W&T Offshore (WTI) 10-K 9 Mar 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Mar. 03, 2016	Jun. 30, 2015
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
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 Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		76,506,489
Entity Public Float			$ 191,676,000

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Statement Of Financial Position [Abstract]
Oil and natural gas properties and equipment - full cost method, amount excluded from amortization	$ 18,595	$ 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	79,375,662	78,768,588
Common stock, outstanding	76,506,489	75,899,415
Treasury stock, shares	2,869,173	2,869,173

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 85,414	$ 23,666
Receivables:
Oil and natural gas sales	35,005	67,242
Joint interest and other	22,012	43,645
Total receivables	57,017	110,887
Prepaid expenses and other assets	26,879	36,347
Total current assets	169,310	170,900
Property and equipment - at cost:
Oil and natural gas properties and equipment (full cost method, of which $18,595 at December 31, 2015 and $109,824 at December 31, 2014 were excluded from amortization)	7,902,494	8,045,666
Furniture, fixtures and other	20,802	23,269
Total property and equipment	7,923,296	8,068,935
Less accumulated depreciation, depletion and amortization	6,933,247	5,575,078
Net property and equipment	990,049	2,493,857
Deferred income taxes	27,595
Restricted deposits for asset retirement obligations	15,606	15,444
Other assets	5,462	9,307
Total assets	1,208,022	2,689,508
Current liabilities:
Accounts payable	109,797	194,109
Undistributed oil and natural gas proceeds	21,439	37,009
Asset retirement obligations	84,335	36,003
Accrued liabilities	11,922	17,377
Total current liabilities	227,493	284,498
Long-term debt	1,196,855	1,352,120
Asset retirement obligations, less current portion	293,987	354,565
Deferred income taxes		175,326
Other liabilities	$ 16,178	$ 13,691
Commitments and contingencies
Shareholders’ equity (deficit):
Preferred stock, $0.00001 par value; 20,000,000 shares authorized; 0 issued at December 31, 2015 and 2014
Common stock, $0.00001 par value; 118,330,000 shares authorized; 79,375,662 issued and 76,506,489 outstanding at December 31, 2015; 78,768,588 issued and 75,899,415 outstanding at December 31, 2014	$ 1	$ 1
Additional paid-in capital	423,499	414,580
Retained earnings (deficit)	(925,824)	118,894
Treasury stock, at cost; 2,869,173 shares at December 31, 2015 and 2014	(24,167)	(24,167)
Total shareholders’ equity (deficit)	(526,491)	509,308
Total liabilities and shareholders’ equity (deficit)	$ 1,208,022	$ 2,689,508

Consolidated Statements Of Oper

Consolidated Statements Of Operations - USD ($)	3 Months Ended																12 Months Ended
	Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement [Abstract]
Revenues	$ 104,064,000		$ 126,228,000		$ 149,066,000		$ 127,907,000		$ 196,677,000		$ 234,521,000		$ 262,994,000		$ 254,516,000		$ 507,265,000	$ 948,708,000	$ 984,088,000
Operating costs and expenses:
Lease operating expenses																	192,765,000	264,751,000	270,839,000
Production taxes																	3,002,000	7,932,000	7,135,000
Gathering and transportation																	17,157,000	19,821,000	17,510,000
Depreciation, depletion and amortization																	373,368,000	490,469,000	430,611,000
Asset retirement obligations accretion																	20,703,000	20,633,000	20,918,000
Ceiling test write-down of oil and natural gas properties	32,400,000		441,600,000		252,800,000		260,400,000										987,238,000	0	0
General and administrative expenses																	73,110,000	86,999,000	81,874,000
Derivative (gain) loss																	(14,375,000)	(3,965,000)	8,470,000
Total costs and expenses																	1,652,968,000	886,640,000	837,357,000
Operating income (loss)	(60,816,000)	[1]	(468,573,000)	[1]	(278,806,000)	[1]	(337,508,000)	[1]	(30,543,000)		20,983,000		34,403,000		37,225,000		(1,145,703,000)	62,068,000	146,731,000
Interest expense:
Incurred																	104,592,000	86,922,000	85,639,000
Capitalized																	(7,256,000)	(8,526,000)	(10,058,000)
Other (income) expense, net																	4,663,000	(208,000)	(8,946,000)
Income (loss) before income tax expense (benefit)																	(1,247,702,000)	(16,120,000)	80,096,000
Income tax expense (benefit)																	(202,984,000)	(4,459,000)	28,774,000
Net income (loss)	$ (51,606,000)	[1]	$ (477,568,000)	[1]	$ (260,449,000)	[1]	$ (255,095,000)	[1]	$ (33,371,000)		$ 684,000		$ 9,837,000		$ 11,189,000		$ (1,044,718,000)	$ (11,661,000)	$ 51,322,000
Basic and diluted earnings (loss) per common share	$ (0.68)	[1],[2]	$ (6.29)	[1],[2]	$ (3.43)	[1],[2]	$ (3.36)	[1],[2]	$ (0.44)	[2]	$ 0.01	[2]	$ 0.13	[2]	$ 0.15	[2]	$ (13.76)	$ (0.16)	$ 0.68
[1]	During 2015, we recorded in first, second, third and fourth quarter ceiling test write-downs of oil and natural gas properties of $260.4 million, $252.8 million, $441.6 million and $32.4 million, respectively. See Note 1 for additional information.
[2]	The sum of the individual quarterly earnings (loss) per share may not agree with the year loss per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter.

Consolidated Statements of Chan

Consolidated Statements of Changes In Shareholders' Equity (Deficit) - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock, Regular	Common Stock, Special	Common Stock Outstanding	Additional Paid-In Capital	Retained Earnings (Deficit)	Retained Earnings (Deficit)Common Stock, Regular	Retained Earnings (Deficit)Common Stock, Special	Treasury Stock
Beginning Balances at Dec. 31, 2012	$ 541,187			$ 1	$ 396,186	$ 169,167			$ (24,167)
Beginning Balances (in shares) at Dec. 31, 2012				75,250					2,869
Cash dividends		$ (27,098)	$ (31,748)				$ (27,098)	$ (31,748)
Share-based compensation	11,525				11,525
Stock issued, shares				342
RSUs and shares surrendered for payroll taxes, value	(2,370)				(2,370)
Other	(2,208)				(1,777)	(431)
Net income (loss)	51,322					51,322
Ending Balances at Dec. 31, 2013	540,610			$ 1	403,564	161,212			$ (24,167)
Ending Balances (in shares) at Dec. 31, 2013				75,592					2,869
Cash dividends		$ (30,260)					$ (30,260)
Share-based compensation	14,744				14,744
Stock issued, shares				307
RSUs and shares surrendered for payroll taxes, value	(848)				(848)
Other	(3,277)				(2,880)	(397)
Net income (loss)	(11,661)					(11,661)
Ending Balances at Dec. 31, 2014	509,308			$ 1	414,580	118,894			$ (24,167)
Ending Balances (in shares) at Dec. 31, 2014				75,899					2,869
Share-based compensation	10,242				10,242
Stock issued, shares				607
RSUs and shares surrendered for payroll taxes, value	(674)				(674)
Other	(649)				(649)
Net income (loss)	(1,044,718)					(1,044,718)
Ending Balances at Dec. 31, 2015	$ (526,491)			$ 1	$ 423,499	$ (925,824)			$ (24,167)
Ending Balances (in shares) at Dec. 31, 2015				76,506					2,869

Consolidated Statements of Cha6

Consolidated Statements of Changes In Shareholders' Equity (Deficit) (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Common Stock, Regular
Paid cash dividends, per share	$ 0	$ 0.40	$ 0.36
Common Stock, Special
Paid cash dividends, per share			$ 0.42

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating activities:
Net income (loss)	$ (1,044,718,000)	$ (11,661,000)	$ 51,322,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	394,071,000	511,102,000	451,529,000
Ceiling test write-down of oil and natural gas properties	987,238,000	0	0
Debt issuance costs write-down/amortization of debt items	4,411,000	701,000	1,645,000
Share-based compensation	10,242,000	14,744,000	11,525,000
Derivative (gain) loss	(14,375,000)	(3,965,000)	8,470,000
Cash receipts (payments) on derivative settlements, net	6,703,000	(5,318,000)	(8,589,000)
Deferred income taxes	(203,272,000)	(4,760,000)	30,920,000
Changes in operating assets and liabilities:
Oil and natural gas receivables	32,236,000	29,510,000	980,000
Joint interest and other receivables	21,633,000	(4,255,000)	34,257,000
Income taxes	(7,000)	3,143,000	44,328,000
Prepaid expenses and other assets	17,816,000	15,012,000	(10,044,000)
Asset retirement obligation settlements	(32,555,000)	(74,313,000)	(81,543,000)
Accounts payable, accrued liabilities and other	(46,869,000)	4,033,000	27,908,000
Net cash provided by operating activities	132,554,000	473,973,000	562,708,000
Investing activities:
Acquisition of property interest in oil and natural gas properties		(72,234,000)	(82,424,000)
Investment in oil and natural gas properties and equipment	(230,161,000)	(554,378,000)	(551,954,000)
Changes in operating assets and liabilities associated with investing activities	(55,425,000)	37,450,000	(1,350,000)
Net proceeds from sales of assets	372,939,000		21,008,000
Purchases of furniture, fixtures and other	(1,278,000)	(3,340,000)	(1,435,000)
Net cash provided by (used in) investing activities	86,075,000	(592,502,000)	(616,155,000)
Financing activities:
Borrowings of long-term debt - revolving bank credit facility	263,000,000	556,000,000	563,000,000
Repayments of long-term debt - revolving bank credit facility	(710,000,000)	(399,000,000)	(443,000,000)
Issuance of 9.00% Term Loan	297,000,000
Debt issuance costs	(6,669,000)		(3,892,000)
Dividends to shareholders		(30,260,000)	(58,846,000)
Other	(212,000)	(345,000)	(260,000)
Net cash provided by (used in) financing activities	(156,881,000)	126,395,000	57,002,000
Increase in cash and cash equivalents	61,748,000	7,866,000	3,555,000
Cash and cash equivalents, beginning of period	23,666,000	15,800,000	12,245,000
Cash and cash equivalents, end of period	$ 85,414,000	$ 23,666,000	$ 15,800,000

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Significant Accounting Policies	1. Significant Accounting Policies Operations W&T Offshore, Inc. and 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 2. 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 the parent company, W&T Offshore, Inc. (on a stand-alone basis, the “Parent Company”) and our wholly-owned subsidiary, W & T Energy VI, LLC (“Energy VI”). Basis of Presentation Our consolidated financial statements include the accounts of W&T Offshore, Inc. and its majority-owned subsidiaries. All significant intercompany transactions and amounts have been eliminated for all years presented. Our consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (“GAAP”) and the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”). 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, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates. Early Adoption of Accounting Standard Amendments Accounting Standards Update No. 2015-03 (“ASU 2015-03”), Interest – Imputation of Interest (Subtopic 835-30), Simplifying the Presentation of Debt Issuance Costs Accounting Standards Update No. 2015-17 (“ASU 2015-17”), Balance Sheet Classification of Deferred Taxes, Current assets Deferred income taxes liability Reclassifications Certain reclassifications have been made to prior periods’ financial statements to conform to the current presentation as follows: Within the Consolidated Statements of Cash Flows, adjustments were made for the changes in operating assets and liabilities associated with investing activities. The adjustments resulted in Net cash provided by operating activities and Net cash used in investing activities to be decreased by $37.5 million for 2014 and increased by $1.4 million for 2013. Similar adjustments were made in the Condensed Consolidating Statements of Cash flow totaling the same amounts for the respective years. The adjustments did not affect the Consolidated Balance Sheets or the Consolidated Statements of Operations. Transactions between Entities under Common Control The prior period financial information for 2014 presented in Note 20, Supplemental Guarantor Information , has been retrospectively adjusted due to transactions between entities under common control, as required under authoritative guidance. Recent Events The price we receive for our crude 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 2015 compared to the last few years. We have taken several steps during 2015 to mitigate the effects of these lower prices including: (i) significantly reducing 2015 capital spending from the previous year and budgeted further reductions in capital spending for 2016 (exclusive of acquisitions); (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; (v) entered into a second lien term loan (the “9.00% Term Loan”); (vi) entered into three Amendments to our Fifth Amended and Restated Credit Agreement (as amended, the “Credit Agreement”); and (vii) sold our interest in the Yellow Rose onshore field. See Notes 2 and Note 7 for additional information. In February 2016, we announced that we had borrowed $340.0 million under the Credit Agreement for general corporate purposes. Also, in February and March 2016, we received demands from the Bureau of Ocean Energy Management (“BOEM”) ordering us to secure financial assurances totaling approximately $260.8 million, with amounts specified by certain designated leases. See Note 20 for additional information. We have assessed our financial condition, the current capital markets and options given different scenarios of commodity prices and believe we will have adequate liquidity to fund our operations through December 31, 2016; however, we cannot predict how an extended period of low commodity prices or the impact of future bonding requirements will affect our operations and liquidity levels. Cash Equivalents We consider all highly liquid investments purchased with original or remaining maturities of three months or less at the date of purchase to be cash equivalents. Revenue Recognition We recognize oil and natural gas revenues based on the quantities of our production sold to purchasers under short-term contracts (less than 12 months) at market prices when delivery has occurred, title has transferred and collectability is reasonably assured. We use the sales method of accounting for oil and natural gas revenues from properties with joint ownership. Under this method, we record oil and natural gas revenues based upon physical deliveries to our customers, which can be different from our net revenue ownership interest in field production. These differences create imbalances that we recognize as a liability only when the estimated remaining recoverable reserves of a property will not be sufficient to enable the under-produced party to recoup its entitled share through production. We do not record receivables for those properties in which the Company has taken less than its ownership share of production. At December 31, 2015 and 2014, $6.9 million and $6.4 million, respectively, were included in current liabilities related to natural gas imbalances. Concentration of Credit Risk Our customers are primarily large integrated oil and natural gas companies and large financial institutions. Our production is sold utilizing month-to-month contracts that are based on bid prices. We also have receivables from joint interest owners on properties we operate and we may have the ability to withhold future revenue disbursements to recover amounts due us. We attempt to minimize our credit risk exposure to purchasers of our oil and natural gas, joint interest owners, derivative counterparties and other third-party entities through formal credit policies, monitoring procedures, and letters of credit or guaranties when considered necessary. We historically have not had any significant problems collecting our receivables, but with the decline in commodity prices, several oil and gas companies have filed for bankruptcy. We use the specific identification method of determining if an allowance for doubtful accounts is needed. As of December 31, 2015 and 2014, we recorded $2.5 million and $0.7 million, respectively, in the allowance for doubtful accounts. During 2015 and 2014, there was no usage of the amounts recorded for allowance for doubtful accounts. The following identifies customers from whom we derived 10% or more of receipts from sales of crude oil, NGLs and natural gas. Year Ended December 31, 2015 2014 2013 Customer Shell Trading (US) Co. 50 % 47 % 48 % J. P. Morgan 14 % ** ** ** less than 10% We believe that the loss of any of the customers above would not result in a material adverse effect on our ability to market future oil and natural gas production as replacement customers could be obtained in a relatively short period of time on terms, conditions and pricing substantially similar to those currently existing. Insurance Receivables We recognize insurance receivables with respect to capital, repair and plugging and abandonment costs as a result of hurricane damage when we deem those to be probable of collection, which arises when our insurance underwriters’ adjuster reviews and approves such costs for payment by the underwriters. Claims that have been processed in this manner have customarily been paid on a timely basis. See Note 18 for information related to unpaid claims by certain underwriters. Prepaid expenses and other Amounts recorded in Prepaid expenses and other Year Ended December 31, 2015 2014 Derivative assets - current (1) $ 10,036 $ 7,417 Prepaid insurance and surety bonds 7,475 13,130 Prepaid deposits related to royalties 5,943 9,681 Other (2) 3,425 6,119 Prepaid expenses and other $ 26,879 $ 36,347 (1) Includes open and closed (and not yet collected) derivative commodity contracts recorded at fair value. (2) Individual items were less than 5% of total current assets for either period presented. Properties and Equipment We use the full-cost method of accounting for oil and natural gas properties and equipment. Under this method, all costs associated with the acquisition, exploration, development and abandonment of oil and natural gas properties are capitalized. Acquisition costs include costs incurred to purchase, lease or otherwise acquire properties. Exploration costs include costs of drilling exploratory wells and external geological and geophysical costs, which mainly consist of seismic costs. Development costs include the cost of drilling development wells and costs of completions, platforms, facilities and pipelines. Costs associated with production, certain geological and geophysical costs and general and administrative costs are expensed in the period incurred. Oil and natural gas properties and equipment include costs of unproved properties. The cost of unproved properties related to significant acquisitions are excluded from the amortization base until it is determined that proved reserves can be assigned to such properties or until such time as the Company has made an evaluation that impairment has occurred. The costs of drilling exploratory dry holes are included in the amortization base immediately upon determination that such wells are non-commercial. We capitalize interest on the amount of unproved properties that are excluded from the amortization base. Interest is capitalized only for the period that exploration and development activities are in progress. Capitalization of interest ceases when the property is moved into the amortization base. All capitalized interest is recorded within Oil and natural gas property and equipment Oil and natural gas properties included in the amortization base are amortized using the units-of-production method based on production and estimates of proved reserve quantities. In addition to costs associated with evaluated properties and capitalized asset retirement obligations (“ARO”), the amortization base includes estimated future development costs to be incurred in developing proved reserves as well as estimated plugging and abandonment costs, net of salvage value, related to developing proved reserves. Future development costs related to proved reserves are not recorded as liabilities on the balance sheet, but are part of the calculation of depletion expense. Sales of proved and unproved oil and natural gas properties, whether or not being amortized currently, 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. Furniture, fixtures and non-oil and natural gas property and equipment are depreciated using the straight-line method based on the estimated useful lives of the respective assets, generally ranging from five to seven years. Leasehold improvements are amortized over the shorter of their economic lives or the lease term. Repairs and maintenance costs are expensed in the period incurred. 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 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. The average price using the SEC required methodology at December 31, 2015 was $46.79 per barrel for West Texas Intermediate (“WTI”) crude oil and $2.59 per million British Thermal Unit (“MMBtu”) for Henry Hub natural gas. These prices are before adjustments for quality, transportation, fees, energy content and regional price differentials. The ceiling test write-downs of the carrying value of our oil and natural gas properties, which included $32.4 million in the fourth quarter of 2015, were $987.2 million for the full year of 2015. We did not record a ceiling test write-down during 2014 or 2013. If crude oil and natural gas prices remain or decrease from current levels, it is probable that a ceiling test write-down will be recorded in the first quarter of 2016 and possibly in subsequent quarters during 2016. Asset Retirement Obligations We are required to record a separate liability for the present value of our ARO, with an offsetting increase to the related oil and natural gas properties on our balance sheet. We have significant obligations to plug and abandon well bores, remove our platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. These obligations are primarily associated with plugging and abandoning wells, removing pipelines, removing and disposing of offshore platforms and site cleanup. Estimating the future restoration and removal cost is difficult and requires us to make estimates and judgments because the removal obligations may be many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations, which can substantially affect our estimates of these future costs from period to period. For additional information, refer to Note 5. Oil and Natural Gas Reserve Information We use the unweighted average of first-day-of-the-month commodity prices over the preceding 12-month period when estimating quantities of proved reserves. Similarly, the prices used to calculate the standardized measure of discounted future cash flows and prices used in the ceiling test for impairment are the 12-month average commodity prices. Proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years, with some limited exceptions allowed. Refer to Note 21 for additional information about our proved reserves. Derivative Financial Instruments Our market risk exposure relates primarily to commodity prices and interest rates. From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our credit facility. Our derivative instruments currently consist of commodity swap contracts for oil. We do not enter into derivative instruments for speculative trading purposes. Derivative instruments are recorded on the balance sheet as an asset or a liability at fair value. Changes in a derivative’s fair value are required to be recognized currently in earnings unless specific hedge accounting and documentation criteria are met at the time the derivative contract is entered into. We have elected not to designate our commodity derivatives as hedging instruments, therefore, all changes in fair value are recognized in earnings. Fair Value of Financial Instruments We include fair value information in the notes to our consolidated financial statements when the fair value of our financial instruments is different from the book value or it is required by applicable guidance. We believe that the book value of our cash and cash equivalents, receivables, accounts payable and accrued liabilities materially approximates fair value due to the short-term nature and the terms of these instruments. We believe that the book value of our restricted deposits approximates fair value as deposits are in cash or short-term investments. We believe 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. Fair Value of Acquisitions Acquisitions are recorded on the closing date of the transaction at their fair value, which is determined by applying the market and income approaches using Level 3 inputs. The Level 3 inputs are: (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 are 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 can vary significantly from estimates that are made. No goodwill was recorded for the acquisitions completed in 2014 or 2013. Income Taxes We use the liability method of accounting for income taxes in accordance with the Income Taxes Early Adoption of Accounting Standard Amendments Debt Issuance Costs Debt issuance costs associated with our revolving bank credit facility are amortized using the straight-line method over the scheduled maturity of the debt. Debt issuance costs associated with all other debt are deferred and amortized over the scheduled maturity of the debt utilizing the effective interest method. As described above, unamortized debt issuance costs associated with our revolving bank credit facility is reported within Other Assets Long-Term Debt, less current maturities Premiums Received and Discounts Provided on Debt Issuance Premiums and discounts are recorded in Long-Term Debt, less current maturities Share-Based Compensation Compensation cost for share-based payments to employees and non-employee directors is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which the recipient is required to provide service in exchange for the award. The fair value for equity instruments subject to only time or to Company performance measures was determined using the closing price of the Company’s common stock at the date of grant. The fair value of equity instruments subject to market-based performance measurements was determined using a Monte Carlo simulation probabilistic model. We recognize share-based compensation expense on a straight line basis over the period during which the recipient is required to provide service in exchange for the award. Estimates are made for forfeitures during the vesting period, resulting in the recognition of compensation cost only for those awards that are estimated to vest and estimated forfeitures are adjusted to actual forfeitures when the equity instrument vests. See Note 11 for more information. Earnings Per Share Unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per share under the two-class method. For additional information, refer to Note 14. Other (Income) Expense, Net For 2015, the amount includes write-offs of debt issuance costs of $3.2 million related to reductions in the borrowing base of the revolving bank credit facility under the Credit Agreement. The write-offs of debt issuance costs is included as an adjustment to net income in determining Net cash provided by operating activities Net cash flows from investing activities Net proceeds from sales of assets Recent Accounting Developments In August 2014, the Financial Accounting Standards Board (“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 (Subtopic 606) In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (“ASU 2016-02”), Leases Subtopic 842

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Acquisitions and Divestitures	2. Acquisitions and Divestitures 2015 Divestiture On October 15, 2015, we sold certain onshore oil and natural gas property interests to Ajax Resources, LLC (“Ajax”) for approximately $372.9 million in cash, which includes certain customary price adjustments, and Ajax assumed responsibility for the related ARO. 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 retained 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 New York Mercantile Exchange (“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 was recognized from the sale. 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 estimated 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 using both the market and income approaches, and Level 3 inputs were used to determine fair value. See Note 1 for a description of the Level 3 inputs. No goodwill was recorded in connection with the acquisition of this 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 estimated 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 using both the market and income approaches, and Level 3 inputs were used to determine fair value. See Note 1 for a description of the Level 3 inputs. No goodwill was recorded in connection with the Woodside Properties acquisition. 2014 Acquisitions — Revenues, Net Income and Pro Forma Financial Information - Unaudited 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 2014. Unaudited pro forma information is not presented as the pro forma information is not materially different from the reported results for 2014 and 2013. The Woodside Properties were not included in our consolidated results until the property transfer date, which occurred on May 20 2014. For 2015, the Woodside Properties accounted for $24.4 million of revenues, $9.5 million of direct operating expenses, $14.4 million of depreciation, depletion, amortization and accretion (“DD&A”) and no income tax expense, resulting in $0.5 million of net income. For the period of May 20, 2014 to December 31, 2014, the Woodside Properties accounted for $28.4 million of revenues, $5.5 million of direct operating expenses, $11.0 million of DD&A and $4.2 million of income taxes, resulting in $7.7 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, the unaudited pro forma financial information was computed as if the acquisition of the Woodside Properties 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 (in thousands, except earnings per share): (unaudited) Year Ended December 31, 2014 2013 Revenue $ 971,595 $ 1,047,037 Net income (5,503 ) 71,412 Basic and diluted earnings per common share (0.08 ) 0.94 For the pro forma financial information, certain information was derived from our financial records, Woodside’s financial records and certain information was estimated. The following table presents incremental items included in the pro forma information reported above for the Woodside Properties (in thousands): (unaudited) Year Ended December 31, 2014 (a) 2013 Revenues (b) $ 22,887 $ 62,949 Direct operating expenses (b) 4,417 9,583 DD&A (c) 8,385 20,503 G&A (d) 300 800 Interest expense (e) 330 990 Capitalized interest (f) (19 ) 165 Income tax expense (g) 3,316 10,818 The sources of information and significant assumptions are described below: (a) The adjustments for 2014 are for the period from January 1, 2014 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) Estimated insurance costs related to the Woodside Properties. (e) The 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. 2013 Acquisition On October 17, 2013, W&T Offshore, Inc. entered into a purchase and sale agreement to acquire certain oil and natural gas property interests from Callon Petroleum Operating Company (“Callon”). Pursuant to the purchase and sale agreement, transfers of certain properties that had no preferential rights were consummated on November 5, 2013 and transfers of certain properties subject to preferential rights, of which third-parties declined to exercise their preferential rights, were consummated on December 4, 2013. The properties acquired from Callon (the “Callon Properties”) consist of a 15% working interest in the Medusa field (deepwater Mississippi Canyon blocks 538 and 582), interest in associated production facilities and various interests in other non-operated fields. All of the Callon Properties are located in the Gulf of Mexico. The effective date of the transaction was July 1, 2013. The transaction included customary adjustments for the effective date, certain closing adjustments and we assumed the related ARO. An upward net purchase price adjustment of $0.6 million was recorded during 2014. 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 estimated adjustments, for the acquisition of the Callon Properties (in thousands): Cash consideration: Evaluated properties including equipment $ 73,752 Unevaluated properties 9,248 Sub-total cash consideration 83,000 Non-cash consideration: Asset retirement obligations - current 90 Asset retirement obligations - non-current 4,143 Sub-total non-cash consideration 4,233 Total consideration $ 87,233 The acquisition was recorded at fair value, which was determined using both the market and income approaches, and Level 3 inputs were used to determine fair value. See Note 1 for a description of the Level 3 inputs. No goodwill was recorded in connection with the acquisition of the Callon Properties. 2013 Acquisition — Revenues, Net Income and Pro Forma Financial Information — Unaudited The Callon Properties were not included in our consolidated results until the respective property transfer dates, which occurred during the fourth quarter of 2013. In 2014, the Callon Properties accounted for $32.5 million of revenue, $6.6 million of direct operating expenses, $16.4 million of DD&A and $3.3 million of income taxes, resulting in $6.2 million of net income. In the fourth quarter of 2013, the Callon Properties accounted for $5.8 million of revenues, $1.3 million of direct operating expenses, $2.4 million of DD&A and $0.7 million of income taxes, resulting in $1.4 million of net income. The net income attributable to these properties does not reflect certain expenses, such as 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 Callon Properties are not recorded in a separate entity for tax purposes; therefore, income tax was estimated using the federal statutory tax rate. The unaudited pro forma financial information presented below was computed as if the acquisition of the Callon Properties had been completed on January 1, 2012. The financial information was derived from W&T’s audited historical consolidated financial statements, the Callon Properties’ audited historical financial statement, and the Callon Properties’ unaudited historical financial statement for the periods presented. The pro forma adjustments were based on estimates by management and information believed to be directly related to the purchase of the Callon Properties. The pro forma financial information is not necessarily indicative of the results of operations had the purchase occurred on January 1, 2012. If the transaction had been in effect for the periods indicated, the results may have been substantially different. For example, we may have operated the assets differently than Callon; the realized sales prices for crude oil, NGLs and natural gas may have been different; and the costs of operating the Callon Properties may have been different. The following table presents a summary of our pro forma financial information (in thousands except earnings per share): (unaudited) Year Ended December 31, 2013 Revenue $ 1,018,118 Net income 59,015 Basic and diluted earnings per common share 0.78 For the pro forma financial information, certain information was derived from financial records and certain information was estimated. The following table presents incremental items included in the pro forma information reported above for the Callon Properties (in thousands): (unaudited) Year Ended December 31, 2013 (a) Revenues (b) $ 34,030 Direct operating expenses (b) 6,405 DD&A (c) 14,931 G&A (d) (361 ) Interest expense (e) 1,383 Capitalized interest (f) (164 ) Income tax expense (g) 4,143 The sources of information and significant assumptions are described below: (a) The adjustments for 2013 are for the period from January 1, 2013 to the respective property transfer date, all of which occurred in the fourth quarter of 2013. (b) Revenues and direct operating expenses for the Callon Properties were derived from the historical financial records of Callon. (c) DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Callon Properties’ costs, reserves and production into our currently existing 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) G&A adjustments related to incremental transaction expenses, which were assumed to be funded from cash on hand, and were adjusted from the 2013 results. (e) The acquisition was assumed to be funded entirely with borrowed funds. Interest expense was computed using assumed borrowings of $83.0 million, which equates to the cash component of the transaction, and an interest rate of 2.0%, 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. A positive amount represents an increase to net expenses and a 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. 2013 Divestitures On July 11, 2013, we sold our non-operated working interest in two offshore fields located in the Gulf of Mexico; the Green Canyon 60 field and the Green Canyon 19 field. The effective date was October 1, 2011 and we retained the deep rights in both fields. Due to the length of time from the effective date, we paid $4.3 million to sell the properties as revenues exceeded operating expenses and the purchase price for the period between the effective date and the close date. In connection with the sale, we reversed $15.6 million of our ARO. On September 26, 2013, we sold our working interests in the West Delta area block 29 with an effective date of January 1, 2013. The property is located in the Gulf of Mexico. Including adjustments for the effective date, the net proceeds were $14.7 million, which includes a $1.7 million post-effective-date repayment that occurred during 2014. The transaction was structured as a like-kind exchange under the Internal Revenue Service Code (“IRC”) Section 1031 and other applicable regulations, with funds held by a qualified intermediary until replacement purchases are made. Replacement purchases were made in 2013, which were within the replacement periods as defined under the IRC. In connection with this sale, we reversed $3.9 million of ARO.

Hurricane Remediation and Insur

Hurricane Remediation and Insurance Claims	12 Months Ended
	Dec. 31, 2015
Insurance [Abstract]
Hurricane Remediation and Insurance Claims	3. Hurricane Remediation and Insurance Claims During the third quarter of 2008, Hurricane Ike caused substantial damage to certain of our properties. Our insurance policies in effect on the occurrence date of Hurricane Ike had a retention requirement of $10.0 million per occurrence, which has been satisfied, and coverage policy limits of $150.0 million for property damage due to named windstorms (excluding damage at certain facilities) and $250.0 million for, among other things, removal of wreckage if mandated by any governmental authority. For 2015, 2014 and 2013, we have received insurance proceeds of $0.2 million, $12.2 million and $6.7 million, respectively, primarily related to hurricane damage. These amounts are included within Net cash provided by operating activities Oil and natural gas properties and equipment Lease operating expense

Restricted Deposits

Restricted Deposits	12 Months Ended
	Dec. 31, 2015
Receivables [Abstract]
Restricted Deposits	4. Restricted Deposits Restricted deposits as of December 31, 2015 and 2014 consisted of funds escrowed for the future plugging and abandonment of certain oil and natural gas properties. Pursuant to the Purchase and Sale Agreement with Total E&P USA Inc. (“Total E&P”), security for future plugging and abandonment of certain oil and natural gas properties is required either through surety bonds or payments to an escrow account or a combination thereof. Monthly payments are made to an escrow account and these funds are returned to us once verification is made that the security amount requirements have been met. We were in compliance with the security requirements as of December 31, 2015. See Note 16 for potential future security requirements.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	5. Asset Retirement Obligations Asset retirement obligations associated with the retirement of tangible long-lived assets are required to be recognized as a liability in the period in which a legal obligation is incurred and becomes determinable, with an offsetting increase in the carrying amount of the associated asset. The cost of the tangible asset, including the initially recognized ARO, is depleted such that the cost of the ARO is recognized over the useful life of the asset. The fair value of the ARO is measured using expected cash outflows associated with the ARO, discounted at our credit-adjusted risk-free rate when the liability is initially recorded. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The following is a reconciliation of our ARO liability (in thousands): Year Ended December 31, 2015 2014 Asset retirement obligations, beginning of period $ 390,568 $ 354,422 Liabilities settled (32,555 ) (74,313 ) Accretion of discount 20,703 20,633 Disposition of properties (8,581 ) — Liabilities assumed through acquisition 2,944 21,820 Liabilities incurred 4,780 3,258 Revisions of estimated liabilities 463 64,748 Asset retirement obligations, end of period 378,322 390,568 Less current portion 84,335 36,003 Long-term $ 293,987 $ 354,565 During 2015, we decreased our ARO on an overall basis primarily due to plug and abandonment work performed during 2015, partially offset by increases from accretion. Revisions were basically flat as some service providers reduced their costs of goods and services, some service provider costs remained flat and some service provider costs estimates were increased, all of which were incorporated into our estimates. In addition, revisions were made for scope changes and on the estimates of timing of when the work will be performed. Liability increases from acquisitions and wells drilled were basically offset by reductions from dispositions. During 2014, we increased our ARO on an overall basis primarily due to revisions, acquisitions and accretion of discount. Revisions increased ARO on a net basis primarily attributable to: a) increases at certain non-operated properties, b) regulation interpretations issued by the Bureau of Safety and Environmental Enforcement (“BSEE”), which increased the amount of work involved, c) revisions to third-party contractor estimated prices for certain work on wells and structures, d) revisions accelerating the timing of planned work for certain wells and e) revisions for certain wells that are taking longer to complete the plugging and abandonment work than previously estimated due to operational issues. Increases related to acquisitions include the increase in our ownership interest at Fairway, the acquisition of the Woodside Properties and other minor acquisitions. Partially offsetting these were decreases for the plug and abandonment work performed during the year and the disposition of certain properties.

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	6. 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. Each derivative contract is recorded on the balance sheet as an asset or liability at fair value as of the respective period. 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 8. 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 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 and 2013, 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 December 31, 2015, our open commodity derivative contracts were as follows: 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) Notional Notional Weighted Average Contract Price Quantity Quantity Put Option Call Option Call Option Termination Period (MMBTUs/day) (1) (MMBTUs) (1) (Bought) (Sold) (Bought) 2016: 1st Quarter (2) 40,000 2,400,000 $ 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 13,400,000 2.25 3.50 3.77 (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 January 2016 production were priced and closed in December 2015 and are excluded in the above table as these were closed contracts as of December 31, 2015. The following balance sheet line items included amounts related to the estimated fair value of our open commodity derivative contracts as reported in the following table (in thousands): December 31, 2015 2014 Prepaid and other assets - current $ 7,672 $ — Changes in the fair value and settlements of our commodity derivative contracts were as follows (in thousands): Year Ended December 31, 2015 2014 2013 Derivative (gain) loss: $ (14,375 ) $ (3,965 ) $ 8,470 Cash receipts (payments), net, on commodity derivative contract settlements are included within Net cash provided by operating activities Year Ended December 31, 2015 2014 2013 Cash receipts (payments) on derivative settlements, net $ 6,703 $ (5,318 ) $ (8,589 ) 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 December 31, 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	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Long-Term Debt	7. Long-Term Debt As of December 31, 2015 and 2014, our long-term debt was as follows (in thousands): December 31, 2015 2014 8.50% Senior Notes: Principal $ 900,000 $ 900,000 Debt premiums, net of amortization 10,503 13,057 Debt issuance costs, net of amortization (6,274 ) (7,937 ) 9.00% Term Loan: Principal 300,000 — Debt discounts, net of amortization (2,689 ) — Debt issuance costs, net of amortization (4,685 ) — Revolving bank credit facility — 447,000 Total long-term debt 1,196,855 1,352,120 Current maturities of long-term debt — — Long term debt, less current maturities $ 1,196,855 $ 1,352,120 Aggregate annual maturities of long-term debt as of December 31, 2015 are as follows (in millions): 2016–$0.0; 2017–$0.0; 2018–$0.0; 2019–$900.0; thereafter–$300.0. Senior Notes At December 31, 2015 and 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. We and our restricted subsidiaries are subject to certain covenants under the indenture governing the 8.50% Senior Notes, which limit our and our restricted subsidiaries’ ability to, among other things, make investments, incur additional indebtedness or issue preferred stock, sell assets, consolidate, merge or transfer all or substantially all of our assets, engage in transactions with affiliates, pay dividends or make other distributions on capital stock or subordinated indebtedness and create unrestricted subsidiaries. We were in compliance with those covenants as of December 31, 2015. See Note 1 related to a change in the classification of unamortized debt issuance costs on the Consolidated Balance Sheets. Term Loan In May 2015, we entered into the 9.00% Term Loan, which 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. 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 December 31, 2015. See Note 1 related to a change in the classification of unamortized debt issuance costs on the Consolidated Balance Sheets. Credit Agreement The Credit Agreement, as amended, provides a revolving bank credit facility. Availability under the Credit Agreement is subject to a semi-annual borrowing base determination set at the discretion of our lenders, and the Company and the lenders may each request one additional determination per year. The borrowing base as of December 31, 2015 was $350.0 million. The amount of the borrowing base is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria. Any determination by our lenders to change our borrowing base will result in a similar change in the availability under our revolving bank credit facility. To the extent borrowings and letters of credit outstanding exceed the redetermined borrowing base, such excess or deficiency is required to be repaid within 90 days in three equal monthly payments. Letters of credit may be issued in amounts up to $300.0 million, provided availability under the revolving bank credit facility exists. The revolving bank credit facility is secured and is collateralized by our oil and natural gas properties. The Credit Agreement terminates on November 8, 2018. The Credit Agreement contains covenants that limit, among other things, our ability to: (i) pay cash dividends; (ii) repurchase our common stock or outstanding 8.50% Senior Notes or outstanding 9.00% Term Loan, provided that such limitation will not apply to the repurchase of our existing 8.50% Senior Notes or 9.00% Term Loan in an aggregate principal amount equal to the aggregate principal amount of any new issuance of such debt; (iii) sell our assets; (iv) make certain loans or investments; (v) merge or consolidate; (vi) eliminate certain hedging contracts or enter into certain hedging contacts in excess of 75% of projected oil and gas production on a monthly basis; (vii) enter into certain liens; and (viii) enter into certain other transactions, without the prior consent of the lenders. We are permitted to issue additional indebtedness if certain conditions are met including: (i) the additional debt is subordinate in security and right of payment; (ii) the borrowers enter into an intercreditor agreement with terms acceptable to the Administrative Agent of the Credit Agreement; (iii) we are in compliance with the financial covenants after giving pro forma effect to the additional unsecured indebtedness; and (iv) such additional unsecured indebtedness matures after the maturity date of the Credit Agreement and is not subject to restrictive covenants materially more onerous than those provided for in the Credit Agreement. We are permitted to redeem, repurchase, prepay or defease all or a portion of the 8.50% Senior Notes or the 9.00% Term loan if after giving effect of such redemption, repayment, prepayment or defeasance: (i) no amounts are outstanding on the revolving bank credit facility; (ii) letters of credit outstanding do not exceed $100.0 million; (iii) the then borrowing base is at least $200.0 million; and (iv) no event of default shall have occurred and be continuing, and no borrowing base deficiency shall have occurred and be continuing or result therefrom. The Credit Agreement also contains various customary covenants for certain financial tests, as defined in the Credit Agreement and measured as of the end of each quarter, and for customary events of default. These financial test ratios and limits as of December 31, 2015 and thereafter are: (i) the First Lien leverage Ratio must be less than 1.50 to 1.00; (ii) the Current Ratio must be greater than 0.75 to 1.00 as of December 31, 2015 and must be greater than 1.00 to 1.00 thereafter; and (iii) the Secured Debt Leverage Ratio must be less than 3.50 to 1.00. The customary events of default include: (i) nonpayment of principal when due or nonpayment of interest or other amounts within three business days of when due; (ii) bankruptcy or insolvency with respect to the Company or any of its subsidiaries guaranteeing borrowings under the revolving bank credit facility; or (iii) a change of control. The Credit Agreement contains cross-default clauses with the 8.50 %Senior Notes and the 9.00% Term, and these agreements contain similar cross-default clauses with the Credit Agreement. We were in compliance with all applicable covenants of the Credit Agreement as of December 31, 2015. Borrowings under the revolving bank credit facility bear interest at the applicable London Interbank Offered Rate (“LIBOR”) plus a margin that varies from 2.25% to 3.25% depending on the level of total borrowings under the Credit Agreement, or an alternative base rate equal to the greater of (a) Prime Rate, (b) Federal Funds Rate plus 0.5%, and (c) LIBOR plus 1.0%, plus applicable margin ranging from 1.25% to 2.25%. The unused portion of the borrowing base is subject to a commitment fee ranging from 0.375% to 0.5%. The estimated annual effective interest rate was 3.3% for 2015 for borrowings under the Credit Agreement. The estimated annual effective interest rate includes amortization of debt issuance costs and excludes commitment fees and other costs. During 2015, the borrowing base under the Credit Agreement was reduced to $350.0 million. The reduction in the borrowing base resulted in proportional reduction in the unamortized costs related to the Credit Agreement of $3.2 million, which is included in the line Other (income)/expense, net At December 31, 2015, we had no borrowings and $0.9 million in letters of credit outstanding under the revolving bank credit facility. At December 31, 2014, we had $447.0 million in borrowings and $0.6 million in letters of credit outstanding under the revolving bank credit facility. See Note 20 for borrowings outstanding subsequent to December 31, 2015. For information about fair value measurements of our long-term debt, refer to Note 8.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	8. Fair Value Measurements Under GAAP, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value of an asset should reflect its highest and best use by market participants, whether using an in-use or an in-exchange valuation premise. The fair value of a liability should reflect the risk of nonperformance, which includes, among other things, the Company’s credit risk. Valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach. The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy: · Level 1 – quoted prices in active markets for identical assets or liabilities. · Level 2 – inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs). · Level 3 – unobservable inputs that reflect the Company’s own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability. The following table presents the fair value of our derivative financial instruments, our 8.50% Senior Notes, the 9.00% Term Loan and our revolving bank credit facility (in thousands): December 31, 2015 December 31, 2014 Hierarchy Assets Liabilities Liabilities Derivatives Level 2 $ 7,672 $ — $ — 8.50% Senior Notes Level 2 — 324,000 594,000 9.00% Term Loan Level 2 — 217,500 — Revolving bank credit facility Level 2 — — 447,000 We measure the fair value of our derivative financial instruments by applying the income approach, using models with inputs that are classified within Level 2 of the valuation hierarchy. The inputs used for the fair value measurement of our derivative financial instruments are the exercise price, the expiration date, the settlement date, notional quantities, the implied volatility, the discount curve with spreads and published commodity futures prices. The fair value of our 8.50% Senior Notes and the 9.00% Term Loan is 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. Derivatives are reported in the statement of financial position at fair value. The 8.50% Senior Notes are reported in the statement of financial position at their carrying value, which was $900.0 million at December 31, 2015 and 2014. The 9.00% Term Loan is reported in the statement of financial position at its carrying value, which was $300.0 million at December 31, 2015. The revolving bank credit facility debt is reported in the statement of financial position at its carrying value, which was zero and $447.0 million at December 31, 2015 and 2014, respectively. For additional information about our derivative financial instruments refer to Note 6 and for additional information on our 8.50% Senior Notes, the 9.00% Term Loan and revolving bank credit facility refer to Note 7.

Equity Structure and Transactio

Equity Structure and Transactions	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Equity Structure and Transactions	9. Equity Structure and Transactions As of December 31, 2015 and 2014, the Company was authorized to issue 20 million shares of preferred stock with a par value of $0.00001 per share; however, no preferred shares have been issued or were outstanding as of the respective dates. During 2015, we did not pay any dividends and dividends were suspended. During 2014 and 2013, we paid regular cash dividends of $0.40 and $0.36 per common share, respectively. In December 2013, we paid a special dividend of $0.42 per share or $31.8 million.

Incentive Compensation Plan and

Incentive Compensation Plan and Directors Compensation Plan	12 Months Ended
	Dec. 31, 2015
Compensation Related Costs [Abstract]
Incentive Compensation Plan and Directors Compensation Plan	10. Incentive Compensation Plan and Directors Compensation Plan Incentive Compensation Plan 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 2013. The Plan covers the Company’s eligible employees and consultants. In addition to other cash and share-based compensation awards, the Plan is designed to grant awards that qualify as performance-based compensation within the meaning of section 162(m) of the IRC. The Plan grants the Compensation Committee of the Board of Directors administrative authority over all participants, and grants the President and Chief Executive Officer with authority over the administration of awards granted to participants that are not subject to section 16 of the Exchange Act (as applicable, the “Committee”). Pursuant to the terms of the Plan, the Committee establishes the performance criteria and may use a single measure or combination of business measures as described in the Plan. Also, individual goals may be established by the Committee. Performance awards may be granted in the form of stock options, stock appreciation rights, restricted stock, restricted stock units, bonus stock, dividend equivalents, or other awards related to stock, and awards may be paid in cash, stock, or any combination of cash and stock, as determined by the Committee. The performance awards granted under the Plan can be measured over a performance period of up to 10 years and annual incentive awards (a type of performance award) will generally be paid within 90 days following the applicable year end. Share-based Awards: Restricted Stock Units For 2015, 2014 and 2013, performance awards under the Plan were granted in the form of restricted stock units (“RSUs”). As defined by the Plan, RSUs are rights to receive stock, cash or a combination thereof at the end of a specified vesting period, subject to certain terms and conditions as determined by the Committee. 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 using a predefined scale based on the Company achieving certain predetermined performance criteria. Vesting occurs upon completion of the specified vesting period applicable to each grant. Subsequent to the determination of the performance achievement and prior to vesting, the RSUs earn dividend equivalents at the same rate as dividends paid on our common stock. RSUs are subject to forfeiture until vested and cannot be sold, transferred or disposed of during the restricted period. During 2015, 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 2015 and (ii) Adjusted EBITDA as a percent of total revenue (“Adjusted EBITDA Margin”) for 2015. Adjustments range from 0% to 100% based upon actual results compared against pre-defined performance levels. For 2015, the Company was below target for Adjusted EBITDA and above target for Adjusted EBITDA Margin During 2014, RSUs granted were subject to adjustments based on achievement of a combination of performance criteria, which was comprised of: (i) Adjusted EBITDA for 2014 and (ii) Adjusted EBITDA Margin for 2014. Adjustments range from 0% to 100% based upon actual results compared against pre-defined performance levels. For 2014, the Company was above target for Adjusted EBITDA and was slightly below target for Adjusted EBITDA Margin. During 2013, RSUs granted were subject to 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. Adjustments range from 0% to 150% for portions subject to Adjusted EBITDA and Adjusted EBITDA Margin measurements and adjustments range from 0% to 200% for the portion subject to TSR measurement. For 2013, the Company exceeded the target for Adjusted EBITDA and was approximately at target for 2013 Adjusted EBITDA Margin. For the 2015, 2014 and 2013 periods, the Company was below target for the TSR rankings for each period. In addition, RSUs were granted during 2013 which were not subject to performance criteria and were less than 3% of total grants. All RSUs granted to date are subject to employment-based criteria in addition to performance criteria. Vesting occurs in December of the second calendar year following the date of grant. For example, the RSUs granted during 2013 (after adjustment for performance) vested in December 2015 to eligible employees. Cash-based Awards For 2015, 2014 and 2013, cash-based awards were granted under the Plan to substantially all eligible employees. The cash-based awards, which are a short-term component of the Plan, were determined based on multiple performance measures, such as Adjusted EBITDA, reserve and production growth, cost containment and individual performance measures. With respect to the 2015 cash-based awards, some of the performance criteria targets were achieved and were combined with estimates of personal performance measurements to record potential payments. In addition, for the 2015 cash-based awards, which includes the 2015 incentive plan for the Chief Executive Officer (“CEO”), the Company designed the awards with an additional financial condition that must be achieved on or before December 31, 2017: Adjusted EBITDA less Interest Expense Incurred, as reporting by the Company in its announced Earning Release with respect to the end of any fiscal quarter plus three preceding quarters, exceeds $300.0 million. As this additional financial condition was not achieved as of December 31, 2015, no amounts were accrued or subsequently paid. If this additional financial condition is achieved, payment is to be made within 30 days following the achievement of the financial condition, but subject to all the terms of the 2015 Annual Incentive Award Agreement (the 2015 cash-based award). With respect to the 2014 cash-based awards, some of the performance criteria targets were achieved and were combined with estimates of personal performance measurements to record potential payments. With respect to the 2013 cash-based awards, most of the performance criteria targets were achieved and were combined with the individual’s performance to determine the cash-based award. With respect to the 2012 cash-based awards, some of the performance criteria targets were achieved and were combined with the individual’s performance to determine the cash-based award. In addition, pursuant to the Plan, discretionary authority was exercised for certain non-executive employees, which increased cash-based award amounts in 2012. Eligible employees were paid their cash-based awards within 75 days following year end. Share-based Awards: Common Stock The 2014 annual incentive plan award for the 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. As the number of shares could not be determined until the full-year 2014 results were determined and approved by the Compensation Committee, the CEO’s 2014 award was accounted for as a liability award during 2014 and adjusted to fair value using the company’s closing price at the end of each reporting period. 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. The CEO awards for both years were 100% performance based and were subject to pre-defined performance measures and employment-based criteria, which were the same pre-defined performance measures and employment-based criteria established for the other eligible Company employees, and were subject to approval of the Compensation Committee. Directors Compensation Plan Share-Based Awards Under the Directors Compensation Plan, shares of restricted stock (“Restricted Shares”) were issued in 2015, 2014 and 2013 to the Company’s non-employee directors as a component of their compensation arrangement. Vesting occurs upon completion of the specified vesting period and one-third of each grant vests each year over a three-year period. The holders of Restricted Shares generally have the same rights as a shareholder of the Company with respect to such shares, including the right to vote and receive dividends or other distributions paid with respect to the shares. Restricted Shares are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during the restriction period. For additional information concerning share-based awards and cash-based awards, including expense recognition, see Note 11.

Share-Based and Cash-Based Ince

Share-Based and Cash-Based Incentive Compensation	12 Months Ended
	Dec. 31, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Share-Based and Cash-Based Incentive Compensation	11. Share-Based and Cash-Based Incentive Compensation As allowed by the Plan, in 2015, 2014 and 2013, the Company granted RSUs to certain of its employees. In 2015, 2014 and 2013, restricted stock was granted to the Company’s non-employee directors under the Directors Compensation Plan. In addition to share-based compensation, the Company granted cash-based incentive awards to substantially all eligible employees in 2015, 2014 and 2013. On May 7, 2013, after receiving shareholder approval, 4,000,000 shares of common stock were added to the amount available for issuance under the Plan. As of December 31, 2015, there were 4,239,548 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 Directors Compensation Plan. The shares available for both plans are reduced when restricted stock is granted. RSUs reduce the shares available in the Plan only when 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. Restricted Stock Under the Directors Compensation Plan, shares of restricted stock (“Restricted Shares”) were issued in 2015, 2014 and 2013 to the Company’s non-employee directors. See Note 10 for additional information concerning Restricted Shares. A summary of activity related to Restricted Shares is as follows: 2015 2014 2013 Restricted Shares Weighted Average Grant Date Fair Value Per Share Restricted Shares Weighted Average Grant Date Fair Value Per Share Restricted Shares Weighted Average Grant Date Fair Value Per Share Nonvested, beginning of period 43,210 $ 16.20 43,840 $ 15.96 43,687 $ 18.69 Granted 56,540 6.19 18,815 18.60 27,450 12.75 Vested (21,520 ) 16.26 (19,445 ) 18.00 (27,297 ) 17.09 Nonvested, end of period 78,230 $ 8.95 43,210 $ 16.20 43,840 $ 15.96 Subject to the satisfaction of service conditions, the Restricted Shares outstanding as of December 31, 2015 are expected to vest as follows: Restricted Shares 2016 34,265 2017 25,115 2018 18,850 Total 78,230 Restricted stock fair value at grant date: Restricted stock fair value at vested date: Restricted Stock Units During 2015, 2014 and 2013, the Company granted RSUs to certain employees, with nearly all grants being contingent upon meeting specified performance requirements. The grants are subject to adjustments at the end of the applicable performance period using a predefined scale based on the Company achieving certain predetermined performance criteria. See Note 10 for additional information concerning RSUs. The fair value of the RSUs granted in 2015 and 2014 was determined using the Company’s closing price on the grant dates as the performance measures were all company-specific performance measures comprised of Adjusted EBITDA and Adjusted EBITDA Margin. The fair value of the RSUs granted in 2013 was determined separately for each component. For the components related to the company-specific performance measures (Adjusted EBITDA and Adjusted EBITDA Margin), the fair value was determined using the Company’s closing price on the grant date. The components related to Adjusted EBITDA and Adjusted EBITDA Margin comprised 40% and 30%, respectively, of the amount granted. For the component related to TSR ranking, the fair value was determined using a Monte Carlo simulation probabilistic model. The component related to TSR ranking totaled 30% of the amount granted, with 10% for each of the three-year performance periods. The inputs used in the 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. For the RSUs granted in 2013 that were not subject to performance measures, the fair value was determined using the closing price on the date of grant. A summary of activity related to RSUs is as follows: 2015 2014 2013 Restricted Stock Units Weighted Average Grant Date Fair Value Per Share Restricted Stock Units Weighted Average Grant Date Fair Value Per Share Restricted Stock Units Weighted Average Grant Date Fair Value Per Share Nonvested, beginning of period 1,977,335 $ 15.29 1,331,753 $ 14.96 969,820 $ 22.70 Granted 2,626,930 3.59 1,195,388 16.84 969,919 13.23 Vested (721,038 ) 13.23 (354,692 ) 18.59 (468,925 ) 26.93 Forfeited (409,148 ) 10.63 (195,114 ) 16.53 (139,061 ) 16.50 Nonvested, end of period 3,474,079 $ 7.42 1,977,335 $ 15.29 1,331,753 $ 14.96 Subject to the satisfaction of service conditions, the RSUs outstanding as of December 31, 2015 are eligible to vest in the year indicated in the table below: Restricted Stock Units 2016 1,003,604 2017 2,470,475 Total 3,474,079 RSUs fair value at grant date: RSUs fair value at vested date: Common Stock An issuance of 37,316 shares of common stock was made in March 2015 to the CEO pursuant to the terms of his 2014 annual incentive compensation award, which valued the shares at a predetermined price. The number of shares was determined after deductions for withholding and payroll taxes and the shares were valued at the Company’s closing price as of the date of issuance. A grant and issuance of 42,547 shares of common stock was made in March 2014 to the CEO pursuant to the terms of his 2013 annual incentive compensation award. The number of shares was determined after deductions for withholding and payroll taxes and the shares were valued at the Company’s closing price as of the date of grant. See Note 10 for additional information concerning the CEO annual incentive compensation award. Share-Based Compensation A summary of compensation expense under share-based payment arrangements and the related tax benefit is as follows (in thousands): Year Ended December 31, 2015 2014 2013 Share-based compensation expense from: Restricted stock $ 358 $ 369 $ 397 Restricted stock units 9,978 13,150 11,128 Common shares (94 ) 1,225 — Total $ 10,242 $ 14,744 $ 11,525 Share-based compensation tax benefit: Tax benefit computed at the statutory rate $ 3,585 $ 5,160 $ 4,034 As of December 31, 2015, unrecognized share-based compensation expense related to our awards of Restricted Shares and RSUs was $0.5 million and $12.7 million, respectively. Unrecognized compensation expense will be recognized through April 2018 for restricted shares and November 2017 for RSUs. Cash-based Incentive Compensation As defined by the Plan, annual incentive awards payable in cash may be granted to eligible employees. These awards are performance-based awards consisting of one or more business criteria or individual performance criteria and a targeted level or levels of performance with respect to each of such criteria. Generally, the performance period is the calendar year and determination and payment is made in cash in the first quarter of the following year, although the 2015 awards were designed with an additional financial condition that may be satisfied prior to December 31, 2017. Share-Based Compensation and Cash-Based Incentive Compensation Expense A summary of incentive compensation expense is as follows (in thousands): Year Ended December 31, 2015 2014 2013 Share-based compensation included in: General and administrative $ 10,242 $ 14,744 $ 11,525 Cash-based incentive compensation included in: Lease operating expense 364 3,285 3,482 General and administrative (1) (233 ) 6,950 8,817 Total charged to operating income $ 10,373 $ 24,979 $ 23,824 (1) Adjustments to true up estimates to actual payments resulted in net credit balances to expense for 2015 .

Employee Benefit Plan

Employee Benefit Plan	12 Months Ended
	Dec. 31, 2015
Compensation And Retirement Disclosure [Abstract]
Employee Benefit Plan	12. Employee Benefit Plan We maintain a defined contribution benefit plan in compliance with Section 401(k) of the IRC (the “401(k) Plan”), which covers those employees who meet the 401(k) Plan’s eligibility requirements. During 2015, 2014 and 2013, the Company’s matching contribution was 100% of each participant’s contribution up to a maximum of 6% of the participant’s eligible compensation, subject to limitations imposed by the IRC. The 401(k) Plan provides 100% vesting in Company match contributions on a pro rata basis over five years of service (20% per year). Our expenses relating to the 401(k) Plan were $2.3 million, $2.4 million and $2.1 million for 2015, 2014 and 2013, respectively.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	13. Income Taxes Income Tax Expense (Benefit) Components of income tax expense (benefit) were as follows (in thousands): Year Ended December 31, 2015 2014 2013 Current $ 288 $ 301 $ (2,146 ) Deferred (203,272 ) (4,760 ) 30,920 $ (202,984 ) $ (4,459 ) $ 28,774 Effective Tax Rate Reconciliation The reconciliation of income taxes computed at the U.S. federal statutory tax rate to our income tax expense (benefit) is as follows (in thousands): Year Ended December 31, 2015 2014 2013 Income tax expense (benefit) at the federal statutory rate $ (436,696 ) 35.0 % $ (5,642 ) 35.0 % $ 28,033 35.0 % Share-based compensation 2,940 (0.2 ) — — — — State income taxes (2,343 ) 0.2 263 (1.6 ) 343 0.4 Valuation allowance 232,925 (18.7 ) — — — — Other 190 - 920 (5.7 ) 398 0.5 $ (202,984 ) 16.3 % $ (4,459 ) 27.7 % $ 28,774 35.9 % Our effective tax rate for the year 2015 differed from the federal statutory rate of 35.0% primarily due to recording a valuation allowance for our deferred tax assets, which is discussed below. Our effective tax rate for the year 2014 is distorted due to a small pre-tax loss; consequently, our permanent differences have a larger impact on our effective tax rate. Our effective tax rate for the year 2013 differed from the federal statutory rate primarily as a result of state income taxes. Deferred Tax Assets and Liabilities Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of our deferred tax assets and liabilities were as follows (in thousands): December 31, 2015 2014 Deferred tax liabilities: Property and equipment $ 40,287 $ 518,566 Derivatives 2,697 — Other 3,000 5,019 Total deferred tax liabilities 45,984 523,585 Deferred tax assets: Alternative minimum tax credit 20,486 20,486 Asset retirement obligations 133,018 137,597 Federal net operating losses 145,733 180,024 State net operating losses 5,068 5,008 Valuation allowance (237,275 ) (4,255 ) Accrued cash-based bonus — 3,559 Share-based compensation 4,245 5,042 Other 2,304 798 Total deferred tax assets 73,579 348,259 Net deferred tax asset (liabilities) $ 27,595 $ (175,326 ) During 2015, we did not make any payments for federal and state income taxes or receive any refunds of significance. During 2014, we did not make any payments for federal and state income taxes and we received refunds of $3.0 million. During 2013, we made payments primarily for federal and state income taxes of approximately $3.0 million. During 2013, we received refunds of $59.1 million, of which $9.5 million have been accounted for as unrecognized tax benefits. The refunds were primarily attributable to tax loss carrybacks to 2010 and 2011, and refunds of estimated tax payments. Net Operating Loss and Tax Credit Carryovers The table below presents the details of our net operating loss and tax credit carryovers as of December 31, 2015 (in thousands): Amount Expiration Year Federal net operating loss $ 418,417 2032-2035 State net operating losses 100,651 2021-2029 Alternative minimum tax credit 12,091 Indefinite General business credit 406 2027-2028 The federal net operating loss and alternative minimum tax credit amounts presented in the table, Deferred Tax Assets and Liabilities Valuation Allowance During 2015, we recorded a valuation allowance of $232.9 million 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. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized. As of December 31, 2015 we had a valuation allowance related to Federal, Louisiana and Alabama net operating losses and other deferred taxes. As of December 31, 2014, we had a valuation allowance related only to Louisiana net operating losses. Uncertain Tax Positions The table below sets forth the beginning and ending balance of the total amount of unrecognized tax benefits. There are no unrecognized benefits that would impact the effective tax rate if recognized. While amounts could change in the next 12 months, we do not anticipate it having a material impact on our financial statements. Balances in the uncertain tax positions are as follows (in thousands): December 31, 2015 2014 Balance, beginning and end of period $ 9,482 $ 9,482 We recognize interest and penalties related to uncertain tax positions in income tax expense. For 2015, 2014 and 2013, the amounts recognized in income tax expense were immaterial. Years open to examination The tax years from 2012 through 2015 remain open to examination by the tax jurisdictions to which we are subject.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Earnings Per Share	14. Earnings Per Share The Company’s unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are deemed participating securities and are included in the computation of earnings per share under the two-class method. The following table presents the calculation of basic and diluted earnings per common share (in thousands, except per share amounts): Year Ended December 31, 2015 2014 2013 Net income (loss) $ (1,044,718 ) $ (11,661 ) $ 51,322 Less portion allocated to nonvested shares — 269 303 Net income (loss) allocated to common shares $ (1,044,718 ) $ (11,930 ) $ 51,019 Weighted average common shares outstanding 75,931 75,609 75,239 Basic and diluted earnings (loss) per common share $ (13.76 ) $ (0.16 ) $ 0.68 Shares excluded due to being anti-dilutive (weighted-average) 2,195 2,097 —

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	15. Supplemental Cash Flow Information The following reflects our supplemental cash flow information (in thousands): Year Ended December 31, 2015 2014 2013 Cash paid for interest, net of interest capitalized of $7,256 in 2015, $8,526 in 2014 and $10,058 in 2013 $ 92,622 $ 77,607 $ 73,909 Cash paid for income taxes 390 — 3,000 Cash refunds received for income taxes 90 3,000 59,126 Cash paid for share-based compensation (1) — 431 466 (1) The cash paid for share-based compensation is for dividends on unvested restricted stock and for dividend equivalents paid on RSUs. No cash was received from employees or directors related to share-based compensation and no cash was used to settle any equity instruments granted under share-based compensation arrangements.

Commitments

Commitments	12 Months Ended
	Dec. 31, 2015
Leases [Abstract]
Commitments	16. Commitments We have operating lease agreements for office space and office equipment. The lease for the majority of our office space terminates in December 2022. Minimum future lease payments due under noncancelable operating leases with terms in excess of one year as of December 31, 2015 are as follows: 2016–$1.6 million; 2017–$1.6 million; 2018–$1.7 million; 2019–$1.8 million thereafter–$5.7 million. Total rent expense was approximately $3.3 million, $3.2 million and $2.6 million during 2015, 2014 and 2013, respectively. Pursuant to the Purchase and Sale Agreement with Total E&P, we are required to fulfill security requirements related to ARO for certain properties through bonds or making payments to an escrow account or a combination. As of December 31, 2015, we were in compliance with the security amount requirement of $73.0 million. Additional security requirements are $6.0 million in 2016, $4.0 million in 2017, $5.0 million in 2018, $3.0 million in 2019 and $12.0 million in the 2020 to 2023 time period to a total security requirement of $103.0 million by 2023. Pursuant to the Purchase and Sale agreement with Shell Offshore Inc. (“Shell”) related to ARO for certain properties, we have bonds that are subject to re-appraisal by either party after November 2015. As of December 31, 2015, neither party had requested a re-appraisal to be made. The current security requirement of $64.0 million could be increased up to $94.0 million depending on certain conditions and circumstances. During 2015, 2014 and 2013, we had surety bonds related to our decommissioning obligations or ARO, with the BOEM named as beneficiary. See Note 20 for information concerning a demands received by the BOEM in February and March 2016. Total expenses related to surety bonds, inclusive of the surety bonds in connection with Total E&P, Shell and the BOEM described above, were $5.5 million, $4.1 million and $5.0 million during 2015, 2014 and 2013, respectively. The amount of future commitments is dependent on rates charged in the market place and when asset retirements are completed. Estimated future expenses related to surety bonds were based on current market prices and estimates of the timing of asset retirements, of which some wells and structures are estimated to extend to 2030. Future costs are estimated as follows: 2016–$5.8 million; 2017–$5.9 million; 2018–$5.3 million; 2019–$5.0 million; thereafter–$30.4 million. See Note 20 for information concerning a demand received by the BOEM in February and March 2016, which will impact future cost estimates related to surety bonds. Pursuant to an agreement with the Helix Well Containment Group, we are required to make payments to have access to certain equipment to respond to a subsea spill should a spill occur at a property we operate. As of December 31, 2015, future payments due are $2.1 million in 2016 and $2.1 million in 2017. These payments may increase or decrease depending on whether the number of companies participating in the consortium changes. We have no drilling rig commitments with a term that exceeded one year as of December 31, 2015 and our drilling rig commitments meet the criteria of an operating lease. Future payments of all drilling rig commitments as of December 31, 2015 were $7.0 million.

Related Parties

Related Parties	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Parties	17. Related Parties During 2015, 2014 and 2013, there were certain transactions between us and other companies our majority shareholder either controlled or in which he had an ownership interest. In addition, there were transactions with a company that employs the spouse of our majority shareholder. Our majority shareholder owns an aircraft that the Company used and reimbursed him for such use and for his use. Airplane services were charged to us at rates that were either equal to or below rates charged by non-related, third-party companies. Airplane services transactions were approximately $1.1 million, $0.9 million and $1.2 million for the years 2015, 2014 and 2013, respectively. Our majority shareholder has ownership interests in certain wells operated by us (such ownership interests pre-date our initial public offering). Revenues are disbursed and expenses are collected in accordance with ownership interest. Proportionate insurance premiums were paid to us and proportionate collections of insurance reimbursements attributable to damage on certain wells were disbursed. W&T hired the services of a directional drilling services company, in which our majority shareholder owns a minority ownership interest and serves on its board of directors, and W&T paid no amounts in 2015 and paid $0.2 million and $0.2 million for drilling related services during 2014 and 2013, respectively. A company that provides marine transportation and logistics services to W&T employs the spouse of our majority shareholder. The spouse received commissions partially based on services rendered to W&T which totaled less than $0.2 million per year for 2015, 2014 and 2013. During 2015, an entity controlled by our majority shareholder participated in the 9.00% Term Loan for a $5.0 million principal commitment on the same terms as the other lenders.

Contingencies

Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
Contingencies	18. Contingencies Supplemental bonding requirements by the BOEM The significant reductions in crude oil and natural gas pricing since the middle of 2014 have adversely impacted our financial strength and have resulted in our inability to meet the relevant financial strength and reliability criteria set forth in the BOEM Notice To Lessee #2008-N07, Supplemental Bond Procedures The issuers of such surety bonds may request, and in some cases, have requested, collateral, which could be significant and could impact our liquidity. In addition, pursuant to the terms of our agreements with various sureties under our existing bonds or under any additional bonds we may obtain, we are required to post collateral at any time, on demand, at the surety’s discretion. 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, which we believe has been subsequently reduced to $1.1 million due to revisions in the penalty calculation. We believe the fine is excessive and extreme 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 notice. We intend to contest the fine to the fullest extent possible. The ultimate resolution may result in a waiver of the fine, a reduction of the fine, or payment of the full amount plus interest covering several years. As no amount has been determined as more likely than any other within the range of possible resolutions, no amount has been accrued as of December 31, 2015 or 2014. 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 , 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 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 attorney 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 $43 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., has paid their portion of the first excess liability policy (approximately $5 million), including interest, although the commencement date of the interest calculation is under discussion. 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. Oil and natural gas properties and equipment 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 2016. 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 2015, the Company received four final notices from 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 as of December 31, 2015, 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. Iberville School Board Lawsuit In August, 2013, a citation was issued on behalf of plaintiffs, the State of Louisiana and the Iberville Parish School Board in their suit against the Company (among others) in the 18 th 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 was no material expenses recognized related to accrued and settled claims, complaints and fines for 2015, 2014 or 2013. As of December 31, 2015 and 2014, we had no material amounts recorded in liabilities for claims, complaints and fines.

Selected Quarterly Financial Da

Selected Quarterly Financial Data	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Selected Quarterly Financial Data	19. Selected Quarterly Financial Data—UNAUDITED Unaudited quarterly financial data are as follows (in thousands, except per share amounts): 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Year Ended December 31, 2015 Revenues $ 127,907 $ 149,066 $ 126,228 $ 104,064 Operating loss (1) (337,508 ) (278,806 ) (468,573 ) (60,816 ) Net loss (1) (255,095 ) (260,449 ) (477,568 ) (51,606 ) Basic and diluted loss per common share (1) (2) (3.36 ) (3.43 ) (6.29 ) (0.68 ) Year Ended December 31, 2014 Revenues $ 254,516 $ 262,994 $ 234,521 $ 196,677 Operating income (loss) 37,225 34,403 20,983 (30,543 ) Net income (loss) 11,189 9,837 684 (33,371 ) Basic and diluted earnings (loss) per common share (2) 0.15 0.13 0.01 (0.44 ) (1) During 2015, we recorded in first, second, third and fourth quarter ceiling test write-downs of oil and natural gas properties of $260.4 million, $252.8 million, $441.6 million and $32.4 million, respectively. See Note 1 for additional information. (2) The sum of the individual quarterly earnings (loss) per share may not agree with the year loss per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
Subsequent Events	20. Subsequent Events On February 26, 2016, we announced that we had borrowed $340.0 million under the Credit Agreement for general corporate purposes. Our cash balance after the borrowing was approximately $447.0 million and $9.1 million was the remaining availability under the Credit Agreement. In February and March 2016, we received several demands from the BOEM ordering the Company to secure financial assurances in the form of additional surety bonds in the aggregate of $260.8 million to cover our decommissioning obligations under certain Federal offshore oil and gas leases and rights of way operated by us. The bonds are to be secured on or before March 29, 2016. The issuance of any additional surety bonds to satisfy this order could require the posting of cash collateral or letters of credit, which could be substantial. The BOEM demand states that failure to comply with their order may result in the BOEM taking enforcement action, which includes assessing civil penalties, ordering suspension of operations or production, or initiating procedures to cancel leases. We intend to continue discussions with the BOEM to resolve our issues concerning supplemental financial assurances, and if after review of this order the Company deems it necessary and appropriate, we may exercise our rights to appeal to the Interior Board of Land Appeals or otherwise challenge this order.

Supplemental Guarantor Informat

Supplemental Guarantor Information	12 Months Ended
	Dec. 31, 2015
Supplemental Guarantor Information [Abstract]
Supplemental Guarantor Information	W&T OFFSHORE, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 21. Supplemental Guarantor Information Our payment obligations under the 8.50% Senior Notes, the 9.00% Term Loan and the Credit Agreement (see Note 7) are fully and unconditionally guaranteed by our 100%-owned subsidiaries, W & T Energy VI, LLC and W & T Energy VII, LLC (together, the “Guarantor Subsidiaries”). W & T Energy VII, LLC does not currently have any active operations or contain any assets. Guarantees of the 8.50% Senior Notes will be released under certain circumstances, including: (1) in connection with any sale or other disposition of all or substantially all of the assets of a Guarantor Subsidiary (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary (as such term is defined in the indenture governing the 8.50% Senior Notes) of the Company, if the sale or other disposition does not violate the Asset Sales provisions (as such terms are define in certain debt documents); (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 certain debt documents 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 indenture; (5) upon the liquidation or dissolution of such Guarantor Subsidiary, provided no event of default has occurred and is continuing; or (6) at such time as such Guarantor Subsidiary is no longer required to be a Guarantor Subsidiary 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. Included in the consolidating adjustments was an adjustment related to the ceiling test write-down, as the computation is performed for each subsidiary on a stand-alone basis and also for the consolidated Company. This resulted in write-downs for the combined subsidiaries to be greater than computed on a total Company basis, which required a contra ceiling test write-down adjustment to present the consolidated results appropriately. When transfers of property were made from the Parent Company to the Guarantor Subsidiaries, which were transactions between entities under common control, the prior period financial information was 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 December 31, 2015 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Assets Current assets: Cash and cash equivalents $ 85,414 $ — $ — $ 85,414 Receivables: Oil and natural gas sales 2,742 32,263 — 35,005 Joint interest and other 121,190 — (99,178 ) 22,012 Total receivables 123,932 32,263 (99,178 ) 57,017 Prepaid expenses and other assets 25,375 1,504 — 26,879 Total current assets 234,721 33,767 (99,178 ) 169,310 Property and equipment – at cost: Oil and natural gas properties and equipment 5,682,793 2,219,701 — 7,902,494 Furniture, fixtures and other 20,802 — — 20,802 Total property and equipment 5,703,595 2,219,701 — 7,923,296 Less accumulated depreciation, depletion and amortization 5,258,563 1,822,273 (147,589 ) 6,933,247 Net property and equipment 445,032 397,428 147,589 990,049 Deferred income taxes 27,251 344 — 27,595 Restricted deposits for asset retirement obligations 15,606 — — 15,606 Other assets 498,782 266,748 (760,068 ) 5,462 Total assets $ 1,221,392 $ 698,287 $ (711,657 ) $ 1,208,022 Liabilities and Shareholders’ Equity (Deficit) Current liabilities: Accounts payable $ 100,282 $ 9,515 $ — $ 109,797 Undistributed oil and natural gas proceeds 20,463 976 — 21,439 Asset retirement obligations 63,716 20,619 — 84,335 Accrued liabilities 11,922 99,178 (99,178 ) 11,922 Total current liabilities 196,383 130,288 (99,178 ) 227,493 Long-term debt, less current maturities 1,196,855 — — 1,196,855 Asset retirement obligations, less current portion 173,105 120,882 — 293,987 Deferred income taxes — — — — Other liabilities 329,129 — (312,951 ) 16,178 Shareholders’ equity: Common stock 1 — — 1 Additional paid-in capital 423,499 704,885 (704,885 ) 423,499 Retained earnings (deficit) (1,073,413 ) (257,768 ) 405,357 (925,824 ) Treasury stock, at cost (24,167 ) — — (24,167 ) Total shareholders’ equity (deficit) (674,080 ) 447,117 (299,528 ) (526,491 ) Total liabilities and shareholders’ equity (deficit) $ 1,221,392 $ 698,287 $ (711,657 ) $ 1,208,022 Condensed Consolidating Balance Sheet as of December 31, 2014 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. 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 Prepaid expenses and other assets 28,728 7,619 — 36,347 Total current assets 237,099 33,041 (99,240 ) 170,900 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 966,112 357,992 (1,314,797 ) 9,307 Total assets $ 2,837,940 $ 1,265,605 $ (1,414,037 ) $ 2,689,508 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 1,352,120 — — 1,352,120 Asset retirement obligations, less current portion 235,876 118,689 — 354,565 Deferred income taxes 49,819 125,507 — 175,326 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 $ 2,837,940 $ 1,265,605 $ (1,414,037 ) $ 2,689,508 Condensed Consolidating Statement of Operations for the Year Ended December 31, 2015 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Revenues $ 290,212 $ 217,053 $ — $ 507,265 Operating costs and expenses: Lease operating expenses 126,189 66,576 — 192,765 Production taxes 3,002 — — 3,002 Gathering and transportation 9,209 7,948 — 17,157 Depreciation, depletion and amortization 201,154 172,214 — 373,368 Asset retirement obligations accretion 11,587 9,116 — 20,703 Ceiling test write-down of oil and natural gas properties 616,947 517,880 (147,589 ) 987,238 General and administrative expenses 39,009 34,101 — 73,110 Derivative gain (14,375 ) — — (14,375 ) Total costs and expenses 992,722 807,835 (147,589 ) 1,652,968 Operating loss (702,510 ) (590,782 ) 147,589 (1,145,703 ) Loss of affiliates (464,931 ) — 464,931 — Interest expense: Incurred 101,542 3,050 — 104,592 Capitalized (4,206 ) (3,050 ) — (7,256 ) Other (income) expense, net 4,663 — — 4,663 Loss before income tax benefit (1,269,440 ) (590,782 ) 612,520 (1,247,702 ) Income tax benefit (77,133 ) (125,851 ) — (202,984 ) Net loss $ (1,192,307 ) $ (464,931 ) $ 612,520 $ (1,044,718 ) Condensed Consolidating Statement of Operations for the Year Ended December 31, 2014 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Revenues $ 571,365 $ 377,343 $ — $ 948,708 Operating costs and expenses: Lease operating expenses 180,149 84,602 — 264,751 Production taxes 7,932 — — 7,932 Gathering and transportation 11,790 8,031 — 19,821 Depreciation, depletion, amortization and accretion 267,406 223,063 — 490,469 Asset retirement obligations accretion 10,981 9,652 — 20,633 General and administrative expenses 46,513 40,486 — 86,999 Derivative loss (3,965 ) — — (3,965 ) Total costs and expenses 520,806 365,834 — 886,640 Operating income 50,559 11,509 — 62,068 Earnings of affiliates 8,320 — (8,320 ) — Interest expense: Incurred 84,460 2,462 — 86,922 Capitalized (6,064 ) (2,462 ) — (8,526 ) Other (income) expense, net (208 ) — — (208 ) Income (loss) before income tax expense (19,309 ) 11,509 (8,320 ) (16,120 ) Income tax expense (benefit) (7,648 ) 3,189 — (4,459 ) Net income (loss) $ (11,661 ) $ 8,320 $ (8,320 ) $ (11,661 ) Condensed Consolidating Statement of Operations for the Year Ended December 31, 2013 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Revenues $ 631,267 $ 352,821 $ — $ 984,088 Operating costs and expenses: Lease operating expenses 202,096 68,743 — 270,839 Production taxes 7,135 — — 7,135 Gathering and transportation 9,248 8,262 — 17,510 Depreciation, depletion and amortization 236,600 194,011 — 430,611 Asset retirement obligations accretion 14,218 6,700 — 20,918 General and administrative expenses 44,040 37,834 — 81,874 Derivative loss 8,470 — — 8,470 Total costs and expenses 521,807 315,550 — 837,357 Operating income 109,460 37,271 — 146,731 Earnings of affiliates 24,400 — (24,400 ) — Interest expense: Incurred 82,570 3,069 — 85,639 Capitalized (6,989 ) (3,069 ) — (10,058 ) Other (income) expense, net (8,946 ) — — (8,946 ) Income before income tax expense 67,225 37,271 (24,400 ) 80,096 Income tax expense 15,903 12,871 — 28,774 Net income $ 51,322 $ 24,400 $ (24,400 ) $ 51,322 Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2015 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Operating activities: Net loss $ (1,192,307 ) $ (464,931 ) $ 612,520 $ (1,044,718 ) Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Depreciation, depletion, amortization and accretion 212,741 181,330 — 394,071 Ceiling test write-down of oil and gas properties 616,947 517,880 (147,589 ) 987,238 Debt issuance costs write-off/amortization of debt items 4,411 — — 4,411 Share-based compensation 10,242 — — 10,242 Derivative gain (14,375 ) — — (14,375 ) Cash receipts on derivative settlements, net 6,703 — — 6,703 Deferred income taxes (77,421 ) (125,851 ) — (203,272 ) Loss of affiliates 464,931 — (464,931 ) — Changes in operating assets and liabilities: Oil and natural gas receivables 39,078 (6,842 ) — 32,236 Joint interest and other receivables 21,633 — — 21,633 Income taxes (7 ) — — (7 ) Prepaid expenses and other assets (13,916 ) 122,977 (91,245 ) 17,816 Asset retirement obligation settlements (26,637 ) (5,918 ) — (32,555 ) Accounts payable, accrued liabilities and other (142,270 ) 4,156 91,245 (46,869 ) Net cash provided by (used in) operating activities (90,247 ) 222,801 — 132,554 Investing activities: Investment in oil and natural gas properties and equipment (31,534 ) (198,627 ) — (230,161 ) Changes in operating assets and liabilities associated with investing activities (29,806 ) (25,619 ) — (55,425 ) Proceeds from sales of assets and other, net 372,939 — — 372,939 Investment in subsidiary (1,445 ) — 1,445 — Purchases of furniture, fixtures and other (1,278 ) — — (1,278 ) Net cash used in investing activities 308,876 (224,246 ) 1,445 86,075 Financing activities: Borrowings of long-term debt – revolving bank credit facility 263,000 — — 263,000 Repayments of long-term debt – revolving bank credit facility (710,000 ) — — (710,000 ) Issuance of 9.00% Term Loan 297,000 — — 297,000 Debt issuance costs (6,669 ) — — (6,669 ) Other (212 ) — — (212 ) Investment from parent — 1,445 (1,445 ) — Net cash provided by financing activities (156,881 ) 1,445 (1,445 ) (156,881 ) Decrease in cash and cash equivalents 61,748 — — 61,748 Cash and cash equivalents, beginning of period 23,666 — — 23,666 Cash and cash equivalents, end of period $ 85,414 $ — $ — $ 85,414 Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2014 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Operating activities: Net income (loss) $ (11,661 ) $ 8,320 $ (8,320 ) $ (11,661 ) Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion, amortization and accretion 278,387 232,715 — 511,102 Amortization of debt issuance costs and premium 701 — — 701 Share-based compensation 14,744 — — 14,744 Derivative gain (3,965 ) — — (3,965 ) Cash payments on derivative settlements (5,318 ) — — (5,318 ) Deferred income taxes (32,456 ) 27,696 — (4,760 ) Earnings of affiliates (8,320 ) — 8,320 — Changes in operating assets and liabilities: Oil and natural gas receivables 19,553 9,957 — 29,510 Joint interest and other receivables (4,255 ) — — (4,255 ) Income taxes 27,650 (24,507 ) — 3,143 Prepaid expenses and other assets 45,962 (7,525 ) (23,425 ) 15,012 Asset retirement obligations (57,253 ) (17,060 ) — (74,313 ) Accounts payable, accrued liabilities and other 11,083 (30,475 ) 23,425 4,033 Net cash provided by operating activities 274,852 199,121 — 473,973 Investing activities: Acquisition of property interest in oil and natural gas properties (17,407 ) (54,827 ) — (72,234 ) Investment in oil and natural gas properties and equipment (312,044 ) (242,334 ) — (554,378 ) Changes in operating assets and liabilities associated with investing activities 1,733 35,717 — 37,450 Investment in subsidiary (62,323 ) — 62,323 — Purchases of furniture, fixtures and other (3,340 ) — — (3,340 ) Net cash used in investing activities (393,381 ) (261,444 ) 62,323 (592,502 ) Financing activities: Borrowings of long-term debt – revolving bank credit facility 556,000 — — 556,000 Repayments of long-term debt – revolving bank credit facility (399,000 ) — — (399,000 ) Dividends to shareholders (30,260 ) — — (30,260 ) Other (345 ) — — (345 ) Investment from parent — 62,323 (62,323 ) — Net cash provided in financing activities 126,395 62,323 (62,323 ) 126,395 Increase in cash and cash equivalents 7,866 — — 7,866 Cash and cash equivalents, beginning of period 15,800 — — 15,800 Cash and cash equivalents, end of period $ 23,666 $ — $ — $ 23,666 Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2013 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Operating activities: Net income $ 51,322 $ 24,400 $ (24,400 ) $ 51,322 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion, amortization and accretion 250,818 200,711 — 451,529 Amortization of debt issuance costs and premium 1,645 — — 1,645 Share-based compensation 11,525 — — 11,525 Derivative loss 8,470 — — 8,470 Cash payments on derivative settlements (8,589 ) — — (8,589 ) Deferred income taxes 7,564 23,356 — 30,920 Earnings of affiliates (24,400 ) — 24,400 — Changes in operating assets and liabilities: Oil and natural gas receivables 6,182 (5,202 ) — 980 Joint interest and other receivables 34,257 — — 34,257 Income taxes 54,813 (10,485 ) — 44,328 Prepaid expenses and other assets (25,329 ) (18,835 ) 34,120 (10,044 ) Asset retirement obligations (65,438 ) (16,105 ) — (81,543 ) Accounts payable, accrued liabilities and other 74,693 (12,665 ) (34,120 ) 27,908 Net cash provided by operating activities 377,533 185,175 — 562,708 Investing activities: Acquisition of property interest in oil and natural gas properties — (82,424 ) — (82,424 ) Investment in oil and natural gas properties and equipment (349,804 ) (202,150 ) — (551,954 ) Changes in operating assets and liabilities associated with investing activities (14,732 ) 13,382 (1,350 ) Investment in subsidiary (86,017 ) — 86,017 - Proceeds from sales of assets and other, net 21,008 — — 21,008 Purchases of furniture, fixtures and other (1,435 ) — — (1,435 ) Net cash used in investing activities (430,980 ) (271,192 ) 86,017 (616,155 ) Financing activities: Borrowings of long-term debt – revolving bank credit facility 563,000 — — 563,000 Repayments of long-term debt – revolving bank credit facility (443,000 ) — — (443,000 ) Debt issuance costs (3,892 ) — — (3,892 ) Dividends to shareholders (58,846 ) — — (58,846 ) Other (260 ) — — (260 ) Investment from parent — 86,017 (86,017 ) — Net cash used in financing activities 57,002 86,017 (86,017 ) 57,002 Increase in cash and cash equivalents 3,555 — — 3,555 Cash and cash equivalents, beginning of period 12,245 — — 12,245 Cash and cash equivalents, end of period $ 15,800 $ — $ — $ 15,800

Supplemental Oil and Gas Disclo

Supplemental Oil and Gas Disclosures-unaudited	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
Supplemental Oil and Gas Disclosures-unaudited	22. Supplemental Oil and Gas Disclosures—UNAUDITED Geographic Area of Operation All of our proved reserves are located within the United States, with a majority of those reserves located in the Gulf of Mexico and a minority located in Texas. Therefore, the following disclosures about our costs incurred, results of operations and proved reserves are on a total-company basis. Capitalized Costs Net capitalized costs related to our oil, NGLs and natural gas producing activities are as follows (in millions): December 31, 2015 2014 2013 Net capitalized cost: Proved oil and natural gas properties and equipment $ 7,882.3 $ 7,924.2 $ 7,207.1 Unproved oil and natural gas properties and equipment 20.2 121.5 132.0 Accumulated depreciation, depletion and amortization (1) related to oil, NGLs and natural gas activities (6,916.2 ) (5,557.6 ) (5,069.2 ) Net capitalized costs related to producing activities $ 986.3 $ 2,488.1 $ 2,269.9 (1) Includes ceiling test write-down in 2015. Costs Not Subject To Amortization Costs not subject to amortization relate to unproved properties which are excluded from amortizable capital costs until it is determined that proved reserves can be assigned to such properties or until such time as the Company has made an evaluation that impairment has occurred. Subject to industry conditions, evaluation of most of these properties is expected to be completed within one to five years. The following table provides a summary of costs that are not being amortized as of December 31, 2015, by the year in which the costs were incurred (in millions): Total 2015 2014 2013 Prior to 2013 Costs excluded by year incurred: Acquisition costs $ 13.9 $ — $ 0.5 $ 4.9 $ 8.5 Capitalized interest not subject to amortization 4.7 1.5 1.2 0.9 1.1 Total costs not subject to amortization $ 18.6 $ 1.5 $ 1.7 $ 5.8 $ 9.6 Costs Incurred In Oil and Gas Property Acquisition, Exploration and Development Activities The following costs were incurred in oil and gas acquisition, exploration, and development activities (in millions): Year Ended December 31, 2015 2014 2013 Costs incurred: (1) Proved properties acquisitions $ 15.6 $ 111.5 $ 96.9 Exploration (2) (3) 152.4 411.1 215.3 Development 65.5 198.7 352.9 Unproved properties acquisitions (4) 0.1 3.1 26.3 Total costs incurred in oil and gas property acquisition, exploration and development activities $ 233.6 $ 724.4 $ 691.4 (1) Includes net reductions from capitalized ARO of $0.4 million in 2015 and net additions from capitalized ARO of $88.0 million and $50.6 million during 2014 and 2013, respectively, associated with acquisitions, liabilities incurred, divestitures and revisions of estimates. (2) Includes seismic costs of $3.2 million, $9.0 million and $8.9 million incurred during 2015, 2014 and 2013, respectively. (3) Includes geological and geophysical costs charged to expense of $5.7 million, $7.3 million and $5.9 million during 2015, 2014 and 2013, respectively. (4) The amounts for unproved property acquisitions include capitalized interest associated with unproved properties acquired during the period. Depreciation, depletion, amortization and accretion expense The following table presents our depreciation, depletion, amortization and accretion expense per barrel equivalent (“Boe”) of products sold. Year Ended December 31, 2015 2014 2013 Depreciation, depletion, amortization and accretion per Boe $ 23.11 $ 28.98 $ 25.10 Oil and Natural Gas Reserve Information There are numerous uncertainties in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve information represent estimates only and are inherently imprecise and may be subject to substantial revisions as additional information such as reservoir performance, additional drilling, technological advancements and other factors become available. Decreases in the prices of oil, NGLs and natural gas could have an adverse effect on the carrying value of our proved reserves, reserve volumes and our revenues, profitability and cash flow. We are not the operator with respect to approximately 27% of our proved developed non-producing reserves and 12% of our proved undeveloped reserves, so we may not be in a position to control the timing of all development activities. The following sets forth estimated quantities of our net proved, proved developed and proved undeveloped oil, NGLs and natural gas reserves. All of the reserves are located in the Unites States with all located in state and federal waters in the Gulf of Mexico. The reserve estimates exclude insignificant royalties and interests owned by the Company due to the unavailability of such information. In addition to other criteria, estimated reserves are assessed for economic viability based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for the year in accordance with definitions and guidelines set forth by the SEC and the FASB. The prices used do not purport, nor should it be interpreted, to present the current market prices related to our estimated oil and natural gas reserves. Actual future prices and costs may differ materially from those used in determining our proved reserves for the periods presented. The prices used are presented in the section below entitled “ Standardized Measure of Discounted Future Net Cash Flows”. Total Energy Equivalent Reserves (1) Oil (MMBbls) NGLs (MMBbls) Natural Gas (Bcf) Oil Equivalent (MMBoe) Natural Gas Equivalent (Bcfe) Proved reserves as of Dec. 31, 2012 54.8 15.2 285.1 117.5 705.1 Revisions of previous estimates (2) (4.3 ) 0.2 2.1 (3.8 ) (22.8 ) Extensions and discoveries (3) 13.9 2.6 22.0 20.2 121.0 Purchase of minerals in place (4) 1.5 — 4.4 2.3 13.7 Sales of reserves (5) (0.4 ) — (0.4 ) (0.5 ) (3.2 ) Production (7.0 ) (2.1 ) (53.3 ) (18.0 ) (107.9 ) Proved reserves as of Dec. 31, 2013 58.5 15.9 259.9 117.7 705.9 Revisions of previous estimates (6) 1.6 0.1 14.3 4.1 25.3 Extensions and discoveries (7) 7.3 0.7 10.1 9.7 58.1 Purchase of minerals in place (8) 1.5 1.2 20.7 6.1 36.5 Production (7.2 ) (2.1 ) (50.1 ) (17.6 ) (105.8 ) Proved reserves as of Dec. 31, 2014 61.7 15.8 254.9 120.0 720.0 Revisions of previous estimates (9) 4.8 (0.9 ) 4.9 4.7 28.0 Revisions related to sold properties (10) (12.1 ) (4.8 ) (2.9 ) (17.4 ) (104.3 ) Extensions and discoveries (11) 2.4 0.2 8.8 4.1 24.4 Purchase of minerals in place (12) — — 6.1 1.0 6.1 Sales of reserves (13) (13.5 ) (2.1 ) (20.2 ) (19.0 ) (113.8 ) Production (7.8 ) (1.6 ) (46.2 ) (17.0 ) (102.3 ) Proved reserves as of Dec. 31, 2015 35.5 6.6 205.4 76.4 458.1 Year-end proved developed reserves: 2015 29.4 6.4 198.5 69.0 413.5 2014 35.7 10.7 221.1 83.3 499.7 2013 36.2 11.1 232.7 86.1 516.1 Year-end proved undeveloped reserves: 2015 (14) 6.1 0.2 6.9 7.4 44.6 2014 26.0 5.1 33.8 36.7 220.3 2013 22.3 4.8 27.2 31.6 189.8 Volume measurements: Bbl – barrel Mcf – thousand cubic feet MMBbls – million barrels for crude oil, condensate or NGLs Bcf – billion cubic feet MMBoe – million barrels of oil equivalent Bcfe – billion cubic feet of gas equivalent (1) The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy-equivalent ratio of six Mcf of natural gas to one barrel of crude oil, condensate or NGLs (totals may not compute due to rounding). The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for crude oil, NGLs and natural gas may differ significantly. (2) Includes upward revision due to price of 1.9 MMBoe; negative revisions of 4.9 MMBoe at our Yellow Rose field for performance and technical changes, 2.3 MMBoe at our High Island 21/22 field for performance, 1.3 MMBoe at our Ship Shoal 349/359 field for performance; and positive performance revisions of 0.7 MMBoe at our Main Pass 98 field, 0.7 MMBoe at our South Timbalier 314, 0.6 MMBoe at our Main Pass 108 field and 0.5 MMBoe our South Timbalier 176 field. (3) Includes extensions and discoveries of 12.6 MMBoe at our Yellow Rose field, 4.2 MMBoe at our Ship Shoal 349 field and 1.9 MMBoe at our Mississippi Canyon 698 field. (4) Primarily due to the acquisition of the Callon Properties. (5) Primarily due to the sales of our non-working interests in the Green Canyon 60 field, the Green Canyon 19 field and the West Delta area block 29. (6) Includes upwards revisions due to price of 0.3 MMBoe; positive revisions of 2.4 MMBoe at our Fairway Field, 1.2 MMBoe at our Mississippi Canyon 800 field and 6.4 MMBoe at various fields; and negative revisions of 3.9 MMBoe at our Yellow Rose field and 2.4 MMBoe at various other fields. (7) Includes extensions and discoveries of 4.1 MMBoe at our Yellow Rose field and 4.1 MMBoe at our Mississippi Canyon 782 field. (8) Primarily due to acquiring additional ownership in the Fairway Field and acquisition of the Woodside Properties. (9) Includes upwards revisions of 7.4 MMBoe at the Ship Shoal 349 field (Mahogany), 1.9 MMBoe at our Brazo A-133 field, 1.3 MMBoe at out Atwater 575 field, 1.3 MMBoe at out Mississippi Canyon 243 field (Matterhorn), 1.1 MMBoe at our Fairway Field, partially offset by downward revisions due to price of 10.7 MMBoe. The revision for price excludes the Yellow Rose field sold during 2015. (10) Revisions related to the Yellow Rose field during 2015, which were primarily due to price reductions, up to the date of the sale in October 2015. (11) Primarily due to increases at Ewing Bank 910. (12) Primarily due to purchase of additional interest at Brazos A-133. (13) Related primarily to the sale of the Yellow Rose field in October 2015, which had estimated reserves at the date of sale of 19.0 MMBoe. (14) We believe that we will be able to develop all but 1.2 MMBoe of the reserves classified as proved undeveloped (“PUDs”), or approximately 16%, out of the total of 7.4 MMBoe classified as PUDs at December 31, 2015, within five years from the date such reserves were initially recorded. The exception is at the Mississippi Canyon 243 field (Matterhorn) where the field is being developed using a single floating tension leg platform requiring an extended sequential development plan. The platform cannot support a rig that would allow additional wells to be drilled, but can support a rig to allow sidetracking of wells. A portion of the PUDs in this field were originally recorded in our reserves as of December 31, 2010. The development of these PUDs will be delayed until an existing well is depleted and available to sidetrack. Based on the latest reserve report, a well is expected to be drilled to develop the Mississippi Canyon 243 field (Matterhorn) PUDs in 2020. Standardized Measure of Discounted Future Net Cash Flows The following presents the standardized measure of discounted future net cash flows related to our proved oil and natural gas reserves together with changes therein. Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the unweighted average of first-day-of-the-month commodity prices for the periods presented. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. Due to the lack of a benchmark price for NGLs, a ratio is computed for each field of the NGLs realized price compared to the crude oil realized price. Then, this ratio is applied to the crude oil price using FASB/SEC guidance. The average commodity prices weighted by field production and after adjustments related to the proved reserves are as follows: December 31, 2015 2014 2013 2012 Oil - per barrel $ 46.94 $ 91.12 $ 99.65 $ 98.13 NGLs per barrel 17.60 34.63 35.21 47.30 Natural gas per Mcf 2.50 4.27 3.80 2.77 Future production, development costs and ARO are based on costs in effect at the end of each of the respective years with no escalations. Estimated future net cash flows, net of future income taxes, have been discounted to their present values based on a 10% annual discount rate. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair market value of our oil and natural gas reserves. These estimates reflect proved reserves only and ignore, among other things, future changes in prices and costs, revenues that could result from probable reserves which could become proved reserves in 2016 or later years and the risks inherent in reserve estimates. The standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves is as follows (in millions): Year Ended December 31, 2015 2014 2013 Standardized Measure of Discounted Future Net Cash Flows Future cash inflows $ 2,296.7 $ 7,258.5 $ 7,376.7 Future costs: Production (840.1 ) (2,224.5 ) (2,142.8 ) Development (161.4 ) (922.0 ) (1,001.4 ) Dismantlement and abandonment (471.8 ) (475.4 ) (441.6 ) Income taxes (1) — (948.4 ) (986.9 ) Future net cash inflows before 10% discount 823.4 2,688.2 2,804.0 10% annual discount factor (209.5 ) (985.4 ) (1,129.4 ) Total $ 613.9 $ 1,702.8 $ 1,674.6 (1) No future income taxes were estimated to be paid in 2015 as our present tax position has sufficient tax basis and net operating loss carrying forwards to offset any future taxes. State income taxes were disregarded due to immateriality. Year Ended December 31, 2015 2014 2013 Changes in Standardized Measure Standardized measure, beginning of year $ 1,702.8 $ 1,674.6 $ 1,846.4 Increases (decreases): Sales and transfers of oil and gas produced, net of production costs (289.1 ) (650.9 ) (686.1 ) Net changes in price, net of future production costs (1,455.6 ) (278.6 ) (65.2 ) Extensions and discoveries, net of future production and development costs 65.3 309.6 393.8 Changes in estimated future development costs (8.5 ) (56.4 ) (91.1 ) Previously estimated development costs incurred 158.9 263.1 262.1 Revisions of quantity estimates 137.9 118.6 (91.6 ) Accretion of discount 150.6 180.6 202.2 Net change in income taxes 600.8 (11.4 ) 56.6 Purchases of reserves in-place 6.0 86.7 79.6 Sales of reserves in-place (401.4 ) — (53.1 ) Changes in production rates due to timing and other (53.8 ) 66.9 (179.0 ) Net increase (decrease) in standardized measure (1,088.9 ) 28.2 (171.8 ) Standardized measure, end of year $ 613.9 $ 1,702.8 $ 1,674.6

Significant Accounting Polici30

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Operations	Operations W&T Offshore, Inc. and 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 2. 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 the parent company, W&T Offshore, Inc. (on a stand-alone basis, the “Parent Company”) and our wholly-owned subsidiary, W & T Energy VI, LLC (“Energy VI”).
Basis of Presentation	Basis of Presentation Our consolidated financial statements include the accounts of W&T Offshore, Inc. and its majority-owned subsidiaries. All significant intercompany transactions and amounts have been eliminated for all years presented. Our consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (“GAAP”) and the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”).
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, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates.
Early Adoption of Accounting Standard Amendments	Early Adoption of Accounting Standard Amendments Accounting Standards Update No. 2015-03 (“ASU 2015-03”), Interest – Imputation of Interest (Subtopic 835-30), Simplifying the Presentation of Debt Issuance Costs Accounting Standards Update No. 2015-17 (“ASU 2015-17”), Balance Sheet Classification of Deferred Taxes, Current assets Deferred income taxes liability
Reclassifications	Reclassifications Certain reclassifications have been made to prior periods’ financial statements to conform to the current presentation as follows: Within the Consolidated Statements of Cash Flows, adjustments were made for the changes in operating assets and liabilities associated with investing activities. The adjustments resulted in Net cash provided by operating activities and Net cash used in investing activities to be decreased by $37.5 million for 2014 and increased by $1.4 million for 2013. Similar adjustments were made in the Condensed Consolidating Statements of Cash flow totaling the same amounts for the respective years. The adjustments did not affect the Consolidated Balance Sheets or the Consolidated Statements of Operations.
Transactions Between Entities Under Common Control	Transactions between Entities under Common Control The prior period financial information for 2014 presented in Note 20, Supplemental Guarantor Information , has been retrospectively adjusted due to transactions between entities under common control, as required under authoritative guidance.
Recent Events	Recent Events The price we receive for our crude 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 2015 compared to the last few years. We have taken several steps during 2015 to mitigate the effects of these lower prices including: (i) significantly reducing 2015 capital spending from the previous year and budgeted further reductions in capital spending for 2016 (exclusive of acquisitions); (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; (v) entered into a second lien term loan (the “9.00% Term Loan”); (vi) entered into three Amendments to our Fifth Amended and Restated Credit Agreement (as amended, the “Credit Agreement”); and (vii) sold our interest in the Yellow Rose onshore field. See Notes 2 and Note 7 for additional information. In February 2016, we announced that we had borrowed $340.0 million under the Credit Agreement for general corporate purposes. Also, in February and March 2016, we received demands from the Bureau of Ocean Energy Management (“BOEM”) ordering us to secure financial assurances totaling approximately $260.8 million, with amounts specified by certain designated leases. See Note 20 for additional information. We have assessed our financial condition, the current capital markets and options given different scenarios of commodity prices and believe we will have adequate liquidity to fund our operations through December 31, 2016; however, we cannot predict how an extended period of low commodity prices or the impact of future bonding requirements will affect our operations and liquidity levels.
Cash Equivalents	Cash Equivalents We consider all highly liquid investments purchased with original or remaining maturities of three months or less at the date of purchase to be cash equivalents.
Revenue Recognition	Revenue Recognition We recognize oil and natural gas revenues based on the quantities of our production sold to purchasers under short-term contracts (less than 12 months) at market prices when delivery has occurred, title has transferred and collectability is reasonably assured. We use the sales method of accounting for oil and natural gas revenues from properties with joint ownership. Under this method, we record oil and natural gas revenues based upon physical deliveries to our customers, which can be different from our net revenue ownership interest in field production. These differences create imbalances that we recognize as a liability only when the estimated remaining recoverable reserves of a property will not be sufficient to enable the under-produced party to recoup its entitled share through production. We do not record receivables for those properties in which the Company has taken less than its ownership share of production. At December 31, 2015 and 2014, $6.9 million and $6.4 million, respectively, were included in current liabilities related to natural gas imbalances.
Concentration of Credit Risk	Concentration of Credit Risk Our customers are primarily large integrated oil and natural gas companies and large financial institutions. Our production is sold utilizing month-to-month contracts that are based on bid prices. We also have receivables from joint interest owners on properties we operate and we may have the ability to withhold future revenue disbursements to recover amounts due us. We attempt to minimize our credit risk exposure to purchasers of our oil and natural gas, joint interest owners, derivative counterparties and other third-party entities through formal credit policies, monitoring procedures, and letters of credit or guaranties when considered necessary. We historically have not had any significant problems collecting our receivables, but with the decline in commodity prices, several oil and gas companies have filed for bankruptcy. We use the specific identification method of determining if an allowance for doubtful accounts is needed. As of December 31, 2015 and 2014, we recorded $2.5 million and $0.7 million, respectively, in the allowance for doubtful accounts. During 2015 and 2014, there was no usage of the amounts recorded for allowance for doubtful accounts. The following identifies customers from whom we derived 10% or more of receipts from sales of crude oil, NGLs and natural gas. Year Ended December 31, 2015 2014 2013 Customer Shell Trading (US) Co. 50 % 47 % 48 % J. P. Morgan 14 % ** ** ** less than 10% We believe that the loss of any of the customers above would not result in a material adverse effect on our ability to market future oil and natural gas production as replacement customers could be obtained in a relatively short period of time on terms, conditions and pricing substantially similar to those currently existing.
Insurance Receivables	Insurance Receivables We recognize insurance receivables with respect to capital, repair and plugging and abandonment costs as a result of hurricane damage when we deem those to be probable of collection, which arises when our insurance underwriters’ adjuster reviews and approves such costs for payment by the underwriters. Claims that have been processed in this manner have customarily been paid on a timely basis. See Note 18 for information related to unpaid claims by certain underwriters.
Prepaid Expenses and Other	Prepaid expenses and other Amounts recorded in Prepaid expenses and other Year Ended December 31, 2015 2014 Derivative assets - current (1) $ 10,036 $ 7,417 Prepaid insurance and surety bonds 7,475 13,130 Prepaid deposits related to royalties 5,943 9,681 Other (2) 3,425 6,119 Prepaid expenses and other $ 26,879 $ 36,347 (1) Includes open and closed (and not yet collected) derivative commodity contracts recorded at fair value. (2) Individual items were less than 5% of total current assets for either period presented.
Properties and Equipment	Properties and Equipment We use the full-cost method of accounting for oil and natural gas properties and equipment. Under this method, all costs associated with the acquisition, exploration, development and abandonment of oil and natural gas properties are capitalized. Acquisition costs include costs incurred to purchase, lease or otherwise acquire properties. Exploration costs include costs of drilling exploratory wells and external geological and geophysical costs, which mainly consist of seismic costs. Development costs include the cost of drilling development wells and costs of completions, platforms, facilities and pipelines. Costs associated with production, certain geological and geophysical costs and general and administrative costs are expensed in the period incurred. Oil and natural gas properties and equipment include costs of unproved properties. The cost of unproved properties related to significant acquisitions are excluded from the amortization base until it is determined that proved reserves can be assigned to such properties or until such time as the Company has made an evaluation that impairment has occurred. The costs of drilling exploratory dry holes are included in the amortization base immediately upon determination that such wells are non-commercial. We capitalize interest on the amount of unproved properties that are excluded from the amortization base. Interest is capitalized only for the period that exploration and development activities are in progress. Capitalization of interest ceases when the property is moved into the amortization base. All capitalized interest is recorded within Oil and natural gas property and equipment Oil and natural gas properties included in the amortization base are amortized using the units-of-production method based on production and estimates of proved reserve quantities. In addition to costs associated with evaluated properties and capitalized asset retirement obligations (“ARO”), the amortization base includes estimated future development costs to be incurred in developing proved reserves as well as estimated plugging and abandonment costs, net of salvage value, related to developing proved reserves. Future development costs related to proved reserves are not recorded as liabilities on the balance sheet, but are part of the calculation of depletion expense. Sales of proved and unproved oil and natural gas properties, whether or not being amortized currently, 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. Furniture, fixtures and non-oil and natural gas property and equipment are depreciated using the straight-line method based on the estimated useful lives of the respective assets, generally ranging from five to seven years. Leasehold improvements are amortized over the shorter of their economic lives or the lease term. Repairs and maintenance costs are expensed in the period incurred.
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 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. The average price using the SEC required methodology at December 31, 2015 was $46.79 per barrel for West Texas Intermediate (“WTI”) crude oil and $2.59 per million British Thermal Unit (“MMBtu”) for Henry Hub natural gas. These prices are before adjustments for quality, transportation, fees, energy content and regional price differentials. The ceiling test write-downs of the carrying value of our oil and natural gas properties, which included $32.4 million in the fourth quarter of 2015, were $987.2 million for the full year of 2015. We did not record a ceiling test write-down during 2014 or 2013. If crude oil and natural gas prices remain or decrease from current levels, it is probable that a ceiling test write-down will be recorded in the first quarter of 2016 and possibly in subsequent quarters during 2016.
Asset Retirement Obligations	Asset Retirement Obligations We are required to record a separate liability for the present value of our ARO, with an offsetting increase to the related oil and natural gas properties on our balance sheet. We have significant obligations to plug and abandon well bores, remove our platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. These obligations are primarily associated with plugging and abandoning wells, removing pipelines, removing and disposing of offshore platforms and site cleanup. Estimating the future restoration and removal cost is difficult and requires us to make estimates and judgments because the removal obligations may be many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations, which can substantially affect our estimates of these future costs from period to period. For additional information, refer to Note 5.
Oil and Natural Gas Reserve Information	Oil and Natural Gas Reserve Information We use the unweighted average of first-day-of-the-month commodity prices over the preceding 12-month period when estimating quantities of proved reserves. Similarly, the prices used to calculate the standardized measure of discounted future cash flows and prices used in the ceiling test for impairment are the 12-month average commodity prices. Proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years, with some limited exceptions allowed. Refer to Note 21 for additional information about our proved reserves.
Derivative Financial Instruments	Derivative Financial Instruments Our market risk exposure relates primarily to commodity prices and interest rates. From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our credit facility. Our derivative instruments currently consist of commodity swap contracts for oil. We do not enter into derivative instruments for speculative trading purposes. Derivative instruments are recorded on the balance sheet as an asset or a liability at fair value. Changes in a derivative’s fair value are required to be recognized currently in earnings unless specific hedge accounting and documentation criteria are met at the time the derivative contract is entered into. We have elected not to designate our commodity derivatives as hedging instruments, therefore, all changes in fair value are recognized in earnings.
Fair Value of Financial Instruments	Fair Value of Financial Instruments We include fair value information in the notes to our consolidated financial statements when the fair value of our financial instruments is different from the book value or it is required by applicable guidance. We believe that the book value of our cash and cash equivalents, receivables, accounts payable and accrued liabilities materially approximates fair value due to the short-term nature and the terms of these instruments. We believe that the book value of our restricted deposits approximates fair value as deposits are in cash or short-term investments. We believe 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.
Fair Value of Acquisitions	Fair Value of Acquisitions Acquisitions are recorded on the closing date of the transaction at their fair value, which is determined by applying the market and income approaches using Level 3 inputs. The Level 3 inputs are: (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 are 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 can vary significantly from estimates that are made. No goodwill was recorded for the acquisitions completed in 2014 or 2013.
Income Taxes	Income Taxes We use the liability method of accounting for income taxes in accordance with the Income Taxes Early Adoption of Accounting Standard Amendments
Debt Issuance Costs	Debt Issuance Costs Debt issuance costs associated with our revolving bank credit facility are amortized using the straight-line method over the scheduled maturity of the debt. Debt issuance costs associated with all other debt are deferred and amortized over the scheduled maturity of the debt utilizing the effective interest method. As described above, unamortized debt issuance costs associated with our revolving bank credit facility is reported within Other Assets Long-Term Debt, less current maturities
Premiums Received on Debt Issuance	Premiums Received and Discounts Provided on Debt Issuance Premiums and discounts are recorded in Long-Term Debt, less current maturities
Share-Based Compensation	Share-Based Compensation Compensation cost for share-based payments to employees and non-employee directors is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which the recipient is required to provide service in exchange for the award. The fair value for equity instruments subject to only time or to Company performance measures was determined using the closing price of the Company’s common stock at the date of grant. The fair value of equity instruments subject to market-based performance measurements was determined using a Monte Carlo simulation probabilistic model. We recognize share-based compensation expense on a straight line basis over the period during which the recipient is required to provide service in exchange for the award. Estimates are made for forfeitures during the vesting period, resulting in the recognition of compensation cost only for those awards that are estimated to vest and estimated forfeitures are adjusted to actual forfeitures when the equity instrument vests. See Note 11 for more information.
Earnings Per Share	Earnings Per Share Unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per share under the two-class method. For additional information, refer to Note 14.
Other Income, Net	Other (Income) Expense, Net For 2015, the amount includes write-offs of debt issuance costs of $3.2 million related to reductions in the borrowing base of the revolving bank credit facility under the Credit Agreement. The write-offs of debt issuance costs is included as an adjustment to net income in determining Net cash provided by operating activities Net cash flows from investing activities Net proceeds from sales of assets
Recent Accounting Developments	Recent Accounting Developments In August 2014, the Financial Accounting Standards Board (“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 (Subtopic 606) In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (“ASU 2016-02”), Leases Subtopic 842

Significant Accounting Polici31

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Percentage of Revenue by Major Customers	The following identifies customers from whom we derived 10% or more of receipts from sales of crude oil, NGLs and natural gas. Year Ended December 31, 2015 2014 2013 Customer Shell Trading (US) Co. 50 % 47 % 48 % J. P. Morgan 14 % ** ** ** less than 10%
Schedule of Amounts Recorded in Prepaid Expenses and Other	Amounts recorded in Prepaid expenses and other Year Ended December 31, 2015 2014 Derivative assets - current (1) $ 10,036 $ 7,417 Prepaid insurance and surety bonds 7,475 13,130 Prepaid deposits related to royalties 5,943 9,681 Other (2) 3,425 6,119 Prepaid expenses and other $ 26,879 $ 36,347 (1) Includes open and closed (and not yet collected) derivative commodity contracts recorded at fair value. (2) Individual items were less than 5% of total current assets for either period presented.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2015
Fairway
Business Acquisition [Line Items]
Purchase Price Allocation for Acquisition	The following table presents the purchase price allocation, including estimated 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 estimated 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 (in thousands, except earnings per share): (unaudited) Year Ended December 31, 2014 2013 Revenue $ 971,595 $ 1,047,037 Net income (5,503 ) 71,412 Basic and diluted earnings per common share (0.08 ) 0.94
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) Year Ended December 31, 2014 (a) 2013 Revenues (b) $ 22,887 $ 62,949 Direct operating expenses (b) 4,417 9,583 DD&A (c) 8,385 20,503 G&A (d) 300 800 Interest expense (e) 330 990 Capitalized interest (f) (19 ) 165 Income tax expense (g) 3,316 10,818 The sources of information and significant assumptions are described below: (a) The adjustments for 2014 are for the period from January 1, 2014 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) Estimated insurance costs related to the Woodside Properties. (e) The 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.
Callon Properties
Business Acquisition [Line Items]
Purchase Price Allocation for Acquisition	The following table presents the purchase price allocation, including estimated adjustments, for the acquisition of the Callon Properties (in thousands): Cash consideration: Evaluated properties including equipment $ 73,752 Unevaluated properties 9,248 Sub-total cash consideration 83,000 Non-cash consideration: Asset retirement obligations - current 90 Asset retirement obligations - non-current 4,143 Sub-total non-cash consideration 4,233 Total consideration $ 87,233
Summary of Proforma Financial Information for Acquisition	The following table presents a summary of our pro forma financial information (in thousands except earnings per share): (unaudited) Year Ended December 31, 2013 Revenue $ 1,018,118 Net income 59,015 Basic and diluted earnings per common share 0.78
Business Acquisition Pro Forma Information Incremental Item	For the pro forma financial information, certain information was derived from financial records and certain information was estimated. The following table presents incremental items included in the pro forma information reported above for the Callon Properties (in thousands): (unaudited) Year Ended December 31, 2013 (a) Revenues (b) $ 34,030 Direct operating expenses (b) 6,405 DD&A (c) 14,931 G&A (d) (361 ) Interest expense (e) 1,383 Capitalized interest (f) (164 ) Income tax expense (g) 4,143 The sources of information and significant assumptions are described below: (a) The adjustments for 2013 are for the period from January 1, 2013 to the respective property transfer date, all of which occurred in the fourth quarter of 2013. (b) Revenues and direct operating expenses for the Callon Properties were derived from the historical financial records of Callon. (c) DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Callon Properties’ costs, reserves and production into our currently existing 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) G&A adjustments related to incremental transaction expenses, which were assumed to be funded from cash on hand, and were adjusted from the 2013 results. (e) The acquisition was assumed to be funded entirely with borrowed funds. Interest expense was computed using assumed borrowings of $83.0 million, which equates to the cash component of the transaction, and an interest rate of 2.0%, 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. A positive amount represents an increase to net expenses and a negative amount represents a decrease to net expenses. (g) Income tax expense was computed using the 35% federal statutory rate. The pro forma adjustments do not include adjustments related to any other acquisitions or divestitures.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Reconciliation of Asset Retirement Obligations Liability	The following is a reconciliation of our ARO liability (in thousands): Year Ended December 31, 2015 2014 Asset retirement obligations, beginning of period $ 390,568 $ 354,422 Liabilities settled (32,555 ) (74,313 ) Accretion of discount 20,703 20,633 Disposition of properties (8,581 ) — Liabilities assumed through acquisition 2,944 21,820 Liabilities incurred 4,780 3,258 Revisions of estimated liabilities 463 64,748 Asset retirement obligations, end of period 378,322 390,568 Less current portion 84,335 36,003 Long-term $ 293,987 $ 354,565

Derivative Financial Instrume34

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Open Commodity Derivatives	As of December 31, 2015, our open commodity derivative contracts were as follows: 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) Notional Notional Weighted Average Contract Price Quantity Quantity Put Option Call Option Call Option Termination Period (MMBTUs/day) (1) (MMBTUs) (1) (Bought) (Sold) (Bought) 2016: 1st Quarter (2) 40,000 2,400,000 $ 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 13,400,000 2.25 3.50 3.77 (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 January 2016 production were priced and closed in December 2015 and are excluded in the above table as these were closed contracts as of December 31, 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 reported in the following table (in thousands): December 31, 2015 2014 Prepaid and other assets - current $ 7,672 $ —
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): Year Ended December 31, 2015 2014 2013 Derivative (gain) loss: $ (14,375 ) $ (3,965 ) $ 8,470
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 Year Ended December 31, 2015 2014 2013 Cash receipts (payments) on derivative settlements, net $ 6,703 $ (5,318 ) $ (8,589 )

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Long-Term Debt	As of December 31, 2015 and 2014, our long-term debt was as follows (in thousands): December 31, 2015 2014 8.50% Senior Notes: Principal $ 900,000 $ 900,000 Debt premiums, net of amortization 10,503 13,057 Debt issuance costs, net of amortization (6,274 ) (7,937 ) 9.00% Term Loan: Principal 300,000 — Debt discounts, net of amortization (2,689 ) — Debt issuance costs, net of amortization (4,685 ) — Revolving bank credit facility — 447,000 Total long-term debt 1,196,855 1,352,120 Current maturities of long-term debt — — Long term debt, less current maturities $ 1,196,855 $ 1,352,120

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Schedule of Fair Value of Derivatives Financial Instruments and Long-Term Senior Notes	The following table presents the fair value of our derivative financial instruments, our 8.50% Senior Notes, the 9.00% Term Loan and our revolving bank credit facility (in thousands): December 31, 2015 December 31, 2014 Hierarchy Assets Liabilities Liabilities Derivatives Level 2 $ 7,672 $ — $ — 8.50% Senior Notes Level 2 — 324,000 594,000 9.00% Term Loan Level 2 — 217,500 — Revolving bank credit facility Level 2 — — 447,000

Share-Based and Cash-Based In37

Share-Based and Cash-Based Incentive Compensation (Tables)	12 Months Ended
	Dec. 31, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Schedule of Restricted Stock Activity	A summary of activity related to Restricted Shares is as follows: 2015 2014 2013 Restricted Shares Weighted Average Grant Date Fair Value Per Share Restricted Shares Weighted Average Grant Date Fair Value Per Share Restricted Shares Weighted Average Grant Date Fair Value Per Share Nonvested, beginning of period 43,210 $ 16.20 43,840 $ 15.96 43,687 $ 18.69 Granted 56,540 6.19 18,815 18.60 27,450 12.75 Vested (21,520 ) 16.26 (19,445 ) 18.00 (27,297 ) 17.09 Nonvested, end of period 78,230 $ 8.95 43,210 $ 16.20 43,840 $ 15.96
Schedule of Restricted Stock Awards Outstanding	Subject to the satisfaction of service conditions, the Restricted Shares outstanding as of December 31, 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 related to RSUs is as follows: 2015 2014 2013 Restricted Stock Units Weighted Average Grant Date Fair Value Per Share Restricted Stock Units Weighted Average Grant Date Fair Value Per Share Restricted Stock Units Weighted Average Grant Date Fair Value Per Share Nonvested, beginning of period 1,977,335 $ 15.29 1,331,753 $ 14.96 969,820 $ 22.70 Granted 2,626,930 3.59 1,195,388 16.84 969,919 13.23 Vested (721,038 ) 13.23 (354,692 ) 18.59 (468,925 ) 26.93 Forfeited (409,148 ) 10.63 (195,114 ) 16.53 (139,061 ) 16.50 Nonvested, end of period 3,474,079 $ 7.42 1,977,335 $ 15.29 1,331,753 $ 14.96
Schedule of Restricted Stock Units Outstanding	Subject to the satisfaction of service conditions, the RSUs outstanding as of December 31, 2015 are eligible to vest in the year indicated in the table below: Restricted Stock Units 2016 1,003,604 2017 2,470,475 Total 3,474,079
Summary of Compensation Expense under Share-Based Payment Arrangements and Related Tax Benefit	A summary of compensation expense under share-based payment arrangements and the related tax benefit is as follows (in thousands): Year Ended December 31, 2015 2014 2013 Share-based compensation expense from: Restricted stock $ 358 $ 369 $ 397 Restricted stock units 9,978 13,150 11,128 Common shares (94 ) 1,225 — Total $ 10,242 $ 14,744 $ 11,525 Share-based compensation tax benefit: Tax benefit computed at the statutory rate $ 3,585 $ 5,160 $ 4,034
Summary of Incentive Compensation Expense	A summary of incentive compensation expense is as follows (in thousands): Year Ended December 31, 2015 2014 2013 Share-based compensation included in: General and administrative $ 10,242 $ 14,744 $ 11,525 Cash-based incentive compensation included in: Lease operating expense 364 3,285 3,482 General and administrative (1) (233 ) 6,950 8,817 Total charged to operating income $ 10,373 $ 24,979 $ 23,824 (1) Adjustments to true up estimates to actual payments resulted in net credit balances to expense for 2015 .

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Components of Income Tax Expense (Benefit)	Components of income tax expense (benefit) were as follows (in thousands): Year Ended December 31, 2015 2014 2013 Current $ 288 $ 301 $ (2,146 ) Deferred (203,272 ) (4,760 ) 30,920 $ (202,984 ) $ (4,459 ) $ 28,774
Reconciliation of Income Taxes Computed to Income Tax Expense (Benefit)	The reconciliation of income taxes computed at the U.S. federal statutory tax rate to our income tax expense (benefit) is as follows (in thousands): Year Ended December 31, 2015 2014 2013 Income tax expense (benefit) at the federal statutory rate $ (436,696 ) 35.0 % $ (5,642 ) 35.0 % $ 28,033 35.0 % Share-based compensation 2,940 (0.2 ) — — — — State income taxes (2,343 ) 0.2 263 (1.6 ) 343 0.4 Valuation allowance 232,925 (18.7 ) — — — — Other 190 - 920 (5.7 ) 398 0.5 $ (202,984 ) 16.3 % $ (4,459 ) 27.7 % $ 28,774 35.9 %
Significant Components of Deferred Tax Assets and Liabilities	Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of our deferred tax assets and liabilities were as follows (in thousands): December 31, 2015 2014 Deferred tax liabilities: Property and equipment $ 40,287 $ 518,566 Derivatives 2,697 — Other 3,000 5,019 Total deferred tax liabilities 45,984 523,585 Deferred tax assets: Alternative minimum tax credit 20,486 20,486 Asset retirement obligations 133,018 137,597 Federal net operating losses 145,733 180,024 State net operating losses 5,068 5,008 Valuation allowance (237,275 ) (4,255 ) Accrued cash-based bonus — 3,559 Share-based compensation 4,245 5,042 Other 2,304 798 Total deferred tax assets 73,579 348,259 Net deferred tax asset (liabilities) $ 27,595 $ (175,326 )
Net Operating Loss and Tax Credit Carryovers	The table below presents the details of our net operating loss and tax credit carryovers as of December 31, 2015 (in thousands): Amount Expiration Year Federal net operating loss $ 418,417 2032-2035 State net operating losses 100,651 2021-2029 Alternative minimum tax credit 12,091 Indefinite General business credit 406 2027-2028
Balances in Uncertain Tax Positions	Balances in the uncertain tax positions are as follows (in thousands): December 31, 2015 2014 Balance, beginning and end of period $ 9,482 $ 9,482

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Schedule of Calculation of Basic and Diluted Earnings Per Common Share	The following table presents the calculation of basic and diluted earnings per common share (in thousands, except per share amounts): Year Ended December 31, 2015 2014 2013 Net income (loss) $ (1,044,718 ) $ (11,661 ) $ 51,322 Less portion allocated to nonvested shares — 269 303 Net income (loss) allocated to common shares $ (1,044,718 ) $ (11,930 ) $ 51,019 Weighted average common shares outstanding 75,931 75,609 75,239 Basic and diluted earnings (loss) per common share $ (13.76 ) $ (0.16 ) $ 0.68 Shares excluded due to being anti-dilutive (weighted-average) 2,195 2,097 —

Supplemental Cash Flow Inform40

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	The following reflects our supplemental cash flow information (in thousands): Year Ended December 31, 2015 2014 2013 Cash paid for interest, net of interest capitalized of $7,256 in 2015, $8,526 in 2014 and $10,058 in 2013 $ 92,622 $ 77,607 $ 73,909 Cash paid for income taxes 390 — 3,000 Cash refunds received for income taxes 90 3,000 59,126 Cash paid for share-based compensation (1) — 431 466 (1) The cash paid for share-based compensation is for dividends on unvested restricted stock and for dividend equivalents paid on RSUs. No cash was received from employees or directors related to share-based compensation and no cash was used to settle any equity instruments granted under share-based compensation arrangements.

Selected Quarterly Financial 41

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data	Unaudited quarterly financial data are as follows (in thousands, except per share amounts): 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Year Ended December 31, 2015 Revenues $ 127,907 $ 149,066 $ 126,228 $ 104,064 Operating loss (1) (337,508 ) (278,806 ) (468,573 ) (60,816 ) Net loss (1) (255,095 ) (260,449 ) (477,568 ) (51,606 ) Basic and diluted loss per common share (1) (2) (3.36 ) (3.43 ) (6.29 ) (0.68 ) Year Ended December 31, 2014 Revenues $ 254,516 $ 262,994 $ 234,521 $ 196,677 Operating income (loss) 37,225 34,403 20,983 (30,543 ) Net income (loss) 11,189 9,837 684 (33,371 ) Basic and diluted earnings (loss) per common share (2) 0.15 0.13 0.01 (0.44 ) (1) During 2015, we recorded in first, second, third and fourth quarter ceiling test write-downs of oil and natural gas properties of $260.4 million, $252.8 million, $441.6 million and $32.4 million, respectively. See Note 1 for additional information. (2) The sum of the individual quarterly earnings (loss) per share may not agree with the year loss per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter.

Supplemental Guarantor Inform42

Supplemental Guarantor Information (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Guarantor Information [Abstract]
Condensed Consolidating Balance Sheet	The following condensed consolidating financial information presents the financial condition, results of operations and cash flows of the Parent Company and the Guarantor Subsidiaries, together with consolidating adjustments necessary to present the Company’s results on a consolidated basis. Included in the consolidating adjustments was an adjustment related to the ceiling test write-down, as the computation is performed for each subsidiary on a stand-alone basis and also for the consolidated Company. This resulted in write-downs for the combined subsidiaries to be greater than computed on a total Company basis, which required a contra ceiling test write-down adjustment to present the consolidated results appropriately. When transfers of property were made from the Parent Company to the Guarantor Subsidiaries, which were transactions between entities under common control, the prior period financial information was 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 December 31, 2015 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Assets Current assets: Cash and cash equivalents $ 85,414 $ — $ — $ 85,414 Receivables: Oil and natural gas sales 2,742 32,263 — 35,005 Joint interest and other 121,190 — (99,178 ) 22,012 Total receivables 123,932 32,263 (99,178 ) 57,017 Prepaid expenses and other assets 25,375 1,504 — 26,879 Total current assets 234,721 33,767 (99,178 ) 169,310 Property and equipment – at cost: Oil and natural gas properties and equipment 5,682,793 2,219,701 — 7,902,494 Furniture, fixtures and other 20,802 — — 20,802 Total property and equipment 5,703,595 2,219,701 — 7,923,296 Less accumulated depreciation, depletion and amortization 5,258,563 1,822,273 (147,589 ) 6,933,247 Net property and equipment 445,032 397,428 147,589 990,049 Deferred income taxes 27,251 344 — 27,595 Restricted deposits for asset retirement obligations 15,606 — — 15,606 Other assets 498,782 266,748 (760,068 ) 5,462 Total assets $ 1,221,392 $ 698,287 $ (711,657 ) $ 1,208,022 Liabilities and Shareholders’ Equity (Deficit) Current liabilities: Accounts payable $ 100,282 $ 9,515 $ — $ 109,797 Undistributed oil and natural gas proceeds 20,463 976 — 21,439 Asset retirement obligations 63,716 20,619 — 84,335 Accrued liabilities 11,922 99,178 (99,178 ) 11,922 Total current liabilities 196,383 130,288 (99,178 ) 227,493 Long-term debt, less current maturities 1,196,855 — — 1,196,855 Asset retirement obligations, less current portion 173,105 120,882 — 293,987 Deferred income taxes — — — — Other liabilities 329,129 — (312,951 ) 16,178 Shareholders’ equity: Common stock 1 — — 1 Additional paid-in capital 423,499 704,885 (704,885 ) 423,499 Retained earnings (deficit) (1,073,413 ) (257,768 ) 405,357 (925,824 ) Treasury stock, at cost (24,167 ) — — (24,167 ) Total shareholders’ equity (deficit) (674,080 ) 447,117 (299,528 ) (526,491 ) Total liabilities and shareholders’ equity (deficit) $ 1,221,392 $ 698,287 $ (711,657 ) $ 1,208,022 Condensed Consolidating Balance Sheet as of December 31, 2014 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. 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 Prepaid expenses and other assets 28,728 7,619 — 36,347 Total current assets 237,099 33,041 (99,240 ) 170,900 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 966,112 357,992 (1,314,797 ) 9,307 Total assets $ 2,837,940 $ 1,265,605 $ (1,414,037 ) $ 2,689,508 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 1,352,120 — — 1,352,120 Asset retirement obligations, less current portion 235,876 118,689 — 354,565 Deferred income taxes 49,819 125,507 — 175,326 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 $ 2,837,940 $ 1,265,605 $ (1,414,037 ) $ 2,689,508
Condensed Consolidating Statement of Operations	Condensed Consolidating Statement of Operations for the Year Ended December 31, 2015 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Revenues $ 290,212 $ 217,053 $ — $ 507,265 Operating costs and expenses: Lease operating expenses 126,189 66,576 — 192,765 Production taxes 3,002 — — 3,002 Gathering and transportation 9,209 7,948 — 17,157 Depreciation, depletion and amortization 201,154 172,214 — 373,368 Asset retirement obligations accretion 11,587 9,116 — 20,703 Ceiling test write-down of oil and natural gas properties 616,947 517,880 (147,589 ) 987,238 General and administrative expenses 39,009 34,101 — 73,110 Derivative gain (14,375 ) — — (14,375 ) Total costs and expenses 992,722 807,835 (147,589 ) 1,652,968 Operating loss (702,510 ) (590,782 ) 147,589 (1,145,703 ) Loss of affiliates (464,931 ) — 464,931 — Interest expense: Incurred 101,542 3,050 — 104,592 Capitalized (4,206 ) (3,050 ) — (7,256 ) Other (income) expense, net 4,663 — — 4,663 Loss before income tax benefit (1,269,440 ) (590,782 ) 612,520 (1,247,702 ) Income tax benefit (77,133 ) (125,851 ) — (202,984 ) Net loss $ (1,192,307 ) $ (464,931 ) $ 612,520 $ (1,044,718 ) Condensed Consolidating Statement of Operations for the Year Ended December 31, 2014 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Revenues $ 571,365 $ 377,343 $ — $ 948,708 Operating costs and expenses: Lease operating expenses 180,149 84,602 — 264,751 Production taxes 7,932 — — 7,932 Gathering and transportation 11,790 8,031 — 19,821 Depreciation, depletion, amortization and accretion 267,406 223,063 — 490,469 Asset retirement obligations accretion 10,981 9,652 — 20,633 General and administrative expenses 46,513 40,486 — 86,999 Derivative loss (3,965 ) — — (3,965 ) Total costs and expenses 520,806 365,834 — 886,640 Operating income 50,559 11,509 — 62,068 Earnings of affiliates 8,320 — (8,320 ) — Interest expense: Incurred 84,460 2,462 — 86,922 Capitalized (6,064 ) (2,462 ) — (8,526 ) Other (income) expense, net (208 ) — — (208 ) Income (loss) before income tax expense (19,309 ) 11,509 (8,320 ) (16,120 ) Income tax expense (benefit) (7,648 ) 3,189 — (4,459 ) Net income (loss) $ (11,661 ) $ 8,320 $ (8,320 ) $ (11,661 ) Condensed Consolidating Statement of Operations for the Year Ended December 31, 2013 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Revenues $ 631,267 $ 352,821 $ — $ 984,088 Operating costs and expenses: Lease operating expenses 202,096 68,743 — 270,839 Production taxes 7,135 — — 7,135 Gathering and transportation 9,248 8,262 — 17,510 Depreciation, depletion and amortization 236,600 194,011 — 430,611 Asset retirement obligations accretion 14,218 6,700 — 20,918 General and administrative expenses 44,040 37,834 — 81,874 Derivative loss 8,470 — — 8,470 Total costs and expenses 521,807 315,550 — 837,357 Operating income 109,460 37,271 — 146,731 Earnings of affiliates 24,400 — (24,400 ) — Interest expense: Incurred 82,570 3,069 — 85,639 Capitalized (6,989 ) (3,069 ) — (10,058 ) Other (income) expense, net (8,946 ) — — (8,946 ) Income before income tax expense 67,225 37,271 (24,400 ) 80,096 Income tax expense 15,903 12,871 — 28,774 Net income $ 51,322 $ 24,400 $ (24,400 ) $ 51,322
Condensed Consolidating Statement of Cash Flows	Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2015 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Operating activities: Net loss $ (1,192,307 ) $ (464,931 ) $ 612,520 $ (1,044,718 ) Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Depreciation, depletion, amortization and accretion 212,741 181,330 — 394,071 Ceiling test write-down of oil and gas properties 616,947 517,880 (147,589 ) 987,238 Debt issuance costs write-off/amortization of debt items 4,411 — — 4,411 Share-based compensation 10,242 — — 10,242 Derivative gain (14,375 ) — — (14,375 ) Cash receipts on derivative settlements, net 6,703 — — 6,703 Deferred income taxes (77,421 ) (125,851 ) — (203,272 ) Loss of affiliates 464,931 — (464,931 ) — Changes in operating assets and liabilities: Oil and natural gas receivables 39,078 (6,842 ) — 32,236 Joint interest and other receivables 21,633 — — 21,633 Income taxes (7 ) — — (7 ) Prepaid expenses and other assets (13,916 ) 122,977 (91,245 ) 17,816 Asset retirement obligation settlements (26,637 ) (5,918 ) — (32,555 ) Accounts payable, accrued liabilities and other (142,270 ) 4,156 91,245 (46,869 ) Net cash provided by (used in) operating activities (90,247 ) 222,801 — 132,554 Investing activities: Investment in oil and natural gas properties and equipment (31,534 ) (198,627 ) — (230,161 ) Changes in operating assets and liabilities associated with investing activities (29,806 ) (25,619 ) — (55,425 ) Proceeds from sales of assets and other, net 372,939 — — 372,939 Investment in subsidiary (1,445 ) — 1,445 — Purchases of furniture, fixtures and other (1,278 ) — — (1,278 ) Net cash used in investing activities 308,876 (224,246 ) 1,445 86,075 Financing activities: Borrowings of long-term debt – revolving bank credit facility 263,000 — — 263,000 Repayments of long-term debt – revolving bank credit facility (710,000 ) — — (710,000 ) Issuance of 9.00% Term Loan 297,000 — — 297,000 Debt issuance costs (6,669 ) — — (6,669 ) Other (212 ) — — (212 ) Investment from parent — 1,445 (1,445 ) — Net cash provided by financing activities (156,881 ) 1,445 (1,445 ) (156,881 ) Decrease in cash and cash equivalents 61,748 — — 61,748 Cash and cash equivalents, beginning of period 23,666 — — 23,666 Cash and cash equivalents, end of period $ 85,414 $ — $ — $ 85,414 Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2014 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Operating activities: Net income (loss) $ (11,661 ) $ 8,320 $ (8,320 ) $ (11,661 ) Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion, amortization and accretion 278,387 232,715 — 511,102 Amortization of debt issuance costs and premium 701 — — 701 Share-based compensation 14,744 — — 14,744 Derivative gain (3,965 ) — — (3,965 ) Cash payments on derivative settlements (5,318 ) — — (5,318 ) Deferred income taxes (32,456 ) 27,696 — (4,760 ) Earnings of affiliates (8,320 ) — 8,320 — Changes in operating assets and liabilities: Oil and natural gas receivables 19,553 9,957 — 29,510 Joint interest and other receivables (4,255 ) — — (4,255 ) Income taxes 27,650 (24,507 ) — 3,143 Prepaid expenses and other assets 45,962 (7,525 ) (23,425 ) 15,012 Asset retirement obligations (57,253 ) (17,060 ) — (74,313 ) Accounts payable, accrued liabilities and other 11,083 (30,475 ) 23,425 4,033 Net cash provided by operating activities 274,852 199,121 — 473,973 Investing activities: Acquisition of property interest in oil and natural gas properties (17,407 ) (54,827 ) — (72,234 ) Investment in oil and natural gas properties and equipment (312,044 ) (242,334 ) — (554,378 ) Changes in operating assets and liabilities associated with investing activities 1,733 35,717 — 37,450 Investment in subsidiary (62,323 ) — 62,323 — Purchases of furniture, fixtures and other (3,340 ) — — (3,340 ) Net cash used in investing activities (393,381 ) (261,444 ) 62,323 (592,502 ) Financing activities: Borrowings of long-term debt – revolving bank credit facility 556,000 — — 556,000 Repayments of long-term debt – revolving bank credit facility (399,000 ) — — (399,000 ) Dividends to shareholders (30,260 ) — — (30,260 ) Other (345 ) — — (345 ) Investment from parent — 62,323 (62,323 ) — Net cash provided in financing activities 126,395 62,323 (62,323 ) 126,395 Increase in cash and cash equivalents 7,866 — — 7,866 Cash and cash equivalents, beginning of period 15,800 — — 15,800 Cash and cash equivalents, end of period $ 23,666 $ — $ — $ 23,666 Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2013 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Operating activities: Net income $ 51,322 $ 24,400 $ (24,400 ) $ 51,322 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion, amortization and accretion 250,818 200,711 — 451,529 Amortization of debt issuance costs and premium 1,645 — — 1,645 Share-based compensation 11,525 — — 11,525 Derivative loss 8,470 — — 8,470 Cash payments on derivative settlements (8,589 ) — — (8,589 ) Deferred income taxes 7,564 23,356 — 30,920 Earnings of affiliates (24,400 ) — 24,400 — Changes in operating assets and liabilities: Oil and natural gas receivables 6,182 (5,202 ) — 980 Joint interest and other receivables 34,257 — — 34,257 Income taxes 54,813 (10,485 ) — 44,328 Prepaid expenses and other assets (25,329 ) (18,835 ) 34,120 (10,044 ) Asset retirement obligations (65,438 ) (16,105 ) — (81,543 ) Accounts payable, accrued liabilities and other 74,693 (12,665 ) (34,120 ) 27,908 Net cash provided by operating activities 377,533 185,175 — 562,708 Investing activities: Acquisition of property interest in oil and natural gas properties — (82,424 ) — (82,424 ) Investment in oil and natural gas properties and equipment (349,804 ) (202,150 ) — (551,954 ) Changes in operating assets and liabilities associated with investing activities (14,732 ) 13,382 (1,350 ) Investment in subsidiary (86,017 ) — 86,017 - Proceeds from sales of assets and other, net 21,008 — — 21,008 Purchases of furniture, fixtures and other (1,435 ) — — (1,435 ) Net cash used in investing activities (430,980 ) (271,192 ) 86,017 (616,155 ) Financing activities: Borrowings of long-term debt – revolving bank credit facility 563,000 — — 563,000 Repayments of long-term debt – revolving bank credit facility (443,000 ) — — (443,000 ) Debt issuance costs (3,892 ) — — (3,892 ) Dividends to shareholders (58,846 ) — — (58,846 ) Other (260 ) — — (260 ) Investment from parent — 86,017 (86,017 ) — Net cash used in financing activities 57,002 86,017 (86,017 ) 57,002 Increase in cash and cash equivalents 3,555 — — 3,555 Cash and cash equivalents, beginning of period 12,245 — — 12,245 Cash and cash equivalents, end of period $ 15,800 $ — $ — $ 15,800

Supplemental Oil and Gas Disc43

Supplemental Oil and Gas Disclosures-unaudited (Tables)	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
Capitalized Costs Related to Oil and Natural Gas	Net capitalized costs related to our oil, NGLs and natural gas producing activities are as follows (in millions): December 31, 2015 2014 2013 Net capitalized cost: Proved oil and natural gas properties and equipment $ 7,882.3 $ 7,924.2 $ 7,207.1 Unproved oil and natural gas properties and equipment 20.2 121.5 132.0 Accumulated depreciation, depletion and amortization (1) related to oil, NGLs and natural gas activities (6,916.2 ) (5,557.6 ) (5,069.2 ) Net capitalized costs related to producing activities $ 986.3 $ 2,488.1 $ 2,269.9 (1) Includes ceiling test write-down in 2015.
Capitalized Costs Not Subject to Amortization	Costs not subject to amortization relate to unproved properties which are excluded from amortizable capital costs until it is determined that proved reserves can be assigned to such properties or until such time as the Company has made an evaluation that impairment has occurred. Subject to industry conditions, evaluation of most of these properties is expected to be completed within one to five years. The following table provides a summary of costs that are not being amortized as of December 31, 2015, by the year in which the costs were incurred (in millions): Total 2015 2014 2013 Prior to 2013 Costs excluded by year incurred: Acquisition costs $ 13.9 $ — $ 0.5 $ 4.9 $ 8.5 Capitalized interest not subject to amortization 4.7 1.5 1.2 0.9 1.1 Total costs not subject to amortization $ 18.6 $ 1.5 $ 1.7 $ 5.8 $ 9.6
Cost Incurred in Oil and Gas Property Acquisition Exploration and Development Activities	The following costs were incurred in oil and gas acquisition, exploration, and development activities (in millions): Year Ended December 31, 2015 2014 2013 Costs incurred: (1) Proved properties acquisitions $ 15.6 $ 111.5 $ 96.9 Exploration (2) (3) 152.4 411.1 215.3 Development 65.5 198.7 352.9 Unproved properties acquisitions (4) 0.1 3.1 26.3 Total costs incurred in oil and gas property acquisition, exploration and development activities $ 233.6 $ 724.4 $ 691.4 (1) Includes net reductions from capitalized ARO of $0.4 million in 2015 and net additions from capitalized ARO of $88.0 million and $50.6 million during 2014 and 2013, respectively, associated with acquisitions, liabilities incurred, divestitures and revisions of estimates. (2) Includes seismic costs of $3.2 million, $9.0 million and $8.9 million incurred during 2015, 2014 and 2013, respectively. (3) Includes geological and geophysical costs charged to expense of $5.7 million, $7.3 million and $5.9 million during 2015, 2014 and 2013, respectively. (4) The amounts for unproved property acquisitions include capitalized interest associated with unproved properties acquired during the period.
Schedule of Depreciation, Depletion, Amortization and Accretion Expense	The following table presents our depreciation, depletion, amortization and accretion expense per barrel equivalent (“Boe”) of products sold. Year Ended December 31, 2015 2014 2013 Depreciation, depletion, amortization and accretion per Boe $ 23.11 $ 28.98 $ 25.10
Schedule of Oil and Natural Gas Information	The following sets forth estimated quantities of our net proved, proved developed and proved undeveloped oil, NGLs and natural gas reserves. All of the reserves are located in the Unites States with all located in state and federal waters in the Gulf of Mexico. The reserve estimates exclude insignificant royalties and interests owned by the Company due to the unavailability of such information. In addition to other criteria, estimated reserves are assessed for economic viability based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for the year in accordance with definitions and guidelines set forth by the SEC and the FASB. The prices used do not purport, nor should it be interpreted, to present the current market prices related to our estimated oil and natural gas reserves. Actual future prices and costs may differ materially from those used in determining our proved reserves for the periods presented. The prices used are presented in the section below entitled “ Standardized Measure of Discounted Future Net Cash Flows”. Total Energy Equivalent Reserves (1) Oil (MMBbls) NGLs (MMBbls) Natural Gas (Bcf) Oil Equivalent (MMBoe) Natural Gas Equivalent (Bcfe) Proved reserves as of Dec. 31, 2012 54.8 15.2 285.1 117.5 705.1 Revisions of previous estimates (2) (4.3 ) 0.2 2.1 (3.8 ) (22.8 ) Extensions and discoveries (3) 13.9 2.6 22.0 20.2 121.0 Purchase of minerals in place (4) 1.5 — 4.4 2.3 13.7 Sales of reserves (5) (0.4 ) — (0.4 ) (0.5 ) (3.2 ) Production (7.0 ) (2.1 ) (53.3 ) (18.0 ) (107.9 ) Proved reserves as of Dec. 31, 2013 58.5 15.9 259.9 117.7 705.9 Revisions of previous estimates (6) 1.6 0.1 14.3 4.1 25.3 Extensions and discoveries (7) 7.3 0.7 10.1 9.7 58.1 Purchase of minerals in place (8) 1.5 1.2 20.7 6.1 36.5 Production (7.2 ) (2.1 ) (50.1 ) (17.6 ) (105.8 ) Proved reserves as of Dec. 31, 2014 61.7 15.8 254.9 120.0 720.0 Revisions of previous estimates (9) 4.8 (0.9 ) 4.9 4.7 28.0 Revisions related to sold properties (10) (12.1 ) (4.8 ) (2.9 ) (17.4 ) (104.3 ) Extensions and discoveries (11) 2.4 0.2 8.8 4.1 24.4 Purchase of minerals in place (12) — — 6.1 1.0 6.1 Sales of reserves (13) (13.5 ) (2.1 ) (20.2 ) (19.0 ) (113.8 ) Production (7.8 ) (1.6 ) (46.2 ) (17.0 ) (102.3 ) Proved reserves as of Dec. 31, 2015 35.5 6.6 205.4 76.4 458.1 Year-end proved developed reserves: 2015 29.4 6.4 198.5 69.0 413.5 2014 35.7 10.7 221.1 83.3 499.7 2013 36.2 11.1 232.7 86.1 516.1 Year-end proved undeveloped reserves: 2015 (14) 6.1 0.2 6.9 7.4 44.6 2014 26.0 5.1 33.8 36.7 220.3 2013 22.3 4.8 27.2 31.6 189.8 Volume measurements: Bbl – barrel Mcf – thousand cubic feet MMBbls – million barrels for crude oil, condensate or NGLs Bcf – billion cubic feet MMBoe – million barrels of oil equivalent Bcfe – billion cubic feet of gas equivalent (1) The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy-equivalent ratio of six Mcf of natural gas to one barrel of crude oil, condensate or NGLs (totals may not compute due to rounding). The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for crude oil, NGLs and natural gas may differ significantly. (2) Includes upward revision due to price of 1.9 MMBoe; negative revisions of 4.9 MMBoe at our Yellow Rose field for performance and technical changes, 2.3 MMBoe at our High Island 21/22 field for performance, 1.3 MMBoe at our Ship Shoal 349/359 field for performance; and positive performance revisions of 0.7 MMBoe at our Main Pass 98 field, 0.7 MMBoe at our South Timbalier 314, 0.6 MMBoe at our Main Pass 108 field and 0.5 MMBoe our South Timbalier 176 field. (3) Includes extensions and discoveries of 12.6 MMBoe at our Yellow Rose field, 4.2 MMBoe at our Ship Shoal 349 field and 1.9 MMBoe at our Mississippi Canyon 698 field. (4) Primarily due to the acquisition of the Callon Properties. (5) Primarily due to the sales of our non-working interests in the Green Canyon 60 field, the Green Canyon 19 field and the West Delta area block 29. (6) Includes upwards revisions due to price of 0.3 MMBoe; positive revisions of 2.4 MMBoe at our Fairway Field, 1.2 MMBoe at our Mississippi Canyon 800 field and 6.4 MMBoe at various fields; and negative revisions of 3.9 MMBoe at our Yellow Rose field and 2.4 MMBoe at various other fields. (7) Includes extensions and discoveries of 4.1 MMBoe at our Yellow Rose field and 4.1 MMBoe at our Mississippi Canyon 782 field. (8) Primarily due to acquiring additional ownership in the Fairway Field and acquisition of the Woodside Properties. (9) Includes upwards revisions of 7.4 MMBoe at the Ship Shoal 349 field (Mahogany), 1.9 MMBoe at our Brazo A-133 field, 1.3 MMBoe at out Atwater 575 field, 1.3 MMBoe at out Mississippi Canyon 243 field (Matterhorn), 1.1 MMBoe at our Fairway Field, partially offset by downward revisions due to price of 10.7 MMBoe. The revision for price excludes the Yellow Rose field sold during 2015. (10) Revisions related to the Yellow Rose field during 2015, which were primarily due to price reductions, up to the date of the sale in October 2015. (11) Primarily due to increases at Ewing Bank 910. (12) Primarily due to purchase of additional interest at Brazos A-133. (13) Related primarily to the sale of the Yellow Rose field in October 2015, which had estimated reserves at the date of sale of 19.0 MMBoe. (14) We believe that we will be able to develop all but 1.2 MMBoe of the reserves classified as proved undeveloped (“PUDs”), or approximately 16%, out of the total of 7.4 MMBoe classified as PUDs at December 31, 2015, within five years from the date such reserves were initially recorded. The exception is at the Mississippi Canyon 243 field (Matterhorn) where the field is being developed using a single floating tension leg platform requiring an extended sequential development plan. The platform cannot support a rig that would allow additional wells to be drilled, but can support a rig to allow sidetracking of wells. A portion of the PUDs in this field were originally recorded in our reserves as of December 31, 2010. The development of these PUDs will be delayed until an existing well is depleted and available to sidetrack. Based on the latest reserve report, a well is expected to be drilled to develop the Mississippi Canyon 243 field (Matterhorn) PUDs in 2020.
Schedule of Prices Weighted by Field Production Related to Proved Reserves	The following presents the standardized measure of discounted future net cash flows related to our proved oil and natural gas reserves together with changes therein. Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the unweighted average of first-day-of-the-month commodity prices for the periods presented. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. Due to the lack of a benchmark price for NGLs, a ratio is computed for each field of the NGLs realized price compared to the crude oil realized price. Then, this ratio is applied to the crude oil price using FASB/SEC guidance. The average commodity prices weighted by field production and after adjustments related to the proved reserves are as follows: December 31, 2015 2014 2013 2012 Oil - per barrel $ 46.94 $ 91.12 $ 99.65 $ 98.13 NGLs per barrel 17.60 34.63 35.21 47.30 Natural gas per Mcf 2.50 4.27 3.80 2.77
Standardized Measure of Discounted Future Net Cash Flow	The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair market value of our oil and natural gas reserves. These estimates reflect proved reserves only and ignore, among other things, future changes in prices and costs, revenues that could result from probable reserves which could become proved reserves in 2016 or later years and the risks inherent in reserve estimates. The standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves is as follows (in millions): Year Ended December 31, 2015 2014 2013 Standardized Measure of Discounted Future Net Cash Flows Future cash inflows $ 2,296.7 $ 7,258.5 $ 7,376.7 Future costs: Production (840.1 ) (2,224.5 ) (2,142.8 ) Development (161.4 ) (922.0 ) (1,001.4 ) Dismantlement and abandonment (471.8 ) (475.4 ) (441.6 ) Income taxes (1) — (948.4 ) (986.9 ) Future net cash inflows before 10% discount 823.4 2,688.2 2,804.0 10% annual discount factor (209.5 ) (985.4 ) (1,129.4 ) Total $ 613.9 $ 1,702.8 $ 1,674.6 (1) No future income taxes were estimated to be paid in 2015 as our present tax position has sufficient tax basis and net operating loss carrying forwards to offset any future taxes. State income taxes were disregarded due to immateriality.
Schedule of Changes In Standardized Measure	Year Ended December 31, 2015 2014 2013 Changes in Standardized Measure Standardized measure, beginning of year $ 1,702.8 $ 1,674.6 $ 1,846.4 Increases (decreases): Sales and transfers of oil and gas produced, net of production costs (289.1 ) (650.9 ) (686.1 ) Net changes in price, net of future production costs (1,455.6 ) (278.6 ) (65.2 ) Extensions and discoveries, net of future production and development costs 65.3 309.6 393.8 Changes in estimated future development costs (8.5 ) (56.4 ) (91.1 ) Previously estimated development costs incurred 158.9 263.1 262.1 Revisions of quantity estimates 137.9 118.6 (91.6 ) Accretion of discount 150.6 180.6 202.2 Net change in income taxes 600.8 (11.4 ) 56.6 Purchases of reserves in-place 6.0 86.7 79.6 Sales of reserves in-place (401.4 ) — (53.1 ) Changes in production rates due to timing and other (53.8 ) 66.9 (179.0 ) Net increase (decrease) in standardized measure (1,088.9 ) 28.2 (171.8 ) Standardized measure, end of year $ 613.9 $ 1,702.8 $ 1,674.6

Significant Accounting Polici44

Significant Accounting Policies - Additional Information (Details)	2 Months Ended	3 Months Ended				12 Months Ended			24 Months Ended
	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2015USD ($)$ / bbl$ / BTU	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2015USD ($)	Feb. 26, 2016USD ($)	May. 31, 2015
Significant Accounting Policies [Line Items]
Other assets		$ 5,462,000				$ 5,462,000	$ 9,307,000		$ 5,462,000
Other liabilities		16,178,000				16,178,000	13,691,000		16,178,000
Deferred income taxes							175,326,000
Net cash provided by operating activities						132,554,000	473,973,000	$ 562,708,000
Net cash used in investing activities						86,075,000	(592,502,000)	(616,155,000)
Natural gas imbalances		6,900,000				6,900,000	6,400,000		6,900,000
Allowance for doubtful accounts receivable		2,500,000				$ 2,500,000	700,000		2,500,000
Usage of the amounts recorded for allowance for doubtful accounts							0		$ 0
Percentage of discount from proved reserves						10.00%
Ceiling test write-down of oil and natural gas properties		$ 32,400,000	$ 441,600,000	$ 252,800,000	$ 260,400,000	$ 987,238,000	0	0
Proved undeveloped reserves classification period to be drilled						5 years
Goodwill, acquired during period							0	0
Write-offs of debt issuance costs						$ 3,200,000
Net proceeds received in conjunction with a payment for an option exercised								9,100,000
SEC Methodology | Natural Gas
Significant Accounting Policies [Line Items]
Price using SEC methodology | $ / BTU						2.59
SEC Methodology | Crude Oil Per Barrel
Significant Accounting Policies [Line Items]
Price using SEC methodology | $ / bbl						46.79
Fixtures and Non-Oil and Natural Gas Property and Equipment | Minimum
Significant Accounting Policies [Line Items]
Estimated useful lives						5 years
Fixtures and Non-Oil and Natural Gas Property and Equipment | Maximum
Significant Accounting Policies [Line Items]
Estimated useful lives						7 years
Subsequent Event
Significant Accounting Policies [Line Items]
Amount borrowed under Credit Agreement										$ 340,000,000
Obligation to secure financial assurances	$ 260,800,000
9.00% Term Loan due 2020
Significant Accounting Policies [Line Items]
Debt instrument interest rate		9.00%				9.00%			9.00%		9.00%
Accounting Standards Update 2015-17
Significant Accounting Policies [Line Items]
Deferred income taxes							11,700,000
Restatement Adjustment
Significant Accounting Policies [Line Items]
Other assets							(7,900,000)
Other liabilities							(7,900,000)
Net cash provided by operating activities							(37,500,000)	1,400,000
Net cash used in investing activities							$ (37,500,000)	$ 1,400,000

Significant Accounting Polici45

Significant Accounting Policies - Percentage of Revenue by Major Customers (Details) - Sales Revenue Net - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Shell Trading (US) Co.
Entity Wide Revenue Major Customer [Line Items]
Percentage of receipts	50.00%	47.00%	48.00%
J. P. Morgan
Entity Wide Revenue Major Customer [Line Items]
Percentage of receipts	14.00%

Significant Accounting Polici46

Significant Accounting Policies - Schedule of Amounts Recorded in Prepaid Expenses and Other (Details) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Prepaid Expense And Other Assets Current [Abstract]
Derivative assets - current	[1]	$ 10,036	$ 7,417
Prepaid insurance and surety bonds		7,475	13,130
Prepaid deposits related to royalties		5,943	9,681
Other	[2]	3,425	6,119
Prepaid expenses and other		$ 26,879	$ 36,347
[1]	(1) Includes open and closed (and not yet collected) derivative commodity contracts recorded at fair value.
[2]	(1) Individual items were less than 5% of total current assets for either period presented.

Acquisitions and Divestitures -

Acquisitions and Divestitures - Additional Information (Details)	Oct. 15, 2015USD ($)a$ / bbl	Sep. 26, 2013USD ($)	Jul. 11, 2013USD ($)	Dec. 31, 2015USD ($)		Sep. 30, 2015USD ($)		Jun. 30, 2015USD ($)		Mar. 31, 2015USD ($)		Dec. 31, 2014USD ($)	Sep. 30, 2014USD ($)	Jun. 30, 2014USD ($)	Mar. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Sep. 15, 2014	Sep. 14, 2014	May. 20, 2014	Oct. 17, 2013
Business Acquisition [Line Items]
Gain (loss) on disposition of proved property	$ 0
Limit on percentage of reserves related to recognition of gain or loss	25.00%
Goodwill, acquired during period																			$ 0	$ 0
Revenues				$ 104,064,000		$ 126,228,000		$ 149,066,000		$ 127,907,000		$ 196,677,000	$ 234,521,000	$ 262,994,000	$ 254,516,000			$ 507,265,000	948,708,000	984,088,000
DD&A																		394,071,000	511,102,000	451,529,000
Income tax expense																		(202,984,000)	(4,459,000)	28,774,000
Net income (loss)				$ (51,606,000)	[1]	$ (477,568,000)	[1]	$ (260,449,000)	[1]	$ (255,095,000)	[1]	$ (33,371,000)	$ 684,000	$ 9,837,000	$ 11,189,000			(1,044,718,000)	(11,661,000)	51,322,000
Green Canyon Fields
Business Acquisition [Line Items]
Proceeds from sale of properties			$ 4,300,000
Reversal of asset retirement obligation			$ 15,600,000
West Delta Area Block Twenty Nine
Business Acquisition [Line Items]
Proceeds from sale of properties		$ 14,700,000
Reversal of asset retirement obligation		$ 3,900,000
West Delta Area Block Twenty Nine | Post Effective Date Repayment
Business Acquisition [Line Items]
Proceeds from sale of properties																			1,700,000
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																	$ 28,400,000	24,400,000
Direct operating expenses																	5,500,000	9,500,000
DD&A																	11,000,000	14,400,000
Income tax expense																	4,200,000	0
Net income (loss)																	$ 7,700,000	$ 500,000
Callon Properties
Business Acquisition [Line Items]
Percentage of working interest																								15.00%
Payments for previous acquisition																			600,000
Goodwill, acquired during period																				$ 0
Revenues																$ 5,800,000			32,500,000
Direct operating expenses																1,300,000			6,600,000
DD&A																2,400,000			16,400,000
Income tax expense																700,000			3,300,000
Net income (loss)																$ 1,400,000			$ 6,200,000
NYMEX
Business Acquisition [Line Items]
Addition to available cash	$ 100,000,000
Crude Oil | NYMEX | Minimum
Business Acquisition [Line Items]
Trading price per barrel | $ / bbl	70
Crude Oil | NYMEX | Maximum
Business Acquisition [Line Items]
Trading price per barrel | $ / bbl	90
Ajax Resources, LLC
Business Acquisition [Line Items]
Proceeds from sale of properties	$ 372,900,000
Acres of oil and gas property, net | a	25,800
Agreement effective date	Jan. 1, 2015
Ajax Resources, LLC | Minimum
Business Acquisition [Line Items]
Overriding royalty interest	1.00%
Ajax Resources, LLC | Maximum
Business Acquisition [Line Items]
Overriding royalty interest	4.00%
[1]	During 2015, we recorded in first, second, third and fourth quarter ceiling test write-downs of oil and natural gas properties of $260.4 million, $252.8 million, $441.6 million and $32.4 million, respectively. See Note 1 for additional information.

Acquisitions and Divestitures48

Acquisitions and Divestitures - Purchase Price Allocation for Acquisition (Details) - USD ($) $ in Thousands	Sep. 15, 2014	May. 20, 2014	Oct. 17, 2013
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
Callon Properties
Cash consideration:
Oil and natural gas properties and equipment			$ 83,000
Non-cash consideration:
Asset retirement obligations - non-current			4,143
Asset retirement obligations - current			90
Non-cash consideration			4,233
Total consideration			87,233
Callon Properties | Evaluated Properties Including Equipment
Cash consideration:
Oil and natural gas properties and equipment			73,752
Callon Properties | Unevaluated Properties
Cash consideration:
Oil and natural gas properties and equipment			$ 9,248

Acquisitions and Divestitures49

Acquisitions and Divestitures - Summary of Proforma Financial Information for Acquisition (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Woodside Properties
Business Acquisition [Line Items]
Revenue	$ 971,595	$ 1,047,037
Net income	$ (5,503)	$ 71,412
Basic and diluted earnings per common share	$ (0.08)	$ 0.94
Callon Properties
Business Acquisition [Line Items]
Revenue		$ 1,018,118
Net income		$ 59,015
Basic and diluted earnings per common share		$ 0.78

Acquisitions and Divestitures50

Acquisitions and Divestitures - Business Acquisition Pro Forma Information Incremental Items (Details) - USD ($)

3 Months Ended

7 Months Ended

12 Months Ended

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Business Acquisition [Line Items]

Revenues

$ 104,064,000

$ 126,228,000

$ 149,066,000

$ 127,907,000

$ 196,677,000

$ 234,521,000

$ 262,994,000

$ 254,516,000

$ 507,265,000

$ 948,708,000

$ 984,088,000

DD&A

394,071,000

511,102,000

451,529,000

G&A

73,110,000

86,999,000

81,874,000

Interest expense

104,592,000

86,922,000

85,639,000

Income tax expense

(202,984,000)

(4,459,000)

28,774,000

Woodside Properties

Business Acquisition [Line Items]

Revenues

$ 28,400,000

24,400,000

Direct operating expenses

5,500,000

9,500,000

DD&A

11,000,000

14,400,000

Income tax expense

$ 4,200,000

$ 0

Woodside Properties | Pro Forma

Business Acquisition [Line Items]

Revenues

[1]

22,887,000

[2]

62,949,000

Direct operating expenses

[1]

4,417,000

[2]

9,583,000

DD&A

[3]

8,385,000

[2]

20,503,000

G&A

[4]

300,000

[2]

800,000

Interest expense

[5]

330,000

[2]

990,000

Capitalized interest

[6]

(19,000)

[2]

165,000

Income tax expense

[7]

3,316,000

[2]

10,818,000

Callon Properties

Business Acquisition [Line Items]

Revenues

$ 5,800,000

32,500,000

Direct operating expenses

1,300,000

6,600,000

DD&A

2,400,000

16,400,000

Income tax expense

$ 700,000

$ 3,300,000

Callon Properties | Pro Forma

Business Acquisition [Line Items]

Revenues

[8],[9]

34,030,000

Direct operating expenses

[8],[9]

6,405,000

DD&A

[9],[10]

14,931,000

G&A

[9],[11]

(361,000)

Interest expense

[9],[12]

1,383,000

Capitalized interest

[9],[13]

(164,000)

Income tax expense

[7],[9]

$ 4,143,000

[1]

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

[2]

The adjustments for 2014 are for the period from January 1, 2014 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]

Estimated insurance costs related to the Woodside Properties.

[5]

The 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.

[8]

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

[9]

The adjustments for 2013 are for the period from January 1, 2013 to the respective property transfer date, all of which occurred in the fourth quarter of 2013.

[10]

DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Callon Properties’ costs, reserves and production into our currently existing 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.

[11]

G&A adjustments related to incremental transaction expenses, which were assumed to be funded from cash on hand, and were adjusted from the 2013 results.

[12]

The acquisition was assumed to be funded entirely with borrowed funds. Interest expense was computed using assumed borrowings of $83.0 million, which equates to the cash component of the transaction, and an interest rate of 2.0%, which equates to the rates applied to incremental borrowings on the revolving bank credit facility.

[13]

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. A positive amount represents an increase to net expenses and a negative amount represents a decrease to net expenses.

Acquisitions and Divestitures51

Acquisitions and Divestitures - Business Acquisition Pro Forma Information Incremental Items (Parenthetical) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Long-term debt, less current maturities	$ 1,196,855	$ 1,352,120
Federal statutory income tax rate	35.00%	35.00%	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%
Callon Properties
Business Acquisition [Line Items]
Long-term debt, less current maturities			$ 83,000
Federal statutory income tax rate			35.00%
Callon Properties | Revolving Credit Facility
Business Acquisition [Line Items]
Effective interest rate			2.00%

Hurricane Remediation and Ins52

Hurricane Remediation and Insurance Claims - Additional Information (Details) - USD ($)	3 Months Ended	12 Months Ended
	Sep. 30, 2008	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Insurance [Abstract]
Retention amount per occurrence	$ 10,000,000
Maximum insurance coverage policy limit due to named windstorms for per incident	150,000,000
Maximum insurance coverage policy limit except for property damage due to named windstorms	$ 250,000,000
Insurance proceeds		$ 200,000	$ 12,200,000	$ 6,700,000
Cumulative insurance recoveries related to hurricanes			$ 161,200,000

Asset Retirement Obligations -

Asset Retirement Obligations - Reconciliation of Asset Retirement Obligations Liability (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations, beginning of period	$ 390,568	$ 354,422
Asset retirement obligation settlements	(32,555)	(74,313)	$ (81,543)
Accretion of discount	20,703	20,633	20,918
Disposition of properties	(8,581)
Liabilities assumed through acquisition	2,944	21,820
Liabilities incurred	4,780	3,258
Revisions of estimated liabilities	463	64,748
Asset retirement obligations, end of period	378,322	390,568	$ 354,422
Less current portion	84,335	36,003
Long-term	$ 293,987	$ 354,565

Derivative Financial Instrume54

Derivative Financial Instruments - Additional Information (Details)	Dec. 31, 2014DerivativeInstrument
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Number of open derivative instruments	0

Derivative Financial Instrume55

Derivative Financial Instruments - Open Commodity Derivatives (Details)	12 Months Ended
	Dec. 31, 2015MMBTU$ / Derivativebbl
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 Natural Gas - Three-Way Collars
Derivatives Fair Value [Line Items]
Notional Quantity (MMBTUs) | MMBTU	13,400,000	[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	3.77
NYMEX Natural Gas - Three-Way Collars | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	3.50
2016: 1st Quarter | NYMEX Crude Oil - Two-Way Collars
Derivatives Fair Value [Line Items]
Termination Period	1st Quarter
Notional Quantity (Bbls/day) | bbl	5,000	[1]
Notional Quantity (Bbls) | bbl	455,000	[1]
2016: 1st Quarter | NYMEX Crude Oil - Two-Way Collars | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	40
2016: 1st Quarter | NYMEX Crude Oil - Two-Way Collars | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	81.47
2016: 1st Quarter | NYMEX Natural Gas - Three-Way Collars
Derivatives Fair Value [Line Items]
Termination Period	1st Quarter	[2]
Notional Quantity (MMBTUs/day) | MMBTU	40,000	[1],[2]
Notional Quantity (MMBTUs) | MMBTU	2,400,000	[1],[2]
2016: 1st Quarter | NYMEX Natural Gas - Three-Way Collars | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	2.25	[2]
2016: 1st Quarter | NYMEX Natural Gas - Three-Way Collars | Call Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	3.77	[2]
2016: 1st Quarter | NYMEX Natural Gas - Three-Way Collars | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	3.50	[2]
2016: 2nd Quarter | NYMEX Crude Oil - Two-Way Collars
Derivatives Fair Value [Line Items]
Termination Period	2nd Quarter
Notional Quantity (Bbls/day) | bbl	5,000	[1]
Notional Quantity (Bbls) | bbl	455,000	[1]
2016: 2nd Quarter | NYMEX Crude Oil - Two-Way Collars | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	40
2016: 2nd Quarter | NYMEX Crude Oil - Two-Way Collars | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	81.47
2016: 2nd Quarter | NYMEX Natural Gas - Three-Way Collars
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]
2016: 2nd Quarter | NYMEX Natural Gas - Three-Way Collars | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	2.25
2016: 2nd Quarter | NYMEX Natural Gas - Three-Way Collars | Call Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	3.77
2016: 2nd Quarter | NYMEX Natural Gas - Three-Way Collars | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	3.50
2016: 3rd Quarter | NYMEX Crude Oil - Two-Way Collars
Derivatives Fair Value [Line Items]
Termination Period	3rd Quarter
Notional Quantity (Bbls/day) | bbl	5,000	[1]
Notional Quantity (Bbls) | bbl	460,000	[1]
2016: 3rd Quarter | NYMEX Crude Oil - Two-Way Collars | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	40
2016: 3rd Quarter | NYMEX Crude Oil - Two-Way Collars | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	81.47
2016: 3rd Quarter | NYMEX Natural Gas - Three-Way Collars
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]
2016: 3rd Quarter | NYMEX Natural Gas - Three-Way Collars | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	2.25
2016: 3rd Quarter | NYMEX Natural Gas - Three-Way Collars | Call Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	3.77
2016: 3rd Quarter | NYMEX Natural Gas - Three-Way Collars | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	3.50
2016: 4th Quarter | NYMEX Crude Oil - Two-Way Collars
Derivatives Fair Value [Line Items]
Termination Period	4th Quarter
Notional Quantity (Bbls/day) | bbl	5,000	[1]
Notional Quantity (Bbls) | bbl	460,000	[1]
2016: 4th Quarter | NYMEX Crude Oil - Two-Way Collars | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	40
2016: 4th Quarter | NYMEX Crude Oil - Two-Way Collars | Call Option | Sold
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	81.47
2016: 4th Quarter | NYMEX Natural Gas - Three-Way Collars
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]
2016: 4th Quarter | NYMEX Natural Gas - Three-Way Collars | Put Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	2.25
2016: 4th Quarter | NYMEX Natural Gas - Three-Way Collars | Call Option | Bought
Derivatives Fair Value [Line Items]
Weighted Average Contract Price	3.77
2016: 4th Quarter | NYMEX Natural Gas - Three-Way Collars | 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 January 2016 production were priced and closed in December 2015 and are excluded in the above table as these were closed contracts as of December 31, 2015

Derivative Financial Instrume56

Derivative Financial Instruments - Estimated Fair Value of Derivative Contracts (Details) $ in Thousands	Dec. 31, 2015USD ($)
Prepaid And Other Assets - Current
Derivatives Fair Value [Line Items]
Fair value of commodity derivative contracts	$ 7,672

Derivative Financial Instrume57

Derivative Financial Instruments - Changes in Fair Value of Commodity Derivative Contracts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Gain Loss On Derivative Instruments Net Pretax [Abstract]
Derivative (gain) loss	$ (14,375)	$ (3,965)	$ 8,470

Derivative Financial Instrume58

Derivative Financial Instruments - Cash Payments on Derivative Settlements, Net Included within Net Cash Provided by Operating Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Cash receipts (payments) on derivative settlements, net	$ 6,703	$ (5,318)	$ (8,589)

Long-Term Debt - Long-Term Debt

Long-Term Debt - Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Revolving bank credit facility		$ 447,000
Total long-term debt	$ 1,196,855	1,352,120
Long-term debt, less current maturities	1,196,855	1,352,120
8.50% Senior Notes
Debt Instrument [Line Items]
Principal	900,000	900,000
Debt premiums, net of amortization	10,503	13,057
Debt issuance costs, net of amortization	(6,274)	$ (7,937)
9.00% Term Loan due 2020
Debt Instrument [Line Items]
Principal	300,000
Debt issuance costs, net of amortization	(4,685)
Debt discounts, net of amortization	$ (2,689)

Long-Term Debt - Long-Term De60

Long-Term Debt - Long-Term Debt (Parenthetical) (Details) - USD ($) $ in Millions	Dec. 31, 2015	May. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Aggregate annual maturities of long-term debt, 2016	$ 0
Aggregate annual maturities of long-term debt, 2017	0
Aggregate annual maturities of long-term debt, 2018	0
Aggregate annual maturities of long-term debt, 2019	900
Aggregate annual maturities of long-term debt, thereafter	$ 300
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	12 Months Ended
	May. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Minimum borrowing base amount allowed before term loan purchase		$ 200,000,000
Letter of credit maximum amount outstanding prior to repurchase of term loan		100,000,000
Debt issuance costs write-down/amortization of debt items		$ 4,411,000	$ 701,000	$ 1,645,000
Revolving bank credit facility			$ 447,000,000
London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate		1.00%
Federal Funds Effective Swap Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate		0.50%
Maximum
Debt Instrument [Line Items]
Percentage of hedging contracts		75.00%
First lien leverage ratio		150.00%
Current ratio		100.00%
Secured debt leverage ratio		350.00%
Maximum | Thereafter
Debt Instrument [Line Items]
Current ratio		100.00%
Minimum
Debt Instrument [Line Items]
First lien leverage ratio		100.00%
Current ratio		75.00%
Secured debt leverage ratio		100.00%
Minimum | Thereafter
Debt Instrument [Line Items]
Current ratio		100.00%
Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit maximum amount outstanding prior to repurchase of term loan		$ 0
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%
Senior notes maturity date		Jun. 15, 2019
Principal		$ 900,000,000	$ 900,000,000
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%
Debt instruments, discount rate	1.00%
Principal		$ 300,000,000
Revolving Bank Credit Facility Due November 2018
Debt Instrument [Line Items]
Effective interest rate		3.30%
Credit agreement expiration date		Nov. 8, 2018
Borrowings and letters of credit, repayment terms		To the extent borrowings and letters of credit outstanding exceed the redetermined borrowing base, such excess or deficiency is required to be repaid within 90 days in three equal monthly payments.
Revolving bank credit facility borrowing base		$ 350,000,000
Revolving bank credit facility interest rate description		Borrowings under the revolving bank credit facility bear interest at the applicable London Interbank Offered Rate (“LIBOR”) plus a margin that varies from 2.25% to 3.25% depending on the level of total borrowings under the Credit Agreement, or an alternative base rate equal to the greater of (a) Prime Rate, (b) Federal Funds Rate plus 0.5%, and (c) LIBOR plus 1.0%, plus applicable margin ranging from 1.25% to 2.25%.
Debt issuance costs write-down/amortization of debt items		$ 3,200,000
Revolving bank credit facility		0	447,000,000
Letters of credit outstanding		$ 900,000	$ 600,000
Revolving Bank Credit Facility Due November 2018 | Maximum
Debt Instrument [Line Items]
Unused portion of the borrowing base commitment fee		0.50%
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 | London Interbank Offered Rate Additional Applicable Margin
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate		2.25%
Revolving Bank Credit Facility Due November 2018 | Minimum
Debt Instrument [Line Items]
Unused portion of the borrowing base commitment fee		0.375%
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 | London Interbank Offered Rate Additional Applicable Margin
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate		1.25%
Revolving Bank Credit Facility Due November 2018 | Letter Of Credit
Debt Instrument [Line Items]
Revolving bank credit facility maximum lender commitment		$ 300,000,000

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	Dec. 31, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair value of commodity derivative contracts	$ 7,672
Revolving bank credit facility		$ 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	324,000	$ 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	$ 217,500

Fair Value Measurements - Sch63

Fair Value Measurements - Schedule of Fair Value of Derivatives Financial Instruments and Long-Term Debt (Parenthetical) (Details)	Dec. 31, 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%

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Details) - USD ($) $ in Thousands	Dec. 31, 2015	May. 31, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Revolving bank credit facility			$ 447,000
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%
Carrying value of senior notes	$ 900,000		$ 900,000
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%
Carrying value of senior notes	$ 300,000
Fair Value, Inputs, Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Revolving bank credit facility	$ 0		$ 447,000
Fair Value, Inputs, Level 2 | 8.50% Senior Notes
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Debt instrument interest rate	8.50%
Fair Value, Inputs, Level 2 | 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%

Equity Structure and Transact65

Equity Structure and Transactions - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Equity Structure And Transactions [Line Items]
Preferred stock, shares authorized	20,000,000	20,000,000
Preferred stock, par value	$ 0.00001	$ 0.00001
Preferred stock, issued	0	0
Cash dividends paid		$ 30,260	$ 58,846
Common Stock, Regular
Equity Structure And Transactions [Line Items]
Paid cash dividends, per share	$ 0	$ 0.40	$ 0.36
Common Stock, Special
Equity Structure And Transactions [Line Items]
Paid cash dividends, per share			$ 0.42
Cash dividends paid			$ 31,800

Incentive Compensation Plan a66

Incentive Compensation Plan and Directors Compensation Plan - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2013
Compensation Plan [Line Items]
Share based compensation performance awards grant performance period	10 years
Annual incentive awards payment period	90 days
Percentage of restricted stock units granted not subject to performance criteria			3.00%
Expected vesting month and year			2015-12
Cash based compensation payment period after achievement of financial condition	30 days
Cash based compensation payment period		75 days
2014 Annual Incentive Plan Award | Chief Executive Officer
Compensation Plan [Line Items]
Common stock pre-determined price per share		$ 14.66
Performance based awards, percentage		100.00%
2013 Annual Incentive Plan Award | Chief Executive Officer
Compensation Plan [Line Items]
Common stock pre-determined price per share			$ 14.84	$ 14.84
Performance based awards, percentage				100.00%
Cash-based Awards | Minimum
Compensation Plan [Line Items]
Adjusted EBITDA less interest expense	$ 300,000,000
Restricted Shares | Directors Compensation Plan Share-Based Awards
Compensation Plan [Line Items]
Vesting rights description	Vesting occurs upon completion of the specified vesting period and one-third of each grant vests each year over a three-year period.
Grant vesting period	3 years	3 years	3 years
Adjusted EBITDA and Adjusted EBITDA Margin
Compensation Plan [Line Items]
Restricted stock units earning per share, minimum	0.00%	0.00%	0.00%
Restricted stock units earning per share, maximum	100.00%	100.00%	150.00%
Shareholder ​Return ​Performance ​Stock ​Awards
Compensation Plan [Line Items]
Restricted stock units earning per share, minimum			0.00%
Restricted stock units earning per share, maximum			200.00%

Share-Based and Cash-Based In67

Share-Based and Cash-Based Incentive Compensation - Additional Information (Details) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Additional shares authorized under share based compensation arrangements			4,000,000
Common stock available for award under plans			4,239,548
Restricted Shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares granted, grant date fair value			$ 0.3	$ 0.3	$ 0.3
Shares vested, vested date fair value			$ 0.1	$ 0.3	$ 0.4
Number of shares granted			56,540	18,815	27,450
Unrecognized share-based compensation expense			$ 0.5
Recognition period for unrecognized compensation expense			2018-04
Restricted Stock Units (RSUs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares granted, grant date fair value			$ 9.4	$ 20.1	$ 12.8
Shares vested, vested date fair value			$ 2.1	$ 2	$ 7.2
Adjusted EBITDA					40.00%
Adjusted EBITDA margin					30.00%
TSR ranking					30.00%
TSR ranking for each of three-year performance periods					10.00%
Expected volatility, minimum					30.00%
Expected volatility, maximum					63.00%
Number of shares granted			2,626,930	1,195,388	969,919
Unrecognized share-based compensation expense			$ 12.7
Recognition period for unrecognized compensation expense			2017-11
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]
Number of shares issued	37,316
CEO's 2013 Award | Chief Executive Officer
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of shares issued		42,547
Number of shares granted		42,547
Directors Compensation Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common stock available for award under plans			444,024

Share-Based and Cash-Based In68

Share-Based and Cash-Based Incentive Compensation - Schedule of Restricted Stock Activity (Details) - Restricted Shares - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Nonvested, beginning of period	43,210	43,840	43,687
Granted	56,540	18,815	27,450
Vested	(21,520)	(19,445)	(27,297)
Nonvested, end of period	78,230	43,210	43,840
Weighted Average Grant Date Value, Beginning of period	$ 16.20	$ 15.96	$ 18.69
Weighted Average Grant Date Fair Value, Granted	6.19	18.60	12.75
Weighted Average Grant Date Fair Value, Vested	16.26	18	17.09
Weighted Average Grant Date Value, End of period	$ 8.95	$ 16.20	$ 15.96

Share-Based and Cash-Based In69

Share-Based and Cash-Based Incentive Compensation - Schedule of Restricted Stock Awards Outstanding (Details) - Restricted Shares - shares	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	78,230	43,210	43,840	43,687
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 and Cash-Based In70

Share-Based and Cash-Based Incentive Compensation - Summary of Share Activity Related to Restricted Stock Units (Details) - Restricted Stock Units (RSUs) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Nonvested, beginning of period	1,977,335	1,331,753	969,820
Granted	2,626,930	1,195,388	969,919
Vested	(721,038)	(354,692)	(468,925)
Forfeited	(409,148)	(195,114)	(139,061)
Nonvested, end of period	3,474,079	1,977,335	1,331,753
Weighted Average Grant Date Value, Beginning of period	$ 15.29	$ 14.96	$ 22.70
Weighted Average Grant Date Fair Value, Granted	3.59	16.84	13.23
Weighted Average Grant Date Fair Value, Vested	13.23	18.59	26.93
Weighted Average Grant Date Fair Value, Forfeited	10.63	16.53	16.50
Weighted Average Grant Date Value, End of period	$ 7.42	$ 15.29	$ 14.96

Share-Based and Cash-Based In71

Share-Based and Cash-Based Incentive Compensation - Schedule of Restricted Stock Units Outstanding (Details) - Restricted Stock Units (RSUs) - shares	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	3,474,079	1,977,335	1,331,753	969,820
2,016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	1,003,604
2,017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	2,470,475

Share-Based and Cash-Based In72

Share-Based and Cash-Based Incentive Compensation - Summary of Compensation Expense under Share-Based Payment Arrangements and Related Tax Benefit (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation	$ 10,242	$ 14,744	$ 11,525
Tax benefit computed at the statutory rate	3,585	5,160	4,034
Restricted Shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation	358	369	397
Restricted Stock Units (RSUs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation	9,978	13,150	$ 11,128
Common Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation	$ (94)	$ 1,225

Share-Based and Cash-Based In73

Share-Based and Cash-Based Incentive Compensation - Summary of Incentive Compensation Expense (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Share-based compensation charged to operating income		$ 10,242	$ 14,744	$ 11,525
Total charged to operating income		10,373	24,979	23,824
General And Administrative Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Share-based compensation charged to operating income		10,242	14,744	11,525
Cash-based incentive compensation charged to operating income	[1]	(233)	6,950	8,817
Lease Operating Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Cash-based incentive compensation charged to operating income		$ 364	$ 3,285	$ 3,482
[1]	Adjustments to true up estimates to actual payments resulted in net credit balances to expense for 2015.

Employee Benefit Plan - Additio

Employee Benefit Plan - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Compensation And Retirement Disclosure [Abstract]
Percentage of matching contribution of each participants	100.00%	100.00%	100.00%
Maximum contribution percentage of participating employees	6.00%	6.00%	6.00%
Year of service on which employer's matching contribution under 401K plan will be 100% vested	5 years
Defined Contribution Plan, Employers Matching Contribution, Annual Vesting Percentage	20.00%
Company's contribution to 401K plan	$ 2.3	$ 2.4	$ 2.1

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current	$ 288	$ 301	$ (2,146)
Deferred	(203,272)	(4,760)	30,920
Income tax expense (benefit)	$ (202,984)	$ (4,459)	$ 28,774

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Income Taxes Computed to Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income tax expense (benefit) at the federal statutory rate	$ (436,696)	$ (5,642)	$ 28,033
Share-based compensation	2,940
State income taxes	(2,343)	263	343
Valuation allowance	232,925
Other	190	920	398
Income tax expense (benefit)	$ (202,984)	$ (4,459)	$ 28,774
Income tax expense (benefit) at the federal statutory rate, tax rate	35.00%	35.00%	35.00%
Share-based compensation, tax rate	(0.20%)
State income taxes, tax rate	0.20%	(1.60%)	0.40%
Valuation allowance, tax rate	(18.70%)
Other, tax rate		(5.70%)	0.50%
Effective income tax rate, total	16.30%	27.70%	35.90%

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Federal statutory income tax rate	35.00%	35.00%	35.00%
Cash paid for income taxes	$ 390		$ 3,000
Unrecognized tax benefits	9,482	$ 9,482	9,482
Proceeds from income tax refunds	90	$ 3,000	$ 59,126
Valuation allowance	$ 232,900
Minimum
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Tax years under examination	2,012
Maximum
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Tax years under examination	2,015

Income Taxes - Significant Comp

Income Taxes - Significant Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Deferred tax liabilities:
Property and equipment	$ 40,287	$ 518,566
Derivatives	2,697
Other	3,000	5,019
Total deferred tax liabilities	45,984	523,585
Deferred tax assets:
Alternative minimum tax credit	20,486	20,486
Asset retirement obligations	133,018	137,597
Federal net operating losses	145,733	180,024
State net operating losses	5,068	5,008
Valuation allowance	(237,275)	(4,255)
Accrued cash-based bonus		3,559
Share-based compensation	4,245	5,042
Other	2,304	798
Total deferred tax assets	73,579	348,259
Net deferred tax asset	$ 27,595
Net deferred tax (liability)		$ (175,326)

Income Taxes - Net Operating Lo

Income Taxes - Net Operating Loss and Tax Credit Carryovers (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)
Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]
Net operating loss	$ 418,417
Internal Revenue Service (IRS) | Minimum
Operating Loss Carryforwards [Line Items]
Net operating loss, expiration year	Dec. 31, 2032
Internal Revenue Service (IRS) | Maximum
Operating Loss Carryforwards [Line Items]
Net operating loss, expiration year	Dec. 31, 2035
State and Local Jurisdiction
Operating Loss Carryforwards [Line Items]
Net operating loss	$ 100,651
State and Local Jurisdiction | Minimum
Operating Loss Carryforwards [Line Items]
Net operating loss, expiration year	Dec. 31, 2021
State and Local Jurisdiction | Maximum
Operating Loss Carryforwards [Line Items]
Net operating loss, expiration year	Dec. 31, 2029
Alternative Minimum Tax Credit
Operating Loss Carryforwards [Line Items]
Tax credit carryforward	$ 12,091
Tax credit carryforward, expiration year description	Indefinite
General Business Tax Credit Carryforward
Operating Loss Carryforwards [Line Items]
Tax credit carryforward	$ 406
General Business Tax Credit Carryforward | Minimum
Operating Loss Carryforwards [Line Items]
Tax credit carryforward, expiration year	Dec. 31, 2027
General Business Tax Credit Carryforward | Maximum
Operating Loss Carryforwards [Line Items]
Tax credit carryforward, expiration year	Dec. 31, 2028

Income Taxes - Balances in Unce

Income Taxes - Balances in Uncertain Tax Positions (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Balance, beginning and end of period	$ 9,482	$ 9,482	$ 9,482

Earnings Per Share - Schedule o

Earnings Per Share - Schedule of Calculation of Basic and Diluted Earnings Per Common Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2015	[1]	Sep. 30, 2015	[1]	Jun. 30, 2015	[1]	Mar. 31, 2015	[1]	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share, Basic and Diluted [Abstract]
Net income (loss)	$ (51,606)		$ (477,568)		$ (260,449)		$ (255,095)		$ (33,371)		$ 684		$ 9,837		$ 11,189		$ (1,044,718)	$ (11,661)	$ 51,322
Less portion allocated to nonvested shares																		269	303
Net income (loss) allocated to common shares																	$ (1,044,718)	$ (11,930)	$ 51,019
Weighted average common shares outstanding																	75,931	75,609	75,239
Basic and diluted earnings (loss) per common share	$ (0.68)	[2]	$ (6.29)	[2]	$ (3.43)	[2]	$ (3.36)	[2]	$ (0.44)	[2]	$ 0.01	[2]	$ 0.13	[2]	$ 0.15	[2]	$ (13.76)	$ (0.16)	$ 0.68
Shares excluded due to being anti-dilutive (weighted-average)																	2,195	2,097
[1]	During 2015, we recorded in first, second, third and fourth quarter ceiling test write-downs of oil and natural gas properties of $260.4 million, $252.8 million, $441.6 million and $32.4 million, respectively. See Note 1 for additional information.
[2]	The sum of the individual quarterly earnings (loss) per share may not agree with the year loss per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter.

Supplemental Cash Flow Inform82

Supplemental Cash Flow Information - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Cash Flow Elements [Abstract]
Cash paid for interest, net of interest capitalized of $7,256 in 2015, $8,526 in 2014 and $10,058 in 2013		$ 92,622	$ 77,607	$ 73,909
Cash paid for income taxes		390		3,000
Cash refunds received for income taxes		$ 90	3,000	59,126
Cash paid for share-based compensation	[1]		$ 431	$ 466
[1]	The cash paid for share-based compensation is for dividends on unvested restricted stock and for dividend equivalents paid on RSUs. No cash was received from employees or directors related to share-based compensation and no cash was used to settle any equity instruments granted under share-based compensation arrangements.

Supplemental Cash Flow Inform83

Supplemental Cash Flow Information - Supplemental Cash Flow Information (Parenthetical) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Cash Flow Elements [Abstract]
Cash paid, interest capitalized	$ 7,256	$ 8,526	$ 10,058

Commitments - Additional Inform

Commitments - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments [Line Items]
Minimum future lease payments due under noncancelable operating leases, 2016	$ 1,600,000
Minimum future lease payments due under noncancelable operating leases, 2017	1,600,000
Minimum future lease payments due under noncancelable operating leases, 2018	1,700,000
Minimum future lease payments due under noncancelable operating leases, 2019	1,800,000
Minimum future lease payments due under noncancelable operating leases, thereafter	5,700,000
Total rent expense	3,300,000	$ 3,200,000	$ 2,600,000
Security amount requirement	73,000,000
Additional security requirements for 2016	6,000,000
Additional security requirements for 2017	4,000,000
Additional security requirements for 2018	5,000,000
Additional security requirements for 2019	3,000,000
Additional security requirements for 2020 to 2023	12,000,000
Total security requirement	$ 103,000,000
Lease expiration date	Dec. 31, 2023
Expenses related to surety bonds	$ 5,500,000	$ 4,100,000	$ 5,000,000
Other commitments	5,800,000
Future estimated costs, 2017	5,900,000
Future estimated costs, 2018	5,300,000
Future estimated costs, 2019	5,000,000
Future estimated costs, thereafter	30,400,000
Drilling Rig Commitments
Commitments [Line Items]
Minimum future lease payments due under noncancelable operating leases, 2015	7,000,000
Helix Well Containment Group
Commitments [Line Items]
Other commitments	2,100,000
Future estimated costs, 2017	2,100,000
Other commitment
Commitments [Line Items]
Security requirement minimum	64,000,000
Security requirement maximum	$ 94,000,000

Related Parties - Additional In

Related Parties - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	May. 31, 2015
9.00% Term Loan due 2020
Related Party Transaction [Line Items]
Debt instrument interest rate	9.00%			9.00%
Carrying value of senior notes	$ 300,000,000
Airplane Services
Related Party Transaction [Line Items]
Related party transactions	1,100,000	$ 900,000	$ 1,200,000
Directional Drilling Services
Related Party Transaction [Line Items]
Related party transactions	$ 0	200,000	200,000
Majority Shareholder [Member] | 9.00% Term Loan due 2020
Related Party Transaction [Line Items]
Debt instrument interest rate	9.00%
Carrying value of senior notes	$ 5,000,000
Minimum | Marine Transportation and Logistic Services
Related Party Transaction [Line Items]
Related party transactions	$ 200,000	$ 200,000	$ 200,000

Contingencies - Additional Info

Contingencies - Additional Information (Details)	1 Months Ended	3 Months Ended	12 Months Ended
	Jan. 31, 2014USD ($)	Mar. 31, 2014USD ($)	Dec. 31, 2015USD ($)claim	Dec. 31, 2014USD ($)	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
Statutory fine payment relative to underpayment revised value		$ 1,100,000
Amount accrued			$ 0	$ 0
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			$ 43,000,000
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			31,000,000
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

Selected Quarterly Financial 87

Selected Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 104,064		$ 126,228		$ 149,066		$ 127,907		$ 196,677		$ 234,521		$ 262,994		$ 254,516		$ 507,265	$ 948,708	$ 984,088
Operating income (loss)	(60,816)	[1]	(468,573)	[1]	(278,806)	[1]	(337,508)	[1]	(30,543)		20,983		34,403		37,225		(1,145,703)	62,068	146,731
Net income (loss)	$ (51,606)	[1]	$ (477,568)	[1]	$ (260,449)	[1]	$ (255,095)	[1]	$ (33,371)		$ 684		$ 9,837		$ 11,189		$ (1,044,718)	$ (11,661)	$ 51,322
Basic and diluted earnings (loss) per common share	$ (0.68)	[1],[2]	$ (6.29)	[1],[2]	$ (3.43)	[1],[2]	$ (3.36)	[1],[2]	$ (0.44)	[2]	$ 0.01	[2]	$ 0.13	[2]	$ 0.15	[2]	$ (13.76)	$ (0.16)	$ 0.68
[1]	During 2015, we recorded in first, second, third and fourth quarter ceiling test write-downs of oil and natural gas properties of $260.4 million, $252.8 million, $441.6 million and $32.4 million, respectively. See Note 1 for additional information.
[2]	The sum of the individual quarterly earnings (loss) per share may not agree with the year loss per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter.

Selected Quarterly Financial 88

Selected Quarterly Financial Data (Parenthetical) (Details) - USD ($)	3 Months Ended				12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Ceiling test write-down of oil and natural gas properties	$ 32,400,000	$ 441,600,000	$ 252,800,000	$ 260,400,000	$ 987,238,000	$ 0	$ 0

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) - USD ($) $ in Thousands	2 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015	Feb. 26, 2016	Dec. 31, 2014
Subsequent Event [Line Items]
Revolving bank credit facility				$ 447,000
Bonds to be secured, date		Mar. 29, 2016
Subsequent Event
Subsequent Event [Line Items]
Revolving bank credit facility			$ 340,000
Cash balance after borrowing			447,000
Line of credit, borrowing availability			$ 9,100
Obligation to secure financial assurances	$ 260,800

Supplemental Guarantor Inform90

Supplemental Guarantor Information - Additional Information (Details)	Dec. 31, 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 Inform91

Supplemental Guarantor Information - Condensed Consolidating Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 85,414	$ 23,666	$ 15,800	$ 12,245
Receivables:
Oil and natural gas sales	35,005	67,242
Joint interest and other	22,012	43,645
Total receivables	57,017	110,887
Prepaid expenses and other assets	26,879	36,347
Total current assets	169,310	170,900
Property and equipment - at cost:
Oil and natural gas properties and equipment	7,902,494	8,045,666
Furniture, fixtures and other	20,802	23,269
Total property and equipment	7,923,296	8,068,935
Less accumulated depreciation, depletion and amortization	6,933,247	5,575,078
Net property and equipment	990,049	2,493,857
Deferred income taxes	27,595
Restricted deposits for asset retirement obligations	15,606	15,444
Other assets	5,462	9,307
Total assets	1,208,022	2,689,508
Current liabilities:
Accounts payable	109,797	194,109
Undistributed oil and natural gas proceeds	21,439	37,009
Asset retirement obligations	84,335	36,003
Accrued liabilities	11,922	17,377
Total current liabilities	227,493	284,498
Long-term debt, less current maturities	1,196,855	1,352,120
Asset retirement obligations, less current portion	293,987	354,565
Deferred income taxes		175,326
Other liabilities	16,178	13,691
Shareholders’ equity:
Common stock	1	1
Additional paid-in capital	423,499	414,580
Retained earnings (deficit)	(925,824)	118,894
Treasury stock, at cost	(24,167)	(24,167)
Total shareholders’ equity (deficit)	(526,491)	509,308	540,610	541,187
Total liabilities and shareholders’ equity (deficit)	1,208,022	2,689,508
Parent Company
Current assets:
Cash and cash equivalents	85,414	23,666	$ 15,800	$ 12,245
Receivables:
Oil and natural gas sales	2,742	41,820
Joint interest and other	121,190	142,885
Total receivables	123,932	184,705
Prepaid expenses and other assets	25,375	28,728
Total current assets	234,721	237,099
Property and equipment - at cost:
Oil and natural gas properties and equipment	5,682,793	6,038,915
Furniture, fixtures and other	20,802	23,269
Total property and equipment	5,703,595	6,062,184
Less accumulated depreciation, depletion and amortization	5,258,563	4,442,899
Net property and equipment	445,032	1,619,285
Deferred income taxes	27,251
Restricted deposits for asset retirement obligations	15,606	15,444
Other assets	498,782	966,112
Total assets	1,221,392	2,837,940
Current liabilities:
Accounts payable	100,282	188,654
Undistributed oil and natural gas proceeds	20,463	36,130
Asset retirement obligations	63,716	30,711
Accrued liabilities	11,922	17,437
Total current liabilities	196,383	272,932
Long-term debt, less current maturities	1,196,855	1,352,120
Asset retirement obligations, less current portion	173,105	235,876
Deferred income taxes		49,819
Other liabilities	329,129	417,885
Shareholders’ equity:
Common stock	1	1
Additional paid-in capital	423,499	414,580
Retained earnings (deficit)	(1,073,413)	118,894
Treasury stock, at cost	(24,167)	(24,167)
Total shareholders’ equity (deficit)	(674,080)	509,308
Total liabilities and shareholders’ equity (deficit)	1,221,392	2,837,940
Guarantor Subsidiaries
Receivables:
Oil and natural gas sales	32,263	25,422
Total receivables	32,263	25,422
Prepaid expenses and other assets	1,504	7,619
Total current assets	33,767	33,041
Property and equipment - at cost:
Oil and natural gas properties and equipment	2,219,701	2,006,751
Total property and equipment	2,219,701	2,006,751
Less accumulated depreciation, depletion and amortization	1,822,273	1,132,179
Net property and equipment	397,428	874,572
Deferred income taxes	344
Other assets	266,748	357,992
Total assets	698,287	1,265,605
Current liabilities:
Accounts payable	9,515	5,455
Undistributed oil and natural gas proceeds	976	879
Asset retirement obligations	20,619	5,292
Accrued liabilities	99,178	99,180
Total current liabilities	130,288	110,806
Asset retirement obligations, less current portion	120,882	118,689
Deferred income taxes		125,507
Shareholders’ equity:
Additional paid-in capital	704,885	703,440
Retained earnings (deficit)	(257,768)	207,163
Total shareholders’ equity (deficit)	447,117	910,603
Total liabilities and shareholders’ equity (deficit)	698,287	1,265,605
Eliminations
Receivables:
Joint interest and other	(99,178)	(99,240)
Total receivables	(99,178)	(99,240)
Total current assets	(99,178)	(99,240)
Property and equipment - at cost:
Less accumulated depreciation, depletion and amortization	(147,589)
Net property and equipment	147,589
Other assets	(760,068)	(1,314,797)
Total assets	(711,657)	(1,414,037)
Current liabilities:
Accrued liabilities	(99,178)	(99,240)
Total current liabilities	(99,178)	(99,240)
Other liabilities	(312,951)	(404,194)
Shareholders’ equity:
Additional paid-in capital	(704,885)	(703,440)
Retained earnings (deficit)	405,357	(207,163)
Total shareholders’ equity (deficit)	(299,528)	(910,603)
Total liabilities and shareholders’ equity (deficit)	$ (711,657)	$ (1,414,037)

Supplemental Guarantor Inform92

Supplemental Guarantor Information - Condensed Consolidating Statement of Operations (Details) - USD ($)	3 Months Ended												12 Months Ended
	Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Income Statements Captions [Line Items]
Revenues	$ 104,064,000		$ 126,228,000		$ 149,066,000		$ 127,907,000		$ 196,677,000	$ 234,521,000	$ 262,994,000	$ 254,516,000	$ 507,265,000	$ 948,708,000	$ 984,088,000
Operating costs and expenses:
Lease operating expenses													192,765,000	264,751,000	270,839,000
Production taxes													3,002,000	7,932,000	7,135,000
Gathering and transportation													17,157,000	19,821,000	17,510,000
Depreciation, depletion and amortization													373,368,000	490,469,000	430,611,000
Asset retirement obligations accretion													20,703,000	20,633,000	20,918,000
Ceiling test write-down of oil and natural gas properties	32,400,000		441,600,000		252,800,000		260,400,000						987,238,000	0	0
General and administrative expenses													73,110,000	86,999,000	81,874,000
Derivative (gain) loss													(14,375,000)	(3,965,000)	8,470,000
Total costs and expenses													1,652,968,000	886,640,000	837,357,000
Operating income (loss)	(60,816,000)	[1]	(468,573,000)	[1]	(278,806,000)	[1]	(337,508,000)	[1]	(30,543,000)	20,983,000	34,403,000	37,225,000	(1,145,703,000)	62,068,000	146,731,000
Interest expense:
Incurred													104,592,000	86,922,000	85,639,000
Capitalized													(7,256,000)	(8,526,000)	(10,058,000)
Other (income) expense, net													4,663,000	(208,000)	(8,946,000)
Income (loss) before income tax expense (benefit)													(1,247,702,000)	(16,120,000)	80,096,000
Income tax expense (benefit)													(202,984,000)	(4,459,000)	28,774,000
Net income (loss)	$ (51,606,000)	[1]	$ (477,568,000)	[1]	$ (260,449,000)	[1]	$ (255,095,000)	[1]	$ (33,371,000)	$ 684,000	$ 9,837,000	$ 11,189,000	(1,044,718,000)	(11,661,000)	51,322,000
Parent Company
Condensed Income Statements Captions [Line Items]
Revenues													290,212,000	571,365,000	631,267,000
Operating costs and expenses:
Lease operating expenses													126,189,000	180,149,000	202,096,000
Production taxes													3,002,000	7,932,000	7,135,000
Gathering and transportation													9,209,000	11,790,000	9,248,000
Depreciation, depletion and amortization													201,154,000	267,406,000	236,600,000
Asset retirement obligations accretion													11,587,000	10,981,000	14,218,000
Ceiling test write-down of oil and natural gas properties													616,947,000
General and administrative expenses													39,009,000	46,513,000	44,040,000
Derivative (gain) loss													(14,375,000)	(3,965,000)	8,470,000
Total costs and expenses													992,722,000	520,806,000	521,807,000
Operating income (loss)													(702,510,000)	50,559,000	109,460,000
Earnings (loss) of affiliates													(464,931,000)	8,320,000	24,400,000
Interest expense:
Incurred													101,542,000	84,460,000	82,570,000
Capitalized													(4,206,000)	(6,064,000)	(6,989,000)
Other (income) expense, net													4,663,000	(208,000)	(8,946,000)
Income (loss) before income tax expense (benefit)													(1,269,440,000)	(19,309,000)	67,225,000
Income tax expense (benefit)													(77,133,000)	(7,648,000)	15,903,000
Net income (loss)													(1,192,307,000)	(11,661,000)	51,322,000
Guarantor Subsidiaries
Condensed Income Statements Captions [Line Items]
Revenues													217,053,000	377,343,000	352,821,000
Operating costs and expenses:
Lease operating expenses													66,576,000	84,602,000	68,743,000
Gathering and transportation													7,948,000	8,031,000	8,262,000
Depreciation, depletion and amortization													172,214,000	223,063,000	194,011,000
Asset retirement obligations accretion													9,116,000	9,652,000	6,700,000
Ceiling test write-down of oil and natural gas properties													517,880,000
General and administrative expenses													34,101,000	40,486,000	37,834,000
Total costs and expenses													807,835,000	365,834,000	315,550,000
Operating income (loss)													(590,782,000)	11,509,000	37,271,000
Interest expense:
Incurred													3,050,000	2,462,000	3,069,000
Capitalized													(3,050,000)	(2,462,000)	(3,069,000)
Income (loss) before income tax expense (benefit)													(590,782,000)	11,509,000	37,271,000
Income tax expense (benefit)													(125,851,000)	3,189,000	12,871,000
Net income (loss)													(464,931,000)	8,320,000	24,400,000
Eliminations
Operating costs and expenses:
Ceiling test write-down of oil and natural gas properties													(147,589,000)
Total costs and expenses													(147,589,000)
Operating income (loss)													147,589,000
Earnings (loss) of affiliates													464,931,000	(8,320,000)	(24,400,000)
Interest expense:
Income (loss) before income tax expense (benefit)													612,520,000	(8,320,000)	(24,400,000)
Net income (loss)													$ 612,520,000	$ (8,320,000)	$ (24,400,000)
[1]	During 2015, we recorded in first, second, third and fourth quarter ceiling test write-downs of oil and natural gas properties of $260.4 million, $252.8 million, $441.6 million and $32.4 million, respectively. See Note 1 for additional information.

Supplemental Guarantor Inform93

Supplemental Guarantor Information - Condensed Consolidating Statement of Cash Flows (Details) - USD ($)	3 Months Ended												12 Months Ended
	Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating activities:
Net income (loss)	$ (51,606,000)	[1]	$ (477,568,000)	[1]	$ (260,449,000)	[1]	$ (255,095,000)	[1]	$ (33,371,000)	$ 684,000	$ 9,837,000	$ 11,189,000	$ (1,044,718,000)	$ (11,661,000)	$ 51,322,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion													394,071,000	511,102,000	451,529,000
Ceiling test write-down of oil and natural gas properties	32,400,000		$ 441,600,000		$ 252,800,000		260,400,000						987,238,000	0	0
Debt issuance costs write-off/amortization of debt items													4,411,000	701,000	1,645,000
Share-based compensation													10,242,000	14,744,000	11,525,000
Derivative (gain) loss													(14,375,000)	(3,965,000)	8,470,000
Cash receipts (payments) on derivative settlements, net													6,703,000	(5,318,000)	(8,589,000)
Deferred income taxes													(203,272,000)	(4,760,000)	30,920,000
Changes in operating assets and liabilities:
Oil and natural gas receivables													32,236,000	29,510,000	980,000
Joint interest and other receivables													21,633,000	(4,255,000)	34,257,000
Income taxes													(7,000)	3,143,000	44,328,000
Prepaid expenses and other assets													17,816,000	15,012,000	(10,044,000)
Asset retirement obligation settlements													(32,555,000)	(74,313,000)	(81,543,000)
Accounts payable, accrued liabilities and other													(46,869,000)	4,033,000	27,908,000
Net cash provided by operating activities													132,554,000	473,973,000	562,708,000
Investing activities:
Acquisition of property interest in oil and natural gas properties														(72,234,000)	(82,424,000)
Investment in oil and natural gas properties and equipment													(230,161,000)	(554,378,000)	(551,954,000)
Changes in operating assets and liabilities associated with investing activities													(55,425,000)	37,450,000	(1,350,000)
Proceeds from sales of assets and other, net													372,939,000		21,008,000
Purchases of furniture, fixtures and other													(1,278,000)	(3,340,000)	(1,435,000)
Net cash provided by (used in) investing activities													86,075,000	(592,502,000)	(616,155,000)
Financing activities:
Borrowings of long-term debt - revolving bank credit facility													263,000,000	556,000,000	563,000,000
Repayments of long-term debt - revolving bank credit facility													(710,000,000)	(399,000,000)	(443,000,000)
Issuance of 9.00% Term Loan													297,000,000
Debt issuance costs													(6,669,000)		(3,892,000)
Dividends to shareholders														(30,260,000)	(58,846,000)
Other													(212,000)	(345,000)	(260,000)
Net cash provided by (used in) financing activities													(156,881,000)	126,395,000	57,002,000
Increase in cash and cash equivalents													61,748,000	7,866,000	3,555,000
Cash and cash equivalents, beginning of period							23,666,000					15,800,000	23,666,000	15,800,000	12,245,000
Cash and cash equivalents, end of period	85,414,000								23,666,000				85,414,000	23,666,000	15,800,000
Parent Company
Operating activities:
Net income (loss)													(1,192,307,000)	(11,661,000)	51,322,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion													212,741,000	278,387,000	250,818,000
Ceiling test write-down of oil and natural gas properties													616,947,000
Debt issuance costs write-off/amortization of debt items													4,411,000	701,000	1,645,000
Share-based compensation													10,242,000	14,744,000	11,525,000
Derivative (gain) loss													(14,375,000)	(3,965,000)	8,470,000
Cash receipts (payments) on derivative settlements, net													6,703,000	(5,318,000)	(8,589,000)
Deferred income taxes													(77,421,000)	(32,456,000)	7,564,000
Earnings (loss) of affiliates													464,931,000	(8,320,000)	(24,400,000)
Changes in operating assets and liabilities:
Oil and natural gas receivables													39,078,000	19,553,000	6,182,000
Joint interest and other receivables													21,633,000	(4,255,000)	34,257,000
Income taxes													(7,000)	27,650,000	54,813,000
Prepaid expenses and other assets													(13,916,000)	45,962,000	(25,329,000)
Asset retirement obligation settlements													(26,637,000)	(57,253,000)	(65,438,000)
Accounts payable, accrued liabilities and other													(142,270,000)	11,083,000	74,693,000
Net cash provided by operating activities													(90,247,000)	274,852,000	377,533,000
Investing activities:
Acquisition of property interest in oil and natural gas properties														(17,407,000)
Investment in oil and natural gas properties and equipment													(31,534,000)	(312,044,000)	(349,804,000)
Changes in operating assets and liabilities associated with investing activities													(29,806,000)	1,733,000	(14,732,000)
Proceeds from sales of assets and other, net													372,939,000		21,008,000
Investment in subsidiary													(1,445,000)	(62,323,000)	(86,017,000)
Purchases of furniture, fixtures and other													(1,278,000)	(3,340,000)	(1,435,000)
Net cash provided by (used in) investing activities													308,876,000	(393,381,000)	(430,980,000)
Financing activities:
Borrowings of long-term debt - revolving bank credit facility													263,000,000	556,000,000	563,000,000
Repayments of long-term debt - revolving bank credit facility													(710,000,000)	(399,000,000)	(443,000,000)
Issuance of 9.00% Term Loan													297,000,000
Debt issuance costs													(6,669,000)		(3,892,000)
Dividends to shareholders														(30,260,000)	(58,846,000)
Other													(212,000)	(345,000)	(260,000)
Net cash provided by (used in) financing activities													(156,881,000)	126,395,000	57,002,000
Increase in cash and cash equivalents													61,748,000	7,866,000	3,555,000
Cash and cash equivalents, beginning of period							$ 23,666,000					$ 15,800,000	23,666,000	15,800,000	12,245,000
Cash and cash equivalents, end of period	$ 85,414,000								$ 23,666,000				85,414,000	23,666,000	15,800,000
Guarantor Subsidiaries
Operating activities:
Net income (loss)													(464,931,000)	8,320,000	24,400,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion													181,330,000	232,715,000	200,711,000
Ceiling test write-down of oil and natural gas properties													517,880,000
Deferred income taxes													(125,851,000)	27,696,000	23,356,000
Changes in operating assets and liabilities:
Oil and natural gas receivables													(6,842,000)	9,957,000	(5,202,000)
Income taxes														(24,507,000)	(10,485,000)
Prepaid expenses and other assets													122,977,000	(7,525,000)	(18,835,000)
Asset retirement obligation settlements													(5,918,000)	(17,060,000)	(16,105,000)
Accounts payable, accrued liabilities and other													4,156,000	(30,475,000)	(12,665,000)
Net cash provided by operating activities													222,801,000	199,121,000	185,175,000
Investing activities:
Acquisition of property interest in oil and natural gas properties														(54,827,000)	(82,424,000)
Investment in oil and natural gas properties and equipment													(198,627,000)	(242,334,000)	(202,150,000)
Changes in operating assets and liabilities associated with investing activities													(25,619,000)	35,717,000	13,382,000
Net cash provided by (used in) investing activities													(224,246,000)	(261,444,000)	(271,192,000)
Financing activities:
Investment from parent													1,445,000	62,323,000	86,017,000
Net cash provided by (used in) financing activities													1,445,000	62,323,000	86,017,000
Eliminations
Operating activities:
Net income (loss)													612,520,000	(8,320,000)	(24,400,000)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Ceiling test write-down of oil and natural gas properties													(147,589,000)
Earnings (loss) of affiliates													(464,931,000)	8,320,000	24,400,000
Changes in operating assets and liabilities:
Prepaid expenses and other assets													(91,245,000)	(23,425,000)	34,120,000
Accounts payable, accrued liabilities and other													91,245,000	23,425,000	(34,120,000)
Investing activities:
Investment in subsidiary													1,445,000	62,323,000	86,017,000
Net cash provided by (used in) investing activities													1,445,000	62,323,000	86,017,000
Financing activities:
Investment from parent													(1,445,000)	(62,323,000)	(86,017,000)
Net cash provided by (used in) financing activities													$ (1,445,000)	$ (62,323,000)	$ (86,017,000)
[1]	During 2015, we recorded in first, second, third and fourth quarter ceiling test write-downs of oil and natural gas properties of $260.4 million, $252.8 million, $441.6 million and $32.4 million, respectively. See Note 1 for additional information.

Supplemental Guarantor Inform94

Supplemental Guarantor Information - Condensed Consolidating Statement of Cash Flows (Parenthetical) (Details)	Dec. 31, 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%

Supplemental Oil and Gas Disc95

Supplemental Oil and Gas Disclosures - Capitalized Costs Related to Oil and Natural Gas (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net capitalized cost:
Proved oil and natural gas properties and equipment		$ 7,882.3	$ 7,924.2	$ 7,207.1
Unproved oil and natural gas properties and equipment		20.2	121.5	132
Accumulated depreciation, depletion and amortization related to oil, NGLs and natural gas activities	[1]	(6,916.2)	(5,557.6)	(5,069.2)
Net capitalized costs related to producing activities		$ 986.3	$ 2,488.1	$ 2,269.9
[1]	Includes ceiling test write-down in 2015.

Supplemental Oil and Gas Disc96

Supplemental Oil and Gas Disclosures - Additional Information (Details)	12 Months Ended
	Dec. 31, 2015
Reserve Quantities [Line Items]
Percentage non-operated non-producing reserves	27.00%
Percentage of proved undeveloped reserves	12.00%
Present value discounted percentage	10.00%
Minimum
Reserve Quantities [Line Items]
Expected time to evaluate properties, in years	1 year
Maximum
Reserve Quantities [Line Items]
Expected time to evaluate properties, in years	5 years

Supplemental Oil and Gas Disc97

Supplemental Oil and Gas Disclosures - Capitalized Costs Not Subject to Amortization (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Costs excluded by year incurred:
Acquisition costs, Total	$ 13.9
Capitalized interest not subject to amortization, Total	4.7
Total costs not subject to amortization, Total	18.6
Acquisition costs		$ 0.5	$ 4.9	$ 8.5
Capitalized interest not subject to amortization	1.5	1.2	0.9	1.1
Total costs not subject to amortization	$ 1.5	$ 1.7	$ 5.8	$ 9.6

Supplemental Oil and Gas Disc98

Supplemental Oil and Gas Disclosures - Cost Incurred in Oil and Gas Property Acquisition Exploration and Development Activities (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Costs incurred:
Proved properties acquisitions	[1]	$ 15.6	$ 111.5	$ 96.9
Exploration	[1],[2],[3]	152.4	411.1	215.3
Development	[1]	65.5	198.7	352.9
Unproved property acquisitions	[1],[4]	0.1	3.1	26.3
Total costs incurred in oil and gas property acquisition, exploration and development activities	[1]	$ 233.6	$ 724.4	$ 691.4
[1]	Includes net reductions from capitalized ARO of $0.4 million in 2015 and net additions from capitalized ARO of $88.0 million and $50.6 million during 2014 and 2013, respectively, associated with acquisitions, liabilities incurred, divestitures and revisions of estimates.
[2]	Includes geological and geophysical costs charged to expense of $5.7 million, $7.3 million and $5.9 million during 2015, 2014 and 2013, respectively.
[3]	Includes seismic costs of $3.2 million, $9.0 million and $8.9 million incurred during 2015, 2014 and 2013, respectively.
[4]	The amounts for unproved property acquisitions include capitalized interest associated with unproved properties acquired during the period.

Supplemental Oil and Gas Disc99

Supplemental Oil and Gas Disclosures - Cost Incurred in Oil and Gas Property Acquisition Exploration and Development Activities (Parenthetical) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Capitalized Costs Oil And Gas Producing Activities Net [Abstract]
Additions (reductions) of asset retirement obligations	$ (0.4)	$ 88	$ 50.6
Seismic costs	3.2	9	8.9
Geological and geophysical costs	$ 5.7	$ 7.3	$ 5.9

Supplemental Oil and Gas Dis100

Supplemental Oil and Gas Disclosures - Schedule of Depreciation, Depletion, Amortization and Accretion Expense (Details) - $ / Boe	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Capitalized Costs Oil And Gas Producing Activities Net [Abstract]
Depreciation, depletion, amortization and accretion per Boe	23.11	28.98	25.10

Supplemental Oil and Gas Dis101

Supplemental Oil and Gas Disclosures - Estimated Quantities of Net Proved, Proved Developed and Proved Undeveloped Oil, Ngls and Natural Gas Reserves (Details) Bcfe in Millions		12 Months Ended
		Dec. 31, 2015MMBoeBcfeMMBblsBcf		Dec. 31, 2014MMBoeBcfeMMBblsBcf		Dec. 31, 2013MMBoeBcfeMMBblsBcf
Oil
Reserve Quantities [Line Items]
Proved reserves, beginning balance		61.7		58.5		54.8
Revisions of previous estimates		4.8	[1]	1.6	[2]	(4.3)	[3]
Revisions related to sold properties	[4]	(12.1)
Extensions and discoveries		2.4	[5]	7.3	[6]	13.9	[7]
Purchase of minerals in place				1.5	[8]	1.5	[9]
Sales of reserves		(13.5)	[10]			(0.4)	[11]
Production		(7.8)		(7.2)		(7)
Proved reserves, ending balance		35.5		61.7		58.5
Oil | Proved Developed Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance		35.7		36.2
Proved reserves, ending balance		29.4		35.7		36.2
Oil | Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance		26		22.3
Proved reserves, ending balance		6.1	[12]	26		22.3
NGLs
Reserve Quantities [Line Items]
Proved reserves, beginning balance		15.8		15.9		15.2
Revisions of previous estimates		(0.9)	[1]	0.1	[2]	0.2	[3]
Revisions related to sold properties	[4]	(4.8)
Extensions and discoveries		0.2	[5]	0.7	[6]	2.6	[7]
Purchase of minerals in place	[8]			1.2
Sales of reserves	[10]	(2.1)
Production		(1.6)		(2.1)		(2.1)
Proved reserves, ending balance		6.6		15.8		15.9
NGLs | Proved Developed Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance		10.7		11.1
Proved reserves, ending balance		6.4		10.7		11.1
NGLs | Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance		5.1		4.8
Proved reserves, ending balance		0.2	[12]	5.1		4.8
Natural Gas
Reserve Quantities [Line Items]
Proved reserves, beginning balance | Bcf		254,900		259,900		285,100
Revisions of previous estimates | Bcf		4,900	[1]	14,300	[2]	2,100	[3]
Revisions related to sold properties | Bcf	[4]	(2,900)
Extensions and discoveries | Bcf		8,800	[5]	10,100	[6]	22,000	[7]
Purchase of minerals in place | Bcf		6,100	[13]	20,700	[8]	4,400	[9]
Sales of reserves | Bcf		(20,200)	[10]			(400)	[11]
Production | Bcf		(46,200)		(50,100)		(53,300)
Proved reserves, ending balance | Bcf		205,400		254,900		259,900
Natural Gas | Proved Developed Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance | Bcf		221,100		232,700
Proved reserves, ending balance | Bcf		198,500		221,100		232,700
Natural Gas | Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance | Bcf		33,800		27,200
Proved reserves, ending balance | Bcf		6,900	[12]	33,800		27,200
Barrel Equivalent
Reserve Quantities [Line Items]
Proved reserves, beginning balance | MMBoe	[14]	120		117.7		117.5
Revisions of previous estimates | MMBoe	[14]	4.7	[1]	4.1	[2]	(3.8)	[3]
Revisions related to sold properties | MMBoe	[4],[14]	(17.4)
Extensions and discoveries | MMBoe	[14]	4.1	[5]	9.7	[6]	20.2	[7]
Purchase of minerals in place | MMBoe	[14]	1	[13]	6.1	[8]	2.3	[9]
Sales of reserves | MMBoe	[14]	(19)	[10]			(0.5)	[11]
Production | MMBoe	[14]	(17)		(17.6)		(18)
Proved reserves, ending balance | MMBoe	[14]	76.4		120		117.7
Barrel Equivalent | Proved Developed Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance | MMBoe	[14]	83.3		86.1
Proved reserves, ending balance | MMBoe	[14]	69		83.3		86.1
Barrel Equivalent | Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance | MMBoe	[14]	36.7		31.6
Proved reserves, ending balance | MMBoe	[14]	7.4	[12]	36.7		31.6
Natural Gas Equivalent
Reserve Quantities [Line Items]
Proved reserves, beginning balance | Bcfe	[14]	720		705.9		705.1
Revisions of previous estimates | Bcfe	[14]	28	[1]	25.3	[2]	(22.8)	[3]
Revisions related to sold properties | Bcfe	[4],[14]	(104.3)
Extensions and discoveries | Bcfe	[14]	24.4	[5]	58.1	[6]	121	[7]
Purchase of minerals in place | Bcfe	[14]	6.1	[13]	36.5	[8]	13.7	[9]
Sales of reserves | Bcfe	[14]	(113.8)	[10]			(3.2)	[11]
Production | Bcfe	[14]	(102.3)		(105.8)		(107.9)
Proved reserves, ending balance | Bcfe	[14]	458.1		720		705.9
Natural Gas Equivalent | Proved Developed Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance | Bcfe	[14]	499.7		516.1
Proved reserves, ending balance | Bcfe	[14]	413.5		499.7		516.1
Natural Gas Equivalent | Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance | Bcfe	[14]	220.3		189.8
Proved reserves, ending balance | Bcfe	[14]	44.6	[12]	220.3		189.8
[1]	Includes upwards revisions of 7.4 MMBoe at the Ship Shoal 349 field (Mahogany), 1.9 MMBoe at our Brazo A-133 field, 1.3 MMBoe at out Atwater 575 field, 1.3 MMBoe at out Mississippi Canyon 243 field (Matterhorn), 1.1 MMBoe at our Fairway Field, partially offset by downward revisions due to price of 10.7 MMBoe. The revision for price excludes the Yellow Rose field sold during 2015.
[2]	Includes upwards revisions due to price of 0.3 MMBoe; positive revisions of 2.4 MMBoe at our Fairway Field, 1.2 MMBoe at our Mississippi Canyon 800 field and 6.4 MMBoe at various fields; and negative revisions of 3.9 MMBoe at our Yellow Rose field and 2.4 MMBoe at various other fields.
[3]	Includes upward revision due to price of 1.9 MMBoe; negative revisions of 4.9 MMBoe at our Yellow Rose field for performance and technical changes, 2.3 MMBoe at our High Island 21/22 field for performance, 1.3 MMBoe at our Ship Shoal 349/359 field for performance; and positive performance revisions of 0.7 MMBoe at our Main Pass 98 field, 0.7 MMBoe at our South Timbalier 314, 0.6 MMBoe at our Main Pass 108 field and 0.5 MMBoe our South Timbalier 176 field.
[4]	Revisions related to the Yellow Rose field during 2015, which were primarily due to price reductions, up to the date of the sale in October 2015.
[5]	Primarily due to increases at Ewing Bank 910.
[6]	Includes extensions and discoveries of 4.1 MMBoe at our Yellow Rose field and 4.1 MMBoe at our Mississippi Canyon 782 field.
[7]	Includes extensions and discoveries of 12.6 MMBoe at our Yellow Rose field, 4.2 MMBoe at our Ship Shoal 349 field and 1.9 MMBoe at our Mississippi Canyon 698 field.
[8]	Primarily due to acquiring additional ownership in the Fairway Field and acquisition of the Woodside Properties.
[9]	Primarily due to the acquisition of the Callon Properties.
[10]	Related primarily to the sale of the Yellow Rose field in October 2015, which had estimated reserves at the date of sale of 19.0 MMBoe.
[11]	Primarily due to the sales of our non-working interests in the Green Canyon 60 field, the Green Canyon 19 field and the West Delta area block 29.
[12]	We believe that we will be able to develop all but 1.2 MMBoe of the reserves classified as proved undeveloped (“PUDs”), or approximately 16%, out of the total of 7.4 MMBoe classified as PUDs at December 31, 2015, within five years from the date such reserves were initially recorded. The exception is at the Mississippi Canyon 243 field (Matterhorn) where the field is being developed using a single floating tension leg platform requiring an extended sequential development plan. The platform cannot support a rig that would allow additional wells to be drilled, but can support a rig to allow sidetracking of wells. A portion of the PUDs in this field were originally recorded in our reserves as of December 31, 2010. The development of these PUDs will be delayed until an existing well is depleted and available to sidetrack. Based on the latest reserve report, a well is expected to be drilled to develop the Mississippi Canyon 243 field (Matterhorn) PUDs in 2020.
[13]	Primarily due to purchase of additional interest at Brazos A-133.
[14]	The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy-equivalent ratio of six Mcf of natural gas to one barrel of crude oil, condensate or NGLs (totals may not compute due to rounding). The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for crude oil, NGLs and natural gas may differ significantly.

Supplemental Oil and Gas Dis102

Supplemental Oil and Gas Disclosures - Estimated Quantities of Net Proved, Proved Developed and Proved Undeveloped Oil, Ngls and Natural Gas Reserves (Parenthetical) (Details) - MMBoe		1 Months Ended	12 Months Ended
		Oct. 31, 2015	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Reserve Quantities [Line Items]
Proved undeveloped reserves, that will not be developed with in five years			1.2
Percentage of proved undeveloped reserves that will be developed with in five years			16.00%
Wells expected to be drilled, year					2,020
Barrel Equivalent
Reserve Quantities [Line Items]
Revisions of previous estimates	[2]		4.7	[1]	4.1	[3]	(3.8)	[4]
Extensions and discoveries	[2]		4.1	[5]	9.7	[6]	20.2	[7]
Proved reserves	[2]		76.4		120		117.7		117.5
Barrel Equivalent | Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Proved reserves	[2]		7.4	[8]	36.7		31.6
Changes due to price
Reserve Quantities [Line Items]
Revisions of previous estimates			10.7		0.3		1.9
Changes at the Yellow Rose field
Reserve Quantities [Line Items]
Revisions of previous estimates					(3.9)		4.9
Extensions and discoveries					4.1		12.6
Proved estimated reserve at the date of sale		19
Changes at the High Island 21/22 field
Reserve Quantities [Line Items]
Revisions of previous estimates							2.3
Changes at the Ship Shoal 349/359 field
Reserve Quantities [Line Items]
Revisions of previous estimates							1.3
Changes at the Main Pass 98 field
Reserve Quantities [Line Items]
Revisions of previous estimates							0.7
Changes at the South Timbalier 314 field
Reserve Quantities [Line Items]
Revisions of previous estimates							0.7
Changes at the Main Pass 108 field
Reserve Quantities [Line Items]
Revisions of previous estimates							0.6
Changes at the South Timbalier 176 field
Reserve Quantities [Line Items]
Revisions of previous estimates							0.5
Changes at the Ship Shoal 349 field
Reserve Quantities [Line Items]
Extensions and discoveries							4.2
Changes at the Mississippi Canyon 698 field
Reserve Quantities [Line Items]
Extensions and discoveries							1.9
Changes at the Fairway Field
Reserve Quantities [Line Items]
Revisions of previous estimates			1.1		2.4
Changes at the Mississippi Canyon 800 field
Reserve Quantities [Line Items]
Revisions of previous estimates					1.2
Various field positive revisions
Reserve Quantities [Line Items]
Revisions of previous estimates					6.4
Various field negative revisions
Reserve Quantities [Line Items]
Revisions of previous estimates					(2.4)
Changes at the Mississippi Canyon 782 field
Reserve Quantities [Line Items]
Extensions and discoveries					4.1
Changes at Ship Shoal 349 Field (Mahogany)
Reserve Quantities [Line Items]
Revisions of previous estimates			7.4
Changes at the Brazo A-133 Field
Reserve Quantities [Line Items]
Revisions of previous estimates			1.9
Changes at Atwater 575 Field
Reserve Quantities [Line Items]
Revisions of previous estimates			1.3
Mississippi Canyon 243 Field (Matterhorn)
Reserve Quantities [Line Items]
Revisions of previous estimates			1.3
[1]	Includes upwards revisions of 7.4 MMBoe at the Ship Shoal 349 field (Mahogany), 1.9 MMBoe at our Brazo A-133 field, 1.3 MMBoe at out Atwater 575 field, 1.3 MMBoe at out Mississippi Canyon 243 field (Matterhorn), 1.1 MMBoe at our Fairway Field, partially offset by downward revisions due to price of 10.7 MMBoe. The revision for price excludes the Yellow Rose field sold during 2015.
[2]	The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy-equivalent ratio of six Mcf of natural gas to one barrel of crude oil, condensate or NGLs (totals may not compute due to rounding). The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for crude oil, NGLs and natural gas may differ significantly.
[3]	Includes upwards revisions due to price of 0.3 MMBoe; positive revisions of 2.4 MMBoe at our Fairway Field, 1.2 MMBoe at our Mississippi Canyon 800 field and 6.4 MMBoe at various fields; and negative revisions of 3.9 MMBoe at our Yellow Rose field and 2.4 MMBoe at various other fields.
[4]	Includes upward revision due to price of 1.9 MMBoe; negative revisions of 4.9 MMBoe at our Yellow Rose field for performance and technical changes, 2.3 MMBoe at our High Island 21/22 field for performance, 1.3 MMBoe at our Ship Shoal 349/359 field for performance; and positive performance revisions of 0.7 MMBoe at our Main Pass 98 field, 0.7 MMBoe at our South Timbalier 314, 0.6 MMBoe at our Main Pass 108 field and 0.5 MMBoe our South Timbalier 176 field.
[5]	Primarily due to increases at Ewing Bank 910.
[6]	Includes extensions and discoveries of 4.1 MMBoe at our Yellow Rose field and 4.1 MMBoe at our Mississippi Canyon 782 field.
[7]	Includes extensions and discoveries of 12.6 MMBoe at our Yellow Rose field, 4.2 MMBoe at our Ship Shoal 349 field and 1.9 MMBoe at our Mississippi Canyon 698 field.
[8]	We believe that we will be able to develop all but 1.2 MMBoe of the reserves classified as proved undeveloped (“PUDs”), or approximately 16%, out of the total of 7.4 MMBoe classified as PUDs at December 31, 2015, within five years from the date such reserves were initially recorded. The exception is at the Mississippi Canyon 243 field (Matterhorn) where the field is being developed using a single floating tension leg platform requiring an extended sequential development plan. The platform cannot support a rig that would allow additional wells to be drilled, but can support a rig to allow sidetracking of wells. A portion of the PUDs in this field were originally recorded in our reserves as of December 31, 2010. The development of these PUDs will be delayed until an existing well is depleted and available to sidetrack. Based on the latest reserve report, a well is expected to be drilled to develop the Mississippi Canyon 243 field (Matterhorn) PUDs in 2020.

Supplemental Oil and Gas Dis103

Supplemental Oil and Gas Disclosures - Schedule of Prices Weighted by Field Production Related to Proved Reserves (Details)	12 Months Ended
	Dec. 31, 2015$ / Boe$ / Mcf	Dec. 31, 2014$ / Boe$ / Mcf	Dec. 31, 2013$ / Boe$ / Mcf	Dec. 31, 2012$ / Boe$ / Mcf
Oil
Reserve Quantities [Line Items]
Weighted price	46.94	91.12	99.65	98.13
NGLs
Reserve Quantities [Line Items]
Weighted price	17.60	34.63	35.21	47.30
Natural Gas
Reserve Quantities [Line Items]
Weighted price | $ / Mcf	2.50	4.27	3.80	2.77

Supplemental Oil and Gas Dis104

Supplemental Oil and Gas Disclosures - Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Standardized Measure of Discounted Future Net Cash Flows
Future cash inflows	$ 2,296,700,000	$ 7,258,500,000		$ 7,376,700,000
Production	(840,100,000)	(2,224,500,000)		(2,142,800,000)
Development	(161,400,000)	(922,000,000)		(1,001,400,000)
Dismantlement and abandonment	(471,800,000)	(475,400,000)		(441,600,000)
Income taxes	0	(948,400,000)	[1]	(986,900,000)	[1]
Future net cash inflows before 10% discount	823,400,000	2,688,200,000		2,804,000,000
10% annual discount factor	(209,500,000)	(985,400,000)		(1,129,400,000)
Standardized measure of discounted future net cash flows	$ 613,900,000	$ 1,702,800,000		$ 1,674,600,000		$ 1,846,400,000
[1]	No future income taxes were estimated to be paid in 2015 as our present tax position has sufficient tax basis and net operating loss carrying forwards to offset any future taxes. State income taxes were disregarded due to immateriality.

Supplemental Oil and Gas Dis105

Supplemental Oil and Gas Disclosures - Standardized Measure of Discounted Future Net Cash Flows (Parenthetical) (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013
Extractive Industries [Abstract]
Income taxes	$ 0	$ (948,400,000)	[1]	$ (986,900,000)	[1]
[1]	No future income taxes were estimated to be paid in 2015 as our present tax position has sufficient tax basis and net operating loss carrying forwards to offset any future taxes. State income taxes were disregarded due to immateriality.

Supplemental Oil and Gas Dis106

Supplemental Oil and Gas Disclosures - Schedule of Changes in Standardized Measure (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Changes in Standardized Measure
Changes in Standardized Measure, beginning of year	$ 1,702.8	$ 1,674.6	$ 1,846.4
Sales and transfers of oil and gas produced, net of production costs	(289.1)	(650.9)	(686.1)
Net changes in price, net of future production costs	(1,455.6)	(278.6)	(65.2)
Extensions and discoveries, net of future production and development costs	65.3	309.6	393.8
Changes in estimated future development costs	(8.5)	(56.4)	(91.1)
Previously estimated development costs incurred	158.9	263.1	262.1
Revisions of quantity estimates	137.9	118.6	(91.6)
Accretion of discount	150.6	180.6	202.2
Net change in income taxes	600.8	(11.4)	56.6
Purchases of reserves in-place	6	86.7	79.6
Sales of reserves in-place	(401.4)		(53.1)
Changes in production rates due to timing and other	(53.8)	66.9	(179)
Net increase (decrease) in standardized measure	(1,088.9)	28.2	(171.8)
Changes in Standardized measure, end of year	$ 613.9	$ 1,702.8	$ 1,674.6