W&T Offshore (WTI) 10-Q 6 Nov 15 2015 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Nov. 02, 2015
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q3
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	Sep. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 7,463	$ 23,666
Receivables:
Oil and natural gas sales	43,955	67,242
Joint interest and other	42,435	43,645
Total receivables	86,390	110,887
Deferred income taxes	4,328	11,662
Prepaid expenses and other assets	25,513	36,347
Total current assets	123,694	182,562
Property and equipment - at cost:
Oil and natural gas properties and equipment (full cost method, of which $111,677 at September 30, 2015 and $109,824 at December 31, 2014 were excluded from amortization)	8,257,118	8,045,666
Furniture, fixtures and other	21,372	23,269
Total property and equipment	8,278,490	8,068,935
Less accumulated depreciation, depletion and amortization	6,838,075	5,575,078
Net property and equipment	1,440,415	2,493,857
Restricted deposits for asset retirement obligations	15,578	15,444
Other assets	20,284	17,244
Total assets	1,599,971	2,709,107
Current liabilities:
Accounts payable	107,469	194,109
Undistributed oil and natural gas proceeds	28,870	37,009
Asset retirement obligations	84,588	36,003
Accrued liabilities	39,171	17,377
Total current liabilities	260,098	284,498
Long-term debt, less current maturities	1,473,348	1,360,057
Asset retirement obligations, less current portion	315,038	354,565
Deferred income taxes	13,173	186,988
Other liabilities	$ 14,065	$ 13,691
Commitments and contingencies
Shareholders’ equity:
Preferred stock, $0.00001 par value; 20,000,000 shares authorized; 0 issued at September 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 September 30, 2015; 78,768,588 issued and 75,899,415 outstanding at December 31, 2014	$ 1	$ 1
Additional paid-in capital	422,633	414,580
Retained earnings (deficit)	(874,218)	118,894
Treasury stock, at cost	(24,167)	(24,167)
Total shareholders’ equity (deficit)	(475,751)	509,308
Total liabilities and shareholders’ equity	$ 1,599,971	$ 2,709,107

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Statement Of Financial Position [Abstract]
Oil and natural gas properties and equipment - full cost method, amount excluded from amortization	$ 111,677	$ 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		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Income Statement [Abstract]
Revenues	$ 126,228	$ 234,521	$ 403,201	$ 752,031
Operating costs and expenses:
Lease operating expenses	45,039	71,732	143,500	189,116
Production taxes	889	1,794	2,526	5,628
Gathering and transportation	3,572	4,115	13,189	13,396
Depreciation, depletion, amortization and accretion	97,329	128,671	326,138	380,213
Ceiling test write-down of oil and natural gas properties	441,688	0	954,850	0
General and administrative expenses	16,515	21,007	57,038	64,277
Derivative (gain) loss	(10,231)	(13,781)	(9,153)	6,790
Total costs and expenses	594,801	213,538	1,488,088	659,420
Operating income (loss)	(468,573)	20,983	(1,084,887)	92,611
Interest expense:
Incurred	28,754	21,783	77,816	64,703
Capitalized	(2,203)	(2,191)	(6,010)	(6,422)
Other (income) expense, net	964	(197)	2,647	(205)
Income (loss) before income tax expense (benefit)	(496,088)	1,588	(1,159,340)	34,535
Income tax expense (benefit)	(18,520)	904	(166,228)	12,825
Net income (loss)	$ (477,568)	$ 684	$ (993,112)	$ 21,710
Basic and diluted earnings (loss) per common share	$ (6.29)	$ 0.01	$ (13.08)	$ 0.28
Dividends declared per common share	$ 0	$ 0.10	$ 0	$ 0.30

Condensed Consolidated Stateme5

Condensed Consolidated Statement of Changes In Shareholders' Equity - 9 months ended Sep. 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	$ 8,313		8,313
Other	(260)		(260)
Other, shares		112,000
Net loss	(993,112)			(993,112)
Ending Balances at Sep. 30, 2015	$ (475,751)	$ 1	$ 422,633	$ (874,218)	$ (24,167)
Ending Balances (in shares) at Sep. 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		9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Operating activities:
Net income (loss)	$ (477,568)	$ 684	$ (993,112)	$ 21,710
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	97,329	128,671	326,138	380,213
Ceiling test write-down of oil and natural gas properties	441,688	0	954,850	0	$ 0
Debt issuance costs write-off/amortization of debt items			2,862	537
Share-based compensation	2,605	3,754	8,313	11,398
Derivative (gain) loss	(10,231)	(13,781)	(9,153)	6,790
Cash receipts (payments) on derivative settlements			2,139	(18,543)
Deferred income taxes			(166,258)	12,825
Changes in operating assets and liabilities:
Oil and natural gas receivables			23,287	(936)
Joint interest and other receivables			1,210	1,890
Income taxes			(289)	2,884
Prepaid expenses and other assets			16,692	21,228
Asset retirement obligation settlements			(25,515)	(42,011)
Accounts payable, accrued liabilities and other			(6,371)	21,793
Net cash provided by operating activities			134,793	419,778
Investing activities:
Acquisition of property interest in oil and natural gas properties				(71,515)
Investment in oil and natural gas properties and equipment			(192,811)	(383,953)
Changes in operating assets and liabilities associated with investing activities			(65,463)	5,167
Purchases of furniture, fixtures and other			(1,185)	(2,181)
Net cash used in investing activities			(259,459)	(452,482)
Financing activities:
Borrowings of long-term debt - revolving bank credit facility			263,000	378,000
Repayments of long-term debt - revolving bank credit facility			(445,000)	(321,000)
Issuance of 9.00% Term Loan			297,000
Debt issuance costs			(6,591)
Dividends to shareholders				(22,695)
Other			54	(181)
Net cash provided by financing activities			108,463	34,124
Increase (decrease) in cash and cash equivalents			(16,203)	1,420
Cash and cash equivalents, beginning of period			23,666	15,800	15,800
Cash and cash equivalents, end of period	$ 7,463	$ 17,220	$ 7,463	$ 17,220	$ 23,666

Basis of Presentation

Basis of Presentation	9 Months Ended
	Sep. 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. On October 15, 2015, a substantial amount of our interest in onshore acreage was sold, which is described in Note 12. 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 nine months ended September 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. Reclassifications. Certain reclassifications were made to the prior period’s financial statements to conform to the current presentation. In the Condensed Consolidated Statements of Cash flows, Net cash provided by operating activities was increased by $5.2 million and Net cash used in investing activities was increased by $5.2 million for the nine months ended September 30, 2014 to account for the changes in operating liabilities associated with investing activities. 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 for each product, 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, we recorded ceiling test write-downs in 2015 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 nine months ended September 30, 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; (iv) implementing numerous cost reduction projects to reduce our operating costs and (v) on October 15, 2015, sold our interest in the Yellow Rose field. See Note 12 for additional information. During 2015, we have entered into three Amendments to our Fifth Amended and Restated Credit Agreement (as amended, the “Credit Agreement”), which, among other things, changed or eliminated certain financial covenants and authorized the administrative agent under the Credit Agreement to enter into an Intercreditor Agreement among the Company and various lenders. We entered into a second lien term loan (the We have assessed our financial condition, the current capital markets and options given different scenarios of future commodity prices and believe we will have adequate liquidity to fund our operations through September 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 is to 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	9 Months Ended
	Sep. 30, 2015
Business Combinations [Abstract]
Acquisitions and Divestitures	2. Acquisitions and Divestitures 2015 Divestiture See Note 12 for information on a divestiture occurring subsequent to September 30, 2015. 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 $ 52,347 Unevaluated properties 2,660 Sub-total cash consideration 55,007 Non-cash consideration: Asset retirement obligations - current 782 Asset retirement obligations - non-current 10,543 Sub-total non-cash consideration 11,325 Total consideration $ 66,332 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 nine month periods ended September 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 nine month periods ended September 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 September 30, 2015, the Woodside Properties accounted for $5.8 million of revenues, $2.4 million of direct operating expenses, $3.4 million of depreciation, depletion, amortization and accretion (“DD&A”) and no income tax expense, resulting in less than $0.1 million of net income. For the nine months ended September 30, 2015, the Woodside Properties accounted for $19.2 million of revenues, $7.5 million of direct operating expenses, $11.4 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) Nine Months Ended September 30, 2014 Revenue $ 774,918 Net income 27,803 Basic and diluted earnings per common share 0.36 For the pro forma financial information, certain information was derived from our financial records, Woodside’s financial records and certain information was estimated. Pro forma financial information for the three month period ended September 30, 2014 is not presented as there were no material differences from reported results. The following table presents incremental items included in the pro forma information reported above for the Woodside Properties (in thousands): (unaudited) Nine Months Ended September 30, 2014 (a) Revenues (b) $ 22,887 Direct operating expenses (b) 4,417 DD&A (c) 8,385 G&A (d) 400 Interest expense (e) 330 Capitalized interest (f) (19 ) Income tax expense (g) 3,281 The sources of information and significant assumptions are described below: (a) The adjustments for the period 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. As the acquisition occurred in the second quarter of 2014, pro forma financial information for the three months ended September 30, 2014 is not presented as there would be no differences from reported results.

Asset Retirement Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 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 (25,515 ) Accretion of discount 15,883 Disposition of properties (965 ) Liabilities incurred 7,615 Revisions of estimated liabilities (1) 12,040 Balance, September 30, 2015 399,626 Less current portion 84,588 Long-term $ 315,038 (1) Revisions were primarily attributable to increases in scope of work, additional time to complete the work and from non-operated properties.

Derivative Financial Instrument

Derivative Financial Instruments	9 Months Ended
	Sep. 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 2015, we entered into crude oil 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 WTI crude oil prices as quoted off the New York Mercantile Exchange (“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 September 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) (1) (Bbls) (1) (Bought) (Sold) (Bought) 2015: 4th Quarter 6,000 552,000 $ 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) (1) (Bbls) (1) (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) (1) (MMBTUs) (1) (Bought) (Sold) (Bought) 2015: 4th Quarter (2) 30,000 1,830,000 $ 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 16,470,000 2.25 3.47 3.74 (1) Volume Measurements: Bbls – barrelsMMBTUs – million British Thermal Units (2) 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 October 2015 production were priced and closed in September 2015 and are not included in the above table as these were not open derivative contracts as of September 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): September 30, December 31, 2015 2014 Prepaid and other assets (current) $ 5,970 $ — Other assets (noncurrent) 1,044 — Changes in the fair value and settlements of our commodity derivative contracts were as follows (in thousands): Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 Derivative (gain) loss $ (10,231 ) $ (13,781 ) $ (9,153 ) $ 6,790 Cash receipts (payments), net, on commodity derivative contract settlements are included within Net cash provided by operating activities Nine Months Ended September 30, 2015 2014 Cash receipts (payments) on derivative settlements, net $ 2,139 $ (18,543) Offsetting Commodity Derivatives During 2015, all our commodity derivative contracts permit netting of derivative gains and losses upon settlement. In general, the terms of the contracts provide for offsetting of amounts payable or receivable between us and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same commodity. If an event of default were to occur causing an acceleration of payment under our revolving bank credit facility, that event may also trigger an acceleration of settlement of our derivative instruments. If we were required to settle all of our open derivative contracts, we would be able to net payments and receipts per counterparty pursuant to the derivative contracts. Although our derivative contracts allow for netting, which would allow for recording assets and liabilities per counterparty on a net basis, we have historically accounted for our derivative contracts on a gross basis per contract as either an asset or liability. For the open derivative contracts as of September 30, 2015, there would have been no difference if the contracts were presented on net basis. There were no open derivative contracts as of December 31, 2014.

Long-Term Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2015
Debt Disclosure [Abstract]
Long-Term Debt	5. Long-Term Debt Our long-term debt was as follows (in thousands): September 30, December 31, 2015 2014 8.50% Senior Notes $ 900,000 $ 900,000 Debt premiums, net of amortization 11,161 13,057 9.00% Term Loan 300,000 — Debt discounts, net of amortization (2,813 ) — Revolving bank credit facility 265,000 447,000 Total long-term debt 1,473,348 1,360,057 Current maturities of long-term debt — — Long term debt, less current maturities $ 1,473,348 $ 1,360,057 At September 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 September 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. 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 September 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 September 30, 2015 and December 31, 2014, we had $0.9 million of letters of credit outstanding under the revolving bank credit facility. The estimated annual effective interest rate was 3.3% for the nine months ended September 30, 2015 for average daily 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 September 30, 2015, our borrowing base was $500.0 million and our borrowing availability was $234.1 million. See Note 12 for the results of the semi-annual redetermination and an amendment to the Credit Agreement subsequent to September 30, 2015. Through September 30, 2015, we have 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 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 O ther (income) and expense, 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 September 30, 2015. See Note 12 for information on the third amendment and changes to the borrowing base subsequent to September 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	9 Months Ended
	Sep. 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, credit risk 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, as reported in the Condensed Consolidated Balance Sheets (in thousands): September 30, 2015 December 31, 2014 Hierarchy Assets Liabilities Liabilities Derivatives Level 2 $ 7,014 $ — $ — 8.50% Senior Notes (1) Level 2 — 400,500 594,000 9.00% Term Loan (1) Level 2 — 259,500 — Revolving bank credit facility (1) Level 2 — 265,000 447,000 (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	9 Months Ended
	Sep. 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 nine months ended September 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 September 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 September 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, September 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 September 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 nine months ended September 30, 2015 and the nine months ended September 30, 2014 was $0.3 million for both periods. The fair values of Restricted Shares that vested during the nine months ended September 30, 2015 and the nine months ended September 30, 2014 were $0.1 million and $0.3 million, respectively. Awards Based on Restricted Stock Units. As of September 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 remain 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 (114,900 ) 15.18 Nonvested, September 30, 2015 1,838,935 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 September 30, 2015 potentially eligible to vest are listed in the table below: Restricted Stock Units 2015 - subject to service requirements 689,075 2015 - subject to service and other requirements (1) 84,855 2016 - subject to service requirements 1,065,005 Total 1,838,935 (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 nine months ended September 30, 2014 was $20.0 million. The fair value of RSUs that vested during the nine months ended September 30, 2015 and the nine months ended September 30, 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 Nine Months Ended September 30, September 30, 2015 2014 2015 2014 Share-based compensation expense from: Restricted stock $ 87 $ 93 $ 270 $ 276 Restricted stock units 2,518 3,658 8,137 9,819 Common shares — 3 (94 ) 1,303 Total $ 2,605 $ 3,754 $ 8,313 $ 11,398 Share-based compensation tax benefit: Tax benefit computed at the statutory rate $ 912 $ 1,314 $ 2,910 $ 3,989 Unrecognized Share-Based Compensation. As of September 30, 2015, unrecognized share-based compensation expense related to our awards of Restricted Shares and RSUs was $0.6 million and $8.1 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 nine months ended September 30, 2015, the Company issued cash-based incentive awards for 2015 that, in addition to being performance-based awards related to 2015 criteria, the payment of such awards is contingent on the Company achieving the following financial condition on or before December 31, 2017: Adjusted EBITDA less Interest Expense, as reported by the Company in its announced Earnings Release with respect to the end of any fiscal quarter plus three preceding quarters, exceeds $300.0 million. As the Company does not expect to achieve this financial condition by December 31, 2015, no amount was recognized related to the 2015 awards during the nine months ended September 30, 2015. Amounts recorded during the nine months ended September 30, 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 Nine Months Ended September 30, September 30, 2015 2014 2015 2014 Share-based compensation included in: General and administrative expenses $ 2,605 $ 3,754 $ 8,313 $ 11,398 Cash-based incentive compensation included in: Lease operating expense — 586 364 2,363 General and administrative expenses (1) — 2,724 (233 ) 6,038 Total charged to operating income $ 2,605 $ 7,064 $ 8,444 $ 19,799 (1) Adjustments to true up estimates to actual payments resulted in net credit balances to expense for the nine months ended September 30, 2015.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2015
Income Tax Disclosure [Abstract]
Income Taxes	8. Income Taxes Our income tax benefit for the three and nine months ended September 30, 2015 was $18.5 million and $166.2 million, respectively. Our effective tax rate for the three and nine months ended September 30, 2015 was 3.7% and 14.3%, 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 nine months ended September 30, 2014 was $0.9 million and $12.8 million, respectively. Our effective tax rate for the three months ended September 30, 2014 was not meaningful due to adjustments for a revised estimated effective rate computed on a year-to-date basis. Our effective tax rate for the nine months ended September 30, 2014 was 37.1%, and differed from the federal statutory rate primarily as a result of state income taxes and other permanent items. During the three and nine months ended September 30, 2015, we recorded a valuation allowance of $156.2 million and $241.6 million, respectively, related to federal and state deferred tax assets. 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 nine months ended September 30, 2015 and 2014, we recorded immaterial amounts of accrued interest expense related to our unrecognized tax benefit.

Earnings Per Share

Earnings Per Share	9 Months Ended
	Sep. 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 Nine Months Ended September 30, September 30, 2015 2014 2015 2014 Net income (loss) $ (477,568 ) $ 684 $ (993,112 ) $ 21,710 Less portion allocated to nonvested shares — 70 — 208 Net income (loss) allocated to common shares $ (477,568 ) $ 614 $ (993,112 ) $ 21,502 Weighted average common shares outstanding 75,932 75,613 75,900 75,592 Basic and diluted earnings (loss) per common share $ (6.29 ) $ 0.01 $ (13.08 ) $ 0.28 Shares excluded due to being anti-dilutive (weighted-average) 431 — 308 —

Dividends

Dividends	9 Months Ended
	Sep. 30, 2015
Equity [Abstract]
Dividends	10. Dividends During the nine months ended September 30, 2015, we did not declare or pay any dividends. During the nine months ended September 30, 2014, we paid regular cash dividends per common share of $0.10 each quarter. No dividends were paid during the nine months ended September 30, 2015 and dividends have been suspended.

Contingencies

Contingencies	9 Months Ended
	Sep. 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 improper and 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 2014 notice. We are currently engaged in discovery with the ONRR. 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 September 30, 2015 or December 31, 2014 per authoritative guidance. 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 nine months ended September 30, 2015, the Company received four final notices from the Bureau of Safety and Environmental Enforcement (the “BSEE”) of civil penalties related to Incidents of Noncompliance (“INCs”) at various offshore locations. An aggregate $0.2 million has been paid in respect of three of the four final notices. The Company also received three proposed notices from BSEE related to INCs at various offshore locations. The occurrence dates range from June 2012 to June 2014. For the unpaid proposed penalties, the Company has accrued approximately $1.0 million, which is the Company’s best estimate of the final settlement once all appeals have been exhausted. The proposed amounts by the BSEE for the unpaid proposed penalties totaled $8.1 million. The Company’s position is that the proposed civil penalties are excessive given the specific facts and circumstances related to the INCs. 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 nine months ended September 30, 2015 and 2014. As of September 30, 2015 and December 31, 2014, we had no material amounts recorded in liabilities for claims, complaints and fines.

Subsequent Events

Subsequent Events	9 Months Ended
	Sep. 30, 2015
Subsequent Events [Abstract]
Subsequent Events	12. Subsequent Events On October 15, 2015, we sold certain oil and natural gas property interests to Ajax Resources, LLC (“Ajax”) for approximately $376.1 million in cash and the assumption of certain ARO, subject to certain customary purchase price adjustments. The effective date of the sale was January 1, 2015. Ajax acquired all of our interest in the Yellow Rose field in the Permian Basin, covering approximately 25,800 net acres in Andrews, Martin, Gaines and Dawson counties in West Texas. We were also assigned a non-expense bearing overriding royalty interest (“ORRI”) in production from the working interests assigned to Ajax, which percentage varies on a sliding scale from one percent for each month that the prompt month NYMEX trading price for light sweet crude oil is at or below $70.00 per barrel to a maximum of four percent for each month that such NYMEX trading price is greater than $90.00 per barrel. We used a portion of the proceeds of the sale to repay all outstanding borrowings under the revolving bank credit facility, while the remaining balance of approximately $100.0 million was added to available cash. Under the full cost method, sales or abandonments of oil and natural gas properties, whether or not being amortized, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to the cost center. The sale to Ajax did not represent greater than 25% of the Company’s proved reserves of oil and natural gas attributable to the full cost pool. As a result, alteration in the relationship between capitalized costs and proved reserves of oil and natural gas attributable to the full cost pool was not deemed significant and no gain or loss will be recognized from the sale. On October 30, 2015, the Company entered into the third Amendment to the Credit Agreement, which amended the Credit Agreement as follows: · Eliminated the maximum Leverage Ratio. · Eliminated the minimum Interest Coverage Ratio. · Revised the First Lien Leverage Ratio from 2.50:1.00 to 1.50:1.00 effective for the third quarter of 2015. · Maintained the minimum Current Ratio requirement of 0.75:1.00 through the fourth quarter of 2015 and maintained increasing the ratio to 1.00:1.00 in the first quarter of 2016. · Maintained the maximum Secured Debt Leverage Ratio requirement at 3.50:1.00. · Permitted uncapped bond and term loan repurchases subject to: o the revolver loan balance outstanding being $0, after giving effect to such repurchases; o having a minimum borrowing base of $200 million; o having a maximum outstanding letters of credit balance of $100 million; o having no Event of Default having occurred or being continuing; and o having no Borrowing Base Deficiency occurred, being continuing or resulting therefrom. The foregoing description of the amendment to the Credit Agreement does not purport to be complete and is qualified in its entirety by reference to the agreement. Capitalized terms used but not defined above have the meanings given to them in the Credit Agreement. After the fall of 2015 redetermination, the borrowing base was set at $350.0 million effective on October 30, 2015. As such, a proportional amount of the unamortized debt issuance costs will be expensed in the fourth quarter of 2015.

Supplemental Guarantor Informat

Supplemental Guarantor Information	9 Months Ended
	Sep. 30, 2015
Supplemental Guarantor Information [Abstract]
Supplemental Guarantor Information	W&T OFFSHORE, INC. AND SUBSIDIARIES 13. Supplemental Guarantor Information Our payment obligations under the 8.50% Senior Notes, the 9.00% Term Loan and the Credit Agreement (see Note 5 and 12) 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 September 30, 2015 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Assets Current assets: Cash and cash equivalents $ 7,463 $ — $ — $ 7,463 Receivables: Oil and natural gas sales 15,798 28,157 — 43,955 Joint interest and other 116,178 — (73,743 ) 42,435 Total receivables 131,976 28,157 (73,743 ) 86,390 Deferred income taxes 6,848 1,864 (4,384 ) 4,328 Prepaid expenses and other assets 24,693 820 — 25,513 Total current assets 170,980 30,841 (78,127 ) 123,694 Property and equipment – at cost: Oil and natural gas properties and equipment 6,071,263 2,185,855 — 8,257,118 Furniture, fixtures and other 21,372 — — 21,372 Total property and equipment 6,092,635 2,185,855 — 8,278,490 Less accumulated depreciation, depletion and amortization 5,229,074 1,609,001 — 6,838,075 Net property and equipment 863,561 576,854 — 1,440,415 Restricted deposits for asset retirement obligations 15,578 — — 15,578 Other assets 744,364 292,411 (1,016,491 ) 20,284 Total assets $ 1,794,483 $ 900,106 $ (1,094,618 ) $ 1,599,971 Liabilities and Shareholders’ Equity Current liabilities: Accounts payable $ 101,848 $ 5,621 $ — $ 107,469 Undistributed oil and natural gas proceeds 27,816 1,054 — 28,870 Asset retirement obligations 64,085 20,503 — 84,588 Accrued liabilities 44,610 68,304 (73,743 ) 39,171 Total current liabilities 238,359 95,482 (73,743 ) 260,098 Long-term debt, less current maturities 1,473,348 — — 1,473,348 Asset retirement obligations, less current portion 191,066 123,972 — 315,038 Deferred income taxes 341 17,216 (4,384 ) 13,173 Other liabilities 367,120 — (353,055 ) 14,065 Shareholders’ equity: Common stock 1 — — 1 Additional paid-in capital 422,633 704,885 (704,885 ) 422,633 Retained earnings (deficit) (874,218 ) (41,449 ) 41,449 (874,218 ) Treasury stock, at cost (24,167 ) — — (24,167 ) Total shareholders’ equity (deficit) (475,751 ) 663,436 (663,436 ) (475,751 ) Total liabilities and shareholders’ equity $ 1,794,483 $ 900,106 $ (1,094,618 ) $ 1,599,971 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 September 30, 2015 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Revenues $ 71,092 $ 55,136 $ — $ 126,228 Operating costs and expenses: Lease operating expenses 29,721 15,318 — 45,039 Production taxes 889 — — 889 Gathering and transportation 1,712 1,860 — 3,572 Depreciation, depletion, amortization and accretion 50,960 46,369 — 97,329 Ceiling test write-down of oil and natural gas properties 244,952 196,736 — 441,688 General and administrative expenses 8,590 7,925 — 16,515 Derivative gain (10,231 ) — — (10,231 ) Total costs and expenses 326,593 268,208 — 594,801 Operating loss (255,501 ) (213,072 ) — (468,573 ) Loss of affiliates (129,061 ) — 129,061 — Interest expense: Incurred 27,911 843 — 28,754 Capitalized (1,360 ) (843 ) — (2,203 ) Other (income) expense, net 964 — — 964 Loss before income tax expense (benefit) (412,077 ) (213,072 ) 129,061 (496,088 ) Income tax expense (benefit) 65,491 (84,011 ) — (18,520 ) Net loss $ (477,568 ) $ (129,061 ) $ 129,061 $ (477,568 ) Condensed Consolidating Statement of Operations for the Nine Months Ended September 30, 2015 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Revenues $ 238,900 $ 164,301 $ — $ 403,201 Operating costs and expenses: Lease operating expenses 97,463 46,037 — 143,500 Production taxes 2,526 — — 2,526 Gathering and transportation 7,046 6,143 — 13,189 Depreciation, depletion, amortization and accretion 180,334 145,804 — 326,138 Ceiling test write-down of oil and natural gas properties 616,947 337,903 — 954,850 General and administrative expenses 31,205 25,833 — 57,038 Derivative gain (9,153 ) — — (9,153 ) Total costs and expenses 926,368 561,720 — 1,488,088 Operating loss (687,468 ) (397,419 ) — (1,084,887 ) Loss of affiliates (248,613 ) — 248,613 — Interest expense: Incurred 75,465 2,351 — 77,816 Capitalized (3,659 ) (2,351 ) — (6,010 ) Other (income) expense, net 2,647 — — 2,647 Loss before income tax benefit (1,010,534 ) (397,419 ) 248,613 (1,159,340 ) Income tax benefit (17,422 ) (148,806 ) — (166,228 ) Net loss $ (993,112 ) $ (248,613 ) $ 248,613 $ (993,112 ) Condensed Consolidating Statement of Operations for the Three Months Ended September 30, 2014 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Revenues $ 145,950 $ 88,571 $ — $ 234,521 Operating costs and expenses: Lease operating expenses 46,793 24,939 — 71,732 Production taxes 1,794 — — 1,794 Gathering and transportation 2,872 1,243 — 4,115 Depreciation, depletion, amortization and accretion 70,922 57,749 — 128,671 General and administrative expenses 11,450 9,557 — 21,007 Derivative gain (13,781 ) — — (13,781 ) Total costs and expenses 120,050 93,488 — 213,538 Operating income (loss) 25,900 (4,917 ) — 20,983 Loss of affiliates (5,729 ) — 5,729 — Interest expense: Incurred 20,932 851 — 21,783 Capitalized (1,340 ) (851 ) — (2,191 ) Other (income) expense, net (197) (197) Income before income tax expense 776 (4,917 ) 5,729 1,588 Income tax expense 92 812 — 904 Net income (loss) $ 684 $ (5,729 ) $ 5,729 $ 684 Condensed Consolidating Statement of Operations for the Nine Months Ended September 30, 2014 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Revenues $ 448,107 $ 303,924 $ — $ 752,031 Operating costs and expenses: Lease operating expenses 126,966 62,150 — 189,116 Production taxes 5,628 — — 5,628 Gathering and transportation 8,452 4,944 — 13,396 Depreciation, depletion, amortization and accretion 203,040 177,173 — 380,213 General and administrative expenses 33,299 30,978 — 64,277 Derivative loss 6,790 — — 6,790 Total costs and expenses 384,175 275,245 — 659,420 Operating income 63,932 28,679 — 92,611 Earnings of affiliates 16,211 — (16,211 ) — Interest expense: Incurred 63,078 1,625 — 64,703 Capitalized (4,797 ) (1,625 ) — (6,422 ) Other (income) expense, net (205) (205) Income before income tax expense 22,067 28,679 (16,211 ) 34,535 Income tax expense 357 12,468 — 12,825 Net income $ 21,710 $ 16,211 $ (16,211 ) $ 21,710 Condensed Consolidating Statement of Cash Flows for the Nine Months Ended September 30, 2015 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Operating activities: Net loss $ (993,112 ) $ (248,613 ) $ 248,613 $ (993,112 ) Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Depreciation, depletion, amortization and accretion 180,334 145,804 — 326,138 Ceiling test write-down of oil and gas properties 616,947 337,903 — 954,850 Debt issuance costs write-off/amortization of debt items 2,862 — — 2,862 Share-based compensation 8,313 — — 8,313 Derivative gain (9,153 ) — — (9,153 ) Cash receipts on derivative settlements, net 2,139 — — 2,139 Deferred income taxes (50,743 ) (115,515 ) — (166,258 ) Loss of affiliates 248,613 — (248,613 ) — Changes in operating assets and liabilities: Oil and natural gas receivables 26,022 (2,735 ) — 23,287 Joint interest and other receivables 1,210 — — 1,210 Income taxes 33,002 (33,291 ) — (289 ) Prepaid expenses and other assets (47,057 ) 114,888 (51,139 ) 16,692 Asset retirement obligation settlements (22,901 ) (2,614 ) — (25,515 ) Accounts payable, accrued liabilities and other (57,851 ) 341 51,139 (6,371 ) Net cash provided by (used in) operating activities (61,375 ) 196,168 — 134,793 Investing activities: Investment in oil and natural gas properties and equipment (29,930 ) (162,881 ) — (192,811 ) Changes in operating assets and liabilities associated with investing activities (30,731 ) (34,732 ) — (65,463 ) Investment in subsidiary (1,445 ) — 1,445 — Purchases of furniture, fixtures and other (1,185 ) — — (1,185 ) Net cash used in investing activities (63,291 ) (197,613 ) 1,445 (259,459 ) Financing activities: Borrowings of long-term debt – revolving bank credit facility 263,000 — — 263,000 Repayments of long-term debt – revolving bank credit facility (445,000 ) — — (445,000 ) Issuance of 9.00% Term Loan 297,000 — — 297,000 Debt issuance costs (6,591 ) — — (6,591 ) Other 54 — — 54 Investment from parent — 1,445 (1,445 ) — Net cash provided by financing activities 108,463 1,445 (1,445 ) 108,463 Decrease in cash and cash equivalents (16,203 ) — — (16,203 ) Cash and cash equivalents, beginning of period 23,666 — — 23,666 Cash and cash equivalents, end of period $ 7,463 $ — $ — $ 7,463 Condensed Consolidating Statement of Cash Flows for the Nine Months Ended September 30, 2014 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Operating activities: Net income $ 21,710 $ 16,211 $ (16,211 ) $ 21,710 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion, amortization and accretion 203,040 177,173 — 380,213 Amortization of debt issuance costs and premium 537 — — 537 Share-based compensation 11,398 — — 11,398 Derivative loss 6,790 — — 6,790 Cash payments on derivative settlements (18,543 ) — — (18,543 ) Deferred income taxes 17,621 (4,796 ) — 12,825 Earnings of affiliates (16,211 ) — 16,211 — Changes in operating assets and liabilities: Oil and natural gas receivables 9,041 (9,977 ) — (936 ) Joint interest and other receivables 1,890 — — 1,890 Income taxes (14,381 ) 17,265 — 2,884 Prepaid expenses and other assets 55,450 (61,646 ) 27,424 21,228 Asset retirement obligations (28,492 ) (13,519 ) — (42,011 ) Accounts payable, accrued liabilities and other 44,296 4,921 (27,424 ) 21,793 Net cash provided by operating activities 294,146 125,632 — 419,778 Investing activities: Acquisition of property interest in oil and natural gas properties (18,152 ) (53,363 ) — (71,515 ) Investment in oil and natural gas properties and equipment (245,561 ) (138,392 ) — (383,953 ) Changes in operating assets and liabilities associated with investing activities (2,258 ) 7,425 — 5,167 Investment in subsidiary (58,698 ) — 58,698 — Purchases of furniture, fixtures and other (2,181 ) — — (2,181 ) Net cash used in investing activities (326,850 ) (184,330 ) 58,698 (452,482 ) Financing activities: Borrowings of long-term debt – revolving bank credit facility 378,000 — — 378,000 Repayments of long-term debt – revolving bank credit facility (321,000 ) — — (321,000 ) Dividends to shareholders (22,695 ) — — (22,695 ) Other (181 ) — — (181 ) Investment from parent — 58,698 (58,698 ) — Net cash provided in financing activities 34,124 58,698 (58,698 ) 34,124 Increase in cash and cash equivalents 1,420 — — 1,420 Cash and cash equivalents, beginning of period 15,800 — — 15,800 Cash and cash equivalents, end of period $ 17,220 $ — $ — $ 17,220

Basis of Presentation (Policies

Basis of Presentation (Policies)	9 Months Ended
	Sep. 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. On October 15, 2015, a substantial amount of our interest in onshore acreage was sold, which is described in Note 12. 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 nine months ended September 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.
Reclassification	Reclassifications. Certain reclassifications were made to the prior period’s financial statements to conform to the current presentation. In the Condensed Consolidated Statements of Cash flows, Net cash provided by operating activities was increased by $5.2 million and Net cash used in investing activities was increased by $5.2 million for the nine months ended September 30, 2014 to account for the changes in operating liabilities associated with investing activities.
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 for each product, 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, we recorded ceiling test write-downs in 2015 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 nine months ended September 30, 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; (iv) implementing numerous cost reduction projects to reduce our operating costs and (v) on October 15, 2015, sold our interest in the Yellow Rose field. See Note 12 for additional information. During 2015, we have entered into three Amendments to our Fifth Amended and Restated Credit Agreement (as amended, the “Credit Agreement”), which, among other things, changed or eliminated certain financial covenants and authorized the administrative agent under the Credit Agreement to enter into an Intercreditor Agreement among the Company and various lenders. We entered into a second lien term loan (the We have assessed our financial condition, the current capital markets and options given different scenarios of future commodity prices and believe we will have adequate liquidity to fund our operations through September 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 is to 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)	9 Months Ended
	Sep. 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 $ 52,347 Unevaluated properties 2,660 Sub-total cash consideration 55,007 Non-cash consideration: Asset retirement obligations - current 782 Asset retirement obligations - non-current 10,543 Sub-total non-cash consideration 11,325 Total consideration $ 66,332
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) Nine Months Ended September 30, 2014 Revenue $ 774,918 Net income 27,803 Basic and diluted earnings per common share 0.36
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) Nine Months Ended September 30, 2014 (a) Revenues (b) $ 22,887 Direct operating expenses (b) 4,417 DD&A (c) 8,385 G&A (d) 400 Interest expense (e) 330 Capitalized interest (f) (19 ) Income tax expense (g) 3,281 The sources of information and significant assumptions are described below: (a) The adjustments for the period 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. As the acquisition occurred in the second quarter of 2014, pro forma financial information for the three months ended September 30, 2014 is not presented as there would be no differences from reported results.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 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 (25,515 ) Accretion of discount 15,883 Disposition of properties (965 ) Liabilities incurred 7,615 Revisions of estimated liabilities (1) 12,040 Balance, September 30, 2015 399,626 Less current portion 84,588 Long-term $ 315,038 (1) Revisions were primarily attributable to increases in scope of work, additional time to complete the work and from non-operated properties.

Derivative Financial Instrume23

Derivative Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Open Commodity Derivatives	As of September 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) (1) (Bbls) (1) (Bought) (Sold) (Bought) 2015: 4th Quarter 6,000 552,000 $ 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) (1) (Bbls) (1) (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) (1) (MMBTUs) (1) (Bought) (Sold) (Bought) 2015: 4th Quarter (2) 30,000 1,830,000 $ 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 16,470,000 2.25 3.47 3.74 (1) Volume Measurements: Bbls – barrelsMMBTUs – million British Thermal Units (2) 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 October 2015 production were priced and closed in September 2015 and are not included in the above table as these were not open derivative contracts as of September 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): September 30, December 31, 2015 2014 Prepaid and other assets (current) $ 5,970 $ — Other assets (noncurrent) 1,044 —
Changes in Fair Value and Settlements of Commodity Derivative Contracts	Changes in the fair value and settlements of our commodity derivative contracts were as follows (in thousands): Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 Derivative (gain) loss $ (10,231 ) $ (13,781 ) $ (9,153 ) $ 6,790
Cash Payments on Derivative Settlements, Net Included within Net Cash Provided by Operating Activities	Cash receipts (payments), net, on commodity derivative contract settlements are included within Net cash provided by operating activities Nine Months Ended September 30, 2015 2014 Cash receipts (payments) on derivative settlements, net $ 2,139 $ (18,543)

Long-Term Debt (Tables)

Long-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2015
Debt Disclosure [Abstract]
Long-Term Debt	Our long-term debt was as follows (in thousands): September 30, December 31, 2015 2014 8.50% Senior Notes $ 900,000 $ 900,000 Debt premiums, net of amortization 11,161 13,057 9.00% Term Loan 300,000 — Debt discounts, net of amortization (2,813 ) — Revolving bank credit facility 265,000 447,000 Total long-term debt 1,473,348 1,360,057 Current maturities of long-term debt — — Long term debt, less current maturities $ 1,473,348 $ 1,360,057

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 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, as reported in the Condensed Consolidated Balance Sheets (in thousands): September 30, 2015 December 31, 2014 Hierarchy Assets Liabilities Liabilities Derivatives Level 2 $ 7,014 $ — $ — 8.50% Senior Notes (1) Level 2 — 400,500 594,000 9.00% Term Loan (1) Level 2 — 259,500 — Revolving bank credit facility (1) Level 2 — 265,000 447,000 (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 26

Share-Based Compensation and Cash-Based Incentive Compensation (Tables)	9 Months Ended
	Sep. 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, September 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 September 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 (114,900 ) 15.18 Nonvested, September 30, 2015 1,838,935 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 September 30, 2015 potentially eligible to vest are listed in the table below: Restricted Stock Units 2015 - subject to service requirements 689,075 2015 - subject to service and other requirements (1) 84,855 2016 - subject to service requirements 1,065,005 Total 1,838,935 (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 Nine Months Ended September 30, September 30, 2015 2014 2015 2014 Share-based compensation expense from: Restricted stock $ 87 $ 93 $ 270 $ 276 Restricted stock units 2,518 3,658 8,137 9,819 Common shares — 3 (94 ) 1,303 Total $ 2,605 $ 3,754 $ 8,313 $ 11,398 Share-based compensation tax benefit: Tax benefit computed at the statutory rate $ 912 $ 1,314 $ 2,910 $ 3,989
Summary of Incentive Compensation Expense	A summary of incentive compensation expense is as follows (in thousands): Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 Share-based compensation included in: General and administrative expenses $ 2,605 $ 3,754 $ 8,313 $ 11,398 Cash-based incentive compensation included in: Lease operating expense — 586 364 2,363 General and administrative expenses (1) — 2,724 (233 ) 6,038 Total charged to operating income $ 2,605 $ 7,064 $ 8,444 $ 19,799 (1) Adjustments to true up estimates to actual payments resulted in net credit balances to expense for the nine months ended September 30, 2015.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	9 Months Ended
	Sep. 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 Nine Months Ended September 30, September 30, 2015 2014 2015 2014 Net income (loss) $ (477,568 ) $ 684 $ (993,112 ) $ 21,710 Less portion allocated to nonvested shares — 70 — 208 Net income (loss) allocated to common shares $ (477,568 ) $ 614 $ (993,112 ) $ 21,502 Weighted average common shares outstanding 75,932 75,613 75,900 75,592 Basic and diluted earnings (loss) per common share $ (6.29 ) $ 0.01 $ (13.08 ) $ 0.28 Shares excluded due to being anti-dilutive (weighted-average) 431 — 308 —

Supplemental Guarantor Inform28

Supplemental Guarantor Information (Tables)	9 Months Ended
	Sep. 30, 2015
Supplemental Guarantor Information [Abstract]
Condensed Consolidating Balance Sheet	W&T OFFSHORE, INC. AND SUBSIDIARIES 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 September 30, 2015 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Assets Current assets: Cash and cash equivalents $ 7,463 $ — $ — $ 7,463 Receivables: Oil and natural gas sales 15,798 28,157 — 43,955 Joint interest and other 116,178 — (73,743 ) 42,435 Total receivables 131,976 28,157 (73,743 ) 86,390 Deferred income taxes 6,848 1,864 (4,384 ) 4,328 Prepaid expenses and other assets 24,693 820 — 25,513 Total current assets 170,980 30,841 (78,127 ) 123,694 Property and equipment – at cost: Oil and natural gas properties and equipment 6,071,263 2,185,855 — 8,257,118 Furniture, fixtures and other 21,372 — — 21,372 Total property and equipment 6,092,635 2,185,855 — 8,278,490 Less accumulated depreciation, depletion and amortization 5,229,074 1,609,001 — 6,838,075 Net property and equipment 863,561 576,854 — 1,440,415 Restricted deposits for asset retirement obligations 15,578 — — 15,578 Other assets 744,364 292,411 (1,016,491 ) 20,284 Total assets $ 1,794,483 $ 900,106 $ (1,094,618 ) $ 1,599,971 Liabilities and Shareholders’ Equity Current liabilities: Accounts payable $ 101,848 $ 5,621 $ — $ 107,469 Undistributed oil and natural gas proceeds 27,816 1,054 — 28,870 Asset retirement obligations 64,085 20,503 — 84,588 Accrued liabilities 44,610 68,304 (73,743 ) 39,171 Total current liabilities 238,359 95,482 (73,743 ) 260,098 Long-term debt, less current maturities 1,473,348 — — 1,473,348 Asset retirement obligations, less current portion 191,066 123,972 — 315,038 Deferred income taxes 341 17,216 (4,384 ) 13,173 Other liabilities 367,120 — (353,055 ) 14,065 Shareholders’ equity: Common stock 1 — — 1 Additional paid-in capital 422,633 704,885 (704,885 ) 422,633 Retained earnings (deficit) (874,218 ) (41,449 ) 41,449 (874,218 ) Treasury stock, at cost (24,167 ) — — (24,167 ) Total shareholders’ equity (deficit) (475,751 ) 663,436 (663,436 ) (475,751 ) Total liabilities and shareholders’ equity $ 1,794,483 $ 900,106 $ (1,094,618 ) $ 1,599,971 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 September 30, 2015 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Revenues $ 71,092 $ 55,136 $ — $ 126,228 Operating costs and expenses: Lease operating expenses 29,721 15,318 — 45,039 Production taxes 889 — — 889 Gathering and transportation 1,712 1,860 — 3,572 Depreciation, depletion, amortization and accretion 50,960 46,369 — 97,329 Ceiling test write-down of oil and natural gas properties 244,952 196,736 — 441,688 General and administrative expenses 8,590 7,925 — 16,515 Derivative gain (10,231 ) — — (10,231 ) Total costs and expenses 326,593 268,208 — 594,801 Operating loss (255,501 ) (213,072 ) — (468,573 ) Loss of affiliates (129,061 ) — 129,061 — Interest expense: Incurred 27,911 843 — 28,754 Capitalized (1,360 ) (843 ) — (2,203 ) Other (income) expense, net 964 — — 964 Loss before income tax expense (benefit) (412,077 ) (213,072 ) 129,061 (496,088 ) Income tax expense (benefit) 65,491 (84,011 ) — (18,520 ) Net loss $ (477,568 ) $ (129,061 ) $ 129,061 $ (477,568 ) Condensed Consolidating Statement of Operations for the Nine Months Ended September 30, 2015 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Revenues $ 238,900 $ 164,301 $ — $ 403,201 Operating costs and expenses: Lease operating expenses 97,463 46,037 — 143,500 Production taxes 2,526 — — 2,526 Gathering and transportation 7,046 6,143 — 13,189 Depreciation, depletion, amortization and accretion 180,334 145,804 — 326,138 Ceiling test write-down of oil and natural gas properties 616,947 337,903 — 954,850 General and administrative expenses 31,205 25,833 — 57,038 Derivative gain (9,153 ) — — (9,153 ) Total costs and expenses 926,368 561,720 — 1,488,088 Operating loss (687,468 ) (397,419 ) — (1,084,887 ) Loss of affiliates (248,613 ) — 248,613 — Interest expense: Incurred 75,465 2,351 — 77,816 Capitalized (3,659 ) (2,351 ) — (6,010 ) Other (income) expense, net 2,647 — — 2,647 Loss before income tax benefit (1,010,534 ) (397,419 ) 248,613 (1,159,340 ) Income tax benefit (17,422 ) (148,806 ) — (166,228 ) Net loss $ (993,112 ) $ (248,613 ) $ 248,613 $ (993,112 ) Condensed Consolidating Statement of Operations for the Three Months Ended September 30, 2014 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Revenues $ 145,950 $ 88,571 $ — $ 234,521 Operating costs and expenses: Lease operating expenses 46,793 24,939 — 71,732 Production taxes 1,794 — — 1,794 Gathering and transportation 2,872 1,243 — 4,115 Depreciation, depletion, amortization and accretion 70,922 57,749 — 128,671 General and administrative expenses 11,450 9,557 — 21,007 Derivative gain (13,781 ) — — (13,781 ) Total costs and expenses 120,050 93,488 — 213,538 Operating income (loss) 25,900 (4,917 ) — 20,983 Loss of affiliates (5,729 ) — 5,729 — Interest expense: Incurred 20,932 851 — 21,783 Capitalized (1,340 ) (851 ) — (2,191 ) Other (income) expense, net (197) (197) Income before income tax expense 776 (4,917 ) 5,729 1,588 Income tax expense 92 812 — 904 Net income (loss) $ 684 $ (5,729 ) $ 5,729 $ 684 Condensed Consolidating Statement of Operations for the Nine Months Ended September 30, 2014 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Revenues $ 448,107 $ 303,924 $ — $ 752,031 Operating costs and expenses: Lease operating expenses 126,966 62,150 — 189,116 Production taxes 5,628 — — 5,628 Gathering and transportation 8,452 4,944 — 13,396 Depreciation, depletion, amortization and accretion 203,040 177,173 — 380,213 General and administrative expenses 33,299 30,978 — 64,277 Derivative loss 6,790 — — 6,790 Total costs and expenses 384,175 275,245 — 659,420 Operating income 63,932 28,679 — 92,611 Earnings of affiliates 16,211 — (16,211 ) — Interest expense: Incurred 63,078 1,625 — 64,703 Capitalized (4,797 ) (1,625 ) — (6,422 ) Other (income) expense, net (205) (205) Income before income tax expense 22,067 28,679 (16,211 ) 34,535 Income tax expense 357 12,468 — 12,825 Net income $ 21,710 $ 16,211 $ (16,211 ) $ 21,710
Condensed Consolidating Statement of Cash Flows	Condensed Consolidating Statement of Cash Flows for the Nine Months Ended September 30, 2015 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Operating activities: Net loss $ (993,112 ) $ (248,613 ) $ 248,613 $ (993,112 ) Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Depreciation, depletion, amortization and accretion 180,334 145,804 — 326,138 Ceiling test write-down of oil and gas properties 616,947 337,903 — 954,850 Debt issuance costs write-off/amortization of debt items 2,862 — — 2,862 Share-based compensation 8,313 — — 8,313 Derivative gain (9,153 ) — — (9,153 ) Cash receipts on derivative settlements, net 2,139 — — 2,139 Deferred income taxes (50,743 ) (115,515 ) — (166,258 ) Loss of affiliates 248,613 — (248,613 ) — Changes in operating assets and liabilities: Oil and natural gas receivables 26,022 (2,735 ) — 23,287 Joint interest and other receivables 1,210 — — 1,210 Income taxes 33,002 (33,291 ) — (289 ) Prepaid expenses and other assets (47,057 ) 114,888 (51,139 ) 16,692 Asset retirement obligation settlements (22,901 ) (2,614 ) — (25,515 ) Accounts payable, accrued liabilities and other (57,851 ) 341 51,139 (6,371 ) Net cash provided by (used in) operating activities (61,375 ) 196,168 — 134,793 Investing activities: Investment in oil and natural gas properties and equipment (29,930 ) (162,881 ) — (192,811 ) Changes in operating assets and liabilities associated with investing activities (30,731 ) (34,732 ) — (65,463 ) Investment in subsidiary (1,445 ) — 1,445 — Purchases of furniture, fixtures and other (1,185 ) — — (1,185 ) Net cash used in investing activities (63,291 ) (197,613 ) 1,445 (259,459 ) Financing activities: Borrowings of long-term debt – revolving bank credit facility 263,000 — — 263,000 Repayments of long-term debt – revolving bank credit facility (445,000 ) — — (445,000 ) Issuance of 9.00% Term Loan 297,000 — — 297,000 Debt issuance costs (6,591 ) — — (6,591 ) Other 54 — — 54 Investment from parent — 1,445 (1,445 ) — Net cash provided by financing activities 108,463 1,445 (1,445 ) 108,463 Decrease in cash and cash equivalents (16,203 ) — — (16,203 ) Cash and cash equivalents, beginning of period 23,666 — — 23,666 Cash and cash equivalents, end of period $ 7,463 $ — $ — $ 7,463 Condensed Consolidating Statement of Cash Flows for the Nine Months Ended September 30, 2014 Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. (In thousands) Operating activities: Net income $ 21,710 $ 16,211 $ (16,211 ) $ 21,710 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion, amortization and accretion 203,040 177,173 — 380,213 Amortization of debt issuance costs and premium 537 — — 537 Share-based compensation 11,398 — — 11,398 Derivative loss 6,790 — — 6,790 Cash payments on derivative settlements (18,543 ) — — (18,543 ) Deferred income taxes 17,621 (4,796 ) — 12,825 Earnings of affiliates (16,211 ) — 16,211 — Changes in operating assets and liabilities: Oil and natural gas receivables 9,041 (9,977 ) — (936 ) Joint interest and other receivables 1,890 — — 1,890 Income taxes (14,381 ) 17,265 — 2,884 Prepaid expenses and other assets 55,450 (61,646 ) 27,424 21,228 Asset retirement obligations (28,492 ) (13,519 ) — (42,011 ) Accounts payable, accrued liabilities and other 44,296 4,921 (27,424 ) 21,793 Net cash provided by operating activities 294,146 125,632 — 419,778 Investing activities: Acquisition of property interest in oil and natural gas properties (18,152 ) (53,363 ) — (71,515 ) Investment in oil and natural gas properties and equipment (245,561 ) (138,392 ) — (383,953 ) Changes in operating assets and liabilities associated with investing activities (2,258 ) 7,425 — 5,167 Investment in subsidiary (58,698 ) — 58,698 — Purchases of furniture, fixtures and other (2,181 ) — — (2,181 ) Net cash used in investing activities (326,850 ) (184,330 ) 58,698 (452,482 ) Financing activities: Borrowings of long-term debt – revolving bank credit facility 378,000 — — 378,000 Repayments of long-term debt – revolving bank credit facility (321,000 ) — — (321,000 ) Dividends to shareholders (22,695 ) — — (22,695 ) Other (181 ) — — (181 ) Investment from parent — 58,698 (58,698 ) — Net cash provided in financing activities 34,124 58,698 (58,698 ) 34,124 Increase in cash and cash equivalents 1,420 — — 1,420 Cash and cash equivalents, beginning of period 15,800 — — 15,800 Cash and cash equivalents, end of period $ 17,220 $ — $ — $ 17,220

Basis of Presentation - Additio

Basis of Presentation - Additional Information (Details) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)	Sep. 30, 2015USD ($)$ / bbl$ / MMBTU	Sep. 30, 2014USD ($)	Dec. 31, 2014USD ($)	Oct. 30, 2015USD ($)	Oct. 01, 2015$ / bbl$ / MMBTU	May. 31, 2015USD ($)
Basis Of Presentation [Line Items]
Net cash provided by operating activities			$ 134,793	$ 419,778
Net cash used in investing activities			$ (259,459)	(452,482)
Percentage of discount from proved reserves			10.00%
Ceiling test write-down of oil and natural gas properties	$ 441,688	$ 0	$ 954,850	0	$ 0
Addition to available cash	$ 100,000		$ 100,000
Second Lien Term Loan
Basis Of Presentation [Line Items]
Term loan								$ 300,000
Debt instrument maturity date			May 15, 2020
Debt instrument interest rate								9.00%
Subsequent Event | Credit Agreement
Basis Of Presentation [Line Items]
Revolving bank credit facility borrowing base						$ 350,000
SEC Methodology | Crude Oil
Basis Of Presentation [Line Items]
Weighted price | $ / bbl			55.73
SEC Methodology | Natural Gas
Basis Of Presentation [Line Items]
Weighted price | $ / MMBTU			3.06
Industry Quoted Spot Prices | Crude Oil | Subsequent Event
Basis Of Presentation [Line Items]
Average Spot Price | $ / bbl							41.25
Henry Hub Spot Prices | Natural Gas | Subsequent Event
Basis Of Presentation [Line Items]
Average Spot Price | $ / MMBTU							2.48
Reclassifications
Basis Of Presentation [Line Items]
Net cash provided by operating activities				5,200
Net cash used in investing activities				$ 5,200

Acquisitions and Divestitures -

Acquisitions and Divestitures - Additional Information (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Sep. 15, 2015	Sep. 14, 2015	May. 20, 2014
Business Acquisition [Line Items]
Revenues	$ 126,228,000	$ 234,521,000	$ 403,201,000	$ 752,031,000
DD&A	97,329,000	128,671,000	326,138,000	380,213,000
Income tax expense	(18,520,000)	904,000	(166,228,000)	12,825,000
Net income (loss)	(477,568,000)	$ 684,000	(993,112,000)	$ 21,710,000
Fairway
Business Acquisition [Line Items]
Percentage Of Working Interest					100.00%	64.30%
Payments For Previous Acquisition			1,300,000
Goodwill, acquired during period			0
Woodside Properties
Business Acquisition [Line Items]
Percentage Of Working Interest							20.00%
Payments For Previous Acquisition			200,000
Goodwill, acquired during period			0
Revenues	5,800,000		19,200,000
Direct operating expenses	2,400,000		7,500,000
DD&A	3,400,000		11,400,000
Income tax expense	0		100,000
Net income (loss)	$ 100,000		$ 200,000

Acquisitions and Divestitures31

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		$ 55,007
Non-cash consideration:
Asset retirement obligations - non-current		10,543
Asset retirement obligations - current		782
Non-cash consideration		11,325
Total consideration		66,332
Woodside Properties | Evaluated Properties Including Equipment
Cash consideration:
Oil and natural gas properties and equipment		52,347
Woodside Properties | Unevaluated Properties
Cash consideration:
Oil and natural gas properties and equipment		$ 2,660

Acquisitions and Divestitures32

Acquisitions and Divestitures - Summary of Proforma Financial Information for Acquisition (Details) - Woodside Properties $ / shares in Units, $ in Thousands	9 Months Ended
	Sep. 30, 2014USD ($)$ / shares
Business Acquisition [Line Items]
Revenue	$ 774,918
Net income	$ 27,803
Basic and diluted earnings per common share | $ / shares	$ 0.36

Acquisitions and Divestitures33

Acquisitions and Divestitures - Business Acquisition Pro Forma Information Incremental Items (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Business Acquisition [Line Items]
Revenues		$ 126,228	$ 234,521	$ 403,201	$ 752,031
DD&A		97,329	128,671	326,138	380,213
G&A		16,515	21,007	57,038	64,277
Interest expense		28,754	21,783	77,816	64,703
Capitalized		(2,203)	(2,191)	(6,010)	(6,422)
Income tax expense		(18,520)	$ 904	(166,228)	12,825
Woodside Properties
Business Acquisition [Line Items]
Revenues		5,800		19,200
Direct operating expenses		2,400		7,500
DD&A		3,400		11,400
Income tax expense		$ 0		$ 100
Woodside Properties | Pro Forma
Business Acquisition [Line Items]
Revenues	[1],[2]				22,887
Direct operating expenses	[1],[2]				4,417
DD&A	[2],[3]				8,385
G&A	[2],[4]				400
Interest expense	[2],[5]				330
Capitalized	[2],[6]				(19)
Income tax expense	[2],[7]				$ 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 period 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 Divestitures34

Acquisitions and Divestitures - Business Acquisition Pro Forma Information Incremental Items (Parenthetical) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Business Acquisition [Line Items]
Long-term debt, less current maturities	$ 1,473,348		$ 1,360,057
Federal statutory income tax rate	35.00%
Woodside Properties
Business Acquisition [Line Items]
Long-term debt, less current maturities		$ 55,000
Federal statutory income tax rate		35.00%
Woodside Properties | Revolving Credit Facility
Business Acquisition [Line Items]
Effective interest rate		1.80%

Asset Retirement Obligations -

Asset Retirement Obligations - Summary of Changes to Asset Retirement Obligation (Details) - USD ($) $ in Thousands		9 Months Ended
		Sep. 30, 2015	Sep. 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		(25,515)	$ (42,011)
Accretion of discount		15,883
Disposition of properties		(965)
Liabilities incurred		7,615
Revisions of estimated liabilities	[1]	12,040
Asset retirement obligations, end of period		399,626
Less current portion		84,588		$ 36,003
Long-term		$ 315,038		$ 354,565
[1]	Revisions were primarily attributable to increases in scope of work, additional time to complete the work and from non-operated properties.

Derivative Financial Instrume36

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

Derivative Financial Instrume37

Derivative Financial Instruments - Open Commodity Derivatives (Details)	9 Months Ended
	Sep. 30, 2015MMBTU$ / Derivativebbl
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	[1]
Notional Quantity (Bbls) | bbl	552,000	[1]
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	[1]
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	[1]
Notional Quantity (Bbls) | bbl	455,000	[1]
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	[1]
Notional Quantity (Bbls) | bbl	455,000	[1]
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	[1]
Notional Quantity (Bbls) | bbl	460,000	[1]
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	[1]
Notional Quantity (Bbls) | bbl	460,000	[1]
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	16,470,000	[1]
NYMEX Natural Gas - Three-Way Collars | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	2.25
NYMEX Natural Gas - Three-Way Collars | Call Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	3.74
NYMEX Natural Gas - Three-Way Collars | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	3.47
NYMEX Natural Gas - Three-Way Collars | 2015: 4th Quarter
Derivatives Fair Value [Line Items]
Termination Period	4th Quarter	[2]
Notional Quantity (MMBTUs/day) | MMBTU	30,000	[1],[2]
Notional Quantity (MMBTUs) | MMBTU	1,830,000	[1],[2]
NYMEX Natural Gas - Three-Way Collars | 2015: 4th Quarter | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	2.25	[2]
NYMEX Natural Gas - Three-Way Collars | 2015: 4th Quarter | Call Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	3.51	[2]
NYMEX Natural Gas - Three-Way Collars | 2015: 4th Quarter | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	3.25	[2]
NYMEX Natural Gas - Three-Way Collars | 2016: 1st Quarter
Derivatives Fair Value [Line Items]
Termination Period	1st Quarter
Notional Quantity (MMBTUs/day) | MMBTU	40,000	[1]
Notional Quantity (MMBTUs) | MMBTU	3,640,000	[1]
NYMEX Natural Gas - Three-Way Collars | 2016: 1st Quarter | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	2.25
NYMEX Natural Gas - Three-Way Collars | 2016: 1st Quarter | Call Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	3.77
NYMEX Natural Gas - Three-Way Collars | 2016: 1st Quarter | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	3.50
NYMEX Natural Gas - Three-Way Collars | 2016: 2nd Quarter
Derivatives Fair Value [Line Items]
Termination Period	2nd Quarter
Notional Quantity (MMBTUs/day) | MMBTU	40,000	[1]
Notional Quantity (MMBTUs) | MMBTU	3,640,000	[1]
NYMEX Natural Gas - Three-Way Collars | 2016: 2nd Quarter | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	2.25
NYMEX Natural Gas - Three-Way Collars | 2016: 2nd Quarter | Call Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	3.77
NYMEX Natural Gas - Three-Way Collars | 2016: 2nd Quarter | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	3.50
NYMEX Natural Gas - Three-Way Collars | 2016: 3rd Quarter
Derivatives Fair Value [Line Items]
Termination Period	3rd Quarter
Notional Quantity (MMBTUs/day) | MMBTU	40,000	[1]
Notional Quantity (MMBTUs) | MMBTU	3,680,000	[1]
NYMEX Natural Gas - Three-Way Collars | 2016: 3rd Quarter | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	2.25
NYMEX Natural Gas - Three-Way Collars | 2016: 3rd Quarter | Call Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	3.77
NYMEX Natural Gas - Three-Way Collars | 2016: 3rd Quarter | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	3.50
NYMEX Natural Gas - Three-Way Collars | 2016: 4th Quarter
Derivatives Fair Value [Line Items]
Termination Period	4th Quarter
Notional Quantity (MMBTUs/day) | MMBTU	40,000	[1]
Notional Quantity (MMBTUs) | MMBTU	3,680,000	[1]
NYMEX Natural Gas - Three-Way Collars | 2016: 4th Quarter | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	2.25
NYMEX Natural Gas - Three-Way Collars | 2016: 4th Quarter | Call Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	3.77
NYMEX Natural Gas - Three-Way Collars | 2016: 4th Quarter | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	3.50
[1]	Volume Measurements: Bbls – barrelsMMBTUs – million British Thermal Units
[2]	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 October 2015 production were priced and closed in September 2015 and are not included in the above table as these were not open derivative contracts as of September 30, 2015

Derivative Financial Instrume38

Derivative Financial Instruments - Estimated Fair Value of Derivative Contracts (Details) $ in Thousands	Sep. 30, 2015USD ($)
Prepaid And Other Assets (Current)
Derivatives Fair Value [Line Items]
Fair value of commodity derivative contracts	$ 5,970
Other Assets (Noncurrent)
Derivatives Fair Value [Line Items]
Fair value of commodity derivative contracts	$ 1,044

Derivative Financial Instrume39

Derivative Financial Instruments - Changes in Fair Value of Commodity Derivative Contracts (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Gain Loss On Derivative Instruments Net Pretax [Abstract]
Derivative (gain) loss	$ (10,231)	$ (13,781)	$ (9,153)	$ 6,790

Derivative Financial Instrume40

Derivative Financial Instruments - Cash Payments on Derivative Settlements, Net Included within Net Cash Provided by Operating Activities (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Cash receipts (payments) on derivative settlements	$ 2,139	$ (18,543)

Long-Term Debt - Long-Term Debt

Long-Term Debt - Long-Term Debt (Details) - USD ($) $ in Thousands	Sep. 30, 2015	May. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Revolving bank credit facility	$ 265,000		$ 447,000
Total long-term debt	1,473,348		1,360,057
Long-term debt, less current maturities	1,473,348		1,360,057
8.50% Senior Notes
Debt Instrument [Line Items]
8.50% Senior Notes	900,000		900,000
Debt premiums, net of amortization	11,161		$ 13,057
9.00% Term Loan due 2020
Debt Instrument [Line Items]
9.00% Term Loan	300,000	$ 300,000
Debt discounts, net of amortization	$ (2,813)

Long-Term Debt - Long-Term De42

Long-Term Debt - Long-Term Debt (Parenthetical) (Details)	Sep. 30, 2015	May. 31, 2015	Dec. 31, 2014
8.50% Senior Notes
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	9 Months Ended
	May. 31, 2015	Sep. 30, 2015	Sep. 30, 2014	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014
Debt Instrument [Line Items]
Reduction of base rate		33.00%
Mortgaged collateral requirement		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		$ 2,862,000	$ 537,000
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%
Debt instrument payment terms		semi-annually in arrears on June 15 and December 15
Effective interest rate		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%
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
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		3.30%
Credit agreement expiration date		Nov. 8, 2018
Letters of credit outstanding		$ 900,000			$ 900,000
Revolving bank credit facility maximum lender commitment		500,000,000
Line of credit, borrowing availability		$ 234,100,000
Borrowings under Credit Agreement margin increase		0.50%
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%.
Revolving bank credit facility borrowing base		$ 500,000,000
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)	Sep. 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		Sep. 30, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets		$ 7,014
Revolving bank credit facility	[1]	265,000	$ 447,000
8.50% Senior Notes
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Long-term debt, senior notes fair value	[1]	400,500	$ 594,000
9.00% Term Loan due 2020
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Long-term debt, term loan fair value	[1]	$ 259,500
[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 - Sch46

Fair Value Measurements - Schedule of Fair Value of Derivatives Financial Instruments and Long-Term Debt (Parenthetical) (Details)	Sep. 30, 2015	May. 31, 2015	Dec. 31, 2014
8.50% Senior Notes
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 47

Share-Based Compensation and Cash-Based Incentive Compensation - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended		9 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Sep. 30, 2015	Sep. 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				$ 20
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			$ 8.1
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
Cash-Based Incentive Awards | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Adjusted EBITDA less interest expense			$ 300

Share-Based Compensation and 48

Share-Based Compensation and Cash-Based Incentive Compensation - Schedule of Restricted Stock Activity (Details) - Restricted Shares	9 Months Ended
	Sep. 30, 2015$ / sharesshares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Nonvested, beginning of period | shares	43,210
Granted | shares	56,540
Vested | shares	(21,520)
Nonvested, end of period | shares	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 49

Share-Based Compensation and Cash-Based Incentive Compensation - Outstanding Restricted Shares Issued to Non-employee Directors (Details) - Restricted Shares - shares	Sep. 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 50

Share-Based Compensation and Cash-Based Incentive Compensation - Summary of Share Activity Related to Restricted Stock Units (Details) - Restricted Stock Units (RSUs)	9 Months Ended
	Sep. 30, 2015$ / sharesshares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Nonvested, beginning of period | shares	1,977,335
Vested | shares	(23,500)
Forfeited | shares	(114,900)
Nonvested, end of period | shares	1,838,935
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	15.18
Weighted Average Grant Date Value, End of period	$ 15.30

Share-Based Compensation and 51

Share-Based Compensation and Cash-Based Incentive Compensation - Schedule of Restricted Stock Units Outstanding (Details) - Restricted Stock Units (RSUs) - shares		Sep. 30, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period		1,838,935	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		689,075
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]	84,855
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		1,065,005
[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 52

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	9 Months Ended
	Sep. 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 53

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		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation	$ 2,605	$ 3,754	$ 8,313	$ 11,398
Tax benefit computed at the statutory rate	912	1,314	2,910	3,989
Restricted Shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation	87	93	270	276
Restricted Stock Units (RSUs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation	$ 2,518	3,658	8,137	9,819
Common Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation		$ 3	$ (94)	$ 1,303

Share-Based Compensation and 54

Share-Based Compensation and Cash-Based Incentive Compensation - Summary of Incentive Compensation Expense (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Share-based compensation charged to operating income		$ 2,605	$ 3,754	$ 8,313	$ 11,398
Total charged to operating income		2,605	7,064	8,444	19,799
General And Administrative Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Share-based compensation charged to operating income		$ 2,605	3,754	8,313	11,398
Cash-based incentive compensation charged to operating income	[1]		2,724	(233)	6,038
Lease Operating Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Cash-based incentive compensation charged to operating income			$ 586	$ 364	$ 2,363
[1]	Adjustments to true up estimates to actual payments resulted in net credit balances to expense for the nine months ended September 30, 2015.

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Income tax expense (benefit)	$ (18,520)	$ 904	$ (166,228)	$ 12,825
Effective tax rate	3.70%		14.30%	37.10%
Federal statutory income tax rate			35.00%
Valuation allowance	$ 156,200		$ 241,600
Louisiana
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Valuation allowance related to net operating losses	$ 4,300		$ 4,300		$ 4,300
Minimum | State Tax Jurisdiction
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Tax years under examination			2,011
Minimum | Federal
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Tax years under examination			2,012
Maximum | State Tax Jurisdiction
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Tax years under examination			2,014
Maximum | Federal
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		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Earnings Per Share, Basic and Diluted [Abstract]
Net income (loss)	$ (477,568)	$ 684	$ (993,112)	$ 21,710
Less portion allocated to nonvested shares		70		208
Net income (loss) allocated to common shares	$ (477,568)	$ 614	$ (993,112)	$ 21,502
Weighted average common shares outstanding	75,932	75,613	75,900	75,592
Basic and diluted earnings (loss) per common share	$ (6.29)	$ 0.01	$ (13.08)	$ 0.28
Shares excluded due to being anti-dilutive (weighted-average)	431		308

Dividends - Additional Informat

Dividends - Additional Information (Details) - $ / shares	9 Months Ended
	Sep. 30, 2015	Sep. 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	9 Months Ended
	Jan. 31, 2014USD ($)	Mar. 31, 2014USD ($)	Sep. 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
Number of notices received | claim			4
Unpaid proposed penalties			$ 1,000,000
BSEE
Loss Contingencies [Line Items]
Number of notices received | claim			3
Proposed civil penalties paid			$ 200,000
Unpaid proposed penalties			8,100,000
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

Subsequent Events - Additional

Subsequent Events - Additional Information (Details)	Oct. 30, 2015USD ($)	Oct. 15, 2015USD ($)a$ / bbl	Oct. 30, 2015USD ($)	Sep. 30, 2015USD ($)
Subsequent Event [Line Items]
Addition to available cash				$ 100,000,000
Minimum | Third Quarter of 2015
Subsequent Event [Line Items]
Current ratio				75.00%
Subsequent Event
Subsequent Event [Line Items]
Gain (loss) on disposition of proved property		$ 0
Minimum borrowing base amount allowed before bond or term loan purchase	$ 200,000,000		$ 200,000,000
Letter of credit maximum amount outstanding prior to repurchase of bonds or term loans	100,000,000		100,000,000
Subsequent Event | Revolving Credit Facility
Subsequent Event [Line Items]
Line of credit maximum amount outstanding prior to repurchase of bonds or term loans	0		0
Revolving bank credit facility borrowing base	$ 350,000,000		$ 350,000,000
Line of credit effective date			Oct. 30, 2015
Subsequent Event | Minimum | Fourth Quarter of 2015
Subsequent Event [Line Items]
Current ratio	0.75%
Subsequent Event | Minimum | Third Quarter of 2015
Subsequent Event [Line Items]
First lien leverage ratio	1.50%
Subsequent Event | Maximum
Subsequent Event [Line Items]
Limit on percentage of reserves related to recognition of gain or loss		25.00%
Secured debt leverage ratio	3.50%
Subsequent Event | Maximum | First Quarter of 2016
Subsequent Event [Line Items]
Current ratio	1.00%
Subsequent Event | Maximum | Third Quarter of 2015
Subsequent Event [Line Items]
First lien leverage ratio	2.50%
Subsequent Event | Ajax Resources, LLC
Subsequent Event [Line Items]
Acres of oil and gas property, net | a		25,800
Proceeds from sale of interests		$ 376,100,000
Agreement effective date		Jan. 1, 2015
Subsequent Event | Ajax Resources, LLC | Minimum
Subsequent Event [Line Items]
Overriding royalty interest		1.00%
Subsequent Event | Ajax Resources, LLC | Maximum
Subsequent Event [Line Items]
Overriding royalty interest		4.00%
Subsequent Event | NYMEX
Subsequent Event [Line Items]
Addition to available cash		$ 100,000,000
Subsequent Event | Crude Oil | NYMEX | Minimum
Subsequent Event [Line Items]
Trading price per barrel | $ / bbl		70
Subsequent Event | Crude Oil | NYMEX | Maximum
Subsequent Event [Line Items]
Trading price per barrel | $ / bbl		90

Supplemental Guarantor Inform60

Supplemental Guarantor Information - Additional Information (Details)	Sep. 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 Inform61

Supplemental Guarantor Information - Condensed Consolidating Balance Sheet (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 7,463	$ 23,666	$ 17,220	$ 15,800
Receivables:
Oil and natural gas sales	43,955	67,242
Joint interest and other	42,435	43,645
Total receivables	86,390	110,887
Deferred income taxes	4,328	11,662
Prepaid expenses and other assets	25,513	36,347
Total current assets	123,694	182,562
Property and equipment - at cost:
Oil and natural gas properties and equipment	8,257,118	8,045,666
Furniture, fixtures and other	21,372	23,269
Total property and equipment	8,278,490	8,068,935
Less accumulated depreciation, depletion and amortization	6,838,075	5,575,078
Net property and equipment	1,440,415	2,493,857
Restricted deposits for asset retirement obligations	15,578	15,444
Other assets	20,284	17,244
Total assets	1,599,971	2,709,107
Current liabilities:
Accounts payable	107,469	194,109
Undistributed oil and natural gas proceeds	28,870	37,009
Asset retirement obligations	84,588	36,003
Accrued liabilities	39,171	17,377
Total current liabilities	260,098	284,498
Long-term debt, less current maturities	1,473,348	1,360,057
Asset retirement obligations, less current portion	315,038	354,565
Deferred income taxes	13,173	186,988
Other liabilities	14,065	13,691
Shareholders’ equity:
Common stock	1	1
Additional paid-in capital	422,633	414,580
Retained earnings (deficit)	(874,218)	118,894
Treasury stock, at cost	(24,167)	(24,167)
Total shareholders’ equity (deficit)	(475,751)	509,308
Total liabilities and shareholders’ equity	1,599,971	2,709,107
Parent Company
Current assets:
Cash and cash equivalents	7,463	23,666	$ 17,220	$ 15,800
Receivables:
Oil and natural gas sales	15,798	41,820
Joint interest and other	116,178	142,885
Total receivables	131,976	184,705
Deferred income taxes	6,848	9,797
Prepaid expenses and other assets	24,693	28,728
Total current assets	170,980	246,896
Property and equipment - at cost:
Oil and natural gas properties and equipment	6,071,263	6,038,915
Furniture, fixtures and other	21,372	23,269
Total property and equipment	6,092,635	6,062,184
Less accumulated depreciation, depletion and amortization	5,229,074	4,442,899
Net property and equipment	863,561	1,619,285
Restricted deposits for asset retirement obligations	15,578	15,444
Other assets	744,364	974,049
Total assets	1,794,483	2,855,674
Current liabilities:
Accounts payable	101,848	188,654
Undistributed oil and natural gas proceeds	27,816	36,130
Asset retirement obligations	64,085	30,711
Accrued liabilities	44,610	17,437
Total current liabilities	238,359	272,932
Long-term debt, less current maturities	1,473,348	1,360,057
Asset retirement obligations, less current portion	191,066	235,876
Deferred income taxes	341	59,616
Other liabilities	367,120	417,885
Shareholders’ equity:
Common stock	1	1
Additional paid-in capital	422,633	414,580
Retained earnings (deficit)	(874,218)	118,894
Treasury stock, at cost	(24,167)	(24,167)
Total shareholders’ equity (deficit)	(475,751)	509,308
Total liabilities and shareholders’ equity	1,794,483	2,855,674
Guarantor Subsidiaries
Receivables:
Oil and natural gas sales	28,157	25,422
Total receivables	28,157	25,422
Deferred income taxes	1,864	1,865
Prepaid expenses and other assets	820	7,619
Total current assets	30,841	34,906
Property and equipment - at cost:
Oil and natural gas properties and equipment	2,185,855	2,006,751
Total property and equipment	2,185,855	2,006,751
Less accumulated depreciation, depletion and amortization	1,609,001	1,132,179
Net property and equipment	576,854	874,572
Other assets	292,411	357,992
Total assets	900,106	1,267,470
Current liabilities:
Accounts payable	5,621	5,455
Undistributed oil and natural gas proceeds	1,054	879
Asset retirement obligations	20,503	5,292
Accrued liabilities	68,304	99,180
Total current liabilities	95,482	110,806
Asset retirement obligations, less current portion	123,972	118,689
Deferred income taxes	17,216	127,372
Shareholders’ equity:
Additional paid-in capital	704,885	703,440
Retained earnings (deficit)	(41,449)	207,163
Total shareholders’ equity (deficit)	663,436	910,603
Total liabilities and shareholders’ equity	900,106	1,267,470
Eliminations
Receivables:
Joint interest and other	(73,743)	(99,240)
Total receivables	(73,743)	(99,240)
Deferred income taxes	(4,384)
Total current assets	(78,127)	(99,240)
Property and equipment - at cost:
Other assets	(1,016,491)	(1,314,797)
Total assets	(1,094,618)	(1,414,037)
Current liabilities:
Accrued liabilities	(73,743)	(99,240)
Total current liabilities	(73,743)	(99,240)
Deferred income taxes	(4,384)
Other liabilities	(353,055)	(404,194)
Shareholders’ equity:
Additional paid-in capital	(704,885)	(703,440)
Retained earnings (deficit)	41,449	(207,163)
Total shareholders’ equity (deficit)	(663,436)	(910,603)
Total liabilities and shareholders’ equity	$ (1,094,618)	$ (1,414,037)

Supplemental Guarantor Inform62

Supplemental Guarantor Information - Condensed Consolidating Statement of Operations (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Condensed Income Statements Captions [Line Items]
Revenues	$ 126,228	$ 234,521	$ 403,201	$ 752,031
Operating costs and expenses:
Lease operating expenses	45,039	71,732	143,500	189,116
Production taxes	889	1,794	2,526	5,628
Gathering and transportation	3,572	4,115	13,189	13,396
Depreciation, depletion, amortization and accretion	97,329	128,671	326,138	380,213
Ceiling test write-down of oil and natural gas properties	441,688	0	954,850	0	$ 0
General and administrative expenses	16,515	21,007	57,038	64,277
Derivative (gain) loss	(10,231)	(13,781)	(9,153)	6,790
Total costs and expenses	594,801	213,538	1,488,088	659,420
Operating income (loss)	(468,573)	20,983	(1,084,887)	92,611
Interest expense:
Incurred	28,754	21,783	77,816	64,703
Capitalized	(2,203)	(2,191)	(6,010)	(6,422)
Other (income) expense, net	964	(197)	2,647	(205)
Income (loss) before income tax expense (benefit)	(496,088)	1,588	(1,159,340)	34,535
Income tax expense (benefit)	(18,520)	904	(166,228)	12,825
Net income (loss)	(477,568)	684	(993,112)	21,710
Parent Company
Condensed Income Statements Captions [Line Items]
Revenues	71,092	145,950	238,900	448,107
Operating costs and expenses:
Lease operating expenses	29,721	46,793	97,463	126,966
Production taxes	889	1,794	2,526	5,628
Gathering and transportation	1,712	2,872	7,046	8,452
Depreciation, depletion, amortization and accretion	50,960	70,922	180,334	203,040
Ceiling test write-down of oil and natural gas properties	244,952		616,947
General and administrative expenses	8,590	11,450	31,205	33,299
Derivative (gain) loss	(10,231)	(13,781)	(9,153)	6,790
Total costs and expenses	326,593	120,050	926,368	384,175
Operating income (loss)	(255,501)	25,900	(687,468)	63,932
Earnings (loss) of affiliates	(129,061)	(5,729)	(248,613)	16,211
Interest expense:
Incurred	27,911	20,932	75,465	63,078
Capitalized	(1,360)	(1,340)	(3,659)	(4,797)
Other (income) expense, net	964	(197)	2,647	(205)
Income (loss) before income tax expense (benefit)	(412,077)	776	(1,010,534)	22,067
Income tax expense (benefit)	65,491	92	(17,422)	357
Net income (loss)	(477,568)	684	(993,112)	21,710
Guarantor Subsidiaries
Condensed Income Statements Captions [Line Items]
Revenues	55,136	88,571	164,301	303,924
Operating costs and expenses:
Lease operating expenses	15,318	24,939	46,037	62,150
Gathering and transportation	1,860	1,243	6,143	4,944
Depreciation, depletion, amortization and accretion	46,369	57,749	145,804	177,173
Ceiling test write-down of oil and natural gas properties	196,736		337,903
General and administrative expenses	7,925	9,557	25,833	30,978
Total costs and expenses	268,208	93,488	561,720	275,245
Operating income (loss)	(213,072)	(4,917)	(397,419)	28,679
Interest expense:
Incurred	843	851	2,351	1,625
Capitalized	(843)	(851)	(2,351)	(1,625)
Income (loss) before income tax expense (benefit)	(213,072)	(4,917)	(397,419)	28,679
Income tax expense (benefit)	(84,011)	812	(148,806)	12,468
Net income (loss)	(129,061)	(5,729)	(248,613)	16,211
Eliminations
Operating costs and expenses:
Earnings (loss) of affiliates	129,061	5,729	248,613	(16,211)
Interest expense:
Income (loss) before income tax expense (benefit)	129,061	5,729	248,613	(16,211)
Net income (loss)	$ 129,061	$ 5,729	$ 248,613	$ (16,211)

Supplemental Guarantor Inform63

Supplemental Guarantor Information - Condensed Consolidating Statement of Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Operating activities:
Net income (loss)	$ (477,568)	$ 684	$ (993,112)	$ 21,710
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	97,329	128,671	326,138	380,213
Ceiling test write-down of oil and natural gas properties	441,688	0	954,850	0	$ 0
Debt issuance costs write-off/amortization of debt items			2,862	537
Share-based compensation	2,605	3,754	8,313	11,398
Derivative (gain) loss	(10,231)	(13,781)	(9,153)	6,790
Cash receipts (payments) on derivative settlements			2,139	(18,543)
Deferred income taxes			(166,258)	12,825
Changes in operating assets and liabilities:
Oil and natural gas receivables			23,287	(936)
Joint interest and other receivables			1,210	1,890
Income taxes			(289)	2,884
Prepaid expenses and other assets			16,692	21,228
Asset retirement obligation settlements			(25,515)	(42,011)
Accounts payable, accrued liabilities and other			(6,371)	21,793
Net cash provided by operating activities			134,793	419,778
Investing activities:
Acquisition of property interest in oil and natural gas properties				(71,515)
Investment in oil and natural gas properties and equipment			(192,811)	(383,953)
Changes in operating assets and liabilities associated with investing activities			(65,463)	5,167
Purchases of furniture, fixtures and other			(1,185)	(2,181)
Net cash used in investing activities			(259,459)	(452,482)
Financing activities:
Borrowings of long-term debt - revolving bank credit facility			263,000	378,000
Repayments of long-term debt - revolving bank credit facility			(445,000)	(321,000)
Dividends to shareholders				(22,695)
Issuance of 9.00% Term Loan			297,000
Debt issuance costs			(6,591)
Other			54	(181)
Net cash provided by financing activities			108,463	34,124
Increase (decrease) in cash and cash equivalents			(16,203)	1,420
Cash and cash equivalents, beginning of period			23,666	15,800	15,800
Cash and cash equivalents, end of period	7,463	17,220	7,463	17,220	23,666
Parent Company
Operating activities:
Net income (loss)	(477,568)	684	(993,112)	21,710
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	50,960	70,922	180,334	203,040
Ceiling test write-down of oil and natural gas properties	244,952		616,947
Debt issuance costs write-off/amortization of debt items			2,862	537
Share-based compensation			8,313	11,398
Derivative (gain) loss	(10,231)	(13,781)	(9,153)	6,790
Cash receipts (payments) on derivative settlements			2,139	(18,543)
Deferred income taxes			(50,743)	17,621
Earnings (loss) of affiliates	129,061	5,729	248,613	(16,211)
Changes in operating assets and liabilities:
Oil and natural gas receivables			26,022	9,041
Joint interest and other receivables			1,210	1,890
Income taxes			33,002	(14,381)
Prepaid expenses and other assets			(47,057)	55,450
Asset retirement obligation settlements			(22,901)	(28,492)
Accounts payable, accrued liabilities and other			(57,851)	44,296
Net cash provided by operating activities			(61,375)	294,146
Investing activities:
Acquisition of property interest in oil and natural gas properties				(18,152)
Investment in oil and natural gas properties and equipment			(29,930)	(245,561)
Changes in operating assets and liabilities associated with investing activities			(30,731)	(2,258)
Investment in subsidiary			(1,445)	(58,698)
Purchases of furniture, fixtures and other			(1,185)	(2,181)
Net cash used in investing activities			(63,291)	(326,850)
Financing activities:
Borrowings of long-term debt - revolving bank credit facility			263,000	378,000
Repayments of long-term debt - revolving bank credit facility			(445,000)	(321,000)
Dividends to shareholders				(22,695)
Issuance of 9.00% Term Loan			297,000
Debt issuance costs			(6,591)
Other			54	(181)
Net cash provided by financing activities			108,463	34,124
Increase (decrease) in cash and cash equivalents			(16,203)	1,420
Cash and cash equivalents, beginning of period			23,666	15,800	15,800
Cash and cash equivalents, end of period	7,463	17,220	7,463	17,220	$ 23,666
Guarantor Subsidiaries
Operating activities:
Net income (loss)	(129,061)	(5,729)	(248,613)	16,211
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	46,369	57,749	145,804	177,173
Ceiling test write-down of oil and natural gas properties	196,736		337,903
Deferred income taxes			(115,515)	(4,796)
Changes in operating assets and liabilities:
Oil and natural gas receivables			(2,735)	(9,977)
Income taxes			(33,291)	17,265
Prepaid expenses and other assets			114,888	(61,646)
Asset retirement obligation settlements			(2,614)	(13,519)
Accounts payable, accrued liabilities and other			341	4,921
Net cash provided by operating activities			196,168	125,632
Investing activities:
Acquisition of property interest in oil and natural gas properties				(53,363)
Investment in oil and natural gas properties and equipment			(162,881)	(138,392)
Changes in operating assets and liabilities associated with investing activities			(34,732)	7,425
Net cash used in investing activities			(197,613)	(184,330)
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)	129,061	5,729	248,613	(16,211)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Earnings (loss) of affiliates	$ (129,061)	$ (5,729)	(248,613)	16,211
Changes in operating assets and liabilities:
Prepaid expenses and other assets			(51,139)	27,424
Accounts payable, accrued liabilities and other			51,139	(27,424)
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 Inform64

Supplemental Guarantor Information - Condensed Consolidating Statement of Cash Flows (Parenthetical) (Details)	Sep. 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%