Clayton Williams Energy (CWEI) 10-K 2 Mar 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 23, 2017	Jun. 30, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	CLAYTON WILLIAMS ENERGY INC /DE
Entity Central Index Key	880,115
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Public Float			$ 161,820,517
Entity Common Stock, Shares Outstanding		17,629,338
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
CURRENT ASSETS
Cash and cash equivalents	$ 573,025	$ 7,780
Accounts receivable:
Oil and gas sales	18,752	16,660
Joint interest and other, net of allowance for doubtful accounts of $2,919 at December 31, 2016 and $2,447 at December 31, 2015	4,148	3,661
Affiliates	258	260
Inventory	25,781	31,455
Deferred income taxes	6,520	6,526
Prepaids and other	2,702	2,463
TOTAL CURRENT ASSETS	631,186	68,805
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	1,717,209	2,585,502
Pipelines and other midstream facilities	63,228	60,120
Contract drilling equipment	118,256	123,876
Other	20,822	19,371
PROPERTY AND EQUIPMENT, GROSS	1,919,515	2,788,869
Less accumulated depreciation, depletion and amortization	(1,063,379)	(1,587,585)
Property and equipment, net	856,136	1,201,284
OTHER ASSETS
Investments and other	7,317	17,331
Total assets	1,494,639	1,287,420
Accounts payable:
Trade	44,809	29,197
Oil and gas sales	20,862	19,490
Affiliates	252	383
Fair value of commodity derivatives	12,895	0
Accrued liabilities and other	27,948	16,669
TOTAL CURRENT LIABILITIES	106,766	65,739
NON-CURRENT LIABILITIES
Long-term debt	847,995	742,410
Fair value of common stock warrants	246,743	0
Deferred income taxes	76,590	108,996
Asset retirement obligations	47,223	48,728
Accrued compensation under non-equity award plans	4,655	16,254
Deferred revenue from volumetric production payment and other	4,136	5,695
TOTAL NON-CURRENT LIABILITIES	1,227,342	922,083
COMMITMENTS AND CONTINGENCIES (see Note 15)
SHAREHOLDERS’ EQUITY
Preferred stock, par value $.10 per share, authorized — 3,000,000 shares; issued and outstanding — 3,500 shares at December 31, 2016 and none at December 31, 2015	0	0
Common stock, par value $.10 per share, authorized — 30,000,000 shares; issued and outstanding — 17,630,801 shares at December 31, 2016 and 12,169,536 at December 31, 2015	1,763	1,216
Additional paid-in capital	305,223	152,686
Retained earnings (accumulated deficit)	(146,455)	145,696
TOTAL STOCKHOLDERS' EQUITY	160,531	299,598
Total liabilities and equity	$ 1,494,639	$ 1,287,420

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 2,919	$ 2,447
Preferred stock, par value (in dollars per share)	$ 0.10	$ 0.10
Preferred stock, authorized shares (in shares)	3,000,000	3,000,000
Preferred stock, issued shares (in shares)	3,500	0
Preferred stock, outstanding shares (in shares)	3,500	0
Common stock, par value (in dollars per share)	$ 0.10	$ 0.10
Common stock, authorized shares (in shares)	30,000,000	30,000,000
Common stock, issued shares (in shares)	17,630,801	12,169,536
Common stock, outstanding shares (in shares)	17,630,801	12,169,536

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
REVENUES
Oil and gas sales	$ 160,331	$ 217,485	$ 418,330
Midstream services	5,688	6,122	6,705
Drilling rig services	0	23	28,028
Other operating revenues	123,392	8,742	15,393
Total revenues	289,411	232,372	468,456
COSTS AND EXPENSES
Production	70,920	87,557	105,296
Exploration:
Abandonments and impairments	3,536	6,509	20,647
Seismic and other	925	1,318	2,314
Midstream services	2,173	1,688	2,212
Drilling rig services	3,938	5,238	19,232
Depreciation, depletion and amortization	145,614	162,262	154,356
Impairment of property and equipment	7,593	41,917	12,027
Accretion of asset retirement obligations	4,364	3,945	3,662
General and administrative	22,988	22,788	34,524
Other operating expenses	5,046	12,585	2,547
Total costs and expenses	267,097	345,807	356,817
Operating income (loss)	22,314	(113,435)	111,639
OTHER INCOME (EXPENSE)
Interest expense	(93,693)	(54,422)	(50,907)
Gain on early extinguishment of long-term debt	3,967	0	0
Loss on change in fair value of common stock warrants	(229,980)	0	0
Gain (loss) on commodity derivatives	(20,289)	12,519	4,789
Impairment of investments and other	(4,797)	2,003	3,047
Total other income (expense)	(344,792)	(39,900)	(43,071)
Income (loss) before income taxes	(322,478)	(153,335)	68,568
Income tax (expense) benefit	30,327	55,139	(24,687)
NET INCOME (LOSS)	$ (292,151)	$ (98,196)	$ 43,881
Net income (loss) per common share:
Basic (in dollars per share)	$ (20.87)	$ (8.07)	$ 3.61
Diluted (in dollars per share)	$ (20.87)	$ (8.07)	$ 3.61
Weighted average common shares outstanding:
Basic (in shares)	14,000	12,170	12,167
Diluted (in shares)	14,000	12,170	12,167

CONSOLIDATED STATEMENT OF STOCK

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Retained Earnings
BALANCE at Dec. 31, 2013	$ 353,783	$ 1,216	$ 152,556	$ 200,011
BALANCE (in shares) at Dec. 31, 2013		12,166
Increase (Decrease) in Stockholders' Equity
Net income (loss)	43,881	$ 0	0	43,881
Issuance of stock through compensation plans, including income tax benefits	130	$ 0	130	0
Issuance of stock through compensation plans, including income tax benefits (in shares)		4
BALANCE at Dec. 31, 2014	397,794	$ 1,216	152,686	243,892
BALANCE (in shares) at Dec. 31, 2014		12,170
Increase (Decrease) in Stockholders' Equity
Net income (loss)	(98,196)	$ 0	0	(98,196)
BALANCE at Dec. 31, 2015	299,598	$ 1,216	152,686	145,696
BALANCE (in shares) at Dec. 31, 2015		12,170
Increase (Decrease) in Stockholders' Equity
Net income (loss)	(292,151)	$ 0	0	(292,151)
Sale of common stock	147,340	$ 506	146,834	0
Sale of common stock (in shares)		5,051
Issuance of stock through compensation plans, including income tax benefits	5,744	$ 41	5,703	0
Issuance of stock through compensation plans, including income tax benefits (in shares)		410
BALANCE at Dec. 31, 2016	$ 160,531	$ 1,763	$ 305,223	$ (146,455)
BALANCE (in shares) at Dec. 31, 2016		17,631

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ (292,151)	$ (98,196)	$ 43,881
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	145,614	162,262	154,356
Impairment of property and equipment	7,593	41,917	12,027
Abandonments and impairments	3,536	6,509	20,647
(Gain) loss on sales of assets and impairment of inventory, net	(118,786)	3,018	(9,138)
Deferred income tax expense (benefit)	(32,400)	(55,218)	24,460
Non-cash employee compensation	(6,019)	(2,674)	1,397
(Gain) loss on commodity derivatives	20,289	(12,519)	(4,789)
Cash settlements of commodity derivatives	(7,394)	12,519	7,099
Loss on change in fair value of common stock warrants	229,980	0	0
Accretion of asset retirement obligations	4,364	3,945	3,662
Amortization of debt issue costs and original issue discount	7,106	3,246	3,030
Gain on early extinguishment of long-term debt	(3,967)	0	0
Amortization of deferred revenue from volumetric production payment	(1,479)	(6,822)	(7,708)
Paid in-kind interest expense	27,196	0	0
Impairment of investment and other	8,751	1,542	0
Changes in operating working capital:
Accounts receivable	(2,577)	30,817	5,255
Accounts payable	10,657	(35,860)	4,561
Other	10,414	(2,327)	(619)
Net cash provided by operating activities	10,727	52,159	258,121
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(111,541)	(179,827)	(422,473)
Termination of volumetric production payment	0	(13,703)	0
Proceeds from sales of assets	423,905	71,460	104,529
(Increase) decrease in equipment inventory	1,414	1,733	(1,886)
Proceeds from volumetric production payment and other	(551)	2,942	833
Net cash provided by (used in) investing activities	313,227	(117,395)	(318,997)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	343,237	45,000	102,139
Net repayments of Senior Notes	(95,001)	0	0
Repayments of long-term debt	(160,000)	0	(40,000)
Payment of debt issuance costs	(11,048)	0	0
Proceeds from sale of common stock	147,340	0	0
Proceeds from issuance of common stock warrants	16,763	0	0
Proceeds from exercise of stock options	0	0	130
Net cash provided by financing activities	241,291	45,000	62,269
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	565,245	(20,236)	1,393
CASH AND CASH EQUIVALENTS
Beginning of period	7,780	28,016	26,623
End of period	573,025	7,780	28,016
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	49,451	51,293	47,817
Cash paid for income taxes	$ 135	$ 0	$ 1,600

Nature of Operations

Nature of Operations	12 Months Ended
	Dec. 31, 2016
Nature of Operations Disclosures [Abstract]
Nature of Operations	Nature of Operations Clayton Williams Energy, Inc., a Delaware corporation, is an independent oil and gas company engaged in the exploration for and development and production of oil and natural gas primarily in its core area in Southern Reeves County, Texas. Unless the context otherwise requires, references to “CWEI” mean Clayton Williams Energy, Inc., the parent company, and references to “the Company,” “we,” “us” or “our” mean Clayton Williams Energy, Inc. and its consolidated subsidiaries. Approximately 17.6% of CWEI’s outstanding common stock is beneficially owned by Clayton W. Williams, Jr. (“Mr. Williams”), Chairman of the Board and Chief Executive Officer of the Company, and approximately 17.3% is owned by a partnership in which Mr. Williams’ adult children are limited partners, and Mel G. Riggs, our President, is the sole member in the general partner. Ares Management, LLC (“Ares”) beneficially owns, either individually or through its affiliates, 42.0% of the outstanding shares of our common stock. In addition, Ares possesses the right to elect up to two members of our Board and to recommend one other director to the Nominating and Governance Committee of the Board for appointment to the Board. Through its elected and recommended Board members and substantial ownership of our common stock, Ares has significant influence in matters voted on by our shareholders, including the election of our Board members. Substantially all of our oil and gas production is sold under short-term contracts which are market-sensitive. Accordingly, our results of operations and capital resources are highly dependent upon prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. These factors include the level of global supply and demand for oil and natural gas, market uncertainties, weather conditions, domestic governmental regulations and taxes, political and economic conditions in oil producing countries, price and availability of alternative fuels and overall domestic and foreign economic conditions.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Estimates and Assumptions The preparation of these consolidated financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ materially from those estimates. The accounting policies most affected by management’s estimates and assumptions are as follows: • Provisions for depreciation, depletion and amortization and estimates of non-equity plans are based on estimates of proved reserves; • Impairments of long-lived assets are based on estimates of future net cash flows and, when applicable, the estimated fair values of impaired assets; • Exploration expenses related to impairments of unproved acreage are based on estimates of fair values of the underlying leases; • Asset retirement obligations (“ARO”) are based on estimates regarding the timing and cost of future asset retirements; • Valuation of derivative financial instruments are based on the fair value of commodity derivatives; • Valuation of stock-based compensation is based on the grant date fair value; • Valuation of common stock warrants are based on their fair value using the Black-Scholes method; • Impairments of inventory are based on estimates of fair values of tubular goods and other well equipment held in inventory; and • Exploration expenses related to well abandonment costs are based on the judgments regarding the productive status of in-progress exploratory wells. Principles of Consolidation The consolidated financial statements include the accounts of CWEI and its wholly owned subsidiaries. We account for our undivided interests in oil and gas limited partnerships using the proportionate consolidation method. Under this method, we consolidate our proportionate share of assets, liabilities, revenues and expenses of such limited partnerships. Less than 5% of our consolidated total assets and total revenues are derived from oil and gas limited partnerships. Substantially all intercompany transactions and balances associated with the consolidated operations have been eliminated. Oil and Gas Properties We follow the successful efforts method of accounting for oil and gas properties, whereby costs of productive wells, developmental dry holes and productive leases are capitalized into appropriate groups of properties based on geographical and geological similarities. These capitalized costs are amortized using the unit-of-production method based on estimated proved reserves. Proceeds from sales of properties are credited to property costs, and a gain or loss is recognized when a significant portion of an amortization base is sold or abandoned. Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to exploration expense if and when the well is determined to be nonproductive. The determination of an exploratory well’s ability to produce must be made within one year from the completion of drilling activities. The acquisition costs of unproved acreage are initially capitalized and are carried at cost, net of accumulated impairment provisions, until such leases are transferred to proved properties or charged to exploration expense as impairments of unproved properties. Pipelines and Other Midstream Facilities and Other Property and Equipment Pipelines and other midstream facilities consist of pipelines to transport oil, natural gas and water, natural gas processing facilities and compressors. Other property and equipment consists primarily of field equipment and facilities, office equipment, leasehold improvements and vehicles. Major renewals and betterments are capitalized while repairs and maintenance are charged to expense as incurred. The cost of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and any gain or loss is included in operating income (loss) in the accompanying consolidated statements of operations and comprehensive income (loss). Depreciation of pipelines and other midstream facilities and other property and equipment is computed on the straight-line method over the estimated useful lives of the assets, which generally range from 3 to 30 years. Contract Drilling We conduct contract drilling operations through Desta Drilling, L.P. (“Desta Drilling”), a wholly owned subsidiary of CWEI. Desta Drilling recognizes revenues and expenses from daywork drilling contracts as the work is performed, but defers revenues and expenses from footage or turnkey contracts until the well is substantially completed or until a loss, if any, on a contract is determinable. Property and equipment, including buildings, major replacements, improvements and capitalized interest on construction-in-progress, are capitalized and are depreciated using the straight-line method over estimated useful lives of 3 to 40 years. Upon disposition, the costs and related accumulated depreciation of assets are eliminated from the accounts and the resulting gain or loss is recognized. Valuation of Property and Equipment Our long-lived assets, including proved oil and gas properties and contract drilling equipment, are assessed for potential impairment in their carrying values, based on depletable groupings, whenever events or changes in circumstances indicate such impairment may have occurred. An impairment is recognized when the estimated undiscounted future net cash flows of the asset are less than its carrying value. Any such impairment is recognized based on the difference in the carrying value and estimated fair value of the impaired asset. Unproved oil and gas properties are periodically assessed, and any impairment in value is charged to exploration costs. The amount of impairment recognized on unproved properties which are not individually significant is determined by impairing the costs of such properties within appropriate groups based on our historical experience, acquisition dates and average lease terms. The valuation of unproved properties is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values. Asset Retirement Obligations We recognize a liability for the present value of all legal obligations associated with the retirement of tangible, long-lived assets and capitalize an equal amount as a cost of the asset. The cost associated with the asset retirement obligation, along with any estimated salvage value, is included in the computation of depreciation, depletion and amortization. Income Taxes We utilize the asset and liability method to account for income taxes. Under this method of accounting for income taxes, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the consolidated financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in enacted tax rates is recognized in the consolidated statements of operations and comprehensive income (loss) in the period that includes the enactment date. We also record any financial statement recognition and disclosure requirements for uncertain tax positions taken or expected to be taken in a tax return. Financial statement recognition of the tax position is dependent on an assessment of a 50% or greater likelihood that the tax position will be sustained upon examination, based on the technical merits of the position. Any interest and penalties related to uncertain tax positions are recorded as interest expense. Hedging Transactions From time to time, we utilize commodity derivative instruments, consisting of swaps, floors and collars, to attempt to optimize the price received for our oil and gas production. All of our commodity derivative instruments are recognized as assets or liabilities in the balance sheet, measured at fair value. The accounting for changes in the fair value of a commodity derivative depends on both the intended purpose and the formal designation of the commodity derivative. Designation is established at the inception of a commodity derivative, but subsequent changes to the designation are permitted. For commodity derivatives designated as cash flow hedges and meeting the effectiveness guidelines under applicable accounting standards, changes in fair value are recognized in other comprehensive income (loss) until the hedged item is recognized in earnings. Hedge effectiveness is measured quarterly based on relative changes in fair value between the commodity derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Changes in fair value of commodity derivative instruments which are not designated as cash flow hedges or do not meet the effectiveness guidelines are recorded in earnings as the changes occur. If designated as cash flow hedges, actual gains or losses on settled commodity derivatives are recorded as oil and gas revenues in the period the hedged production is sold, while actual gains or losses on interest rate derivatives are recorded in interest expense for the applicable period. Actual gains or losses from commodity derivatives not designated as cash flow hedges are recorded in other income (expense) as gain (loss) on commodity derivatives. Stock-Based Compensation Restricted stock and stock options issued to employees and directors are recorded at grant-date fair value. Stock-based compensation expense is recognized in our consolidated statement of operations and comprehensive income (loss) on an accelerated basis over the awards’ vesting periods based on their fair values on the dates of grant, net of an estimate for forfeitures. Stock-based compensation awards generally vest over a period ranging from one to three years. We utilize the Black-Scholes option pricing model to measure the fair value of stock options. Common Stock Warrants Common stock warrant liabilities are measured at fair value on a recurring basis until the underlying common stock warrants are exercised (see Note 3). We measure the fair value of the common stock warrant liabilities using the Black-Scholes method (Level 2 inputs). Inputs used to determine fair value under this method include our price volatility and expected remaining life. Inventory Inventory consists primarily of tubular goods and other well equipment which we plan to utilize in our exploration and development activities and is stated at the lower of average cost or estimated market value. Capitalization of Interest Interest costs associated with our inventory of unproved oil and gas property lease acquisition costs are capitalized during the periods for which exploration activities are in progress. During the years ended December 31, 2016 , 2015 and 2014 , we capitalized interest totaling approximately $0.1 million , $0.3 million and $1 million , respectively. Cash and Cash Equivalents We consider all cash and highly liquid investments with original maturities of three months or less to be cash equivalents. Net Income (Loss) Per Common Share Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of common shares outstanding for the period. Diluted net income (loss) per share reflects the potential dilution that could occur if dilutive stock options were exercised, calculated using the treasury stock method. The diluted net income (loss) per share calculations for December 31, 2016 , 2015 and 2014 include changes in potential shares attributable to dilutive stock options and restricted stock. Fair Value Measurements We follow a framework for measuring fair value, which outlines a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements. Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued. We categorize our assets and liabilities recorded at fair value in the accompanying consolidated balance sheets based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities are as follows: Level 1 - Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date. Level 2 - Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life. Level 3 - Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model. Revenue Recognition and Gas Balancing We utilize the sales method of accounting for oil, natural gas and natural gas liquids (“NGL”) revenues whereby revenues, net of royalties, are recognized as the production is sold to purchasers. The amount of gas sold may differ from the amount to which we are entitled based on our revenue interests in the properties. We did not have any significant gas imbalance positions at December 31, 2016 , 2015 or 2014 . Revenues from midstream services and drilling rig services are recognized as services are provided. Comprehensive Income (Loss) There were no differences between net income (loss) and comprehensive income (loss) in December 31, 2016 , 2015 and 2014 . Concentration Risks We sell our oil and natural gas production to various customers, serve as operator in the drilling, completion and operation of oil and gas wells, and enter into derivatives with various counterparties. When management deems appropriate, we obtain letters of credit to secure amounts due from our principal oil and gas purchasers and follow other procedures to monitor credit risk from joint owners and derivatives counterparties. Allowances for doubtful accounts at December 31, 2016 and 2015 relate to amounts due from joint interest owners. Recent Accounting Pronouncements In August 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.” The objective of the standard is to reduce the existing diversity in practice of several cash flow issues, including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payment made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows and application of the predominance principle. The guidance in ASU 2016-15 is effective for public entities for annual reporting periods beginning after December 15, 2017, including interim periods therein. Early adoption is permitted and is to be applied on retrospective basis. We are currently evaluating the method of adoption and impact this standard may have on our financial statements and related disclosures. In March 2016, the FASB issued ASU 2016-09, “Compensation - Stock Compensation.” ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as certain classification changes in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Upon adoption, we expect to record a cumulative-effect adjustment to reclassify approximately $7.5 million of excess tax benefits that were not previously recognized because the related tax deduction had not reduced taxes payable. We plan to adopt ASU 2016-09 during the quarter ended March 31, 2017 to be effective as of January 1, 2017. In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842),” which supersedes current lease guidance. The new lease standard requires all leases with a term greater than one year to be recognized on the balance sheet while maintaining substantially similar classifications for finance and operating leases. Lease expense recognition on the income statement will be effectively unchanged. This guidance is effective for reporting periods beginning after December 15, 2018 and early adoption is permitted. We do not plan to early adopt the standard. We enter into lease agreements to support our operations. These agreements are for leases on assets such as office space and vehicles. We are currently in the process of reviewing all contracts that could be applicable to this new guidance. We believe this new guidance will have a moderate impact to our consolidated balance sheet due to the recognition of lease-related assets and liabilities that were not previously recognized. In November 2015, the FASB issued ASU No. 2015-17, “Income Taxes.” This ASU requires that deferred tax assets and liabilities be classified as non-current on the balance sheet. The standard will be effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption will be permitted as of the beginning of an interim or annual reporting period. This standard may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. Adoption of the new guidance will affect the presentation of our consolidated balance sheets and will not have a material impact on our consolidated financial statements. In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory.” This ASU requires entities to measure most inventory at the lower of cost and net realizable value, thereby simplifying the current guidance under which an entity must measure inventory at the lower of cost or market. ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years and should be applied prospectively, with early adoption permitted. The adoption of this standard will not have a material impact on our consolidated financial statements. In April 2015, the FASB issued ASU No. 2015-03, “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” which requires net debt issuance costs directly related to our senior notes and our second lien term loan to be classified as a direct deduction from the carrying amount of the related senior notes and second lien term loan. We adopted this ASU as of March 31, 2016 and reclassified $7.3 million of debt issuance costs at December 31, 2015 from a non-current asset to a direct deduction in long-term debt. The debt issuance costs related to our revolving credit facility remains classified as a non-current asset due to the revolving nature of that facility. In August 2014, the FASB issued ASU No. 2014-15, “Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.” ASU 2014-15 requires management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. Certain disclosures are required should substantial doubt exist. This evaluation is performed each annual and interim reporting period to assess conditions or events within one year after the date that the financial statements are issued. This ASU was effective beginning December 31, 2016; however, no additional disclosures as contemplated by this ASU were warranted. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” that outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. In summary, revenue recognition would occur upon the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Additionally, ASU 2014-09 requires enhanced financial statement disclosures over revenue recognition as part of the new accounting guidance. The standard will be effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. In March 2016, the FASB released certain implementation guidance through ASU 2016-08 to clarify principal versus agent considerations. We are evaluating the guidance to determine the method of adoption and the impact this standard will have on our consolidated financial statements and related disclosures. Based on our initial evaluation, though not currently quantified, the adoption of the standard is not expected to have a material impact on the timing of revenue recognized, results of operations or cash flows.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Long-term debt consists of the following: December 31, December 31, (In thousands) 7.75% Senior Notes, due 2019 $ 500,000 $ 600,000 Original issue discount (144 ) (241 ) Debt issuance costs (4,405 ) (7,349 ) Net 7.75% Senior Notes, due 2019 $ 495,451 $ 592,410 Second Lien Term Loan, due March 2021 $ 377,196 $ — Original issue discount (14,961 ) — Debt issuance costs (9,691 ) — Net Second Lien Term Loan, due March 2021 $ 352,544 $ — Revolving Credit Facility, due April 2019 $ — $ 150,000 $ 847,995 $ 742,410 Revolving Credit Facility We have a revolving credit facility with a syndicate of 16 banks led by JP Morgan Chase Bank, N.A. On March 8, 2016 , we entered into an amendment to the revolving credit facility in connection with the Refinancing (as defined below) (see “— Term Loan Credit Facility” ). The amendment, among other things, reduced the borrowing base and aggregate commitments of the lenders from $450 million to $100 million . The aggregate commitments may be increased to $150 million if we meet a minimum ratio of the discounted present value of our proved developed producing reserves to our debt under the revolving credit facility of 1.2 to 1.0 . Increases in aggregate lender commitments require the consent of each lender. The amendment also increased the applicable interest rates under our revolving credit facility by 0.75% at every borrowing base utilization level. At our election, interest under the revolving credit facility is determined by reference to (1) LIBOR plus an applicable margin between 2.5% and 3.5% per year or (2) the greatest of (A) the prime rate, (B) the federal funds rate plus 0.5% or (C) one-month LIBOR plus 1% plus, in any of (A), (B) or (C), an applicable margin between 1.5% and 2.5% per year. We are also required to pay a commitment fee on the unused portion of the commitments under the revolving credit facility of 0.5% per year. The applicable margin is determined based on the utilization of the borrowing base. Interest and fees are payable quarterly, except that interest on LIBOR-based tranches is due at maturity of each tranche but no less frequently than quarterly. The revolving credit facility also contains various covenants and restrictive provisions that may, among other things, limit our ability to sell assets, incur additional indebtedness, make investments or loans and create liens. One such covenant requires that we maintain a ratio of consolidated current assets to consolidated current liabilities of at least 1 to 1 . The March 2016 amendment replaced a requirement that we maintain certain ratios of consolidated funded indebtedness to consolidated EBITDAX with a less restrictive ratio of debt outstanding solely under the revolving credit facility to consolidated EBITDAX to be less than 2.0 to 1.0 . The revolving credit facility matures in April 2019 and is subject to an accelerated maturity date of October 1, 2018 unless our existing 7.75% Senior Notes due 2019 (the “2019 Senior Notes”) are refinanced or extended in accordance with the terms of the revolving credit facility prior to October 1, 2018 . The borrowing base, which is based on the discounted present value of future net cash flows from oil and gas production, is redetermined by the banks semi-annually in May and November. We or the banks may also request an unscheduled borrowing base redetermination at other times during the year. If, at any time, the borrowing base is less than the amount of outstanding credit exposure under the revolving credit facility, we will be required to (1) provide additional security, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the deficiency, (3) prepay the deficiency in not more than five equal monthly installments plus accrued interest, or (4) take any combination of options (1) through (3). The revolving credit facility is collateralized by a first lien on substantially all of our assets, including at least 90% of the adjusted engineered value (as defined in the revolving credit facility) attributed to our proved oil and gas interests evaluated in determining the borrowing base. The obligations under the revolving credit facility are guaranteed by each of CWEI’s material restricted domestic subsidiaries. At December 31, 2016 , we had $98.1 million available under the revolving credit facility after allowing for outstanding letters of credit totaling $1.9 million . The effective annual interest rate on borrowings under the revolving credit facility, excluding bank fees and amortization of debt issue costs, for the year ended December 31, 2016 was 2.5% . We were in compliance with all financial and non-financial covenants at December 31, 2016 and December 31, 2015 . The failure to comply with the foregoing covenants will constitute an event of default (subject, in the case of certain covenants, to applicable notice and/or cure periods) under the revolving credit facility. Other events of default under the revolving credit facility include, among other things, (1) the failure to timely pay principal, interest, fees or other amounts due and owing, (2) the inaccuracy of representations or warranties in any material respect, (3) the occurrence of certain bankruptcy or insolvency events, and (4) the loss of lien perfection or priority. The occurrence and continuance of an event of default could result in, among other things, acceleration of all amounts outstanding. Term Loan Credit Facility On March 8, 2016 , we entered into the term loan credit facility with funds managed by Ares providing for the lenders to make secured term loans to us in the principal amount of $350 million (the “Refinancing”). As part of the Refinancing, we issued warrants to purchase 2,251,364 shares of our common stock at a price of $22.00 per share and required certain amendments to the revolving credit facility. The term loans were issued at an original issue discount of $16.8 million , which amount equaled the cash consideration received by us for the issuance of the related warrants and shares of special voting preferred stock. Aggregate cash proceeds from the Refinancing of approximately $340 million , net of transaction costs, were used to fully repay the then-outstanding balance on the revolving credit facility of $160 million , plus accrued interest and fees. The warrants expire in 2026 and contain various anti-dilution provisions. Pursuant to FASB ASC 815-40, we account for the warrants as derivative instruments and carry the warrants as a non-current liability at their fair value, with the calculated increase or decrease in fair value each quarter being recognized in the statement of operations and comprehensive income (loss) (see Note 9). The warrants had a fair value of $16.8 million at the date of issuance and a fair value of $246.7 million at December 31, 2016 . As a result, for the year ended December 31, 2016 , we recorded a loss on revaluation of the warrant liability of $230 million . Interest on the term loans is payable quarterly in cash at 12.5% per year; however, during the period from March 15, 2016 through March 31, 2018 , we may elect to pay interest for any quarter in-kind at 15% per year. We paid interest for the period commencing from March 15, 2016 and ending March 31, 2016 in cash, and elected to pay interest for the quarterly periods ended June 30, 2016 and September 30, 2016 in-kind. We paid interest for the quarterly period ending December 31, 2016 in cash. In February 2017, we elected to pay interest for the quarterly period ending March 31, 2017 in cash. Future quarterly elections to pay in-kind must be made 30 days prior to the beginning of each calendar quarter. The term loan credit facility matures on March 15, 2021 , but is subject to an earlier maturity on December 31, 2018 , if we do not extend or refinance our existing 2019 Senior Notes on or prior to that date. The term loan credit facility is collateralized by a second lien on substantially all of our assets, including at least 90% of the adjusted engineered value (as defined in the term loan credit facility) attributed to our proved oil and gas interests. The obligations under the term loan credit facility are guaranteed by each of CWEI’s material restricted domestic subsidiaries. Optional and mandatory prepayments made prior to September 15, 2020 are subject to make-whole or prepayment premiums. The term loan credit facility also contains various covenants and restrictive provisions which may, among other things, limit our ability to sell assets, incur additional indebtedness, make investments or loans and create liens. One such covenant requires that we maintain an asset-to-secured debt coverage ratio as of each December 31 and June 30 of each year, beginning with December 31, 2018 , of at least 1.2 to 1.0 . We were in compliance with all covenants at December 31, 2016 . The failure to comply with these covenants will constitute an event of default (subject, in the case of certain covenants, to applicable notice and/or cure periods) under the term loan credit facility. Other events of default under the term loan credit facility include, among other things, (1) the failure to timely pay principal, interest, fees or other amounts due and owing, (2) the inaccuracy of representations or warranties in any material respect, (3) the occurrence of certain bankruptcy or insolvency events, and (4) the loss of lien perfection or priority. The occurrence and continuance of an event of default could result in, among other things, acceleration of all amounts outstanding. On July 22, 2016 , we entered into an agreement to sell 5,051,100 shares of common stock to funds managed by Ares for cash proceeds of $150 million , or approximately $29.70 per share (the “Private Placement”), which transaction closed on August 29, 2016 . In connection with the Private Placement, we entered into an amendment to the term loan facility, waiving certain restrictions to enable us to use proceeds from equity issuances and specified asset sales for debt reduction and capital expenditures. Senior Notes In March 2011, we issued $300 million of aggregate principal amount of 2019 Senior Notes. The 2019 Senior Notes, which are unsecured, were issued at par and bear interest at 7.75% per year, payable semi-annually on April 1 and October 1 of each year. In April 2011, we issued an additional $50 million aggregate principal amount of the 2019 Senior Notes with an original issue discount of 1% or $0.5 million . In October 2013, we issued an additional $250 million of aggregate principal amount of the 2019 Senior Notes at par to yield 7.75% to maturity. All of the 2019 Senior Notes are treated as a single class of debt securities under the same indenture. In August 2016, we redeemed $100 million in aggregate principal amount of the 2019 Senior Notes in a tender offer and for the year ended December 31, 2016 recorded a $4 million gain on early extinguishment of long-term debt, consisting of a $5 million discount and a $1 million write-off of debt issuance costs. We may redeem some or all of the 2019 Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 100% beginning on April 1, 2017 or for any period thereafter, in each case plus accrued and unpaid interest. The Indenture contains covenants that restrict our ability to: (1) borrow money; (2) issue redeemable or preferred stock; (3) pay distributions or dividends; (4) make investments; (5) create liens without securing the 2019 Senior Notes; (6) enter into agreements that restrict dividends from subsidiaries; (7) sell certain assets or merge with or into other companies; (8) enter into transactions with affiliates; (9) guarantee indebtedness; and (10) enter into new lines of business. One such covenant generally restricts our ability to incur indebtedness if our ratio of consolidated EBITDAX to consolidated interest expense (as these terms are defined in the Indenture) is less than 2.25 times. However, this restriction does not prevent us from incurring indebtedness under a credit facility (as defined in the Indenture) in an aggregate principal amount at any time outstanding not to exceed the greater of (a) $500 million and (b) 30% of Adjusted Consolidated Net Tangible Assets (as defined in the Indenture). These covenants are subject to a number of additional important exceptions and qualifications as described in the Indenture. We were in compliance with these covenants at December 31, 2016 and December 31, 2015 .

Sales of Assets

Sales of Assets	12 Months Ended
	Dec. 31, 2016
Sale Of Assets [Abstract]
Sales of Assets	Sales of Assets In December 2016, we sold substantially all of our assets in the Giddings Area in East Central Texas for cash consideration of $400 million , subject to customary closing adjustments. In September 2016, we sold certain acreage in Burleson County, Texas for cash consideration of $1.4 million . In July 2016, we sold our interests in certain wells in Glasscock County, Texas for approximately $19.4 million , subject to customary post-closing adjustments. In June 2016, we sold our interests in certain wells in Oklahoma for cash consideration of $1.5 million . In April 2016, we sold certain acreage in Burleson County, Texas for cash consideration of $2 million . In February 2016, we sold certain acreage in Burleson County, Texas for cash consideration of $0.8 million . In December 2015, we sold certain acreage in Burleson County, Texas for cash consideration of $21.8 million . This acreage, located east of our contiguous acreage block, was sold under a three -year term assignment that may be extended beyond the stated term as long as the buyer maintains a 180-day continuous development program on the acreage. We retained our rights to all depths and formations other than the Eagle Ford formation and also retained our interest in acreage and production in all wells currently situated on the acreage. We also reserved an overriding royalty interest to the extent the net revenue interest of any assigned lease exceeds 75% . In September 2015, we sold our interests in selected leases and wells in South Louisiana for $11.8 million subject to customary closing adjustments. In June 2015, we sold certain acreage in Burleson County, Texas for cash consideration of $22.1 million . We retained our rights to all depths and formations other than the Eagle Ford formation and also retained our interest in acreage and production associated with the Porter E Unit #1, our only Eagle Ford well situated on this acreage, a reversionary interest in acreage if the buyer fails to maintain a continuous development program and an overriding royalty interest in leases to the extent the net revenue interest exceeds 75% . During the first half of 2015, we sold our interests in selected leases in Oklahoma and sold our interests in certain wells in Martin and Yoakum Counties, Texas for proceeds totaling $7.3 million . In September 2014, we sold our interests in approximately 7,500 net acres in the Delaware Basin in Ward and Winkler Counties, Texas to an unaffiliated third party for $29.3 million . In March 2014, we closed a transaction to sell our interests in selected wells and leases in Wilson, Brazos, La Salle, Frio and Robertson Counties, Texas for $71 million , subject to customary closing adjustments. At closing, $6.8 million of the total proceeds was placed in escrow pending resolution of certain title requirements. In May 2015, the title requirements were satisfied and the remaining proceeds were released. In February 2014, we sold a property in Ward County, Texas for $5.1 million , subject to customary closing adjustments. Net proceeds from each of these transactions were used to repay the then-outstanding balance on the revolving credit facility and to fund a portion of our planned capital expenditures for 2016, 2015 and 2014.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations We record the ARO associated with the retirement of our long-lived assets in the period in which they are incurred and become determinable. Under this method, we record a liability for the expected future cash outflows discounted at our credit-adjusted risk-free interest rate for the dismantlement and abandonment costs, excluding salvage values, of each oil and gas property. We also record an asset retirement cost to the oil and gas properties equal to the ARO liability. The fair value of the asset retirement cost and the ARO liability is measured using primarily Level 3 inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, inflation rate and well life. The inputs are calculated based on historical data as well as current estimated costs. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted over the useful life of the related asset. The following table reflects the changes in ARO for the years ended December 31, 2016 and 2015 : 2016 2015 (In thousands) Beginning of year $ 48,728 $ 45,697 Additional ARO from new properties 61 469 Sales or abandonments of properties (17,206 ) (4,435 ) Accretion expense 4,364 3,945 Revisions of previous estimates 11,276 3,052 End of year $ 47,223 $ 48,728

Deferred Revenue from Volumetri

Deferred Revenue from Volumetric Production Payment	12 Months Ended
	Dec. 31, 2016
Deferred Revenue Disclosure [Abstract]
Deferred Revenue from Volumetric Production Payment	Deferred Revenue from Volumetric Production Payment In March 2012, Southwest Royalties, Inc. (“SWR”), a wholly owned subsidiary of CWEI, completed the mergers of each of the 24 limited partnerships of which SWR was the general partner, into SWR, with SWR continuing as the surviving entity in the mergers. To obtain the funds to finance the aggregate merger consideration, SWR entered into a volumetric production payment (“VPP”) with a third party for upfront cash proceeds of $44.4 million and deferred future advances aggregating $4.7 million . Under the terms of the VPP, SWR conveyed to the third party a term overriding royalty interest covering approximately 725 MBOE of estimated future oil and gas production from certain properties derived from the mergers. The scheduled volumes under the VPP relate to production months from March 2012 through December 2019 and were to be delivered to, or sold on behalf of, the third party free of all costs associated with the production and development of the underlying properties. Once the scheduled volumes were delivered to the third party, the term overriding royalty interest would terminate. SWR retained the obligation to prudently operate and produce the properties during the term of the VPP, and the third party assumed all risks associated with product prices. As a result, the VPP was accounted for as a sale of reserves, with the sales proceeds being deferred and amortized into oil and gas sales as the scheduled volumes were produced. The net proceeds from the VPP were recorded as a non-current liability in the consolidated balance sheets. Deferred revenue from the VPP was amortized over the life of the VPP and recognized in oil and gas sales in the consolidated statements of operations and comprehensive income (loss). In August 2015, we terminated the VPP covering 277 MBOE of oil and gas production from August 2015 through December 2019 for $13.7 million . The termination of the VPP was accounted for as a repurchase of reserves, with the repurchase price offsetting the non-current liability and the balance of the remaining non-current liability amortized over the original term of the VPP and recognized in oil and gas sales in the consolidated statements of operations and comprehensive income (loss). As of December 31, 2016 , we have no further obligations under the VPP. The following table reflects the changes in deferred revenue during the years ended December 31, 2016 and 2015 : 2016 2015 (In thousands) Beginning of year $ 5,470 $ 23,129 Deferred revenue from VPP — 2,866 Amortization of deferred revenue from VPP (1,479 ) (6,822 ) Termination of VPP — (13,703 ) End of year $ 3,991 $ 5,470

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Deferred tax assets and liabilities are the result of temporary differences between the consolidated financial statement carrying values and the tax basis of assets and liabilities. Significant components of net deferred tax liabilities at December 31, 2016 and 2015 are as follows: 2016 2015 (In thousands) Deferred tax assets: Net operating loss carryforwards $ 76,213 $ 106,992 Statutory depletion carryforwards 9,913 9,809 Asset retirement obligations and other 22,518 21,249 108,644 138,050 Deferred tax liabilities: Property and equipment (178,714 ) (240,520 ) Net deferred tax liabilities $ (70,070 ) $ (102,470 ) Components of net deferred tax liabilities: Current assets $ 6,520 $ 6,526 Non-current liabilities (76,590 ) (108,996 ) Net deferred tax liabilities $ (70,070 ) $ (102,470 ) For the years ended December 31, 2016 , 2015 and 2014 , effective income tax rates were different than the statutory federal income tax rates for the following reasons: 2016 2015 2014 (In thousands) Income tax expense (benefit) at statutory rate of 35% $ (112,867 ) $ (53,667 ) $ 23,999 Tax depletion in excess of basis (164 ) (282 ) (729 ) Revision of previous tax estimates 63 30 (155 ) State income tax expense (benefit), net of federal tax effect 857 (1,472 ) 1,008 Permanent and other (a) 81,784 252 564 Income tax expense (benefit) $ (30,327 ) $ (55,139 ) $ 24,687 Current $ 2,073 $ 79 $ 227 Deferred (32,400 ) (55,218 ) 24,460 Income tax expense (benefit) $ (30,327 ) $ (55,139 ) $ 24,687 ______ (a) Includes $80.5 million of permanent differences related to the change in fair value of common stock warrants in 2016. We derive a tax deduction when options are exercised under our stock option plans. To the extent these tax deductions are used to reduce currently payable taxes in any period, we record a tax benefit for the excess of the tax deduction over cumulative book compensation expense as additional paid-in capital and as a financing cash flow in the accompanying consolidated financial statements. At December 31, 2016 , our cumulative tax loss carryforwards were approximately $239.3 million , of which $22 million relates to excess tax benefits from exercise of stock options. The cumulative tax loss carryforwards are scheduled to expire if not utilized between 2027 and 2031 . In assessing the ability to realize deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. If it is more likely than not that some portion or all of the assets will not be realized, the assets are reduced by a valuation allowance. Based on our analysis of future taxable income, no valuation allowance is required. CWEI and its subsidiaries file federal income tax returns with the United States Internal Revenue Service and state income tax returns in various state tax jurisdictions. As a general rule, the Company’s tax returns for fiscal years after 2012 currently remain subject to examination by appropriate taxing authorities. None of our income tax returns are under examination at this time. We do not have any uncertain tax positions as of December 31, 2016 and 2015 .

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	Derivatives Commodity Derivatives From time to time, we utilize commodity derivatives, consisting of swaps, floors and collars, to attempt to optimize the price received for our oil and gas production. When using swaps to hedge oil and natural gas production, we receive a fixed price for the respective commodity and pay a floating market price as defined in each contract, generally New York Mercantile Exchange (“NYMEX”) futures prices, resulting in a net amount due to or from the counterparty. In floor transactions, we receive a fixed price (put strike price) if the market price falls below the put strike price for the respective commodity. If the market price is greater than the put strike price, no payments are due from either party. Costless collars are a combination of puts and calls, and contain a fixed floor price (put strike price) and ceiling price (call strike price). If the market price for the respective commodity exceeds the call strike price or falls below the put strike price, then we receive the fixed price and pay the market price. If the market price is between the call and the put strike prices, no payments are due from either party. Commodity derivatives are settled monthly as the contract production periods mature. The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to December 31, 2016 . Settlement prices of commodity derivatives are based on NYMEX futures prices. Swaps: Oil MBbls Price Production Period: 1st Quarter 2017 178 $ 44.85 2nd Quarter 2017 165 $ 44.65 3rd Quarter 2017 37 $ 50.00 4th Quarter 2017 27 $ 50.00 407 Costless Collars: Oil MBbls Weighted Average Floor Price Weighted Average Ceiling Price Production Period: 1st Quarter 2017 355 $ 42.26 $ 51.67 2nd Quarter 2017 354 $ 42.27 $ 51.67 3rd Quarter 2017 356 $ 42.27 $ 51.65 4th Quarter 2017 350 $ 42.27 $ 51.66 1,415 Accounting for Commodity Derivatives We did not designate any of our commodity derivatives as cash flow hedges; therefore, all changes in the fair value of these contracts prior to maturity, plus any realized gains or losses at maturity, were recorded as other income (expense) in our consolidated statements of operations and comprehensive income (loss). Effect of Commodity Derivative Instruments on the Consolidated Balance Sheets Fair Value of Commodity Derivative Instruments as of December 31, 2016 Asset Commodity Derivatives Liability Commodity Derivatives Balance Sheet Location Fair Value Balance Sheet Location Fair Value (In thousands) (In thousands) Commodity derivatives not designated as hedging instruments: Commodity derivatives Fair value of commodity derivatives: Fair value of commodity derivatives: Current $ — Current $ 12,895 Non-current — Non-current — Total $ — $ 12,895 Fair Value of Commodity Derivative Instruments as of December 31, 2015 Asset Commodity Derivatives Liability Commodity Derivatives Balance Sheet Location Fair Value Balance Sheet Location Fair Value (In thousands) (In thousands) Commodity derivatives not designated as hedging instruments: Commodity derivatives Fair value of commodity derivatives: Fair value of commodity derivatives: Current $ — Current $ — Non-current — Non-current — Total $ — $ — Gross to Net Presentation Reconciliation of Commodity Derivative Assets and Liabilities December 31, 2016 Assets Liabilities (In thousands) Fair value of commodity derivatives — gross presentation $ — $ 12,895 Effects of netting arrangements — — Fair value of commodity derivatives — net presentation $ — $ 12,895 December 31, 2015 Assets Liabilities (In thousands) Fair value of commodity derivatives — gross presentation $ — $ — Effects of netting arrangements — — Fair value of commodity derivatives — net presentation $ — $ — Our commodity derivative contracts are with JPMorgan Chase Bank, N.A. and Shell Trading Risk Management LLC. Effect of Commodity Derivative Instruments Recognized in Earnings on the Consolidated Statements of Operations and Comprehensive Income (Loss) Amount of Gain or (Loss) Recognized in Earnings Year Ended December 31, Location of Gain or (Loss) Recognized in Earnings 2016 2015 2014 (In thousands) Commodity derivatives not designated as hedging instruments: Commodity derivatives: Other income (expense) - Gain (loss) on commodity derivatives $ (20,289 ) $ 12,519 $ 4,789 Total $ (20,289 ) $ 12,519 $ 4,789

Fair Value of Financial Instrum

Fair Value of Financial Instruments	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	Fair Value of Financial Instruments Cash and cash equivalents, receivables, accounts payable and accrued liabilities were each estimated to have a fair value approximating the carrying amount due to the short maturity of those instruments. Indebtedness under the revolving credit facility was estimated to have a fair value approximating the carrying amount since the interest rate is generally market sensitive. Fair Value Measurements We follow a framework for measuring fair value, which outlines a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements. Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued. We categorize our assets and liabilities recorded at fair value in the accompanying consolidated balance sheets based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities, are as follows: Level 1 - Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date. Level 2 - Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life. Level 3 - Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model. The financial assets and liabilities measured on a recurring basis at December 31, 2016 and December 31, 2015 were commodity derivatives and common stock warrants. Common stock warrant liabilities are measured at fair value on a recurring basis until the underlying common stock warrants are exercised (see Note 3). We measure the fair value of the common stock warrant liabilities using the Black-Scholes method (Level 2 inputs). Inputs used to determine fair value under this method include our price volatility and expected remaining life. The fair value of all commodity derivative contracts and common stock warrants are reflected on the consolidated balance sheets as detailed in the following schedule: December 31, 2016 December 31, 2015 Description Significant Other Observable Inputs (Level 2) (In thousands) Assets: Fair value of commodity derivatives $ — $ — Total assets $ — $ — Liabilities: Fair value of commodity derivatives $ 12,895 $ — Fair value of common stock warrants 246,743 — Total liabilities $ 259,638 $ — Fair Value of Other Financial Instruments We estimate the fair value of the 2019 Senior Notes using quoted market prices. The fair value of our Second Lien Term Loan as of December 31, 2016 is based upon our discounted cash flow model. Fair value is compared to the carrying value in the table below: Fair Value December 31, 2016 December 31, 2015 Hierarchy Carrying Estimated Carrying Estimated Description Level Amount Fair Value Amount Fair Value (In thousands) 7.75% Senior Notes, due 2019 1 $ 495,451 $ 505,650 $ 592,410 $ 462,750 Second Lien Term Loan, due March 2021 3 $ 352,544 $ 378,996 $ — $ —

Stockholders' Equity and Earnin

Stockholders' Equity and Earnings (Loss) Per Share (Notes)	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Stockholders' Equity and Earnings Per Share	Shareholders’ Equity and Earnings (Loss) Per Share In August 2016, we completed the sale of 5,051,100 shares of our common stock to funds managed by Ares for cash proceeds of $150 million or approximately $29.70 per share. Net proceeds from the sale, after offering expenses of $2.7 million , were used to repay indebtedness and provide additional funds for general corporate purposes. Earnings (Loss) Per Share Basic earnings (loss) per share amounts have been computed based on the weighted average number of shares of common stock outstanding for the period. Diluted earnings (loss) per share include the effect of potentially dilutive shares outstanding for the period. For the year ended December 31, 2016 , there were 282,000 shares that were not included in the computation of diluted earnings (loss) per share because their inclusion would have been anti-dilutive for the periods.

Compensation Plans

Compensation Plans	12 Months Ended
	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Compensation Plans	Compensation Plans Long-Term Incentive Plan In June 2016, shareholders approved the Clayton Williams Energy, Inc. Long-Term Incentive Plan (the “LTIP”), which was adopted by the Compensation Committee of the Board in April 2016. The LTIP was adopted in order to enable us to attract and retain highly qualified employees, directors and consultants and to provide equity-based compensation to those individuals that will align their interests with the interests of our shareholders. The LTIP provides for the granting of restricted stock awards, restricted stock units, stock options, stock appreciation rights, dividend-equivalent awards, other stock-based awards, cash awards, performance awards, and any combination of such awards. A total of 1,400,000 shares of our common stock have been reserved for issuance under the LTIP and are expected to consist of new shares of the Company. During the year ended December 31, 2016 , grants of awards under the LTIP were made as disclosed in the tables below. Stock Options All outstanding nonqualified and incentive stock options under the LTIP expire seven years from the date of grant and vest ratably over a three-year period. The exercise price of stock options under the LTIP may not be less than the market value of the stock on the date of grant. The fair value of the stock options on the date of grant is expensed ratably over the applicable vesting period. We estimate the fair value of stock options granted using a Black-Scholes option valuation model, which requires us to make certain assumptions, as follows: • Expected volatility of the underlying common stock is based on our historical stock volatility; • Expected term of options granted is based on the mid-point between the final vesting date and the expiration date since our common stock does not have sufficient history to predict the expected term using historical data; and • Risk-free interest rate is based on the U.S. Treasury yield curve for the expected term of the options at the date of grant. The following table summarizes the weighted average grant date fair values and related assumptions for grants made during the year ended December 31, 2016 : December 31, 2016 Grant-date fair value $ 45.88 Expected volatility 76.3 % Expected term (in years) 5 Risk-free rate 1.2 % The following table sets forth certain information regarding our stock options as of December 31, 2016 : Weighted Average Options Exercise Price Remaining Term Aggregate Intrinsic Value Outstanding at January 1, 2016 — $ — Granted 282,000 $ 74.21 Exercised — $ — Outstanding at December 31, 2016 282,000 $ 74.21 Vested and expected to vest at December 31, 2016 282,000 $ 74.21 6.7 $ 12,705,250 Exercisable at December 31, 2016 — $ — — $ — As of December 31, 2016 , the unrecognized compensation cost related to granted stock options was $11.8 million . Such cost is expected to be recognized over a weighted-average period of 2.7 years. Restricted Stock Awards Restricted stock awards granted under the LTIP as of December 31, 2016 vest over either a one-year or three-year period. The estimated fair value of restricted stock grants, computed based on the closing price of our common stock on the date of grant, is expensed ratably over the applicable vesting period. The following table presents our restricted stock activity as of December 31, 2016 : Restricted Stock Awards Weighted-Average Grant Date Fair Value Unvested at January 1, 2016 — $ — Granted 410,165 $ 71.26 Vested (25,000 ) $ 63.11 Forfeited — $ — Unvested at December 31, 2016 385,165 $ 71.79 The aggregate fair value of restricted stock awards granted during the year ended December 31, 2016 was $29.2 million . As of December 31, 2016 , our unrecognized compensation cost related to unvested restricted stock awards was $24.6 million . Such cost is expected to be recognized over a weighted-average period of 2.6 years. Stock-based compensation expense related to stock options and restricted stock awards was $5.7 million for the year ended December 31, 2016 and none for the years ended December 31, 2015 and 2014 . Non-Equity Award Plans The Compensation Committee of the Board has adopted an after-payout (“APO”) incentive plan (the “APO Incentive Plan”) for officers, key employees and consultants who promote our drilling and acquisition programs. The Compensation Committee’s objective in adopting this plan is to further align the interests of the participants with ours by granting the participants an APO interest in the production developed, directly or indirectly, through the efforts of the participants. The plan generally provides for the creation of a series of partnerships or participation arrangements, which are treated as partnerships for tax purposes (the “APO Partnerships”), between us and the participants, to which we contribute a portion of our economic interest in wells drilled or acquired within certain areas. Generally, we pay all costs to acquire, drill and produce applicable wells and receive all revenues until we have recovered all of our costs, plus interest (“payout”). At payout, the participants receive 99% to 100% of all subsequent revenues and pay 99% to 100% of all subsequent expenses attributable to the economic interests that are subject to the APO Partnerships. Between 5% and 7.5% of our economic interests in specified wells drilled or acquired by us subsequent to October 2002 are subject to the APO Incentive Plan. We record our allocable share of the assets, liabilities, revenues, expenses and oil and gas reserves of these APO Partnerships in our consolidated financial statements. Participants in the APO Incentive Plan are immediately vested in all future amounts payable under the plan. The Compensation Committee has also adopted an APO reward plan (the “APO Reward Plan”) which offers eligible officers, key employees and consultants the opportunity to receive bonus payments that are based on certain profits derived from a portion of our working interest in specified areas where we are conducting drilling and production enhancement operations. The wells subject to an APO Reward Plan are not included in the APO Incentive Plan. Likewise, wells included in the APO Incentive Plan are not included in the APO Reward Plan. Although conceptually similar to the APO Incentive Plan, the APO Reward Plan is a compensatory bonus plan through which we pay participants a bonus equal to a portion of the APO cash flows received by us from our working interest in wells in a specified area. Unlike the APO Incentive Plan, however, participants in the APO Reward Plan are not immediately vested in all future amounts payable under the plan. To date, we have granted awards under the APO Reward Plan in eight specified areas, each of which established a quarterly bonus amount equal to 7% or 10% of the APO cash flow from wells drilled or recompleted in the respective areas after the effective date set forth in each plan, which dates range from January 1, 2007 to June 11, 2014. As of June 23, 2016 , all eight awards were fully vested. On May 4, 2016, the Compensation Committee amended the definition of a well in each plan to end the inclusion of new wells in all plans. A well is a well drilled by the employer in the area described provided that the well has a spud date between the effective date and May 4, 2016. All other terms of the plan remain unchanged. Future payments to participants in the plan will be based on the performance of only those wells that meet the revised definition of a well. The Compensation Committee expects to utilize the LTIP in lieu of future grants under the APO Reward Plan. In January 2007, we granted awards under the Southwest Royalties Reward Plan (the “SWR Reward Plan”), a one-time incentive plan which established a quarterly bonus amount for participants equal to the APO cash flow from a 22.5% working interest in one well. The plan is fully vested and 100% of subsequent quarterly bonus amounts are payable to participants. To continue as a participant in the APO Reward Plan or the SWR Reward Plan, participants must remain in the employment or service of the Company through the full vesting date established for each award. The full vesting date may be accelerated in the event of a change of control or sale transaction, as defined in the plan documents. We recognize compensation expense related to the APO Partnerships based on the estimated value of economic interests conveyed to the participants. Estimated compensation expense applicable to the APO Reward Plan and the SWR Reward Plan is recognized over the applicable vesting periods, which range from two years to five years . Compensation expense related to non-equity award plans was $(7.9) million in 2016 , $(0.03) million in 2015 and $4.6 million in 2014 . Credits to expense resulted from the reversal of previously accrued compensation expense attributable to changes in estimates of future compensation expense. Accrued compensation under non-equity award plans is reflected in the accompanying consolidated balance sheets as detailed in the following schedule: 2016 2015 (In thousands) Current liabilities: Accrued liabilities and other $ 1,087 $ 1,251 Non-current liabilities: Accrued compensation under non-equity award plans 4,655 16,254 Total accrued compensation under non-equity award plans $ 5,742 $ 17,505

Transactions with Affiliates

Transactions with Affiliates	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Transactions with Affiliates	Transactions with Affiliates The Company and other entities (the “Williams Entities”) controlled by Mr. Williams are parties to an agreement (the “Service Agreement”) pursuant to which the Company furnishes services to, and receives services from, such entities. Under the Service Agreement, as amended from time to time, CWEI provides legal, computer, payroll and benefits administration, insurance administration, tax preparation services, tax planning services, and financial and accounting services to the Williams Entities, as well as technical services with respect to certain oil and gas properties owned by the Williams Entities. The Williams Entities provide business entertainment to or for the benefit of CWEI. The following table summarizes the charges to and from the Williams Entities for the years ended December 31, 2016 , 2015 and 2014 . 2016 2015 2014 (In thousands) Amounts received from the Williams Entities: Service Agreement: Services $ 603 $ 622 $ 663 Insurance premiums and benefits 989 922 960 Reimbursed expenses 252 500 296 $ 1,844 $ 2,044 $ 1,919 Amounts paid to the Williams Entities: Rent (a) $ 1,697 $ 1,741 $ 1,614 Service Agreement: Business entertainment (b) 155 155 205 Reimbursed expenses 135 226 204 $ 1,987 $ 2,122 $ 2,023 ______ (a) Rent amounts were paid to ClayDesta Buildings, L.P., a Texas limited partnership referred to as CDBLP, of which the Company owns 33.5% and affiliates of the Company own 25.8% . A Williams Entity provides property management services to the buildings owned and operated by CDBLP. (b) Consists primarily of hunting and fishing recreation for business associates and employees of the Company on land owned by affiliates of Mr. Williams. Accounts receivable from affiliates and accounts payable to affiliates include, among other things, amounts for customary charges by the Company as operator of certain wells in which affiliates own an interest.

Other Operating Revenues and Ex

Other Operating Revenues and Expenses	12 Months Ended
	Dec. 31, 2016
Other Income and Expenses [Abstract]
Other Operating Revenues and Expenses	Other Operating Revenues and Expenses Other operating revenues and expenses for the years ended December 31, 2016 , 2015 and 2014 are as follows: 2016 2015 2014 (In thousands) Other operating revenues: Gain on sales of assets $ 123,392 $ 8,718 $ 11,685 Marketing revenue — 24 3,708 Total other operating revenues $ 123,392 $ 8,742 $ 15,393 Other operating expenses: Loss on sales of assets $ 3,152 $ 1,355 $ 2,511 Marketing expense 440 849 — Impairment of inventory 1,454 10,381 36 Total other operating expenses $ 5,046 $ 12,585 $ 2,547 Gain on sales of assets for the year ended December 31, 2016 included the sale of substantially all of our assets in the Giddings Area in East Central Texas in December 2016 and the sale of our interests in certain wells in Glasscock County, Texas in July 2016 (see Note 4). Gain on sales of assets for the year ended December 31, 2015 included the sale of selected leases and wells in South Louisiana in September 2015, the release of sales proceeds previously held in escrow pending resolution of title requirements associated with the sale of certain non-core Austin Chalk/Eagle Ford assets sold in March 2014, the sale of leases in Oklahoma in May and June 2015 and the sale of selected wells in Martin and Yoakum Counties, Texas in March 2015 (see Note 4). Gain on sales of assets for the year ended December 31, 2014 included the sale of certain non-core Austin Chalk/Eagle Ford assets in March 2014 and the sale of a property in Ward County, Texas in February 2014 (see Note 4). We maintain an inventory of tubular goods and other well equipment for use in our exploration and development drilling activities. Inventory is carried at the lower of average cost or estimated fair market value. We categorize the measurement of fair value of inventory as Level 2 under applicable accounting standards. To determine estimated fair value of inventory, we subscribe to market surveys and obtain quotes from equipment dealers for similar equipment. We then correlate the data as needed to estimate the fair value of the specific items (or groups of similar items) in our inventory. If the estimated fair values for those specific items (or groups of similar items) in our inventory are less than the related average cost, a provision for impairment is made.

Investment in Dalea Investment

Investment in Dalea Investment Group, LLC	12 Months Ended
	Dec. 31, 2016
Investments, All Other Investments [Abstract]
Investment in Dalea Investment Group, LLC	Investment in Dalea Investment Group, LLC In June 2012, we cancelled an $11 million note receivable in exchange for a 7.66% non-controlling membership interest in Dalea Investment Group, LLC (“Dalea”), an international oilfield services company formed in March 2012. Since the membership interests in Dalea are privately-held and are not traded in an active market, our investment in Dalea was carried at the lower of its initial cost of $11 million and its estimated fair value based on a qualitative assessment. We recorded an $8.4 million impairment on our investment in Dalea for the year ended December 31, 2016 , $2.6 million for the year ended December 31, 2015 and none for the year ended December 31, 2014 . As of December 31, 2016 , our investment in Dalea was fully impaired compared to an estimated fair value of $8.4 million at December 31, 2015 . We categorize the measurement of fair value of this investment as a Level 3 input.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Leases We lease office space from affiliates and nonaffiliates under noncancelable operating leases. Rental expense pursuant to the office leases amounted to $1.9 million , $1.9 million and $1.8 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Future minimum payments under noncancelable leases at December 31, 2016 are as follows: Leases Capital (a) Operating Total (In thousands) 2017 $ 241 $ 887 $ 1,128 2018 85 614 699 2019 45 613 658 Thereafter — 102 102 Total minimum lease payments $ 371 $ 2,216 $ 2,587 ______ (a) Relates to vehicle leases. Legal Proceedings In February 2012, BMT O&G TX, L.P. filed a suit in the 143rd Judicial District in Reeves County, Texas to terminate a lease under our farm-in agreement with Chesapeake Exploration, L.L.C. (“Chesapeake”). Plaintiffs are the lessors and claim a breach of the lease which they allege gives rise to termination of the lease. CWEI denies a breach and argues in the alternative that (i) any breach was cured in accordance with the lease and (ii) a breach will not give rise to lease termination. In October 2013, a judge ruled that CWEI and Chesapeake are jointly and severally liable for damages to plaintiffs in the amount of approximately $2.9 million and attorney fees of $0.8 million . A loss of $1.4 million was recorded for the year ended December 31, 2013 in connection with the judgment. CWEI appealed the judgment and on July 8, 2015, the El Paso Court of Appeals reversed the trial court judgment in its entirety and rendered judgment that Plaintiffs take nothing on all claims against CWEI and Chesapeake. Plaintiffs have appealed the decision of the Court of Appeals to the Texas Supreme Court and on October 21, 2016, the Texas Supreme Court denied Plaintiffs’ Petition for Review. Plaintiffs moved for rehearing on the denial, and CWEI’s and Chesapeake’s responses are due February 22, 2017. CWEI has been named a defendant in three lawsuits filed in Louisiana, one by Southeast Louisiana Flood Protection Authority-East (“SELFPA”) and two by Plaquemines Parish, each alleging that historical industry operations have significantly damaged coastal marshlands. In July 2013, the SELFPA case was filed in Orleans Parish and alleged that dredging and other oilfield operations of the 95 oil and gas company defendants caused degradation and destruction of the coastal marshlands which serve as a buffer protecting the coastal area of Louisiana from storms. The case was removed to Federal District Court. Legislation was enacted in Louisiana in 2014 in response to the suit which would effectively eliminate the claims, but in late 2014 the Louisiana state court judge declared the new law unconstitutional. A motion to dismiss the claims was granted in Federal District Court and the plaintiff has appealed to the United States Fifth Circuit Court of Appeals. Oral argument was heard on February 29, 2016. The Court has not yet ruled. In November 2013, we were served with two separate suits filed by Plaquemines Parish in the 25th Judicial District Court of Plaquemines Parish, Louisiana (Designated Case Nos. 61-002 and 60-982). Multiple defendants are named in each suit, and each suit involves a different area of operation within Plaquemines Parish. Except as to the named defendants and areas of operation, the suits are identical. Plaintiff alleges that defendants’ oil and gas operations violated certain laws relating to the coastal zone management including failure to obtain permits, violation of permits, use of unlined waste pits, discharge of oil field wastes, including naturally occurring radioactive material, and that dredging operations exceeded unspecified permit limitations. Plaintiff makes no specific allegations against any individual defendant and seeks unspecified monetary damages and declaratory relief, as well as restoration, costs of remediation and attorney fees. The cases were removed to the U.S. District Court for the Eastern District of Louisiana but were remanded back to the state court in 2015. In November 2015, the Plaquemines Parish Council passed Resolution 15-389 requiring its attorneys to cease all work on the cases other than to dismiss all actions and lawsuits, but in April of 2016 the Parish voted to rescind such resolution. The State of Louisiana Department of Natural Resources, Office of Coastal Management has intervened in these cases and the Louisiana Attorney General has filed to supersede the Parish as Plaintiff. Status conferences were held in November 2016. Our overall exposure to these suits is not currently determinable and we intend to vigorously defend these cases. We are also a defendant in several other lawsuits that have arisen in the ordinary course of business. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect any of these lawsuits to have a material adverse effect on our consolidated financial condition or results of operations.

Impairment of Property and Equi

Impairment of Property and Equipment	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment Impairment or Disposal [Abstract]
Impairment of Property and Equipment	Impairment of Property and Equipment We impair our long-lived assets, including oil and gas properties and contract drilling equipment, when estimated undiscounted future net cash flows of an asset are less than its carrying value. The amount of any such impairment is recognized based on the difference between the carrying value and the estimated fair value of the asset. We categorize the measurement of fair value of these assets as Level 3 inputs. We estimate the fair value of the impaired property by applying weighting factors to fair values determined under three different methods: (1) discounted cash flow method; (2) flowing daily production method; and (3) proved reserves per BOE method. We then assign applicable weighting factors based on the relevant facts and circumstances. We utilize all three methods when that information is available, or if not will utilize the discounted cash flow method. We recorded provisions for impairment of property and equipment aggregating $7.6 million in 2016 , $41.9 million in 2015 and $12 million in 2014 to reduce the carrying value of those properties to their estimated fair values. The 2016 provision of $7.6 million included $5.2 million related to the write-down of non-core properties in North Dakota, Oklahoma, California and the Cotton Valley area of Texas and $2.4 million related to the write-down of certain drilling rigs and related equipment to reduce the carrying values of these properties to their estimated fair values. The 2015 provision of $41.9 million included $37.9 million related primarily to the write-down of certain non-core properties in the Permian Basin and Oklahoma and $4 million related to the write-down of certain drilling rigs and related equipment to reduce the carrying values of these properties to their estimated fair values. The 2014 provision of $12 million related to the write-down of certain non-core properties in the Permian Basin and North Dakota. Unproved properties are nonproducing and do not have estimable cash flow streams. Therefore, we estimate the fair value of individually significant prospects by obtaining, when available, information about recent market transactions in the vicinity of the prospects and adjust the market data as needed to give consideration to the proximity of the prospects to known fields and reservoirs, the extent of geological and geophysical data on the prospects, the remaining terms of leases holding the acreage in the prospects, recent drilling results in the vicinity of the prospects, and other risk-related factors such as drilling and completion costs, estimated product prices and other economic factors. Individually insignificant prospects are grouped and impaired based on remaining lease terms and our historical experience with similar prospects. Based on the assessments previously discussed, we will impair our unproved oil and gas properties when we determine that a prospect’s carrying value exceeds its estimated fair value. We categorize the measurement of fair value of unproved properties as Level 3 inputs. We recorded provisions for impairment of unproved properties aggregating $2.3 million , $2.8 million and $15.4 million in 2016 , 2015 and 2014 , respectively, and charged these impairments to abandonments and impairments in the accompanying consolidated statements of operations and comprehensive income (loss).

Costs of Oil and Gas Properties

Costs of Oil and Gas Properties	12 Months Ended
	Dec. 31, 2016
Oil and Gas Property, Successful Effort Method, Gross [Abstract]
Costs of Oil and Gas Properties	Costs of Oil and Gas Properties The following table sets forth certain information with respect to costs incurred in connection with the Company’s oil and gas producing activities during the years ended December 31, 2016 , 2015 and 2014 . 2016 2015 2014 (In thousands) Property acquisitions: Proved $ — $ — $ — Unproved 32,840 29,711 56,327 Developmental costs 49,614 81,466 342,716 Exploratory costs 20,095 14,342 4,350 Total $ 102,549 $ 125,519 $ 403,393 The following table sets forth the net capitalized costs for oil and gas properties as of 2016 and 2015 . 2016 2015 (In thousands) Proved properties $ 1,643,038 $ 2,539,480 Unproved properties 74,171 46,022 Total capitalized costs 1,717,209 2,585,502 Accumulated depletion (928,927 ) (1,460,404 ) Net capitalized costs $ 788,282 $ 1,125,098

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Segment Information	Segment Information We have two reportable operating segments, which are (1) oil and gas exploration and production and (2) contract drilling services. The following tables present selected financial information regarding our operating segments for the years ended December 31, 2016 , 2015 and 2014 . Contract Intercompany Consolidated For the Year Ended December 31, 2016 Oil and Gas Drilling Eliminations Total (In thousands) Revenues $ 289,246 $ 165 $ — $ 289,411 Depreciation, depletion and amortization (a) 138,875 14,332 — 153,207 Other operating expenses (b) 110,119 3,771 — 113,890 Interest expense 93,693 — — 93,693 Other (income) expense (c) 241,557 9,542 — 251,099 Income (loss) before income taxes (294,998 ) (27,480 ) — (322,478 ) Income tax (expense) benefit 20,709 9,618 — 30,327 Net income (loss) $ (274,289 ) $ (17,862 ) $ — $ (292,151 ) Total assets $ 1,524,220 $ 19,180 $ (48,761 ) $ 1,494,639 Additions to property and equipment $ 112,429 $ 58 $ — $ 112,487 Contract Intercompany Consolidated For the Year Ended December 31, 2015 Oil and Gas Drilling Eliminations Total (In thousands) Revenues $ 232,279 $ 2,837 $ (2,744 ) $ 232,372 Depreciation, depletion and amortization (a) 187,913 16,832 (566 ) 204,179 Other operating expenses (b) 135,177 9,178 (2,727 ) 141,628 Interest expense 54,422 — — 54,422 Other (income) expense (c) (17,091 ) 2,569 — (14,522 ) Income (loss) before income taxes (128,142 ) (25,742 ) 549 (153,335 ) Income tax (expense) benefit 46,129 9,010 — 55,139 Net income (loss) $ (82,013 ) $ (16,732 ) $ 549 $ (98,196 ) Total assets $ 1,283,649 $ 48,943 $ (45,172 ) $ 1,287,420 Additions to property and equipment $ 124,996 $ 1,202 $ 549 $ 126,747 Contract Intercompany Consolidated For the Year Ended December 31, 2014 Oil and Gas Drilling Eliminations Total (In thousands) Revenues $ 440,428 $ 59,107 $ (31,079 ) $ 468,456 Depreciation, depletion and amortization (a) 157,164 13,307 (4,088 ) 166,383 Other operating expenses (b) 170,878 41,912 (22,356 ) 190,434 Interest expense 50,907 — — 50,907 Other (income) expense (8,001 ) 165 — (7,836 ) Income (loss) before income taxes 69,480 3,723 (4,635 ) 68,568 Income tax (expense) benefit (23,384 ) (1,303 ) — (24,687 ) Net income (loss) $ 46,096 $ 2,420 $ (4,635 ) $ 43,881 Total assets $ 1,473,611 $ 70,051 $ (42,029 ) $ 1,501,633 Additions to property and equipment $ 412,951 $ 27,128 $ (4,635 ) $ 435,444 _______ (a) Includes impairment of property and equipment. (b) Includes the following expenses: production, exploration, midstream services, drilling rig services, accretion of ARO, G&A expenses and other operating expenses. (c) Includes impairment of our investment in Dalea.

Guarantor Financial Information

Guarantor Financial Information	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Guarantor Financial Information	Guarantor Financial Information In March and April 2011, we issued $350 million of aggregate principal amount of 2019 Senior Notes. In October 2013 , we issued $250 million of aggregate principal amount of the 2019 Senior Notes. The 2019 Senior Notes issued in October 2013 and the 2019 Senior Notes originally issued in March and April 2011 are treated as a single class of debt securities under the Indenture. In August 2016, we redeemed $100 million in aggregate principal amount of the 2019 Senior Notes in a tender offer and for the year ended December 31, 2016 recorded a $4 million gain on early extinguishment of long-term debt, consisting of a $5 million discount and a $1 million write-off of debt issuance costs (see Note 3). Presented below is condensed consolidated financial information of CWEI (the “Issuer”) and the Issuer’s material wholly owned subsidiaries. Other than CWEI Andrews Properties, GP, LLC, the general partner of CWEI Andrews Properties, L.P., an affiliated limited partnership formed in April 2013 , all of the Issuer’s wholly owned and active subsidiaries (“Guarantor Subsidiaries”) have jointly and severally, irrevocably and unconditionally guaranteed the performance and payment when due of all obligations under the 2019 Senior Notes. The guarantee by a Guarantor Subsidiary of the 2019 Senior Notes may be released under certain customary circumstances as set forth in the Indenture. CWEI Andrews Properties, GP, LLC, is not a guarantor of the 2019 Senior Notes and its accounts are reflected in the “Non-Guarantor Subsidiary” column in this Note 19. The financial information which follows sets forth our condensed consolidating financial statements as of and for the periods indicated. Condensed Consolidating Balance Sheet December 31, 2016 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Current assets $ 678,174 $ 244,756 $ 1,314 $ (293,058 ) $ 631,186 Property and equipment, net 585,803 267,128 3,205 — 856,136 Investments in subsidiaries 289,424 — — (289,424 ) — Other assets 5,197 2,120 — — 7,317 Total assets $ 1,558,598 $ 514,004 $ 4,519 $ (582,482 ) $ 1,494,639 Current liabilities $ 284,955 $ 101,349 $ 111 $ (279,649 ) $ 106,766 Non-current liabilities: Long-term debt 847,995 — — — 847,995 Fair value of commodity derivatives 12,895 — — (12,895 ) — Fair value of common stock warrants 246,743 — — — 246,743 Deferred income taxes 99,879 85,113 (2,070 ) (106,332 ) 76,590 Other 11,418 44,290 306 — 56,014 1,218,930 129,403 (1,764 ) (119,227 ) 1,227,342 Equity 54,713 283,252 6,172 (183,606 ) 160,531 Total liabilities and equity $ 1,558,598 $ 514,004 $ 4,519 $ (582,482 ) $ 1,494,639 Condensed Consolidating Balance Sheet December 31, 2015 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Current assets $ 112,861 $ 272,310 $ 1,441 $ (317,807 ) $ 68,805 Property and equipment, net 892,791 304,936 3,557 — 1,201,284 Investments in subsidiaries 324,484 — — (324,484 ) — Other assets 6,681 10,650 — — 17,331 Total assets $ 1,336,817 $ 587,896 $ 4,998 $ (642,291 ) $ 1,287,420 Current liabilities $ 276,354 $ 102,267 $ 117 $ (312,999 ) $ 65,739 Non-current liabilities: Long-term debt 742,410 — — — 742,410 Deferred income taxes 90,387 130,471 (1,236 ) (110,626 ) 108,996 Other 33,886 36,539 252 — 70,677 866,683 167,010 (984 ) (110,626 ) 922,083 Equity 193,780 318,619 5,865 (218,666 ) 299,598 Total liabilities and equity $ 1,336,817 $ 587,896 $ 4,998 $ (642,291 ) $ 1,287,420 Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Year Ended December 31, 2016 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Total revenue $ 235,841 $ 52,609 $ 961 $ — $ 289,411 Costs and expenses 172,727 93,114 1,256 — 267,097 Operating income (loss) 63,114 (40,505 ) (295 ) — 22,314 Other income (expense) (337,807 ) (7,753 ) 768 — (344,792 ) Equity in earnings of subsidiaries (31,060 ) — — 31,060 — Income tax (expense) benefit 13,602 16,890 (165 ) — 30,327 Net income (loss) $ (292,151 ) $ (31,368 ) $ 308 $ 31,060 $ (292,151 ) Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Year Ended December 31, 2015 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Total revenue $ 169,705 $ 61,224 $ 1,443 $ — $ 232,372 Costs and expenses 244,187 87,008 14,612 — 345,807 Operating income (loss) (74,482 ) (25,784 ) (13,169 ) — (113,435 ) Other income (expense) (41,187 ) (808 ) 2,095 — (39,900 ) Equity in earnings of subsidiaries (24,483 ) — — 24,483 — Income tax (expense) benefit 41,956 9,307 3,876 — 55,139 Net income (loss) $ (98,196 ) $ (17,285 ) $ (7,198 ) $ 24,483 $ (98,196 ) Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Year Ended December 31, 2014 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Total revenue $ 324,055 $ 140,857 $ 3,544 $ — $ 468,456 Costs and expenses 242,658 111,750 2,409 — 356,817 Operating income (loss) 81,397 29,107 1,135 — 111,639 Other income (expense) (45,538 ) 919 1,548 — (43,071 ) Equity in earnings of subsidiaries 21,261 — — (21,261 ) — Income tax (expense) benefit (13,239 ) (10,509 ) (939 ) — (24,687 ) Net income (loss) $ 43,881 $ 19,517 $ 1,744 $ (21,261 ) $ 43,881 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2016 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Operating activities $ 33,099 $ (22,247 ) $ (125 ) $ — $ 10,727 Investing activities 320,038 (6,801 ) (10 ) — 313,227 Financing activities 212,329 28,961 1 — 241,291 Net increase (decrease) in cash and cash equivalents 565,466 (87 ) (134 ) — 565,245 Cash at the beginning of the period 4,663 1,855 1,262 — 7,780 Cash at end of the period $ 570,129 $ 1,768 $ 1,128 $ — $ 573,025 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2015 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Operating activities $ 61,138 $ 836 $ (10,381 ) $ 566 $ 52,159 Investing activities (113,543 ) (15,143 ) 11,857 (566 ) (117,395 ) Financing activities 35,851 9,469 (320 ) — 45,000 Net increase (decrease) in cash and cash equivalents (16,554 ) (4,838 ) 1,156 — (20,236 ) Cash at the beginning of the period 21,217 6,693 106 — 28,016 Cash at end of the period $ 4,663 $ 1,855 $ 1,262 $ — $ 7,780 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2014 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Operating activities $ 178,769 $ 69,543 $ 5,842 $ 3,967 $ 258,121 Investing activities (274,629 ) (34,749 ) (5,652 ) (3,967 ) (318,997 ) Financing activities 97,384 (34,987 ) (128 ) — 62,269 Net increase (decrease) in cash and cash equivalents 1,524 (193 ) 62 — 1,393 Cash at the beginning of the period 19,693 6,886 44 — 26,623 Cash at end of the period $ 21,217 $ 6,693 $ 106 $ — $ 28,016

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2016
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events Proposed Merger with Noble Energy On January 13, 2017 , we entered into the Merger Agreement with Noble Energy, Merger Sub and Merger Sub II, pursuant to which Noble Energy will acquire the Company in exchange for a combination of Noble Energy Common Shares and cash. Under the terms of the Merger Agreement, at the Effective Time of the Merger, each share of the Company’s common stock issued and outstanding immediately prior to the Effective Time (other than common stock held in treasury and common stock held by shareholders who properly comply in all respects with the provisions of Section 262 of the DGCL as to appraisal rights) and each unexercised CWEI Warrant issued and outstanding as of the Effective Time will be cancelled and extinguished and automatically converted into the right to receive, at the election of the shareholder or warrant holder, as applicable, and subject to proration as described below, one of the following forms of Merger Consideration: • for each share of common stock, one of (i) 3.7222 Noble Energy Common Shares (the “Share Consideration”); (ii) (A) $34.75 in cash (subject to applicable withholding tax), without interest, and (B) 2.7874 Noble Energy Common Shares (the “Mixed Consideration”); or (iii) $138.39 in cash (subject to applicable withholding tax), without interest (the “Cash Consideration”); and • for each CWEI Warrant, either (i) the Share Consideration in respect of the number of shares of common stock of the Company that would be issued upon a cashless exercise of such CWEI Warrant immediately prior to the Effective Time (“Warrant Notional Common Shares”); (ii) the Mixed Consideration in respect of the number of Warrant Notional Common Shares represented by such CWEI Warrant; or (iii) the Cash Consideration in respect of the number of Warrant Notional Common Shares represented by such CWEI Warrant. The Merger Agreement contains certain termination rights for both Noble Energy and the Company, including if the Merger is not consummated by July 17, 2017 , and further provides that, upon termination of the Merger Agreement under certain circumstances, the Company may be required to pay Noble Energy a termination fee equal to $87 million . The closing of the Merger is expected to occur in the second quarter of 2017 . Purchase of Net Mineral Acres in Southern Reeves County, Texas In January 2017 , we purchased approximately 1,900 net mineral acres in Southern Reeves County, Texas from a private seller, for cash consideration totaling $44.3 million . The acreage is located in and around our existing contiguous acreage block. Also included in the deal was a non-operated gross working interest of approximately 26% in an existing horizontal well. We have evaluated events and transactions that occurred after the balance sheet date of December 31, 2016 and have determined that no other events or transactions have occurred that would require recognition in the consolidated financial statements or disclosures in these notes to the consolidated financial statements.

Supplemental Quarterly Financia

Supplemental Quarterly Financial Information	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Supplemental Quarterly Financial Information	Supplemental Quarterly Financial Data The following table summarizes results for each of the four quarters in the years ended 2016 and 2015 . First Quarter Second Quarter Third Quarter Fourth Quarter Year (In thousands, except per share) Year Ended December 31, 2016 Total revenues (a) $ 30,314 $ 42,195 $ 55,438 $ 161,464 $ 289,411 Operating income (loss) (a) $ (36,577 ) $ (33,565 ) $ (13,013 ) $ 105,469 $ 22,314 Net income (loss) $ (35,261 ) $ (80,937 ) $ (148,776 ) $ (27,177 ) $ (292,151 ) Net income (loss) per common share (b) : Basic $ (2.90 ) $ (6.65 ) $ (10.62 ) $ (1.54 ) $ (20.87 ) Diluted $ (2.90 ) $ (6.65 ) $ (10.62 ) $ (1.54 ) $ (20.87 ) Weighted average common shares outstanding: Basic 12,170 12,170 14,013 17,608 14,000 Diluted 12,170 12,170 14,013 17,608 14,000 Year Ended December 31, 2015 Total revenues $ 64,142 $ 73,231 $ 54,581 $ 40,418 $ 232,372 Operating income (loss) $ (20,182 ) $ (11,058 ) $ (19,739 ) $ (62,456 ) $ (113,435 ) Net income (loss) $ (18,232 ) $ (23,332 ) $ (9,423 ) $ (47,209 ) $ (98,196 ) Net income (loss) per common share (b) : Basic $ (1.50 ) $ (1.92 ) $ (0.77 ) $ (3.88 ) $ (8.07 ) Diluted $ (1.50 ) $ (1.92 ) $ (0.77 ) $ (3.88 ) $ (8.07 ) Weighted average common shares outstanding: Basic 12,170 12,170 12,170 12,170 12,170 Diluted 12,170 12,170 12,170 12,170 12,170 ______ (a) Includes gains on sales of assets related to the sale of substantially all of our assets in the Giddings Area in East Central Texas in December 2016. (b) The sum of the individual quarterly net income (loss) per share amounts may not agree to the total for the year since each period’s computation is based on the weighted average number of common shares outstanding during each period.

Supplemental Oil and Gas Reserv

Supplemental Oil and Gas Reserve Information	12 Months Ended
	Dec. 31, 2016
Extractive Industries [Abstract]
Supplemental Oil and Gas Reserve Information	Supplemental Oil and Gas Reserve Information The estimates of proved oil and gas reserves utilized in the preparation of the consolidated financial statements were prepared by independent petroleum engineers. Such estimates are in accordance with guidelines established by the Securities and Exchange Commission and the FASB. All of our reserves are located in the United States. For information about our results of operations from oil and gas activities, see the accompanying consolidated statements of operations and comprehensive income (loss). We emphasize that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. In addition, a portion of our proved reserves are classified as proved developed nonproducing and proved undeveloped, which increases the imprecision inherent in estimating reserves which may ultimately be produced. We did not have any capital costs relating to exploratory wells pending the determination of proved reserves for the years ended 2016 , 2015 and 2014 . The following table sets forth estimated proved reserves together with the changes therein (oil and NGL in MBbls, gas in MMcf, gas converted to MBOE by dividing MMcf by six) for the years ended 2016 , 2015 and 2014 . Oil Natural Gas Liquids Natural Gas MBOE Proved reserves: December 31, 2013 48,665 8,487 77,179 70,015 Extensions and discoveries 19,032 2,298 12,034 23,336 Revisions (7,786 ) (1,160 ) (6,934 ) (10,101 ) Sales of minerals-in-place (1,850 ) (73 ) (803 ) (2,057 ) Production (4,194 ) (585 ) (5,901 ) (5,763 ) December 31, 2014 53,867 8,967 75,575 75,430 Extensions and discoveries 2,669 407 2,796 3,542 Revisions (18,912 ) (3,344 ) (23,414 ) (26,158 ) Sales of minerals-in-place (291 ) (12 ) (1,016 ) (472 ) Production (4,257 ) (550 ) (5,794 ) (5,773 ) December 31, 2015 33,076 5,468 48,147 46,569 Extensions and discoveries 2,864 604 3,651 4,077 Revisions 553 (48 ) (4,036 ) (168 ) Sales of minerals-in-place (8,523 ) (656 ) (9,292 ) (10,728 ) Production (3,623 ) (557 ) (4,893 ) (4,996 ) December 31, 2016 24,347 4,811 33,577 34,754 Proved developed reserves: December 31, 2014 29,059 4,668 51,072 42,239 December 31, 2015 25,349 4,266 39,987 36,280 December 31, 2016 14,540 3,335 24,620 21,978 CLAYTON WILLIAMS ENERGY, INC. SUPPLEMENTAL INFORMATION (Continued) (UNAUDITED) The 168 MBOE of net downward revisions in proved reserves for 2016 resulted from a combination of (1) net upward revisions of 11,670 MBOE related primarily to performance in our Delaware Basin program, and (2) downward revisions of 11,838 MBOE related to the effects of lower commodity prices on the estimated quantities of proved reserves. The standardized measure of discounted future net cash flows relating to estimated proved reserves as of 2016 , 2015 and 2014 was as follows: 2016 2015 2014 (In thousands) Future cash inflows $ 1,035,786 $ 1,721,207 $ 5,479,211 Future costs: Production (424,092 ) (711,887 ) (1,719,989 ) Abandonment (65,852 ) (120,737 ) (149,112 ) Development (148,108 ) (147,189 ) (695,180 ) Income taxes (12,204 ) (38,306 ) (833,601 ) Future net cash flows 385,530 703,088 2,081,329 10% discount factor (226,567 ) (312,445 ) (1,148,416 ) Standardized measure of discounted net cash flows $ 158,963 $ 390,643 $ 932,913 Changes in the standardized measure of discounted future net cash flows relating to estimated proved reserves for the years ended 2016 , 2015 and 2014 were as follows: 2016 2015 2014 (In thousands) Standardized measure, beginning of period $ 390,643 $ 932,913 $ 926,923 Net changes in sales prices, net of production costs (71,603 ) (965,126 ) (94,104 ) Revisions of quantity estimates 329 (245,035 ) (234,612 ) Accretion of discount 44,278 137,998 138,095 Changes in future development costs, including development costs incurred that reduced future development costs 10,145 308,261 146,392 Changes in timing and other (29,458 ) (69,160 ) (70,774 ) Net change in income taxes 9,068 395,888 2,893 Future abandonment cost, net of salvage (2,357 ) (2,968 ) 4,066 Extensions and discoveries 39,678 48,367 431,895 Sales, net of production costs (84,384 ) (126,455 ) (309,758 ) Sales of minerals-in-place (147,376 ) (24,040 ) (8,103 ) Standardized measure, end of period $ 158,963 $ 390,643 $ 932,913 CLAYTON WILLIAMS ENERGY, INC. SUPPLEMENTAL INFORMATION (Continued) (UNAUDITED) The estimated present value of future cash flows relating to estimated proved reserves is extremely sensitive to prices used at any measurement period. Average prices for 2016 , 2015 and 2014 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period from January through December during each respective calendar year. These benchmark average prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to our properties. The average prices used for each commodity for the years ended 2016 , 2015 and 2014 were as follows: Average Price Oil Natural Gas Liquids Natural Gas ($/Bbl) ($/Bbl) ($/Mcf) As of December 31: 2016 $ 36.60 $ 13.60 $ 2.36 2015 $ 45.75 $ 15.84 $ 2.52 2014 $ 90.48 $ 31.54 $ 4.27

Summary of Significant Accoun29

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Estimates and Assumptions	Estimates and Assumptions The preparation of these consolidated financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ materially from those estimates. The accounting policies most affected by management’s estimates and assumptions are as follows: • Provisions for depreciation, depletion and amortization and estimates of non-equity plans are based on estimates of proved reserves; • Impairments of long-lived assets are based on estimates of future net cash flows and, when applicable, the estimated fair values of impaired assets; • Exploration expenses related to impairments of unproved acreage are based on estimates of fair values of the underlying leases; • Asset retirement obligations (“ARO”) are based on estimates regarding the timing and cost of future asset retirements; • Valuation of derivative financial instruments are based on the fair value of commodity derivatives; • Valuation of stock-based compensation is based on the grant date fair value; • Valuation of common stock warrants are based on their fair value using the Black-Scholes method; • Impairments of inventory are based on estimates of fair values of tubular goods and other well equipment held in inventory; and • Exploration expenses related to well abandonment costs are based on the judgments regarding the productive status of in-progress exploratory wells.
Principles of Consolidation	Principles of Consolidation The consolidated financial statements include the accounts of CWEI and its wholly owned subsidiaries. We account for our undivided interests in oil and gas limited partnerships using the proportionate consolidation method. Under this method, we consolidate our proportionate share of assets, liabilities, revenues and expenses of such limited partnerships. Less than 5% of our consolidated total assets and total revenues are derived from oil and gas limited partnerships. Substantially all intercompany transactions and balances associated with the consolidated operations have been eliminated.
Oil and Gas Properties	Oil and Gas Properties We follow the successful efforts method of accounting for oil and gas properties, whereby costs of productive wells, developmental dry holes and productive leases are capitalized into appropriate groups of properties based on geographical and geological similarities. These capitalized costs are amortized using the unit-of-production method based on estimated proved reserves. Proceeds from sales of properties are credited to property costs, and a gain or loss is recognized when a significant portion of an amortization base is sold or abandoned. Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to exploration expense if and when the well is determined to be nonproductive. The determination of an exploratory well’s ability to produce must be made within one year from the completion of drilling activities. The acquisition costs of unproved acreage are initially capitalized and are carried at cost, net of accumulated impairment provisions, until such leases are transferred to proved properties or charged to exploration expense as impairments of unproved properties.
Pipelines and Other Midstream Facilities and Other Property and Equipment	Pipelines and Other Midstream Facilities and Other Property and Equipment Pipelines and other midstream facilities consist of pipelines to transport oil, natural gas and water, natural gas processing facilities and compressors. Other property and equipment consists primarily of field equipment and facilities, office equipment, leasehold improvements and vehicles. Major renewals and betterments are capitalized while repairs and maintenance are charged to expense as incurred. The cost of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and any gain or loss is included in operating income (loss) in the accompanying consolidated statements of operations and comprehensive income (loss). Depreciation of pipelines and other midstream facilities and other property and equipment is computed on the straight-line method over the estimated useful lives of the assets, which generally range from 3 to 30 years.
Contract Drilling	Contract Drilling We conduct contract drilling operations through Desta Drilling, L.P. (“Desta Drilling”), a wholly owned subsidiary of CWEI. Desta Drilling recognizes revenues and expenses from daywork drilling contracts as the work is performed, but defers revenues and expenses from footage or turnkey contracts until the well is substantially completed or until a loss, if any, on a contract is determinable. Property and equipment, including buildings, major replacements, improvements and capitalized interest on construction-in-progress, are capitalized and are depreciated using the straight-line method over estimated useful lives of 3 to 40 years. Upon disposition, the costs and related accumulated depreciation of assets are eliminated from the accounts and the resulting gain or loss is recognized.
Valuation of Property and Equipment	Valuation of Property and Equipment Our long-lived assets, including proved oil and gas properties and contract drilling equipment, are assessed for potential impairment in their carrying values, based on depletable groupings, whenever events or changes in circumstances indicate such impairment may have occurred. An impairment is recognized when the estimated undiscounted future net cash flows of the asset are less than its carrying value. Any such impairment is recognized based on the difference in the carrying value and estimated fair value of the impaired asset. Unproved oil and gas properties are periodically assessed, and any impairment in value is charged to exploration costs. The amount of impairment recognized on unproved properties which are not individually significant is determined by impairing the costs of such properties within appropriate groups based on our historical experience, acquisition dates and average lease terms. The valuation of unproved properties is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values.
Asset Retirement Obligations	Asset Retirement Obligations We recognize a liability for the present value of all legal obligations associated with the retirement of tangible, long-lived assets and capitalize an equal amount as a cost of the asset. The cost associated with the asset retirement obligation, along with any estimated salvage value, is included in the computation of depreciation, depletion and amortization.
Income Taxes	Income Taxes We utilize the asset and liability method to account for income taxes. Under this method of accounting for income taxes, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the consolidated financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in enacted tax rates is recognized in the consolidated statements of operations and comprehensive income (loss) in the period that includes the enactment date. We also record any financial statement recognition and disclosure requirements for uncertain tax positions taken or expected to be taken in a tax return. Financial statement recognition of the tax position is dependent on an assessment of a 50% or greater likelihood that the tax position will be sustained upon examination, based on the technical merits of the position. Any interest and penalties related to uncertain tax positions are recorded as interest expense.
Hedging Transactions	Hedging Transactions From time to time, we utilize commodity derivative instruments, consisting of swaps, floors and collars, to attempt to optimize the price received for our oil and gas production. All of our commodity derivative instruments are recognized as assets or liabilities in the balance sheet, measured at fair value. The accounting for changes in the fair value of a commodity derivative depends on both the intended purpose and the formal designation of the commodity derivative. Designation is established at the inception of a commodity derivative, but subsequent changes to the designation are permitted. For commodity derivatives designated as cash flow hedges and meeting the effectiveness guidelines under applicable accounting standards, changes in fair value are recognized in other comprehensive income (loss) until the hedged item is recognized in earnings. Hedge effectiveness is measured quarterly based on relative changes in fair value between the commodity derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Changes in fair value of commodity derivative instruments which are not designated as cash flow hedges or do not meet the effectiveness guidelines are recorded in earnings as the changes occur. If designated as cash flow hedges, actual gains or losses on settled commodity derivatives are recorded as oil and gas revenues in the period the hedged production is sold, while actual gains or losses on interest rate derivatives are recorded in interest expense for the applicable period. Actual gains or losses from commodity derivatives not designated as cash flow hedges are recorded in other income (expense) as gain (loss) on commodity derivatives.
Stock-Based Compensation	Stock-Based Compensation Restricted stock and stock options issued to employees and directors are recorded at grant-date fair value. Stock-based compensation expense is recognized in our consolidated statement of operations and comprehensive income (loss) on an accelerated basis over the awards’ vesting periods based on their fair values on the dates of grant, net of an estimate for forfeitures. Stock-based compensation awards generally vest over a period ranging from one to three years. We utilize the Black-Scholes option pricing model to measure the fair value of stock options.
Common Stock Warrants	Common Stock Warrants Common stock warrant liabilities are measured at fair value on a recurring basis until the underlying common stock warrants are exercised (see Note 3). We measure the fair value of the common stock warrant liabilities using the Black-Scholes method (Level 2 inputs). Inputs used to determine fair value under this method include our price volatility and expected remaining life.
Inventory	Inventory Inventory consists primarily of tubular goods and other well equipment which we plan to utilize in our exploration and development activities and is stated at the lower of average cost or estimated market value.
Capitalization of Interest	Capitalization of Interest Interest costs associated with our inventory of unproved oil and gas property lease acquisition costs are capitalized during the periods for which exploration activities are in progress.
Cash and Cash Equivalents	Cash and Cash Equivalents We consider all cash and highly liquid investments with original maturities of three months or less to be cash equivalents.
Net Income (Loss) Per Common Share	Net Income (Loss) Per Common Share Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of common shares outstanding for the period. Diluted net income (loss) per share reflects the potential dilution that could occur if dilutive stock options were exercised, calculated using the treasury stock method. The diluted net income (loss) per share calculations for December 31, 2016 , 2015 and 2014 include changes in potential shares attributable to dilutive stock options and restricted stock.
Fair Value Measurements	Fair Value Measurements We follow a framework for measuring fair value, which outlines a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements. Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued. We categorize our assets and liabilities recorded at fair value in the accompanying consolidated balance sheets based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities are as follows: Level 1 - Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date. Level 2 - Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life. Level 3 - Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.
Revenue Recognition and Gas Balancing	Revenue Recognition and Gas Balancing We utilize the sales method of accounting for oil, natural gas and natural gas liquids (“NGL”) revenues whereby revenues, net of royalties, are recognized as the production is sold to purchasers. The amount of gas sold may differ from the amount to which we are entitled based on our revenue interests in the properties. We did not have any significant gas imbalance positions at December 31, 2016 , 2015 or 2014 . Revenues from midstream services and drilling rig services are recognized as services are provided.
Comprehensive Income (Loss)	Comprehensive Income (Loss) There were no differences between net income (loss) and comprehensive income (loss) in December 31, 2016 , 2015 and 2014 .
Concentration Risks	Concentration Risks We sell our oil and natural gas production to various customers, serve as operator in the drilling, completion and operation of oil and gas wells, and enter into derivatives with various counterparties. When management deems appropriate, we obtain letters of credit to secure amounts due from our principal oil and gas purchasers and follow other procedures to monitor credit risk from joint owners and derivatives counterparties. Allowances for doubtful accounts at December 31, 2016 and 2015 relate to amounts due from joint interest owners.
Recent Accounting Pronouncements	Recent Accounting Pronouncements In August 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.” The objective of the standard is to reduce the existing diversity in practice of several cash flow issues, including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payment made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows and application of the predominance principle. The guidance in ASU 2016-15 is effective for public entities for annual reporting periods beginning after December 15, 2017, including interim periods therein. Early adoption is permitted and is to be applied on retrospective basis. We are currently evaluating the method of adoption and impact this standard may have on our financial statements and related disclosures. In March 2016, the FASB issued ASU 2016-09, “Compensation - Stock Compensation.” ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as certain classification changes in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Upon adoption, we expect to record a cumulative-effect adjustment to reclassify approximately $7.5 million of excess tax benefits that were not previously recognized because the related tax deduction had not reduced taxes payable. We plan to adopt ASU 2016-09 during the quarter ended March 31, 2017 to be effective as of January 1, 2017. In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842),” which supersedes current lease guidance. The new lease standard requires all leases with a term greater than one year to be recognized on the balance sheet while maintaining substantially similar classifications for finance and operating leases. Lease expense recognition on the income statement will be effectively unchanged. This guidance is effective for reporting periods beginning after December 15, 2018 and early adoption is permitted. We do not plan to early adopt the standard. We enter into lease agreements to support our operations. These agreements are for leases on assets such as office space and vehicles. We are currently in the process of reviewing all contracts that could be applicable to this new guidance. We believe this new guidance will have a moderate impact to our consolidated balance sheet due to the recognition of lease-related assets and liabilities that were not previously recognized. In November 2015, the FASB issued ASU No. 2015-17, “Income Taxes.” This ASU requires that deferred tax assets and liabilities be classified as non-current on the balance sheet. The standard will be effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption will be permitted as of the beginning of an interim or annual reporting period. This standard may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. Adoption of the new guidance will affect the presentation of our consolidated balance sheets and will not have a material impact on our consolidated financial statements. In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory.” This ASU requires entities to measure most inventory at the lower of cost and net realizable value, thereby simplifying the current guidance under which an entity must measure inventory at the lower of cost or market. ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years and should be applied prospectively, with early adoption permitted. The adoption of this standard will not have a material impact on our consolidated financial statements. In April 2015, the FASB issued ASU No. 2015-03, “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” which requires net debt issuance costs directly related to our senior notes and our second lien term loan to be classified as a direct deduction from the carrying amount of the related senior notes and second lien term loan. We adopted this ASU as of March 31, 2016 and reclassified $7.3 million of debt issuance costs at December 31, 2015 from a non-current asset to a direct deduction in long-term debt. The debt issuance costs related to our revolving credit facility remains classified as a non-current asset due to the revolving nature of that facility. In August 2014, the FASB issued ASU No. 2014-15, “Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.” ASU 2014-15 requires management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. Certain disclosures are required should substantial doubt exist. This evaluation is performed each annual and interim reporting period to assess conditions or events within one year after the date that the financial statements are issued. This ASU was effective beginning December 31, 2016; however, no additional disclosures as contemplated by this ASU were warranted. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” that outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. In summary, revenue recognition would occur upon the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Additionally, ASU 2014-09 requires enhanced financial statement disclosures over revenue recognition as part of the new accounting guidance. The standard will be effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. In March 2016, the FASB released certain implementation guidance through ASU 2016-08 to clarify principal versus agent considerations. We are evaluating the guidance to determine the method of adoption and the impact this standard will have on our consolidated financial statements and related disclosures. Based on our initial evaluation, though not currently quantified, the adoption of the standard is not expected to have a material impact on the timing of revenue recognized, results of operations or cash flows.

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Schedule of long-term debt	Long-term debt consists of the following: December 31, December 31, (In thousands) 7.75% Senior Notes, due 2019 $ 500,000 $ 600,000 Original issue discount (144 ) (241 ) Debt issuance costs (4,405 ) (7,349 ) Net 7.75% Senior Notes, due 2019 $ 495,451 $ 592,410 Second Lien Term Loan, due March 2021 $ 377,196 $ — Original issue discount (14,961 ) — Debt issuance costs (9,691 ) — Net Second Lien Term Loan, due March 2021 $ 352,544 $ — Revolving Credit Facility, due April 2019 $ — $ 150,000 $ 847,995 $ 742,410

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Schedule of changes in asset retirement obligations	The following table reflects the changes in ARO for the years ended December 31, 2016 and 2015 : 2016 2015 (In thousands) Beginning of year $ 48,728 $ 45,697 Additional ARO from new properties 61 469 Sales or abandonments of properties (17,206 ) (4,435 ) Accretion expense 4,364 3,945 Revisions of previous estimates 11,276 3,052 End of year $ 47,223 $ 48,728

Deferred Revenue from Volumet32

Deferred Revenue from Volumetric Production Payment (Tables)	12 Months Ended
	Dec. 31, 2016
Deferred Revenue Disclosure [Abstract]
Schedule of changes in deferred revenue from the VPP	The following table reflects the changes in deferred revenue during the years ended December 31, 2016 and 2015 : 2016 2015 (In thousands) Beginning of year $ 5,470 $ 23,129 Deferred revenue from VPP — 2,866 Amortization of deferred revenue from VPP (1,479 ) (6,822 ) Termination of VPP — (13,703 ) End of year $ 3,991 $ 5,470

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Schedule of deferred tax assets and liabilities	Significant components of net deferred tax liabilities at December 31, 2016 and 2015 are as follows: 2016 2015 (In thousands) Deferred tax assets: Net operating loss carryforwards $ 76,213 $ 106,992 Statutory depletion carryforwards 9,913 9,809 Asset retirement obligations and other 22,518 21,249 108,644 138,050 Deferred tax liabilities: Property and equipment (178,714 ) (240,520 ) Net deferred tax liabilities $ (70,070 ) $ (102,470 ) Components of net deferred tax liabilities: Current assets $ 6,520 $ 6,526 Non-current liabilities (76,590 ) (108,996 ) Net deferred tax liabilities $ (70,070 ) $ (102,470 )
Schedule of effective income tax rate reconciliation	For the years ended December 31, 2016 , 2015 and 2014 , effective income tax rates were different than the statutory federal income tax rates for the following reasons: 2016 2015 2014 (In thousands) Income tax expense (benefit) at statutory rate of 35% $ (112,867 ) $ (53,667 ) $ 23,999 Tax depletion in excess of basis (164 ) (282 ) (729 ) Revision of previous tax estimates 63 30 (155 ) State income tax expense (benefit), net of federal tax effect 857 (1,472 ) 1,008 Permanent and other (a) 81,784 252 564 Income tax expense (benefit) $ (30,327 ) $ (55,139 ) $ 24,687 Current $ 2,073 $ 79 $ 227 Deferred (32,400 ) (55,218 ) 24,460 Income tax expense (benefit) $ (30,327 ) $ (55,139 ) $ 24,687 ______ (a) Includes $80.5 million of permanent differences related to the change in fair value of common stock warrants in 2016.

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of price risk derivatives	The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to December 31, 2016 . Settlement prices of commodity derivatives are based on NYMEX futures prices. Swaps: Oil MBbls Price Production Period: 1st Quarter 2017 178 $ 44.85 2nd Quarter 2017 165 $ 44.65 3rd Quarter 2017 37 $ 50.00 4th Quarter 2017 27 $ 50.00 407 Costless Collars: Oil MBbls Weighted Average Floor Price Weighted Average Ceiling Price Production Period: 1st Quarter 2017 355 $ 42.26 $ 51.67 2nd Quarter 2017 354 $ 42.27 $ 51.67 3rd Quarter 2017 356 $ 42.27 $ 51.65 4th Quarter 2017 350 $ 42.27 $ 51.66 1,415
Schedule of effect of commodity derivative instruments on the consolidated balance sheet	Effect of Commodity Derivative Instruments on the Consolidated Balance Sheets Fair Value of Commodity Derivative Instruments as of December 31, 2016 Asset Commodity Derivatives Liability Commodity Derivatives Balance Sheet Location Fair Value Balance Sheet Location Fair Value (In thousands) (In thousands) Commodity derivatives not designated as hedging instruments: Commodity derivatives Fair value of commodity derivatives: Fair value of commodity derivatives: Current $ — Current $ 12,895 Non-current — Non-current — Total $ — $ 12,895 Fair Value of Commodity Derivative Instruments as of December 31, 2015 Asset Commodity Derivatives Liability Commodity Derivatives Balance Sheet Location Fair Value Balance Sheet Location Fair Value (In thousands) (In thousands) Commodity derivatives not designated as hedging instruments: Commodity derivatives Fair value of commodity derivatives: Fair value of commodity derivatives: Current $ — Current $ — Non-current — Non-current — Total $ — $ —
Schedule of gross to net presentation reconciliation of commodity derivative assets and liabilities	Gross to Net Presentation Reconciliation of Commodity Derivative Assets and Liabilities December 31, 2016 Assets Liabilities (In thousands) Fair value of commodity derivatives — gross presentation $ — $ 12,895 Effects of netting arrangements — — Fair value of commodity derivatives — net presentation $ — $ 12,895 December 31, 2015 Assets Liabilities (In thousands) Fair value of commodity derivatives — gross presentation $ — $ — Effects of netting arrangements — — Fair value of commodity derivatives — net presentation $ — $ —
Schedule of effect of derivative instruments on the consolidated statement of operations and Comprehensive Income (Loss)	Effect of Commodity Derivative Instruments Recognized in Earnings on the Consolidated Statements of Operations and Comprehensive Income (Loss) Amount of Gain or (Loss) Recognized in Earnings Year Ended December 31, Location of Gain or (Loss) Recognized in Earnings 2016 2015 2014 (In thousands) Commodity derivatives not designated as hedging instruments: Commodity derivatives: Other income (expense) - Gain (loss) on commodity derivatives $ (20,289 ) $ 12,519 $ 4,789 Total $ (20,289 ) $ 12,519 $ 4,789

Fair Value of Financial Instr35

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Schedule of financial assets and liabilities measured on a recurring basis	The fair value of all commodity derivative contracts and common stock warrants are reflected on the consolidated balance sheets as detailed in the following schedule: December 31, 2016 December 31, 2015 Description Significant Other Observable Inputs (Level 2) (In thousands) Assets: Fair value of commodity derivatives $ — $ — Total assets $ — $ — Liabilities: Fair value of commodity derivatives $ 12,895 $ — Fair value of common stock warrants 246,743 — Total liabilities $ 259,638 $ —
Schedule of comparison of fair value to the carrying value of the 2019 Senior Notes	Fair value is compared to the carrying value in the table below: Fair Value December 31, 2016 December 31, 2015 Hierarchy Carrying Estimated Carrying Estimated Description Level Amount Fair Value Amount Fair Value (In thousands) 7.75% Senior Notes, due 2019 1 $ 495,451 $ 505,650 $ 592,410 $ 462,750 Second Lien Term Loan, due March 2021 3 $ 352,544 $ 378,996 $ — $ —

Compensation Plans (Tables)

Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of weighted average grant date fair values and related assumptions for grants made	The following table summarizes the weighted average grant date fair values and related assumptions for grants made during the year ended December 31, 2016 : December 31, 2016 Grant-date fair value $ 45.88 Expected volatility 76.3 % Expected term (in years) 5 Risk-free rate 1.2 %
Schedule of stock options activity	The following table sets forth certain information regarding our stock options as of December 31, 2016 : Weighted Average Options Exercise Price Remaining Term Aggregate Intrinsic Value Outstanding at January 1, 2016 — $ — Granted 282,000 $ 74.21 Exercised — $ — Outstanding at December 31, 2016 282,000 $ 74.21 Vested and expected to vest at December 31, 2016 282,000 $ 74.21 6.7 $ 12,705,250 Exercisable at December 31, 2016 — $ — — $ —
Schedule of restricted stock activity	The following table presents our restricted stock activity as of December 31, 2016 : Restricted Stock Awards Weighted-Average Grant Date Fair Value Unvested at January 1, 2016 — $ — Granted 410,165 $ 71.26 Vested (25,000 ) $ 63.11 Forfeited — $ — Unvested at December 31, 2016 385,165 $ 71.79
Schedule of aggregate compensation under non-equity award plans reflected on the balance sheet	Accrued compensation under non-equity award plans is reflected in the accompanying consolidated balance sheets as detailed in the following schedule: 2016 2015 (In thousands) Current liabilities: Accrued liabilities and other $ 1,087 $ 1,251 Non-current liabilities: Accrued compensation under non-equity award plans 4,655 16,254 Total accrued compensation under non-equity award plans $ 5,742 $ 17,505

Transactions with Affiliates (T

Transactions with Affiliates (Tables)	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Summary of charges to and from Williams Entities	The following table summarizes the charges to and from the Williams Entities for the years ended December 31, 2016 , 2015 and 2014 . 2016 2015 2014 (In thousands) Amounts received from the Williams Entities: Service Agreement: Services $ 603 $ 622 $ 663 Insurance premiums and benefits 989 922 960 Reimbursed expenses 252 500 296 $ 1,844 $ 2,044 $ 1,919 Amounts paid to the Williams Entities: Rent (a) $ 1,697 $ 1,741 $ 1,614 Service Agreement: Business entertainment (b) 155 155 205 Reimbursed expenses 135 226 204 $ 1,987 $ 2,122 $ 2,023 ______ (a) Rent amounts were paid to ClayDesta Buildings, L.P., a Texas limited partnership referred to as CDBLP, of which the Company owns 33.5% and affiliates of the Company own 25.8% . A Williams Entity provides property management services to the buildings owned and operated by CDBLP. (b) Consists primarily of hunting and fishing recreation for business associates and employees of the Company on land owned by affiliates of Mr. Williams.

Other Operating Revenues and 38

Other Operating Revenues and Expenses (Tables)	12 Months Ended
	Dec. 31, 2016
Other Income and Expenses [Abstract]
Schedule of net gain on sales of assets and impairment of inventory	Other operating revenues and expenses for the years ended December 31, 2016 , 2015 and 2014 are as follows: 2016 2015 2014 (In thousands) Other operating revenues: Gain on sales of assets $ 123,392 $ 8,718 $ 11,685 Marketing revenue — 24 3,708 Total other operating revenues $ 123,392 $ 8,742 $ 15,393 Other operating expenses: Loss on sales of assets $ 3,152 $ 1,355 $ 2,511 Marketing expense 440 849 — Impairment of inventory 1,454 10,381 36 Total other operating expenses $ 5,046 $ 12,585 $ 2,547

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Schedule Future minimum payments under noncancelable leases	Future minimum payments under noncancelable leases at December 31, 2016 are as follows: Leases Capital (a) Operating Total (In thousands) 2017 $ 241 $ 887 $ 1,128 2018 85 614 699 2019 45 613 658 Thereafter — 102 102 Total minimum lease payments $ 371 $ 2,216 $ 2,587 ______ (a) Relates to vehicle leases.

Costs of Oil and Gas Properti40

Costs of Oil and Gas Properties (Tables)	12 Months Ended
	Dec. 31, 2016
Oil and Gas Property, Successful Effort Method, Gross [Abstract]
Costs incurred in connection with the company's oil and gas producing activities	The following table sets forth certain information with respect to costs incurred in connection with the Company’s oil and gas producing activities during the years ended December 31, 2016 , 2015 and 2014 . 2016 2015 2014 (In thousands) Property acquisitions: Proved $ — $ — $ — Unproved 32,840 29,711 56,327 Developmental costs 49,614 81,466 342,716 Exploratory costs 20,095 14,342 4,350 Total $ 102,549 $ 125,519 $ 403,393
Schedule of net capitalized costs for oil and gas properties	The following table sets forth the net capitalized costs for oil and gas properties as of 2016 and 2015 . 2016 2015 (In thousands) Proved properties $ 1,643,038 $ 2,539,480 Unproved properties 74,171 46,022 Total capitalized costs 1,717,209 2,585,502 Accumulated depletion (928,927 ) (1,460,404 ) Net capitalized costs $ 788,282 $ 1,125,098

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Schedule of selected financial information regarding operating segments	The following tables present selected financial information regarding our operating segments for the years ended December 31, 2016 , 2015 and 2014 . Contract Intercompany Consolidated For the Year Ended December 31, 2016 Oil and Gas Drilling Eliminations Total (In thousands) Revenues $ 289,246 $ 165 $ — $ 289,411 Depreciation, depletion and amortization (a) 138,875 14,332 — 153,207 Other operating expenses (b) 110,119 3,771 — 113,890 Interest expense 93,693 — — 93,693 Other (income) expense (c) 241,557 9,542 — 251,099 Income (loss) before income taxes (294,998 ) (27,480 ) — (322,478 ) Income tax (expense) benefit 20,709 9,618 — 30,327 Net income (loss) $ (274,289 ) $ (17,862 ) $ — $ (292,151 ) Total assets $ 1,524,220 $ 19,180 $ (48,761 ) $ 1,494,639 Additions to property and equipment $ 112,429 $ 58 $ — $ 112,487 Contract Intercompany Consolidated For the Year Ended December 31, 2015 Oil and Gas Drilling Eliminations Total (In thousands) Revenues $ 232,279 $ 2,837 $ (2,744 ) $ 232,372 Depreciation, depletion and amortization (a) 187,913 16,832 (566 ) 204,179 Other operating expenses (b) 135,177 9,178 (2,727 ) 141,628 Interest expense 54,422 — — 54,422 Other (income) expense (c) (17,091 ) 2,569 — (14,522 ) Income (loss) before income taxes (128,142 ) (25,742 ) 549 (153,335 ) Income tax (expense) benefit 46,129 9,010 — 55,139 Net income (loss) $ (82,013 ) $ (16,732 ) $ 549 $ (98,196 ) Total assets $ 1,283,649 $ 48,943 $ (45,172 ) $ 1,287,420 Additions to property and equipment $ 124,996 $ 1,202 $ 549 $ 126,747 Contract Intercompany Consolidated For the Year Ended December 31, 2014 Oil and Gas Drilling Eliminations Total (In thousands) Revenues $ 440,428 $ 59,107 $ (31,079 ) $ 468,456 Depreciation, depletion and amortization (a) 157,164 13,307 (4,088 ) 166,383 Other operating expenses (b) 170,878 41,912 (22,356 ) 190,434 Interest expense 50,907 — — 50,907 Other (income) expense (8,001 ) 165 — (7,836 ) Income (loss) before income taxes 69,480 3,723 (4,635 ) 68,568 Income tax (expense) benefit (23,384 ) (1,303 ) — (24,687 ) Net income (loss) $ 46,096 $ 2,420 $ (4,635 ) $ 43,881 Total assets $ 1,473,611 $ 70,051 $ (42,029 ) $ 1,501,633 Additions to property and equipment $ 412,951 $ 27,128 $ (4,635 ) $ 435,444 _______ (a) Includes impairment of property and equipment. (b) Includes the following expenses: production, exploration, midstream services, drilling rig services, accretion of ARO, G&A expenses and other operating expenses. (c) Includes impairment of our investment in Dalea.

Guarantor Financial Informati42

Guarantor Financial Information (Tables)	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Condensed Consolidating Balance Sheet	Condensed Consolidating Balance Sheet December 31, 2016 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Current assets $ 678,174 $ 244,756 $ 1,314 $ (293,058 ) $ 631,186 Property and equipment, net 585,803 267,128 3,205 — 856,136 Investments in subsidiaries 289,424 — — (289,424 ) — Other assets 5,197 2,120 — — 7,317 Total assets $ 1,558,598 $ 514,004 $ 4,519 $ (582,482 ) $ 1,494,639 Current liabilities $ 284,955 $ 101,349 $ 111 $ (279,649 ) $ 106,766 Non-current liabilities: Long-term debt 847,995 — — — 847,995 Fair value of commodity derivatives 12,895 — — (12,895 ) — Fair value of common stock warrants 246,743 — — — 246,743 Deferred income taxes 99,879 85,113 (2,070 ) (106,332 ) 76,590 Other 11,418 44,290 306 — 56,014 1,218,930 129,403 (1,764 ) (119,227 ) 1,227,342 Equity 54,713 283,252 6,172 (183,606 ) 160,531 Total liabilities and equity $ 1,558,598 $ 514,004 $ 4,519 $ (582,482 ) $ 1,494,639 Condensed Consolidating Balance Sheet December 31, 2015 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Current assets $ 112,861 $ 272,310 $ 1,441 $ (317,807 ) $ 68,805 Property and equipment, net 892,791 304,936 3,557 — 1,201,284 Investments in subsidiaries 324,484 — — (324,484 ) — Other assets 6,681 10,650 — — 17,331 Total assets $ 1,336,817 $ 587,896 $ 4,998 $ (642,291 ) $ 1,287,420 Current liabilities $ 276,354 $ 102,267 $ 117 $ (312,999 ) $ 65,739 Non-current liabilities: Long-term debt 742,410 — — — 742,410 Deferred income taxes 90,387 130,471 (1,236 ) (110,626 ) 108,996 Other 33,886 36,539 252 — 70,677 866,683 167,010 (984 ) (110,626 ) 922,083 Equity 193,780 318,619 5,865 (218,666 ) 299,598 Total liabilities and equity $ 1,336,817 $ 587,896 $ 4,998 $ (642,291 ) $ 1,287,420
Schedule of Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)	Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Year Ended December 31, 2016 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Total revenue $ 235,841 $ 52,609 $ 961 $ — $ 289,411 Costs and expenses 172,727 93,114 1,256 — 267,097 Operating income (loss) 63,114 (40,505 ) (295 ) — 22,314 Other income (expense) (337,807 ) (7,753 ) 768 — (344,792 ) Equity in earnings of subsidiaries (31,060 ) — — 31,060 — Income tax (expense) benefit 13,602 16,890 (165 ) — 30,327 Net income (loss) $ (292,151 ) $ (31,368 ) $ 308 $ 31,060 $ (292,151 ) Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Year Ended December 31, 2015 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Total revenue $ 169,705 $ 61,224 $ 1,443 $ — $ 232,372 Costs and expenses 244,187 87,008 14,612 — 345,807 Operating income (loss) (74,482 ) (25,784 ) (13,169 ) — (113,435 ) Other income (expense) (41,187 ) (808 ) 2,095 — (39,900 ) Equity in earnings of subsidiaries (24,483 ) — — 24,483 — Income tax (expense) benefit 41,956 9,307 3,876 — 55,139 Net income (loss) $ (98,196 ) $ (17,285 ) $ (7,198 ) $ 24,483 $ (98,196 ) Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Year Ended December 31, 2014 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Total revenue $ 324,055 $ 140,857 $ 3,544 $ — $ 468,456 Costs and expenses 242,658 111,750 2,409 — 356,817 Operating income (loss) 81,397 29,107 1,135 — 111,639 Other income (expense) (45,538 ) 919 1,548 — (43,071 ) Equity in earnings of subsidiaries 21,261 — — (21,261 ) — Income tax (expense) benefit (13,239 ) (10,509 ) (939 ) — (24,687 ) Net income (loss) $ 43,881 $ 19,517 $ 1,744 $ (21,261 ) $ 43,881
Schedule of Condensed Consolidating Statement of Cash Flows	Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2016 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Operating activities $ 33,099 $ (22,247 ) $ (125 ) $ — $ 10,727 Investing activities 320,038 (6,801 ) (10 ) — 313,227 Financing activities 212,329 28,961 1 — 241,291 Net increase (decrease) in cash and cash equivalents 565,466 (87 ) (134 ) — 565,245 Cash at the beginning of the period 4,663 1,855 1,262 — 7,780 Cash at end of the period $ 570,129 $ 1,768 $ 1,128 $ — $ 573,025 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2015 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Operating activities $ 61,138 $ 836 $ (10,381 ) $ 566 $ 52,159 Investing activities (113,543 ) (15,143 ) 11,857 (566 ) (117,395 ) Financing activities 35,851 9,469 (320 ) — 45,000 Net increase (decrease) in cash and cash equivalents (16,554 ) (4,838 ) 1,156 — (20,236 ) Cash at the beginning of the period 21,217 6,693 106 — 28,016 Cash at end of the period $ 4,663 $ 1,855 $ 1,262 $ — $ 7,780 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2014 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Operating activities $ 178,769 $ 69,543 $ 5,842 $ 3,967 $ 258,121 Investing activities (274,629 ) (34,749 ) (5,652 ) (3,967 ) (318,997 ) Financing activities 97,384 (34,987 ) (128 ) — 62,269 Net increase (decrease) in cash and cash equivalents 1,524 (193 ) 62 — 1,393 Cash at the beginning of the period 19,693 6,886 44 — 26,623 Cash at end of the period $ 21,217 $ 6,693 $ 106 $ — $ 28,016

Supplemental Quarterly Financ43

Supplemental Quarterly Financial Information (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	The following table summarizes results for each of the four quarters in the years ended 2016 and 2015 . First Quarter Second Quarter Third Quarter Fourth Quarter Year (In thousands, except per share) Year Ended December 31, 2016 Total revenues (a) $ 30,314 $ 42,195 $ 55,438 $ 161,464 $ 289,411 Operating income (loss) (a) $ (36,577 ) $ (33,565 ) $ (13,013 ) $ 105,469 $ 22,314 Net income (loss) $ (35,261 ) $ (80,937 ) $ (148,776 ) $ (27,177 ) $ (292,151 ) Net income (loss) per common share (b) : Basic $ (2.90 ) $ (6.65 ) $ (10.62 ) $ (1.54 ) $ (20.87 ) Diluted $ (2.90 ) $ (6.65 ) $ (10.62 ) $ (1.54 ) $ (20.87 ) Weighted average common shares outstanding: Basic 12,170 12,170 14,013 17,608 14,000 Diluted 12,170 12,170 14,013 17,608 14,000 Year Ended December 31, 2015 Total revenues $ 64,142 $ 73,231 $ 54,581 $ 40,418 $ 232,372 Operating income (loss) $ (20,182 ) $ (11,058 ) $ (19,739 ) $ (62,456 ) $ (113,435 ) Net income (loss) $ (18,232 ) $ (23,332 ) $ (9,423 ) $ (47,209 ) $ (98,196 ) Net income (loss) per common share (b) : Basic $ (1.50 ) $ (1.92 ) $ (0.77 ) $ (3.88 ) $ (8.07 ) Diluted $ (1.50 ) $ (1.92 ) $ (0.77 ) $ (3.88 ) $ (8.07 ) Weighted average common shares outstanding: Basic 12,170 12,170 12,170 12,170 12,170 Diluted 12,170 12,170 12,170 12,170 12,170 ______ (a) Includes gains on sales of assets related to the sale of substantially all of our assets in the Giddings Area in East Central Texas in December 2016. (b) The sum of the individual quarterly net income (loss) per share amounts may not agree to the total for the year since each period’s computation is based on the weighted average number of common shares outstanding during each period.

Supplemental Oil and Gas Rese44

Supplemental Oil and Gas Reserve Information (Tables)	12 Months Ended
	Dec. 31, 2016
Extractive Industries [Abstract]
Schedule of estimated proved oil and gas reserves	The following table sets forth estimated proved reserves together with the changes therein (oil and NGL in MBbls, gas in MMcf, gas converted to MBOE by dividing MMcf by six) for the years ended 2016 , 2015 and 2014 . Oil Natural Gas Liquids Natural Gas MBOE Proved reserves: December 31, 2013 48,665 8,487 77,179 70,015 Extensions and discoveries 19,032 2,298 12,034 23,336 Revisions (7,786 ) (1,160 ) (6,934 ) (10,101 ) Sales of minerals-in-place (1,850 ) (73 ) (803 ) (2,057 ) Production (4,194 ) (585 ) (5,901 ) (5,763 ) December 31, 2014 53,867 8,967 75,575 75,430 Extensions and discoveries 2,669 407 2,796 3,542 Revisions (18,912 ) (3,344 ) (23,414 ) (26,158 ) Sales of minerals-in-place (291 ) (12 ) (1,016 ) (472 ) Production (4,257 ) (550 ) (5,794 ) (5,773 ) December 31, 2015 33,076 5,468 48,147 46,569 Extensions and discoveries 2,864 604 3,651 4,077 Revisions 553 (48 ) (4,036 ) (168 ) Sales of minerals-in-place (8,523 ) (656 ) (9,292 ) (10,728 ) Production (3,623 ) (557 ) (4,893 ) (4,996 ) December 31, 2016 24,347 4,811 33,577 34,754 Proved developed reserves: December 31, 2014 29,059 4,668 51,072 42,239 December 31, 2015 25,349 4,266 39,987 36,280 December 31, 2016 14,540 3,335 24,620 21,978
Standardized measure of discounted future net cash flows relating to estimated proved reserves	The standardized measure of discounted future net cash flows relating to estimated proved reserves as of 2016 , 2015 and 2014 was as follows: 2016 2015 2014 (In thousands) Future cash inflows $ 1,035,786 $ 1,721,207 $ 5,479,211 Future costs: Production (424,092 ) (711,887 ) (1,719,989 ) Abandonment (65,852 ) (120,737 ) (149,112 ) Development (148,108 ) (147,189 ) (695,180 ) Income taxes (12,204 ) (38,306 ) (833,601 ) Future net cash flows 385,530 703,088 2,081,329 10% discount factor (226,567 ) (312,445 ) (1,148,416 ) Standardized measure of discounted net cash flows $ 158,963 $ 390,643 $ 932,913
Schedule of changes in the standardized measure of discounted future net cash flows relating to estimated proved reserves	Changes in the standardized measure of discounted future net cash flows relating to estimated proved reserves for the years ended 2016 , 2015 and 2014 were as follows: 2016 2015 2014 (In thousands) Standardized measure, beginning of period $ 390,643 $ 932,913 $ 926,923 Net changes in sales prices, net of production costs (71,603 ) (965,126 ) (94,104 ) Revisions of quantity estimates 329 (245,035 ) (234,612 ) Accretion of discount 44,278 137,998 138,095 Changes in future development costs, including development costs incurred that reduced future development costs 10,145 308,261 146,392 Changes in timing and other (29,458 ) (69,160 ) (70,774 ) Net change in income taxes 9,068 395,888 2,893 Future abandonment cost, net of salvage (2,357 ) (2,968 ) 4,066 Extensions and discoveries 39,678 48,367 431,895 Sales, net of production costs (84,384 ) (126,455 ) (309,758 ) Sales of minerals-in-place (147,376 ) (24,040 ) (8,103 ) Standardized measure, end of period $ 158,963 $ 390,643 $ 932,913
Schedule of average prices used for each commodity	The average prices used for each commodity for the years ended 2016 , 2015 and 2014 were as follows: Average Price Oil Natural Gas Liquids Natural Gas ($/Bbl) ($/Bbl) ($/Mcf) As of December 31: 2016 $ 36.60 $ 13.60 $ 2.36 2015 $ 45.75 $ 15.84 $ 2.52 2014 $ 90.48 $ 31.54 $ 4.27

Nature of Operations (Details)

Nature of Operations (Details)	Dec. 31, 2016
Related Party Transaction [Line Items]
Percentage of outstanding common stock owned by a partnership in which Mr. Williams' adult children are limited partners	17.30%
Ares Management LLC
Related Party Transaction [Line Items]
Percentage of outstanding common stock beneficially owned	42.00%
Mr. Williams
Related Party Transaction [Line Items]
Percentage of outstanding common stock beneficially owned	17.60%

Summary of Significant Accoun46

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Concentration Risk [Line Items]
Capitalized interest costs	$ 0.1	$ 0.3	$ 1
Maximum | Assets, Total | Partnership Concentration Risk
Concentration Risk [Line Items]
The percentage of consolidated total assets and total revenues derived from oil and gas partnerships is less than	5.00%

Summary of Significant Accoun47

Summary of Significant Accounting Policies - Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2016
Pipelines and other midstream facilities | Minimum
Property, Plant and Equipment [Line Items]
Useful life	3 years
Pipelines and other midstream facilities | Maximum
Property, Plant and Equipment [Line Items]
Useful life	30 years
Building and Building Improvements | Minimum
Property, Plant and Equipment [Line Items]
Useful life	3 years
Building and Building Improvements | Maximum
Property, Plant and Equipment [Line Items]
Useful life	40 years

Summary of Significant Accoun48

Summary of Significant Accounting Policies - Recent Accounting Pronouncements (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2015
Other Noncurrent Assets [Member] | Accounting Standards Update 2015-03
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Debt issuance costs		$ (7.3)
Long-term Debt | Accounting Standards Update 2015-03
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Debt issuance costs		$ 7.3
Scenario, Forecast | Accounting Standards Update 2016-09
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification of excess tax benefits	$ (7.5)
Scenario, Forecast | Additional Paid-in Capital | Accounting Standards Update 2016-09
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative effect of new accounting adjustment	$ 7.5

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Mar. 08, 2016	Dec. 31, 2015	Apr. 30, 2011
Debt Instrument [Line Items]
Long-term debt	$ 847,995		$ 742,410
7.75% Senior Notes due 2019
Debt Instrument [Line Items]
Long-term debt, gross	500,000		600,000
Unamortized original issue discount	(144)		(241)	$ (500)
Debt issuance costs	(4,405)		(7,349)
Long-term debt	$ 495,451		$ 592,410
Interest rate percentage	7.75%		7.75%
Term Loan Credit Facility
Debt Instrument [Line Items]
Long-term debt, gross	$ 377,196		$ 0
Unamortized original issue discount	(14,961)	$ (16,800)	0
Debt issuance costs	(9,691)		0
Long-term debt	352,544		0
Revolving credit facility, due April 2019
Debt Instrument [Line Items]
Long-term debt	$ 0		$ 150,000

Long-Term Debt Credit Facility

Long-Term Debt Credit Facility (Details) - Revolving credit facility, due April 2019	Mar. 08, 2016USD ($)installment	Dec. 31, 2016USD ($)Bank	Mar. 09, 2016USD ($)
Debt Instrument [Line Items]
Number of banks syndicated to provide for line of credit | Bank		16
Aggregate commitment amount	$ 450,000,000		$ 100,000,000
Unused capacity, commitment fee percentage	0.50%
Remaining borrowing capacity		$ 98,100,000
Letters of credit outstanding, amount		$ 1,900,000
Effective interest rate		2.50%
Federal funds rate
Debt Instrument [Line Items]
Basis spread on variable rate	0.50%
One-month LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate	1.00%
Base rate
Debt Instrument [Line Items]
Interest rate, stated percentage	0.75%
Minimum
Debt Instrument [Line Items]
Minimum ratio of discounted present value to debt	1.2
Basis spread on variable rate, additional spread	1.50%
Covenant current ratio	1
Percentage of adjusted engineered value of oil and gas interests serving as collateral	90.00%
Minimum | LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate	2.50%
Maximum
Debt Instrument [Line Items]
Higher borrowing capacity option	$ 150,000,000
Basis spread on variable rate, additional spread	2.50%
Covenant consolidated funded indebtedness to EBI TDA ratio	2
Deficiency prepayment, number of equal periodic installments | installment	5
Maximum | LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate	3.50%

Long-Term Debt Term Loan Credit

Long-Term Debt Term Loan Credit Facility (Details) $ / shares in Units, $ in Thousands	Mar. 08, 2016USD ($)$ / sharesshares	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Jul. 22, 2016USD ($)$ / sharesshares
Debt Instrument [Line Items]
Fair value of common stock warrants		$ 246,743	$ 0
Loss on change in fair value of common stock warrants		229,980	0	$ 0
Term Loan Credit Facility
Debt Instrument [Line Items]
Principal amount of term loan	$ 350,000
Unamortized original issue discount	16,800	14,961	$ 0
Proceeds from line of credit	340,000
Fair value of common stock warrants	$ 16,800	$ 246,700
Interest rate, stated percentage	12.50%
Interest rate, stated percentage, in-kind	15.00%
Common stock, shares subscribed but unissued (in shares) | shares					5,051,100
Cash proceeds of common stock					$ 150,000
Common stock price per share (in dollars per share) | $ / shares					$ 29.70
Revolving Credit Facility
Debt Instrument [Line Items]
Outstanding balance repaid, plus interest and fees	$ 160,000
Minimum | Term Loan Credit Facility
Debt Instrument [Line Items]
Percentage of adjusted engineered value of oil and gas interests serving as collateral	90.00%
Asset to secured debt coverage ratio	1.2
Minimum | Revolving Credit Facility
Debt Instrument [Line Items]
Percentage of adjusted engineered value of oil and gas interests serving as collateral	90.00%
Common Stock
Debt Instrument [Line Items]
Warrants issued (in shares) | shares	2,251,364
Exercise price of warrant (in dollars per share) | $ / shares	$ 22

Long-Term Debt Senior Notes (De

Long-Term Debt Senior Notes (Details)	1 Months Ended	12 Months Ended
	Mar. 31, 2011USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Aug. 31, 2016USD ($)	Oct. 31, 2013USD ($)	Apr. 30, 2011USD ($)
Debt Instrument [Line Items]
Loss on early extinguishment of long-term debt		$ 3,967,000	$ 0	$ 0
7.75% Senior Notes due 2019
Debt Instrument [Line Items]
Debt instrument, face amount	$ 300,000,000					$ 250,000,000	$ 50,000,000
Interest rate percentage		7.75%	7.75%
Debt instrument, repurchased face amount					$ 100,000,000
Original issue discount (as a percent)							1.00%
Unamortized original issue discount		$ 144,000	$ 241,000				$ 500,000
Discount on debt extinguishment		5,000,000
Write off of deferred debt issuance cost		$ 1,000,000
Minimum ratio of EBITDAX to consolidated interest expense	2.25
Current borrowing capacity	$ 500,000,000
Percent of net assets	0.3
7.75% Senior Notes due 2019 | Redemption Period Beginning April 2017
Debt Instrument [Line Items]
Redemption price of debt instrument (as a percent)		100.00%

Sales of Assets (Details)

Sales of Assets (Details) $ in Thousands

1 Months Ended

6 Months Ended

12 Months Ended

Dec. 31, 2016USD ($)

Sep. 30, 2016USD ($)

Jul. 31, 2016USD ($)

Jun. 30, 2016USD ($)

Apr. 30, 2016USD ($)

Feb. 29, 2016USD ($)

Dec. 31, 2015USD ($)

Sep. 30, 2015USD ($)

Jun. 30, 2015USD ($)

Sep. 30, 2014USD ($)a

Mar. 31, 2014USD ($)

Feb. 28, 2014USD ($)

Jun. 30, 2015USD ($)

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Sale Of Assets [Line Items]

Net proceeds from sale of interest in wells and related leasehold interest

$ 29,300

$ 71,000

Sale of oil and gas, term assignment

3 years

Threshold percent of net revenue

75.00%

75.00%

Proceeds from sale of assets

$ 423,905

$ 71,460

$ 104,529

Gas and oil area sold | a

7,500

Escrow deposits related to property sales

$ 6,800

Proceeds from sale of property

$ 5,100

OKLAHOMA

Sale Of Assets [Line Items]

Net proceeds from sale of interest in wells and related leasehold interest

$ 1,500

Giddings Area, TX

Sale Of Assets [Line Items]

Net proceeds from sale of interest in wells and related leasehold interest

$ 400,000

Glasscock County, TX

Sale Of Assets [Line Items]

Net proceeds from sale of interest in wells and related leasehold interest

$ 19,400

Burleson County, TX

Sale Of Assets [Line Items]

Net proceeds from sale of interest in wells and related leasehold interest

$ 1,400

$ 2,000

$ 800

$ 21,800

$ 22,100

South Louisiana

Sale Of Assets [Line Items]

Proceeds from sale of assets

$ 11,800

Wells and Related Equipment and Facilities

Sale Of Assets [Line Items]

Net proceeds from sale of interest in wells and related leasehold interest

$ 7,300

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Changes in asset retirement obligations
Beginning of period	$ 48,728	$ 45,697
Additional ARO from new properties	61	469
Sales or abandonments of properties	(17,206)	(4,435)
Accretion of asset retirement obligations	4,364	3,945	$ 3,662
Revisions of previous estimates	11,276	3,052
End of period	$ 47,223	$ 48,728	$ 45,697

Deferred Revenue from Volumet55

Deferred Revenue from Volumetric Production Payment (Details) $ in Thousands	1 Months Ended		12 Months Ended
	Aug. 31, 2015USD ($)MBoe	Mar. 31, 2012USD ($)MBoepartnership	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Changes in deferred revenue from the VPP
Beginning of year			$ 5,470	$ 23,129
Deferred revenue from VPP			0	2,866
Amortization of deferred revenue from VPP			(1,479)	(6,822)	$ (7,708)
Termination of VPP			0	(13,703)	0
End of year			$ 3,991	$ 5,470	$ 23,129
Number of limited partnerships involved in the mergers | partnership		24
Southwest Royalties, Inc. | Limited partnerships
Changes in deferred revenue from the VPP
Termination of VPP	$ (13,700)
Upfront cash proceeds under VPP		$ 44,400
Deferred future advances under VPP		$ 4,700
Barrels of oil equivalents of future oil and gas production covered by a term overriding royalty interest conveyed to a third party under the terms of the VPP (in BOE) | MBoe		725
Volumetric production payment terminated during period (in MBOE) | MBoe	277

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Deferred tax assets:
Net operating loss carryforwards	$ 76,213	$ 106,992
Statutory depletion carryforwards	9,913	9,809
Asset retirement obligations and other	22,518	21,249
Deferred tax assets, gross	108,644	138,050
Deferred tax liabilities:
Property and equipment	(178,714)	(240,520)
Net deferred tax liabilities	(70,070)	(102,470)
Components of net deferred tax liabilities:
Current assets	6,520	6,526
Non-current liabilities	(76,590)	(108,996)
Net deferred tax liabilities	$ (70,070)	$ (102,470)

Income Taxes Income Taxes (Deta

Income Taxes Income Taxes (Details 2) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Expense (Benefit), Continuing Operations, Income Tax Reconciliation [Abstract]
Income tax expense (benefit) at statutory rate of 35%	$ (112,867)	$ (53,667)	$ 23,999
Tax depletion in excess of basis	(164)	(282)	(729)
Revision of previous tax estimates	63	30	(155)
State income tax expense (benefit), net of federal tax effect	857	(1,472)	1,008
Permanent and other(a)	81,784	252	564
Income tax expense (benefit)	(30,327)	(55,139)	24,687
Current	2,073	79	227
Deferred	(32,400)	(55,218)	24,460
Income tax expense (benefit)	$ (30,327)	$ (55,139)	$ 24,687
Statutory tax rate	35.00%	35.00%	35.00%

Income Taxes Income Taxes (De58

Income Taxes Income Taxes (Details - Textuals) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Operating Loss Carryforwards [Line Items]
Permanent difference related to change in fair value of common stock warrants	$ 80,500,000
Tax carryforward amount	239,300,000
Income tax, uncertain tax positions	0	$ 0
Stock Option Exercise Tax Benefit
Operating Loss Carryforwards [Line Items]
Tax carryforward amount	$ 22,000,000

Derivatives (Commodities) (Deta

Derivatives (Commodities) (Details) - Oil MBbls in Thousands	Dec. 31, 2016MBbls$ / bbl
Derivative [Line Items]
MBbls | MBbls	407
Current Swap, First Quarter
Derivative [Line Items]
MBbls | MBbls	178
Swap, fixed price (in dollars per unit)	44.85
Current Swap, Second Quarter
Derivative [Line Items]
MBbls | MBbls	165
Swap, fixed price (in dollars per unit)	44.65
Current Swap, Third Quarter
Derivative [Line Items]
MBbls | MBbls	37
Swap, fixed price (in dollars per unit)	50
Current Swap, Fourth Quarter
Derivative [Line Items]
MBbls | MBbls	27
Swap, fixed price (in dollars per unit)	50
1st Quarter 2017
Derivative [Line Items]
MBbls | MBbls	355
Weighted average floor price (in dollars per unit)	42.26
Weighted average ceiling price (in dollars per unit)	51.67
2nd Quarter 2017
Derivative [Line Items]
MBbls | MBbls	354
Weighted average floor price (in dollars per unit)	42.27
Weighted average ceiling price (in dollars per unit)	51.67
3rd Quarter 2017
Derivative [Line Items]
MBbls | MBbls	356
Weighted average floor price (in dollars per unit)	42.27
Weighted average ceiling price (in dollars per unit)	51.65
4th Quarter 2017
Derivative [Line Items]
MBbls | MBbls	350
Weighted average floor price (in dollars per unit)	42.27
Weighted average ceiling price (in dollars per unit)	51.66
Crude Oil Costless Collar
Derivative [Line Items]
MBbls | MBbls	1,415

Derivatives Commodity Derivativ

Derivatives Commodity Derivatives Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Effect of Derivative Instruments on the Consolidated Balance Sheet [Line Items]
Asset derivatives, fair value	$ 0	$ 0
Fair value of derivative liabilities, current	12,895	0
Fair value of commodity derivatives	0
Liability derivatives, fair value	12,895	0
Assets
Fair value of commodity derivatives — gross presentation	0	0
Effects of netting arrangements	0	0
Asset derivatives, fair value	0	0
Liabilities
Fair value of commodity derivatives — gross presentation	12,895	0
Effects of netting arrangements	0	0
Liability derivatives, fair value	12,895	0
Not Designated as Hedging Instrument | Commodity Contract
Effect of Derivative Instruments on the Consolidated Balance Sheet [Line Items]
Fair value of derivative assets, current	0	0
Fair value of derivative assets, noncurrent	0	0
Asset derivatives, fair value	0	0
Fair value of derivative liabilities, current	12,895	0
Fair value of commodity derivatives	0	0
Liability derivatives, fair value	12,895	0
Assets
Asset derivatives, fair value	0	0
Liabilities
Liability derivatives, fair value	$ 12,895	$ 0

Derivatives (Details 2)

Derivatives (Details 2) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Amount of Gain or (Loss) Recognized in Earnings
Gain (loss) on commodity derivatives	$ (20,289)	$ 12,519	$ 4,789
Nondesignated | Commodity Contract
Amount of Gain or (Loss) Recognized in Earnings
Gain (loss) on commodity derivatives	$ (20,289)	$ 12,519	$ 4,789

Fair Value of Financial Instr62

Fair Value of Financial Instruments Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Assets:
Fair value of commodity derivatives	$ 0	$ 0
Liabilities:
Fair value of commodity derivatives	12,895	0
Fair value of common stock warrants	246,743	0
Recurring | Fair Value, Inputs, Level 2
Assets:
Fair value of commodity derivatives	0	0
Total assets	0	0
Liabilities:
Fair value of commodity derivatives	12,895	0
Fair value of common stock warrants	246,743
Total liabilities	$ 259,638	$ 0

Fair Value of Other Financial I

Fair Value of Other Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
7.75% Senior Notes due 2019
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Interest rate percentage	7.75%	7.75%
Reported Value Measurement | Fair Value, Inputs, Level 1 | 7.75% Senior Notes due 2019
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Long-term debt, fair value	$ 495,451	$ 592,410
Reported Value Measurement | Fair Value, Inputs, Level 3 | Term Loan Credit Facility
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Long-term debt, fair value	352,544	0
Estimate of Fair Value Measurement | Fair Value, Inputs, Level 1 | 7.75% Senior Notes due 2019
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Long-term debt, fair value	505,650	462,750
Estimate of Fair Value Measurement | Fair Value, Inputs, Level 3 | Term Loan Credit Facility
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Long-term debt, fair value	$ 378,996	$ 0

Stockholders' Equity and Earn64

Stockholders' Equity and Earnings (Loss) Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	12 Months Ended
	Aug. 31, 2016	Dec. 31, 2016
Equity [Abstract]
Sale of common stock (in shares)	5,051,100
Sale of common stock	$ 150,000	$ 147,340
Sale of stock, price per share (in dollars per share)	$ 29.70
Offering expenses	$ 2,700
Shares excluded from computation of diluted earnings per share (in shares)		282,000

Compensation Plans - Long Term

Compensation Plans - Long Term Incentive Plans (Details)	Jun. 30, 2016shares
Long Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares reserved for issuance under the LTIP (in shares)	1,400,000

Compensation Plans - Stock Opti

Compensation Plans - Stock Options Activity (Details)	12 Months Ended
	Dec. 31, 2016USD ($)$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Grant-date fair value (in dollars per share)	$ 45.88
Expected volatility	76.30%
Expected term (in years)	5 years
Risk-free rate	1.20%
Stock Option Activity
Number of options outstanding at January 1, 2016 (in shares) | shares	0
Number of options granted (in shares) | shares	282,000
Number of options exercised (in shares) | shares	0
Number of options outstanding at December 31, 2016 (in shares) | shares	282,000
Stock Options Weighted Average Exercise Price
Options outstanding, weighted average exercise price at January 1, 2016 (in dollars per share)	$ 0
Options granted, weighted average exercise price (in dollars per share)	74.21
Options exercised, weighted average exercise price (in dollars per share)	0
Options outstanding, weighted average exercise price at December 31, 2016 (in dollars per share)	$ 74.21
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Options vested and expected to vest at December 31, 2016 (in shares) | shares	282,000
Options vested and expected to vest at December 31, 2016, weighted average exercise price (in dollars per share)	$ 74.21
Options vested and expected to vest at December 31, 2016, remaining term	6 years 8 months
Options vested and expected to vest at December 31, 2016, aggregate intrinsic value | $	$ 12,705,250
Options exercisable at December 31, 2016 (in shares) | shares	0
Options exercisable at December 31, 2016, weighted average exercise price (in dollars per share)	$ 0
Options exercisable at December 31, 2016, weighted average remaining term	0 years
Options exercisable at December 31, 2016, aggregate intrinsic value | $	$ 0
Employee Stock Option
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Unrecognized compensation cost for options granted | $	$ 11,800,000
Unrecognized compensation cost, period for recognition	2 years 8 months

Compensation Plans - Restricted

Compensation Plans - Restricted Stock Activity (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Employee Stock Option
Weighted Average Grant Date Fair Value
Unrecognized compensation cost, period for recognition	2 years 8 months
Stock-based compensation expense	$ 5,700,000	$ 0	$ 0
Restricted Stock Units (RSUs)
Nonvested Restricted Stock Unit Activity
Shares unvested at January 1, 2016 (in shares)	0
Granted (in shares)	410,165
Vested (in shares)	(25,000)
Forfeited (in shares)	0
Shares unvested at December 31, 2016 (in shares)	385,165	0
Weighted Average Grant Date Fair Value
Shares unvested at January 1, 2016, weighted average grant date fair value (in dollars per share)	$ 0
Granted, weighted average grant date fair value (in dollars per share)	71.26
Vested, weighted average grant date fair value (in dollars per share)	63.11
Forfeited, weighted average grant date fair value (in dollars per share)	0
Shares unvested at December 31, 2016, weighted average grant date fair value (in dollars per share)	$ 71.79	$ 0
Aggregate fair value of awards	$ 29,200,000
Unrecognized compensation cost	$ 24,600,000
Unrecognized compensation cost, period for recognition	2 years 7 months
Stock-based compensation expense	$ 5,700,000	$ 0	$ 0

Compensation Plans - Non-Equity

Compensation Plans - Non-Equity Award Plans (Details) $ in Thousands	1 Months Ended	3 Months Ended	12 Months Ended
	Jan. 31, 2007well	Dec. 31, 2016USD ($)area	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense recorded			$ (7,900)	$ (30)	$ 4,600
Current liabilities:
Accrued liabilities and other		$ 1,087	1,087	1,251
Non-current liabilities:
Accrued compensation under non-equity award plans		4,655	4,655	16,254
Total accrued compensation under non-equity award plans		$ 5,742	$ 5,742	$ 17,505
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period			2 years
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period			5 years
APO Incentive Plan | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Subsequent revenues received by participants (as a percent)			99.00%
Subsequent expenses paid by participants (as a percent)			99.00%
Economic interests in specified wells drilled or acquired as part of the plan (as a percent)			5.00%
APO Incentive Plan | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Subsequent revenues received by participants (as a percent)			100.00%
Subsequent expenses paid by participants (as a percent)			100.00%
Economic interests in specified wells drilled or acquired as part of the plan (as a percent)			7.50%
APO Reward Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of specified areas in which awards granted | area		8
Quarterly bonus amount, percentage of after-payout cash flow from wells drilled or recompleted, one		7.00%
Quarterly bonus amount, percentage of after-payout cash flow from wells drilled or recompleted, two		10.00%
SWR Reward Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of working interest in well	22.50%
Number of wells, working interest | well	1
SWR Reward Plan | Full Vesting Date 25 October 2011 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of subsequent quarterly bonus amounts payable	100.00%

Transactions with Affiliates (D

Transactions with Affiliates (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Amounts paid to the Williams Entities:
Percentage of ownership of affiliates of the company in the partnership	33.50%
Percentage of owner of company in affiliated partnership	25.80%
Affiliated Entity
Amounts received from the Williams Entities:
Services	$ 603	$ 622	$ 663
Insurance premiums and benefits	989	922	960
Reimbursed expenses	252	500	296
Amount received from Williams Entities	1,844	2,044	1,919
Amounts paid to the Williams Entities:
Rent	1,697	1,741	1,614
Business entertainment	155	155	205
Reimbursed expenses	135	226	204
Amounts paid to the Williams Entities	$ 1,987	$ 2,122	$ 2,023

Other Operating Revenues and 70

Other Operating Revenues and Expenses (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other operating revenues:
Gain on sales of assets	$ 123,392	$ 8,718	$ 11,685
Marketing revenue	0	24	3,708
Total other operating revenues	123,392	8,742	15,393
Other operating expenses:
Loss on sales of assets	3,152	1,355	2,511
Marketing expense	440	849	0
Impairment of inventory	1,454	10,381	36
Other operating expenses	$ 5,046	$ 12,585	$ 2,547

Investment in Dalea Investmen71

Investment in Dalea Investment Group, LLC (Details) - Dalea Investment Group, LLC - USD ($)	1 Months Ended	12 Months Ended
	Jun. 30, 2012	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Investment in Dalea Investment Group, LLC
Note receivable cancelled	$ 11,000,000
Non-controlling membership interest (as a percent)	7.66%
Recorded investment	$ 11,000,000		$ 8,400,000
Cost-method Investments, Other than Temporary Impairment		$ 8,400,000	$ 2,600,000	$ 0

Commitments and Contingencies72

Commitments and Contingencies (Details) $ in Thousands	1 Months Ended			12 Months Ended
	Dec. 31, 2013USD ($)	Oct. 31, 2013USD ($)	Jul. 31, 2013defendantlawsuit	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Nov. 30, 2013lawsuit
Operating Leased Assets [Line Items]
Rental expense				$ 1,900	$ 1,900	$ 1,800
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,017				241
2,018				85
2,019				45
Thereafter				0
Total minimum lease payments				371
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,017				887
2,018				614
2,019				613
Thereafter				102
Total minimum lease payments				2,216
Non-Cancelable Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,017				1,128
2,018				699
2,019				658
Thereafter				102
Total minimum lease payments				$ 2,587
LOUISIANA
Non-Cancelable Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Number of pending claims | lawsuit			3
BMT O&G TX, L.P.
Non-Cancelable Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Loss contingency, settlement amount		$ 2,900
Attorney fees		$ 800
Loss related to litigation settlement	$ 1,400
South Louisiana Flood Protection Authority-East [Member]
Non-Cancelable Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Number of pending claims | lawsuit			1
Number of defendants | defendant			95
Plaquemines Parish [Member]
Non-Cancelable Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Number of pending claims | lawsuit							2

Impairment of Property and Eq73

Impairment of Property and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of property and equipment	$ 7,593	$ 41,917	$ 12,027
Provisions for impairment of unproved properties	2,300	2,800	15,400
Non Core Properties
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of property and equipment	5,200	37,900	$ 12,000
Drilling Rigs
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of property and equipment	$ 2,400	$ 4,000

Costs of Oil and Gas Properti74

Costs of Oil and Gas Properties (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Oil and Gas Property, Successful Effort Method, Gross [Abstract]
Property acquisitions, Proved	$ 0	$ 0	$ 0
Property acquisitions, Unproved	32,840	29,711	56,327
Developmental costs	49,614	81,466	342,716
Exploratory costs	20,095	14,342	4,350
Total	$ 102,549	$ 125,519	$ 403,393

Costs of Oil and Gas Properti75

Costs of Oil and Gas Properties (Details 2) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Oil and Gas Property, Successful Effort Method, Gross [Abstract]
Proved properties	$ 1,643,038	$ 2,539,480
Unproved properties	74,171	46,022
Total capitalized costs	1,717,209	2,585,502
Accumulated depletion	(928,927)	(1,460,404)
Net capitalized costs	$ 788,282	$ 1,125,098

Segment Information (Details)

Segment Information (Details) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2016USD ($)segment	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Segment Reporting [Abstract]
Number of reportable operating segments | segment									2
Segment Information
Revenues	$ 161,464	$ 55,438	$ 42,195	$ 30,314	$ 40,418	$ 54,581	$ 73,231	$ 64,142	$ 289,411	$ 232,372	$ 468,456
Depreciation, depletion and amortization									153,207	204,179	166,383
Other operating expenses									113,890	141,628	190,434
Interest expense									93,693	54,422	50,907
Other (income) expense									251,099	(14,522)	(7,836)
Income (loss) before income taxes									(322,478)	(153,335)	68,568
Income tax (expense) benefit									30,327	55,139	(24,687)
Net income (loss)	(27,177)	$ (148,776)	$ (80,937)	$ (35,261)	(47,209)	$ (9,423)	$ (23,332)	$ (18,232)	(292,151)	(98,196)	43,881
Total assets	1,494,639				1,287,420				1,494,639	1,287,420	1,501,633
Additions to property and equipment									112,487	126,747	435,444
Operating Segments | Oil and Gas
Segment Information
Revenues									289,246	232,279	440,428
Depreciation, depletion and amortization									138,875	187,913	157,164
Other operating expenses									110,119	135,177	170,878
Interest expense									93,693	54,422	50,907
Other (income) expense									241,557	(17,091)	(8,001)
Income (loss) before income taxes									(294,998)	(128,142)	69,480
Income tax (expense) benefit									20,709	46,129	(23,384)
Net income (loss)									(274,289)	(82,013)	46,096
Total assets	1,524,220				1,283,649				1,524,220	1,283,649	1,473,611
Additions to property and equipment									112,429	124,996	412,951
Operating Segments | Contract Drilling
Segment Information
Revenues									165	2,837	59,107
Depreciation, depletion and amortization									14,332	16,832	13,307
Other operating expenses									3,771	9,178	41,912
Interest expense									0	0	0
Other (income) expense									9,542	2,569	165
Income (loss) before income taxes									(27,480)	(25,742)	3,723
Income tax (expense) benefit									9,618	9,010	(1,303)
Net income (loss)									(17,862)	(16,732)	2,420
Total assets	19,180				48,943				19,180	48,943	70,051
Additions to property and equipment									58	1,202	27,128
Intercompany Eliminations
Segment Information
Revenues									0	(2,744)	(31,079)
Depreciation, depletion and amortization									0	(566)	(4,088)
Other operating expenses									0	(2,727)	(22,356)
Interest expense									0	0	0
Other (income) expense									0	0	0
Income (loss) before income taxes									0	549	(4,635)
Income tax (expense) benefit									0	0	0
Net income (loss)									0	549	(4,635)
Total assets	$ (48,761)				$ (45,172)				(48,761)	(45,172)	(42,029)
Additions to property and equipment									$ 0	$ 549	$ (4,635)

Guarantor Financial Informati77

Guarantor Financial Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Aug. 31, 2016	Oct. 31, 2013	Apr. 30, 2011	Mar. 31, 2011
Performance and payment guaranteed
Gain on early extinguishment of long-term debt	$ 3,967,000	$ 0	$ 0
2019 Senior Notes
Performance and payment guaranteed
Aggregate principal amount of notes issued					$ 250,000,000	$ 50,000,000	$ 300,000,000
Debt instrument, repurchased face amount				$ 100,000,000
Discount on debt extinguishment	5,000,000
Write off of deferred debt issuance cost	$ 1,000,000
Guarantor Subsidiaries | Guarantee on senior notes | 2019 Senior Notes
Performance and payment guaranteed
Aggregate principal amount of notes issued					$ 250,000,000	$ 350,000,000

Guarantor Financial Informati78

Guarantor Financial Information (Details 2) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed consolidating financial statements
Current assets	$ 631,186	$ 68,805
Property and equipment, net	856,136	1,201,284
Investments in subsidiaries	0	0
Other assets	7,317	17,331
Total assets	1,494,639	1,287,420	$ 1,501,633
Current liabilities	106,766	65,739
Non-current liabilities:
Long-term debt	847,995	742,410
Fair value of commodity derivatives	0
Fair value of common stock warrants	246,743	0
Deferred income taxes	76,590	108,996
Other	56,014	70,677
TOTAL NON-CURRENT LIABILITIES	1,227,342	922,083
Equity	160,531	299,598	$ 397,794	$ 353,783
Total liabilities and equity	1,494,639	1,287,420
Issuer
Condensed consolidating financial statements
Current assets	678,174	112,861
Property and equipment, net	585,803	892,791
Investments in subsidiaries	289,424	324,484
Other assets	5,197	6,681
Total assets	1,558,598	1,336,817
Current liabilities	284,955	276,354
Non-current liabilities:
Long-term debt	847,995	742,410
Fair value of commodity derivatives	12,895
Fair value of common stock warrants	246,743
Deferred income taxes	99,879	90,387
Other	11,418	33,886
TOTAL NON-CURRENT LIABILITIES	1,218,930	866,683
Equity	54,713	193,780
Total liabilities and equity	1,558,598	1,336,817
Guarantor Subsidiaries
Condensed consolidating financial statements
Current assets	244,756	272,310
Property and equipment, net	267,128	304,936
Investments in subsidiaries	0	0
Other assets	2,120	10,650
Total assets	514,004	587,896
Current liabilities	101,349	102,267
Non-current liabilities:
Long-term debt	0	0
Fair value of commodity derivatives	0
Fair value of common stock warrants	0
Deferred income taxes	85,113	130,471
Other	44,290	36,539
TOTAL NON-CURRENT LIABILITIES	129,403	167,010
Equity	283,252	318,619
Total liabilities and equity	514,004	587,896
Non-Guarantor Subsidiary
Condensed consolidating financial statements
Current assets	1,314	1,441
Property and equipment, net	3,205	3,557
Investments in subsidiaries	0	0
Other assets	0	0
Total assets	4,519	4,998
Current liabilities	111	117
Non-current liabilities:
Long-term debt	0	0
Fair value of commodity derivatives	0
Fair value of common stock warrants	0
Deferred income taxes	(2,070)	(1,236)
Other	306	252
TOTAL NON-CURRENT LIABILITIES	(1,764)	(984)
Equity	6,172	5,865
Total liabilities and equity	4,519	4,998
Adjustments/ Eliminations
Condensed consolidating financial statements
Current assets	(293,058)	(317,807)
Property and equipment, net	0	0
Investments in subsidiaries	(289,424)	(324,484)
Other assets	0	0
Total assets	(582,482)	(642,291)
Current liabilities	(279,649)	(312,999)
Non-current liabilities:
Long-term debt	0	0
Fair value of commodity derivatives	(12,895)
Fair value of common stock warrants	0
Deferred income taxes	(106,332)	(110,626)
Other	0	0
TOTAL NON-CURRENT LIABILITIES	(119,227)	(110,626)
Equity	(183,606)	(218,666)
Total liabilities and equity	$ (582,482)	$ (642,291)

Guarantor Financial Informati79

Guarantor Financial Information (Details 3) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Condensed consolidating financial statements
Total revenue	$ 161,464	$ 55,438	$ 42,195	$ 30,314	$ 40,418	$ 54,581	$ 73,231	$ 64,142	$ 289,411	$ 232,372	$ 468,456
Costs and expenses									267,097	345,807	356,817
Operating income	105,469	(13,013)	(33,565)	(36,577)	(62,456)	(19,739)	(11,058)	(20,182)	22,314	(113,435)	111,639
Other income (expense)									(344,792)	(39,900)	(43,071)
Equity in earnings of subsidiaries									0	0	0
Income tax (expense) benefit									30,327	55,139	(24,687)
NET INCOME (LOSS)	$ (27,177)	$ (148,776)	$ (80,937)	$ (35,261)	$ (47,209)	$ (9,423)	$ (23,332)	$ (18,232)	(292,151)	(98,196)	43,881
Issuer
Condensed consolidating financial statements
Total revenue									235,841	169,705	324,055
Costs and expenses									172,727	244,187	242,658
Operating income									63,114	(74,482)	81,397
Other income (expense)									(337,807)	(41,187)	(45,538)
Equity in earnings of subsidiaries									(31,060)	(24,483)	21,261
Income tax (expense) benefit									13,602	41,956	(13,239)
NET INCOME (LOSS)									(292,151)	(98,196)	43,881
Guarantor Subsidiaries
Condensed consolidating financial statements
Total revenue									52,609	61,224	140,857
Costs and expenses									93,114	87,008	111,750
Operating income									(40,505)	(25,784)	29,107
Other income (expense)									(7,753)	(808)	919
Equity in earnings of subsidiaries									0	0	0
Income tax (expense) benefit									16,890	9,307	(10,509)
NET INCOME (LOSS)									(31,368)	(17,285)	19,517
Non-Guarantor Subsidiary
Condensed consolidating financial statements
Total revenue									961	1,443	3,544
Costs and expenses									1,256	14,612	2,409
Operating income									(295)	(13,169)	1,135
Other income (expense)									768	2,095	1,548
Equity in earnings of subsidiaries									0	0	0
Income tax (expense) benefit									(165)	3,876	(939)
NET INCOME (LOSS)									308	(7,198)	1,744
Adjustments/Eliminations
Condensed consolidating financial statements
Total revenue									0	0	0
Costs and expenses									0	0	0
Operating income									0	0	0
Other income (expense)									0	0	0
Equity in earnings of subsidiaries									31,060	24,483	(21,261)
Income tax (expense) benefit									0	0	0
NET INCOME (LOSS)									$ 31,060	$ 24,483	$ (21,261)

Guarantor Financial Informati80

Guarantor Financial Information (Details 4) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Condensed consolidating financial statements
Operating activities	$ 10,727	$ 52,159	$ 258,121
Investing activities	313,227	(117,395)	(318,997)
Financing activities	241,291	45,000	62,269
Net increase (decrease) in cash and cash equivalents	565,245	(20,236)	1,393
Beginning of period	7,780	28,016	26,623
End of period	573,025	7,780	28,016
Issuer
Condensed consolidating financial statements
Operating activities	33,099	61,138	178,769
Investing activities	320,038	(113,543)	(274,629)
Financing activities	212,329	35,851	97,384
Net increase (decrease) in cash and cash equivalents	565,466	(16,554)	1,524
Beginning of period	4,663	21,217	19,693
End of period	570,129	4,663	21,217
Guarantor Subsidiaries
Condensed consolidating financial statements
Operating activities	(22,247)	836	69,543
Investing activities	(6,801)	(15,143)	(34,749)
Financing activities	28,961	9,469	(34,987)
Net increase (decrease) in cash and cash equivalents	(87)	(4,838)	(193)
Beginning of period	1,855	6,693	6,886
End of period	1,768	1,855	6,693
Non-Guarantor Subsidiary
Condensed consolidating financial statements
Operating activities	(125)	(10,381)	5,842
Investing activities	(10)	11,857	(5,652)
Financing activities	1	(320)	(128)
Net increase (decrease) in cash and cash equivalents	(134)	1,156	62
Beginning of period	1,262	106	44
End of period	1,128	1,262	106
Adjustments/Eliminations
Condensed consolidating financial statements
Operating activities	0	566	3,967
Investing activities	0	(566)	(3,967)
Financing activities	0	0	0
Net increase (decrease) in cash and cash equivalents	0	0	0
Beginning of period	0	0	0
End of period	$ 0	$ 0	$ 0

Subsequent Events (Details)

Subsequent Events (Details) $ / shares in Units, $ in Millions	Jan. 13, 2017$ / sharesshares	Jan. 31, 2017USD ($)a	Jun. 30, 2017USD ($)
Subsequent Event | Reeves County, TX
Subsequent Event [Line Items]
Net mineral acres purchased | a		1,900
Cash consideration paid | $		$ 44.3
Non-operated gross working interest		26.00%
Noble Energy | Scenario, Forecast
Subsequent Event [Line Items]
Termination fee | $			$ 87
Share Consideration | Noble Energy | Subsequent Event
Subsequent Event [Line Items]
Shares of stock, right to receive, per share (in shares) | shares	3.7222
Mixed Consideration | Noble Energy | Subsequent Event
Subsequent Event [Line Items]
Shares of stock, right to receive, per share (in shares) | shares	2.7874
Cash received, per share (in dollars per share) | $ / shares	$ 34.75
Cash Consideration | Noble Energy | Subsequent Event
Subsequent Event [Line Items]
Cash received, per share (in dollars per share) | $ / shares	$ 138.39

Supplemental Quarterly Financ82

Supplemental Quarterly Financial Information (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Total revenue	$ 161,464	$ 55,438	$ 42,195	$ 30,314	$ 40,418	$ 54,581	$ 73,231	$ 64,142	$ 289,411	$ 232,372	$ 468,456
Operating income	105,469	(13,013)	(33,565)	(36,577)	(62,456)	(19,739)	(11,058)	(20,182)	22,314	(113,435)	111,639
Net income (loss)	$ (27,177)	$ (148,776)	$ (80,937)	$ (35,261)	$ (47,209)	$ (9,423)	$ (23,332)	$ (18,232)	$ (292,151)	$ (98,196)	$ 43,881
Net income (loss) per common share:
Basic (in dollars per share)	$ (1.54)	$ (10.62)	$ (6.65)	$ (2.90)	$ (3.88)	$ (0.77)	$ (1.92)	$ (1.50)	$ (20.87)	$ (8.07)	$ 3.61
Diluted (in dollars per share)	$ (1.54)	$ (10.62)	$ (6.65)	$ (2.90)	$ (3.88)	$ (0.77)	$ (1.92)	$ (1.50)	$ (20.87)	$ (8.07)	$ 3.61
Weighted average common shares outstanding:
Basic (in shares)	17,608	14,013	12,170	12,170	12,170	12,170	12,170	12,170	14,000	12,170	12,167
Diluted (in shares)	17,608	14,013	12,170	12,170	12,170	12,170	12,170	12,170	14,000	12,170	12,167

Supplemental Oil and Gas Rese83

Supplemental Oil and Gas Reserve Information (Details) Mcf in Thousands, MBoe in Thousands, MBbls in Thousands	12 Months Ended
	Dec. 31, 2016MBoeMBblsMcf	Dec. 31, 2015MBoeMBblsMcf	Dec. 31, 2014MBoeMBblsMcf
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, net (MBOE) (at beginning) | MBoe	46,569	75,430	70,015
Extensions and discoveries (MBOE) | MBoe	4,077	3,542	23,336
Revisions (MBOE) | MBoe	(168)	(26,158)	(10,101)
Sales of minerals-in-place (MBOE) | MBoe	(10,728)	(472)	(2,057)
Production (MBOE) | MBoe	(4,996)	(5,773)	(5,763)
Proved developed and undeveloped reserves, net (MBOE) (at ending) | MBoe	34,754	46,569	75,430
Proved developed reserves (MBOE) | MBoe	21,978	36,280	42,239
Proved developed and undeveloped reserves, upward revisions of previous estimates attributable to well performance | MBoe	11,670
Proved developed and undeveloped reserves, downward revisions | MBoe	11,838
Oil
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, net (at beginning)	33,076	53,867	48,665
Extensions and discoveries	2,864	2,669	19,032
Revisions	553	(18,912)	(7,786)
Sales of minerals-in-place	(8,523)	(291)	(1,850)
Production	(3,623)	(4,257)	(4,194)
Proved developed and undeveloped reserves, net (at end)	24,347	33,076	53,867
Proved developed reserves (volume)	14,540	25,349	29,059
Natural Gas Liquids
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, net (at beginning)	5,468	8,967	8,487
Extensions and discoveries	604	407	2,298
Revisions	(48)	(3,344)	(1,160)
Sales of minerals-in-place	(656)	(12)	(73)
Production	(557)	(550)	(585)
Proved developed and undeveloped reserves, net (at end)	4,811	5,468	8,967
Proved developed reserves (volume)	3,335	4,266	4,668
Natural Gas
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, net (at beginning) | Mcf	48,147	75,575	77,179
Extensions and discoveries | Mcf	3,651	2,796	12,034
Revisions | Mcf	(4,036)	(23,414)	(6,934)
Sales of minerals-in-place | Mcf	(9,292)	(1,016)	(803)
Production | Mcf	(4,893)	(5,794)	(5,901)
Proved developed and undeveloped reserves, net (at end) | Mcf	33,577	48,147	75,575
Proved developed reserves (volume) | Mcf	24,620	39,987	51,072

Supplemental Oil and Gas Rese84

Supplemental Oil and Gas Reserve Information (Details 1) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Abstract]
Future cash inflows	$ 1,035,786	$ 1,721,207	$ 5,479,211
Future costs, production	(424,092)	(711,887)	(1,719,989)
Future costs, abandonment	(65,852)	(120,737)	(149,112)
Future costs, development	(148,108)	(147,189)	(695,180)
Future costs, income taxes	(12,204)	(38,306)	(833,601)
Future net cash flows	385,530	703,088	2,081,329
10% discount factor	(226,567)	(312,445)	(1,148,416)
Standardized measure of discounted net cash flows	$ 158,963	$ 390,643	$ 932,913	$ 926,923

Supplemental Oil and Gas Rese85

Supplemental Oil and Gas Reserve Information (Details 2) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure, beginning of period	$ 390,643	$ 932,913	$ 926,923
Net changes in sales prices, net of production costs	(71,603)	(965,126)	(94,104)
Revisions of quantity estimates	329	(245,035)	(234,612)
Accretion of discount	44,278	137,998	138,095
Changes in future development costs, including development costs incurred that reduced future development costs	10,145	308,261	146,392
Changes in timing and other	(29,458)	(69,160)	(70,774)
Net change in income taxes	9,068	395,888	2,893
Future abandonment cost, net of salvage	(2,357)	(2,968)	4,066
Extensions and discoveries	39,678	48,367	431,895
Sales, net of production costs	84,384	126,455	309,758
Sales of minerals-in-place	(147,376)	(24,040)	(8,103)
Standardized measure, end of period	$ 158,963	$ 390,643	$ 932,913

Supplemental Oil and Gas Rese86

Supplemental Oil and Gas Reserve Information (Details 3)	12 Months Ended
	Dec. 31, 2016$ / bbl$ / Mcf	Dec. 31, 2015$ / bbl$ / Mcf	Dec. 31, 2014$ / bbl$ / Mcf
Oil
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average sales price	36.60	45.75	90.48
Natural Gas Liquids
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average sales price	13.60	15.84	31.54
Natural Gas
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average sales price | $ / Mcf	2.36	2.52	4.27