation		—			—		3,576		—			—		—			3,576
Restricted stock issued, net of forfeitures		(73	)		—		—		—			—		—			—
Net income		—			—		—		97,373			—		—			97,373

Balances at September 30, 2010		74,638		$	1	$	376,626	$	99,977			2,869	$	(24,167	)	$	452,437

See Notes to Condensed Consolidated Financial Statements.

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Nine Months Ended September 30,
	2010			2009
	(In thousands)
	(Unaudited)
Operating activities:
Net income (loss)	$	97,373		$	(251,874	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		220,546			267,303
Impairment of oil and natural gas properties		—			218,871
Amortization of debt issuance costs and discount on indebtedness		1,004			1,503
Loss on extinguishment of debt		—			2,817
Share-based compensation related to restricted stock issuances		3,576			4,835
Derivative (gain) loss		(8,500	)		4,697
Cash payments on derivative settlements		(410	)		(4,603	)
Deferred income taxes (benefit)		6,483			(142	)
Other		—			610
Changes in operating assets and liabilities:
Oil and natural gas receivables		3,630			(18,904	)
Joint interest and other receivables		29,542			28,609
Insurance receivables		36,763			9,637
Income taxes		84,152			(17,355	)
Prepaid expenses and other assets		(1,464	)		(12,271	)
Asset retirement obligations		(62,620	)		(75,397	)
Accounts payable and accrued liabilities		(30,148	)		(66,328	)
Other liabilities		12,950			(137	)

Net cash provided by operating activities		392,877			91,871


Investing activities:
Acquisition of property interests		(116,589	)		—
Investment in oil and natural gas properties and equipment		(127,427	)		(275,965	)
Proceeds from sales of oil and natural gas properties and equipment		1,335			8,368
Proceeds from insurance		—			5,174
Purchases of furniture, fixtures and other		(405	)		(649	)

Net cash used in investing activities		(243,086	)		(263,072	)


Financing activities:
Borrowings of long-term debt		427,500			205,441
Repayments of long-term debt		(427,500	)		(268,441	)
Dividends to shareholders		(7,467	)		(6,872	)
Repurchases of common stock		—			(9,247	)
Other		—			114

Net cash used in financing activities		(7,467	)		(79,005	)

Increase (decrease) in cash and cash equivalents		142,324			(250,206	)
Cash and cash equivalents, beginning of period		38,187			357,552

Cash and cash equivalents, end of period	$	180,511		$	107,346

See Notes to Condensed Consolidated Financial Statements.

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 oil and natural gas producer, active in the acquisition, exploitation, exploration and development of oil and natural gas properties primarily 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 (“GAAP”) 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 GAAP 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.

The accompanying financial statements included adjustments related to prior years that were not deemed material with respect to such prior years or the anticipated results or the trend of earnings for fiscal year 2010. For the nine months ended September 30, 2010, a reduction of hurricane remediation, facilities and workover expenses was recorded, totaling approximately $5.1 million related to prior years. The amounts were recorded in the first quarter of 2010.

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, 2009.

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 GAAP 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.

Ceiling Test. The carrying amount of our oil and natural gas properties was written down by $218.9 million as of March 31, 2009 through application of the full cost ceiling limitation as prescribed by the SEC, primarily as a result of lower natural gas prices at March 31, 2009 as compared to December 31, 2008. The previously reported amount of $205.0 million was subsequently increased by $13.9 million in the fourth quarter of 2009 as a result of further analysis of our March 31, 2009 ceiling test calculation. As such, operating income, net income and our basic and diluted loss per common share for the nine months ended September 30, 2009 have been adjusted as well. We did not have a ceiling test write-down during the three and nine months ended September 30, 2010.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

2. Recent Accounting Pronouncements

Effective for our annual reporting period ended December 31, 2009, we adopted certain amendments to the Extractive Activities—Oil and Gas Topic of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (the “Codification”) that updated and aligned the FASB’s reserve estimation and disclosure requirements for oil and natural gas companies with the reserve estimation and disclosure requirements that were adopted by the SEC in December 2008. In accordance with the new rules, we use the unweighted average of first-day-of-the-month commodity prices over the preceding 12-month period, rather than end-of-period commodity prices, when estimating quantities of proved reserves. Additionally, the estimated future net revenues used to calculate the ceiling test are based on the 12-month average commodity price for each product. Refer to our Annual Report on Form 10-K for the year ended December 31, 2009 for additional information about the impact of these new requirements on our oil and natural gas reserves and financial statements.

In January 2010, the FASB issued certain amendments to the Fair Value Measurements and Disclosures topic of the Codification. These amendments added new requirements for fair value disclosures about transfers into and out of Levels 1 and 2 and separate disclosures about purchases, sales, issuances and settlements relating to Level 3 measurements. The amendments also clarified existing requirements regarding the level of disaggregation as well as inputs and valuation techniques used to measure fair value. The amendments were adopted in our first quarter ended March 31, 2010, except for the requirement to provide Level 3 activity on a gross basis, which will be effective for our first quarter ended March 31, 2011. The amendments change disclosure requirements and not accounting practices; therefore, the adoption of these amendments did not have, nor is it expected to have, any impact on our financial position, results of operations or cash flows.

In July 2010, the FASB issued certain amendments to the Receivables topic of the Codification. These amendments expanded disclosure requirements with respect to the credit quality of financing receivables and the related allowance for credit losses. Entities are required to disaggregate by portfolio segment or class certain existing disclosures and provide certain new disclosures about their financing receivables and related allowance for credit losses. Trade receivables with maturities of one year or less are excluded from the disclosure requirements. The amendments are effective for our fiscal year ending December 31, 2010. The amendments only change disclosure requirements and not accounting practices; therefore, the adoption of these amendment is not expected to have any impact on our financial position, results of operations or cash flows.

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. A summary of our asset retirement obligations is as follows (in thousands):


Balance, December 31, 2009	$	348,800
Liabilities settled		(62,620	)
Accretion of discount		18,676
Disposition of properties		(2,070	)
Liabilities assumed through acquisition		6,521
Liabilities incurred		442
Revisions of estimated liabilities due to Hurricane Ike		36,663
Revision of estimated liabilities due to NTL 2010-G05 (1)		18,725
Revisions of estimated liabilities – all other		9,950

Balance, September 30, 2010		375,087
Less current portion		95,970

Long-term	$	279,117

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

(1)

Notice to Lessees and Operators No. 2010-G05, “Decommissioning Guidance for Wells and Platforms” issued by the Bureau of Ocean Energy Management, Regulation and Enforcement (the “BOEM” and formerly the Minerals Management Service) on September 15, 2010 and effective as of October 15, 2010, which will require us to decommission any wells and platforms that have not been used during the past five years for exploration or production on active leases and are no longer capable of producing in paying quantities within three years. The accelerated time frame will cause our estimated liabilities for asset retirement obligations to be incurred in earlier periods, resulting in a higher present value of such liabilities.

4. Acquisition

On April 7, 2010, we entered into a Purchase and Sale Agreement (“PSA”) with Total E&P USA, Inc. (“Total”) to acquire all of Total’s interest, including production platforms and facilities, in three federal offshore lease blocks located in the Gulf of Mexico for a purchase price of $150 million, subject to customary closing adjustments, with an effective date of January 1, 2010. The properties acquired from Total are producing interests with future development potential, and include a 100% working interest in Mississippi Canyon block 243 (“Matterhorn”) and a 64% working interest in Viosca Knoll blocks 822 and 823 (“Virgo”). The transaction closed on April 30, 2010, with our wholly-owned subsidiary, W&T Energy VI, LLC (“Energy VI”) as purchaser. The purchase price was adjusted for, among other things, net revenue and operating expenses from the effective date to the closing date, resulting in a net payment of $116.6 million. This acquisition was funded with cash on hand. In accordance with the PSA, Energy VI obtained unsecured surety bonds in favor of the BOEM to secure the retirement obligations with respect to these assets. The PSA provides for annual increases in the required security for the asset retirement obligations. To help satisfy the annual increases, Energy VI has agreed to make periodic payments from production of the acquired properties to an escrow agent. As long as the required security amount then in effect is met, the payments will be promptly released to us by the escrow agent. As of September 30, 2010, we were in compliance with the required security amount.

5. Long-Term Debt

At September 30, 2010 and December 31, 2009, the balance outstanding under our 8.25% Senior Notes (the “Notes”) was $450.0 million and was classified as long-term. The Notes bear interest at a fixed rate of 8.25%, with interest payable semi-annually in arrears on June 15 and December 15. At September 30, 2010 and December 31, 2009, the estimated fair value of the Notes was approximately $429.8 million and $432.0 million, respectively. The estimated annual effective interest rate on the Notes is 8.4%. For additional details about fair value measurements, refer to Note 6.

The Third Amended and Restated Credit Agreement, as amended, (the “Credit Agreement”) governs our revolving loan facility. Borrowings under our revolving loan facility are secured by our oil and natural gas properties. Availability under such facility is subject to a semi-annual redetermination (March and September) of our borrowing base, calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria. In November 2010, our borrowing base was reaffirmed by our lenders at $405.5 million. At September 30, 2010 and December 31, 2009, we had no amounts outstanding under the revolving loan facility and we had $0.3 million and $0.7 million, respectively, of letters of credit outstanding.

Under the Credit Agreement, we are subject to various financial covenants calculated as of the last day of each fiscal quarter, including a minimum current ratio and a maximum leverage ratio, as defined in the Credit Agreement. We were in compliance with all applicable covenants of the Credit Agreement as of September 30, 2010.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

6. Fair Value Measurements

We measure the fair value of our derivative financial instruments by applying the income approach, using models with inputs that are classified within Level 2 of the valuation hierarchy. The inputs used in measuring the fair value of our derivative financial instruments consist of market-based or independently-sourced market parameters, including but not limited to forward curves for oil and natural gas, and volatilities. In addition to market information, the models also incorporate the contractual terms of the instruments. The fair value of our derivative assets and liabilities, including adjustments for credit risk, were $1.7 million and $2.5 million, respectively, at September 30, 2010, and $0.1 million and $9.9 million, respectively, at December 31, 2009. For additional details about our derivative financial instruments, refer to Note 7.

The estimated fair value of the Notes, as disclosed in Note 5, was based on quoted prices and the inputs are classified within Level 1 of the valuation hierarchy.

7. Derivative Financial Instruments

We account for derivative contracts in accordance with the Derivatives and Hedging Topic of the Codification, which requires each derivative to be recorded on the balance sheet as an asset or a liability at its fair value. Changes in a derivative’s fair value are required to be recognized currently in earnings unless specific hedge accounting criteria are met at the time we enter into a derivative contract.

Our market risk exposure relates primarily to commodity prices and interest rates. From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our revolving loan facility. We do not enter into derivative instruments for speculative trading purposes. Our derivative instruments currently consist of commodity option contracts and a commodity swap contract. The Company is exposed to credit loss in the event of nonperformance by the counterparties; however, we do not currently anticipate any of our counterparties being unable to fulfill their contractual obligations.

Commodity Derivative: We have entered into a limited number of commodity option contracts and a commodity swap contract to help manage our exposure to commodity price risk from sales of oil and natural gas during the fiscal years ending December 31, 2010, 2011 and 2012. We have elected not to designate our commodity derivatives as hedging instruments. 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. As of September 30, 2010, our open commodity derivatives were as follows:

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


Zero Cost Collars – Oil
Effective Date	Termination Date		Notional Quantity (Bbls)		Weighted Average NYMEX Contract Price				Fair Value Liability (in thousands)
Effective Date	Termination Date		Notional Quantity (Bbls)		Floor		Ceiling		Fair Value Liability (in thousands)
10/1/2010		12/31/2010		634,950	$	72.98	$	87.56	$	352
1/1/2011		3/31/2011		668,200		75.00		92.96		71
4/1/2011		6/30/2011		618,700		75.00		92.80		452
7/1/2011		9/30/2011		231,900		75.00		93.02		255
10/1/2011		12/31/2011		392,100		75.00		95.58		428
1/1/2012		3/31/2012		182,000		75.00		96.25		229
4/1/2012		6/30/2012		182,000		75.00		96.25		290
7/1/2012		9/30/2012		62,000		75.00		96.25		110
10/1/2012		12/31/2012		165,600		75.00		98.00		267

				3,137,450	$	74.59	$	92.88	$	2,454


Zero Cost Collars – Natural Gas
Effective Date	Termination Date		Notional Quantity (MMBtu)		Weighted Average NYMEX Contract Price				Fair Value Asset (in thousands)
Effective Date	Termination Date		Notional Quantity (MMBtu)		Floor		Ceiling		Fair Value Asset (in thousands)
11/1/2010		12/31/2010		1,475,300	$	5.00	$	8.48	$	1,430


Swap – Natural Gas
Effective Date	Termination Date		Notional Quantity (MMBtu)		Swap Price				Fair Value Asset (in thousands)
11/1/2010		12/31/2010		122,000		$5.71			$	182

Changes in the fair value of our commodity derivative contracts are recognized currently in earnings. For the three and nine months ended September 30, 2010, we recognized a loss of $4.8 million and a gain of $8.8 million, respectively, related to a change in the fair value of our commodity derivatives. During the three and nine month periods ended September 30, 2009, we recognized a loss of $3.3 million related to a change in the fair value of our commodity derivatives.

At September 30, 2010, $1.7 million was included in prepaid expenses and other assets, $1.2 million was included in accrued liabilities, and $1.3 million was included in other long-term liabilities related to our open commodity derivative contracts. At December 31, 2009, $0.1 million was included in prepaid expenses and other assets and $5.5 million was included in accrued liabilities related to our open commodity derivative contracts.

Interest Rate Swap: Our interest rate swap contract with a fixed interest rate of 5.21% expired in August 2010. Initially, this swap was designated as a hedge of the floating-rate interest payments on our Tranche B term loan facility. However, as a result of payments on the term loan and changes to the swap contract, hedge accounting was discontinued completely in 2007. Changes in fair value subsequent to the discontinuation of hedge accounting were immediately recognized in earnings.

For the three months ended September 30, 2010, no gain or loss was recognized related to a change in the fair value of our interest rate swap. For the nine months ended September 30, 2010, we recognized a loss of $0.3 million. For the three and nine months ended September 30, 2009, we recognized a loss of $0.6 million and $1.4 million, respectively, related to a change in the fair value of our interest rate swap.

At December 31, 2009, the fair value of our interest rate swap was $4.4 million, which was included in accrued liabilities.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

8. Income Taxes

Income tax expense of $0.7 million and $7.8 million was recorded during the three and nine months ended September 30, 2010, respectively, compared to an income tax benefit of $0.5 million and $35.1 million for the same periods of 2009. Our effective tax rate for the three and nine months ended September 30, 2010 was approximately 2.4% and 7.4%, respectively, and primarily reflects a reduction in our valuation allowance against our deferred tax assets. Forecasted taxable income in 2010 has allowed us to reduce a portion of our valuation allowance. Our effective tax rate for the quarter ended September 30, 2009 was approximately 29.0% and primarily reflected adjustments for prior year taxes and other discrete items. Our effective tax rate for the nine months ended September 30, 2009 was approximately 12.2% and primarily reflected the effect of a valuation allowance against our deferred tax assets.

Inclusive of interest, the amount of unrecognized tax benefit recorded in other liabilities was $12.9 million as of September 30, 2010.

We recognize interest and penalties related to unrecognized tax benefits in income tax expense. During the three and nine months ended September 30, 2010, we recognized $0.1 million (net of tax), in income tax expense for interest related to our unrecognized tax benefit. We did not have any unrecognized tax benefits during the year ended December 31, 2009. The tax years from 2006 through 2009 remain open to examination by the tax jurisdictions to which we are subject.

9. Hurricane Remediation and Insurance Claims

During the third quarter of 2008, Hurricane Ike, and to a much lesser extent Hurricane Gustav, caused property damage and disruptions to our exploration and production activities. We currently have insurance coverage for named windstorms but we do not carry business interruption insurance. Our insurance policies in effect on the occurrence dates of Hurricanes Ike and Gustav had a retention requirement of $10 million per occurrence to be satisfied by us before we could be indemnified for losses. In the fourth quarter of 2008, we satisfied our $10 million retention requirement for Hurricane Ike in connection with two platforms that were toppled and were deemed total losses. Our insurance coverage policy limits at the time of Hurricane Ike were $150 million for property damage due to named windstorms (excluding certain damage incurred at our marginal facilities) and $250 million for, among other things, removal of wreckage if mandated by any governmental authority. The damage we incurred as a result of Hurricane Gustav was well below our retention amount.

Included in lease operating expenses for the three months ended September 30, 2010 is a net reduction of $7.1 million of costs related to Hurricanes Ike and Gustav, which reflect receipts from our insurance carrier for previously filed claims and that are in excess of current expenditures. Included in lease operating expenses for the nine months ended September 30, 2010 is a net reduction of $11.3 million of costs related to receipts from our insurance carrier for previously filed claims and that are in excess of current expenditures and include reductions to previous estimates (see Note 1 Basis of Presentation – Interim Financial Statements) of hurricane remediation costs. Included in lease operating expenses for the three and nine months ended September 30, 2009 are hurricane remediation costs that exceeded insurance claims by $4.0 million and $19.3 million, respectively, related to Hurricanes Ike and Gustav.

We recognize insurance receivables with respect to capital, repair and plugging and abandonment costs as a result of hurricane damage when we deem those to be probable of collection. Our assessment of probability considers the review and approval of such costs by our insurance underwriters’ adjuster. Claims that have been processed in this manner have customarily been paid on a timely basis.

We have also recognized in the past an insurance receivable to the extent our insurance underwriters’ adjuster has reviewed our work plans and other information related to plugging and abandonment activities that were accelerated by Hurricane Ike and has indicated that our insurance policies provide coverage for such costs and such costs are within policy limits.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Below is a reconciliation of our insurance receivables from December 31, 2009 to September 30, 2010 (in thousands):


Balance, December 31, 2009	$	30,543

Costs approved under our insurance policies:
Remediation		9,879
Plugging and abandonment		17,969

Payments received:
Remediation		(4,957	)
Plugging and abandonment		(41,952	)


Balance, September 30, 2010	$	11,482

At September 30, 2010 and December 31, 2009, $6.2 million and $1.3 million, respectively, of remediation costs and $5.3 million and $29.2 million, respectively, related to the plugging and abandonment of wells and dismantlement of facilities damaged by Hurricanes Ike are included in insurance receivables. We expect that our available cash and cash equivalents, cash flow from operations and the availability under our revolving loan facility will be sufficient to meet any necessary expenditures that may exceed our insurance coverage for damages incurred as a result of Hurricanes Ike and Gustav.

10. Share-Based Compensation and Cash-Based Incentive 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.

In 2010, the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan, (“the Plan”) was approved. As allowed by the Plan, in August 2010, the Company granted restricted stock units (“RSUs”) to certain of its employees and currently intends to use RSUs in the future. Prior to 2010, the Company granted restricted stock to its employees. In 2010 and in prior years, restricted stock was granted to the Company’s non-employee directors under the Director Compensation Plan. In addition to share-based compensation, in August 2010, the Company granted its employees cash incentive awards.

At September 30, 2010, there were 1,967,715 shares of common stock available for award under the Plan and 583,891 shares of common stock available for award under the Directors Compensation Plan.

Restricted Stock: In 2008 and 2009, the Company issued to its employees restricted shares in connection with its share-based payment plans. In 2010, restricted shares were issued to the Company’s non-employee directors. Restricted shares are subject to forfeiture until vested and cannot be sold, transferred or disposed of during the restricted 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.

A summary of share activity related to restricted stock for the nine months ended September 30, 2010, is as follows:

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


	Restricted Stock
	Shares			Weighted Average Grant Date Fair Value Per Share
Outstanding restricted shares, December 31, 2009		1,050,506		$	8.48
Granted		35,000			10.00
Vested		(14,424	)		17.81
Forfeited		(107,350	)		8.27

Outstanding restricted shares, September 30, 2010		963,732			8.42

At September 30, 2010, the composition of our restricted stock awards outstanding, by year granted, was as follows:


	Shares
Employees – granted in:
2009		855,477	(1)
2008		49,522	(2)

Non-employee directors – granted in:
2010		35,000	(3)
2009		21,545	(4)
2008		2,188	(5)


Total		963,732

Vesting is expected to occur as follows, less any forfeitures:

(1)	Equal installments in December 2010 and 2011.

(2)	December 2010.

(3)	Equal installments in May 2011, 2012 and 2013.

(4)	Equal installments in May 2011 and 2012.

(5)

May 2011.

Restricted Stock Units: As defined by the Plan, RSUs are rights to receive stock, cash or a combination thereof at the end of a specified vesting period, subject to certain terms and conditions as determined by the Compensation Committee of the Board of Directors. In 2010, the Company awarded RSUs to certain employees that are 100% contingent upon meeting a specified performance requirement. That performance requirement is to meet or exceed an earnings per share target for the year 2010. If the performance is met, vesting occurs upon completion of the specified vesting period. RSUs will earn dividends effective January 2011 at the same rate as our common stock. RSUs are subject to forfeiture until vested and cannot be sold, transferred or disposed of during the restricted period.

A summary of share activity related to RSUs for the nine months ended September 30, 2010, is as follows:


	Restricted Stock Units
	Units (1)			Weighted Average Grant Date Fair Value Per Unit
Outstanding RSUs, December 31, 2009		—		$	—
Granted		1,280,501			9.36
Vested		—			—
Forfeited		(6,795	)		9.36

Outstanding RSUs, September 30, 2010		1,273,706			9.36

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

(1)

Units are subject to performance requirements determined upon completion of calendar year 2010 and approval by the Compensation Committee. Through the nine months ended September 30, 2010, the Company’s performance has met or exceeded the criteria for awarding 100% of the amounts granted; therefore, the maximum amount of the awards is reported in the above table.

All of the RSUs granted in 2010 will vest in December 2012 subject to employment conditions.

The weighted average grant date fair value of restricted stock granted during the nine months ended September 30, 2010 and 2009 was $0.4 million and $10.9 million, respectively, and the weighted average grant date fair value of restricted stock units granted during the nine months ended September 30, 2010 was $12.0 million. The weighted average fair value of the restricted stock that vested during the nine months ended September 30, 2010 and 2009 was $0.1 million and $0.3 million, respectively, based on the closing prices on the dates of vesting.

A summary of incentive compensation expense under share-based payment arrangements and the related tax benefit for the three and nine months ended September 30, 2010 and 2009 is as follows (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Share-based compensation expense from:
Restricted stock	$	807	$	1,719	$	2,750	$	6,184
Restricted stock units		826		—		826		—

Total	$	1,633	$	1,719	$	3,576	$	6,184


Share-based compensation tax benefit:
Tax benefit computed at the statutory rate	$	572	$	602	$	1,252	$	2,164

Cash-based Incentive Compensation: As defined by the Plan, performance and annual incentive awards may be granted to eligible employees. These awards are performance-based awards consisting of one or more business criteria or individual performance criteria and a targeted level or levels of performance with respect to each of such criteria. Generally, the performance period is the calendar year and determination and payment is made in cash in the first quarter of the following year.

A summary of incentive compensation expense for the three and nine months ended September 30, 2010 and 2009 is as follows (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Share-based compensation expense included in:
Lease operating expense	$	171	$	367	$	599	$	1,912
General and administrative		1,462		1,352		2,977		4,272

Total charged to operating income (loss)		1,633		1,719		3,576		6,184


Cash-based incentive compensation included in:
Lease operating expense		507		—		1,284		1,472
General and administrative		2,564		136		5,475		1,389

Total charged to operating income (loss)		3,071		136		6,759		2,861


Total incentive compensation charged to operating income (loss)	$	4,704	$	1,855	$	10,335	$	9,045

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

As of September 30, 2010, unrecognized share-based compensation expense related to our issued restricted shares and RSUs was $3.1 million and $10.7 million, respectively. The unrecognized expense related to restricted shares was decreased by $0.8 million for the three months ended September 30, 2010 due to a change in the estimated forfeiture rate based upon historical experience. Unrecognized compensation expense will be recognized through April 2013 for restricted shares and November 2012 for RSUs.

11. Earnings (Loss) Per Share

The following table presents the calculation of basic earnings (loss) per common share for the three and nine months ended September 30, 2010 and 2009 (in thousands, except per share amounts):


	Three Months Ended September 30,					Nine Months Ended September 30,
	2010		2009			2010		2009
Net income (loss)	$	27,188	$	(1,322	)	$	97,373	$	(251,874	)
Less portion allocated to nonvested shares		351		—			1,304		—

Net income (loss) allocated to common shares	$	26,837	$	(1,322	)	$	96,069	$	(251,874	)


Weighted average common shares outstanding		73,675		74,659			73,668		75,089


Basic and diluted earnings (loss) per common share	$	0.36	$	(0.02	)	$	1.30	$	(3.35	)

Shares excluded due to being anti-dilutive (weighted-average)		1,787		1,724			1,310		1,274

12. Dividends

During the first three quarters of 2010, we paid regular cash dividends of $0.03, $0.03, and $0.04 per common share per quarter, respectively. During the first three quarters of 2009, we paid regular cash dividends of $0.03 per common share per quarter. On November 1, 2010, our board of directors declared a cash dividend of $0.04 per common share, payable on December 8, 2010 to shareholders of record on November 17, 2010.

13. Contingencies

In the third quarter of 2009, the Company recognized $5.3 million in allowable reductions of cash payments for royalties owed to the BOEM for transportation of their deepwater production through our subsea pipeline systems. In 2010, BOEM audited the calculations and support related to this usage fee, and in the third quarter, we were notified that BOEM had disallowed approximately $4.7 million of the reductions taken. We recorded a reduction to other revenue of $4.7 million for the three months ended September 30, 2010 to reflect this disallowance; however, we disagree with the position taken by BOEM and plan to pursue our claim, including taking legal action, if necessary, to resolve the matter.

We are a party to various pending or threatened claims and complaints seeking damages or other remedies concerning our commercial operations and other matters in the ordinary course of our business. In addition, claims or contingencies may arise related to matters occurring prior to our acquisition of properties or related to matters occurring subsequent to our sale of properties. In certain cases, we have indemnified the sellers of properties we have acquired, and in other cases, we have indemnified the buyers of properties we have sold. We are also subject to federal and state administrative proceedings conducted in the ordinary course of business. Although we can give no assurance about the outcome of pending legal and federal or state administrative proceedings and the effect such an outcome may have on us, 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 our consolidated financial position, results of operations or liquidity.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

14. Subsequent Event

On November 4, 2010, the Company, through Energy VI, executed an Asset Purchase Agreement acquiring interests in five offshore producing fields located in the deepwater Gulf of Mexico from Shell Offshore Inc. for an aggregate purchase price of $395.0 million cash and the assumption of asset retirement obligations for plugging and abandonment liability for the acquired interests. Certain non-operated interests included in the acquisition have been closed into escrow pending the exercise or waiver of an operator’s preferential right of purchase. The Company also entered into a letter of intent to acquire the interests of Shell Offshore Inc. in a sixth field located in the shallow shelf waters of the Gulf of Mexico for an additional $55.0 million cash plus assumption of related asset retirement obligations, subject to completion of due diligence and negotiation of definitive agreements. The acquisitions are being funded with cash on hand and from borrowings on our revolving loan facility.

Pursuant to the Asset Purchase Agreement, on November 4, 2010 we acquired (i) operated working interests in the Tahoe (70% W.I.) and Southeast Tahoe (100% W.I.) fields, located in Viosca Knoll 783 and 784 Federal lease blocks respectively, (ii) non-operated working interests in the Marlin (11.5-25% W.I.) and Dorado (25% W.I.) fields, located in the Viosca Knoll 871 and 915 Federal lease blocks and (iii) a 6.25% of 8/8ths overriding royalty interest in the Droshky oil field, located in the Green Canyon 244 Federal lease block. The acquisition of the interests in the Marlin and Dorado fields was funded in escrow for approximately 30 days pending waiver or exercise of a preferential purchase right held by the third party operator of the fields. In the event the Droshky oil field cumulatively produces over 30 million barrel equivalents from and after September 1, 2010, our overriding royalty interest will change to 5.25% of 8/8ths.

The working interest acquisitions include interests in wells, platforms, pipelines, and related contracts. Shell Offshore Inc.will provide certain transitional services in connection with the operated properties. The purchase price is subject to adjustment for an economic effective date of September 1, 2010 and other customary post-effective date adjustments. The Company estimates that it will accrue approximately $50 million for asset retirement obligations for the interests in the six fields.

15. Supplemental Guarantor Information

Our payment obligations under the Notes and the Credit Agreement (see Note 5) are fully and unconditionally guaranteed by our wholly-owned subsidiary, Energy VI (“Guarantor Subsidiary”). The guaranty of the Credit Agreement became effective on April 30, 2010.

The following unaudited condensed consolidating financial information presents the financial condition, results of operations and cash flows of W&T Offshore, Inc. and Energy VI, together with consolidating adjustments necessary to present the Company’s results on a consolidated basis.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Condensed Consolidating Balance Sheet as of September 30, 2010


	Parent Company			Guarantor Subsidiary (1)		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents	$	180,511		$	—	$	—		$	180,511
Receivables:
Oil and natural gas sales		42,037			9,311		—			51,348
Joint interest and other		21,770			—		—			21,770
Insurance		11,482			—		—			11,482
Income taxes		6,656			—		(5,351	)		1,305

Total receivables		81,945			9,311		(5,351	)		85,905
Prepaid expenses and other assets		31,337			—		—			31,337

Total current assets		293,793			9,311		(5,351	)		297,753
Property and equipment – at cost:
Oil and natural gas properties and equipment (full cost method, of which $65,950 at September 30, 2010 and $77,301 at December 31, 2009 were excluded from amortization)		4,902,356			125,551		—			5,027,907
Furniture, fixtures and other		15,485			—		—			15,485

Total property and equipment		4,917,841			125,551		—			5,043,392
Less accumulated depreciation, depletion and amortization		3,939,492			15,359		—			3,954,851

Net property and equipment		978,349			110,192		—			1,088,541
Restricted deposits for asset retirement obligations		30,633			—		—			30,633
Other assets		137,145			29,448		(160,117	)		6,476

Total assets	$	1,439,920		$	148,951	$	(165,468	)	$	1,423,403


Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	73,550		$	2,304	$	—		$	75,854
Undistributed oil and natural gas proceeds		24,230			180		—			24,410
Asset retirement obligations		95,970			—		—			95,970
Accrued liabilities		22,314			—		—			22,314
Income taxes		—			5,351		(5,351	)		—
Deferred income taxes		3,542			—		—			3,542

Total current liabilities		219,606			7,835		(5,351	)		222,090
Long-term debt		450,000			—		—			450,000
Asset retirement obligations, less current portion		270,900			8,217		—			279,117
Other liabilities		46,977			2,230		(29,448	)		19,759
Commitments and contingencies
Shareholders’ equity:
Common stock, $0.00001 par value; 118,330,000 shares authorized; 77,507,618 issued and 74,638,445 outstanding at September 30, 2010; 77,579,968 issued and 74,710,795 outstanding at December 31, 2009		1			—		—			1
Additional paid-in capital		376,626			116,589		(116,589	)		376,626
Retained earnings		99,977			14,080		(14,080	)		99,977
Treasury stock, at cost		(24,167	)		—		—			(24,167	)

Total shareholders’ equity		452,437			130,669		(130,669	)		452,437

Total liabilities and shareholders’ equity	$	1,439,920		$	148,951	$	(165,468	)	$	1,423,403

(1)	Began operations on May 1, 2010

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Condensed Consolidating Statement of Income for the Three Months Ended September 30, 2010


	Parent Company			Guarantor Subsidiary (1)		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Revenues	$	140,410		$	29,165	$	—		$	169,575


Operating costs and expenses:
Lease operating expenses		31,091			3,280		—			34,371
Production taxes		276			—		—			276
Gathering and transportation		4,225			382		—			4,607
Depreciation, depletion and amortization		59,756			9,295		—			69,051
Asset retirement obligation accretion		6,119			145		—			6,264
General and administrative expenses		13,389			—		—			13,389
Derivative loss		4,770			—		—			4,770

Total costs and expenses		119,626			13,102		—			132,728

Operating income		20,784			16,063		—			36,847
Earnings of affiliates		10,441			—		(10,441	)		—
Interest expense:
Incurred		10,485			—		—			10,485
Capitalized		(1,345	)		—		—			(1,345	)
Other income		150			—		—			150

Income before income tax expense		22,235			16,063		(10,441	)		27,857
Income tax expense (benefit)		(4,953	)		5,622		—			669

Net income	$	27,188		$	10,441	$	(10,441	)	$	27,188

(1)	Began operations on May 1, 2010

Condensed Consolidating Statement of Income for the Nine Months Ended September 30, 2010


	Parent Company			Guarantor Subsidiary (1)		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Revenues	$	470,506		$	48,321	$	—		$	518,827


Operating costs and expenses:
Lease operating expenses		113,004			9,190		—			122,194
Production taxes		788			—		—			788
Gathering and transportation		12,324			596		—			12,920
Depreciation, depletion and amortization		186,511			15,359		—			201,870
Asset retirement obligation accretion		18,435			241		—			18,676
General and administrative expenses		36,870			1,273		—			38,143
Derivative (gain)		(8,500	)		—		—			(8,500	)

Total costs and expenses		359,432			26,659		—			386,091

Operating income		111,074			21,662		—			132,736
Earnings of affiliates		14,080			—		(14,080	)		—
Interest expense:
Incurred		32,319			—		—			32,319
Capitalized		(4,090	)		—		—			(4,090	)
Other income		632			—		—			632

Income before income tax expense		97,557			21,662		(14,080	)		105,139
Income tax expense		184			7,582		—			7,766

Net income	$	97,373		$	14,080	$	(14,080	)	$	97,373

(1)	Began operations on May 1, 2010

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Condensed Consolidating Statement of Cash Flows for the Nine Months Ended September 30, 2010


	Parent Company			Guarantor Subsidiary (1)			Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Operating activities:
Net income	$	97,373		$	14,080		$	(14,080	)	$	97,373
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		204,946			15,600			—			220,546
Amortization of debt issuance costs and discount on indebtedness		1,004			—			—			1,004
Share-based compensation related to restricted stock issuances		3,576			—			—			3,576
Derivative gain		(8,500	)		—			—			(8,500	)
Cash payments on derivative settlements		(410	)		—			—			(410	)
Deferred income taxes		4,253			2,230			—			6,483
Earnings of affiliates		(14,080	)		—			14,080			—
Changes in operating assets and liabilities:
Oil and natural gas receivables		12,941			(9,311	)		—			3,630
Joint interest and other receivables		29,542			—			—			29,542
Insurance receivables		36,763			—			—			36,763
Income taxes		78,801			5,351			—			84,152
Prepaid expenses and other assets		(1,464	)		(29,448	)		29,448			(1,464	)
Asset retirement obligations		(62,620	)		—			—			(62,620	)
Accounts payable and accrued liabilities		(32,632	)		2,484			—			(30,148	)
Other liabilities		42,398			—			(29,448	)		12,950

Net cash provided by operating activities		391,891			986			—			392,877


Investing activities:
Acquisition of property interests		—			(116,589	)		—			(116,589	)
Investment in oil and natural gas properties and equipment		(126,441	)		(986	)		—			(127,427	)
Proceeds from sales of oil and natural gas properties and equipment		1,335			—			—			1,335
Investment in subsidiary		(116,589	)		—			116,589			—
Purchases of furniture, fixtures and other		(405	)		—			—			(405	)

Net cash used in investing activities		(242,100	)		(117,575	)		116,589			(243,086	)


Financing activities:
Borrowings of long-term debt		427,500			—			—			427,500
Repayments of long-term debt		(427,500	)		—			—			(427,500	)
Dividends to shareholders		(7,467	)		—			—			(7,467	)
Investment from parent		—			116,589			(116,589	)		—

Net cash provided by (used in) financing activities		(7,467	)		116,589			(116,589	)		(7,467	)

Increase in cash and cash equivalents		142,324			—			—			142,324
Cash and cash equivalents, beginning of period		38,187			—			—			38,187

Cash and cash equivalents, end of period	$	180,511		$	—		$	—		$	180,511

(1)	Began operations on May 1, 2010

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 in Item 1 of this Quarterly Report on Form 10-Q. 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 of 1933 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, 2009 and may be discussed or updated from time to time in subsequent reports filed with the SEC. 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 consolidated subsidiaries.

Overview

W&T is an independent oil and natural gas producer focused primarily in the Gulf of Mexico. W&T has grown through acquisitions, exploitation and exploration and currently holds working interests in approximately 72 producing or capable of producing fields in federal and state waters. The majority of our daily production is derived from offshore wells we operate.

Our financial condition, cash flow and results of operations are significantly affected by the volume of our oil and natural gas production and the price that we receive for such production. Our production volume for the nine months ended September 30, 2010 was comprised of approximately 49% oil and 51% natural gas, determined using the ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of crude oil, condensate or natural gas liquids. During the nine months ended September 30, 2010, our combined total production of oil and natural gas was approximately 10.4% lower than during the same period in 2009.

The Henry Hub spot price for natural gas was $3.85 per MMBtu as of September 30, 2010, representing a decrease of 33.5% from $5.79 per MMBtu at the end of 2009. We are expecting continued weakness in natural gas prices unless demand for natural gas increases as a result of a strong economic recovery, drilling activity subsides dramatically or forced production shut-ins occur. There is also a risk that, as a result of successful exploration and development activities in the shale areas coupled with the availability of increasing amounts of liquefied natural gas, increased supplies of natural gas will offset or mitigate the impact of any natural gas shut-ins or demand increases resulting from improved economic conditions. According to industry sources, the rig count for horizontal drilling rigs, used primarily in the shale formation areas of Louisiana, Arkansas and Texas, has reached or exceeded record levels. Natural gas production and supply continues to exceed demand. Onshore natural gas producers have continued to drill in attempts to yield production sufficient to preserve existing leases, while such production is hedged at prices significantly higher than current levels, allowing funding of projects that continue to increase supply to an already oversupplied market. Seasonal weather conditions also impact the demand for and price of natural gas.

The West Texas Intermediate posted price for oil was $76.50 per barrel as of September 30, 2010, representing an increase of 0.7% from $76.00 per barrel at the end of 2009. Long-term forecasts for oil demand, and therefore global oil prices, continue to be favorable in several key growing markets, specifically China and India.

Although the price for natural gas was lower and the price for oil was basically flat at September 30, 2010 compared to December 31, 2009, average prices for both the three months and nine months ended September 30, 2010 were much higher than the comparable period in 2009. During the first half of 2009, prices and the economy continued to be affected by the financial crisis and economic recession that affected much of the world and even continue today in parts of the world. However, oil prices recovered through out much of 2009 and have continued to be strong thus far in 2010. Natural gas prices are much more affected by domestic issues, such as supply, local demand issues, and domestic economic conditions.

During the nine months ended September 30, 2010, the average realized sales prices of our oil and natural gas were 37.2% and 19.3% higher, respectively, than the comparable average realized sales prices during the same period in 2009, which contributed to higher cash provided by operating activities in the 2010 period. Declines in oil and natural gas prices after September 30, 2010, if those were to occur, would negatively impact our future oil and natural gas revenues, earnings and liquidity, and could result in ceiling test write-downs of the carrying value of our oil and natural gas properties, issues with financial ratio compliance, and a reduction of the borrowing base associated with our credit agreement. Such declines, if those were to occur, may limit the willingness of financial institutions and investors to provide borrowings or capital to us and others in the oil and natural gas industry.

In April 2010, there was a fire and explosion aboard the Deepwater Horizon drilling platform operated by BP in ultra deep water in the Gulf of Mexico. As a result of the explosion, ensuing fire and apparent failure of the blowout preventers, the rig sank and created a catastrophic oil spill that produced widespread economic, environmental and natural resource damage in the Gulf Coast region. In response to the explosion and spill, the BOEM of the U.S. Department of the Interior issued a “Notice to Lessees”, or “NTL”, on May 30, 2010, and a revised notice on July 12, 2010, implementing a moratorium on deepwater drilling activities that effectively halted deepwater drilling of wells using subsea blowout preventers (“BOPs”) or surface BOPs on a floating facility. While the moratorium was in place, the BOEM issued a series of NTLs and adopted changes to its regulations to impose a variety of new measures intended to help prevent a similar disaster in the future. The moratorium was lifted on October 12, 2010, but offshore operators must now comply with strict new safety and operating requirements. For example, before being allowed to resume drilling in deepwater, outer continental shelf operators must certify compliance with all applicable operating regulations found in 30 C.F.R. Part 250, including those rules recently placed into effect, such as rules relating to well casing and cementing, BOPs, safety certification, emergency response, and worker training. Operators also must demonstrate the availability of adequate spill response and blowout containment resources. Notwithstanding the lifting of the moratorium, we anticipate that there will continue to be delays in the resumption of drilling-related activities, including delays in the issuance of drilling permits, as these various regulatory initiatives are fully implemented. We do not expect the additional safety requirements set forth by these NTLs to have a significant impact on our operations. However, we cannot predict the ultimate impact the Deepwater Horizon incident and resulting changes in regulations and perceptions of offshore oil and natural gas operations will have on us.

The spill moratorium also has caused drilling rig operators to move or contemplate moving their rigs to locations outside of the Gulf of Mexico. If and when we require the use of a deepwater drilling rig, the potentially reduced inventory of such rigs and the new permitting process could cause delays in timing and result in additional costs. As a result, we may experience delays in drilling, completion and ultimately, production activities, which would negatively impact our financial position, cash flows and results of operations.

In addition, the BOEM recently issued a NTL dated to be effective October 15, 2010 that establishes a more stringent regimen for the timely decommissioning of what is known as “idle iron” – wells, platforms and pipelines that are no longer producing or serving exploration or support functions related to an operator’s lease – in the Gulf of Mexico. The recently issued NTL sets forth more stringent standards for decommissioning timing requirements by applying the requirement that any well that has not been used during the past five years for exploration or production on active leases and is no longer capable of producing in paying quantities must be permanently plugged or temporarily abandoned within three years. Plugging or abandonment of wells may be delayed by two years if all of the well’s hydrocarbon and sulphur zones are appropriately isolated. Similarly, platforms or other facilities that are no longer useful for operations must be removed within five years of the cessation of operations. The triggering of these plugging, abandonment and removal activities under what may be viewed as an accelerated schedule in comparison to historical decommissioning efforts may serve to increase, perhaps materially, our future plugging, abandonment and removal costs, which may translate into a need to increase our estimate of future asset retirement obligations required to meet such increased costs. During the third quarter of 2010, we increased our estimate of asset retirement obligations by $18.7 million based on our expected acceleration in timing for such obligations as a result of implementing this NTL. (For additional details, refer to Item 1 Financial Statements – Note 3 – Asset Retirement Obligations.) However, the potential increase in decommissioning activity in the Gulf of Mexico over the next few years as a result of the NTL could likely result in increased demand for salvage contractors and equipment, resulting in increased estimates of plugging, abandonment and removal costs and increases in related asset retirement obligations.

In the second quarter of 2010, we renewed our insurance policies covering well control, hurricane damage, general and excess liabilities and pollution control. For a more complete description of these policies and the risks they cover, refer to “–Liquidity and Capital Resources – Hurricane Remediation and Insurance Claims” below.

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,
	2010			2009			Change			%			2010			2009 (1)			Change			%
	(In thousands, except percentages and per share data)
Financial:
Revenues:
Oil	$	126,325		$	118,548		$	7,777			6.6	%	$	366,567		$	270,675		$	95,892			35.4	%
Natural gas		47,236			43,222			4,014			9.3	%		156,025			158,938			(2,913	)		(1.8	%)
Other (2)		(3,986	)		5,272			(9,258	)		NM			(3,765	)		5,283			(9,048	)		NM

Total revenues (3)		169,575			167,042			2,533			1.5	%		518,827			434,896			83,931			19.3	%
Operating costs and expenses:
Lease operating expenses (4)		34,371			53,820			(19,449	)		(36.1	%)		122,194			158,131			(35,937	)		(22.7	%)
Production taxes		276			174			102			58.6	%		788			1,464			(676	)		(46.2	%)
Gathering and transportation		4,607			4,050			557			13.8	%		12,920			10,400			2,520			24.2	%
Depreciation, depletion, amortization and accretion		75,315			88,073			(12,758	)		(14.5	%)		220,546			264,203			(43,657	)		(16.5	%)
Impairment of oil and natural gas properties (1)		—			—			—			—			—			218,871			(218,871	)		(100.0	%)
General and administrative expenses		13,389			9,758			3,631			37.2	%		38,143			31,925			6,218			19.5	%
Derivative loss (gain)		4,770			3,845			925			24.1	%		(8,500	)		4,697			(13,197	)		NM

Total costs and expenses		132,728			159,720			(26,992	)		(16.9	%)		386,091			689,691			(303,600	)		(44.0	%)

Operating income (loss)		36,847			7,322			29,525			403.2	%		132,736			(254,795	)		387,531			NM
Interest expense, net of amounts capitalized		9,140			9,222			(82	)		(0.9	%)		28,229			29,967			(1,738	)		(5.8	%)
Loss on extinguishment of debt		—			—			—			—			—			2,926			(2,926	)		(100.0	%)
Other income		150			39			111			284.6	%		632			762			(130	)		(17.1	%)

Income (loss) before income tax expense (benefit)		27,857			(1,861	)		29,718			NM			105,139			(286,926	)		392,065			NM
Income tax expense (benefit)		669			(539	)		1,208			NM			7,766			(35,052	)		42,818			NM

Net income (loss)	$	27,188		$	(1,322	)	$	28,510			NM		$	97,373		$	(251,874	)	$	349,247			NM

Basic and diluted earnings (loss) per common Share	$	0.36		$	(0.02	)	$	0.38			NM		$	1.30		$	(3.35	)	$	4.65			NM


	Three Months Ended September 30,										Nine Months Ended September 30,
	2010		2009		Change			%			2010		2009		Change			%
Operating:
Net sales:
Natural gas (Bcf)		10.6		14.0		(3.4	)		(24.3	%)		32.9		39.9		(7.0	)		(17.5	%)
Oil (MMBbls)		1.8		1.9		(0.1	)		(5.3	%)		5.3		5.3		—			—
Total natural gas and oil (Bcfe) (5) (6)		21.6		25.7		(4.1	)		(16.0	%)		64.4		71.9		(7.5	)		(10.4	%)
Average daily equivalent sales (MMcfe/d)		235.3		278.9		(43.6	)		(15.6	%)		235.9		263.3		(27.4	)		(10.4	%)

Average realized sales prices (Unhedged):
Natural gas ($/Mcf)	$	4.47	$	3.08	$	1.39			45.1	%	$	4.75	$	3.98	$	0.77			19.3	%
Oil ($/Bbl)		68.35		61.09		7.26			11.9	%		69.73		50.82		18.91			37.2	%
Natural gas equivalent ($/Mcfe)		8.02		6.30		1.72			27.3	%		8.12		5.98		2.14			35.8	%

Average realized sales prices (Hedged):
Natural gas ($/Mcf)	$	4.58	$	3.08	$	1.50			48.7	%	$	4.91	$	3.98	$	0.93			23.4	%
Oil ($/Bbl)		68.35		61.09		7.26			11.9	%		69.55		50.82		18.73			36.9	%
Natural gas equivalent ($/Mcfe)		8.07		6.30		1.77			28.1	%		8.18		5.98		2.20			36.8	%

Average per Mcfe ($/Mcfe):
Lease operating expenses (4)	$	1.59	$	2.10	$	(0.51	)		(24.3	%)	$	1.90	$	2.20	$	(0.30	)		(13.6	%)
Gathering and transportation		0.21		0.15		0.06			40.0	%		0.20		0.15		0.05			33.3	%

Production costs		1.80		2.25		(0.45	)		(20.0	%)		2.10		2.35		(0.25	)		(10.6	%)
Production taxes		0.01		0.01		—			—			0.01		0.02		(0.01	)		(50.0	%)
Depreciation, depletion, amortization and accretion		3.48		3.43		0.05			1.5	%		3.42		3.68		(0.26	)		(7.1	%)
General and administrative expenses		0.62		0.38		0.24			63.2	%		0.59		0.44		0.15			34.1	%

	$	5.91	$	6.07	$	(0.16	)		(2.6	%)	$	6.12	$	6.49	$	(0.37	)		(5.7	%)


Total number of wells drilled (gross)		2		1		1			100	%		7		11		(4	)		(36.4	%)
Total number of productive wells drilled (gross)		—		1		(1	)		(100	%)		4		8		(4	)		(50.0	%)

(1)

The carrying amount of our oil and natural gas properties was written down by $218.9 million as of March 31, 2009 through application of the full cost ceiling limitation as prescribed by the SEC, primarily as a result of lower natural gas prices at March 31, 2009, as compared to December 31, 2008. The previously reported amount of $205.0 million was subsequently increased by $13.9 million in the fourth quarter of 2009 as a result of further analysis of our March 31, 2009 ceiling test calculation. As such, operating income, net income and our basic and diluted loss per common share for the nine months ended September 30, 2009 have been adjusted as well. We did not have a ceiling test write-down during the three and nine months ended September 30, 2010.

(2)

For the three and nine months ended September 30, 2010, a reduction in other revenue of $4.7 million was recorded to adjust amounts originally recorded in the three and nine months ended September 30, 2009. This amount relates to the disallowance by the BOEM of royalty relief for transportation of deepwater production through our subsea pipeline system. We are contesting this BOEM adjustment.

(3)

Included in total revenues for the three and nine months ended September 30, 2010 is $4.8 million and $24.9 million, respectively, related to the recoupment of royalties paid to the BOEM in prior periods based on price thresholds that were believed to limit the availability of royalty relief on certain of our properties subject to the Outer Continental Shelf (“OCS”) Deepwater Royalty Relief Act of 1995.

(4)

Included in lease operating expenses are hurricane remediation costs and insurance claims, net, related to Hurricanes Ike and Gustav that incorporate reimbursement for claims paid under our policies by our insurance underwriters, credits for approved claims, expenses not yet approved for payment under our insurance policies, expenses not covered by insurance and revisions to previous estimates for hurricane remediation. The net amounts for the three and nine months ended September 30, 2010 were a reduction of expenses of $7.1 million and $11.3 million, respectively. The net amounts for the three and nine months ended September 30, 2009 were an increase of expenses of $4.0 million and $19.3 million, respectively.

(5)	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).

(6)	Included in natural gas and oil sales volumes for the three and nine months ended September 30, 2010 is approximately 0.5 Bcfe and 3.0 Bcfe, respectively, related to the recoupment of royalties paid to the BOEM in prior periods as noted above.

NM	= percentage change not meaningful

Three Months Ended September 30, 2010 Compared to the Three Months Ended September 30, 2009

Revenues. Total revenues increased $2.5 million to $169.6 million for the three months ended September 30, 2010 as compared to the same period in 2009. Oil revenues increased $7.8 million, natural gas revenues increased $4.0 million and other revenues decreased $9.3 million. The oil revenue increase was attributable to an 11.9% increase in the average realized oil sales price to $68.35 per barrel for the three months ended September 30, 2010 from $61.09 per barrel for the same period in 2009, partially offset by a 5.3% decrease in sales volumes. The sales volume decrease for oil is primarily attributable to property divestitures in 2009 and natural reservoir declines, partially offset by an increase associated with the Matterhorn and Virgo fields we purchased in the second quarter of 2010. The increase in natural gas revenue resulted from a 45.1% increase in the average realized natural gas sales price to $4.47 per Mcf in the 2010 period from $3.08 per Mcf in the 2009 period, partially offset by a 24.3% decrease in sales volumes. The sales volume decrease for natural gas is primarily attributable to production shut in at our Main Pass 108 field as a result of a pipeline outage that began in early June 2010. The decrease in other revenues was attributable to reversing $4.7 million originally recorded in the third quarter of 2009 as this amount relates to the disallowance by the BOEM of royalty relief for transportation of deepwater production through our subsea pipeline system. We are contesting this BOEM adjustment. For additional information, refer to Item 1 Financial Statements – Note 13 – Contingencies.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, insurance, workovers, maintenance on our facilities, and net hurricane remediation costs and insurance claims, decreased to $1.59 per Mcfe during the three months ended September 30, 2010 from $2.10 per Mcfe during the three months ended September 30, 2009. On a nominal basis, lease operating expenses decreased $19.4 million to $34.4 million in the third quarter of 2010, compared to the third quarter of 2009. On a component basis, hurricane remediation costs and insurance claims, net, insurance premiums, base lease operating expenses, and workover costs decreased $11.1 million, $3.7 million, $3.6 million, and $2.6 million respectively, while facility expenses costs increased $1.6 million. Hurricane remediation costs and insurance claims, net, decreased due to insurance reimbursements in excess of cost incurred for 2010. The decrease in insurance premiums resulted primarily from renewal of our insurance policies effective June 1, 2010 covering well control and hurricane damage at an annual cost of approximately $20.7 million, representing a decrease of approximately 41% from 2009. For a more complete description of our insurance renewal, refer to “- Liquidity and Capital Resources –Hurricane Remediation and insurance Claims” below. The decrease in base lease operating expenses primarily reflects property divestitures in 2009, partially offset by increases associated with the Matterhorn and Virgo fields we purchased in the second quarter of 2010. The decrease in workover expense is due primarily to decreased work activity. The increase in facility costs is attributable to increased work on certain platforms primarily for sandblasting and painting.

Production taxes. Production taxes increased primarily due to production that began in 2010 related to an onshore well. Most of our production is from federal waters where there are no production taxes.

Gathering and transportation costs. Gathering and transportation costs increased primarily due to costs associated with operating the new Matterhorn and Virgo platforms, partially offset by property divestitures that occurred in 2009.

Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion (“DD&A”) decreased to $75.3 million for the quarter ended September 30, 2010 from $88.1 million for the same period in 2009. DD&A decreased primarily due to lower production of oil and natural gas. On a per Mcfe basis, DD&A was $3.48 for the quarter ended September 30, 2010, compared to $3.43 for the quarter ended September 30, 2009.

General and administrative expenses. General and administrative expenses (“G&A”) increased to $13.4 million for the three months ended September 30, 2010 from $9.8 million for the same period in 2009, primarily due to higher incentive compensation and reductions in billings to joint-interest parties attributable to certain capital projects. Incentive compensation increased due to the Company’s improved financial and operational performance in 2010. On a per Mcfe basis, G&A was $0.62 per Mcfe for the three months ended September 30, 2010, compared to $0.38 per Mcfe for the same period in 2009.

Derivative gain/loss. For the three months ended September 30, 2010, our derivative loss of $4.8 million related entirely to a change in the fair value of our commodity derivatives. For the three months ended September 30, 2009, our derivative loss of $3.8 million related to changes in the fair values of our commodity derivatives and interest rate swap of $3.3 million and $0.6 million, respectively. For additional details about our derivatives, refer to Item 1 Financial Statements – Note 7 – Derivative Financial Instruments.

Interest expense. Interest expense incurred decreased to $10.5 million for the quarter ended September 30, 2010 from $11.1 million for the quarter ended September 30, 2009 primarily due to lower amounts of borrowings outstanding during the 2010 period. During the 2010 and 2009 periods, $1.3 million and $1.9 million, respectively, of interest was capitalized to unevaluated oil and natural gas properties.

Income tax expense/benefit. Income tax expense increased to $0.7 million for the three months ended September 30, 2010 from an income tax benefit of $0.5 million for the same period of 2009. Our effective tax rate for the three months ended September 30, 2010 was approximately 2.4% and primarily reflects a reduction in our valuation allowance against our deferred tax assets. Forecasted taxable income in 2010 has allowed us to reduce a portion of our valuation allowance. For 2009, the income tax benefit resulted from a pre-tax loss. Our effective tax rate for the three months ended September 30, 2009 was approximately 29.0% and primarily reflected adjustments for prior year taxes and other discrete items.

Nine Months Ended September 30, 2010 Compared to the Nine Months Ended September 30, 2009

Revenues. Total revenues increased $83.9 million to $518.8 million for the nine months ended September 30, 2010 as compared to the same period in 2009. Oil revenues increased $95.9 million, natural gas revenues decreased $2.9 million and other revenues decreased $9.0 million. The oil revenue increase was attributable to a 37.2% increase in the average realized oil sales price to $69.73 per barrel for the nine months ended September 30, 2010 from $50.82 per barrel for the same period in 2009. The sales volume for oil was basically flat, primarily due to decreases attributable to property divestitures in 2009, offset by increases associated with the Matterhorn and Virgo fields we purchased in the second quarter of 2010. The decrease in natural gas revenue resulted from a 17.5% decrease in sales volumes, partially offset by a 19.3% increase in the average realized natural gas sales price to $4.75 per Mcf in the 2010 period from $3.98 per Mcf in the 2009 period. The sales volume decrease for natural gas is primarily attributable to production shut in at our Main Pass 108 field as a result of a pipeline outage that began in early June 2010. The decrease in other revenues was attributable to reversing $4.7 million originally recorded in the third quarter of 2009 as this amount relates to the disallowance by the BOEM of royalty relief for transportation of deepwater production through our subsea pipeline system. We are contesting this BOEM adjustment. For additional information, refer to Item 1 Financial Statements – Note 13 – Contingencies.

Lease operating expenses. Lease operating expenses decreased to $1.90 per Mcfe during the nine months ended September 30, 2010 from $2.20 per Mcfe during the nine months ended September 30, 2009. On a nominal basis, lease operating expenses decreased $35.9 million to $122.2 million during the nine months ended September 30, 2010, compared to the same period in 2009. On a component basis, hurricane remediation costs and insurance claims, net, base lease operating expenses, and facilities expense decreased $30.6 million, $16.0 million, and $2.0 million respectively, while workover expenses and insurance increased $10.1 million and $2.5 million, respectively. Hurricane remediation costs and insurance claims, net, decreased due to insurance reimbursements in excess of cost incurred for 2010. The decrease in base lease operating expenses primarily reflects decreases attributable to property divestitures, partially offset by increases associated with the Matterhorn and Virgo fields we purchased in the second quarter of 2010. The increase in workover expense is related to three separate workover projects that required the use of rigs to perform the activity. The increase in insurance expense is attributable to higher insurance premiums incurred prior to our insurance renewal in June 2010.

Production taxes. Production taxes decreased to $0.8 million for the nine months ended September 30, 2010 from $1.5 million for the same period in 2009 primarily due to property divestitures in 2009. Most of our production is from federal waters where there are no production taxes.

Gathering and transportation costs. Gathering and transportation costs increased to $12.9 million for the nine months ended September 30, 2010 from $10.4 million for the same period in 2009 primarily due to costs associated with operating the new Matterhorn and Virgo platforms, partially offset by property divestitures that occurred in 2009.

Depreciation, depletion, amortization and accretion. DD&A decreased to $220.5 million for the nine months ended September 30, 2010 from $264.2 million for the same period in 2009. DD&A decreased primarily due to lower production of oil and natural gas. In addition, decreases were due to a lower depreciable base (including our estimate of the cost of asset retirement obligations). The decrease in our depreciable base reflects property divestitures in 2009, partially offset by an increase associated with the Matterhorn and Virgo fields we purchased in the second quarter of 2010. The decrease in our depreciable base also reflects lower future development costs in the first quarter of 2010 due to the write-off of certain proved undeveloped reserves at the end of 2009 in connection with new reserve reporting requirements for oil and natural gas companies enacted by the SEC and the FASB. On a per Mcfe basis, DD&A was $3.42 for the nine months ended September 30, 2010, compared to $3.68 for the same period in 2009.

Impairment of oil and natural gas properties. At March 31, 2009, we recorded a ceiling test write-down of our oil and natural gas properties of $218.9 million through application of the full cost ceiling limitation as prescribed by the SEC, primarily as a result of a further decline in natural gas prices at March 31, 2009 as compared to December 31, 2008. We did not have a ceiling test write-down during the nine months ended September 30, 2010.

General and administrative expenses. G&A increased to $38.1 million for the nine months ended September 30, 2010 from $31.9 million for the same period in 2009, primarily due to higher incentive compensation and reductions in billings to joint-interest parties attributable to certain capital projects. Incentive compensation increased due to the Company’s improved financial and operational performance in 2010. On a per Mcfe basis, G&A was $0.59 per Mcfe for the nine months ended September 30, 2010, compared to $0.44 per Mcfe for the same period in 2009.

Derivative gain/loss. For the nine months ended September 30, 2010, our derivative gain of $8.5 million consisted of a gain of $8.8 million related to a change in the fair value of our commodity derivatives, partially offset by a loss of $0.3 million related to a change in the fair value of our interest rate swap. For the nine months ended September 30, 2009, our derivative loss of $4.7 million related to changes in the fair values of our commodity derivatives and interest rate swap of $3.3 million and $1.4 million, respectively. For additional details about our derivatives, refer to Item 1 Financial Statements – Note 7 – Derivative Financial Instruments.

Interest expense. Interest expense incurred decreased to $32.3 million for the nine months ended September 30, 2010 from $35.3 million for the nine months ended September 30, 2009 primarily due to lower amounts of borrowings outstanding during the 2010 period. During the 2010 and 2009 periods, $4.1 million and $5.4 million, respectively, of interest was capitalized to unevaluated oil and natural gas properties.

Loss on extinguishment of debt. In May 2009, we repaid our Tranche B term loan facility in full with borrowings under our revolving loan facility. During the nine months ended September 30, 2009, we recorded a loss of $2.9 million related to the write-off of all the deferred financing costs related to the Tranche B term loan facility and the write-off of a portion of the deferred financing costs related to the revolving loan facility, as well as the incurrence of other incidental costs in connection with the payoff of the Tranche B term loan facility.

Income tax expense/benefit. Income tax expense increased to $7.8 million for the nine months ended September 30, 2010 from an income tax benefit of $35.1 million for the same period of 2009. Our effective tax rate for the nine months ended September 30, 2010 was approximately 7.4% and primarily reflects a reduction in our valuation allowance against our deferred tax assets. Forecasted taxable income in 2010 has allowed us to reduce a portion of our valuation allowance. For 2009, the income tax benefit resulted from a pre-tax loss. Our effective tax rate for the nine months ended September 30, 2009 was approximately 12.2% and primarily reflected the effect of a valuation allowance for our deferred tax assets.

Liquidity and Capital Resources

Our primary liquidity needs are to fund capital expenditures to allow us to replace our oil and natural gas reserves, repay outstanding borrowings and make related interest payments and to fund strategic property acquisitions. We have funded our capital expenditures, including acquisitions, with cash on hand, cash provided by operations, securities offerings and bank borrowings. These sources of liquidity have historically been sufficient to fund our ongoing cash requirements.

Cash flow and working capital. Net cash provided by operating activities for the nine months ended September 30, 2010 was $392.9 million, compared to net cash provided by operating activities of $91.9 million for the comparable period in 2009. Included in the 2010 period are refunds of federal income taxes paid in prior years totaling $99.8 million, consisting primarily of carrybacks of net operating losses generated in 2009 and 2008. Also included in the 2010 are $46.9 million of insurance reimbursements for remediation and plugging and abandonment costs incurred primarily in connection with Hurricane Ike. Although our combined total production of oil and natural gas during the nine months ended September 30, 2010 was approximately 10.4% lower compared to the same period in 2009, our combined average realized sales price was 35.8% higher in the 2010 period, which contributed to the increase in cash provided by operating activities in the 2010 period compared to the 2009 period.

Net cash used in investing activities totaled $243.1 million and $263.1 million during the first nine months of 2010 and 2009, respectively, which primarily represents our investments in oil and natural gas properties. Included in the 2010 period is $116.6 million for the acquisition of the Matterhorn and Virgo fields from Total. At September 30, 2010, we had a cash balance of $180.5 million and we had $405.2 million of undrawn capacity under the revolving loan facility. We believe that 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.

From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our revolving loan facility. As of September 30, 2010, our derivative instruments outstanding consisted primarily of commodity option contracts relating to approximately 5 Bcfe, 11 Bcfe, and 4 Bcfe of our anticipated production for the 4^th quarter of 2010 and for calendar years 2011 and 2012, respectively. For additional details about our derivatives, refer to Item 1 Financial Statements – Note 7 – Derivative Financial Instruments.

Hurricane Remediation and Insurance Claims. During the third quarter of 2008, Hurricane Ike, and to a much lesser extent Hurricane Gustav, caused property damage and disruptions to our exploration and production activities. We currently have insurance coverage for named windstorms but we do not carry business interruption insurance. Our insurance policies in effect on the occurrence dates of Hurricanes Ike and Gustav had a retention requirement of $10 million per occurrence to be satisfied by us before we could be indemnified for losses. In the fourth quarter of 2008, we satisfied our $10 million retention requirement for Hurricane Ike in connection with two platforms that were toppled and were deemed total losses. Our insurance coverage policy limits at the time of Hurricane Ike were $150 million for property damage due to named windstorms (excluding certain damage incurred at our marginal facilities) and $250 million for, among other things, removal of wreckage if mandated by any governmental authority. The damage we incurred as a result of Hurricane Gustav was well below our retention amount.

For a discussion of our hurricane remediation costs related to lease operating expenses incurred during the three and nine months ended September 30, 2010 and 2009, refer to Item 1 Financial Statements – Note 9 – Hurricane Remediation and Insurance Claims. Lease operating expenses will be offset in future periods to the extent that costs incurred are approved for payment under our insurance policies.

To the extent our insurance underwriters’ adjuster has reviewed work plans and other information provided by us in connection with our plugging and abandonment activities scheduled to be completed and that were accelerated by Hurricane Ike, and has indicated that our insurance policies provide coverage for such costs and they are within policy limits, we have recognized an insurance receivable.

At September 30, 2010 and December 31, 2009, $6.2 million and $1.3 million, respectively, of remediation costs and $5.3 million and $29.2 million, respectively, related to the plugging and abandonment of wells and dismantlement of facilities damaged by Hurricanes Ike are included in insurance receivables. Refer to Item 1 Financial Statements – Note 9 – Hurricane Remediation and Insurance Claims for a reconciliation of our insurance receivables from December 31, 2009 to September 30, 2010. We expect that our available cash and cash equivalents, cash flow from operations and the availability under our revolving loan facility will be sufficient to meet any necessary expenditures that may exceed our insurance coverage for damages incurred as a result of Hurricanes Ike and Gustav.

Due to increased insurance claims in recent years associated with hurricanes in the Gulf of Mexico and continuing restrictions in the capital markets, property damage and well control insurance coverage has become more limited and the cost of such coverage has been significantly higher than historical levels. We currently carry three layers of insurance coverage for our operating activities in the Gulf of Mexico, each of which was renewed during the second quarter of 2010. In June 2010, we renewed our insurance policies covering well control and hurricane damage at an annual cost of approximately $20.7 million, representing the most significant cost of our insurance coverage. The current policy limits for well control and hurricane damage are $100 million and $85 million, respectively. We carry an additional $100 million of well control coverage on six wells at our Ship Shoal 349 field and six wells at our Matterhorn field. A retention amount of $5 million for well control event and $35 million per hurricane occurrence must be satisfied by us before we are indemnified for losses. Certain properties we have deemed as non-core are not covered for hurricane damage; however, properties representing approximately 90% of our PV-10 value at December 31, 2009 (before estimated asset retirement obligations) are covered under our new insurance policies for hurricane damage. Pollution causing a negative environmental impact is characterized as a covered component of each of the well control and hurricane sections of the policy.

In May 2010, we renewed our general and excess liability policy, which provides for $250 million of liability coverage for bodily injury and property damage, including liability claims resulting from seepage, pollution or contamination. In April 2010, we renewed our insurance policy with respect to the Oil Spill Financial Responsibility (“OSFR”) requirement under the Oil Pollution Act of 1990 (“OPA”), under which we are currently required to evidence $70 million of financial responsibility to the BOEM. We qualify to self-insure for $35 million of this amount, and the remaining $35 million is covered by our insurance policy. We may only collect proceeds under this OSFR policy after our well control, hurricane damage and excess liability policies have been exhausted.

In light of recent events in the Gulf of Mexico, our insurers may not continue to offer this type and level of coverage to us, or our costs may increase substantially as a result of increased premiums and the increased risk of uninsured losses that may have been previously insured, all of which could have a material adverse effect on our financial condition and results of operations. We are also exposed to the possibility that in the future we will be unable to buy insurance at any price or that if we do have a claim, the insurance companies will not pay our claim. However, we are not aware of any financial issues related to any of our insurance underwriters that would affect their ability to pay claims. We do not carry business interruption insurance.

Capital expenditures. The level of our investment in oil and natural gas properties changes from time to time depending on numerous factors, including the prices of oil and natural gas, anticipated operating cash flow, acquisition opportunities and the results of our exploration and development activities. For the nine months ended September 30, 2010, our capital expenditures for oil and natural gas properties and equipment of $244.0 million included $116.6 million for the acquisition of the Matterhorn and Virgo fields from Total, $68.6 million for exploration activities, $40.5 million for development activities and $18.3 million for seismic, capitalized interest and other leasehold costs. Our development and exploration capital expenditures consisted of $93.8 million on the conventional shelf and other projects, $6.4 million in the deepwater, $5.5 million onshore and $3.4 million on the deep shelf. Our capital expenditures for the nine months ended September 30, 2010 were financed by cash flow from operating activities and cash on hand.

On November 4, 2010, we executed an Asset Purchase Agreement acquiring interests in five offshore producing fields located in the deepwater Gulf of Mexico from Shell Offshore Inc. for an aggregate purchase price of $395.0 million cash and the assumption of asset retirement obligations for plugging and abandonment liability for the acquired interests. Certain non-operated interests included in the acquisition have been closed into escrow pending the exercise or waiver of an operator’s preferential right of purchase. We also entered into a letter of intent to acquire the interests of Shell Offshore Inc. in a sixth field located in the shallow shelf waters of the Gulf of Mexico for an additional $55.0 million cash plus assumption of related asset retirement obligations, subject to completion of due diligence and negotiation of definitive agreements. The acquisitions are being funded with cash on hand and from borrowings on our revolving loan facility.

The working interest acquisitions include interests in wells, platforms, pipelines, and related contracts. Shell Offshore Inc. will provide certain transitional services in connection with the operated properties. The purchase price is subject to adjustment for an economic effective date of September 1, 2010 and other customary post-effective date adjustments. We estimate that we will accrue approximately $50 million for asset retirement obligations for the interests in the six fields.

Our original total capital expenditure budget for 2010 was $450 million, comprised of both identified capital investment programs as described below and potential (but yet unidentified) acquisitions, joint ventures and other drilling opportunities. The budget, as recently updated, includes the drilling of three exploratory wells onshore, six offshore wells (five exploratory and one development) and other capital items such as well recompletions, facilities capital, seismic and leasehold items. At this time, we anticipate these capital expenditures will cost approximately $160 million. Another $116.6 million has been allocated to the purchase of certain properties from Total as discussed below. With the acquisition of certain properties from Shell Offshore Inc. noted above, we expect our capital expenditures for 2010 to be in the range of $650 million to $800 million. We anticipate fully funding our 2010 capital expenditures with internally generated cash flow, cash on hand and with borrowings under our revolving loan facility.

On April 7, 2010, we entered into the PSA with Total to acquire all of Total’s interest, including production platforms and facilities, in three federal offshore lease blocks located in the Gulf of Mexico for a purchase price of $150 million, subject to customary closing adjustments, with an effective date of January 1, 2010. The transaction closed on April 30, 2010, with our wholly-owned subsidiary, Energy VI, as purchaser. The purchase price was adjusted for, among other things, net revenue and operating expenses from the effective date to the closing date, resulting in a net payment of $116.6 million. This acquisition was funded with cash on hand. In accordance with the PSA, Energy VI obtained unsecured surety bonds in favor of the BOEM to secure the retirement obligations with respect to these assets. The PSA provides for annual increases in the required security for the asset retirement obligations. To help satisfy the annual increases, Energy VI has agreed to make periodic payments from production of the acquired properties to an escrow agent. As long as the required security amount then in effect is met, the payments will be promptly released to us by the escrow agent. As of September 30, 2010, we were in compliance with the required security amount.

The properties acquired from Total are producing interests with future development potential, and include a 100% working interest in Matterhorn and a 64% working interest in Virgo. The estimated proved oil and natural gas reserves on the closing date (determined using the unweighted average of first-day-of-the-month commodity prices over the preceding 12-month period) were 10.9 million Boe, or 65.6 Bcfe of natural gas, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. The reserves acquired were estimated as 64% oil and 36% natural gas.

Credit agreement and long-term debt. As of September 30, 2010 and December 31, 2009, there were no borrowings outstanding under our revolving loan facility and $450.0 million of our 8.25% Senior Notes outstanding. During each quarter of 2010, we borrowed $142.5 million under our revolving loan facility and repaid such borrowings during the quarter. As of September 30, 2010, we had $405.2 million of undrawn capacity under our revolving loan facility, which matures in 2012. The Senior Notes are classified as long-term. For additional details about our long-term debt, refer to Item 1 Financial Statements – Note 5 – Long-Term Debt.

Availability under our revolving loan facility is subject to a semi-annual redetermination (March and September) of our borrowing base and is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria. In November 2010, our borrowing base under the Credit Agreement was reaffirmed by our lenders at $405.5 million. Fifteen lenders participate in our revolving loan facility and we do not anticipate any of them being unable to satisfy their obligations under the Credit Agreement. We do not anticipate any immediate need for access to the capital markets due to having approximately $585 million of cash and borrowing capacity available as of September 30, 2010. Following the closing of the purchase of properties from Shell Offshore Inc. as described above, we expect to have adequate cash and borrowing capacity in the near term. Our borrowing base may increase due to the increased reserves from this acquisition, but any such increase would be subject to approval of each of the lenders participating in the revolving loan facility.

The Credit Agreement contains various financial covenants calculated as of the last day of each fiscal quarter, including a minimum current ratio and a maximum leverage ratio, as defined in the Credit Agreement. We were in compliance with all applicable covenants of the Credit Agreement as of September 30, 2010.

Income taxes. During the nine months ended September 30, 2010, we received refunds of federal income taxes paid in prior years totaling $99.8 million, consisting primarily of carrybacks of net operating losses generated in 2009 and 2008. Approximately $12.9 million of refunds are subject to recognition limitations in accordance with the Income Taxes Topic of the Codification, and as a result, we recorded an unrecognized tax benefit plus interest thereon in other liabilities. No potential benefits are included in the balance of unrecognized tax benefits that would affect the effective tax rate on income from continuing operations if recognized.

Dividends. During the first three quarters of 2010, we paid regular cash dividends of $0.03, $0.03, and $0.04 per common share per quarter, respectively. During the first three quarters of 2009, we paid regular cash dividends of $0.03 per common share per quarter. On November 1, 2010, our board of directors declared a cash dividend of $0.04 per common share, payable on December 8, 2010 to shareholders of record on November 17, 2010.

Contractual obligations. Except as described in “Cash flow and working capital,” “Capital expenditures” and “Long-term debt” above, information about contractual obligations for the nine months ended September 30, 2010, did not change materially from the disclosures in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2009.

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, 2009. Also refer to the Notes to Condensed Consolidated Financial Statements included in Part 1, Item 1 of this Quarterly Report on Form 10-Q.

Recent Accounting Pronouncements

For a description of recent accounting pronouncements, see Item 1 Financial Statements – Note 2 – Recent Accounting Pronouncements.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Information about market risks for the three and nine months ended September 30, 2010, did not change materially from the disclosures in Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2009 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, 2009.

On July 21, 2010, President Obama signed the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”) into law, to which one of the areas relates to increased regulation of the markets for derivative products of the type we use to manage areas of market risk. While the Commodity Futures Trading Commission has yet to issue regulations to implement this increased regulation, the Act may result in increased costs to us to implement our market risk management strategy.

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 have adversely affected our revenues, net cash provided by operating activities and profitability. We have entered into a limited number of commodity option contracts and a commodity swap contract to help manage our exposure to commodity price risk from sales of oil and natural gas during the fiscal years ending December 31, 2010, 2011 and 2012. As of September 30, 2010, our derivative instruments outstanding consisted primarily of commodity option contracts relating to approximately 5 Bcfe, 11 Bcfe, and 4 Bcfe of our anticipated production for the 4^th quarter of 2010 and for calendar years 2011 and year 2012, respectively. 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 instruments for speculative trading purposes. For additional details about our commodity derivatives, refer to Item 1 Financial Statements – Note 7 – Derivative Financial Instruments.

Interest Rate Risk. Our interest rate swap contract expired in August 2010. As of September 30, 2010, we had no floating rate debt outstanding. For additional details about our historical interest rate swap contract, refer to Item 1 Financial Statements – Note 7 – Derivative Financial Instruments.

Item 4.

Controls and Procedures

We have established disclosure controls and procedures designed to ensure that material information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC and that any material information relating to us is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

As required by Exchange Act Rule 13a-15(b), 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 defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) 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, 2010 our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that our controls and procedures are designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

During the quarter ended September 30, 2010, 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

Carefully consider the risk factors set forth below, as well as the risk factors included under the caption “Risk Factors” under Part I, Item 1A in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009, together with all of the other information included in this document, in the Company’s Annual Report on Form 10-K and in the Company’s other public filings, press releases and discussions with Company management.

Legislative and regulatory initiatives relating to offshore operations, which include consideration of increases in the minimum levels of demonstrated financial responsibility required to conduct exploration and production operations on the outer continental shelf and elimination of liability limitations on damages, will, if adopted, likely result in increased costs and additional operating restrictions and could have a material adverse effect on our business.

There have been a variety of proposals to change existing laws and regulations that could affect our operations and cause us to incur substantial costs. Implementation of any one or more of the various proposed changes could materially adversely affect operations in the Gulf of Mexico by raising operating costs, increasing insurance premiums, delaying drilling operations and increasing regulatory burdens, and, further, could lead to a wide variety of other unforeseeable consequences that make operations in the Gulf of Mexico and other offshore waters more difficult, more time consuming, and more costly. For example, Congress is currently considering a variety of amendments to the Oil Pollution Act of 1990, or “OPA”, in response to the Deepwater Horizon incident. OPA and regulations adopted pursuant to OPA impose a variety of requirements related to the prevention of and response to oil spills into waters of the United States, including the outer continental shelf waters where we have substantial operations. OPA subjects operators of offshore leases and owners and operators of oil handling facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from an oil spill, including, but not limited to, the costs of responding to a spill, natural resource damages and economic damages suffered by persons adversely affected by the spill. OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating in offshore waters, although the Secretary of Interior may increase this amount up to $150 million in certain situations. At least one proposed bill that Congress is considering with regard to OPA, which has been approved by the House of Representatives (H.R. 3534, the “Consolidated Land, Energy and Aquatic Resources Act”), would increase the minimum level of financial responsibility to $300 million. If OPA is amended to increase the minimum level of financial responsibility to $300 million, we may experience difficulty in providing financial assurances sufficient to comply with this requirement. If we are unable to provide the level of financial assurance required by OPA, we may be forced to sell our properties or operations located in offshore waters or enter into partnerships with other companies that can meet the increased financial responsibility requirement, and any such developments could have an adverse effect on the value of our offshore assets and the results of our operations. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required for companies operating in offshore waters will be increased.

Our estimates of future asset retirement obligations may vary significantly from period to period and are especially significant because our operations are almost exclusively in the Gulf of Mexico.

We are required to record a liability for the discounted present value of our asset retirement obligations to plug and abandon inactive, non-producing wells, to remove inactive or damaged platforms, facilities and equipment, and to restore the land or seabed at the end of oil and natural gas production operations. These costs are typically considerably more expensive for offshore operations as compared to most land-based operations due to increased regulatory scrutiny and the logistical issues associated with working in waters of various depths. Estimating future restoration and removal costs in the Gulf of Mexico is especially difficult because most of the removal obligations may be many years in the future, regulatory requirements are subject to change or more restrictive interpretation, and asset removal technologies are constantly evolving, which may result in additional or increased costs. As a result, we may make significant increases or decreases to our estimated asset retirement obligations in future periods. For example, because we operate in the Gulf of Mexico, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes. The estimated cost to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged or toppled rather than structurally intact. Accordingly, our estimate of future asset retirement obligations could differ dramatically from what we may ultimately incur as a result of damage from a hurricane.

In addition, the BOEM recently issued an NTL dated to be effective October 15, 2010 that establishes a more stringent regimen for the timely decommissioning of what is known as “idle iron” – wells, platforms and pipelines that are no longer producing or serving exploration or support functions related to an operator’s lease – in the Gulf of Mexico. Historically, many oil and natural gas producers in the Gulf of Mexico have scheduled the plugging, abandoning or removal of such idle iron for when they meet the final decommissioning regulatory requirement, which has been established as being within one year after the lease expires or terminates, a time period that sometimes is years after use of the idle iron has been discontinued. The determination of productive lease termination dates are generally based on management’s estimate as to when it would become likely that production, including from future development activities, would cease on the lease. The recently issued NTL, however, sets forth more stringent standards for decommissioning timing requirements by applying the requirement that any well that has not been used during the past five years for exploration or production on active leases and is no longer capable of producing in paying quantities must be permanently plugged or temporarily abandoned within three years. Plugging or abandonment of wells may be delayed by two years if all of the well’s hydrocarbon and sulphur zones are appropriately isolated. Similarly, platforms or other facilities that are no longer useful for operations must be removed within five years of the cessation of operations. Triggering of these plugging, abandonment and removal activities under what may be viewed as an accelerated schedule in comparison to historical decommissioning efforts may serve to increase, perhaps materially, our future plugging, abandonment and removal costs, which may translate into a need to increase our estimate of future asset retirement obligations required to meet such increased costs. In addition, the potential increase in decommissioning activity in the Gulf of Mexico over the next few years as a result of the NTL could likely result in increased demand for salvage contractors and equipment, resulting in increased estimates of plugging, abandonment and removal costs and increases in related asset retirement obligations.

Item 5.

Other Information

On August 2, 2010, the Company approved grants pursuant to the Incentive Compensation Plan. The Forms of the Executive Annual Incentive Award Agreement and the Executive Restricted Stock Unit Agreement that govern such grants are filed as Exhibits 10.5 and 10.6, respectively, to this Quarterly Report on Form 10-Q.

Item 6.

Exhibits

The exhibits to this report are listed in the Exhibit Index appearing on page 35 hereof.

SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on November 5, 2010.


W&T OFFSHORE, INC.

By:		/S/ JOHN D. GIBBONS
		John D. Gibbons
		Senior Vice President, Chief Financial Officer and Chief Accounting Officer, duly authorized to sign on behalf of the registrant

EXHIBIT INDEX


Exhibit Number		Description

2.1		Purchase and Sale Agreement between Total E&P USA, Inc. and W&T Offshore, Inc., effective January 1, 2010. (Incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K, filed May 3, 2010)

3.1		Amended and Restated Articles of Incorporation of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed February 24, 2006)

3.2		Amended and Restated Bylaws of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.2 of the Company’s Registration Statement on Form S-1, filed May 3, 2004 (File No. 333-115103))

10.1		W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan. (Incorporated by reference from Appendix A to the Company’s Definitive Proxy Statement on Schedule 14A, filed April 2, 2010)

10.2		Resignation Agreement dated as of July 1, 2010 between W. Reid Lea and W&T Offshore, Inc. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed July 8, 2010)

10.3		Form of Employment Agreement for Jamie L. Vazquez, John D. Gibbons and Stephen L. Schroeder. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed August 6, 2010)

10.4		Employment Agreement for Tracy W. Krohn. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed on November 5, 2010)

10.5*		Form of the Executive Annual Incentive Award Agreement for Fiscal Year 2010.

10.6*		Form of the Executive Restricted Stock Unit Agreement.

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.

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company