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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2011

¨	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 þ 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 þ 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 þ

As of August 2, 2011, there were 74,468,455 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 June 30, 2011 and December 31, 2010		1
	Condensed Consolidated Statements of Income for the Three and Six Months Ended June 30, 2011 and 2010		2
	Condensed Consolidated Statement of Changes in Shareholders’ Equity for the Six Months Ended June 30, 2011		3
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2011 and 2010		4
	Notes to Condensed Consolidated Financial Statements		5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		23

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		33

Item 4.	Controls and Procedures		34

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings		34

Item 1A.	Risk Factors		34

Item 5.	Other information - Submission of Matters to a Vote of Security Holders		35

Item 6.	Exhibits		35

SIGNATURE			36

EXHIBIT INDEX			37

PART I – FINANCIAL INFORMATION

Item 1.

Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30, 2011			December 31, 2010
	(In thousands, except share data) (Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	8,710		$	28,655
Receivables:
Oil and natural gas sales		91,517			79,911
Joint interest and other		11,308			25,415
Insurance		6,925			1,014

Total receivables		109,750			106,340
Deferred income taxes		—			5,784
Prepaid expenses and other assets		44,153			23,426

Total current assets		162,613			164,205
Property and equipment – at cost:
Oil and natural gas properties and equipment (full cost method, of which $151,934 at June 30, 2011 and $65,419 at December 31, 2010 were excluded from amortization)		5,707,628			5,225,582
Furniture, fixtures and other		16,018			15,841

Total property and equipment		5,723,646			5,241,423
Less accumulated depreciation, depletion and amortization		4,163,013			4,021,395

Net property and equipment		1,560,633			1,220,028
Restricted deposits for asset retirement obligations		33,921			30,636
Deferred income taxes		—			2,819
Other assets		15,297			6,406

Total assets	$	1,772,464		$	1,424,094

Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	65,636		$	80,442
Undistributed oil and natural gas proceeds		36,263			25,240
Asset retirement obligations		105,379			92,575
Accrued liabilities		23,331			25,827
Income taxes payable		2,596			17,552
Income taxes deferred – current portion		2,249			—
Long-term debt – current portion		43,850			—

Total current liabilities		279,304			241,636
Long-term debt		675,000			450,000
Asset retirement obligations, less current portion		287,699			298,741
Deferred income taxes		24,806			—
Other liabilities		12,383			11,974
Commitments and contingencies		—			—
Shareholders’ equity:
Preferred stock, $0.00001 par value; 2,000,000 shares authorized; 0 issued at June 30, 2011 and December 31, 2010		—			—
Common stock, $0.00001 par value; 118,330,000 shares authorized; 77,338,074 issued and 74,468,901 outstanding at June 30, 2011; 77,343,520 issued and 74,474,347 outstanding at December 31, 2010		1			1
Additional paid-in capital		381,191			377,529
Retained earnings		136,247			68,380
Treasury stock, at cost		(24,167	)		(24,167	)

Total shareholders’ equity		493,272			421,743

Total liabilities and shareholders’ equity	$	1,772,464		$	1,424,094

See Notes to Condensed Consolidated Financial Statements.

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(In thousands, except per share data)
	(Unaudited)
Revenues	$	252,922		$	179,667		$	463,777		$	349,252

Operating costs and expenses:
Lease operating expenses		48,597			52,457			101,002			87,823
Production taxes		845			283			1,133			512
Gathering and transportation		3,797			3,726			8,350			8,313
Depreciation, depletion and amortization		75,880			69,895			141,618			132,819
Asset retirement obligation accretion		7,490			6,127			15,844			12,412
General and administrative expenses		18,002			14,375			36,131			24,754
Derivative (gain) loss		(17,332	)		(7,374	)		6,508			(13,270	)

Total costs and expenses		137,279			139,489			310,586			253,363

Operating income		115,643			40,178			153,191			95,889
Interest expense:
Incurred		12,056			10,914			22,192			21,834
Capitalized		(2,079	)		(1,329	)		(3,491	)		(2,745	)
Loss on extinguishment of debt		20,663			—			20,663			—
Other income		9			354			16			482

Income before income tax expense		85,012			30,947			113,843			77,282
Income tax expense		29,837			3,077			40,019			7,097

Net income	$	55,175		$	27,870		$	73,824		$	70,185

Basic and diluted earnings per common share	$	0.73		$	0.37		$	0.98		$	0.94
Dividends declared per common share	$	0.04		$	0.03		$	0.08		$	0.06

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, 2010		74,474		$	1	$	377,529	$	68,380			2,869	$	(24,167	)	$	421,743
Cash dividends		—			—		—		(5,957	)		—		—			(5,957	)
Share-based compensation		—			—		3,662		—			—		—			3,662
Restricted stock issued, net of forfeitures		(5	)		—		—		—			—		—			—
Net income		—			—		—		73,824			—		—			73,824

Balances at June 30, 2011		74,469		$	1	$	381,191	$	136,247			2,869	$	(24,167	)	$	493,272

See Notes to Condensed Consolidated Financial Statements.

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six Months Ended June 30,
	2011			2010
	(In thousands)
	(Unaudited)
Operating activities:
Net income	$	73,824		$	70,185
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		157,462			145,231
Amortization of debt issuance costs and discount on indebtedness		815			669
Loss on extinguishment of debt		20,663			—
Share-based compensation		3,662			1,943
Derivative (gain) loss		6,508			(13,270	)
Cash payments on derivative settlements		(8,322	)		(442	)
Deferred income taxes		35,726			2,945
Changes in operating assets and liabilities:
Oil and natural gas receivables		(11,606	)		(11,739	)
Joint interest and other receivables		14,107			21,931
Insurance receivables		12,583			29,879
Income taxes		(14,957	)		91,513
Prepaid expenses and other assets		(24,650	)		(9,129	)
Asset retirement obligations		(29,703	)		(35,210	)
Accounts payable and accrued liabilities		(6,382	)		(62,542	)
Other liabilities		115			12,354

Net cash provided by operating activities		229,845			244,318

Investing activities:
Acquisitions of significant property interests in oil and natural gas properties		(396,976	)		(116,589	)
Investment in oil and natural gas properties and equipment		(85,801	)		(89,705	)
Proceeds from sales of oil and natural gas properties and equipment		—			1,335
Purchases of furniture, fixtures and other		(178	)		(167	)

Net cash used in investing activities		(482,955	)		(205,126	)

Financing activities:
Issuance of 8.5% Senior Notes		600,000			—
Repurchase of 8.25% Senior Notes		(406,150	)		—
Borrowings of long-term debt – revolving bank credit facility		310,000			285,000
Repayments of long-term debt – revolving bank credit facility		(235,000	)		(285,000	)
Repurchase premium and debt issuance costs		(29,728	)		—
Dividends to shareholders		(5,957	)		(4,481	)

Net cash provided (used) in financing activities		233,165			(4,481	)

Increase (decrease) in cash and cash equivalents		(19,945	)		34,711
Cash and cash equivalents, beginning of period		28,655			38,187

Cash and cash equivalents, end of period	$	8,710		$	72,898

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 deepwater and deep shelf regions in the Gulf of Mexico. W&T has recently diversified its operations by expanding onshore primarily in the West Texas Permian Basin.

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.

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 thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010.

Reclassifications. Certain reclassifications have been made to the 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.

2. Acquisitions

On May 11, 2011, we completed the acquisition of approximately 21,900 gross acres (21,500 net acres) of oil and gas leasehold interests in the West Texas Permian Basin (the “Permian Basin Properties”) from Opal Resources LLC and Opal Resources Operating Company LLC (“Opal”). The stated purchase price was $366.3 million, subject to certain adjustments, including adjustments from an effective date of January 1, 2011. Taking into account adjustments through June 30, 2011, the purchase price was $399.5 million. The increase of $33.2 million primarily reflects drilling costs in excess of cash flow from the effective date of January 1, 2011 to the closing date of May 11, 2011. The purchase price is subject to further adjustments and we expect final settlement could occur as early as the third quarter of 2011. We acquired estimated proved reserves of approximately 30 million barrels of oil equivalent (182 Bcfe) (using a 6 to 1 Mcf to barrel equivalency) as of December 31, 2010, comprised of approximately 91% oil and natural gas liquids and which are approximately 78% proved undeveloped. The acquisition was funded from cash on hand and borrowings under our revolving bank credit facility.

During 2010, we closed on two major acquisition transactions. On April 30, 2010, through our wholly-owned subsidiary, W&T Energy VI, LLC (“Energy VI”), we acquired all of Total E&P USA’s (“Total”) interest, including production platforms and facilities, in three federal offshore lease blocks located in the Gulf of Mexico and assumed the asset retirement obligations (“ARO”) for plugging and abandonment of the acquired interest. The purchase price was $121.3 million. The properties acquired from Total are producing interests and include a 100% working interest in the Matterhorn field (Mississippi Canyon block 243) and a 64% working interest in the Virgo field (Viosca Knoll blocks 822 and 823).

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

On November 4, 2010, through Energy VI, we acquired all of Shell Offshore Inc.’s (“Shell”) interests, including production platforms and facilities, in three federal offshore lease blocks located in the Gulf of Mexico and assumed the ARO for plugging and abandonment of the acquired interest. The purchase price was $139.9 million. The properties acquired from Shell are producing interests and include a 70% working interest in the Tahoe field (Viosca Knoll 783), 100% working interest in the Southeast Tahoe field (Viosca Knoll 784) and a 6.25% of 8/8ths overriding royalty interest in the Droshky field (Green Canyon 244).

The Permian Basin Properties accounted for $11.1 million of revenue, $1.4 million of direct operating expenses, $2.4 million of depreciation, depletion, amortization and accretion (“DD&A”) and $2.6 million of income taxes, resulting in $4.8 million of net income for the three and six months ended June 30, 2011. The net income attributable to these properties does not reflect certain expenses, such as general and administrative expenses and interest expense; therefore this information is not intended to report results as if these operations were managed on a stand-alone basis. In addition, the Permian Basin Properties are not recorded in a separate entity for tax purposes; therefore income tax was estimated using the federal statutory tax rate.

Pro forma financial statements have been prepared due to the acquisition being significant to us. The unaudited pro forma financial information was computed as if the acquisition of the Permian Basin Properties had been completed on January 1, 2010. The historical financial information is derived from the unaudited historical consolidated financial statements of W&T and the unaudited historical statements of revenues and direct operating expenses of the Permian Basin Properties (which were based on information provided by Opal). The adjustments noted below assume the entire transaction was financed with borrowings because the cash and cash equivalents balances for the assumed acquisition date was less than the cash and cash equivalents on hand used on the actual closing date of May 11, 2011.

The pro forma adjustments were based on information and estimates by management to be directly related to the purchase of the Permian Basin Properties. The pro forma financial information is not necessarily indicative of the results of operations had the purchase occurred on January 1, 2010. If the transaction had been in effect for the periods indicated, the results may have been substantially different. For example, we may have operated the assets differently than Opal, realized sales prices may have been different and costs of operating the properties may have been different. The following tables present a summary of our pro forma consolidated statement of income (loss) for the six months ended June 30, 2011 and 2010 (in thousands except earnings per share):

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


	Six Months Ended June 30, 2011
	Historical			Permian Basin Properties			Pro Forma Adjustments			Pro Forma
Revenues	$	463,777		$	23,801	(a)	$	—		$	487,578

Operating costs and expenses:
Lease operating expenses		101,002			5,261	(a)		—			106,263
Production taxes		1,133			1,352	(a)		—			2,485
Gathering and transportation		8,350			10	(a)		—			8,360
Depreciation, depletion and amortization		141,618			—			9,263	(b)		150,881
Asset retirement obligation accretion		15,844			—			10	(c)		15,854
General and administrative expenses		36,131			—			(282	)(d)		35,849
Derivative loss		6,508			—			—			6,508

Total costs and expenses		310,586			6,623			8,991			326,200

Operating income/(loss)		153,191			17,178			(8,991	)		161,378
Interest expense:
Incurred		22,192			—			3,865	(e)		26,057
Capitalized		(3,491	)		—			(1,165	)(f)		(4,656	)
Loss on extinguishment of debt		20,663			—			—			20,663
Other income		16			—			—			16

Income/(loss) before income tax expense		113,843			17,178			(11,691	)		119,330
Income tax expense		40,019			—			1,920	(g)		41,939

Net income/(loss)	$	73,824		$	17,178		$	(13,611	)	$	77,391

Basic and diluted earnings per common share	$	0.98								$	1.02

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)


	Six Months Ended June 30, 2010
	Historical			Permian Basin Properties			Pro Forma Adjustments			Pro Forma
Revenues	$	349,252		$	12,043	(a)	$	—		$	361,295

Operating costs and expenses:
Lease operating expenses		87,823			1,695	(a)		—			89,518
Production taxes		512			575	(a)		—			1,087
Gathering and transportation		8,313			4	(a)		—			8,317
Depreciation, depletion and amortization		132,819			—			13,857	(b)		146,676
Asset retirement obligation accretion		12,412			—			15	(c)		12,427
General and administrative expenses		24,754			—			—			24,754
Derivative (gain)		(13,270	)		—			—			(13,270	)

Total costs and expenses		253,363			2,274			13,872			269,509

Operating income/(loss)		95,889			9,769			(13,872	)		91,786
Interest expense:
Incurred		21,834			—			5,489	(e)		27,323
Capitalized		(2,745	)		—			(1,548	)(f)		(4,293	)
Other income		482			—			—			482

Income/(loss) before income tax expense		77,282			9,769			(17,813	)		69,238
Income tax expense/(benefit)		7,097			—			(2,815	)(g)		4,282

Net income/(loss)	$	70,185		$	9,769		$	(14,998	)	$	64,956

Basic and diluted earnings per common share	$	0.94								$	0.87

The purchase price is subject to further adjustments and we expect final settlement could occur as early as the third quarter of 2011. For these pro forma financial statements, the cash consideration is assumed to be funded entirely from borrowings from the revolving bank credit facility. The following table presents the purchase price allocation for the Permian Basin Properties as of June 30, 2011 (in thousands):


Oil and natural gas properties and equipment (full cost method, $84,720 excluded from amortization)	$	399,501
Asset retirement obligation		(382	)
Long-term liability		(2,143	)

Total cash paid	$	396,976

The following adjustments were made in the preparation of the condensed combined financial statements:

(a)

Revenues and direct operating expenses for the Permian Basin Properties were derived from the historical records of Opal up to the closing date of May 11, 2011.

(b)

Depreciation, depletion and amortization (“DD&A”) was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Permian Basin costs, reserves and production into the computation. The purchase price allocation included $84.7 million allocated to the pool of unevaluated properties for oil and gas interests. Accordingly, no DD&A expense was estimated for the unevaluated properties.

(c)

Asset retirement obligations and related accretion were estimated by the management of W&T.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

(d)

Incremental transaction expenses related to the purchase of Permian Basin Properties were $0.3 million and were assumed to be funded from cash on hand.

(e)

Interest expense was computed using interest rates that were in effect during the applicable time period and it was assumed that six-month LIBOR borrowings were made as allowed under the revolving bank credit facility. The assumed interest rates ranged from 3.1% to 3.5%. A reduction in the revolving bank credit facility commitment fee related to the assumed borrowings was netted against the computed incremental interest expense.

(f)

Incremental capitalized interest was computed for the addition of $84.7 million allocated to the pool of unevaluated properties and the capitalization interest rate was adjusted for the assumed borrowings.

(g)

Income tax was computed using the 35% federal statutory rate.

3. 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. 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 below our retention amount.

Below is a summary of remediation costs and amounts approved for payments related to Hurricanes Ike and Gustav that were included in lease operating expense (in thousands). Bracketed amounts represent credits to expense:


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Incurred and reversals of accruals	$	114		$	2,229		$	76		$	(1,878	)
Plus amounts returned to insurers		—			—			1,240			—
Less amounts approved for payment by insurers		(587	)		(138	)		(587	)		(2,357	)

Included in lease operating expense	$	(473	)	$	2,091		$	729		$	(4,235	)

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. Incurred expenses included revisions of previous estimates. Amounts in 2011 include return of reimbursements that were previously received by us related to prepayments based on preliminary estimates. See Note 4 for additional information about the impact of hurricane related items on our asset retirement obligations.

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, 2010 to June 30, 2011 (in thousands):


Balance, December 31, 2010	$	1,014
Costs approved under our insurance policies, net		17,841
Payments received, net		(11,930	)

Balance, June 30, 2011	$	6,925

At June 30, 2011 and December 31, 2010, substantially all of the amounts in insurance receivables relate to the plugging and abandonment of wells and dismantlement of facilities damaged by Hurricane Ike. We expect that our available cash and cash equivalents, cash flow from operations and the availability under our revolving bank credit facility will be sufficient to meet necessary expenditures that may exceed our insurance coverage for damages incurred as a result of Hurricane Ike.

4. 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 the changes to our asset retirement obligations is as follows (in thousands):


Balance, December 31, 2010	$	391,316
Liabilities settled		(29,703	)
Accretion of discount		15,844
Liabilities assumed through acquisition		382
Liabilities incurred		330
Revisions of estimated liabilities due to Hurricane Ike		6,628
Revisions of estimated liabilities – all other		8,281

Balance, June 30, 2011		393,078
Less current portion		105,379

Long-term	$	287,699

5. Derivative Financial Instruments

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 bank credit facility. We do not enter into derivative instruments for speculative trading purposes. Our derivative instruments currently consist of commodity option contracts. We are 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.

We account for derivative contracts in accordance with GAAP, 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. We have elected not to designate our commodity derivatives as hedging instruments. For additional information about fair value measurements, refer to Note 7.

Commodity Derivative: During 2010, we entered into commodity option contracts to manage our exposure to commodity price risk from sales of oil through December 31, 2012. While these contracts are intended to reduce the effects of price volatility, they may also limit future income from favorable price movements. As of June 30, 2011, 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)
7/1/2011	9/30/2011		231,900	$	75.00	$	93.02	$	934
10/1/2011	12/31/2011		392,100		75.00		95.58		2,714
1/1/2012	3/31/2012		364,000		75.00		97.88		2,726
4/1/2012	6/30/2012		364,000		75.00		97.88		3,186
7/1/2012	9/30/2012		124,000		75.00		97.88		1,152
10/1/2012	12/31/2012		251,000		75.00		98.99		2,357

			1,727,000	$	75.00	$	96.86	$	13,069

At June 30, 2011, $9.6 million and $3.5 million were included in accrued liabilities and other long-term liabilities, respectively, related to our commodity derivative contracts. At December 31, 2010, $9.5 million and $5.4 million were included in accrued liabilities and other long-term liabilities, respectively, related to our commodity derivative contracts. Our derivative gain for the three months ended June 30, 2011 includes realized losses of $6.1 million and unrealized gains of $23.4 million related to our commodity derivatives. Our derivative loss for the six months ended June 30, 2011 includes realized losses of $8.3 million and unrealized gains of $1.8 million related to our commodity derivatives. Our derivative gain for the three months ended June 30, 2010 includes realized and unrealized gains of $2.1 million and $5.3 million, respectively, related to our commodity derivatives. Our derivative gain for the six months ended June 30, 2010 includes realized and unrealized gains of $3.2 million and $10.4 million, respectively, related to our commodity derivatives.

Interest Rate Swap: Our interest rate swap contract with a fixed interest rate of 5.21% expired in August 2010. During the three months ended June 30, 2010, we recognized an unrealized gain of $1.8 million and a realized loss of $1.8 million for this contract. During the six months ended June 30, 2010, we recognized an unrealized gain of $3.3 million and a realized loss of $3.6 million for this contract.

6. Long-Term Debt

On June 10, 2011, we issued $600 million of our Senior Notes at par with an interest rate of 8.5% and maturity date of June 15, 2019 (the “8.5% Senior Notes”). Interest is payable semi-annually in arrears on June 15 and December 15 of each year beginning on December 15, 2011. The 8.5% Senior Notes are unsecured and are fully and unconditionally guaranteed by certain of our subsidiaries. The restrictive covenants and redemption provisions of the 8.5% Senior Notes are substantially similar to the terms of the 8.25% Senior Notes due 2014 (the “8.25% Senior Notes”). At June 30, 2011, the outstanding balance of our 8.5% Senior Notes was $600 million and was classified at their carrying value as long-term debt. The estimated annual effective interest rate on the 8.5% Senior Notes is 8.7% which includes amortization of debt issuance costs. At June 30, 2011, the estimated fair value of the 8.5% Senior Notes was approximately $606 million. For additional details about fair value measurements, refer to Note 7.

We used a portion of the net proceeds from the issuance of the 8.5% Senior Notes to fund a concurrent tender offer of our 8.25% Senior Notes, pursuant to which $406.2 million in principal amount of the 8.25% Senior Notes were tendered for repurchase. At June 30, 2011, the outstanding balance of our 8.25% Senior Notes was $43.9 million and was classified at their carrying value as short-term debt. At December 31, 2010, the outstanding balance of our 8.25% Senior Notes was $450 million and was classified at their carrying value as long-term debt. The estimated annual effective interest rate on the 8.25% Senior Notes during the six months ended June 30, 2011 was 8.4%. At June 30, 2011 and December 31, 2010, the estimated fair value of the 8.25% Senior Notes was approximately $45.7 million and $441 million, respectively. For additional details about fair value measurements, refer to Note 7. Costs related to the 8.25% Senior Notes that were repurchased pursuant to the tender offer, which includes the repurchase premium and a prorated amount of the unamortized debt issuance costs, are included in the statement of income within the line item classification, Loss on extinguishment of debt, in the amount of $20.0 million. See Note 13 for additional information regarding the remaining $43.9 million of 8.25% Senior Notes.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

On May 5, 2011, we entered into a Fourth Amended and Restated Credit Agreement (the “Credit Agreement”) which provides a revolving bank credit facility with an initial borrowing base of $525 million. This is a secured facility that is collateralized by our oil and natural gas properties. The Credit Agreement terminates on May 5, 2015 and replaces the prior Third Amended and Restated Credit Agreement (the “Prior Credit Agreement”), which would have expired July 23, 2012. The pricing terms and restrictive covenants of the Credit Agreement are substantially similar to the terms of the Prior Credit Agreement. Availability under the Credit Agreement is subject to a semi-annual borrowing base determination set at the discretion of our lenders. The amount of the borrowing base is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria. Any determination by our lenders to change our borrowing base will result in a similar change in the availability under our revolving bank credit facility.

The initial borrowing base is reduced by $0.25 for every dollar of senior note indebtedness in excess of $450 million. Due to the issuance of the 8.5% Senior Notes, our borrowing base was reduced to $487.5 million.

The Credit Agreement contains covenants that restrict, among other things, the payment of cash dividends and share repurchases of up to $60 million per year, borrowings other than from the revolving bank credit facility, sales of assets, loans to others, investments, merger activity, hedging contracts, liens and certain other transactions without the prior consent of the lenders. Letters of credit may be issued up to $90 million, provided availability under the revolving bank credit facility exists. 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 such ratios are defined in the Credit Agreement. We were in compliance with all applicable covenants of the Credit Agreement as of June 30, 2011.

Borrowings under the revolving bank credit facility bear interest at the applicable London Interbank Offered Rate (“LIBOR”) plus a margin that varies from 2.00% to 2.75% depending on the level of total borrowings under the Credit Agreement, or an alternative base rate equal to the applicable margin ranging from 1.00% to 1.75% plus the highest of the (a) the Prime Rate, (b) the Federal Funds Rate plus 0.50%, and (c) LIBOR plus 1.0%. The unused portion of the borrowing base is subject to a commitment fee of 0.50%. The estimated annual effective interest rate was 7.2% for the first six months of 2011 for borrowings under the Credit Agreement and the Prior Credit Agreement and includes amortization of debt issuance costs, commitment fees and other related costs.

Unamortized debt issuance costs related to the Prior Credit Agreement are included in the statement of income within the line item classification, Loss on extinguishment of debt, in the amount of $0.7 million.

At June 30, 2011, we had $75 million in borrowings and $0.5 million in letters of credit outstanding under the revolving bank credit facility. At December 31, 2010, we had no borrowings and $0.4 million in letters of credit outstanding under the revolving bank credit facility provided by the Prior Credit Agreement.

7. 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 for the fair value measurement of our derivative financial instruments are the exercise price, the expiration date, the settlement date, notional quantities, the implied volatility, the discount curve with spreads and published commodity futures prices. As described in Note 5, our derivative financial instruments are reported in the balance sheet at fair value and changes in fair value are recognized currently in earnings.

The fair value of our Senior Notes is based on quoted prices. The market for our Senior Notes is not an active market; therefore the fair value is classified within Level 2. The Senior Notes are reported in the balance sheet at their carrying value and their fair value is reported in Note 6.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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

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 in January 2011, the Company granted restricted stock to one of its employees. RSUs are a long-term compensation component of the Plan, are granted to only certain employees, and are subject to adjustment based on the Company achieving certain predetermined performance criteria and vest at the end of a specified deferral period. Prior to 2010, the Company granted only restricted stock to its employees. In 2011 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, the Company may grant its employees cash-based incentive awards, which are a short-term component of the Plan, and are based on the Company and the employee achieving certain predetermined performance criteria.

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. We are also required to estimate forfeitures, resulting in the recognition of compensation cost only for those awards that actually vest.

At June 30, 2011, there were 2,152,377 shares of common stock available for award under the Plan and 568,783 shares of common stock available for award under the Directors Compensation Plan.

Restricted Stock: The Company currently has unvested restricted shares outstanding issued to employees and 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 six months ended June 30, 2011 is as follows:


	Restricted Stock
	Shares			Weighted Average Grant Date Fair Value Per Share
Outstanding restricted shares, December 31, 2010		470,392		$	7.42
Granted		20,433			25.45
Vested		(24,633	)		13.26
Forfeited		(25,879	)		6.83

Outstanding restricted shares, June 30, 2011		440,313			7.97

At June 30, 2011, the composition of our restricted stock awards outstanding, by year granted, was as follows:


	Shares
Employees – granted in:
2011		5,325	(1)
2009		385,780	(2)
Non-employee directors – granted in:
2011		15,108	(3)
2010		23,330	(4)
2009		10,770	(5)

Total		440,313

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

(1)	Equal installments in December 2011 and December 2012.

(2)	December 2011.

(3)	Equal installments in May 2012, 2013 and 2014.

(4)	Equal installments in May 2012 and 2013.

(5)

May 2012.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The grant date fair value of restricted stock granted during the six months ended June 30, 2011 and 2010 was $0.5 million and $0.4 million, respectively. The fair value of the shares that vested during the six months ended June 30, 2011 and 2010 was $0.6 million and $0.1 million, respectively.

Restricted Stock Units: During 2010, the Company awarded to certain employees RSUs that were 100% contingent upon meeting a specified performance requirement, which was achieved in 2010. RSUs are subject to forfeiture until vested and cannot be sold, transferred or disposed of during the restricted period. Effective January 2011, RSUs awarded in 2010 earn dividend equivalents at the same rate as dividends paid on our common stock.

A summary of share activity related to RSUs for the six months ended June 30, 2011 is as follows:


	Restricted Stock Units
	Units (1)			Weighted Average Grant Date Fair Value Per Unit
Outstanding RSUs, December 31, 2010		1,266,617		$	9.36
Granted		—			—
Vested		—			—
Forfeited		(33,096	)		9.36

Outstanding RSUs, June 30, 2011		1,233,521			9.36

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

During the six months ended June 30, 2011 and 2010, there were no grants or vesting of RSUs.

Share-Based Compensation: A summary of incentive compensation expense under share-based payment arrangements and the related tax benefit for the three and six months ended June 30, 2011 and 2010 is as follows (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Share-based compensation expense from:
Restricted stock	$	603	$	747	$	1,191	$	1,943
Restricted stock units		1,232		—		2,471		—

Total	$	1,835	$	747	$	3,662	$	1,943

Share-based compensation tax benefit:
Tax benefit computed at the statutory rate	$	642	$	261	$	1,282	$	680

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 and 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.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Incentive Compensation: A summary of incentive compensation expense for the three and six months ended June 30, 2011 and 2010 is as follows (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Share-based compensation expense included in:
Lease operating expense	$	116	$	159	$	233	$	428
General and administrative		1,719		588		3,429		1,515

Total charged to operating income		1,835		747		3,662		1,943

Cash-based incentive compensation included in:
Lease operating expense		1,119		651		2,199		777
General and administrative		3,288		2,377		6,052		2,911

Total charged to operating income		4,407		3,028		8,251		3,688

Total incentive compensation charged to operating income	$	6,242	$	3,775	$	11,913	$	5,631

As of June 30, 2011, unrecognized share-based compensation expense related to our outstanding restricted shares and RSUs was $1.7 million and $6.9 million, respectively. Unrecognized compensation expense will be recognized through April 2014 for restricted shares and November 2012 for RSUs.

9. Income Taxes

Income tax expense of $29.8 million and $40.0 million was recorded during the three and six months ended June 30, 2011, respectively. Our effective tax rate for the three and six months ended June 30, 2011 was 35.1% and 35.2%, respectively, which approximated the federal and state statutory rates. Income tax expense of $3.1 million and $7.1 million was recorded during the three and six months ended June 30, 2010, respectively. Our effective tax rate for the three and six months ended June 30, 2010 was 9.9% and 9.2% and primarily reflects a reduction in our valuation allowance that was recorded in prior years.

Exclusive of interest, the amount of unrecognized tax benefit recorded in other liabilities was $ 3.6 million as of June 30, 2011 and December 31, 2010. We recognize interest and penalties related to unrecognized tax benefits in income tax expense and these amounts were immaterial for the six months ended June 30, 2011 and 2010. The tax years from 2007 through 2010 remain open to examination by the applicable tax jurisdictions.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

10. Earnings Per Share

The following table presents the calculation of basic earnings per common share for the three and six months ended June 30, 2011 and 2010 (in thousands, except per share amounts):


	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Net income	$	55,175	$	27,870	$	73,824	$	70,185
Less portion allocated to nonvested shares		1,178		379		1,558		957

Net income allocated to common shares	$	53,997	$	27,491	$	72,266	$	69,228


Weighted average common shares outstanding		74,020		73,669		74,012		73,665


Basic and diluted earnings per common share	$	0.73	$	0.37	$	0.98	$	0.94

Shares excluded due to being anti-dilutive (weighted-average)		1,683		1,017		1,699		1,021

11. Dividends

During the six months ended June 30, 2011 and 2010, we paid regular cash dividends of $0.04 and $0.03 per common share per quarter, respectively. On August 3, 2011, our board of directors declared a cash dividend of $0.04 per common share, payable on September 12, 2011 to shareholders of record on August 22, 2011.

12. Contingencies

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.

13. Subsequent Event

On July 18, 2011, we redeemed the remaining outstanding $43.9 million principal amount of our 8.25% Senior Notes, which would have matured in June 2014, at a redemption price of 104.125% plus accrued interest under the terms of the applicable indenture. These were 8.25% Senior Notes that were not tendered and repurchased during our tender offer conducted in June 2011. The redemption premium and remaining unamortized debt issuance costs of $2.0 million will be included in the statement of income within the line item classification, Loss on extinguishment of debt, in the third quarter of 2011.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

14. Supplemental Guarantor Information

Our payment obligations under the 8.5% Senior Notes, the 8.25% Senior Notes and the Credit Agreement (see Note 6) are fully and unconditionally guaranteed by certain of our wholly-owned subsidiaries, Energy VI and W&T Energy VII, which does not have any active operations, (together, the “Guarantor Subsidiaries”).

The following unaudited condensed consolidating financial information presents the financial condition, results of operations and cash flows of W&T Offshore, Inc. and other consolidated subsidiaries (“Parent Company”) and the Guarantor Subsidiaries, together with consolidating adjustments necessary to present the Company’s results on a consolidated basis. Consolidated subsidiaries other than the Guarantor Subsidiaries are considered “minor” under applicable accounting rules of the SEC.

Condensed Consolidating Balance Sheet as of June 30, 2011


	Parent Company			Guarantor Subsidiaries		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	8,710		$	—	$	—		$	8,710
Receivables:
Oil and natural gas sales		69,201			22,316		—			91,517
Joint interest and other		11,308			—		—			11,308
Insurance		6,925			—		—			6,925
Income taxes		45,830			—		(45,830	)		—

Total receivables		133,264			22,316		(45,830	)		109,750
Deferred income taxes		—			9,183		(9,183	)		—
Prepaid expenses and other assets		44,153			—		—			44,153

Total current assets		186,127			31,499		(55,013	)		162,613
Property and equipment – at cost:
Oil and natural gas properties and equipment		5,435,135			272,493		—			5,707,628
Furniture, fixtures and other		16,018			—		—			16,018

Total property and equipment		5,451,153			272,493		—			5,723,646
Less accumulated depreciation, depletion and amortization		4,094,280			68,733		—			4,163,013

Net property and equipment		1,356,873			203,760		—			1,560,633
Restricted deposits for asset retirement obligations		33,921			—		—			33,921
Other assets		325,119			155,804		(465,626	)		15,297

Total assets	$	1,902,040		$	391,063	$	(520,639	)	$	1,772,464

Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	64,285		$	1,351	$	—		$	65,636
Undistributed oil and natural gas proceeds		35,937			326		—			36,263
Asset retirement obligations		105,348			—		31			105,379
Accrued liabilities		23,331			—		—			23,331
Income taxes		—			48,426		(45,830	)		2,596
Deferred income taxes – current		2,249			—		—			2,249
Long-term debt - current		43,850			—		—			43,850

Total current liabilities		275,000			50,103		(45,799	)		279,304
Long-term debt		675,000			—		—			675,000
Asset retirement obligations, less current portion		256,593			31,136		(30	)		287,699
Deferred income taxes		33,989			—		(9,183	)		24,806
Other liabilities		168,186			—		(155,803	)		12,383
Commitments and contingencies		—			—		—			—
Shareholders’ equity:
Common stock		1			—		—			1
Additional paid-in capital		381,191			236,944		(236,944	)		381,191
Retained earnings		136,247			72,880		(72,880	)		136,247
Treasury stock, at cost		(24,167	)		—		—			(24,167	)

Total shareholders’ equity		493,272			309,824		(309,824	)		493,272

Total liabilities and shareholders’ equity	$	1,902,040		$	391,063	$	(520,639	)	$	1,772,464

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Condensed Consolidating Balance Sheet as of December 31, 2010


	Parent Company			Guarantor Subsidiaries		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	28,655		$	—	$	—		$	28,655
Receivables:
Oil and natural gas sales		50,421			29,490		—			79,911
Joint interest and other		25,415			—		—			25,415
Insurance		1,014			—		—			1,014
Income taxes		2,492			—		(2,492	)		—

Total receivables		79,342			29,490		(2,492	)		106,340
Deferred income taxes		5,784			2,755		(2,755	)		5,784
Prepaid expenses and other assets		23,426			—		—			23,426

Total current assets		137,207			32,245		(5,247	)		164,205
Property and equipment – at cost:
Oil and natural gas properties and equipment		4,955,460			270,122		—			5,225,582
Furniture, fixtures and other		15,841			—		—			15,841

Total property and equipment		4,971,301			270,122		—			5,241,423
Less accumulated depreciation, depletion and amortization		3,994,085			27,310		—			4,021,395

Net property and equipment		977,216			242,812		—			1,220,028
Restricted deposits for asset retirement obligations		30,636			—		—			30,636
Deferred income taxes		2,819			—		—			2,819
Other assets		275,461			47,160		(316,215	)		6,406

Total assets	$	1,423,339		$	322,217	$	(321,462	)	$	1,424,094

Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	77,422		$	3,020	$	—		$	80,442
Undistributed oil and natural gas proceeds		24,866			374		—			25,240
Asset retirement obligations		92,575			—		—			92,575
Accrued liabilities		25,827			—		—			25,827
Income taxes		—			20,044		(2,492	)		17,552

Total current liabilities		220,690			23,438		(2,492	)		241,636
Long-term debt		450,000			—		—			450,000
Asset retirement obligations, less current portion		269,016			29,725		—			298,741
Deferred income taxes		2,755			—		(2,755	)		—
Other liabilities		59,135			—		(47,161	)		11,974
Commitments and contingencies		—			—		—			—
Shareholders’ equity:
Common stock		1			—		—			1
Additional paid-in capital		377,529			236,944		(236,944	)		377,529
Retained earnings		68,380			32,110		(32,110	)		68,380
Treasury stock, at cost		(24,167	)		—		—			(24,167	)

Total shareholders’ equity		421,743			269,054		(269,054	)		421,743

Total liabilities and shareholders’ equity	$	1,423,339		$	322,217	$	(321,462	)	$	1,424,094

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Condensed Consolidating Statement of Income for the Three Months Ended June 30, 2011


	Parent Company			Guarantor Subsidiaries		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Revenues	$	192,527		$	60,395	$	—		$	252,922

Operating costs and expenses:
Lease operating expenses		38,066			10,531		—			48,597
Production taxes		845			—		—			845
Gathering and transportation		3,249			548		—			3,797
Depreciation, depletion and amortization		56,432			19,448		—			75,880
Asset retirement obligation accretion		6,784			706		—			7,490
General and administrative expenses		16,892			1,110		—			18,002
Derivative (gain)		(17,332	)		—		—			(17,332	)

Total costs and expenses		104,936			32,343		—			137,279

Operating income		87,591			28,052		—			115,643
Earnings of affiliates		18,234			—		(18,234	)		—
Interest expense:
Incurred		12,056			—		—			12,056
Capitalized		(2,079	)		—		—			(2,079	)
Loss on extinguishment of debt		20,663			—		—			20,663
Interest income		9			—		—			9

Income before income tax expense		75,194			28,052		(18,234	)		85,012
Income tax expense		20,019			9,818		—			29,837

Net income	$	55,175		$	18,234	$	(18,234	)	$	55,175

Condensed Consolidating Statement of Income for the Six Months Ended June 30, 2011


	Parent Company			Guarantor Subsidiaries		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Revenues	$	332,753		$	131,024	$	—		$	463,777

Operating costs and expenses:
Lease operating expenses		80,147			20,855		—			101,002
Production taxes		1,133			—		—			1,133
Gathering and transportation		6,321			2,029		—			8,350
Depreciation, depletion and amortization		100,195			41,423		—			141,618
Asset retirement obligation accretion		14,432			1,412		—			15,844
General and administrative expenses		33,549			2,582		—			36,131
Derivative loss		6,508			—		—			6,508

Total costs and expenses		242,285			68,301		—			310,586

Operating income		90,468			62,723		—			153,191
Earnings of affiliates		40,770			—		(40,770	)		—
Interest expense:
Incurred		22,192			—		—			22,192
Capitalized		(3,491	)		—		—			(3,491	)
Loss on extinguishment of debt		20,663			—		—			20,663
Interest income		16			—		—			16

Income before income tax expense		91,890			62,723		(40,770	)		113,843
Income tax expense		18,066			21,953		—			40,019

Net income	$	73,824		$	40,770	$	(40,770	)	$	73,824

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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


	Parent Company			Guarantor Subsidiaries (1)		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Revenues	$	160,511		$	19,156	$	—		$	179,667

Operating costs and expenses:
Lease operating expenses		46,546			5,911		—			52,457
Production taxes		283			—		—			283
Gathering and transportation		3,512			214		—			3,726
Depreciation, depletion and amortization		63,831			6,064		—			69,895
Asset retirement obligation accretion		6,031			96		—			6,127
General and administrative expenses		13,102			1,273		—			14,375
Derivative (gain)		(7,374	)		—		—			(7,374	)

Total costs and expenses		125,931			13,558		—			139,489

Operating income		34,580			5,598		—			40,178
Earnings of affiliates		3,639			—		(3,639	)		—
Interest expense:
Incurred		10,914			—		—			10,914
Capitalized		(1,329	)		—		—			(1,329	)
Interest income		354			—		—			354

Income before income tax expense		28,988			5,598		(3,639	)		30,947
Income tax expense		1,118			1,959		—			3,077

Net income	$	27,870		$	3,639	$	(3,639	)	$	27,870

(1)	Began operations on May 1, 2010. Includes only May and June of 2010.

Condensed Consolidating Statement of Income for the Six Months Ended June 30, 2010


	Parent Company			Guarantor Subsidiaries (1)		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Revenues	$	330,096		$	19,156	$	—		$	349,252

Operating costs and expenses:
Lease operating expenses		81,912			5,911		—			87,823
Production taxes		512			—		—			512
Gathering and transportation		8,099			214		—			8,313
Depreciation, depletion and amortization		126,755			6,064		—			132,819
Asset retirement obligation accretion		12,316			96		—			12,412
General and administrative expenses		23,481			1,273		—			24,754
Derivative (gain)		(13,270	)		—		—			(13,270	)

Total costs and expenses		239,805			13,558		—			253,363

Operating income		90,291			5,598		—			95,889
Earnings of affiliates		3,639			—		(3,639	)		—
Interest expense:
Incurred		21,834			—		—			21,834
Capitalized		(2,745	)		—		—			(2,745	)
Interest income		482			—		—			482

Income before income tax expense		75,323			5,598		(3,639	)		77,282
Income tax expense		5,138			1,959		—			7,097

Net income	$	70,185		$	3,639	$	(3,639	)	$	70,185

(1)	Began operations on May 1, 2010. Includes only May and June of 2010.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Condensed Consolidating Statement of Cash Flows for the Six Months Ended June 30, 2011


	Parent Company			Guarantor Subsidiaries			Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Operating activities:
Net income	$	73,824		$	40,770		$	(40,770	)	$	73,824
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		114,627			42,835			—			157,462
Amortization of debt issuance costs and discount on indebtedness		815			—			—			815
Loss on extinguishment of debt		20,663			—			—			20,663
Share-based compensation		3,662			—			—			3,662
Derivative loss		6,508			—			—			6,508
Cash payments on derivative settlements		(8,322	)		—			—			(8,322	)
Deferred income taxes		42,154			(6,428	)		—			35,726
Earnings of affiliates		(40,770	)		—			40,770			—
Changes in operating assets and liabilities:
Oil and natural gas receivables		(18,779	)		7,173			—			(11,606	)
Joint interest and other receivables		14,107			—			—			14,107
Insurance receivables		12,583			—			—			12,583
Income taxes		(43,339	)		28,382			—			(14,957	)
Prepaid expenses and other assets		(24,650	)		(108,643	)		108,643			(24,650	)
Asset retirement obligations		(29,703	)		—			—			(29,703	)
Accounts payable and accrued liabilities		(4,665	)		(1,717	)		—			(6,382	)
Other liabilities		108,758			—			(108,643	)		115

Net cash provided by operating activities		227,473			2,372			—			229,845

Investing activities:
Acquisition of significant property interest in oil and natural gas properties		(396,976	)		—			—			(396,976	)
Investment in oil and natural gas properties and equipment		(83,429	)		(2,372	)		—			(85,801	)
Purchases of furniture, fixtures and other		(178	)		—			—			(178	)

Net cash used in investing activities		(480,583	)		(2,372	)		—			(482,955	)

Financing activities:
Issuance of 8.5% Senior Notes		600,000			—			—			600,000
Repurchase of 8.25% Senior Notes		(406,150	)		—			—			(406,150	)
Borrowings of long-term debt – revolving bank credit facility		310,000			—			—			310,000
Repayments of long-term debt – revolving bank credit facility		(235,000	)		—			—			(235,000	)
Repurchase premium and debt issuance costs		(29,728	)		—			—			(29,728	)
Dividends to shareholders		(5,957	)		—			—			(5,957	)

Net cash provided by (used in) financing activities		233,165			—			—			233,165

Increase in cash and cash equivalents		(19,945	)		—			—			(19,945	)
Cash and cash equivalents, beginning of period		28,655			—			—			28,655

Cash and cash equivalents, end of period	$	8,710		$	—		$	—		$	8,710

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Condensed Consolidating Statement of Cash Flows for the Six Months Ended June 30, 2010


	Parent Company			Guarantor Subsidiaries (1)			Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Operating activities:
Net income	$	70,185		$	3,639		$	(3,639	)	$	70,185
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		139,071			6,160			—			145,231
Amortization of debt issuance costs and discount on indebtedness		669			—			—			669
Share-based compensation		1,943			—			—			1,943
Derivative gain		(13,270	)		—			—			(13,270	)
Cash payments on derivative settlements		(442	)		—			—			(442	)
Deferred income taxes		144			2,801			—			2,945
Earnings of affiliates		(3,639	)		—			3,639			—
Changes in operating assets and liabilities:
Oil and natural gas receivables		(2,140	)		(9,599	)		—			(11,739	)
Joint interest and other receivables		21,931			—			—			21,931
Insurance receivables		29,879			—			—			29,879
Income taxes		92,355			(842	)		—			91,513
Prepaid expenses and other assets		(9,129	)		(5,154	)		5,154			(9,129	)
Asset retirement obligations		(35,210	)		—			—			(35,210	)
Accounts payable and accrued liabilities		(65,537	)		2,995			—			(62,542	)
Other liabilities		17,508			—			(5,154	)		12,354

Net cash provided by operating activities		244,318			—			—			244,318

Investing activities:
Acquisition of significant property interests in oil and natural gas properties		—			(116,589	)		—			(116,589	)
Investment in oil and natural gas properties and equipment		(89,705	)		—			—			(89,705	)
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		(167	)		—			—			(167	)

Net cash used in investing activities		(205,126	)		(116,589	)		116,589			(205,126	)

Financing activities:
Borrowings of long-term debt – revolving bank credit facility		285,000			—			—			285,000
Repayments of long-term debt – revolving bank credit facility		(285,000	)		—			—			(285,000	)
Dividends to shareholders		(4,481	)		—			—			(4,481	)
Investment from parent		—			116,589			(116,589	)		—

Net cash provided by (used in) financing activities		(4,481	)		116,589			(116,589	)		(4,481	)

Increase in cash and cash equivalents		34,711			—			—			34,711
Cash and cash equivalents, beginning of period		38,187			—			—			38,187

Cash and cash equivalents, end of period	$	72,898		$	—		$	—		$	72,898

(1)	Began operations on May 1, 2010. Includes only May and June of 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, 2010 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 67 producing or capable of producing fields in federal and state waters. The majority of our daily production was derived from offshore wells we operate. In May 2011, we closed on the acquisition of the Permian Basin Properties as described below. After completing this acquisition, we now hold working interests in over 30,000 net acres onshore primarily in the West Texas Permian Basin. Acquiring these onshore properties has diversified our business by having both significant offshore and onshore operations.

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 volumes for the first six months of 2011 was comprised of approximately 47% oil, condensate and natural gas liquids and 53% 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. The conversion ratio does not assume price equivalency, and the price per one thousand cubic feet equivalent (“Mcfe”) for oil and natural gas liquids may differ significantly from the price per Mcf for natural gas. For example, for the first six months of 2011, our average realized price for oil and NGLs on a Mcfe basis was $15.72 compared to $4.37 per Mcf for natural gas. For the first six months of 2011, our combined total production of oil, condensate, natural gas liquids and natural gas was approximately 11.0% higher on a Mcfe basis than during the same period in 2010.

During May 2011, we completed the acquisition of approximately 21,900 gross acres (21,500 net acres) of oil and gas leasehold interests in the Permian Basin Properties from Opal. The stated purchase price was $366.3 million, subject to certain adjustments, including adjustments from an effective date of January 1, 2011. Taking into account adjustments through June 30, 2011, the purchase price was $399.5 million. The increase of $33.2 million primarily reflects drilling costs in excess of cash flow from the effective date of January 1, 2011 to the closing date of May 11, 2011. The purchase price is subject to further adjustments and we expect final settlement could occur as early as the third quarter of 2011. We acquired estimated proved reserves of approximately 30 million barrels of oil equivalent (182 Bcfe) (using a 6 to 1 Mcf to barrel equivalency) as of December 31, 2010, comprised of approximately 91% oil and natural gas liquids and which are approximately 78% proved undeveloped. The properties include interests in producing wells, which produced approximately 2,534 net barrels of oil equivalents per day for the month of June 2011. Capital expenditures associated with planned development activities for these properties from the closing date of May 11, 2011 to December 31, 2011 are currently estimated to be between $40 million and $50 million. The acquisition was funded from cash on hand and borrowings under our revolving bank credit facility.

During 2010, we closed on two major acquisitions. In April 2010, we acquired property interests from Total and in November 2010, we acquired property interests from Shell. These transactions are described in Financial Statements - Note 2 – Acquisitions under Part I, Item 1 of this Form 10-Q.

On March 31, 2011, the third-party pipeline used by our Main Pass 108, 98 and 180 fields, which had been offline since June 2010, became operational. In the second quarter of 2011, we gradually increased production in this area and in June 2011, it produced approximately 41 MMcfe per day, made up of 29,700 Mcf of natural gas and 1,937 barrels of oil/NGLs per day. Production in the second quarter of 2011 was impacted due to a shut down of our Matterhorn field for approximately one month for repairs, which had an average production of approximately 3,900 Boe per day in the month prior to the shutdown.

Prices for oil have continued to be volatile in 2011. The West Texas Intermediate posted spot price for oil was $98.08 per barrel for the first six months of 2011, representing an increase of 25.3% from $78.30 for the first six months of 2010. The price for oil during the first six months of 2011 ranged from a low of $83.13 per barrel to a high of $113.39 per barrel and during the first six months of 2010 prices ranged from $64.78 to $86.54 per barrel. For the first six months of 2011, our average realized sales price for oil and NGLs increased by 33.8% over the comparable period in 2010. Oil prices continue to be impacted by market fundamentals such as supply and demand and also by political events and disruptions throughout the world such as events in Japan, Africa and the Middle East. Long-term forecasts for oil demand, and therefore global oil prices, continue to be favorable in several key growing markets, specifically China and India.

The wide spreads between West Texas Intermediate crude and other crudes have continued since the early part of 2011. A significant majority of our oil production, which is located in south Louisiana, has received price premiums between $7.00 and $15.00 per barrel in the first six months of 2011. In comparison, the average premium spread between Light Louisiana Sweet crude and West Texas Intermediate crude was approximately $3.00 per barrel during 2010. We may continue to experience higher premiums to West Texas Intermediate crude in our future sales of crude oil until such time as the causative factors are resolved. We cannot predict with any certainty how long such pricing conditions will last.

Natural gas prices are much more affected by domestic issues, such as supply, local demand issues and domestic economic conditions. The Henry Hub posted spot price for natural gas was $4.27 per MMBtu for the first six months of 2011, representing a decrease of 9.3% from $4.71 per MMBtu for the first six months of 2010. The price for natural gas in the first six months of 2011 ranged from a low of $3.70 per MMBtu to a high of $4.92 per MMBtu and the range in the first six months of 2010 was from $3.72 to $7.51 per MMBtu. During the first six months of 2011, the average realized sales price of our natural gas decreased 10.5% from the comparable period of 2010. 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 such as Louisiana, Arkansas, Texas, North Dakota and Pennsylvania, 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. Seasonal weather conditions also impact the demand for and price of natural gas.

Should prices decline for oil and natural gas in the future, it 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, create issues with financial ratio compliance, and result in a reduction of the borrowing base associated with our credit agreement, depending on the severity of such declines. If those were to occur and were significant, it may limit the willingness of financial institutions and investors to provide 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 and ensuing fire, the rig sank, causing loss of life, and created a major oil spill that produced economic, environmental and natural resource damage in the Gulf Coast region. In response to the explosion and spill, the Bureau of Ocean Energy Management, Regulation and Enforcement (the “BOEMRE”) issued a series of “Notices to Lessees” (“NTLs”), and other significant changes in regulations. In addition, the BOEMRE implemented a six-month moratorium on drilling activities which began in May 2010. There also continue to be many proposed changes in laws, regulations, guidance and policy in response to the Deepwater Horizon explosion and spill. After the moratorium ended in 2010, it was not until March 2011 that deep water drilling permits began to be issued, and even then only sporadically, to continue drilling activities that had commenced prior to the Deepwater Horizon incident. Since March 2011, a small number of deepwater drilling permits have been issued, but at a much lower rate than prior to the Deepwater Horizon event. The most significant regulation changes since the Deepwater Horizon event are regulations related to assessing the potential environmental impact of future spills using worse case discharge scenarios, spill response documentation, compliance reviews, operator practices related to safety and implementing a safety and environmental

management system. The new regulations and increased review process increases the time it takes to obtain drilling permits and increases the cost of operations. As these new regulations and guidance continue to evolve, we cannot estimate the cost and impact to our business at this time. The permitting process is also slow and inconsistent for shallow water work as well. We have not experienced delays in obtaining permits related to our onshore operations.

Results of Operations

The following table sets forth selected financial data for the periods indicated (all values are net to our interest unless indicated otherwise):


	Three Months Ended												Six Months Ended
	June 30, ⁽¹⁾												June 30, ⁽¹⁾
	2011			2010			Change			%			2011		2010			Change			%
	(In thousands, except percentages and per share data)
Financial:
Revenues:
Oil and NGLs	$	193,944		$	124,762		$	69,182			55.5	%	$	353,431	$	240,242		$	113,189			47.1	%
Natural gas		58,661			54,719			3,942			7.2	%		109,579		108,789			790			0.7	%
Other		317			186			131			70.4	%		767		221			546			247.1	%

Total revenues		252,922			179,667			73,255			40.8	%		463,777		349,252			114,525			32.8	%
Operating costs and expenses:
Lease operating expenses (2)		48,597			52,457			(3,860	)		(7.4	%)		101,002		87,823			13,179			15.0	%
Production taxes		845			283			562			198.6	%		1,133		512			621			121.3	%
Gathering and transportation		3,797			3,726			71			1.9	%		8,350		8,313			37			0.4	%
Depreciation, depletion, amortization and accretion		83,370			76,022			7,348			9.7	%		157,462		145,231			12,231			8.4	%
General and administrative expenses		18,002			14,375			3,627			25.2	%		36,131		24,754			11,377			46.0	%
Derivative (gain) loss		(17,332	)		(7,374	)		(9,958	)		135.0	%		6,508		(13,270	)		19,778			NM

Total costs and expenses		137,279			139,489			(2,210	)		(1.6	%)		310,586		253,363			57,223			22.6	%

Operating income		115,643			40,178			75,465			187.8	%		153,191		95,889			57,302			59.8	%
Interest expense, net of amounts capitalized		9,977			9,585			392			4.1	%		18,701		19,089			(388	)		(2.0	%)
Loss on extinguishment of debt (3)		20,663			—			20,663			NM			20,663		—			20,663			NM
Other income		9			354			(345	)		(97.5	%)		16		482			(466	)		(96.7	%)

Income before income tax expense		85,012			30,947			54,065			174.7	%		113,843		77,282			36,561			47.3	%
Income tax expense		29,837			3,077			26,760			NM			40,019		7,097			32,922			463.9	%

Net income	$	55,175		$	27,870		$	27,305			98.0	%	$	73,824	$	70,185		$	3,639			5.2	%

Basic and diluted earnings per common share	$	0.73		$	0.37		$	0.36			97.3	%	$	0.98	$	0.94		$	0.04			4.3	%

(1)	During the second quarter of 2011, we acquired the Permian Basin Properties. During 2010, we acquired property interests from Total in the second quarter and property interests from Shell in the fourth quarter. These acquisitions affect the comparability of results between time periods.

(2)

Included in lease operating expenses are repair expenses, insurance reimbursements and other items related to hurricane damage. For additional details about our hurricane related items, refer to Financial Statements – Note 3 – Hurricane Remediation and Insurance Claims under Part I, Item 1 of this Form 10-Q.

(3)

In May 2011, we entered into the Fourth Amended and Restated Credit Agreement, which replaced the Prior Credit Agreement. Unamortized debt issuance costs of $0.7 million related to the Prior Credit Agreement were expensed. In June 2011, we conducted a tender offer for our 8.25% Senior Notes, pursuant to which $406.2 million of the $450 million were tendered and repurchased, which resulted in loss on extinguishment of debt of $20.0 million.

NM = percentage change not meaningful

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


	Three Months Ended										Six Months Ended
	June 30, ⁽¹⁾										June 30, ⁽¹⁾
	2011		2010		Change			%			2011		2010		Change			%
Operating:
Net sales:
Natural gas (Bcf)		13.2		12.3		0.9			7.3	%		25.1		22.3		2.8			12.6	%
Oil and NGLs (MMBbls)		1.9		1.7		0.2			11.8	%		3.7		3.4		0.3			8.8	%
Total natural gas and oil (Bcfe) (2)		24.8		22.8		2.0			8.8	%		47.5		42.8		4.7			11.0	%
Total natural gas and oil (MMBoe) (2)		4.1		3.8		0.3			7.9	%		7.9		7.1		0.8			11.3	%

Average daily equivalent sales (MMcfe/d)		273.0		250.5		22.5			9.0	%		262.7		236.2		26.5			11.2	%

Average realized sales prices (Unhedged):
Natural gas ($/Mcf)	$	4.45	$	4.47	$	(0.02	)		(0.4	%)	$	4.37	$	4.88	$	(0.51	)		(10.5	%)
Oil and NGLs($/Bbl)		99.72		70.97		28.75			40.5	%		94.29		70.48		23.81			33.8	%
Natural gas equivalent ($/Mcfe)		10.17		7.87		2.30			29.2	%		9.74		8.16		1.58			19.4	%
Average realized sales prices (Hedged):
Natural gas ($/Mcf)	$	4.45	$	4.65	$	(0.20	)		(4.3	%)	$	4.37	$	5.06	$	(0.69	)		(13.6	%)
Oil and NGLs ($/Bbl)		96.59		70.90		25.69			36.2	%		92.07		70.21		21.86			31.1	%
Natural gas equivalent ($/Mcfe)		9.92		7.97		1.95			24.5	%		9.56		8.24		1.32			16.0	%
Average per Mcfe ($/Mcfe):
Lease operating expenses	$	1.96	$	2.30	$	(0.34	)		(14.8	%)	$	2.13	$	2.05	$	0.08			3.9	%
Gathering and transportation		0.15		0.16		(0.01	)		(6.3	%)		0.18		0.19		(0.01	)		(5.3	%)

Production costs		2.11		2.46		(0.35	)		(14.2	%)		2.31		2.24		0.07			3.1	%
Production taxes		0.03		0.01		0.02			200.0	%		0.02		0.01		0.01			100.0	%
Depreciation, depletion, amortization and accretion		3.36		3.33		0.03			0.9	%		3.31		3.40		(0.09	)		(2.6	%)
General and administrative expenses		0.73		0.63		0.10			15.9	%		0.76		0.58		0.18			31.0	%

	$	6.23	$	6.43	$	(0.20	)		(3.1	%)	$	6.40	$	6.23	$	0.17			2.7	%


Total number of offshore wells drilled (gross)		2		2		—			—			3		5		(2	)		(40.0	%)
Total number of onshore wells drilled (gross)		9		—		9			NM			10		—		10			NM
Total number of offshore productive wells drilled (gross)		2		2		—			—			3		4		(1	)		(25.0	%)
Total number of onshore productive wells drilled (gross)		9		—		9			NM			10		—		10			NM

(1)	During the second quarter of 2011, we acquired the Permian Basin Properties. During 2010, we acquired property interests from Total in the second quarter and property interests from Shell in the fourth quarter. These acquisitions affect the comparability of results between time periods.

(2)

The conversion to cubic feet equivalent and barrels of equivalent measures determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids (totals may not compute due to rounding). The conversion ratio does not assume price equivalency, and the price per Mcfe for oil and natural gas liquids may differ significantly from the price per Mcf for natural gas.

NM = percentage change not meaningful

Three Months Ended June 30, 2011 Compared to the Three Months Ended June 30, 2010

Revenues. Total revenues increased $73.3 million, or 40.8%, to $252.9 million for the second quarter of 2011 as compared to the same period in 2010. Oil and NGL revenues increased $69.2 million, natural gas revenues increased $3.9 million and other revenues increased $0.2 million. The oil and NGL revenue increase was attributable to a 40.5% increase in the average realized sales price to $99.72 per barrel for the three months ended June 30, 2011 from $70.97 per barrel for the same period in 2010, combined with an increase of 11.8% in sales volumes. The sales volume increase for oil and NGL is primarily attributable to increases associated with the properties purchased from Shell in November of 2010. The increase in natural gas revenue resulted from a 7.3% increase in sales volumes, partially offset by a 0.4% decrease in the average realized natural gas sales price. For the three months ended June 30, 2011, the natural gas average realized sales price was $4.45 per Mcf compared to $4.47 per Mcf for the same period in 2010. The sales volume increase for natural gas is primarily attributable to increases associated with the properties acquired from Shell in 2010.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, insurance, workovers, maintenance on our facilities, and hurricane remediation costs net of insurance claims, decreased $3.9 million to $48.6 million in the second quarter of 2011 compared to the second quarter of 2010. On a per Mcfe basis, lease operating expenses decreased to $1.96 per Mcfe during the second quarter of 2011 compared to $2.30 per Mcfe during the second quarter of 2010. On a component basis, hurricane remediation costs net of insurance claims, base lease operating expenses, insurance premiums and workover costs decreased $2.6 million, $2.0 million, $1.8 million and $1.5 million, respectively, while facility expenses increased $4.1 million. Hurricane remediation costs net of insurance claims decreased due to lower repair expenses and higher claims submitted for reimbursement. The decrease in base lease operating expenses is primarily attributable to lower base operating expenses at the properties purchased from Total in 2010. The decrease in insurance resulted primarily from lower premiums on our insurance policies covering well control and hurricane damage. Workover costs decreased due to numerous projects undertaken in 2010 that did not reoccur in 2011. The increase in facility expenses is primarily attributable to work performed on the tendon tension monitoring system and mechanical repairs at our Matterhorn platform.

Production taxes. Production taxes increased to $0.8 million for the quarter compared to $0.3 million in the prior year due to the acquisition of the Permian Basin Properties and are currently not a large component of our operating costs. Most of our production is from federal waters where there are no production taxes while onshore operations are subject to production taxes.

Gathering and transportation costs. Gathering and transportation costs were basically flat for the quarter compared to the prior year.

Depreciation, depletion, amortization and accretion (“DD&A”). DD&A, including accretion for ARO, increased slightly to $3.36 per Mcfe for the second quarter of 2011 from $3.33 per Mcfe in the second quarter of 2010. On a nominal basis, DD&A increased to $83.4 million for the second quarter of 2011 from $76.0 million in the second quarter of 2010. The slight increase to DD&A on a per Mcfe basis was due to the acquisition of the Permian Basin Properties while DD&A on a nominal basis increased due to higher production volumes.

General and administrative expenses (“G&A”). G&A expenses increased to $18.0 million for the second quarter of 2011 from $14.4 million for the same period in 2010, primarily due to higher incentive compensation as a result of improved financial and operational performance, reduced overhead charges billed to joint interest operators and slightly higher salaries. On a per Mcfe basis, G&A was $0.73 per Mcfe for the second quarter of 2011, compared to $0.63 per Mcfe for the same period in 2010.

Derivative (gain)/loss. For the second quarter of 2011, our derivative gain of $17.3 million related entirely to a change in the fair value of our commodity derivatives as a result of changes in crude oil prices. For the second quarter of 2010, our derivative gain of $7.4 million related primarily to a gain from our commodity derivatives as a result of changes in crude oil and natural gas prices. For additional details about our derivatives, refer to Financial Statements – Note 5 – Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q.

Interest expense. Interest expense incurred increased to $12.1 million for the second quarter of 2011 from $10.9 million for the same period in 2010 primarily as a result of increased borrowings related to the funding of the acquisition of the Permian Basin Properties. Combined with cash on hand, funding was obtained initially through borrowings on the revolving bank credit facility. The borrowings on the revolving bank credit facility were subsequently reduced through the proceeds received from the issuance of our 8.5% Senior Notes. Additionally, the effective interest rate and outstanding principal of our long-term debt increased after consummation of the 8.5% Senior Notes issuance and the tender offer for the 8.25% Senior Notes (see Liquidity and Capital Resources below). During the second quarter of 2011 and 2010, $2.1 million and $1.3 million, respectively, of interest was capitalized to unevaluated oil and natural gas properties with the increase attributable to the acquisition of the Permian Basin Properties.

Loss on extinguishment of debt. The loss on extinguishment of debt of $20.7 million was attributable primarily to the repurchase premium related to the tender offer for the 8.25% Senior Notes. This offer was made concurrently with, and was funded using a portion of the proceeds from, the issuance of the 8.5% Senior Notes. The consent payment, unamortized debt issuance costs and other related expenses totaled $20.0 million. In addition, the previous revolving bank credit facility was replaced resulting in the write off of unamortized debt issuance costs of $0.7 million. For additional information about our long-term debt and revolving bank credit facility, refer to Financial Statements – Note 6 – Long-Term Debt under Part I, Item 1 of this Form 10-Q.

Income tax expense. Income tax expense increased to $29.8 million for the second quarter of 2011 compared to $3.1 million for the same period of 2010. Our effective tax rate for the second quarter of 2011 was 35.1%, which approximates the statutory rate. Our effective tax rate for the second quarter of 2010 was approximately 9.9% and primarily reflects a reduction in our valuation allowance that was recorded in prior years.

Six Months Ended June 30, 2011 Compared to the Six Months Ended June 30, 2010

Revenues. Total revenues increased $114.5 million, or 32.8%, to $463.8 million for the first six months of 2011 as compared to the same period in 2010. Oil and NGL revenues increased $113.2 million, natural gas revenues increased $0.8 million and other revenues increased $0.5 million. The oil and NGL revenue increase was attributable to a 33.8% increase in the average realized sales price to $94.29 per barrel for the six months ended June 30, 2011 from $70.48 per barrel for the same period in 2010, combined with an increase of 8.8% in sales volumes. The sales volume increase for oil and NGL is primarily attributable to increases associated with the properties purchased from Shell in November 2010 and Total in April of 2010. The increase in natural gas revenue resulted from a 12.6% increase in sales volumes, partially offset by a 10.5% decrease in the average realized natural gas sales price to $4.37 per Mcf for the six months ended June 30, 2011 from $4.88 per Mcf for the same period in 2010. The sales volume increase for natural gas is primarily attributable to increases associated with the properties purchased from Total and Shell in 2010.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, insurance, workovers, maintenance on our facilities, and hurricane remediation costs net of insurance claims, increased $13.2 million to $101.0 million in the first six months of 2011 compared to the first six months of 2010. On a per Mcfe basis, lease operating expenses increased to $2.13 per Mcfe during the first six months of 2011 compared to $2.05 per Mcfe during the first six months of 2010. On a component basis, facility expenses, base lease operating expenses, and hurricane remediation costs net of insurance claims, increased $9.6 million, $5.3 million and $5.0 million, respectively, while insurance premiums and workover costs decreased $4.6 million and $2.1 million, respectively. The increase in facility expenses is primarily attributable to work performed on the tendon tension monitoring system and mechanical repairs at our Matterhorn platform, the pipeline repairs at our Ship Shoal 300 field to remove paraffin and other work on newly acquired deepwater properties. The increase in base lease operating expenses is primarily attributable to the properties purchased from Shell in 2010, the acquisition of the Permian Basin Properties in 2011 and the final settlement adjustments related to properties sold in 2009 that served to reduce expenses in 2010. Hurricane remediation costs net of insurance claims increased due to the return of insurance reimbursements previously received by us related to prepayments based on preliminary estimates, reversal of previously recorded hurricane remediation accruals in the first quarter of 2010, and reductions in claims submitted for reimbursement. The decrease in insurance resulted primarily from lower premiums on our insurance policies covering well control and hurricane damage. Workover costs decreased due to numerous projects undertaken in 2010 that did not reoccur in 2011.

Production taxes. Production taxes increased to $1.1 million for the first six months of 2011 compared to $0.5 million in the prior year due to the acquisition of the Permian Basin Properties and are currently not a large component of our operating costs. Most of our production is from federal waters where there are no production taxes while onshore operations are subject to production taxes.

Gathering and transportation costs. Gathering and transportation costs were basically flat for the first six months compared to the prior year.

Depreciation, depletion, amortization and accretion. DD&A, including accretion for ARO, decreased to $3.31 per Mcfe for the first six months of 2011 from $3.40 per Mcfe in the first six months of 2010. On a nominal basis, DD&A increased to $157.5 million for the first six months of 2011 from $145.2 million in the first six months of 2010. DD&A on a per Mcfe basis decreased due to an increase in proved reserves while DD&A on a nominal basis increased due to higher production volumes.

General and administrative expenses. General and administrative expenses increased to $36.1 million for the first six months of 2011 from $24.8 million for the same period in 2010, primarily due to higher incentive compensation as a result of improved financial and operational performance, higher salaries, surety premiums, fees paid to Shell for administrative services attributable to the properties purchased from Shell, reduced overhead charges billed to joint interest operators and service fee income received in 2010 attributable to a property divestiture. On a per Mcfe basis, G&A was $0.76 per Mcfe for the first six months of 2011, compared to $0.58 per Mcfe for the same period in 2010.

Derivative (gain)/loss. For the first six months of 2011, our derivative loss of $6.5 million related entirely to a change in the fair value of our commodity derivatives as a result of the changes in crude oil prices. For the first six months of 2010, our derivative gain of $13.3 million related to a gain from our commodity derivatives of $13.6 million and a loss of $0.3 million related to our interest rate swap. For additional details about our derivatives, refer to Item 1 Financial Statements – Note 5 – Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q.

Interest expense. Interest expense incurred increased to $22.2 million for the first six months of 2011 from $21.8 million for the same period in 2010 primarily as a result of increased borrowings related to the funding of the acquisition of the Permian Basin Properties. During the first six months of 2011 and 2010, $3.5 million and $2.7 million, respectively, of interest was capitalized to unevaluated oil and natural gas properties with the increase attributable to the acquisition of the Permian Basin Properties.

Loss on extinguishment of debt. The loss on extinguishment of debt of $20.7 million was attributable primarily due to the repurchase premium related to the tender offer for the 8.25% Senior Notes. This offer was made concurrently with, and funded with a portion of the proceeds from, the issuance of the 8.5% Senior Notes. The consent payment, unamortized debt issuance costs and other related expenses totaled $20.0 million. In addition, the previous revolving bank credit facility was replaced resulting in the write off of unamortized debt issuance costs of $0.7 million. For additional information about our long-term debt and revolving bank credit facility, refer to Financial Statements – Note 6 – Long-Term Debt under Part I, Item 1 of this Form 10-Q.

Income tax expense. Income tax expense increased to $40.0 million for the first six months of 2011 compared to $7.1 million for the same period of 2010. Our effective tax rate for the first six months of 2011 was 35.2%, which approximates the statutory rate. Our effective tax rate for the first six months of 2010 was approximately 9.2% and primarily reflects a reduction in our valuation allowance that was recorded in prior years.

Liquidity and Capital Resources

Our primary liquidity needs are to fund capital expenditures and strategic property acquisitions to allow us to replace our oil and natural gas reserves, repay outstanding borrowings and make related interest payments. 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 first six months of 2011 was $229.8 million, compared to $244.3 million for the first six months of 2010. The decrease is primarily due to income tax payments in 2011 of $19.1 million compared to tax refunds of $99.8 million received in the 2010 period. Otherwise cash flow provided by operating activities is higher due to a significant improvement in operations attributable to higher prices and higher production. Our combined average realized sales price was 19.4% higher than the comparable 2010 period and our combined total production of oil, NGLs and natural gas during the first six months of 2011 was approximately 11.0% higher than the comparable 2010 period.

Net cash used in investing activities totaled $483.0 million and $205.1 million during the first six months of 2011 and 2010, respectively, which primarily represents our investments in oil and natural gas properties. Major acquisitions consisted of the cash portion of the Permian Basin Properties purchased in 2011 ($397.0 million) and the offshore properties purchased from Total in 2010 ($116.6 million). In addition, investments in other oil and natural gas properties and equipment were $85.8 million in the first six months of 2011 compared to $89.7 million in the first six months of 2010. There were no proceeds from sales of assets in the first six months of 2011 and proceeds from asset sales were $1.3 million for the first six months of 2010.

Net cash provided by financing activities was $233.2 million during the first six months of 2011. Funds were provided through net borrowings on the revolving bank credit facility of $75 million and issuance of $600 million of 8.5% Senior Notes; partially offset by the purchase of $406.2 million of the 8.25% Senior Notes, repurchase premium and debt issuance costs of $29.7 million and the payment of dividends of $6.0 million. See Financial Statements – Note 6 – Long-Term Debt under Part I, Item 1 of this Form 10-Q for additional information on the Senior Notes transactions. Net cash used in financing activities during the first six months of 2010 was $4.5 million which reflects dividend payments during the period.

At June 30, 2011, we had a cash balance of $8.7 million and $412.0 million of undrawn capacity available under the new revolving bank credit facility.

Credit agreement and long-term debt. At June 30, 2011, there were $75 million borrowings outstanding under our revolving bank credit facility compared to zero at December 31, 2010. At June 30, there was $600 million of our 8.5% Senior Notes outstanding and $43.9 million of our 8.25% Senior Notes outstanding and at December 31, 2011 there was $450 million outstanding of our 8.25% Senior Notes. We believe that cash provided by operations, borrowings available under our revolving bank credit facility and other external sources of liquidity should be sufficient to fund our ongoing cash requirements.

On May 5, 2011, we entered into the Credit Agreement which provides a revolving bank credit facility with an initial borrowing base of $525 million collateralized by our oil and natural gas properties. The Credit Agreement terminates on May 5, 2015 and replaces the Prior Credit Agreement, which would have expired July 23, 2012. Fees and transactions costs related to the Credit agreement were approximately $5.6 million. The terms of the Credit Agreement are substantially similar to the terms of the Prior Credit Agreement. Availability under the Credit Agreement is subject to a semi-annual borrowing base determination set at the discretion of our lenders. The amount of the borrowing base is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria. Any determination by our lenders to change our borrowing base will result in a similar change in the availability under our revolving bank credit facility. As of June 30, 2011, our borrowing base was $487.5 million as the borrowing base was reduced due to the issuance of the 8.5% Senior Notes. The borrowing base will be increased by $50 million if we close on the acquisition of certain properties owned by Shell by September 2, 2011.

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 June 30, 2011. During the first six months of 2011, borrowings outstanding on the revolving bank credit facility increased to $300 million to fund the acquisition of the Permian Basin Properties, which also included funding from cash on hand. These borrowings were subsequently reduced to $75 million as of June 30, 2011, by utilizing cash from operations and funds received from the senior note transactions described below. Letters of credit outstanding as of June 30, 2011 were $0.5 million.

On June 10, 2011, we issued $600 million of 8.5% Senior Notes and used a portion of the net proceeds to repurchase $406.2 million of the 8.25% Senior Notes. The net cash provided by these Senior Notes transactions as of June 30, 2011, which includes initial purchaser fees, consent payments and other transactions costs, was $169.7 million. These transactions extended the maturity date of our long-term debt and we used the remaining net proceeds to pay down outstanding borrowings under the revolving bank credit facility. The 8.5% Senior Notes mature on June 15, 2019. Interest is payable semi-annually in arrears on June 15 and December 15 of each year beginning on December 15, 2011. On July 18, 2011, we purchased the remaining $43.9 million of the 8.25% Senior Notes for $45.7 million, representing a redemption premium of 4.125% pursuant to the terms of the 8.25% Senior Notes.

For additional information about our credit agreement and long-term debt, refer to Financial Statements – Note 6 – Long-Term Debt under Part I, Item 1 of this Form 10-Q.

Derivatives. 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 bank credit facility. As of June 30, 2011, our derivative instruments outstanding consisted of commodity option contracts relating to approximately 0.6 MMBbls and 1.1 MMBbls of our anticipated oil production for the balance of 2011 and the full year of 2012, respectively. For additional details about our derivatives, refer to Item 1 Financial Statements – Note 5– Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q.

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. 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 policies in effect on the occurrence dates of Hurricanes Ike and Gustav had a retention requirement of $10 million per occurrence. In 2008, we satisfied our $10 million retention requirement for Hurricane Ike in connection with two platforms that were toppled and were deemed total losses. The damage we incurred as a result of Hurricane Gustav was below our retention amount.

In the first six months of 2011 and the year 2010, we received cash of $11.9 million and $65.5 million, respectively, from our insurance carrier related to Hurricane Ike claims. We have recorded $6.9 million of insurance receivables as of June 30, 2011 for claims that have been submitted and approved for payment. As of June 30, 2011, we have recorded in ARO an estimate of $65.5 million for additional costs to be incurred related to Hurricane Ike and we estimate that this work will be completed by the end of 2012. We expect to receive reimbursement for a portion of these costs from our insurance carrier once the costs are incurred, claims are processed and payments are approved, but cannot estimate the amount of reimbursement to be received at this time. Should necessary expenditures exceed our insurance coverage for damages incurred as a result of Hurricane Ike, or claims are denied by our insurance carrier for other reasons, we expect that our available cash on hand, cash flow from operations and the availability under our revolving bank credit facility will be sufficient to meet these future cash needs.

For a discussion of our hurricane remediation costs related to lease operating expenses incurred during the first six months of 2011 and 2010, refer to Financial Statements – Note 3 – Hurricane Remediation and Insurance Claims under Part I, Item 1 of this Form 10-Q. Lease operating expenses will be offset in future periods to the extent that these costs incurred are approved for payment under our insurance policies.

We currently carry three layers of insurance coverage for our operating activities in the Gulf of Mexico. The current policy limits for well control and hurricane damage (defined as named windstorm in our policies) are up to $100 million and $120 million, respectively, and the policies are effective until June 1, 2012. We carry an additional $100 million of well control coverage effective until June 1, 2012 on certain wells at our Mahogany, Matterhorn, Virgo, Tahoe and SE Tahoe fields. A retention amount of $5 million for well control events and $37.5 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 96% of our present value of estimated future net revenues discounted at 10% (“PV-10”) at December 31, 2010 are covered under our 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.

Our general and excess liability policy provides for $250 million of liability coverage for bodily injury and property damage, including liability claims resulting from seepage, pollution or contamination. With respect to the Oil Spill Financial Responsibility (“OSFR”) requirement under the Oil Pollution Act (the “OPA”), we are required to evidence $150 million of financial responsibility to the BOEMRE. We qualify to self-insure for $35 million of this amount and the remaining $115 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.

These policies summarized above have annual terms that expire in May and June of 2012. The premiums for the above policies were $30 million compared to $22 million for the policies that expired in May and June of 2011. Although we have not been informed otherwise, in the future, 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, acquisition opportunities, and the results of our exploration and development activities. The following table presents our capital expenditures for acquisitions, exploration, development and other leasehold costs:


	Six Months Ended June 30,
	2011		2010
	(in thousands)
Acquisition of Opal properties (Permian Basin)	$	396,976	$	—
Acquisition of Total properties		—		116,589
Exploration (1)		20,891		48,563
Development (1)		52,229		25,790
Seismic, capitalized interest, other leasehold costs		12,681		15,352

Acquisitions and investments in oil and gas property/equipment	$	482,777	$	206,294

(1)	Reported by geography in the subsequent table.

The following table presents our exploration and development capital expenditures by geography:


	Six Months Ended June 30,
	2011		2010
	(in thousands)
Conventional shelf	$	52,387	$	67,281
Deepwater		2,195		4,806
Deep shelf		31		2,266
Onshore		18,507		—

Exploration and development capital expenditures	$	73,120	$	74,353

Our 2011 capital expenditures were financed by cash flow from operating activities, cash on hand and additional borrowings. Our 2010 capital expenditures were financed by cash flow from operating activities and cash on hand.

During the first six months of 2011, we participated in the drilling of ten onshore wells and three offshore wells, all of which were successful. One onshore well was an exploration well in south Texas and the other nine onshore wells were development wells in the Permian Basin of West Texas. All of the offshore wells were on the conventional shelf with one being an exploration well and the other two being development wells.

During the first six months of 2010, we participated in the drilling of five offshore wells, four of which were successful. Of the successful wells, all four were on the conventional shelf with three being exploration wells and one a development well.

Our total capital expenditure budget for 2011 is $310 million, which excludes acquisitions. Although there has been considerable shuffling of wells and focus areas since the original budget was prepared, we believe that the $310 million continues to be a reasonable estimate of our capital expenditures, excluding acquisitions, for 2011. The budget includes amounts for drilling and evaluation of wells, well completions, facilities capital, recompletions, seismic and leasehold items. Our 2011 capital budget is subject to change as conditions warrant and our budget is sufficiently flexible such that most any change can be made without incurring any contractor breakage or commitment fees.

Capital expenditures associated with development activities for the Permian Basin Properties acquired in May 2011 from the closing date of May 11, 2011 to December 31, 2011 are currently estimated between $40 million and $50 million and are included in the total annual capital expenditure budget described above. For additional information on this acquisition, please see Financial Statements - Note 2 – Acquisitions under Part I, Item 1 of this Form 10-Q.

We intend to continue to pursue acquisitions and joint venture opportunities during 2011 should attractive opportunities arise. We are actively evaluating several other opportunities and expect to complement our drilling and exploitation projects with acquisitions providing acceptable rates of return. We anticipate funding our 2011 capital budget and acquisitions with internally generated cash flow, cash on hand, borrowings under our revolving bank credit facility, issuance of our 8.5% Senior Notes and additional long-term debt as needed.

Income taxes. During the six months ended June 30, 2011, we made tax payments of $19.1 million which relate to the 2010 tax year. For the six months ended June 30, 2010, we received refunds of approximately $99.8 million. For the year 2011, we expect substantially all of our income tax will be deferred and only minimal payments are expected primarily related to alternative minimum tax.

Dividends. During the first six months of 2011 and 2010, we paid regular cash dividends of $0.04 and $0.03 per common share per quarter, respectively. On August 3, 2011, our board of directors declared a cash dividend of $0.04 per common share, payable on September 12, 2011 to shareholders of record on August 22, 2011.

Contractual obligations. Major changes in contractual obligations from those disclosed in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2010 are as follows: 1) asset retirement obligations as disclosed in Financial Statements - Note 4 – Asset Retirement Obligations under Part I, Item 1 of this Form 10-Q; 2) additions of principal and interest related to our 8.5% Senior Notes and reductions of principal and interest related to our 8.25% Senior Notes principal as disclosed in Financial Statements - Note 6 – Long-Term Debt under Part I, Item 1 of this Form 10-Q; 3) drilling rig contracts with terms of six months or less have additional commitments of $27.6 million subsequent to June 30, 2010; and 4) changes to derivative contracts as disclosed in Financial Statements - Note 5 – Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q.

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, 2010. Also refer to the Notes to Condensed Consolidated Financial Statements included in Part 1, Item 1 of this Form 10-Q.

Recent Accounting Pronouncements

None.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Information about market risks for the first six months of 2011 did not change materially from the disclosures in Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2010. 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, 2010.

Commodity Price Risk. Our revenues, profitability and future rate of growth substantially depend upon market prices of oil and natural gas, which fluctuate widely. In the past, oil and natural gas price declines and volatility have negatively affected our revenues, net cash provided by operating activities and profitability. We have entered into a limited number of commodity option contracts to help manage our exposure to commodity price risk from sales of oil during the fiscal years ending December 31, 2011 and 2012. As of June 30, 2011 our derivative instruments outstanding consisted of commodity option contracts relating to approximately 0.6 MMBbls and 1.1 MMBbls of our anticipated production for the balance of 2011 and year 2012, respectively. While these contracts are intended to reduce the effects of volatile oil prices, they may also limit future income if oil prices were to rise substantially over the price established by the hedge. Currently, we do not have any commodity option contracts for natural gas. 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 5 – Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q.

Interest Rate Risk. We currently do not have any derivative instruments related to interest rates. As of June 30, 2011, we had $75 million of floating rate debt outstanding. Borrowings on our revolving bank credit facility are subject to interest rate risk.

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 June 30, 2011 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 June 30, 2011, 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 1.

Legal Proceedings

None.

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, 2010, 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.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. We utilize hydraulic fracturing techniques in connection with developing our recently acquired Permian Basin Properties and other properties. The process involves the injection of water, sand and small amounts of chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. The federal Environmental Protection Agency (“EPA”), however, recently asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the federal Safe Drinking Water Act’s (the “SDWA”) Underground Injection Control Program and has begun the process of drafting guidance documents on regulating requirements for companies that plan to conduct hydraulic fracturing using diesel fuel. In addition, a number of federal agencies are analyzing a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing activities, with initial results expected to be available by late 2012 and final results by 2014. A committee of the United States House of Representatives also has conducted an investigation of hydraulic fracturing practices. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. Legislation also has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states and local governments have adopted, and other states and local governments are considering

adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations, including states in which we operate. For example, on June 17, 2011, Texas signed into law a bill that requires the disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas (the entity that regulates oil and natural gas production in Texas) and the public. The disclosure of information regarding the constituents of hydraulic fracturing fluids could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based upon allegations that specific chemicals used in the fracturing process could adversely affect the environment, including groundwater, soil or surface water. In addition, disclosure of proprietary chemical formulas or disclosure of any chemicals used in such formulas to the public could diminish the value of those formulas and could result in competitive harm to us. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

Recently Proposed Rules Regulating Air Emissions from Oil and Gas Operations Could Cause Us to Incur Increased Capital Expenditures and Operating Costs

On July 28, 2011, the Environmental Protection Agency (“EPA”) proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA’s proposed rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. EPA’s proposal would require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks, and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. EPA will receive public comment and hold hearings regarding the proposed rules and must take final action on them by February 28, 2012. If finalized, these rules could require a number of modifications to our operations including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

Item 5.

Other Information - Submission of Matters to a Vote of Security Holders

As disclosed in the Company’s Form 10-Q for the quarter ended March 31, 2011, the shareholders’ non-binding advisory vote selected three-years as the frequency of future non-binding advisory votes to approve the compensation of the Company’s executives. On August 3, 2011, the Board approved a resolution to use the three-year frequency for future non-binding advisory votes to approve the compensation of the Company’s executives until the next required vote on the frequency of shareholder votes on the compensation of the Company’s executives.

Item 6.

Exhibits

The exhibits to this report are listed in the Exhibit Index.

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 August 4, 2011.


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 Opal Resources, LLC and W&T Offshore, Inc. (Incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K, filed May 13, 2011)

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))

4.1		First Supplemental Indenture, dated as of June 10, 2011, by and among W&T Offshore, Inc., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K, filed June 16, 2011)

4.2		Indenture, dated as of June 10, 2011, by and among W&T Offshore, Inc., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K, filed June 16, 2011)

4.3		Form of 8.5% Senior Notes due 2019 (included in Exhibit 4.2)

4.4		Registration Rights Agreement, dated June 10, 2011, by and among W&T Offshore, Inc., the Guarantors named therein and Morgan Stanley & Co. LLC, as representative of the Initial Purchasers. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K, filed June 16, 2011)

10.1		Fourth Amended and Restated Credit Agreement, dated May 5, 2011, by and among W&T Offshore, Inc., Toronto Dominion (Texas) LLC, as agent and the various agents and lenders party thereto. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed May 6, 2011)

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.

101.INS*		XBRL Instance Document

101.SCH*		XBRL Schema Document

101.CAL*		XBRL Calculation Linkbase Document

101.DEF*		XBRL Definition Linkbase Document

101.LAB*		XBRL Label Linkbase Document

101.PRE*		XBRL Presentation Linkbase Document

*	Filed or furnished herewith.

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company