Edgar Filing: W&T OFFSHORE INC

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 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 x No ¨

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

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

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

As of October 29, 2012, there were 74,370,825 shares outstanding of the registrant’s common stock, par value $0.00001.

W&T OFFSHORE, INC. AND SUBSIDIARIES

TABLE OF CONTENTS


		Page

PART I – FINANCIAL INFORMATION

Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011		1
	Condensed Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2012 and 2011		2
	Condensed Consolidated Statement of Changes in Shareholders’ Equity for the Nine Months Ended September 30, 2012		3
	Condensed Consolidated Statements of Cash Flows for the Three and Nine Months Ended September 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		26

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		37

Item 4.	Controls and Procedures		38

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings		38

Item 1A.	Risk Factors		39

Item 6.	Exhibits		39

SIGNATURE			40

EXHIBIT INDEX			41

PART I – FINANCIAL INFORMATION

Item 1.

Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30,			December 31,
	2012			2011
	(In thousands, except share data)
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	6,993		$	4,512
Receivables:
Oil and natural gas sales		68,230			98,550
Joint interest and other		21,105			25,804
Income tax receivable		14,284			—

Total receivables		103,619			124,354
Deferred income taxes – current portion		—			2,007
Restricted cash and cash equivalents		24,026			—
Deposit for acquisition		22,800			—
Prepaid expenses and other assets		32,455			30,315

Total current assets		189,893			161,188
Property and equipment – at cost:
Oil and natural gas properties and equipment (full cost method, of which $158,585 at September 30, 2012 and $154,516 at December 31, 2011 were excluded from amortization)		6,229,626			5,959,016
Furniture, fixtures and other		20,912			19,500

Total property and equipment		6,250,538			5,978,516
Less accumulated depreciation, depletion and amortization		4,556,548			4,320,410

Net property and equipment		1,693,990			1,658,106
Restricted deposits for asset retirement obligations		28,441			33,462
Other assets		14,328			16,169

Total assets	$	1,926,652		$	1,868,925


Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	104,274		$	75,871
Undistributed oil and natural gas proceeds		34,660			33,732
Asset retirement obligations		83,545			138,185
Accrued liabilities		32,331			29,705
Income taxes payable		350			10,392
Deferred income taxes – current portion		2,945			—

Total current liabilities		258,105			287,885
Long-term debt		719,000			717,000
Asset retirement obligations, less current portion		250,704			255,695
Deferred income taxes		98,393			58,881
Other liabilities		9,470			4,890
Commitments and contingencies		—			—
Shareholders’ equity:
Preferred stock, $0.00001 par value; 20,000,000 shares authorized; 0 issued at September 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 September 30, 2012; and 77,220,706 issued and 74,351,533 outstanding at December 31, 2011		1			1
Additional paid-in capital		396,601			386,920
Retained earnings		218,545			181,820
Treasury stock, at cost		(24,167	)		(24,167	)

Total shareholders’ equity		590,980			544,574

Total liabilities and shareholders’ equity	$	1,926,652		$	1,868,925

See Notes to Condensed Consolidated Financial Statements.

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
	(In thousands, except per share data)
	(Unaudited)

Revenues	$	185,946		$	245,371		$	637,345		$	709,148


Operating costs and expenses:
Lease operating expenses		53,411			58,899			170,349			159,901
Production taxes		1,353			1,050			4,174			2,183
Gathering and transportation		2,810			4,853			11,140			13,203
Depreciation, depletion, amortization and accretion		77,462			84,455			251,894			241,917
General and administrative expenses		18,691			18,104			62,793			54,235
Derivative (gain) loss		24,659			(17,323	)		14,421			(10,815	)

Total costs and expenses		178,386			150,038			514,771			460,624

Operating income		7,560			95,333			122,574			248,524
Interest expense:
Incurred		14,791			14,721			43,409			36,913
Capitalized		(3,383	)		(3,163	)		(9,899	)		(6,654	)
Loss on extinguishment of debt		—			2,031			—			22,694
Other income		202			6			210			22

Income (loss) before income tax expense		(3,646	)		81,750			89,274			195,593
Income tax expense (benefit)		(2,175	)		28,822			33,959			68,841

Net income (loss)	$	(1,471	)	$	52,928		$	55,315		$	126,752


Basic and diluted earnings (loss) per common share	$	(0.02	)	$	0.70		$	0.73		$	1.68
Dividends declared per common share	$	0.08		$	0.04		$	0.24		$	0.12

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										Total
	Common Stock Outstanding				Paid-In		Retained			Treasury Stock					Shareholders’
	Shares		Value		Capital		Earnings			Shares		Value			Equity
	(In thousands)
	(Unaudited)

Balances at December 31, 2011		74,352	$	1	$	386,920	$	181,820			2,869	$	(24,167	)	$	544,574
Cash dividends		—		—		—		(17,848	)		—		—			(17,848	)
Share-based compensation		21		—		9,137		—			—		—			9,137
Other		—		—		544		(742	)		—		—			(198	)
Net income		—		—		—		55,315			—		—			55,315

Balances at September 30, 2012		74,373	$	1	$	396,601	$	218,545			2,869	$	(24,167	)	$	590,980

See Notes to Condensed Consolidated Financial Statements.

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Nine Months Ended September 30,
	2012			2011
	(In thousands)
	(Unaudited)
Operating activities:
Net income	$	55,315		$	126,752
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		251,894			241,917
Amortization of debt issuance costs		2,046			1,401
Loss on extinguishment of debt		—			22,694
Share-based compensation		9,137			6,437
Derivative (gain) loss		14,421			(10,815	)
Cash payments on derivative settlements		(6,960	)		(9,239	)
Deferred income taxes		44,465			59,442
Changes in operating assets and liabilities:
Oil and natural gas receivables		30,320			(2,913	)
Joint interest and other receivables		3,935			7,465
Insurance receivables		500			18,971
Income taxes		(24,327	)		(15,894	)
Prepaid expenses and other assets		670			(22,601	)
Asset retirement obligations		(63,150	)		(51,349	)
Accounts payable and accrued liabilities		32,311			23,892
Other liabilities		912			(109	)

Net cash provided by operating activities		351,489			396,051


Investing activities:
Acquisitions of property interests in oil and natural gas properties		—			(434,582	)
Investment in oil and natural gas properties and equipment		(312,372	)		(185,222	)
Proceeds from sales of oil and natural gas properties and equipment		30,453			15
Change in restricted cash		(24,026	)		—
Deposit for acquisition		(22,800	)		—
Purchases of furniture, fixtures and other		(2,125	)		(318	)

Net cash used in investing activities		(330,870	)		(620,107	)


Financing activities:
Issuance of 8.50% Senior Notes		—			600,000
Repurchase of 8.25% Senior Notes		—			(450,000	)
Borrowings of long-term debt – revolving bank credit facility		316,000			512,000
Repayments of long-term debt – revolving bank credit facility		(314,000	)		(418,000	)
Repurchase premium and debt issuance costs		(2,081	)		(31,997	)
Dividends to shareholders		(17,848	)		(8,936	)
Other		(209	)		—

Net cash (used in) provided by financing activities		(18,138	)		203,067

Increase (decrease) in cash and cash equivalents		2,481			(20,989	)
Cash and cash equivalents, beginning of period		4,512			28,655

Cash and cash equivalents, end of period	$	6,993		$	7,666

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,” “we” 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. See Note 13 for information on an acquisition completed subsequent to September 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, net, 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 replacement purchases could be executed. Funds remaining from this sale to be used for replacement purchases are reported in current assets as restricted cash and cash equivalents on the balance sheet as of September 30, 2012. In connection with this sale, we reversed $4.0 million of asset retirement obligation (“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 nine months ended September 30, 2012, the purchase price was reduced by $2.7 million. The purchase price is subject to further post-effective date adjustments and final settlement is expected to occur in the first half of 2013. 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	$	47,993
Asset retirement obligations – non-current		(7,812	)

Total cash paid	$	40,181

For the three months ended September 30, 2011, the Yellow Rose Properties and the Fairway Properties accounted for $21.6 million of revenue, $8.8 million of direct operating expenses, $7.2 million of depreciation, depletion, amortization and accretion (“DD&A”) and $2.0 million of income taxes, resulting in $3.6 million of net income. For the nine months ended September 30, 2011, the Yellow Rose Properties and the Fairway Properties accounted for $32.8 million of revenue, $10.7 million of direct operating expenses, $9.6 million of DD&A and $4.4 million of income taxes, resulting in $8.1 million of net income. Such amounts are for the period from each respective close date to September 30, 2011. The net income attributable to these properties does not reflect certain expenses, such as general and administrative expenses and interest expense; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis. In addition, the Yellow Rose Properties and the Fairway Properties are not recorded in a separate entity for tax purposes; therefore, income tax was estimated using the federal statutory tax rate. Expenses associated with acquisition activities and transition activities related to these acquisitions for the three and nine months ended September 30, 2011 were $0.8 million and $1.4 million, respectively, and are included in general and administrative expenses.

Pro Forma Financial Information

Pro forma financial information has been prepared due to the Yellow Rose Properties being significant. The Fairway Properties acquisition, which was not significant, was combined with the Yellow Rose Properties to disclose the effect of both acquisitions. The unaudited pro forma financial information was computed as if these two acquisitions had been completed on January 1, 2010. The historical financial information is derived from the unaudited historical consolidated financial statements of W&T and the unaudited historical statements of the sellers.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The pro forma adjustments were based on estimates by management and information believed to be directly related to the purchase of the Yellow Rose Properties and the Fairway Properties. The pro forma financial information is not necessarily indicative of the results of operations had the acquisitions occurred on January 1, 2010. If the transactions had been in effect for the periods indicated, the results may have been substantially different. For example, we may have operated the assets differently than the sellers, realized sales prices may have been different and costs of operating the properties may have been different. The following table presents a summary of our pro forma condensed combined statements of income for the three and nine months ended September 30, 2011 (in thousands except earnings per share):


	Three Months Ended, September 30,		Nine Months Ended, September 30,
	2011		2011

Revenue	$	250,257	$	761,531
Net income		56,207		139,134
Basic and diluted earnings per common share		0.74		1.84

For this pro forma financial information, we assumed the transactions were financed with borrowings from the revolving bank credit facility because the cash and cash equivalents balances for the assumed acquisition date was less than the cash and cash equivalents on hand used on the actual closing dates of the two acquisitions. Also, we assumed that the revolving bank credit facility capacity would have been increased due to the increase in reserves.

The following adjustments were made in the preparation of the condensed combined statement of income:

(a)

Revenues and direct operating expenses for the Yellow Rose Properties and the Fairway Properties were derived from the historical records of the sellers up to the respective closing dates.

(b)

DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Yellow Rose Properties and Fairway Properties costs, reserves and production into the computation. The purchase price allocation included $82.6 million allocated to the pool of unevaluated properties for oil and gas interests. Accordingly, no DD&A expense was estimated for the unevaluated properties.

(c)

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

(d)

Incremental transaction expenses related to the acquisitions for the three and nine months ended September 30, 2011 were $0.8 million and $1.4 million, respectively, and were assumed to be funded from cash on hand.

(e)

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

(f)

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

(g)

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

2011 Divestitures. There were no material divestitures completed during the nine months ended September 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

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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 ARO.

From the third quarter of 2008 through September 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.

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 since December 31, 2011 is as follows (in thousands):


Balance, December 31, 2011	$	393,880
Liabilities settled		(63,150	)
Accretion of discount		15,043
Disposition of properties		(3,993	)
Liabilities incurred		486
Revisions of estimated liabilities due to Hurricane Ike (1)		(29,571	)
Revisions of estimated liabilities – all other (2)		21,554

Balance, September 30, 2012		334,249
Less current portion		83,545

Long-term	$	250,704

(1)

During the nine months ended September 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.

(2)	The majority of the increase is attributable to properties that we do not operate.

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. All of the derivative counterparties are also lenders or affiliates of lenders participating in our revolving bank credit facility. We are exposed to credit loss in the event of nonperformance by the derivative counterparties; however, we do not currently anticipate that any of our derivative counterparties will be unable to fulfill their contractual obligations. Additional collateral is not required by us due to the derivative counterparties’ collateral rights as lenders and we do not require collateral from our derivative counterparties. Our derivative agreements allow for netting of derivative gains and losses upon settlement. If an event of default were to occur causing an acceleration of payment under our revolving bank credit facility, that event may also trigger an acceleration of settlement of our derivative instruments.

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. We have elected not to designate our commodity derivatives as hedging instruments, therefore, all changes in the fair value of derivative contracts are recognized currently in earnings. For additional information about fair value measurements, refer to Note 7.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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 nine months ended September 30, 2012 and 2011, our derivative contracts consisted entirely of crude oil contracts. The zero cost collars are priced off the West Texas Intermediate (“WTI”) 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. Although our Gulf of Mexico crude oil is based off the WTI crude oil price plus a premium, the realized prices received for the types of crude oil have been closer to the Brent crude oil price because of competition with foreign supplied crude oil, which is based off the Brent crude oil price. Therefore, we entered into swap oil contracts priced off the Brent crude oil price to mitigate a portion of the price risk associated with our Gulf of Mexico crude oil production.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

As of September 30, 2012, our open commodity derivative contracts were as follows:

Zero Cost Collars – Oil (NYMEX)

Termination Period

Notional
Quantity (Bbls)

Weighted Average
Contract Price

Fair Value
Liability
(in thousands)

Floor

Ceiling

2012:

4th quarter

251,000

75.00

98.99

345


Swaps – Oil (ICE)
Termination Period		Notional Quantity (Bbls)		Weighted Average Contract Price		Fair Value Liability (in thousands)
2012:	4th quarter		257,600	$	107.28	$	977
2013:	1st quarter		351,000		101.97		2,501
	2nd quarter		336,700		101.97		1,862
	3rd quarter		312,800		101.98		1,265
	4th quarter		294,400		101.98		805
2014:	1st quarter		180,000		97.38		1,073
	2nd quarter		172,900		97.38		807
	3rd quarter		165,600		97.38		573
	4th quarter		156,400		97.37		365

			2,227,400	$	101.19	$	10,228

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


	September 30, 2012		December 31, 2011
Prepaid and other assets	$	—	$	2,341
Other assets		—		1,746
Accrued liabilities		6,950		7,199
Other liabilities		3,623		—

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 September 30,					Nine Months Ended September 30,
	2012		2011			2012		2011
Derivative (gain) loss:
Realized	$	875	$	917		$	6,960	$	9,239
Unrealized		23,784		(18,240	)		7,461		(20,054	)

Total	$	24,659	$	(17,323	)	$	14,421	$	(10,815	)

6. Long-Term Debt

At September 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 September 30, 2012.

See Note 13 for information on additional senior notes issued subsequent to September 30, 2012.

The Fourth Amended and Restated Credit Agreement, as amended, (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 “First 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.

See Note 13 for information on an additional amendment to the Credit Agreement executed subsequent to September 30, 2012.

At September 30, 2012 and December 31, 2011, we had $119.0 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 bank credit facility was classified as long-term at the carrying value. The estimated annual effective interest rate was 4.8% for borrowings under the revolving bank credit facility for the nine months ended September 30, 2012. The estimated annual effective interest rate includes amortization of debt issuance costs and excludes commitment fees and other costs. As of September 30, 2012, our borrowing base was $650.0 million and our borrowing capacity availability was $530.4 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 September 30, 2012.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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

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).


			September 30, 2012				December 31, 2011
	Hierarchy		Assets		Liabilities		Assets		Liabilities
Commodity derivatives		Level 2	$	—	$	10,573	$	4,087	$	7,199
8.50% Senior Notes		Level 2		—		648,000		—		612,000
Revolving bank credit facility		Level 2		—		119,000		—		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 to 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 September 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. As of September 30, 2012, the Company had 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. The fair value of restricted stock was estimated by using the Company’s closing price on the grant date.

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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, September 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 nine months ended September 30, 2012 and 2011 was $0.4 million and $0.5 million, respectively. The fair value of restricted shares that vested during the nine months ended September 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 2012, 10% of the award conditioned on achieving total shareholder return (“TSR”) targets for 2012, 10% of the award conditioned on achieving TSR targets for 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”) ranging from 0.15% to 0.72% 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. The fair value of the 2010 and 2011 RSUs was estimated by using the Company’s closing price on the grant date.

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 after achieving the specified performance requirement for that component of the RSUs.

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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)		764,478			18.64
Vested		—			—
Forfeited		(53,199	)		21.59

Outstanding RSUs, September 30, 2012 (2)		2,443,982		$	15.76

(1)

Grants for the 2012 RSUs are subject to adjustment once the specified performance requirements can be measured. As of September 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 864,867 RSUs as of September 30, 2012.

(2)

Subject to the satisfaction of service conditions, 1,198,208 and 493,716 RSUs will vest in 2012 and 2013, respectively. Subject to the satisfaction of performance and service conditions, 752,058 RSUs will vest in 2014, which may be increased up to 864,867 RSUs depending on the specified performance results.

During the nine months ended September 30, 2011, there were 534,375 grants and no RSUs vested.

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 September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Share-based compensation expense from:
Restricted stock	$	110	$	593	$	324	$	1,784
Restricted stock units		3,209		2,182		8,813		4,653

Total	$	3,319	$	2,775	$	9,137	$	6,437


Share-based compensation tax benefit:
Tax benefit computed at the statutory rate	$	1,162	$	971	$	3,198	$	2,253

As of September 30, 2012, unrecognized share-based compensation expense related to our outstanding restricted shares and RSUs was $0.7 million and $14.0 million, respectively. Unrecognized compensation expense will be recognized through April 2015 for restricted shares and through November 2014 for RSUs.

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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 September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Share-based compensation expense included in:
Lease operating expense	$	—	$	116	$	—	$	349
General and administrative		3,319		2,659		9,137		6,088

Total charged to operating income		3,319		2,775		9,137		6,437


Cash-based incentive compensation included in:
Lease operating expense		947		697		2,846		2,836
General and administrative		3,048		3,024		4,926		9,175

Total charged to operating income		3,995		3,721		7,772		12,011


Total incentive compensation charged to operating income	$	7,314	$	6,496	$	16,909	$	18,448

9. Income Taxes

During the three and nine months ended September 30, 2012, we recorded an income tax benefit of $2.2 million and income tax expense of $34.0 million, respectively. Our effective tax rate for the three and nine months ended September 30, 2012 was 59.7% and 38.0%, respectively. The tax benefit in the third quarter exceeded the amount computed at the statutory rate of 35.0% as a result of a decrease in our full year forecasted effective tax rate. The effective tax rate for the third quarter of 2012 is not representative of the effective tax rate going forward. The rate for the nine month period differed from the federal statutory rate 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. The effective tax rate for the nine months ended September 30, 2012 agrees to our full year forecasted effective tax rate of 38.0%. During the three and nine months ended September 30, 2011, we recorded income tax expense of $28.8 million and $68.8 million, respectively. Our effective tax rate for the three and nine months ended September 30, 2011 was 35.3% and 35.2%, respectively, which approximated the federal statutory rate.

As of September 30, 2012 and December 31, 2011, we did not have any unrecognized tax benefit recorded. As of September 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.

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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 September 30,					Nine Months Ended September 30,
	2012			2011		2012		2011
Net income (loss)	$	(1,471	)	$	52,928	$	55,315	$	126,752
Less portion distributed and allocated to nonvested shares		90			1,118		1,128		2,680

Net income (loss) allocated to common shares	$	(1,561	)	$	51,810	$	54,187	$	124,072


Weighted average common shares outstanding		74,327			74,028		74,315		74,017


Basic and diluted earnings (loss) per common share	$	(0.02	)	$	0.70	$	0.73	$	1.68

Shares excluded due to being anti-dilutive (weighted-average)		1,866			1,995		1,823		1,798

11. Dividends

During the nine months ended September 30, 2012 and 2011, we paid regular cash dividends of $0.08 and $0.04 per common share per quarter, respectively. On October 30, 2012, our board of directors declared a cash dividend of $0.08 per common share and a special dividend of $0.47 per common share, payable on December 3, 2012 to shareholders of record on November 16, 2012.

12. Contingencies

Federal Grand Jury Investigation. 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. We are in settlement discussions with the government. 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.

Cameron Parish Louisiana Claim. Certain Cameron Parish land owners filed suits 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 lawsuits, plaintiffs alleged that property they own has been contaminated or otherwise damaged by the defendants’ oil and gas exploration and production activities and they are seeking compensatory and punitive damages. During the third quarter of 2012, we settled the majority of the claims related to this matter and paid $9.0 million. We assessed the remainder of the claims to be probable and have estimated additional payments to be $1.8 million, which were included in our contingent liabilities accrual as of September 30, 2012.

Qui Tam Litigation. The Company was recently served with a complaint in a qui tam action filed under the federal False Claims Act by an employee of a Company contractor. The lawsuit, United States ex rel. Comeaux v. W&T Offshore, Inc., et al.; CA No. 10-494, was filed in the United States District Court for the Eastern District of Louisiana, against the Company and three other working interest owners related to claims associated with three of the Company’s operated production platforms. A qui tam action, also known as a “whistleblower” action, is a lawsuit brought by a private citizen seeking civil penalties or damages against a person or company on behalf of the government for alleged violations of law. If

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

the claims are successful, the person filing the suit may recover a percentage of the damages or penalty from the lawsuit as a reward for exposing a wrongdoing and recovering funds on behalf of the government. The complaint was originally filed in 2010 but kept under confidential seal in order for the federal government to decide if it wished to intervene and take over the prosecution of the qui tam action. The government declined to intervene in this suit and the complaint was unsealed and made public in June 2012, thereby giving the plaintiff the opportunity to pursue the claims on behalf of the government. The complaint was served on the Company on September 21, 2012.

The complaint alleges that environmental violations at three of the Company’s operated production platforms in the Gulf of Mexico violate the federal offshore lease provisions so that the Company, among other things, wrongfully retained benefits under the applicable leases. The alleged environmental violations include allegations of discharges of relatively small amounts of oil into the Gulf of Mexico, the failure to report and record such discharges, and falsification of certain produced water samples and related reports required under federal law. The events are alleged to have occurred in 2009. These are largely the same allegations involved in the ongoing federal grand jury investigation of the Company, which the Company has previously disclosed and in which the Company is fully cooperating.

The Company intends to vigorously defend the claims made in this lawsuit. Since it has only recently been served, the Company has not made any determination of the likelihood of an adverse outcome or the amount or range of any potential loss in the event of an adverse outcome.

Contingent Liability Recorded. During the three and nine months ended September 30, 2012, we recognized expenses related to accrued and settled claims and complaints of $0.4 million and $8.8 million, respectively, and during the three and nine months ended September 30, 2011, we recognized expenses of $0.4 million and $0.2 million, respectively. These expenses are reported in General and administrative expenses on the statement of income and reflect the items noted above and other various claims and complaints. As of September 30, 2012 and December 31, 2011, we have recorded a liability of $1.8 million and $2.0 million, respectively, which is included in Accrued liabilities on the balance sheet, for the loss contingencies matters that include the events described above and other minor environmental and litigation matters which we are addressing in the normal course of business.

Royalties. 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.

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

13. Subsequent Events

Acquisitions

On October 5, 2012, we completed the acquisition of certain oil and gas leasehold interests (the “Newfield Properties”) from Newfield Exploration Company and its subsidiary, Newfield Exploration Gulf Coast LLC (together, “Newfield”). The stated purchase price was $228.0 million, subject to certain adjustments, including adjustments from an effective date of

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

July 1, 2012 until the closing date, October 5, 2012, and the assumption of future ARO. The properties acquired consists of leases covering 78 federal offshore blocks on approximately 432,700 gross acres (416,000 gross acres excluding overriding royalty interests), comprised of 65 blocks in the deepwater, six of which are producing, ten blocks on the conventional shelf, four of which are producing, and an overriding royalty interest in three deepwater blocks, two of which are producing. The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand.

The following table presents the preliminary purchase price allocation, including estimated adjustments, for the acquisition of the Newfield Properties (in thousands):


Oil and natural gas properties and equipment (1)	$	238,004
Asset retirement obligations – current		(7,250	)
Asset retirement obligations – non-current		(23,086	)

Total cash paid	$	207,668

(1)

The allocation to unproved properties amounts is initially estimated at $13.1 million. Amounts recorded as unproved properties are excluded from the full cost pool and amortization base.

Expenses associated with acquisition activities and transition activities related to the acquisition of the Newfield Properties for the nine months ended September 30, 2012 were $0.1 million and are included in general and administrative expenses (“G&A”).

Pro Forma Financial Information

Pro forma financial information has been prepared because the Newfield Properties constitute a significant acquisition. The unaudited pro forma financial information was computed as if the acquisition had been completed on January 1, 2011. The historical financial information is derived from the unaudited historical consolidated financial statements of W&T and the unaudited historical financial statements of Newfield.

The pro forma adjustments were based on estimates by management and information believed to be directly related to the purchase of the Newfield Properties. The pro forma financial information is not necessarily indicative of the results of operations had the purchase occurred on January 1, 2011. If the transaction had been in effect for the periods indicated, the results may have been substantially different. For example, we may have operated the assets differently than Newfield, realized oil, NGLs and natural gas sales prices may have been different and costs of operating the properties may have been different. The following table presents a summary of our pro forma financial information (in thousands except earnings per share):


	(unaudited)
	Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012		2011
Revenue	$	216,954		$	294,370	$	739,766	$	877,944
Net income (loss)		(640	)		62,404		59,879		165,363
Basic and diluted earnings (loss) per common share		(0.01	)		0.82		0.79		2.18

The purchase price of the acquisitions may be subject to further adjustments. At this time, the revenues, operating expenses and ARO include estimates and are subject to change upon further analysis and review. For the pro forma financial information, we assumed the transaction was financed with borrowings from the additional senior notes issued shortly after the acquisition closed.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following adjustments were made in the preparation of the pro forma financial information:

(a)

Revenues and direct operating expenses for the Newfield Properties were derived from the historical financial records of Newfield.

(b)

Depreciation, depletion, amortization and accretion (“DD&A”) was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Newfield Properties’ costs, reserves and production into our currently existing full cost pool in order to compute such amounts. The purchase price allocation included $13.1 million that was allocated to the pool of unevaluated properties for oil and natural gas interests. Accordingly, no DD&A expense was estimated for the unevaluated properties.

(c)

ARO and related accretion were estimated by W&T management.

(d)

Incremental transaction expenses related to the acquisition completed during 2012 were $0.1 million and were assumed to be funded from cash on hand.

(e)

Interest expense was computed using assumed borrowings of $207.7 million, which equates to the cash component of the transaction, and an interest rate of 7.7%, which equates to the effective yield on net proceeds for the additional senior notes issued shortly after the acquisition closed. See below for information on these additional senior notes.

(f)

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

(g)

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

(h)

The 2011 periods do not include any pro forma adjustments related to the 2011 acquisitions as described in Note 2.

Credit Agreement Amendment

On October 12, 2012, we entered into the Second Amendment to the Credit Agreement (the “Second Amendment”) which, among other things, allows for the issuance of additional senior unsecured indebtedness. Following the amendment, we may issue additional senior unsecured indebtedness, however, the borrowing base under the Credit Agreement will be automatically and simultaneously reduced by $0.25 for every $1.00 increase in unsecured indebtedness incurred in excess of the $600.0 million aggregate principal amount of our existing notes until such time as the borrowing base has been redetermined or otherwise adjusted pursuant to the Credit Agreement. All other terms of the Credit Agreement remain substantially the same, including the termination date of May 5, 2015, interest rates spreads and covenants.

Additional 8.50% Senior Notes

On October 24, 2012, we completed an offering for an additional $300.0 million in aggregate principal amount of 8.50% Senior Notes (the “New Notes”), which have identical terms to the 8.50% Senior Notes issued in June 2011, except that the issuance and sale of the New Notes was not registered with the SEC. The New Notes were sold in a private offering that was exempt from the registration requirements of the Securities Act of 1933 and issued at a premium of 106% of par value. The net proceeds after fees and expenses were approximately $312.0 million. The funds were used to repay all of our outstanding indebtedness under our revolving bank credit facility, a portion of which was recently incurred to partially fund our acquisition of the Newfield Properties described above, and for general corporate purposes. The issuance of the New Notes resulted in a reduction of our borrowing base from $650.0 million to $575.0 million until such time as the fall redetermination occurs.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

14. 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 September 30, 2012


	Parent Company			Guarantor Subsidiaries		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	6,993		$	—	$	—		$	6,993
Receivables:
Oil and natural gas sales		53,969			14,261		—			68,230
Joint interest and other		21,105			—		—			21,105
Income taxes		124,012			—		(109,728	)		14,284

Total receivables		199,086			14,261		(109,728	)		103,619
Restricted cash and cash equivalents		24,026			—		—			24,026
Deposit for acquisition		22,800			—		—			22,800
Prepaid expenses and other assets		32,455			—		—			32,455

Total current assets		285,360			14,261		(109,728	)		189,893
Property and equipment – at cost:
Oil and natural gas properties and equipment		5,917,591			312,035		—			6,229,626
Furniture, fixtures and other		20,912			—		—			20,912

Total property and equipment		5,938,503			312,035		—			6,250,538
Less accumulated depreciation, depletion and amortization		4,384,839			171,709		—			4,556,548

Net property and equipment		1,553,664			140,326		—			1,693,990
Restricted deposits for asset retirement obligations		28,441			—		—			28,441
Deferred income taxes		—			15,986		(15,986	)		—
Other assets		421,125			376,655		(783,452	)		14,328

Total assets	$	2,288,590		$	547,228	$	(909,166	)	$	1,926,652


Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	103,370		$	904	$	—		$	104,274
Undistributed oil and natural gas proceeds		34,437			223		—			34,660
Asset retirement obligations		83,545			—		—			83,545
Accrued liabilities		32,331			—		—			32,331
Income taxes		—			110,078		(109,728	)		350
Deferred income taxes – current		2,945			—		—			2,945

Total current liabilities		256,628			111,205		(109,728	)		258,105
Long-term debt		719,000			—		—			719,000
Asset retirement obligations, less current portion		221,478			29,226		—			250,704
Deferred income taxes		114,379			—		(15,986	)		98,393
Other liabilities		386,125			—		(376,655	)		9,470
Shareholders’ equity:
Common stock		1			—		—			1
Additional paid-in capital		396,601			231,759		(231,759	)		396,601
Retained earnings		218,545			175,038		(175,038	)		218,545
Treasury stock, at cost		(24,167	)		—		—			(24,167	)

Total shareholders’ equity		590,980			406,797		(406,797	)		590,980

Total liabilities and shareholders’ equity	$	2,288,590		$	547,228	$	(909,166	)	$	1,926,652

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Condensed Consolidating Balance Sheet as of December 31, 2011


	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 – current		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 September 30, 2012


	Parent Company			Guarantor Subsidiaries		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)

Revenues	$	141,139		$	44,807	$	—		$	185,946


Operating costs and expenses:
Lease operating expenses		47,353			6,058		—			53,411
Production taxes		1,353			—		—			1,353
Gathering and transportation		2,084			726		—			2,810
Depreciation, depletion, amortization and accretion		58,744			18,718		—			77,462
General and administrative expenses		18,691			—		—			18,691
Derivative loss		24,659			—		—			24,659

Total costs and expenses		152,884			25,502		—			178,386

Operating income (loss)		(11,745	)		19,305		—			7,560
Earnings of affiliates		12,551			—		(12,551	)		—
Interest expense:
Incurred		14,791			—		—			14,791
Capitalized		(3,383	)		—		—			(3,383	)
Other income		202			—		—			202

Income (loss) before income tax expense (benefit)		(10,400	)		19,305		(12,551	)		(3,646	)
Income tax expense (benefit)		(8,929	)		6,754		—			(2,175	)

Net income (loss)	$	(1,471	)	$	12,551	$	(12,551	)	$	(1,471	)

Condensed Consolidating Statement of Income for the Nine Months Ended September 30, 2012


	Parent Company			Guarantor Subsidiaries		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)

Revenues	$	473,297		$	164,048	$	—		$	637,345


Operating costs and expenses:
Lease operating expenses		150,860			19,489		—			170,349
Production taxes		4,174			—		—			4,174
Gathering and transportation		8,788			2,352		—			11,140
Depreciation, depletion, amortization and accretion		189,827			62,067		—			251,894
General and administrative expenses		60,200			2,593		—			62,793
Derivative loss		14,421			—		—			14,421

Total costs and expenses		428,270			86,501		—			514,771

Operating income		45,027			77,547		—			122,574
Earnings of affiliates		50,395			—		(50,395	)		—
Interest expense:
Incurred		43,409			—		—			43,409
Capitalized		(9,899	)		—		—			(9,899	)
Other income		210			—		—			210

Income before income tax expense		62,122			77,547		(50,395	)		89,274
Income tax expense		6,807			27,152		—			33,959

Net income	$	55,315		$	50,395	$	(50,395	)	$	55,315

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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


	Parent Company			Guarantor Subsidiaries		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)

Revenues	$	174,935		$	70,436	$	—		$	245,371


Operating costs and expenses:
Lease operating expenses		49,854			9,045		—			58,899
Production taxes		1,050			—		—			1,050
Gathering and transportation		3,669			1,184		—			4,853
Depreciation, depletion, amortization and accretion		62,372			22,083		—			84,455
General and administrative expenses		18,104			—		—			18,104
Derivative gain		(17,323	)		—		—			(17,323	)

Total costs and expenses		117,726			32,312		—			150,038

Operating income		57,209			38,124		—			95,333
Earnings of affiliates		24,780			—		(24,780	)		—
Interest expense:
Incurred		14,721			—		—			14,721
Capitalized		(3,163	)		—		—			(3,163	)
Loss on extinguishment of debt		2,031			—		—			2,031
Other income		6			—		—			6

Income before income tax expense		68,406			38,124		(24,780	)		81,750
Income tax expense		15,478			13,344		—			28,822

Net income	$	52,928		$	24,780	$	(24,780	)	$	52,928

Condensed Consolidating Statement of Income for the Nine Months Ended September 30, 2011


	Parent Company			Guarantor Subsidiaries		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)

Revenues	$	507,689		$	201,459	$	—		$	709,148


Operating costs and expenses:
Lease operating expenses		130,001			29,900		—			159,901
Production taxes		2,183			—		—			2,183
Gathering and transportation		9,990			3,213		—			13,203
Depreciation, depletion, amortization and accretion		176,999			64,918		—			241,917
General and administrative expenses		51,653			2,582		—			54,235
Derivative gain		(10,815	)		—		—			(10,815	)

Total costs and expenses		360,011			100,613		—			460,624

Operating income		147,678			100,846		—			248,524
Earnings of affiliates		65,550			—		(65,550	)		—
Interest expense:
Incurred		36,913			—		—			36,913
Capitalized		(6,654	)		—		—			(6,654	)
Loss on extinguishment of debt		22,694			—		—			22,694
Other income		22			—		—			22

Income before income tax expense		160,297			100,846		(65,550	)		195,593
Income tax expense		33,545			35,296		—			68,841

Net income	$	126,752		$	65,550	$	(65,550	)	$	126,752

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Condensed Consolidating Statement of Cash Flows for the Nine Months Ended September 30, 2012


	Parent Company			Guarantor Subsidiaries			Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Operating activities:
Net income	$	55,315		$	50,395		$	(50,395	)	$	55,315
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		189,827			62,067			—			251,894
Amortization of debt issuance costs		2,046			—			—			2,046
Share-based compensation		9,137			—			—			9,137
Derivative loss		14,421			—			—			14,421
Cash payments on derivative settlements		(6,960	)		—			—			(6,960	)
Deferred income taxes		42,816			1,649			—			44,465
Earnings of affiliates		(50,395	)		—			50,395			—
Changes in operating assets and liabilities:
Oil and natural gas receivables		24,162			6,158			—			30,320
Joint interest and other receivables		3,935			—			—			3,935
Insurance receivables		500			—			—			500
Income taxes		(49,830	)		25,503			—			(24,327	)
Prepaid expenses and other assets		669			(101,473	)		101,474			670
Asset retirement obligations		(63,150	)		—			—			(63,150	)
Accounts payable and accrued liabilities		34,063			(1,752	)		—			32,311
Other liabilities		102,386			—			(101,474	)		912

Net cash provided by operating activities		308,942			42,547			—			351,489


Investing activities:
Investment in oil and natural gas properties and equipment		(269,825	)		(42,547	)		—			(312,372	)
Proceeds from sales of oil and gas properties and equipment		30,453			—			—			30,453
Change in restricted cash		(24,026	)		—			—			(24,026	)
Deposit for acquisition		(22,800	)		—			—			(22,800	)
Purchases of furniture, fixtures and other		(2,125	)		—			—			(2,125	)

Net cash used in investing activities		(288,323	)		(42,547	)		—			(330,870	)


Financing activities:
Borrowings of long-term debt – revolving bank credit facility		316,000			—			—			316,000
Repayments of long-term debt – revolving bank credit facility		(314,000	)		—			—			(314,000	)
Debt issuance costs		(2,081	)		—			—			(2,081	)
Dividends to shareholders		(17,848	)		—			—			(17,848	)
Other		(209	)		—			—			(209	)

Net cash used in financing activities		(18,138	)		—			—			(18,138	)

Increase in cash and cash equivalents		2,481			—			—			2,481
Cash and cash equivalents, beginning of period		4,512			—			—			4,512

Cash and cash equivalents, end of period	$	6,993		$	—		$	—		$	6,993

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Condensed Consolidating Statement of Cash Flows for the Nine Months Ended September 30, 2011


	Parent Company			Guarantor Subsidiaries			Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Operating activities:
Net income	$	126,752		$	65,550		$	(65,550	)	$	126,752
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		176,999			64,918			—			241,917
Amortization of debt issuance costs		1,401			—			—			1,401
Loss on extinguishment of debt		22,694			—			—			22,694
Share-based compensation		6,437			—			—			6,437
Derivative gain		(10,815	)		—			—			(10,815	)
Cash payments on derivative settlements		(9,239	)		—			—			(9,239	)
Deferred income taxes		68,350			(8,908	)		—			59,442
Earnings of affiliates		(65,550	)		—			65,550			—
Changes in operating assets and liabilities:
Oil and natural gas receivables		(10,946	)		8,033			—			(2,913	)
Joint interest and other receivables		7,465			—			—			7,465
Insurance receivables		18,971			—			—			18,971
Income taxes		(60,099	)		44,205			—			(15,894	)
Prepaid expenses and other assets		(22,796	)		(165,495	)		165,690			(22,601	)
Asset retirement obligations		(51,349	)		—			—			(51,349	)
Accounts payable and accrued liabilities		25,717			(1,631	)		(194	)		23,892
Other liabilities		165,387			—			(165,496	)		(109	)

Net cash provided by operating activities		389,379			6,672			—			396,051


Investing activities:
Acquisition of significant property interest in oil and natural gas properties		(434,582	)		—			—			(434,582	)
Investment in oil and natural gas properties and equipment		(183,735	)		(1,487	)		—			(185,222	)
Investment in subsidiary		5,185			—			(5,185	)		—
Purchases of furniture, fixtures and other		(303	)		—			—			(303	)

Net cash used in investing activities		(613,435	)		(1,487	)		(5,185	)		(620,107	)


Financing activities:
Issuance of 8.5% Senior Notes		600,000			—			—			600,000
Repurchase of 8.25% Senior Notes		(450,000	)		—			—			(450,000	)
Borrowings of long-term debt – revolving bank credit facility		512,000			—			—			512,000
Repayments of long-term debt – revolving bank credit facility		(418,000	)		—			—			(418,000	)
Repurchase premium and debt issuance costs		(31,997	)		—			—			(31,997	)
Investment from parent		—			(5,185	)		5,185			—
Dividends to shareholders		(8,936	)		—			—			(8,936	)

Net cash provided by financing activities		203,067			(5,185	)		5,185			203,067

Decrease in cash and cash equivalents		(20,989	)		—			—			(20,989	)
Cash and cash equivalents, beginning of period		28,655			—			—			28,655

Cash and cash equivalents, end of period	$	7,666		$	—		$	—		$	7,666

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 67 producing offshore fields in federal and state waters, and in the deepwater. During 2011, we expanded onshore into West Texas and East Texas where we are actively pursuing exploration and development activities. However, the majority of our daily production continues to be 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 nine months ended September 30, 2012, our combined total production of oil, condensate, NGLs and natural gas increased by 2.3% and our combined average realized sales prices decreased by 12.3% compared to the same period in 2011 based on an energy equivalency ratio. Our production volumes for the nine months ended September 30, 2012 were comprised of approximately 34.6% oil and condensate, 12.5% NGLs and 52.9% natural gas. In the nine months ended September 30, 2012, oil sales represented 72.5% of total revenues, while NGLs represented 10.2% and natural gas represented 17.1% 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.

On October 5, 2012, we completed the acquisition of certain oil and gas leasehold interests from Newfield. The stated purchase price was $228.0 million, subject to certain adjustments, including adjustments from an effective date of July 1, 2012 until the closing date, October 5, 2012. The preliminary adjusted purchase price, excluding ARO was $207.7 million, which is subject to further post-effective date adjustments and the assumption of future ARO estimated at $30.4 million for these properties. The properties acquired consist of leases covering 78 federal offshore blocks on approximately 432,700 gross acres (416,000 gross acres excluding over-riding interests), comprised of 65 blocks in the deepwater, six of which are producing, ten blocks on the conventional shelf, four of which are producing, and an overriding royalty interest in three deepwater blocks, two of which are producing. The Newfield Properties had estimated proved reserves as of July 1, 2012 of 7.7 million barrels of oil equivalent (“MMBoe”) or 46.0 billion cubic feet equivalent (“Bcfe”) comprised of approximately 60% natural gas, 36% oil and 4% NGLs and 100% of which were classified as proved developed. The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand.

During 2011, we closed two acquisition transactions. On May 11, 2011, we completed the acquisition of the Yellow Rose Properties, which consisted 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 MMBoe, or 180.4 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 September 30, 2012, the adjusted purchase price was $40.2 million excluding ARO. The purchase price is subject to further post-effective date adjustments and final settlement is expected to occur in the fourth 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 nine months ended September 30, 2012, our average realized oil sales price (unhedged) increased 2.0% compared to the nine months ended September 30, 2011. Two comparable benchmarks are the unweighted average daily posted spot price of WTI crude oil and the unweighted average daily posted spot price of Brent crude oil, which increased 1.0 % and 0.2 %, respectively 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 nine months ended September 30, 2012, these various crudes sold at a significant premium relative to WTI. During the nine months ended September 30, 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 September 2012, the average premium for these crudes was between $17.00 and $18.00 per barrel. In comparison, the average premium for these crudes was between $4.00 and $24.00 per barrel for the nine months ended September 30, 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 relieve most of the over supply situation at Cushing, which may affect the premiums we receive on our offshore oil production although we did not experience a decline in the third quarter of 2012. 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 nine months ended September 30, 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 being 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. For the nine months ended September 30, 2012, WTI crude oil prices have ranged from a high of approximately $109.00 per barrel to a low of $78.00 per barrel. The volatility 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 was weakening. The U.S. Energy Information Administration (“EIA”) expects the oil market to loosen in the near term as consumption falls from its seasonal peak and output outside of OPEC recovers from unplanned outages. EIA expects consumption growth to come primarily from China, the Middle East, Central and South America. EIA estimates global oil demand for 2012 and 2013 at 89.1 and 90.0 million barrels per day, respectively, which would be less than 1% growth for each year.

Our average realized NGLs sales prices (unhedged) decreased 26.1% during the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011. According to industry sources, domestic NGLs production significantly increased over 2011 levels which affected price realizations. During the nine months ended September 30, 2012, prices for domestic ethane and propane, two common NGL components, decreased 44% and 29%, respectively, from the nine months ended September 30, 2011 and other domestic NGLs prices decreased 9% to 10%. 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 nine months ended September 30, 2012, our average realized sales price of natural gas (unhedged) decreased 37.3% from the nine months ended September 30, 2011 to $2.72 per Mcf. A comparable bench mark is the Henry Hub unweighted average daily posted spot price, which decreased 39.8% 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. EIA estimates that natural gas consumption in 2012 will increase 4.7% from 2011 to 69.8 billion cubic feet per day due to gains in electrical power use offsetting declines in residential, commercial and industrial consumption and expects 2013 consumption to be approximately equal to 2012 levels. The EIA expects production growth to decrease in 2013 due to the decrease in current domestic natural gas rig count of approximately 50% as compared to the natural gas rig count from 2012. Due to the high production and historically high inventory levels, we believe natural gas prices may continue to be weak until such time as crude prices weaken (which will in turn decrease oil 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 fuel switching between coal and natural gas in the production of electricity. However, the EIA indicates that higher expected natural gas prices will reduce the percentage of electrical power generation from natural gas from a projected 27.8% in the fourth quarter of 2012 to 25.8% in the first quarter of 2013. The EIA’s currently estimates electricity consumption in 2013 to be approximately flat as compared to the estimated consumption for 2012.

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 31% in September 2012 compared to September 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.

Many proposed changes in laws, regulations, guidance and policy continue to affect our industry. The process for obtaining offshore drilling permits, especially deepwater 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 September 30, ⁽¹⁾												Nine Months Ended September 30, ⁽¹⁾
	2012			2011			Change			%			2012		2011			Change			%
	(In thousands, except percentages and per share data)
Financial:
Revenues:
Oil	$	138,034		$	155,719		$	(17,685	)		(11.4	)%	$	461,846	$	466,493		$	(4,647	)		(1.0	)%
NGLs		12,468			28,250			(15,782	)		(55.9	)%		64,793		70,907			(6,114	)		(8.6	)%
Natural gas		35,054			61,174			(26,120	)		(42.7	)%		109,174		170,753			(61,579	)		(36.1	)%
Other		390			228			162			71.1	%		1,532		995			537			54.0	%

Total revenues		185,946			245,371			(59,425	)		(24.2	)%		637,345		709,148			(71,803	)		(10.1	)%
Operating costs and expenses:
Lease operating expenses		53,411			58,899			(5,488	)		(9.3	)%		170,349		159,901			10,448			6.5	%
Production taxes		1,353			1,050			303			28.9	%		4,174		2,183			1,991			91.2	%
Gathering and transportation		2,810			4,853			(2,043	)		(42.1	)%		11,140		13,203			(2,063	)		(15.6	)%
Depreciation, depletion, amortization and accretion		77,462			84,455			(6,993	)		(8.3	)%		251,894		241,917			9,977			4.1	%
General and administrative expenses		18,691			18,104			587			3.2	%		62,793		54,235			8,558			15.8	%
Derivative (gain) loss		24,659			(17,323	)		41,982			NM			14,421		(10,815	)		25,236			NM

Total costs and expenses		178,386			150,038			28,348			18.9	%		514,771		460,624			54,147			11.8	%

Operating income		7,560			95,333			(87,773	)		(92.1	)%		122,574		248,524			(125,950	)		(50.7	)%
Interest expense, net of amounts capitalized		11,408			11,558			(150	)		(1.3	)%		33,510		30,259			3,251			10.7	%
Loss on extinguishment of debt (2)		—			2,031			(2,031	)		NM			—		22,694			(22,694	)		NM
Other income		202			6			196			NM			210		22			188			NM

Income (loss) before income tax expense (benefit)		(3,646	)		81,750			(85,396	)		(104.5	)%		89,274		195,593			(106,319	)		(54.4	)%
Income tax expense (benefit)		(2,175	)		28,822			(30,997	)		(107.5	)%		33,959		68,841			(34,882	)		(50.7	)%

Net income (loss)	$	(1,471	)	$	52,928		$	(54,399	)		(102.8	)%	$	55,315	$	126,752		$	(71,437	)		(56.4	)%


Basic and diluted earnings (loss) per common share	$	(0.02	)	$	0.70		$	(0.72	)		(102.9	)%	$	0.73	$	1.68		$	(0.95	)		(56.5	)%

(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 2011, we charged to expense repurchase premiums, deferred financing costs and other costs totaling $22.0 million related to the repurchase of $450.0 million in aggregate principal amount of our 8.25% Senior Notes due 2014 and expensed $0.7 million of deferred financing costs related to replacement of our revolving bank credit facility.

NM = percentage change not meaningful


	Three Months Ended September 30, ⁽¹⁾										Nine Months Ended September 30, ⁽¹⁾
	2012		2011		Change			%			2012		2011		Change			%
Operating:
Net sales volumes:
Oil (MBbls)		1,371		1,524		(153	)		(10.0	)%		4,361		4,495		(134	)		(3.0	)%
NGLs (MBbls)		451		501		(50	)		(10.0	)%		1,581		1,279		302			23.6	%
Natural gas (MMcf)		11,401		14,332		(2,931	)		(20.5	)%		40,097		39,384		713			1.8	%
Total natural gas and oil (MBoe) (2)		3,722		4,414		(692	)		(15.7	)%		12,625		12,338		287			2.3	%
Total natural gas and oil (MMcfe) (2)		22,331		26,483		(4,152	)		(15.7	)%		75,749		74,025		1,724			2.3	%

Average daily equivalent sales (Boe/d) (2)		40,454		47,977		(7,523	)		(15.7	)%		46,076		45,193		883			2.0	%
Average daily equivalent sales (Mcfe/d) (2)		242,723		287,860		(45,137	)		(15.7	)%		276,455		271,156		5,299			2.0	%

Average realized sales prices (Unhedged):
Oil ($/Bbl)	$	100.68	$	102.14	$	(1.46	)		(1.4	)%	$	105.89	$	103.78	$	2.11			2.0	%
NGLs ($/Bbl)		27.66		56.43		(28.77	)		(51.0	)%		40.99		55.45		(14.46	)		(26.1	)%
Natural gas ($/Mcf)		3.07		4.27		(1.20	)		(28.1	)%		2.72		4.34		(1.62	)		(37.3	)%
Oil equivalent ($/Boe) (2)		49.86		55.54		(5.68	)		(10.2	)%		50.36		57.40		(7.04	)		(12.3	)%
Natural gas equivalent ($/Mcfe) (2)		8.31		9.26		(0.95	)		(10.3	)%		8.39		9.57		(1.18	)		(12.3	)%

Average realized sales prices (Hedged) (3):
Oil ($/Bbl)	$	100.05	$	101.54	$	(1.49	)		(1.5	)%	$	104.30	$	101.73	$	2.57			2.5	%
NGLs ($/Bbl)		27.66		56.43		(28.77	)		(51.0	)%		40.99		55.45		(14.46	)		(26.1	)%
Natural gas ($/Mcf)		3.07		4.27		(1.20	)		(28.1	)%		2.72		4.34		(1.62	)		(37.3	)%
Oil equivalent ($/Boe) (2)		49.62		55.33		(5.71	)		(10.3	)%		49.81		56.65		(6.84	)		(12.1	)%
Natural gas equivalent ($/Mcfe) (2)		8.27		9.22		(0.95	)		(10.3	)%		8.30		9.44		(1.14	)		(12.1	)%

Average per Mcfe ($/Mcfe) (2):
Lease operating expenses	$	2.39	$	2.22	$	0.17			7.7	%	$	2.25	$	2.16	$	0.09			4.2	%
Gathering and transportation		0.13		0.18		(0.05	)		(27.8	)		0.15		0.18		(0.03	)		(16.7	)%

Production costs		2.52		2.40		0.12			5.0	%		2.40		2.34		0.06			2.6	%
Production taxes		0.06		0.04		0.02			50.0	%		0.06		0.03		0.03			100.0	%
Depreciation, depletion, amortization and accretion		3.47		3.19		0.28			8.8	%		3.33		3.27		0.06			1.8	%
General and administrative expenses		0.84		0.68		0.16			23.5	%		0.83		0.73		0.10			13.7	%

	$	6.89	$	6.31	$	0.58			9.2	%	$	6.62	$	6.37	$	0.25			3.9	%


Total number of wells drilled (gross):
Offshore		1		2		(1	)		(50.0	)%		3		4		(1	)		(25.0	)%
Onshore		18		17		1			5.9	%		55		24		31			129.2	%

Total number of productive wells drilled (gross):
Offshore		1		2		(1	)		(50.0	)%		3		4		(1	)		(25.0	)%
Onshore		18		16		2			12.5	%		55		23		32			139.1	%

(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 September 30, 2012 Compared to the Three Months Ended September 30, 2011

Revenues. Total revenues decreased $59.4 million to $185.9 million for the third quarter of 2012 as compared to the prior year period. Oil revenues decreased $17.7 million, NGLs revenues decreased $15.8 million, natural gas revenues decreased $26.1 million and other revenues increased $0.2 million. The oil revenue decrease was attributable to a 1.4% decrease in the average realized sales price (unhedged) to $100.68 per barrel for third quarter of 2012, combined with a 10.0% decrease in sales volumes. The NGLs revenue decrease was attributable to a 51.0% decrease in the average realized sales price (unhedged) to $27.66 per barrel and a decrease of 10.0% in sales volumes. NGLs average realized prices as a percentage of oil average realized prices decreased to 27.5% for the third quarter of 2012 compared to 55.2% for the prior year period. The decrease in natural gas revenue resulted from a 28.1% decrease in the average realized natural gas sales price (unhedged) to $3.07 per Mcf and a decrease primarily in sales volume of 20.5%. The sales volumes for all commodities declined 15.7% on an MBoe basis and were negatively impacted by Hurricane Isaac and various pipeline outages. Production was also impacted by the sale of South Timbalier 41, the sanding up of the Mississippi Canyon 243 A2 ST well and natural production declines. Partially offsetting these declines was successful exploration and development efforts. In addition, NGLs and natural gas volumes were positively impacted by the Fairway acquisition which occurred during the third quarter of 2011. Revenues from oil and NGLs increased as a percentage of our total revenues, increasing to 80.9% for the three months ended September 30, 2012 compared to 75.0% for the prior year period.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, insurance, workovers, maintenance on our facilities, and other expenses decreased $5.5 million to $53.4 million in the third quarter of 2012 compared to the prior year period. On a per Mcfe basis, lease operating expenses were $2.39 per Mcfe during the third quarter 2012 compared to $2.22 per Mcfe during the comparable 2011 period. On a component basis, base lease operating expenses and insurance premiums decreased $9.1 million and $0.3 million, respectively. Partially offsetting these declines were increases in workover expenses, facilities expense and other expenses, of $2.3 million, $1.1 million and $0.5 million, respectively. The decrease in base lease operating expenses is primarily attributable to an ad valorem tax refund; an increase in processing fees charged to third parties; adjusted operating fees at the Fairway and Yellowhammer properties; the sale of South Timbalier 41 earlier in 2012; and fewer repairs and maintenance. Workover costs increased at various offshore locations, with the largest increase at the Main Pass 108 field for stimulation treatment. The facilities expense increases were primarily at Mississippi Canyon 243 related to installation of two gas compressors.

Production taxes. Production taxes increased to $1.4 million in the third quarter of 2012 compared to $1.1 million in the prior year period primarily due to the properties acquired in 2011. Production taxes are currently not a large component of our operating costs as most of our production is from federal waters where no production taxes are due, while onshore operations are subject to production taxes.

Gathering and transportation costs. Gathering and transportation costs decreased $2.1 million in the third quarter compared to the prior year period due to lower production volumes.

Depreciation, depletion, amortization and accretion. DD&A, including accretion for ARO, increased to $3.47 per Mcfe in the third quarter of 2012 from $3.19 per Mcfe in the prior year period. Increases to estimated future development costs without corresponding increases to proved reserves have caused the DD&A per Mcfe rate to increase. In addition, we have incurred development capital expenditures above estimates and most of our exploration capital expenditures have not increased proved reserves as of September 30, 2012, as the wells were in process of being drilled, the wells have not yet been completed or the reserves have not yet been evaluated as proved. On a nominal basis, DD&A decreased to $77.5 million in the third quarter of 2012 from $84.5 million in the prior year period. DD&A on a nominal basis decreased primarily due to lower production volumes.

General and administrative expenses. G&A increased to $18.7 million in the third quarter of 2012 from $18.1 million in the prior year period, primarily due to increased salaries and benefits and decreased overhead credits related to joint interest arrangements, partially offset by lower legal expenses. G&A on a per Mcfe basis was $0.84 per Mcfe in the third quarter of 2012, compared to $0.68 per Mcfe in the prior year period.

Derivative gains and losses. For the third quarter of 2012 and 2011, we recognized a loss of $24.7 million and a gain of $17.3 million, 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 both the current and future years, changes in the fair value for all open contracts are recorded currently. For the third quarter of 2012, the loss was comprised of a $0.9 million realized loss and a $23.8 million unrealized loss. For the third quarter of 2011, the gain was comprised of a $0.9 million realized loss and an $18.2 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 was $14.8 million for the third quarter of 2012 and was relatively flat compared to the prior year period. During the third quarter of 2012 and 2011, interest of $3.4 million and $3.2 million, respectively, was capitalized to unevaluated oil and natural gas properties.

Loss on extinguishment of debt. For the third quarter of 2011, loss on extinguishment of debt was $2.0 million. In July 2011, we repurchased the remaining $43.8 million outstanding of our 8.25% Senior Notes, which resulted in a loss on extinguishment of debt.

Income tax expense (benefit). Income tax benefit for the third quarter of 2012 was $2.2 million compared to an income tax expense of $28.8 million for the prior year period. The change is primarily attributable to having a loss in the current period compared to income in the prior period. The tax benefit rate of 59.7% in the third quarter exceeded the amount computed at the statutory rate of 35.0% as a result of a decrease in our full year forecasted effective tax rate. The effective tax rate for the third quarter of 2012 is not representative of the effective tax rate going forward. Our effective tax rate for the third quarter of 2011 was 35.3%, which approximated the federal statutory rate.

Nine Months Ended September 30, 2012 Compared to the Nine Months Ended September 30, 2011

Revenues. Total revenues decreased $71.8 million to $637.3 million for the nine months ended September 30, 2012 as compared to the prior year period. Oil revenues decreased $4.6 million, NGLs revenues decreased $6.1 million, natural gas revenues decreased $61.6 million and other revenues increased $0.5 million. The oil revenue decrease was attributable to a 3.0% decrease in sales volumes, partially offset by a 2.0% increase in the average realized sales price (unhedged) to $105.89 per barrel for nine months ended September 30, 2012. The NGLs revenue decrease was attributable to a 26.1% decrease in the average realized sales price (unhedged) to $40.99 per barrel for the nine months ended September 30, 2012, partially offset by an increase of 23.6% in sales volumes from the comparable period. NGLs average realized prices as a percentage of oil average realized prices decreased to 38.7% for the nine months ended September 30, 2012 compared to 53.4% for the prior year period. The decrease in natural gas revenue resulted from a 37.3% decrease in the average realized natural gas sales price (unhedged) to $2.72 per Mcf in the nine months ended September 30, 2012, partially offset by a 1.8% increase in sales volumes. The sales volume changes for all commodities were negatively impacted by Hurricane Isaac, various pipeline outages, and natural production declines; partially offset by acquisitions and successful exploration and development efforts. In addition, NGLs and natural gas volumes were positively impacted by the June 2011 production resumption in the Main Pass 108 fields. Revenues from oil and NGLs increased as a percentage of our total revenues, increasing to 82.6% for the nine months ended September 30, 2012 compared to 75.8% for the prior year period.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, insurance, workovers, maintenance on our facilities, and other expenses increased $10.4 million to $170.3 million in the nine months ended September 30, 2012 compared to the prior year period. On a per Mcfe basis, lease operating expenses were $2.25 per Mcfe compared to $2.16 per Mcfe during the comparable 2011 period. On a component basis, base lease operating expenses, workover expenses and insurance premiums increased $5.8 million, $4.1 million and $3.0 million, respectively. As a partial offset, facilities expense and other expenses decreased $2.3 million and $0.2 million, respectively. The increase in base lease operating expenses is primarily attributable to our Fairway and Yellow Rose properties acquired in 2011. Workover costs increases were primarily attributable to increases for our onshore operations, which had approximately four months of expenses in 2011. The increase in insurance premiums is attributable to increases effective with the June 1, 2011 renewal, which included an expansion in coverage. The decrease in facilities expense is primarily attributable to pipeline repairs at our Ship Shoal 300 field which were completed in the 2011 period. Facilities expense related to other projects completed in 2011 were approximately offset by facilities expense related to 2012 projects.

Production taxes. Production taxes increased to $4.2 million in the nine months ended September 30, 2012 compared to $2.2 million in the prior year period primarily due to acquisition activities. Production taxes are currently not a large component of our operating costs as most of our production is from federal waters where no production taxes are due, while onshore operations are subject to production taxes.

Gathering and transportation costs. Gathering and transportation costs decreased $2.1 million in the nine months ended September 30, 2012 compared to the prior year period due to lower volumes in the third quarter.

Depreciation, depletion, amortization and accretion. DD&A, including accretion for ARO, increased to $3.33 per Mcfe in the nine months ended September 30, 2012 from $3.27 per Mcfe in the prior year period. On a nominal basis, DD&A increased to $251.9 million in the nine months ended September 30, 2012 from $241.9 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 $62.8 million in the nine months ended September 30, 2012 from $54.2 million in the prior year period, primarily due to the 2012 settlement of a lawsuit related to property damage. Other increases for increased share-based compensation and lower overhead credits related to joint interest arrangements were partially offset by lower cash-based incentive compensation expense. G&A on a per Mcfe basis was $0.83 per Mcfe in the nine months ended September 30, 2012, compared to $0.73 per Mcfe in the prior year period.

Derivative gains and losses. For the nine months ended September 30, 2012 and 2011, we recognized a loss of $14.4 million and a gain of $10.8 million, 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 both the current and future years, changes in the fair value for all open contracts are recorded currently. For the nine months ended September 30, 2012, the loss was comprised of a $7.0 million realized loss and a $7.4 million unrealized loss. For the nine months ended September 30, 2011, the gain was comprised of a $9.2 million realized loss and a $20.0 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 $43.4 million for the nine months ended September 30, 2012 from $36.9 million for the prior year period. The average amount of our Senior Notes outstanding increased due to our June 2011 issuance of $600 million of our 8.50% Senior Notes and repurchase of $450 million of our 8.25% Senior Notes. During the nine months ended September 30, 2012 and 2011, interest of $9.9 million and $6.7 million, respectively, was capitalized to unevaluated oil and natural gas properties. The increase is primarily attributable to in the amount of unevaluated properties that were acquired in conjunction with the acquisition of the Yellow Rose Properties in 2011.

Loss on extinguishment of debt. For the nine months ended September 30, 2011, loss on extinguishment of debt was $22.7 million. In 2011, we expensed repurchase premiums, deferred financing costs and other costs totaling $22.0 million related to the repurchase of $450.0 million in aggregate principal amount of our 8.25% Senior Notes due 2014 and expensed $0.7 million of deferred financing costs related to replacement of our revolving bank credit facility.

Income tax expense. Income tax expense decreased to $34.0 million for the nine months ended September 30, 2012 compared to $68.8 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 nine months ended September 30, 2012 was 38.0% 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 nine months ended September 30, 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 nine months ended September 30, 2012 was $351.5 million, compared to $396.1 million in the nine months ended September 30, 2011. The decrease was primarily due to decreases in operating income driven by lower realized prices, partially offset by working capital changes, lower income tax payments and higher sales volumes. Our combined average realized sales price (hedged) per Mcfe during the nine months ended September 30, 2012 was 12.1% lower than the comparable 2011 period, but our combined production of oil, NGLs and natural gas on a Mcfe basis was 2.3% higher than the comparable 2011 period.

Net cash used in investing activities during the nine months ended September 30, 2012 and 2011 was $330.9 million and $620.1 million, respectively, which primarily represents our investments in oil and gas properties, both offshore and onshore. The 2012 period reflects increased investments in oil and gas properties of $312.4 million, which includes increased drilling activity. Funds received from the sale of South Timbalier 41 were held in escrow for utilization in purchasing like-kind properties under the IRC section 1031 regulation. During September 2012, a deposit of $22.8 million was made for the acquisition of the Newfield Properties, which closed subsequent to September 30, 2012. The 2011 period includes the acquisition of the Yellow Rose and Fairway Properties of $434.6 million and investments of $185.2 million in oil and gas properties.

Net cash used in financing activities was $18.1 million during the nine months ended September 30, 2012 and net cash provided by financing activities was $203.1 million during the nine months ended September 30, 2011. The cash used in the nine months ended September 30, 2012 was primarily attributable to $17.8 million of dividend payments. The cash provided in the nine months ended September 30, 2011 was attributable to the issuance of $600 million of 8.50% Senior Notes and net borrowings on the revolving bank credit facility of $94.0 million, partially offset by the purchase of $450.0 million of the 8.25% Senior Notes, repurchase premium and debt issuance costs of $32.0 million and the payment of dividends of $8.9 million.

At September 30, 2012, we had a cash balance of $7.0 million and $530.4 million of undrawn capacity available under the revolving bank credit facility, which had a borrowing base of $650.0 million.

Credit Agreement and long-term debt. At September 30, 2012 and December 31, 2011, $119.0 million and $117.0 million, respectively, were outstanding under our revolving bank credit facility. During the nine months ended September 30, 2012, the outstanding borrowings on our revolving bank credit facility ranged from $44.0 million to $145.0 million. At September 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, 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. Fees incurred related to the First Amendment were $2.1 million and are being amortized over the remaining term of the Credit Agreement. We have 17 participating lenders under the revolving bank credit facility, with individual commitments ranging from $20.0 million to $55.0 million. While we have not experienced, nor do we anticipate, any difficulties obtaining funding from any of the participating lenders at this time, any lack of or delay in funding from such lenders could negatively impact our liquidity position.

On October 12, 2012, we entered into the Second Amendment to the Credit Agreement which, among other things, allows for the issuance of additional senior unsecured indebtedness. Following the amendment, we may issue additional senior unsecured indebtedness; however, the borrowing base under the Credit Agreement will be automatically and simultaneously reduced by $0.25 for every $1.00 increase in unsecured indebtedness incurred in excess of the $600.0 million aggregate principal amount of our existing notes until such time as the borrowing base has been redetermined or otherwise adjusted pursuant to the Credit Agreement. All other terms of the Credit Agreement remain substantially the same, including the termination date of May 5, 2015, interest rates spreads and covenants.

On October 24, 2012, we completed an offering for an additional $300.0 million in aggregate principal amount of 8.50% Senior Notes, which have identical terms to the 8.50% Senior Notes issued in June 2011, except that the issuance and the sale of the New Notes was not registered with the SEC. The New Notes were sold in a private offering that was exempt from the registration requirements of the Securities Act of 1933 and issued at a premium of 106% of par value. The net proceeds after fees and expenses were approximately $312.0 million. The funds were used to repay all of our outstanding indebtedness under our revolving bank credit facility, a portion of which was recently incurred to partially fund our acquisition of the Newfield Properties described above, and for general corporate purposes. The issuance of the New Notes resulted in a reduction of our borrowing base from $650.0 million to $575.0 million until such time as the fall redetermination occurs.

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 September 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 September 30, 2012, our derivative instruments outstanding consisted of oil contracts relating to approximately 0.5 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 September 30, 2012, we have received $140.0 million from our insurance carrier related to Hurricane Ike. As of September 30, 2012, we had no insurance receivables for claims that have been submitted and approved for payment. As of September 30, 2012, we have recorded an estimate of $12.8 million in ARO for additional costs to be incurred related to Hurricane Ike and we estimate 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 we 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:


	Nine Months Ended September 30,
	2012			2011
	(in thousands)
Acquisition of Yellow Rose Properties	$	—		$	394,594
Acquisition of Fairway Properties (1)		(2,689	)		39,988
Exploration (2)		59,183			40,045
Development (2)		229,255			128,255
Seismic, capitalized interest, other leasehold costs		26,623			16,922

Acquisitions and investments in oil and gas property/equipment	$	312,372		$	619,804

(1)

The amount in 2012 represents reductions to the purchase price for post-effective date adjustments.

(2)

Reported by geography in the subsequent table.

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


	Nine Months Ended September 30,
	2012		2011
	(in thousands)
Conventional shelf	$	71,438	$	99,317
Deepwater		41,359		3,072
Deep shelf		8,116		1,816
Onshore		167,525		64,095

Exploration and development capital expenditures	$	288,438	$	168,300

Our capital expenditures for the nine months ended September 30, 2012 were financed primarily by cash flow from operating activities. Our capital expenditures for the nine months ended September 30, 2011 were financed by additional net borrowings, cash flow from operating activities and cash on hand.

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


	Nine Months Ended September 30,
	2012				2011
	Gross		Net		Gross		Net
Development wells:
Offshore wells:
Productive		3		3.0		3		3.0
Dry		—		—		—		—

Onshore wells:
Productive		37		36.9		18		18.0
Dry		—		—		—		—

Total development wells		40		39.9		21		21.0


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

Onshore wells:
Productive		18		15.1		5		2.6
Dry		—		—		1		0.7

Total exploration wells		18		15.1		7		4.3



Total wells		58		55.0		28		25.3

Our total capital expenditure budget for 2012 is $425.0 million, not including 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, net of effective date adjustments. 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 nine months ended September 30, 2012, we made tax payments of $14.1 million and received refunds of $0.4 million. During the nine months ended September 30, 2011, we made tax payments of $25.3 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 nine months ended September 30, 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 nine months ended September 30, 2012 represents a 100% increase to the regular dividend per share of $0.04 paid in each of the quarters of 2011. On October 30, 2012, our board of directors declared a cash dividend of $0.08 per common share and a special dividend of $0.47 per common share, payable on December 3, 2012 to shareholders of record on November 16, 2012.

Contractual obligations. Updated information on certain contractual obligations is provided in Financial Statements – Note 4 – Asset Retirement Obligations, Financial Statements – Note 6 – Long Term Debt and Financial Statements – Note 13 – Subsequent Events under Part I, Item 1 of this Form 10-Q. As of September 30, 2012, drilling rig commitments were approximately $35.8 million compared to $33.8 million as of December 31, 2011. The current drilling rig commitments all expire within one year from September 30, 2012. Other contractual obligations as of September 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 nine months ended September 30, 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 September 30, 2012, these derivative contracts had a notional quantity of 2.5 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 September 30, 2012, we had $119.0 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 September 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 September 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 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. We are in settlement discussions with the government. 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.

Certain Cameron Parish land owners filed suits 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 lawsuits, plaintiffs alleged that property they own has been contaminated or otherwise damaged by the defendants’ oil and gas exploration and production activities and they are seeking compensatory and punitive damages. During the third quarter of 2012, we settled the majority of the claims related to this matter and paid $9.0 million. We assessed the remainder of the claims to be probable and have estimated additional payments to be $1.8 million, which were included in our contingent liability accrual as of September 30, 2012.

The Company was recently served with a complaint in a qui tam action filed under the federal False Claims Act by an employee of a Company contractor. The lawsuit, United States ex rel. Comeaux v. W&T Offshore, Inc., et al.; CA No. 10-494,

was filed in the United States District Court for the Eastern District of Louisiana, against the Company and three other working interest owners related to claims associated with three of the Company’s operated production platforms. A qui tam action, also known as a “whistleblower” action, is a lawsuit brought by a private citizen seeking civil penalties or damages against a person or company on behalf of the government for alleged violations of law. If the claims are successful, the person filing the suit may recover a percentage of the damages or penalty from the lawsuit as a reward for exposing a wrongdoing and recovering funds on behalf of the government. The complaint was originally filed in 2010 but kept under confidential seal in order for the federal government to decide if it wished to intervene and take over the prosecution of the qui tam action. The government declined to intervene in this suit and the complaint was unsealed and made public in June 2012, thereby giving the plaintiff the opportunity to pursue the claims on behalf of the government. The complaint was served on the Company on September 21, 2012.

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, except as set forth below.

Recently adopted rules regulating air emissions from oil and gas operations could cause us to incur increased capital expenditures and operating costs.

On April 17, 2012, the U.S. Environmental Protection Agency (“EPA”) approved final regulations under the Clean Air Act that, among other things, require additional emissions controls for natural gas and natural gas liquids production, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with such production activities. The final regulations require, among other things, the reduction of VOC emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. For well completion operations occurring at such well sites before January 1, 2015, the final regulations allow operators to capture and direct flowback emissions to completion combustion devices, such as flares, in lieu of performing green completions. These regulations also establish specific new requirements regarding emissions from dehydrators, storage tanks and other production equipment. Compliance with these requirements could increase our costs of development and production, which costs may be significant.

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 November 1, 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

2.1		Purchase and Sale Agreement, dated as of September 17, 2012, by and among Newfield Exploration Company and Newfield Exploration Gulf Coast LLC, as Sellers, and W&T Offshore, Inc., as Buyer (Incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K, filed October 12, 2012)

2.2		First Amendment to Purchase and Sale Agreement, dated as of October 5, 2012, by and among Newfield Exploration Company and Newfield Exploration Gulf Coast LLC, as Sellers, and W&T Offshore, Inc., as Buyer (Incorporated by reference to Exhibit 2.2 of the Company’s Current Report on Form 8-K, filed October 12, 2012)

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. (Incorporated by reference to Exhibit 3.3 of the Company’s Quarterly Report on Form 10-Q, filed July 31, 2012)

10.1		Second Amendment to the Fourth Amended and Restated Credit Agreement as of October 12, 2012. (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed October 17, 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.