Edgar Filing: W&T OFFSHORE INC

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Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2010

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

For the transition period from to

Commission File Number 1-32414

W&T OFFSHORE, INC.

(Exact name of registrant as specified in its charter)


Texas		72-1121985
(State of incorporation)		(IRS Employer Identification Number)

Nine Greenway Plaza, Suite 300 Houston, Texas		77046-0908
(Address of principal executive offices)		(Zip Code)

(713) 626-8525

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

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

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

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

As of August 4, 2010, there were 74,647,644 shares outstanding of the registrant’s common stock, par value $0.00001.

W&T OFFSHORE, INC. AND SUBSIDIARIES

TABLE OF CONTENTS


		Page
PART I – FINANCIAL INFORMATION

Item 1.	Financial Statements

	Condensed Consolidated Balance Sheets as of June 30, 2010 and December 31, 2009	1

	Condensed Consolidated Statements of Income (Loss) for the Three and Six Months Ended June 30, 2010 and 2009	2

	Condensed Consolidated Statement of Changes in Shareholders’ Equity for the Six Months Ended June 30, 2010	3

	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2010 and 2009	4

	Notes to Condensed Consolidated Financial Statements	5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	26

Item 4.	Controls and Procedures	26

PART II – OTHER INFORMATION

Item 1A.	Risk Factors	27

Item 6.	Exhibits	28

SIGNATURE		29

EXHIBIT INDEX		30

PART I – FINANCIAL INFORMATION

Item 1.

Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30, 2010			December 31, 2009
	(In thousands, except share data) (Unaudited)
Assets

Current assets:
Cash and cash equivalents	$	72,898		$	38,187
Receivables:
Oil and natural gas sales		66,717			54,978
Joint interest and other		29,381			51,312
Insurance		13,848			30,543
Income taxes		—			85,457

Total receivables		109,946			222,290
Prepaid expenses and other assets		40,723			28,777

Total current assets		223,567			289,254
Property and equipment – at cost:
Oil and natural gas properties and equipment (full cost method, of which $64,605 at June 30, 2010 and $77,301 at December 31, 2009 were excluded from amortization)		4,943,283			4,732,696
Furniture, fixtures and other		15,248			15,080

Total property and equipment		4,958,531			4,747,776
Less accumulated depreciation, depletion and amortization		3,885,800			3,752,980

Net property and equipment		1,072,731			994,796
Restricted deposits for asset retirement obligations		31,281			30,614
Deferred income taxes		5,975			5,117
Other assets		7,896			7,052

Total assets	$	1,341,450		$	1,326,833

Liabilities and Shareholders’ Equity

Current liabilities:
Accounts payable	$	55,041		$	115,683
Undistributed oil and natural gas proceeds		25,127			32,216
Asset retirement obligations		99,474			117,421
Accrued liabilities		9,982			13,509
Income taxes		6,055			—
Deferred income taxes		8,921			5,117

Total current liabilities		204,600			283,946
Long-term debt		450,000			450,000
Asset retirement obligations, less current portion		245,339			231,379
Other liabilities		14,912			2,558
Commitments and contingencies
Shareholders’ equity:
Common stock, $0.00001 par value; 118,330,000 shares authorized; 77,555,011 issued and 74,685,838 outstanding at June 30, 2010; 77,579,968 issued and 74,710,795 outstanding at December 31, 2009		1			1
Additional paid-in capital		374,993			373,050
Retained earnings		75,772			10,066
Treasury stock, at cost		(24,167	)		(24,167	)

Total shareholders’ equity		426,599			358,950

Total liabilities and shareholders’ equity	$	1,341,450		$	1,326,833

See Notes to Condensed Consolidated Financial Statements.

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS)


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(In thousands, except per share data) (Unaudited)

Revenues	$	179,667		$	150,432		$	349,252		$	267,854


Operating costs and expenses:
Lease operating expenses		52,457			54,080			87,823			104,311
Production taxes		283			580			512			1,290
Gathering and transportation		3,726			3,755			8,313			6,350
Depreciation, depletion and amortization		69,895			74,515			132,819			155,303
Asset retirement obligation accretion		6,127			10,080			12,412			20,827
Impairment of oil and natural gas properties		—			—			—			218,871
General and administrative expenses		14,375			10,731			24,754			22,167
Derivative (gain) loss		(7,374	)		460			(13,270	)		852

Total costs and expenses		139,489			154,201			253,363			529,971

Operating income (loss)		40,178			(3,769	)		95,889			(262,117	)
Interest expense:
Incurred		10,914			11,740			21,834			24,249
Capitalized		(1,329	)		(1,722	)		(2,745	)		(3,504	)
Loss on extinguishment of debt		—			2,926			—			2,926
Other income		354			218			482			723

Income (loss) before income tax expense (benefit)		30,947			(16,495	)		77,282			(285,065	)
Income tax expense (benefit)		3,077			(10,521	)		7,097			(34,513	)

Net income (loss)	$	27,870		$	(5,974	)	$	70,185		$	(250,552	)


Basic and diluted earnings (loss) per common share	$	0.37		$	(0.08	)	$	0.94		$	(3.33	)
Dividends declared per common share	$	0.03		$	0.03		$	0.06		$	0.06

See Notes to Condensed Consolidated Financial Statements.

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY


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

Balances at December 31, 2009	74,711		$	1	$	373,050	$	10,066		2,869	$	(24,167	)	$	358,950
Cash dividends	—			—		—		(4,479	)	—		—			(4,479	)
Share-based compensation	—			—		1,943		—		—		—			1,943
Restricted stock issued, net of forfeitures	(25	)		—		—		—		—		—			—
Net income	—			—		—		70,185		—		—			70,185

Balances at June 30, 2010	74,686		$	1	$	374,993	$	75,772		2,869	$	(24,167	)	$	426,599

See Notes to Condensed Consolidated Financial Statements.

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six Months Ended June 30,
	2010			2009
	(In thousands) (Unaudited)

Operating activities:
Net income (loss)	$	70,185		$	(250,552	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		145,231			179,230
Impairment of oil and natural gas properties		—			218,871
Amortization of debt issuance costs and discount on indebtedness		669			1,176
Loss on extinguishment of debt		—			2,817
Share-based compensation related to restricted stock issuances		1,943			3,116
Derivative (gain) loss		(13,270	)		852
Cash payments on derivative settlements		(442	)		(2,871	)
Deferred income taxes		2,945			(158	)
Other		—			458
Changes in operating assets and liabilities:
Oil and natural gas receivables		(11,739	)		(16,988	)
Joint interest and other receivables		21,931			21,475
Insurance receivables		29,879			(3,392	)
Income taxes		91,513			(16,799	)
Prepaid expenses and other assets		(9,129	)		(27,004	)
Asset retirement obligations		(35,210	)		(30,969	)
Accounts payable and accrued liabilities		(62,542	)		(32,502	)
Other liabilities		12,354			(347	)

Net cash provided by operating activities		244,318			46,413


Investing activities:
Acquisition of property interests		(116,589	)		—
Investment in oil and natural gas properties and equipment		(89,705	)		(239,684	)
Proceeds from sales of oil and natural gas properties and equipment		1,335			8,368
Proceeds from insurance		—			5,260
Purchases of furniture, fixtures and other		(167	)		(479	)

Net cash used in investing activities		(205,126	)		(226,535	)


Financing activities:
Borrowings of long-term debt		285,000			205,441
Repayments of long-term debt		(285,000	)		(268,441	)
Dividends to shareholders		(4,481	)		(4,581	)
Repurchases of common stock		—			(9,247	)
Other		—			131

Net cash used in financing activities		(4,481	)		(76,697	)

Increase (decrease) in cash and cash equivalents		34,711			(256,819	)
Cash and cash equivalents, beginning of period		38,187			357,552

Cash and cash equivalents, end of period	$	72,898		$	100,733

See Notes to Condensed Consolidated Financial Statements.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

Operations. W&T Offshore, Inc. and subsidiaries, referred to herein as “W&T” or the “Company,” is an independent oil and natural gas producer, active in the acquisition, exploitation, exploration and development of oil and natural gas properties primarily in the Gulf of Mexico.

Interim Financial Statements. The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) for interim financial information and the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, the condensed consolidated financial statements do not include all of the information and footnote disclosures required by GAAP for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. The accompanying financial statements for the six months ended June 30, 2010 include a reduction of hurricane remediation, facilities and workover expenses totaling approximately $5.1 million related to prior years. The amounts were recorded in the first quarter of 2010 and were not deemed material with respect to such prior years or the anticipated results and the trend of earnings for fiscal year 2010. Operating results for interim periods are not necessarily indicative of the results that may be expected for the entire year. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009.

Reclassifications. Certain reclassifications have been made to prior periods’ financial statements to conform to the current presentation.

Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

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

2. Recent Accounting Pronouncements

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

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

3. Asset Retirement Obligations

Our asset retirement obligations primarily represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives in accordance with applicable laws. A summary of our asset retirement obligations is as follows (in thousands):


Balance, December 31, 2009	$	348,800
Liabilities settled		(35,210	)
Accretion of discount		12,412
Disposition of properties		(1,520	)
Liabilities assumed through acquisition		6,289
Revisions of estimated liabilities due to Hurricane Ike		11,088
Revisions of estimated liabilities – all other		2,954

Balance, June 30, 2010		344,813
Less current portion		99,474

Long-term	$	245,339

4. Acquisition

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

5. Long-Term Debt

At June 30, 2010 and December 31, 2009, borrowings outstanding under our 8.25% Senior notes (the “Notes”) were $450.0 million, all of which are classified as long-term, and we had no amounts outstanding under our committed revolving loan facility. Also at June 30, 2010 and December 31, 2009, we had $0.3 million and $0.7 million, respectively, of letters of credit outstanding under the Third Amended and Restated Credit Agreement, as amended (the “Credit Agreement”), which governs our revolving loan facility and is described below.

Borrowings under the Credit Agreement are secured by our oil and natural gas properties. Availability under the Credit Agreement is subject to a semi-annual borrowing base redetermination (March and September) set at the discretion of our lenders. The amount of the borrowing base is calculated by our lenders based on their valuation of our proved reserves and their own internal criteria. In April 2010, our borrowing base under the Credit Agreement was reaffirmed by our lenders at $405.5 million. In July 2010, we borrowed $142.5 million under our revolving loan facility.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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

The Notes bear interest at a fixed rate of 8.25%, with interest payable semi-annually in arrears on June 15 and December 15. At June 30, 2010 and December 31, 2009, the estimated fair value of the Notes was approximately $405.0 million and $432.0 million, respectively, based on quoted prices. The estimated annual effective interest rate on the Notes is 8.4%.

6. Fair Value Measurements

We measure the fair value of our derivative financial instruments by applying the income approach, using models with inputs that are classified within Level 2 of the valuation hierarchy. The inputs used in measuring the fair value of our derivative financial instruments consist of market-based or independently-sourced market parameters, including but not limited to forward curves for oil, natural gas and interest rates, and volatilities. In addition to market information, the models also incorporate the contractual terms of the instruments. The fair values of our derivative assets and liabilities include adjustments for credit risk and were $5.1 million and $1.1 million, respectively, at June 30, 2010, and $0.1 million and $9.9 million, respectively, at December 31, 2009. For additional details about our derivative financial instruments, refer to Note 7. The estimated fair value of the Notes, as disclosed in Note 5, was based on quoted prices, which are classified as Level 1 inputs.

7. Derivative Financial Instruments

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

Our market risk exposure relates primarily to commodity prices and interest rates. From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our revolving loan facility. We do not enter into derivative instruments for speculative trading purposes. Our derivative instruments currently consist of commodity option contracts, a commodity swap contract and an interest rate swap contract. The Company is exposed to credit loss in the event of nonperformance by the counterparties; however, none is currently anticipated.

Commodity Derivatives. We have entered into a limited number of commodity option contracts and a commodity swap contract to help manage our exposure to commodity price risk from sales of oil and natural gas during the fiscal years ending December 31, 2010 and 2011. We have elected not to designate our commodity derivatives as hedging instruments. While these contracts are intended to reduce the effects of volatile oil and natural gas prices, they may also limit future income from favorable price movements. As of June 30, 2010, our open commodity derivatives were as follows:


Zero Cost Collars – Oil
			Weighted Average				Fair Value
Effective	Termination	Notional	NYMEX Contract Price				Asset
Date	Date	Quantity (Bbls)	Floor		Ceiling		(in thousands)
7/1/2010	9/30/2010	310,300	$	71.54	$	86.83	$	175
10/1/2010	12/31/2010	420,650		71.95		89.07		444
1/1/2011	3/31/2011	434,200		75.00		94.62		1,271
4/1/2011	6/30/2011	382,100		75.00		94.60		957
7/1/2011	9/30/2011	151,300		75.00		94.68		343
10/1/2011	12/31/2011	244,900		75.00		96.08		547

		1,943,450	$	73.79	$	92.36	$	3,737

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Zero Cost Collars – Natural Gas



Effective Date	Termination Date	Notional Quantity (MMBtu)	Weighted Average NYMEX Contract Price				Fair Value Asset (in thousands)
Effective Date	Termination Date	Notional Quantity (MMBtu)	Floor		Ceiling		Fair Value Asset (in thousands)
8/1/2010	9/30/2010	708,500	$	5.00	$	6.73	$	352
10/1/2010	12/31/2010	1,831,800		5.00		8.35		696

		2,540,300	$	5.00	$	7.90	$	1,048

Swap – Natural Gas



Effective Date	Termination Date	Notional Quantity (MMBtu)	Swap Price		Fair Value Asset (in thousands)
8/1/2010	12/31/2010	306,000	$	5.71	$	214

Changes in the fair value of our commodity derivative contracts are recognized currently in earnings. For the three and six months ended June 30, 2010, we recognized gains of $7.4 million and $13.6 million, respectively, related to a change in the fair value of our commodity derivatives. We did not have any open commodity derivative positions during the three and six months ended June 30, 2009.

At June 30, 2010, $4.2 million was included in prepaid expenses and other assets, $0.9 million was included in other assets and $0.1 million was included in accrued liabilities related to our open commodity derivative contracts. At December 31, 2009, $0.1 million was included in prepaid expenses and other assets and $5.5 million was included in accrued liabilities related to our open commodity derivative contracts.

Interest Rate Swap. We have one interest rate swap contract outstanding with a fixed interest rate of 5.21%, which expires in August 2010. Initially, this swap was designated as a hedge of the floating-rate interest payments on our Tranche B term loan facility. However, as a result of payments on the loan and changes to the swap contract, hedge accounting was discontinued completely in 2007. Changes in fair value subsequent to the discontinuation of hedge accounting have been immediately recognized in earnings. As of June 30, 2010, the total notional amount of our swap was $145.5 million.

For the six months ended June 30, 2010, we recognized a loss of $0.3 million related to a change in the fair value of our interest rate swap. For the three and six months ended June 30, 2009, we recognized a loss of $0.5 million and $0.9 million, respectively, related to a change in the fair value of our interest rate swap.

At June 30, 2010 and December 31, 2009, the fair value of our interest rate swap was $1.0 million and $4.4 million, respectively. Both amounts were included in accrued liabilities on the respective dates.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

8. Income Taxes

Income tax expense of $3.1 million and $7.1 million was recorded during the three and six months ended June 30, 2010, respectively, compared to an income tax benefit of $10.5 million and $34.5 million for the same periods of 2009. Our effective tax rate for the three and six months ended June 30, 2010 was approximately 9.9% and 9.2%, respectively, and primarily reflects a reduction in our valuation allowance against our deferred tax assets. Our effective tax rate for the quarter ended June 30, 2009 was approximately 63.8% and primarily reflected adjustments to our forecasted annual tax rate. Our effective tax rate for the six months ended June 30, 2009 was approximately 12.1% and primarily reflected the effect of a valuation allowance against our deferred tax assets.

During the second quarter of 2010, we received refunds of federal income taxes paid in prior years totaling $99.7 million, consisting primarily of carrybacks of net operating losses generated in 2009 and 2008. Approximately $12.3 million of these refunds were subject to recognition limitations in accordance with the Income Taxes Topic of the Codification, and as a result, during the second quarter of 2010, we recorded an unrecognized tax benefit of $12.3 million plus interest thereon in other liabilities. No potential benefits are included in the balance of unrecognized tax benefits that would affect the effective tax rate on income from continuing operations if recognized.

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

9. Hurricane Remediation and Insurance Claims

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

Included in lease operating expenses for the three months ended June 30, 2010 are hurricane remediation costs of $2.1 million related to Hurricanes Ike and Gustav that were either not yet approved for payment under our insurance policies or were not covered by insurance. Included in lease operating expenses for the six months ended June 30, 2010 is a reduction of $4.2 million related to amounts approved for payment under our insurance policies and revisions to previous estimates (see Note 1 Basis of Presentation – Interim Financial Statements) of hurricane remediation costs incurred in connection with Hurricanes Ike and Gustav. Included in lease operating expenses for the three and six months ended June 30, 2009 are hurricane remediation costs of $5.0 million and $15.2 million, respectively, related to Hurricanes Ike and Gustav that were either not yet approved for payment or were not covered by insurance.

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

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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

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


Balance, December 31, 2009	$	30,543

Costs approved under our insurance policies:
Remediation		2,357
Plugging and abandonment		13,452
Payments received:
Remediation		(3,525	)
Plugging and abandonment		(28,979	)

Balance, June 30, 2010	$	13,848

At June 30, 2010 and December 31, 2009, $0.1 million and $1.3 million, respectively, of remediation costs and $13.7 million and $29.2 million, respectively, related to the plugging and abandonment of wells and dismantlement of facilities damaged by Hurricanes Ike and Gustav are included in insurance receivables. We expect that our available cash and cash equivalents, cash flow from operations and the availability under our revolving loan facility will be sufficient to meet any necessary expenditures that may exceed our insurance coverage for damages incurred as a result of Hurricanes Ike and Gustav.

10. Incentive Compensation

We recognize compensation cost for share-based payments to employees and non-employee directors over the period during which the recipient is required to provide service in exchange for the award, based on the fair value of the equity instrument on the date of grant. A summary of share activity pursuant to our share-based payment plans for the six months ended June 30, 2010, is as follows:


	Restricted Shares		Weighted Average Grant Date Price Per Share
Nonvested at December 31, 2009	1,050,506		$	8.48
Granted	35,000			10.00
Vested	(14,424	)		17.81
Forfeited	(59,957	)		8.44

Nonvested at June 30, 2010	1,011,125			8.40

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

At June 30, 2010, the composition of our nonvested shares outstanding, by year granted, was as follows:


	Restricted Shares
Employees – granted in:
2009	900,572	(1)
2008	51,820	(2)

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


Total	1,011,125

Vesting is expected to occur as follows, less any forfeited shares:

(1)	Equal installments in December 2010 and 2011.

(2)	December 2010.

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

(4)	Equal installments in May 2011 and 2012.

(5)

May 2011.

At June 30, 2010, there were 1,920,332 shares of common stock available for award under the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan and 583,891 shares of common stock available for award under the Directors Compensation Plan.

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

Total compensation expense under share-based payment arrangements was $1.0 million ($0.9 million, net of tax) and $1.9 million ($1.8 million, net of tax), during the three and six months ended June 30, 2010, respectively. During the three and six months ended June 30, 2009, total compensation expense under share-based payment arrangements was $2.6 million ($0.9 million, net of tax) and $4.2 million ($3.7 million, net of tax), respectively. As of June 30, 2010, there was $4.7 million of total unrecognized share-based compensation expense related to restricted shares issued. Such amount is expected to be recognized in the period beginning July 2010 and ending April 2013.

During the second quarter of 2010, the Company’s shareholders approved certain amendments to its long-term incentive compensation plan, resulting in the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (the “Plan”). Among other things, the amendments ensure the Plan’s continued compliance with Section 162(m) of the Internal Revenue Code of 1986, as amended. During the three and six months ended June 30, 2010, we expensed $2.2 million and $2.9 million, respectively, pursuant to the Plan related to incentive compensation for the 2010 Plan year.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

11. Earnings (Loss) Per Share

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


	Three Months Ended June 30,					Six Months Ended June 30,
	2010		2009			2010		2009
Net income (loss)	$	27,870	$	(5,974	)	$	70,185	$	(250,552	)
Less portion allocated to nonvested shares		379		—			957		—

Net income (loss) allocated to common shares	$	27,491	$	(5,974	)	$	69,228	$	(250,552	)


Weighted average common shares outstanding		73,669		74,642			73,665		75,308


Basic earnings (loss) per common share	$	0.37	$	(0.08	)	$	0.94	$	(3.33	)

Diluted earnings (loss) per common share is the same as basic earnings (loss) per common share because the nonvested shares outstanding during the periods are anti-dilutive.

12. Dividends

During each of the six month periods ended June 30, 2010 and 2009, we paid regular cash dividends of $0.06 per common share. On August 2, 2010, our board of directors declared a cash dividend of $0.04 per common share, payable on September 10, 2010 to shareholders of record on August 20, 2010.

13. Contingencies

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

14. Supplemental Guarantor Information

Our payment obligations under the Notes and the Credit Agreement (see Note 5) are fully and unconditionally guaranteed by our wholly-owned subsidiary, Energy VI (“Guarantor Subsidiary”). The guaranty of the Credit Agreement became effective on April 30, 2010. These guarantees are the joint and several obligations of Energy VI. The following unaudited condensed consolidating financial information presents the financial condition, results of operations and cash flows of W&T Offshore, Inc. and Energy VI, together with consolidating adjustments necessary to present the Company’s results on a consolidated basis.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Condensed Consolidating Balance Sheet as of June 30, 2010


	Parent Company			Guarantor Subsidiary		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands, except share data)
Assets

Current assets:
Cash and cash equivalents	$	72,898		$	—	$	—		$	72,898
Receivables:
Oil and natural gas sales		57,118			9,599		—			66,717
Joint interest and other		29,381			—		—			29,381
Insurance		13,848			—		—			13,848
Income taxes		—			842		(842	)		—

Total receivables		100,347			10,441		(842	)		109,946
Prepaid expenses and other assets		40,723			—		—			40,723

Total current assets		213,968			10,441		(842	)		223,567
Property and equipment – at cost:
Oil and natural gas properties and equipment (full cost method, of which $64,605 at June 30, 2010 and $77,301 at December 31, 2009 were excluded from amortization)		4,820,405			122,878		—			4,943,283
Furniture, fixtures and other		15,248			—		—			15,248

Total property and equipment		4,835,653			122,878		—			4,958,531
Less accumulated depreciation, depletion and amortization		3,879,736			6,064		—			3,885,800

Net property and equipment		955,917			116,814		—			1,072,731
Restricted deposits for asset retirement obligations		31,281			—		—			31,281
Deferred income taxes		8,776			—		(2,801	)		5,975
Other assets		128,124			5,155		(125,383	)		7,896

Total assets	$	1,338,066		$	132,410	$	(129,026	)	$	1,341,450


Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	52,146		$	2,895	$	—		$	55,041
Undistributed oil and natural gas proceeds		25,027			100		—			25,127
Asset retirement obligations		99,474			—		—			99,474
Accrued liabilities		9,982			—		—			9,982
Income taxes		6,897			—		(842	)		6,055
Deferred income taxes		8,921			—		—			8,921

Total current liabilities		202,447			2,995		(842	)		204,600
Long-term debt		450,000			—		—			450,000
Asset retirement obligations, less current portion		238,953			6,386		—			245,339
Deferred income taxes		—			2,801		(2,801	)		—
Other liabilities		20,067			—		(5,155	)		14,912
Commitments and contingencies
Shareholders’ equity:
Common stock, $0.00001 par value; 118,330,000 shares authorized; 77,555,011 issued and 74,685,838 outstanding at June 30, 2010; 77,579,968 issued and 74,710,795 outstanding at December 31, 2009		1			—		—			1
Additional paid-in capital		374,993			116,589		(116,589	)		374,993
Retained earnings		75,772			3,639		(3,639	)		75,772
Treasury stock, at cost		(24,167	)		—		—			(24,167	)

Total shareholders’ equity		426,599			120,228		(120,228	)		426,599

Total liabilities and shareholders’ equity	$	1,338,066		$	132,410	$	(129,026	)	$	1,341,450

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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


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

Revenues	$	160,511		$	19,156	$	—		$	179,667


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

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

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

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

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

Condensed Consolidating Statement of Income for the Six Months Ended June 30, 2010
	Parent Company			Guarantor Subsidiary		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)

Revenues	$	330,096		$	19,156	$	—		$	349,252


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

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

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

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

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

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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


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

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

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


Investing activities:
Acquisition of property interests		—			(116,589	)		—			(116,589	)
Investment in oil and natural gas properties and equipment		(89,705	)		—			—			(89,705	)
Proceeds from sales of oil and natural gas properties and equipment		1,335			—			—			1,335
Investment in subsidiary		(116,589	)		—			116,589			—
Purchases of furniture, fixtures and other		(167	)		—			—			(167	)

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


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

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

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

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

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements

The following discussion and analysis should be read in conjunction with our accompanying unaudited condensed consolidated financial statements and the notes to those financial statements included in Item 1 of this Quarterly Report on Form 10-Q. The following discussion contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Exchange Act, that involve risks, uncertainties and assumptions. If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions. All statements other than statements of historical fact are statements that could be deemed forward-looking statements, such as those statements that address activities, events or developments that we expect, believe or anticipate will or may occur in the future. These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. Certain factors that may affect our financial condition and results of operations are discussed in Item 1A “Risk Factors” and Item 7A “Quantitative and Qualitative Disclosures About Market Risk” of our Annual Report on Form 10-K for the year ended December 31, 2009 and may be discussed or updated from time to time in subsequent reports filed with the SEC. We assume no obligation, nor do we intend, to update these forward-looking statements. Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q to “W&T,” “we,” “us,” “our” and the “Company” refer to W&T Offshore, Inc. and its consolidated subsidiaries.

Overview

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

Our financial condition, cash flow and results of operations are significantly affected by the volume of our oil and natural gas production and the price that we receive for such production. Our production volume for the six months ended June 30, 2010 was comprised of approximately 48% oil and 52% natural gas, determined using the ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of crude oil, condensate or natural gas liquids. During the six months ended June 30, 2010, our combined total production of oil and natural gas was approximately 7.4% lower compared to the same period in 2009.

Oil and natural gas prices have been and are expected to remain volatile. The Henry Hub spot price for natural gas was $4.53 per MMBtu as of June 30, 2010, representing a decrease of 21.8% from $5.79 per MMBtu at the end of 2009. We are expecting continued weakness in natural gas prices unless demand for natural gas increases as a result of a strong economic recovery, or there is reduced drilling activity or forced production shut-ins. There is also a risk that, as a result of successful exploration and development activities in the shale areas coupled with the availability of increasing amounts of liquefied natural gas, increased supplies of natural gas will offset or mitigate the impact of any natural gas shut-ins or demand increases resulting from improved economic conditions. According to industry sources, the rig count for horizontal drilling rigs, used primarily in the shale formation areas of Louisiana, Arkansas and Texas, has reached or exceeded record levels. Natural gas production and supply continues to exceed demand. Onshore natural gas producers have continued to drill in lease-saving attempts, protected by hedges entered into during earlier periods when prices were much higher than current levels, allowing funding of projects that continue to increase supply to an already oversupplied market. Seasonal weather conditions also impact the demand for and price of natural gas.

The West Texas Intermediate posted price for oil was $72.00 per barrel as of June 30, 2010, representing a decrease of 5.3% from $76.00 per barrel at the end of 2009. Long-term forecasts for oil demand, and therefore global oil prices, continue to be favorable in several key growing markets, specifically China and India.

During the six months ended June 30, 2010, the average realized sales prices of our oil and natural gas were 56.9% and 9.2% higher, respectively, than the comparable average realized sales prices during the same period in 2009, which contributed to higher cash provided by operating activities in the 2010 period. Declines in oil and natural gas prices after June 30, 2010, if those were to occur, would negatively impact our future oil and natural gas revenues, earnings and liquidity, and could result in ceiling test write-downs of the carrying value of our oil and natural gas properties, issues with financial ratio compliance, and a reduction of the borrowing base associated with our credit agreement. Such declines, if those were to occur, may limit the willingness of financial institutions and investors to provide borrowings or capital to us and others in the oil and natural gas industry.

On April 20, 2010, the Transocean Deepwater Horizon drilling rig, operating on Mississippi Canyon Block 252, 130 miles south of New Orleans, Louisiana, experienced a fire and subsequently sank. The resulting release of crude oil into the Gulf of Mexico has been declared a Spill of National Significance by the United States Department of Homeland Security, and the spill continues to harm the marine ecosystem, wildlife, property and industries along the Gulf Coast of the United States. We do not have any ownership interest in this field.

In response to the Deepwater Horizon incident, the BOEM issued a Notice to Lessees and Operators (“NTL”), effective May 30, 2010, which imposed a six-month moratorium on the issuance of permits for the drilling of new deepwater wells in the Gulf of Mexico. This NTL also called for the cessation of deepwater wells that were currently being drilled. Although a federal judge in New Orleans subsequently blocked the six-month moratorium in late June, the Secretary of the Interior directed the BOEM to issue a revised and more specific moratorium. The revised moratorium prohibits the drilling of any new wells that utilize subsea blowout preventers or surface blowout preventers on a floating facility, which are used primarily in deepwater drilling activities, and requires operators that were in the process of drilling affected wells to proceed to the next safe opportunity to secure and temporarily abandon such wells through November 30, 2010, subject to modification by the BOEM. We were not in the process of drilling any deepwater wells when the original moratorium went into effect; however, the revised moratorium may cause our anticipated recompletion work at the recently acquired Matterhorn and Virgo fields to be delayed. As a further result of the revised moratorium, the permitting process related to any new deepwater wells that we may contemplate drilling could be prolonged and more costly. The original moratorium and the anticipation of the revised moratorium has caused drilling rig operators to move or contemplate moving their rigs to locations outside of the Gulf of Mexico. If and when we require the use of a deepwater drilling rig, the potentially reduced inventory of such rigs could cause delays in timing and result in additional costs. As a result, we may experience delays in drilling, completion and ultimately, production activities, which would negatively impact our financial position, cash flows and results of operations.

Another NTL was issued in response to the Deepwater Horizon incident, effective June 8, 2010, that set forth additional safety requirements applicable to oil and natural gas operations in both the deepwater and shallow water. These additional safety requirements direct, among other things, operators to certify to the BOEM their compliance with existing safety regulations and require all new wells to have an independent third-party verification that the blowout preventer is compatible with the specific well location, well design and well execution plan. We do not expect the additional safety requirements set forth by this NTL to have a significant impact on our operations. However, we cannot predict the ultimate impact the Deepwater Horizon incident and resulting changes in regulations and perceptions of offshore oil and natural gas operations will have on us.

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

Results of Operations

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


	Three Months Ended June 30,											Six Months Ended June 30,
	2010			2009			Change			%		2010			2009 (1)			Change			%
	(In thousands, except percentages and per share data)
Financial:
Revenues:
Oil	$	124,762		$	98,532		$	26,230		26.6	%	$	240,242		$	152,127		$	88,115		57.9	%
Natural gas		54,719			51,895			2,824		5.4	%		108,789			115,716			(6,927	)	(6.0	%)
Other (2)		186			5			181		NM			221			11			210		NM

Total revenues (3)		179,667			150,432			29,235		19.4	%		349,252			267,854			81,398		30.4	%
Operating costs and expenses:
Lease operating expenses (4)		52,457			54,080			(1,623	)	(3.0	%)		87,823			104,311			(16,488	)	(15.8	%)
Production taxes		283			580			(297	)	(51.2	%)		512			1,290			(778	)	(60.3	%)
Gathering and transportation		3,726			3,755			(29	)	(0.8	%)		8,313			6,350			1,963		30.9
Depreciation, depletion, amortization and accretion		76,022			84,595			(8,573	)	(10.1	%)		145,231			176,130			(30,899	)	(17.5	%)
Impairment of oil and natural gas properties (1)		—			—			—		—			—			218,871			(218,871	)	(100.0	%)
General and administrative expenses		14,375			10,731			3,644		34.0	%		24,754			22,167			2,587		11.7	%
Derivative (gain) loss (2)		(7,374	)		460			(7,834	)	NM			(13,270	)		852			(14,122	)	NM

Total costs and expenses		139,489			154,201			(14,712	)	(9.5	%)		253,363			529,971			(276,608	)	(52.2	%)

Operating income (loss) (2)		40,178			(3,769	)		43,947		NM			95,889			(262,117	)		358,006		136.6	%
Interest expense, net of amounts capitalized		9,585			10,018			(433	)	(4.3	%)		19,089			20,745			(1,656	)	(8.0	%)
Loss on extinguishment of debt		—			2,926			(2,926	)	(100.0	%)		—			2,926			(2,926	)	(100.0	%)
Other income		354			218			136		62.4	%		482			723			(241	)	(33.3	%)

Income (loss) before income tax expense (benefit)		30,947			(16,495	)		47,442		287.6	%		77,282			(285,065	)		362,347		127.1	%
Income tax expense (benefit)		3,077			(10,521	)		13,598		129.2	%		7,097			(34,513	)		41,610		120.6	%

Net income (loss)	$	27,870		$	(5,974	)	$	33,844		566.5	%	$	70,185		$	(250,552	)	$	320,737		128.0	%

Basic and diluted earnings (loss) per common share	$	0.37		$	(0.08	)	$	0.45		562.5	%	$	0.94		$	(3.33	)	$	4.27		128.2	%

	Three Months Ended June 30,											Six Months Ended June 30,
	2010			2009			Change			%		2010			2009			Change			%
Operating:
Net sales:
Natural gas (Bcf)		12.3			13.3			(1.0	)	(7.5	%)		22.3			25.9			(3.6	)	(13.9	%)
Oil (MMBbls)		1.7			1.9			(0.2	)	(10.5	%)		3.4			3.4			—		—
Total natural gas and oil (Bcfe) (5) (6)		22.8			24.8			(2.0	)	(8.1	%)		42.8			46.2			(3.4	)	(7.4	%)
Average daily equivalent sales (MMcfe/d)		250.5			272.6			(22.1	)	(8.1	%)		236.2			255.4			(19.2	)	(7.5	%)
Average realized sales prices (Unhedged):
Natural gas ($/Mcf)	$	4.47		$	3.89		$	0.58		14.9	%	$	4.88		$	4.47		$	0.41		9.2	%
Oil ($/Bbl)		70.97			51.61			19.36		37.5	%		70.48			44.93			25.55		56.9	%
Natural gas equivalent ($/Mcfe)		7.87			6.06			1.81		29.9	%		8.16			5.79			2.37		40.9	%
Average realized sales prices (Hedged):
Natural gas ($/Mcf)	$	4.65		$	3.89		$	0.76		19.5	%	$	5.06		$	4.47		$	0.59		13.2	%
Oil ($/Bbl)		70.90			51.61			19.29		37.4	%		70.21			44.93			25.28		56.3	%
Natural gas equivalent ($/Mcfe)		7.97			6.06			1.91		31.5	%		8.24			5.79			2.45		42.3	%
Average per Mcfe ($/Mcfe):
Lease operating expenses (4)	$	2.30		$	2.18		$	0.12		5.5	%	$	2.05		$	2.26		$	(0.21	)	(9.3	%)
Gathering and transportation		0.16			0.15			0.01		6.7	%		0.19			0.14			0.05		35.7	%

Production costs		2.46			2.33			0.13		5.6	%		2.24			2.40			(0.16	)	(6.7	%)
Production taxes		0.01			0.02			(0.01	)	(50.0	%)		0.01			0.03			(0.02	)	(66.7	%)
Depreciation, depletion, amortization and accretion		3.33			3.41			(0.08	)	(2.3	%)		3.40			3.81			(0.41	)	(10.8	%)
General and administrative expenses		0.63			0.43			0.20		46.5	%		0.58			0.48			0.10		20.8	%

	$	6.43		$	6.19		$	0.24		3.9	%	$	6.23		$	6.72		$	(0.49	)	(7.3	%)

Total number of wells drilled (gross)		2			6			(4	)	(66.7	%)		5			10			(5	)	(50.0	%)
Total number of productive wells drilled (gross)		2			4			(2	)	(50.0	%)		4			7			(3	)	(42.9	%)

(1)

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

(2)	Percentage change not meaningful (“NM”).

(3)

Included in total revenues for the three and six months ended June 30, 2010 is $20.1 million related to the recoupment of royalties paid to the BOEM in prior periods based on price thresholds that were believed to limit the availability of royalty relief on certain of our properties subject to the Outer Continental Shelf (“OCS”) Deepwater Royalty Relief Act of 1995.

(4)

Included in lease operating expenses for the three months ended June 30, 2010 are hurricane remediation costs of $2.1 million related to Hurricanes Ike and Gustav that were either not yet approved for payment under our insurance policies or were not covered by insurance. Included in lease operating expenses for the six months ended June 30, 2010 is a reduction of $4.2 million related to amounts approved for payment under our insurance policies and revisions to previous estimates of hurricane remediation costs incurred in connection with Hurricanes Ike and Gustav. Included in lease operating expenses for the three and six months ended June 30, 2009 are hurricane remediation costs of $5.0 million and $15.2 million, respectively, related to Hurricanes Ike and Gustav that were either not yet approved for payment or were not covered by insurance.

(5)	One billion cubic feet equivalent (Bcfe), one million cubic feet equivalent (MMcfe) and one thousand cubic feet equivalent (Mcfe) are determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids (totals may not add due to rounding).

(6)	Included in natural gas and oil sales volumes for the three and six months ended June 30, 2010 is approximately 2.5 Bcfe related to the recoupment of royalties paid to the BOEM in prior periods as noted above.

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

Revenues. Total revenues increased $29.2 million to $179.7 million for the three months ended June 30, 2010 as compared to the same period in 2009. Oil revenues increased $26.2 million, natural gas revenues increased $2.8 million and other revenues increased $0.2 million. The oil revenue increase was attributable to a 37.5% increase in the average realized oil sales price to $70.97 per barrel for the three months ended June 30, 2010 from $51.61 per barrel for the same period in 2009, partially offset by a 10.5% decrease in sales volumes. Included in oil revenues and sales volumes for the three months ended June 30, 2010 is approximately $6.2 million and 0.1 MMBbls, respectively, related to the recoupment of royalties paid to the BOEM in prior periods based on price thresholds that were believed to limit the availability of royalty relief on certain of our properties subject to the OCS Deepwater Royalty Relief Act of 1995. Excluding those additional oil sales volumes, the sales volume decrease for oil (0.3 MMBbls) is primarily attributable to decreases resulting from the sale of one of our fields in Louisiana state waters in June 2009, the sale of 36 non-core oil and natural gas fields in the fourth quarter of 2009 and natural reservoir declines, partially offset by an increase associated with the Matterhorn and Virgo fields we purchased in the second quarter of 2010. The increase in natural gas revenue resulted from a 14.9% increase in the average realized natural gas sales price to $4.47 per Mcf in the 2010 period from $3.89 per Mcf in the 2009 period, partially offset by a 7.5% decrease in sales volumes. Included in natural gas revenues and sales volumes for the three months ended June 30, 2010 is approximately $13.9 million and 2.0 Bcf, respectively, related to the recoupment of royalties paid to the BOEM in prior periods as described above. Excluding those additional natural gas sales volumes, the sales volume decrease for natural gas (3.0 Bcf) is primarily attributable to the property divestitures mentioned above and natural reservoir declines, partially offset by an increase associated with the Matterhorn and Virgo fields we purchased in the second quarter of 2010.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, insurance, workovers, maintenance on our facilities, hurricane remediation costs and insurance reimbursements of hurricane remediation costs, increased to $2.30 per Mcfe during the three months ended June 30, 2010 from $2.18 per Mcfe during the three months ended June 30, 2009. On a nominal basis, lease operating expenses decreased $1.6 million to $52.5 million in the second quarter of 2010, compared to the second quarter of 2009. Base lease operating expenses and facility expenditures decreased $5.8 million and $0.7 million, respectively, while insurance and workover costs increased $3.0 million and $4.8 million, respectively. Included in lease operating expenses for the 2010 and 2009 periods are hurricane remediation costs of $2.1 million and $5.0 million, respectively, related to Hurricanes Ike and Gustav that were either not yet approved for payment or were not covered by insurance. Lease operating expenses will be offset in future periods to the extent that costs incurred are approved for payment under our insurance policies. The decrease in base lease operating expenses primarily reflects the sale of certain properties in 2009 as described above, partially offset by an increase associated with the Matterhorn and Virgo fields we purchased in the second quarter of 2010. The increase in workover costs is related to numerous projects undertaken during the second quarter of 2010 in an effort to stimulate, maintain and/or restore production at various wells. In June 2010, we renewed our insurance policies covering well control and hurricane damage at a cost of approximately $20.7 million, representing a decrease of approximately 41% from 2009. The impact to lease operating expenses resulting from the lower premium will be reflected beginning in the third quarter of 2010.

Production taxes. Production taxes decreased to $0.3 million for the three months ended June 30, 2010 from $0.6 million for the same period in 2009 primarily due to the sale of one of our fields in Louisiana state waters in June 2009. Most of our production is from federal waters where there are no production taxes.

Gathering and transportation costs. Gathering and transportation costs decreased to $3.7 million for the three months ended June 30, 2010 from $3.8 million for the same period in 2009 primarily due to property divestitures in 2009, partially offset by an increase related to properties we purchased from Total in the second quarter of 2010.

Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion (“DD&A”) decreased to $76.0 million for the quarter ended June 30, 2010 from $84.6 million for the same period in 2009. DD&A decreased due to a lower depreciable base (including our estimate of the cost of asset retirement obligations) and lower production of oil and natural gas, partially offset by lower oil and natural gas reserves, compared to 2009. The decrease in our depreciable base reflects the sale of certain oil and natural gas fields in the fourth quarter of 2009, partially offset by an increase associated with the Matterhorn and Virgo fields we purchased in the second quarter of 2010. On a per Mcfe basis, DD&A was $3.33 for the quarter ended June 30, 2010, compared to $3.41 for the quarter ended June 30, 2009.

General and administrative expenses. General and administrative expenses (“G&A”) increased to $14.4 million for the three months ended June 30, 2010 from $10.7 million for the same period in 2009, primarily due to higher incentive compensation expense, additional G&A related to properties we purchased from Total in the second quarter of 2010 and higher travel-related expenses. On a per Mcfe basis, G&A was $0.63 per Mcfe for the three months ended June 30, 2010, compared to $0.43 per Mcfe for the same period in 2009.

Derivative gain/loss. For the three months ended June 30, 2010, our derivative gain of $7.4 million related entirely to a change in the fair value of our commodity derivatives. For the three months ended June 30, 2009, our derivative loss of $0.5 million related entirely to a change in the fair value of our interest rate swap. For additional details about our derivatives, refer to Item 1 Financial Statements – Note 7 – Derivative Financial Instruments.

Interest expense. Interest expense incurred decreased to $10.9 million for the quarter ended June 30, 2010 from $11.7 million for the quarter ended June 30, 2009 primarily due to lower amounts of borrowings outstanding during the 2010 period. During the 2010 and 2009 periods, $1.3 million and $1.7 million, respectively, of interest was capitalized to unevaluated oil and natural gas properties.

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

Income tax expense/benefit. Income tax expense increased to $3.1 million for the three months ended June 30, 2010 from an income tax benefit of $10.5 million for the same period of 2009. Our effective tax rate for the three months ended June 30, 2010 was approximately 9.9% and primarily reflects a reduction in our valuation allowance against our deferred tax assets. Forecasted taxable income in 2010 has allowed us to reduce a portion of our valuation allowance. For 2009, the income tax benefit resulted from a pre-tax loss. Our effective tax rate for the three months ended June 30, 2009 was approximately 63.8% and primarily reflected adjustments to our forecasted annual tax rate.

Six Months Ended June 30, 2010 Compared to the Six Months Ended June 30, 2009

Revenues. Total revenues increased $81.4 million to $349.3 million for the six months ended June 30, 2010 as compared to the same period in 2009. Oil revenues increased $88.1 million, natural gas revenues decreased $6.9 million and other revenues increased $0.2 million. The oil revenue increase was attributable to a 56.9% increase in the average realized oil sales price to $70.48 per barrel for the six months ended June 30, 2010 from $44.93 per barrel for the same period in 2009. Included in oil revenues and sales volumes for the six months ended June 30, 2010 is approximately $6.2 million and 0.1 MMBbls, respectively, related to the recoupment of royalties paid to the BOEM in prior periods as described above. Excluding those additional oil sales volumes, the sales volume decrease for oil (0.1 MMBbls) is primarily attributable to decreases resulting from the property divestitures mentioned above, partially offset by an increase associated with the Matterhorn and Virgo fields we purchased in the second quarter of 2010. The decrease in natural gas revenue resulted from a 13.9% decrease in sales volumes, partially offset by a 9.2% increase in the average realized natural gas sales price to $4.88 per Mcf in the 2010 period from $4.47 per Mcf in the 2009 period. Included in natural gas revenues and sales volumes for the six months ended June 30, 2010 is approximately $13.9 million and 2.0 Bcf, respectively, related to the recoupment of royalties paid to the BOEM in prior periods as described above. Excluding those additional natural gas sales volumes, the sales volume decrease for natural gas (5.6 Bcf) is primarily attributable to decreases resulting from the property divestitures mentioned above and natural reservoir declines, partially offset by an increase associated with the Matterhorn and Virgo fields we purchased in the second quarter of 2010.

Lease operating expenses. Lease operating expenses decreased to $2.05 per Mcfe during the six months ended June 30, 2010 from $2.26 per Mcfe during the six months ended June 30, 2009. On a nominal basis, lease operating expenses decreased $16.5 million to $87.8 million during the six months ended June 30, 2010, compared to the same period in 2009. Base lease operating expenses and facility expenditures decreased $12.4 million and $3.6 million, respectively, while insurance and workover costs increased $6.2 million and $12.7 million, respectively. Included in lease operating expenses for the 2010 period is a reduction of $4.2 million related to amounts approved for payment under our insurance policies and revisions to previous estimates (see Note 1 Basis of Presentation – Interim Financial Statements) of hurricane remediation costs incurred in connection with Hurricanes Ike and Gustav. Included in lease operating expenses for the 2009 period are hurricane remediation costs of $15.2 million related to Hurricanes Ike and Gustav that were either not yet approved for payment or were not covered by insurance. Lease operating expenses will be offset in future periods to the extent that costs incurred are approved for payment under our insurance policies. The decrease in base lease operating expenses primarily reflects the sale of certain properties in 2009 as described above, partially offset by an increase associated with the Matterhorn and Virgo fields we purchased in the second quarter of 2010. The increase in workover costs is related to numerous projects undertaken in 2010 in an effort to stimulate, maintain and/or restore production at various wells. In June 2010, we renewed our insurance policies covering well control and hurricane damage at a cost of approximately $20.7 million, representing a decrease of approximately 41% from 2009. The impact to lease operating expenses resulting from the lower premium will be reflected beginning in the third quarter of 2010.

Production taxes. Production taxes decreased to $0.5 million for the six months ended June 30, 2010 from $1.3 million for the same period in 2009 primarily due to the sale of one of our fields in Louisiana state waters in June of 2009. Most of our production is from federal waters where there are no production taxes.

Gathering and transportation costs. Gathering and transportation costs increased to $8.3 million for the six months ended June 30, 2010 from $6.4 million for the same period in 2009 primarily due to increases resulting from higher throughput of natural gas liquids at our processing facilities and the purchase of properties from Total in the 2010 period, partially offset by a decrease resulting from property divestitures in 2009.

Depreciation, depletion, amortization and accretion. DD&A decreased to $145.2 million for the six months ended June 30, 2010 from $176.1 million for the same period in 2009. DD&A decreased due to a lower depreciable base (including our estimate of the cost of asset retirement obligations) and lower production of oil and natural gas, partially offset by lower oil and natural gas reserves, compared to 2009. The decrease in our depreciable base reflects the sale of certain oil and natural gas fields in the second and fourth quarters of 2009, partially offset by an increase associated with the Matterhorn and Virgo fields we purchased in the second quarter of 2010. The decrease in our depreciable base also reflects lower future development costs in the first quarter of 2010 due to the write-off of certain proved undeveloped reserves at the end of 2009 in connection with new reserve reporting requirements for oil and natural gas companies enacted by the SEC and the FASB. On a per Mcfe basis, DD&A was $3.40 for the six months ended June 30, 2010, compared to $3.81 for the same period in 2009.

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

General and administrative expenses. G&A increased to $24.8 million for the six months ended June 30, 2010 from $22.2 million for the same period in 2009, primarily due to additional G&A related to properties we purchased from Total in the second quarter of 2010, reduced overhead charges billed to joint operators and higher legal and professional fees, travel-related expenses and incentive compensation. On a per Mcfe basis, G&A was $0.58 per Mcfe for the six months ended June 30, 2010, compared to $0.48 per Mcfe for the same period in 2009.

Derivative gain/loss. For the six months ended June 30, 2010, our derivative gain of $13.3 million consisted of a gain of $13.6 million related to a change in the fair value of our commodity derivatives, offset by a loss of $0.3 million related to a change in the fair value of our interest rate swap. For the six months ended June 30, 2009, our derivative loss of $0.9 million related entirely to a change in the fair value of our interest rate swap. For additional details about our derivatives, refer to Item 1 Financial Statements – Note 7 – Derivative Financial Instruments.

Interest expense. Interest expense incurred decreased to $21.8 million for the six months ended June 30, 2010 from $24.2 million for the six months ended June 30, 2009 primarily due to lower amounts of borrowings outstanding during the 2010 period. During the 2010 and 2009 periods, $2.7 million and $3.5 million, respectively, of interest was capitalized to unevaluated oil and natural gas properties.

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

Income tax expense/benefit. Income tax expense increased to $7.1 million for the six months ended June 30, 2010 from an income tax benefit of $34.5 million for the same period of 2009. Our effective tax rate for the six months ended June 30, 2010 was approximately 9.2% and primarily reflects a reduction in our valuation allowance against our deferred tax assets. Forecasted taxable income in 2010 has allowed us to reduce a portion of our valuation allowance. For 2009, the income tax benefit resulted from a pre-tax loss. Our effective tax rate for the six months ended June 30, 2009 was approximately 12.1% and primarily reflected the effect of a valuation allowance for our deferred tax assets.

Liquidity and Capital Resources

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

Cash flow and working capital. Net cash provided by operating activities for the six months ended June 30, 2010 was $244.3 million, compared to net cash provided by operating activities of $46.4 million for the comparable period in 2009. Included in the 2010 and 2009 periods are $32.5 million and $10.3 million, respectively, of insurance reimbursements for remediation and plugging and abandonment costs incurred primarily in connection with Hurricane Ike. Also included in the 2010 period are refunds of federal incomes taxes paid in prior years totaling $99.8 million, consisting primarily of carrybacks of net operating losses generated in 2009 and 2008. Net cash used in investing activities totaled $205.1 million and $226.5 million during the first six months of 2010 and 2009, respectively, which primarily represents our investments in oil and natural gas properties. Included in the 2010 period is $116.6 million for the acquisition of the Matterhorn and Virgo fields from Total. At June 30, 2010, we had a cash balance of $72.9 million and we had $405.2 million of undrawn capacity under the revolving portion of the Credit Agreement. We believe that cash provided by operations, borrowings available under our revolving loan facility and other external sources of liquidity should be sufficient to fund our ongoing cash requirements.

Although our combined total production of oil and natural gas during the six months ended June 30, 2010 was approximately 7.4% lower compared to the same period in 2009, our combined average realized sales price was 40.9% higher in the 2010 period, which contributed to the increase in cash provided by operating activities in the 2010 period compared to the 2009 period. During the six months ended June 30, 2010, the average realized sales prices of our oil and natural gas were $70.48 per barrel and $4.88 per Mcf, respectively. Oil and natural gas prices have been and are expected to remain volatile. The Henry Hub spot price for natural gas was $4.53 per MMBtu as of June 30, 2010, representing a decrease of 21.8% from $5.79 per MMBtu at the end of 2009. The West Texas Intermediate posted price for oil was $72.00 per barrel as of June 30, 2010, representing a decrease of 5.3% from $76.00 per barrel at the end of 2009.

From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our revolving loan facility. During the six months ended June 30, 2010, we entered into commodity option contracts relating to approximately 4 Bcfe and 7 Bcfe of our anticipated production in 2010 and 2011, respectively. As of June 30, 2010, our derivative instruments consisted of commodity option contracts and a commodity swap contract relating to approximately 7 Bcfe of our anticipated production during the remainder of 2010 and approximately 7 Bcfe of our anticipated production in 2011. We also have an interest rate swap contract that serves to manage the risk associated with the floating rate of interest on our revolving loan facility. For additional details about our derivatives, refer to Item 1 Financial Statements – Note 7 – Derivative Financial Instruments.

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

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

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

At June 30, 2010 and December 31, 2009, $0.1 million and $1.3 million, respectively, of remediation costs and $13.7 million and $29.2 million, respectively, related to the plugging and abandonment of wells and dismantlement of facilities damaged by Hurricanes Ike and Gustav are included in insurance receivables. Refer to Item 1 Financial Statements – Note 9 – Hurricane Remediation and Insurance Claims for a reconciliation of our insurance receivables from December 31, 2009 to June 30, 2010. We expect that our available cash and cash equivalents, cash flow from operations and the availability under our revolving loan facility will be sufficient to meet any necessary expenditures that may exceed our insurance coverage for damages incurred as a result of Hurricanes Ike and Gustav.

Due to increased insurance claims in recent years associated with hurricanes in the Gulf of Mexico and continuing restrictions in the capital markets, property damage and well control insurance coverage has become more limited and the cost of such coverage has increased. We currently carry three layers of insurance coverage for our operating activities in the Gulf of Mexico, each of which was renewed during the quarter ended June 30, 2010. In June 2010, we renewed our insurance policies covering well control and hurricane damage at a cost of approximately $20.7 million, representing the most significant cost of our insurance coverage. The current policy limits for well control and hurricane damage are $100 million and $85 million, respectively. We carry an additional $100 million of well control coverage on six wells at our Ship Shoal 349 field and six wells at our Matterhorn field. A retention amount of $35 million per hurricane occurrence must be satisfied by us before we are indemnified for losses. Certain properties we have deemed as non-core are not covered for hurricane damage; however, properties representing approximately 90% of our PV-10 value at December 31, 2009 (before estimated asset retirement obligations) are covered under our new insurance policies for hurricane damage. Pollution causing a negative environmental impact is characterized as a covered component of each of the well control and hurricane sections of the policy.

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

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

Capital expenditures. The level of our investment in oil and natural gas properties changes from time to time depending on numerous factors, including the prices of oil and natural gas, anticipated operating cash flow, acquisition opportunities and the results of our exploration and development activities. For the six months ended June 30, 2010, our capital expenditures for oil and natural gas properties and equipment of $206.3 million included $116.6 million for the acquisition of the Matterhorn and Virgo fields from Total, $48.6 million for exploration activities, $25.8 million for development activities and $15.3 million for seismic, capitalized interest and other leasehold costs. Our development and exploration capital expenditures consisted of $67.3 million on the conventional shelf and other projects, $4.8 million in the deepwater and $2.3 million on the deep shelf. Our capital expenditures for the six months ended June 30, 2010 were financed by cash from operating activities and cash on hand.

Our total capital expenditure budget for 2010 is $450 million, comprised of both identified capital investment programs as described below and potential (but yet unidentified) acquisitions, joint ventures and other drilling opportunities. We anticipate fully funding our 2010 capital budget with internally generated cash flow, cash on hand and to the extent necessary, with borrowings under our revolving loan facility. The budget, as recently updated, includes three exploratory wells onshore, six offshore wells (five exploratory and one development) and other capital items such as well recompletions, facilities capital, seismic and leasehold items. At this time, we anticipate these capital expenditures will cost approximately $200 million. Another $116.6 million has been allocated to the purchase of certain properties as discussed below. The balance of the $450 million budget will be allocated to acquisitions, additional drilling opportunities from the company’s prospect inventory and/or new joint ventures offshore and onshore. Our 2010 capital budget is subject to change as conditions warrant.

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

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

Long-term debt. At June 30, 2010, we had $0.3 million of letters of credit outstanding and we had $405.2 million of undrawn capacity under our revolving loan facility, which matures in 2012. Borrowings outstanding under our 8.25% Senior notes were $450.0 million at June 30, 2010, all of which are classified as long-term. In July 2010, we borrowed $142.5 million under our revolving loan facility. For additional details about our long-term debt, refer to Item 1 Financial Statements – Note 5 – Long-Term Debt.

Availability under the Credit Agreement is subject to a semi-annual borrowing base redetermination (March and September) set at the discretion of our lenders. The amount of the borrowing base is calculated by our lenders based on their valuation of our proved reserves and their own internal criteria. In April 2010, our borrowing base under the Credit Agreement was reaffirmed by our lenders at $405.5 million. Fifteen lenders participate in our revolving loan facility and we do not anticipate any of them being unable to satisfy their obligations under the Credit Agreement. We do not anticipate any immediate need for access to the capital markets. However, because of various factors, including our credit rating and our reserve and production profile, it could be difficult and/or expensive to obtain debt or equity capital funding at sufficient levels in the future.

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

Income taxes. During the six months ended June 30, 2010, we received refunds of federal income taxes paid in prior years totaling $99.8 million, consisting primarily of carrybacks of net operating losses generated in 2009 and 2008. Approximately $12.3 million of these refunds were subject to recognition limitations in accordance with the Income Taxes Topic of the Codification, and as a result, during the second quarter of 2010, we recorded an unrecognized tax benefit of $12.3 million plus interest thereon in other liabilities. No potential benefits are included in the balance of unrecognized tax benefits that would affect the effective tax rate on income from continuing operations if recognized.

Dividends. During each of the six month periods ended June 30, 2010 and 2009, we paid regular cash dividends of $0.06 per common share. On August 2, 2010, our board of directors declared a cash dividend of $0.04 per common share, payable on September 10, 2010 to shareholders of record on August 20, 2010.

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

Critical Accounting Policies

Our significant accounting policies are summarized in Note 1 of Notes to Consolidated Financial Statements included in our Annual Report on Form 10-K for the year ended December 31, 2009. Also refer to the Notes to Condensed Consolidated Financial Statements included in Part 1, Item 1 of this Quarterly Report on Form 10-Q.

Recent Accounting Pronouncements

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

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Information about market risks for the three and six months ended June 30, 2010, did not change materially from the disclosures in Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2009 except as noted below. As such, the information contained herein should be read in conjunction with the related disclosures in our Annual Report on Form 10-K for the year ended December 31, 2009.

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

Commodity Price Risk. Our revenues, profitability and future rate of growth substantially depend upon market prices of oil and natural gas, which fluctuate widely. Oil and natural gas price declines and volatility have adversely affected our revenues, net cash provided by operating activities and profitability. We have entered into a limited number of commodity option contracts and a commodity swap contract to help manage our exposure to commodity price risk from sales of oil and natural gas during the fiscal years ending December 31, 2010 and 2011. As of June 30, 2010, we had commodity derivative instruments relating to approximately 7 Bcfe of our anticipated production during the remainder of 2010 and approximately 7 Bcfe of our anticipated production in 2011. While these contracts are intended to reduce the effects of volatile oil and natural gas prices, they may also limit future income if oil and natural gas prices were to rise substantially over the price established by the hedge. We do not enter into derivative instruments for speculative trading purposes. For additional details about our commodity derivatives, refer to Item 1 Financial Statements – Note 7 – Derivative Financial Instruments.

Interest Rate Risk. We have an interest rate swap contract that serves to manage the risk associated with the floating rate of interest on our revolving loan facility. For additional details about our interest rate swap, refer to Item 1 Financial Statements – Note 7 – Derivative Financial Instruments.

Item 4.

Controls and Procedures

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

As required by Exchange Act Rule 13a-15(b), we performed an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have each concluded that as of June 30, 2010 our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that our controls and procedures are designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

During the quarter ended June 30, 2010, there was no change in our internal control over financial reporting that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1A.

Risk Factors

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

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

The OPA and related regulations impose a variety of requirements related to the prevention of and response to oil spills into waters of the United States. The OPA subjects operators of offshore leases and owners and operators of oil handling facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. The OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. The OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating on the OCS, although the Secretary of Interior may increase this amount up to $150 million in certain situations. The OPA also currently limits the liability of a responsible party for economic damages, excluding all oil spill response costs, to $75 million, although this limit does not apply if a federal safety, construction or operating regulation was violated. The states in which we operate have also adopted similar laws and regulations relating to offshore operations in their waters. Congress is currently considering a variety of amendments to the OPA in response to the recent Deepwater Horizon incident in the Gulf of Mexico, including an increase in the minimum level of financial responsibility, an elimination of all liability limitations on damages, and enhancements to safety and spill-response requirements. Additional state regulation in these areas is also possible. Any new requirements would likely increase the cost of operations for our offshore activities, including insurance costs, and expose us to increased liability, which could have an adverse effect on our results of operations. If we are unable to satisfy new legislative and regulatory requirements, we may be required to curtail operations, sell our offshore properties or operations, or enter into partnerships with other companies that can meet the new requirements, which may have an adverse effect on the value of our offshore assets and the results of our operations. We cannot predict at this time whether the OPA will be amended or new state regulations will be adopted, what the substance of any such amendment or regulations will be or what impact any such amendments might have on our operations. In addition, our costs could also increase for our onshore operations due to changes in standard industry practices in anticipation of, or in reaction to, any new offshore regulation.

Increased governmental regulation of our operations and related developments in response to the Deepwater Horizon incident may result in drilling delays or substantial increases in our costs of operations.

In response to the Deepwater Horizon incident, the Secretary of the Interior has directed the BOEM to issue a moratorium prohibiting the drilling of any wells that utilize subsea blowout preventers or surface blowout preventers on a floating facility, which are used primarily in deepwater drilling activities, and requiring operators that were in the process of drilling affected wells to proceed to the next safe opportunity to secure and temporarily abandon such wells through November 30, 2010. Consequently, anticipated recompletion work at our recently acquired Matterhorn and Virgo fields may be delayed. Additionally, as a result of this moratorium or subsequent directives from the BOEM, the permitting process related to any new deepwater wells we may contemplate drilling could be delayed or more costly. The anticipation of this moratorium on deepwater drilling has also caused drilling rig operators to move or contemplate moving their rigs to locations outside of the Gulf of Mexico. If and when we require the use of a deepwater drilling rig, the potentially reduced inventory of such rigs could cause delays in timing and result in additional costs. The BOEM may also decide to implement additional regulatory mechanisms that would result in increased costs or delays in drilling operations, and we cannot predict with any certainty what form any additional regulation will take. As a result, we may experience delays in drilling, completion and ultimately, production activities, which would negatively impact our financial position, cash flows and results of operations.

This accident may also lead to further tightening of an increasingly difficult market for offshore property damage and well control insurance coverage. Insurers may not continue to offer the type and level of coverage which we currently maintain, and our costs may increase substantially as a result of increased premiums, potentially to the point where coverage is not available on economically manageable terms. If either additional governmental regulation is imposed or the insurance market becomes more restricted, it may increase the costs of conducting offshore exploration and development activities or result in significant delays, which could materially impact our business, financial condition and results of operations.

The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on the Company’s ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with its business.

The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The new legislation was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require the Company to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its derivative activities, although the application of those provisions to the Company is uncertain at this time. The financial reform legislation may also require the counterparties to the Company’s derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Company encounters, reduce the Company’s ability to monetize or restructure its existing derivative contracts, and increase the Company’s exposure to less creditworthy counterparties. If the Company reduces its use of derivatives as a result of the legislation and regulations, the Company’s results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Company’s ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. The Company’s revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on the Company, its financial condition, and its results of operations.

Item 6.

Exhibits

The exhibits to this report are listed in the Exhibit Index appearing on page 30 hereof.

SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on August 4, 2010.


W&T OFFSHORE, INC.

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

EXHIBIT INDEX


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

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

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

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

31.1*		Section 302 Certification of Chief Executive Officer.

31.2*		Section 302 Certification of Chief Financial Officer.

32.1*		Section 906 Certification of Chief Executive Officer and Chief Financial Officer.

*	Filed or furnished herewith.

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company