W&T Offshore (WTI) 10-K 2 Mar 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 28, 2017	Jun. 30, 2016
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
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		137,674,372
Entity Public Float			$ 81,638,000

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 70,236	$ 85,414
Receivables:
Oil and natural gas sales	43,073	35,005
Joint interest	21,885	22,000
Insurance reimbusrements	30,100	12
Income tax	11,943
Total receivables	107,001	57,017
Prepaid expenses and other assets	14,504	26,879
Total current assets	191,741	169,310
Property and equipment - at cost:
Oil and natural gas properties and equipment (full cost method, of which $0 at December 31, 2016 and $18,595 at December 31, 2015 were excluded from amortization)	7,932,504	7,902,494
Furniture, fixtures and other	20,898	20,802
Total property and equipment	7,953,402	7,923,296
Less accumulated depreciation, depletion and amortization	7,406,349	6,933,247
Net property and equipment	547,053	990,049
Deferred income taxes		27,595
Restricted deposits for asset retirement obligations	27,371	15,606
Income tax receivables	52,097
Other assets	11,464	5,462
Total assets	829,726	1,208,022
Current liabilities:
Accounts payable	81,039	109,797
Undistributed oil and natural gas proceeds	26,254	21,439
Asset retirement obligations	78,264	84,335
Long-term debt	8,272
Accrued liabilities	9,200	11,922
Total current liabilities	203,029	227,493
Long-term debt, less current portion	1,012,455	1,196,855
Asset retirement obligations, less current portion	256,174	293,987
Other liabilities	17,105	16,178
Commitments and contingencies (Notes 15 and 17)
Shareholders’ equity (deficit):
Preferred stock, $0.00001 par value; 20,000,000 shares authorized; 0 issued at December 31, 2016 and 2015
Common stock, $0.00001 par value; 200,000,000 shares authorized; 140,543,545 issued and 137,674,372 outstanding at December 31, 2016; 79,375,662 issued and 76,506,489 outstanding at December 31, 2015	1	1
Additional paid-in capital	539,973	423,499
Retained earnings (deficit)	(1,174,844)	(925,824)
Treasury stock, at cost; 2,869,173 shares at December 31, 2016 and 2015	(24,167)	(24,167)
Total shareholders’ equity (deficit)	(659,037)	(526,491)
Total liabilities and shareholders’ equity (deficit)	$ 829,726	$ 1,208,022

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Statement Of Financial Position [Abstract]
Oil and natural gas properties and equipment - full cost method, amount excluded from amortization	$ 0	$ 18,595
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	200,000,000	200,000,000
Common stock, issued	140,543,545	79,375,662
Common stock, outstanding	137,674,372	76,506,489
Treasury stock, shares	2,869,173	2,869,173

Consolidated Statements Of Oper

Consolidated Statements Of Operations - USD ($)	3 Months Ended																12 Months Ended
	Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Statement [Abstract]
Revenues	$ 115,213,000		$ 107,403,000		$ 99,655,000		$ 77,715,000		$ 104,064,000		$ 126,228,000		$ 149,066,000		$ 127,907,000		$ 399,986,000	$ 507,265,000	$ 948,708,000
Operating costs and expenses:
Lease operating expenses																	152,399,000	192,765,000	264,751,000
Production taxes																	1,889,000	3,002,000	7,932,000
Gathering and transportation																	22,928,000	17,157,000	19,821,000
Depreciation, depletion and amortization																	194,038,000	373,368,000	490,469,000
Asset retirement obligations accretion																	17,571,000	20,703,000	20,633,000
Ceiling test write-down of oil and natural gas properties	0		57,900,000		104,600,000		116,600,000		32,400,000		441,600,000		252,800,000		260,400,000		279,063,000	987,238,000	0
General and administrative expenses																	59,740,000	73,110,000	86,999,000
Derivative (gain) loss																	2,926,000	(14,375,000)	(3,965,000)
Total costs and expenses																	730,554,000	1,652,968,000	886,640,000
Operating income (loss)	21,319,000	[1]	(58,276,000)	[1]	(126,997,000)	[1]	(166,614,000)	[1]	(60,816,000)	[1]	(468,573,000)	[1]	(278,806,000)	[1]	(337,508,000)	[1]	(330,568,000)	(1,145,703,000)	62,068,000
Interest expense:
Incurred																	92,791,000	104,592,000	86,922,000
Capitalized																	(520,000)	(7,256,000)	(8,526,000)
Gain on exchange of debt			123,900,000														123,923,000
Other (income) expense, net																	(6,520,000)	4,663,000	(208,000)
Loss before income tax benefit																	(292,396,000)	(1,247,702,000)	(16,120,000)
Income tax benefit																	(43,376,000)	(202,984,000)	(4,459,000)
Net loss	$ 16,483,000	[1]	$ 45,928,000	[1]	$ (120,922,000)	[1]	$ (190,509,000)	[1]	$ (51,606,000)	[1]	$ (477,568,000)	[1]	$ (260,449,000)	[1]	$ (255,095,000)	[1]	$ (249,020,000)	$ (1,044,718,000)	$ (11,661,000)
Basic and diluted loss per common share	$ 0.12	[1],[2]	$ 0.48	[1],[2]	$ (1.58)	[1],[2]	$ (2.49)	[1],[2]	$ (0.68)	[1],[2]	$ (6.29)	[1],[2]	$ (3.43)	[1],[2]	$ (3.36)	[1],[2]	$ (2.60)	$ (13.76)	$ (0.16)
[1]	During 2016, we recorded in first, second and third quarter ceiling test write-downs of oil and natural gas properties of $116.6 million, $104.6 million and $57.9 million, respectively. In the third quarter of 2016, we recorded a gain on exchange of debt of $123.9 million. 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 does 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 Outstanding	Additional Paid-In Capital	Retained Earnings (Deficit)	Treasury Stock
Beginning Balances at Dec. 31, 2013	$ 540,610	$ 1	$ 403,564	$ 161,212	$ (24,167)
Beginning 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 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 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
Share-based compensation	11,013		11,013
Stock issued	106,366		106,366
Stock issued, shares		61,168
RSUs and shares surrendered for payroll taxes, value	(905)		(905)
Net loss	(249,020)			(249,020)
Ending Balances at Dec. 31, 2016	$ (659,037)	$ 1	$ 539,973	$ (1,174,844)	$ (24,167)
Ending Balances (in shares) at Dec. 31, 2016		137,674			2,869

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating activities:
Net loss	$ (249,020,000)	$ (1,044,718,000)	$ (11,661,000)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	211,609,000	394,071,000	511,102,000
Ceiling test write-down of oil and natural gas properties	279,063,000	987,238,000	0
Gain on exchange of debt	(123,923,000)
Debt issuance costs write-down/amortization of debt items	2,548,000	4,411,000	701,000
Share-based compensation	11,013,000	10,242,000	14,744,000
Derivative (gain) loss	2,926,000	(14,375,000)	(3,965,000)
Cash receipts (payments) on derivative settlements, net	4,746,000	6,703,000	(5,318,000)
Deferred income taxes	28,392,000	(203,272,000)	(4,760,000)
Changes in operating assets and liabilities:
Oil and natural gas receivables	(7,005,000)	32,236,000	29,510,000
Joint interest receivables and insurance	(1,126,000)	21,633,000	(4,255,000)
Income taxes	(64,274,000)	(7,000)	3,143,000
Prepaid expenses and other assets	(14,946,000)	17,816,000	15,012,000
Asset retirement obligation settlements	(72,320,000)	(32,555,000)	(74,313,000)
Accounts payable, accrued liabilities and other	6,497,000	(46,195,000)	4,881,000
Net cash provided by (used in) operating activities	14,180,000	133,228,000	474,821,000
Investing activities:
Acquisition of property interest in oil and natural gas properties			(72,234,000)
Investment in oil and natural gas properties and equipment	(48,606,000)	(230,161,000)	(554,378,000)
Changes in operating assets and liabilities associated with investing activities	(35,194,000)	(55,425,000)	37,450,000
Net proceeds from sales of assets	1,500,000	372,939,000
Purchases of furniture, fixtures and other	(96,000)	(1,278,000)	(3,340,000)
Net cash provided by (used in) investing activities	(82,396,000)	86,075,000	(592,502,000)
Financing activities:
Borrowings of long-term debt - revolving bank credit facility	340,000,000	263,000,000	556,000,000
Repayments of long-term debt - revolving bank credit facility	(340,000,000)	(710,000,000)	(399,000,000)
Debt exchange/issuance costs	(18,464,000)	(6,669,000)
Dividends to shareholders			(30,260,000)
Other	(928,000)	(886,000)	(1,193,000)
Net cash provided by (used in) financing activities	53,038,000	(157,555,000)	125,547,000
Increase (decrease) in cash and cash equivalents	(15,178,000)	61,748,000	7,866,000
Cash and cash equivalents, beginning of period	85,414,000	23,666,000	15,800,000
Cash and cash equivalents, end of period	70,236,000	85,414,000	$ 23,666,000
11.00% 1.5 Lien Term Loan, Due November 2019
Financing activities:
Issuance of Term Loan	75,000,000
Payment of interest on 1.5 Lien Term Loan	$ (2,570,000)
9.00 % Second Lien Term Loan, Due May 2020
Financing activities:
Issuance of Term Loan		$ 297,000,000

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
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 7. We are 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. 2016-09 (“ASU 2016-09”), Compensation – Stock Compensation Subtopic 718 . 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, were significantly lower during 2015 and lower still in 2016 compared to prior years. We took a number of steps during 2015 and 2016 to mitigate the effects of these lower prices including: (i) significantly reducing capital spending from previous year levels and budgeting conservative capital spending for 2017 (exclusive of acquisitions); (ii) restructuring our debt and issuing our common stock through an exchange transaction, which is described in Note 2, (iii) receiving funds through two debt issuances, which are described in Note 2 (iv) suspending our quarterly common stock dividend; (iv) implementing numerous cost reduction projects to reduce our operating costs; and (v) selling our interest in the Yellow Rose onshore field, which is described in Note 7. During 2016, the Bureau of Ocean Energy Management (“BOEM”) issued orders to us concerning financial assurances related to plug and abandonment (decommissioning) obligations for Federal offshore leases, including an order issued to us in December 2016 regarding additional security required for sole liability properties. In July 2016, effective September 2016, the BOEM issued Notice to Lessees #2016-N01 (“NTL #2016-N01”), related to obligations for decommissioning activities on the Outer Continental Shelf (“OCS”) for leases, rights-of-way (“ROWs”) or rights of use and easement (“RUEs”). In January 2017, the BOEM extended the implementation timeline by an additional six months of NTL #2016-N01 as to leases, ROWs and RUEs for which there are co-lessees and/or predecessors in interest (non-sole liability properties), with certain exceptions. In February 2017, the BOEM withdrew the sole liability orders it had issued in December 2016 to allow time for the new President’s administration to review the complex financial assurance program. See Note 17 and 19 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 for at least 12 months from the date of issuance of this Form 10-K, which is the threshold of a going concern under GAAP; however, we cannot predict with any certainty future commodity prices or the actions of the BOEM concerning financial assurance requirements, either of which could 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 we have taken less than our ownership share of production. At December 31, 2016 and 2015, $5.3 million and $6.9 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. The majority of 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, including some of our joint interest partners. We use the specific identification method of determining if an allowance for doubtful accounts is needed. As of December 31, 2016 and 2015, $7.6 million and $2.5 million, respectively, were recorded as an allowance for doubtful accounts. During 2016 and 2015, there were no reductions recorded in the allowance for doubtful accounts (no collections of accounts previously reserved and no permanent write-off of receivable accounts). The following identifies customers from whom we derived 10% or more of our receipts from sales of crude oil, NGLs and natural gas. Year Ended December 31, 2016 2015 2014 Customer Shell Trading (US) Co. 43 % 50 % 47 % Vitol Inc. 20 % ** ** 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 company’s adjuster reviews and approves such costs for payment or when the insurance company has agreed to reimbursement amounts. Claims that have been processed in this manner have customarily been paid on a timely basis. See Note 5, 17 and 19 for information related to settlement of previously unpaid claims by certain insurance companies. Prepaid expenses and other Amounts recorded in Prepaid expenses and other Year Ended December 31, 2016 2015 Derivative assets - current (1) $ — $ 10,036 Prepaid/accrued insurance and surety bonds 5,386 7,475 Prepaid deposits related to royalties 6,237 5,943 Other (2) 2,881 3,425 Prepaid expenses and other $ 14,504 $ 26,879 (1) Includes open and closed (and not yet collected) derivative commodity contracts recorded at fair value as of December 31, 2015. (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 we have 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 perform a “ceiling test” calculation quarterly, 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 and 2016, which are reported as a separate line in the Statements of Operations. The average price using the SEC required methodology at December 31, 2016 was $39.25 per barrel for West Texas Intermediate (“WTI”) crude oil and $2.48 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 were $279.1 million and $987.2 million for 2016 and 2015, respectively. There was no ceiling test write-down in the fourth quarter of 2016. We did not record a ceiling test write-down during 2014. If average crude oil and natural gas prices decrease from 2016 levels, it is possible that a ceiling test write-down will be recorded during 2017. 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 4. 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. As of December 31, 2016, we did not have any open derivative financial instruments. 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. Whenever we have entered into derivative contracts, we did not 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 11.00% 1.5 Lien Term Loan, due November 2019, (the “1.5 Lien Term Loan”) approximates fair value because the debt was recently executed and reflective of market rates and conditions. 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. Income Taxes We use the liability method of accounting for income taxes in accordance with the Income Taxes Troubled Debt Restructuring We accounted for an exchange transaction, which is described in Note 2, as a troubled debt restructuring pursuant to the guidance under Accounting Standard Codification 470-60, Troubled Debt Restructuring 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. 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. 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 10 for additional information. Loss 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 loss per share under the two-class method when the effect is dilutive. For additional information, refer to Note 13. Other (Income) Expense, Net For 2016, the amount includes $7.7 million of income related to the settlement of certain insurance claims. In 2016 and 2015, the amount includes write-offs of debt issuance costs of $1.4 million and $3.2 million, respectively, related to a reduction in the borrowing base of the revolving bank credit facility under the Fifth Amended and Restated Credit Agreement (as amended, the “Credit Agreement”). The write-offs of debt issuance costs in both 2016 and 2015 are included as an adjustment to net income in determining Net cash provided by operating activities Recent Accounting Developments In May 2014, the Financial Accounting Standards Board (“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 In June 2016, the FASB issued Accounting Standards Update No. 2016-13, (“ASU 2016-13”), Financial Instruments – Credit Losses Subtopic 326 In August 2016, the FASB issued Accounting Standards Update No. 2016-15, (“ASU 2016-15”), Statement of Cash Flows (Topic 230) – Classification of Certain Cash Receipts and Cash Payments In November 2016, the FASB issued Accounting Standards Update No. 2016-18, (“ASU 2016-18”), Statement of Cash Flows (Topic 230) – Restricted Cash

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Long-Term Debt	2. Long-Term Debt As of December 31, 2016 and 2015, our long-term debt was as follows (in thousands): December 31, December 31, 2016 2015 PIK Payable/ Interest Payable/ Carrying Principal/ Principal Other Value Other* 11.00% 1.5 Lien Term Loan, due November 2019 $ 75,000 $ 23,823 $ 98,823 $ — 9.00 % Second Lien Term Loan, due May 2020 300,000 — 300,000 300,000 9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020 163,007 60,898 223,905 — 8.50%/10.00% Third Lien PIK Toggle Notes, due June 2021 145,897 67,549 213,446 — 8.50% Unsecured Senior Notes, due June 2019 189,829 — 189,829 900,000 Subtotal 873,733 152,270 1,026,003 1,200,000 Debt premium, discount, issuance costs, net of amortization — (5,276 ) (5,276 ) (3,145 ) Total long-term debt 873,733 146,994 1,020,727 1,196,855 Current maturities of long-term debt — 8,272 8,272 — Long term debt, less current maturities $ 873,733 $ 138,722 $ 1,012,455 $ 1,196,855 * Amounts also equal carrying value Aggregate annual maturities of amounts recorded for long-term debt as of December 31, 2016 are as follows (in millions): 2017–$8.2; 2018–$23.8; 2019–$303.7; 2020–$510.1; thereafter–$180.1. See below for discussion on the determination of recorded amounts. Exchange Transaction On September 7, 2016, we consummated a transaction whereby we exchanged approximately $710.2 million in aggregate principal amount, or 79%, of our 8.500% Senior Notes (the “Unsecured Senior Notes”), due June 15, 2019, for: (i) $159.8 million in aggregate principal amount of 9.00%/10.75% Senior Second Lien PIK Toggle Notes, due May 15, 2020, (the “Second Lien PIK Toggle Notes”); (ii) $142.0 million in aggregate principal amount of 8.50%/10.00% Senior Third Lien PIK Toggle Notes, due June 15, 2021, (the “Third Lien PIK Toggle Notes”); and (iii) 60.4 million shares of our common stock (collectively, the “Debt Exchange”). At the same time on closing on the Debt Exchange, we closed on a $75.0 million, 11.00% 1.5 Lien Term Loan, due November 2019, with the then largest holder of our Unsecured Senior Notes (collectively with the Debt Exchange, the “Exchange Transaction”). We accounted for the Exchange Transaction as a Troubled Debt Restructuring pursuant to the guidance under ASC 470-60. Under ASC 470-60, the carrying value of the newly issued Second Lien PIK Toggle Notes, Third Lien PIK Toggle Notes and 1.5 Lien Term Loan (the “New Debt”) is measured using all future undiscounted payments (principal and interest); therefore, no interest expense was recorded for the New Debt in the Consolidated Statements of Operations for the period from September 7, 2016 to December 31, 2016. Additionally, no interest expense related to the New Debt will be recorded in future periods as payments of interest on the New Debt will be recorded as a reduction in the carrying amount; thus, our reported interest expense will be significantly less than the contractual interest payments through the terms of the New Debt. A gain of $123.9 million was recognized related to the Exchange Transaction. Under ASC 470-60, a gain was recognized as the sum of (i) the future undiscounted payments (principal and interest) related to the New Debt, (ii) the fair value of the common stock issued and (iii) deal transaction costs of $18.9 million was less than the sum of (iv) the carrying value of the Unsecured Senior Notes exchanged and (v) the funds received from the 1.5 Lien Term Loan. The shares of common stock issued were valued at $1.76 per share, which was the closing price on September 7, 2016. The effect on basic and diluted earnings per share for 2016 was a $1.30 per share, which assumes the gain would not affect income tax benefit for 2016. The funds received from the 1.5 Lien Term Loan were used to pay transaction costs related to the Exchange Transaction and to pay down borrowings on the revolving bank credit facility. The balance of the borrowings on the revolving bank credit facility was paid down from available cash. In conjunction with the Exchange Transactions, certain terms of our Credit Agreement were modified and are reflected in the description of the Credit Agreement below. Credit Agreement The Credit Agreement 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 (historically in the spring and fall), and we and our lenders may each request one additional determination per year. The borrowing base as of December 31, 2016 was $150.0 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 $150.0 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 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 indebtedness; and (iv) such additional unsecured indebtedness matures at least six months 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. With consent of the lenders, such limitation will not apply to the repurchase of our existing debt in an aggregate principal amount equal to or less than the aggregate principal amount of any new issuance of such debt. We are permitted to redeem, repurchase, prepay or defease up to $35 million of our Unsecured Senior Notes if after giving effect to 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 $5 million; (iii) the Consolidated Cash balance is at least $35 million after the redemption or repayment; 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, 2016 and thereafter are: (i) the First Lien Leverage Ratio must be less than 2.50 to 1.00 through June 30, 2017, then 2.00 to 1.00 thereafter; (ii) the Asset Coverage Ratio must be not less than 1.25 to 1.00 as of December 31, 2016, then is suspended thereafter; and (ii) the Current Ratio must be greater than 1.00 to 1.00. As of December 31, 2016, the current ratio was 2.93 to 1.00. As of December 31, 2016, the First Lien Leverage Ratio and the Asset Coverage Ratio were in compliance, but not meaningful as no borrowings were outstanding on the revolving bank credit facility and only minor amounts of letters of credit were outstanding. 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 other debt agreements, 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, 2016. We are required to have deposit accounts only with banks party to the Credit Agreement with certain exceptions. We may not have unrestricted cash balances above $35 million if outstanding balances on the revolving bank credit agreement (including letters of credit) are greater than $5 million. Borrowings under the revolving bank credit facility bear interest at the applicable London Interbank Offered Rate (“LIBOR”) plus a margin that varies from 3.00% to 4.00% 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 0.50%, or (c) LIBOR plus 1.0%, plus applicable margin ranging from 2.00% to 3.00%. The unused portion of the borrowing base is subject to a commitment fee of 0.50%. The estimated annual effective interest rate was 3.3% for 2016 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 2016 and 2015, the borrowing base under the Credit Agreement was reduced. The reductions in the borrowing base resulted in proportional reductions in the unamortized costs related to the Credit Agreement of $1.4 million and $3.2 million in 2016 and 2015, respectively, which is included in the line Other (income)/expense, net At December 31, 2016 and 2015, we had no borrowings outstanding under the revolving bank credit facility. At December 31, 2016 and 2015, we had $0.5 million and $0.9 million, respectively, outstanding in letters of credit under the revolving bank credit facility. 1.5 Lien Term Loan As part of the Exchange Transaction, we entered into the 1.5 Lien Term Loan on September 7, 2016 with a maturity date of November 15, 2019. The maturity date will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes have not been extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019. Interest accrues at 11.00% per annum and is payable quarterly in cash. The holder of the 1.5 Lien Term Loan was the largest holder of our Unsecured Senior Notes prior to the Exchange Transaction. The 1.5 Lien Term Loan is secured by a 1.5 priority lien on all of our assets pledged under the Credit Agreement. The lien securing the 1.5 Lien Term Loan is subordinate to the liens securing the Credit Agreement and has priority above the liens securing the Second Lien Term Loan (defined below), the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes. All future undiscounted cash flows have been included in the carrying value under ASC 470-60. Current maturities of our long-term debt represent the cash interest payable for the 1.5 Lien Term Loan payable in the next 12 months. The 1.5 Lien Term Loan contains various covenants that limit, among other things, our ability to: (i) pay cash dividends; (ii) repurchase our common stock; (iii) sell our assets; (iv) make certain loans or investments; (v) merge or consolidate; (vi) enter into certain liens; and (vii) enter into transactions with affiliates. We were in compliance with those covenants as of December 31, 2016. Second Lien Term Loan In May 2015, we entered into the 9.00% Term Loan (the “Second Lien Term Loan”), which bears an annual interest rate of 9.00%, was issued at a 1.0% discount to par and matures on May 15, 2020 and is recorded at its carrying value consisting of principal, unamortized discount and unamortized debt issuance costs. Interest on the Second Lien Term Loan is payable in arrears semi-annually on May 15 and November 15. The estimated annual effective interest rate on the Second Lien Term Loan is 9.7%, which includes amortization of debt issuance costs and discounts. The Second Lien Term Loan is secured by a second-priority lien on all of our assets that are secured under the Credit Agreement. The Second Lien Term Loan is effectively subordinate to the Credit Agreement and the 1.5 Lien Term Loan (discussed above) and is effectively pari passu Second Lien PIK Toggle Notes As part of the Exchange Transaction, we issued Second Lien PIK Toggle Notes on September 7, 2016, with a maturity date of May 15, 2020. Cash interest accrues at 9.00% per annum and is payable on May 15 and November 15 of each year. The Second Lien PIK Toggle Notes contain payment-in-kind (“PIK”) interest provisions, where certain semi-annual interest is added to the principal amount instead of being paid in cash in the then current semi-annual period. We have the option for the first 18 months to pay all or a portion of interest in kind at a rate of 10.75% per annum, except that the initial interest payment on November 15, 2016 had to be paid solely using PIK. The Second Lien PIK Toggle Notes are secured by a second-priority lien on all of our assets that are pledged under the Credit Agreement. The Second Lien PIK Toggle Notes are effectively subordinate to the Credit Agreement and the 1.5 Lien Term Loan (discussed above) and is effectively pari passu Third Lien PIK Toggle Notes As part of the Exchange Transaction, we issued Third Lien PIK Toggle Notes on September 7, 2016, with a maturity date of June 15, 2021. The maturity date will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes have not been extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019. Cash interest accrues at 8.50% per annum and is payable on June 15 and December 15 of each year. The Third Lien PIK Toggle Notes contain PIK interest provisions, where certain semi-annual interest is added to the principal amount instead of being paid in cash in the then current semi-annual period. We have the option for the first 24 months to pay all or a portion of interest in kind at a rate of 10.00% per annum, except that the initial interest payment on December 15, 2016 had to be paid solely using PIK. The Third Lien PIK Toggle Notes are secured by a third-priority lien on all of our assets that are secured under the Credit Agreement. The Third Lien PIK Toggle Notes are effectively subordinate to the Second Lien Term Loan and the Second Lien PIK Toggle Notes. For purposes of determining the gain from the Exchange Transaction under ASC 470-60, we assumed we will elect full use of the PIK option and these amounts will increase the principal amount. All future undiscounted cash flows have been included in the carrying value under ASC 470-60. The Third Lien PIK Toggle Notes contain covenants that restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt; (ii) make payments or distributions on account of our or our restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of our restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company. We were in compliance with those covenants as of December 31, 2016. Unsecured Senior Notes At December 31, 2016 and 2015, our outstanding Unsecured Senior Notes, which bear an annual interest rate of 8.50% and mature on June 15, 2019, were classified as long-term at their carrying value. Interest on the Unsecured Senior Notes is payable semi-annually in arrears on June 15 and December 15. The estimated annual effective interest rate on the Unsecured 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 Unsecured 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, 2016. For information about fair value measurements of our long-term debt, refer to Note 3.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements	3. 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 our 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 long-term debt (in thousands): December 31, Hierarchy 2016 2015 11.00% 1.5 Lien Term Loan, due November 2019 Level 2 $ 75,000 $ — 9.00 % Second Lien Term Loan, due May 2020 Level 2 255,000 217,500 9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020 Level 2 122,255 — 8.50%/10.00% Third Lien PIK Toggle Notes due June 2021 Level 2 80,243 — 8.50% Unsecured Senior Notes, due June 2019 Level 2 123,389 324,000 The fair value of long-term debt is based on quoted prices, although the market is not an active market; therefore, the fair value is classified within Level 2. An exception is the fair value of the 1.5 Lien Term Loan, which is held by one entity, and was not traded since its inception in September 2016. As the 1.5 Lien Term Loan was recently executed, the fair value was assumed to be the carrying value, excluding amounts recorded for future interest payments. As of December 31, 2016, there were no open derivatives financial instruments. As of December 31, 2015, the carrying value of our open derivative financial instruments equaled the estimated fair value. 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 carrying value of our long-term debt is disclosed in Note 2 above. For additional information about our derivative financial instruments, refer to Note 8.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	4. 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, 2016 2015 Asset retirement obligations, beginning of period $ 378,322 $ 390,568 Liabilities settled (72,320 ) (32,555 ) Accretion of discount 17,571 20,703 Disposition of properties — (8,581 ) Liabilities assumed through acquisition — 2,944 Liabilities incurred 398 4,780 Revisions of estimated liabilities 10,467 463 Asset retirement obligations, end of period 334,438 378,322 Less current portion 78,264 84,335 Long-term $ 256,174 $ 293,987 During 2016, we decreased our ARO on an overall basis primarily due to plug and abandonment work performed during 2016, partially offset by increases from accretion and revisions of previous estimates. Upward revisions were primarily related to sustained casing pressure issues for idle iron at our West Cameron fields identified while performing preliminary plug and abandonment work at these fields. In addition, increases were attributable to non-operated properties. Partially offsetting are downward revisions to cost estimates from service providers for plug and abandonment work at certain locations. 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.

Insurance Claims

Insurance Claims	12 Months Ended
	Dec. 31, 2016
Insurance [Abstract]
Insurance Claims	5. 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 2016, 2015 and 2014, we received insurance reimbursements of $10.2 million, $0.2 million and $12.2 million, respectively, primarily related to hurricane damage. In addition, we recorded receivables of $30.1 million as of December 31, 2016 for recent settlements with certain insurance companies related to Hurricane Ike claims within Receivables – Joint interest, insurance reimbursements and other Net cash provided by operating activities Oil and natural gas properties and equipment Lease operating expense General and administrative expenses Other income (expense), net

Restricted Deposits

Restricted Deposits	12 Months Ended
	Dec. 31, 2016
Receivables [Abstract]
Restricted Deposits	6. Restricted Deposits Restricted deposits as of December 31, 2016 and 2015 consisted of funds escrowed for collateral related to the future plugging and abandonment obligations 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. See Note 15 for potential future security requirements.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Acquisitions and Divestitures	7. 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 $370.9 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. A net purchase price adjustment of $0.9 million for final customary effective date adjustments was recorded during 2016. 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”) equal to a variable percentage 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 our 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) December 31, 2014 (a) Revenue $ 971,595 Net loss (5,504 ) Basic and diluted loss per common share (0.08 ) 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) December 31, 2014 (a) Revenues (b) $ 22,887 Direct operating expenses (b) 4,417 DD&A (c) 8,385 G&A (d) 300 Interest expense (e) 330 Capitalized interest (f) (19 ) Income tax expense (g) 3,316 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.

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	8. 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 Commodity Derivatives As of December 31, 2016, we did not have any open derivative contracts. 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. 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 have the potential to 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. During 2014, we used crude oil swap contracts and have used various derivative instruments in prior years to manage our exposure to commodity price risk from sales of our oil and natural gas. 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, 2016 2015 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, 2016 2015 2014 Derivative (gain) loss $ 2,926 $ (14,375 ) $ (3,965 ) Cash receipts (payments), net, on commodity derivative contract settlements are included within Net cash provided by operating activities Year Ended December 31, 2016 2015 2014 Cash receipts (payments) on derivative settlements, net $ 4,746 $ 6,703 $ (5,318 ) Offsetting Commodity Derivatives During 2016 and 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.

Equity Transactions

Equity Transactions	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Equity Transactions	9. Equity Transactions During 2016, after receiving shareholder approval, the Company increased the amount of common stock authorized from 118.3 During 2016 and 2015, we did not pay any dividends and dividends are currently suspended. During 2014, we paid regular cash dividends of $0.40 per common share.

Share-Based Awards and Cash-Bas

Share-Based Awards and Cash-Based Awards	12 Months Ended
	Dec. 31, 2016
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Share-Based Awards and Cash-Based Awards	10. Share-Based Awards and Cash-Based Awards 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 2016. 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 the Chief Executive Officer (“CEO”) 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. On May 4, 2016, after receiving shareholder approval, 3,300,000 shares of common stock were added to the amount available for issuance under the Plan. As of December 31, 2016, there were 6,933,337 shares of common stock available for issuance in satisfaction of awards under the Plan. RSUs reduce the shares available in the Plan when settled in shares of common stock, net of withholding tax. Share-based Awards: Restricted Stock Units For 2016, 2015 and 2014, performance awards under the Plan were granted in the form of 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 2016, 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 2016 and (ii) Adjusted EBITDA as a percent of total revenue (“Adjusted EBITDA Margin”) for 2016. Adjustments range from 0% to 100% based upon actual results compared against pre-defined performance levels. For 2016, the Company was below target for Adjusted EBITDA and achieved target for Adjusted EBITDA Margin. During 2015, RSUs granted were subject to adjustments based on achievement of a combination of performance criteria, which was comprised of: (i) Adjusted EBITDA for 2015 and (ii) 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 achieved 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 achieved target for Adjusted EBITDA and was slightly below target for Adjusted EBITDA Margin. 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 2014 (after adjustment for performance) vested in December 2016 to eligible employees. 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. During 2016, 2015 and 2014, the Company granted RSUs to certain employees, with nearly all grants being contingent upon meeting specified performance requirements described above. The fair value of the RSUs granted in 2016, 2015 and 2014 was determined using the Company’s closing price on the grant dates. A summary of activity related to RSUs is as follows: 2016 2015 2014 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 3,474,079 $ 7.42 1,977,335 $ 15.29 1,331,753 $ 14.96 Granted 4,213,964 2.21 2,626,930 3.59 1,195,388 16.84 Vested (968,652 ) 16.69 (721,038 ) 13.23 (354,692 ) 18.59 Forfeited (612,143 ) 3.64 (409,148 ) 10.63 (195,114 ) 16.53 Nonvested, end of period 6,107,248 $ 2.73 3,474,079 $ 7.42 1,977,335 $ 15.29 Subject to the satisfaction of service conditions, the RSUs outstanding as of December 31, 2016 are eligible to vest in the year indicated in the table below: Restricted Stock Units 2017 2,311,434 2018 3,795,814 Total 6,107,248 RSUs fair value at grant date: During 2016, 2015 and 2014, the grant date fair value of RSUs granted was $9.3 million, $9.4 million and $20.1 million, respectively. RSUs fair value at vested date: The fair value of the RSUs that vested during 2016, 2015 and 2014 was $2.4 million, $2.1 million and $2.0 million, respectively, based on the Company’s closing price on the vesting date. 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 and adjusted to fair value using the Company’s closing price at the end of each reporting period. The CEO award for 2014 was 100% performance based and was 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 employees, and were subject to approval of the Compensation Committee. An issuance of 37,316 shares of common stock was made in March 2015 to the CEO for his 2014 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 issuance. Share-Based Awards: Restricted Stock Under the Directors Compensation Plan, shares of restricted stock (“Restricted Shares”) were issued in 2016, 2015 and 2014 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. As of December 31, 2016, there were 317,896 shares of common stock available for issuance in satisfaction of awards under the Directors Compensation Plan. Reductions in shares available are made when Restricted Shares are granted. A summary of activity related to Restricted Shares is as follows: 2016 2015 2014 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 78,230 $ 8.95 43,210 $ 16.20 43,840 $ 15.96 Granted 126,128 2.22 56,540 6.19 18,815 18.60 Vested (43,062 ) 9.75 (21,520 ) 16.26 (19,445 ) 18.00 Nonvested, end of period 161,296 $ 3.47 78,230 $ 8.95 43,210 $ 16.20 Subject to the satisfaction of service conditions, the Restricted Shares outstanding as of December 31, 2016 are expected to vest as follows: Restricted Shares 2017 62,136 2018 57,120 2019 42,040 Total 161,296 Restricted stock fair value at grant date: The grant date fair value of restricted stock granted during 2016, 2015 and 2014 was $0.3 million for all periods based on the Company’s closing price on the date of grant. Restricted stock fair value at vested date: The fair value of the restricted stock that vested during 2016, 2015 and 2014 was $0.1 million, $0.1 million and $0.3 million, respectively, based on the Company’s closing price on the date of vesting. 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, 2016 2015 2014 Share-based compensation expense from: Restricted stock units $ 10,640 $ 9,978 $ 13,150 Restricted stock 373 358 369 Common shares — (94 ) 1,225 Total $ 11,013 $ 10,242 $ 14,744 Share-based compensation tax benefit: Tax benefit computed at the statutory rate $ 3,855 $ 3,585 $ 5,160 As of December 31, 2016, unrecognized share-based compensation expense related to our awards of RSUs and Restricted Shares was $9.7 million and $0.4 million, respectively. Unrecognized compensation expense will be recognized through November 2018 for RSUs and April 2019 for Restricted Shares. Cash-based Awards In addition to share-based compensation, cash-based awards were granted under the Plan to substantially all eligible employees in 2016, 2015 and 2014. The cash-based awards, which are a short-term component of the Plan, 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. In addition, for the 2016 and 2015 cash-based awards, which includes the 2016/2015 incentive plan for the CEO, the Company designed the awards with an additional financial condition that must be achieved on or before December 31, 2018 for the 2016 awards, and on or before December 31, 2017 for the 2015 awards: 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, 2016, 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 2016 and 2015 Annual Incentive Award Agreement (the 2016 and 2015 cash-based awards). 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. Eligible employees were paid their cash-based awards within 75 days following year end 2014. Share-Based Awards and Cash-Based Awards Compensation Expense A summary of compensation expense related to share-based awards and cash-based awards is as follows (in thousands): Year Ended December 31, 2016 2015 2014 Share-based compensation included in: General and administrative $ 11,013 $ 10,242 $ 14,744 Cash-based incentive compensation included in: Lease operating expense — 364 3,285 General and administrative (1) — (233 ) 6,950 Total charged to operating income $ 11,013 $ 10,373 $ 24,979 (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, 2016
Compensation And Retirement Disclosure [Abstract]
Employee Benefit Plan	11. 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. As of March 5, 2016, the Company suspended matching contributions. From January 1, 2016 to March 5, 2016, and during 2015 and 2014, 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 $0.4 million, $2.3 million and $2.4 million for 2016, 2015 and 2014, respectively.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	12. Income Taxes Income Tax Expense (Benefit) Components of income tax expense (benefit) were as follows (in thousands): Year Ended December 31, 2016 2015 2014 Current $ (71,768 ) $ 288 $ 301 Deferred 28,392 (203,272 ) (4,760 ) Total income tax( benefit) $ (43,376 ) $ (202,984 ) $ (4,459 ) Effective Tax Rate Reconciliation The reconciliation of income taxes computed at the U.S. federal statutory tax rate to our income tax benefit is as follows (in thousands, except percentages): Year Ended December 31, 2016 2015 2014 Income tax (benefit) at the federal statutory rate $ (102,339 ) 35.0 % $ (436,696 ) 35.0 % $ (5,642 ) 35.0 % Share-based compensation 4,920 (1.7 ) 2,940 (0.2 ) — — State income taxes (755 ) 0.2 (2,343 ) 0.2 263 (1.6 ) Valuation allowance 52,915 (18.1 ) 232,925 (18.7 ) — — Debt restructuring cost 1,463 (0.5 ) — — — — Other 420 (0.1 ) 190 — 920 (5.7 ) $ (43,376 ) 14.8 % $ (202,984 ) 16.3 % $ (4,459 ) 27.7 % Our effective tax rate for the years 2016 and 2015 differed from the federal statutory rate of 35.0% primarily due to recording and adjusting 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. 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, 2016 2015 Deferred tax liabilities: Property and equipment $ — $ 40,287 Derivatives — 2,697 Other 1,423 3,000 Total deferred tax liabilities 1,423 45,984 Deferred tax assets: Alternative minimum tax credit — 20,486 Property and equipment 42,385 — Asset retirement obligations 117,588 133,018 Federal net operating losses — 145,733 State net operating losses 5,615 5,068 Valuation allowance (290,190 ) (237,275 ) Exchange transaction 118,467 — Share-based compensation 2,353 4,245 Other 4,798 2,304 Total deferred tax assets 1,016 73,579 Net deferred tax asset (liabilities) $ (407 ) $ 27,595 During 2016, we made income tax payments of $0.3 million and received $7.8 million of refunds, which includes an income tax refund of $5.8 million related to an NOL claim for 2015 carried back to 2005 filed on Form 1139, Corporation Application for Tentative Refund . Income Tax Receivables As of December 31, 2016, we have recorded current income tax receivables of $11.9 million and non-current income tax receivables of $52.1 million. The current income tax receivables primarily relates to a net operating loss claim for 2016 carried back to 2006 and is included in the receivable line Joint interest, insurance reimbursement and other on the Consolidated Balance Sheet. The non-current income tax receivables relates to our NOL claims for the years 2012, 2013 and 2014 that were carried back to the years 2003, 2004, 2007, 2010 and 2011 filed on Form 1120X, U.S. Corporation Income Tax Return . These carryback claims are made pursuant to IRC Section 172(f), which permits certain platform dismantlement, well abandonment and site clearance costs to be carried back 10 years. The refund claims filed on Form 1120X will require a review by the Congressional Joint Committee on Taxation and are accordingly classified as non-current. 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, 2016 (in thousands): Amount Expiration Year Federal net operating loss $ — N/A State net operating losses 112,512 2021-2030 Alternative minimum tax credit — N/A General business credit — N/A Exchange Transaction Tax Gain The tax gain on the Exchange Transaction associated with the cancellation of a portion of our debt was not recognized pursuant to Internal Revenue Code Section 108. Certain tax attributes including net operating losses, alternative minimum tax credit, general business credit carryovers and the tax basis of assets are required to be reduced, as reflected in the table above. No carryovers will be available to 2017. Valuation Allowance During 2016 and 2015, we recorded increases in the valuation allowance of $52.9 million and $232.9 million, respectively, related to federal and state deferred tax assets. Deferred tax assets are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses are deductible. 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, 2016 and 2015, we had a valuation allowance related to Federal and state deferred tax assets. 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, 2016 2015 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 2016, 2015 and 2014, the amounts recognized in income tax expense were immaterial. Years open to examination The tax years from 2013 through 2016 remain open to examination by the tax jurisdictions to which we are subject.

Loss Per Share

Loss Per Share	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Loss Per Share	13. Loss 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 when the effect is dilutive. The following table presents the calculation of basic and diluted loss per common share (in thousands, except per share amounts): Year Ended December 31, 2016 2015 2014 Net loss $ (249,020 ) $ (1,044,718 ) $ (11,661 ) Less portion allocated to nonvested shares — — 269 Net loss allocated to common shares $ (249,020 ) $ (1,044,718 ) $ (11,930 ) Weighted average common shares outstanding 95,644 75,931 75,609 Basic and diluted loss per common share $ (2.60 ) $ (13.76 ) $ (0.16 ) Shares excluded due to being anti-dilutive (weighted-average) 5,269 2,195 2,097

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2016
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	14. Supplemental Cash Flow Information The following reflects our supplemental cash flow information (in thousands): Year Ended December 31, 2016 2015 2014 Supplemental cash items: Cash paid for interest, net of interest capitalized of $520 in 2016, $7,256 in 2015 and $8,526 in 2014 $ 96,501 $ 92,622 $ 77,607 Cash paid for income taxes 310 390 — Cash refunds received for income taxes 7,796 90 3,000 Cash paid for share-based compensation (1) — — 431 Non-cash investing activities: Accruals for property and equipment 9,129 44,324 99,750 ARO - additions, dispositions and revisions, net 10,865 (394 ) 89,826 Non-cash financing activities: Exchange transaction — non-cash securities issued: 11.00% 1.5 Lien Term Loan - interest payable 23,823 — — 9.00%/10.75% Second Lien PIK Toggle Notes - carrying value 223,905 — — 8.50%/10.00% Third Lien PIK Toggle Notes - carrying value 213,446 — — Common stock issued - fair value at issuance date 106,366 — — Exchange transaction — non-cash securities exchanged: 8.50% Unsecured Senior Notes - carrying value (712,967 ) — — (1) The cash paid for share-based compensation in 2014 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, 2016
Leases [Abstract]
Commitments	15. 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, 2016 are as follows: 2017–$1.6 million; 2018–$1.7 million; 2019–$1.8 million; 2020–$1.8 million thereafter–$3.7 million. Total rent expense was approximately $3.2 million, $3.3 million and $3.2 million during 2016, 2015 and 2014, respectively. Pursuant to the Purchase and Sale Agreement with Total E&P, we may fulfill security requirements related to ARO for certain properties through securing bonds, or through making payments to an escrow account under a formula pursuant to the agreement, or a combination thereof, until certain prescribed thresholds are met. Once the threshold is met for that year, excess funds in the escrow account are returned to us. As of December 31, 2016, we had bonds totaling $75.0 million and had $1.9 million in an escrow account. The threshold is $83.0 million for 2017, $88.0 million for 2018 and escalates to $103.0 million for 2023 in $3.0 million per year increments. 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, 2016, 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 2016, 2015 and 2014, we had surety bonds related to our decommissioning obligations or ARO. Total expenses related to surety bonds, inclusive of the surety bonds in connection with the Total E&P and Shell agreements described above, were $4.3 million, $5.5 million and $4.1 million during 2016, 2015 and 2014, 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: 2017–$6.1 million; 2018–$5.9 million; 2019–$5.2 million; 2020–$5.0 million; thereafter–$38.6 million. See Notes 17 and 19 for information concerning financial assurances per the BOEM regulations, which could impact future cost estimates related to surety bonds. As of December 31, 2016, we had $16.9 million of collateral deposits for certain sureties related to certain surety bonds for decommissioning obligations and appeals submitted to the Interior Board of Land Appeals (the “IBLA”). Pursuant to an agreement with the Helix Well Containment Group, we are required to make payments quarterly in advance 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, 2016, future payments due are $1.7 million in 2017 and $1.7 million in 2018. 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, 2016 and our drilling rig commitments meet the criteria of an operating lease. Future payments of all drilling rig commitments as of December 31, 2016 were $7.4 million, of which $2.9 million relates to ARO projects.

Related Parties

Related Parties	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Related Parties	16. Related Parties During 2016, 2015 and 2014, there were certain transactions between us and other companies our CEO either controlled or in which he had an ownership interest. In addition, there were transactions with a company that employs the spouse of our CEO. Our CEO 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, $1.1 million and $0.9 million for the years 2016, 2015 and 2014, respectively. Our CEO 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 CEO owns a minority ownership interest and serves on its board of directors. We paid no amounts in 2016 and 2015 and paid $0.2 million for drilling related services during 2014. A company that provides marine transportation and logistics services to W&T employs the spouse of our CEO. The spouse received commissions partially based on services rendered to W&T which totaled less than $0.2 million per year for 2016, 2015 and 2014. During 2015, an entity controlled by our CEO participated in the Second Lien Term Loan for a $5.0 million principal commitment on the same terms as the other lenders.

Contingencies

Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
Contingencies	17. Contingencies Financial Assurance Requirements by the BOEM The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities on the OCS. In July 2016, the BOEM issued NTL #2016-N01 to clarify the procedures and guidelines that BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS leases, ROWs or RUEs. This NTL became effective in September 2016 and supersedes and replaces NTL #2008-N07. 1. In the first quarter of 2016, we received several orders from the BOEM pursuant to NTL #2008-N07 demanding the Company to secure financial assurances in the aggregate of $260.8 million, with amounts specified with respect to certain designated leases, ROWs and RUEs. We filed various appeals to the Interior Board of Land Appeals (the “IBLA”) concerning these orders. The IBLA, acknowledging the BOEM and the Company were seeking to resolve the BOEM demands through settlement discussions, stayed the effectiveness of these orders several times, with the current stay effective to May 31, 2017. • In September 2016, we received notice from the BOEM confirming that we do not qualify to self-insure a portion of any additional financial assurance under NTL #2016-N01. 2. In October 2016, we received from the BOEM proposal letters outlining what additional security the BOEM proposes to require for leases, ROWs and RUEs in which we are designated operator. See Note 19 for a BOEM order issued in December 2016 related to additional financial assurance for sole liability properties, which was subsequently withdrawn in February 2017 by the BOEM. See Note 19 regarding a notice issued in January 2017 by the BOEM extending the implementation timeline by an additional six months of the new regulations as to non-sole liability leases, ROWs and RUEs. Surety Bond Issuers’ Collateral Requirements The issuers of surety bonds in some cases have requested and received additional collateral related to surety bonds for plugging and abandonment activities. 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. We received notice from the ONRR of a statutory fine of $2.3 million (subsequently reduced to $1.1 million) relative to such underpayment. We believe the fine is excessive considering the circumstances and in relation to the amount of underpayment. A hearing on this matter was held with an Administrative Law Judge in August 2016. A decision on this case has been deferred until March 2017 at the earliest. 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, 2016 or 2015. 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 (the “JOA”) related to, among other things, the abandonment of deepwater wells in the Mississippi Canyon area of the Gulf of Mexico. On October 28, 2016, the jury made the following findings: 3. W&T failed to comply with the contract by failing to pay its proportionate share of the costs to plug and abandon the MC 674 wells. 4. The amount of money to compensate Apache for W&T’s failure to pay its proportionate share of the costs to plug and abandon the MC 674 wells was $43.2 million. 5. The $43.2 million referred to in #2 should be offset by $17.0 million. 6. Apache acted in bad faith thereby causing W&T to not comply with the contract. In November 2016 we filed a motion with the trial court requesting a judgment consistent with the jury’s finding that Apache acted in bad faith thereby causing W&T not to comply with the contract, which W&T asserted bars Apache from recovery for damages under applicable law, and if damages are not barred in their entirety, that any judgment for monetary damages should be offset by $17.0 million as determined by the jury. After Apache filed its opposing motion, a hearing was held by the trial court in December 2016. As of the filing date of this Form 10-K, no judgment has been entered by the court. Insurance Claims The matter concerning certain claims with certain insurance companies was settled during the fourth quarter of 2016. See Note 5 for a description of the settlement and the accounting of the funds received. The settlement does not include claims that have not yet been made subject to adjustment or requested for reimbursement by us as of the date of the settlement. Appeal with ONRR In 2009, we 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 IBLA under the Department of the Interior. See Note 19 regarding the denial of our appeal subsequent to December 31, 2016. Royalties – “Unbundling” Initiative The ONRR has publicly announced an “unbundling” initiative to revise 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. The ONRR’s initiative requires re-computing allowable transportation and processing costs using revised guidance from the ONRR going back 84 months for every gas processing plant for which we had gas processed. In the second quarter of 2015, pursuant to the initiative, we received requests from the ONRR for additional data regarding our transportation and processing allowances on natural gas production that was processed through a specific processing plant. We also received a preliminary determination notice from the ONRR asserting its preliminary determination that our 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. We submitted revised calculations covering certain plants and certain time periods and has not yet received official responses as to the preliminary determination asserting the reasonableness of its revised 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 our Federal oil and gas leases for current and prior periods. We have paid $0.5 million during 2016 based on our revised calculations for one plant covering part of the 84 month period. We are not able to determine the range of any additional royalties or, if and when assessed, whether such amounts would be material. Notices of Proposed Civil Penalty Assessment During 2016 and 2015, we paid $0.1 million and $0.2 million of civil penalties issued by the BSEE related to Incidents of Noncompliance (“INCs”) issued by the BSEE at various offshore locations. We currently have four open civil penalties issued by the BSEE arising from INCs, which have not been settled as of the filing of this Form 10-K. The INC’s underlying the civil penalties were issued during 2015, with one re-issued during 2016, and relate to four separate offshore locations with occurrence dates ranging from July 2012 to June 2014. The proposed civil penalties for these INCs total $8.1 million. We have accrued approximately $1.5 million, which is our best estimate of the final settlement once all appeals have been exhausted. Our position is that the proposed civil penalties are excessive given the specific facts and circumstances related to these 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.

Selected Quarterly Financial Da

Selected Quarterly Financial Data	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Selected Quarterly Financial Data	18. 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, 2016 Revenues $ 77,715 $ 99,655 $ 107,403 $ 115,213 Operating income (loss) (1) (166,614 ) (126,997 ) (58,276 ) 21,319 Net income (loss) (1) (190,509 ) (120,922 ) 45,928 16,483 Basic and diluted income (loss) per common share (1) (2) (2.49 ) (1.58 ) 0.48 0.12 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 ) (1) During 2016, we recorded in first, second and third quarter ceiling test write-downs of oil and natural gas properties of $116.6 million, $104.6 million and $57.9 million, respectively. In the third quarter of 2016, we recorded a gain on exchange of debt of $123.9 million. 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 does 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, 2016
Subsequent Events [Abstract]
Subsequent Events	19. Subsequent Events Financial Assurance Requirements by the BOEM In January 2017, the IBLA stay related to our appeal of the BOEM orders issued during the first quarter of 2016 was extended to May 31, 2017. In January 2017, the BOEM, in a notice to stakeholders, extended the implementation timeline for NTL #2016-N01 by an additional six months with respect to non-sole liability properties, except in circumstances in which the BOEM determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities. The extension did not affect the demand to provide financial assurance for leases, ROWs and RUEs constituting sole liability properties. In February 2017, the BOEM withdrew the orders it issued in December 2016 affecting so called “sole liability properties” to allow time for the new President’s administration to review the complex financial assurance program. Sole liability properties are leases, ROWs or RUEs for which the holder is the only liable party, i.e., there are no co-lessees, operating rights owners and/or other grant holders, and no prior interest holders liable to meet the lease and/or grant obligations. This withdrawal rescinded the Order to Provide Additional Security issued to us in December 2016. However, the BOEM may re-issue sole liability orders before the end of the six-month period if it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities. As suggested by the BOEM in its January and February notices, we intend to use the six month extension granted by the BOEM as an opportunity to propose and negotiate acceptable plans dealing with both sole and non-sole liability properties. Appeal with ONRR On January 27, 2017, the IBLA affirmed the decision of the ONRR requiring W&T to pay approximately $4.7 million in additional royalties, which is described in Note 17. We are reviewing the decision with counsel to determine an appropriate course of action.

Supplemental Guarantor Informat

Supplemental Guarantor Information	12 Months Ended
	Dec. 31, 2016
Supplemental Guarantor Information [Abstract]
Supplemental Guarantor Information	W&T OFFSHORE, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 20. Supplemental Guarantor Information Our payment obligations under the Credit Agreement, the 1.5 Lien Term Loan, the Second Lien Term Loan, the Second Lien PIK Toggle Notes, the Third Lien PIK Toggle Notes and the Unsecured Senior Notes (see Note 2) 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 any assets. Guarantees 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, if the sale or other disposition does not violate the Asset Sales provisions (as such terms are defined 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 the indenture and the Guarantor Subsidiary ceases to be a subsidiary of the Company as a result of such sales or disposition; (3) if such Guarantor Subsidiary is a Restricted Subsidiary and the Company designates such Guarantor Subsidiary as an Unrestricted Subsidiary in accordance with the applicable provisions of certain debt documents; (4) upon Legal Defeasance or Covenant Defeasance (as such terms are defined in certain debt documents) or upon satisfaction and discharge of the certain debt documents; (5) upon the liquidation or dissolution of such Guarantor Subsidiary, provided no event of default has occurred and is continuing; or (6) at such time as such Guarantor Subsidiary is no longer required to be a Guarantor Subsidiary as described in certain debt documents, provided no event of default has occurred and is continuing. The following condensed consolidating financial information presents the financial condition, results of operations and cash flows of the Parent Company and the Guarantor Subsidiaries, together with consolidating adjustments necessary to present the Company’s results on a consolidated basis. 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 or less 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, 2016 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Assets Current assets: Cash and cash equivalents $ 70,236 $ — $ — $ 70,236 Receivables: Oil and natural gas sales 2,173 40,900 — 43,073 Joint interest and other 163,200 — (99,272 ) 63,928 Total receivables 165,373 40,900 (99,272 ) 107,001 Prepaid expenses and other assets 12,448 2,056 — 14,504 Total current assets 248,057 42,956 (99,272 ) 191,741 Property and equipment – at cost: Oil and natural gas properties and equipment 5,700,205 2,232,299 — 7,932,504 Furniture, fixtures and other 20,898 — — 20,898 Total property and equipment 5,721,103 2,232,299 — 7,953,402 Less accumulated depreciation, depletion and amortization 5,360,137 2,045,259 953 7,406,349 Net property and equipment 360,966 187,040 (953 ) 547,053 Restricted deposits for asset retirement obligations 27,371 — — 27,371 Income tax receivables 52,097 — — 52,097 Other assets 394,931 344,742 (728,209 ) 11,464 Total assets $ 1,083,422 $ 574,738 $ (828,434 ) $ 829,726 Liabilities and Shareholders’ Equity (Deficit) Current liabilities: Accounts payable $ 74,306 $ 6,733 $ — $ 81,039 Undistributed oil and natural gas proceeds 24,493 1,761 — 26,254 Asset retirement obligations 62,261 16,003 — 78,264 Long-term debt 8,272 — — 8,272 Accrued liabilities 9,293 99,179 (99,272 ) 9,200 Total current liabilities 178,625 123,676 (99,272 ) 203,029 Long-term debt, less current maturities 1,012,455 — — 1,012,455 Asset retirement obligations, less current portion 142,376 113,798 — 256,174 Other liabilities 408,050 — (390,945 ) 17,105 Shareholders’ equity (deficit): Common stock 1 — — 1 Additional paid-in capital 539,973 704,885 (704,885 ) 539,973 Retained earnings (deficit) (1,173,891 ) (367,621 ) 366,668 (1,174,844 ) Treasury stock, at cost (24,167 ) — — (24,167 ) Total shareholders’ equity (deficit) (658,084 ) 337,264 (338,217 ) (659,037 ) Total liabilities and shareholders’ equity (deficit) $ 1,083,422 $ 574,738 $ (828,434 ) $ 829,726 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 (deficit): Common stock 1 — — 1 Additional paid-in capital 423,499 704,885 (704,885 ) 423,499 Retained earnings (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 Statement of Operations for the Year Ended December 31, 2016 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Revenues $ 161,063 $ 238,923 $ — $ 399,986 Operating costs and expenses: Lease operating expenses 84,415 67,984 — 152,399 Production taxes 1,889 — — 1,889 Gathering and transportation 9,795 13,133 — 22,928 Depreciation, depletion and amortization 73,268 112,277 8,493 194,038 Asset retirement obligations accretion 8,165 9,406 — 17,571 Ceiling test write-down of oil and natural gas properties 28,305 110,709 140,049 279,063 General and administrative expenses 24,817 34,923 — 59,740 Derivative loss 2,926 — — 2,926 Total costs and expenses 233,580 348,432 148,542 730,554 Operating loss (72,517 ) (109,509 ) (148,542 ) (330,568 ) Loss of affiliates (109,853 ) — 109,853 — Interest expense: Incurred 92,607 184 — 92,791 Capitalized (336 ) (184 ) — (520 ) Gain on exchange of debt 123,923 — — 123,923 Other (income) expense, net (6,520 ) — — (6,520 ) Loss before income tax expense (benefit) (144,198 ) (109,509 ) (38,689 ) (292,396 ) Income tax expense (benefit) (43,720 ) 344 — (43,376 ) Net loss $ (100,478 ) $ (109,853 ) $ (38,689 ) $ (249,020 ) 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 loss (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 ) Earnings 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 expense (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 and amortization 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 gain (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 (benefit) (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 Cash Flows for the Year Ended December 31, 2016 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Operating activities: Net loss $ (100,478 ) $ (109,853 ) $ (38,689 ) $ (249,020 ) Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Depreciation, depletion, amortization and accretion 81,433 121,683 8,493 211,609 Ceiling test write-down of oil and gas properties 28,305 110,709 140,049 279,063 Gain on exchange of debt (123,923 ) — — (123,923 ) Debt issuance costs write-off/amortization of debt items 2,548 — — 2,548 Share-based compensation 11,013 — — 11,013 Derivative gain 2,926 — — 2,926 Cash receipts on derivative settlements, net 4,746 — — 4,746 Deferred income taxes 28,048 344 — 28,392 Loss of affiliates 109,853 — (109,853 ) — Changes in operating assets and liabilities: Oil and natural gas receivables 1,630 (8,635 ) — (7,005 ) Joint interest and other receivables (1,126 ) — — (1,126 ) Income taxes (64,274 ) — — (64,274 ) Prepaid expenses and other assets (14,395 ) (78,547 ) 77,996 (14,946 ) Asset retirement obligation settlements (49,303 ) (23,017 ) — (72,320 ) Accounts payable, accrued liabilities and other 46,955 37,538 (77,996 ) 6,497 Net cash provided by (used in) operating activities (36,042 ) 50,222 — 14,180 Investing activities: Investment in oil and natural gas properties and equipment (37,418 ) (11,188 ) — (48,606 ) Changes in operating assets and liabilities associated with investing activities 4,340 (39,534 ) — (35,194 ) Proceeds from sales of assets and other, net 1,000 500 — 1,500 Purchases of furniture, fixtures and other (96 ) — — (96 ) Net cash used in investing activities (32,174 ) (50,222 ) — (82,396 ) Financing activities: Borrowings of long-term debt – revolving bank credit facility 340,000 — — 340,000 Repayments of long-term debt – revolving bank credit facility (340,000 ) — — (340,000 ) Issuance of 1.5 Lien Term Loan 75,000 — — 75,000 Payment of interest on 1.5 Lien Term Loan (2,570 ) — — (2,570 ) Debt exchange costs (18,464 ) — — (18,464 ) Other (928 ) — — (928 ) Net cash provided by financing activities 53,038 — — 53,038 Decrease in cash and cash equivalents (15,178 ) — — (15,178 ) Cash and cash equivalents, beginning of period 85,414 — — 85,414 Cash and cash equivalents, end of period $ 70,236 $ — $ — $ 70,236 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 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 Amortization of debt issuance costs and premium 4,411 — — 4,411 Share-based compensation 10,242 — — 10,242 Derivative gain (14,375 ) — — (14,375 ) Cash payments on derivative settlements 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 obligations (26,637 ) (5,918 ) — (32,555 ) Accounts payable, accrued liabilities and other (141,596 ) 4,156 91,245 (46,195 ) Net cash provided by (used in) operating activities (89,573 ) 222,801 — 133,228 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 provided by (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% Second Lien Term Loan 297,000 — — 297,000 Debt issuance costs (6,669 ) — — (6,669 ) Other (886 ) — — (886 ) Investment from parent — 1,445 (1,445 ) — Net cash provided by (used in) financing activities (157,555 ) 1,445 (1,445 ) (157,555 ) Increase 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 (loss) 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 loss (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 11,931 (30,475 ) 23,425 4,881 Net cash provided by operating activities 275,700 199,121 — 474,821 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 (1,193 ) — — (1,193 ) Investment from parent — 62,323 (62,323 ) — Net cash provided by financing activities 125,547 62,323 (62,323 ) 125,547 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

Supplemental Oil and Gas Disclo

Supplemental Oil and Gas Disclosures-unaudited	12 Months Ended
	Dec. 31, 2016
Extractive Industries [Abstract]
Supplemental Oil and Gas Disclosures-UNAUDITED	21. Supplemental Oil and Gas Disclosures—UNAUDITED Geographic Area of Operation All of our proved reserves are located within the United States in the Gulf of Mexico. 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, 2016 2015 2014 Net capitalized cost: Proved oil and natural gas properties and equipment $ 7,932.5 $ 7,882.3 $ 7,924.2 Unproved oil and natural gas properties and equipment — 20.2 121.5 Accumulated depreciation, depletion and amortization (1) related to oil, NGLs and natural gas activities (7,387.8 ) (6,916.2 ) (5,557.6 ) Net capitalized costs related to producing activities $ 544.7 $ 986.3 $ 2,488.1 (1) Includes ceiling test write-down in 2016 and 2015. 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, 2016 2015 2014 Costs incurred: (1) Proved properties acquisitions $ 1.3 $ 15.6 $ 111.5 Exploration (2) (3) 4.8 152.4 411.1 Development 56.9 65.5 198.7 Unproved properties acquisitions (4) 0.5 0.1 3.1 Total costs incurred in oil and gas property acquisition, exploration and development activities $ 63.5 $ 233.6 $ 724.4 (1) Includes net addition from capitalized ARO of $10.8 million in 2016, net reductions from capitalized ARO of $0.4 million in 2015, and net additions from capitalized ARO of $88.0 million during 2014. These adjustments for ARO are associated with acquisitions, liabilities incurred, divestitures and revisions of estimates. (2) Includes seismic costs of $0.2 million, $3.2 million and $9.0 million incurred during 2016, 2015 and 2014, respectively. (3) Includes geological and geophysical costs charged to expense of $4.1 million, $5.7 million and $7.3 million during 2016, 2015 and 2014, 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, 2016 2015 2014 Depreciation, depletion, amortization and accretion per Boe $ 13.77 $ 23.11 $ 28.98 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 represents 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 19% of our proved developed non-producing reserves as of December 31, 2016 so we may not be in a position to control the timing of all development activities. We are the operator for all of our proved undeveloped reserves as of December 31, 2016. In prior years, we were not the operator of all proved undeveloped reserves. 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, 2013 58.5 15.9 259.9 117.7 705.9 Revisions of previous estimates (2) 1.6 0.1 14.3 4.1 25.3 Extensions and discoveries (3) 7.3 0.7 10.1 9.7 58.1 Purchase of minerals in place (4) 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 (5) 4.8 (0.9 ) 4.9 4.7 28.0 Revisions related to sold properties (6) (12.1 ) (4.8 ) (2.9 ) (17.4 ) (104.3 ) Extensions and discoveries (7) 2.4 0.2 8.8 4.1 24.4 Purchase of minerals in place (8) — — 6.1 1.0 6.1 Sales of reserves (9) (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 Revisions of previous estimates (10) 4.6 3.1 32.1 13.0 78.1 Production (7.2 ) (1.5 ) (39.7 ) (15.4 ) (92.2 ) Proved reserves as of Dec. 31, 2016 32.9 8.2 197.8 74.0 444.0 Year-end proved developed reserves: 2016 26.6 7.6 183.1 64.7 388.2 2015 29.4 6.4 198.5 69.0 413.5 2014 35.7 10.7 221.1 83.3 499.7 Year-end proved undeveloped reserves: 2016 (11) 6.3 0.6 14.7 9.3 55.8 2015 6.1 0.2 6.9 7.4 44.6 2014 26.0 5.1 33.8 36.7 220.3 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 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 extensions and discoveries of 4.1 MMBoe at our Yellow Rose field and 4.1 MMBoe at our Mississippi Canyon 782 field. (4) Primarily due to acquiring additional ownership in the Fairway Field and acquisition of the Woodside Properties. (5) 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. (6) 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. (7) Primarily due to increases at our Ewing Bank 910 field. (8) Primarily due to purchase of additional interest at our Brazos A-133 field. (9) 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. (10) Primarily related to upward revisions of 14.2 MMBoe, which included upward revisions of 3.8 MMBoe at our Viosca Knoll 823 (Tahoe/SE Tahoe) field, 1.5 MMBoe at our Fairway field, 1.3 MMBoe at our Mississippi Canyon 782 (Dantzler) field, and 1.2 MMBoe at our Main Pass 108 field. Partially offsetting were decreases for price revisions of 1.2 MMBoe. (11) We believe that we will be able to develop all but 1.3 MMBoe, or approximately 14%, of the total of 9.3 MMBoe reserves classified as proved undeveloped (“PUDs”) at December 31, 2016, within five years from the date such reserves were initially recorded. The lone 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. One of the sidetrack PUD locations in this field was originally recorded in our proved reserves as of December 31, 2010. The development of this PUD 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 this PUD location in 2023. 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, 2016 2015 2014 2013 Oil - per barrel $ 36.28 $ 46.94 $ 91.12 $ 99.65 NGLs per barrel 16.82 17.60 34.63 35.21 Natural gas per Mcf 2.47 2.50 4.27 3.80 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, 2016 2015 2014 Standardized Measure of Discounted Future Net Cash Flows Future cash inflows $ 1,818.4 $ 2,296.7 $ 7,258.5 Future costs: Production (691.5 ) (840.1 ) (2,224.5 ) Development (141.1 ) (161.4 ) (922.0 ) Dismantlement and abandonment (427.7 ) (471.8 ) (475.4 ) Income taxes (1) — — (948.4 ) Future net cash inflows before 10% discount 558.1 823.4 2,688.2 10% annual discount factor (79.8 ) (209.5 ) (985.4 ) Total $ 478.3 $ 613.9 $ 1,702.8 (1) No future income taxes were estimated to be paid in 2016 and 2015 as our tax position has sufficient tax basis to offset estimated future taxes. State income taxes were disregarded due to immateriality. The change in 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, 2016 2015 2014 Changes in Standardized Measure Standardized measure, beginning of year $ 613.9 $ 1,702.8 $ 1,674.6 Increases (decreases): Sales and transfers of oil and gas produced, net of production costs (218.6 ) (289.1 ) (650.9 ) Net changes in price, net of future production costs (275.2 ) (1,455.6 ) (278.6 ) Extensions and discoveries, net of future production and development costs — 65.3 309.6 Changes in estimated future development costs (32.5 ) (8.5 ) (56.4 ) Previously estimated development costs incurred 114.5 158.9 263.1 Revisions of quantity estimates 190.1 137.9 118.6 Accretion of discount 52.6 150.6 180.6 Net change in income taxes — 600.8 (11.4 ) Purchases of reserves in-place — 6.0 86.7 Sales of reserves in-place — (401.4 ) — Changes in production rates due to timing and other 33.5 (53.8 ) 66.9 Net increase (decrease) in standardized measure (135.6 ) (1,088.9 ) 28.2 Standardized measure, end of year $ 478.3 $ 613.9 $ 1,702.8

Significant Accounting Polici28

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
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 7. We are 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. 2016-09 (“ASU 2016-09”), Compensation – Stock Compensation Subtopic 718 .
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, were significantly lower during 2015 and lower still in 2016 compared to prior years. We took a number of steps during 2015 and 2016 to mitigate the effects of these lower prices including: (i) significantly reducing capital spending from previous year levels and budgeting conservative capital spending for 2017 (exclusive of acquisitions); (ii) restructuring our debt and issuing our common stock through an exchange transaction, which is described in Note 2, (iii) receiving funds through two debt issuances, which are described in Note 2 (iv) suspending our quarterly common stock dividend; (iv) implementing numerous cost reduction projects to reduce our operating costs; and (v) selling our interest in the Yellow Rose onshore field, which is described in Note 7. During 2016, the Bureau of Ocean Energy Management (“BOEM”) issued orders to us concerning financial assurances related to plug and abandonment (decommissioning) obligations for Federal offshore leases, including an order issued to us in December 2016 regarding additional security required for sole liability properties. In July 2016, effective September 2016, the BOEM issued Notice to Lessees #2016-N01 (“NTL #2016-N01”), related to obligations for decommissioning activities on the Outer Continental Shelf (“OCS”) for leases, rights-of-way (“ROWs”) or rights of use and easement (“RUEs”). In January 2017, the BOEM extended the implementation timeline by an additional six months of NTL #2016-N01 as to leases, ROWs and RUEs for which there are co-lessees and/or predecessors in interest (non-sole liability properties), with certain exceptions. In February 2017, the BOEM withdrew the sole liability orders it had issued in December 2016 to allow time for the new President’s administration to review the complex financial assurance program. See Note 17 and 19 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 for at least 12 months from the date of issuance of this Form 10-K, which is the threshold of a going concern under GAAP; however, we cannot predict with any certainty future commodity prices or the actions of the BOEM concerning financial assurance requirements, either of which could 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 we have taken less than our ownership share of production. At December 31, 2016 and 2015, $5.3 million and $6.9 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. The majority of 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, including some of our joint interest partners. We use the specific identification method of determining if an allowance for doubtful accounts is needed. As of December 31, 2016 and 2015, $7.6 million and $2.5 million, respectively, were recorded as an allowance for doubtful accounts. During 2016 and 2015, there were no reductions recorded in the allowance for doubtful accounts (no collections of accounts previously reserved and no permanent write-off of receivable accounts). The following identifies customers from whom we derived 10% or more of our receipts from sales of crude oil, NGLs and natural gas. Year Ended December 31, 2016 2015 2014 Customer Shell Trading (US) Co. 43 % 50 % 47 % Vitol Inc. 20 % ** ** 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 company’s adjuster reviews and approves such costs for payment or when the insurance company has agreed to reimbursement amounts. Claims that have been processed in this manner have customarily been paid on a timely basis. See Note 5, 17 and 19 for information related to settlement of previously unpaid claims by certain insurance companies.
Prepaid Expenses and Other	Prepaid expenses and other Amounts recorded in Prepaid expenses and other Year Ended December 31, 2016 2015 Derivative assets - current (1) $ — $ 10,036 Prepaid/accrued insurance and surety bonds 5,386 7,475 Prepaid deposits related to royalties 6,237 5,943 Other (2) 2,881 3,425 Prepaid expenses and other $ 14,504 $ 26,879 (1) Includes open and closed (and not yet collected) derivative commodity contracts recorded at fair value as of December 31, 2015. (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 we have 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 perform a “ceiling test” calculation quarterly, 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 and 2016, which are reported as a separate line in the Statements of Operations. The average price using the SEC required methodology at December 31, 2016 was $39.25 per barrel for West Texas Intermediate (“WTI”) crude oil and $2.48 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 were $279.1 million and $987.2 million for 2016 and 2015, respectively. There was no ceiling test write-down in the fourth quarter of 2016. We did not record a ceiling test write-down during 2014. If average crude oil and natural gas prices decrease from 2016 levels, it is possible that a ceiling test write-down will be recorded during 2017.
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 4.
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. As of December 31, 2016, we did not have any open derivative financial instruments. 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. Whenever we have entered into derivative contracts, we did not 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 11.00% 1.5 Lien Term Loan, due November 2019, (the “1.5 Lien Term Loan”) approximates fair value because the debt was recently executed and reflective of market rates and conditions.
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.
Income Taxes	Income Taxes We use the liability method of accounting for income taxes in accordance with the Income Taxes
Troubled Debt Restructuring	Troubled Debt Restructuring We accounted for an exchange transaction, which is described in Note 2, as a troubled debt restructuring pursuant to the guidance under Accounting Standard Codification 470-60, Troubled Debt Restructuring
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. 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. 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 10 for additional information.
Loss Per Share	Loss 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 loss per share under the two-class method when the effect is dilutive. For additional information, refer to Note 13.
Other (Income) Expense, Net	Other (Income) Expense, Net For 2016, the amount includes $7.7 million of income related to the settlement of certain insurance claims. In 2016 and 2015, the amount includes write-offs of debt issuance costs of $1.4 million and $3.2 million, respectively, related to a reduction in the borrowing base of the revolving bank credit facility under the Fifth Amended and Restated Credit Agreement (as amended, the “Credit Agreement”). The write-offs of debt issuance costs in both 2016 and 2015 are included as an adjustment to net income in determining Net cash provided by operating activities
Recent Accounting Developments	Recent Accounting Developments In May 2014, the Financial Accounting Standards Board (“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 In June 2016, the FASB issued Accounting Standards Update No. 2016-13, (“ASU 2016-13”), Financial Instruments – Credit Losses Subtopic 326 In August 2016, the FASB issued Accounting Standards Update No. 2016-15, (“ASU 2016-15”), Statement of Cash Flows (Topic 230) – Classification of Certain Cash Receipts and Cash Payments In November 2016, the FASB issued Accounting Standards Update No. 2016-18, (“ASU 2016-18”), Statement of Cash Flows (Topic 230) – Restricted Cash

Significant Accounting Polici29

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Percentage of Revenue by Major Customers	The following identifies customers from whom we derived 10% or more of our receipts from sales of crude oil, NGLs and natural gas. Year Ended December 31, 2016 2015 2014 Customer Shell Trading (US) Co. 43 % 50 % 47 % Vitol Inc. 20 % ** ** 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, 2016 2015 Derivative assets - current (1) $ — $ 10,036 Prepaid/accrued insurance and surety bonds 5,386 7,475 Prepaid deposits related to royalties 6,237 5,943 Other (2) 2,881 3,425 Prepaid expenses and other $ 14,504 $ 26,879 (1) Includes open and closed (and not yet collected) derivative commodity contracts recorded at fair value as of December 31, 2015. (2) Individual items were less than 5% of total current assets for either period presented.

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Long-Term Debt	As of December 31, 2016 and 2015, our long-term debt was as follows (in thousands): December 31, December 31, 2016 2015 PIK Payable/ Interest Payable/ Carrying Principal/ Principal Other Value Other* 11.00% 1.5 Lien Term Loan, due November 2019 $ 75,000 $ 23,823 $ 98,823 $ — 9.00 % Second Lien Term Loan, due May 2020 300,000 — 300,000 300,000 9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020 163,007 60,898 223,905 — 8.50%/10.00% Third Lien PIK Toggle Notes, due June 2021 145,897 67,549 213,446 — 8.50% Unsecured Senior Notes, due June 2019 189,829 — 189,829 900,000 Subtotal 873,733 152,270 1,026,003 1,200,000 Debt premium, discount, issuance costs, net of amortization — (5,276 ) (5,276 ) (3,145 ) Total long-term debt 873,733 146,994 1,020,727 1,196,855 Current maturities of long-term debt — 8,272 8,272 — Long term debt, less current maturities $ 873,733 $ 138,722 $ 1,012,455 $ 1,196,855 * Amounts also equal carrying value

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Schedule of Fair Value of Long-Term Debt	The following table presents the fair value of our long-term debt (in thousands): December 31, Hierarchy 2016 2015 11.00% 1.5 Lien Term Loan, due November 2019 Level 2 $ 75,000 $ — 9.00 % Second Lien Term Loan, due May 2020 Level 2 255,000 217,500 9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020 Level 2 122,255 — 8.50%/10.00% Third Lien PIK Toggle Notes due June 2021 Level 2 80,243 — 8.50% Unsecured Senior Notes, due June 2019 Level 2 123,389 324,000

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 Asset retirement obligations, beginning of period $ 378,322 $ 390,568 Liabilities settled (72,320 ) (32,555 ) Accretion of discount 17,571 20,703 Disposition of properties — (8,581 ) Liabilities assumed through acquisition — 2,944 Liabilities incurred 398 4,780 Revisions of estimated liabilities 10,467 463 Asset retirement obligations, end of period 334,438 378,322 Less current portion 78,264 84,335 Long-term $ 256,174 $ 293,987

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2016
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 Pro Forma Financial Information for Acquisition	The following table presents a summary of our pro forma financial information (in thousands, except earnings per share): (unaudited) December 31, 2014 (a) Revenue $ 971,595 Net loss (5,504 ) Basic and diluted loss per common share (0.08 )
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) December 31, 2014 (a) Revenues (b) $ 22,887 Direct operating expenses (b) 4,417 DD&A (c) 8,385 G&A (d) 300 Interest expense (e) 330 Capitalized interest (f) (19 ) Income tax expense (g) 3,316 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.

Derivative Financial Instrume34

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
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, 2016 2015 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, 2016 2015 2014 Derivative (gain) loss $ 2,926 $ (14,375 ) $ (3,965 )
Cash Receipts (Payments) on Derivative Settlements 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, 2016 2015 2014 Cash receipts (payments) on derivative settlements, net $ 4,746 $ 6,703 $ (5,318 )

Share-Based Awards and Cash-B35

Share-Based Awards and Cash-Based Awards (Tables)	12 Months Ended
	Dec. 31, 2016
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Share Activity Related to Restricted Stock Units	A summary of activity related to RSUs is as follows: 2016 2015 2014 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 3,474,079 $ 7.42 1,977,335 $ 15.29 1,331,753 $ 14.96 Granted 4,213,964 2.21 2,626,930 3.59 1,195,388 16.84 Vested (968,652 ) 16.69 (721,038 ) 13.23 (354,692 ) 18.59 Forfeited (612,143 ) 3.64 (409,148 ) 10.63 (195,114 ) 16.53 Nonvested, end of period 6,107,248 $ 2.73 3,474,079 $ 7.42 1,977,335 $ 15.29
Schedule of Restricted Stock Units Outstanding	Subject to the satisfaction of service conditions, the RSUs outstanding as of December 31, 2016 are eligible to vest in the year indicated in the table below: Restricted Stock Units 2017 2,311,434 2018 3,795,814 Total 6,107,248
Schedule of Restricted Stock Activity	A summary of activity related to Restricted Shares is as follows: 2016 2015 2014 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 78,230 $ 8.95 43,210 $ 16.20 43,840 $ 15.96 Granted 126,128 2.22 56,540 6.19 18,815 18.60 Vested (43,062 ) 9.75 (21,520 ) 16.26 (19,445 ) 18.00 Nonvested, end of period 161,296 $ 3.47 78,230 $ 8.95 43,210 $ 16.20
Schedule of Restricted Stock Awards Outstanding	Subject to the satisfaction of service conditions, the Restricted Shares outstanding as of December 31, 2016 are expected to vest as follows: Restricted Shares 2017 62,136 2018 57,120 2019 42,040 Total 161,296
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, 2016 2015 2014 Share-based compensation expense from: Restricted stock units $ 10,640 $ 9,978 $ 13,150 Restricted stock 373 358 369 Common shares — (94 ) 1,225 Total $ 11,013 $ 10,242 $ 14,744 Share-based compensation tax benefit: Tax benefit computed at the statutory rate $ 3,855 $ 3,585 $ 5,160
Summary of Compensation Expense Related to Share-Based Awards and Cash-Based Awards	A summary of compensation expense related to share-based awards and cash-based awards is as follows (in thousands): Year Ended December 31, 2016 2015 2014 Share-based compensation included in: General and administrative $ 11,013 $ 10,242 $ 14,744 Cash-based incentive compensation included in: Lease operating expense — 364 3,285 General and administrative (1) — (233 ) 6,950 Total charged to operating income $ 11,013 $ 10,373 $ 24,979 (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, 2016
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, 2016 2015 2014 Current $ (71,768 ) $ 288 $ 301 Deferred 28,392 (203,272 ) (4,760 ) Total income tax( benefit) $ (43,376 ) $ (202,984 ) $ (4,459 )
Reconciliation of Income Taxes Computed to Income Tax Benefit	The reconciliation of income taxes computed at the U.S. federal statutory tax rate to our income tax benefit is as follows (in thousands, except percentages): Year Ended December 31, 2016 2015 2014 Income tax (benefit) at the federal statutory rate $ (102,339 ) 35.0 % $ (436,696 ) 35.0 % $ (5,642 ) 35.0 % Share-based compensation 4,920 (1.7 ) 2,940 (0.2 ) — — State income taxes (755 ) 0.2 (2,343 ) 0.2 263 (1.6 ) Valuation allowance 52,915 (18.1 ) 232,925 (18.7 ) — — Debt restructuring cost 1,463 (0.5 ) — — — — Other 420 (0.1 ) 190 — 920 (5.7 ) $ (43,376 ) 14.8 % $ (202,984 ) 16.3 % $ (4,459 ) 27.7 %
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, 2016 2015 Deferred tax liabilities: Property and equipment $ — $ 40,287 Derivatives — 2,697 Other 1,423 3,000 Total deferred tax liabilities 1,423 45,984 Deferred tax assets: Alternative minimum tax credit — 20,486 Property and equipment 42,385 — Asset retirement obligations 117,588 133,018 Federal net operating losses — 145,733 State net operating losses 5,615 5,068 Valuation allowance (290,190 ) (237,275 ) Exchange transaction 118,467 — Share-based compensation 2,353 4,245 Other 4,798 2,304 Total deferred tax assets 1,016 73,579 Net deferred tax asset (liabilities) $ (407 ) $ 27,595
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, 2016 (in thousands): Amount Expiration Year Federal net operating loss $ — N/A State net operating losses 112,512 2021-2030 Alternative minimum tax credit — N/A General business credit — N/A
Balances in Uncertain Tax Positions	Balances in the uncertain tax positions are as follows (in thousands): December 31, 2016 2015 Balance, beginning and end of period $ 9,482 $ 9,482

Loss Per Share (Tables)

Loss Per Share (Tables)	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Schedule of Calculation of Basic and Diluted Loss Per Common Share	The following table presents the calculation of basic and diluted loss per common share (in thousands, except per share amounts): Year Ended December 31, 2016 2015 2014 Net loss $ (249,020 ) $ (1,044,718 ) $ (11,661 ) Less portion allocated to nonvested shares — — 269 Net loss allocated to common shares $ (249,020 ) $ (1,044,718 ) $ (11,930 ) Weighted average common shares outstanding 95,644 75,931 75,609 Basic and diluted loss per common share $ (2.60 ) $ (13.76 ) $ (0.16 ) Shares excluded due to being anti-dilutive (weighted-average) 5,269 2,195 2,097

Supplemental Cash Flow Inform38

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2016
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	The following reflects our supplemental cash flow information (in thousands): Year Ended December 31, 2016 2015 2014 Supplemental cash items: Cash paid for interest, net of interest capitalized of $520 in 2016, $7,256 in 2015 and $8,526 in 2014 $ 96,501 $ 92,622 $ 77,607 Cash paid for income taxes 310 390 — Cash refunds received for income taxes 7,796 90 3,000 Cash paid for share-based compensation (1) — — 431 Non-cash investing activities: Accruals for property and equipment 9,129 44,324 99,750 ARO - additions, dispositions and revisions, net 10,865 (394 ) 89,826 Non-cash financing activities: Exchange transaction — non-cash securities issued: 11.00% 1.5 Lien Term Loan - interest payable 23,823 — — 9.00%/10.75% Second Lien PIK Toggle Notes - carrying value 223,905 — — 8.50%/10.00% Third Lien PIK Toggle Notes - carrying value 213,446 — — Common stock issued - fair value at issuance date 106,366 — — Exchange transaction — non-cash securities exchanged: 8.50% Unsecured Senior Notes - carrying value (712,967 ) — — (1) The cash paid for share-based compensation in 2014 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 39

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 Revenues $ 77,715 $ 99,655 $ 107,403 $ 115,213 Operating income (loss) (1) (166,614 ) (126,997 ) (58,276 ) 21,319 Net income (loss) (1) (190,509 ) (120,922 ) 45,928 16,483 Basic and diluted income (loss) per common share (1) (2) (2.49 ) (1.58 ) 0.48 0.12 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 ) (1) During 2016, we recorded in first, second and third quarter ceiling test write-downs of oil and natural gas properties of $116.6 million, $104.6 million and $57.9 million, respectively. In the third quarter of 2016, we recorded a gain on exchange of debt of $123.9 million. 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 does 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 Inform40

Supplemental Guarantor Information (Tables)	12 Months Ended
	Dec. 31, 2016
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 or less 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, 2016 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Assets Current assets: Cash and cash equivalents $ 70,236 $ — $ — $ 70,236 Receivables: Oil and natural gas sales 2,173 40,900 — 43,073 Joint interest and other 163,200 — (99,272 ) 63,928 Total receivables 165,373 40,900 (99,272 ) 107,001 Prepaid expenses and other assets 12,448 2,056 — 14,504 Total current assets 248,057 42,956 (99,272 ) 191,741 Property and equipment – at cost: Oil and natural gas properties and equipment 5,700,205 2,232,299 — 7,932,504 Furniture, fixtures and other 20,898 — — 20,898 Total property and equipment 5,721,103 2,232,299 — 7,953,402 Less accumulated depreciation, depletion and amortization 5,360,137 2,045,259 953 7,406,349 Net property and equipment 360,966 187,040 (953 ) 547,053 Restricted deposits for asset retirement obligations 27,371 — — 27,371 Income tax receivables 52,097 — — 52,097 Other assets 394,931 344,742 (728,209 ) 11,464 Total assets $ 1,083,422 $ 574,738 $ (828,434 ) $ 829,726 Liabilities and Shareholders’ Equity (Deficit) Current liabilities: Accounts payable $ 74,306 $ 6,733 $ — $ 81,039 Undistributed oil and natural gas proceeds 24,493 1,761 — 26,254 Asset retirement obligations 62,261 16,003 — 78,264 Long-term debt 8,272 — — 8,272 Accrued liabilities 9,293 99,179 (99,272 ) 9,200 Total current liabilities 178,625 123,676 (99,272 ) 203,029 Long-term debt, less current maturities 1,012,455 — — 1,012,455 Asset retirement obligations, less current portion 142,376 113,798 — 256,174 Other liabilities 408,050 — (390,945 ) 17,105 Shareholders’ equity (deficit): Common stock 1 — — 1 Additional paid-in capital 539,973 704,885 (704,885 ) 539,973 Retained earnings (deficit) (1,173,891 ) (367,621 ) 366,668 (1,174,844 ) Treasury stock, at cost (24,167 ) — — (24,167 ) Total shareholders’ equity (deficit) (658,084 ) 337,264 (338,217 ) (659,037 ) Total liabilities and shareholders’ equity (deficit) $ 1,083,422 $ 574,738 $ (828,434 ) $ 829,726 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 (deficit): Common stock 1 — — 1 Additional paid-in capital 423,499 704,885 (704,885 ) 423,499 Retained earnings (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 Statement of Operations	Condensed Consolidating Statement of Operations for the Year Ended December 31, 2016 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Revenues $ 161,063 $ 238,923 $ — $ 399,986 Operating costs and expenses: Lease operating expenses 84,415 67,984 — 152,399 Production taxes 1,889 — — 1,889 Gathering and transportation 9,795 13,133 — 22,928 Depreciation, depletion and amortization 73,268 112,277 8,493 194,038 Asset retirement obligations accretion 8,165 9,406 — 17,571 Ceiling test write-down of oil and natural gas properties 28,305 110,709 140,049 279,063 General and administrative expenses 24,817 34,923 — 59,740 Derivative loss 2,926 — — 2,926 Total costs and expenses 233,580 348,432 148,542 730,554 Operating loss (72,517 ) (109,509 ) (148,542 ) (330,568 ) Loss of affiliates (109,853 ) — 109,853 — Interest expense: Incurred 92,607 184 — 92,791 Capitalized (336 ) (184 ) — (520 ) Gain on exchange of debt 123,923 — — 123,923 Other (income) expense, net (6,520 ) — — (6,520 ) Loss before income tax expense (benefit) (144,198 ) (109,509 ) (38,689 ) (292,396 ) Income tax expense (benefit) (43,720 ) 344 — (43,376 ) Net loss $ (100,478 ) $ (109,853 ) $ (38,689 ) $ (249,020 ) 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 loss (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 ) Earnings 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 expense (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 and amortization 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 gain (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 (benefit) (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 Cash Flows	Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2016 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Operating activities: Net loss $ (100,478 ) $ (109,853 ) $ (38,689 ) $ (249,020 ) Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Depreciation, depletion, amortization and accretion 81,433 121,683 8,493 211,609 Ceiling test write-down of oil and gas properties 28,305 110,709 140,049 279,063 Gain on exchange of debt (123,923 ) — — (123,923 ) Debt issuance costs write-off/amortization of debt items 2,548 — — 2,548 Share-based compensation 11,013 — — 11,013 Derivative gain 2,926 — — 2,926 Cash receipts on derivative settlements, net 4,746 — — 4,746 Deferred income taxes 28,048 344 — 28,392 Loss of affiliates 109,853 — (109,853 ) — Changes in operating assets and liabilities: Oil and natural gas receivables 1,630 (8,635 ) — (7,005 ) Joint interest and other receivables (1,126 ) — — (1,126 ) Income taxes (64,274 ) — — (64,274 ) Prepaid expenses and other assets (14,395 ) (78,547 ) 77,996 (14,946 ) Asset retirement obligation settlements (49,303 ) (23,017 ) — (72,320 ) Accounts payable, accrued liabilities and other 46,955 37,538 (77,996 ) 6,497 Net cash provided by (used in) operating activities (36,042 ) 50,222 — 14,180 Investing activities: Investment in oil and natural gas properties and equipment (37,418 ) (11,188 ) — (48,606 ) Changes in operating assets and liabilities associated with investing activities 4,340 (39,534 ) — (35,194 ) Proceeds from sales of assets and other, net 1,000 500 — 1,500 Purchases of furniture, fixtures and other (96 ) — — (96 ) Net cash used in investing activities (32,174 ) (50,222 ) — (82,396 ) Financing activities: Borrowings of long-term debt – revolving bank credit facility 340,000 — — 340,000 Repayments of long-term debt – revolving bank credit facility (340,000 ) — — (340,000 ) Issuance of 1.5 Lien Term Loan 75,000 — — 75,000 Payment of interest on 1.5 Lien Term Loan (2,570 ) — — (2,570 ) Debt exchange costs (18,464 ) — — (18,464 ) Other (928 ) — — (928 ) Net cash provided by financing activities 53,038 — — 53,038 Decrease in cash and cash equivalents (15,178 ) — — (15,178 ) Cash and cash equivalents, beginning of period 85,414 — — 85,414 Cash and cash equivalents, end of period $ 70,236 $ — $ — $ 70,236 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 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 Amortization of debt issuance costs and premium 4,411 — — 4,411 Share-based compensation 10,242 — — 10,242 Derivative gain (14,375 ) — — (14,375 ) Cash payments on derivative settlements 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 obligations (26,637 ) (5,918 ) — (32,555 ) Accounts payable, accrued liabilities and other (141,596 ) 4,156 91,245 (46,195 ) Net cash provided by (used in) operating activities (89,573 ) 222,801 — 133,228 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 provided by (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% Second Lien Term Loan 297,000 — — 297,000 Debt issuance costs (6,669 ) — — (6,669 ) Other (886 ) — — (886 ) Investment from parent — 1,445 (1,445 ) — Net cash provided by (used in) financing activities (157,555 ) 1,445 (1,445 ) (157,555 ) Increase 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 (loss) 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 loss (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 11,931 (30,475 ) 23,425 4,881 Net cash provided by operating activities 275,700 199,121 — 474,821 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 (1,193 ) — — (1,193 ) Investment from parent — 62,323 (62,323 ) — Net cash provided by financing activities 125,547 62,323 (62,323 ) 125,547 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

Supplemental Oil and Gas Disc41

Supplemental Oil and Gas Disclosures-unaudited (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 2014 Net capitalized cost: Proved oil and natural gas properties and equipment $ 7,932.5 $ 7,882.3 $ 7,924.2 Unproved oil and natural gas properties and equipment — 20.2 121.5 Accumulated depreciation, depletion and amortization (1) related to oil, NGLs and natural gas activities (7,387.8 ) (6,916.2 ) (5,557.6 ) Net capitalized costs related to producing activities $ 544.7 $ 986.3 $ 2,488.1 (1) Includes ceiling test write-down in 2016 and 2015.
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, 2016 2015 2014 Costs incurred: (1) Proved properties acquisitions $ 1.3 $ 15.6 $ 111.5 Exploration (2) (3) 4.8 152.4 411.1 Development 56.9 65.5 198.7 Unproved properties acquisitions (4) 0.5 0.1 3.1 Total costs incurred in oil and gas property acquisition, exploration and development activities $ 63.5 $ 233.6 $ 724.4 (1) Includes net addition from capitalized ARO of $10.8 million in 2016, net reductions from capitalized ARO of $0.4 million in 2015, and net additions from capitalized ARO of $88.0 million during 2014. These adjustments for ARO are associated with acquisitions, liabilities incurred, divestitures and revisions of estimates. (2) Includes seismic costs of $0.2 million, $3.2 million and $9.0 million incurred during 2016, 2015 and 2014, respectively. (3) Includes geological and geophysical costs charged to expense of $4.1 million, $5.7 million and $7.3 million during 2016, 2015 and 2014, 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, 2016 2015 2014 Depreciation, depletion, amortization and accretion per Boe $ 13.77 $ 23.11 $ 28.98
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, 2013 58.5 15.9 259.9 117.7 705.9 Revisions of previous estimates (2) 1.6 0.1 14.3 4.1 25.3 Extensions and discoveries (3) 7.3 0.7 10.1 9.7 58.1 Purchase of minerals in place (4) 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 (5) 4.8 (0.9 ) 4.9 4.7 28.0 Revisions related to sold properties (6) (12.1 ) (4.8 ) (2.9 ) (17.4 ) (104.3 ) Extensions and discoveries (7) 2.4 0.2 8.8 4.1 24.4 Purchase of minerals in place (8) — — 6.1 1.0 6.1 Sales of reserves (9) (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 Revisions of previous estimates (10) 4.6 3.1 32.1 13.0 78.1 Production (7.2 ) (1.5 ) (39.7 ) (15.4 ) (92.2 ) Proved reserves as of Dec. 31, 2016 32.9 8.2 197.8 74.0 444.0 Year-end proved developed reserves: 2016 26.6 7.6 183.1 64.7 388.2 2015 29.4 6.4 198.5 69.0 413.5 2014 35.7 10.7 221.1 83.3 499.7 Year-end proved undeveloped reserves: 2016 (11) 6.3 0.6 14.7 9.3 55.8 2015 6.1 0.2 6.9 7.4 44.6 2014 26.0 5.1 33.8 36.7 220.3 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 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 extensions and discoveries of 4.1 MMBoe at our Yellow Rose field and 4.1 MMBoe at our Mississippi Canyon 782 field. (4) Primarily due to acquiring additional ownership in the Fairway Field and acquisition of the Woodside Properties. (5) 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. (6) 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. (7) Primarily due to increases at our Ewing Bank 910 field. (8) Primarily due to purchase of additional interest at our Brazos A-133 field. (9) 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. (10) Primarily related to upward revisions of 14.2 MMBoe, which included upward revisions of 3.8 MMBoe at our Viosca Knoll 823 (Tahoe/SE Tahoe) field, 1.5 MMBoe at our Fairway field, 1.3 MMBoe at our Mississippi Canyon 782 (Dantzler) field, and 1.2 MMBoe at our Main Pass 108 field. Partially offsetting were decreases for price revisions of 1.2 MMBoe. (11) We believe that we will be able to develop all but 1.3 MMBoe, or approximately 14%, of the total of 9.3 MMBoe reserves classified as proved undeveloped (“PUDs”) at December 31, 2016, within five years from the date such reserves were initially recorded. The lone 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. One of the sidetrack PUD locations in this field was originally recorded in our proved reserves as of December 31, 2010. The development of this PUD 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 this PUD location in 2023.
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, 2016 2015 2014 2013 Oil - per barrel $ 36.28 $ 46.94 $ 91.12 $ 99.65 NGLs per barrel 16.82 17.60 34.63 35.21 Natural gas per Mcf 2.47 2.50 4.27 3.80
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, 2016 2015 2014 Standardized Measure of Discounted Future Net Cash Flows Future cash inflows $ 1,818.4 $ 2,296.7 $ 7,258.5 Future costs: Production (691.5 ) (840.1 ) (2,224.5 ) Development (141.1 ) (161.4 ) (922.0 ) Dismantlement and abandonment (427.7 ) (471.8 ) (475.4 ) Income taxes (1) — — (948.4 ) Future net cash inflows before 10% discount 558.1 823.4 2,688.2 10% annual discount factor (79.8 ) (209.5 ) (985.4 ) Total $ 478.3 $ 613.9 $ 1,702.8 (1) No future income taxes were estimated to be paid in 2016 and 2015 as our tax position has sufficient tax basis to offset estimated future taxes. State income taxes were disregarded due to immateriality.
Schedule of Changes In Standardized Measure	The change in 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, 2016 2015 2014 Changes in Standardized Measure Standardized measure, beginning of year $ 613.9 $ 1,702.8 $ 1,674.6 Increases (decreases): Sales and transfers of oil and gas produced, net of production costs (218.6 ) (289.1 ) (650.9 ) Net changes in price, net of future production costs (275.2 ) (1,455.6 ) (278.6 ) Extensions and discoveries, net of future production and development costs — 65.3 309.6 Changes in estimated future development costs (32.5 ) (8.5 ) (56.4 ) Previously estimated development costs incurred 114.5 158.9 263.1 Revisions of quantity estimates 190.1 137.9 118.6 Accretion of discount 52.6 150.6 180.6 Net change in income taxes — 600.8 (11.4 ) Purchases of reserves in-place — 6.0 86.7 Sales of reserves in-place — (401.4 ) — Changes in production rates due to timing and other 33.5 (53.8 ) 66.9 Net increase (decrease) in standardized measure (135.6 ) (1,088.9 ) 28.2 Standardized measure, end of year $ 478.3 $ 613.9 $ 1,702.8

Significant Accounting Polici42

Significant Accounting Policies - Additional Information (Details)	3 Months Ended								4 Months Ended	12 Months Ended
	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2016USD ($)$ / bbl$ / MMBTU$ / Mcf	Dec. 31, 2015USD ($)$ / Mcf	Dec. 31, 2014USD ($)$ / Mcf	Dec. 31, 2013$ / Mcf	Sep. 07, 2016
Significant Accounting Policies [Line Items]
Natural gas imbalances	$ 5,300,000				$ 6,900,000				$ 5,300,000	$ 5,300,000	$ 6,900,000
Allowance for doubtful accounts receivable	7,600,000				2,500,000				$ 7,600,000	7,600,000	2,500,000
Reductions recorded in allowance for doubtful accounts										$ 0	0
Percentage of discount from proved reserves										10.00%
Ceiling test write-down of oil and natural gas properties	$ 0	$ 57,900,000	$ 104,600,000	$ 116,600,000	$ 32,400,000	$ 441,600,000	$ 252,800,000	$ 260,400,000		$ 279,063,000	987,238,000	$ 0
Proved undeveloped reserves classification period to be drilled										5 years
Write-offs of debt issuance costs										$ 1,400,000	$ 3,200,000
Hurricane Ike
Significant Accounting Policies [Line Items]
Other income related to settlement of insurance claims										$ 7,700,000
11.00% 1.5 Lien Term Loan, Due November 2019
Significant Accounting Policies [Line Items]
Debt instrument interest rate	11.00%								11.00%	11.00%
11.00% 1.5 Lien Term Loan, Due November 2019 | Exchange Transaction
Significant Accounting Policies [Line Items]
Debt instrument interest rate														11.00%
1.5 Lien Term Loan | Exchange Transaction
Significant Accounting Policies [Line Items]
Interest expense recorded for new debt									$ 0
Natural Gas
Significant Accounting Policies [Line Items]
Weighted price | $ / Mcf										2.47	2.50	4.27	3.80
SEC Methodology | Natural Gas
Significant Accounting Policies [Line Items]
Weighted price | $ / MMBTU										2.48
SEC Methodology | Crude Oil Per Barrel
Significant Accounting Policies [Line Items]
Weighted price | $ / bbl										39.25
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
Accounting Standards Update 2016-09
Significant Accounting Policies [Line Items]
Prior period reclassification adjustment											$ 700,000	$ 800,000

Significant Accounting Polici43

Significant Accounting Policies - Percentage of Revenue by Major Customers (Details) - Sales Revenue Net - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Shell Trading (US) Co.
Entity Wide Revenue Major Customer [Line Items]
Percentage of receipts	43.00%	50.00%	47.00%
Vitol Inc.
Entity Wide Revenue Major Customer [Line Items]
Percentage of receipts	20.00%
J. P. Morgan
Entity Wide Revenue Major Customer [Line Items]
Percentage of receipts		14.00%

Significant Accounting Polici44

Significant Accounting Policies - Schedule of Amounts Recorded in Prepaid Expenses and Other (Details) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Prepaid Expense And Other Assets Current [Abstract]
Derivative assets - current	[1]		$ 10,036
Prepaid/accrued insurance and surety bonds		$ 5,386	7,475
Prepaid deposits related to royalties		6,237	5,943
Other	[2]	2,881	3,425
Prepaid expenses and other		$ 14,504	$ 26,879
[1]	Includes open and closed (and not yet collected) derivative commodity contracts recorded at fair value as of December 31, 2015.
[2]	Individual items were less than 5% of total current assets for either period presented.

Long-Term Debt - Long-Term Debt

Long-Term Debt - Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Principal	$ 873,733	$ 1,200,000
PIK Payable/Interest Payable/Other	152,270
PIK Payable/Interest Payable/Other, premium, discount, issuance costs, net of amortization	(5,276)
PIK Payable/Interest Payable/Other, Total	146,994
PIK Payable/Interest Payable/Other, Current maturities	8,272
PIK Payable/Interest Payable/Other, less current maturities	138,722
Carrying Value	1,026,003
Debt premium, discount, issuance costs, net of amortization	(5,276)	(3,145)
Total long-term debt	1,020,727	1,196,855
Long-term debt	8,272
Long-term debt, less current portion	1,012,455	1,196,855
11.00% 1.5 Lien Term Loan, Due November 2019
Debt Instrument [Line Items]
Principal	75,000
PIK Payable/Interest Payable/Other	23,823
Carrying Value	98,823
9.00 % Second Lien Term Loan, Due May 2020
Debt Instrument [Line Items]
Principal	300,000	300,000
Carrying Value	300,000
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020
Debt Instrument [Line Items]
Principal	163,007
PIK Payable/Interest Payable/Other	60,898
Carrying Value	223,905
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021
Debt Instrument [Line Items]
Principal	145,897
PIK Payable/Interest Payable/Other	67,549
Carrying Value	213,446
8.50% Unsecured Senior Notes, Due June 2019
Debt Instrument [Line Items]
Principal	189,829	$ 900,000
Carrying Value	$ 189,829

Long-Term Debt - Long-Term De46

Long-Term Debt - Long-Term Debt (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Sep. 07, 2016	May 31, 2015
11.00% 1.5 Lien Term Loan, Due November 2019
Debt Instrument [Line Items]
Debt instrument interest rate	11.00%
Debt instrument maturity date	Nov. 15, 2019
9.00 % Second Lien Term Loan, Due May 2020
Debt Instrument [Line Items]
Debt instrument interest rate	9.00%	9.00%		9.00%
Debt instrument maturity date	May 15, 2020	May 15, 2020
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020
Debt Instrument [Line Items]
Debt instrument interest rate	9.00%		9.00%
Debt instrument maturity date	May 15, 2020
Debt instrument paid in kind interest rate	10.75%
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021
Debt Instrument [Line Items]
Debt instrument interest rate	8.50%		8.50%
Debt instrument maturity date	Jun. 15, 2021
Debt instrument paid in kind interest rate	10.00%
8.50% Unsecured Senior Notes, Due June 2019
Debt Instrument [Line Items]
Debt instrument interest rate	8.50%	8.50%
Debt instrument maturity date	Jun. 15, 2019	Jun. 15, 2019

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Details) - USD ($) $ / shares in Units, shares in Millions	Sep. 07, 2016	May 31, 2015	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Aggregate annual maturities of long-term debt, 2017				$ 8,200,000	$ 8,200,000
Aggregate annual maturities of long-term debt, 2018				23,800,000	23,800,000
Aggregate annual maturities of long-term debt, 2019				303,700,000	303,700,000
Aggregate annual maturities of long-term debt, 2020				510,100,000	510,100,000
Aggregate annual maturities of long-term debt, thereafter				180,100,000	180,100,000
Debt instrument aggregate principle amount				873,733,000	873,733,000	$ 1,200,000,000
Gain on exchange of debt			$ 123,900,000		$ 123,923,000
First lien leverage ratio, through June 30, 2017					250.00%
First lien leverage ratio, after June 30, 2017					200.00%
Current ratio					100.00%
Current ratio					293.00%
Asset coverage ratio					125.00%
Write-offs of debt issuance costs					$ 1,400,000	3,200,000
8.50% Unsecured Senior Notes, Due June 2019
Debt Instrument [Line Items]
Debt instrument aggregate principle amount				$ 189,829,000	$ 189,829,000	$ 900,000,000
Debt instrument maturity date					Jun. 15, 2019	Jun. 15, 2019
Debt instrument interest rate				8.50%	8.50%	8.50%
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020
Debt Instrument [Line Items]
Debt instrument aggregate principle amount				$ 163,007,000	$ 163,007,000
Debt instrument maturity date					May 15, 2020
Debt instrument interest rate	9.00%			9.00%	9.00%
Debt instrument paid in kind interest rate				10.75%	10.75%
Debt instrument payment terms					Cash interest accrues at 9.00% per annum and is payable on May 15 and November 15 of each year. The Second Lien PIK Toggle Notes contain payment-in-kind (“PIK”) interest provisions, where certain semi-annual interest is added to the principal amount instead of being paid in cash in the then current semi-annual period. We have the option for the first 18 months to pay all or a portion of interest in kind at a rate of 10.75% per annum, except that the initial interest payment on November 15, 2016 had to be paid solely using PIK.
Debt instrument, period in which interest can be paid-in-kind	18 months
Debt instrument stated interest rate percentage for payment-in-kind	10.75%
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021
Debt Instrument [Line Items]
Debt instrument aggregate principle amount				$ 145,897,000	$ 145,897,000
Debt instrument maturity date					Jun. 15, 2021
Debt instrument interest rate	8.50%			8.50%	8.50%
Debt instrument paid in kind interest rate				10.00%	10.00%
Debt instrument payment terms					The maturity date will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes have not been extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019. Cash interest accrues at 8.50% per annum and is payable on June 15 and December 15 of each year. The Third Lien PIK Toggle Notes contain PIK interest provisions, where certain semi-annual interest is added to the principal amount instead of being paid in cash in the then current semi-annual period. We have the option for the first 24 months to pay all or a portion of interest in kind at a rate of 10.00% per annum, except that the initial interest payment on December 15, 2016 had to be paid solely using PIK.
Debt instrument, period in which interest can be paid-in-kind	24 months
Debt instrument stated interest rate percentage for payment-in-kind	10.00%
11.00% 1.5 Lien Term Loan, Due November 2019
Debt Instrument [Line Items]
Debt instrument aggregate principle amount				$ 75,000,000	$ 75,000,000
Debt instrument maturity date					Nov. 15, 2019
Debt instrument interest rate				11.00%	11.00%
Revolving Bank Credit Facility Due November 2018
Debt Instrument [Line Items]
Revolving bank credit facility borrowing base				$ 150,000,000	$ 150,000,000
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 maximum lender commitment				150,000,000	$ 150,000,000
Credit agreement expiration date					Nov. 8, 2018
Debt redemption amount				35,000,000	$ 35,000,000
Line of credit maximum amount outstanding prior to repurchase of term loan				0	0
Letter of credit maximum amount outstanding prior to repurchase of term loan				5,000,000	5,000,000
Consolidated Cash balance				35,000,000	35,000,000
Outstanding balances on the revolving bank credit facility (including letters of credit)				$ 5,000,000	$ 5,000,000
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 3.00% to 4.00% 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 0.50%, or (c) LIBOR plus 1.0%, plus applicable margin ranging from 2.00% to 3.00%.
Unused portion of the borrowing base commitment fee					0.50%
Annual effective interest rate				3.30%	3.30%
Write-offs of debt issuance costs					$ 1,400,000	$ 3,200,000
Revolving bank credit facility borrowings outstanding				$ 0	0	0
Letters of credit outstanding				500,000	$ 500,000	900,000
Revolving Bank Credit Facility Due November 2018 | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate					1.00%
Revolving Bank Credit Facility Due November 2018 | Federal Funds Effective Swap Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate					0.50%
Revolving Bank Credit Facility Due November 2018 | Scenario Covenants
Debt Instrument [Line Items]
Maximum unrestricted cash balance if revolver balance is above $5 million				35,000,000	$ 35,000,000
Revolving Bank Credit Facility Due November 2018 | Minimum | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate					3.00%
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					2.00%
Revolving Bank Credit Facility Due November 2018 | Maximum
Debt Instrument [Line Items]
Percentage of hedging contracts					75.00%
Revolving Bank Credit Facility Due November 2018 | Maximum | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate					4.00%
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					3.00%
11.00% 1.5 Lien Term Loan, Due November 2019
Debt Instrument [Line Items]
Debt instrument maturity date	Nov. 15, 2019
Debt instrument interest rate	11.00%
Debt instrument, maturity date, description					1.5 Lien Term Loan on September 7, 2016 with a maturity date of November 15, 2019. The maturity date will accelerate to February 28, 2019 if the remaining Unsecured Senior Notes have not been extended, renewed, refunded, defeased, discharged, replaced or refinanced by February 28, 2019.
Debt instrument payment terms					Interest accrues at 11.00% per annum and is payable quarterly in cash.
Debt instrument frequency of interest payment in cash					Quarterly
9.00 % Second Lien Term Loan, Due May 2020
Debt Instrument [Line Items]
Debt instrument aggregate principle amount				$ 300,000,000	$ 300,000,000	$ 300,000,000
Debt instrument maturity date					May 15, 2020	May 15, 2020
Debt instrument interest rate		9.00%		9.00%	9.00%	9.00%
Annual effective interest rate				9.70%	9.70%
Debt instrument payment terms					Interest on the Second Lien Term Loan is payable in arrears semi-annually on May 15 and November 15
Debt instrument discount rate		1.00%
8.50% Senior Notes due June 2019
Debt Instrument [Line Items]
Debt instrument maturity date					Jun. 15, 2019
Debt instrument interest rate				8.50%	8.50%	8.50%
Annual effective interest rate				8.40%	8.40%
Debt instrument payment terms					semi-annually in arrears on June 15 and December 15
Exchange Transaction
Debt Instrument [Line Items]
Gain on exchange of debt	$ 123,900,000
Deal transaction costs	$ 18,900,000
Common stock issued value per share	$ 1.76
Basic and diluted income (loss) per common share					$ 1.30
Exchange Transaction | Common Stock
Debt Instrument [Line Items]
Debt conversion, common stock shares issued					60.4
Exchange Transaction | 8.50% Unsecured Senior Notes, Due June 2019
Debt Instrument [Line Items]
Debt instrument aggregate principle amount	$ 710,200,000
Percentage of unsecured senior notes exchanged	79.00%
Debt instrument maturity date					Jun. 15, 2019
Exchange Transaction | 8.50% Unsecured Senior Notes, Due June 2019 | Common Stock
Debt Instrument [Line Items]
Debt conversion, common stock shares issued	60.4
Exchange Transaction | 9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020
Debt Instrument [Line Items]
Debt instrument aggregate principle amount	$ 159,800,000
Exchange Transaction | 9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020 | Minimum
Debt Instrument [Line Items]
Debt instrument interest rate	9.00%
Exchange Transaction | 9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020 | Maximum
Debt Instrument [Line Items]
Debt instrument paid in kind interest rate	10.75%
Exchange Transaction | 8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021
Debt Instrument [Line Items]
Debt instrument aggregate principle amount	$ 142,000,000
Debt instrument maturity date					Jun. 15, 2021
Exchange Transaction | 8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021 | Minimum
Debt Instrument [Line Items]
Debt instrument interest rate	8.50%
Exchange Transaction | 8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021 | Maximum
Debt Instrument [Line Items]
Debt instrument paid in kind interest rate	10.00%
Exchange Transaction | 11.00% 1.5 Lien Term Loan, Due November 2019
Debt Instrument [Line Items]
Debt instrument aggregate principle amount	$ 75,000,000
Debt instrument maturity date					Nov. 15, 2019
Debt instrument interest rate	11.00%
Exchange Transaction | 1.5 Lien Term Loan
Debt Instrument [Line Items]
Interest expense recorded for new debt				$ 0

Fair Value Measurements - Sched

Fair Value Measurements - Schedule of Fair Value of Long-Term Debt (Details) - Fair Value, Inputs, Level 2 - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
11.00% 1.5 Lien Term Loan, Due November 2019
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Long-term debt, term loan fair value	$ 75,000
9.00 % Second Lien Term Loan, Due May 2020
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Long-term debt, term loan fair value	255,000	$ 217,500
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Long-term debt, notes fair value	122,255
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Long-term debt, notes fair value	80,243
8.50% Unsecured Senior Notes, Due June 2019
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Long-term debt, notes fair value	$ 123,389	$ 324,000

Fair Value Measurements - Sch49

Fair Value Measurements - Schedule of Fair Value of Long-Term Debt (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Sep. 07, 2016	May 31, 2015
11.00% 1.5 Lien Term Loan, Due November 2019
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Debt instrument interest rate	11.00%
Debt instrument maturity date	Nov. 15, 2019
9.00 % Second Lien Term Loan, Due May 2020
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Debt instrument interest rate	9.00%	9.00%		9.00%
Debt instrument maturity date	May 15, 2020	May 15, 2020
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Debt instrument interest rate	9.00%		9.00%
Debt instrument maturity date	May 15, 2020
Debt instrument paid in kind interest rate	10.75%
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Debt instrument interest rate	8.50%		8.50%
Debt instrument maturity date	Jun. 15, 2021
Debt instrument paid in kind interest rate	10.00%
8.50% Unsecured Senior Notes, Due June 2019
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Debt instrument interest rate	8.50%	8.50%
Debt instrument maturity date	Jun. 15, 2019	Jun. 15, 2019

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Details)	Dec. 31, 2016DerivativeInstrument
Fair Value Disclosures [Abstract]
Number of open derivative financial instruments	0

Asset Retirement Obligations -

Asset Retirement Obligations - Reconciliation of Asset Retirement Obligations Liability (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations, beginning of period	$ 378,322	$ 390,568
Asset retirement obligation settlements	(72,320)	(32,555)	$ (74,313)
Accretion of discount	17,571	20,703	20,633
Disposition of properties		(8,581)
Liabilities assumed through acquisition		2,944
Liabilities incurred	398	4,780
Revisions of estimated liabilities	10,467	463
Asset retirement obligations, end of period	334,438	378,322	$ 390,568
Less current portion	78,264	84,335
Long-term	$ 256,174	$ 293,987

Insurance Claims - Additional I

Insurance Claims - Additional Information (Details) - USD ($)	3 Months Ended	12 Months Ended			102 Months Ended
	Sep. 30, 2008	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2016
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 reimbursements		$ 10,200,000	$ 200,000	$ 12,200,000
Additional Receivables From Insurance Settlement		$ 30,100,000			$ 30,100,000
Cumulative insurance recoveries related to hurricanes					$ 171,400,000

Acquisitions and Divestitures -

Acquisitions and Divestitures - Additional Information (Details)	Oct. 15, 2015USD ($)a$ / bbl	Dec. 31, 2016USD ($)		Sep. 30, 2016USD ($)		Jun. 30, 2016USD ($)		Mar. 31, 2016USD ($)		Dec. 31, 2015USD ($)		Sep. 30, 2015USD ($)		Jun. 30, 2015USD ($)		Mar. 31, 2015USD ($)		Dec. 31, 2014USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Sep. 15, 2014	Sep. 14, 2014	May 20, 2014
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%
Revenues		$ 115,213,000		$ 107,403,000		$ 99,655,000		$ 77,715,000		$ 104,064,000		$ 126,228,000		$ 149,066,000		$ 127,907,000			$ 399,986,000	$ 507,265,000	$ 948,708,000
DD&A																			211,609,000	394,071,000	511,102,000
Income tax expense																			(43,376,000)	(202,984,000)	(4,459,000)
Net income (loss)		$ 16,483,000	[1]	$ 45,928,000	[1]	$ (120,922,000)	[1]	$ (190,509,000)	[1]	$ (51,606,000)	[1]	$ (477,568,000)	[1]	$ (260,449,000)	[1]	$ (255,095,000)	[1]		(249,020,000)	(1,044,718,000)	$ (11,661,000)
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
Crude Oil | Minimum
Business Acquisition [Line Items]
Trading price per barrel | $ / bbl	70
Crude Oil | Maximum
Business Acquisition [Line Items]
Trading price per barrel | $ / bbl	90
Ajax Resources, LLC
Business Acquisition [Line Items]
Proceeds from sale of properties	$ 370,900,000
Acres of oil and gas property, net | a	25,800
Agreement effective date	Jan. 1, 2015
Purchase price adjustment, net																			$ 900,000
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%
Ajax Resources, LLC | NYMEX
Business Acquisition [Line Items]
Addition to available cash	$ 100,000,000
[1]	During 2016, we recorded in first, second and third quarter ceiling test write-downs of oil and natural gas properties of $116.6 million, $104.6 million and $57.9 million, respectively. In the third quarter of 2016, we recorded a gain on exchange of debt of $123.9 million. 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 Divestitures54

Acquisitions and Divestitures - Purchase Price Allocation for Acquisition (Details) - USD ($) $ in Thousands	Sep. 15, 2014	May 20, 2014
Fairway
Non-cash consideration:
Asset retirement obligations - non-current	$ 6,124
Total consideration	24,817
Fairway | Evaluated Properties Including Equipment
Cash consideration:
Oil and natural gas properties and equipment	$ 18,693
Woodside Properties
Cash consideration:
Oil and natural gas properties and equipment		$ 55,007
Non-cash consideration:
Asset retirement obligations - non-current		10,543
Asset retirement obligations - current		782
Non-cash consideration		11,325
Total consideration		66,332
Woodside Properties | Evaluated Properties Including Equipment
Cash consideration:
Oil and natural gas properties and equipment		52,347
Woodside Properties | Unevaluated Properties
Cash consideration:
Oil and natural gas properties and equipment		$ 2,660

Acquisitions and Divestitures55

Acquisitions and Divestitures - Summary of Pro Forma Financial Information for Acquisition (Details) - Woodside Properties $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2014USD ($)$ / shares	[1]
Business Acquisition [Line Items]
Revenue	$ 971,595
Net loss	$ (5,504)
Basic and diluted loss per common share | $ / shares	$ (0.08)
[1]	The adjustments for 2014 are for the period from January 1, 2014 to May 20, 2014.

Acquisitions and Divestitures56

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

3 Months Ended

7 Months Ended

12 Months Ended

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Business Acquisition [Line Items]

Revenues

$ 115,213,000

$ 107,403,000

$ 99,655,000

$ 77,715,000

$ 104,064,000

$ 126,228,000

$ 149,066,000

$ 127,907,000

$ 399,986,000

$ 507,265,000

$ 948,708,000

DD&A

211,609,000

394,071,000

511,102,000

G&A

59,740,000

73,110,000

86,999,000

Interest expense

92,791,000

104,592,000

86,922,000

Income tax expense

$ (43,376,000)

(202,984,000)

(4,459,000)

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],[2]

22,887,000

Direct operating expenses

[1],[2]

4,417,000

DD&A

[2],[3]

8,385,000

G&A

[2],[4]

300,000

Interest expense

[2],[5]

330,000

Capitalized interest

[2],[6]

(19,000)

Income tax expense

[2],[7]

$ 3,316,000

[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.

Acquisitions and Divestitures57

Acquisitions and Divestitures - Business Acquisition Pro Forma Information Incremental Items (Parenthetical) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Long-term debt, less current maturities	$ 1,012,455	$ 1,196,855
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%

Derivative Financial Instrume58

Derivative Financial Instruments - Additional Information (Details)	Dec. 31, 2016DerivativeInstrument
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Number of open derivative financial instruments	0

Derivative Financial Instrume59

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 Instrume60

Derivative Financial Instruments - Changes in Fair Value and Settlements of Commodity Derivative Contracts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Gain Loss On Derivative Instruments Net Pretax [Abstract]
Derivative (gain) loss	$ 2,926	$ (14,375)	$ (3,965)

Derivative Financial Instrume61

Derivative Financial Instruments - Cash Receipts (Payments) on Derivative Settlements, Net Included within Net Cash Provided by Operating Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Cash receipts (payments) on derivative settlements, net	$ 4,746	$ 6,703	$ (5,318)

Equity Transactions - Additiona

Equity Transactions - Additional Information (Details) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Equity Transactions [Line Items]
Common stock, shares authorized	200,000,000	200,000,000
Common Stock, Regular
Equity Transactions [Line Items]
Paid cash dividends, per share	$ 0	$ 0	$ 0.40
Minimum
Equity Transactions [Line Items]
Common stock, shares authorized	118,300,000
Maximum
Equity Transactions [Line Items]
Common stock, shares authorized	200,000,000
Exchange Transaction | Common Stock
Equity Transactions [Line Items]
Debt conversion, common stock shares issued	60,400,000

Share-Based Awards and Cash-B63

Share-Based Awards and Cash-Based Awards - Additional Information (Details) - USD ($)	1 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share based compensation performance awards grant performance period		10 years
Annual incentive awards payment period		90 days
Additional shares authorized under share based compensation arrangements		3,300,000
Common stock available for award under plans		6,933,337
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
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common stock pre-determined price per share				$ 14.66
Performance based awards, percentage				100.00%
Directors Compensation Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common stock available for award under plans		317,896
Restricted Stock Units (RSUs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares granted, grant date fair value		$ 9,300,000	$ 9,400,000	$ 20,100,000
Shares vested, vested date fair value		2,400,000	2,100,000	2,000,000
Unrecognized share-based compensation expense		$ 9,700,000
Recognition period for unrecognized compensation expense		2018-11
CEO's 2014 Award | Chief Executive Officer
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of shares issued	37,316
Restricted Shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares granted, grant date fair value		$ 300,000	300,000	300,000
Shares vested, vested date fair value		100,000	$ 100,000	$ 300,000
Unrecognized share-based compensation expense		$ 400,000
Recognition period for unrecognized compensation expense		2019-04
Restricted Shares | Directors Compensation Plan Share-Based Awards
Share Based Compensation Arrangement By Share Based Payment Award [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
Cash-based Awards | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Adjusted EBITDA less interest expense		$ 300,000,000
Adjusted EBITDA and Adjusted EBITDA Margin
Share Based Compensation Arrangement By Share Based Payment Award [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%	100.00%

Share-Based Awards and Cash-B64

Share-Based Awards and Cash-Based Awards - Summary of Share Activity Related to Restricted Stock Units (Details) - Restricted Stock Units (RSUs) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Nonvested, beginning of period	3,474,079	1,977,335	1,331,753
Granted	4,213,964	2,626,930	1,195,388
Vested	(968,652)	(721,038)	(354,692)
Forfeited	(612,143)	(409,148)	(195,114)
Nonvested, end of period	6,107,248	3,474,079	1,977,335
Weighted Average Grant Date Value, Beginning of period	$ 7.42	$ 15.29	$ 14.96
Weighted Average Grant Date Fair Value, Granted	2.21	3.59	16.84
Weighted Average Grant Date Fair Value, Vested	16.69	13.23	18.59
Weighted Average Grant Date Fair Value, Forfeited	3.64	10.63	16.53
Weighted Average Grant Date Value, End of period	$ 2.73	$ 7.42	$ 15.29

Share-Based Awards and Cash-B65

Share-Based Awards and Cash-Based Awards - Schedule of Restricted Stock Units Outstanding (Details) - Restricted Stock Units (RSUs) - shares	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	6,107,248	3,474,079	1,977,335	1,331,753
2,017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	2,311,434
2,018
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	3,795,814

Share-Based Awards and Cash-B66

Share-Based Awards and Cash-Based Awards - Schedule of Restricted Stock Activity (Details) - Restricted Shares - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Nonvested, beginning of period	78,230	43,210	43,840
Granted	126,128	56,540	18,815
Vested	(43,062)	(21,520)	(19,445)
Nonvested, end of period	161,296	78,230	43,210
Weighted Average Grant Date Value, Beginning of period	$ 8.95	$ 16.20	$ 15.96
Weighted Average Grant Date Fair Value, Granted	2.22	6.19	18.60
Weighted Average Grant Date Fair Value, Vested	9.75	16.26	18
Weighted Average Grant Date Value, End of period	$ 3.47	$ 8.95	$ 16.20

Share-Based Awards and Cash-B67

Share-Based Awards and Cash-Based Awards - Schedule of Restricted Stock Awards Outstanding (Details) - Restricted Shares - shares	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	161,296	78,230	43,210	43,840
2,017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	62,136
2,018
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	57,120
2,019
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	42,040

Share-Based Awards and Cash-B68

Share-Based Awards and Cash-Based Awards - Summary of Compensation Expense under Share-Based Payment Arrangements and Related Tax Benefit (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation	$ 11,013	$ 10,242	$ 14,744
Tax benefit computed at the statutory rate	3,855	3,585	5,160
Restricted Stock Units (RSUs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation	10,640	9,978	13,150
Restricted Shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation	$ 373	358	369
Common Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation		$ (94)	$ 1,225

Share-Based Awards and Cash-B69

Share-Based Awards and Cash-Based Awards - Summary of Compensation Expense Related to Share-Based Awards and Cash-Based Awards (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Share-based compensation charged to operating income		$ 11,013	$ 10,242	$ 14,744
Total charged to operating income		11,013	10,373	24,979
General And Administrative Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Share-based compensation charged to operating income		$ 11,013	10,242	14,744
Cash-based incentive compensation charged to operating income	[1]		(233)	6,950
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
[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	2 Months Ended	12 Months Ended
	Mar. 05, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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		$ 0.4	$ 2.3	$ 2.4

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current	$ (71,768)	$ 288	$ 301
Deferred	28,392	(203,272)	(4,760)
Total income tax( benefit)	$ (43,376)	$ (202,984)	$ (4,459)

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Income Taxes Computed to Income Tax Benefit (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income tax (benefit) at the federal statutory rate	$ (102,339)	$ (436,696)	$ (5,642)
Share-based compensation	4,920	2,940
State income taxes	(755)	(2,343)	263
Valuation allowance	52,915	232,925
Debt restructuring cost	1,463
Other	420	190	920
Total income tax( benefit)	$ (43,376)	$ (202,984)	$ (4,459)
Income tax expense (benefit) at the federal statutory rate, tax rate	35.00%	35.00%	35.00%
Share-based compensation, tax rate	(1.70%)	(0.20%)
State income taxes, tax rate	0.20%	0.20%	(1.60%)
Valuation allowance, tax rate	(18.10%)	(18.70%)
Debt restructuring cost	(0.50%)
Other, tax rate	(0.10%)		(5.70%)
Effective income tax rate, total	14.80%	16.30%	27.70%

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Federal statutory income tax rate	35.00%	35.00%	35.00%
Cash paid for income taxes	$ 310	$ 390
Income tax refund received	7,796	90	$ 3,000
Current income tax receivables	11,943
Non-current income tax receivables	52,097
Increase in valuation allowance	$ 52,900	$ 232,900
Minimum
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Tax years under examination	2,013
Maximum
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Tax years under examination	2,016
Tax Year 2015
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Income tax refund received related to NOL claim	$ 5,800

Income Taxes - Significant Comp

Income Taxes - Significant Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Deferred tax liabilities:
Property and equipment		$ 40,287
Derivatives		2,697
Other	$ 1,423	3,000
Total deferred tax liabilities	1,423	45,984
Deferred tax assets:
Alternative minimum tax credit		20,486
Property and equipment	42,385
Asset retirement obligations	117,588	133,018
Federal net operating losses		145,733
State net operating losses	5,615	5,068
Valuation allowance	(290,190)	(237,275)
Exchange transaction	118,467
Share-based compensation	2,353	4,245
Other	4,798	2,304
Total deferred tax assets	1,016	73,579
Net deferred tax liabilities	$ (407)
Net deferred tax asset		$ 27,595

Income Taxes - Net Operating Lo

Income Taxes - Net Operating Loss and Tax Credit Carryovers (Details) - State and Local Jurisdiction $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)
Operating Loss Carryforwards [Line Items]
Net operating loss	$ 112,512
Minimum
Operating Loss Carryforwards [Line Items]
Net operating loss, expiration year	Dec. 31, 2021
Maximum
Operating Loss Carryforwards [Line Items]
Net operating loss, expiration year	Dec. 31, 2030

Income Taxes - Balances in Unce

Income Taxes - Balances in Uncertain Tax Positions (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Balance, beginning and end of period	$ 9,482	$ 9,482

Loss Per Share - Schedule of Ca

Loss Per Share - Schedule of Calculation of Basic and Diluted Loss Per Common Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2016	[1]	Sep. 30, 2016	[1]	Jun. 30, 2016	[1]	Mar. 31, 2016	[1]	Dec. 31, 2015	[1]	Sep. 30, 2015	[1]	Jun. 30, 2015	[1]	Mar. 31, 2015	[1]	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Earnings Per Share, Basic and Diluted [Abstract]
Net loss	$ 16,483		$ 45,928		$ (120,922)		$ (190,509)		$ (51,606)		$ (477,568)		$ (260,449)		$ (255,095)		$ (249,020)	$ (1,044,718)	$ (11,661)
Less portion allocated to nonvested shares																			269
Net loss allocated to common shares																	$ (249,020)	$ (1,044,718)	$ (11,930)
Weighted average common shares outstanding																	95,644	75,931	75,609
Basic and diluted loss per common share	$ 0.12	[2]	$ 0.48	[2]	$ (1.58)	[2]	$ (2.49)	[2]	$ (0.68)	[2]	$ (6.29)	[2]	$ (3.43)	[2]	$ (3.36)	[2]	$ (2.60)	$ (13.76)	$ (0.16)
Shares excluded due to being anti-dilutive (weighted-average)																	5,269	2,195	2,097
[1]	During 2016, we recorded in first, second and third quarter ceiling test write-downs of oil and natural gas properties of $116.6 million, $104.6 million and $57.9 million, respectively. In the third quarter of 2016, we recorded a gain on exchange of debt of $123.9 million. 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 does 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 Inform78

Supplemental Cash Flow Information - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental cash items:
Cash paid for interest, net of interest capitalized of $520 in 2016, $7,256 in 2015 and $8,526 in 2014		$ 96,501	$ 92,622	$ 77,607
Cash paid for income taxes		310	390
Cash refunds received for income taxes		7,796	90	3,000
Cash paid for share-based compensation	[1]			431
Non-cash investing activities:
Accruals for property and equipment		9,129	44,324	99,750
ARO - additions, dispositions and revisions, net		10,865	$ (394)	$ 89,826
Non-cash financing activities:
Common stock issued - fair value at issuance date		106,366
11.00% 1.5 Lien Term Loan, Due November 2019
Non-cash financing activities:
Exchange transaction — non-cash securities issued, value		23,823
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020
Non-cash financing activities:
Exchange transaction — non-cash securities issued, value		223,905
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021
Non-cash financing activities:
Exchange transaction — non-cash securities issued, value		213,446
8.50% Unsecured Senior Notes, Due June 2019
Non-cash financing activities:
Exchange transaction — non-cash securities exchanged, value		$ (712,967)
[1]	The cash paid for share-based compensation in 2014 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 Inform79

Supplemental Cash Flow Information - Supplemental Cash Flow Information (Parenthetical) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Sep. 07, 2016
Supplemental Cash Flow Elements [Line Items]
Cash paid, interest capitalized	$ 520	$ 7,256	$ 8,526
11.00% 1.5 Lien Term Loan, Due November 2019
Supplemental Cash Flow Elements [Line Items]
Debt instrument interest rate	11.00%
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020
Supplemental Cash Flow Elements [Line Items]
Debt instrument interest rate	9.00%			9.00%
Debt instrument paid in kind interest rate	10.75%
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021
Supplemental Cash Flow Elements [Line Items]
Debt instrument interest rate	8.50%			8.50%
Debt instrument paid in kind interest rate	10.00%
8.50% Unsecured Senior Notes, Due June 2019
Supplemental Cash Flow Elements [Line Items]
Debt instrument interest rate	8.50%	8.50%

Commitments - Additional Inform

Commitments - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Commitments [Line Items]
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, 2020	1,800,000
Minimum future lease payments due under noncancelable operating leases, thereafter	3,700,000
Total rent expense	3,200,000	$ 3,300,000	$ 3,200,000
Security amount requirement	75,000,000
Escrow deposit	1,900,000
Additional security requirements for 2017	83,000,000
Additional security requirements for 2018	88,000,000
Additional security requirements for 2023	103,000,000
Annual increment in threshold	3,000,000
Collateral deposits	16,900,000
Expenses related to surety bonds	4,300,000	$ 5,500,000	$ 4,100,000
ARO Projects
Commitments [Line Items]
Minimum future lease payments due under noncancelable operating leases, 2016	2,900,000
Drilling Rig Commitments
Commitments [Line Items]
Minimum future lease payments due under noncancelable operating leases, 2016	7,400,000
Helix Well Containment Group
Commitments [Line Items]
Future estimated costs, 2017	1,700,000
Future estimated costs, 2018	1,700,000
Surety Bonds
Commitments [Line Items]
Future estimated costs, 2017	6,100,000
Future estimated costs, 2018	5,900,000
Future estimated costs, 2019	5,200,000
Future estimated costs, 2020	5,000,000
Future estimated costs, thereafter	38,600,000
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, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Debt instrument aggregate principle amount	$ 873,733,000	$ 1,200,000,000
Airplane Services
Related Party Transaction [Line Items]
Related party transactions	1,100,000	1,100,000	$ 900,000
Directional Drilling Services
Related Party Transaction [Line Items]
Related party transactions	0	0	200,000
CEO and Largest Shareholder | Second Lien Term Loan
Related Party Transaction [Line Items]
Debt instrument aggregate principle amount		5,000,000
Maximum | 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)	Oct. 28, 2016USD ($)	Jan. 31, 2014USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2016USD ($)claim	Dec. 31, 2015USD ($)	Dec. 31, 2010USD ($)
Loss Contingencies [Line Items]
Obligation to secure financial assurances			$ 260,800,000
Underpayment of royalties		$ 30,000
Under payment percentage of total royalty payments		0.0045%
Statutory fine payment relative to underpayment		$ 2,300,000		$ 1,100,000
Amount accrued				$ 0	$ 0
Notified disallowed amount in reductions taken by ONRR						$ 4,700,000
Royalty payment processing revised period				84 months
Payments for royalty				$ 500,000
Proposed penalties				$ 1,500,000
BSEE
Loss Contingencies [Line Items]
Number of notices | claim				4
Proposed civil penalties related to various incidents of noncompliance, total				$ 8,100,000
Payments for civil penalty				$ 100,000	$ 200,000
Apache Corporation | Judicial Ruling
Loss Contingencies [Line Items]
Amount awarded for non-compliance fines and lawsuits	$ 43,200,000
Amount offset against litigation compensation amount	$ 17,000,000

Selected Quarterly Financial 83

Selected Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 115,213		$ 107,403		$ 99,655		$ 77,715		$ 104,064		$ 126,228		$ 149,066		$ 127,907		$ 399,986	$ 507,265	$ 948,708
Operating income (loss)	21,319	[1]	(58,276)	[1]	(126,997)	[1]	(166,614)	[1]	(60,816)	[1]	(468,573)	[1]	(278,806)	[1]	(337,508)	[1]	(330,568)	(1,145,703)	62,068
Net income (loss)	$ 16,483	[1]	$ 45,928	[1]	$ (120,922)	[1]	$ (190,509)	[1]	$ (51,606)	[1]	$ (477,568)	[1]	$ (260,449)	[1]	$ (255,095)	[1]	$ (249,020)	$ (1,044,718)	$ (11,661)
Basic and diluted income (loss) per common share	$ 0.12	[1],[2]	$ 0.48	[1],[2]	$ (1.58)	[1],[2]	$ (2.49)	[1],[2]	$ (0.68)	[1],[2]	$ (6.29)	[1],[2]	$ (3.43)	[1],[2]	$ (3.36)	[1],[2]	$ (2.60)	$ (13.76)	$ (0.16)
[1]	During 2016, we recorded in first, second and third quarter ceiling test write-downs of oil and natural gas properties of $116.6 million, $104.6 million and $57.9 million, respectively. In the third quarter of 2016, we recorded a gain on exchange of debt of $123.9 million. 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 does 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 84

Selected Quarterly Financial Data (Parenthetical) (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Ceiling test write-down of oil and natural gas properties	$ 0	$ 57,900,000	$ 104,600,000	$ 116,600,000	$ 32,400,000	$ 441,600,000	$ 252,800,000	$ 260,400,000	$ 279,063,000	$ 987,238,000	$ 0
Gain on exchange of debt		$ 123,900,000							$ 123,923,000

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) - USD ($) $ in Millions	Jan. 27, 2017	Dec. 31, 2010
Subsequent Event [Line Items]
Payments for royalties		$ 4.7
Subsequent Event
Subsequent Event [Line Items]
Payments for royalties	$ 4.7

Supplemental Guarantor Inform86

Supplemental Guarantor Information - Additional Information (Details)	Dec. 31, 2016
Debt Disclosure [Abstract]
Percentage of subsidiaries owned	100.00%

Supplemental Guarantor Inform87

Supplemental Guarantor Information - Condensed Consolidating Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 70,236	$ 85,414	$ 23,666	$ 15,800
Receivables:
Oil and natural gas sales	43,073	35,005
Joint interest and other	63,928	22,012
Total receivables	107,001	57,017
Prepaid expenses and other assets	14,504	26,879
Total current assets	191,741	169,310
Property and equipment - at cost:
Oil and natural gas properties and equipment (full cost method, of which $0 at December 31, 2016 and $18,595 at December 31, 2015 were excluded from amortization)	7,932,504	7,902,494
Furniture, fixtures and other	20,898	20,802
Total property and equipment	7,953,402	7,923,296
Less accumulated depreciation, depletion and amortization	7,406,349	6,933,247
Net property and equipment	547,053	990,049
Deferred income taxes		27,595
Restricted deposits for asset retirement obligations	27,371	15,606
Income tax receivables	52,097
Other assets	11,464	5,462
Total assets	829,726	1,208,022
Current liabilities:
Accounts payable	81,039	109,797
Undistributed oil and natural gas proceeds	26,254	21,439
Asset retirement obligations	78,264	84,335
Long-term debt	8,272
Accrued liabilities	9,200	11,922
Total current liabilities	203,029	227,493
Long-term debt, less current maturities	1,012,455	1,196,855
Asset retirement obligations, less current portion	256,174	293,987
Other liabilities	17,105	16,178
Shareholders’ equity (deficit):
Common stock, $0.00001 par value; 200,000,000 shares authorized; 140,543,545 issued and 137,674,372 outstanding at December 31, 2016; 79,375,662 issued and 76,506,489 outstanding at December 31, 2015	1	1
Additional paid-in capital	539,973	423,499
Retained earnings (deficit)	(1,174,844)	(925,824)
Treasury stock, at cost; 2,869,173 shares at December 31, 2016 and 2015	(24,167)	(24,167)
Total shareholders’ equity (deficit)	(659,037)	(526,491)	509,308	540,610
Total liabilities and shareholders’ equity (deficit)	829,726	1,208,022
Parent Company
Current assets:
Cash and cash equivalents	70,236	85,414	$ 23,666	$ 15,800
Receivables:
Oil and natural gas sales	2,173	2,742
Joint interest and other	163,200	121,190
Total receivables	165,373	123,932
Prepaid expenses and other assets	12,448	25,375
Total current assets	248,057	234,721
Property and equipment - at cost:
Oil and natural gas properties and equipment (full cost method, of which $0 at December 31, 2016 and $18,595 at December 31, 2015 were excluded from amortization)	5,700,205	5,682,793
Furniture, fixtures and other	20,898	20,802
Total property and equipment	5,721,103	5,703,595
Less accumulated depreciation, depletion and amortization	5,360,137	5,258,563
Net property and equipment	360,966	445,032
Deferred income taxes		27,251
Restricted deposits for asset retirement obligations	27,371	15,606
Income tax receivables	52,097
Other assets	394,931	498,782
Total assets	1,083,422	1,221,392
Current liabilities:
Accounts payable	74,306	100,282
Undistributed oil and natural gas proceeds	24,493	20,463
Asset retirement obligations	62,261	63,716
Long-term debt	8,272
Accrued liabilities	9,293	11,922
Total current liabilities	178,625	196,383
Long-term debt, less current maturities	1,012,455	1,196,855
Asset retirement obligations, less current portion	142,376	173,105
Other liabilities	408,050	329,129
Shareholders’ equity (deficit):
Common stock, $0.00001 par value; 200,000,000 shares authorized; 140,543,545 issued and 137,674,372 outstanding at December 31, 2016; 79,375,662 issued and 76,506,489 outstanding at December 31, 2015	1	1
Additional paid-in capital	539,973	423,499
Retained earnings (deficit)	(1,173,891)	(1,073,413)
Treasury stock, at cost; 2,869,173 shares at December 31, 2016 and 2015	(24,167)	(24,167)
Total shareholders’ equity (deficit)	(658,084)	(674,080)
Total liabilities and shareholders’ equity (deficit)	1,083,422	1,221,392
Guarantor Subsidiaries
Receivables:
Oil and natural gas sales	40,900	32,263
Total receivables	40,900	32,263
Prepaid expenses and other assets	2,056	1,504
Total current assets	42,956	33,767
Property and equipment - at cost:
Oil and natural gas properties and equipment (full cost method, of which $0 at December 31, 2016 and $18,595 at December 31, 2015 were excluded from amortization)	2,232,299	2,219,701
Total property and equipment	2,232,299	2,219,701
Less accumulated depreciation, depletion and amortization	2,045,259	1,822,273
Net property and equipment	187,040	397,428
Deferred income taxes		344
Other assets	344,742	266,748
Total assets	574,738	698,287
Current liabilities:
Accounts payable	6,733	9,515
Undistributed oil and natural gas proceeds	1,761	976
Asset retirement obligations	16,003	20,619
Accrued liabilities	99,179	99,178
Total current liabilities	123,676	130,288
Asset retirement obligations, less current portion	113,798	120,882
Shareholders’ equity (deficit):
Additional paid-in capital	704,885	704,885
Retained earnings (deficit)	(367,621)	(257,768)
Total shareholders’ equity (deficit)	337,264	447,117
Total liabilities and shareholders’ equity (deficit)	574,738	698,287
Eliminations
Receivables:
Joint interest and other	(99,272)	(99,178)
Total receivables	(99,272)	(99,178)
Total current assets	(99,272)	(99,178)
Property and equipment - at cost:
Less accumulated depreciation, depletion and amortization	953	(147,589)
Net property and equipment	(953)	147,589
Other assets	(728,209)	(760,068)
Total assets	(828,434)	(711,657)
Current liabilities:
Accrued liabilities	(99,272)	(99,178)
Total current liabilities	(99,272)	(99,178)
Other liabilities	(390,945)	(312,951)
Shareholders’ equity (deficit):
Additional paid-in capital	(704,885)	(704,885)
Retained earnings (deficit)	366,668	405,357
Total shareholders’ equity (deficit)	(338,217)	(299,528)
Total liabilities and shareholders’ equity (deficit)	$ (828,434)	$ (711,657)

Supplemental Guarantor Inform88

Supplemental Guarantor Information - Condensed Consolidating Statement of Operations (Details) - USD ($)	3 Months Ended																12 Months Ended
	Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Condensed Income Statements Captions [Line Items]
Revenues	$ 115,213,000		$ 107,403,000		$ 99,655,000		$ 77,715,000		$ 104,064,000		$ 126,228,000		$ 149,066,000		$ 127,907,000		$ 399,986,000	$ 507,265,000	$ 948,708,000
Operating costs and expenses:
Lease operating expenses																	152,399,000	192,765,000	264,751,000
Production taxes																	1,889,000	3,002,000	7,932,000
Gathering and transportation																	22,928,000	17,157,000	19,821,000
Depreciation, depletion and amortization																	194,038,000	373,368,000	490,469,000
Asset retirement obligations accretion																	17,571,000	20,703,000	20,633,000
Ceiling test write-down of oil and natural gas properties	0		57,900,000		104,600,000		116,600,000		32,400,000		441,600,000		252,800,000		260,400,000		279,063,000	987,238,000	0
General and administrative expenses																	59,740,000	73,110,000	86,999,000
Derivative (gain) loss																	2,926,000	(14,375,000)	(3,965,000)
Total costs and expenses																	730,554,000	1,652,968,000	886,640,000
Operating income (loss)	21,319,000	[1]	(58,276,000)	[1]	(126,997,000)	[1]	(166,614,000)	[1]	(60,816,000)	[1]	(468,573,000)	[1]	(278,806,000)	[1]	(337,508,000)	[1]	(330,568,000)	(1,145,703,000)	62,068,000
Interest expense:
Incurred																	92,791,000	104,592,000	86,922,000
Capitalized																	(520,000)	(7,256,000)	(8,526,000)
Gain on exchange of debt			123,900,000														123,923,000
Other (income) expense, net																	(6,520,000)	4,663,000	(208,000)
Loss before income tax benefit																	(292,396,000)	(1,247,702,000)	(16,120,000)
Income tax expense (benefit)																	(43,376,000)	(202,984,000)	(4,459,000)
Net loss	$ 16,483,000	[1]	$ 45,928,000	[1]	$ (120,922,000)	[1]	$ (190,509,000)	[1]	$ (51,606,000)	[1]	$ (477,568,000)	[1]	$ (260,449,000)	[1]	$ (255,095,000)	[1]	(249,020,000)	(1,044,718,000)	(11,661,000)
Parent Company
Condensed Income Statements Captions [Line Items]
Revenues																	161,063,000	290,212,000	571,365,000
Operating costs and expenses:
Lease operating expenses																	84,415,000	126,189,000	180,149,000
Production taxes																	1,889,000	3,002,000	7,932,000
Gathering and transportation																	9,795,000	9,209,000	11,790,000
Depreciation, depletion and amortization																	73,268,000	201,154,000	267,406,000
Asset retirement obligations accretion																	8,165,000	11,587,000	10,981,000
Ceiling test write-down of oil and natural gas properties																	28,305,000	616,947,000
General and administrative expenses																	24,817,000	39,009,000	46,513,000
Derivative (gain) loss																	2,926,000	(14,375,000)	(3,965,000)
Total costs and expenses																	233,580,000	992,722,000	520,806,000
Operating income (loss)																	(72,517,000)	(702,510,000)	50,559,000
Earnings (loss) of affiliates																	(109,853,000)	(464,931,000)	8,320,000
Interest expense:
Incurred																	92,607,000	101,542,000	84,460,000
Capitalized																	(336,000)	(4,206,000)	(6,064,000)
Gain on exchange of debt																	123,923,000
Other (income) expense, net																	(6,520,000)	4,663,000	(208,000)
Loss before income tax benefit																	(144,198,000)	(1,269,440,000)	(19,309,000)
Income tax expense (benefit)																	(43,720,000)	(77,133,000)	(7,648,000)
Net loss																	(100,478,000)	(1,192,307,000)	(11,661,000)
Guarantor Subsidiaries
Condensed Income Statements Captions [Line Items]
Revenues																	238,923,000	217,053,000	377,343,000
Operating costs and expenses:
Lease operating expenses																	67,984,000	66,576,000	84,602,000
Gathering and transportation																	13,133,000	7,948,000	8,031,000
Depreciation, depletion and amortization																	112,277,000	172,214,000	223,063,000
Asset retirement obligations accretion																	9,406,000	9,116,000	9,652,000
Ceiling test write-down of oil and natural gas properties																	110,709,000	517,880,000
General and administrative expenses																	34,923,000	34,101,000	40,486,000
Total costs and expenses																	348,432,000	807,835,000	365,834,000
Operating income (loss)																	(109,509,000)	(590,782,000)	11,509,000
Interest expense:
Incurred																	184,000	3,050,000	2,462,000
Capitalized																	(184,000)	(3,050,000)	(2,462,000)
Loss before income tax benefit																	(109,509,000)	(590,782,000)	11,509,000
Income tax expense (benefit)																	344,000	(125,851,000)	3,189,000
Net loss																	(109,853,000)	(464,931,000)	8,320,000
Eliminations
Operating costs and expenses:
Depreciation, depletion and amortization																	8,493,000
Ceiling test write-down of oil and natural gas properties																	140,049,000	(147,589,000)
Total costs and expenses																	148,542,000	(147,589,000)
Operating income (loss)																	(148,542,000)	147,589,000
Earnings (loss) of affiliates																	109,853,000	464,931,000	(8,320,000)
Interest expense:
Loss before income tax benefit																	(38,689,000)	612,520,000	(8,320,000)
Net loss																	$ (38,689,000)	$ 612,520,000	$ (8,320,000)
[1]	During 2016, we recorded in first, second and third quarter ceiling test write-downs of oil and natural gas properties of $116.6 million, $104.6 million and $57.9 million, respectively. In the third quarter of 2016, we recorded a gain on exchange of debt of $123.9 million. 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 Inform89

Supplemental Guarantor Information - Condensed Consolidating Statement of Cash Flows (Details) - USD ($)	3 Months Ended																12 Months Ended
	Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating activities:
Net income (loss)	$ 16,483,000	[1]	$ 45,928,000	[1]	$ (120,922,000)	[1]	$ (190,509,000)	[1]	$ (51,606,000)	[1]	$ (477,568,000)	[1]	$ (260,449,000)	[1]	$ (255,095,000)	[1]	$ (249,020,000)	$ (1,044,718,000)	$ (11,661,000)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion, amortization and accretion																	211,609,000	394,071,000	511,102,000
Ceiling test write-down of oil and natural gas properties	0		57,900,000		$ 104,600,000		116,600,000		32,400,000		$ 441,600,000		$ 252,800,000		260,400,000		279,063,000	987,238,000	0
Gain on exchange of debt			$ (123,900,000)														(123,923,000)
Debt issuance costs write-off/amortization of debt items																	2,548,000	4,411,000	701,000
Share-based compensation																	11,013,000	10,242,000	14,744,000
Derivative (gain) loss																	2,926,000	(14,375,000)	(3,965,000)
Cash receipts (payments) on derivative settlements, net																	4,746,000	6,703,000	(5,318,000)
Deferred income taxes																	28,392,000	(203,272,000)	(4,760,000)
Changes in operating assets and liabilities:
Oil and natural gas receivables																	(7,005,000)	32,236,000	29,510,000
Joint interest and other receivables																	(1,126,000)	21,633,000	(4,255,000)
Income taxes																	(64,274,000)	(7,000)	3,143,000
Prepaid expenses and other assets																	(14,946,000)	17,816,000	15,012,000
Asset retirement obligation settlements																	(72,320,000)	(32,555,000)	(74,313,000)
Accounts payable, accrued liabilities and other																	6,497,000	(46,195,000)	4,881,000
Debt issuance costs write-down/amortization of debt items																	2,548,000	4,411,000	701,000
Net cash provided by (used in) operating activities																	14,180,000	133,228,000	474,821,000
Investing activities:
Acquisition of property interest in oil and natural gas properties																			(72,234,000)
Investment in oil and natural gas properties and equipment																	(48,606,000)	(230,161,000)	(554,378,000)
Changes in operating assets and liabilities associated with investing activities																	(35,194,000)	(55,425,000)	37,450,000
Net proceeds from sales of assets																	1,500,000	372,939,000
Purchases of furniture, fixtures and other																	(96,000)	(1,278,000)	(3,340,000)
Net cash provided by (used in) investing activities																	(82,396,000)	86,075,000	(592,502,000)
Financing activities:
Borrowings of long-term debt - revolving bank credit facility																	340,000,000	263,000,000	556,000,000
Repayments of long-term debt - revolving bank credit facility																	(340,000,000)	(710,000,000)	(399,000,000)
Debt exchange/issuance costs																	(18,464,000)	(6,669,000)
Dividends to shareholders																			(30,260,000)
Other																	(928,000)	(886,000)	(1,193,000)
Net cash provided by (used in) financing activities																	53,038,000	(157,555,000)	125,547,000
Increase (decrease) in cash and cash equivalents																	(15,178,000)	61,748,000	7,866,000
Cash and cash equivalents, beginning of period							85,414,000								23,666,000		85,414,000	23,666,000	15,800,000
Cash and cash equivalents, end of period	70,236,000								85,414,000								70,236,000	85,414,000	23,666,000
Parent Company
Operating activities:
Net income (loss)																	(100,478,000)	(1,192,307,000)	(11,661,000)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion, amortization and accretion																	81,433,000	212,741,000	278,387,000
Ceiling test write-down of oil and natural gas properties																	28,305,000	616,947,000
Gain on exchange of debt																	(123,923,000)
Debt issuance costs write-off/amortization of debt items																	2,548,000	4,411,000	701,000
Share-based compensation																	11,013,000	10,242,000	14,744,000
Derivative (gain) loss																	2,926,000	(14,375,000)	(3,965,000)
Cash receipts (payments) on derivative settlements, net																	4,746,000	6,703,000	(5,318,000)
Deferred income taxes																	28,048,000	(77,421,000)	(32,456,000)
Earnings (loss) of affiliates																	109,853,000	464,931,000	(8,320,000)
Changes in operating assets and liabilities:
Oil and natural gas receivables																	1,630,000	39,078,000	19,553,000
Joint interest and other receivables																	(1,126,000)	21,633,000	(4,255,000)
Income taxes																	(64,274,000)	(7,000)	27,650,000
Prepaid expenses and other assets																	(14,395,000)	(13,916,000)	45,962,000
Asset retirement obligation settlements																	(49,303,000)	(26,637,000)	(57,253,000)
Accounts payable, accrued liabilities and other																	46,955,000	(141,596,000)	11,931,000
Debt issuance costs write-down/amortization of debt items																	2,548,000	4,411,000	701,000
Net cash provided by (used in) operating activities																	(36,042,000)	(89,573,000)	275,700,000
Investing activities:
Acquisition of property interest in oil and natural gas properties																			(17,407,000)
Investment in oil and natural gas properties and equipment																	(37,418,000)	(31,534,000)	(312,044,000)
Changes in operating assets and liabilities associated with investing activities																	4,340,000	(29,806,000)	1,733,000
Net proceeds from sales of assets																	1,000,000	372,939,000
Investment in subsidiary																		(1,445,000)	(62,323,000)
Purchases of furniture, fixtures and other																	(96,000)	(1,278,000)	(3,340,000)
Net cash provided by (used in) investing activities																	(32,174,000)	308,876,000	(393,381,000)
Financing activities:
Borrowings of long-term debt - revolving bank credit facility																	340,000,000	263,000,000	556,000,000
Repayments of long-term debt - revolving bank credit facility																	(340,000,000)	(710,000,000)	(399,000,000)
Debt exchange/issuance costs																	(18,464,000)	(6,669,000)
Dividends to shareholders																			(30,260,000)
Other																	(928,000)	(886,000)	(1,193,000)
Net cash provided by (used in) financing activities																	53,038,000	(157,555,000)	125,547,000
Increase (decrease) in cash and cash equivalents																	(15,178,000)	61,748,000	7,866,000
Cash and cash equivalents, beginning of period							$ 85,414,000								$ 23,666,000		85,414,000	23,666,000	15,800,000
Cash and cash equivalents, end of period	$ 70,236,000								$ 85,414,000								70,236,000	85,414,000	23,666,000
Guarantor Subsidiaries
Operating activities:
Net income (loss)																	(109,853,000)	(464,931,000)	8,320,000
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion, amortization and accretion																	121,683,000	181,330,000	232,715,000
Ceiling test write-down of oil and natural gas properties																	110,709,000	517,880,000
Deferred income taxes																	344,000	(125,851,000)	27,696,000
Changes in operating assets and liabilities:
Oil and natural gas receivables																	(8,635,000)	(6,842,000)	9,957,000
Income taxes																			(24,507,000)
Prepaid expenses and other assets																	(78,547,000)	122,977,000	(7,525,000)
Asset retirement obligation settlements																	(23,017,000)	(5,918,000)	(17,060,000)
Accounts payable, accrued liabilities and other																	37,538,000	4,156,000	(30,475,000)
Net cash provided by (used in) operating activities																	50,222,000	222,801,000	199,121,000
Investing activities:
Acquisition of property interest in oil and natural gas properties																			(54,827,000)
Investment in oil and natural gas properties and equipment																	(11,188,000)	(198,627,000)	(242,334,000)
Changes in operating assets and liabilities associated with investing activities																	(39,534,000)	(25,619,000)	35,717,000
Net proceeds from sales of assets																	500,000
Net cash provided by (used in) investing activities																	(50,222,000)	(224,246,000)	(261,444,000)
Financing activities:
Investment from parent																		1,445,000	62,323,000
Net cash provided by (used in) financing activities																		1,445,000	62,323,000
11.00% 1.5 Lien Term Loan, Due November 2019
Financing activities:
Issuance of Term Loan																	75,000,000
Payment of interest on Term Loan																	2,570,000
11.00% 1.5 Lien Term Loan, Due November 2019 | Parent Company
Financing activities:
Issuance of Term Loan																	75,000,000
Payment of interest on Term Loan																	2,570,000
9.00 % Second Lien Term Loan, Due May 2020
Financing activities:
Issuance of Term Loan																		297,000,000
9.00 % Second Lien Term Loan, Due May 2020 | Parent Company
Financing activities:
Issuance of Term Loan																		297,000,000
Eliminations
Operating activities:
Net income (loss)																	(38,689,000)	612,520,000	(8,320,000)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion, amortization and accretion																	8,493,000
Ceiling test write-down of oil and natural gas properties																	140,049,000	(147,589,000)
Earnings (loss) of affiliates																	(109,853,000)	(464,931,000)	8,320,000
Changes in operating assets and liabilities:
Prepaid expenses and other assets																	77,996,000	(91,245,000)	(23,425,000)
Accounts payable, accrued liabilities and other																	$ (77,996,000)	91,245,000	23,425,000
Investing activities:
Investment in subsidiary																		1,445,000	62,323,000
Net cash provided by (used in) investing activities																		1,445,000	62,323,000
Financing activities:
Investment from parent																		(1,445,000)	(62,323,000)
Net cash provided by (used in) financing activities																		$ (1,445,000)	$ (62,323,000)
[1]	During 2016, we recorded in first, second and third quarter ceiling test write-downs of oil and natural gas properties of $116.6 million, $104.6 million and $57.9 million, respectively. In the third quarter of 2016, we recorded a gain on exchange of debt of $123.9 million. 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 Oil and Gas Disc90

Supplemental Oil and Gas Disclosures - Capitalized Costs Related to Oil and Natural Gas (Details) - USD ($) $ in Millions		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net capitalized cost:
Proved oil and natural gas properties and equipment		$ 7,932.5	$ 7,882.3	$ 7,924.2
Unproved oil and natural gas properties and equipment			20.2	121.5
Accumulated depreciation, depletion and amortization related to oil, NGLs and natural gas activities	[1]	(7,387.8)	(6,916.2)	(5,557.6)
Net capitalized costs related to producing activities		$ 544.7	$ 986.3	$ 2,488.1
[1]	Includes ceiling test write-down in 2016 and 2015.

Supplemental Oil and Gas Disc91

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Costs incurred:
Proved properties acquisitions	[1]	$ 1.3	$ 15.6	$ 111.5
Exploration	[1],[2],[3]	4.8	152.4	411.1
Development	[1]	56.9	65.5	198.7
Unproved property acquisitions	[1],[4]	0.5	0.1	3.1
Total costs incurred in oil and gas property acquisition, exploration and development activities	[1]	$ 63.5	$ 233.6	$ 724.4
[1]	Includes net addition from capitalized ARO of $10.8 million in 2016, net reductions from capitalized ARO of $0.4 million in 2015, and net additions from capitalized ARO of $88.0 million during 2014. These adjustments for ARO are associated with acquisitions, liabilities incurred, divestitures and revisions of estimates.
[2]	Includes geological and geophysical costs charged to expense of $4.1 million, $5.7 million and $7.3 million during 2016, 2015 and 2014, respectively.
[3]	Includes seismic costs of $0.2 million, $3.2 million and $9.0 million incurred during 2016, 2015 and 2014, respectively.
[4]	The amounts for unproved property acquisitions include capitalized interest associated with unproved properties acquired during the period.

Supplemental Oil and Gas Disc92

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Capitalized Costs Oil And Gas Producing Activities Net [Abstract]
Additions (reductions) of asset retirement obligations	$ 10.8	$ (0.4)	$ 88
Seismic costs	0.2	3.2	9
Geological and geophysical costs	$ 4.1	$ 5.7	$ 7.3

Supplemental Oil and Gas Disc93

Supplemental Oil and Gas Disclosures - Schedule of Depreciation, Depletion, Amortization and Accretion Expense (Details) - $ / Boe	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Capitalized Costs Oil And Gas Producing Activities Net [Abstract]
Depreciation, depletion, amortization and accretion per Boe	13.77	23.11	28.98

Supplemental Oil and Gas Disc94

Supplemental Oil and Gas Disclosures - Additional Information (Details)	12 Months Ended
	Dec. 31, 2016
Capitalized Costs Oil And Gas Producing Activities Net [Abstract]
Percentage non-operated non-producing reserves	19.00%
Present value discounted percentage	10.00%

Supplemental Oil and Gas Disc95

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, 2016MMBoeBcfeMMBblsBcf		Dec. 31, 2015MMBoeBcfeMMBblsBcf		Dec. 31, 2014MMBoeBcfeMMBblsBcf
Reserve Quantities [Line Items]
Revisions of previous estimates | MMBoe		14.2
Oil
Reserve Quantities [Line Items]
Proved reserves, beginning balance		35.5		61.7		58.5
Revisions of previous estimates		4.6	[1]	4.8	[2]	1.6	[3]
Revisions related to sold properties	[4]			(12.1)
Extensions and discoveries				2.4	[5]	7.3	[6]
Purchase of minerals in place	[7]					1.5
Sales of reserves	[8]			(13.5)
Production		(7.2)		(7.8)		(7.2)
Proved reserves, ending balance		32.9		35.5		61.7
Oil | Proved Developed Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance		29.4		35.7
Proved reserves, ending balance		26.6		29.4		35.7
Oil | Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance		6.1		26
Proved reserves, ending balance		6.3	[9]	6.1		26
NGLs
Reserve Quantities [Line Items]
Proved reserves, beginning balance		6.6		15.8		15.9
Revisions of previous estimates		3.1	[1]	(0.9)	[2]	0.1	[3]
Revisions related to sold properties	[4]			(4.8)
Extensions and discoveries				0.2	[5]	0.7	[6]
Purchase of minerals in place	[7]					1.2
Sales of reserves	[8]			(2.1)
Production		(1.5)		(1.6)		(2.1)
Proved reserves, ending balance		8.2		6.6		15.8
NGLs | Proved Developed Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance		6.4		10.7
Proved reserves, ending balance		7.6		6.4		10.7
NGLs | Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance		0.2		5.1
Proved reserves, ending balance		0.6	[9]	0.2		5.1
Natural Gas
Reserve Quantities [Line Items]
Proved reserves, beginning balance | Bcf		205,400		254,900		259,900
Revisions of previous estimates | Bcf		32,100	[1]	4,900	[2]	14,300	[3]
Revisions related to sold properties | Bcf	[4]			(2,900)
Extensions and discoveries | Bcf				8,800	[5]	10,100	[6]
Purchase of minerals in place | Bcf				6,100	[10]	20,700	[7]
Sales of reserves | Bcf	[8]			(20,200)
Production | Bcf		(39,700)		(46,200)		(50,100)
Proved reserves, ending balance | Bcf		197,800		205,400		254,900
Natural Gas | Proved Developed Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance | Bcf		198,500		221,100
Proved reserves, ending balance | Bcf		183,100		198,500		221,100
Natural Gas | Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance | Bcf		6,900		33,800
Proved reserves, ending balance | Bcf		14,700	[9]	6,900		33,800
Barrel Equivalent
Reserve Quantities [Line Items]
Proved reserves, beginning balance | MMBoe	[11]	76.4		120		117.7
Revisions of previous estimates | MMBoe	[11]	13	[1]	4.7	[2]	4.1	[3]
Revisions related to sold properties | MMBoe	[4],[11]			(17.4)
Extensions and discoveries | MMBoe	[11]			4.1	[5]	9.7	[6]
Purchase of minerals in place | MMBoe	[11]			1	[10]	6.1	[7]
Sales of reserves | MMBoe	[8],[11]			(19)
Production | MMBoe	[11]	(15.4)		(17)		(17.6)
Proved reserves, ending balance | MMBoe	[11]	74		76.4		120
Barrel Equivalent | Proved Developed Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance | MMBoe	[11]	69		83.3
Proved reserves, ending balance | MMBoe	[11]	64.7		69		83.3
Barrel Equivalent | Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance | MMBoe	[11]	7.4		36.7
Proved reserves, ending balance | MMBoe	[11]	9.3	[9]	7.4		36.7
Natural Gas Equivalent
Reserve Quantities [Line Items]
Proved reserves, beginning balance | Bcfe	[11]	458.1		720		705.9
Revisions of previous estimates | Bcfe	[11]	78.1	[1]	28	[2]	25.3	[3]
Revisions related to sold properties | Bcfe	[4],[11]			(104.3)
Extensions and discoveries | Bcfe	[11]			24.4	[5]	58.1	[6]
Purchase of minerals in place | Bcfe	[11]			6.1	[10]	36.5	[7]
Sales of reserves | Bcfe	[8],[11]			(113.8)
Production | Bcfe	[11]	(92.2)		(102.3)		(105.8)
Proved reserves, ending balance | Bcfe	[11]	444		458.1		720
Natural Gas Equivalent | Proved Developed Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance | Bcfe	[11]	413.5		499.7
Proved reserves, ending balance | Bcfe	[11]	388.2		413.5		499.7
Natural Gas Equivalent | Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance | Bcfe	[11]	44.6		220.3
Proved reserves, ending balance | Bcfe	[11]	55.8	[9]	44.6		220.3
[1]	Primarily related to upward revisions of 14.2 MMBoe, which included upward revisions of 3.8 MMBoe at our Viosca Knoll 823 (Tahoe/SE Tahoe) field, 1.5 MMBoe at our Fairway field, 1.3 MMBoe at our Mississippi Canyon 782 (Dantzler) field, and 1.2 MMBoe at our Main Pass 108 field. Partially offsetting were decreases for price revisions of 1.2 MMBoe.
[2]	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.
[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]	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 our Ewing Bank 910 field.
[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]	Primarily due to acquiring additional ownership in the Fairway Field and acquisition of the Woodside Properties.
[8]	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.
[9]	We believe that we will be able to develop all but 1.3 MMBoe, or approximately 14%, of the total of 9.3 MMBoe reserves classified as proved undeveloped (“PUDs”) at December 31, 2016, within five years from the date such reserves were initially recorded. The lone 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. One of the sidetrack PUD locations in this field was originally recorded in our proved reserves as of December 31, 2010. The development of this PUD 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 this PUD location in 2023.
[10]	Primarily due to purchase of additional interest at our Brazos A-133 field.
[11]	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 Disc96

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, 2016		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Reserve Quantities [Line Items]
Revisions of previous estimates			14.2
Proved undeveloped reserves, that will not be developed within five years			1.3
Percentage of proved undeveloped reserves that will be developed within five years			14.00%
Wells expected to be drilled, year			2,023
Barrel Equivalent
Reserve Quantities [Line Items]
Revisions of previous estimates	[2]		13	[1]	4.7	[3]	4.1	[4]
Extensions and discoveries	[2]				4.1	[5]	9.7	[6]
Proved reserves	[2]		74		76.4		120		117.7
Barrel Equivalent | Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Proved reserves	[2]		9.3	[7]	7.4		36.7
Changes Due to Price
Reserve Quantities [Line Items]
Revisions of previous estimates					10.7		0.3
Changes at the Fairway Field
Reserve Quantities [Line Items]
Revisions of previous estimates			1.5		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
Changes at the Yellow Rose field
Reserve Quantities [Line Items]
Revisions of previous estimates							(3.9)
Extensions and discoveries							4.1
Proved estimated reserve at the date of sale		19
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]
Revisions of previous estimates			1.3
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
Changes at the Viosca Knoll 823
Reserve Quantities [Line Items]
Revisions of previous estimates			3.8
Changes at the Main Pass 108 field
Reserve Quantities [Line Items]
Revisions of previous estimates			1.2
[1]	Primarily related to upward revisions of 14.2 MMBoe, which included upward revisions of 3.8 MMBoe at our Viosca Knoll 823 (Tahoe/SE Tahoe) field, 1.5 MMBoe at our Fairway field, 1.3 MMBoe at our Mississippi Canyon 782 (Dantzler) field, and 1.2 MMBoe at our Main Pass 108 field. Partially offsetting were decreases for price revisions of 1.2 MMBoe.
[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 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.
[4]	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.
[5]	Primarily due to increases at our Ewing Bank 910 field.
[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]	We believe that we will be able to develop all but 1.3 MMBoe, or approximately 14%, of the total of 9.3 MMBoe reserves classified as proved undeveloped (“PUDs”) at December 31, 2016, within five years from the date such reserves were initially recorded. The lone 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. One of the sidetrack PUD locations in this field was originally recorded in our proved reserves as of December 31, 2010. The development of this PUD 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 this PUD location in 2023.

Supplemental Oil and Gas Disc97

Supplemental Oil and Gas Disclosures - Schedule of Prices Weighted by Field Production Related to Proved Reserves (Details)	12 Months Ended
	Dec. 31, 2016$ / Boe$ / Mcf	Dec. 31, 2015$ / Boe$ / Mcf	Dec. 31, 2014$ / Boe$ / Mcf	Dec. 31, 2013$ / Boe$ / Mcf
Oil
Reserve Quantities [Line Items]
Weighted price	36.28	46.94	91.12	99.65
NGLs
Reserve Quantities [Line Items]
Weighted price	16.82	17.60	34.63	35.21
Natural Gas
Reserve Quantities [Line Items]
Weighted price | $ / Mcf	2.47	2.50	4.27	3.80

Supplemental Oil and Gas Disc98

Supplemental Oil and Gas Disclosures - Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013
Standardized Measure of Discounted Future Net Cash Flows
Future cash inflows	$ 1,818,400,000	$ 2,296,700,000	$ 7,258,500,000
Production	(691,500,000)	(840,100,000)	(2,224,500,000)
Development	(141,100,000)	(161,400,000)	(922,000,000)
Dismantlement and abandonment	(427,700,000)	(471,800,000)	(475,400,000)
Income taxes	0	0	(948,400,000)	[1]
Future net cash inflows before 10% discount	558,100,000	823,400,000	2,688,200,000
10% annual discount factor	(79,800,000)	(209,500,000)	(985,400,000)
Standardized measure of discounted future net cash flows	$ 478,300,000	$ 613,900,000	$ 1,702,800,000		$ 1,674,600,000
[1]	No future income taxes were estimated to be paid in 2016 and 2015 as our tax position has sufficient tax basis to offset estimated future taxes. State income taxes were disregarded due to immateriality.

Supplemental Oil and Gas Disc99

Supplemental Oil and Gas Disclosures - Standardized Measure of Discounted Future Net Cash Flows (Parenthetical) (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Income taxes	$ 0	$ 0	$ (948,400,000)	[1]
[1]	No future income taxes were estimated to be paid in 2016 and 2015 as our tax position has sufficient tax basis to offset estimated future taxes. State income taxes were disregarded due to immateriality.

Supplemental Oil and Gas Dis100

Supplemental Oil and Gas Disclosures - Change in Standard Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Changes in Standardized Measure
Changes in Standardized Measure, beginning of year	$ 613.9	$ 1,702.8	$ 1,674.6
Sales and transfers of oil and gas produced, net of production costs	(218.6)	(289.1)	(650.9)
Net changes in price, net of future production costs	(275.2)	(1,455.6)	(278.6)
Extensions and discoveries, net of future production and development costs		65.3	309.6
Changes in estimated future development costs	(32.5)	(8.5)	(56.4)
Previously estimated development costs incurred	114.5	158.9	263.1
Revisions of quantity estimates	190.1	137.9	118.6
Accretion of discount	52.6	150.6	180.6
Net change in income taxes		600.8	(11.4)
Purchases of reserves in-place		6	86.7
Sales of reserves in-place		(401.4)
Changes in production rates due to timing and other	33.5	(53.8)	66.9
Net increase (decrease) in standardized measure	(135.6)	(1,088.9)	28.2
Changes in Standardized measure, end of year	$ 478.3	$ 613.9	$ 1,702.8