W&T Offshore (WTI) 10-K 2 Mar 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 28, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
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		139,091,289
Entity Public Float			$ 182,243,000

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 99,058	$ 70,236
Receivables:
Oil and natural gas sales	45,443	43,073
Joint interest	19,754	21,885
Insurance reimbursement		30,100
Income taxes	13,006	11,943
Total receivables	78,203	107,001
Prepaid expenses and other assets (Note 1)	13,419	14,504
Total current assets	190,680	191,741
Oil and natural gas properties and other, net - at cost: (Note 1)	579,016	547,053
Restricted deposits for asset retirement obligations	25,394	27,371
Income tax receivables	52,097	52,097
Other assets (Note 1)	60,393	11,464
Total assets	907,580	829,726
Current liabilities:
Accounts payable	83,665	81,039
Undistributed oil and natural gas proceeds	20,129	26,254
Asset retirement obligations	23,613	78,264
Long-term debt	22,925	8,272
Accrued liabilities (Note 1)	17,930	9,200
Total current liabilities	168,262	203,029
Long-term debt: (Note 2)
Principal	889,790	873,733
Carrying value adjustments	79,337	138,722
Long term debt, less current portion - carrying value	969,127	1,012,455
Asset retirement obligations, less current portion	276,833	256,174
Other liabilities (Note 1)	66,866	17,105
Commitments and contingencies (Note 9)
Shareholders’ deficit:
Preferred stock, $0.00001 par value; 20,000,000 shares authorized; 0 issued at December 31, 2017 and December 31, 2016
Common stock, $0.00001 par value; 200,000,000 shares authorized; 141,960,462 issued and 139,091,289 outstanding at December 31, 2017 and 140,543,545 issued and 137,674,372 outstanding at December 31, 2016	1	1
Additional paid-in capital	545,820	539,973
Retained earnings (deficit)	(1,095,162)	(1,174,844)
Treasury stock, at cost; 2,869,173 shares at December 31, 2017 and December 31, 2016	(24,167)	(24,167)
Total shareholders’ equity (deficit)	(573,508)	(659,037)
Total liabilities and shareholders’ equity (deficit)	$ 907,580	$ 829,726

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Statement Of Financial Position [Abstract]
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	141,960,462	140,543,545
Common stock, outstanding	139,091,289	137,674,372
Treasury stock, shares	2,869,173	2,869,173

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Thousands	3 Months Ended												12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Statement [Abstract]
Revenues	$ 129,099	$ 110,281	$ 123,323	$ 124,393	$ 115,213		$ 107,403		$ 99,655		$ 77,715		$ 487,096	$ 399,986	$ 507,265
Operating costs and expenses:
Lease operating expenses													143,738	152,399	192,765
Production taxes													1,740	1,889	3,002
Gathering and transportation													20,441	22,928	17,157
Depreciation, depletion and amortization													138,510	194,038	373,368
Asset retirement obligations accretion													17,172	17,571	20,703
Ceiling test write-down of oil and natural gas properties							57,900		104,600		116,600		0	279,063	987,238
General and administrative expenses													59,744	59,740	73,110
Derivative (gain) loss													(4,199)	2,926	(14,375)
Total costs and expenses													377,146	730,554	1,652,968
Operating income (loss)	33,166	15,700	32,888	28,196	21,319	[1]	(58,276)	[1]	(126,997)	[1]	(166,614)	[1]	109,950	(330,568)	(1,145,703)
Interest expense:
Incurred													45,836	92,791	104,592
Capitalized													0	(520)	(7,256)
Gain on exchange of debt							123,900						7,811	123,923
Other (income) expense, net													4,812	(6,520)	4,663
Income (loss) before income tax benefit													67,113	(292,396)	(1,247,702)
Income tax benefit													(12,569)	(43,376)	(202,984)
Net income (loss)	$ 23,365	$ (1,297)	$ 33,315	$ 24,299	$ 16,483	[1]	$ 45,928	[1]	$ (120,922)	[1]	$ (190,509)	[1]	$ 79,682	$ (249,020)	$ (1,044,718)
Basic and diluted earnings (loss) per common share	$ 0.16	$ (0.01)	$ 0.23	$ 0.17	$ 0.12	[1],[2]	$ 0.48	[1],[2]	$ (1.58)	[1],[2]	$ (2.49)	[1],[2]	$ 0.56	$ (2.60)	$ (13.76)
[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. See Note 1 and Note 2 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. During the third quarter of 2016, 60.4 million shares of common stock were issued in conjunction with the Exchange Transaction.

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, 2014	$ 509,308	$ 1	$ 414,580	$ 118,894	$ (24,167)
Beginning Balances (in shares) at Dec. 31, 2014		75,899			2,869
Share-based compensation	10,242		10,242
Stock issued, shares		607
RSUs and shares surrendered for payroll taxes, value	(674)		(674)
Other	(649)		(649)
Net income (loss)	(1,044,718)			(1,044,718)
Ending Balances at Dec. 31, 2015	(526,491)	$ 1	423,499	(925,824)	$ (24,167)
Ending Balances (in shares) at Dec. 31, 2015		76,506			2,869
Share-based compensation	11,013		11,013
Stock issued, shares		61,168
Stock issued	106,366		106,366
RSUs and shares surrendered for payroll taxes, value	(905)		(905)
Net income (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
Share-based compensation	7,191		7,191
Stock issued, shares		1,417
RSUs and shares surrendered for payroll taxes, value	(1,344)		(1,344)
Net income (loss)	79,682			79,682
Ending Balances at Dec. 31, 2017	$ (573,508)	$ 1	$ 545,820	$ (1,095,162)	$ (24,167)
Ending Balances (in shares) at Dec. 31, 2017		139,091			2,869

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)
Operating activities:
Net income (loss)	$ 79,682
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	155,682
Ceiling test write-down of oil and natural gas properties	0
Gain on exchange of debt	(7,811)
Debt issuance costs write-down/amortization of debt items	1,715
Share-based compensation	7,191
Derivative (gain) loss	(4,199)
Cash receipts on derivative settlements, net	4,199
Deferred income taxes	217
Changes in operating assets and liabilities:
Oil and natural gas receivables	(2,370)
Joint interest receivables	2,131
Insurance reimbursements	31,740
Income taxes	(1,063)
Prepaid expenses and other assets	3,238
Escrow deposit - Apache lawsuit	(49,500)
Asset retirement obligation settlements	(72,409)
Accounts payable, accrued liabilities and other	10,965
Net cash provided by (used in) operating activities	159,408
Investing activities:
Investment in oil and natural gas properties and equipment	(130,048)
Changes in operating assets and liabilities associated with investing activities	23,874
Purchases of furniture, fixtures and other	(933)
Net cash provided by (used in) investing activities	(107,107)
Financing activities:
Debt exchange/issuance costs	(421)
Other	(1,295)
Net cash provided by (used in) financing activities	(23,479)
Increase (decrease) in cash and cash equivalents	28,822
Cash and cash equivalents, beginning of period	70,236
Cash and cash equivalents, end of period	99,058
11.00% 1.5 Lien Term Loan, Due November 2019
Financing activities:
Payment of interest	(8,227)
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020
Financing activities:
Payment of interest	(7,335)
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021
Financing activities:
Payment of interest	$ (6,201)

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
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 with substantially all of its operations 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. 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, proved reserves and future rate of growth. The average realized prices of these commodities improved in 2017 compared to the average realized prices in 2016. Operating costs were lower for 2017 on an absolute and on a per barrel oil equivalent (“Boe”) basis compared to the operating costs for 2016. In September 2016, we consummated the Exchange Transaction, as defined and described below in Note 2, which reduced our interest payments for 2017 as compared to 2016. In addition, the Exchange Transaction extended the maturities on a portion of our debt, although for a portion of the New Debt, as defined and described in Note 2, the maturities of two of the new loans will accelerate if certain events do not transpire. We have continued working to further reduce our operating costs, capital expenditures and costs related to asset retirement obligations (“ARO”). Our capital expenditures incurred in 2017 were higher than the capital expenditures incurred during 2016, but were significantly lower than spending levels incurred during 2015 and prior years. Our current capital expenditure budget for 2018 is approximately the same level as incurred in 2017. As of the filing date of this Form 10-K, the Company is in compliance with its financial assurance obligations to the Bureau of Ocean Energy Management (“BOEM”) and has no outstanding BOEM orders related to financial assurance obligations. During the second quarter of 2017, a trial court judgment was rendered in Apache Corporation’s (“Apache”) lawsuit against us. As a result, we deposited $49.5 million with the registry of the court from cash on hand as a first step to allow us to appeal the decision. See Note 17 for additional information. We have assessed our financial condition, the current capital markets and options given different scenarios of commodity prices. We believe we will have adequate liquidity to fund our operations through March 2019, the period of assessment to qualify as a going concern. We are evaluating various alternatives and believe our plans can be executed in the current market and are within our capabilities. Our plans address the possible maturity acceleration of certain debt instruments, which could accelerate to February 28, 2019 if certain events were not to occur, and address events needed to extend our Credit Agreement, which matures on November 8, 2018. However, we cannot predict the potential changes in commodity prices or future bonding requirements, either of which could affect our operations, liquidity levels and compliance with debt obligations. 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, 2017 and 2016, $4.7 million and $5.3 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, large financial institutions and large trading houses. The majority of our production is sold utilizing month-to-month contracts that are based on bid prices. 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 guarantees when considered necessary. The following table 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, 2017 2016 2015 Customer Shell Trading (US) Co. 46 % 43 % 50 % Vitol Inc. 15 % 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. Accounts Receivables and Allowance for Bad Debts Our accounts receivables are recorded at their historical cost, less an allowance for doubtful accounts. The carrying value approximates fair value because of the short-term nature of such accounts. In addition to receivables from sales of our production to our customers, we also have receivables from joint interest owners on properties we operate. In certain arrangements, we have the ability to withhold future revenue disbursements to recover amounts due us from the joint interest partners. We have not had any significant problems collecting our receivables from our customers, but with the decline in commodity prices starting in 2015, several oil and gas companies have filed for bankruptcy where we have joint interest arrangements. We use the specific identification method of determining if an allowance for doubtful accounts is needed. The following table describes the balance and changes to the allowance for doubtful accounts: 2017 2016 2015 Allowance for doubtful accounts, beginning of period $ 7,602 $ 2,490 $ 704 Additional provisions for the year 1,512 5,112 1,786 Uncollectable accounts written off — — — Allowance for doubtful accounts, end of period $ 9,114 $ 7,602 $ 2,490 Insurance Receivables We recognize insurance receivables with respect to capital, repair and plugging and abandonment costs primarily as a result of hurricane damage when we deem those to be probable of collection, which normally 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. During 2017, we received payments by certain insurance companies related to settlement of previously unpaid claims. See Note 5 for additional information. Prepaid expenses and other Amounts recorded in Prepaid expenses and other Year Ended December 31, 2017 2016 Prepaid/accrued insurance $ 2,401 $ 2,924 Surety bonds unamortized premiums 2,676 2,462 Prepaid deposits related to royalties 6,456 6,237 Other 1,886 2,881 Prepaid expenses and other $ 13,419 $ 14,504 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 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. Oil and natural gas properties and equipment are recorded at cost using the full cost method. Oil and Natural Gas Properties and Other, Net – at cost Oil and natural gas properties and equipment are recorded at cost using the full cost method. There were no amounts excluded from amortization as of the dates presented in the following table (in thousands): December 31, 2017 2016 Oil and natural gas properties and equipment $ 8,102,044 $ 7,932,504 Furniture, fixtures and other 21,831 20,898 Total property and equipment 8,123,875 7,953,402 Less accumulated depreciation, depletion and amortization 7,544,859 7,406,349 Oil and natural gas properties and other, net $ 579,016 $ 547,053 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. We did not record a ceiling test write-down during 2017. We recorded ceiling test write-downs in 2016 and 2015, which are reported as a separate line in the Statements of Operations, due primarily to declines in the unweighted rolling 12-month average of first-day-of-the-month commodity prices for oil and natural gas. 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. If average crude oil and natural gas prices decrease from 2016 levels, it is possible that ceiling test write-downs could be recorded during 2018 or future periods. 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. From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas. When we have outstanding borrowings on our revolving bank credit facility, we may use various derivative financial instruments to manage our exposure to interest rate risk from floating interest rates. During 2017, no borrowings were outstanding on our revolving bank credit facility. We do not enter into derivative instruments for speculative trading purposes. We entered into commodity derivatives contracts during 2017, which were settled or expired during 2017. As of December 31, 2017 and 2016, we did not have any open derivative financial instruments. 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 of the debt’s superior collateral ranking amongst our various debt instruments even though such debt was not traded. 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 Other Assets (long-term) The major categories recorded in Other assets December 31, 2017 2016 Escrow deposit - Apache lawsuit $ 49,500 $ — Appeal bond deposits 6,925 6,925 Investment in White Cap, LLC 2,511 2,520 Other 1,457 2,019 Total other assets $ 60,393 $ 11,464 Accrued Liabilities The major categories recorded in Accrued liabilities are presented in the following table (in thousands): December 31, 2017 2016 Accrued interest $ 4,200 $ 4,189 Accrued salaries/payroll taxes/benefits 2,454 2,777 Incentive compensation plans 7,366 — Litigation accruals 3,480 1,891 Other 430 343 Total accrued liabilities $ 17,930 $ 9,200 Troubled Debt Restructuring We accounted for a debt exchange transaction in 2016, 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 Other Liabilities (long-term) The major categories recorded in Other liabilities December 31, 2017 2016 Apache lawsuit $ 49,500 $ — Uncertain tax positions including interest/penalties 11,015 10,584 Other 6,351 6,521 Total other liabilities (long-term) $ 66,866 $ 17,105 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. Earnings (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 earnings (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 2017, the amount consists primarily of expense items related to the Apache lawsuit of $6.3 million, partially offset by loss-of-use reimbursements from a third-party for damages incurred at one of our platforms of $1.1 million. 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”), Revenue from Contracts and Customers Topic 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 In August 2017, the FASB issued Accounting Standards Update No. 2017-12, (“ASU 2017-12”), Derivatives and Hedging (Topic 815) – Targeted Improvements to Accounting for Hedging Activities

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Long-Term Debt	2. Long-Term Debt The components of our long-term debt are presented in the following tables (in thousands): December 31, 2017 December 31, 2016 Adjustments to Adjustments to Carrying Carrying Carrying Carrying Principal Value (1) Value Principal Value (1) Value 11.00% 1.5 Lien Term Loan, due November 2019: Principal $ 75,000 $ — $ 75,000 $ 75,000 $ — $ 75,000 Future interest payments — 15,596 15,596 — 23,823 23,823 Subtotal 75,000 15,596 90,596 75,000 23,823 98,823 9.00 % Second Lien Term Loan, due May 2020: 300,000 — 300,000 300,000 — 300,000 9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020: Principal 171,769 — 171,769 163,007 — 163,007 Future payments-in-kind — 5,745 5,745 — 24,048 24,048 Future interest payments — 34,872 34,872 — 36,850 36,850 Subtotal 171,769 40,617 212,386 163,007 60,898 223,905 8.50%/10.00% Third Lien PIK Toggle Notes, due June 2021: Principal 153,192 — 153,192 145,897 — 145,897 Future payments-in-kind — 11,323 11,323 — 26,844 26,844 Future interest payments — 38,682 38,682 — 40,705 40,705 Subtotal 153,192 50,005 203,197 145,897 67,549 213,446 8.50% Unsecured Senior Notes, due June 2019 189,829 — 189,829 189,829 — 189,829 Debt premium, discount, issuance costs, net of amortization — (3,956 ) (3,956 ) — (5,276 ) (5,276 ) Total long-term debt 889,790 102,262 992,052 873,733 146,994 1,020,727 Current maturities of long-term debt (2) — 22,925 22,925 — 8,272 8,272 Long term debt, less current maturities $ 889,790 $ 79,337 $ 969,127 $ 873,733 $ 138,722 $ 1,012,455 (1) Future interest payments and future payments-in-kind (“PIK”) are recorded on an undiscounted basis. (2) Future interest payments on the 1.5 Lien Term Loan, Second Lien PIK Toggle Notes and Third Lien PIK Toggle Notes due within twelve months. Aggregate annual maturities of amounts recorded for long-term debt as of December 31, 2017 are as follows (in millions): 2018–$22.9; 2019–$302.1; 2020–$499.5; 2021–$171.5. See below for a discussion of our debt instruments. 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, due June 15, 2019 (the “Unsecured Senior Notes”), 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, 1.5 Lien Term Loan 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 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 since September 7, 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 maturities of the New Debt. Under ASC 470-60, payments related to the New Debt are reported in the financing section of the Condensed Consolidated Statements of Cash Flows. A gain of $123.9 million was recognized related to the Exchange Transaction during 2016. 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 both basic and diluted earnings per share for 2016 was $1.30 per share, which assumes the gain would not affect our 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. During the second quarter of 2017, interest on the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes was paid in cash rather than in kind. As a result of the cash interest payment, an $8.2 million net reduction was recorded to long-term debt on the Consolidated Balance Sheet and the offset to Gain on exchange of debt Gain on exchange of debt The primary terms of our long-term debt following the Exchange Transaction are described below. Credit Agreement The Credit Agreement provides a revolving bank credit facility. Availability under the Credit Agreement is subject to a semi-annual redetermination of our borrowing base that occurs in the spring and fall of each year and is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria. We and our lenders may request one additional determination per year. The borrowing base as of December 31, 2017 was $150.0 million. Any redetermination 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 a first priority lien on substantially all of our oil and natural gas properties. The Credit Agreement matures 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 contracts 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, 2017 and thereafter are: (i) the First Lien Leverage Ratio must be less than 2.00 to 1.00; and (ii) the Current Ratio must be greater than 1.00 to 1.00. As of December 31, 2017, the Current Ratio was 2.80 to 1.00. As of December 31, 2017, the First Lien Leverage Ratio was 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, 2017. 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%. 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, 2017 and 2016, we had no borrowings outstanding under the revolving bank credit facility. At December 31, 2017 and 2016, we had $0.3 million and $0.5 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. Certain amendments under the 1.5 Lien Term Loan and the Credit Agreement will likely be required in the event replacement financing is not utilized. 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 include 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, 2017. 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%. The Second Lien Loan was issued at a 1.0% discount to par, 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 9.6%, 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 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. This payment-in-kind provision expires on March 7, 2018. For the initial interest payment on November 15, 2016, interest could only be paid-in-kind at 10.75% per annum. For the six month interest period ending May 15, 2017, we paid the interest payment in cash rather than using the payment-in-kind provision. For the six-month period ended November 15, 2017, we exercised the payment-in-kind provision. For the interest period ending May 15, 2018, we have exercised the payment-in-kind provision to pay interest through March 7, 2018, and, thereafter, interest will be paid in cash. When the PIK option is utilized, the principal amount of the notes increases. 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 are 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. Certain amendments under the 1.5 Lien Term Loan and the Credit Agreement will likely be required in the event replacement financing is not utilized. 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. This payment-in-kind provision expires on September 7, 2018. For the initial interest payment on December 15, 2016, interest could only be paid-in-kind at 10.00% per annum. For the six month interest period ending June 15, 2017, we paid the interest payment in cash rather than using the payment-in-kind provision. For the six-month period ended November 15, 2017, we exercised the payment-in-kind provision. For the six-month period ended June 15, 2018, we have exercised the payment-in-kind provision. When the PIK option is utilized, the principal amount of the notes increases. 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 carrying amount under ASC 470-60, we anticipate the remaining eligible interest payments will be paid-in-kind versus paid in cash. 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 all applicable covenants as of December 31, 2017. Unsecured Senior Notes At December 31, 2017 and 2016, 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. The Unsecured Senior Notes are currently redeemable at par. Subject to limited exceptions, our 1.5 Lien Term Loan and Credit Agreement restrict us from using cash on hand to repay or repurchase our Unsecured Senior Notes prior to their stated maturity, although we can generally refinance our Unsecured Senior Notes with new indebtedness within customary parameters. Certain amendments under the 1.5 Lien Term Loan and the Credit Agreement will likely be required in the event replacement financing is not utilized. 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 8.3%, which includes amortization of debt issuance costs and premiums. The Unsecured Senior 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 all applicable covenants as of December 31, 2017. 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, 2017
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 2017 2016 11.00% 1.5 Lien Term Loan, due November 2019 Level 2 $ 75,000 $ 75,000 9.00 % Second Lien Term Loan, due May 2020 Level 2 288,000 255,000 9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020 Level 2 162,322 122,255 8.50%/10.00% Third Lien PIK Toggle Notes due June 2021 Level 2 119,490 80,243 8.50% Unsecured Senior Notes, due June 2019 Level 2 178,439 123,389 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 has not traded since its inception in September 2016. We believe the carrying amount of debt under our 1.5 Lien Term Loan approximates fair value because of the debt’s superior collateral ranking amongst our debt instruments even though such debt was not traded. Given the relatively short time until maturity, having an interest rate higher than any our other debt instruments and having superior collateral ranking over our other debt instruments, we assessed the fair value of the 1.5 Lien Term Loan to be at least equivalent to its carrying value. As of December 31, 2017 and 2016, there were no open derivatives financial instruments. The carrying value of our long-term debt is disclosed in Note 2 above.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2017
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 table is a reconciliation of our ARO liability (in thousands): Year Ended December 31, 2017 2016 Asset retirement obligations, beginning of period $ 334,438 $ 378,322 Liabilities settled (72,409 ) (72,320 ) Accretion of discount 17,172 17,571 Liabilities incurred 163 398 Revisions of estimated liabilities 21,082 10,467 Asset retirement obligations, end of period 300,446 334,438 Less current portion 23,613 78,264 Long-term $ 276,833 $ 256,174 During 2017, we decreased our ARO liability on an overall basis primarily due to plug and abandonment work performed during 2017, partially offset by increases from accretion and revisions of previous estimates. Revisions were primarily related to increased costs associated with wells at four fields that experienced sustained casing pressure issues. Wells that experience sustained casing pressure require more days and greater work scope to complete the abandonment project. Partially offsetting are downward revisions to cost estimates from service providers for plug and abandonment work at certain locations. During 2016, we decreased our ARO liability 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 at our West Cameron fields identified while performing preliminary plug and abandonment work at these fields. In addition, increases were attributable to several non-operated properties under which we have no control. Partially offsetting are downward revisions to cost estimates from service providers for plug and abandonment work at certain locations.

Insurance Claims

Insurance Claims	12 Months Ended
	Dec. 31, 2017
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 2017, 2016 and 2015, we received insurance reimbursements of $31.7 million, $10.2 million and $0.2 million, respectively, primarily related to hurricane damage. Cash receipts from insurance proceeds are included within 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, 2017
Receivables [Abstract]
Restricted Deposits	6. Restricted Deposits Restricted deposits as of December 31, 2017 and 2016 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.

Divestitures

Divestitures	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Divestitures	7. 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.

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2017
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. While these contracts are intended to reduce the effects of price volatility, they may have limited incremental income from favorable price movements. Commodity Derivatives As of December 31, 2017 and 2016, we did not have any open derivative contracts. During 2017, 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 West Texas Intermediate (“ Changes in the fair value and settlements of our commodity derivative contracts were as follows (in thousands): Year Ended December 31, 2017 2016 2015 Derivative (gain) loss $ (4,199 ) $ 2,926 $ (14,375 ) Cash receipts (payments), net, on commodity derivative contract settlements are included within Net cash provided by operating activities Year Ended December 31, 2017 2016 2015 Cash receipts on derivative settlements, net $ 4,199 $ 4,746 $ 6,703

Equity Transactions

Equity Transactions	12 Months Ended
	Dec. 31, 2017
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 2017, 2016 and 2015, we did not pay any dividends and dividends are currently suspended.

Share-Based Awards and Cash-Bas

Share-Based Awards and Cash-Based Awards	12 Months Ended
	Dec. 31, 2017
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. During 2017, 2016, and 2013, amendments to the Plan were approved by our shareholders. The Plan covers the Company’s eligible employees and consultants. In addition to other cash and share-based compensation awards, the Plan has historically been designed to grant awards that qualified as performance-based compensation within the meaning of section 162(m) of the Internal Revenue Code (“IRC”). Beginning in 2018, IRC section 162(m) will no longer contain deduction exemptions for performance-based compensation except for plans in place prior to November 2, 2017 that meet certain certifications. The Plan grants the Compensation Committee of the Board of Directors administrative authority over all participants, and grants 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 vesting or performance criteria applicable to the award 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 (“RSUs”), 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. The 2017 amendment increased the number of shares available in the Plan by 7,700,000 shares of common stock. As of December 31, 2017, there were 13,363,792 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 2017, 2016 and 2015, performance awards under the Plan were granted in the form of RSUs to eligible employees. 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 2017, 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 2017 and (ii) Adjusted EBITDA as a percent of total revenue (“Adjusted EBITDA Margin”) for 2017. Adjustments range from 0% to 100% based upon actual results compared against pre-defined performance levels. For 2017, the Company achieved target for both Adjusted EBITDA and Adjusted EBITDA Margin. During 2016 and 2015, RSUs granted were subject to adjustments based on achievement of a combination of performance criteria, which was comprised of: (i) Adjusted EBITDA and (ii) Adjusted EBITDA Margin for each respective year. Adjustments range from 0% to 100% based upon actual results compared against pre-defined performance levels. For both 2016 and 2015, the Company was below target for Adjusted EBITDA and achieved 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 2015 (after adjustment for performance) vested in December 2017 to eligible employees. The Company has the option to settle RSUs in stock or cash at vesting. Prior to 2017, only shares of common stock were used to settle vested RSUs. During 2017, cash was used to settle vested RSUs related to the retirement of an executive officer and shares of common stock were used to settle all other vested RSUs. The Company plans to settle RSUs that vest in the future using shares of common stock. During 2017, 2016 and 2015, 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 for all years presented was determined using the Company’s closing price on the grant dates. A summary of activity related to RSUs is as follows: 2017 2016 2015 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 6,107,248 $ 2.73 3,474,079 $ 7.42 1,977,335 $ 15.29 Granted 2,128,879 2.76 4,213,964 2.21 2,626,930 3.59 Vested (2,108,553 ) 3.45 (968,652 ) 16.69 (721,038 ) 13.23 Forfeited (362,323 ) 2.87 (612,143 ) 3.64 (409,148 ) 10.63 Nonvested, end of period 5,765,251 $ 2.48 6,107,248 $ 2.73 3,474,079 $ 7.42 Subject to the satisfaction of service conditions, the RSUs outstanding as of December 31, 2017 are eligible to vest in the year indicated in the table below: Restricted Stock Units 2018 3,742,509 2019 2,022,742 Total 5,765,251 RSUs fair value at grant date - During 2017, 2016 and 2015, the grant date fair value of RSUs granted was $5.9 million, $9.3 million and $9.4 million, respectively. RSUs fair value at vested date - The fair value of the RSUs that vested during 2017, 2016 and 2015 was $5.5 million, $2.4 million and $2.1 million, respectively, based on the Company’s closing price on the vesting date. Share-Based Awards: Restricted Stock Under the Directors Compensation Plan, shares of restricted stock (“Restricted Shares”) were issued in 2017, 2016 and 2015 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, 2017, there were 170,524 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: 2017 2016 2015 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 161,296 $ 3.47 78,230 $ 8.95 43,210 $ 16.20 Granted 147,372 1.90 126,128 2.22 56,540 6.19 Vested (62,140 ) 4.51 (43,062 ) 9.75 (21,520 ) 16.26 Nonvested, end of period 246,528 $ 2.27 161,296 $ 3.47 78,230 $ 8.95 Subject to the satisfaction of service conditions, the Restricted Shares outstanding as of December 31, 2017 are expected to vest as follows: Restricted Shares 2018 106,240 2019 91,164 2020 49,124 Total 246,528 Restricted stock fair value at grant date - The grant date fair value of restricted stock granted during 2017, 2016 and 2015 was $0.3 million each year for all years presented 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 2017, 2016 and 2015 was $0.1 million each year for all years presented 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, 2017 2016 2015 Share-based compensation expense from: Restricted stock units $ 7,785 $ 10,640 $ 9,978 Restricted stock 280 373 358 Common shares — — (94 ) Total $ 8,065 $ 11,013 $ 10,242 Share-based compensation tax benefit: Tax benefit computed at the statutory rate $ 1,694 $ 3,855 $ 3,585 As of December 31, 2017, unrecognized share-based compensation expense related to our awards of RSUs and Restricted Shares was $6.2 million and $0.4 million, respectively. Unrecognized compensation expense will be recognized through November 2019 for our RSUs and April 2020 for our 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 2017, 2016 and 2015. 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, these cash-based awards included an additional financial condition requiring Adjusted EBITDA less reported Interest Expense Incurred for any fiscal quarter plus the three preceding quarters to exceed defined levels measured over defined time periods for each cash-based award. Expense is recognized over the service period once the business criteria, individual performance criteria and financial condition are met. • For the 2017 cash-based awards, a portion of the business criteria and individual performance criteria were achieved. The financial condition requirement of Adjusted EBITDA less reported Interest Expense Incurred exceeding $200 million over four consecutive quarters was achieved; therefore, incentive compensation expense was recognized in 2017 for the 2017 cash-based awards. Payments are expected to be made in March 2018 and are subject to all the terms of the 2017 Annual Incentive Award Agreement. • For the 2016 cash-based awards, the financial condition requirement of Adjusted EBITDA less reported Interest Expense Incurred exceeding $300 million over four consecutive quarters was not achieved as of December 31, 2017; therefore no expense was recognized during 2017 or 2016. The terms of the 2016 cash-based awards allow for the measurement of the financial condition to be made up through December 31, 2018. If the financial condition is achieved, payment is to be made within 30 days of achievement of the financial condition. • For the 2015 cash-based awards, the financial condition was not achieved through the measurement date; therefore, all awards granted were forfeited and no expense was recognized in any of the reported periods. 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, 2017 2016 2015 Share-based compensation included in: General and administrative $ 8,065 $ 11,013 $ 10,242 Cash-based incentive compensation included in: Lease operating expense 2,101 — 364 General and administrative (1) 5,032 — (233 ) Total charged to operating income $ 15,198 $ 11,013 $ 10,373 (1) Adjustments to true up estimates to actual payments resulted in net credit balances to expense in 2015 .

Employee Benefit Plan

Employee Benefit Plan	12 Months Ended
	Dec. 31, 2017
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. From March 5, 2016 to March 1, 2017, the Company suspended matching contributions. During the time periods where matching occurred, 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 $1.4 million, $0.4 million and $2.3 million for 2017, 2016 and 2015, respectively.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 2015 Current $ (12,786 ) $ (71,768 ) $ 288 Deferred 217 28,392 (203,272 ) Total income tax (benefit) $ (12,569 ) $ (43,376 ) $ (202,984 ) 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, 2017 2016 2015 Income tax (benefit) at the federal statutory rate $ 23,490 35.0 % $ (102,339 ) 35.0 % $ (436,696 ) 35.0 % Share-based compensation 664 1.0 4,920 (1.7 ) 2,940 (0.2 ) State income taxes 63 0.1 (755 ) 0.2 (2,343 ) 0.2 Debt restructuring cost 18 — 1,463 (0.5 ) — — Change in statutory federal tax rate 105,933 157.8 — — — — Gain on exchange of debt (24,981 ) (37.2 ) — — — — Valuation allowance (118,643 ) (176.8 ) 52,915 (18.1 ) 232,925 (18.7 ) Other 887 1.4 420 (0.1 ) 190 — Total income tax (benefit) $ (12,569 ) (18.7 %) $ (43,376 ) 14.8 % $ (202,984 ) 16.3 % Our effective tax rate for the years 2017, 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. 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, 2017 2016 Deferred tax liabilities: Other $ 695 $ 1,423 Total deferred tax liabilities 695 1,423 Deferred tax assets: Property and equipment 18,234 42,385 Asset retirement obligations 63,755 117,588 Federal net operating losses 18,988 — State net operating losses 7,126 5,615 Exchange transaction 55,807 118,467 Share-based compensation 1,335 2,353 Valuation allowance (171,547 ) (290,190 ) Other 6,805 4,798 Total deferred tax assets 503 1,016 Net deferred tax assets (liabilities) $ (192 ) $ (407 ) During 2017, we received refunds of $11.9 million and made income tax payments of $0.2 million. During 2016, we received $7.8 million of refunds and Income Taxes Receivables As of December 31, 2017, we have recorded a current income taxes receivable of $13.0 million and a non-current income taxes receivable of $52.1 million. The current income taxes receivable primarily relate to a net operating loss carried back claim for 2017. The non-current income taxes receivable relates to our NOL claims for the years 2012, 2013 and 2014 that were carried back to prior years. 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 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, 2017 (in thousands): Amount Expiration Year Federal net operating loss $ 18,988 2037 State net operating losses 118,027 2025-2036 Valuation Allowance During 2017, we recorded a decrease in the valuation allowance of $118.6 million and in 2016, we recorded an increase in the valuation allowance of $52.9 million related to federal and state deferred tax assets. As a result of the enactment of the Tax Cuts and Jobs Act (“TCJA”), on December 22, 2017, our net deferred tax assets and its respective valuation allowance were provisionally adjusted downwards by $105.9 million as of December 31, 2017. 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, 2017 and 2016, we had a valuation allowance related to our federal and state deferred tax assets. Due to the timing and the complexity involved in applying the provisions of the TCJA, our application of the TCJA may require further adjustments during 2018 in the determination of the final effects in our financial statements. 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, 2017 2016 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 2017, 2016 and 2015, the amounts recognized in income tax expense were immaterial. Years open to examination The tax years from 2013 through 2017 remain open to examination by the tax jurisdictions to which we are subject.

Earnings_ (Loss) Per Share

Earnings/ (Loss) Per Share	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Earnings/ (Loss) Per Share	13. Earnings (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 earnings (loss) per common share (in thousands, except per share amounts): Year Ended December 31, 2017 2016 2015 Net income (loss) $ 79,682 $ (249,020 ) $ (1,044,718 ) Less portion allocated to nonvested shares 3,244 — — Net income (loss) allocated to common shares $ 76,438 $ (249,020 ) $ (1,044,718 ) Weighted average common shares outstanding 137,617 95,644 75,931 Basic and diluted earnings (loss) per common share $ 0.56 $ (2.60 ) $ (13.76 ) Shares excluded due to being anti-dilutive (weighted-average) — 5,269 2,195

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2017
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	14. Supplemental Cash Flow Information The following table reflects our supplemental cash flow information (in thousands): Year Ended December 31, 2017 2016 2015 Supplemental cash items: Cash paid for interest, net of interest capitalized of $0 in 2017, $520 in 2016 and $7,256 in 2015 (1) $ 65,873 $ 96,501 $ 92,622 Cash paid for income taxes 185 310 390 Cash refunds received for income taxes 11,906 7,796 90 Cash paid for share-based compensation (2) 874 — — Non-cash investing activities: Accruals of property and equipment 33,003 9,129 44,324 ARO - additions, dispositions and revisions, net 21,245 10,865 (394 ) 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) During 2017 and 2016, cash paid for interest included amounts related to the New Debt, which are accounted for under ASC 470-60 and recorded against the carrying value of the New Debt instruments on the Consolidated Balance Sheets and included in financing activities (2) During 2017, cash was used to settle vested RSUs related to the retirement of an executive officer and shares of common stock were used to settle all other vested RSUs and to settle restricted stock. During 2016 and 2015, only common shares were used to settle vested RSUs and Restrict stock.

Commitments

Commitments	12 Months Ended
	Dec. 31, 2017
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, 2017 are as follows: 2018–$1.8 million; 2019–$1.8 million; 2020–$1.8 million; 2021–$1.8 million thereafter–$2.0 million. Total rent expense was approximately $3.0 million, $3.2 million and $3.3 million during 2017, 2016 and 2015, 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, 2017, we had bonds related to the agreement with Total E&P totaling $81.3 million and had no amounts in escrow. The threshold is $88.0 million for 2018, $91.0 million for 2019 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. As of December 31, 2017, 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 2017, 2016 and 2015, we had surety bonds primarily 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 $5.7 million, $4.3 million and $5.5 million during 2017, 2016 and 2015, 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: 2018–$6.2 million; 2019–$6.0 million; 2020–$5.7 million; 2021–$5.3 million; thereafter–$42.4 million. Future surety bond costs may change due to a number of factors, including changes and interpretations of regulations by the BOEM regulations. As of December 31, 2017, 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, 2017, our commitment is $1.5 million for 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, 2017 and our drilling rig commitments meet the criteria of an operating lease. Future payments of all drilling rig commitments as of December 31, 2017 were $5.7 million.

Related Parties

Related Parties	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Related Parties	16. Related Parties During 2017, 2016 and 2015, 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 pursuant to his employment contract. 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 $1.2 million, $1.1 million and $1.1 million for the years 2017, 2016 and 2015, 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. A company that provides marine transportation and logistics services to W&T employs the spouse of our CEO. The rates charged for these marine and transportation services were either equal to or below rates charged by non-related, third-party companies. Payments to such company totaled $22.8 million in 2017. The spouse received commissions partially based on services rendered to W&T which were approximately $0.2 million 2017 and less than $0.2 million for both 2016 and 2015. 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, 2017
Commitments And Contingencies Disclosure [Abstract]
Contingencies	17. Contingencies Supplemental Bonding Requirements by the BOEM The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or provide acceptable financial assurances to satisfy lease obligations, including decommissioning activities on the OCS. As of the filing date of this Form 10-K, the Company is in compliance with its financial assurance obligations to the BOEM and has no outstanding BOEM orders related to assurance obligations. W&T and other offshore Gulf of Mexico producers may in the ordinary course receive future demands for financial assurances from the BOEM as the BOEM continues to reevaluate its requirements for financial assurances. 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. We may be required to post collateral at any time pursuant to the terms of our agreement with various sureties under our existing bonds, if they so demand at their discretion. We did not receive any collateral demands from surety bond providers during 2017. Apache Lawsuit On December 15, 2014, Apache filed a lawsuit against the Company alleging that W&T breached the joint operating agreement related to, among other things, the abandonment of three deepwater wells in the Mississippi Canyon (“MC”) area of the Gulf of Mexico. A trial court judgment was rendered from the U.S. District Court for the Southern District of Texas on May 31, 2017 directing the Company to pay Apache $43.2 million, plus $6.3 million in prejudgment interest, attorney's fees and costs assessed in the judgment. We filed an appeal of the trial court judgment in the U.S. Court of Appeals for the Fifth Circuit. Prior to filing the appeal, in order to stay execution of the judgment, we deposited $49.5 million with the registry of the court in June 2017. The dispute relates to Apache's use of drilling rigs instead of a previously contracted intervention vessel for the plugging and abandonment work. We contended that the costs to use the drilling rigs were unnecessary and unreasonable, and that Apache chose to use the rigs without W&T's consent because they otherwise would have been idle at Apache's expense. We believe the use of the rigs was in bad faith, as found by the jury, and that such conduct caused W&T not to comply with the applicable joint operating agreement, particularly since another vessel had been contracted by Apache for the abandonment a year in advance. We had previously paid $24.9 million to Apache as an undisputed amount for the plug and abandonment work. On October 28, 2016, the jury made the following findings: 1. 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. 2. 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. 3. The $43.2 million referred to in #2 should be offset by $17.0 million. 4. Apache acted in bad faith thereby causing W&T to not comply with the contract. The deposit of $49.5 million with the registry of the court is recorded in Other assets Other liabilities Oil and natural gas properties and other, net Other (income) expense, net 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. On January 27, 2017, the IBLA affirmed the decision of the ONRR requiring W&T to pay approximately $4.7 million in additional royalties. We filed an appeal of the IBLA decision on July 25, 2017 in the U.S. District Court for the Eastern District of Louisiana. 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 that processed our gas. 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 related to a specific processing plant. We also received a preliminary determination notice from the ONRR asserting that our allocation of certain processing costs and plant fuel use at another processing plant was not allowed as deductions in the determination of royalties owed under Federal oil and gas leases. We have submitted revised calculations covering certain plants and time periods to the ONRR. As of the filing date of this Form 10-K, we have not received a response from the ONRR related to our submissions. 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. During 2017 and 2016, we paid $1.6 million and $0.5 million, respectively, of additional royalties and expect to pay more in the future. We are not able to determine the range of any additional royalties or if such amounts would be material. Notices of Proposed Civil Penalty Assessment During 2017 and 2016, we paid $0.2 million and $0.1 million, respectively, of civil penalties to 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 $7.3 million. We have accrued approximately $3.3 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. 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, 2017
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, 2017 Revenues $ 124,393 $ 123,323 $ 110,281 $ 129,099 Operating income 28,196 32,888 15,700 33,166 Net income (loss) 24,299 33,315 (1,297 ) 23,365 Basic and diluted earnings (loss) per common share 0.17 0.23 (0.01 ) 0.16 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 earnings (loss) per common share (1) (2) (2.49 ) (1.58 ) 0.48 0.12 (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. See Note 1 and Note 2 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. During the third quarter of 2016, 60.4 million shares of common stock were issued in conjunction with the Exchange Transaction.

Supplemental Guarantor Informat

Supplemental Guarantor Information	12 Months Ended
	Dec. 31, 2017
Supplemental Guarantor Information [Abstract]
Supplemental Guarantor Information	W&T OFFSHORE, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 19. 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 certain of our 100%-owned subsidiaries, W & T Energy VI and W & T Energy VII, LLC (together, the “Guarantor Subsidiaries”). W & T Energy VII, LLC does not currently have any active operations or 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 Sale provisions (as such capitalized terms are defined in the applicable indenture); (2) in connection with any sale or other disposition of the capital stock of such Guarantor Subsidiary to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary of the Company, if the sale or other disposition does not violate the Asset Sale 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 the applicable indenture) 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. As to the ceiling test write-downs recorded in 2016 and 2015, the computation is performed for each subsidiary on a stand-alone basis and also for the consolidated Company. Due to this methodology, consolidating adjustments are required to present the consolidated results appropriately. Condensed Consolidating Balance Sheet as of December 31, 2017 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Assets Current assets: Cash and cash equivalents $ 99,058 $ — $ — $ 99,058 Receivables: Oil and natural gas sales 5,665 39,778 — 45,443 Joint interest 19,754 — — 19,754 Income taxes 128,835 — (115,829 ) 13,006 Total receivables 154,254 39,778 (115,829 ) 78,203 Prepaid expenses and other assets 11,154 2,265 — 13,419 Total current assets 264,466 42,043 (115,829 ) 190,680 Oil and natural gas properties and other, net - at cost: 430,354 152,464 (3,802 ) 579,016 Restricted deposits for asset retirement obligations 25,394 — — 25,394 Income tax receivables 52,097 — — 52,097 Other assets 505,304 453,306 (898,217 ) 60,393 Total assets $ 1,277,615 $ 647,813 $ (1,017,848 ) $ 907,580 Liabilities and Shareholders’ Equity (Deficit) Current liabilities: Accounts payable $ 76,703 $ 6,962 $ — $ 83,665 Undistributed oil and natural gas proceeds 18,762 1,367 — 20,129 Asset retirement obligations 22,488 1,125 — 23,613 Long-term debt 22,925 — — 22,925 Accrued liabilities 18,058 115,701 (115,829 ) 17,930 Total current liabilities 158,936 125,155 (115,829 ) 168,262 Long-term debt: Principal 889,790 — — 889,790 Carrying value adjustments 79,337 — — 79,337 Long term debt, less current portion - carrying value 969,127 — — 969,127 Asset retirement obligations, less current portion 152,883 123,950 — 276,833 Other liabilities 566,375 — (499,509 ) 66,866 Shareholders’ equity (deficit): Common stock 1 — — 1 Additional paid-in capital 545,820 704,885 (704,885 ) 545,820 Retained earnings (deficit) (1,091,360 ) (306,177 ) 302,375 (1,095,162 ) Treasury stock, at cost (24,167 ) — — (24,167 ) Total shareholders’ equity (deficit) (569,706 ) 398,708 (402,510 ) (573,508 ) Total liabilities and shareholders’ equity (deficit) $ 1,277,615 $ 647,813 $ (1,017,848 ) $ 907,580 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 21,885 — 21,885 Insurance reimbursement 30,100 — — 30,100 Income taxes 111,215 — (99,272 ) 11,943 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 Oil and natural gas properties and other, net 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: Principal 873,733 — — 873,733 Carrying value adjustments 138,722 — — 138,722 Long term debt, less current portion - carrying value 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 Statement of Operations for the Year Ended December 31, 2017 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Revenues $ 231,396 $ 255,700 $ — $ 487,096 Operating costs and expenses: Lease operating expenses 79,695 64,043 — 143,738 Production taxes 1,740 — — 1,740 Gathering and transportation 9,781 10,660 — 20,441 Depreciation, depletion and amortization 73,962 61,700 2,848 138,510 Asset retirement obligations accretion 7,416 9,756 — 17,172 General and administrative expenses 28,170 31,574 — 59,744 Derivative gain (4,199 ) — — (4,199 ) Total costs and expenses 196,565 177,733 2,848 377,146 Operating Income 34,831 77,967 (2,848 ) 109,950 Earnings of affiliates 61,444 — (61,444 ) — Interest expense incurred 45,836 — — 45,836 Gain on exchange of debt 7,811 — — 7,811 Other expense, net 4,812 — — 4,812 Income before income tax expense (benefit) 53,438 77,967 (64,292 ) 67,113 Income tax expense (benefit) (29,092 ) 16,523 — (12,569 ) Net income $ 82,530 $ 61,444 $ (64,292 ) $ 79,682 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, 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 gain (14,375 ) — — (14,375 ) Total costs and expenses 992,722 807,835 (147,589 ) 1,652,968 Operating loss (702,510 ) (590,782 ) 147,589 (1,145,703 ) Loss of affiliates (464,931 ) — 464,931 — Interest expense: Incurred 101,542 3,050 — 104,592 Capitalized (4,206 ) (3,050 ) — (7,256 ) Other expense, net 4,663 — — 4,663 Loss before income tax benefit (1,269,440 ) (590,782 ) 612,520 (1,247,702 ) Income tax benefit (77,133 ) (125,851 ) — (202,984 ) Net loss $ (1,192,307 ) $ (464,931 ) $ 612,520 $ (1,044,718 ) Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2017 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Operating activities: Net income $ 82,530 $ 61,444 $ (64,292 ) $ 79,682 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion, amortization and accretion 81,378 71,456 2,848 155,682 Gain on exchange of debt (7,811 ) — — (7,811 ) Amortization of debt items 1,715 — — 1,715 Share-based compensation 7,191 — — 7,191 Derivative gain (4,199 ) — — (4,199 ) Cash receipts on derivative settlements, net 4,199 — — 4,199 Deferred income taxes 217 — — 217 Loss of affiliates (61,444 ) — 61,444 — Changes in operating assets and liabilities: Oil and natural gas receivables (3,491 ) 1,121 — (2,370 ) Joint interest receivables 2,131 — — 2,131 Insurance reimbursements 31,740 — — 31,740 Income taxes (17,586 ) 16,523 — (1,063 ) Prepaid expenses and other assets 3,447 (108,773 ) 108,564 3,238 Escrow deposit - Apache lawsuit (49,500 ) — — (49,500 ) Asset retirement obligation settlements (55,672 ) (16,737 ) — (72,409 ) Accounts payable, accrued liabilities and other 127,496 (7,967 ) (108,564 ) 10,965 Net cash provided by operating activities 142,341 17,067 — 159,408 Investing activities: Investment in oil and natural gas properties and equipment (105,179 ) (24,869 ) — (130,048 ) Changes in operating assets and liabilities associated with investing activities 16,072 7,802 — 23,874 Purchases of furniture, fixtures and other (933 ) — — (933 ) Net cash used in investing activities (90,040 ) (17,067 ) — (107,107 ) Financing activities: Payment of interest on 1.5 Lien Term Loan (8,227 ) — — (8,227 ) Payment of interest on 2nd Lien PIK Toggle Notes (7,335 ) — — (7,335 ) Payment of interest on 3rd Lien PIK Toggle Notes (6,201 ) — — (6,201 ) Debt exchange costs (421 ) — — (421 ) Other (1,295 ) — — (1,295 ) Net cash used in financing activities (23,479 ) — — (23,479 ) Increase in cash and cash equivalents 28,822 — — 28,822 Cash and cash equivalents, beginning of period 70,236 — — 70,236 Cash and cash equivalents, end of period $ 99,058 $ — $ — $ 99,058 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 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-down/amortization of debt items 2,548 — — 2,548 Share-based compensation 11,013 — — 11,013 Derivative gain 2,926 — — 2,926 Cash payments on derivative settlements 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 receivables 12 — — 12 Income taxes (64,274 ) — — (64,274 ) Prepaid expenses and other assets (14,395 ) (78,547 ) 77,996 (14,946 ) Asset retirement obligations (49,303 ) (23,017 ) — (72,320 ) Accounts payable, accrued liabilities and other 45,817 37,538 (77,996 ) 5,359 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, 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 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 Debt issuance costs write-down/amortization of debt items 4,411 — — 4,411 Share-based compensation 10,242 — — 10,242 Derivative loss (14,375 ) — — (14,375 ) Cash payments on derivative settlements 6,703 — — 6,703 Deferred income taxes (77,421 ) (125,851 ) — (203,272 ) Earnings 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 receivables 21,645 — — 21,645 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 (141,608 ) 4,156 91,245 (46,207 ) 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, 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

Supplemental Oil and Gas Disclo

Supplemental Oil and Gas Disclosures-unaudited	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Supplemental Oil and Gas Disclosures-UNAUDITED	20. 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, 2017 2016 2015 Net capitalized cost: Proved oil and natural gas properties and equipment $ 8,102.0 $ 7,932.5 $ 7,882.3 Unproved oil and natural gas properties and equipment — — 20.2 Accumulated depreciation, depletion and amortization (1) related to oil, NGLs and natural gas activities (7,525.0 ) (7,387.8 ) (6,916.2 ) Net capitalized costs related to producing activities $ 577.0 $ 544.7 $ 986.3 (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, 2017 2016 2015 Costs incurred: (1) Proved properties acquisitions $ 1.1 $ 1.3 $ 15.6 Exploration (2) (3) 62.0 4.8 152.4 Development 92.5 56.9 65.5 Unproved properties acquisitions — 0.5 0.1 Total costs incurred in oil and gas property acquisition, exploration and development activities $ 155.6 $ 63.5 $ 233.6 (1) Includes net additions from capitalized ARO of $21.3 million in 2017, net additions from capitalized ARO of $10.8 million in 2016, and net reductions from capitalized ARO of $0.4 million during 2015. These adjustments for ARO are associated with acquisitions, liabilities incurred, divestitures and revisions of estimates. (2) Includes seismic costs of $0.5 million, $0.2 million and $3.2 million incurred during 2017, 2016 and 2015, respectively. (3) Includes geological and geophysical costs charged to expense of $4.2 million, $4.1 million and $5.7 million during 2017, 2016 and 2015, respectively. 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, 2017 2016 2015 Depreciation, depletion, amortization and accretion per Boe $ 10.68 $ 13.77 $ 23.11 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 25% of our proved developed non-producing reserves as of December 31, 2017 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, 2017. 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, 2014 61.7 15.8 254.9 120.0 720.0 Revisions of previous estimates (2) 4.8 (0.9 ) 4.9 4.7 28.0 Revisions related to sold properties (3) (12.1 ) (4.8 ) (2.9 ) (17.4 ) (104.3 ) Extensions and discoveries (4) 2.4 0.2 8.8 4.1 24.4 Purchase of minerals in place (5) — — 6.1 1.0 6.1 Sales of reserves (6) (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 (7) 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 Revisions of previous estimates (8) 4.5 0.7 25.8 9.6 57.4 Extensions and discoveries (9) 4.1 0.3 5.4 5.2 31.3 Production (7.1 ) (1.4 ) (36.8 ) (14.6 ) (87.4 ) Proved reserves as of Dec. 31, 2017 34.4 7.8 192.2 74.2 445.3 Year-end proved developed reserves: 2017 26.1 7.2 173.5 62.2 373.3 2016 26.6 7.6 183.1 64.7 388.2 2015 29.4 6.4 198.5 69.0 413.5 Year-end proved undeveloped reserves: 2017 (10) 8.3 0.6 18.7 12.0 72.0 2016 6.3 0.6 14.7 9.3 55.8 2015 6.1 0.2 6.9 7.4 44.6 Volume measurements: 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 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) 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. (4) Primarily due to increases at our Ewing Bank 910 field. (5) Primarily due to purchase of additional interest at our Brazos A-133 field. (6) 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. (7) 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. (8) Primarily related to upward revisions of 6.2 MMBoe, which included upwards revisions of 1.1 MMBoe at our Mississippi Canyon 698 (Big Bend) field, 1.0 MMBoe at our Fairway field, 0.8 MMBoe at our Ewing Bank 910 field and 0.8 MMBoe at our Viosca Knoll 783 (Virgo) field. Additionally, increases of 3.4 MMBoe were due to price revisions. (9) Primarily related to extensions and discoveries at our Ship Shoal 349 (Mahogany) field of 3.5 MMBoe and at our Main Pass 286 field of 1.5 MMBoe. (10) We believe that we will be able to develop all but 1.8 MMBoe (approximately 15%) of the total of 12.0 MMBoe reserves classified as proved undeveloped (“PUDs”) at December 31, 2017, within five years from the date such reserves were initially recorded. The lone exceptions are 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. Two sidetrack PUD locations in this field will be delayed until an existing well is depleted and available to sidetrack. Based on the latest reserve report, these PUD locations are expected to be developed 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, 2017 2016 2015 2014 Oil - per barrel $ 46.58 $ 36.28 $ 46.94 $ 91.12 NGLs per barrel 22.65 16.82 17.60 34.63 Natural gas per Mcf 2.86 2.47 2.50 4.27 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 2017 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, 2017 2016 2015 Standardized Measure of Discounted Future Net Cash Flows Future cash inflows $ 2,328.8 $ 1,818.4 $ 2,296.7 Future costs: Production (813.8 ) (691.5 ) (840.1 ) Development (157.4 ) (141.1 ) (161.4 ) Dismantlement and abandonment (361.9 ) (427.7 ) (471.8 ) Income taxes (1) (74.8 ) — — Future net cash inflows before 10% discount 920.9 558.1 823.4 10% annual discount factor (180.3 ) (79.8 ) (209.5 ) Total $ 740.6 $ 478.3 $ 613.9 (1) No future income taxes were estimated for 2016 and 2015 as our tax position had 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, 2017 2016 2015 Changes in Standardized Measure Standardized measure, beginning of year $ 478.3 $ 613.9 $ 1,702.8 Increases (decreases): Sales and transfers of oil and gas produced, net of production costs (315.3 ) (218.6 ) (289.1 ) Net changes in price, net of future production costs 288.0 (275.2 ) (1,455.6 ) Extensions and discoveries, net of future production and development costs 119.3 — 65.3 Changes in estimated future development costs (38.9 ) (32.5 ) (8.5 ) Previously estimated development costs incurred 102.8 114.5 158.9 Revisions of quantity estimates 106.4 190.1 137.9 Accretion of discount 30.2 52.6 150.6 Net change in income taxes (54.7 ) — 600.8 Purchases of reserves in-place — — 6.0 Sales of reserves in-place — — (401.4 ) Changes in production rates due to timing and other 24.5 33.5 (53.8 ) Net increase (decrease) in standardized measure 262.3 (135.6 ) (1,088.9 ) Standardized measure, end of year $ 740.6 $ 478.3 $ 613.9

Significant Accounting Polici27

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
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 with substantially all of its operations 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.
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, proved reserves and future rate of growth. The average realized prices of these commodities improved in 2017 compared to the average realized prices in 2016. Operating costs were lower for 2017 on an absolute and on a per barrel oil equivalent (“Boe”) basis compared to the operating costs for 2016. In September 2016, we consummated the Exchange Transaction, as defined and described below in Note 2, which reduced our interest payments for 2017 as compared to 2016. In addition, the Exchange Transaction extended the maturities on a portion of our debt, although for a portion of the New Debt, as defined and described in Note 2, the maturities of two of the new loans will accelerate if certain events do not transpire. We have continued working to further reduce our operating costs, capital expenditures and costs related to asset retirement obligations (“ARO”). Our capital expenditures incurred in 2017 were higher than the capital expenditures incurred during 2016, but were significantly lower than spending levels incurred during 2015 and prior years. Our current capital expenditure budget for 2018 is approximately the same level as incurred in 2017. As of the filing date of this Form 10-K, the Company is in compliance with its financial assurance obligations to the Bureau of Ocean Energy Management (“BOEM”) and has no outstanding BOEM orders related to financial assurance obligations. During the second quarter of 2017, a trial court judgment was rendered in Apache Corporation’s (“Apache”) lawsuit against us. As a result, we deposited $49.5 million with the registry of the court from cash on hand as a first step to allow us to appeal the decision. See Note 17 for additional information. We have assessed our financial condition, the current capital markets and options given different scenarios of commodity prices. We believe we will have adequate liquidity to fund our operations through March 2019, the period of assessment to qualify as a going concern. We are evaluating various alternatives and believe our plans can be executed in the current market and are within our capabilities. Our plans address the possible maturity acceleration of certain debt instruments, which could accelerate to February 28, 2019 if certain events were not to occur, and address events needed to extend our Credit Agreement, which matures on November 8, 2018. However, we cannot predict the potential changes in commodity prices or future bonding requirements, either of which could affect our operations, liquidity levels and compliance with debt obligations.
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, 2017 and 2016, $4.7 million and $5.3 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, large financial institutions and large trading houses. The majority of our production is sold utilizing month-to-month contracts that are based on bid prices. 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 guarantees when considered necessary. The following table 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, 2017 2016 2015 Customer Shell Trading (US) Co. 46 % 43 % 50 % Vitol Inc. 15 % 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. Accounts Receivables and Allowance for Bad Debts Our accounts receivables are recorded at their historical cost, less an allowance for doubtful accounts. The carrying value approximates fair value because of the short-term nature of such accounts. In addition to receivables from sales of our production to our customers, we also have receivables from joint interest owners on properties we operate. In certain arrangements, we have the ability to withhold future revenue disbursements to recover amounts due us from the joint interest partners. We have not had any significant problems collecting our receivables from our customers, but with the decline in commodity prices starting in 2015, several oil and gas companies have filed for bankruptcy where we have joint interest arrangements. We use the specific identification method of determining if an allowance for doubtful accounts is needed. The following table describes the balance and changes to the allowance for doubtful accounts: 2017 2016 2015 Allowance for doubtful accounts, beginning of period $ 7,602 $ 2,490 $ 704 Additional provisions for the year 1,512 5,112 1,786 Uncollectable accounts written off — — — Allowance for doubtful accounts, end of period $ 9,114 $ 7,602 $ 2,490
Insurance Receivables	Insurance Receivables We recognize insurance receivables with respect to capital, repair and plugging and abandonment costs primarily as a result of hurricane damage when we deem those to be probable of collection, which normally 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. During 2017, we received payments by certain insurance companies related to settlement of previously unpaid claims. See Note 5 for additional information.
Prepaid Expenses and Other	Prepaid expenses and other Amounts recorded in Prepaid expenses and other Year Ended December 31, 2017 2016 Prepaid/accrued insurance $ 2,401 $ 2,924 Surety bonds unamortized premiums 2,676 2,462 Prepaid deposits related to royalties 6,456 6,237 Other 1,886 2,881 Prepaid expenses and other $ 13,419 $ 14,504
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 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. Oil and natural gas properties and equipment are recorded at cost using the full cost method. Oil and Natural Gas Properties and Other, Net – at cost Oil and natural gas properties and equipment are recorded at cost using the full cost method. There were no amounts excluded from amortization as of the dates presented in the following table (in thousands): December 31, 2017 2016 Oil and natural gas properties and equipment $ 8,102,044 $ 7,932,504 Furniture, fixtures and other 21,831 20,898 Total property and equipment 8,123,875 7,953,402 Less accumulated depreciation, depletion and amortization 7,544,859 7,406,349 Oil and natural gas properties and other, net $ 579,016 $ 547,053
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. We did not record a ceiling test write-down during 2017. We recorded ceiling test write-downs in 2016 and 2015, which are reported as a separate line in the Statements of Operations, due primarily to declines in the unweighted rolling 12-month average of first-day-of-the-month commodity prices for oil and natural gas. 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. If average crude oil and natural gas prices decrease from 2016 levels, it is possible that ceiling test write-downs could be recorded during 2018 or future periods.
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. From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas. When we have outstanding borrowings on our revolving bank credit facility, we may use various derivative financial instruments to manage our exposure to interest rate risk from floating interest rates. During 2017, no borrowings were outstanding on our revolving bank credit facility. We do not enter into derivative instruments for speculative trading purposes. We entered into commodity derivatives contracts during 2017, which were settled or expired during 2017. As of December 31, 2017 and 2016, we did not have any open derivative financial instruments. 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 of the debt’s superior collateral ranking amongst our various debt instruments even though such debt was not traded.
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
Other Assets (Long-term)	Other Assets (long-term) The major categories recorded in Other assets December 31, 2017 2016 Escrow deposit - Apache lawsuit $ 49,500 $ — Appeal bond deposits 6,925 6,925 Investment in White Cap, LLC 2,511 2,520 Other 1,457 2,019 Total other assets $ 60,393 $ 11,464
Accrued Liabilities	Accrued Liabilities The major categories recorded in Accrued liabilities are presented in the following table (in thousands): December 31, 2017 2016 Accrued interest $ 4,200 $ 4,189 Accrued salaries/payroll taxes/benefits 2,454 2,777 Incentive compensation plans 7,366 — Litigation accruals 3,480 1,891 Other 430 343 Total accrued liabilities $ 17,930 $ 9,200
Troubled Debt Restructuring	Troubled Debt Restructuring We accounted for a debt exchange transaction in 2016, 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
Other Liabilities (Long-term)	Other Liabilities (long-term) The major categories recorded in Other liabilities December 31, 2017 2016 Apache lawsuit $ 49,500 $ — Uncertain tax positions including interest/penalties 11,015 10,584 Other 6,351 6,521 Total other liabilities (long-term) $ 66,866 $ 17,105
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.
Earnings (Loss) Per Share	Earnings (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 earnings (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 2017, the amount consists primarily of expense items related to the Apache lawsuit of $6.3 million, partially offset by loss-of-use reimbursements from a third-party for damages incurred at one of our platforms of $1.1 million. 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”), Revenue from Contracts and Customers Topic 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 In August 2017, the FASB issued Accounting Standards Update No. 2017-12, (“ASU 2017-12”), Derivatives and Hedging (Topic 815) – Targeted Improvements to Accounting for Hedging Activities

Significant Accounting Polici28

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Percentage of Revenue by Major Customers	The following table 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, 2017 2016 2015 Customer Shell Trading (US) Co. 46 % 43 % 50 % Vitol Inc. 15 % 20 % ** J. P. Morgan ** ** 14 % ** Less than 10%
Schedule of Changes to Allowance for Doubtful Accounts	The following table describes the balance and changes to the allowance for doubtful accounts: 2017 2016 2015 Allowance for doubtful accounts, beginning of period $ 7,602 $ 2,490 $ 704 Additional provisions for the year 1,512 5,112 1,786 Uncollectable accounts written off — — — Allowance for doubtful accounts, end of period $ 9,114 $ 7,602 $ 2,490
Schedule of Amounts Recorded in Prepaid Expenses and Other	Amounts recorded in Prepaid expenses and other Year Ended December 31, 2017 2016 Prepaid/accrued insurance $ 2,401 $ 2,924 Surety bonds unamortized premiums 2,676 2,462 Prepaid deposits related to royalties 6,456 6,237 Other 1,886 2,881 Prepaid expenses and other $ 13,419 $ 14,504
Schedule of Oil and Natural Gas Properties and Other, Net at Cost	Oil and natural gas properties and equipment are recorded at cost using the full cost method. There were no amounts excluded from amortization as of the dates presented in the following table (in thousands): December 31, 2017 2016 Oil and natural gas properties and equipment $ 8,102,044 $ 7,932,504 Furniture, fixtures and other 21,831 20,898 Total property and equipment 8,123,875 7,953,402 Less accumulated depreciation, depletion and amortization 7,544,859 7,406,349 Oil and natural gas properties and other, net $ 579,016 $ 547,053
Schedule of Other Assets (Long-term)	The major categories recorded in Other assets December 31, 2017 2016 Escrow deposit - Apache lawsuit $ 49,500 $ — Appeal bond deposits 6,925 6,925 Investment in White Cap, LLC 2,511 2,520 Other 1,457 2,019 Total other assets $ 60,393 $ 11,464
Schedule of Accrued Liabilities	The major categories recorded in Accrued liabilities December 31, 2017 2016 Accrued interest $ 4,200 $ 4,189 Accrued salaries/payroll taxes/benefits 2,454 2,777 Incentive compensation plans 7,366 — Litigation accruals 3,480 1,891 Other 430 343 Total accrued liabilities $ 17,930 $ 9,200
Schedule of Other Liabilities (Long-term)	The major categories recorded in Other liabilities December 31, 2017 2016 Apache lawsuit $ 49,500 $ — Uncertain tax positions including interest/penalties 11,015 10,584 Other 6,351 6,521 Total other liabilities (long-term) $ 66,866 $ 17,105

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Long-Term Debt	The components of our long-term debt are presented in the following tables (in thousands): December 31, 2017 December 31, 2016 Adjustments to Adjustments to Carrying Carrying Carrying Carrying Principal Value (1) Value Principal Value (1) Value 11.00% 1.5 Lien Term Loan, due November 2019: Principal $ 75,000 $ — $ 75,000 $ 75,000 $ — $ 75,000 Future interest payments — 15,596 15,596 — 23,823 23,823 Subtotal 75,000 15,596 90,596 75,000 23,823 98,823 9.00 % Second Lien Term Loan, due May 2020: 300,000 — 300,000 300,000 — 300,000 9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020: Principal 171,769 — 171,769 163,007 — 163,007 Future payments-in-kind — 5,745 5,745 — 24,048 24,048 Future interest payments — 34,872 34,872 — 36,850 36,850 Subtotal 171,769 40,617 212,386 163,007 60,898 223,905 8.50%/10.00% Third Lien PIK Toggle Notes, due June 2021: Principal 153,192 — 153,192 145,897 — 145,897 Future payments-in-kind — 11,323 11,323 — 26,844 26,844 Future interest payments — 38,682 38,682 — 40,705 40,705 Subtotal 153,192 50,005 203,197 145,897 67,549 213,446 8.50% Unsecured Senior Notes, due June 2019 189,829 — 189,829 189,829 — 189,829 Debt premium, discount, issuance costs, net of amortization — (3,956 ) (3,956 ) — (5,276 ) (5,276 ) Total long-term debt 889,790 102,262 992,052 873,733 146,994 1,020,727 Current maturities of long-term debt (2) — 22,925 22,925 — 8,272 8,272 Long term debt, less current maturities $ 889,790 $ 79,337 $ 969,127 $ 873,733 $ 138,722 $ 1,012,455 (1) Future interest payments and future payments-in-kind (“PIK”) are recorded on an undiscounted basis. (2) Future interest payments on the 1.5 Lien Term Loan, Second Lien PIK Toggle Notes and Third Lien PIK Toggle Notes due within twelve months.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
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 2017 2016 11.00% 1.5 Lien Term Loan, due November 2019 Level 2 $ 75,000 $ 75,000 9.00 % Second Lien Term Loan, due May 2020 Level 2 288,000 255,000 9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020 Level 2 162,322 122,255 8.50%/10.00% Third Lien PIK Toggle Notes due June 2021 Level 2 119,490 80,243 8.50% Unsecured Senior Notes, due June 2019 Level 2 178,439 123,389

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Reconciliation of Asset Retirement Obligations Liability	The following table is a reconciliation of our ARO liability (in thousands): Year Ended December 31, 2017 2016 Asset retirement obligations, beginning of period $ 334,438 $ 378,322 Liabilities settled (72,409 ) (72,320 ) Accretion of discount 17,172 17,571 Liabilities incurred 163 398 Revisions of estimated liabilities 21,082 10,467 Asset retirement obligations, end of period 300,446 334,438 Less current portion 23,613 78,264 Long-term $ 276,833 $ 256,174

Derivative Financial Instrume32

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Estimated Fair Value of Derivative Contracts
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, 2017 2016 2015 Derivative (gain) loss $ (4,199 ) $ 2,926 $ (14,375 )
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, 2017 2016 2015 Cash receipts on derivative settlements, net $ 4,199 $ 4,746 $ 6,703

Share-Based Awards and Cash-B33

Share-Based Awards and Cash-Based Awards (Tables)	12 Months Ended
	Dec. 31, 2017
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: 2017 2016 2015 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 6,107,248 $ 2.73 3,474,079 $ 7.42 1,977,335 $ 15.29 Granted 2,128,879 2.76 4,213,964 2.21 2,626,930 3.59 Vested (2,108,553 ) 3.45 (968,652 ) 16.69 (721,038 ) 13.23 Forfeited (362,323 ) 2.87 (612,143 ) 3.64 (409,148 ) 10.63 Nonvested, end of period 5,765,251 $ 2.48 6,107,248 $ 2.73 3,474,079 $ 7.42
Schedule of Restricted Stock Units Outstanding	Subject to the satisfaction of service conditions, the RSUs outstanding as of December 31, 2017 are eligible to vest in the year indicated in the table below: Restricted Stock Units 2018 3,742,509 2019 2,022,742 Total 5,765,251
Schedule of Restricted Stock Activity	A summary of activity related to Restricted Shares is as follows: 2017 2016 2015 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 161,296 $ 3.47 78,230 $ 8.95 43,210 $ 16.20 Granted 147,372 1.90 126,128 2.22 56,540 6.19 Vested (62,140 ) 4.51 (43,062 ) 9.75 (21,520 ) 16.26 Nonvested, end of period 246,528 $ 2.27 161,296 $ 3.47 78,230 $ 8.95
Schedule of Restricted Stock Awards Outstanding	Subject to the satisfaction of service conditions, the Restricted Shares outstanding as of December 31, 2017 are expected to vest as follows: Restricted Shares 2018 106,240 2019 91,164 2020 49,124 Total 246,528
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, 2017 2016 2015 Share-based compensation expense from: Restricted stock units $ 7,785 $ 10,640 $ 9,978 Restricted stock 280 373 358 Common shares — — (94 ) Total $ 8,065 $ 11,013 $ 10,242 Share-based compensation tax benefit: Tax benefit computed at the statutory rate $ 1,694 $ 3,855 $ 3,585
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, 2017 2016 2015 Share-based compensation included in: General and administrative $ 8,065 $ 11,013 $ 10,242 Cash-based incentive compensation included in: Lease operating expense 2,101 — 364 General and administrative (1) 5,032 — (233 ) Total charged to operating income $ 15,198 $ 11,013 $ 10,373 (1) Adjustments to true up estimates to actual payments resulted in net credit balances to expense in 2015 .

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 2015 Current $ (12,786 ) $ (71,768 ) $ 288 Deferred 217 28,392 (203,272 ) Total income tax (benefit) $ (12,569 ) $ (43,376 ) $ (202,984 )
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, 2017 2016 2015 Income tax (benefit) at the federal statutory rate $ 23,490 35.0 % $ (102,339 ) 35.0 % $ (436,696 ) 35.0 % Share-based compensation 664 1.0 4,920 (1.7 ) 2,940 (0.2 ) State income taxes 63 0.1 (755 ) 0.2 (2,343 ) 0.2 Debt restructuring cost 18 — 1,463 (0.5 ) — — Change in statutory federal tax rate 105,933 157.8 — — — — Gain on exchange of debt (24,981 ) (37.2 ) — — — — Valuation allowance (118,643 ) (176.8 ) 52,915 (18.1 ) 232,925 (18.7 ) Other 887 1.4 420 (0.1 ) 190 — Total income tax (benefit) $ (12,569 ) (18.7 %) $ (43,376 ) 14.8 % $ (202,984 ) 16.3 %
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, 2017 2016 Deferred tax liabilities: Other $ 695 $ 1,423 Total deferred tax liabilities 695 1,423 Deferred tax assets: Property and equipment 18,234 42,385 Asset retirement obligations 63,755 117,588 Federal net operating losses 18,988 — State net operating losses 7,126 5,615 Exchange transaction 55,807 118,467 Share-based compensation 1,335 2,353 Valuation allowance (171,547 ) (290,190 ) Other 6,805 4,798 Total deferred tax assets 503 1,016 Net deferred tax assets (liabilities) $ (192 ) $ (407 )
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, 2017 (in thousands): Amount Expiration Year Federal net operating loss $ 18,988 2037 State net operating losses 118,027 2025-2036
Balances in Uncertain Tax Positions	Balances in the uncertain tax positions are as follows (in thousands): December 31, 2017 2016 Balance, beginning and end of period $ 9,482 $ 9,482

Earnings_ (Loss) Per Share (Tab

Earnings/ (Loss) Per Share (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Schedule of Calculation of Basic and Diluted Earnings (Loss) Per Common Share	The following table presents the calculation of basic and diluted earnings (loss) per common share (in thousands, except per share amounts): Year Ended December 31, 2017 2016 2015 Net income (loss) $ 79,682 $ (249,020 ) $ (1,044,718 ) Less portion allocated to nonvested shares 3,244 — — Net income (loss) allocated to common shares $ 76,438 $ (249,020 ) $ (1,044,718 ) Weighted average common shares outstanding 137,617 95,644 75,931 Basic and diluted earnings (loss) per common share $ 0.56 $ (2.60 ) $ (13.76 ) Shares excluded due to being anti-dilutive (weighted-average) — 5,269 2,195

Supplemental Cash Flow Inform36

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2017
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	The following table reflects our supplemental cash flow information (in thousands): Year Ended December 31, 2017 2016 2015 Supplemental cash items: Cash paid for interest, net of interest capitalized of $0 in 2017, $520 in 2016 and $7,256 in 2015 (1) $ 65,873 $ 96,501 $ 92,622 Cash paid for income taxes 185 310 390 Cash refunds received for income taxes 11,906 7,796 90 Cash paid for share-based compensation (2) 874 — — Non-cash investing activities: Accruals of property and equipment 33,003 9,129 44,324 ARO - additions, dispositions and revisions, net 21,245 10,865 (394 ) 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) During 2017 and 2016, cash paid for interest included amounts related to the New Debt, which are accounted for under ASC 470-60 and recorded against the carrying value of the New Debt instruments on the Consolidated Balance Sheets and included in financing activities (2) During 2017, cash was used to settle vested RSUs related to the retirement of an executive officer and shares of common stock were used to settle all other vested RSUs and to settle restricted stock. During 2016 and 2015, only common shares were used to settle vested RSUs and Restrict stock.

Selected Quarterly Financial 37

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 Revenues $ 124,393 $ 123,323 $ 110,281 $ 129,099 Operating income 28,196 32,888 15,700 33,166 Net income (loss) 24,299 33,315 (1,297 ) 23,365 Basic and diluted earnings (loss) per common share 0.17 0.23 (0.01 ) 0.16 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 earnings (loss) per common share (1) (2) (2.49 ) (1.58 ) 0.48 0.12 (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. See Note 1 and Note 2 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. During the third quarter of 2016, 60.4 million shares of common stock were issued in conjunction with the Exchange Transaction.

Supplemental Guarantor Inform38

Supplemental Guarantor Information (Tables)	12 Months Ended
	Dec. 31, 2017
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. As to the ceiling test write-downs recorded in 2016 and 2015, the computation is performed for each subsidiary on a stand-alone basis and also for the consolidated Company. Due to this methodology, consolidating adjustments are required to present the consolidated results appropriately. Condensed Consolidating Balance Sheet as of December 31, 2017 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Assets Current assets: Cash and cash equivalents $ 99,058 $ — $ — $ 99,058 Receivables: Oil and natural gas sales 5,665 39,778 — 45,443 Joint interest 19,754 — — 19,754 Income taxes 128,835 — (115,829 ) 13,006 Total receivables 154,254 39,778 (115,829 ) 78,203 Prepaid expenses and other assets 11,154 2,265 — 13,419 Total current assets 264,466 42,043 (115,829 ) 190,680 Oil and natural gas properties and other, net - at cost: 430,354 152,464 (3,802 ) 579,016 Restricted deposits for asset retirement obligations 25,394 — — 25,394 Income tax receivables 52,097 — — 52,097 Other assets 505,304 453,306 (898,217 ) 60,393 Total assets $ 1,277,615 $ 647,813 $ (1,017,848 ) $ 907,580 Liabilities and Shareholders’ Equity (Deficit) Current liabilities: Accounts payable $ 76,703 $ 6,962 $ — $ 83,665 Undistributed oil and natural gas proceeds 18,762 1,367 — 20,129 Asset retirement obligations 22,488 1,125 — 23,613 Long-term debt 22,925 — — 22,925 Accrued liabilities 18,058 115,701 (115,829 ) 17,930 Total current liabilities 158,936 125,155 (115,829 ) 168,262 Long-term debt: Principal 889,790 — — 889,790 Carrying value adjustments 79,337 — — 79,337 Long term debt, less current portion - carrying value 969,127 — — 969,127 Asset retirement obligations, less current portion 152,883 123,950 — 276,833 Other liabilities 566,375 — (499,509 ) 66,866 Shareholders’ equity (deficit): Common stock 1 — — 1 Additional paid-in capital 545,820 704,885 (704,885 ) 545,820 Retained earnings (deficit) (1,091,360 ) (306,177 ) 302,375 (1,095,162 ) Treasury stock, at cost (24,167 ) — — (24,167 ) Total shareholders’ equity (deficit) (569,706 ) 398,708 (402,510 ) (573,508 ) Total liabilities and shareholders’ equity (deficit) $ 1,277,615 $ 647,813 $ (1,017,848 ) $ 907,580 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 21,885 — 21,885 Insurance reimbursement 30,100 — — 30,100 Income taxes 111,215 — (99,272 ) 11,943 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 Oil and natural gas properties and other, net 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: Principal 873,733 — — 873,733 Carrying value adjustments 138,722 — — 138,722 Long term debt, less current portion - carrying value 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 Statement of Operations	Condensed Consolidating Statement of Operations for the Year Ended December 31, 2017 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Revenues $ 231,396 $ 255,700 $ — $ 487,096 Operating costs and expenses: Lease operating expenses 79,695 64,043 — 143,738 Production taxes 1,740 — — 1,740 Gathering and transportation 9,781 10,660 — 20,441 Depreciation, depletion and amortization 73,962 61,700 2,848 138,510 Asset retirement obligations accretion 7,416 9,756 — 17,172 General and administrative expenses 28,170 31,574 — 59,744 Derivative gain (4,199 ) — — (4,199 ) Total costs and expenses 196,565 177,733 2,848 377,146 Operating Income 34,831 77,967 (2,848 ) 109,950 Earnings of affiliates 61,444 — (61,444 ) — Interest expense incurred 45,836 — — 45,836 Gain on exchange of debt 7,811 — — 7,811 Other expense, net 4,812 — — 4,812 Income before income tax expense (benefit) 53,438 77,967 (64,292 ) 67,113 Income tax expense (benefit) (29,092 ) 16,523 — (12,569 ) Net income $ 82,530 $ 61,444 $ (64,292 ) $ 79,682 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, 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 gain (14,375 ) — — (14,375 ) Total costs and expenses 992,722 807,835 (147,589 ) 1,652,968 Operating loss (702,510 ) (590,782 ) 147,589 (1,145,703 ) Loss of affiliates (464,931 ) — 464,931 — Interest expense: Incurred 101,542 3,050 — 104,592 Capitalized (4,206 ) (3,050 ) — (7,256 ) Other expense, net 4,663 — — 4,663 Loss before income tax benefit (1,269,440 ) (590,782 ) 612,520 (1,247,702 ) Income tax benefit (77,133 ) (125,851 ) — (202,984 ) Net loss $ (1,192,307 ) $ (464,931 ) $ 612,520 $ (1,044,718 )
Condensed Consolidating Statement of Cash Flows	Condensed Consolidating Statement of Cash Flows for the Year Ended December 31, 2017 (In thousands) Consolidated Parent Guarantor W&T Company Subsidiaries Eliminations Offshore, Inc. Operating activities: Net income $ 82,530 $ 61,444 $ (64,292 ) $ 79,682 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion, amortization and accretion 81,378 71,456 2,848 155,682 Gain on exchange of debt (7,811 ) — — (7,811 ) Amortization of debt items 1,715 — — 1,715 Share-based compensation 7,191 — — 7,191 Derivative gain (4,199 ) — — (4,199 ) Cash receipts on derivative settlements, net 4,199 — — 4,199 Deferred income taxes 217 — — 217 Loss of affiliates (61,444 ) — 61,444 — Changes in operating assets and liabilities: Oil and natural gas receivables (3,491 ) 1,121 — (2,370 ) Joint interest receivables 2,131 — — 2,131 Insurance reimbursements 31,740 — — 31,740 Income taxes (17,586 ) 16,523 — (1,063 ) Prepaid expenses and other assets 3,447 (108,773 ) 108,564 3,238 Escrow deposit - Apache lawsuit (49,500 ) — — (49,500 ) Asset retirement obligation settlements (55,672 ) (16,737 ) — (72,409 ) Accounts payable, accrued liabilities and other 127,496 (7,967 ) (108,564 ) 10,965 Net cash provided by operating activities 142,341 17,067 — 159,408 Investing activities: Investment in oil and natural gas properties and equipment (105,179 ) (24,869 ) — (130,048 ) Changes in operating assets and liabilities associated with investing activities 16,072 7,802 — 23,874 Purchases of furniture, fixtures and other (933 ) — — (933 ) Net cash used in investing activities (90,040 ) (17,067 ) — (107,107 ) Financing activities: Payment of interest on 1.5 Lien Term Loan (8,227 ) — — (8,227 ) Payment of interest on 2nd Lien PIK Toggle Notes (7,335 ) — — (7,335 ) Payment of interest on 3rd Lien PIK Toggle Notes (6,201 ) — — (6,201 ) Debt exchange costs (421 ) — — (421 ) Other (1,295 ) — — (1,295 ) Net cash used in financing activities (23,479 ) — — (23,479 ) Increase in cash and cash equivalents 28,822 — — 28,822 Cash and cash equivalents, beginning of period 70,236 — — 70,236 Cash and cash equivalents, end of period $ 99,058 $ — $ — $ 99,058 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 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-down/amortization of debt items 2,548 — — 2,548 Share-based compensation 11,013 — — 11,013 Derivative gain 2,926 — — 2,926 Cash payments on derivative settlements 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 receivables 12 — — 12 Income taxes (64,274 ) — — (64,274 ) Prepaid expenses and other assets (14,395 ) (78,547 ) 77,996 (14,946 ) Asset retirement obligations (49,303 ) (23,017 ) — (72,320 ) Accounts payable, accrued liabilities and other 45,817 37,538 (77,996 ) 5,359 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, 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 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 Debt issuance costs write-down/amortization of debt items 4,411 — — 4,411 Share-based compensation 10,242 — — 10,242 Derivative loss (14,375 ) — — (14,375 ) Cash payments on derivative settlements 6,703 — — 6,703 Deferred income taxes (77,421 ) (125,851 ) — (203,272 ) Earnings 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 receivables 21,645 — — 21,645 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 (141,608 ) 4,156 91,245 (46,207 ) 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, 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

Supplemental Oil and Gas Disc39

Supplemental Oil and Gas Disclosures-unaudited (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 2015 Net capitalized cost: Proved oil and natural gas properties and equipment $ 8,102.0 $ 7,932.5 $ 7,882.3 Unproved oil and natural gas properties and equipment — — 20.2 Accumulated depreciation, depletion and amortization (1) related to oil, NGLs and natural gas activities (7,525.0 ) (7,387.8 ) (6,916.2 ) Net capitalized costs related to producing activities $ 577.0 $ 544.7 $ 986.3 (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, 2017 2016 2015 Costs incurred: (1) Proved properties acquisitions $ 1.1 $ 1.3 $ 15.6 Exploration (2) (3) 62.0 4.8 152.4 Development 92.5 56.9 65.5 Unproved properties acquisitions — 0.5 0.1 Total costs incurred in oil and gas property acquisition, exploration and development activities $ 155.6 $ 63.5 $ 233.6 (1) Includes net additions from capitalized ARO of $21.3 million in 2017, net additions from capitalized ARO of $10.8 million in 2016, and net reductions from capitalized ARO of $0.4 million during 2015. These adjustments for ARO are associated with acquisitions, liabilities incurred, divestitures and revisions of estimates. (2) Includes seismic costs of $0.5 million, $0.2 million and $3.2 million incurred during 2017, 2016 and 2015, respectively. (3) Includes geological and geophysical costs charged to expense of $4.2 million, $4.1 million and $5.7 million during 2017, 2016 and 2015, respectively.
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, 2017 2016 2015 Depreciation, depletion, amortization and accretion per Boe $ 10.68 $ 13.77 $ 23.11
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, 2014 61.7 15.8 254.9 120.0 720.0 Revisions of previous estimates (2) 4.8 (0.9 ) 4.9 4.7 28.0 Revisions related to sold properties (3) (12.1 ) (4.8 ) (2.9 ) (17.4 ) (104.3 ) Extensions and discoveries (4) 2.4 0.2 8.8 4.1 24.4 Purchase of minerals in place (5) — — 6.1 1.0 6.1 Sales of reserves (6) (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 (7) 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 Revisions of previous estimates (8) 4.5 0.7 25.8 9.6 57.4 Extensions and discoveries (9) 4.1 0.3 5.4 5.2 31.3 Production (7.1 ) (1.4 ) (36.8 ) (14.6 ) (87.4 ) Proved reserves as of Dec. 31, 2017 34.4 7.8 192.2 74.2 445.3 Year-end proved developed reserves: 2017 26.1 7.2 173.5 62.2 373.3 2016 26.6 7.6 183.1 64.7 388.2 2015 29.4 6.4 198.5 69.0 413.5 Year-end proved undeveloped reserves: 2017 (10) 8.3 0.6 18.7 12.0 72.0 2016 6.3 0.6 14.7 9.3 55.8 2015 6.1 0.2 6.9 7.4 44.6 Volume measurements: 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 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) 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. (4) Primarily due to increases at our Ewing Bank 910 field. (5) Primarily due to purchase of additional interest at our Brazos A-133 field. (6) 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. (7) 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. (8) Primarily related to upward revisions of 6.2 MMBoe, which included upwards revisions of 1.1 MMBoe at our Mississippi Canyon 698 (Big Bend) field, 1.0 MMBoe at our Fairway field, 0.8 MMBoe at our Ewing Bank 910 field and 0.8 MMBoe at our Viosca Knoll 783 (Virgo) field. Additionally, increases of 3.4 MMBoe were due to price revisions. (9) Primarily related to extensions and discoveries at our Ship Shoal 349 (Mahogany) field of 3.5 MMBoe and at our Main Pass 286 field of 1.5 MMBoe. (10) We believe that we will be able to develop all but 1.8 MMBoe (approximately 15%) of the total of 12.0 MMBoe reserves classified as proved undeveloped (“PUDs”) at December 31, 2017, within five years from the date such reserves were initially recorded. The lone exceptions are 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. Two sidetrack PUD locations in this field will be delayed until an existing well is depleted and available to sidetrack. Based on the latest reserve report, these PUD locations are expected to be developed 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, 2017 2016 2015 2014 Oil - per barrel $ 46.58 $ 36.28 $ 46.94 $ 91.12 NGLs per barrel 22.65 16.82 17.60 34.63 Natural gas per Mcf 2.86 2.47 2.50 4.27
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 2017 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, 2017 2016 2015 Standardized Measure of Discounted Future Net Cash Flows Future cash inflows $ 2,328.8 $ 1,818.4 $ 2,296.7 Future costs: Production (813.8 ) (691.5 ) (840.1 ) Development (157.4 ) (141.1 ) (161.4 ) Dismantlement and abandonment (361.9 ) (427.7 ) (471.8 ) Income taxes (1) (74.8 ) — — Future net cash inflows before 10% discount 920.9 558.1 823.4 10% annual discount factor (180.3 ) (79.8 ) (209.5 ) Total $ 740.6 $ 478.3 $ 613.9 (1) No future income taxes were estimated for 2016 and 2015 as our tax position had 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, 2017 2016 2015 Changes in Standardized Measure Standardized measure, beginning of year $ 478.3 $ 613.9 $ 1,702.8 Increases (decreases): Sales and transfers of oil and gas produced, net of production costs (315.3 ) (218.6 ) (289.1 ) Net changes in price, net of future production costs 288.0 (275.2 ) (1,455.6 ) Extensions and discoveries, net of future production and development costs 119.3 — 65.3 Changes in estimated future development costs (38.9 ) (32.5 ) (8.5 ) Previously estimated development costs incurred 102.8 114.5 158.9 Revisions of quantity estimates 106.4 190.1 137.9 Accretion of discount 30.2 52.6 150.6 Net change in income taxes (54.7 ) — 600.8 Purchases of reserves in-place — — 6.0 Sales of reserves in-place — — (401.4 ) Changes in production rates due to timing and other 24.5 33.5 (53.8 ) Net increase (decrease) in standardized measure 262.3 (135.6 ) (1,088.9 ) Standardized measure, end of year $ 740.6 $ 478.3 $ 613.9

Significant Accounting Polici40

Significant Accounting Policies - Additional Information (Details)	3 Months Ended			4 Months Ended	12 Months Ended			16 Months Ended
	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2017USD ($)LoanPlatform	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2017USD ($)Loan	Sep. 07, 2016
Significant Accounting Policies [Line Items]
Number of loans for which maturities will be accelerated | Loan					2			2
Outstanding obligation to secure financial assurances upon rescindment					$ 0
Deposit Into registry of court					$ 49,500,000			$ 49,500,000
Debt instrument, maturity acceleration, month and year					2019-02
Debt instrument maturity, month and year					2018-11
Natural gas imbalances				$ 5,300,000	$ 4,700,000	$ 5,300,000		4,700,000
Percentage of discount from proved reserves					10.00%
Ceiling test write-down of oil and natural gas properties	$ 57,900,000	$ 104,600,000	$ 116,600,000		$ 0	279,063,000	$ 987,238,000
Proved undeveloped reserves classification period to be drilled					5 years
Revolving bank credit facility borrowings outstanding					$ 0			$ 0
Number of Platforms Damaged | Platform					1
Reimbursements from a third-party for damages					$ 1,100,000
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%
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				$ 0
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
Apache Corporation
Significant Accounting Policies [Line Items]
Deposit Into registry of court					$ 49,500,000			$ 49,500,000
Expense related to lawsuit					$ 6,300,000

Significant Accounting Polici41

Significant Accounting Policies - Percentage of Revenue by Major Customers (Details) - Sales Revenue Net - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Shell Trading (US) Co.
Entity Wide Revenue Major Customer [Line Items]
Percentage of receipts	46.00%	43.00%	50.00%
Vitol Inc.
Entity Wide Revenue Major Customer [Line Items]
Percentage of receipts	15.00%	20.00%
J. P. Morgan
Entity Wide Revenue Major Customer [Line Items]
Percentage of receipts			14.00%

Significant Accounting Polici42

Significant Accounting Policies - Schedule of Changes to Allowance for Doubtful Accounts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Receivables [Abstract]
Allowance for doubtful accounts, beginning of period	$ 7,602	$ 2,490	$ 704
Additional provisions for the year	1,512	5,112	1,786
Allowance for doubtful accounts, end of period	$ 9,114	$ 7,602	$ 2,490

Significant Accounting Polici43

Significant Accounting Policies - Schedule of Amounts Recorded in Prepaid Expenses and Other (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Prepaid Expense And Other Assets Current [Abstract]
Prepaid/accrued insurance	$ 2,401	$ 2,924
Surety bonds unamortized premiums	2,676	2,462
Prepaid deposits related to royalties	6,456	6,237
Other	1,886	2,881
Prepaid expenses and other	$ 13,419	$ 14,504

Significant Accounting Polici44

Significant Accounting Policies - Schedule of Oil and Natural Gas Properties and Other, Net at Cost (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Property Plant And Equipment Net [Abstract]
Oil and natural gas properties and equipment	$ 8,102,044	$ 7,932,504
Furniture, fixtures and other	21,831	20,898
Total property and equipment	8,123,875	7,953,402
Less accumulated depreciation, depletion and amortization	7,544,859	7,406,349
Oil and natural gas properties and other, net	$ 579,016	$ 547,053

Significant Accounting Polici45

Significant Accounting Policies - Schedule of Other Assets (Long-term) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Other Assets [Abstract]
Escrow deposit - Apache lawsuit	$ 49,500
Appeal bond deposits	6,925	$ 6,925
Investment in White Cap, LLC	2,511	2,520
Other	1,457	2,019
Total other assets	$ 60,393	$ 11,464

Significant Accounting Polici46

Significant Accounting Policies - Schedule of Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Payables And Accruals [Abstract]
Accrued interest	$ 4,200	$ 4,189
Accrued salaries/payroll taxes/benefits	2,454	2,777
Incentive compensation plans	7,366
Litigation accruals	3,480	1,891
Other	430	343
Total accrued liabilities	$ 17,930	$ 9,200

Significant Accounting Polici47

Significant Accounting Policies - Schedule of Other Liabilities (Long-term) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Other Liabilities Disclosure [Abstract]
Apache lawsuit	$ 49,500
Uncertain tax positions including interest/penalties	11,015	$ 10,584
Other	6,351	6,521
Total other liabilities (long-term)	$ 66,866	$ 17,105

Long-Term Debt - Components of

Long-Term Debt - Components of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Principal	$ 889,790	$ 873,733
Adjustments to carrying value, Debt premium, discount, issuance costs, net of amortization	(3,956)	(5,276)
Adjustments to carrying value, Total	102,262	146,994
Adjustments to carrying value, Current maturities	22,925	8,272
Adjustments to carrying value, less current maturities	79,337	138,722
Debt premium, discount, issuance costs, net of amortization	(3,956)	(5,276)
Total long-term debt	992,052	1,020,727
Long-term debt	22,925	8,272
Long term debt, less current maturities	969,127	1,012,455
11.00% 1.5 Lien Term Loan, Due November 2019
Debt Instrument [Line Items]
Principal	75,000	75,000
Adjustments to carrying value, Future interest payments	15,596	23,823
Adjustments to carrying value, Subtotal	15,596	23,823
Carrying Value	90,596	98,823
9.00 % Second Lien Term Loan, Due May 2020
Debt Instrument [Line Items]
Principal	300,000	300,000
Carrying Value	300,000	300,000
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020
Debt Instrument [Line Items]
Principal	171,769	163,007
Adjustments to carrying value, Future payments-in-kind	5,745	24,048
Adjustments to carrying value, Future interest payments	34,872	36,850
Adjustments to carrying value, Subtotal	40,617	60,898
Carrying Value	212,386	223,905
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021
Debt Instrument [Line Items]
Principal	153,192	145,897
Adjustments to carrying value, Future payments-in-kind	11,323	26,844
Adjustments to carrying value, Future interest payments	38,682	40,705
Adjustments to carrying value, Subtotal	50,005	67,549
Carrying Value	203,197	213,446
8.50% Unsecured Senior Notes, Due June 2019
Debt Instrument [Line Items]
Principal	189,829	189,829
Carrying Value	$ 189,829	$ 189,829

Long-Term Debt - Components o49

Long-Term Debt - Components of Long-Term Debt (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	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%	11.00%
Debt instrument maturity date	Nov. 15, 2019	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%	9.00%
Debt instrument maturity date	May 15, 2020	May 15, 2020
Debt instrument paid in kind interest rate	10.75%	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%	8.50%
Debt instrument maturity date	Jun. 15, 2021	Jun. 15, 2021
Debt instrument paid in kind interest rate	10.00%	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, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2017	Jun. 30, 2017
Debt Instrument [Line Items]
Aggregate annual maturities of long-term debt, 2018					$ 22,900,000			$ 22,900,000
Aggregate annual maturities of long-term debt, 2019					302,100,000			302,100,000
Aggregate annual maturities of long-term debt, 2020					499,500,000			499,500,000
Aggregate annual maturities of long-term debt, 2021					171,500,000			171,500,000
Debt instrument aggregate principle amount				$ 873,733,000	889,790,000	$ 873,733,000		889,790,000
Gain on exchange of debt			$ 123,900,000		$ 7,811,000	123,923,000
Credit agreement expiration date					Nov. 8, 2018
Revolving bank credit facility borrowings outstanding					$ 0			0
Write-offs of debt issuance costs						$ 1,400,000	$ 3,200,000
Revolving Bank Credit Facility
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
Percentage of hedging contracts						75.00%
Debt redemption amount				35,000,000		$ 35,000,000
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
First lien leverage ratio					200.00%
Current ratio					280.00%
Revolving bank credit facility borrowings outstanding				0	$ 0	0		0
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%
Write-offs of debt issuance costs						1,400,000	$ 3,200,000
Letters of credit outstanding				500,000	$ 300,000	500,000		300,000
Revolving Bank Credit Facility | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate					1.00%
Revolving Bank Credit Facility | Federal Funds Effective Swap Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate					0.50%
Revolving Bank Credit Facility | Scenario Covenants
Debt Instrument [Line Items]
Maximum unrestricted cash balance if revolver balance is above $5 million					$ 35,000,000			35,000,000
Minimum | Revolving Bank Credit Facility
Debt Instrument [Line Items]
Current ratio					100.00%
Minimum | Revolving Bank Credit Facility | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate					3.00%
Minimum | Revolving Bank Credit Facility | London Interbank Offered Rate Additional Applicable Margin
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate					2.00%
Maximum | Revolving Bank Credit Facility | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate					4.00%
Maximum | Revolving Bank Credit Facility | London Interbank Offered Rate Additional Applicable Margin
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate					3.00%
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020
Debt Instrument [Line Items]
Debt instrument aggregate principle amount				$ 163,007,000	$ 171,769,000	$ 163,007,000		$ 171,769,000
Debt instrument maturity date					May 15, 2020	May 15, 2020
Debt instrument interest rate	9.00%			9.00%	9.00%	9.00%		9.00%
Debt instrument paid in kind interest rate				10.75%	10.75%	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 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. This payment-in-kind provision expires on March 7, 2018. For the initial interest payment on November 15, 2016, interest could only be paid-in-kind at 10.75% per annum.
Debt instrument stated interest rate percentage for payment-in-kind					10.75%			10.75%
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020 | Minimum
Debt Instrument [Line Items]
Cash interest payable stub period					Mar. 7, 2018
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020 | Maximum
Debt Instrument [Line Items]
Cash interest payable stub period					May 15, 2018
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021
Debt Instrument [Line Items]
Debt instrument aggregate principle amount				$ 145,897,000	$ 153,192,000	$ 145,897,000		$ 153,192,000
Debt instrument maturity date					Jun. 15, 2021	Jun. 15, 2021
Debt instrument interest rate	8.50%			8.50%	8.50%	8.50%		8.50%
Debt instrument paid in kind interest rate				10.00%	10.00%	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. Certain amendments under the 1.5 Lien Term Loan and the Credit Agreement will likely be required in the event replacement financing is not utilized. 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. This payment-in-kind provision expires on September 7, 2018. For the initial interest payment on December 15, 2016, interest could only be paid-in-kind at 10.00% per annum. For the six month interest period ending June 15, 2017, we paid the interest payment in cash rather than using the payment-in-kind provision. For the six-month period ended November 15, 2017, we exercised the payment-in-kind provision. For the six-month period ended June 15, 2018, we have exercised the payment-in-kind provision. When the PIK option is utilized, the principal amount of the notes increases.
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	$ 75,000,000		$ 75,000,000
Debt instrument maturity date					Nov. 15, 2019	Nov. 15, 2019
Debt instrument interest rate				11.00%	11.00%	11.00%		11.00%
Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes
Debt Instrument [Line Items]
Net reduction to long term debt									$ 8,200,000
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		$ 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%		9.00%
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%
Effective interest rate					9.60%			9.60%
8.50% Unsecured Senior Notes, Due June 2019
Debt Instrument [Line Items]
Debt instrument aggregate principle amount				$ 189,829,000	$ 189,829,000	$ 189,829,000		$ 189,829,000
Debt instrument maturity date					Jun. 15, 2019	Jun. 15, 2019
Debt instrument interest rate				8.50%	8.50%	8.50%		8.50%
Debt instrument payment terms					semi-annually in arrears on June 15 and December 15
Effective interest rate					8.30%			8.30%
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					$ 0.06	$ 1.30
Additional expense charged to gain on exchange of debt					$ 400,000
Exchange Transaction | Common Stock
Debt Instrument [Line Items]
Debt conversion, common stock shares issued	60.4		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
Debt instrument maturity date					May 15, 2020
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. 30, 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				$ 0
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

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, 2017	Dec. 31, 2016
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	$ 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	288,000	255,000
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	162,322	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	119,490	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	$ 178,439	$ 123,389

Fair Value Measurements - Sch52

Fair Value Measurements - Schedule of Fair Value of Long-Term Debt (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	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%	11.00%
Debt instrument maturity date	Nov. 15, 2019	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%	9.00%
Debt instrument maturity date	May 15, 2020	May 15, 2020
Debt instrument paid in kind interest rate	10.75%	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%	8.50%
Debt instrument maturity date	Jun. 15, 2021	Jun. 15, 2021
Debt instrument paid in kind interest rate	10.00%	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) - DerivativeInstrument	Dec. 31, 2017	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Number of open derivative financial instruments	0	0

Asset Retirement Obligations -

Asset Retirement Obligations - Reconciliation of Asset Retirement Obligations Liability (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations, beginning of period	$ 334,438	$ 378,322
Asset retirement obligation settlements	(72,409)	(72,320)	$ (32,555)
Accretion of discount	17,172	17,571	20,703
Liabilities incurred	163	398
Revisions of estimated liabilities	21,082	10,467
Asset retirement obligations, end of period	300,446	334,438	$ 378,322
Less current portion	23,613	78,264
Long-term	$ 276,833	$ 256,174

Insurance Claims - Additional I

Insurance Claims - Additional Information (Details) - USD ($)	3 Months Ended	12 Months Ended			114 Months Ended
	Sep. 30, 2008	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2017
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		$ 31,700,000	$ 10,200,000	$ 200,000
Cumulative insurance recoveries related to hurricanes					$ 203,100,000
Outstanding hurricane claims		$ 0			$ 0

Divestitures - Additional Infor

Divestitures - Additional Information (Details)	Oct. 15, 2015USD ($)a$ / bbl	Dec. 31, 2016USD ($)
Business Divestiture [Line Items]
Gain (loss) on disposition of proved property	$ 0
Limit on percentage of reserves related to recognition of gain or loss	25.00%
Crude Oil | Minimum
Business Divestiture [Line Items]
Trading price per barrel | $ / bbl	70
Crude Oil | Maximum
Business Divestiture [Line Items]
Trading price per barrel | $ / bbl	90
Ajax Resources, LLC
Business Divestiture [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 Divestiture [Line Items]
Overriding royalty interest	1.00%
Ajax Resources, LLC | Maximum
Business Divestiture [Line Items]
Overriding royalty interest	4.00%
Ajax Resources, LLC | NYMEX
Business Divestiture [Line Items]
Addition to available cash	$ 100,000,000

Derivative Financial Instrume57

Derivative Financial Instruments - Additional Information (Details) - DerivativeInstrument	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Number of open derivative financial instruments	0	0

Derivative Financial Instrume58

Derivative Financial Instruments - Changes in Fair Value and Settlements of Commodity Derivative Contracts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Gain Loss On Derivative Instruments Net Pretax [Abstract]
Derivative (gain) loss	$ (4,199)	$ 2,926	$ (14,375)

Derivative Financial Instrume59

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Cash receipts on derivative settlements, net	$ 4,199	$ 4,746	$ 6,703

Equity Transactions - Additiona

Equity Transactions - Additional Information (Details) - $ / shares	Sep. 07, 2016	Sep. 30, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
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
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	60,400,000

Share-Based Awards and Cash-B61

Share-Based Awards and Cash-Based Awards - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
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
Common stock available for award under plans	13,363,792
Recognized incentive compensation expense	$ 8,065,000	$ 11,013,000	$ 10,242,000
Restricted Stock Units (RSUs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares granted, grant date fair value	5,900,000	9,300,000	9,400,000
Shares vested, vested date fair value	5,500,000	2,400,000	2,100,000
Unrecognized share-based compensation expense	$ 6,200,000
Recognition period for unrecognized compensation expense	2019-11
Recognized incentive compensation expense	$ 7,785,000	10,640,000	9,978,000
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	100,000
Unrecognized share-based compensation expense	$ 400,000
Recognition period for unrecognized compensation expense	2020-04
Recognized incentive compensation expense	$ 280,000	373,000	358,000
2017 Cash-based Awards | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Adjusted EBITDA less interest expense	$ 200,000,000
2017 Annual Incentive Award Agreement
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Cash based award expected payment period	2018-03
2016 Cash-based Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Recognized incentive compensation expense	$ 0	$ 0
Cash based compensation payment period after achievement of financial condition		30 days
2016 Cash-based Awards | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Adjusted EBITDA less interest expense		$ 300,000,000
2015 Cash-based Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Recognized incentive compensation expense			$ 0
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%
Amended and Restated Incentive Compensation Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Amendment increased the number of shares available in the Plan	7,700,000
Directors Compensation Plan Share-Based Awards | Restricted Shares
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
Directors Compensation Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common stock available for award under plans	170,524

Share-Based Awards and Cash-B62

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Nonvested, beginning of period	6,107,248	3,474,079	1,977,335
Granted	2,128,879	4,213,964	2,626,930
Vested	(2,108,553)	(968,652)	(721,038)
Forfeited	(362,323)	(612,143)	(409,148)
Nonvested, end of period	5,765,251	6,107,248	3,474,079
Weighted Average Grant Date Value, Beginning of period	$ 2.73	$ 7.42	$ 15.29
Weighted Average Grant Date Fair Value, Granted	2.76	2.21	3.59
Weighted Average Grant Date Fair Value, Vested	3.45	16.69	13.23
Weighted Average Grant Date Fair Value, Forfeited	2.87	3.64	10.63
Weighted Average Grant Date Value, End of period	$ 2.48	$ 2.73	$ 7.42

Share-Based Awards and Cash-B63

Share-Based Awards and Cash-Based Awards - Schedule of Restricted Stock Units Outstanding (Details) - Restricted Stock Units (RSUs) - shares	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	5,765,251	6,107,248	3,474,079	1,977,335
2,018
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	3,742,509
2,019
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	2,022,742

Share-Based Awards and Cash-B64

Share-Based Awards and Cash-Based Awards - Schedule of Restricted Stock Activity (Details) - Restricted Shares - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Nonvested, beginning of period	161,296	78,230	43,210
Granted	147,372	126,128	56,540
Vested	(62,140)	(43,062)	(21,520)
Nonvested, end of period	246,528	161,296	78,230
Weighted Average Grant Date Value, Beginning of period	$ 3.47	$ 8.95	$ 16.20
Weighted Average Grant Date Fair Value, Granted	1.90	2.22	6.19
Weighted Average Grant Date Fair Value, Vested	4.51	9.75	16.26
Weighted Average Grant Date Value, End of period	$ 2.27	$ 3.47	$ 8.95

Share-Based Awards and Cash-B65

Share-Based Awards and Cash-Based Awards - Schedule of Restricted Stock Awards Outstanding (Details) - Restricted Shares - shares	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	246,528	161,296	78,230	43,210
2,018
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	106,240
2,019
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	91,164
2,020
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards expected to vest by period	49,124

Share-Based Awards and Cash-B66

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation	$ 8,065	$ 11,013	$ 10,242
Tax benefit computed at the statutory rate	1,694	3,855	3,585
Restricted Stock Units (RSUs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation	7,785	10,640	9,978
Restricted Shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation	$ 280	$ 373	358
Common Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation			$ (94)

Share-Based Awards and Cash-B67

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Share-based compensation charged to operating income		$ 8,065	$ 11,013	$ 10,242
Total charged to operating income		15,198	11,013	10,373
General And Administrative Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Share-based compensation charged to operating income		8,065	$ 11,013	10,242
Cash-based incentive compensation charged to operating income	[1]	5,032		(233)
Lease Operating Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Cash-based incentive compensation charged to operating income		$ 2,101		$ 364
[1]	Adjustments to true up estimates to actual payments resulted in net credit balances to expense in 2015.

Employee Benefit Plan - Additio

Employee Benefit Plan - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Mar. 01, 2017	Dec. 31, 2016	Dec. 31, 2015
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	$ 1.4		$ 0.4	$ 2.3

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current	$ (12,786)	$ (71,768)	$ 288
Deferred	217	28,392	(203,272)
Total income tax (benefit)	$ (12,569)	$ (43,376)	$ (202,984)

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Income Taxes Computed to Income Tax Benefit (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income tax (benefit) at the federal statutory rate	$ 23,490	$ (102,339)	$ (436,696)
Share-based compensation	664	4,920	2,940
State income taxes	63	(755)	(2,343)
Debt restructuring cost	18	1,463
Change in statutory federal tax rate	105,933
Gain on exchange of debt	(24,981)
Valuation allowance	(118,643)	52,915	232,925
Other	887	420	190
Total income tax (benefit)	$ (12,569)	$ (43,376)	$ (202,984)
Income tax expense (benefit) at the federal statutory rate, tax rate	35.00%	35.00%	35.00%
Share-based compensation, tax rate	1.00%	(1.70%)	(0.20%)
State income taxes, tax rate	0.10%	0.20%	0.20%
Debt restructuring cost		(0.50%)
Change in statutory federal tax rate	157.80%
Gain on exchange of debt, tax rate	(37.20%)
Valuation allowance, tax rate	(176.80%)	(18.10%)	(18.70%)
Other, tax rate	1.40%	(0.10%)
Total income tax (benefit), tax rate	(18.70%)	14.80%	16.30%

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Federal statutory income tax rate		35.00%	35.00%	35.00%
Cash paid for income taxes		$ 185	$ 310	$ 390
Income tax refund received		11,906	7,796	$ 90
Current income taxes receivable	$ 13,006	13,006	11,943
Non-current income taxes receivable	52,097	52,097	52,097
Increase and (decrease) in valuation allowance	$ (105,900)	$ (118,600)	52,900
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		2,017
Tax Year 2016 and 2017
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Income tax refund received related to NOL claim		$ 11,900	$ 7,800

Income Taxes - Significant Comp

Income Taxes - Significant Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Deferred tax liabilities:
Other	$ 695	$ 1,423
Total deferred tax liabilities	695	1,423
Deferred tax assets:
Property and equipment	18,234	42,385
Asset retirement obligations	63,755	117,588
Federal net operating losses	18,988
State net operating losses	7,126	5,615
Exchange transaction	55,807	118,467
Share-based compensation	1,335	2,353
Valuation allowance	(171,547)	(290,190)
Other	6,805	4,798
Total deferred tax assets	503	1,016
Net deferred tax liabilities	$ (192)	$ (407)

Income Taxes - Net Operating Lo

Income Taxes - Net Operating Loss and Tax Credit Carryovers (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)
Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]
Net operating loss	$ 18,988
Net operating loss, expiration year	Dec. 31, 2037
State and Local Jurisdiction
Operating Loss Carryforwards [Line Items]
Net operating loss	$ 118,027
State and Local Jurisdiction | Minimum
Operating Loss Carryforwards [Line Items]
Net operating loss, expiration year	Dec. 31, 2025
State and Local Jurisdiction | Maximum
Operating Loss Carryforwards [Line Items]
Net operating loss, expiration year	Dec. 31, 2036

Income Taxes - Balances in Unce

Income Taxes - Balances in Uncertain Tax Positions (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Balance, beginning and end of period	$ 9,482	$ 9,482

Earnings_ (Loss) Per Share - Sc

Earnings/ (Loss) Per Share - Schedule of Calculation of Basic and Diluted Earnings (Loss) Per Common Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended												12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	[1]	Sep. 30, 2016	[1]	Jun. 30, 2016	[1]	Mar. 31, 2016	[1]	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share, Basic and Diluted [Abstract]
Net income (loss)	$ 23,365	$ (1,297)	$ 33,315	$ 24,299	$ 16,483		$ 45,928		$ (120,922)		$ (190,509)		$ 79,682	$ (249,020)	$ (1,044,718)
Less portion allocated to nonvested shares													3,244
Net income (loss) allocated to common shares													$ 76,438	$ (249,020)	$ (1,044,718)
Weighted average common shares outstanding													137,617	95,644	75,931
Basic and diluted earnings (loss) per common share	$ 0.16	$ (0.01)	$ 0.23	$ 0.17	$ 0.12	[2]	$ 0.48	[2]	$ (1.58)	[2]	$ (2.49)	[2]	$ 0.56	$ (2.60)	$ (13.76)
Shares excluded due to being anti-dilutive (weighted-average)														5,269	2,195
[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. See Note 1 and Note 2 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. During the third quarter of 2016, 60.4 million shares of common stock were issued in conjunction with the Exchange Transaction.

Supplemental Cash Flow Inform76

Supplemental Cash Flow Information - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental cash items:
Cash paid for interest, net of interest capitalized of $0 in 2017, $520 in 2016 and $7,256 in 2015	[1]	$ 65,873	$ 96,501	$ 92,622
Cash paid for income taxes		185	310	390
Cash refunds received for income taxes		11,906	7,796	90
Cash paid for share-based compensation	[2]	874
Non-cash investing activities:
Accruals of property and equipment		33,003	9,129	44,324
ARO - additions, dispositions and revisions, net		$ 21,245	10,865	$ (394)
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]	During 2017 and 2016, cash paid for interest included amounts related to the New Debt, which are accounted for under ASC 470-60 and recorded against the carrying value of the New Debt instruments on the Consolidated Balance Sheets and included in financing activities on the Consolidated Statements of Cash Flows.
[2]	During 2017, cash was used to settle vested RSUs related to the retirement of an executive officer and shares of common stock were used to settle all other vested RSUs and to settle restricted stock. During 2016 and 2015, only common shares were used to settle vested RSUs and Restrict stock.

Supplemental Cash Flow Inform77

Supplemental Cash Flow Information - Supplemental Cash Flow Information (Parenthetical) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 07, 2016
Supplemental Cash Flow Elements [Line Items]
Cash paid, interest capitalized	$ 0	$ 520	$ 7,256
11.00% 1.5 Lien Term Loan, Due November 2019
Supplemental Cash Flow Elements [Line Items]
Debt instrument interest rate	11.00%	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%		9.00%
Debt instrument paid in kind interest rate	10.75%	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%		8.50%
Debt instrument paid in kind interest rate	10.00%	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, 2017	Dec. 31, 2016	Dec. 31, 2015
Commitments [Line Items]
Minimum future lease payments due under noncancelable operating leases, 2018	$ 1,800,000
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, 2021	1,800,000
Minimum future lease payments due under noncancelable operating leases, thereafter	2,000,000
Total rent expense	3,000,000	$ 3,200,000	$ 3,300,000
Escrow related to Purchase and Sale Agreement	49,500,000
Collateral deposits	16,900,000
Expenses related to surety bonds	5,700,000	$ 4,300,000	$ 5,500,000
Drilling Rig Commitments
Commitments [Line Items]
Minimum future lease payments due under noncancelable operating leases, 2017	5,700,000
Surety Bonds
Commitments [Line Items]
Future estimated costs, 2018	6,200,000
Future estimated costs, 2019	6,000,000
Future estimated costs, 2020	5,700,000
Future estimated costs, 2021	5,300,000
Future estimated costs, thereafter	42,400,000
Other commitment
Commitments [Line Items]
Security requirement minimum	64,000,000
Security requirement maximum	94,000,000
Total E&P Member
Commitments [Line Items]
Security amount requirement	81,300,000
Escrow related to Purchase and Sale Agreement	0
Additional security requirements for 2018	88,000,000
Additional security requirements for 2019	91,000,000
Additional security requirements for 2023	103,000,000
Annual increment in threshold	3,000,000
Helix Well Containment Group
Commitments [Line Items]
Future estimated costs, 2018	$ 1,500,000

Related Parties - Additional In

Related Parties - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Principal	$ 889,790	$ 873,733
Airplane Services
Related Party Transaction [Line Items]
Related party transactions	1,200	1,100	$ 1,100
Marine Transportation and Logistic Services
Related Party Transaction [Line Items]
Related party transactions	200
Payments to related party transactions	$ 22,800
Marine Transportation and Logistic Services | Maximum
Related Party Transaction [Line Items]
Related party transactions		$ 200	200
CEO and Largest Shareholder | Second Lien Term Loan
Related Party Transaction [Line Items]
Principal			$ 5,000

Contingencies - Additional Info

Contingencies - Additional Information (Details)	Jan. 27, 2017USD ($)	Oct. 28, 2016USD ($)	Dec. 15, 2014USD ($)DeepwaterWell	Dec. 31, 2017USD ($)claim	Dec. 31, 2016USD ($)	Jun. 30, 2017USD ($)	May 31, 2017USD ($)	Dec. 31, 2010USD ($)
Loss Contingencies [Line Items]
Outstanding obligation to secure financial assurances upon rescindment				$ 0
Number of deepwater wells abandoned | DeepwaterWell			3
Deposit Into registry of court				49,500,000
Loss contingency accrued amount				49,500,000
Notified disallowed amount in reductions taken by ONRR								$ 4,700,000
Payments for royalty	$ 4,700,000
Royalty payment processing revised period					84 months
Royalties paid				1,600,000	$ 500,000
BSEE
Loss Contingencies [Line Items]
Loss contingency accrued amount				$ 3,300,000
Number of notices | claim				4
Proposed civil penalties related to various incidents of noncompliance, total				$ 7,300,000
Payments for civil penalty				200,000	$ 100,000
Apache Corporation
Loss Contingencies [Line Items]
Deposit Into registry of court				49,500,000
Apache Corporation | Judicial Ruling
Loss Contingencies [Line Items]
Amount owed to Apache under judicial decision							$ 43,200,000
Prejudgment interest, attorney fees and judgment costs							$ 6,300,000
Amount awarded for non-compliance fines and lawsuits		$ 43,200,000	$ 24,900,000
Amount offset against litigation compensation amount		$ 17,000,000
Apache Corporation | Judicial Ruling | Other Income/Expense
Loss Contingencies [Line Items]
Recognized prejudgment interest, attorney fees and judgment costs.				6,300,000
Apache Corporation | Judicial Ruling | Asset Retirement Obligation
Loss Contingencies [Line Items]
Capitalized loss contingency damages payable to other party except attorney fees judgment costs and prejudgment interest				43,200,000
Apache Corporation | Judicial Ruling | Other Noncurrent Assets
Loss Contingencies [Line Items]
Deposit Into registry of court						$ 49,500,000
Apache Corporation | Judicial Ruling | Other Noncurrent Liabilities
Loss Contingencies [Line Items]
Loss contingency accrued amount				$ 49,500,000

Selected Quarterly Financial 81

Selected Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended												12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 129,099	$ 110,281	$ 123,323	$ 124,393	$ 115,213		$ 107,403		$ 99,655		$ 77,715		$ 487,096	$ 399,986	$ 507,265
Operating income (loss)	33,166	15,700	32,888	28,196	21,319	[1]	(58,276)	[1]	(126,997)	[1]	(166,614)	[1]	109,950	(330,568)	(1,145,703)
Net income (loss)	$ 23,365	$ (1,297)	$ 33,315	$ 24,299	$ 16,483	[1]	$ 45,928	[1]	$ (120,922)	[1]	$ (190,509)	[1]	$ 79,682	$ (249,020)	$ (1,044,718)
Basic and diluted earnings (loss) per common share	$ 0.16	$ (0.01)	$ 0.23	$ 0.17	$ 0.12	[1],[2]	$ 0.48	[1],[2]	$ (1.58)	[1],[2]	$ (2.49)	[1],[2]	$ 0.56	$ (2.60)	$ (13.76)
[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. See Note 1 and Note 2 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. During the third quarter of 2016, 60.4 million shares of common stock were issued in conjunction with the Exchange Transaction.

Selected Quarterly Financial 82

Selected Quarterly Financial Data (Parenthetical) (Details) - USD ($) $ in Thousands, shares in Millions	Sep. 07, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Data [Line Items]
Ceiling test write-down of oil and natural gas properties		$ 57,900	$ 104,600	$ 116,600	$ 0	$ 279,063	$ 987,238
Gain on exchange of debt		$ 123,900			$ 7,811	123,923
Exchange Transaction
Quarterly Financial Data [Line Items]
Gain on exchange of debt						$ 123,900
Exchange Transaction | Common Stock
Quarterly Financial Data [Line Items]
Debt conversion, common stock shares issued	60.4	60.4

Supplemental Guarantor Inform83

Supplemental Guarantor Information - Additional Information (Details)	Dec. 31, 2017
Debt Disclosure [Abstract]
Percentage of subsidiaries owned	100.00%

Supplemental Guarantor Inform84

Supplemental Guarantor Information - Condensed Consolidating Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Mar. 03, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 99,058	$ 70,236	$ 85,414	$ 23,666	$ 23,666
Receivables:
Oil and natural gas sales	45,443	43,073
Joint interest	19,754	21,885
Insurance reimbursement		30,100
Income taxes	13,006	11,943
Total receivables	78,203	107,001
Prepaid expenses and other assets	13,419	14,504
Total current assets	190,680	191,741
Oil and natural gas properties and other, net - at cost:	579,016	547,053
Restricted deposits for asset retirement obligations	25,394	27,371
Income tax receivables	52,097	52,097
Other assets	60,393	11,464
Total assets	907,580	829,726
Current liabilities:
Accounts payable	83,665	81,039
Undistributed oil and natural gas proceeds	20,129	26,254
Asset retirement obligations	23,613	78,264
Long-term debt	22,925	8,272
Accrued liabilities	17,930	9,200
Total current liabilities	168,262	203,029
Long-term debt:
Principal	889,790	873,733
Carrying value adjustments	79,337	138,722
Long term debt, less current portion - carrying value	969,127	1,012,455
Asset retirement obligations, less current portion	276,833	256,174
Other liabilities	66,866	17,105
Shareholders’ equity (deficit):
Common stock	1	1
Additional paid-in capital	545,820	539,973
Retained earnings (deficit)	(1,095,162)	(1,174,844)
Treasury stock, at cost	(24,167)	(24,167)
Total shareholders’ equity (deficit)	(573,508)	(659,037)	(526,491)		$ 509,308
Total liabilities and shareholders’ equity (deficit)	907,580	829,726
Parent Company
Current assets:
Cash and cash equivalents	99,058	70,236	$ 85,414	$ 23,666
Receivables:
Oil and natural gas sales	5,665	2,173
Joint interest	19,754	21,885
Insurance reimbursement		30,100
Income taxes	128,835	111,215
Total receivables	154,254	165,373
Prepaid expenses and other assets	11,154	12,448
Total current assets	264,466	248,057
Oil and natural gas properties and other, net - at cost:	430,354	360,966
Restricted deposits for asset retirement obligations	25,394	27,371
Income tax receivables	52,097	52,097
Other assets	505,304	394,931
Total assets	1,277,615	1,083,422
Current liabilities:
Accounts payable	76,703	74,306
Undistributed oil and natural gas proceeds	18,762	24,493
Asset retirement obligations	22,488	62,261
Long-term debt	22,925	8,272
Accrued liabilities	18,058	9,293
Total current liabilities	158,936	178,625
Long-term debt:
Principal	889,790	873,733
Carrying value adjustments	79,337	138,722
Long term debt, less current portion - carrying value	969,127	1,012,455
Asset retirement obligations, less current portion	152,883	142,376
Other liabilities	566,375	408,050
Shareholders’ equity (deficit):
Common stock	1	1
Additional paid-in capital	545,820	539,973
Retained earnings (deficit)	(1,091,360)	(1,173,891)
Treasury stock, at cost	(24,167)	(24,167)
Total shareholders’ equity (deficit)	(569,706)	(658,084)
Total liabilities and shareholders’ equity (deficit)	1,277,615	1,083,422
Guarantor Subsidiaries
Receivables:
Oil and natural gas sales	39,778	40,900
Total receivables	39,778	40,900
Prepaid expenses and other assets	2,265	2,056
Total current assets	42,043	42,956
Oil and natural gas properties and other, net - at cost:	152,464	187,040
Other assets	453,306	344,742
Total assets	647,813	574,738
Current liabilities:
Accounts payable	6,962	6,733
Undistributed oil and natural gas proceeds	1,367	1,761
Asset retirement obligations	1,125	16,003
Accrued liabilities	115,701	99,179
Total current liabilities	125,155	123,676
Long-term debt:
Asset retirement obligations, less current portion	123,950	113,798
Shareholders’ equity (deficit):
Additional paid-in capital	704,885	704,885
Retained earnings (deficit)	(306,177)	(367,621)
Total shareholders’ equity (deficit)	398,708	337,264
Total liabilities and shareholders’ equity (deficit)	647,813	574,738
Eliminations
Receivables:
Income taxes	(115,829)	(99,272)
Total receivables	(115,829)	(99,272)
Total current assets	(115,829)	(99,272)
Oil and natural gas properties and other, net - at cost:	(3,802)	(953)
Other assets	(898,217)	(728,209)
Total assets	(1,017,848)	(828,434)
Current liabilities:
Accrued liabilities	(115,829)	(99,272)
Total current liabilities	(115,829)	(99,272)
Long-term debt:
Other liabilities	(499,509)	(390,945)
Shareholders’ equity (deficit):
Additional paid-in capital	(704,885)	(704,885)
Retained earnings (deficit)	302,375	366,668
Total shareholders’ equity (deficit)	(402,510)	(338,217)
Total liabilities and shareholders’ equity (deficit)	$ (1,017,848)	$ (828,434)

Supplemental Guarantor Inform85

Supplemental Guarantor Information - Condensed Consolidating Statement of Operations (Details) - USD ($) $ in Thousands	3 Months Ended												12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Condensed Income Statements Captions [Line Items]
Revenues	$ 129,099	$ 110,281	$ 123,323	$ 124,393	$ 115,213		$ 107,403		$ 99,655		$ 77,715		$ 487,096	$ 399,986	$ 507,265
Operating costs and expenses:
Lease operating expenses													143,738	152,399	192,765
Production taxes													1,740	1,889	3,002
Gathering and transportation													20,441	22,928	17,157
Depreciation, depletion and amortization													138,510	194,038	373,368
Asset retirement obligations accretion													17,172	17,571	20,703
Ceiling test write-down of oil and natural gas properties							57,900		104,600		116,600		0	279,063	987,238
General and administrative expenses													59,744	59,740	73,110
Derivative (gain) loss													(4,199)	2,926	(14,375)
Total costs and expenses													377,146	730,554	1,652,968
Operating income (loss)	33,166	15,700	32,888	28,196	21,319	[1]	(58,276)	[1]	(126,997)	[1]	(166,614)	[1]	109,950	(330,568)	(1,145,703)
Interest expense:
Incurred													45,836	92,791	104,592
Capitalized													0	(520)	(7,256)
Gain on exchange of debt							123,900						7,811	123,923
Other (income) expense, net													4,812	(6,520)	4,663
Income (loss) before income tax benefit													67,113	(292,396)	(1,247,702)
Income tax expense (benefit)													(12,569)	(43,376)	(202,984)
Net income (loss)	$ 23,365	$ (1,297)	$ 33,315	$ 24,299	$ 16,483	[1]	$ 45,928	[1]	$ (120,922)	[1]	$ (190,509)	[1]	79,682	(249,020)	(1,044,718)
Parent Company
Condensed Income Statements Captions [Line Items]
Revenues													231,396	161,063	290,212
Operating costs and expenses:
Lease operating expenses													79,695	84,415	126,189
Production taxes													1,740	1,889	3,002
Gathering and transportation													9,781	9,795	9,209
Depreciation, depletion and amortization													73,962	73,268	201,154
Asset retirement obligations accretion													7,416	8,165	11,587
Ceiling test write-down of oil and natural gas properties														28,305	616,947
General and administrative expenses													28,170	24,817	39,009
Derivative (gain) loss													(4,199)	2,926	(14,375)
Total costs and expenses													196,565	233,580	992,722
Operating income (loss)													34,831	(72,517)	(702,510)
Earnings (loss) of affiliates													61,444	(109,853)	(464,931)
Interest expense:
Incurred													45,836	92,607	101,542
Capitalized														(336)	(4,206)
Gain on exchange of debt													7,811	123,923
Other (income) expense, net													4,812	(6,520)	4,663
Income (loss) before income tax benefit													53,438	(144,198)	(1,269,440)
Income tax expense (benefit)													(29,092)	(43,720)	(77,133)
Net income (loss)													82,530	(100,478)	(1,192,307)
Guarantor Subsidiaries
Condensed Income Statements Captions [Line Items]
Revenues													255,700	238,923	217,053
Operating costs and expenses:
Lease operating expenses													64,043	67,984	66,576
Gathering and transportation													10,660	13,133	7,948
Depreciation, depletion and amortization													61,700	112,277	172,214
Asset retirement obligations accretion													9,756	9,406	9,116
Ceiling test write-down of oil and natural gas properties														110,709	517,880
General and administrative expenses													31,574	34,923	34,101
Total costs and expenses													177,733	348,432	807,835
Operating income (loss)													77,967	(109,509)	(590,782)
Interest expense:
Incurred														184	3,050
Capitalized														(184)	(3,050)
Income (loss) before income tax benefit													77,967	(109,509)	(590,782)
Income tax expense (benefit)													16,523	344	(125,851)
Net income (loss)													61,444	(109,853)	(464,931)
Eliminations
Operating costs and expenses:
Depreciation, depletion and amortization													2,848	8,493
Ceiling test write-down of oil and natural gas properties														140,049	(147,589)
Total costs and expenses													2,848	148,542	(147,589)
Operating income (loss)													(2,848)	(148,542)	147,589
Earnings (loss) of affiliates													(61,444)	109,853	464,931
Interest expense:
Income (loss) before income tax benefit													(64,292)	(38,689)	612,520
Net income (loss)													$ (64,292)	$ (38,689)	$ 612,520
[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. See Note 1 and Note 2 for additional information.

Supplemental Guarantor Inform86

Supplemental Guarantor Information - Condensed Consolidating Statement of Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended												12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating activities:
Net income (loss)	$ 23,365	$ (1,297)	$ 33,315	$ 24,299	$ 16,483	[1]	$ 45,928	[1]	$ (120,922)	[1]	$ (190,509)	[1]	$ 79,682	$ (249,020)	$ (1,044,718)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion													155,682	211,609	394,071
Ceiling test write-down of oil and natural gas properties							57,900		$ 104,600		116,600		0	279,063	987,238
Gain on exchange of debt							$ (123,900)						(7,811)	(123,923)
Debt issuance costs write-down/amortization of debt items													1,715	2,548	4,411
Share-based compensation													7,191	11,013	10,242
Derivative (gain) loss													(4,199)	2,926	(14,375)
Cash receipts (payments) on derivative settlements, net													4,199	4,746	6,703
Deferred income taxes													217	28,392	(203,272)
Changes in operating assets and liabilities:
Oil and natural gas receivables													(2,370)	(7,005)	32,236
Joint interest receivables													2,131	12	21,645
Insurance reimbursements													31,740
Income taxes													(1,063)	(64,274)	(7)
Prepaid expenses and other assets													3,238	(14,946)	17,816
Escrow deposit - Apache lawsuit													(49,500)
Asset retirement obligation settlements													(72,409)	(72,320)	(32,555)
Accounts payable, accrued liabilities and other													10,965	5,359	(46,207)
Net cash provided by (used in) operating activities													159,408	14,180	133,228
Investing activities:
Investment in oil and natural gas properties and equipment													(130,048)	(48,606)	(230,161)
Changes in operating assets and liabilities associated with investing activities													23,874	(35,194)	(55,425)
Proceeds from sales of assets, net														1,500	372,939
Purchases of furniture, fixtures and other													(933)	(96)	(1,278)
Net cash provided by (used in) investing activities													(107,107)	(82,396)	86,075
Financing activities:
Borrowings of long-term debt - revolving bank credit facility														340,000	263,000
Repayments of long-term debt - revolving bank credit facility														(340,000)	(710,000)
Debt exchange/issuance costs													(421)	(18,464)	(6,669)
Other													(1,295)	(928)	(886)
Net cash provided by (used in) financing activities													(23,479)	53,038	(157,555)
Increase (decrease) in cash and cash equivalents													28,822	(15,178)	61,748
Cash and cash equivalents, beginning of period				70,236							85,414		70,236	85,414	23,666
Cash and cash equivalents, end of period	99,058				70,236								99,058	70,236	85,414
Parent Company
Operating activities:
Net income (loss)													82,530	(100,478)	(1,192,307)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion													81,378	81,433	212,741
Ceiling test write-down of oil and natural gas properties														28,305	616,947
Gain on exchange of debt													(7,811)	(123,923)
Debt issuance costs write-down/amortization of debt items													1,715	2,548	4,411
Share-based compensation													7,191	11,013	10,242
Derivative (gain) loss													(4,199)	2,926	(14,375)
Cash receipts (payments) on derivative settlements, net													4,199	4,746	6,703
Deferred income taxes													217	28,048	(77,421)
Earnings (loss) of affiliates													(61,444)	109,853	464,931
Changes in operating assets and liabilities:
Oil and natural gas receivables													(3,491)	1,630	39,078
Joint interest receivables													2,131	12	21,645
Insurance reimbursements													31,740
Income taxes													(17,586)	(64,274)	(7)
Prepaid expenses and other assets													3,447	(14,395)	(13,916)
Escrow deposit - Apache lawsuit													(49,500)
Asset retirement obligation settlements													(55,672)	(49,303)	(26,637)
Accounts payable, accrued liabilities and other													127,496	45,817	(141,608)
Net cash provided by (used in) operating activities													142,341	(36,042)	(89,573)
Investing activities:
Investment in oil and natural gas properties and equipment													(105,179)	(37,418)	(31,534)
Changes in operating assets and liabilities associated with investing activities													16,072	4,340	(29,806)
Proceeds from sales of assets, net														1,000	372,939
Investment in subsidiary															(1,445)
Purchases of furniture, fixtures and other													(933)	(96)	(1,278)
Net cash provided by (used in) investing activities													(90,040)	(32,174)	308,876
Financing activities:
Borrowings of long-term debt - revolving bank credit facility														340,000	263,000
Repayments of long-term debt - revolving bank credit facility														(340,000)	(710,000)
Debt exchange/issuance costs													(421)	(18,464)	(6,669)
Other													(1,295)	(928)	(886)
Net cash provided by (used in) financing activities													(23,479)	53,038	(157,555)
Increase (decrease) in cash and cash equivalents													28,822	(15,178)	61,748
Cash and cash equivalents, beginning of period				$ 70,236							$ 85,414		70,236	85,414
Cash and cash equivalents, end of period	$ 99,058				$ 70,236								99,058	70,236	85,414
Guarantor Subsidiaries
Operating activities:
Net income (loss)													61,444	(109,853)	(464,931)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion													71,456	121,683	181,330
Ceiling test write-down of oil and natural gas properties														110,709	517,880
Deferred income taxes														344	(125,851)
Changes in operating assets and liabilities:
Oil and natural gas receivables													1,121	(8,635)	(6,842)
Income taxes													16,523
Prepaid expenses and other assets													(108,773)	(78,547)	122,977
Asset retirement obligation settlements													(16,737)	(23,017)	(5,918)
Accounts payable, accrued liabilities and other													(7,967)	37,538	4,156
Net cash provided by (used in) operating activities													17,067	50,222	222,801
Investing activities:
Investment in oil and natural gas properties and equipment													(24,869)	(11,188)	(198,627)
Changes in operating assets and liabilities associated with investing activities													7,802	(39,534)	(25,619)
Proceeds from sales of assets, net														500
Net cash provided by (used in) investing activities													(17,067)	(50,222)	(224,246)
Financing activities:
Investment from parent															1,445
Net cash provided by (used in) financing activities															1,445
11.00% 1.5 Lien Term Loan, Due November 2019
Financing activities:
Issuance of Term Loan														75,000
Payment of interest													(8,227)	(2,570)
11.00% 1.5 Lien Term Loan, Due November 2019 | Parent Company
Financing activities:
Issuance of Term Loan														75,000
Payment of interest													(8,227)	(2,570)
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020
Financing activities:
Payment of interest													(7,335)
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020 | Parent Company
Financing activities:
Payment of interest													(7,335)
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021
Financing activities:
Payment of interest													(6,201)
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021 | Parent Company
Financing activities:
Payment of interest													(6,201)
9.00 % Second Lien Term Loan, Due May 2020
Financing activities:
Issuance of Term Loan															297,000
9.00 % Second Lien Term Loan, Due May 2020 | Parent Company
Financing activities:
Issuance of Term Loan															297,000
Eliminations
Operating activities:
Net income (loss)													(64,292)	(38,689)	612,520
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion													2,848	8,493
Ceiling test write-down of oil and natural gas properties														140,049	(147,589)
Earnings (loss) of affiliates													61,444	(109,853)	(464,931)
Changes in operating assets and liabilities:
Prepaid expenses and other assets													108,564	77,996	(91,245)
Accounts payable, accrued liabilities and other													$ (108,564)	$ (77,996)	91,245
Investing activities:
Investment in subsidiary															1,445
Net cash provided by (used in) investing activities															1,445
Financing activities:
Investment from parent															(1,445)
Net cash provided by (used in) financing activities															$ (1,445)
[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. See Note 1 and Note 2 for additional information.

Supplemental Oil and Gas Disc87

Supplemental Oil and Gas Disclosures - Capitalized Costs Related to Oil and Natural Gas (Details) - USD ($) $ in Millions		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Net capitalized cost:
Proved oil and natural gas properties and equipment		$ 8,102	$ 7,932.5	$ 7,882.3
Unproved oil and natural gas properties and equipment				20.2
Accumulated depreciation, depletion and amortization related to oil, NGLs and natural gas activities	[1]	(7,525)	(7,387.8)	(6,916.2)
Net capitalized costs related to producing activities		$ 577	$ 544.7	$ 986.3
[1]	Includes ceiling test write-down in 2016 and 2015.

Supplemental Oil and Gas Disc88

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Costs incurred:
Proved properties acquisitions	[1]	$ 1.1	$ 1.3	$ 15.6
Exploration	[1],[2],[3]	62	4.8	152.4
Development	[1]	92.5	56.9	65.5
Unproved property acquisitions	[1]		0.5	0.1
Total costs incurred in oil and gas property acquisition, exploration and development activities	[1]	$ 155.6	$ 63.5	$ 233.6
[1]	Includes net additions from capitalized ARO of $21.3 million in 2017, net additions from capitalized ARO of $10.8 million in 2016, and net reductions from capitalized ARO of $0.4 million during 2015. 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 $4.2 million, $4.1 million and $5.7 million during 2017, 2016 and 2015, respectively.
[3]	Includes seismic costs of $0.5 million, $0.2 million and $3.2 million incurred during 2017, 2016 and 2015, respectively.

Supplemental Oil and Gas Disc89

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Capitalized Costs Oil And Gas Producing Activities Net [Abstract]
Additions (reductions) of asset retirement obligations	$ 21.3	$ 10.8	$ (0.4)
Seismic costs	0.5	0.2	3.2
Geological and geophysical costs	$ 4.2	$ 4.1	$ 5.7

Supplemental Oil and Gas Disc90

Supplemental Oil and Gas Disclosures - Schedule of Depreciation, Depletion, Amortization and Accretion Expense (Details) - $ / Boe	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Capitalized Costs Oil And Gas Producing Activities Net [Abstract]
Depreciation, depletion, amortization and accretion per Boe	10.68	13.77	23.11

Supplemental Oil and Gas Disc91

Supplemental Oil and Gas Disclosures - Additional Information (Details)	12 Months Ended
	Dec. 31, 2017
Capitalized Costs Oil And Gas Producing Activities Net [Abstract]
Percentage non-operated non-producing reserves	25.00%
Present value discounted percentage	10.00%

Supplemental Oil and Gas Disc92

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, 2017MMBoeBcfeMMBblsBcf		Dec. 31, 2016MMBoeBcfeMMBblsBcf		Dec. 31, 2015MMBoeBcfeMMBblsBcf
Reserve Quantities [Line Items]
Revisions of previous estimates | MMBoe		6.2		14.2
Oil
Reserve Quantities [Line Items]
Proved reserves, beginning balance		32.9		35.5		61.7
Revisions of previous estimates		4.5	[1]	4.6	[2]	4.8	[3]
Revisions related to sold properties	[4]					(12.1)
Extensions and discoveries		4.1	[5]			2.4	[6]
Sales of reserves	[7]					(13.5)
Production		(7.1)		(7.2)		(7.8)
Proved reserves, ending balance		34.4		32.9		35.5
Oil | Proved Developed Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance		26.6		29.4
Proved reserves, ending balance		26.1		26.6		29.4
Oil | Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance		6.3		6.1
Proved reserves, ending balance		8.3	[8]	6.3		6.1
NGLs
Reserve Quantities [Line Items]
Proved reserves, beginning balance		8.2		6.6		15.8
Revisions of previous estimates		0.7	[1]	3.1	[2]	(0.9)	[3]
Revisions related to sold properties	[4]					(4.8)
Extensions and discoveries		0.3	[5]			0.2	[6]
Sales of reserves	[7]					(2.1)
Production		(1.4)		(1.5)		(1.6)
Proved reserves, ending balance		7.8		8.2		6.6
NGLs | Proved Developed Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance		7.6		6.4
Proved reserves, ending balance		7.2		7.6		6.4
NGLs | Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance		0.6		0.2
Proved reserves, ending balance		0.6	[8]	0.6		0.2
Natural Gas
Reserve Quantities [Line Items]
Proved reserves, beginning balance | Bcf		197,800		205,400		254,900
Revisions of previous estimates | Bcf		25,800	[1]	32,100	[2]	4,900	[3]
Revisions related to sold properties | Bcf	[4]					(2,900)
Extensions and discoveries | Bcf		5,400	[5]			8,800	[6]
Purchase of minerals in place | Bcf	[9]					6,100
Sales of reserves | Bcf	[7]					(20,200)
Production | Bcf		(36,800)		(39,700)		(46,200)
Proved reserves, ending balance | Bcf		192,200		197,800		205,400
Natural Gas | Proved Developed Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance | Bcf		183,100		198,500
Proved reserves, ending balance | Bcf		173,500		183,100		198,500
Natural Gas | Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance | Bcf		14,700		6,900
Proved reserves, ending balance | Bcf		18,700	[8]	14,700		6,900
Barrel Equivalent
Reserve Quantities [Line Items]
Proved reserves, beginning balance | MMBoe	[10]	74		76.4		120
Revisions of previous estimates | MMBoe	[10]	9.6	[1]	13	[2]	4.7	[3]
Revisions related to sold properties | MMBoe	[4],[10]					(17.4)
Extensions and discoveries | MMBoe	[10]	5.2	[5]			4.1	[6]
Purchase of minerals in place | MMBoe	[9],[10]					1
Sales of reserves | MMBoe	[7],[10]					(19)
Production | MMBoe	[10]	(14.6)		(15.4)		(17)
Proved reserves, ending balance | MMBoe	[10]	74.2		74		76.4
Barrel Equivalent | Proved Developed Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance | MMBoe	[10]	64.7		69
Proved reserves, ending balance | MMBoe	[10]	62.2		64.7		69
Barrel Equivalent | Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance | MMBoe	[10]	9.3		7.4
Proved reserves, ending balance | MMBoe	[10]	12	[8]	9.3		7.4
Natural Gas Equivalent
Reserve Quantities [Line Items]
Proved reserves, beginning balance | Bcfe	[10]	444		458.1		720
Revisions of previous estimates | Bcfe	[10]	57.4	[1]	78.1	[2]	28	[3]
Revisions related to sold properties | Bcfe	[4],[10]					(104.3)
Extensions and discoveries | Bcfe	[10]	31.3	[5]			24.4	[6]
Purchase of minerals in place | Bcfe	[9],[10]					6.1
Sales of reserves | Bcfe	[7],[10]					(113.8)
Production | Bcfe	[10]	(87.4)		(92.2)		(102.3)
Proved reserves, ending balance | Bcfe	[10]	445.3		444		458.1
Natural Gas Equivalent | Proved Developed Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance | Bcfe	[10]	388.2		413.5
Proved reserves, ending balance | Bcfe	[10]	373.3		388.2		413.5
Natural Gas Equivalent | Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Proved reserves, beginning balance | Bcfe	[10]	55.8		44.6
Proved reserves, ending balance | Bcfe	[10]	72	[8]	55.8		44.6
[1]	Primarily related to upward revisions of 6.2 MMBoe, which included upwards revisions of 1.1 MMBoe at our Mississippi Canyon 698 (Big Bend) field, 1.0 MMBoe at our Fairway field, 0.8 MMBoe at our Ewing Bank 910 field and 0.8 MMBoe at our Viosca Knoll 783 (Virgo) field. Additionally, increases of 3.4 MMBoe were due to price revisions.
[2]	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.
[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]	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 related to extensions and discoveries at our Ship Shoal 349 (Mahogany) field of 3.5 MMBoe and at our Main Pass 286 field of 1.5 MMBoe.
[6]	Primarily due to increases at our Ewing Bank 910 field.
[7]	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.
[8]	We believe that we will be able to develop all but 1.8 MMBoe (approximately 15%) of the total of 12.0 MMBoe reserves classified as proved undeveloped (“PUDs”) at December 31, 2017, within five years from the date such reserves were initially recorded. The lone exceptions are 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. Two sidetrack PUD locations in this field will be delayed until an existing well is depleted and available to sidetrack. Based on the latest reserve report, these PUD locations are expected to be developed in 2023.
[9]	Primarily due to purchase of additional interest at our Brazos A-133 field.
[10]	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 Disc93

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, 2017		Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Reserve Quantities [Line Items]
Revisions of previous estimates			6.2		14.2
Proved undeveloped reserves, that will not be developed within five years			1.8
Percentage of proved undeveloped reserves that will be developed within five years			15.00%
Wells expected to be drilled, year			2,023
Barrel Equivalent
Reserve Quantities [Line Items]
Revisions of previous estimates	[2]		9.6	[1]	13	[3]	4.7	[4]
Extensions and discoveries	[2]		5.2	[5]			4.1	[6]
Proved reserves	[2]		74.2		74		76.4		120
Barrel Equivalent | Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Proved reserves	[2]		12	[7]	9.3		7.4
Changes at Ship Shoal 349 Field (Mahogany)
Reserve Quantities [Line Items]
Revisions of previous estimates							7.4
Extensions and discoveries			3.5
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 Fairway Field
Reserve Quantities [Line Items]
Revisions of previous estimates			1		1.5		1.1
Changes Due to Price
Reserve Quantities [Line Items]
Revisions of previous estimates			3.4		1.2		10.7
Changes at the Yellow Rose Field
Reserve Quantities [Line Items]
Proved estimated reserve at the date of sale		19
Changes at the Viosca Knoll 823
Reserve Quantities [Line Items]
Revisions of previous estimates					3.8
Changes at the Mississippi Canyon 782 field
Reserve Quantities [Line Items]
Revisions of previous estimates					1.3
Changes at the Main Pass 108 field
Reserve Quantities [Line Items]
Revisions of previous estimates					1.2
Mississippi Canyon 698 (Big Bend)
Reserve Quantities [Line Items]
Revisions of previous estimates			1.1
Ewing Bank 910 Field
Reserve Quantities [Line Items]
Revisions of previous estimates			0.8
Viosca Knoll 783 (Virgo) Field
Reserve Quantities [Line Items]
Revisions of previous estimates			0.8
Main Pass 286 Field
Reserve Quantities [Line Items]
Extensions and discoveries			1.5
[1]	Primarily related to upward revisions of 6.2 MMBoe, which included upwards revisions of 1.1 MMBoe at our Mississippi Canyon 698 (Big Bend) field, 1.0 MMBoe at our Fairway field, 0.8 MMBoe at our Ewing Bank 910 field and 0.8 MMBoe at our Viosca Knoll 783 (Virgo) field. Additionally, increases of 3.4 MMBoe were due to price revisions.
[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]	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.
[4]	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.
[5]	Primarily related to extensions and discoveries at our Ship Shoal 349 (Mahogany) field of 3.5 MMBoe and at our Main Pass 286 field of 1.5 MMBoe.
[6]	Primarily due to increases at our Ewing Bank 910 field.
[7]	We believe that we will be able to develop all but 1.8 MMBoe (approximately 15%) of the total of 12.0 MMBoe reserves classified as proved undeveloped (“PUDs”) at December 31, 2017, within five years from the date such reserves were initially recorded. The lone exceptions are 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. Two sidetrack PUD locations in this field will be delayed until an existing well is depleted and available to sidetrack. Based on the latest reserve report, these PUD locations are expected to be developed in 2023.

Supplemental Oil and Gas Disc94

Supplemental Oil and Gas Disclosures - Schedule of Prices Weighted by Field Production Related to Proved Reserves (Details)	12 Months Ended
	Dec. 31, 2017$ / Boe$ / Mcf	Dec. 31, 2016$ / Boe$ / Mcf	Dec. 31, 2015$ / Boe$ / Mcf	Dec. 31, 2014$ / Boe$ / Mcf
Oil
Reserve Quantities [Line Items]
Weighted price	46.58	36.28	46.94	91.12
NGLs
Reserve Quantities [Line Items]
Weighted price	22.65	16.82	17.60	34.63
Natural Gas
Reserve Quantities [Line Items]
Weighted price | $ / Mcf	2.86	2.47	2.50	4.27

Supplemental Oil and Gas Disc95

Supplemental Oil and Gas Disclosures - Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($)	Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Standardized Measure of Discounted Future Net Cash Flows
Future cash inflows	$ 2,328,800,000		$ 1,818,400,000	$ 2,296,700,000
Production	(813,800,000)		(691,500,000)	(840,100,000)
Development	(157,400,000)		(141,100,000)	(161,400,000)
Dismantlement and abandonment	(361,900,000)		(427,700,000)	(471,800,000)
Income taxes	(74,800,000)	[1]	0	0
Future net cash inflows before 10% discount	920,900,000		558,100,000	823,400,000
10% annual discount factor	(180,300,000)		(79,800,000)	(209,500,000)
Standardized measure of discounted future net cash flows	$ 740,600,000		$ 478,300,000	$ 613,900,000	$ 1,702,800,000
[1]	No future income taxes were estimated for 2016 and 2015 as our tax position had sufficient tax basis to offset estimated future taxes. State income taxes were disregarded due to immateriality.

Supplemental Oil and Gas Disc96

Supplemental Oil and Gas Disclosures - Standardized Measure of Discounted Future Net Cash Flows (Parenthetical) (Details) - USD ($)	Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2015
Extractive Industries [Abstract]
Income taxes	$ (74,800,000)	[1]	$ 0	$ 0
[1]	No future income taxes were estimated for 2016 and 2015 as our tax position had sufficient tax basis to offset estimated future taxes. State income taxes were disregarded due to immateriality.

Supplemental Oil and Gas Disc97

Supplemental Oil and Gas Disclosures - Change in Standard Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Changes in Standardized Measure
Changes in Standardized Measure, beginning of year	$ 478.3	$ 613.9	$ 1,702.8
Sales and transfers of oil and gas produced, net of production costs	(315.3)	(218.6)	(289.1)
Net changes in price, net of future production costs	288	(275.2)	(1,455.6)
Extensions and discoveries, net of future production and development costs	119.3		65.3
Changes in estimated future development costs	(38.9)	(32.5)	(8.5)
Previously estimated development costs incurred	102.8	114.5	158.9
Revisions of quantity estimates	106.4	190.1	137.9
Accretion of discount	30.2	52.6	150.6
Net change in income taxes	(54.7)		600.8
Purchases of reserves in-place			6
Sales of reserves in-place			(401.4)
Changes in production rates due to timing and other	24.5	33.5	(53.8)
Net increase (decrease) in standardized measure	262.3	(135.6)	(1,088.9)
Changes in Standardized measure, end of year	$ 740.6	$ 478.3	$ 613.9