Edgar Filing: W&T OFFSHORE INC

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

FORM 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

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

For the quarterly period ended March 31, 2013

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

For the transition period from to

Commission File Number 1-32414

W&T OFFSHORE, INC.

(Exact name of registrant as specified in its charter)


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

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

(713) 626-8525

(Registrant’s telephone number, including area code)

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

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

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

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

As of May 6, 2013, there were 75,249,630 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 March 31, 2013 and December 31, 2012		1
Condensed Consolidated Statements of Income for the Three Months Ended March 31, 2013 and 2012		2
Condensed Consolidated Statement of Changes in Shareholders’ Equity for the Three Months Ended March 31, 2013		3
Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2013 and 2012		4
Notes to Condensed Consolidated Financial Statements		5

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk		33

Item 4. Controls and Procedures		33

PART II – OTHER INFORMATION		34

Item 1. Legal Proceedings		34

Item 1A. Risk Factors		35

Item 6. Exhibits		35

SIGNATURE		36

EXHIBIT INDEX		37

PART I – FINANCIAL INFORMATION

Item 1.

Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	March 31, 2013			December 31, 2012
	(In thousands, except share data)
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	12,277		$	12,245
Receivables:
Oil and natural gas sales		97,309			97,733
Joint interest and other		35,681			56,439
Income taxes		45,638			47,884

Total receivables		178,628			202,056
Deferred income taxes		1,432			267
Prepaid expenses and other assets		22,363			25,555

Total current assets		214,700			240,123
Property and equipment – at cost:
Oil and natural gas properties and equipment (full cost method, of which $125,485 at March 31, 2013 and $123,503 at December 31, 2012 were excluded from amortization)		6,836,590			6,694,510
Furniture, fixtures and other		21,949			21,786

Total property and equipment		6,858,539			6,716,296
Less accumulated depreciation, depletion and amortization		4,759,198			4,655,841

Net property and equipment		2,099,341			2,060,455
Restricted deposits for asset retirement obligations		29,161			28,466
Other assets		18,855			19,943

Total assets	$	2,362,057		$	2,348,987

Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	112,223		$	123,885
Undistributed oil and natural gas proceeds		41,255			37,073
Asset retirement obligations		69,964			92,630
Accrued liabilities		39,067			21,021

Total current liabilities		262,509			274,609
Long-term debt		1,060,079			1,087,611
Asset retirement obligations, less current portion		308,261			291,423
Deferred income taxes		158,922			145,249
Other liabilities		8,288			8,908
Commitments and contingencies		—			—
Shareholders’ equity:
Preferred stock, $0.00001 par value; 20,000,000 shares authorized; 0 issued at March 31, 2013 and December 31, 2012		—			—
Common stock, $0.00001 par value; 118,330,000 shares authorized; 78,118,803 issued and 75,249,630 outstanding at March 31, 2013, and December 31, 2012		1			1
Additional paid-in capital		398,465			396,186
Retained earnings		189,699			169,167
Treasury stock, at cost		(24,167	)		(24,167	)

Total shareholders’ equity		563,998			541,187

Total liabilities and shareholders’ equity	$	2,362,057		$	2,348,987

See Notes to Condensed Consolidated Financial Statements.

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


	Three Months Ended March 31,
	2013			2012
	(In thousands, except per share data)
	(Unaudited)
Revenues	$	259,222		$	235,886

Operating costs and expenses:
Lease operating expenses		59,341			56,663
Production taxes		1,789			1,485
Gathering and transportation		4,444			4,221
Depreciation, depletion, amortization and accretion		108,872			88,491
General and administrative expenses		21,087			29,479
Derivative loss		3,368			39,634

Total costs and expenses		198,901			219,973

Operating income		60,321			15,913
Interest expense:
Incurred		21,234			13,905
Capitalized		(2,433	)		(3,191	)

Income before income tax expense		41,520			5,199
Income tax expense		14,902			1,981

Net income	$	26,618		$	3,218

Basic and diluted earnings per common share	$	0.35		$	0.04
Dividends declared per common share	$	0.08		$	0.08

See Notes to Condensed Consolidated Financial Statements.

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY


	Common Stock Outstanding				Additional Paid-In Capital		Retained Earnings			Treasury Stock					Total Shareholders’ Equity
	Shares		Value		Additional Paid-In Capital		Retained Earnings			Shares		Value			Total Shareholders’ Equity
	(In thousands)
	(Unaudited)
Balances at December 31, 2012		75,250	$	1	$	396,186	$	169,167			2,869	$	(24,167	)	$	541,187
Cash dividends		—		—		—		(6,020	)		—		—			(6,020	)
Share-based compensation		—		—		2,255		—			—		—			2,255
Other		—		—		24		(66	)		—		—			(42	)
Net income		—		—		—		26,618			—		—			26,618

Balances at March 31, 2013		75,250	$	1	$	398,465	$	189,699			2,869	$	(24,167	)	$	563,998

See Notes to Condensed Consolidated Financial Statements.

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Three Months Ended March 31,
	2013			2012
	(In thousands)
	(Unaudited)
Operating activities:
Net income	$	26,618		$	3,218
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		108,872			88,491
Amortization of debt issuance costs and premium		447			586
Share-based compensation		2,255			2,659
Derivative loss		3,368			39,634
Cash payments on derivative settlements		(4,271	)		(5,800	)
Deferred income taxes		12,507			2,550
Changes in operating assets and liabilities:
Oil and natural gas receivables		423			9,516
Joint interest and other receivables		25,875			(2,170	)
Insurance receivables		—			715
Income taxes		2,372			(10,386	)
Prepaid expenses and other assets		4,911			3,884
Asset retirement obligation settlements		(23,464	)		(5,384	)
Accounts payable, accrued liabilities and other		9,921			644

Net cash provided by operating activities		169,834			128,157

Investing activities:
Investment in oil and natural gas properties and equipment		(136,626	)		(84,626	)
Purchases of furniture, fixtures and other		(114	)		(500	)

Net cash used in investing activities		(136,740	)		(85,126	)

Financing activities:
Borrowings of long-term debt – revolving bank credit facility		112,000			84,000
Repayments of long-term debt – revolving bank credit facility		(139,000	)		(117,000	)
Dividends to shareholders		(6,020	)		(5,948	)
Other		(42	)		(87	)

Net cash used in financing activities		(33,062	)		(39,035	)

Increase in cash and cash equivalents		32			3,996
Cash and cash equivalents, beginning of period		12,245			4,512

Cash and cash equivalents, end of period	$	12,277		$	8,508

See Notes to Condensed Consolidated Financial Statements.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

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

Interim Financial Statements. The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with U. S. generally accepted accounting principles (“GAAP”) for interim financial information and the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, the condensed consolidated financial statements do not include all of the information and footnote disclosures required by GAAP for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included.

Operating results for interim periods are not necessarily indicative of the results that may be expected for the entire year. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012.

Reclassifications. Certain reclassifications have been made to the prior periods’ financial statements to conform to the current presentation. Income taxes was combined with Accrued liabilities on the Balance Sheet and changes in Other liabilities was combined with the changes in Accounts payable and accrued liabilities on the Statement of Cash Flows.

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.

Recent Accounting Developments. In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities which applies to certain items in the statement of financial position (balance sheet), and was further clarified in January 2013 by ASU 2013-01, Balance Sheet (Topic 210):Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which clarified the scope of ASU 2011-11 to derivative instruments, repurchase agreements and securities lending transactions. The effective date for the amendments is for annual periods beginning after January 1, 2013, and interim periods within those annual periods. ASU 2011-11 requires disclosures of the gross and net amounts for items eligible for offset in the balance sheet. Although the Company’s derivative financial instruments are subject to master netting agreements, the Company records its derivative financial instruments on a gross basis by contract; therefore, the ASUs did not significantly affect the Company’s disclosures. Other items of the ASUs were not applicable to the Company.

In February 2013, the FASB issued ASU 2013-04, Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date, which requires an entity that is joint and severally liable to measure the obligation as the sum of the amount the entity has agreed with co-obligors to pay and any additional amount it expects to pay on behalf of one or more co-obligors. Required disclosures include a description of the nature of the arrangement, how the liability arose, the relationship with co-obligors and the terms and conditions of the arrangement. The effective date for the amendment is for annual periods beginning after December 15, 2013, and interim periods within those annual periods. The amendment is to be applied retrospectively to all prior periods presented. The Company is currently assessing the impact of ASU 2013-04 to determine the effects on the balance sheet and disclosures, if any.

2. Acquisitions and Divestitures

2013 Acquisitions and Divestitures. There were no acquisitions or divestures completed during the three months ended March 31, 2013.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

2012 Acquisitions. On October 5, 2012, we acquired from Newfield Exploration Company and its subsidiary, Newfield Exploration Gulf Coast LLC (together, “Newfield”) certain oil and gas leasehold interests in the Gulf of Mexico (the “Newfield Properties”). The Newfield Properties consist of leases covering 78 offshore blocks on approximately 416,000 gross acres (268,000 net acres) (excluding overriding royalty interests), comprised of 65 blocks in the deepwater, six of which are producing, 10 blocks on the conventional shelf, four of which are producing, and an overriding royalty interest in three deepwater blocks, two of which are producing. Including adjustments from an effective date of July 1, 2012, the adjusted purchase price was $205.6 million and we assumed the future asset retirement obligations (“ARO”) associated with the Newfield Properties. The purchase price may be subject to further adjustments. The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand. Subsequently in the same month, the amounts borrowed under our revolving bank credit facility were paid down with funds provided from the issuance of long-term debt in October 2012. (See Note 6 for information on long-term debt.)

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


Oil and natural gas properties and equipment	$	237,278
Asset retirement obligations – current		(7,250	)
Asset retirement obligations – non-current		(24,414	)

Total cash paid	$	205,614

The acquisition was recorded at fair value, which was determined by applying the market and income approaches using Level 3 inputs. The Level 3 inputs were: (i) analysis of comparable transactions obtained from various third-parties, (ii) estimates of ultimate recoveries of reserves and (iii) estimates of discounted cash flows based on estimated reserve quantities, reserve categories, timing of production, costs to produce and develop reserves, future prices, ARO and discount rates. The estimates and assumptions were determined by management and third-parties. The fair value is based on subjective estimates and assumptions, which are inherently imprecise, and the actual realized values could vary significantly from these estimates. No goodwill was recorded for the Newfield Properties acquisition.

Revenue, Net Income and Pro Forma Financial Information — Unaudited

The Newfield Properties were not included in our consolidated results until the closing date of October 5, 2012. For the three months ended March 31, 2013, the Newfield Properties accounted for $28.6 million of revenue, $6.6 million of direct operating expenses, $10.5 million of depreciation, depletion, amortization and accretion (“DD&A”) and $4.0 million of income taxes, resulting in $7.5 million of net income. The net income attributable to these properties does not reflect certain expenses, such as general and administrative expense (“G&A”) and interest expense; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis. In addition, the Newfield Properties are not recorded in a separate entity for tax purposes; therefore, income tax was estimated using the federal statutory tax rate. There were no expenses associated with acquisition activities and transition activities related to the acquisition of the Newfield Properties for the three months ended March 31, 2012.

The unaudited pro forma financial information was computed as if the acquisition of the Newfield Properties had been completed on January 1, 2011. The financial information was derived from W&T’s audited historical consolidated financial statement for annual periods, W&T’s unaudited historical condensed consolidated financial statement for the interim period, the Newfield Properties’ audited historical financial statements for 2011 and the Newfield Properties’ unaudited historical financial statement for the 2012 interim period.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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


	Three Months Ended March 31, 2012
Revenue	$	279,108
Net income		8,168
Basic and diluted earnings per common share		0.11

For the pro forma financial information, certain information was derived from financial records and certain information was estimated. The sources of information and significant assumptions are described below:

(a)

Revenues and direct operating expenses for the Newfield Properties were derived from the historical financial records of Newfield. Incremental revenues and direct operating expenses for the three month period ended March 31, 2012 were $43.2 million and $11.3 million, respectively.

(b)

Incremental costs for insurance for the three month period ended March 31, 2012 were estimated at $0.2 million, which were derived from the incremental costs to add the Newfield Properties to W&T’s insurance programs. The direct operating expenses for the Newfield Properties described above excluded insurance costs.

(c)

DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Newfield Properties’ costs, reserves and production into our currently existing full cost pool in order to compute such amounts. The purchase price allocation included $13.1 million that was allocated to the pool of unevaluated properties for oil and natural gas interests. Accordingly, no DD&A expense was estimated for the unevaluated properties. ARO was estimated by W&T management. Incremental DD&A was estimated at $20.4 million for the three month period ended March 31, 2012.

(d)

The acquisition was assumed to be funded entirely with borrowed funds. Interest expense was computed using assumed borrowings of $205.6 million, which equates to the cash component of the transaction, and an interest rate of 7.7%, which equates to the effective yield on net proceeds for the additional senior notes issued shortly after the acquisition closed. Incremental interest expense was estimated at $4.0 million for the three month period ended March 31, 2012.

(e)

Incremental capitalized interest was computed for the addition to the pool of unevaluated properties and the capitalization interest rate was adjusted for the assumed borrowings. Incremental capitalized interest was estimated at $0.2 million for the three month period ended March 31, 2012.

(f)

Income tax expense was computed using the 35% federal statutory rate. Incremental income tax expense was estimated at $2.7 million for the three month period ended March 31, 2012.

2012 Divestiture. On May 15, 2012, we sold our 40%, non-operated working interest in the South Timbalier 41 field located in the Gulf of Mexico for $30.5 million, net, with an effective date of April 1, 2012. The transaction was structured as a like-kind exchange under the Internal Revenue Service Code (“IRC”) Section 1031 and other applicable regulations, with funds held by a qualified intermediary until replacement purchases could be executed. Replacement purchases were consummated during 2012. In connection with this sale, we reversed $4.0 million of ARO.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

3. Hurricane Remediation and Insurance Claims

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

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

As of March 31, 2013, insurance receivables were $5.1 million and were included in Joint interest and other receivables on the balance sheet. As of December 31, 2012, no insurance receivables were recorded. From the third quarter of 2008 through March 31, 2013, we have received $142.2 million from our insurance underwriters related to Hurricane Ike. To the extent that additional remediation costs or plug and abandonment costs are incurred that are not covered by insurance, we expect that our available cash and cash equivalents, cash flow from operations and the availability under our revolving bank credit facility will be sufficient to meet necessary expenditures that may exceed our insurance coverage for damages incurred as a result of Hurricane Ike. See Note 4 for additional information about the impact of hurricane related items on our ARO. See Note 12 for information regarding legal actions taken by certain insurers and the Company.

4. Asset Retirement Obligations

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


Balance, December 31, 2012	$	384,053
Liabilities settled		(23,464	)
Accretion of discount		5,515
Liabilities incurred		131
Revisions of estimated liabilities due to Hurricane Ike		3,951
Revisions of estimated liabilities – all other (1)		8,039

Balance, March 31, 2013		378,225
Less current portion		69,964

Long-term	$	308,261

(1)

Revisions are primarily due to increases in the scope of work at several offshore locations required by the Bureau of Safety and Environmental Enforcement.

5. Derivative Financial Instruments

Our market risk exposure relates primarily to commodity prices and interest rates. From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our revolving bank credit facility. Our derivative instruments currently consist of crude oil swap and option contracts. All of the derivative counterparties are also lenders or affiliates of lenders participating in our revolving bank credit facility. We are exposed to credit loss in the event of nonperformance by the derivative counterparties; however, we currently anticipate that each of our derivative counterparties will be able to fulfill their contractual obligations.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Additional collateral is not required by us due to the derivative counterparties’ collateral rights as lenders and we do not require collateral from our derivative counterparties. All of our current derivative agreements allow for netting of derivative gains and losses upon settlement. If an event of default were to occur causing an acceleration of payment under our revolving bank credit facility, that event may also trigger an acceleration of settlement of our derivative instruments. If we were required to settle all of our open derivative instruments, we would be able to net payments and receipts per counterparty pursuant to the derivative agreements.

We account for our derivative contracts in accordance with GAAP, which requires each derivative to be recorded on the balance sheet as an asset or a liability at its fair value. Although our derivative agreements allow for netting, which would allow for recording assets and liabilities per counterparty on a net basis, we account for our derivative contracts on a gross basis per contract as either an asset or liability. We have elected not to designate our commodity derivatives as hedging instruments; therefore, all changes in the fair value of derivative contracts are recognized currently in earnings. For additional information about fair value measurements, refer to Note 7.

Commodity Derivatives: We have entered into commodity swap contracts to manage a portion of our exposure to commodity price risk from sales of oil through December 2014. While these contracts are intended to reduce the effects of price volatility, they may also limit future income from favorable price movements. During the three months ended March 31, 2013 and 2012, our derivative contracts consisted entirely of crude oil contracts. The crude oil swap contracts are comprised of a portion based on West Texas Intermediate (“WTI”) crude oil prices and a portion based on Brent crude oil prices. The WTI based swaps are priced off the New York Mercantile Exchange, known as NYMEX. The Brent based swaps are priced off the Brent crude oil price quoted on the IntercontinentalExchange, known as ICE. Although our Gulf of Mexico crude oil is based off the WTI crude oil price plus a premium, the realized prices received for the types of crude oil have been closer to the Brent crude oil price because of competition with foreign supplied crude oil, which is based off the Brent crude oil price. Therefore, a portion of the swap oil contracts are priced off the Brent crude oil price to mitigate a portion of the price risk associated with our Gulf of Mexico crude oil production.

As of March 31, 2013, our open commodity derivatives were as follows:


	Swaps – Oil
	Priced off Brent (ICE)				Priced off WTI (NYMEX)
Termination Period	Notional Quantity (Bbls)		Weighted Average Contract Price		Notional Quantity (Bbls)		Weighted Average Contract Price
2013: 2nd quarter		668,700	$	106.48		244,000	$	97.25
3rd quarter		405,800		103.85		185,000		97.13
4th quarter		294,400		101.98		520,000		97.38
2014: 1st quarter		180,000		97.38		59,000		97.02
2nd quarter		172,900		97.38		—		—
3rd quarter		165,600		97.38		—		—
4th quarter		156,400		97.37		—		—

		2,043,800	$	102.30		1,008,000	$	97.28

Bbls = barrels

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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


	March 31, 2013		December 31, 2012
Prepaid and other assets	$	867	$	—
Accrued liabilities		6,938		6,355
Other liabilities (noncurrent)		2,427		3,046

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


	Three Months Ended March 31,
	2013			2012
Derivative (gain) loss:
Realized	$	4,271		$	5,800
Unrealized		(903	)		33,834

Total	$	3,368		$	39,634

6. Long-Term Debt

Our long-term debt was as follows (in thousands):


	March 31, 2013		December 31, 2012
8.50% Senior Notes	$	900,000	$	900,000
Debt premiums, net of amortization		17,079		17,611
Revolving bank credit facility		143,000		170,000

Total long-term debt		1,060,079		1,087,611
Current maturities of long-term debt		—		—

Long-term debt, less current maturities	$	1,060,079	$	1,087,611

At March 31, 2013 and December 31, 2012, the balance outstanding of our senior notes, which bear an annual interest rate of 8.50% and mature on June 15, 2019 (the “8.50% Senior Notes”), was classified as long-term at their carrying value. Interest on the 8.50% Senior Notes is payable semi-annually in arrears on June 15 and December 15. The estimated annual effective interest rate on the 8.50% Senior Notes is 8.4%, which includes amortization of debt issuance costs and premiums. We are subject to various financial and other covenants under the indenture governing the 8.50% Senior Notes and we were in compliance with those covenants as of March 31, 2013.

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

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

At March 31, 2013 and December 31, 2012, we had $0.6 million of letters of credit outstanding under the revolving bank credit facility. The estimated annual effective interest rate was 3.7% for the three months ended March 31, 2013 for borrowings under the revolving bank credit facility. The estimated annual effective interest rate includes amortization of debt issuance costs and excludes commitment fees and other costs. As of March 31, 2013, our borrowing base was $725.0 million and our borrowing capacity availability was $581.4 million. See Note 13 for information on a subsequent increase of the borrowing base to $800.0 million.

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, each as defined in the Credit Agreement. We were in compliance with all applicable covenants of the Credit Agreement as of March 31, 2013.

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

7. Fair Value Measurements

We measure the fair value of our derivative financial instruments by applying the income approach, using models with inputs that are classified within Level 2 of the valuation hierarchy. The inputs used for the fair value measurement of our derivative financial instruments are the exercise price, the expiration date, the settlement date, notional quantities, the implied volatility, the discount curve with spreads and published commodity futures prices. The fair value of our 8.50% Senior Notes is based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2. The carrying amount of debt under our revolving bank credit facility approximates fair value because the interest rates are variable and reflective of market rates.

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


			March 31, 2013				December 31, 2012
	Hierarchy		Assets		Liabilities		Assets		Liabilities
Derivatives		Level 2	$	867	$	9,365	$	—	$	9,401
8.50% Senior Notes		Level 2		—		976,500		—		963,000
Revolving bank credit facility		Level 2		—		143,000		—		170,000

As described in Note 5, our derivative financial instruments are reported in the balance sheet at fair value and changes in fair value are recognized currently in earnings. The 8.50% Senior Notes and revolving bank credit facility are reported in the balance sheet at their carrying value as described in Note 6.

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

In 2010, the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (the “Plan”) was approved by our shareholders. As allowed by the Plan, in 2012 and in 2011, the Company granted restricted stock units (“RSUs”) to certain of its employees. RSUs are a long-term compensation component of the Plan, which are granted to only certain employees, and are subject to adjustments at the end of the applicable performance period based on the achievement of certain predetermined criteria. The RSUs granted in 2012 (the “2012 RSUs”) were subject to performance criteria of earnings per share and total shareholder return (“TSR”), while the RSUs granted in 2011 (the “2011 RSUs”) were subject to only earnings per share performance measurement. In 2012 and in prior years, restricted stock was granted to the Company’s non-employee directors under the Director Compensation Plan. The restricted stock and RSUs each vest at the end of specified service periods. In addition to share-based compensation, the Company may grant to its employees cash-based incentive awards, which are a short-term component of the Plan and are based on the Company and the employee achieving certain predetermined performance criteria.

We recognize compensation cost for share-based payments to employees and non-employee directors over the period during which the recipient is required to provide service in exchange for the award, based on the fair value of the equity instrument on the date of grant. We are also required to estimate forfeitures, resulting in the recognition of compensation cost only for those awards that are expected to actually vest.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

At March 31, 2013, there were 1,393,602 shares of common stock available for issuance in satisfaction of awards under the Plan and 546,829 shares of common stock available for issuance in satisfaction of awards under the Director Compensation Plan. The shares available for both plans are reduced when restricted stock is granted. RSUs will reduce the shares available in the Plan only if RSUs are settled in shares of common stock. Although the Company has the option to settle RSUs in stock or cash at vesting, only common stock has been used to settle vested RSUs to date. See Note 13 regarding shareholder approval received on May 7, 2013 to increase the shares available for issuance in the Plan by 4,000,000 shares and to make certain other amendments to the Plan.

Restricted Stock. As of March 31, 2013, the Company had 43,687 unvested restricted shares outstanding, all of which were issued to the non-employee directors. Restricted shares are subject to forfeiture until vested and cannot be sold, transferred or disposed of during the restricted period. The holders of restricted shares generally have the same rights as a shareholder of the Company with respect to such shares, including the right to vote and receive dividends or other distributions paid with respect to the shares. The fair value of restricted stock was estimated by using the Company’s closing price on the grant date.

Subject to the satisfaction of service conditions, the outstanding restricted shares issued to the non-employee directors as of March 31, 2013 are expected to vest as follows:


	Shares
2013 (1)		27,297
2014		10,295
2015		6,095

Total		43,687

(1)

Includes accelerated vesting of restricted shares held by one non-employee director who did not stand for re-election to the Board.

There were no grants, forfeitures or vesting of restricted shares during the three months ended March 31, 2013 and 2012.

Restricted Stock Units. As of March 31, 2013, the Company had outstanding RSUs issued to certain employees. A portion of the 2012 RSUs remains subject to the certain pre-defined performance measures of TSR for the defined periods in 2013 and 2014; therefore, this portion will be determined whether eligible for vesting at the end of the respective performance periods. TSR is determined based upon the change in the entity’s stock price and dividends for the performance period. The TSR targets are the ranking of the Company’s TSR compared to the TSR of 19 peer companies. The TSR components have an issuance scale from 0% to 150%. The portion of RSUs subject to TSR performance measurement is disclosed in the second table below.

The fair value for the 2012 RSUs was determined separately for the component related to the earnings per share targets and the component related to TSR targets. The fair value of the 2012 RSUs component related to earnings per share targets was determined using the Company’s closing price on the grant date. The fair value for the 2012 RSUs component related to TSR targets was determined by using a Monte Carlo simulation probabilistic model. The inputs used in the probabilistic model for the Company and the peer companies were: average closing stock prices during January 2012; risk-free interest rates using the London Interbank Offered Rate (“LIBOR”) ranging from 0.15% to 0.72% over the service period; expected volatilities ranging from 33% to 74%; expected dividend yields ranging from 0.0% to 2.5%; and correlation factors ranging from (67%) to 94%. The expected volatilities, expected dividends and correlation factors were developed using historical data. The fair value of the 2011 RSUs was estimated by using the Company’s closing price on the grant date.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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

A summary of activity related to RSUs is as follows:


	Restricted Stock Units
	Units			Weighted Average Grant Date Fair Value Per Unit
Outstanding RSUs, December 31, 2012		969,820		$	22.70
Granted (1)		1,171			18.39
Vested		—			—
Forfeited		(11,293	)		19.26

Outstanding RSUs, March 31, 2013		959,698		$	22.73

(1)

Adjustments to amounts granted in 2012.

Subject to the satisfaction of service conditions, the RSUs outstanding as of March 31, 2013 are eligible to vest in December of the year indicated in the table below:


	Shares
2013		474,812
2014		344,288
2014 (2)		140,598

Total		959,698

(2)

In addition to service requirements, these RSUs are also subject to certain performance requirements not yet measureable, with adjustments ranging from 0% to 150%.

During the three months ended March 31, 2012, there were no grants or vesting of RSUs.

Share-Based Compensation. A summary of incentive compensation expense under share-based payment arrangements and the related tax benefit is as follows (in thousands):


	Three Months Ended March 31,
	2013		2012
Share-based compensation expense from:
Restricted stock	$	99	$	106
Restricted stock units		2,156		2,553

Total	$	2,255	$	2,659

Share-based compensation tax benefit:
Tax benefit computed at the statutory rate	$	789	$	931

Unrecognized Share-Based Compensation. As of March 31, 2013, unrecognized share-based compensation expense related to our outstanding restricted shares and RSUs was $0.4 million and $9.2 million, respectively. Unrecognized share-based compensation expense will be recognized through April 2015 for restricted shares and November 2014 for RSUs.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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

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


	Three Months Ended March 31,
	2013		2012
Share-based compensation expense included in:
General and administrative	$	2,255	$	2,659

Total charged to operating income		2,255		2,659

Cash-based incentive compensation included in:
Lease operating expense		1,393		1,900
General and administrative		3,530		1,878

Total charged to operating income		4,923		3,778

Total incentive compensation charged to operating income	$	7,178	$	6,437

9. Income Taxes

Income tax expense of $14.9 million and $2.0 million was recorded during the three months ended March 31, 2013 and 2012, respectively. Our effective tax rate for the three months ended March 31, 2013 was 35.9% and differed from the federal statutory rate of 35.0% primarily as a result of state income taxes. Our effective tax rate for the three months ended March 31, 2012 was 38.1%, and differed from the federal statutory rate primarily as a result of the recapture of deductions for qualified domestic production activities under Section 199 of the IRC as a result of loss carrybacks to prior years. Income taxes receivables as of March 31, 2013 is comprised of $4.9 million of refunds related to 2012 estimated payments; $42.9 million of refunds related to tax loss carrybacks to 2010 and 2011; and partially offset by $2.2 million of accrued taxes payable related to 2013 alternative minimum tax.

As of March 31, 2013 and December 31, 2012, we did not have any unrecognized tax benefit recorded. As of March 31, 2013 and December 31, 2012, we had a valuation allowance related to state net operating losses. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses are deductible. The tax years from 2009 through 2012 remain open to examination by the tax jurisdictions to which we are subject.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

10. Earnings Per Share

The following table presents the calculation of basic and diluted earnings per common share (in thousands, except per share amounts):


	Three Months Ended March 31,
	2013		2012
Net income	$	26,618	$	3,218
Less portion allocated to nonvested shares		281		140

Net income allocated to common shares	$	26,337	$	3,078

Weighted average common shares outstanding		75,206		74,300

Basic and diluted earnings per common share	$	0.35	$	0.04
Shares excluded due to being anti-dilutive (weighted-average)		870		1,765

11. Dividends

During the three months ended March 31, 2013 and 2012, we paid regular cash dividends of $0.08 per common share each period. On May 7, 2013, our board of directors declared a cash dividend of $0.09 per common share, payable on June 4, 2013 to shareholders of record on May 24, 2013.

12. Contingencies

Cameron Parish Louisiana Claim. Since 2009, certain Cameron Parish landowners have filed suits in the 38th Judicial District Court, Cameron Parish, Louisiana against the Company and its Chief Executive Officer, Tracy W. Krohn, as well as several other defendants unrelated to us. In their lawsuits, plaintiffs alleged that property they own has been contaminated or otherwise damaged by the defendants’ oil and gas exploration and production activities and they are seeking compensatory and punitive damages. During 2012, we settled claims with certain landowners and paid $10.0 million. We assessed the remaining claims to be probable and have accrued $1.3 million in our contingent liabilities as of March 31, 2013 and December 31, 2012, of which one claim was settled in April 2013 for $0.5 million. However, we cannot state with certainty that our estimates of additional exposure are accurate concerning this matter.

Qui Tam Litigation. On September 21, 2012, the Company was served with a complaint in a qui tam action filed under the federal False Claims Act by an employee of a Company contractor. The lawsuit, United States ex rel. Comeaux v. W&T Offshore, Inc., et al.; CA No. 10-494, was filed in the United States District Court for the Eastern District of Louisiana, against the Company and three other working interest owners related to claims associated with three of the Company’s operated production platforms. A qui tam action, also known as a “whistleblower” action, is a lawsuit brought by a private citizen seeking civil penalties or damages against a person or company on behalf of the government for alleged violations of law. If the claims are successful, the person filing the suit may recover a percentage of the damages or penalty from the lawsuit as a reward for exposing a wrongdoing and recovering funds on behalf of the government. The complaint was originally filed in 2010 but kept under confidential seal in order for the federal government to decide if it wished to intervene and take over the prosecution of the qui tam action. The government declined to intervene in this suit and the complaint was unsealed and made public in June 2012, thereby giving the plaintiff the opportunity to pursue the claims on behalf of the government.

The complaint alleges that environmental violations at three of the Company’s operated production platforms in the Gulf of Mexico violate the federal offshore lease provisions so that the Company, among other things, wrongfully retained benefits under the applicable leases. The alleged environmental violations include allegations of discharges of relatively small amounts of oil into the Gulf of Mexico, the failure to report and record such discharges, and falsification of certain produced water samples and related reports required under federal law. The events are alleged to have occurred in 2009. These are largely the same underlying environmental allegations that resulted in the plea agreement described in the audited financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012. The Company has filed a motion to dismiss the plaintiff’s claims. The plaintiff dismissed his claims against the three other working interest owners after they filed motions to dismiss. The plaintiff conceded that certain of his claims should be dismissed in his reply to the Company’s motion to dismiss. The motion remains pending before the court.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The Company intends to vigorously defend the claims made in this lawsuit. While the Company has determined that the likelihood of an adverse outcome may be reasonably possible, the range of potential loss cannot yet be estimated, and accordingly, no accrual has been made.

Insurance Claims. During the fourth quarter of 2012, underwriters of W&T’s excess liability policies (Indemnity Insurance Company of North America, New York Marine & General Insurance Company, Navigators Insurance Company, XL Specialty Insurance Company and Liberty Mutual Insurance Co.) filed declaratory judgment actions in the United States District Court for the Southern District of Texas seeking a determination that such policies do not cover removal of wreck and debris claims arising from Hurricane Ike that occurred in 2008. The court consolidated the various suits filed by the underwriters. W&T has not yet filed any claim under such excess policies, but W&T anticipates that such claims may reach $50.0 million in aggregate. In January 2013, the Company filed a motion for summary judgment seeking the court’s determination that such excess policies do in fact provide coverage for such removal of wreck and debris claims. The motion for summary judgment is pending. If the motion is successful, the Company expects to receive reimbursement for these costs once the claims are submitted. The Company has incurred $49.7 million to date in costs related to removal of wreck associated with platforms damaged by Hurricane Ike and expects to incur an additional $0.7 million. Removal of wreck costs are recorded in Oil and natural gas properties and equipment on the Balance Sheet. Any recoveries from claims made on these policies related to this issue will be recorded as reductions in this line item, which will reduce the Company’s DD&A rate and replenish our cash expenditures.

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

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

Contingent Liability Recorded. Recognized expenses related to accrued and settled claims, complaints and fines were zero for the three months ended March 31, 2013 and $8.3 million for the three months ended March 31, 2012. These expenses are reported in General and administrative expenses on the statement of income and reflect the items noted above and other various claims and complaints. As of March 31, 2013 and December 31, 2012, we have recorded a liability of $1.3 million, which is included in Accrued liabilities on the balance sheet, for the loss contingencies matters that include the events described above and other minor environmental and litigation matters which we are addressing in the normal course of business.

13. Subsequent Events

Effective April 19, 2013, the borrowing base and the amount available for borrowing under the revolving bank credit facility was increased to $800.0 million. There were no changes to the terms of the Credit Agreement, such as the maturity date, interest rates, covenants or collateral.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

On May 7, 2013, at our annual shareholder meeting, our shareholders approved a proposal to increase the number of shares available for issuance in the Plan by 4,000,000 shares beyond the amount previously authorized and to extend the term of the Plan for an additional five years to April 15, 2019. This increase in shares reserved for issuance under the Plan is expected to be registered with the SEC within one month. The source of the shares to be issued as awards may come from authorized but unissued common stock or common stock held in the Company’s treasury, which was previously acquired by the Company in the open market. In addition, an amendment to the Plan was approved, which allows the Compensation Committee to take certain transactions, accounting or legal changes, and charges or certain other unusual items into account when determining whether performance goals that are applicable to performance awards under the Plan have been met.

14. Supplemental Guarantor Information

Our payment obligations under the Company’s outstanding 8.50% Senior Notes and the Credit Agreement (see Note 6) are fully and unconditionally guaranteed by certain of our wholly-owned subsidiaries, including W&T Energy VI, LLC and W&T Energy VII, LLC (together, the “Guarantor Subsidiaries”). W&T Energy VII, LLC does not currently have any active operations. Guarantees of the 8.50% Senior Notes will be released under certain circumstances, including:

(1) in connection with any sale or other disposition of all or substantially all of the assets of a Guarantor Subsidiary (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary (as such term is defined in the indenture governing the 8.50% Senior Notes) of the Company, if the sale or other disposition does not violate the “Asset Sales” provisions of the indenture;

(2) in connection with any sale or other disposition of the capital stock of such Guarantor Subsidiary to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary of the Company, if the sale or other disposition does not violate the “Asset Sales” provisions of the indenture and the Guarantor Subsidiary ceases to be a subsidiary of the Company as a result of such sales or disposition;

(3) if such Guarantor Subsidiary is a Restricted Subsidiary and the Company designates such Guarantor Subsidiary as an Unrestricted Subsidiary in accordance with the applicable provisions of the indenture;

(4) upon Legal Defeasance or Covenant Defeasance (as such terms are defined in the indenture) or upon satisfaction and discharge of the indenture;

(5) upon the liquidation or dissolution of such Guarantor Subsidiary, provided no event of default has occurred and is continuing; or

(6) at such time as such Guarantor Subsidiary is no longer required to be a Guarantor Subsidiary of the 8.50% Senior Notes as described in the indenture, provided no event of default has occurred and is continuing.

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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

Condensed Consolidating Balance Sheet as of March 31, 2013


	Parent Company			Guarantor Subsidiaries		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	12,277		$	—	$	—		$	12,277
Receivables:
Oil and natural gas sales		80,556			16,753		—			97,309
Joint interest and other		35,681			—		—			35,681
Income taxes		167,708			—		(122,070	)		45,638

Total receivables		283,945			16,753		(122,070	)		178,628
Deferred income taxes		1,432			—		—			1,432
Prepaid expenses and other assets		22,363			—		—			22,363

Total current assets		320,017			16,753		(122,070	)		214,700
Property and equipment – at cost:
Oil and natural gas properties and equipment		6,480,011			356,579		—			6,836,590
Furniture, fixtures and other		21,949			—		—			21,949

Total property and equipment		6,501,960			356,579		—			6,858,539
Less accumulated depreciation, depletion and amortization		4,543,468			215,730		—			4,759,198

Net property and equipment		1,958,492			140,849		—			2,099,341
Restricted deposits for asset retirement obligations		29,161			—		—			29,161
Deferred income taxes		—			12,776		(12,776	)		—
Other assets		454,552			417,655		(853,352	)		18,855

Total assets	$	2,762,222		$	588,033	$	(988,198	)	$	2,362,057

Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	112,207		$	16	$	—		$	112,223
Undistributed oil and natural gas proceeds		41,011			244		—			41,255
Asset retirement obligations		69,964			—		—			69,964
Accrued liabilities		38,676			122,461		(122,070	)		39,067

Total current liabilities		261,858			122,721		(122,070	)		262,509
Long-term debt		1,060,079			—		—			1,060,079
Asset retirement obligations, less current portion		278,646			29,615		—			308,261
Deferred income taxes		171,698			—		(12,776	)		158,922
Other liabilities		425,942			—		(417,654	)		8,288
Shareholders’ equity:
Common stock		1			—		—			1
Additional paid-in capital		398,465			231,759		(231,759	)		398,465
Retained earnings		189,700			203,938		(203,939	)		189,699
Treasury stock, at cost		(24,167	)		—		—			(24,167	)

Total shareholders’ equity		563,999			435,697		(435,698	)		563,998

Total liabilities and shareholders’ equity	$	2,762,222		$	588,033	$	(988,198	)	$	2,362,057

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Condensed Consolidating Balance Sheet as of December 31, 2012


	Parent Company			Guarantor Subsidiaries		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	12,245		$	—	$	—		$	12,245
Receivables:
Oil and natural gas sales		80,729			17,004		—			97,733
Joint interest and other		56,439			—		—			56,439
Income taxes		163,750			—		(115,866	)		47,884

Total receivables		300,918			17,004		(115,866	)		202,056
Deferred income taxes		267			—		—			267
Prepaid expenses and other assets		25,555			—		—			25,555

Total current assets		338,985			17,004		(115,866	)		240,123
Property and equipment – at cost:
Oil and natural gas properties and equipment		6,356,529			337,981		—			6,694,510
Furniture, fixtures and other		21,786			—		—			21,786

Total property and equipment		6,378,315			337,981		—			6,716,296
Less accumulated depreciation, depletion and amortization		4,461,886			193,955		—			4,655,841

Net property and equipment		1,916,429			144,026		—			2,060,455
Restricted deposits for asset retirement obligations		28,466			—		—			28,466
Deferred income taxes		—			13,509		(13,509	)		—
Other assets		442,540			393,499		(816,096	)		19,943

Total assets	$	2,726,420		$	568,038	$	(945,471	)	$	2,348,987

Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	123,792		$	93	$	—		$	123,885
Undistributed oil and natural gas proceeds		36,791			282		—			37,073
Asset retirement obligations		92,595			—		35			92,630
Accrued liabilities		20,755			116,132		(115,866	)		21,021

Total current liabilities		273,933			116,507		(115,831	)		274,609
Long-term debt		1,087,611			—		—			1,087,611
Asset retirement obligations, less current portion		262,524			28,934		(35	)		291,423
Deferred income taxes		158,758			—		(13,509	)		145,249
Other liabilities		402,407			—		(393,499	)		8,908
Shareholders’ equity:
Common stock		1			—		—			1
Additional paid-in capital		396,186			231,759		(231,759	)		396,186
Retained earnings		169,167			190,838		(190,838	)		169,167
Treasury stock, at cost		(24,167	)		—		—			(24,167	)

Total shareholders’ equity		541,187			422,597		(422,597	)		541,187

Total liabilities and shareholders’ equity	$	2,726,420		$	568,038	$	(945,471	)	$	2,348,987

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Condensed Consolidating Statement of Income for the Three Months Ended March 31, 2013


	Parent Company			Guarantor Subsidiaries		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Revenues	$	209,528		$	49,694	$	—		$	259,222

Operating costs and expenses:
Lease operating expenses		54,529			4,812		—			59,341
Production taxes		1,789			—		—			1,789
Gathering and transportation		3,662			782		—			4,444
Depreciation, depletion, amortization and accretion		86,416			22,456		—			108,872
General and administrative expenses		19,604			1,483		—			21,087
Derivative loss		3,368			—		—			3,368

Total costs and expenses		169,368			29,533		—			198,901

Operating income		40,160			20,161		—			60,321
Earnings of affiliates		13,100			—		(13,100	)		—
Interest expense:
Incurred		21,234			—		—			21,234
Capitalized		(2,433	)		—		—			(2,433	)

Income before income tax expense		34,459			20,161		(13,100	)		41,520
Income tax expense		7,841			7,061		—			14,902

Net income	$	26,618		$	13,100	$	(13,100	)	$	26,618

Condensed Consolidating Statement of Income for the Three Months Ended March 31, 2012


	Parent Company			Guarantor Subsidiaries		Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Revenues	$	176,562		$	59,324	$	—		$	235,886

Operating costs and expenses:
Lease operating expenses		50,018			6,645		—			56,663
Production taxes		1,485			—		—			1,485
Gathering and transportation		3,484			737		—			4,221
Depreciation, depletion, amortization and accretion		67,623			20,868		—			88,491
General and administrative expenses		26,887			2,592		—			29,479
Derivative loss		39,634			—		—			39,634

Total costs and expenses		189,131			30,842		—			219,973

Operating income (loss)		(12,569	)		28,482		—			15,913
Earnings of affiliates		18,516			—		(18,516	)		—
Interest expense:
Incurred		13,905			—		—			13,905
Capitalized		(3,191	)		—		—			(3,191	)

Income (loss) before income tax expense		(4,767	)		28,482		(18,516	)		5,199
Income tax expense (benefit)		(7,985	)		9,966		—			1,981

Net income	$	3,218		$	18,516	$	(18,516	)	$	3,218

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Condensed Consolidating Statement of Cash Flows for the Three Months Ended March 31, 2013


	Parent Company			Guarantor Subsidiaries			Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Operating activities:
Net income	$	26,618		$	13,100		$	(13,100	)	$	26,618
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		86,416			22,456			—			108,872
Amortization of debt issuance costs and premium		447			—			—			447
Share-based compensation		2,255			—			—			2,255
Derivative loss		3,368			—			—			3,368
Cash payments on derivative settlements		(4,271	)		—			—			(4,271	)
Deferred income taxes		11,774			733			—			12,507
Earnings of affiliates		(13,100	)		—			13,100			—
Changes in operating assets and liabilities:
Oil and natural gas receivables		172			251			—			423
Joint interest and other receivables		25,875			—			—			25,875
Income taxes		(3,957	)		6,329			—			2,372
Prepaid expenses and other assets		4,911			(24,155	)		24,155			4,911
Asset retirement obligation settlements		(23,311	)		(153	)		—			(23,464	)
Accounts payable, accrued liabilities and other		34,191			(115	)		(24,155	)		9,921

Net cash provided by operating activities		151,388			18,446			—			169,834

Investing activities:
Investment in oil and natural gas properties and equipment		(118,180	)		(18,446	)		—			(136,626	)
Purchases of furniture, fixtures and other		(114	)		—			—			(114	)

Net cash used in investing activities		(118,294	)		(18,446	)		—			(136,740	)

Financing activities:
Borrowings of long-term debt – revolving bank credit facility		112,000			—			—			112,000
Repayments of long-term debt – revolving bank credit facility		(139,000	)		—			—			(139,000	)
Dividends to shareholders		(6,020	)		—			—			(6,020	)
Other		(42	)		—			—			(42	)

Net cash used in financing activities		(33,062	)		—			—			(33,062	)

Increase in cash and cash equivalents		32			—			—			32
Cash and cash equivalents, beginning of period		12,245			—			—			12,245

Cash and cash equivalents, end of period	$	12,277		$	—		$	—		$	12,277

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Condensed Consolidating Statement of Cash Flows for the Three Months Ended March 31, 2012


	Parent Company			Guarantor Subsidiaries			Eliminations			Consolidated W&T Offshore, Inc.
	(In thousands)
Operating activities:
Net income	$	3,218		$	18,516		$	(18,516	)	$	3,218
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		67,623			20,868			—			88,491
Amortization of debt issuance costs		586			—			—			586
Share-based compensation		2,659			—			—			2,659
Derivative loss		39,634			—			—			39,634
Cash payments on derivative settlements		(5,800	)		—			—			(5,800	)
Deferred income taxes		2,963			(413	)		—			2,550
Earnings of affiliates		(18,516	)		—			18,516			—
Changes in operating assets and liabilities:
Oil and natural gas receivables		8,187			1,329			—			9,516
Joint interest and other receivables		(2,170	)		—			—			(2,170	)
Insurance receivables		715			—			—			715
Income taxes		(20,766	)		10,380			—			(10,386	)
Prepaid expenses and other assets		3,735			(37,855	)		38,004			3,884
Asset retirement obligation settlements		(5,384	)		—			—			(5,384	)
Accounts payable, accrued liabilities and other		40,556			(1,908	)		(38,004	)		644

Net cash provided by operating activities		117,240			10,917			—			128,157

Investing activities:
Investment in oil and natural gas properties and equipment		(73,709	)		(10,917	)		—			(84,626	)
Purchases of furniture, fixtures and other		(500	)		—			—			(500	)

Net cash used in investing activities		(74,209	)		(10,917	)		—			(85,126	)

Financing activities:
Borrowings of long-term debt – revolving bank credit facility		84,000			—			—			84,000
Repayments of long-term debt – revolving bank credit facility		(117,000	)		—			—			(117,000	)
Dividends to shareholders		(5,948	)		—			—			(5,948	)
Other		(87	)		—			—			(87	)

Net cash used in financing activities		(39,035	)		—			—			(39,035	)

Increase in cash and cash equivalents		3,996			—			—			3,996
Cash and cash equivalents, beginning of period		4,512			—			—			4,512

Cash and cash equivalents, end of period	$	8,508		$	—		$	—		$	8,508

Item 2.

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

Forward-Looking Statements

The following discussion and analysis should be read in conjunction with our accompanying unaudited condensed consolidated financial statements and the notes to those financial statements included in Item 1 of this Quarterly Report on Form 10-Q. The following discussion contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Exchange Act of 1934, which involve risks, uncertainties and assumptions. If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions. All statements other than statements of historical fact are statements that could be deemed forward-looking statements, such as those statements that address activities, events or developments that we expect, believe or anticipate will or may occur in the future. These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. Known material risks that may affect our financial condition and results of operations are discussed in Item 1A “Risk Factors” and market risks are discussed in Item 7A “Quantitative and Qualitative Disclosures About Market Risk” of our Annual Report on Form 10-K for the year ended December 31, 2012 and may be discussed or updated from time to time in subsequent reports filed with the SEC. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We assume no obligation, nor do we intend, to update these forward-looking statements. Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q to “W&T,” “we,” “us,” “our” and the “Company” refer to W&T Offshore, Inc. and its consolidated subsidiaries.

Overview

We are an independent oil and natural gas producer with operations offshore in the Gulf of Mexico and onshore in both the Permian Basin of West Texas and in East Texas. We have grown through acquisitions, exploration and development and currently hold working interests in approximately 72 producing offshore fields in federal and state waters (69 producing and three fields capable of producing). We currently have under lease approximately 1.4 million gross acres including approximately 0.7 million gross acres on the Gulf of Mexico Shelf, approximately 0.5 million gross acres in the deepwater and approximately 0.2 million gross acres onshore in Texas. A substantial majority of our daily production is derived from wells we operate offshore. In managing our business, we are concerned primarily with maximizing return on shareholders’ equity. To accomplish this primary goal, we focus on profitably increasing production and finding oil and gas reserves at a favorable cost. We strive to grow our reserves and production through acquisitions and our drilling programs. We have focused on acquiring properties where we can develop an inventory of drilling prospects that will enable us to continue to add reserves post-acquisition.

Our financial condition, cash flow and results of operations are significantly affected by the volume of our oil, NGLs and natural gas production and the prices that we receive for such production. Our production volumes for the first quarter of 2013 were comprised of approximately 41.0% oil and condensate, 11.9% NGLs and 47.1% natural gas, determined using the energy equivalency ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of crude oil, condensate or NGLs. The conversion ratio does not assume price equivalency, and the price per one thousand cubic feet equivalent (“Mcfe”) for oil, NGLs and natural gas may differ significantly. In the first quarter of 2013, revenues from the sale of oil and NGLs made up 83.3% of our total revenues, compared to 83.2% in the first quarter of 2012. For the first quarter of 2013, our combined total production of oil, condensate, NGLs and natural gas was approximately 0.4% higher on a Mcfe basis than during the same period in 2012.

In October 2012, we acquired from Newfield certain oil and gas leasehold interests in the Gulf of Mexico. The Newfield Properties consist of leases covering 78 federal offshore blocks on approximately 416,000 gross acres (268,000 net acres) (excluding overriding royalty interests), comprised of 65 blocks in the deepwater, six of which are producing, 10 blocks on the conventional shelf, four of which are producing, and an overriding royalty interest in three deepwater blocks, two of which are producing. Internal estimates of proved reserves associated with the Newfield Properties as of the acquisition date were approximately 7.0 million barrels of oil equivalent (“MMBoe”) (42.0 billion cubic feet equivalent (“Bcfe”)), comprised of approximately 61% natural gas, 36% oil and 3% NGLs, all of which were classified as proved developed. Including adjustments from an effective date of July 1, 2012, the adjusted purchase price was $205.6 million and we assumed the ARO associated with the Newfield Properties, which we have estimated to be $31.7 million. The acquisition was initially funded from borrowings under our revolving bank credit facility and cash on hand. Subsequently in the same month, the amounts borrowed under our revolving bank credit facility were paid down with funds provided from the issuance of an additional $300.0 million of 8.50% Senior Notes.

During the first quarter of 2013, our realized oil sales price (unhedged) decreased 2.9%, compared to the first quarter of 2012. Two comparable benchmarks are the unweighted average daily posted spot price of WTI crude oil, which decreased 8.4% from the comparable period, and the unweighted average daily posted spot price of Brent crude oil, which decreased 5.3% from the comparable period. WTI is frequently used to value domestically produced crude oil, and the majority of our oil production is priced using the spot price for WTI as a base price plus a premium depending on the type of crude oil. Most of our oil production is from our offshore production, which is comprised of various crudes including Heavy Louisiana Sweet, Light Louisiana Sweet, Poseidon and others. Starting in the first quarter of 2011 and continuing through the first quarter of 2013, these various crudes sold at a significant premium relative to WTI. During the first quarter of 2013, premiums for Heavy Louisiana Sweet crude and Light Louisiana Sweet crude ranged between $18.00 and $22.00 per barrel higher than WTI. During the first quarter of 2012, premiums for Heavy Louisiana Sweet crude and Light Louisiana Sweet crude ranged between $10.00 and $19.00 per barrel. The average premium spread prior to 2011 was approximately $2.00 to $3.00 per barrel. We may continue to experience higher premiums to WTI crude in our future sales of crude oil. We cannot predict how long such pricing conditions will last.

A possible cause cited by industry publications for the premiums afforded our offshore crudes is an oversupply situation at Cushing, Oklahoma, a primary domestic hub for crude oil priced using the WTI benchmark. Citing the Cushing crude over supply situation, the owners of the Seaway pipeline reversed the flow of crude oil in June 2012 to flow crude from Cushing to Freeport, Texas. In January 2013, the Seaway pipeline capacity was increased from 150,000 barrels per day to 400,000 barrels per day. Although this change increased the amount of crude oil available to Gulf Coast refineries, we did not experience a decline in premiums in the first quarter of 2013. The owners of the Seaway pipeline have announced plans to construct a parallel pipeline to be completed in the first quarter of 2014, which is expected to increase the capacity to 850,000 barrels per day. Other pipeline projects are underway that, when added to the Seaway pipeline capacity, could bring 1.9 million barrels per day of mid-continent crude oil to the Gulf Coast. That capacity is expected to grow to 2.4 million barrels per day by the end of 2014. We believe these actions may reduce the oversupply situation at Cushing, which may affect the premiums we receive on our offshore oil production.

Oil prices are affected by world events, such as political unrest in the Middle East, the threat of hostilities, demand changes in various countries and world economic growth. Some commentators believe world economic growth, which is currently being affected by the economies of China, Brazil, India and Russia, may support strong crude oil prices in the long term, although prices may deteriorate due to slower growth in China and softening of economies in other countries.

Notwithstanding these long-term views, crude oil prices will likely continue to be volatile. For the first quarter of 2013, WTI crude oil prices ranged from $90.00 to $98.00 per barrel and Brent crude oil prices ranged from $106.00 to $119.00 per barrel. The U.S. Energy Information Administration (“EIA”) estimates that global consumption outpaced global production during the first quarter of 2013. For the full year of 2013, EIA projects global consumption to be higher than production, and expect the situation to reverse in 2014 with production being higher the consumption. China is expected to be the leading contributor to consumption growth in 2013. North America’s production growth is expected to be partially offset by anticipated reductions from the Organization of the Petroleum Exporting Countries in 2013. Even though EIA projects global demand above global supply in 2013, EIA projects WTI average prices for 2013 to be approximately flat to 2012 and projects Brent average prices for 2013 to be below 2012 by approximately 4%. The new pipeline capacity for moving mid-continent crude to the Gulf Coast refineries was noted by EIA as being the primary rationale behind the lower Brent prices projected for 2013. Not only is pipeline capacity increasing, but rail receiving capacity on both the Gulf Coast and East Coast will allow crude to be shipped to the coastal refineries and may have the effect of narrowing the Brent to WTI differential.

Our average realized NGLs sales prices (unhedged) decreased 29.4% during the first quarter of 2013 compared to the first quarter of 2012. According to industry sources, increased domestic NGLs production has been the primary factor affecting price realizations. During the first quarter of 2013, prices for domestic ethane and propane, two common NGL components, decreased 50% and 31%, respectively, from the comparable period in 2012 and other domestic NGLs prices decreased between 6% and 20%. As long as ethane and propane inventories continue to be high and NGLs production continues to be high, we would expect prices for NGLs to be weak. In addition, as long as the crude to natural gas price ratio remains wide, NGLs production may continue to be high, which would continue to put downward pressure on the entire NGLs stream. Many natural gas processing facilities are re-injecting ethane back into the natural gas stream after processing due to increasing ethane supplies. This in turn increases natural gas supplies and has negatively impacted natural gas pricing.

Natural gas prices are more affected by domestic issues (as compared to crude oil prices), such as weather (particularly extreme heat or cold), supply, local demand issues and domestic economic conditions, and they have historically been subject to substantial fluctuation. During the first quarter of 2013, the average realized sales price for our natural gas production increased 26.6% from the comparable period in 2012 to $3.38 per Mcf. A comparable benchmark is the Henry Hub unweighted average daily posted spot price, which increased 43.0% from the comparable period. Although the price has increased significantly on a percentage basis, the price is still weak from an overall economic standpoint and we expect continued weakness in natural gas prices for a number of reasons, including (i) producers continuing to drill in order to secure and to hold large lease positions before expiration, particularly in shale and similar resource plays, (ii) natural gas storage levels building during the injection season, (iii) natural gas continuing to be produced as a by-product in conjunction with the high level of oil drilling, (iv) increasing availability of liquefied natural gas, (v) production efficiency gains are achieved in the shale gas areas resulting from better hydraulic fracturing, horizontal drilling and production techniques and (vi) re-injecting ethane into the natural gas stream as indicated above which increases the natural gas supply. Per EIA, natural gas working inventories ended March 2013 were 30% below the level at the same time a year ago and 2% below the five-year average due in part to March 2013 being colder than expected. EIA expects the Henry Hub gas spot price, which averaged $2.75 per British thermal unit (MMBtu) in 2012, will average $3.52 per MMBtu in 2013 and $3.60 per MMBtu in 2014. EIA projects U.S. consumption to be slightly higher than production for both 2013 and 2014 by approximately 1%, which would lower inventories but not sufficiently enough to raise prices. According to Baker Hughes, the natural gas rig count at the end of the first quarter of 2013 is down approximately 42% compared to the end of the first quarter of 2012. With actual and forecasted natural gas prices being above comparable 2012 periods, EIA expects some U.S. energy producers to switch to coal-powered energy from natural gas during 2013. Industry sources have indicated that a natural gas price above $4.50 per Mcf will probably cause power producers to switch back to coal from natural gas, which in effect creates limits to how far natural gas prices can rise until such time as demand for natural gas increases from other sources.

Should prices decline for oil, NGLs and natural gas in the future, it would negatively impact our future oil, NGLs 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, reductions in proved reserves, issues with financial ratio compliance, and a reduction of the borrowing base associated with our Credit Agreement, depending on the severity of such declines. If any of these events were to occur and were significant, it may limit the willingness of financial institutions and investors to provide capital to us and others in the oil and natural gas industry.

There continues to be many proposed changes in laws, regulations, guidance and policy in our industry. The process for obtaining offshore drilling permits, especially deepwater drilling permits, has expanded and lengthened in the past few years. The most significant regulation changes in recent years are regulations related to potential environmental impacts, spill response documentation, compliance reviews, operator practices related to safety and implementing a safety and environmental management system. The new regulations and increased review process increases the time to obtain drilling permits and increases the cost of operations. As these new regulations and guidance continue to evolve, we cannot estimate the cost and impact to our business at this time.

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 March 31,
	2013⁽¹⁾		2012		Change			%
	(In thousands, except percentages and per share data)
Financial:
Revenues:
Oil	$	197,564	$	169,974	$	27,590			16.2	%
NGLs		18,327		26,384		(8,057	)		(30.5	)%
Natural gas		42,937		38,436		4,501			11.7	%
Other		394		1,092		(698	)		(63.9	)%

Total revenues		259,222		235,886		23,336			9.9	%
Operating costs and expenses:
Lease operating expenses		59,341		56,663		2,678			4.7	%
Production taxes		1,789		1,485		304			20.5	%
Gathering and transportation		4,444		4,221		223			5.3	%
Depreciation, depletion, amortization and accretion		108,872		88,491		20,381			23.0	%
General and administrative expenses		21,087		29,479		(8,392	)		(28.5	)%
Derivative loss		3,368		39,634		(36,266	)		(91.5	)%

Total costs and expenses		198,901		219,973		(21,072	)		(9.6	)%

Operating income		60,321		15,913		44,408			279.1	%
Interest expense, net of amounts capitalized		18,801		10,714		8,087			75.5	%

Income before income tax expense		41,520		5,199		36,321			698.6	%
Income tax expense		14,902		1,981		12,921			652.2	%

Net income	$	26,618	$	3,218	$	23,400			727.2	%

Basic and diluted earnings per common share	$	0.35	$	0.04	$	0.31			775.0	%

(1)

In the fourth quarter of 2012, we acquired the Newfield Properties.


	Three Months Ended March 31,
	2013⁽¹⁾		2012		Change			%
Operating:
Net sales volumes:
Oil (MBbls)		1,844		1,540		304			19.7	%
NGLs (MBbls)		535		544		(9	)		(1.7	)%
Natural gas (MMcf)		12,720		14,376		(1,656	)		(11.5	)%
Total oil equivalent (MBoe) (2)		4,499		4,480		19			0.4	%
Total natural gas equivalent (MMcfe) (2)		26,993		26,877		116			0.4	%
Average daily equivalent sales (Boe/d) (2)		49,988		49,226		762			1.5	%
Average daily equivalent sales (Mcfe/d) (2)		299,928		295,354		4,574			1.5	%
Average realized sales prices (Unhedged):
Oil ($/Bbl)	$	107.15	$	110.39	$	(3.24	)		(2.9	)%
NGLs ($/Bbl)		34.25		48.51		(14.26	)		(29.4	)%
Natural gas ($/Mcf)		3.38		2.67		0.71			26.6	%
Oil equivalent ($/Boe) (2)		57.53		52.41		5.12			9.8	%
Natural gas equivalent ($/Mcfe) (2)		9.59		8.74		0.85			9.7	%
Average realized sales prices (Hedged) (3):
Oil ($/Bbl)	$	104.83	$	106.63	$	(1.80	)		(1.7	)%
NGLs ($/Bbl)		34.25		48.51		(14.26	)		(29.4	)%
Natural gas ($/Mcf)		3.38		2.67		0.71			26.6	%
Oil equivalent ($/Boe) (2)		56.58		51.12		5.46			10.7	%
Natural gas equivalent ($/Mcfe) (2)		9.43		8.52		0.91			10.7	%
Average per Mcfe ($/Mcfe) (2):
Lease operating expenses	$	2.20	$	2.11	$	0.09			4.3	%
Gathering and transportation		0.16		0.16		—			—	%

Production costs		2.36		2.27		0.09			4.0	%
Production taxes		0.07		0.05		0.02			40.0	%
Depreciation, depletion, amortization and accretion		4.03		3.29		0.74			22.5	%
General and administrative expenses		0.78		1.10		(0.32	)		(29.1	)%

	$	7.24	$	6.71	$	0.53			7.9	%

Total number of wells drilled (gross):
Offshore		2		—		2			N/A
Onshore		14		18		(4	)		(22.2	)%
Total number of productive wells drilled (gross):
Offshore		1		—		1			N/A
Onshore		14		18		(4	)		(22.2	)%

(1)

In the fourth quarter of 2012, we acquired the Newfield Properties.

(2)

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

(3)

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

Volume measurements:


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

N/A = percentage change not applicable

Three Months Ended March 31, 2013 Compared to the Three Months Ended March 31, 2012

Revenues. Total revenues increased $23.3 million to $259.2 million for the first quarter of 2013 as compared to the same period in 2012. Oil revenues increased $27.6 million, NGLs revenues decreased $8.1 million, natural gas revenues increased $4.5 million and other revenues decreased $0.7 million. The oil revenue increase was attributable to a 19.7% increase in sales volumes, partially offset by a 2.9% decrease in the average realized sales price (unhedged) to $107.15 per barrel for the first quarter of 2013 from $110.39 per barrel for the prior year period. The sales volume increase for oil was primarily attributable to increased production at Ship Shoal 349, the Newfield Properties acquired in 2012 and onshore properties in West Texas. These increases for oil production were partially offset by natural production declines in various fields. The NGLs revenue decrease was attributable to a 29.4% decrease in the average realized sales price (unhedged) to $34.25 per barrel for the first quarter of 2013 from $48.51 per barrel for the prior year period and a decrease of 1.7% in sales volumes from the comparable period. The sales volume decrease for NGLs was primarily attributable to pipeline and platform outages, natural production declines, individual well performances and the sale of South Timbalier 41 in 2012; and was partially offset by production from the Newfield Properties acquired in 2012 and new wells. The increase in natural gas revenue resulted from a 26.6% increase in the average realized natural gas sales price (unhedged) to $3.38 per Mcf in the first quarter of 2013 from $2.67 per Mcf for the prior year period, partially offset by a 11.5% decrease in sales volumes from the comparable period. The sales volume decrease for natural gas was primarily attributable to pipeline and platform outages, natural production declines, individual well performances and the sale of South Timbalier 41; and was partially offset by production from the Newfield Properties acquired in 2012 and increases at Ship Shoal 349. Revenues from oil and liquids as a percent of our total revenues were approximately the same, 83.3% for the first quarter of 2013 compared to 83.2% for the prior year period. NGLs realized prices as a percent of oil realized prices decreased to 32.0% for the first quarter of 2013 compared to 43.9% for the comparable period.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, insurance, workovers, maintenance on our facilities, and hurricane remediation costs net of insurance claims, increased $2.7 million to $59.3 million in the first quarter of 2013 compared to the prior year period. On a per Mcfe basis, lease operating expenses increased to $2.20 per Mcfe during the first quarter 2013 compared to $2.11 per Mcfe during the comparable 2012 period. On a component basis, facilities, base lease operating expenses and hurricane remediation costs net of insurance claims increased $3.3 million, $0.6 million and $0.3 million respectively. As a partial offset, workover expense decreased $1.5 million. Insurance premiums were approximately flat between periods. The increase in facilities expense was attributable to numerous activities at multiple locations, with no one activity causing a substantial portion of the increase. The activities included sandblasting/painting, repairs, underwater inspection and installations of temporary equipment. The increase in base lease operating expenses is primarily attributable to the Newfield Properties acquired in 2012, partially offset by increased fees received from third parties for product handling. Workover expense decreases were primarily attributable to expenses incurred in 2012 related to an onshore well.

Production taxes. Production taxes increased to $1.8 million in the first quarter of 2013 compared to $1.5 million in the prior year period primarily due to onshore activities and are currently not a large component of our operating costs. Most of our production is from federal waters where no production taxes are imposed, whereas onshore operations are subject to production taxes.

Gathering and transportation costs. Gathering and transportation costs increased $0.2 million for the first quarter of 2013 compared to the prior year period.

Depreciation, depletion, amortization and accretion. DD&A, including accretion for ARO, increased to $4.03 per Mcfe for the first quarter of 2013 from $3.29 per Mcfe in the prior year period. On a nominal basis, DD&A increased to $108.9 million for the first quarter of 2013 from $88.5 million in the prior year period. DD&A on a per Mcfe basis and nominal basis increased primarily due to cost capitalized to the full cost pool from both the unevaluated pool and from increases in our ARO estimates without a corresponding increase in proved reserves, which primarily occurred in the latter part of 2012. In addition, our incurred development costs during 2012 were above estimates, we increased estimates of future development costs at year end 2012 and the Newfield Properties acquired in 2012 increased the DD&A on a per Mcfe basis.

General and administrative expenses. G&A decreased to $21.1 million for the first quarter of 2013 from $29.5 million for the prior year period primarily due to no litigation settlement expense recorded in the first quarter of 2013 compared to an $8.3 million litigation accrual recorded in the prior year period. G&A on a per Mcfe basis was $0.78 per Mcfe for the first quarter of 2013, compared to $1.10 per Mcfe for the prior year period.

Derivative loss. For the first quarter of 2013 and 2012, our derivative net losses were $3.4 million and $39.6 million, respectively, and relate to the change in the fair value of our crude oil commodity derivatives as a result of changes in crude oil prices. Although the contracts relate to production for the current year and next year, changes in the fair value for all open contracts are recorded currently. For the first quarter of 2013, the net loss was comprised of a $4.3 million realized loss and a $0.9 million unrealized gain. For the first quarter of 2012, $5.8 million of the loss was realized and $33.8 million was unrealized. For additional information about our derivatives, refer to Item 1 Financial Statements – Note 5 – Derivative Financial Instruments.

Interest expense. Interest expense incurred increased to $21.2 million for the first quarter of 2013 from $13.9 million for the prior year period. The aggregate principal amount of our 8.50% Senior Notes outstanding was $900.0 million in the first quarter of 2013 compared to $600.0 million in the prior year period due to the issuance of 8.50% Senior Notes during October 2012. During the first quarter of 2013 and 2012, $2.4 million and $3.2 million, respectively, of interest was capitalized to unevaluated oil and natural gas properties. The decrease is primarily attributable to reclassifying unevaluated properties to the full cost pool during the fourth quarter of 2012.

Income tax expense. Income tax expense increased to $14.9 million for the first quarter of 2013 compared to $2.0 million for the same period of 2012. The increase is primarily attributable to the change in pre-tax income. Our effective tax rate for the three months ended March 31, 2013 was 35.9% and differed from the federal statutory rate of 35.0% primarily as a result of state income taxes. Our effective tax rate for the three months ended March 31, 2012 was 38.1% and differed from the federal statutory rate of 35.0% primarily as a result of the recapture of deductions for qualified domestic production activities under Section 199 of the IRC as a result of loss carrybacks to prior years.

Liquidity and Capital Resources

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

Cash flow and working capital. Net cash provided by operating activities for the first quarter of 2013 was $169.8 million compared to $128.2 million for the first quarter of 2012. The change was primarily due to higher revenues associated with increased production volumes for oil, increases in prices for natural gas, collections on joint interest receivables and lower income tax payments, partially offset by higher payments related to ARO. Our combined average realized sales price (hedged) per Mcfe was 10.7% higher than the comparable 2012 period due to oil increasing from 34% to 41% of our combined production and higher natural gas prices. Our combined production of oil, NGLs and natural gas on a Mcfe basis during the first quarter of 2013 was slightly higher than the first quarter of 2012.

Net cash used in investing activities during the first quarter of 2013 and 2012 was $136.7 million and $85.1 million, respectively, which represents our investments in both offshore and onshore oil and gas properties. The increase is primarily attributable to an increase in offshore drilling activity. There were no acquisitions completed in either period.

Net cash used in financing activities was $33.1 million and $39.0 million during the first quarter of 2013 and 2012, respectively. The cash used in the first quarter of 2013 and 2012 was attributable to net pay downs on the revolving bank credit facility and dividend payments.

At March 31, 2013, we had a cash balance of $12.3 million and $581.4 million of undrawn capacity available under the revolving bank credit facility, which had a borrowing base of $725.0 million as of March 31, 2013. See Financial Statements – Note 13 – Subsequent Events under Part I, Item 1 of this Form 10-Q describing an increase in our borrowing base to $800.0 million effective in April 2013.

Credit Agreement and long-term debt. At March 31, 2013 and December 31, 2012, $143.0 million and $170.0 million, respectively, were outstanding under our revolving bank credit facility. During the three months ended March 31, 2013, the outstanding borrowings on our revolving bank credit facility ranged from $143.0 million to $218.0 million. At March 31, 2013 and December 31, 2012, $900.0 million in aggregate principal amount of our 8.50% Senior Notes was outstanding. We believe that cash provided by operations, borrowings available under our revolving bank credit facility and other external sources of liquidity should be sufficient to fund our ongoing cash requirements, but additional financing could be required if we are successful in finding suitable acquisitions. For additional information about our long-term debt, refer to Financial Statements – Note 6 – Long-Term Debt under Part I, Item 1 of this Form 10-Q.

Availability under our revolving bank credit facility is subject to a semi-annual redetermination of our borrowing base that occurs in the spring and fall of each year and is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria. The Credit Agreement contains various financial covenants calculated as of the last day of each fiscal quarter, including a minimum current ratio and a maximum leverage ratio, as defined in the Credit Agreement. We were in compliance with all applicable covenants of the Credit Agreement and all applicable covenants related to the 8.50% Senior Notes as of March 31, 2013.

Derivatives. From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our revolving loan facility. As of March 31, 2013, our derivative instruments outstanding consisted of oil contracts relating to approximately 2.3 million barrels (“MMBbls”) and 0.7 MMBbls of our anticipated production for the balance of 2013 and the year 2014, respectively. See Financial Statements – Note 5– Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q for additional information.

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

Through March 2013, we have received cash from our insurance carrier related to Hurricane Ike claims totaling $142.2 million and have $5.1 million of insurance receivables recorded as of March 31, 2013 for claims that have been submitted and approved for payment. As of March 31, 2013, we have recorded in ARO an estimate of $6.4 million for additional costs to be incurred related to Hurricane Ike and we have estimated that this work will be completed by the end of 2013. We expect to receive reimbursement for a portion of these costs once costs are incurred and claims submitted. In addition, we have incurred removal of wreck costs related to Hurricane Ike, but some of our insurance carriers are disputing whether such costs are covered costs. Should necessary future expenditures exceed our insurance coverage for damages incurred as a result of Hurricane Ike, or claims are denied or there are significant delays in recovering further claims for other reasons, we expect that our available cash on hand, cash flow from operations and the availability under our revolving bank credit facility will be sufficient to meet these future cash needs.

During the fourth quarter of 2012, underwriters of our excess liability policies (Indemnity Insurance Company of North America, New York Marine & General Insurance Company, Navigators Insurance Company, XL Specialty Insurance Company and Liberty Mutual Insurance Co.) filed declaratory judgment actions in the United States District Court for the Southern District of Texas seeking a determination that such policies do not cover removal of wreck and debris claims arising from Hurricane Ike that occurred in 2008. The court consolidated the various suits filed by underwriters. We have not yet filed any claim under such excess policies, but we anticipate that such claims may reach $50.0 million in aggregate. In January 2013, we filed a motion for summary judgment seeking the court’s determination that such excess policies do in fact provide coverage for such removal of wreck and debris claims. The motion for summary judgment is pending. If the motion is successful, we expect to receive reimbursement for these costs once the claims are submitted. We have incurred $49.7 million to date in costs related to removal of wreck associated with platforms damaged by Hurricane Ike and expect to incur an additional $0.7 million. Removal of wreck costs are recorded in Oil and natural gas properties and equipment on the Balance Sheet. Any recoveries from claims made on these policies related to this issue will be recorded as reductions in this line item, which will reduce our DD&A rate and replenish our cash expenditures.

We currently carry three layers of insurance coverage for our operating activities in the Gulf of Mexico. The current policy limits for well control and hurricane damage (defined as named windstorm in our policies) are up to $100.0 million and $140.0 million, respectively, and the policies are effective until June 1, 2013. We carry an additional $100.0 million of well control coverage effective until June 1, 2013 on certain wells at our Mahogany, Matterhorn, Virgo, Main Pass 107/108, Tahoe and SE Tahoe fields. A retention amount of $5.0 million for well control events and $40.5 million per hurricane occurrence must be satisfied by us before we are indemnified for losses. Pollution causing a negative environmental impact is characterized as a covered component of each of the well control and hurricane sections of the policy.

We estimate that as of December 31, 2012, approximately 91% of the estimated future net revenues discounted at 10% (PV-10) attributable to our Gulf of Mexico properties are on platforms that are covered under our current insurance policies for named windstorm damage. This PV-10 percentage coverage is less than the previous year due to the acquisition of the Newfield Properties. Since we closed on the Newfield Properties near the end of named windstorm season and much of the property value is in subsea wells, we elected not to purchase named windstorm insurance on the assets at the time of the acquisition. There are certain other properties we have deemed as non-core and do not cover for named windstorm damage.

Our general and excess liability policy was recently renewed for another year and is effective until May 1, 2014. This policy provides for $300.0 million of liability coverage for bodily injury and property damage, including liability claims resulting from seepage, pollution or contamination. With respect to the Oil Spill Financial Responsibility requirement under the Ocean Pollution Act, we are required to evidence $150.0 million of financial responsibility to the Bureau of Safety and Environmental Enforcement. We qualify to self-insure for $54.0 million of this amount and the remaining $96.0 million is covered by insurance.

We are currently in the process of renewing our policies for well control and damages from named windstorms that expire on June 1, 2013 and believe we will be able to renew such policies at acceptable terms and premiums. Although we have not been informed otherwise, in the future, our insurers may not continue to offer this type and level of coverage to us, or our costs may increase substantially as a result of increased premiums and there could be an increased risk of uninsured losses that may have been previously insured, all of which could have a material adverse effect on our financial condition and results of operations. We are also exposed to the possibility that in the future we will be unable to buy insurance at any price or that if we do have claims, the insurers will not pay our claims. However, we are not aware of any financial issues related to any of our insurance underwriters that would affect their ability to pay claims. We do not carry business interruption insurance.

Capital expenditures. The level of our investment in oil and natural gas properties changes from time to time depending on numerous factors, including the prices of oil, NGLs and natural gas, acquisition opportunities, and the results of our exploration and development activities. The following table presents our capital expenditures for exploration, development and other leasehold costs and acquisitions:


	Three Months Ended March 31,
	2013		2012
	(in thousands)
Exploration (1)	$	60,624	$	17,285
Development (1)		73,722		62,535
Seismic, capitalized interest, other leasehold costs		2,280		4,806

Acquisitions and investments in oil and gas property/equipment	$	136,626	$	84,626

(1)	Reported geographically in the subsequent table.

The following table presents our exploration and development capital expenditures geographically:


	Three Months Ended March 31,
	2013		2012
	(in thousands)
Conventional shelf	$	42,220	$	22,762
Deepwater		21,086		10,417
Deep shelf		21,237		237
Onshore		49,803		46,404

Exploration and development capital expenditures	$	134,346	$	79,820

Our first quarter 2013 and 2012 capital expenditures were financed by cash flow from operating activities and cash on hand.

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


	Three Months Ended March 31,
	2013				2012
	Gross		Net		Gross		Net
Development wells:
Offshore wells:
Productive		1		1.0		—		—
Non-productive		—		—		—		—
Onshore wells:
Productive		11		11.0		9		9.0
Non-productive		—		—		—		—

Total development wells		12		12.0		9		9.0

Exploration wells:
Offshore wells:
Productive		—		—		—		—
Non Productive		1		1.0		—		—
Onshore wells:
Productive		3		2.9		9		8.1
Non-productive		—		—		—		—

Total exploration wells		4		3.9		9		8.1

Total wells		16		15.9		18		17.1

We intend to continue to pursue acquisitions and joint venture opportunities during 2013 should we identify attractive opportunities. We are actively evaluating opportunities and expect to complement our drilling and development projects with acquisitions providing acceptable rates of return. We anticipate funding our 2013 capital budget and acquisitions with internally generated cash flow, cash on hand, borrowings under our revolving loan facility, and accessing the capital markets to the extent necessary.

Income taxes. During the three months ended March 31, 2013, we made no income tax payments and received no refunds. During the three months ended March 31, 2012, we made income tax payments of $10.2 million and received refunds of $0.4 million. For the remainder of 2013, we expect a substantial amount of our income tax will be deferred and expect payments to be primarily related to alternative minimum tax. We received a tax refund of $4.9 million in April 2013 related to 2012 estimated payments and anticipate tax refunds in the third quarter of 2013 of approximately $42.9 million attributable to tax loss carrybacks to 2010 and 2011. After the 2012 net operating loss carryback, the amount of remaining net operating losses generated in 2012 available to offset future taxable income in 2013 and forward is $35.4 million. We also have $22.3 million of alternative minimum tax credit carryforwards available to be utilized in 2013 and forward.

Dividends. During the first quarter of 2013 and 2012, we paid regular cash dividends of $0.08 per common share each quarter. On May 7, 2013, our board of directors declared a cash dividend of $0.09 per common share, payable on June 4, 2013 to shareholders of record on May 24, 2013.

Contractual obligations. Updated information on certain contractual obligations is provided in Financial Statements –Note 4 – Asset Retirement Obligations and Financial Statements – Note 6 – Long-Term Debt under Part I, Item 1 of this Form 10-Q. As of March 31, 2013, drilling rig commitments were approximately $48.4 million compared to $36.5 million as of December 31, 2012. The current drilling rig commitments all expire within one year from March 31, 2013. Other contractual obligations as of March 31, 2013 did not change materially, except for scheduled utilization, from the disclosures in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2012.

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, 2012. Also refer to the Notes to Condensed Consolidated Financial Statements under Part 1, Item 1 of this Form 10-Q.

Recent Accounting Pronouncements

In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities which applies to certain items in the statement of financial position (balance sheet), and was further clarified in January 2013 by ASU 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which clarified the scope of ASU 2011-11 to derivative instruments, repurchase agreements and securities lending transactions. The effective date for the amendments is for annual periods beginning after January 1, 2013, and interim periods within those annual periods. ASU 2011-11 requires disclosures of the gross and net amounts for items eligible for offset in the balance sheet. Although our derivative financial instruments are subject to master netting agreements, we record our derivative financial instruments on a gross basis by contract; therefore, the ASUs did not significantly affect our disclosures. Other items of the ASUs were not applicable to us.

In February 2013, the FASB issued ASU 2013-04, Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date, which requires an entity that is joint and severally liable to measure the obligation as the sum of the amount the entity has agreed with co-obligors to pay and any additional amount it expects to pay on behalf of one or more co-obligors. Required disclosures include a description of the nature of the arrangement, how the liability arose, the relationship with co-obligors and the terms and conditions of the arrangement. The effective date for the amendment is for annual periods beginning after December 15, 2013, and interim periods within those annual periods. The amendment is to be applied retrospectively to all prior periods presented. We are currently assessing the impact of ASU 2013-04 to determine the effects on the balance sheet and disclosures, if any.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Information about market risks for the first quarter of 2013 did not change materially from the disclosures in Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2012. 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, 2012.

Commodity Price Risk. Our revenues, profitability and future rate of growth substantially depend upon market prices of oil, NGLs and natural gas, which fluctuate widely. Oil, NGLs and natural gas price declines and volatility could adversely affect our revenues, net cash provided by operating activities and profitability. We currently have open crude oil derivative contracts to manage a portion of our exposure to commodity price risk from sales of oil for the balance of 2013 and the year 2014. As of March 31, 2013, these derivative contracts had a notional quantity of 3.1 MMBbls. We do not designate our commodity derivatives as hedging instruments. While these contracts are intended to reduce the effects of volatile oil prices, they may also limit future income from favorable price movements. See Financial Statements – Note 5– Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q for additional information.

Interest Rate Risk. As of March 31, 2013, we had $143.0 million outstanding on our revolving bank credit facility. The revolving bank credit facility has a variable interest rate, which is primarily impacted by the rates for the LIBOR and the margin, which ranges from 2.00% to 2.75% depending on the amount outstanding. We currently do not have any derivative instruments related to interest rates.

Item 4.

Controls and Procedures

We have established disclosure controls and procedures designed to ensure that material information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC and that any material information relating to us is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions

regarding required disclosures. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

As required by Exchange Act Rule 13a-15(b), we performed an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have each concluded that as of March 31, 2013 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 March 31, 2013, there was no change in our internal control over financial reporting that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1.

Legal Proceedings

Cameron Parish Louisiana Claim. Since 2009, certain Cameron Parish landowners have filed suits in the 38th Judicial District Court, Cameron Parish, Louisiana against us and our Chief Executive Officer, Tracy W. Krohn, as well as several other defendants unrelated to us. In their lawsuits, plaintiffs alleged that property they own has been contaminated or otherwise damaged by the defendants’ oil and gas exploration and production activities and they are seeking compensatory and punitive damages. During 2012, we settled claims with certain landowners and paid $10.0 million. We assessed the remaining claims to be probable and have accrued $1.3 million in our contingent liabilities as of March 31, 2013 and December 31, 2012, of which one claim was settled in April 2013 for $0.5 million. However, we cannot state with certainty that our estimates of additional exposure are accurate concerning this matter.

Qui Tam Litigation. On September 21, 2012, we were served with a complaint in a qui tam action filed under the federal False Claims Act by an employee of one of our contractors. The lawsuit, United States ex rel. Comeaux v. W&T Offshore, Inc., et al.; CA No. 10-494, was filed in the United States District Court for the Eastern District of Louisiana, against us and three other working interest owners related to claims associated with three of our operated production platforms. A qui tam action, also known as a “whistleblower” action, is a lawsuit brought by a private citizen seeking civil penalties or damages against a person or company on behalf of the government for alleged violations of law. If the claims are successful, the person filing the suit may recover a percentage of the damages or penalty from the lawsuit as a reward for exposing a wrongdoing and recovering funds on behalf of the government. The complaint was originally filed in 2010 but kept under confidential seal in order for the federal government to decide if it wished to intervene and take over the prosecution of the qui tam action. The government declined to intervene in this suit and the complaint was unsealed and made public in June 2012, thereby giving the plaintiff the opportunity to pursue the claims on behalf of the government.

The complaint alleges that environmental violations at three of our operated production platforms in the Gulf of Mexico violate the federal offshore lease provisions so that we, among other things, wrongfully retained benefits under the applicable leases. The alleged environmental violations include allegations of discharges of relatively small amounts of oil into the Gulf of Mexico, the failure to report and record such discharges, and falsification of certain produced water samples and related reports required under federal law. The events are alleged to have occurred in 2009. These are largely the same underlying environmental allegations that resulted in the plea agreement described in the audited financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2012. We have filed a motion to dismiss the plaintiff’s claims. The plaintiff dismissed his claims against the three other working interest owners after they filed motions to dismiss. The plaintiff conceded that certain of his claims should be dismissed in his reply to our motion to dismiss. The motion remains pending before the court.

We intend to vigorously defend the claims made in this lawsuit. While we have determined that the likelihood of an adverse outcome may be reasonably possible, the range of potential loss cannot yet be estimated, and accordingly, no accrual has been made.

Insurance Claims. During the fourth quarter of 2012, underwriters of our excess liability policies (Indemnity Insurance Company of North America, New York Marine & General Insurance Company, Navigators Insurance Company, XL Specialty Insurance Company and Liberty Mutual Insurance Co.) filed declaratory judgment actions in the United States District Court for the Southern District of Texas seeking a determination that such policies do not cover removal of wreck and debris claims arising from Hurricane Ike that occurred in 2008. The court consolidated the various suits filed by the underwriters. We have not yet filed any claim under such excess policies, but we anticipate that such claims may reach $50.0 million in aggregate. In January 2013, we filed a motion for summary judgment seeking the court’s determination that such excess policies do in fact provide coverage for such removal of wreck and debris claims. The motion for summary judgment is pending. If the motion is successful, we expect to receive reimbursement for these costs once the claims are submitted. We have incurred $49.7 million to date in costs related to removal of wreck associated with platforms damaged by Hurricane Ike and expect to incur an additional $0.7 million. Removal of wreck costs are recorded in Oil and natural gas properties and equipment on the Balance Sheet. Any recoveries from claims made on these policies related to this issue will be recorded as reductions in this line item, which will reduce our DD&A rate and replenish our cash expenditures.

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

Item 1A.

Risk Factors

Investors should carefully consider the risk factors included under Risk Factors under Part I, Item 1A in our Annual Report on Form 10-K for the year ended December 31, 2012, together with all of the other information included in this document, in our Annual Report on Form 10-K and in our other public filings, press releases and discussions with our management. Notwithstanding the matters discussed herein, there have been no material changes in our risk factors as previously disclosed in Part I, Item 1A in our Annual Report on Form 10-K for the year ended December 31, 2012.

Item 6.

Exhibits

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

SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on May 8, 2013.


W&T OFFSHORE, INC.

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

EXHIBIT INDEX


Exhibit Number		Description

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

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

3.3		Certificate of Amendment to the Amended and Restated Articles of Incorporation of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.3 of the Company’s Quarterly Report on Form 10-Q, filed July 31, 2012 (File No. 001-32414))

31.1*		Section 302 Certification of Chief Executive Officer.

31.2*		Section 302 Certification of Chief Financial Officer.

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

101.INS**		XBRL Instance Document.

101.SCH**		XBRL Schema Document

101.CAL**		XBRL Calculation Linkbase Document

101.DEF**		XBRL Definition Linkbase Document.

101.LAB**		XBRL Label Linkbase Document

101.PRE**		XBRL Presentation Linkbase Document.

*	Filed herewith.

**	Furnished herewith.

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company