Edgar Filing: W&T OFFSHORE INC

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Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2012

¨	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 July 27, 2012, there were 74,373,487 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, 2012 and December 31, 2011		1
	Condensed Consolidated Statements of Income for the Three and Six Months Ended June 30, 2012 and 2011		2
	Condensed Consolidated Statement of Changes in Shareholders’ Equity for the Six Months Ended June 30, 2012		3
	Condensed Consolidated Statements of Cash Flows for the Three and Six Months Ended June 30, 2012 and 2011		4
	Notes to Condensed Consolidated Financial Statements		5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		22

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		33

Item 4.	Controls and Procedures		33

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings		34

Item 1A.	Risk Factors		34

Item 6.	Exhibits		34

SIGNATURE			35

EXHIBIT INDEX			36

PART I – FINANCIAL INFORMATION

Item 1.

Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30, 2012			December 31, 2011
	(In thousands, except share data)
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	8,553		$	4,512
Receivables:
Oil and natural gas sales		72,429			98,550
Joint interest and other		21,410			25,804
Income tax receivable		12,033			—

Total receivables		105,872			124,354
Deferred income taxes		—			2,007
Restricted cash and cash equivalents		30,763			—
Prepaid expenses and other assets		54,110			30,315

Total current assets		199,298			161,188
Property and equipment – at cost:
Oil and natural gas properties and equipment (full cost method, of which $155,403 at June 30, 2012 and $154,516 at December 31, 2011 were excluded from amortization)		6,090,065			5,959,016
Furniture, fixtures and other		20,169			19,500

Total property and equipment		6,110,234			5,978,516
Less accumulated depreciation, depletion and amortization		4,484,496			4,320,410

Net property and equipment		1,625,738			1,658,106
Restricted deposits for asset retirement obligations		28,514			33,462
Other assets		19,268			16,169

Total assets	$	1,872,818		$	1,868,925

Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	86,215		$	75,871
Undistributed oil and natural gas proceeds		35,248			33,732
Asset retirement obligations		99,211			138,185
Accrued liabilities		15,980			29,705
Income taxes payable		363			10,392
Deferred income taxes – current portion		13,081			—

Total current liabilities		250,098			287,885
Long-term debt		680,000			717,000
Asset retirement obligations, less current portion		249,790			255,695
Deferred income taxes		91,912			58,881
Other liabilities		5,851			4,890
Commitments and contingencies		—			—
Shareholders’ equity:
Preferred stock, $0.00001 par value; 20,000,000 shares authorized; 0 issued at June 30, 2012 and December 31, 2011		—			—
Common stock, $0.00001 par value; 118,330,000 shares authorized; 77,242,660 issued and 74,373,487 outstanding at June 30, 2012; and 77,220,706 issued and 74,351,533 outstanding at December 31, 2011		1			1
Additional paid-in capital		393,233			386,920
Retained earnings		226,100			181,820
Treasury stock, at cost		(24,167	)		(24,167	)

Total shareholders’ equity		595,167			544,574

Total liabilities and shareholders’ equity	$	1,872,818		$	1,868,925

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,
	2012			2011			2012			2011
	(In thousands, except per share data)
	(Unaudited)

Revenues	$	215,513		$	252,922		$	451,399		$	463,777

Operating costs and expenses:
Lease operating expenses		60,276			48,597			116,938			101,002
Production taxes		1,335			845			2,821			1,133
Gathering and transportation		4,110			3,797			8,330			8,350
Depreciation, depletion, amortization and accretion		85,941			83,370			174,432			157,462
General and administrative expenses		14,623			18,002			44,102			36,131
Derivative (gain) loss		(49,872	)		(17,332	)		(10,238	)		6,508

Total costs and expenses		116,413			137,279			336,385			310,586

Operating income		99,100			115,643			115,014			153,191
Interest expense:
Incurred		14,706			12,047			28,612			22,176
Capitalized		(3,326	)		(2,079	)		(6,517	)		(3,491	)
Loss on extinguishment of debt		—			20,663			—			20,663

Income before income tax expense		87,720			85,012			92,919			113,843
Income tax expense		34,153			29,837			36,134			40,019

Net income	$	53,567		$	55,175		$	56,785		$	73,824


Basic and diluted earnings per common share	$	0.70		$	0.73		$	0.75		$	0.98

Dividends declared per common share	$	0.08		$	0.04		$	0.16		$	0.08

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, 2011		74,352	$	1	$	386,920	$	181,820			2,869	$	(24,167	)	$	544,574
Cash dividends		—		—		—		(11,898	)		—		—			(11,898	)
Share-based compensation		21		—		5,818		—			—		—			5,818
Other		—		—		495		(607	)		—		—			(112	)
Net income		—		—		—		56,785			—		—			56,785

Balances at June 30, 2012		74,373	$	1	$	393,233	$	226,100			2,869	$	(24,167	)	$	595,167

See Notes to Condensed Consolidated Financial Statements.

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six Months Ended June 30,
	2012			2011
	(In thousands)
	(Unaudited)
Operating activities:
Net income	$	56,785		$	73,824
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		174,432			157,462
Amortization of debt issuance costs		1,287			815
Loss on extinguishment of debt		—			20,663
Share-based compensation		5,818			3,662
Derivative (gain) loss		(10,238	)		6,508
Cash payments on derivative settlements		(6,084	)		(8,322	)
Deferred income taxes		48,120			35,726
Changes in operating assets and liabilities:
Oil and natural gas receivables		26,121			(11,606	)
Joint interest and other receivables		3,630			14,107
Insurance receivables		500			12,583
Income taxes		(22,062	)		(14,957	)
Prepaid expenses and other assets		(14,110	)		(24,650	)
Asset retirement obligations		(29,228	)		(29,703	)
Accounts payable and accrued liabilities		5,439			(6,382	)
Other liabilities		915			115

Net cash provided by operating activities		241,325			229,845

Investing activities:
Acquisitions of property interests in oil and natural gas properties		—			(396,976	)
Investment in oil and natural gas properties and equipment		(187,284	)		(85,801	)
Proceeds from sales of oil and natural gas properties and equipment		30,453			—
Change in restricted cash		(30,763	)		—
Purchases of furniture, fixtures and other		(668	)		(178	)

Net cash used in investing activities		(188,262	)		(482,955	)

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		197,000			310,000
Repayments of long-term debt – revolving bank credit facility		(234,000	)		(235,000	)
Repurchase premium and debt issuance costs		—			(29,728	)
Dividends to shareholders		(11,898	)		(5,957	)
Other		(124	)		—

Net cash (used in) provided by financing activities		(49,022	)		233,165

Increase (decrease) in cash and cash equivalents		4,041			(19,945	)
Cash and cash equivalents, beginning of period		4,512			28,655

Cash and cash equivalents, end of period	$	8,553		$	8,710

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 focused primarily in the Gulf of Mexico and onshore Texas. The Company is active in the acquisition, exploration and development of oil and natural gas properties.

Interim Financial Statements. The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with U.S. 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 included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011.

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 and Divestitures

2012 Acquisitions. There were no material acquisitions completed during the six months ended June 30, 2012.

2012 Divestitures. On May 15, 2012, we sold our 40%, non-operating working interest in the South Timbalier 41 field located in the Gulf of Mexico for $30.5 million with an effective date of April 1, 2012. The transaction was structured as a like-kind exchange under the Internal Revenue Service Code (“IRC”) Section 1031 and other applicable regulations, with funds held by a qualified intermediary until a replacement purchase is executed. Funds from this sale are included in current assets as restricted cash and cash equivalents on the balance sheet as of June 30, 2012. In connection with this sale, we reversed $4.0 million of asset retirement obligations (“ARO”).

2011 Acquisitions. On May 11, 2011, we completed the acquisition of approximately 24,500 gross acres (21,900 net acres) of oil and gas leasehold interests in the West Texas Permian Basin from Opal Resources LLC and Opal Resources Operating Company LLC (collectively, “Opal”) and, in 2011, we acquired minor amounts of undeveloped leasehold acreage in the related geography from another third party (collectively, with the properties acquired from Opal, the “Yellow Rose Properties”). The acquisitions were funded from cash on hand and borrowings under our revolving bank credit facility.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table presents the purchase price allocation for the acquisitions of the Yellow Rose Properties (in thousands):



Oil and natural gas properties and equipment	$	396,902
Asset retirement obligations – non-current		(382	)
Long-term liability		(2,143	)


Total cash paid	$	394,377

On August 10, 2011, we completed the acquisition from Shell Offshore Inc. (“Shell”) of its 64.3% interest in the Fairway Field along with a like interest in the associated Yellowhammer gas treatment plant (collectively, the “Fairway Properties”). During the six months ended June 30, 2012, the purchase price was reduced by $3.7 million. The purchase price is subject to further post-effective date adjustments and final settlement is expected to occur in the third quarter of 2012. The acquisition was funded from borrowings under our revolving bank credit facility.

The following table presents the purchase price allocation for the acquisition of the Fairway Properties (in thousands):



Oil and natural gas properties and equipment	$	46,993
Asset retirement obligations – non-current		(7,812	)


Total cash paid	$	39,181

2011 Divestitures. There were no divestitures completed during the six months ended June 30, 2011.

3. Hurricane Remediation and Insurance Claims

During the third quarter of 2008, Hurricane Ike caused substantial property damage and we continue to incur costs and submit claims to our insurance underwriters related to repairing such damage. Our insurance policies in effect on the occurrence date of Hurricane Ike had a retention requirement of $10.0 million per occurrence, which has been satisfied, and coverage policy limits of $150.0 million for property damage due to named windstorms (excluding damage at certain facilities) and $250.0 million for, among other things, removal of wreckage if mandated by any governmental authority.

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, which arises when our insurance underwriters’ adjuster reviews and approves such costs for payment by the underwriters. Claims that have been processed in this manner have customarily been paid on a timely basis. See Note 4 for additional information about the impact of hurricane related items on our asset retirement obligations.

From the third quarter of 2008 through June 30, 2012, we have received $140.0 million from our insurance underwriters related to Hurricane Ike. To the extent additional remediation costs or plug and abandonment costs are incurred that are not covered by insurance, 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.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

4. Asset Retirement Obligations

Our ARO 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 ARO is as follows (in thousands):



Balance, December 31, 2011	$	393,880
Liabilities settled		(29,228	)
Accretion of discount		10,347
Disposition of properties		(3,993	)
Liabilities incurred		362
Revisions of estimated liabilities due to Hurricane Ike (1)		(30,360	)
Revisions of estimated liabilities – all other		7,993

Balance, June 30, 2012		349,001
Less current portion		99,211


Long-term	$	249,790

(1)

During the six months ended June 30, 2012, our recommended remediation plan for one of the hurricane damaged platforms and its associated wells was approved by all required parties. The approved plan, which included remediating the damaged platform as a reef in place, was responsible for most of the reduction of the estimated costs.

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 crude oil swap and option contracts. We are exposed to credit loss in the event of nonperformance by the counterparties (Natixis; ING Capital Markets, LLC-EDP; the Toronto Dominion Bank; and Wells Fargo Bank, N.A.); 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 Derivatives. We have entered into commodity option contracts to manage a portion of our exposure to commodity price risk from sales of oil through December 2014. While these contracts are intended to reduce the effects of price volatility, they may also limit future income from favorable price movements. During the six months ended June 30, 2012 and 2011, our derivative contracts consisted entirely of crude oil contracts. The zero cost collars are priced off the West Texas Intermediate crude oil price quoted on the New York Mercantile Exchange, known as NYMEX, and the swaps are priced off the Brent crude oil price quoted on the IntercontinentalExchange, known as ICE.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

As of June 30, 2012, our open commodity derivatives were as follows:


Zero Cost Collars – Oil (NYMEX)
Termination Period	Notional Quantity (Bbls)		Weighted Average Contract Price				Fair Value Asset (in thousands)
Termination Period	Notional Quantity (Bbls)		Floor		Ceiling		Fair Value Asset (in thousands)
2012: 3rd quarter		124,000	$	75.00	$	97.88	$	6
4th quarter		251,000		75.00		98.99		68

		375,000	$	75.00	$	98.62	$	74


Swaps – Oil (ICE)
Termination Period	Notional Quantity (Bbls)		Weighted Average Contract Price		Fair Value Asset (in thousands)
2012: 3rd quarter		414,000	$	107.28	$	3,860
4th quarter		257,600		107.28		2,405
2013: 1st quarter		351,000		101.97		1,446
2nd quarter		336,700		101.97		1,403
3rd quarter		312,800		101.98		1,396
4th quarter		294,400		101.98		1,447
2014: 1st quarter		180,000		97.38		177
2nd quarter		172,900		97.38		257
3rd quarter		165,600		97.38		338
4th quarter		156,400		97.37		407

		2,641,400	$	102.15	$	13,136

The following balance sheet line items included amounts related to the estimated fair value of our derivative contracts as indicated in the following table (in thousands):


	June 30, 2012		December 31, 2011
Prepaid and other assets	$	9,188	$	2,341
Other assets		4,022		1,746
Accrued liabilities		—		7,199

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Changes in the fair value of our derivative contracts are recognized currently in earnings and were as follows (in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Derivative (gain) loss:
Realized	$	285		$	6,099		$	6,084		$	8,322
Unrealized		(50,157	)		(23,431	)		(16,322	)		(1,814	)

Total	$	(49,872	)	$	(17,332	)	$	(10,238	)	$	6,508

6. Long-Term Debt

At June 30, 2012 and December 31, 2011, the balance outstanding of our senior notes, which bear an annual interest rate of 8.50% and mature on June 15, 2019 (the “8.50% Senior Notes”), was $600.0 million and was classified as long-term at their carrying value. Interest on the 8.50% Senior Notes is payable semi-annually in arrears on June 15 and December 15. The estimated annual effective interest rate on the 8.50% Senior Notes is 8.6%. We are subject to various financial and other covenants under the indenture governing the 8.50% Senior Notes and we were in compliance with those covenants as of June 30, 2012.

The Fourth Amended and Restated Credit Agreement (the “Credit Agreement”) governs our revolving bank credit facility and terminates on May 5, 2015. Borrowings under our revolving bank credit facility are secured by our oil and natural gas properties. Availability under such facility is subject to a semi-annual redetermination of our borrowing base that occurs in the spring and fall of each year and is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria.

On May 7, 2012, we executed the First Amendment to the Fourth Amended and Restated Credit Agreement (the “Amendment”), which, among other things, increased the number of participating lenders, increased the borrowing base from $575.0 million to $650.0 million and added a provision permitting the Company to maintain security interests in favor of any hedging counterparties that cease to be lenders under the Company’s revolving bank credit facility. All other terms of the Credit Agreement remain substantially the same prior to the Amendment.

At June 30, 2012 and December 31, 2011, we had $80.0 million and $117.0 million, respectively, of loans outstanding and $0.6 million and $0.4 million, respectively, of letters of credit outstanding under the revolving bank credit facility. The outstanding balance under the revolving credit facility was classified as long-term at the carrying value. The estimated annual effective interest rate was 4.5% for borrowings under the revolving bank credit facility for the six months ended June 30, 2012. The estimated annual effective interest rate includes amortization of debt issuance costs and excludes commitment fees and other costs. As of June 30, 2012, our borrowing base was $650.0 million and our borrowing capacity availability was $569.4 million.

Under the Credit Agreement, we are subject to two financial covenants calculated as of the last day of each fiscal quarter, comprised of a minimum current ratio and a maximum leverage ratio, each as defined in the Credit Agreement. We were in compliance with all applicable covenants of the Credit Agreement as of June 30, 2012.

For information about fair value measurements for our 8.50% Senior Notes and revolving bank credit facility, refer to Note 7.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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. The fair value of our 8.50% Senior Notes is based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2. The carrying amount of debt under our revolving bank credit facility approximates fair value because the interest rates are variable and reflective of market rates.

The following table presents the fair value of our derivative financial instruments, 8.50% Senior Notes and revolving bank credit facility for the periods indicated (in thousands).


			June 30, 2012				December 31, 2011
	Hierarchy		Assets		Liabilities		Assets		Liabilities
Commodity derivatives		Level 2	$	13,210	$	—	$	4,087	$	7,199
8.50% Senior Notes		Level 2		—		616,500		—		612,000
Revolving bank credit facility		Level 2		—		80,000		—		117,000

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 8.50% Senior Notes and revolving bank credit facility are reported in the balance sheet at their carrying value as described in Note 6.

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 by our shareholders. As allowed by the Plan, in 2012 and in prior years, 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, which are granted to only certain employees, and are subject to adjustments at the end of the applicable performance period based on the achievement of certain predetermined criteria. In 2012 and in prior years, restricted stock was granted to the Company’s non-employee directors under the Director Compensation Plan. The restricted stock and RSUs vest at the end of a specified service period. 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 are expected to actually vest.

At June 30, 2012, there were 2,269,745 shares of common stock available for issuance in satisfaction of awards under the Plan and 546,829 shares of common stock available for issuance in satisfaction of awards under the Director Compensation Plan. The shares available for both plans are reduced when restricted stock is granted. RSUs will reduce the shares available in the Plan only if RSUs are settled in shares of common stock. The Company has the option to settle RSUs in stock or cash at vesting.

Restricted Stock. The Company currently has unvested restricted shares outstanding issued to the non-employee directors and one employee. 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.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

A summary of activity related to restricted stock is as follows:


	Restricted Stock
	Shares			Weighted Average Grant Date Fair Value Per Share
Outstanding restricted shares, December 31, 2011		51,870		$	15.81
Granted		21,954			19.13
Vested		(27,475	)		13.59
Forfeited		—			—

Outstanding restricted shares, June 30, 2012 (1)		46,349		$	18.70

(1)

Subject to the satisfaction of service conditions, 2,662 shares, 24,019 shares, 12,354 shares and 7,314 shares will vest in 2012, 2013, 2014 and 2015, respectively.

The grant date fair value of restricted shares granted during the six months ended June 30, 2012 and 2011 was $0.4 million and $0.5 million, respectively. The fair value of restricted shares that vested during the six months ended June 30, 2012 and 2011 was $0.5 million and $0.6 million, respectively.

Restricted Stock Units. During 2012, the Company awarded to certain employees RSUs that were 100% contingent upon meeting specified performance requirements, with 70% of the award conditioned on achieving earnings per share targets for the year 2012, 10% of the award conditioned on achieving total shareholder return (“TSR”) targets for the year 2012, 10% of the award conditioned on achieving TSR targets for the year 2013 and 10% of the award conditioned on achieving TSR targets for the period January 1, 2014 to October 31, 2014 (collectively, the “2012 RSUs”). TSR is determined based upon the change in the entity’s stock price and dividends for the performance period. The TSR targets are the ranking of the Company’s TSR compared to the TSR of 19 peer companies. The 2012 RSUs related to the earnings per share targets have an issuance scale from 0% to 100%. The 2012 RSUs related to TSR targets have an issuance scale from 0% to 150%. Subject to achieving the predetermined performance criteria and the service condition, vesting for the 2012 RSUs occurs on December 15, 2014.

The fair value at the date of grant for the 2012 RSUs was determined separately for the component related to the earnings per share targets and the component related to TSR targets. The fair value of the component related to earnings per share targets was determined using the Company’s closing price on the grant date and a forecast of earnings per share for 2012 to estimate the number of shares eligible for vesting. The fair value for the component related to TSR targets was determined by using a Monte Carlo simulation probabilistic model. The inputs used in the probabilistic model for the Company and the peer companies were: average closing stock prices during January 2012; risk-free interest rates using the London Interbank Offered Rate (“LIBOR”) Zero ranging from .15% to .72% over the service period; expected volatilities ranging from 33% to 74%; expected dividend yields ranging from 0.0% to 2.5%; and correlation factors ranging from (67%) to 94%. The expected volatilities, expected dividends and correlation factors were developed using historical data.

During 2010 and 2011, the Company awarded to certain employees RSUs that were 100% contingent upon meeting specified performance requirements, which were achieved for both awards. Subject to satisfaction of the service condition, vesting will occur on December 15, 2012 and December 15, 2013, respectively.

All RSUs awarded are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during the restricted period. Dividend equivalents are earned at the same rate as dividends paid on our common stock and are earned after achieving the specified performance requirement for that component of the RSUs.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

A summary of activity related to RSUs is as follows:


	Restricted Stock Units
	Units			Weighted Average Grant Date Fair Value Per Unit
Outstanding RSUs, December 31, 2011		1,732,703		$	14.67
Granted (1)		757,699			18.64
Vested		—			—
Forfeited		(36,543	)		24.38

Outstanding RSUs, June 30, 2012 (2)		2,453,859		$	15.75

(1)

Grants for the 2012 RSUs are subject to adjustment once the specified performance requirements can be measured. As of June 30, 2012, none of the performance targets for the 2012 RSUs are measurable as the earnings per share and the TSR for 2012 components are measured as of December 31, 2012. Subject to the performance against specified targets, the range of 2012 RSUs that may ultimately be issued is zero to 871,354 RSUs as of June 30, 2012.

(2)

Subject to the satisfaction of service conditions, 1,205,755 and 496,339 RSUs will vest in 2012 and 2013, respectively. Subject to the satisfaction of performance and service conditions, 751,765 RSUs will vest in 2014, which may be increased up to 871,354 RSUs depending on the specified performance results.

During the six months ended June 30, 2011, 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 is as follows (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Share-based compensation expense from:
Restricted stock	$	108	$	603	$	214	$	1,191
Restricted stock units		3,051		1,232		5,604		2,471

Total	$	3,159	$	1,835	$	5,818	$	3,662

Share-based compensation tax benefit:
Tax benefit computed at the statutory rate	$	1,106	$	642	$	2,036	$	1,282

As of June 30, 2012, unrecognized share-based compensation expense related to our outstanding restricted shares and RSUs was $0.8 million and $16.7 million, respectively. Unrecognized compensation expense will be recognized through April 2015 for restricted shares and November 2014 for RSUs.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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

Share-Based Compensation and Cash-Based Incentive Compensation Expense. A summary of incentive compensation expense is as follows (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Share-based compensation expense included in:
Lease operating expense	$	—	$	116	$	—	$	233
General and administrative		3,159		1,719		5,818		3,429

Total charged to operating income		3,159		1,835		5,818		3,662

Cash-based incentive compensation included in:
Lease operating expense		—		1,119		1,900		2,199
General and administrative		—		3,288		1,878		6,052

Total charged to operating income		—		4,407		3,778		8,251


Total incentive compensation charged to operating income	$	3,159	$	6,242	$	9,596	$	11,913

9. Income Taxes

Income tax expense of $34.2 million and $36.1 million was recorded during the three and six months ended June 30, 2012, respectively. Our effective tax rate for the three and six months ended June 30, 2012 was 38.9% for both periods, and differed from the federal statutory rate of 35.0% primarily as a result of the recapture of deductions for qualified domestic production activities under Section 199 of the IRC as a function of loss carrybacks to prior years. 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 statutory rate.

As of June 30, 2012 and December 31, 2011, we did not have any unrecognized tax benefit recorded. As of June 30, 2012 and December 31, 2011, we had a valuation allowance related to state net operating losses. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses are deductible. The tax years from 2008 through 2011 remain open to examination by the tax jurisdictions to which we are subject.

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 and diluted earnings per common share (in thousands, except per share amounts):


	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Net income	$	53,567	$	55,175	$	56,785	$	73,824
Less portion allocated to nonvested shares		1,185		1,178		1,214		1,558

Net income allocated to common shares	$	52,382	$	53,997	$	55,571	$	72,266


Weighted average common shares outstanding		74,318		74,020		74,309		74,012


Basic and diluted earnings per common share	$	0.70	$	0.73	$	0.75	$	0.98

Shares excluded due to being anti-dilutive (weighted-average)		1,913		1,683		1,839		1,699

11. Dividends

During the six months ended June 30, 2012 and 2011, we paid regular cash dividends of $0.08 and $0.04 per common share per quarter, respectively. On July 30, 2012, our board of directors declared a cash dividend of $0.08 per common share, payable on September 12, 2012 to shareholders of record on August 22, 2012.

12. Contingencies

The United States Attorney’s Office for the Eastern District of Louisiana, along with the Criminal Investigation Division of the U.S. Environmental Protection Agency (the “EPA”), has been conducting a federal grand jury investigation of environmental compliance matters relating to surface discharges and reporting on four of our offshore platforms in the Gulf of Mexico. We are fully cooperating with the investigation which began in late 2010 and is currently ongoing . The United States Attorney’s Office has informed us that it is continuing its investigation with the intent to seek a criminal disposition. The outcome of this investigation could have a material adverse effect upon us. We are not able at this time to estimate our potential exposure, if any, related to this matter.

On May 6, 2009, certain Cameron Parish land owners filed suit in the 38th Judicial District Court, Cameron Parish, Louisiana against the Company and Tracy W. Krohn as well as several other defendants unrelated to us. In their lawsuit, plaintiffs are alleging that property they own has been contaminated or otherwise damaged by the defendants’ oil and gas exploration and production activities and are seeking compensatory and punitive damages. The ultimate resolution of this matter cannot be estimated by management at this time. We are vigorously defending this litigation.

During the six months ended June 30, 2012, we increased our estimated contingency reserve by $8.4 million, which was charged to General and administrative expenses on the statement of income. As of June 30, 2012 and December 31, 2011, we have recorded a liability of $10.4 million and $2.0 million, respectively, which is included in Accrued liabilities on the balance sheet, for the loss contingencies of environmental matters that include the events described above and other minor environmental and litigation matters we are addressing.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

In 2009, the Company recognized $5.3 million in allowable reductions of cash payments for royalties owed to the Office of Natural Resources Revenue (the “ONRR”) for transportation of their deepwater production through our subsea pipeline systems. In 2010, the ONRR audited the calculations and support related to this usage fee, and in the third quarter of 2010, we were notified that the ONRR had disallowed approximately $4.7 million of the reductions taken. We recorded a reduction to other revenue of $4.7 million in the third quarter of 2010 to reflect this disallowance; however, we disagree with the position taken by the ONRR and we are pursuing our claim to resolve the matter.

We are a party to various pending or threatened claims and complaints seeking damages or other remedies concerning our commercial operations and other matters in the ordinary course of our business. In addition, claims or contingencies may arise related to matters occurring prior to our acquisition of properties or related to matters occurring subsequent to our sale of properties. In certain cases, we have indemnified the sellers of properties we have acquired, and in other cases, we have indemnified the buyers of properties we have sold. We are also subject to federal and state administrative proceedings conducted in the ordinary course of business. Although we can give no assurance about the outcome of pending legal and federal or state administrative proceedings and the effect such an outcome may have on us, management believes that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

13. Supplemental Guarantor Information

Our payment obligations under the 8.50% Senior Notes and the Credit Agreement (see Note 6) are fully and unconditionally guaranteed by certain of our wholly-owned subsidiaries, W&T Energy VI, LLC and W&T Energy VII, LLC, 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. (when referred to on a stand-alone basis, the “Parent Company”) and the Guarantor Subsidiaries, together with consolidating adjustments necessary to present the Company’s results on a consolidated basis.

Condensed Consolidating Balance Sheet as of June 30, 2012


									Consolidated W&T Offshore, Inc.
	Parent Company			Guarantor Subsidiaries		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	8,553		$	—	$	—		$	8,553
Receivables:
Oil and natural gas sales		55,381			17,048		—			72,429
Joint interest and other		21,410			—		—			21,410
Income taxes		114,534			—		(102,501	)		12,033

Total receivables		191,325			17,048		(102,501	)		105,872
Restricted cash and cash equivalents		30,763			—		—			30,763
Prepaid expenses and other assets		54,110			—		—			54,110

Total current assets		284,751			17,048		(102,501	)		199,298
Property and equipment – at cost:
Oil and natural gas properties and equipment		5,788,799			301,266		—			6,090,065
Furniture, fixtures and other		20,169			—		—			20,169

Total property and equipment		5,808,968			301,266		—			6,110,234
Less accumulated depreciation, depletion and amortization		4,330,857			153,639		—			4,484,496

Net property and equipment		1,478,111			147,627		—			1,625,738
Restricted deposits for asset retirement obligations		28,514			—		—			28,514
Deferred income taxes		—			15,526		(15,526	)		—
Other assets		413,514			346,600		(740,846	)		19,268

Total assets	$	2,204,890		$	526,801	$	(858,873	)	$	1,872,818

Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	85,357		$	858	$	—		$	86,215
Undistributed oil and natural gas proceeds		34,993			255		—			35,248
Asset retirement obligations		99,211			—		—			99,211
Accrued liabilities		15,980			—		—			15,980
Income taxes		—			102,864		(102,501	)		363
Deferred income taxes – current		13,081			—		—			13,081

Total current liabilities		248,622			103,977		(102,501	)		250,098
Long-term debt		680,000			—		—			680,000
Asset retirement obligations, less current portion		221,212			28,578		—			249,790
Deferred income taxes		107,438			—		(15,526	)		91,912
Other liabilities		352,451			—		(346,600	)		5,851
Shareholders’ equity:
Common stock		1			—		—			1
Additional paid-in capital		393,233			231,759		(231,759	)		393,233
Retained earnings		226,100			162,487		(162,487	)		226,100
Treasury stock, at cost		(24,167	)		—		—			(24,167	)

Total shareholders’ equity		595,167			394,246		(394,246	)		595,167

Total liabilities and shareholders’ equity	$	2,204,890		$	526,801	$	(858,873	)	$	1,872,818

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Condensed Consolidating Balance Sheet as of December 31, 2011


									Consolidated W&T Offshore, Inc.
	Parent Company			Guarantor Subsidiaries		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	4,512		$	—	$	—		$	4,512
Receivables:
Oil and natural gas sales		78,131			20,419		—			98,550
Joint interest and other		25,804			—		—			25,804
Income taxes		74,183			—		(74,183	)		—

Total receivables		178,118			20,419		(74,183	)		124,354
Deferred income taxes		2,007			—		—			2,007
Prepaid expenses and other assets		30,315			—		—			30,315

Total current assets		214,952			20,419		(74,183	)		161,188
Property and equipment – at cost:
Oil and natural gas properties and equipment		5,689,535			269,481		—			5,959,016
Furniture, fixtures and other		19,500			—		—			19,500

Total property and equipment		5,709,035			269,481		—			5,978,516
Less accumulated depreciation, depletion and amortization		4,208,825			111,585		—			4,320,410

Net property and equipment		1,500,210			157,896		—			1,658,106
Restricted deposits for asset retirement obligations		33,462			—		—			33,462
Deferred income taxes		—			17,637		(17,637	)		—
Other assets		372,572			275,181		(631,584	)		16,169

Total assets	$	2,121,196		$	471,133	$	(723,404	)	$	1,868,925

Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	73,333		$	2,538	$	—		$	75,871
Undistributed oil and natural gas proceeds		33,391			341		—			33,732
Asset retirement obligations		138,185			—		—			138,185
Accrued liabilities		29,705			—		—			29,705
Income taxes		—			84,575		(74,183	)		10,392

Total current liabilities		274,614			87,454		(74,183	)		287,885
Long-term debt		717,000			—		—			717,000
Asset retirement obligations, less current portion		228,419			27,276		—			255,695
Deferred income taxes		76,518			—		(17,637	)		58,881
Other liabilities		280,071			—		(275,181	)		4,890
Shareholders’ equity:
Common stock		1			—		—			1
Additional paid-in capital		386,920			231,759		(231,759	)		386,920
Retained earnings		181,820			124,644		(124,644	)		181,820
Treasury stock, at cost		(24,167	)		—		—			(24,167	)

Total shareholders’ equity		544,574			356,403		(356,403	)		544,574

Total liabilities and shareholders’ equity	$	2,121,196		$	471,133	$	(723,404	)	$	1,868,925

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, 2012


									Consolidated W&T Offshore, Inc.
	Parent Company			Guarantor Subsidiaries		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Revenues	$	155,595		$	59,918	$	—		$	215,513

Operating costs and expenses:
Lease operating expenses		53,490			6,786		—			60,276
Production taxes		1,335			—		—			1,335
Gathering and transportation		3,221			889		—			4,110
Depreciation, depletion, amortization and accretion		63,459			22,482		—			85,941
General and administrative expenses		14,623			—		—			14,623
Derivative gain		(49,872	)		—		—			(49,872	)

Total costs and expenses		86,256			30,157		—			116,413

Operating income		69,339			29,761		—			99,100
Earnings of affiliates		19,328			—		(19,328	)		—
Interest expense:
Incurred		14,706			—		—			14,706
Capitalized		(3,326	)		—		—			(3,326	)

Income before income tax expense		77,287			29,761		(19,328	)		87,720
Income tax expense		23,720			10,433		—			34,153

Net income	$	53,567		$	19,328	$	(19,328	)	$	53,567

Condensed Consolidating Statement of Income for the Six Months Ended June 30, 2012


									Consolidated W&T Offshore, Inc.
	Parent Company			Guarantor Subsidiaries		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Revenues	$	332,157		$	119,242	$	—		$	451,399

Operating costs and expenses:
Lease operating expenses		103,507			13,431		—			116,938
Production taxes		2,821			—		—			2,821
Gathering and transportation		6,704			1,626		—			8,330
Depreciation, depletion, amortization and accretion		131,082			43,350		—			174,432
General and administrative expenses		41,510			2,592		—			44,102
Derivative gain		(10,238	)		—		—			(10,238	)

Total costs and expenses		275,386			60,999		—			336,385

Operating income		56,771			58,243		—			115,014
Earnings of affiliates		37,844			—		(37,844	)		—
Interest expense:
Incurred		28,612			—		—			28,612
Capitalized		(6,517	)		—		—			(6,517	)

Income before income tax expense		72,520			58,243		(37,844	)		92,919
Income tax expense		15,735			20,399		—			36,134

Net income	$	56,785		$	37,844	$	(37,844	)	$	56,785

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		63,216			20,154		—			83,370
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		12,047			—		—			12,047
Capitalized		(2,079	)		—		—			(2,079	)
Loss on extinguishment of debt		20,663			—		—			20,663

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		114,627			42,835		—			157,462
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		22,176			—		—			22,176
Capitalized		(3,491	)		—		—			(3,491	)
Loss on extinguishment of debt		20,663			—		—			20,663

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 Cash Flows for the Six Months Ended June 30, 2012


	Parent Company			Guarantor Subsidiaries			Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Operating activities:
Net income	$	56,785		$	37,844		$	(37,844	)	$	56,785
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		131,082			43,350			—			174,432
Amortization of debt issuance costs		1,287			—			—			1,287
Share-based compensation		5,818			—			—			5,818
Derivative gain		(10,238	)		—			—			(10,238	)
Cash payments on derivative settlements		(6,084	)		—			—			(6,084	)
Deferred income taxes		46,010			2,110			—			48,120
Earnings of affiliates		(37,844	)		—			37,844			—
Changes in operating assets and liabilities:
Oil and natural gas receivables		22,750			3,371			—			26,121
Joint interest and other receivables		3,630			—			—			3,630
Insurance receivables		500			—			—			500
Income taxes		(40,351	)		18,289			—			(22,062	)
Prepaid expenses and other assets		(14,110	)		(71,419	)		71,419			(14,110	)
Asset retirement obligations		(29,228	)		—			—			(29,228	)
Accounts payable and accrued liabilities		7,205			(1,766	)		—			5,439
Other liabilities		72,334			—			(71,419	)		915

Net cash provided by operating activities		209,546			31,779			—			241,325

Investing activities:
Investment in oil and natural gas properties and equipment		(155,505	)		(31,779	)		—			(187,284	)
Proceeds from sales of oil and gas properties and equipment		30,453			—			—			30,453
Change in restricted cash		(30,763	)		—			—			(30,763	)
Purchases of furniture, fixtures and other		(668	)		—			—			(668	)

Net cash used in investing activities		(156,483	)		(31,779	)		—			(188,262	)

Financing activities:
Borrowings of long-term debt – revolving bank credit facility		197,000			—			—			197,000
Repayments of long-term debt – revolving bank credit facility		(234,000	)		—			—			(234,000	)
Dividends to shareholders		(11,898	)		—			—			(11,898	)
Other		(124	)		—			—			(124	)

Net cash used in financing activities		(49,022	)		—			—			(49,022	)

Increase in cash and cash equivalents		4,041			—			—			4,041
Cash and cash equivalents, beginning of period		4,512			—			—			4,512

Cash and cash equivalents, end of period	$	8,553		$	—		$	—		$	8,553

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 financing activities		233,165			—			—			233,165

Decrease 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

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 of 1934, which 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. Known material risks that may affect our financial condition and results of operations are discussed in Item 1A “Risk Factors” and market risks are discussed in Item 7A “Quantitative and Qualitative Disclosures About Market Risk” of our Annual Report on Form 10-K for the year ended December 31, 2011 and may be discussed or updated from time to time in subsequent reports filed with the SEC. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. 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

We are an independent oil and natural gas producer focused primarily in the Gulf of Mexico and Texas. We have grown through acquisitions, exploration and development and currently hold working interests in approximately 60 producing offshore fields in federal and state waters. During 2011, we expanded onshore into West Texas and East Texas where we are actively pursuing exploration and development activities. The majority of our daily production is derived from wells we operate offshore. In managing our business, we are concerned primarily with maximizing long-term return on shareholders’ equity. To accomplish this primary goal, we focus on profitably increasing production and finding oil and gas reserves at a favorable cost. We strive to increase our reserves and production through acquisitions and our drilling programs. We have focused on acquiring properties where we can develop an inventory of drilling prospects that will enable us to continue to add reserves post-acquisition.

Our financial condition, cash flow and results of operations are significantly affected by the volume of our oil, natural gas liquids (“NGLs”) and natural gas production and the prices that we receive for such production. For the first half of 2012, our combined total production of oil, condensate, NGLs and natural gas increased by 12.4% and our combined average realized prices decreased by 13.4% compared to the same period in 2011 based on an energy equivalency ratio. Our production volumes for the first half of 2012 were comprised of approximately 33.6% oil and condensate, 12.7% NGLs and 53.7% natural gas. In the first half of 2012, oil sales represented 71.7% of total revenues, while NGLs represented 11.6% and natural gas represented 16.4% of total revenues. Energy equivalency is determined using the ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of crude oil, condensate or NGLs and is reported herein as thousand cubic feet equivalent (“Mcfe”) or barrel of equivalent (“Boe”). The conversion ratio does not assume price equivalency, and the price per Mcfe for oil, NGLs and natural gas may differ significantly.

During 2011, we closed two acquisition transactions. On May 11, 2011, we completed the acquisition of the Yellow Rose Properties, which consist of approximately 24,500 gross acres (21,900 net acres) of oil and gas leasehold interests in the Permian Basin of West Texas. Based on internal estimates, proved reserves associated with the Yellow Rose Properties as of the acquisition date were approximately 30.1 million barrels of oil equivalent (“MMBoe”), or 180.4 billion cubic feet natural gas equivalent (“Bcfe”), comprised of approximately 69% oil, 22% NGLs and 9% natural gas, and approximately 30% of which were classified as proved developed. The adjusted purchase price was $394.4 million excluding ARO and long-term liabilities. We assumed the ARO, which we estimated to be $0.4 million, and recorded a long-term liability of $2.1 million. The acquisition was funded from cash on hand and borrowings under our revolving bank credit facility.

On August 10, 2011, we completed the acquisition of the Fairway Properties, which consisted of a 64.3% working interest in the Fairway field along with a like interest in the associated Yellowhammer gas treatment plant. Based on internal estimates, proved reserves associated with the Fairway field as of the acquisition date were 8.9 MMBoe (53.5 Bcfe) comprised of approximately 72% natural gas, 27% NGLs and less than 1% oil and 100% of which were classified as proved developed. As of June 30, 2012, the adjusted purchase price was $39.2 million excluding ARO. The purchase price is subject to further post-effective date adjustments and final settlement is expected to occur in the third quarter of 2012. We assumed the ARO associated with the properties and plant, which we estimated to be $7.8 million. The acquisition was funded from borrowings under our revolving bank credit facility.

Industry Trends

During the first half of 2012, our average realized oil sales price (unhedged) increased 3.5% compared to the first half of 2011. Two comparable benchmarks are the unweighted average daily posted spot price of West Texas Intermediate (“WTI”) crude oil, which was flat with the comparable 2011 period, and the unweighted average daily posted spot price of Brent crude oil, which increased 2.0 % from the comparable 2011 period. WTI is frequently used to value domestically produced crude oil, and the majority of our oil production is priced using the spot price for WTI as a base price plus a premium depending on the type of crude oil. Most of our oil production is from our offshore operations and is comprised of various crudes including Heavy Louisiana Sweet, Light Louisiana Sweet, Poseidon and others. Starting in the first quarter of 2011 and continuing through the first half of 2012, these various crudes sold at a significant premium relative to WTI. During the first half of 2012, premiums for Heavy Louisiana Sweet crude ranged between $11.00 and $22.00 per barrel and premiums for Light Louisiana Sweet crude ranged between $10.00 and $21.00 per barrel. For the month of June 2012, the average premium for these crudes was between $13.00 and $16.00 per barrel. In comparison, the average premium for these crudes was between $7.00 and $15.00 per barrel for the first half of 2011, and in 2010, the average premium was approximately $2.00 to $3.00 per barrel, which is representative of the historical norm. We may continue to experience higher premiums to WTI crude in our future sales of crude oil until such time as the causative factors, described below, are resolved. We cannot predict with any certainty how long such pricing conditions will last.

A possible cause cited by industry publications for the premiums afforded our offshore crudes is an over supply situation at Cushing, Oklahoma, a primary domestic hub for crude oil priced using the WTI benchmark. Citing the Cushing crude over supply situation, the owners of the Seaway pipeline reversed the flow of crude oil in June 2012 to flow crude from Cushing to Freeport, Texas. The pipeline has a current capacity of 150,000 barrels per day. The owners have also announced plans to increase the capacity to 400,000 barrels per day in early 2013 and to construct a parallel pipeline to be completed in mid-2014, which is expected to double the capacity to 850,000 barrels per day. We believe these plans should help to relieve most of the over supply situation at Cushing, which may affect the premiums we receive on our offshore oil production. An additional factor that has appeared to affect the premiums for Heavy Louisiana Sweet and Light Louisiana Sweet is the difference between the Brent and WTI crude oil prices, which continue to have a higher spread than historical norms. When the price of Brent crude increases relative to WTI, the value of low-sulfur U.S. crude grades that compete with West African crude increases. This trend of higher Brent spreads began in the first quarter of 2011 and has continued through the first half of 2012.

Oil prices are affected by world events, such as production stoppages in the Middle East, the threat of hostilities, demand changes in various countries and world economic growth. Some commentators believe world economic growth, which is currently affected by the economies of China, Brazil, India and Russia, may support strong crude oil prices in the long term.

Not withstanding this long-term view, crude oil prices may continue to be volatile. Between May and June of 2012, WTI crude oil prices fell from a high of over $106.00 per barrel to a low of $78.00 per barrel. The fall in price was attributed by some commentators to be due in part to the debt crisis in Europe and the belief that economic growth in certain world markets, such as China, was weakening. Citing these and other factors, the U.S. Energy Information Administration (“EIA”) lowered its estimate of global oil demand for 2013 to 89.4 million barrels per day and to 89.3 million barrels per day for the second half of 2012.

Our average realized NGLs prices (unhedged) decreased 15.5% during the first half of 2012 compared to the first half of 2011. According to industry sources, domestic NGLs production significantly increased over 2011 levels which affected price realizations. During the first half of 2012, prices for domestic ethane and propane, two common NGL components, decreased 53% and 25%, respectively, from the first half of 2011 and other domestic NGLs prices were relatively unchanged. As long as ethane and propane inventories continue to be high and NGLs production continues to increase, we could expect prices for these two commodities to be weak. In addition, as long as the crude to natural gas price ratio remains wide, NGLs production may continue to be high, which may put downward pressure on the entire NGLs stream.

Natural gas prices are much more affected by domestic issues (as compared to crude oil prices), such as weather (particularly extreme heat or cold), supply, local demand issues and domestic economic conditions, and they have historically been subject to substantial fluctuation. During the first half of 2012, our average realized sales price of natural gas (unhedged) decreased 41.0% from the first half of 2011 to $2.58 per Mcf. A comparable bench mark is the Henry Hub unweighted average daily posted spot price, which decreased 44.7% from the comparable period. We expect continued weakness in natural gas prices for a number of reasons, including (i) producers continuing to drill in order to secure and to hold large lease positions before expiration, particularly in shale and similar resource plays, (ii) natural gas storage levels continuing to build to ever higher levels throughout this injection season, (iii) natural gas continuing to be produced as a by-product in conjunction with the substantial ramp up of oil drilling, (iv) increasing availability of liquefied natural gas and, (v) production efficiency gains are achieved in the shale gas areas resulting from better fracking, horizontal drilling and production techniques. According to a report published in Reuters, the EIA in its July Short-Term Energy Outlook revised upwards its estimate for domestic natural gas production and consumption growth in 2012 due to continued growth from shale formations. In addition, high NGLs prices (until recently) have made the shale plays economic despite the extremely low natural gas prices. The EIA reported that it expected marketed natural gas production in 2012 to rise by 2.8 billion cubic feet per day (“Bcf/d”), or 4.2%, to a record 68.98 Bcf/d. The EIA expects production growth to increase by another 0.69 Bcf/d, or 1%, to 69.67 Bcf/d next year. As a result, we believe natural gas prices may continue to be weak until such time as crude prices weaken (which will in turn decrease drilling activity and decrease the likelihood of producing natural gas as a by product), economic activity increases dramatically or fuel switching increases.

Over the last several months, the United States has experienced significant fuel switching between coal and natural gas in the production of electricity. Consumption of coal and natural gas for producing electricity was at parity recently for the first time in the history of the United States. However, the Energy Department has reduced its estimate of electricity sales in 2012 by 0.3% on forecasts that above-normal temperatures this summer will not match last year’s record heat. Electricity consumption is estimated to average 10.43 billion kilowatt-hours per day this year, down from 10.57 billion kilowatt-hours per day in 2011.

Due to elevated crude oil prices, domestic drilling activity for oil is at high levels and successful oil wells are producing natural gas as a by-product, which as indicated above, contributes to higher natural gas production despite extremely low prices. According to industry sources, the total domestic oil rig count is up over 41% in June 2012 compared to June 2011.

Future price declines for oil, NGLs and natural gas would negatively impact our future revenues, earnings and liquidity, and could result in ceiling test write-downs of the carrying value of our oil and natural gas properties, reductions in proved reserves, issues with financial ratio compliance, and a reduction of the borrowing base associated with our Credit Agreement, depending on the severity of such declines. If those events were to occur and were significant, the willingness of financial institutions and investors to provide capital to us and others in the oil and natural gas industry may be limited.

There continues to be many proposed changes in laws, regulations, guidance and policy in our industry. The process for obtaining offshore drilling permits, especially deep water drilling permits, has expanded and lengthened in the past few years. The most significant regulation changes in the last two years are related to potential environmental impacts, spill response documentation, compliance reviews, operator practices related to safety and implementing a safety and environmental management system. These new regulations and increased review processes increase both the time to obtain drilling permits and 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.

Results of Operations

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


	Three Months Ended June 30,⁽¹⁾												Six Months Ended June 30,⁽¹⁾
	2012			2011			Change			%			2012			2011		Change			%
	(In thousands, except percentages and per share data)
Financial:
Revenues:
Oil	$	153,838		$	169,225		$	(15,387	)		(9.1	)%	$	323,812		$	310,774	$	13,038			4.2	%
NGLs		25,941			24,719			1,222			4.9	%		52,325			42,657		9,668			22.7	%
Natural gas		35,683			58,661			(22,978	)		(39.2	)%		74,119			109,579		(35,460	)		(32.4	)%
Other		51			317			(266	)		(83.9	)%		1,143			767		376			49.0	%

Total revenues		215,513			252,922			(37,409	)		(14.8	)%		451,399			463,777		(12,378	)		(2.7	)%
Operating costs and expenses:
Lease operating expenses		60,276			48,597			11,679			24.0	%		116,938			101,002		15,936			15.8	%
Production taxes		1,335			845			490			58.0	%		2,821			1,133		1,688			149.0	%
Gathering and transportation		4,110			3,797			313			8.2	%		8,330			8,350		(20	)		(0.2	)%
Depreciation, depletion, amortization and accretion		85,941			83,370			2,571			3.1	%		174,432			157,462		16,970			10.8	%
General and administrative expenses		14,623			18,002			(3,379	)		(18.8	)%		44,102			36,131		7,971			22.1	%
Derivative (gain) loss		(49,872	)		(17,332	)		(32,540	)		NM			(10,238	)		6,508		(16,746	)		NM

Total costs and expenses		116,413			137,279			(20,866	)		(15.2	)%		336,385			310,586		25,799			8.3	%

Operating income		99,100			115,643			(16,543	)		(14.3	)%		115,014			153,191		(38,177	)		(24.9	)%
Interest expense, net of amounts capitalized		11,380			9,968			1,412			14.2	%		22,095			18,685		3,410			18.2	%
Loss on extinguishment of debt⁽²⁾		—			20,663			(20,663	)		NM			—			20,663		(20,663	)		NM

Income before income tax expense		87,720			85,012			2,708			3.2	%		92,919			113,843		(20,924	)		(18.4	)%
Income tax expense		34,153			29,837			4,316			14.5	%		36,134			40,019		(3,885	)		(9.7	)%

Net income	$	53,567		$	55,175		$	(1,608	)		(2.9	)%	$	56,785		$	73,824	$	(17,039	)		(23.1	)%

Basic and diluted earnings per common share	$	0.70		$	0.73		$	(0.03	)		(4.1	)%	$	0.75		$	0.98	$	(0.23	)		(23.5	)%

(1)	In the second quarter of 2011, we acquired the Yellow Rose Properties and, in the third quarter of 2011, we acquired the Fairway Properties.

(2)

In May 2011, we entered into the Fourth Amended and Restated Credit Agreement, which replaced our prior credit agreement. Unamortized debt issuance costs of $0.7 million related to the prior 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 $450.0 million principal amount of 8.25% Senior Notes were tendered and repurchased, which resulted in loss on extinguishment of debt of $20.0 million.

NM = percentage change not meaningful


	Three Months Ended June 30, ⁽¹⁾										Six Months Ended June 30, ⁽¹⁾
	2012		2011		Change			%			2012		2011		Change			%
Operating:
Net sales volumes:
Oil (MBbls)		1,451		1,525		(74	)		(4.9	)%		2,991		2,970		21			0.7	%
NGLs (MBbls)		586		420		166			39.5	%		1,130		778		352			45.2	%
Natural gas (MMcf)		14,320		13,174		1,146			8.7	%		28,696		25,052		3,644			14.5	%
Total natural gas and oil (MBoe) (2)		4,423		4,140		283			6.8	%		8,903		7,924		979			12.4	%
Total natural gas and oil (MMcfe) (2)		26,541		24,843		1,698			6.8	%		53,418		47,542		5,876			12.4	%

Average daily equivalent sales (Boe/d) (2)		48,610		45,500		3,110			6.8	%		48,918		43,777		5,141			11.7	%
Average daily equivalent sales (Mcfe/d) (2)		291,659		272,999		18,660			6.8	%		293,506		262,665		30,841			11.7	%

Average realized sales prices (Unhedged):
Oil ($/Bbl)	$	106.04	$	111.00	$	(4.96	)		(4.5	)%	$	108.28	$	104.63	$	3.65			3.5	%
NGLs ($/Bbl)		44.27		58.81		(14.54	)		(24.7	)%		46.31		54.82		(8.51	)		(15.5	)%
Natural gas ($/Mcf)		2.49		4.45		(1.96	)		(44.0	)%		2.58		4.37		(1.79	)		(41.0	)%
Oil equivalent ($/Boe) (2)		48.71		61.01		(12.30	)		(20.2	)%		50.57		58.43		(7.86	)		(13.5	)%
Natural gas equivalent ($/Mcfe) (2)		8.12		10.17		(2.05	)		(20.2	)%		8.43		9.74		(1.31	)		(13.4	)%
Average realized sales prices (Hedged) (3):
Oil ($/Bbl)	$	105.84	$	107.00	$	(1.16	)		(1.1	)%	$	106.24	$	101.82	$	4.42			4.3	%
NGLs ($/Bbl)		44.27		58.81		(14.54	)		(24.7	)%		46.31		54.82		(8.51	)		(15.5	)%
Natural gas ($/Mcf)		2.49		4.45		(1.96	)		(44.0	)%		2.58		4.37		(1.79	)		(41.0	)%
Oil equivalent ($/Boe) (2)		48.64		59.54		(10.90	)		(18.3	)%		49.89		57.38		(7.49	)		(13.1	)%
Natural gas equivalent ($/Mcfe) (2)		8.11		9.92		(1.81	)		(18.2	)%		8.31		9.56		(1.25	)		(13.1	)%
Average per Mcfe ($/Mcfe) (2):
Lease operating expenses	$	2.27	$	1.96	$	0.31			15.8	%	$	2.19	$	2.13	$	0.06			2.8	%
Gathering and transportation		0.15		0.15		—			—			0.16		0.18		(0.02	)		(11.1	)%

Production costs		2.42		2.11		0.31			14.7	%		2.35		2.31		0.04			1.7	%
Production taxes		0.05		0.03		0.02			66.7	%		0.05		0.02		0.03			150.0	%
Depreciation, depletion, amortization and accretion		3.24		3.36		(0.12	)		(3.6	)%		3.27		3.31		(0.04	)		(1.2	)%
General and administrative expenses		0.55		0.73		(0.18	)		(24.7	)%		0.83		0.76		0.07			9.2	%

	$	6.26	$	6.23	$	0.03			0.5	%	$	6.50	$	6.40	$	0.10			1.6	%


Total number of wells drilled (gross):
Offshore		2		1		1			100.0	%		2		2		—			—
Onshore		19		6		13			216.7	%		37		7		30			428.6	%

Total number of productive wells drilled (gross):
Offshore		2		1		1			100.0	%		2		2		—			—
Onshore		19		6		13			216.7	%		37		7		30			428.6	%

(1)	In the second quarter of 2011, we acquired the Yellow Rose Properties and, in the third quarter of 2011, we acquired the Fairway Properties.

(2)

The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy equivalency ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs (totals may not compute due to rounding). The conversion ratio does not assume price equivalency, and the price on an equivalent basis for oil, NGLs and natural gas may differ significantly.

(3)	Data for all periods presented includes the effects of realized gains and losses on commodity derivative contracts, none of which qualified for hedge accounting.


Volume measurements:
Boe – barrel of oil equivalent		MMcf – million cubic feet
Boe/d – barrel of oil equivalent per day		MMcfe – million cubic feet equivalent
MBbls – thousand barrels for crude oil, condensate or NGLs		Mcfe/d – thousand cubic feet equivalent per day
MBoe – thousand barrels of oil equivalent

NM = percentage change not meaningful

Three Months Ended June 30, 2012 Compared to the Three Months Ended June 30, 2011

Revenues. Total revenues decreased $37.4 million to $215.5 million for the second quarter of 2012 as compared to the prior year period. Oil revenues decreased $15.4 million, NGLs revenues increased $1.2 million, natural gas revenues decreased $23.0 million and other revenues decreased $0.2 million. The oil revenue decrease was attributable to a 4.5% decrease in the average realized sales price (unhedged) to $106.04 per barrel for second quarter of 2012, combined with a 4.9% decrease in sales volumes. The sales volume decrease for oil is primarily attributable to natural production declines, partially offset by successful exploration/development efforts and acquisition activities. The NGLs revenue increase was attributable to an increase of 39.5% in sales volumes from the comparable period, and was partially offset by a 24.7% decrease in the average realized sales price (unhedged) to $44.27 per barrel. NGLs average realized prices as a percent of oil average realized prices decreased to 41.7% for the second quarter of 2012 compared to 53.0% for the prior year period. The sales volume increase for NGLs is primarily attributable to acquisition activities. The decrease in natural gas revenue resulted from a 44.0% decrease in the average realized natural gas sales price (unhedged) to $2.49 per Mcf, partially offset by an 8.7% increase in sales volumes. The sales volume increase for natural gas is primarily attributable to properties acquired in the later half of 2011 and successful exploration/development efforts, partially offset by natural production declines.

Production taxes. Production taxes increased to $1.3 million in the second quarter of 2012 compared to $0.8 million in the prior year period primarily due to the properties acquired in 2011 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 increased $0.3 million in the second quarter compared to the prior year period.

Depreciation, depletion, amortization and accretion (“DD&A”). DD&A, including accretion for ARO, decreased to $3.24 per Mcfe in the second quarter of 2012 from $3.36 per Mcfe in the prior year period. On a nominal basis, DD&A increased to $85.9 million in the second quarter of 2012 from $83.4 million in the prior year period. DD&A on a nominal basis increased primarily due to higher production volumes.

General and administrative expenses (“G&A”). G&A decreased to $14.6 million in the second quarter of 2012 from $18.0 million in the prior year period, primarily due to lower incentive compensation expense, increased overhead credits related to joint interest arrangements and lower premiums related to surety bonds, partially offset by higher share-based compensation and higher salaries. G&A on a per Mcfe basis was $0.55 per Mcfe in the second quarter of 2012, compared to $0.73 per Mcfe in the prior year period.

Derivative gains. For the second quarter of 2012 and 2011, we had gains of $49.9 million and $17.3 million, respectively, related to the change in the fair value of our crude oil commodity derivatives as a result of decreases in crude oil prices relative to the prices at the beginning of the period. Although the contracts relate to production for the current and future years, changes in the fair value for all open contracts are recorded currently. For the second quarter of 2012, the gain was comprised of a $0.3 million realized loss and a $50.2 million unrealized gain. For the second quarter of 2011, the gain was comprised of a $6.1 million realized loss and a $23.4 million unrealized gain. For additional information 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 $14.7 million for the second quarter of 2012 from $12.1 million for the prior year period. The amount of our Senior Notes outstanding increased to $600.0 million from $450.0 million due to issuing our 8.50% Senior Notes and repurchasing our 8.25% Senior Notes, which occurred in June 2011. During the second quarter of 2012 and 2011, interest of $3.3 million and $2.1 million, respectively, was capitalized to unevaluated oil and natural gas properties. The increase is primarily attributable to an increase in the dollar amount of unevaluated properties that were acquired in conjunction with the acquisition of the Yellow Rose Properties.

Loss on extinguishment of debt. For the second quarter of 2011, loss on extinguishment of debt was $20.7 million. In May 2011, we entered into the Fourth Amended and Restated Credit Agreement, which replaced our prior credit agreement. Unamortized debt issuance costs of $0.7 million related to our 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 $450.0 million were tendered and repurchased, which resulted in loss on extinguishment of debt of $20.0 million.

Income tax expense. Income tax expense increased to $34.2 million for the second quarter of 2012 compared to $29.8 million for the prior year period. The increase is primarily attributable to the change in the effective tax rate. Our effective tax rate for the second quarter was 38.9% and differed from the federal statutory rate of 35.0% primarily as a result of the recapture of deductions for qualified domestic production activities under Section 199 of the IRC as a function of loss carrybacks to prior years. Our effective tax rate for the second quarter of 2011 was 35.1%, which approximated the federal statutory rate.

Six Months Ended June 30, 2012 Compared to the Six Months Ended June 30, 2011

Revenues. Total revenues decreased $12.4 million to $451.4 million for the first half of 2012 as compared to the prior year period. Oil revenues increased $13.0 million, NGLs revenues increased $9.7 million, natural gas revenues decreased $35.5 million and other revenues increased $0.4 million. The oil revenue increase was attributable to a 3.5% increase in the average realized sales price (unhedged) to $108.28 per barrel for first half of 2012, combined with a 0.7% increase in sales volumes. The change in sales volume for oil was essentially flat as increases from acquisition activities and successful exploration/development efforts were offset by natural production declines. The NGLs revenue increase was attributable to an increase of 45.2% in sales volumes from the comparable period, and was partially offset by a 15.5% decrease in the average realized sales price (unhedged) to $46.31 per barrel for the first half of 2012. NGLs average realized prices as a percent of oil average realized prices decreased to 42.8% for the first half of 2012 compared to 52.4% for the prior year period. The sales volume increase for NGLs is primarily attributable to acquisition activities. The decrease in natural gas revenue resulted from a 41.0% decrease in the average realized natural gas sales price (unhedged) to $2.58 per Mcf in the first half of 2012, partially offset by a 14.5% increase in sales volumes. The sales volume increase for natural gas is primarily attributable to increases associated with properties acquired in the later half of 2011, the Main Pass 108 fields resuming production and successful exploration/development efforts, and was partially offset by natural production declines. Revenues from oil and liquids increased as a percent of our total revenues, increasing to 83.3% for the first half of 2012 compared to 76.2% for the prior year period.

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 $15.9 million to $116.9 million in the first half of 2012 compared to the prior year period. On a per Mcfe basis, lease operating expenses were $2.19 per Mcfe during the first half 2012 compared to $2.13 per Mcfe during the comparable 2011 period. On a component basis, base lease operating expenses, insurance premiums and workover expenses increased $14.9 million, $3.3 million and $1.9 million, respectively. As a partial offset, facilities expense and hurricane remediation costs net of insurance claims decreased $3.4 million and $0.8 million, respectively. The increase in base lease operating expenses is primarily attributable to our Yellow Rose and Fairway properties acquired in 2011. The increase in insurance premiums is attributable to increases effective with the June 1, 2011 renewal, which included a substantial expansion in coverage. Workover costs increased in our onshore operations, which had minimal expense in 2011. The decrease in facilities expense is primarily attributable to pipeline repairs at our Ship Shoal 300 field and work on newly acquired deepwater properties, which were completed in the 2011 period that did not reoccur in the comparable period in 2012. Hurricane remediation costs net of insurance claims decreased as there were minimal net costs in the first half of 2012 compared to net costs incurred in the prior year period related to returns of previously received insurance reimbursements.

Production taxes. Production taxes increased to $2.8 million in the first half of 2012 compared to $1.1 million in the prior year period primarily due to acquisition activities 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 in the first half compared to the prior year period.

Depreciation, depletion, amortization and accretion. DD&A, including accretion for ARO, decreased to $3.27 per Mcfe in the first half of 2012 from $3.31 per Mcfe in the prior year period. On a nominal basis, DD&A increased to $174.4 million in the first half of 2012 from $157.5 million in the prior year period. DD&A on a nominal basis increased primarily due to higher production volumes.

General and administrative expenses. G&A increased to $44.1 million in the first half of 2012 from $36.1 million in the prior year period, primarily due to increased legal, compensation, and benefit expense, partially offset by lower incentive compensation expense and increased overhead credits related to joint interest arrangements. G&A on a per Mcfe basis was $0.83 per Mcfe in the first half of 2012, compared to $0.76 per Mcfe in the prior year period.

Derivative gains and losses. For the first half of 2012 and 2011, we had a $10.2 million gain and a $6.5 million loss, respectively, related to the change in the fair value of our crude oil commodity derivatives as a result of changes in crude oil prices relative to the prices at the beginning of the period. Although the contracts relate to production for the current and future years, changes in the fair value for all open contracts are recorded currently. For the first half of 2012, the gain was comprised of a $6.1 million realized loss and a $16.3 million unrealized gain. For the first half of 2011, the loss was comprised of a $8.3 million realized loss and a $1.8 million unrealized gain. For additional information 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 $28.6 million for the first half of 2012 from $22.2 million for the prior year period. The amount of our Senior Notes outstanding increased to $600.0 million from $450.0 million due to issuing our 8.50% Senior Notes and repurchasing our 8.25% Senior Notes, which occurred in June 2011. During the first half of 2012 and 2011, interest of $6.5 million and $3.5 million, respectively, was capitalized to unevaluated oil and natural gas properties. The increase is primarily attributable to an increase in the dollar amount of unevaluated properties that were acquired in conjunction with the acquisition of the Yellow Rose Properties.

Loss on extinguishment of debt. For the first half of 2011, loss on extinguishment of debt was $20.7 million. In May 2011, we entered into the Fourth Amended and Restated Credit Agreement, which replaced our prior credit agreement. Unamortized debt issuance costs of $0.7 million related to our 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.

Income tax expense. Income tax expense decreased to $36.1 million for the first half of 2012 compared to $40.0 million for the prior year period. The decrease is primarily attributable to the change in pre-tax income and was partially offset by the increase in the effective tax rate. Our effective tax rate for the first half of 2012 was 38.9% and differed from the federal statutory rate of 35.0% primarily as a result of the recapture of deductions for qualified domestic production activities under Section 199 of the IRC as a function of loss carrybacks to prior years. Our effective tax rate for the first half of 2011 was 35.2%, which approximated the federal statutory rate.

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 interest and dividends payments. We have funded such activities with cash on hand, cash provided by operating activities, 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 in the first half of 2012 was $241.3 million, compared to $229.8 million in the first half of 2011. The increase was primarily due to decreases in working capital, increased production volumes and lower income tax payments. This increase was partially offset by decreases in prices for natural gas and NGLs and higher lease operating expenses. Our combined production of oil, NGLs and natural gas on a Mcfe basis during the first half of 2012 was 12.4% higher than the first half of 2011, but our combined average realized sales price (hedged) per Mcfe was 13.4% lower than the comparable 2011 period.

Net cash used in investing activities during the first half of 2012 and 2011 was $188.3 million and $483.0 million, respectively, which represents our investments in oil and gas properties, both offshore and onshore. The 2012 period reflects increased investments in oil and gas properties of $187.3 million, which includes increased drilling activity. The 2011 period includes the acquisition of the Yellow Rose Properties of $397.0 million and investments of $85.8 million in oil and gas properties. There were no acquisitions completed in the first half of 2012.

Net cash used in financing activities was $49.0 million during the first half of 2012 and net cash provided by financing activities was $233.2 million during the first half 2011. The cash used in the first half of 2012 was primarily attributable to net pay downs on the revolving bank credit facility of $37.0 million and $11.9 million of dividend payments. The cash provided in the first half of 2011 was attributable to net borrowings on the revolving bank credit facility of $75.0 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.

At June 30, 2012, we had a cash balance of $8.6 million and $569.4 million of undrawn capacity available under the revolving bank credit facility, which had a borrowing base of $650.0 million as of June 30, 2012.

Credit Agreement and long-term debt. At June 30, 2012 and December 31, 2011, $80.0 million and $117.0 million, respectively, were outstanding under our revolving bank credit facility. During the six months ended June 30, 2012, the outstanding borrowings on our revolving bank credit facility ranged from $44.0 million to $145.0 million. At June 30, 2012 and December 31, 2011, $600.0 million in aggregate principal amount of our 8.50% Senior Notes was outstanding. 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, but additional financing may be required if we are successful in finding suitable acquisitions. For additional information about our long-term debt, refer to Financial Statements – Note 6 – Long-Term Debt under Part I, Item 1 of this Form 10-Q.

Availability under our revolving bank credit facility is subject to a semi-annual redetermination of our borrowing base that occurs in the spring and fall of each year and is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria. On May 7, 2012, we executed the First Amendment to the Fourth Amended and Restated Credit Agreement (the “Amendment”), which, among other things, increased the number of participating lenders, increased the borrowing base from $575.0 million to $650.0 million and added a provision permitting the Company to maintain security interest in favor of any hedging counterparties that cease to be lenders under the Company’s revolving bank credit facility. All other terms of the Credit Agreement remain substantially the same prior to the Amendment. We currently have 17 lenders within the revolving bank credit facility, with commitments ranging from $20.0 million to $55.0 million for the current borrowing base of $650.0 million. While we have not experienced, nor do we anticipate, any difficulties in obtaining funding from any of these lenders at this time, any lack of or delay in funding by members of our banking group could negatively impact our liquidity position.

The Credit Agreement contains two financial covenants calculated as of the last day of each fiscal quarter, comprised of 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 and all applicable covenants related to the 8.50% Senior Notes as of June 30, 2012.

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, 2012, our derivative instruments outstanding consisted of oil contracts relating to approximately 1.0 MMBbls, 1.3 MMBbls and 0.7 MMBbls of our anticipated production for the balance of 2012 and the years 2013 and 2014, respectively. See Financial Statements – Note 5– Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q for additional information.

Hurricane Remediation, Insurance Claims and Insurance. During the third quarter of 2008, Hurricane Ike caused substantial property damage and we continue to incur costs and submit claims to our insurance underwriters related to repairing such damage. Our insurance policies in effect on the occurrence date of Hurricane Ike had a retention requirement of $10.0 million per occurrence, which has been satisfied, and coverage policy limits of $150.0 million for property damage due to named windstorms (excluding damage at certain facilities) and $250.0 million for, among other things, removal of wreckage if mandated by any governmental authority.

From the third quarter of 2008 through June 30, 2012, we have received $140.0 million from our insurance carrier related to Hurricane Ike. As of June 30, 2012, we did not have any insurance receivables for claims that have been submitted and approved for payment. As of June 30, 2012, we have recorded in ARO an estimate of $21.1 million for additional costs to be incurred related to Hurricane Ike and we have estimated this work will be completed in 2013. 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. We believe at this time that covered costs under the applicable policies will not exceed policy limits. 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.

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 $100.0 million and $140.0 million, respectively, and the policies are effective until June 1, 2013. We carry an additional $100.0 million of well control coverage effective until June 1, 2013 on certain wells at our Mahogany, Matterhorn, Virgo, Main Pass 107/108, Tahoe and SE Tahoe fields. A retention amount of $5.0 million for well control events and $40.5 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. We estimate that approximately 98% of the estimated future net revenues discounted at 10% (“PV-10”) attributable to our Gulf of Mexico properties are on platforms that are covered under our current insurance policies for named windstorm 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 is effective until May 1, 2013 and provides for $250.0 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 requirement under the Ocean Pollution Act, we are required to evidence $150.0 million of financial responsibility to the Bureau of Safety and Environmental Enforcement. We qualify to self-insure for $35.0 million of this amount and the remaining $115.0 million is covered by insurance.

We renewed our well control and hurricane damage, and general and excess liability policies in the second quarter of 2012. 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 there could be an 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 claims, the insurers will not pay our claims. 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, NGLs and natural gas, acquisition opportunities, and the results of our exploration and development activities. The following table presents our capital expenditures for exploration, development and other leasehold costs and acquisitions:


	Six Months Ended June 30,
	2012		2011
	(in thousands)
Acquisition of Yellow Rose Properties	$	—	$	396,976
Exploration (1)		36,939		20,891
Development (1)		141,989		52,229
Seismic, capitalized interest, other leasehold costs		8,356		12,681

Acquisitions and investments in oil and gas property/equipment	$	187,284	$	482,777

(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,
	2012		2011
	(in thousands)
Conventional shelf	$	44,246	$	52,387
Deepwater		31,128		2,195
Deep shelf		2,418		31
Onshore		101,136		18,507

Exploration and development capital expenditures	$	178,928	$	73,120

Our first half 2012 capital expenditures were financed by cash flow from operating activities and cash on hand. Our first half 2011 capital expenditures were financed by additional borrowings, cash flow from operating activities and cash on hand.

The following table presents our wells drilled based on a completed basis:


	Six Months Ended June 30,
	2012				2011
	Gross		Net		Gross		Net
Development wells:
Offshore wells:
Productive		2		2.0		1		1.0
Dry		—		—		—		—

Onshore wells:
Productive		21		21.0		6		6.0
Dry		—		—		—		—

Total development wells		23		23.0		7		7.0


Exploration wells:
Offshore wells:
Productive		—		—		1		1.0
Dry		—		—		—		—

Onshore wells:
Productive		16		13.1		1		0.5
Dry		—		—		—		—

Total exploration wells		16		13.1		2		1.5

Total wells		39		36.1		9		8.5

Our total capital expenditure budget for 2012 is $425.0 million, not including any potential acquisitions. The budget includes $209.0 million to drill, evaluate and complete ten offshore wells (six exploration and four development wells) and $170.0 million to drill, evaluate and complete 65 onshore wells (19 exploration and 46 development wells). The budget also includes $46.0 million for facilities capital, recompletions, seismic and leasehold items. Our 2012 capital budget is subject to change as conditions warrant and we strive to be as flexible as possible.

We intend to continue to pursue acquisitions and joint venture opportunities during 2012 should attractive opportunities arise. We are actively evaluating opportunities and expect to complement our drilling and development projects with acquisitions providing acceptable rates of return. We anticipate funding our 2012 capital budget and acquisitions with internally generated cash flow, cash on hand, borrowings under our revolving bank credit facility, and accessing the capital markets to the extent necessary.

On May 15, 2012, we sold our 40%, non-operating working interest in the South Timbalier 41 field located in the Gulf of Mexico for $30.5 million. The transaction was structured as a like-kind exchange under the IRC section 1031 and other applicable regulations, with funds held by a qualified intermediary until a replacement purchase is executed. We expect to complete the purchase side of the transaction by year end. In connection with this sale, we reversed $4.0 million of ARO.

Income taxes. During the six months ended June 30, 2012, we made tax payments of $10.4 million and received refunds of $0.4 million. During the six months ended June 30, 2011, we made tax payments of $19.1 million and did not receive any refunds. For the remainder of 2012, we expect a substantial amount of our income tax will be deferred and expect payments to be primarily related to alternative minimum tax.

Dividends. During the first half of 2012 and 2011, we paid regular cash dividends of $0.08 and $0.04 per common share each quarter, respectively. The dividend of $0.08 per share per quarter in the first half of 2012 represents a 100% increase to the regular dividend per share of $0.04 paid in each of the quarters of 2011. On July 30, 2012, our board of directors declared a cash dividend of $0.08 per common share, payable on September 12, 2012 to shareholders of record on August 22, 2012.

Contractual obligations. Updated information on certain contractual obligations is provided in Financial Statements –Note 4 – Asset Retirement Obligations and Financial Statements –Note 6 – Long Term Debt under Part I, Item 1 of this Form 10-Q. As of June 30, 2012, drilling rig commitments were approximately $36.9 million compared to $33.8 million as of December 31, 2011. The current drilling rig commitments all expire within one year from June 30, 2012. Other contractual obligations as of June 30, 2012 did not change materially, except for scheduled utilization, from the disclosures in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2011.

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, 2011. Also refer to the Notes to Condensed Consolidated Financial Statements under 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 half of 2012 did not change materially from the disclosures in Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2011. 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, 2011.

Commodity Price Risk. Our revenues, profitability and future rate of growth substantially depend upon market prices of oil, NGLs and natural gas, which fluctuate widely. Oil, NGLs and natural gas price declines and volatility could adversely affect our revenues, net cash provided by operating activities and profitability. We currently have open crude oil derivative contracts to manage a portion of our exposure to commodity price risk from sales of oil for the balance of 2012 and the years 2013 and 2014. As of June 30, 2012, these derivative contracts had a notional quantity of 3.0 MMBbls. We do not designate our commodity derivatives as hedging instruments. While these contracts are intended to reduce the effects of volatile oil prices, they may also limit future income from favorable price movements. See Financial Statements – Note 5– Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q for additional information.

Interest Rate Risk. As of June 30, 2012, we had $80.0 million outstanding on our revolving bank credit facility. The revolving bank credit facility has a variable interest rate, which is primarily impacted by the rates for the LIBOR and the margin, which ranges from 2.00% to 2.75% depending on the amount outstanding. We currently do not have any derivative instruments related to interest rates.

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, 2012 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, 2012, 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

The United States Attorney’s Office for the Eastern District of Louisiana, along with the Criminal Investigation Division of the EPA, has been conducting a federal grand jury investigation of environmental compliance matters relating to surface discharges and reporting on four of our offshore platforms in the Gulf of Mexico. We are fully cooperating with the investigation which began in late 2010 and is currently ongoing. The United States Attorney’s Office has informed us that it is continuing its investigation with the intent to seek a criminal disposition. The outcome of this investigation could have a material adverse effect upon us. We are not able at this time to estimate our potential exposure, if any, related to this matter.

From time to time, we are party to other litigation or legal and administrative proceedings that we consider to be a part of the ordinary course of our business. Except for the matters noted above, we are not involved in any legal proceedings nor are we party to any pending or threatened claims that could, individually or in the aggregate, reasonably be expected to have a material adverse effect on our financial condition, cash flow or results of operations.

Item 1A.

Risk Factors

Investors should carefully consider the risk factors included under Risk Factors under Part I, Item 1A in our Annual Report on Form 10-K for the year ended December 31, 2011, together with all of the other information included in this document, in our Annual Report on Form 10-K and in our other public filings, press releases and discussions with our management. Notwithstanding the matters discussed herein, there have been no material changes in our risk factors as previously disclosed in Part I, Item 1A in our Annual Report on Form 10-K for the year ended December 31, 2011.

Item 6.

Exhibits

The exhibits to this report are listed in the Exhibit Index following the signature page of this report.

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 July 31, 2012.


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

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))

3.3*		Certificate of Amendment to the Amended and Restated Articles of Incorporation of W&T Offshore, Inc.

10.1		First Amendment to the Fourth Amended and Restated Credit Agreement, dated May 7, 2012, by and among W&T Offshore, Inc, Toronto Dominion (Texas) LLC as agent and 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 10, 2012)

10.2+*		Form of Executive Restricted Stock Unit Agreement as of April 26, 2012.

10.3+		Form of Employment Agreement by and between W&T Offshore, Inc. and Thomas P. Murphy (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed August 6, 2010)

10.4		Indemnification and Hold Harmless Agreement by and between W&T Offshore, Inc. and Thomas P. Murphy, dated as of June 19, 2012. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed June 22, 2012)

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 herewith.

**	Furnished herewith.

+	Management contract or compensatory plan or arrangement.

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company