W&T Offshore (WTI) 10-Q 6 Aug 15 2015 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Aug. 03, 2015
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q2
Trading Symbol	WTI
Entity Registrant Name	W&T OFFSHORE INC
Entity Central Index Key	1,288,403
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		76,010,554

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 5,671	$ 23,666
Receivables:
Oil and natural gas sales	51,957	67,242
Joint interest and other	32,608	43,645
Total receivables	84,565	110,887
Deferred income taxes	6,820	11,662
Prepaid expenses and other assets	27,290	36,347
Total current assets	124,346	182,562
Property and equipment - at cost:
Oil and natural gas properties and equipment (full cost method, of which $110,400 at June 30, 2015 and $109,824 at December 31, 2014 were excluded from amortization)	8,207,165	8,045,666
Furniture, fixtures and other	23,981	23,269
Total property and equipment	8,231,146	8,068,935
Less accumulated depreciation, depletion and amortization	6,306,119	5,575,078
Net property and equipment	1,925,027	2,493,857
Restricted deposits for asset retirement obligations	15,538	15,444
Other assets	20,066	17,244
Total assets	2,084,977	2,709,107
Current liabilities:
Accounts payable	135,165	194,109
Undistributed oil and natural gas proceeds	29,693	37,009
Asset retirement obligations	41,494	36,003
Accrued liabilities	13,120	17,377
Total current liabilities	219,472	284,498
Long-term debt, less current maturities	1,468,870	1,360,057
Asset retirement obligations, less current portion	348,573	354,565
Deferred income taxes	34,290	186,988
Other liabilities	$ 14,560	$ 13,691
Commitments and contingencies
Shareholders’ equity:
Preferred stock, $0.00001 par value; 20,000,000 shares authorized; 0 issued at June 30, 2015 and December 31, 2014
Common stock, $0.00001 par value; 118,330,000 shares authorized; 78,879,727 issued and 76,010,554 outstanding at June 30, 2015; 78,768,588 issued and 75,899,415 outstanding at December 31, 2014	$ 1	$ 1
Additional paid-in capital	420,028	414,580
Retained earnings (deficit)	(396,650)	118,894
Treasury stock, at cost	(24,167)	(24,167)
Total shareholders’ equity (deficit)	(788)	509,308
Total liabilities and shareholders’ equity	$ 2,084,977	$ 2,709,107

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Statement Of Financial Position [Abstract]
Oil and natural gas properties and equipment - full cost method, amount excluded from amortization	$ 110,400	$ 109,824
Preferred stock, par value	$ 0.00001	$ 0.00001
Preferred stock, shares authorized	20,000,000	20,000,000
Preferred stock, issued	0	0
Common stock, par value	$ 0.00001	$ 0.00001
Common stock, shares authorized	118,330,000	118,330,000
Common stock, issued	78,879,727	78,768,588
Common stock, outstanding	76,010,554	75,899,415

Condensed Consolidated Statemen

Condensed Consolidated Statements Of Operations - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Income Statement [Abstract]
Revenues	$ 149,066	$ 262,994	$ 276,973	$ 517,510
Operating costs and expenses:
Lease operating expenses	45,130	61,765	98,461	117,384
Production taxes	1,000	1,842	1,637	3,834
Gathering and transportation	4,793	3,985	9,617	9,281
Depreciation, depletion, amortization and accretion	103,342	128,236	228,809	251,542
Ceiling test write-down of oil and natural gas properties	252,772	0	513,162	0
General and administrative expenses	19,757	19,682	40,523	43,270
Derivative loss	1,078	13,079	1,078	20,571
Total costs and expenses	427,872	228,589	893,287	445,882
Operating income (loss)	(278,806)	34,405	(616,314)	71,628
Interest expense:
Incurred	26,116	21,454	49,062	42,912
Capitalized	(2,024)	(2,159)	(3,807)	(4,231)
Debt issuance costs write-off and other, net	1,685	0	1,683	0
Income (loss) before income tax expense (benefit)	(304,583)	15,110	(663,252)	32,947
Income tax expense (benefit)	(44,134)	5,273	(147,708)	11,921
Net income (loss)	$ (260,449)	$ 9,837	$ (515,544)	$ 21,026
Basic and diluted earnings (loss) per common share	$ (3.43)	$ 0.13	$ (6.79)	$ 0.28
Dividends declared per common share	$ 0	$ 0.10	$ 0	$ 0.20

Condensed Consolidated Stateme5

Condensed Consolidated Statement of Changes In Shareholders' Equity - 6 months ended Jun. 30, 2015 - USD ($) $ in Thousands	Total	Common Stock Outstanding	Additional Paid-In Capital	Retained Earnings (Deficit)	Treasury Stock
Beginning Balances at Dec. 31, 2014	$ 509,308	$ 1	$ 414,580	$ 118,894	$ (24,167)
Beginning Balances (in shares) at Dec. 31, 2014	75,899,415	75,899,000			2,869,000
Share-based compensation	$ 5,708		5,708
Other	(260)		(260)
Other, shares		112,000
Net loss	(515,544)			(515,544)
Ending Balances at Jun. 30, 2015	$ (788)	$ 1	$ 420,028	$ (396,650)	$ (24,167)
Ending Balances (in shares) at Jun. 30, 2015	76,010,554	76,011,000			2,869,000

Condensed Consolidated Stateme6

Condensed Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Operating activities:
Net income (loss)	$ (260,449)	$ 9,837	$ (515,544)	$ 21,026
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	103,342	128,236	228,809	251,542
Ceiling test write-down of oil and natural gas properties	252,772	0	513,162	0	$ 0
Debt issuance costs write-off/amortization of debt items			2,432	366
Share-based compensation	2,892	3,887	5,708	7,644
Derivative loss	1,078	13,079	1,078	20,571
Cash payments on derivative settlements				(14,310)
Deferred income taxes			(147,708)	11,921
Changes in operating assets and liabilities:
Oil and natural gas receivables			15,285	2,335
Joint interest and other receivables			11,036	3,550
Income taxes			(325)	2,918
Prepaid expenses and other assets			8,929	4,439
Asset retirement obligation settlements			(21,939)	(30,338)
Accounts payable, accrued liabilities and other			(70,862)	(10,614)
Net cash provided by operating activities			30,061	271,050
Investing activities:
Acquisition of property interest in oil and natural gas properties				(53,363)
Investment in oil and natural gas properties and equipment			(150,994)	(212,680)
Purchases of furniture, fixtures and other			(709)	(1,715)
Net cash used in investing activities			(151,703)	(267,758)
Financing activities:
Borrowings of long-term debt - revolving bank credit facility			194,000	220,000
Repayments of long-term debt - revolving bank credit facility			(381,000)	(200,000)
Issuance of 9.00% Term Loan			297,000
Debt issuance costs			(6,407)
Dividends to shareholders				(15,129)
Other			54	(116)
Net cash provided by financing activities			103,647	4,755
Increase (decrease) in cash and cash equivalents			(17,995)	8,047
Cash and cash equivalents, beginning of period			23,666	15,800	15,800
Cash and cash equivalents, end of period	$ 5,671	$ 23,847	$ 5,671	$ 23,847	$ 23,666

Basis of Presentation

Basis of Presentation	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Basis of Presentation	1. Basis of Presentation Operations. W&T Offshore, Inc. (with subsidiaries referred to herein as “W&T,” “we,” “us,” “our,” 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. Our interest in fields, leases, structures and equipment are primarily owned by W&T Offshore, Inc. (on a stand-alone basis, the “Parent Company”) and its 100%-owned subsidiary, W & T Energy VI, LLC (“Energy VI”). 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 periods 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 for annual periods. 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, 2014. Transactions between Entities under Common Control. The prior period financial information for the three and six months ended June 30, 2014 presented in Note 13, Supplemental Guarantor Information , has been retrospectively adjusted due to transactions between entities under common control, as required under authoritative guidance. Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Ceiling Test Write-Down. Under the full cost method of accounting, we are required to periodically perform a “ceiling test,” which determines a limit on the book value of our oil and natural gas properties. If the net capitalized cost of oil and natural gas properties (including capitalized asset retirement obligations (“ARO”)) net of related deferred income taxes exceeds the ceiling test limit, the excess is charged to expense on a pre-tax basis and separately disclosed. Any such write downs are not recoverable or reversible in future periods. The ceiling test limit is calculated as: (i) the present value of estimated future net revenues from proved reserves, less estimated future development costs, discounted at 10%; (ii) plus the cost of unproved oil and natural gas properties not being amortized; (iii) plus the lower of cost or estimated fair value of unproved oil and natural gas properties included in the amortization base; and (iv) less related income tax effects. Estimated future net revenues used in the ceiling test for each period are based on current prices, defined by the SEC as the unweighted average of first-day-of-the-month commodity prices over the prior twelve months for that period. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. Due primarily to declines in the unweighted rolling 12-month average of first-day-of-the-month commodity prices for oil and natural gas for the first and second quarters of 2015, we recorded ceiling test write-downs which are reported as a separate line in the Statements of Operations Recent Events. The price we receive for our oil, natural gas liquids (“NGLs”) and natural gas production directly affects our revenues, profitability, cash flows, liquidity, access to capital and future rate of growth. The prices of these commodities began falling in the second half of 2014 and were significantly lower during the first half of 2015 compared to the last few years. We have taken several steps to mitigate the effects of these lower prices including: (i) significantly reducing the 2015 capital budget from the previous year; (ii) suspending our drilling and completion activities at several locations; (iii) suspending the regular quarterly common stock dividend and (iv) implementing numerous cost reduction projects to reduce our operating costs. During the second quarter of 2015, we entered into two Amendments to our Fifth Amended and Restated Credit Agreement (as amended, the “Credit Agreement”), which, among other things, revised certain financial covenants to be less restrictive, modified the borrowing base adjustment for additional debt and authorized the administrative agent under the Credit Agreement to enter into an Intercreditor Agreement among the Company, the lenders under the Credit Agreement and the lenders under the second lien term loan (the We have assessed our financial condition, the current capital markets and options given different scenarios of commodity prices and believe we will have adequate liquidity to fund our operations through June 30, 2016. However, we cannot predict how an extended period of commodity prices at existing levels or a significant reduction in our borrowing base will affect our operations and liquidity levels. Recent Accounting Developments. In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2015-03 (“ASU 2015-03”), Interest – Imputation of Interest (Subtopic 835-30), Simplifying the Presentation of Debt Issuance Costs . The guidance seeks to simplify the presentation of debt issuance costs. The amendment would require debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of liability, consistent with debt discounts or premiums. The guidance was further clarified to state that debt issuance costs related to credit facilities could be reported as an asset regardless of the balance outstanding. The recognition and measurement guidance for debt issuance costs would not be affected by the amendment. ASU 2015-03 is effective in 2016 and should be applied on a retrospective basis. Early adoption is permitted. We do not expect the revised guidance to materially affect our balance sheets as amounts will be reclassified from long-term assets to partial offsets of long-term debt. The revised guidance will not affect the statements of operations or the statements of cash flows. In August 2014, the FASB issued Accounting Standards Update No. 2014-15 (“ASU 2014-15”), Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40). In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (“ASU 2014-09”), Summary and Amendments that Create Revenue from Contracts and Customers (Topic 606).

Acquisitions and Divestitures

Acquisitions and Divestitures	6 Months Ended
	Jun. 30, 2015
Business Combinations [Abstract]
Acquisitions and Divestitures	2. Acquisitions and Divestitures 2014 Acquisitions Fairway On September 15, 2014, the Parent Company entered into an asset purchase agreement with a third party to increase its ownership interest from 64.3% to 100% in the Mobile Bay blocks 113 and 132 (the “Fairway Field”) and the associated Yellowhammer gas processing plant (collectively, “Fairway”). The Fairway Field is located in the state waters of Alabama and the Yellowhammer gas processing plant is located in the state of Alabama. The effective date of the transaction was July 1, 2014. The transaction included customary adjustments for the effective date, certain closing adjustments and our assumption of the related ARO. A net purchase price increase of $1.3 million for customary final closing adjustments was recorded in 2015. The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand. The following table presents the purchase price allocation, including adjustments, for the increased ownership interest in Fairway (in thousands): Cash consideration: Evaluated properties including equipment $ 18,693 Non-cash consideration: Asset retirement obligations - non-current 6,124 Total consideration $ 24,817 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 in connection with this acquisition of an additional working interest in Fairway. Woodside Properties On May 20, 2014, Energy VI entered into a purchase and sale agreement to acquire certain oil and natural gas property interests from Woodside Energy (USA) Inc. (“Woodside”). The properties acquired from Woodside (the “Woodside Properties”) consisted of a 20% non-operated working interest in the producing Neptune field (deepwater Atwater Valley blocks 574, 575 and 618), along with an interest in the Neptune tension-leg platform, associated production facilities and various interests in 24 other deepwater lease blocks. All of the Woodside Properties are located in the Gulf of Mexico. The effective date of the transaction was November 1, 2013. The transaction included customary adjustments for the effective date, certain closing adjustments and our assumption of the related ARO. A net purchase price increase of $0.2 million for customary final closing adjustments was recorded in 2015. The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand. The following table presents the purchase price allocation, including adjustments, for the acquisition of the Woodside Properties (in thousands): Cash consideration: Evaluated properties including equipment $ 52,329 Unevaluated properties 2,660 Sub-total cash consideration 54,989 Non-cash consideration: Asset retirement obligations - current 782 Asset retirement obligations - non-current 10,543 Sub-total non-cash consideration 11,325 Total consideration $ 66,314 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 in connection with the Woodside Properties acquisition. 2014 Acquisitions — Revenues, Net Income and Pro Forma Financial Information The increase in working interest ownership for Fairway was not included in our consolidated results until the property transfer date, which occurred in September 2014 and the incremental revenue and operating expenses were immaterial for the three and six month periods ended June 30, 2015. Unaudited pro forma information showing the effect of the acquisition of an additional Fairway working interest is not presented as the pro forma information is not materially different from the reported results presented for the three and six month periods ended June 30, 2014. The Woodside Properties were not included in our consolidated results until the property transfer date, which occurred in May 2014. For the three months ended June 30, 2015, the Woodside Properties accounted for $7.9 million of revenues, $1.8 million of direct operating expenses, $3.9 million of depreciation, depletion, amortization and accretion (“DD&A”) and $0.8 million of income tax expense, resulting in $1.4 million of net income. For the six months ended June 30, 2015, the Woodside Properties accounted for $13.4 million of revenues, $5.1 million of direct operating expenses, $8.0 million of DD&A and $0.1 million of income tax expense, resulting in $0.2 million of net income. The net income attributable to the Woodside Properties does not reflect certain expenses, such as general and administrative expenses (“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 Woodside Properties are not recorded in a separate entity for tax purposes; therefore, income tax was estimated using the federal statutory tax rate. In accordance with the applicable accounting guidance, we have included herein certain unaudited pro forma financial information giving pro forma effect to the acquisition of the Woodside Properties computed as if the acquisition had been completed on January 1, 2013. The financial information was derived from W&T’s audited historical consolidated financial statements for annual periods, W&T’s unaudited historical condensed consolidated financial statements for interim periods, and the Woodside Properties’ unaudited historical financial statements for the annual and interim periods. The pro forma adjustments were based on estimates by management and information believed to be directly related to the purchase of the Woodside Properties. The pro forma financial information is not necessarily indicative of the results of operations had the purchase occurred on January 1, 2013. Had we owned the Woodside Properties during the periods indicated, the results may have been substantially different. For example, we may have operated the assets differently than Woodside; the realized sales prices for oil, NGLs and natural gas may have been different; and the costs of operating the Woodside Properties may have been different. The following table presents a summary of our pro forma financial information giving pro forma effect to the Woodside Properties acquisition (in thousands, except earnings per share): (unaudited) Three Months Ended Six Months Ended June 30, 2014 June 30, 2014 Revenue $ 272,022 $ 540,397 Net income 12,150 27,120 Basic and diluted earnings per common share 0.16 0.35 For the pro forma financial information, certain information was derived from our financial records, Woodside’s financial records and certain information was estimated. The following table presents incremental items included in the pro forma information reported above for the Woodside Properties (in thousands): (unaudited) Three Months Ended Six Months Ended June 30, 2014 (a) June 30, 2014 (a) Revenues (b) $ 9,028 $ 22,887 Direct operating expenses (b) 1,805 4,417 DD&A (c) 3,387 8,384 G&A (d) 200 400 Interest expense (e) 82 330 Capitalized interest (f) (5 ) (19 ) Income tax expense (g) 1,246 3,281 The sources of information and significant assumptions are described below: (a) The adjustments for the periods presented are from the beginning of the period to May 20, 2014. (b ) Revenues and direct operating expenses for the Woodside Properties were derived from the historical financial records of Woodside. (c ) DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Woodside Properties’ costs, reserves and production into our full cost pool in order to compute such amounts. The purchase price allocated to unevaluated properties for oil and natural gas interests was excluded from the DD&A expense estimation. ARO was estimated by W&T management. (d ) Consists of estimated incremental insurance costs related to the Woodside Properties. (e ) The Woodside Properties acquisition was assumed to be funded entirely with borrowed funds. Interest expense was computed using assumed borrowings of $55.0 million, which equates to the cash component of the acquisition purchase price, and an interest rate of 1.8%, which equates to the rates applied to incremental borrowings on the revolving bank credit facility. (f ) The change to capitalized interest was computed for the addition to the pool of unevaluated properties and the capitalization interest rate was adjusted for the assumed borrowings. The negative amount represents a decrease to net expenses. (g ) Income tax expense was computed using the 35% federal statutory rate. The pro forma adjustments do not include adjustments related to any other acquisitions or divestitures.

Asset Retirement Obligations

Asset Retirement Obligations	6 Months Ended
	Jun. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	3. 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, 2014 $ 390,568 Liabilities settled (21,939 ) Accretion of discount 10,930 Disposition of properties (965 ) Liabilities assumed through acquisition 2,944 Liabilities incurred 4,671 Revisions of estimated liabilities (1) 3,858 Balance, June 30, 2015 390,067 Less current portion 41,494 Long-term $ 348,573 (1) Revisions were primarily attributable to increases from non-operated properties.

Derivative Financial Instrument

Derivative Financial Instruments	6 Months Ended
	Jun. 30, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	4. Derivative Financial Instruments Our market risk exposure relates primarily to commodity prices and from time to time, we use various derivative instruments to manage our exposure to this commodity price risk from sales of our oil and natural gas. 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. 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. We have elected not to designate our commodity derivative contracts as hedging instruments; therefore, all changes in the fair value of derivative contracts were recognized currently in earnings during the periods presented. The cash flows of all of our commodity derivative contracts are included in Net cash provided by operating activities For information about fair value measurements, refer to Note 6. Commodity Derivatives During the second quarter of 2015, we entered into crude oil derivative contracts and natural gas derivative contracts for a portion of our anticipated future production. Some of the commodity derivative contracts are known as “three-way collars” consisting of a purchased put option, a sold call option and a purchased call option, each at varying strike prices. The strike prices of the contracts were set so that the contracts were premium neutral (“costless”), which means no net premium was paid to or received from a counterparty. The three-way collar contracts are structured to provide price risk protection if the commodity price falls below the strike price of the put option and provides us the opportunity to benefit if the commodity price rises above the strike price of the purchased call option. These contracts may have the effect of reducing some of our incremental income from favorable price movements if the commodity price is above certain levels, but have unlimited upside potential if prices rise above those levels. In addition, we entered into oil derivative contracts known as “two-way”, “costless” collars, which consist of a purchased put option and a sold call option. These two-way collars provide price risk protection if crude oil prices fall below certain levels, but may limit incremental income from favorable price movements above certain limits. The oil contracts are based on West Texas Intermediate (“WTI”) crude oil prices as quoted off the New York Mercantile Exchange, known as NYMEX. The natural gas contracts are based on Henry Hub natural gas prices as quoted off the NYMEX. As of December 31, 2014, we did not have any open derivative contracts. During 2014, we used crude oil swap contracts and have used various derivative instruments in prior years to manage our exposure to commodity price risk from sales of our oil and natural gas. While these contracts were intended to reduce the effects of price volatility, they may have limited incremental income from favorable price movements. As of June 30, 2015, our open commodity derivative contracts were as follows: Crude Oil: Three-way collars, Priced off WTI (NYMEX) Notional Notional Weighted Average Contract Price Quantity Quantity Put Option Call Option Call Option Termination Period (Bbls/day) (Bbls) (Bought) (Sold) (Bought) 2015: 3rd Quarter 6,000 552,000 $ 50.00 $ 60.00 $ 62.30 4th Quarter 6,000 552,000 50.00 60.00 62.30 1,104,000 50.00 60.00 62.30 Crude Oil: Two-way collars, Priced off WTI (NYMEX) Notional Notional Weighted Average Contract Price Quantity Quantity Put Option Call Option Termination Period (Bbls/day) (Bbls) (Bought) (Sold) 2016: 1st Quarter 5,000 455,000 $ 40.00 $ 81.47 2nd Quarter 5,000 455,000 40.00 81.47 3rd Quarter 5,000 460,000 40.00 81.47 4th Quarter 5,000 460,000 40.00 81.47 1,830,000 40.00 81.47 Natural Gas: Three-way collars, Priced off Henry Hub (NYMEX) ( 1 ) Notional Notional Weighted Average Contract Price Quantity Quantity Put Option Call Option Call Option Termination Period (MMBTUs/day) (MMBTUs) (Bought) (Sold) (Bought) 2015: 3rd Quarter 30,000 1,830,000 $ 2.25 $ 3.25 $ 3.51 4th Quarter 30,000 2,760,000 2.25 3.25 3.51 2016: 1st Quarter 40,000 3,640,000 2.25 3.50 3.77 2nd Quarter 40,000 3,640,000 2.25 3.50 3.77 3rd Quarter 40,000 3,680,000 2.25 3.50 3.77 4th Quarter 40,000 3,680,000 2.25 3.50 3.77 19,230,000 2.25 3.44 3.70 (1) The natural gas derivative contracts are priced and closed in the last week prior to the related production month. Natural gas derivative contracts related to July 2015 production were priced and closed in June 2015 and are not included in the above table as these were not open derivative contracts as of June 30, 2015. The following balance sheet line items included amounts related to the estimated fair value of our open commodity derivative contracts as indicated in the following table (in thousands): June 30, December 31, 2015 2014 Accrued liabilities $ 535 $ — Other liabilities (noncurrent) 544 — Changes in the fair value of our commodity derivative contracts were as follows (in thousands): Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Derivative loss $ 1,078 $ 13,079 $ 1,078 $ 20,571 Cash payments on commodity derivative contract settlements, net, are included within Net cash provided by operating activities Six Months Ended June 30, 2015 2014 Cash payments on derivative settlements, net $ — $ 14,310

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2015
Debt Disclosure [Abstract]
Long-Term Debt	5. Long-Term Debt Our long-term debt was as follows (in thousands): June 30, December 31, 2015 2014 8.50% Senior Notes due 2019 $ 900,000 $ 900,000 Debt premiums, net of amortization 11,805 13,057 9.00% Term Loan due 2020 300,000 — Debt discounts, net of amortization (2,935 ) — Revolving bank credit facility 260,000 447,000 Total long-term debt 1,468,870 1,360,057 Current maturities of long-term debt — — Long term debt, less current maturities $ 1,468,870 $ 1,360,057 At June 30, 2015 and December 31, 2014, our outstanding senior notes, which bear an annual interest rate of 8.50% and mature on June 15, 2019 (the “8.50% Senior Notes”), were 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. The debt premiums, net of amortization, are related to the 8.50% Senior Notes. We are subject to various financial and other covenants under the indenture governing the 8.50% Senior Notes, and we were in compliance with those covenants as of June 30, 2015. In May 2015, we entered into the 9.00% Term Loan, which has a principal of $300.0 million, bears an annual interest rate of 9.00%, was issued at a 1% discount to par and matures on May 15, 2020. The 9.00% Term Loan is secured by a second priority lien covering our oil and gas properties to the extent such properties secure first priority liens granted to secure indebtedness under our Credit Agreement. Interest on the 9.00% Term Loan is payable in arrears semi-annually on May 15 and November 15. The estimated annual effective interest rate on the 9.00% Term Loan is 9.7%, which includes amortization of debt issuance costs and discounts. The net proceeds were used to repay a portion of the outstanding borrowings incurred under our revolving bank credit facility governed by the Credit Agreement. A related party, which was an entity controlled by the Company’s Chairman and Chief Executive Officer, participated in the 9.00% Term Loan for a $5.0 million principal commitment on the same terms as the other lenders. We are subject to various covenants under the terms governing the 9.00% Term Loan, including without limitation covenants that limit our ability to incur other debt, pay dividends or distributions on our equity, merge or consolidate with other entities and make certain investments in other entities. We were in compliance with those covenants as of June 30, 2015. As of June 30, 2015, our revolving bank credit facility governed by the Credit Agreement matures on November 8, 2018. 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. At both June 30, 2015 and December 31, 2014, we had $0.6 million of letters of credit outstanding under the revolving bank credit facility. The estimated annual effective interest rate was 3.2% for the six months ended June 30, 2015 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 June 30, 2015, our borrowing base was $500.0 million and our borrowing availability was $239.4 million. During the second quarter of 2015, we entered into two amendments to the Credit Agreement. Following is a summary of the primary terms of the amendments: · The applicable margin applied to borrowings under the Credit Agreement was increased by 50 basis points (0.5%) on an annual basis. The margins on London Interbank Offered Rate (“LIBOR”) based borrowings range from 2.25% to 3.25% and the margins on alternate base rate borrowings range from 1.25% to 2.25%. · The Amendments permit us to incur additional unsecured indebtedness, or incur additional indebtedness which is subordinate in security compared to the indebtedness under the Credit Agreement, provided that, (A) no event of default has occurred or would result from such incurrence, (B) the Company is in compliance with its financial ratios after giving pro forma effect to the incurrence of the additional indebtedness, (C) such additional indebtedness matures at least six months after the maturity date of the Credit Agreement, and (D) such additional indebtedness is not subject to covenants and events of default that are, taken as a whole, materially more onerous than those provided for in the Credit Agreement. · Upon the incurrence of additional unsecured indebtedness, or the incurrence of additional indebtedness which is subordinate in security compared to the indebtedness under the Credit Agreement, the borrowing base will be reduced by $0.33 for each dollar of additional indebtedness until the borrowing base is redetermined. After giving effect to the issuance of the 9.00% Term Loan and the resulting reduction in the borrowing base, the borrowing base was adjusted to $500.0 million. · We are restricted on making distributions or repurchasing the existing 8.50% Senior Notes, the 9.00% Term Loan or other permitted indebtedness (i) until June 30, 2016, (ii) if an event of default is continuing or would result from such distribution or (iii) if a borrowing base deficiency is continuing or would result therefrom; provided that the restriction in clause (i) of this sentence does not apply to (A) scheduled payments of interest, principal or redemptions on the Company’s existing 8.50% Senior Notes, the 9.00% Term Loan or other permitted additional debt and (B) the redemption or repurchase by the Company of its outstanding indebtedness in an aggregate principal amount equal to the aggregate principal amount of any new indebtedness, provided that any such new notes are not subject to covenants and events of default that are, taken as a whole, materially more restrictive on the Company. · The financial covenants, with definitions of capitalized terms contained in the Credit Agreement, were set as follows: a) The maximum Leverage Ratio was suspended for the first quarter of 2016; then is limited to 5.00:1.00 for the second quarter of 2016; 4.50:1.00 for the third quarter of 2016; and 4.00:1.00 thereafter. b) The minimum Current Ratio is 0.75:1.00 effective for the first quarter of 2015 through the fourth quarter of 2015; and 1.00:1.00 thereafter. c) The maximum First Lien Leverage Ratio is 2.50:1.00 effective for the first quarter of 2015 and thereafter. d) The maximum Secured Debt Leverage Ratio is 3.50:1.00 effective for the first quarter of 2015 and thereafter. e) The minimum Interest Coverage Ratio is 2.20:1.00 effective for the first quarter of 2015 and thereafter. · The mortgaged collateral requirement was increased from 80% to 90% of the total value of both the (i) total proved oil and gas reserves and (ii) the proved developed producing reserves. · We are required to maintain minimum derivative positions of 25% of estimated oil and natural gas production for the second half of 2015 and 35% of estimated oil and natural gas production for 2016. · The amendment authorized the Administrative Agent under the Credit Agreement governing our revolving credit facility to enter into an Intercreditor Agreement with the lenders under the 9.00% Term Loan, which established the relationship and the priority of the liens securing the revolving bank credit facility and the 9.00% Term Loan. The foregoing description of the Credit Agreement does not purport to be complete and is qualified in its entirety by reference to the agreement. During the second quarter of 2015, the borrowing base on the revolving bank credit facility was reduced after the semi-annual redetermination and further reduced in conjunction with the issuance of the 9.00% Term Loan pursuant to the terms of the Credit Agreement. The reductions in the borrowing base resulted in proportional reductions in the unamortized debt issuance costs of $2.0 million related to the Credit Agreement, which is recorded within the line Debt issuance costs write-off and other, net Under the Credit Agreement, we are subject to various financial covenants, as listed above, which are calculated as of the last day of each fiscal quarter. We were in compliance with all applicable covenants of the Credit Agreement as of June 30, 2015. For information about fair value measurements for our 8.50% Senior Notes, 9.00% Term Loan and revolving bank credit facility, refer to Note 6.

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	6. Fair Value Measurements We measure the fair value of our open 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 values of our 8.50% Senior Notes and 9.00% Term Loan were based on quoted prices, although 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 derivatives and long-term debt, all of which are reported as liabilities on the Condensed Consolidated Balance Sheets (in thousands): Hierarchy June 30, 2015 December 31, 2014 Derivatives Level 2 $ 1,079 $ — 8.50% Senior Notes due 2019 ( 1 ) Level 2 633,060 594,000 9.00% Term Loan due 2020 ( 1 ) Level 2 296,250 — Revolving bank credit facility ( 1 ) Level 2 260,000 447,000 (1) The long-term debt items are reported on the Condensed Consolidated Balance Sheets at their carrying value as described in Note 5.

Share-Based Compensation and Ca

Share-Based Compensation and Cash-Based Incentive Compensation	6 Months Ended
	Jun. 30, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Share-Based Compensation and Cash-Based Incentive Compensation	7. 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, and amendments to the Plan were approved by our shareholders in May 2013. As allowed by the Plan, during 2014 and in 2013, the Company granted restricted stock units (“RSUs”) to certain of its employees. During the six months ended June 30, 2015, no RSUs were granted. RSUs are a long-term compensation component of the Plan, which are granted to only certain employees, and are subject to adjustments at the end of the applicable performance period based on the achievement of certain predetermined criteria. In 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 pre-defined performance criteria. During 2014, RSUs granted were subject to adjustments based on achievement of a combination of performance criteria, which was comprised of: (i) net income before income tax expense, net interest expense, depreciation, depletion, amortization, accretion and certain other items (“Adjusted EBITDA”) for 2014 and (ii) Adjusted EBITDA as a percent of total revenues (“Adjusted EBITDA Margin”) for 2014. For 2014, the Company was above target for Adjusted EBITDA and was slightly below target for Adjusted EBITDA Margin. During 2013, RSUs granted were also subject to adjustments based on achievement of a combination of performance criteria, which was comprised of: (i) Adjusted EBITDA for 2013; (ii) Adjusted EBITDA Margin for 2013; and (iii) the Company’s total shareholder return (“TSR”) ranking against peer companies’ TSR for 2013, 2014 and January 1, 2015 to October 31, 2015. TSR is determined based upon the change in the entity’s stock price plus dividends for the applicable performance period. For 2013, the Company exceeded the target for Adjusted EBITDA and was approximately at target for 2013 Adjusted EBITDA Margin. For 2014 and 2013, the Company was below target for the TSR rankings for each period. All RSUs granted to date are subject to employment-based criteria and vesting occurs in December of the second year after the grant. For example, the RSUs granted during 2013 will vest in December 2015 to eligible employees assuming the requisite performance goals and employment-based criteria are also satisfied. The 2014 annual incentive award for the Chief Executive Officer (“CEO”) was settled in shares of common stock based on a pre-determined price of $14.66 per share, pursuant to the terms of his award. In March 2015, after reductions for employee payroll and withholding taxes, the net amount of the CEO’s 2014 award resulted in 37,316 shares of common stock issued to the CEO. The 2013 annual incentive award for the CEO was settled in shares of common stock based at the price of $14.84, which was the Company’s closing price the day prior to the settlement date. In March 2014, after reductions for employee payroll and withholding taxes, the net amount of the CEO’s 2013 award resulted in 42,547 Under the Director Compensation Plan, shares of restricted stock (“Restricted Shares”) have been granted to the Company’s non-employee directors. Grants to non-employee directors were made during 2015, 2014 and 2013. The Restricted Shares are subject to service conditions and vesting occurs at the end of specified service periods. At June 30, 2015, there were 4,735,483 shares of common stock available for issuance in satisfaction of awards under the Plan and 444,024 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 Shares or shares of common stock are granted. RSUs reduce the shares available in the Plan when the RSUs are settled in shares of common stock, net of withholding tax. 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. 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. Awards Based on Restricted Stock to Non-Employee Directors . As of June 30, 2015, all of the unvested shares of Restricted Shares outstanding 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 Restricted Shares, including the right to vote and receive dividends or other distributions paid with respect to the Restricted Shares. The fair value of Restricted Shares was estimated by using the Company’s closing price on the grant date. A summary of activity in 2015 related to Restricted Shares awarded to non-employee directors is as follows: Restricted Shares Weighted Average Grant Date Fair Shares Value Per Share Nonvested, December 31, 2014 43,210 $ 16.20 Granted 56,540 6.19 Vested (21,520 ) 16.26 Nonvested, June 30, 2015 78,230 8.95 Subject to the satisfaction of service conditions, the outstanding Restricted Shares issued to the non-employee directors as of June 30, 2015 are expected to vest as follows: Restricted Shares 2016 34,265 2017 25,115 2018 18,850 Total 78,230 The grant date fair values of Restricted Shares awarded during the first half of 2015 and the first half of 2014 was $0.3 million for both periods. The fair values of Restricted Shares that vested during the first half of 2015 and the first half of 2014 were $0.1 million and $0.3 million, respectively. Awards Based on Restricted Stock Units. As of June 30, 2015, the Company had outstanding RSUs issued to certain employees. As described above, the RSUs granted during 2014 and 2013 were 100% performance based and were subject to pre-defined performance measures and employment-based criteria. A portion of the RSUs granted during 2013 remains subject to the performance measure of TSR for the defined period in 2015; therefore, the number of RSUs may be adjusted upon determination of the performance. The RSUs subject to performance measurement which has not yet been determined are disclosed in the table below for RSUs potentially eligible to vest. The fair value for the RSUs granted during 2014 was determined using the Company’s closing price on the grant date as the performance measures were all Company-specific performance measures comprised of Adjusted EBITDA and Adjusted EBITDA Margin. The fair value for the 2013 RSUs was determined separately for the components related to the TSR targets and the Company specific performance measures (Adjusted EBITDA and Adjusted EBITDA Margin). The fair value for the 2013 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 2013; risk-free interest rates using the LIBOR ranging from 0.27% to 0.91% over the service period; expected volatilities ranging from 30% to 63%; expected dividend yields ranging from 0.0% to 3.1%; and correlation factors ranging from a negative 84% to a positive 95%. The expected volatilities, expected dividends and correlation factors were developed using historical data. The fair value of all other 2013 RSUs components was determined using the Company’s closing price on the grant date. All RSUs awarded are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during the restricted period. Dividend equivalents are earned at the same rate as dividends paid on our common stock after achieving the specified performance requirement for that component of the RSUs. A summary of activity in 2015 related to RSUs is as follows: Restricted Stock Units Weighted Average Grant Date Fair Units Value Per Unit Nonvested, December 31, 2014 1,977,335 $ 15.29 Vested (23,500 ) 14.68 Forfeited (71,890 ) 15.15 Nonvested, June 30, 2015 1,881,945 15.30 All of the outstanding RSUs are subject to the satisfaction of service conditions and a portion of the outstanding RSUs are also subject to pre-defined performance measurements. The RSUs outstanding as of June 30, 2015 potentially eligible to vest are listed in the table below: Restricted Stock Units 2015 - subject to service requirements 706,370 2015 - subject to service and other requirements (1) 86,507 2016 - subject to service requirements 1,089,068 Total 1,881,945 (1) In addition to service requirements, these RSUs are also subject to TSR performance requirements not yet measureable, with awards ranging from 0% to 200% of amounts granted. The grant date fair value of RSUs granted during the first half of 2014 was $19.9 million. The fair value of RSUs that vested during the first half of 2015 and the first half of 2014 was $0.1 million for both periods. 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 Six Months Ended June 30, June 30, 2015 2014 2015 2014 Share-based compensation expense from: Restricted stock $ 90 $ 84 $ 183 $ 183 Restricted stock units 2,802 3,625 5,619 6,161 Common shares — 178 (94 ) 1,300 Total $ 2,892 $ 3,887 $ 5,708 $ 7,644 Share-based compensation tax benefit: Tax benefit computed at the statutory rate $ 1,012 $ 1,360 $ 1,998 $ 2,675 Unrecognized Share-Based Compensation. As of June 30, 2015, unrecognized share-based compensation expense related to our awards of Restricted Shares and RSUs was $0.6 million and $10.9 million, respectively. Unrecognized share-based compensation expense will be recognized through April 2018 for Restricted Shares and November 2016 for RSUs. Cash-Based Incentive Compensation. As defined by the Plan, annual incentive awards may be granted to eligible employees and payable in cash. (In the case of the award to the CEO, the awards for 2014 and 2013 were paid in shares of common stock as described above.) These awards are performance-based awards consisting of one or more business or individual performance criteria and a targeted level or levels of performance with respect to each such criterion. Generally, the performance period is the calendar year and determination and payment is made in cash in the first quarter of the following year. During the first half of 2015, the Company did not issue any cash-based incentive awards for 2015. Amounts recorded during the first half of 2015 relate to the 2014 cash-based awards, for which costs were recognized from the award date through February 2015 (the service period), and adjustments were recorded to true up previous estimates to actual payments. Share-Based Compensation and Cash-Based Incentive Compensation Expense. A summary of incentive compensation expense is as follows (in thousands): Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Share-based compensation included in: General and administrative expenses $ 2,892 $ 3,887 $ 5,708 $ 7,644 Cash-based incentive compensation included in: Lease operating expense — 475 364 1,777 General and administrative expenses (1) — 1,532 (233 ) 3,313 Total charged to operating income $ 2,892 $ 5,894 $ 5,839 $ 12,734 (1) Adjustments to true up estimates to actual payments resulted in net credit balances to expense for the six months ended June 30, 2015.

Income Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2015
Income Tax Disclosure [Abstract]
Income Taxes	8. Income Taxes Our income tax benefit for the three and six months ended June 30, 2015 was $44.1 million and $147.7 million, respectively. The income tax benefit is partially attributable to recording a ceiling test write-down in the three and six months ended June 30, 2015 of $252.8 million and $513.2 million, respectively. Our effective tax rate for the three and six months ended June 30, 2015 was 14.5% and 22.3%, respectively. Both of these percentages differ from the federal statutory rate of 35.0% primarily due to recording a valuation allowance for our deferred tax assets. Income tax expense for the three and six months ended June 30, 2014 was $5.3 million and $11.9 million, respectively. Our effective tax rate for the three and six months ended June 30, 2014 was 34.9% and 36.2%, respectively, and differed from the federal statutory rate primarily as a result of state income taxes and other permanent items. During the three and six months ended June 30, 2015, we recorded a valuation allowance of $62.9 million and $85.4 million, respectively, related to federal deferred tax assets and net operating losses. Deferred tax assets are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods. 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. We recognize interest and penalties related to unrecognized tax benefits in income tax expense. During the six months ended June 30, 2015 and 2014, we recorded immaterial amounts of accrued interest expense related to our unrecognized tax benefit.

Earnings Per Share

Earnings Per Share	6 Months Ended
	Jun. 30, 2015
Earnings Per Share [Abstract]
Earnings Per Share	9. Earnings Per Share The following table presents the calculation of basic and diluted earnings (loss) per common share (in thousands, except per share amounts): Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Net income (loss) $ (260,449 ) $ 9,837 $ (515,544 ) $ 21,026 Less portion allocated to nonvested shares — 100 — 219 Net income (loss) allocated to common shares $ (260,449 ) $ 9,737 $ (515,544 ) $ 20,807 Weighted average common shares outstanding 75,910 75,605 75,884 75,581 Basic and diluted earnings (loss) per common share $ (3.43 ) $ 0.13 $ (6.79 ) $ 0.28 Shares excluded due to being anti-dilutive (weighted-average) 355 — 277 —

Dividends

Dividends	6 Months Ended
	Jun. 30, 2015
Equity [Abstract]
Dividends	10. Dividends During the six months ended June 30, 2015, we did not declare or pay any dividends. During the six months ended June 30, 2014, we paid regular cash dividends per common share of $0.10 each quarter. Pursuant to the financial covenants in the Credit Agreement, the regular quarterly dividend is effectively suspended until June 2016. The suspension imposed by the Credit Agreement will be lifted when the maximum Leverage Ratio, as defined in the Credit Agreement, is reinstated and the Company is able to comply with the covenant. In addition, the dividend may be suspended due to the lack of statutory surplus under state law. See Note 5 for additional information.

Contingencies

Contingencies	6 Months Ended
	Jun. 30, 2015
Commitments And Contingencies Disclosure [Abstract]
Contingencies	11. Contingencies Notification by ONRR of Fine for Non-compliance. In December 2013 and January 2014, we were notified by the Office of Natural Resources Revenue (“ONRR”) of an underpayment of royalties on certain Federal offshore oil and gas leases that cumulatively approximated $30,000 over several years, which represents 0.0045% of royalty payments paid by us during the same period of the underpayment. In March 2014, we received notice from the ONRR of a statutory fine of $2.3 million relative to such underpayment. We believe the fine is excessive considering the circumstances and in relation to the amount of underpayment. On April 23, 2014, we filed a request for a hearing on the record and a general denial of the ONRR’s allegations contained in the March notice. We intend to contest the fine to the fullest extent possible. The ultimate resolution may result in a waiver of the fine, a reduction of the fine, or payment of the full amount plus interest covering several years. As no amount has been determined as more likely than any other within the range of possible resolutions, no amount has been accrued as of June 30, 2015 or December 31, 2014 per authoritative guidance. However, we cannot state with certainty that our estimate of the exposure is accurate concerning this matter. Apache Lawsuit. On December 15, 2014, Apache Corporation (“Apache”) filed a lawsuit against W&T Offshore, Inc., alleging that W&T breached the joint operating agreement (“JOA”) related to deepwater wells in the Mississippi Canyon area of the Gulf of Mexico. That lawsuit, styled Apache Corporation v. W&T Offshore, Inc. , is currently pending in the United States District Court for the Southern District of Texas. Apache contends that W&T has failed to pay its proportional share of the costs associated with plugging and abandoning three wells that are subject to the JOA. We contend that the costs incurred by Apache are excessive and unreasonable. Apache seeks an award of unspecified actual damages, interest, court costs, and attorneys’ fees. In February 2015, we made a payment to Apache for our net share of the amounts that we believe are reasonable to plug and abandon the three wells, all of which was originally recorded as an asset retirement obligation and was accrued on our Condensed Consolidated Balance Sheet as of December 31, 2014. Our estimate of the potential exposure ranges from zero to $32 million related to this matter, which excludes potential interest, court costs and attorneys’ fees. Insurance Claims. During the fourth quarter of 2012, underwriters of W&T’s excess liability policies (“Excess Policies”) (Indemnity Insurance Company of North America, New York Marine & General Insurance Company, Navigators Insurance Company, XL Specialty Insurance Company, National Liability & Fire Insurance Company (“Starr Marine”) and Liberty Mutual Insurance Co.) filed declaratory judgment actions in the United States District Court for the Southern District of Texas (the “District Court”) seeking a determination that our Excess Policies do not cover removal-of-wreck and debris claims arising from Hurricane Ike except to the extent we have first exhausted the limits of our Energy Package (defined as certain insurance policies relating to our oil and gas properties which includes named windstorm coverage) with only removal-of-wreck and debris claims. The court consolidated the various suits filed by the underwriters. In January 2013, we filed a motion for summary judgment seeking the court’s determination that such Excess Policies do not require us to exhaust the limits of our Energy Package policies with only removal-of-wreck and debris claims. In July 2013, the District Court ruled in favor of the underwriters, adopting their position that the Excess Policies cover removal-of-wreck and debris claims only to the extent the limits of our Energy Package policies have been exhausted with removal-of-wreck and debris claims. We appealed the decision in the United States Court of Appeals for the Fifth Circuit (the “Fifth Circuit”) and, in June 2014, the Fifth Circuit reversed the District Court’s ruling and ruled in our favor. The underwriters filed three separate briefs requesting a rehearing or a certification to the Texas Supreme Court, all of which the Court denied. A brief was subsequently filed by one underwriter requesting a rehearing to the District Court of the Fifth Circuit’s decision, which the District Court denied. Claims of approximately $42 million were filed, of which approximately $1 million was paid under the Energy Package and of which approximately $1 million was paid under our Comprehensive General Liability policy. One of the underwriters, Liberty Mutual Insurance Co., paid their portion of the settlement (approximately $5 million), in addition to a portion of interest owed. The other underwriters have not paid in accordance with the Fifth Circuit ruling, and we filed a lawsuit in September 2014 against these underwriters for amounts owed, interest, attorney fees and damages. Subsequent to the filing of that lawsuit, Starr Marine has paid their portion ($5 million) of the first excess liability policy without interest. The lawsuit includes claims for interest underpaid by Liberty Mutual Insurance Co. and interest not paid by Starr Marine. The revised estimate of potential reimbursement is approximately $30 million, plus interest, attorney fees and damages, if any. Removal-of-wreck costs are recorded in Oil and natural gas properties and equipment on the Condensed Consolidated Balance Sheets and recoveries from claims made on these Excess Policies will be recorded as reductions in this line item, which will reduce our future DD&A rate. Royalties. In 2009, the Company recognized allowable reductions of cash payments for royalties owed to 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 2010, we were notified that the ONRR had disallowed approximately $4.7 million of the reductions taken. We recorded a reduction to other revenue in 2010 to reflect this disallowance; however, we disagree with the position taken by the ONRR. We filed an appeal with the ONRR, which was denied in May 2014. On June 17, 2014, we filed an appeal with the Board of Land Appeals (the “BLA”) under the Department of the Interior. W&T’s brief was filed in November 2014 and we expect the briefing before BLA to be completed in 2015. The ONRR has publicly announced an “unbundling” initiative to review the methodology employed by producers in determining the appropriate allowances for transportation and processing costs that are permitted to be deducted in determining royalties under Federal oil and gas leases. In the second quarter of 2015, pursuant to the initiative, the Company received requests from the ONRR for additional data regarding the Company’s transportation and processing allowances on natural gas production that is processed through a specific processing plant. The Company also received a preliminary determination notice from the ONRR asserting its preliminary determination that the Company’s allocation of certain processing costs and plant fuel use at another processing plant were impermissibly allowed as deductions in the determination of royalties owed under Federal oil and gas leases. The Company intends to submit a response to the preliminary determination asserting the reasonableness of its own allocation methodology of such costs. These open ONRR unbundling reviews, and any further similar reviews, could ultimately result in an order for payment of additional royalties under the Company’s Federal oil and gas leases for current and prior periods. The Company is not able to determine the likelihood or range of any additional royalties or, if and when assessed, whether such amounts would be material. Notices of Proposed Civil Penalty Assessment. During the first half of 2015, the Company received two notices from the Bureau of Safety and Environmental Enforcement (the “BSEE”) proposing civil penalties totaling $3.6 million related to Incidents of Noncompliance (“INCs”) at two offshore locations, one of which occurred in 2012 and one occurred in 2014. The Company’s position is the civil penalties are excessive given the specific facts and circumstances related to the INCs and we have accrued an amount less than the proposed assessment . 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 including matters related to alleged royalty underpayments on certain federal-owned properties. 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, we believe 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. There were no material expenses recognized related to accrued and settled claims, complaints and fines for the three and six months ended June 30, 2015 and 2014. As of June 30, 2015 and December 31, 2014, we had no material amounts recorded in liabilities for claims, complaints and fines.

Supplemental Guarantor Informat

Supplemental Guarantor Information	6 Months Ended
	Jun. 30, 2015
Supplemental Guarantor Information [Abstract]
Supplemental Guarantor Information	W&T OFFSHORE, INC. AND SUBSIDIARIES 12. Supplemental Guarantor Information Our payment obligations under the 8.50% Senior Notes, the 9.00% Term Loan and the Credit Agreement (see Note 5) are fully and unconditionally guaranteed by certain of our 100%-owned subsidiaries, including Energy VI and W & T Energy VII, LLC (together, the “Guarantor Subsidiaries”). W & T Energy VII, LLC does not currently have any active operations or contain any assets. Guarantees of the 8.50% Senior Notes will be released under certain circumstances, including: (1) (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 certain debt documents; (4) upon Legal Defeasance or Covenant Defeasance (as such terms are defined in certain debt documents) or upon satisfaction and discharge of the certain debt documents; (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 as described in certain debt documents, provided no event of default has occurred and is continuing. The following condensed consolidating financial information presents the financial condition, results of operations and cash flows of the Parent Company and the Guarantor Subsidiaries, together with consolidating adjustments necessary to present the Company’s results on a consolidated basis. Transfers of property were made from the Parent Company to the Guarantor Subsidiaries. As these transfers were transactions between entities under common control, the prior period financial information has been retrospectively adjusted for comparability purposes, as prescribed under authoritative guidance. None of the adjustments had any effect on the consolidated results for the current or prior periods presented. Condensed Consolidating Balance Sheet as of June 30, 2015 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Assets Current assets: Cash and cash equivalents $ 5,671 $ — $ — $ 5,671 Receivables: Oil and natural gas sales 23,109 28,848 — 51,957 Joint interest and other 114,021 — (81,413 ) 32,608 Total receivables 137,130 28,848 (81,413 ) 84,565 Deferred income taxes 56,955 1,865 (52,000 ) 6,820 Prepaid expenses and other assets 22,821 4,469 — 27,290 Total current assets 222,577 35,182 (133,413 ) 124,346 Property and equipment – at cost: Oil and natural gas properties and equipment 6,064,146 2,143,019 — 8,207,165 Furniture, fixtures and other 23,981 — — 23,981 Total property and equipment 6,088,127 2,143,019 — 8,231,146 Less accumulated depreciation, depletion and amortization 4,937,933 1,368,186 — 6,306,119 Net property and equipment 1,150,194 774,833 — 1,925,027 Restricted deposits for asset retirement obligations 15,538 — — 15,538 Other assets 868,316 293,570 (1,141,820 ) 20,066 Total assets $ 2,256,625 $ 1,103,585 $ (1,275,233 ) $ 2,084,977 Liabilities and Shareholders’ Equity Current liabilities: Accounts payable $ 130,386 $ 4,779 $ — $ 135,165 Undistributed oil and natural gas proceeds 28,650 1,043 — 29,693 Asset retirement obligations 34,992 6,502 — 41,494 Accrued liabilities 13,543 80,990 (81,413 ) 13,120 Total current liabilities 207,571 93,314 (81,413 ) 219,472 Long-term debt, less current maturities 1,468,870 — — 1,468,870 Asset retirement obligations, less current portion 216,706 131,867 — 348,573 Deferred income taxes 382 85,908 (52,000 ) 34,290 Other liabilities 363,884 — (349,324 ) 14,560 Shareholders’ equity: Common stock 1 — — 1 Additional paid-in capital 420,028 704,885 (704,885 ) 420,028 Retained earnings (deficit) (396,650 ) 87,611 (87,611 ) (396,650 ) Treasury stock, at cost (24,167 ) — — (24,167 ) Total shareholders’ equity (deficit) (788 ) 792,496 (792,496 ) (788 ) Total liabilities and shareholders’ equity $ 2,256,625 $ 1,103,585 $ (1,275,233 ) $ 2,084,977 Condensed Consolidating Balance Sheet as of December 31, 2014 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Assets Current assets: Cash and cash equivalents $ 23,666 $ — $ — $ 23,666 Receivables: Oil and natural gas sales 41,820 25,422 — 67,242 Joint interest and other 142,885 — (99,240 ) 43,645 Total receivables 184,705 25,422 (99,240 ) 110,887 Deferred income taxes 9,797 1,865 — 11,662 Prepaid expenses and other assets 28,728 7,619 — 36,347 Total current assets 246,896 34,906 (99,240 ) 182,562 Property and equipment – at cost: Oil and natural gas properties and equipment 6,038,915 2,006,751 — 8,045,666 Furniture, fixtures and other 23,269 — — 23,269 Total property and equipment 6,062,184 2,006,751 — 8,068,935 Less accumulated depreciation, depletion and amortization 4,442,899 1,132,179 — 5,575,078 Net property and equipment 1,619,285 874,572 — 2,493,857 Restricted deposits for asset retirement obligations 15,444 — — 15,444 Other assets 974,049 357,992 (1,314,797 ) 17,244 Total assets $ 2,855,674 $ 1,267,470 $ (1,414,037 ) $ 2,709,107 Liabilities and Shareholders’ Equity Current liabilities: Accounts payable $ 188,654 $ 5,455 $ — $ 194,109 Undistributed oil and natural gas proceeds 36,130 879 — 37,009 Asset retirement obligations 30,711 5,292 — 36,003 Accrued liabilities 17,437 99,180 (99,240 ) 17,377 Total current liabilities 272,932 110,806 (99,240 ) 284,498 Long-term debt, less current maturities 1,360,057 — — 1,360,057 Asset retirement obligations, less current portion 235,876 118,689 — 354,565 Deferred income taxes 59,616 127,372 — 186,988 Other liabilities 417,885 — (404,194 ) 13,691 Shareholders’ equity: Common stock 1 — — 1 Additional paid-in capital 414,580 703,440 (703,440 ) 414,580 Retained earnings 118,894 207,163 (207,163 ) 118,894 Treasury stock, at cost (24,167 ) — — (24,167 ) Total shareholders’ equity 509,308 910,603 (910,603 ) 509,308 Total liabilities and shareholders’ equity $ 2,855,674 $ 1,267,470 $ (1,414,037 ) $ 2,709,107 Condensed Consolidating Statement of Operations for the Three Months Ended June 30, 2015 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Revenues $ 90,465 $ 58,601 $ — $ 149,066 Operating costs and expenses: Lease operating expenses 30,104 15,026 — 45,130 Production taxes 1,000 — — 1,000 Gathering and transportation 2,769 2,024 — 4,793 Depreciation, depletion, amortization and accretion 58,023 45,319 — 103,342 Ceiling test write-down of oil and natural gas properties 181,300 71,472 — 252,772 General and administrative expenses 10,856 8,901 — 19,757 Derivative loss 1,078 — — 1,078 Total costs and expenses 285,130 142,742 — 427,872 Operating loss (194,665 ) (84,141 ) — (278,806 ) Loss of affiliates (54,548 ) — 54,548 — Interest expense: Incurred 25,322 794 — 26,116 Capitalized (1,230 ) (794 ) — (2,024 ) Debt issuance costs write-off and other, net 1,685 — — 1,685 Loss before income tax benefit (274,990 ) (84,141 ) 54,548 (304,583 ) Income tax benefit (14,541 ) (29,593 ) — (44,134 ) Net loss $ (260,449 ) $ (54,548 ) $ 54,548 $ (260,449 ) Condensed Consolidating Statement of Operations for the Six Months Ended June 30, 2015 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Revenues $ 167,808 $ 109,165 $ — $ 276,973 Operating costs and expenses: Lease operating expenses 67,742 30,719 — 98,461 Production taxes 1,637 — — 1,637 Gathering and transportation 5,334 4,283 — 9,617 Depreciation, depletion, amortization and accretion 129,374 99,435 — 228,809 Ceiling test write-down of oil and natural gas properties 371,995 141,167 — 513,162 General and administrative expenses 22,615 17,908 — 40,523 Derivative loss 1,078 — — 1,078 Total costs and expenses 599,775 293,512 — 893,287 Operating loss (431,967 ) (184,347 ) — (616,314 ) Loss of affiliates (119,552 ) — 119,552 — Interest expense: Incurred 47,554 1,508 — 49,062 Capitalized (2,299 ) (1,508 ) — (3,807 ) Debt issuance costs write-off and other, net 1,683 — — 1,683 Loss before income tax benefit (598,457 ) (184,347 ) 119,552 (663,252 ) Income tax benefit (82,913 ) (64,795 ) — (147,708 ) Net loss $ (515,544 ) $ (119,552 ) $ 119,552 $ (515,544 ) Condensed Consolidating Statement of Operations for the Three Months Ended June 30, 2014 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Revenues $ 156,033 $ 106,961 $ — $ 262,994 Operating costs and expenses: Lease operating expenses 40,846 20,919 — 61,765 Production taxes 1,842 — — 1,842 Gathering and transportation 2,232 1,753 — 3,985 Depreciation, depletion, amortization and accretion 68,921 59,315 — 128,236 General and administrative expenses 10,269 9,413 — 19,682 Derivative loss 13,079 — — 13,079 Total costs and expenses 137,189 91,400 — 228,589 Operating income 18,844 15,561 — 34,405 Earnings of affiliates 10,252 — (10,252 ) — Interest expense: Incurred 20,617 837 — 21,454 Capitalized (1,322 ) (837 ) — (2,159 ) Income before income tax expense 9,801 15,561 (10,252 ) 15,110 Income tax expense (benefit) (36 ) 5,309 — 5,273 Net income $ 9,837 $ 10,252 $ (10,252 ) $ 9,837 Condensed Consolidating Statement of Operations for the Six Months Ended June 30, 2014 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Revenues $ 302,156 $ 215,354 $ — $ 517,510 Operating costs and expenses: Lease operating expenses 80,172 37,212 — 117,384 Production taxes 3,834 — — 3,834 Gathering and transportation 5,580 3,701 — 9,281 Depreciation, depletion, amortization and accretion 132,117 119,425 — 251,542 General and administrative expenses 21,850 21,420 — 43,270 Derivative loss 20,571 — — 20,571 Total costs and expenses 264,124 181,758 — 445,882 Operating income 38,032 33,596 — 71,628 Earnings of affiliates 21,940 — (21,940 ) — Interest expense: Incurred 41,294 1,618 — 42,912 Capitalized (2,613 ) (1,618 ) — (4,231 ) Income before income tax expense 21,291 33,596 (21,940 ) 32,947 Income tax expense (benefit) 265 11,656 — 11,921 Net income $ 21,026 $ 21,940 $ (21,940 ) $ 21,026 Condensed Consolidating Statement of Cash Flows for the Six Months Ended June 30, 2015 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Operating activities: Net loss $ (515,544 ) $ (119,552 ) $ 119,552 $ (515,544 ) Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Depreciation, depletion, amortization and accretion 129,374 99,435 — 228,809 Ceiling test write-down of oil and gas properties 371,995 141,167 — 513,162 Debt issuance costs write-off/amortization of debt items 2,432 — — 2,432 Share-based compensation 5,708 — — 5,708 Derivative loss 1,078 — — 1,078 Deferred income taxes (105,818 ) (41,890 ) — (147,708 ) Loss of affiliates 119,552 — (119,552 ) — Changes in operating assets and liabilities: Oil and natural gas receivables 18,710 (3,425 ) — 15,285 Joint interest and other receivables 11,036 — — 11,036 Income taxes 22,580 (22,905 ) — (325 ) Prepaid expenses and other assets (8,913 ) 72,712 (54,870 ) 8,929 Asset retirement obligation settlements (21,146 ) (793 ) — (21,939 ) Accounts payable, accrued liabilities and other (125,219 ) (513 ) 54,870 (70,862 ) Net cash provided by (used in) operating activities (94,175 ) 124,236 — 30,061 Investing activities: Investment in oil and natural gas properties and equipment (25,313 ) (125,681 ) — (150,994 ) Investment in subsidiary (1,445 ) — 1,445 — Purchases of furniture, fixtures and other (709 ) — — (709 ) Net cash used in investing activities (27,467 ) (125,681 ) 1,445 (151,703 ) Financing activities: Borrowings of long-term debt – revolving bank credit facility 194,000 — — 194,000 Repayments of long-term debt – revolving bank credit facility (381,000 ) — — (381,000 ) Issuance of 9.00% Term Loan 297,000 — — 297,000 Debt issuance costs (6,407 ) — — (6,407 ) Other 54 — — 54 Investment from parent — 1,445 (1,445 ) — Net cash provided by financing activities 103,647 1,445 (1,445 ) 103,647 Decrease in cash and cash equivalents (17,995 ) — — (17,995 ) Cash and cash equivalents, beginning of period 23,666 — — 23,666 Cash and cash equivalents, end of period $ 5,671 $ — $ — $ 5,671 Condensed Consolidating Statement of Cash Flows for the Six Months Ended June 30, 2014 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Operating activities: Net income $ 21,026 $ 21,940 $ (21,940 ) $ 21,026 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion, amortization and accretion 132,117 119,425 — 251,542 Amortization of debt issuance costs and premium 366 — — 366 Share-based compensation 7,644 — — 7,644 Derivative loss 20,571 — — 20,571 Cash payments on derivative settlements (14,310 ) — — (14,310 ) Deferred income taxes 25,078 (13,157 ) — 11,921 Earnings of affiliates (21,940 ) — 21,940 — Changes in operating assets and liabilities: Oil and natural gas receivables 7,636 (5,301 ) — 2,335 Joint interest and other receivables 3,550 — — 3,550 Income taxes (21,896 ) 24,814 — 2,918 Prepaid expenses and other assets (123,770 ) (91,015 ) 219,224 4,439 Asset retirement obligations (18,583 ) (11,755 ) — (30,338 ) Accounts payable, accrued liabilities and other 203,344 5,266 (219,224 ) (10,614 ) Net cash provided by operating activities 220,833 50,217 — 271,050 Investing activities: Acquisition of property interest in oil and natural gas properties — (53,363 ) — (53,363 ) Investment in oil and natural gas properties and equipment (157,128 ) (55,552 ) — (212,680 ) Investment in subsidiary (58,698 ) — 58,698 — Purchases of furniture, fixtures and other (1,715 ) — — (1,715 ) Net cash used in investing activities (217,541 ) (108,915 ) 58,698 (267,758 ) Financing activities: Borrowings of long-term debt – revolving bank credit facility 220,000 — — 220,000 Repayments of long-term debt – revolving bank credit facility (200,000 ) — — (200,000 ) Dividends to shareholders (15,129 ) — — (15,129 ) Other (116 ) — — (116 ) Investment from parent — 58,698 (58,698 ) — Net cash used in financing activities 4,755 58,698 (58,698 ) 4,755 Increase in cash and cash equivalents 8,047 — — 8,047 Cash and cash equivalents, beginning of period 15,800 — — 15,800 Cash and cash equivalents, end of period $ 23,847 $ — $ — $ 23,847

Basis of Presentation (Policies

Basis of Presentation (Policies)	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Operations	Operations. W&T Offshore, Inc. (with subsidiaries referred to herein as “W&T,” “we,” “us,” “our,” 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. Our interest in fields, leases, structures and equipment are primarily owned by W&T Offshore, Inc. (on a stand-alone basis, the “Parent Company”) and its 100%-owned subsidiary, W & T Energy VI, LLC (“Energy VI”).
Interim Financial Statements	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 periods 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 for annual periods. 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, 2014.
Transactions between Entities Under Common Control	Transactions between Entities under Common Control. The prior period financial information for the three and six months ended June 30, 2014 presented in Note 13, Supplemental Guarantor Information , has been retrospectively adjusted due to transactions between entities under common control, as required under authoritative guidance.
Use of Estimates	Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.
Ceiling Test Write-Down	Ceiling Test Write-Down. Under the full cost method of accounting, we are required to periodically perform a “ceiling test,” which determines a limit on the book value of our oil and natural gas properties. If the net capitalized cost of oil and natural gas properties (including capitalized asset retirement obligations (“ARO”)) net of related deferred income taxes exceeds the ceiling test limit, the excess is charged to expense on a pre-tax basis and separately disclosed. Any such write downs are not recoverable or reversible in future periods. The ceiling test limit is calculated as: (i) the present value of estimated future net revenues from proved reserves, less estimated future development costs, discounted at 10%; (ii) plus the cost of unproved oil and natural gas properties not being amortized; (iii) plus the lower of cost or estimated fair value of unproved oil and natural gas properties included in the amortization base; and (iv) less related income tax effects. Estimated future net revenues used in the ceiling test for each period are based on current prices, defined by the SEC as the unweighted average of first-day-of-the-month commodity prices over the prior twelve months for that period. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. Due primarily to declines in the unweighted rolling 12-month average of first-day-of-the-month commodity prices for oil and natural gas for the first and second quarters of 2015, we recorded ceiling test write-downs which are reported as a separate line in the Statements of Operations
Recent Events	Recent Events. The price we receive for our oil, natural gas liquids (“NGLs”) and natural gas production directly affects our revenues, profitability, cash flows, liquidity, access to capital and future rate of growth. The prices of these commodities began falling in the second half of 2014 and were significantly lower during the first half of 2015 compared to the last few years. We have taken several steps to mitigate the effects of these lower prices including: (i) significantly reducing the 2015 capital budget from the previous year; (ii) suspending our drilling and completion activities at several locations; (iii) suspending the regular quarterly common stock dividend and (iv) implementing numerous cost reduction projects to reduce our operating costs. During the second quarter of 2015, we entered into two Amendments to our Fifth Amended and Restated Credit Agreement (as amended, the “Credit Agreement”), which, among other things, revised certain financial covenants to be less restrictive, modified the borrowing base adjustment for additional debt and authorized the administrative agent under the Credit Agreement to enter into an Intercreditor Agreement among the Company, the lenders under the Credit Agreement and the lenders under the second lien term loan (the We have assessed our financial condition, the current capital markets and options given different scenarios of commodity prices and believe we will have adequate liquidity to fund our operations through June 30, 2016. However, we cannot predict how an extended period of commodity prices at existing levels or a significant reduction in our borrowing base will affect our operations and liquidity levels.
Recent Accounting Developments	Recent Accounting Developments. In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2015-03 (“ASU 2015-03”), Interest – Imputation of Interest (Subtopic 835-30), Simplifying the Presentation of Debt Issuance Costs . The guidance seeks to simplify the presentation of debt issuance costs. The amendment would require debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of liability, consistent with debt discounts or premiums. The guidance was further clarified to state that debt issuance costs related to credit facilities could be reported as an asset regardless of the balance outstanding. The recognition and measurement guidance for debt issuance costs would not be affected by the amendment. ASU 2015-03 is effective in 2016 and should be applied on a retrospective basis. Early adoption is permitted. We do not expect the revised guidance to materially affect our balance sheets as amounts will be reclassified from long-term assets to partial offsets of long-term debt. The revised guidance will not affect the statements of operations or the statements of cash flows. In August 2014, the FASB issued Accounting Standards Update No. 2014-15 (“ASU 2014-15”), Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40). In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (“ASU 2014-09”), Summary and Amendments that Create Revenue from Contracts and Customers (Topic 606).

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	6 Months Ended
	Jun. 30, 2015
Fairway
Business Acquisition [Line Items]
Purchase Price Allocation for Acquisition	The following table presents the purchase price allocation, including adjustments, for the increased ownership interest in Fairway (in thousands): Cash consideration: Evaluated properties including equipment $ 18,693 Non-cash consideration: Asset retirement obligations - non-current 6,124 Total consideration $ 24,817
Woodside Properties
Business Acquisition [Line Items]
Purchase Price Allocation for Acquisition	The following table presents the purchase price allocation, including adjustments, for the acquisition of the Woodside Properties (in thousands): Cash consideration: Evaluated properties including equipment $ 52,329 Unevaluated properties 2,660 Sub-total cash consideration 54,989 Non-cash consideration: Asset retirement obligations - current 782 Asset retirement obligations - non-current 10,543 Sub-total non-cash consideration 11,325 Total consideration $ 66,314
Summary of Proforma Financial Information for Acquisition	The following table presents a summary of our pro forma financial information giving pro forma effect to the Woodside Properties acquisition (in thousands, except earnings per share): (unaudited) Three Months Ended Six Months Ended June 30, 2014 June 30, 2014 Revenue $ 272,022 $ 540,397 Net income 12,150 27,120 Basic and diluted earnings per common share 0.16 0.35
Business Acquisition Pro Forma Information Incremental Item	The following table presents incremental items included in the pro forma information reported above for the Woodside Properties (in thousands): (unaudited) Three Months Ended Six Months Ended June 30, 2014 (a) June 30, 2014 (a) Revenues (b) $ 9,028 $ 22,887 Direct operating expenses (b) 1,805 4,417 DD&A (c) 3,387 8,384 G&A (d) 200 400 Interest expense (e) 82 330 Capitalized interest (f) (5 ) (19 ) Income tax expense (g) 1,246 3,281 The sources of information and significant assumptions are described below: (a) The adjustments for the periods presented are from the beginning of the period to May 20, 2014. (b ) Revenues and direct operating expenses for the Woodside Properties were derived from the historical financial records of Woodside. (c ) DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Woodside Properties’ costs, reserves and production into our full cost pool in order to compute such amounts. The purchase price allocated to unevaluated properties for oil and natural gas interests was excluded from the DD&A expense estimation. ARO was estimated by W&T management. (d ) Consists of estimated incremental insurance costs related to the Woodside Properties. (e ) The Woodside Properties acquisition was assumed to be funded entirely with borrowed funds. Interest expense was computed using assumed borrowings of $55.0 million, which equates to the cash component of the acquisition purchase price, and an interest rate of 1.8%, which equates to the rates applied to incremental borrowings on the revolving bank credit facility. (f ) The change to capitalized interest was computed for the addition to the pool of unevaluated properties and the capitalization interest rate was adjusted for the assumed borrowings. The negative amount represents a decrease to net expenses. (g ) Income tax expense was computed using the 35% federal statutory rate. The pro forma adjustments do not include adjustments related to any other acquisitions or divestitures.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	6 Months Ended
	Jun. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
Summary of Changes to Asset Retirement Obligation	A summary of the changes to our ARO is as follows (in thousands): Balance, December 31, 2014 $ 390,568 Liabilities settled (21,939 ) Accretion of discount 10,930 Disposition of properties (965 ) Liabilities assumed through acquisition 2,944 Liabilities incurred 4,671 Revisions of estimated liabilities (1) 3,858 Balance, June 30, 2015 390,067 Less current portion 41,494 Long-term $ 348,573 (1) Revisions were primarily attributable to increases from non-operated properties.

Derivative Financial Instrume22

Derivative Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Open Commodity Derivatives	As of June 30, 2015, our open commodity derivative contracts were as follows: Crude Oil: Three-way collars, Priced off WTI (NYMEX) Notional Notional Weighted Average Contract Price Quantity Quantity Put Option Call Option Call Option Termination Period (Bbls/day) (Bbls) (Bought) (Sold) (Bought) 2015: 3rd Quarter 6,000 552,000 $ 50.00 $ 60.00 $ 62.30 4th Quarter 6,000 552,000 50.00 60.00 62.30 1,104,000 50.00 60.00 62.30 Crude Oil: Two-way collars, Priced off WTI (NYMEX) Notional Notional Weighted Average Contract Price Quantity Quantity Put Option Call Option Termination Period (Bbls/day) (Bbls) (Bought) (Sold) 2016: 1st Quarter 5,000 455,000 $ 40.00 $ 81.47 2nd Quarter 5,000 455,000 40.00 81.47 3rd Quarter 5,000 460,000 40.00 81.47 4th Quarter 5,000 460,000 40.00 81.47 1,830,000 40.00 81.47 Natural Gas: Three-way collars, Priced off Henry Hub (NYMEX) ( 1 ) Notional Notional Weighted Average Contract Price Quantity Quantity Put Option Call Option Call Option Termination Period (MMBTUs/day) (MMBTUs) (Bought) (Sold) (Bought) 2015: 3rd Quarter 30,000 1,830,000 $ 2.25 $ 3.25 $ 3.51 4th Quarter 30,000 2,760,000 2.25 3.25 3.51 2016: 1st Quarter 40,000 3,640,000 2.25 3.50 3.77 2nd Quarter 40,000 3,640,000 2.25 3.50 3.77 3rd Quarter 40,000 3,680,000 2.25 3.50 3.77 4th Quarter 40,000 3,680,000 2.25 3.50 3.77 19,230,000 2.25 3.44 3.70 (1) The natural gas derivative contracts are priced and closed in the last week prior to the related production month. Natural gas derivative contracts related to July 2015 production were priced and closed in June 2015 and are not included in the above table as these were not open derivative contracts as of June 30, 2015.
Estimated Fair Value of Derivative Contracts	The following balance sheet line items included amounts related to the estimated fair value of our open commodity derivative contracts as indicated in the following table (in thousands): June 30, December 31, 2015 2014 Accrued liabilities $ 535 $ — Other liabilities (noncurrent) 544 —
Changes in Fair Value of Commodity Derivative Contracts	Changes in the fair value of our commodity derivative contracts were as follows (in thousands): Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Derivative loss $ 1,078 $ 13,079 $ 1,078 $ 20,571
Cash Payments on Derivative Settlements, Net Included within Net Cash Provided by Operating Activities	Cash payments on commodity derivative contract settlements, net, are included within Net cash provided by operating activities Six Months Ended June 30, 2015 2014 Cash payments on derivative settlements, net $ — $ 14,310 Cash payments on commodity derivative contract settlements, net, are included within Net cash provided by operating activities

Long-Term Debt (Tables)

Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2015
Debt Disclosure [Abstract]
Long-Term Debt	Our long-term debt was as follows (in thousands): June 30, December 31, 2015 2014 8.50% Senior Notes due 2019 $ 900,000 $ 900,000 Debt premiums, net of amortization 11,805 13,057 9.00% Term Loan due 2020 300,000 — Debt discounts, net of amortization (2,935 ) — Revolving bank credit facility 260,000 447,000 Total long-term debt 1,468,870 1,360,057 Current maturities of long-term debt — — Long term debt, less current maturities $ 1,468,870 $ 1,360,057

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2015
Fair Value Disclosures [Abstract]
Schedule of Fair Value of Derivatives Financial Instruments and Long-Term Debt	The following table presents the fair value of our derivatives and long-term debt, all of which are reported as liabilities on the Condensed Consolidated Balance Sheets (in thousands): Hierarchy June 30, 2015 December 31, 2014 Derivatives Level 2 $ 1,079 $ — 8.50% Senior Notes due 2019 ( 1 ) Level 2 633,060 594,000 9.00% Term Loan due 2020 ( 1 ) Level 2 296,250 — Revolving bank credit facility ( 1 ) Level 2 260,000 447,000 (1) The long-term debt items are reported on the Condensed Consolidated Balance Sheets at their carrying value as described in Note 5.

Share-Based Compensation and 25

Share-Based Compensation and Cash-Based Incentive Compensation (Tables)	6 Months Ended
	Jun. 30, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Schedule of Restricted Stock Activity	A summary of activity in 2015 related to Restricted Shares awarded to non-employee directors is as follows: Restricted Shares Weighted Average Grant Date Fair Shares Value Per Share Nonvested, December 31, 2014 43,210 $ 16.20 Granted 56,540 6.19 Vested (21,520 ) 16.26 Nonvested, June 30, 2015 78,230 8.95
Schedule of Outstanding Restricted Stock Shares Issued to Non-employee Directors	Subject to the satisfaction of service conditions, the outstanding Restricted Shares issued to the non-employee directors as of June 30, 2015 are expected to vest as follows: Restricted Shares 2016 34,265 2017 25,115 2018 18,850 Total 78,230
Summary of Share Activity Related to Restricted Stock Units	A summary of activity in 2015 related to RSUs is as follows: Restricted Stock Units Weighted Average Grant Date Fair Units Value Per Unit Nonvested, December 31, 2014 1,977,335 $ 15.29 Vested (23,500 ) 14.68 Forfeited (71,890 ) 15.15 Nonvested, June 30, 2015 1,881,945 15.30
Schedule of Restricted Stock Units Outstanding	All of the outstanding RSUs are subject to the satisfaction of service conditions and a portion of the outstanding RSUs are also subject to pre-defined performance measurements. The RSUs outstanding as of June 30, 2015 potentially eligible to vest are listed in the table below: Restricted Stock Units 2015 - subject to service requirements 706,370 2015 - subject to service and other requirements (1) 86,507 2016 - subject to service requirements 1,089,068 Total 1,881,945 (1) In addition to service requirements, these RSUs are also subject to TSR performance requirements not yet measureable, with awards ranging from 0% to 200% of amounts granted.
Summary of Incentive Compensation Expense under Share-Based Payment Arrangements and Related Tax Benefit	A summary of incentive compensation expense under share-based payment arrangements and the related tax benefit is as follows (in thousands): Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Share-based compensation expense from: Restricted stock $ 90 $ 84 $ 183 $ 183 Restricted stock units 2,802 3,625 5,619 6,161 Common shares — 178 (94 ) 1,300 Total $ 2,892 $ 3,887 $ 5,708 $ 7,644 Share-based compensation tax benefit: Tax benefit computed at the statutory rate $ 1,012 $ 1,360 $ 1,998 $ 2,675
Summary of Incentive Compensation Expense	A summary of incentive compensation expense is as follows (in thousands): Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Share-based compensation included in: General and administrative expenses $ 2,892 $ 3,887 $ 5,708 $ 7,644 Cash-based incentive compensation included in: Lease operating expense — 475 364 1,777 General and administrative expenses (1) — 1,532 (233 ) 3,313 Total charged to operating income $ 2,892 $ 5,894 $ 5,839 $ 12,734 (1) Adjustments to true up estimates to actual payments resulted in net credit balances to expense for the six months ended June 30, 2015.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	6 Months Ended
	Jun. 30, 2015
Earnings Per Share [Abstract]
Schedule of Calculation of Basic and Diluted Earnings (loss) Per Common Share	The following table presents the calculation of basic and diluted earnings (loss) per common share (in thousands, except per share amounts): Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Net income (loss) $ (260,449 ) $ 9,837 $ (515,544 ) $ 21,026 Less portion allocated to nonvested shares — 100 — 219 Net income (loss) allocated to common shares $ (260,449 ) $ 9,737 $ (515,544 ) $ 20,807 Weighted average common shares outstanding 75,910 75,605 75,884 75,581 Basic and diluted earnings (loss) per common share $ (3.43 ) $ 0.13 $ (6.79 ) $ 0.28 Shares excluded due to being anti-dilutive (weighted-average) 355 — 277 —

Supplemental Guarantor Inform27

Supplemental Guarantor Information (Tables)	6 Months Ended
	Jun. 30, 2015
Supplemental Guarantor Information [Abstract]
Condensed Consolidating Balance Sheet	The following condensed consolidating financial information presents the financial condition, results of operations and cash flows of the Parent Company and the Guarantor Subsidiaries, together with consolidating adjustments necessary to present the Company’s results on a consolidated basis. Transfers of property were made from the Parent Company to the Guarantor Subsidiaries. As these transfers were transactions between entities under common control, the prior period financial information has been retrospectively adjusted for comparability purposes, as prescribed under authoritative guidance. None of the adjustments had any effect on the consolidated results for the current or prior periods presented. Condensed Consolidating Balance Sheet as of June 30, 2015 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Assets Current assets: Cash and cash equivalents $ 5,671 $ — $ — $ 5,671 Receivables: Oil and natural gas sales 23,109 28,848 — 51,957 Joint interest and other 114,021 — (81,413 ) 32,608 Total receivables 137,130 28,848 (81,413 ) 84,565 Deferred income taxes 56,955 1,865 (52,000 ) 6,820 Prepaid expenses and other assets 22,821 4,469 — 27,290 Total current assets 222,577 35,182 (133,413 ) 124,346 Property and equipment – at cost: Oil and natural gas properties and equipment 6,064,146 2,143,019 — 8,207,165 Furniture, fixtures and other 23,981 — — 23,981 Total property and equipment 6,088,127 2,143,019 — 8,231,146 Less accumulated depreciation, depletion and amortization 4,937,933 1,368,186 — 6,306,119 Net property and equipment 1,150,194 774,833 — 1,925,027 Restricted deposits for asset retirement obligations 15,538 — — 15,538 Other assets 868,316 293,570 (1,141,820 ) 20,066 Total assets $ 2,256,625 $ 1,103,585 $ (1,275,233 ) $ 2,084,977 Liabilities and Shareholders’ Equity Current liabilities: Accounts payable $ 130,386 $ 4,779 $ — $ 135,165 Undistributed oil and natural gas proceeds 28,650 1,043 — 29,693 Asset retirement obligations 34,992 6,502 — 41,494 Accrued liabilities 13,543 80,990 (81,413 ) 13,120 Total current liabilities 207,571 93,314 (81,413 ) 219,472 Long-term debt, less current maturities 1,468,870 — — 1,468,870 Asset retirement obligations, less current portion 216,706 131,867 — 348,573 Deferred income taxes 382 85,908 (52,000 ) 34,290 Other liabilities 363,884 — (349,324 ) 14,560 Shareholders’ equity: Common stock 1 — — 1 Additional paid-in capital 420,028 704,885 (704,885 ) 420,028 Retained earnings (deficit) (396,650 ) 87,611 (87,611 ) (396,650 ) Treasury stock, at cost (24,167 ) — — (24,167 ) Total shareholders’ equity (deficit) (788 ) 792,496 (792,496 ) (788 ) Total liabilities and shareholders’ equity $ 2,256,625 $ 1,103,585 $ (1,275,233 ) $ 2,084,977 Condensed Consolidating Balance Sheet as of December 31, 2014 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Assets Current assets: Cash and cash equivalents $ 23,666 $ — $ — $ 23,666 Receivables: Oil and natural gas sales 41,820 25,422 — 67,242 Joint interest and other 142,885 — (99,240 ) 43,645 Total receivables 184,705 25,422 (99,240 ) 110,887 Deferred income taxes 9,797 1,865 — 11,662 Prepaid expenses and other assets 28,728 7,619 — 36,347 Total current assets 246,896 34,906 (99,240 ) 182,562 Property and equipment – at cost: Oil and natural gas properties and equipment 6,038,915 2,006,751 — 8,045,666 Furniture, fixtures and other 23,269 — — 23,269 Total property and equipment 6,062,184 2,006,751 — 8,068,935 Less accumulated depreciation, depletion and amortization 4,442,899 1,132,179 — 5,575,078 Net property and equipment 1,619,285 874,572 — 2,493,857 Restricted deposits for asset retirement obligations 15,444 — — 15,444 Other assets 974,049 357,992 (1,314,797 ) 17,244 Total assets $ 2,855,674 $ 1,267,470 $ (1,414,037 ) $ 2,709,107 Liabilities and Shareholders’ Equity Current liabilities: Accounts payable $ 188,654 $ 5,455 $ — $ 194,109 Undistributed oil and natural gas proceeds 36,130 879 — 37,009 Asset retirement obligations 30,711 5,292 — 36,003 Accrued liabilities 17,437 99,180 (99,240 ) 17,377 Total current liabilities 272,932 110,806 (99,240 ) 284,498 Long-term debt, less current maturities 1,360,057 — — 1,360,057 Asset retirement obligations, less current portion 235,876 118,689 — 354,565 Deferred income taxes 59,616 127,372 — 186,988 Other liabilities 417,885 — (404,194 ) 13,691 Shareholders’ equity: Common stock 1 — — 1 Additional paid-in capital 414,580 703,440 (703,440 ) 414,580 Retained earnings 118,894 207,163 (207,163 ) 118,894 Treasury stock, at cost (24,167 ) — — (24,167 ) Total shareholders’ equity 509,308 910,603 (910,603 ) 509,308 Total liabilities and shareholders’ equity $ 2,855,674 $ 1,267,470 $ (1,414,037 ) $ 2,709,107
Condensed Consolidating Statement of Income	Condensed Consolidating Statement of Operations for the Three Months Ended June 30, 2015 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Revenues $ 90,465 $ 58,601 $ — $ 149,066 Operating costs and expenses: Lease operating expenses 30,104 15,026 — 45,130 Production taxes 1,000 — — 1,000 Gathering and transportation 2,769 2,024 — 4,793 Depreciation, depletion, amortization and accretion 58,023 45,319 — 103,342 Ceiling test write-down of oil and natural gas properties 181,300 71,472 — 252,772 General and administrative expenses 10,856 8,901 — 19,757 Derivative loss 1,078 — — 1,078 Total costs and expenses 285,130 142,742 — 427,872 Operating loss (194,665 ) (84,141 ) — (278,806 ) Loss of affiliates (54,548 ) — 54,548 — Interest expense: Incurred 25,322 794 — 26,116 Capitalized (1,230 ) (794 ) — (2,024 ) Debt issuance costs write-off and other, net 1,685 — — 1,685 Loss before income tax benefit (274,990 ) (84,141 ) 54,548 (304,583 ) Income tax benefit (14,541 ) (29,593 ) — (44,134 ) Net loss $ (260,449 ) $ (54,548 ) $ 54,548 $ (260,449 ) Condensed Consolidating Statement of Operations for the Six Months Ended June 30, 2015 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Revenues $ 167,808 $ 109,165 $ — $ 276,973 Operating costs and expenses: Lease operating expenses 67,742 30,719 — 98,461 Production taxes 1,637 — — 1,637 Gathering and transportation 5,334 4,283 — 9,617 Depreciation, depletion, amortization and accretion 129,374 99,435 — 228,809 Ceiling test write-down of oil and natural gas properties 371,995 141,167 — 513,162 General and administrative expenses 22,615 17,908 — 40,523 Derivative loss 1,078 — — 1,078 Total costs and expenses 599,775 293,512 — 893,287 Operating loss (431,967 ) (184,347 ) — (616,314 ) Loss of affiliates (119,552 ) — 119,552 — Interest expense: Incurred 47,554 1,508 — 49,062 Capitalized (2,299 ) (1,508 ) — (3,807 ) Debt issuance costs write-off and other, net 1,683 — — 1,683 Loss before income tax benefit (598,457 ) (184,347 ) 119,552 (663,252 ) Income tax benefit (82,913 ) (64,795 ) — (147,708 ) Net loss $ (515,544 ) $ (119,552 ) $ 119,552 $ (515,544 ) Condensed Consolidating Statement of Operations for the Three Months Ended June 30, 2014 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Revenues $ 156,033 $ 106,961 $ — $ 262,994 Operating costs and expenses: Lease operating expenses 40,846 20,919 — 61,765 Production taxes 1,842 — — 1,842 Gathering and transportation 2,232 1,753 — 3,985 Depreciation, depletion, amortization and accretion 68,921 59,315 — 128,236 General and administrative expenses 10,269 9,413 — 19,682 Derivative loss 13,079 — — 13,079 Total costs and expenses 137,189 91,400 — 228,589 Operating income 18,844 15,561 — 34,405 Earnings of affiliates 10,252 — (10,252 ) — Interest expense: Incurred 20,617 837 — 21,454 Capitalized (1,322 ) (837 ) — (2,159 ) Income before income tax expense 9,801 15,561 (10,252 ) 15,110 Income tax expense (benefit) (36 ) 5,309 — 5,273 Net income $ 9,837 $ 10,252 $ (10,252 ) $ 9,837 Condensed Consolidating Statement of Operations for the Six Months Ended June 30, 2014 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Revenues $ 302,156 $ 215,354 $ — $ 517,510 Operating costs and expenses: Lease operating expenses 80,172 37,212 — 117,384 Production taxes 3,834 — — 3,834 Gathering and transportation 5,580 3,701 — 9,281 Depreciation, depletion, amortization and accretion 132,117 119,425 — 251,542 General and administrative expenses 21,850 21,420 — 43,270 Derivative loss 20,571 — — 20,571 Total costs and expenses 264,124 181,758 — 445,882 Operating income 38,032 33,596 — 71,628 Earnings of affiliates 21,940 — (21,940 ) — Interest expense: Incurred 41,294 1,618 — 42,912 Capitalized (2,613 ) (1,618 ) — (4,231 ) Income before income tax expense 21,291 33,596 (21,940 ) 32,947 Income tax expense (benefit) 265 11,656 — 11,921 Net income $ 21,026 $ 21,940 $ (21,940 ) $ 21,026
Condensed Consolidating Statement of Cash Flows	Condensed Consolidating Statement of Cash Flows for the Six Months Ended June 30, 2015 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Operating activities: Net loss $ (515,544 ) $ (119,552 ) $ 119,552 $ (515,544 ) Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Depreciation, depletion, amortization and accretion 129,374 99,435 — 228,809 Ceiling test write-down of oil and gas properties 371,995 141,167 — 513,162 Debt issuance costs write-off/amortization of debt items 2,432 — — 2,432 Share-based compensation 5,708 — — 5,708 Derivative loss 1,078 — — 1,078 Deferred income taxes (105,818 ) (41,890 ) — (147,708 ) Loss of affiliates 119,552 — (119,552 ) — Changes in operating assets and liabilities: Oil and natural gas receivables 18,710 (3,425 ) — 15,285 Joint interest and other receivables 11,036 — — 11,036 Income taxes 22,580 (22,905 ) — (325 ) Prepaid expenses and other assets (8,913 ) 72,712 (54,870 ) 8,929 Asset retirement obligation settlements (21,146 ) (793 ) — (21,939 ) Accounts payable, accrued liabilities and other (125,219 ) (513 ) 54,870 (70,862 ) Net cash provided by (used in) operating activities (94,175 ) 124,236 — 30,061 Investing activities: Investment in oil and natural gas properties and equipment (25,313 ) (125,681 ) — (150,994 ) Investment in subsidiary (1,445 ) — 1,445 — Purchases of furniture, fixtures and other (709 ) — — (709 ) Net cash used in investing activities (27,467 ) (125,681 ) 1,445 (151,703 ) Financing activities: Borrowings of long-term debt – revolving bank credit facility 194,000 — — 194,000 Repayments of long-term debt – revolving bank credit facility (381,000 ) — — (381,000 ) Issuance of 9.00% Term Loan 297,000 — — 297,000 Debt issuance costs (6,407 ) — — (6,407 ) Other 54 — — 54 Investment from parent — 1,445 (1,445 ) — Net cash provided by financing activities 103,647 1,445 (1,445 ) 103,647 Decrease in cash and cash equivalents (17,995 ) — — (17,995 ) Cash and cash equivalents, beginning of period 23,666 — — 23,666 Cash and cash equivalents, end of period $ 5,671 $ — $ — $ 5,671 Condensed Consolidating Statement of Cash Flows for the Six Months Ended June 30, 2014 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Operating activities: Net income $ 21,026 $ 21,940 $ (21,940 ) $ 21,026 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion, amortization and accretion 132,117 119,425 — 251,542 Amortization of debt issuance costs and premium 366 — — 366 Share-based compensation 7,644 — — 7,644 Derivative loss 20,571 — — 20,571 Cash payments on derivative settlements (14,310 ) — — (14,310 ) Deferred income taxes 25,078 (13,157 ) — 11,921 Earnings of affiliates (21,940 ) — 21,940 — Changes in operating assets and liabilities: Oil and natural gas receivables 7,636 (5,301 ) — 2,335 Joint interest and other receivables 3,550 — — 3,550 Income taxes (21,896 ) 24,814 — 2,918 Prepaid expenses and other assets (123,770 ) (91,015 ) 219,224 4,439 Asset retirement obligations (18,583 ) (11,755 ) — (30,338 ) Accounts payable, accrued liabilities and other 203,344 5,266 (219,224 ) (10,614 ) Net cash provided by operating activities 220,833 50,217 — 271,050 Investing activities: Acquisition of property interest in oil and natural gas properties — (53,363 ) — (53,363 ) Investment in oil and natural gas properties and equipment (157,128 ) (55,552 ) — (212,680 ) Investment in subsidiary (58,698 ) — 58,698 — Purchases of furniture, fixtures and other (1,715 ) — — (1,715 ) Net cash used in investing activities (217,541 ) (108,915 ) 58,698 (267,758 ) Financing activities: Borrowings of long-term debt – revolving bank credit facility 220,000 — — 220,000 Repayments of long-term debt – revolving bank credit facility (200,000 ) — — (200,000 ) Dividends to shareholders (15,129 ) — — (15,129 ) Other (116 ) — — (116 ) Investment from parent — 58,698 (58,698 ) — Net cash used in financing activities 4,755 58,698 (58,698 ) 4,755 Increase in cash and cash equivalents 8,047 — — 8,047 Cash and cash equivalents, beginning of period 15,800 — — 15,800 Cash and cash equivalents, end of period $ 23,847 $ — $ — $ 23,847

Basis of Presentation - Additio

Basis of Presentation - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Basis Of Presentation [Line Items]
Percentage of discount from proved reserves			10.00%
Ceiling test write-down of oil and natural gas properties	$ 252,772	$ 0	$ 513,162	$ 0	$ 0
Revolving bank credit facility borrowing base	500,000		500,000
Second Lien Term Loan
Basis Of Presentation [Line Items]
Term loan	$ 300,000		$ 300,000
Debt instrument maturity date			May 15, 2020
Debt instrument interest rate	9.00%		9.00%
Revolving bank credit facility borrowing base	$ 500,000		$ 500,000

Acquisitions and Divestitures -

Acquisitions and Divestitures - Additional Information (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Sep. 15, 2014	Sep. 14, 2014	May. 20, 2014
Business Acquisition [Line Items]
Revenues	$ 149,066,000	$ 262,994,000	$ 276,973,000	$ 517,510,000
DD&A	103,342,000	128,236,000	228,809,000	251,542,000
Income tax expense	(44,134,000)	5,273,000	(147,708,000)	11,921,000
Net income (loss)	(260,449,000)	$ 9,837,000	(515,544,000)	$ 21,026,000
Fairway
Business Acquisition [Line Items]
Percentage of working interest					100.00%	64.30%
Adjustments to purchase price			1,300,000
Goodwill, acquired during period			0
Woodside Properties
Business Acquisition [Line Items]
Percentage of working interest							20.00%
Adjustments to purchase price			200,000
Goodwill, acquired during period			0
Revenues	7,900,000		13,400,000
Direct operating expenses	1,800,000		5,100,000
DD&A	3,900,000		8,000,000
Income tax expense	800,000		100,000
Net income (loss)	$ 1,400,000		$ 200,000

Acquisitions and Divestitures30

Acquisitions and Divestitures - Purchase Price Allocation for Acquisition (Details) - USD ($) $ in Thousands	Sep. 15, 2014	May. 20, 2014
Fairway
Non-cash consideration:
Asset retirement obligations - non-current	$ 6,124
Total consideration	24,817
Fairway | Evaluated Properties Including Equipment
Cash consideration:
Oil and natural gas properties and equipment	$ 18,693
Woodside Properties
Cash consideration:
Oil and natural gas properties and equipment		$ 54,989
Non-cash consideration:
Asset retirement obligations - non-current		10,543
Asset retirement obligations - current		782
Non-cash consideration		11,325
Total consideration		66,314
Woodside Properties | Evaluated Properties Including Equipment
Cash consideration:
Oil and natural gas properties and equipment		52,329
Woodside Properties | Unevaluated Properties
Cash consideration:
Oil and natural gas properties and equipment		$ 2,660

Acquisitions and Divestitures31

Acquisitions and Divestitures - Summary of Proforma Financial Information for Acquisition (Details) - Jun. 30, 2014 - Woodside Properties - USD ($) $ / shares in Units, $ in Thousands	Total	Total
Business Acquisition [Line Items]
Revenue	$ 272,022	$ 540,397
Net income	$ 12,150	$ 27,120
Basic and diluted earnings per common share	$ 0.16	$ 0.35

Acquisitions and Divestitures32

Acquisitions and Divestitures - Business Acquisition Pro Forma Information Incremental Items (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Business Acquisition [Line Items]
Revenues		$ 149,066	$ 262,994	$ 276,973	$ 517,510
DD&A		103,342	128,236	228,809	251,542
G&A		19,757	19,682	40,523	43,270
Interest expense		26,116	21,454	49,062	42,912
Capitalized		(2,024)	(2,159)	(3,807)	(4,231)
Income tax expense		(44,134)	5,273	(147,708)	11,921
Woodside Properties
Business Acquisition [Line Items]
Revenues		7,900		13,400
Direct operating expenses		1,800		5,100
DD&A		3,900		8,000
Income tax expense		$ 800		$ 100
Woodside Properties | Pro Forma
Business Acquisition [Line Items]
Revenues	[1],[2]		9,028		22,887
Direct operating expenses	[1],[2]		1,805		4,417
DD&A	[2],[3]		3,387		8,384
G&A	[2],[4]		200		400
Interest expense	[2],[5]		82		330
Capitalized	[2],[6]		(5)		(19)
Income tax expense	[2],[7]		$ 1,246		$ 3,281
[1]	Revenues and direct operating expenses for the Woodside Properties were derived from the historical financial records of Woodside.
[2]	The adjustments for the periods presented are from the beginning of the period to May 20, 2014.
[3]	DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Woodside Properties’ costs, reserves and production into our full cost pool in order to compute such amounts. The purchase price allocated to unevaluated properties for oil and natural gas interests was excluded from the DD&A expense estimation. ARO was estimated by W&T management.
[4]	Consists of estimated incremental insurance costs related to the Woodside Properties.
[5]	The Woodside Properties acquisition was assumed to be funded entirely with borrowed funds. Interest expense was computed using assumed borrowings of $55.0 million, which equates to the cash component of the acquisition purchase price, and an interest rate of 1.8%, which equates to the rates applied to incremental borrowings on the revolving bank credit facility.
[6]	The change to capitalized interest was computed for the addition to the pool of unevaluated properties and the capitalization interest rate was adjusted for the assumed borrowings. The negative amount represents a decrease to net expenses.
[7]	Income tax expense was computed using the 35% federal statutory rate.

Acquisitions and Divestitures33

Acquisitions and Divestitures - Business Acquisition Pro Forma Information Incremental Items (Parenthetical) (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Business Acquisition [Line Items]
Long-term debt, less current maturities		$ 1,468,870		$ 1,360,057
Federal statutory income tax rate		35.00%
Woodside Properties
Business Acquisition [Line Items]
Long-term debt, less current maturities	$ 55,000		$ 55,000
Effective interest rate	1.80%		1.80%
Federal statutory income tax rate	35.00%		35.00%

Asset Retirement Obligations -

Asset Retirement Obligations - Summary of Changes to Asset Retirement Obligation (Details) - USD ($) $ in Thousands		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations, beginning of period		$ 390,568
Asset retirement obligation settlements		(21,939)	$ (30,338)
Accretion of discount		10,930
Disposition of properties		(965)
Liabilities assumed through acquisition		2,944
Liabilities incurred		4,671
Revisions of estimated liabilities	[1]	3,858
Asset retirement obligations, end of period		390,067
Less current portion		41,494		$ 36,003
Long-term		$ 348,573		$ 354,565
[1]	Revisions were primarily attributable to increases from non-operated properties.

Derivative Financial Instrume35

Derivative Financial Instruments - Additional Information (Details)	Dec. 31, 2014DerivativeInstrument
Derivative Instruments And Hedging Activities Disclosure [Abstract]
No. of open derivative instruments	0

Derivative Financial Instrume36

Derivative Financial Instruments - Open Commodity Derivatives (Details) - Jun. 30, 2015		MMBTU$ / Derivativebbl
NYMEX Crude Oil - Three-Way Collars
Derivatives Fair Value [Line Items]
Notional Quantity (Bbls) | bbl		1,104,000
NYMEX Crude Oil - Three-Way Collars | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price		50
NYMEX Crude Oil - Three-Way Collars | Call Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price		62.30
NYMEX Crude Oil - Three-Way Collars | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price		60
NYMEX Crude Oil - Three-Way Collars | 2015: 3rd Quarter
Derivatives Fair Value [Line Items]
Termination Period		3rd Quarter
Notional Quantity (Bbls/day) | bbl		6,000
Notional Quantity (Bbls) | bbl		552,000
NYMEX Crude Oil - Three-Way Collars | 2015: 3rd Quarter | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price		50
NYMEX Crude Oil - Three-Way Collars | 2015: 3rd Quarter | Call Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price		62.30
NYMEX Crude Oil - Three-Way Collars | 2015: 3rd Quarter | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price		60
NYMEX Crude Oil - Three-Way Collars | 2015: 4th Quarter
Derivatives Fair Value [Line Items]
Termination Period		4th Quarter
Notional Quantity (Bbls/day) | bbl		6,000
Notional Quantity (Bbls) | bbl		552,000
NYMEX Crude Oil - Three-Way Collars | 2015: 4th Quarter | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price		50
NYMEX Crude Oil - Three-Way Collars | 2015: 4th Quarter | Call Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price		62.30
NYMEX Crude Oil - Three-Way Collars | 2015: 4th Quarter | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price		60
NYMEX Crude Oil - Two-Way Collars
Derivatives Fair Value [Line Items]
Notional Quantity (Bbls) | bbl		1,830,000
NYMEX Crude Oil - Two-Way Collars | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price		40
NYMEX Crude Oil - Two-Way Collars | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price		81.47
NYMEX Crude Oil - Two-Way Collars | 2016: 1st Quarter
Derivatives Fair Value [Line Items]
Termination Period		1st Quarter
Notional Quantity (Bbls/day) | bbl		5,000
Notional Quantity (Bbls) | bbl		455,000
NYMEX Crude Oil - Two-Way Collars | 2016: 1st Quarter | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price		40
NYMEX Crude Oil - Two-Way Collars | 2016: 1st Quarter | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price		81.47
NYMEX Crude Oil - Two-Way Collars | 2016: 2nd Quarter
Derivatives Fair Value [Line Items]
Termination Period		2nd Quarter
Notional Quantity (Bbls/day) | bbl		5,000
Notional Quantity (Bbls) | bbl		455,000
NYMEX Crude Oil - Two-Way Collars | 2016: 2nd Quarter | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price		40
NYMEX Crude Oil - Two-Way Collars | 2016: 2nd Quarter | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price		81.47
NYMEX Crude Oil - Two-Way Collars | 2016: 3rd Quarter
Derivatives Fair Value [Line Items]
Termination Period		3rd Quarter
Notional Quantity (Bbls/day) | bbl		5,000
Notional Quantity (Bbls) | bbl		460,000
NYMEX Crude Oil - Two-Way Collars | 2016: 3rd Quarter | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price		40
NYMEX Crude Oil - Two-Way Collars | 2016: 3rd Quarter | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price		81.47
NYMEX Crude Oil - Two-Way Collars | 2016: 4th Quarter
Derivatives Fair Value [Line Items]
Termination Period		4th Quarter
Notional Quantity (Bbls/day) | bbl		5,000
Notional Quantity (Bbls) | bbl		460,000
NYMEX Crude Oil - Two-Way Collars | 2016: 4th Quarter | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price		40
NYMEX Crude Oil - Two-Way Collars | 2016: 4th Quarter | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price		81.47
NYMEX Natural Gas - Three-Way Collars
Derivatives Fair Value [Line Items]
Notional Quantity (MMBTUs) | MMBTU	[1]	19,230,000
NYMEX Natural Gas - Three-Way Collars | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	[1]	2.25
NYMEX Natural Gas - Three-Way Collars | Call Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	[1]	3.70
NYMEX Natural Gas - Three-Way Collars | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	[1]	3.44
NYMEX Natural Gas - Three-Way Collars | 2015: 3rd Quarter
Derivatives Fair Value [Line Items]
Termination Period	[1]	3rd Quarter
Notional Quantity (MMBTUs/day) | MMBTU	[1]	30,000
Notional Quantity (MMBTUs) | MMBTU	[1]	1,830,000
NYMEX Natural Gas - Three-Way Collars | 2015: 3rd Quarter | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	[1]	2.25
NYMEX Natural Gas - Three-Way Collars | 2015: 3rd Quarter | Call Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	[1]	3.51
NYMEX Natural Gas - Three-Way Collars | 2015: 3rd Quarter | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	[1]	3.25
NYMEX Natural Gas - Three-Way Collars | 2015: 4th Quarter
Derivatives Fair Value [Line Items]
Termination Period	[1]	4th Quarter
Notional Quantity (MMBTUs/day) | MMBTU	[1]	30,000
Notional Quantity (MMBTUs) | MMBTU	[1]	2,760,000
NYMEX Natural Gas - Three-Way Collars | 2015: 4th Quarter | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	[1]	2.25
NYMEX Natural Gas - Three-Way Collars | 2015: 4th Quarter | Call Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	[1]	3.51
NYMEX Natural Gas - Three-Way Collars | 2015: 4th Quarter | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	[1]	3.25
NYMEX Natural Gas - Three-Way Collars | 2016: 1st Quarter
Derivatives Fair Value [Line Items]
Termination Period	[1]	1st Quarter
Notional Quantity (MMBTUs/day) | MMBTU	[1]	40,000
Notional Quantity (MMBTUs) | MMBTU	[1]	3,640,000
NYMEX Natural Gas - Three-Way Collars | 2016: 1st Quarter | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	[1]	2.25
NYMEX Natural Gas - Three-Way Collars | 2016: 1st Quarter | Call Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	[1]	3.77
NYMEX Natural Gas - Three-Way Collars | 2016: 1st Quarter | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	[1]	3.50
NYMEX Natural Gas - Three-Way Collars | 2016: 2nd Quarter
Derivatives Fair Value [Line Items]
Termination Period	[1]	2nd Quarter
Notional Quantity (MMBTUs/day) | MMBTU	[1]	40,000
Notional Quantity (MMBTUs) | MMBTU	[1]	3,640,000
NYMEX Natural Gas - Three-Way Collars | 2016: 2nd Quarter | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	[1]	2.25
NYMEX Natural Gas - Three-Way Collars | 2016: 2nd Quarter | Call Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	[1]	3.77
NYMEX Natural Gas - Three-Way Collars | 2016: 2nd Quarter | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	[1]	3.50
NYMEX Natural Gas - Three-Way Collars | 2016: 3rd Quarter
Derivatives Fair Value [Line Items]
Termination Period	[1]	3rd Quarter
Notional Quantity (MMBTUs/day) | MMBTU	[1]	40,000
Notional Quantity (MMBTUs) | MMBTU	[1]	3,680,000
NYMEX Natural Gas - Three-Way Collars | 2016: 3rd Quarter | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	[1]	2.25
NYMEX Natural Gas - Three-Way Collars | 2016: 3rd Quarter | Call Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	[1]	3.77
NYMEX Natural Gas - Three-Way Collars | 2016: 3rd Quarter | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	[1]	3.50
NYMEX Natural Gas - Three-Way Collars | 2016: 4th Quarter
Derivatives Fair Value [Line Items]
Termination Period	[1]	4th Quarter
Notional Quantity (MMBTUs/day) | MMBTU	[1]	40,000
Notional Quantity (MMBTUs) | MMBTU	[1]	3,680,000
NYMEX Natural Gas - Three-Way Collars | 2016: 4th Quarter | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	[1]	2.25
NYMEX Natural Gas - Three-Way Collars | 2016: 4th Quarter | Call Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	[1]	3.77
NYMEX Natural Gas - Three-Way Collars | 2016: 4th Quarter | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	[1]	3.50
[1]	The natural gas derivative contracts are priced and closed in the last week prior to the related production month. Natural gas derivative contracts related to July 2015 production were priced and closed in June 2015 and are not included in the above table as these were not open derivative contracts as of June 30, 2015.

Derivative Financial Instrume37

Derivative Financial Instruments - Estimated Fair Value of Derivative Contracts (Details) $ in Thousands	Jun. 30, 2015USD ($)
Accrued Liabilities
Derivatives Fair Value [Line Items]
Fair value of commodity derivative contracts	$ 535
Other Liabilities (Noncurrent)
Derivatives Fair Value [Line Items]
Fair value of commodity derivative contracts	$ 544

Derivative Financial Instrume38

Derivative Financial Instruments - Changes in Fair Value of Commodity Derivative Contracts (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Gain Loss On Derivative Instruments Net Pretax [Abstract]
Derivative loss	$ 1,078	$ 13,079	$ 1,078	$ 20,571

Derivative Financial Instrume39

Derivative Financial Instruments - Cash Payments on Derivative Settlements, Net Included within Net Cash Provided by Operating Activities (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2014USD ($)
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Cash payments on derivative settlements, net	$ 14,310

Long-Term Debt - Long-Term Debt

Long-Term Debt - Long-Term Debt (Details) - USD ($) $ in Thousands	Jun. 30, 2015	May. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Revolving bank credit facility	$ 260,000		$ 447,000
Total long-term debt	1,468,870		1,360,057
Long-term debt, less current maturities	1,468,870		1,360,057
8.50% Senior Notes due June 2019
Debt Instrument [Line Items]
8.50% Senior Notes due 2019	900,000		900,000
Debt premiums, net of amortization	11,805		$ 13,057
9.00% Term Loan due 2020
Debt Instrument [Line Items]
9.00% Term Loan due 2020	300,000	$ 300,000
Debt discounts, net of amortization	$ (2,935)

Long-Term Debt - Long-Term De41

Long-Term Debt - Long-Term Debt (Parenthetical) (Details)	Jun. 30, 2015	May. 31, 2015	Dec. 31, 2014
8.50% Senior Notes due June 2019
Debt Instrument [Line Items]
Debt instrument interest rate	8.50%		8.50%
9.00% Term Loan due 2020
Debt Instrument [Line Items]
Debt instrument interest rate	9.00%	9.00%

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Details) - USD ($)	1 Months Ended	3 Months Ended	6 Months Ended
	May. 31, 2015	Jun. 30, 2015	Jun. 30, 2015	Jun. 30, 2014	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014
Debt Instrument [Line Items]
Borrowings under Credit Agreement margin increase		0.50%
Reduction of base rate		0.33
Revolving bank credit facility borrowing base		$ 500,000,000	$ 500,000,000
Mortgaged collateral requirement		90.00%	90.00%		80.00%
Percentage of oil and natural gas production for the second half of 2015		25.00%
Percentage of oil and natural gas production to be hedged for 2016		35.00%
Debt issuance costs write-off/amortization of debt items			$ 2,432,000	$ 366,000
Minimum | First Quarter of 2015
Debt Instrument [Line Items]
Current ratio		75.00%
Minimum | Second Quarter of 2015
Debt Instrument [Line Items]
Current ratio		75.00%
Minimum | Third Quarter of 2015
Debt Instrument [Line Items]
Current ratio		75.00%
Minimum | Fourth Quarter of 2015
Debt Instrument [Line Items]
Current ratio		75.00%
Minimum | Fourth Quarter of 2015 and Thereafter
Debt Instrument [Line Items]
Current ratio		100.00%
Minimum | First Quarter of 2015 and Thereafter
Debt Instrument [Line Items]
Interest coverage ratio		220.00%
Maximum | Second Quarter of 2016
Debt Instrument [Line Items]
Leverage ratio		500.00%
Maximum | Third Quarter of 2016
Debt Instrument [Line Items]
Leverage ratio		450.00%
Maximum | Fourth Quarter of 2016 and Thereafter
Debt Instrument [Line Items]
Leverage ratio		400.00%
Maximum | First Quarter of 2015 and Thereafter
Debt Instrument [Line Items]
First lien leverage ratio		250.00%
Secured debt leverage ratio		350.00%
8.50% Senior Notes due June 2019
Debt Instrument [Line Items]
Debt instrument interest rate		8.50%	8.50%			8.50%
Debt instrument payment terms			semi-annually in arrears on June 15 and December 15
Effective interest rate		8.40%	8.40%				8.40%
Debt instrument maturity date			Jun. 15, 2019
9.00% Term Loan due 2020
Debt Instrument [Line Items]
Debt instrument interest rate	9.00%	9.00%	9.00%
Debt instrument payment terms			Interest on the 9.00% Term Loan is payable in arrears semi-annually on May 15 and November 15
Effective interest rate	9.70%
Term loan	$ 300,000,000	$ 300,000,000	$ 300,000,000
Debt instruments, discount rate	1.00%
9.00% Term Loan due 2020 | Chief Executive Officer
Debt Instrument [Line Items]
Debt instrument, principal commitment amount	$ 5,000,000
Revolving Bank Credit Facility Due November 2018
Debt Instrument [Line Items]
Effective interest rate		3.20%	3.20%
Credit agreement expiration date			Nov. 8, 2018
Letters of credit outstanding		$ 600,000	$ 600,000			$ 600,000
Revolving bank credit facility maximum lender commitment		500,000,000	500,000,000
Line of credit, borrowing availability		$ 239,400,000	$ 239,400,000
Credit facility interest rate description			Borrowings under the Credit Agreement was increased by 50 basis points (0.5%) on an annual basis. The London Interbank Offered Rate (“LIBOR”) based borrowings margins range from 2.25% to 3.25% and alternate base rate borrowings margins range from 1.25% to 2.25%.
Line of credit facility description			We are restricted on making distributions or repurchasing the existing 8.50% Senior Notes, the 9.00% Term Loan or other permitted indebtedness (i) until June 30, 2016, (ii) if an event of default is continuing or would result from such distribution or (iii) if a borrowing base deficiency is continuing or would result therefrom; provided that the restriction in clause (i) of this sentence does not apply to (A) scheduled payments of interest, principal or redemptions on the Company’s existing 8.50% Senior Notes, the 9.00% Term Loan or other permitted additional debt and (B) the redemption or repurchase by the Company of its outstanding indebtedness in an aggregate principal amount equal to the aggregate principal amount of any new indebtedness, provided that any such new notes are not subject to covenants and events of default that are, taken as a whole, materially more restrictive on the Company.
Debt issuance costs write-off/amortization of debt items			$ 2,000,000
Revolving Bank Credit Facility Due November 2018 | Minimum | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate		2.25%
Revolving Bank Credit Facility Due November 2018 | Minimum | Alternate Base Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate		1.25%
Revolving Bank Credit Facility Due November 2018 | Maximum | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate		3.25%
Revolving Bank Credit Facility Due November 2018 | Maximum | Alternate Base Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate		2.25%

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Details)	Jun. 30, 2015	May. 31, 2015	Dec. 31, 2014
8.50% Senior Notes due June 2019
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Debt instrument interest rate	8.50%		8.50%
9.00% Term Loan due 2020
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Debt instrument interest rate	9.00%	9.00%

Fair Value Measurements - Sched

Fair Value Measurements - Schedule of Fair Value of Derivatives Financial Instruments and Long-Term Senior Notes (Details) - Fair Value, Inputs, Level 2 - USD ($) $ in Thousands		Jun. 30, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivatives		$ 1,079
Revolving bank credit facility	[1]	260,000	$ 447,000
8.50% Senior Notes due June 2019
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair value of derivatives and long-term debt	[1]	633,060	$ 594,000
9.00% Term Loan due 2020
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair value of derivatives and long-term debt	[1]	$ 296,250
[1]	The long-term debt items are reported on the Condensed Consolidated Balance Sheets at their carrying value as described in Note 5.

Fair Value Measurements - Sch45

Fair Value Measurements - Schedule of Fair Value of Derivatives Financial Instruments and Long-Term Debt (Parenthetical) (Details)	Jun. 30, 2015	May. 31, 2015	Dec. 31, 2014
8.50% Senior Notes due June 2019
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Debt instrument interest rate	8.50%		8.50%
9.00% Term Loan due 2020
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Debt instrument interest rate	9.00%	9.00%

Share-Based Compensation and 46

Share-Based Compensation and Cash-Based Incentive Compensation - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended		6 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common stock available for award under plans			4,735,483
Directors Compensation Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common stock available for award under plans			444,024
Restricted Stock Units (RSUs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of shares granted			0
Performance based awards, percentage					100.00%	100.00%
Shares granted, grant date fair value				$ 19.9
Shares vested, vested date fair value			$ 0.1	0.1
Expected volatility, minimum						30.00%
Expected volatility, maximum						63.00%
Unrecognized share-based compensation expense			$ 10.9
Recognition period for unrecognized compensation expense			2016-11
Restricted Stock Units (RSUs) | London Interbank Offered Rate (LIBOR)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Risk-free interest rate, minimum						0.27%
Risk-free interest rate, maximum						0.91%
Restricted Stock Units (RSUs) | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected dividend yield						0.00%
Correlation of movement of total shareholder return						(84.00%)
Restricted Stock Units (RSUs) | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected dividend yield						3.10%
Correlation of movement of total shareholder return						95.00%
CEO's 2014 Award | Chief Executive Officer
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common stock, price per share	$ 14.66
Number of shares issued	37,316
Performance based awards, percentage	100.00%
CEO's 2013 Award | Chief Executive Officer
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common stock, price per share		$ 14.84
Number of shares issued		42,547
Performance based awards, percentage		100.00%
Restricted Shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of shares granted			56,540
Shares granted, grant date fair value			$ 0.3	0.3
Shares vested, vested date fair value			0.1	$ 0.3
Unrecognized share-based compensation expense			$ 0.6
Recognition period for unrecognized compensation expense			2018-04

Share-Based Compensation and 47

Share-Based Compensation and Cash-Based Incentive Compensation - Schedule of Restricted Stock Activity (Details) - 6 months ended Jun. 30, 2015 - Restricted Shares - $ / shares	Total
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Nonvested, beginning of period	43,210
Granted	56,540
Vested	(21,520)
Nonvested, end of period	78,230
Weighted Average Grant Date Value, Beginning of period	$ 16.20
Weighted Average Grant Date Fair Value, Granted	6.19
Weighted Average Grant Date Fair Value, Vested	16.26
Weighted Average Grant Date Value, End of period	$ 8.95

Share-Based Compensation and 48

Share-Based Compensation and Cash-Based Incentive Compensation - Outstanding Restricted Shares Issued to Non-employee Directors (Details) - Restricted Shares - shares	Jun. 30, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	78,230	43,210
2,016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	34,265
2,017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	25,115
2,018
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	18,850

Share-Based Compensation and 49

Share-Based Compensation and Cash-Based Incentive Compensation - Summary of Share Activity Related to Restricted Stock Units (Details) - 6 months ended Jun. 30, 2015 - Restricted Stock Units (RSUs) - $ / shares	Total
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Nonvested, beginning of period	1,977,335
Vested	(23,500)
Forfeited	(71,890)
Nonvested, end of period	1,881,945
Weighted Average Grant Date Value, Beginning of period	$ 15.29
Weighted Average Grant Date Fair Value, Vested	14.68
Weighted Average Grant Date Fair Value, Forfeited	15.15
Weighted Average Grant Date Value, End of period	$ 15.30

Share-Based Compensation and 50

Share-Based Compensation and Cash-Based Incentive Compensation - Schedule of Restricted Stock Units Outstanding (Details) - Restricted Stock Units (RSUs) - shares		Jun. 30, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period		1,881,945	1,977,335
2015 | Restricted Stock Units subject to service requirements
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period		706,370
2015 | Restricted Stock Units subject to service and other requirements
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	[1]	86,507
2016 | Restricted Stock Units subject to service requirements
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period		1,089,068
[1]	In addition to service requirements, these RSUs are also subject to TSR performance requirements not yet measureable, with awards ranging from 0% to 200% of amounts granted.

Share-Based Compensation and 51

Share-Based Compensation and Cash-Based Incentive Compensation - Schedule of Restricted Stock Units Outstanding (Parenthetical) (Details) - Restricted Stock Units (RSUs) - 2015 - Restricted Stock Units subject to service and other requirements	6 Months Ended
	Jun. 30, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Restricted stock units adjustments, minimum percentage	0.00%
Restricted stock units adjustments, maximum percentage	200.00%

Share-Based Compensation and 52

Share-Based Compensation and Cash-Based Incentive Compensation - Summary of Incentive Compensation Expense under Share-Based Payment Arrangements and Related Tax Benefit (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation	$ 2,892	$ 3,887	$ 5,708	$ 7,644
Tax benefit computed at the statutory rate	1,012	1,360	1,998	2,675
Restricted Shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation	90	84	183	183
Restricted Stock Units (RSUs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation	$ 2,802	3,625	5,619	6,161
Common Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation		$ 178	$ (94)	$ 1,300

Share-Based Compensation and 53

Share-Based Compensation and Cash-Based Incentive Compensation - Summary of Incentive Compensation Expense (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Share-based compensation charged to operating income		$ 2,892	$ 3,887	$ 5,708	$ 7,644
Total charged to operating income		2,892	5,894	5,839	12,734
General And Administrative Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Share-based compensation charged to operating income		$ 2,892	3,887	5,708	7,644
Cash-based incentive compensation charged to operating income	[1]		1,532	(233)	3,313
Lease Operating Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Cash-based incentive compensation charged to operating income			$ 475	$ 364	$ 1,777
[1]	Adjustments to true up estimates to actual payments resulted in net credit balances to expense for the six months ended June 30, 2015.

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Income tax expense (benefit)	$ (44,134)	$ 5,273	$ (147,708)	$ 11,921
Ceiling test write-down	$ 252,772	$ 0	$ 513,162	$ 0	$ 0
Effective tax rate	14.50%	34.90%	22.30%	36.20%
Federal statutory income tax rate			35.00%
Valuation allowance	$ 62,900		$ 85,400
Louisiana
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Valuation allowance related to net operating losses	$ 4,300		$ 4,300		$ 4,300
Minimum
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Tax years under examination			2,010
Maximum
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Tax years under examination			2,014

Earnings Per Share - Schedule o

Earnings Per Share - Schedule of Calculation of Basic and Diluted Earnings (loss) Per Common Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Earnings Per Share, Basic and Diluted [Abstract]
Net income (loss)	$ (260,449)	$ 9,837	$ (515,544)	$ 21,026
Less portion allocated to nonvested shares		100		219
Net income (loss) allocated to common shares	$ (260,449)	$ 9,737	$ (515,544)	$ 20,807
Weighted average common shares outstanding	75,910	75,605	75,884	75,581
Basic and diluted earnings (loss) per common share	$ (3.43)	$ 0.13	$ (6.79)	$ 0.28
Shares excluded due to being anti-dilutive (weighted-average)	355		277

Dividends - Additional Informat

Dividends - Additional Information (Details) - $ / shares	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Equity [Abstract]
Paid cash dividends, per share	$ 0	$ 0.10

Contingencies - Additional Info

Contingencies - Additional Information (Details)	1 Months Ended	3 Months Ended	6 Months Ended
	Jan. 31, 2014USD ($)	Mar. 31, 2014USD ($)	Jun. 30, 2015USD ($)claim	Dec. 15, 2014USD ($)	Dec. 31, 2010USD ($)
Loss Contingencies [Line Items]
Underpayment of royalties	$ 30,000
Under payment percentage of total royalty payments	0.0045%
Statutory fine payment relative to underpayment		$ 2,300,000
Loss contingency, range of possible loss, minimum				$ 0
Loss contingency, range of possible loss, maximum				$ 32,000,000
Insurance claims submitted for removal-of-wreck expenses			$ 42,000,000
Notified disallowed amount in reductions taken by ONRR					$ 4,700,000
BSEE
Loss Contingencies [Line Items]
Number of notices received form BSEE | claim			2
Proposed civil penalties related to various incidents of noncompliance, total			$ 3,600,000
Civil penalties related liability			0
Liberty Mutual Insurance Co
Loss Contingencies [Line Items]
Insurance claims received			5,000,000
Revised estimate
Loss Contingencies [Line Items]
Insurance claims receivable			30,000,000
Comprehensive General Liability policy
Loss Contingencies [Line Items]
Insurance claims received			1,000,000
Energy Package
Loss Contingencies [Line Items]
Insurance claims received			1,000,000
Starr Marine
Loss Contingencies [Line Items]
Insurance claims received			$ 5,000,000

Supplemental Guarantor Inform58

Supplemental Guarantor Information - Additional Information (Details)	Jun. 30, 2015	May. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Percentage of subsidiaries owned	100.00%
8.50% Senior Notes due June 2019
Debt Instrument [Line Items]
Debt instrument interest rate	8.50%		8.50%
9.00% Term Loan due 2020
Debt Instrument [Line Items]
Debt instrument interest rate	9.00%	9.00%

Supplemental Guarantor Inform59

Supplemental Guarantor Information - Condensed Consolidating Balance Sheet (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 5,671	$ 23,666	$ 23,847	$ 15,800
Receivables:
Oil and natural gas sales	51,957	67,242
Joint interest and other	32,608	43,645
Total receivables	84,565	110,887
Deferred income taxes	6,820	11,662
Prepaid expenses and other assets	27,290	36,347
Total current assets	124,346	182,562
Property and equipment - at cost:
Oil and natural gas properties and equipment	8,207,165	8,045,666
Furniture, fixtures and other	23,981	23,269
Total property and equipment	8,231,146	8,068,935
Less accumulated depreciation, depletion and amortization	6,306,119	5,575,078
Net property and equipment	1,925,027	2,493,857
Restricted deposits for asset retirement obligations	15,538	15,444
Other assets	20,066	17,244
Total assets	2,084,977	2,709,107
Current liabilities:
Accounts payable	135,165	194,109
Undistributed oil and natural gas proceeds	29,693	37,009
Asset retirement obligations	41,494	36,003
Accrued liabilities	13,120	17,377
Total current liabilities	219,472	284,498
Long-term debt, less current maturities	1,468,870	1,360,057
Asset retirement obligations, less current portion	348,573	354,565
Deferred income taxes	34,290	186,988
Other liabilities	14,560	13,691
Shareholders’ equity:
Common stock	1	1
Additional paid-in capital	420,028	414,580
Retained earnings (deficit)	(396,650)	118,894
Treasury stock, at cost	(24,167)	(24,167)
Total shareholders’ equity (deficit)	(788)	509,308
Total liabilities and shareholders’ equity	2,084,977	2,709,107
Parent Company
Current assets:
Cash and cash equivalents	5,671	23,666	$ 23,847	$ 15,800
Receivables:
Oil and natural gas sales	23,109	41,820
Joint interest and other	114,021	142,885
Total receivables	137,130	184,705
Deferred income taxes	56,955	9,797
Prepaid expenses and other assets	22,821	28,728
Total current assets	222,577	246,896
Property and equipment - at cost:
Oil and natural gas properties and equipment	6,064,146	6,038,915
Furniture, fixtures and other	23,981	23,269
Total property and equipment	6,088,127	6,062,184
Less accumulated depreciation, depletion and amortization	4,937,933	4,442,899
Net property and equipment	1,150,194	1,619,285
Restricted deposits for asset retirement obligations	15,538	15,444
Other assets	868,316	974,049
Total assets	2,256,625	2,855,674
Current liabilities:
Accounts payable	130,386	188,654
Undistributed oil and natural gas proceeds	28,650	36,130
Asset retirement obligations	34,992	30,711
Accrued liabilities	13,543	17,437
Total current liabilities	207,571	272,932
Long-term debt, less current maturities	1,468,870	1,360,057
Asset retirement obligations, less current portion	216,706	235,876
Deferred income taxes	382	59,616
Other liabilities	363,884	417,885
Shareholders’ equity:
Common stock	1	1
Additional paid-in capital	420,028	414,580
Retained earnings (deficit)	(396,650)	118,894
Treasury stock, at cost	(24,167)	(24,167)
Total shareholders’ equity (deficit)	(788)	509,308
Total liabilities and shareholders’ equity	2,256,625	2,855,674
Guarantor Subsidiaries
Receivables:
Oil and natural gas sales	28,848	25,422
Total receivables	28,848	25,422
Deferred income taxes	1,865	1,865
Prepaid expenses and other assets	4,469	7,619
Total current assets	35,182	34,906
Property and equipment - at cost:
Oil and natural gas properties and equipment	2,143,019	2,006,751
Total property and equipment	2,143,019	2,006,751
Less accumulated depreciation, depletion and amortization	1,368,186	1,132,179
Net property and equipment	774,833	874,572
Other assets	293,570	357,992
Total assets	1,103,585	1,267,470
Current liabilities:
Accounts payable	4,779	5,455
Undistributed oil and natural gas proceeds	1,043	879
Asset retirement obligations	6,502	5,292
Accrued liabilities	80,990	99,180
Total current liabilities	93,314	110,806
Asset retirement obligations, less current portion	131,867	118,689
Deferred income taxes	85,908	127,372
Shareholders’ equity:
Additional paid-in capital	704,885	703,440
Retained earnings (deficit)	87,611	207,163
Total shareholders’ equity (deficit)	792,496	910,603
Total liabilities and shareholders’ equity	1,103,585	1,267,470
Eliminations
Receivables:
Joint interest and other	(81,413)	(99,240)
Total receivables	(81,413)	(99,240)
Deferred income taxes	(52,000)
Total current assets	(133,413)	(99,240)
Property and equipment - at cost:
Other assets	(1,141,820)	(1,314,797)
Total assets	(1,275,233)	(1,414,037)
Current liabilities:
Accrued liabilities	(81,413)	(99,240)
Total current liabilities	(81,413)	(99,240)
Deferred income taxes	(52,000)
Other liabilities	(349,324)	(404,194)
Shareholders’ equity:
Additional paid-in capital	(704,885)	(703,440)
Retained earnings (deficit)	(87,611)	(207,163)
Total shareholders’ equity (deficit)	(792,496)	(910,603)
Total liabilities and shareholders’ equity	$ (1,275,233)	$ (1,414,037)

Supplemental Guarantor Inform60

Supplemental Guarantor Information - Condensed Consolidating Statement of Operations (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Condensed Income Statements Captions [Line Items]
Revenues	$ 149,066	$ 262,994	$ 276,973	$ 517,510
Operating costs and expenses:
Lease operating expenses	45,130	61,765	98,461	117,384
Production taxes	1,000	1,842	1,637	3,834
Gathering and transportation	4,793	3,985	9,617	9,281
Depreciation, depletion, amortization and accretion	103,342	128,236	228,809	251,542
Ceiling test write-down of oil and natural gas properties	252,772	0	513,162	0	$ 0
General and administrative expenses	19,757	19,682	40,523	43,270
Derivative loss	1,078	13,079	1,078	20,571
Total costs and expenses	427,872	228,589	893,287	445,882
Operating income (loss)	(278,806)	34,405	(616,314)	71,628
Interest expense:
Incurred	26,116	21,454	49,062	42,912
Capitalized	(2,024)	(2,159)	(3,807)	(4,231)
Debt issuance costs write-off and other, net	1,685	0	1,683	0
Income (loss) before income tax expense (benefit)	(304,583)	15,110	(663,252)	32,947
Income tax expense (benefit)	(44,134)	5,273	(147,708)	11,921
Net income (loss)	(260,449)	9,837	(515,544)	21,026
Parent Company
Condensed Income Statements Captions [Line Items]
Revenues	90,465	156,033	167,808	302,156
Operating costs and expenses:
Lease operating expenses	30,104	40,846	67,742	80,172
Production taxes	1,000	1,842	1,637	3,834
Gathering and transportation	2,769	2,232	5,334	5,580
Depreciation, depletion, amortization and accretion	58,023	68,921	129,374	132,117
Ceiling test write-down of oil and natural gas properties	181,300		371,995
General and administrative expenses	10,856	10,269	22,615	21,850
Derivative loss	1,078	13,079	1,078	20,571
Total costs and expenses	285,130	137,189	599,775	264,124
Operating income (loss)	(194,665)	18,844	(431,967)	38,032
Earnings (loss) of affiliates	(54,548)	10,252	(119,552)	21,940
Interest expense:
Incurred	25,322	20,617	47,554	41,294
Capitalized	(1,230)	(1,322)	(2,299)	(2,613)
Debt issuance costs write-off and other, net	1,685		1,683
Income (loss) before income tax expense (benefit)	(274,990)	9,801	(598,457)	21,291
Income tax expense (benefit)	(14,541)	(36)	(82,913)	265
Net income (loss)	(260,449)	9,837	(515,544)	21,026
Guarantor Subsidiaries
Condensed Income Statements Captions [Line Items]
Revenues	58,601	106,961	109,165	215,354
Operating costs and expenses:
Lease operating expenses	15,026	20,919	30,719	37,212
Gathering and transportation	2,024	1,753	4,283	3,701
Depreciation, depletion, amortization and accretion	45,319	59,315	99,435	119,425
Ceiling test write-down of oil and natural gas properties	71,472		141,167
General and administrative expenses	8,901	9,413	17,908	21,420
Total costs and expenses	142,742	91,400	293,512	181,758
Operating income (loss)	(84,141)	15,561	(184,347)	33,596
Interest expense:
Incurred	794	837	1,508	1,618
Capitalized	(794)	(837)	(1,508)	(1,618)
Income (loss) before income tax expense (benefit)	(84,141)	15,561	(184,347)	33,596
Income tax expense (benefit)	(29,593)	5,309	(64,795)	11,656
Net income (loss)	(54,548)	10,252	(119,552)	21,940
Eliminations
Operating costs and expenses:
Earnings (loss) of affiliates	54,548	(10,252)	119,552	(21,940)
Interest expense:
Income (loss) before income tax expense (benefit)	54,548	(10,252)	119,552	(21,940)
Net income (loss)	$ 54,548	$ (10,252)	$ 119,552	$ (21,940)

Supplemental Guarantor Inform61

Supplemental Guarantor Information - Condensed Consolidating Statement of Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Operating activities:
Net income (loss)	$ (260,449)	$ 9,837	$ (515,544)	$ 21,026
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	103,342	128,236	228,809	251,542
Ceiling test write-down of oil and natural gas properties	252,772	0	513,162	0	$ 0
Debt issuance costs write-off/amortization of debt items			2,432	366
Share-based compensation	2,892	3,887	5,708	7,644
Derivative loss	1,078	13,079	1,078	20,571
Cash payments on derivative settlements				(14,310)
Deferred income taxes			(147,708)	11,921
Changes in operating assets and liabilities:
Oil and natural gas receivables			15,285	2,335
Joint interest and other receivables			11,036	3,550
Income taxes			(325)	2,918
Prepaid expenses and other assets			8,929	4,439
Asset retirement obligation settlements			(21,939)	(30,338)
Accounts payable, accrued liabilities and other			(70,862)	(10,614)
Net cash provided by operating activities			30,061	271,050
Investing activities:
Acquisition of property interest in oil and natural gas properties				(53,363)
Investment in oil and natural gas properties and equipment			(150,994)	(212,680)
Purchases of furniture, fixtures and other			(709)	(1,715)
Net cash used in investing activities			(151,703)	(267,758)
Financing activities:
Borrowings of long-term debt - revolving bank credit facility			194,000	220,000
Repayments of long-term debt - revolving bank credit facility			(381,000)	(200,000)
Dividends to shareholders				(15,129)
Issuance of 9.00% Term Loan			297,000
Debt issuance costs			(6,407)
Other			54	(116)
Net cash provided by financing activities			103,647	4,755
Increase (decrease) in cash and cash equivalents			(17,995)	8,047
Cash and cash equivalents, beginning of period			23,666	15,800	15,800
Cash and cash equivalents, end of period	5,671	23,847	5,671	23,847	23,666
Parent Company
Operating activities:
Net income (loss)	(260,449)	9,837	(515,544)	21,026
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	58,023	68,921	129,374	132,117
Ceiling test write-down of oil and natural gas properties	181,300		371,995
Debt issuance costs write-off/amortization of debt items			2,432	366
Share-based compensation			5,708	7,644
Derivative loss	1,078	13,079	1,078	20,571
Cash payments on derivative settlements				(14,310)
Deferred income taxes			(105,818)	25,078
Earnings (loss) of affiliates	54,548	(10,252)	119,552	(21,940)
Changes in operating assets and liabilities:
Oil and natural gas receivables			18,710	7,636
Joint interest and other receivables			11,036	3,550
Income taxes			22,580	(21,896)
Prepaid expenses and other assets			(8,913)	(123,770)
Asset retirement obligation settlements			(21,146)	(18,583)
Accounts payable, accrued liabilities and other			(125,219)	203,344
Net cash provided by operating activities			(94,175)	220,833
Investing activities:
Investment in oil and natural gas properties and equipment			(25,313)	(157,128)
Investment in subsidiary			(1,445)	(58,698)
Purchases of furniture, fixtures and other			(709)	(1,715)
Net cash used in investing activities			(27,467)	(217,541)
Financing activities:
Borrowings of long-term debt - revolving bank credit facility			194,000	220,000
Repayments of long-term debt - revolving bank credit facility			(381,000)	(200,000)
Dividends to shareholders				(15,129)
Issuance of 9.00% Term Loan			297,000
Debt issuance costs			(6,407)
Other			54	(116)
Net cash provided by financing activities			103,647	4,755
Increase (decrease) in cash and cash equivalents			(17,995)	8,047
Cash and cash equivalents, beginning of period			23,666	15,800	15,800
Cash and cash equivalents, end of period	5,671	23,847	5,671	23,847	$ 23,666
Guarantor Subsidiaries
Operating activities:
Net income (loss)	(54,548)	10,252	(119,552)	21,940
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	45,319	59,315	99,435	119,425
Ceiling test write-down of oil and natural gas properties	71,472		141,167
Deferred income taxes			(41,890)	(13,157)
Changes in operating assets and liabilities:
Oil and natural gas receivables			(3,425)	(5,301)
Income taxes			(22,905)	24,814
Prepaid expenses and other assets			72,712	(91,015)
Asset retirement obligation settlements			(793)	(11,755)
Accounts payable, accrued liabilities and other			(513)	5,266
Net cash provided by operating activities			124,236	50,217
Investing activities:
Acquisition of property interest in oil and natural gas properties				(53,363)
Investment in oil and natural gas properties and equipment			(125,681)	(55,552)
Net cash used in investing activities			(125,681)	(108,915)
Financing activities:
Investment from parent			1,445	58,698
Net cash provided by financing activities			1,445	58,698
Eliminations
Operating activities:
Net income (loss)	54,548	(10,252)	119,552	(21,940)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Earnings (loss) of affiliates	$ (54,548)	$ 10,252	(119,552)	21,940
Changes in operating assets and liabilities:
Prepaid expenses and other assets			(54,870)	219,224
Accounts payable, accrued liabilities and other			54,870	(219,224)
Investing activities:
Investment in subsidiary			1,445	58,698
Net cash used in investing activities			1,445	58,698
Financing activities:
Investment from parent			(1,445)	(58,698)
Net cash provided by financing activities			$ (1,445)	$ (58,698)

Supplemental Guarantor Inform62

Supplemental Guarantor Information - Condensed Consolidating Statement of Cash Flows (Parenthetical) (Details)	Jun. 30, 2015	May. 31, 2015
9.00% Term Loan due 2020
Condensed Cash Flow Statements Captions [Line Items]
Debt instrument interest rate	9.00%	9.00%