Clayton Williams Energy (CWEI) 10-Q 7 Nov 16 2016 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Oct. 31, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	CLAYTON WILLIAMS ENERGY INC /DE
Entity Central Index Key	880,115
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding		17,493,486

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
CURRENT ASSETS
Cash and cash equivalents	$ 182,993	$ 7,780
Short-term investments	40,041	0
Accounts receivable:
Oil and gas sales	16,529	16,660
Joint interest and other, net of allowance for doubtful accounts of $2,694 at September 30, 2016 and $2,447 at December 31, 2015	4,764	3,661
Affiliates	187	260
Inventory	26,648	31,455
Deferred income taxes	8,778	6,526
Prepaids and other	2,031	2,463
TOTAL CURRENT ASSETS	281,971	68,805
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	2,622,942	2,585,502
Pipelines and other midstream facilities	62,609	60,120
Contract drilling equipment	123,931	123,876
Other	22,268	19,371
PROPERTY AND EQUIPMENT, GROSS	2,831,750	2,788,869
Less accumulated depreciation, depletion and amortization	(1,684,423)	(1,587,585)
Property and equipment, net	1,147,327	1,201,284
OTHER ASSETS
Investments and other	7,654	17,331
Total assets	1,436,952	1,287,420
Accounts payable:
Trade	37,438	29,197
Oil and gas sales	19,750	19,490
Affiliates	1,209	383
Fair value of commodity derivatives	10,136	0
Accrued liabilities and other	24,262	16,669
TOTAL CURRENT LIABILITIES	92,795	65,739
NON-CURRENT LIABILITIES
Long-term debt	846,507	742,410
Deferred income taxes	52,025	108,996
Fair value of commodity derivatives	1,490	0
Fair value of common stock warrants	171,720	0
Asset retirement obligations	62,478	48,728
Accrued compensation under non-equity award plans	22,585	16,254
Deferred revenue from volumetric production payment and other	4,572	5,695
TOTAL NON-CURRENT LIABILITIES	1,161,377	922,083
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock, par value $.10 per share, authorized — 3,000,000 shares; issued and outstanding — 3,500 shares at September 30, 2016 and none at December 31, 2015	0	0
Common stock, par value $.10 per share, authorized — 30,000,000 shares; issued and outstanding — 17,493,486 shares at September 30, 2016 and 12,169,536 at December 31, 2015	1,749	1,216
Additional paid-in capital	300,309	152,686
Retained earnings (accumulated deficit)	(119,278)	145,696
TOTAL STOCKHOLDERS' EQUITY	182,780	299,598
Total liabilities and equity	$ 1,436,952	$ 1,287,420

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 2,694	$ 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
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)	17,493,486	12,169,536
Common stock, outstanding shares (in shares)	17,493,486	12,169,536

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
REVENUES
Oil and gas sales	$ 43,470	$ 51,307	$ 113,351	$ 178,539
Midstream services	1,538	1,500	3,897	4,714
Drilling rig services	0	0	0	23
Other operating revenues	10,430	1,774	10,699	8,678
Total revenues	55,438	54,581	127,947	191,954
COSTS AND EXPENSES
Production	17,776	20,665	54,160	67,188
Exploration:
Abandonments and impairments	2,483	874	3,507	5,005
Seismic and other	(8)	239	421	1,210
Midstream services	195	406	1,364	1,339
Drilling rig services	1,125	922	3,591	4,418
Depreciation, depletion and amortization	38,349	36,861	115,140	121,636
Impairment of property and equipment	1,091	3,089	3,438	5,620
Accretion of asset retirement obligations	1,290	1,001	3,360	2,936
General and administrative	5,571	4,631	23,027	25,102
Other operating expenses	579	5,632	3,094	8,479
Total costs and expenses	68,451	74,320	211,102	242,933
Operating loss	(13,013)	(19,739)	(83,155)	(50,979)
OTHER INCOME (EXPENSE)
Interest expense	(26,580)	(13,565)	(70,224)	(40,451)
Gain on early extinguishment of long-term debt	3,967	0	3,967	0
Loss on change in fair value of common stock warrants	(123,351)	0	(154,956)	0
Gain (loss) on commodity derivatives	1,330	18,099	(13,997)	10,431
Impairment of investments and other	1,367	743	(5,832)	2,307
Total other income (expense)	(143,267)	5,277	(241,042)	(27,713)
Loss before income taxes	(156,280)	(14,462)	(324,197)	(78,692)
Income tax benefit	7,504	5,039	59,223	27,705
NET LOSS	$ (148,776)	$ (9,423)	$ (264,974)	$ (50,987)
Net loss per common share:
Basic (in dollars per share)	$ (10.62)	$ (0.77)	$ (20.72)	$ (4.19)
Diluted (in dollars per share)	$ (10.62)	$ (0.77)	$ (20.72)	$ (4.19)
Weighted average common shares outstanding:
Basic (in shares)	14,013	12,170	12,789	12,170
Diluted (in shares)	14,013	12,170	12,789	12,170

CONSOLIDATED STATEMENT OF STOCK

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (Unaudited) - 9 months ended Sep. 30, 2016 - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Additional Paid-In Capital	Retained Earnings
BEGINNING BALANCE at Dec. 31, 2015	$ 299,598	$ 1,216	$ 152,686	$ 145,696
BEGINNING BALANCE (in shares) at Dec. 31, 2015		12,170
Increase (Decrease) in Stockholders' Equity
Net loss	(264,974)			(264,974)
Sale of common stock (in shares)		5,051
Sale of common stock	147,346	$ 506	146,840
Issuance of common stock through compensation plan (in shares)		273
Stock-based compensation plan	810	$ 27	783
ENDING BALANCE at Sep. 30, 2016	$ 182,780	$ 1,749	$ 300,309	$ (119,278)
ENDING BALANCE (in shares) at Sep. 30, 2016		17,494

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$ (264,974)	$ (50,987)
Adjustments to reconcile net loss to cash provided by operating activities:
Depreciation, depletion and amortization	115,140	121,636
Impairment of property and equipment	3,438	5,620
Abandonments and impairments	3,507	5,005
Gain on sales of assets and impairment of inventory, net	(7,938)	(835)
Deferred income tax benefit	(59,223)	(27,705)
Non-cash employee compensation	7,245	4,405
(Gain) loss on commodity derivatives	13,997	(10,431)
Cash settlements of commodity derivatives	(2,371)	4,585
Accretion of asset retirement obligations	3,360	2,936
Amortization of debt issue costs and original issue discount	5,517	2,241
Gain on early extinguishment of long-term debt	(3,967)	0
Loss on change in fair value of common stock warrants	154,956	0
Amortization of deferred revenue from volumetric production payment	(1,066)	(5,181)
Paid in-kind interest expense	27,196	0
Impairment of investment and other	8,530	669
Changes in operating working capital:
Accounts receivable	(898)	25,307
Accounts payable	(1,702)	(32,057)
Other	7,219	9,788
Net cash provided by operating activities	7,966	54,996
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(62,331)	(155,680)
Termination of volumetric production payment	0	(13,703)
Net purchase of short-term investments	(40,041)	0
Proceeds from sales of assets	27,369	47,484
Decrease in equipment inventory	1,552	1,130
Proceeds from volumetric production payment and other	(689)	1,499
Net cash used in investing activities	(74,140)	(119,270)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	343,237	45,000
Net repayments of Senior Notes	(95,001)	0
Repayments of long-term debt	(160,000)	0
Payment of debt issuance costs	(10,958)	0
Proceeds from sale of common stock	147,346	0
Proceeds from issuance of common stock warrants	16,763	0
Net cash provided by financing activities	241,387	45,000
Net increase (decrease) in cash and cash equivalents	175,213	(19,274)
CASH AND CASH EQUIVALENTS
Beginning of period	7,780	28,016
End of period	182,993	8,742
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	29,794	26,993
Cash paid for income taxes	$ 65	$ 227

Nature of Operations

Nature of Operations	9 Months Ended
	Sep. 30, 2016
Nature of Operations Disclosures [Abstract]
Nature of Operations	1. 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 areas in Texas and New Mexico. 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 17.8% of CWEI’s outstanding common stock, is beneficially owned by Clayton W. Williams, Jr. (“Mr. Williams”), Chairman of the Board of Directors (the “Board”) and Chief Executive Officer of the Company, and approximately 17.4% is owned by a partnership in which Mr. Williams’ adult children are limited partners, and Mel G. Riggs, our President, is the sole general partner. 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.

Presentation

Presentation	9 Months Ended
	Sep. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Presentation	Presentation 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 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. In the opinion of management, our unaudited consolidated financial statements as of September 30, 2016 and for the three and nine months ended September 30, 2016 and 2015 include all adjustments, which are of a normal and recurring nature, that are necessary for a fair presentation in accordance with GAAP. These interim results are not necessarily indicative of the results to be expected for the year ending December 31, 2016 . Certain information and footnote disclosures normally included in the consolidated financial statements prepared in accordance with GAAP have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Form 10-K for the year ended December 31, 2015 . 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).” The main difference between the current requirement under GAAP and ASU 2016-02 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires that a lessee recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term (other than leases that meet the definition of a short-term lease). The liability will be equal to the present value of lease payments. The asset will be based on the liability, subject to adjustment, such as for initial direct costs. For income statement purposes, the FASB retained a dual model, requiring leases to be classified as either operating or finance. Operating leases will result in straight-line expense (similar to current operating leases) while finance leases will result in a front-loaded expense pattern (similar to current capital leases). Classification will be based on criteria that are largely similar to those applied in current lease accounting. For lessors, the guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. ASU 2016-02 is effective for annual and interim periods beginning after December 15, 2018 and early adoption is permitted. ASU 2016-02 must be adopted using a modified retrospective transition, and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. We are evaluating the impact that this new guidance will have on our consolidated financial statements. 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. The standard is effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the provisions of ASU 2014-15 and do not anticipate any impact on our consolidated financial statements. 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. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 by one year. That new standard is now effective for annual reporting periods beginning after December 15, 2017. Early adoption is permitted for fiscal years beginning after December 15, 2016. In May 2016, the FASB issued ASU No. 2016-11, which rescinds guidance from the SEC on accounting for gas balancing arrangements and will eliminate the use of the entitlements method. An entity can apply ASU 2014-09 using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. We are evaluating the impact that this new guidance will have on our consolidated financial statements.

Long-Term Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2016
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Long-term debt consists of the following: September 30, December 31, (In thousands) 7.75% Senior Notes, due 2019 $ 500,000 $ 600,000 Original Issue Discount (159 ) (241 ) Debt Issuance Costs (4,852 ) (7,349 ) Net 7.75% Senior Notes, due 2019 $ 494,989 $ 592,410 Second Lien Term Loan, due March 2021 $ 350,000 $ — Paid in-kind interest 27,196 — Original Issue Discount (15,583 ) — Debt Issuance Costs (10,095 ) — Net Second Lien Term Loan, due March 2021 $ 351,518 $ — Revolving credit facility, due April 2019 $ — $ 150,000 $ 846,507 $ 742,410 Revolving Credit Facility We may borrow money under a revolving credit facility with a syndicate of 16 banks led by JPMorgan 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 September 30, 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 nine months ended September 30, 2016 was 2.5% . We were in compliance with all financial and non-financial covenants at September 30, 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 Management, LLC (“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 loss (see Note 10). The warrants had a fair value of $16.8 million at the date of issuance and a fair value of $171.7 million at September 30, 2016 . As a result, for the three and nine months ended September 30, 2016 , we recorded a loss on revaluation of the warrant liability of $123.4 million and $155 million , respectively. 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 quarters ended June 30, 2016 and September 30, 2016 in-kind. In August 2016, we elected to pay interest for the quarterly period ending December 31, 2016 in cash. Future quarterly elections to pay in-kind must be made at least 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 September 30, 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 (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 three and nine months ended September 30, 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 remaining 2019 Senior Notes at a redemption price (expressed as a percentage 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 September 30, 2016 and December 31, 2015 .

Sales of Assets

Sales of Assets	9 Months Ended
	Sep. 30, 2016
Sale Of Assets [Abstract]
Sale of Assets	Sales of Assets 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 . This acreage was sold under a one-year term assignment as long as the buyer maintains a 180-day continuous development program on the acreage. In February 2016, we sold certain acreage in Burleson County, Texas for cash consideration of $0.8 million . Net proceeds from 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. In September 2015, we sold our interests in selected leases 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 . Net proceeds from each of these transactions were applied to reduce indebtedness outstanding under the revolving credit facility.

Asset Retirement Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations We record asset retirement obligations (“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 during the nine months ended September 30, 2016 and the year ended December 31, 2015 : September 30, December 31, (In thousands) Beginning of period $ 48,728 $ 45,697 Additional ARO from new properties 40 469 Sales or abandonments of properties (924 ) (4,435 ) Accretion expense 3,360 3,945 Revisions of previous estimates 11,274 3,052 End of period $ 62,478 $ 48,728

Deferred Revenue from Volumetri

Deferred Revenue from Volumetric Production Payment	9 Months Ended
	Sep. 30, 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 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 loss. As of September 30, 2016 , we have no further obligations under the VPP. The following table reflects the changes in the deferred revenue during the nine months ended September 30, 2016 and the year ended December 31, 2015 : September 30, December 31, (In thousands) Beginning of period $ 5,470 $ 23,129 Deferred revenue from VPP — 2,866 Amortization of deferred revenue from VPP (1,066 ) (6,822 ) Termination of VPP — (13,703 ) End of period $ 4,404 $ 5,470

Stockholders' Equity and Earnin

Stockholders' Equity and Earnings Per Share (Notes)	9 Months Ended
	Sep. 30, 2016
Equity [Abstract]
Stockholders' Equity and Earnings Per Share	Stockholders’ Equity and Earnings 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 Per Share Basic earnings per share amounts have been computed based on the weighted average number of shares of common stock outstanding for the period. Diluted earnings per share include the effect of potentially dilutive shares outstanding for the period. For the three and nine months ended September 30, 2016 , there were 152,000 shares that were not included in the computation of diluted earnings per share because their inclusion would have been anti-dilutive for the periods presented.

Compensation Plans

Compensation Plans	9 Months Ended
	Sep. 30, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Compensation Plans	Compensation Plans Long Term Incentive Plan In June 2016 , stockholders 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 the Company 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 the Company’s 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 the Company’s common stock have been reserved for issuance under the LTIP and are expected to consist of new shares of the Company. During the quarter ended September 30, 2016 , initial 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. The Company estimates the fair value of stock options granted using a Black-Scholes option valuation model, which requires the Company to make certain assumptions, as follows: • Expected volatility of the underlying common stock is based on the Company’s historical stock volatility; • Expected term of options granted is based on the mid-point between the final vesting date and the expiration date since the Company 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 quarter ended September 30, 2016 : September 30, Grant-date fair value $ 63.80 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 September 30, 2016 : Weighted Average Aggregate Exercise Remaining Intrinsic Options Price Term Value Outstanding at January 1, 2016 — $ — Granted 152,000 $ 63.80 Exercised — $ — Outstanding at September 30, 2016 152,000 $ 63.80 Vested and expected to vest at September 30, 2016 152,000 $ 63.80 6.9 $ 3,289,560 Exercisable at September 30, 2016 — $ — — $ — As of September 30, 2016 , the unrecognized compensation cost related to granted stock options was $5.8 million . Such cost is expected to be recognized over a weighted-average period of 2.9 years. Restricted Stock Awards Restricted stock awards granted under the LTIP as of September 30, 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 the Company’s 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 September 30, 2016 : Weighted Average Restricted Stock Grant-Date Awards Fair Value Unvested at January 1, 2016 — $ — Granted 272,850 $ 63.69 Vested — $ — Forfeited — $ — Unvested at September 30, 2016 272,850 $ — The aggregate fair value of restricted stock awards granted during the nine months ended September 30, 2016 was $17.4 million . As of September 30, 2016 , our unrecognized compensation cost related to unvested restricted stock awards was $16.7 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 $0.8 million for the three and nine months ended September 30, 2016 and none for the three and nine months ended September 30, 2015. 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. Through May 4, 2016, we have granted awards under the APO Reward Plan in 15 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 15 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 22.50% 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 for the three months ended September 30, 2016 and 2015 and the nine months ended September 30, 2016 and 2015 were $(1.1) million , $(2) million and $7.2 million , $6.6 million , respectively. 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: September 30, December 31, (In thousands) Current liabilities: Accrued liabilities and other $ 1,355 $ 1,251 Non-current liabilities: Accrued compensation under non-equity award plans 22,585 16,254 Total accrued compensation under non-equity award plans $ 23,940 $ 17,505

Derivatives

Derivatives	9 Months Ended
	Sep. 30, 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 September 30, 2016 . Settlement prices of commodity derivatives are based on NYMEX futures prices. Swaps: Oil MBbls Price Production Period: 4th Quarter 2016 619 $ 41.18 2017 407 $ 45.58 1,026 Costless Collars: Oil Weighted Weighted Average Average MBbls Floor Price Ceiling Price Production Period: 2017 1,415 $ 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 loss. Effect of Commodity Derivative Instruments on the Consolidated Balance Sheets Fair Value of Commodity Derivative Instruments as of September 30, 2016 Asset Commodity Derivatives Liability Commodity Derivatives Balance Sheet Balance Sheet Location Fair Value 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 $ 10,136 Non-current — Non-current 1,490 Total $ — $ 11,626 Fair Value of Commodity Derivative Instruments as of December 31, 2015 Asset Commodity Derivatives Liability Commodity Derivatives Balance Sheet Balance Sheet Location Fair Value 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 September 30, 2016 Assets Liabilities (In thousands) Fair value of commodity derivatives — gross presentation $ — $ 11,626 Effects of netting arrangements — — Fair value of commodity derivatives — net presentation $ — $ 11,626 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., Shell Trading Risk Management LLC and Fifth Third Bank. Effect of Commodity Derivative Instruments Recognized in Earnings on the Consolidated Statements of Operations and Comprehensive Loss Amount of Gain or (Loss) Recognized in Earnings Three Months Ended Nine Months Ended September 30, September 30, Location of Gain or (Loss) Recognized in Earnings 2016 2015 2016 2015 (In thousands) (In thousands) Commodity derivatives not designated as hedging instruments: Commodity derivatives: Other income (expense) - Gain (loss) on commodity derivatives $ 1,330 $ 18,099 $ (13,997 ) $ 10,431 Total $ 1,330 $ 18,099 $ (13,997 ) $ 10,431

Fair Value of Financial Instrum

Fair Value of Financial Instruments	9 Months Ended
	Sep. 30, 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 is 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 September 30, 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 the Company’s stock price volatility and expected remaining life. The fair value of all commodity derivative contracts and common stock warrants are reflected on the consolidated balance sheet as detailed in the following schedule: September 30, December 31, Significant Other Observable Inputs Description (Level 2) (In thousands) Assets: Fair value of commodity derivatives $ — $ — Total assets $ — $ — Liabilities: Fair value of commodity derivatives $ 11,626 $ — Fair value of common stock warrants 171,720 — Total liabilities $ 183,346 $ — 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 September 30, 2016 is based upon our discounted cash flow model. Fair value is compared to the carrying value in the table below: Fair Value September 30, 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 $ 494,989 $ 481,250 $ 599,759 $ 462,750 Second Lien Term Loan, due March 2021 3 $ 351,518 $ 275,301 $ — $ —

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Our effective federal and state income tax rate for the nine months ended September 30, 2016 of 18.3% differed from the statutory federal rate of 35% due primarily to permanent differences related to revaluation of the warrants issued in connection with the Refinancing, increases related to the effects of the Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from excess statutory depletion deductions. 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.

Other Operating Revenues and Ex

Other Operating Revenues and Expenses	9 Months Ended
	Sep. 30, 2016
Other Operating Revenues [Abstract]
Other Operating Revenues and Expenses	Other Operating Revenues and Expenses Other operating revenues and expenses for the three and nine months ended September 30, 2016 and 2015 are as follows: Three Months Ended Nine Months Ended September 30, September 30, 2016 2015 2016 2015 (In thousands) (In thousands) Other operating revenues: Gain on sales of assets $ 10,430 $ 1,774 $ 10,699 $ 8,655 Marketing revenue — — — 23 Total other operating revenues $ 10,430 $ 1,774 $ 10,699 $ 8,678 Other operating expenses: Loss on sales of assets $ 482 $ 345 $ 1,387 $ 410 Marketing expense 50 445 333 660 Impairment of inventory 47 4,842 1,374 7,409 Total other operating expenses $ 579 $ 5,632 $ 3,094 $ 8,479 During the three and nine months ended September 30, 2016 , gain on sales of assets included the sale of our interests in certain wells in Glasscock County, Texas in July 2016 (see Note 4). During the three months ended September 30, 2015 , gain on sales of assets included the sale of selected leases in South Louisiana in September 2015. During the nine months ended September 30, 2015 , gain on sales of assets included the sale of selected leases 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). 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	9 Months Ended
	Sep. 30, 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 no impairment on our investment in Dalea for the three months ended September 30, 2016 , $8.4 million for the nine months ended September 30, 2016 , and $0.5 million and $1.4 million for the three and nine months ended September 30, 2015 , respectively. At September 30, 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.

Costs of Oil and Gas Properties

Costs of Oil and Gas Properties	9 Months Ended
	Sep. 30, 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 the net capitalized costs for oil and gas properties as of September 30, 2016 and December 31, 2015 : September 30, December 31, (In thousands) Proved properties $ 2,562,372 $ 2,539,480 Unproved properties 60,570 46,022 Total capitalized costs 2,622,942 2,585,502 Accumulated depletion (1,546,087 ) (1,460,404 ) Net capitalized costs $ 1,076,855 $ 1,125,098

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies 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 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. 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 and potential court rulings are set for 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	9 Months Ended
	Sep. 30, 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 a provision for impairment of proved properties of $1.1 million for the three months ended September 30, 2016 and $3.1 million for the three months ended September 30, 2015 . We recorded a provision for impairment of proved properties of $3.4 million for the nine months ended September 30, 2016 and $5.6 million for the nine months ended September 30, 2015 . The provision for the three months ended September 30, 2016 was related to the write-down of certain non-core properties located in California and the Cotton Valley area of Texas to their estimated fair value and the provision for the nine months ended September 30, 2016 was related to the write-down of certain non-core properties located in California, Oklahoma and the Cotton Valley area of Texas to their estimated fair value. The provision for the three months ended September 30, 2015 was related to the write-down of certain non-core properties located in the Permian Basin and California and the provision for the nine months ended September 30, 2015 was related to the write-down of certain non-core properties located in the Permian Basin, California and Louisiana to their estimated fair value. 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 of $2.1 million for the three months ended September 30, 2016 , $0.3 million for the three months ended September 30, 2015 , $2.3 million for the nine months ended September 30, 2016 and $2.7 million for the nine months ended September 30, 2015 , and charged these impairments to abandonments and impairments in the accompanying consolidated statements of operations and comprehensive loss.

Segment Information

Segment Information	9 Months Ended
	Sep. 30, 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 three and nine months ended September 30, 2016 and 2015 : For the Three Months Ended September 30, 2016 (Unaudited) Contract Intercompany Consolidated (In thousands) Oil and Gas Drilling Eliminations Total Revenues $ 55,372 $ 66 $ — $ 55,438 Depreciation, depletion and amortization (a) 36,540 2,900 — 39,440 Other operating expenses (b) 27,886 1,125 — 29,011 Interest expense 26,580 — — 26,580 Other (income) expense 116,687 — — 116,687 Income (loss) before income taxes (152,321 ) (3,959 ) — (156,280 ) Income tax (expense) benefit 6,118 1,386 — 7,504 Net income (loss) $ (146,203 ) $ (2,573 ) $ — $ (148,776 ) Total assets $ 1,459,652 $ 25,457 $ (48,157 ) $ 1,436,952 Additions to property and equipment $ 34,627 $ 3,011 $ — $ 37,638 For the Nine Months Ended September 30, 2016 (Unaudited) Contract Intercompany Consolidated (In thousands) Oil and Gas Drilling Eliminations Total Revenues $ 127,799 $ 148 $ — $ 127,947 Depreciation, depletion and amortization (a) 109,328 9,250 — 118,578 Other operating expenses (b) 89,111 3,413 — 92,524 Interest expense 70,224 — — 70,224 Other (income) expense (c) 162,387 8,431 — 170,818 Income (loss) before income taxes (303,251 ) (20,946 ) — (324,197 ) Income tax (expense) benefit 51,892 7,331 — 59,223 Net income (loss) $ (251,359 ) $ (13,615 ) $ — $ (264,974 ) Total assets $ 1,459,652 $ 25,457 $ (48,157 ) $ 1,436,952 Additions to property and equipment $ 81,292 $ 3,052 $ — $ 84,344 For the Three Months Ended September 30, 2015 (Unaudited) Contract Intercompany Consolidated (In thousands) Oil and Gas Drilling Eliminations Total Revenues $ 54,571 $ 1,606 $ (1,596 ) $ 54,581 Depreciation, depletion and amortization (a) 37,091 3,196 (337 ) 39,950 Other operating expenses (b) 32,441 3,126 (1,197 ) 34,370 Interest expense 13,565 — — 13,565 Other (income) expense (c) (19,337 ) 495 — (18,842 ) Income (loss) before income taxes (9,189 ) (5,211 ) (62 ) (14,462 ) Income tax (expense) benefit 3,215 1,824 — 5,039 Net income (loss) $ (5,974 ) $ (3,387 ) $ (62 ) $ (9,423 ) Total assets $ 1,383,193 $ 52,363 $ (43,730 ) $ 1,391,826 Additions to property and equipment $ 28,005 $ 460 $ (62 ) $ 28,403 For the Nine Months Ended September 30, 2015 (Unaudited) Contract Intercompany Consolidated (In thousands) Oil and Gas Drilling Eliminations Total Revenues $ 191,873 $ 2,328 $ (2,247 ) $ 191,954 Depreciation, depletion and amortization (a) 118,090 9,606 (440 ) 127,256 Other operating expenses (b) 110,118 7,610 (2,051 ) 115,677 Interest expense 40,451 — — 40,451 Other (income) expense (c) (14,155 ) 1,417 — (12,738 ) Income (loss) before income taxes (62,631 ) (16,305 ) 244 (78,692 ) Income tax (expense) benefit 21,998 5,707 — 27,705 Net income (loss) $ (40,633 ) $ (10,598 ) $ 244 $ (50,987 ) Total assets $ 1,383,193 $ 52,363 $ (43,730 ) $ 1,391,826 Additions to property and equipment $ 105,742 $ 1,202 $ 244 $ 107,188 _______ (a) Includes impairment of property and equipment. (b) Includes the following expenses: production, exploration, midstream services, drilling rig services, accretion of ARO, general and administrative and other operating expenses. (c) Includes impairment of our investment in Dalea.

Guarantor Financial Information

Guarantor Financial Information	9 Months Ended
	Sep. 30, 2016
Guarantor Financial Information Disclosure [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 three and nine months ended September 30, 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 18. The financial information which follows sets forth our condensed consolidating financial statements as of and for the periods indicated. Condensed Consolidating Balance Sheet September 30, 2016 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Current assets $ 333,198 $ 269,858 $ 1,014 $ (322,099 ) $ 281,971 Property and equipment, net 862,866 281,133 3,328 — 1,147,327 Investments in subsidiaries 296,918 — — (296,918 ) — Other assets 5,509 2,145 — — 7,654 Total assets $ 1,498,491 $ 553,136 $ 4,342 $ (619,017 ) $ 1,436,952 Current liabilities $ 298,879 $ 100,964 $ 63 $ (307,111 ) $ 92,795 Non-current liabilities: Long-term debt 846,507 — — — 846,507 Fair value of commodity derivatives 11,626 — — (10,136 ) 1,490 Fair value of common stock warrants 171,720 — — — 171,720 Deferred income taxes 47,758 117,051 (2,114 ) (110,670 ) 52,025 Other 45,039 44,296 300 — 89,635 1,122,650 161,347 (1,814 ) (120,806 ) 1,161,377 Equity 76,962 290,825 6,093 (191,100 ) 182,780 Total liabilities and equity $ 1,498,491 $ 553,136 $ 4,342 $ (619,017 ) $ 1,436,952 Condensed Consolidating Balance Sheet December 31, 2015 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary 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) Three Months Ended September 30, 2016 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Total revenue $ 41,983 $ 13,219 $ 236 $ — $ 55,438 Costs and expenses 48,308 19,867 276 — 68,451 Operating income (loss) (6,325 ) (6,648 ) (40 ) — (13,013 ) Other income (expense) (143,695 ) 236 192 — (143,267 ) Equity in earnings of subsidiaries (4,069 ) — — 4,069 — Income tax (expense) benefit 5,313 2,244 (53 ) — 7,504 Net income (loss) $ (148,776 ) $ (4,168 ) $ 99 $ 4,069 $ (148,776 ) Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Nine Months Ended September 30, 2016 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Total revenue $ 89,819 $ 37,442 $ 686 $ — $ 127,947 Costs and expenses 142,557 67,619 926 — 211,102 Operating income (loss) (52,738 ) (30,177 ) (240 ) — (83,155 ) Other income (expense) (233,664 ) (7,968 ) 590 — (241,042 ) Equity in earnings of subsidiaries (24,567 ) — — 24,567 — Income tax (expense) benefit 45,995 13,351 (123 ) — 59,223 Net income (loss) $ (264,974 ) $ (24,794 ) $ 227 $ 24,567 $ (264,974 ) Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Three Months Ended September 30, 2015 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Total revenue $ 39,500 $ 14,765 $ 316 $ — $ 54,581 Costs and expenses 52,630 21,133 557 — 74,320 Operating income (loss) (13,130 ) (6,368 ) (241 ) — (19,739 ) Other income (expense) 4,912 53 312 — 5,277 Equity in earnings of subsidiaries (4,059 ) — — 4,059 — Income tax (expense) benefit 2,854 2,210 (25 ) — 5,039 Net income (loss) $ (9,423 ) $ (4,105 ) $ 46 $ 4,059 $ (9,423 ) Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Nine Months Ended September 30, 2015 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Total revenue $ 140,902 $ 49,906 $ 1,146 $ — $ 191,954 Costs and expenses 177,041 64,042 1,850 — 242,933 Operating income (loss) (36,139 ) (14,136 ) (704 ) — (50,979 ) Other income (expense) (28,720 ) (488 ) 1,495 — (27,713 ) Equity in earnings of subsidiaries (8,991 ) — — 8,991 — Income tax (expense) benefit 22,863 5,118 (276 ) — 27,705 Net income (loss) $ (50,987 ) $ (9,506 ) $ 515 $ 8,991 $ (50,987 ) Condensed Consolidating Statement of Cash Flows Nine Months Ended September 30, 2016 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Operating activities $ (3,780 ) $ 12,090 $ (344 ) $ — $ 7,966 Investing activities (67,166 ) (6,955 ) (19 ) — (74,140 ) Financing activities 246,040 (4,608 ) (45 ) — 241,387 Net increase (decrease) in cash and cash equivalents 175,094 527 (408 ) — 175,213 Cash at beginning of period 4,663 1,855 1,262 — 7,780 Cash at end of period $ 179,757 $ 2,382 $ 854 $ — $ 182,993 Condensed Consolidating Statement of Cash Flows Nine Months Ended September 30, 2015 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Operating activities $ 44,249 $ 9,330 $ 978 $ 439 $ 54,996 Investing activities (101,921 ) (16,741 ) (169 ) (439 ) (119,270 ) Financing activities 41,674 3,631 (305 ) — 45,000 Net increase (decrease) in cash and cash equivalents (15,998 ) (3,780 ) 504 — (19,274 ) Cash at beginning of period 21,217 6,693 106 — 28,016 Cash at end of period $ 5,219 $ 2,913 $ 610 $ — $ 8,742

Subsequent Events

Subsequent Events	9 Months Ended
	Sep. 30, 2016
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events On October 24, 2016 , we entered into a definitive purchase and sale agreement with a third party to sell substantially all of our assets in the Giddings Area in East Central Texas for a sale price of $400 million . The sale is subject to customary closing conditions and adjustments. We expect to close the sale in December 2016 and use the proceeds from the sale to fund development in the Delaware Basin and repay a portion of our outstanding indebtedness. We have evaluated events and transactions that occurred after the balance sheet date of September 30, 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.

Presentation (Policies)

Presentation (Policies)	9 Months Ended
	Sep. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Presentation	Presentation 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 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.
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).” The main difference between the current requirement under GAAP and ASU 2016-02 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires that a lessee recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term (other than leases that meet the definition of a short-term lease). The liability will be equal to the present value of lease payments. The asset will be based on the liability, subject to adjustment, such as for initial direct costs. For income statement purposes, the FASB retained a dual model, requiring leases to be classified as either operating or finance. Operating leases will result in straight-line expense (similar to current operating leases) while finance leases will result in a front-loaded expense pattern (similar to current capital leases). Classification will be based on criteria that are largely similar to those applied in current lease accounting. For lessors, the guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. ASU 2016-02 is effective for annual and interim periods beginning after December 15, 2018 and early adoption is permitted. ASU 2016-02 must be adopted using a modified retrospective transition, and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. We are evaluating the impact that this new guidance will have on our consolidated financial statements. 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. The standard is effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the provisions of ASU 2014-15 and do not anticipate any impact on our consolidated financial statements. 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. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 by one year. That new standard is now effective for annual reporting periods beginning after December 15, 2017. Early adoption is permitted for fiscal years beginning after December 15, 2016. In May 2016, the FASB issued ASU No. 2016-11, which rescinds guidance from the SEC on accounting for gas balancing arrangements and will eliminate the use of the entitlements method. An entity can apply ASU 2014-09 using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. We are evaluating the impact that this new guidance will have on our consolidated financial statements.
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. The financial assets and liabilities measured on a recurring basis at September 30, 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 the Company’s stock price volatility and expected remaining life.

Long-Term Debt (Tables)

Long-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2016
Debt Disclosure [Abstract]
Schedule of long-term debt	Long-term debt consists of the following: September 30, December 31, (In thousands) 7.75% Senior Notes, due 2019 $ 500,000 $ 600,000 Original Issue Discount (159 ) (241 ) Debt Issuance Costs (4,852 ) (7,349 ) Net 7.75% Senior Notes, due 2019 $ 494,989 $ 592,410 Second Lien Term Loan, due March 2021 $ 350,000 $ — Paid in-kind interest 27,196 — Original Issue Discount (15,583 ) — Debt Issuance Costs (10,095 ) — Net Second Lien Term Loan, due March 2021 $ 351,518 $ — Revolving credit facility, due April 2019 $ — $ 150,000 $ 846,507 $ 742,410

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2016
Asset Retirement Obligation Disclosure [Abstract]
Schedule of changes in asset retirement obligations	The following table reflects the changes in ARO during the nine months ended September 30, 2016 and the year ended December 31, 2015 : September 30, December 31, (In thousands) Beginning of period $ 48,728 $ 45,697 Additional ARO from new properties 40 469 Sales or abandonments of properties (924 ) (4,435 ) Accretion expense 3,360 3,945 Revisions of previous estimates 11,274 3,052 End of period $ 62,478 $ 48,728

Deferred Revenue from Volumet29

Deferred Revenue from Volumetric Production Payment (Tables)	9 Months Ended
	Sep. 30, 2016
Deferred Revenue Disclosure [Abstract]
Schedule of changes in deferred revenue from the VPP	The following table reflects the changes in the deferred revenue during the nine months ended September 30, 2016 and the year ended December 31, 2015 : September 30, December 31, (In thousands) Beginning of period $ 5,470 $ 23,129 Deferred revenue from VPP — 2,866 Amortization of deferred revenue from VPP (1,066 ) (6,822 ) Termination of VPP — (13,703 ) End of period $ 4,404 $ 5,470

Compensation Plans (Tables)

Compensation Plans (Tables)	9 Months Ended
	Sep. 30, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of stock option assumptions	The following table summarizes the weighted average grant date fair values and related assumptions for grants made during the quarter ended September 30, 2016 : September 30, Grant-date fair value $ 63.80 Expected volatility 76.3 % Expected term (in years) 5 Risk-free rate 1.2 %
Schedule of stock option activity	The following table sets forth certain information regarding our stock options as of September 30, 2016 : Weighted Average Aggregate Exercise Remaining Intrinsic Options Price Term Value Outstanding at January 1, 2016 — $ — Granted 152,000 $ 63.80 Exercised — $ — Outstanding at September 30, 2016 152,000 $ 63.80 Vested and expected to vest at September 30, 2016 152,000 $ 63.80 6.9 $ 3,289,560 Exercisable at September 30, 2016 — $ — — $ —
Schedule of restricted stock activity	The following table presents our restricted stock activity as of September 30, 2016 : Weighted Average Restricted Stock Grant-Date Awards Fair Value Unvested at January 1, 2016 — $ — Granted 272,850 $ 63.69 Vested — $ — Forfeited — $ — Unvested at September 30, 2016 272,850 $ —
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: September 30, December 31, (In thousands) Current liabilities: Accrued liabilities and other $ 1,355 $ 1,251 Non-current liabilities: Accrued compensation under non-equity award plans 22,585 16,254 Total accrued compensation under non-equity award plans $ 23,940 $ 17,505

Derivatives (Tables)

Derivatives (Tables)	9 Months Ended
	Sep. 30, 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 September 30, 2016 . Settlement prices of commodity derivatives are based on NYMEX futures prices. Swaps: Oil MBbls Price Production Period: 4th Quarter 2016 619 $ 41.18 2017 407 $ 45.58 1,026 Costless Collars: Oil Weighted Weighted Average Average MBbls Floor Price Ceiling Price Production Period: 2017 1,415 $ 42.27 $ 51.66 1,415
Schedule of effect of 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 September 30, 2016 Asset Commodity Derivatives Liability Commodity Derivatives Balance Sheet Balance Sheet Location Fair Value 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 $ 10,136 Non-current — Non-current 1,490 Total $ — $ 11,626 Fair Value of Commodity Derivative Instruments as of December 31, 2015 Asset Commodity Derivatives Liability Commodity Derivatives Balance Sheet Balance Sheet Location Fair Value 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 derivative assets and liabilities	Gross to Net Presentation Reconciliation of Commodity Derivative Assets and Liabilities September 30, 2016 Assets Liabilities (In thousands) Fair value of commodity derivatives — gross presentation $ — $ 11,626 Effects of netting arrangements — — Fair value of commodity derivatives — net presentation $ — $ 11,626 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 Loss Amount of Gain or (Loss) Recognized in Earnings Three Months Ended Nine Months Ended September 30, September 30, Location of Gain or (Loss) Recognized in Earnings 2016 2015 2016 2015 (In thousands) (In thousands) Commodity derivatives not designated as hedging instruments: Commodity derivatives: Other income (expense) - Gain (loss) on commodity derivatives $ 1,330 $ 18,099 $ (13,997 ) $ 10,431 Total $ 1,330 $ 18,099 $ (13,997 ) $ 10,431

Fair Value of Financial Instr32

Fair Value of Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 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 sheet as detailed in the following schedule: September 30, December 31, Significant Other Observable Inputs Description (Level 2) (In thousands) Assets: Fair value of commodity derivatives $ — $ — Total assets $ — $ — Liabilities: Fair value of commodity derivatives $ 11,626 $ — Fair value of common stock warrants 171,720 — Total liabilities $ 183,346 $ —
Schedule of comparison of fair value to the carrying value of the 2019 Senior Notes	The fair value of our Second Lien Term Loan as of September 30, 2016 is based upon our discounted cash flow model. Fair value is compared to the carrying value in the table below: Fair Value September 30, 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 $ 494,989 $ 481,250 $ 599,759 $ 462,750 Second Lien Term Loan, due March 2021 3 $ 351,518 $ 275,301 $ — $ —

Other Operating Revenues and 33

Other Operating Revenues and Expenses (Tables)	9 Months Ended
	Sep. 30, 2016
Other Operating Revenues [Abstract]
Schedule of other operating revenues and expenses	Other operating revenues and expenses for the three and nine months ended September 30, 2016 and 2015 are as follows: Three Months Ended Nine Months Ended September 30, September 30, 2016 2015 2016 2015 (In thousands) (In thousands) Other operating revenues: Gain on sales of assets $ 10,430 $ 1,774 $ 10,699 $ 8,655 Marketing revenue — — — 23 Total other operating revenues $ 10,430 $ 1,774 $ 10,699 $ 8,678 Other operating expenses: Loss on sales of assets $ 482 $ 345 $ 1,387 $ 410 Marketing expense 50 445 333 660 Impairment of inventory 47 4,842 1,374 7,409 Total other operating expenses $ 579 $ 5,632 $ 3,094 $ 8,479

Costs of Oil and Gas Properti34

Costs of Oil and Gas Properties (Tables)	9 Months Ended
	Sep. 30, 2016
Oil and Gas Property, Successful Effort Method, Gross [Abstract]
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 September 30, 2016 and December 31, 2015 : September 30, December 31, (In thousands) Proved properties $ 2,562,372 $ 2,539,480 Unproved properties 60,570 46,022 Total capitalized costs 2,622,942 2,585,502 Accumulated depletion (1,546,087 ) (1,460,404 ) Net capitalized costs $ 1,076,855 $ 1,125,098

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
	Sep. 30, 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 three and nine months ended September 30, 2016 and 2015 : For the Three Months Ended September 30, 2016 (Unaudited) Contract Intercompany Consolidated (In thousands) Oil and Gas Drilling Eliminations Total Revenues $ 55,372 $ 66 $ — $ 55,438 Depreciation, depletion and amortization (a) 36,540 2,900 — 39,440 Other operating expenses (b) 27,886 1,125 — 29,011 Interest expense 26,580 — — 26,580 Other (income) expense 116,687 — — 116,687 Income (loss) before income taxes (152,321 ) (3,959 ) — (156,280 ) Income tax (expense) benefit 6,118 1,386 — 7,504 Net income (loss) $ (146,203 ) $ (2,573 ) $ — $ (148,776 ) Total assets $ 1,459,652 $ 25,457 $ (48,157 ) $ 1,436,952 Additions to property and equipment $ 34,627 $ 3,011 $ — $ 37,638 For the Nine Months Ended September 30, 2016 (Unaudited) Contract Intercompany Consolidated (In thousands) Oil and Gas Drilling Eliminations Total Revenues $ 127,799 $ 148 $ — $ 127,947 Depreciation, depletion and amortization (a) 109,328 9,250 — 118,578 Other operating expenses (b) 89,111 3,413 — 92,524 Interest expense 70,224 — — 70,224 Other (income) expense (c) 162,387 8,431 — 170,818 Income (loss) before income taxes (303,251 ) (20,946 ) — (324,197 ) Income tax (expense) benefit 51,892 7,331 — 59,223 Net income (loss) $ (251,359 ) $ (13,615 ) $ — $ (264,974 ) Total assets $ 1,459,652 $ 25,457 $ (48,157 ) $ 1,436,952 Additions to property and equipment $ 81,292 $ 3,052 $ — $ 84,344 For the Three Months Ended September 30, 2015 (Unaudited) Contract Intercompany Consolidated (In thousands) Oil and Gas Drilling Eliminations Total Revenues $ 54,571 $ 1,606 $ (1,596 ) $ 54,581 Depreciation, depletion and amortization (a) 37,091 3,196 (337 ) 39,950 Other operating expenses (b) 32,441 3,126 (1,197 ) 34,370 Interest expense 13,565 — — 13,565 Other (income) expense (c) (19,337 ) 495 — (18,842 ) Income (loss) before income taxes (9,189 ) (5,211 ) (62 ) (14,462 ) Income tax (expense) benefit 3,215 1,824 — 5,039 Net income (loss) $ (5,974 ) $ (3,387 ) $ (62 ) $ (9,423 ) Total assets $ 1,383,193 $ 52,363 $ (43,730 ) $ 1,391,826 Additions to property and equipment $ 28,005 $ 460 $ (62 ) $ 28,403 For the Nine Months Ended September 30, 2015 (Unaudited) Contract Intercompany Consolidated (In thousands) Oil and Gas Drilling Eliminations Total Revenues $ 191,873 $ 2,328 $ (2,247 ) $ 191,954 Depreciation, depletion and amortization (a) 118,090 9,606 (440 ) 127,256 Other operating expenses (b) 110,118 7,610 (2,051 ) 115,677 Interest expense 40,451 — — 40,451 Other (income) expense (c) (14,155 ) 1,417 — (12,738 ) Income (loss) before income taxes (62,631 ) (16,305 ) 244 (78,692 ) Income tax (expense) benefit 21,998 5,707 — 27,705 Net income (loss) $ (40,633 ) $ (10,598 ) $ 244 $ (50,987 ) Total assets $ 1,383,193 $ 52,363 $ (43,730 ) $ 1,391,826 Additions to property and equipment $ 105,742 $ 1,202 $ 244 $ 107,188 _______ (a) Includes impairment of property and equipment. (b) Includes the following expenses: production, exploration, midstream services, drilling rig services, accretion of ARO, general and administrative and other operating expenses. (c) Includes impairment of our investment in Dalea.

Guarantor Financial Informati36

Guarantor Financial Information (Tables)	9 Months Ended
	Sep. 30, 2016
Guarantor Financial Information Disclosure [Abstract]
Schedule of Condensed Consolidating Balance Sheet	The financial information which follows sets forth our condensed consolidating financial statements as of and for the periods indicated. Condensed Consolidating Balance Sheet September 30, 2016 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Current assets $ 333,198 $ 269,858 $ 1,014 $ (322,099 ) $ 281,971 Property and equipment, net 862,866 281,133 3,328 — 1,147,327 Investments in subsidiaries 296,918 — — (296,918 ) — Other assets 5,509 2,145 — — 7,654 Total assets $ 1,498,491 $ 553,136 $ 4,342 $ (619,017 ) $ 1,436,952 Current liabilities $ 298,879 $ 100,964 $ 63 $ (307,111 ) $ 92,795 Non-current liabilities: Long-term debt 846,507 — — — 846,507 Fair value of commodity derivatives 11,626 — — (10,136 ) 1,490 Fair value of common stock warrants 171,720 — — — 171,720 Deferred income taxes 47,758 117,051 (2,114 ) (110,670 ) 52,025 Other 45,039 44,296 300 — 89,635 1,122,650 161,347 (1,814 ) (120,806 ) 1,161,377 Equity 76,962 290,825 6,093 (191,100 ) 182,780 Total liabilities and equity $ 1,498,491 $ 553,136 $ 4,342 $ (619,017 ) $ 1,436,952 Condensed Consolidating Balance Sheet December 31, 2015 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary 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) Three Months Ended September 30, 2016 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Total revenue $ 41,983 $ 13,219 $ 236 $ — $ 55,438 Costs and expenses 48,308 19,867 276 — 68,451 Operating income (loss) (6,325 ) (6,648 ) (40 ) — (13,013 ) Other income (expense) (143,695 ) 236 192 — (143,267 ) Equity in earnings of subsidiaries (4,069 ) — — 4,069 — Income tax (expense) benefit 5,313 2,244 (53 ) — 7,504 Net income (loss) $ (148,776 ) $ (4,168 ) $ 99 $ 4,069 $ (148,776 ) Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Nine Months Ended September 30, 2016 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Total revenue $ 89,819 $ 37,442 $ 686 $ — $ 127,947 Costs and expenses 142,557 67,619 926 — 211,102 Operating income (loss) (52,738 ) (30,177 ) (240 ) — (83,155 ) Other income (expense) (233,664 ) (7,968 ) 590 — (241,042 ) Equity in earnings of subsidiaries (24,567 ) — — 24,567 — Income tax (expense) benefit 45,995 13,351 (123 ) — 59,223 Net income (loss) $ (264,974 ) $ (24,794 ) $ 227 $ 24,567 $ (264,974 ) Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Three Months Ended September 30, 2015 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Total revenue $ 39,500 $ 14,765 $ 316 $ — $ 54,581 Costs and expenses 52,630 21,133 557 — 74,320 Operating income (loss) (13,130 ) (6,368 ) (241 ) — (19,739 ) Other income (expense) 4,912 53 312 — 5,277 Equity in earnings of subsidiaries (4,059 ) — — 4,059 — Income tax (expense) benefit 2,854 2,210 (25 ) — 5,039 Net income (loss) $ (9,423 ) $ (4,105 ) $ 46 $ 4,059 $ (9,423 ) Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Nine Months Ended September 30, 2015 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Total revenue $ 140,902 $ 49,906 $ 1,146 $ — $ 191,954 Costs and expenses 177,041 64,042 1,850 — 242,933 Operating income (loss) (36,139 ) (14,136 ) (704 ) — (50,979 ) Other income (expense) (28,720 ) (488 ) 1,495 — (27,713 ) Equity in earnings of subsidiaries (8,991 ) — — 8,991 — Income tax (expense) benefit 22,863 5,118 (276 ) — 27,705 Net income (loss) $ (50,987 ) $ (9,506 ) $ 515 $ 8,991 $ (50,987 ) Condensed Consolidating Statement of Cash Flows Nine Months Ended September 30, 2016 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Operating activities $ (3,780 ) $ 12,090 $ (344 ) $ — $ 7,966 Investing activities (67,166 ) (6,955 ) (19 ) — (74,140 ) Financing activities 246,040 (4,608 ) (45 ) — 241,387 Net increase (decrease) in cash and cash equivalents 175,094 527 (408 ) — 175,213 Cash at beginning of period 4,663 1,855 1,262 — 7,780 Cash at end of period $ 179,757 $ 2,382 $ 854 $ — $ 182,993 Condensed Consolidating Statement of Cash Flows Nine Months Ended September 30, 2015 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Operating activities $ 44,249 $ 9,330 $ 978 $ 439 $ 54,996 Investing activities (101,921 ) (16,741 ) (169 ) (439 ) (119,270 ) Financing activities 41,674 3,631 (305 ) — 45,000 Net increase (decrease) in cash and cash equivalents (15,998 ) (3,780 ) 504 — (19,274 ) Cash at beginning of period 21,217 6,693 106 — 28,016 Cash at end of period $ 5,219 $ 2,913 $ 610 $ — $ 8,742
Schedule of Condensed Consolidating Statement of Cash Flows	Condensed Consolidating Statement of Cash Flows Nine Months Ended September 30, 2016 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Operating activities $ (3,780 ) $ 12,090 $ (344 ) $ — $ 7,966 Investing activities (67,166 ) (6,955 ) (19 ) — (74,140 ) Financing activities 246,040 (4,608 ) (45 ) — 241,387 Net increase (decrease) in cash and cash equivalents 175,094 527 (408 ) — 175,213 Cash at beginning of period 4,663 1,855 1,262 — 7,780 Cash at end of period $ 179,757 $ 2,382 $ 854 $ — $ 182,993 Condensed Consolidating Statement of Cash Flows Nine Months Ended September 30, 2015 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Operating activities $ 44,249 $ 9,330 $ 978 $ 439 $ 54,996 Investing activities (101,921 ) (16,741 ) (169 ) (439 ) (119,270 ) Financing activities 41,674 3,631 (305 ) — 45,000 Net increase (decrease) in cash and cash equivalents (15,998 ) (3,780 ) 504 — (19,274 ) Cash at beginning of period 21,217 6,693 106 — 28,016 Cash at end of period $ 5,219 $ 2,913 $ 610 $ — $ 8,742

Nature of Operations (Details)

Nature of Operations (Details)	Sep. 30, 2016
Nature of Operations Disclosures [Abstract]
Percentage of outstanding common stock beneficially owned by Mr.William's	17.80%
Percentage of outstanding common stock owned by a partnership in which Mr. William's adult children are limited partners	17.40%

Presentation (Details)

Presentation (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Dec. 31, 2017	Dec. 31, 2015
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
The percentage of consolidated total assets and total revenues derived from oil and gas partnerships is less than	5.00%
Other Noncurrent Assets | 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]
Cumulated effect adjustment to reclassify 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)	1 Months Ended	3 Months Ended		9 Months Ended
	Mar. 31, 2011USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)	Aug. 31, 2016USD ($)	Mar. 08, 2016USD ($)	Dec. 31, 2015USD ($)	Oct. 31, 2013USD ($)	Apr. 30, 2011USD ($)
Long-Term Debt
Long-term debt, excluding current maturities		$ 846,507,000		$ 846,507,000				$ 742,410,000
Gain on early extinguishment of long term debt		3,967,000	$ 0	3,967,000	$ 0
7.75% Senior Notes due 2019
Long-Term Debt
Long term debt, gross		500,000,000		500,000,000				600,000,000
Unamortized original issue discount		(159,000)		(159,000)				(241,000)		$ (500,000)
Debt issuance costs		(4,852,000)		(4,852,000)				(7,349,000)
Long-term debt, excluding current maturities		$ 494,989,000		$ 494,989,000				$ 592,410,000
Interest rate (as a percent)	7.75%	7.75%		7.75%				7.75%
Aggregate principal amount of notes issued	$ 300,000,000								$ 250,000,000	$ 50,000,000
Original issue discount (as a percent)										1.00%
Amount of debt redeemed						$ 100,000,000
Discount on debt extinguishment				$ 5,000,000
Write off of debt issuance costs				$ 1,000,000
Minimum ratio of EBITDA to consolidated interest expense	2.25
Maximum borrowing capacity	$ 500,000,000
Maximum borrowing capacity, percent of adjusted consolidated net tangible assets	0.3
7.75% Senior Notes due 2019 | On or after April 1, 2017
Long-Term Debt
Redemption price of debt instrument (as a percent)				100.00%
Term Loan Credit Facility
Long-Term Debt
Long term debt, gross		$ 350,000,000		$ 350,000,000				$ 0
Paid in-kind interest		27,196,000		27,196,000				0
Unamortized original issue discount		(15,583,000)		(15,583,000)			$ (16,800,000)	0
Debt issuance costs		(10,095,000)		(10,095,000)				0
Long-term debt, excluding current maturities		351,518,000		351,518,000				0
Revolving credit facility, due April 2019
Long-Term Debt
Long-term debt, excluding current maturities		$ 0		$ 0				$ 150,000,000

Long-Term Debt Revolving Credit

Long-Term Debt Revolving Credit Facility (Details)	Mar. 08, 2016USD ($)	Sep. 30, 2016USD ($)Bankinstallment	Mar. 09, 2016USD ($)	Dec. 31, 2015	Mar. 31, 2011
Revolving Credit Facility
Long-Term Debt
Number of banks syndicated | Bank		16
Aggregate commitment amount	$ 450,000,000		$ 100,000,000
Commitment fee percentage	0.50%
Remaining borrowing capacity		$ 98,100,000
Letters of credit outstanding, amount		$ 1,900,000
Interest rate, effective percentage		2.50%
Revolving Credit Facility | Base rate
Long-Term Debt
Interest rate, stated percentage	0.75%
Revolving Credit Facility | Federal funds rate
Long-Term Debt
Basis spread on variable rate	0.50%
Revolving Credit Facility | One-month LIBOR
Long-Term Debt
Basis spread on variable rate	1.00%
Revolving Credit Facility | Maximum
Long-Term Debt
Higher borrowing capacity option	$ 150,000,000
Basis spread on variable rate additional spread	2.50%
Debt to EBITDAX ratio		2
Facility deficiency prepayment, number of equal periodic installments | installment		5
Revolving Credit Facility | Maximum | LIBOR
Long-Term Debt
Basis spread on variable rate	3.50%
Revolving Credit Facility | Minimum
Long-Term Debt
Higher borrowing capacity option, required reserves to debt ratio	1.2
Basis spread on variable rate additional spread	1.50%
Covenant current ratio	1
Collateral percentage of adjusted engineered value	90.00%
Revolving Credit Facility | Minimum | LIBOR
Long-Term Debt
Basis spread on variable rate	2.50%
7.75% Senior Notes due 2019
Long-Term Debt
Interest rate (as a percent)		7.75%		7.75%	7.75%

Long-Term Debt Term Loan Credit

Long-Term Debt Term Loan Credit Facility (Details) $ / shares in Units, $ in Thousands	Mar. 08, 2016USD ($)$ / sharesshares	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)	Jul. 22, 2016USD ($)$ / sharesshares	Dec. 31, 2015USD ($)
Long-Term Debt
Fair value of common stock warrants		$ 171,720		$ 171,720			$ 0
Fair value adjustments of warrants		123,351	$ 0	154,956	$ 0
Common Stock
Long-Term Debt
Number of securities called by warrants | shares	2,251,364
Exercise price of warrants | $ / shares	$ 22
Term Loan Credit Facility
Long-Term Debt
Long term debt, gross		350,000		350,000			0
Unamortized original issue discount	$ 16,800	15,583		15,583			$ 0
Proceeds from lines of credit	340,000
Fair value of common stock warrants	$ 16,800	$ 171,700		$ 171,700
Interset rate, stated percentage	12.50%
Interest rate, stated percentage, in-kind	15.00%
Shares of common stock issued (in shares) | shares						5,051,100
Cash proceeds						$ 150,000
Common stock, price per share (usd per share) | $ / shares						$ 29.70
Term Loan Credit Facility | Minimum
Long-Term Debt
Collateral percentage of adjusted engineered value	90.00%
Assets to secured debt coverage, ratio	1.2
Revolving Credit Facility
Long-Term Debt
Extinguishment of debt, amount	$ 160,000
Revolving Credit Facility | Minimum
Long-Term Debt
Collateral percentage of adjusted engineered value	90.00%

Sale of Assets (Details)

Sale of Assets (Details) - USD ($) $ in Millions	1 Months Ended							6 Months Ended
	Sep. 30, 2016	Jul. 31, 2016	Jun. 30, 2016	Apr. 30, 2016	Feb. 29, 2016	Sep. 30, 2015	Jun. 30, 2015	Jun. 30, 2015
Sale Of Assets [Line Items]
Proceeds from sale of interest in wells and related leasehold interest						$ 12
Glasscock County, TX
Sale Of Assets [Line Items]
Proceeds from sale of interest in wells and related leasehold interest		$ 19
Oklahoma
Sale Of Assets [Line Items]
Proceeds from sale of interest in wells and related leasehold interest			$ 1.5
Burleson County, TX
Sale Of Assets [Line Items]
Proceeds from sale of interest in wells and related leasehold interest	$ 1			$ 2	$ 0.8		$ 22.1
Sale of interest in wells, overriding royalty interest threshold, percent of net revenue							75.00%
Yoakum County, TX
Sale Of Assets [Line Items]
Proceeds from sale of interest in wells and related leasehold interest								$ 7.3

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Changes in asset retirement obligations
Beginning of period			$ 48,728	$ 45,697	$ 45,697
Additional ARO from new properties			40		469
Sales or abandonments of properties			(924)		(4,435)
Accretion expense	$ 1,290	$ 1,001	3,360	$ 2,936	3,945
Revisions of previous estimates			11,274		3,052
End of period	$ 62,478		$ 62,478		$ 48,728

Stockholders' Equity and Earn44

Stockholders' Equity and Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	3 Months Ended	9 Months Ended
	Aug. 31, 2016	Sep. 30, 2016	Sep. 30, 2016
Equity [Abstract]
Sale of common stock (in shares)	5,051,100
Sale of common stock	$ 150,000		$ 147,346
Sale of stock, price per share (usd per share)	$ 29.70
Offering expenses	$ 2,700
Shares excluded from computation of diluted earnings per share		152,000	152,000

Deferred Revenue from Volumet45

Deferred Revenue from Volumetric Production Payment (Details) $ in Thousands	1 Months Ended		9 Months Ended		12 Months Ended
	Aug. 31, 2015USD ($)MBoe	Mar. 31, 2012USD ($)MBoepartnership	Sep. 30, 2016USD ($)MBoe	Sep. 30, 2015USD ($)	Dec. 31, 2015USD ($)
Deferred Revenue Arrangement [Line Items]
Number of limited partnerships involved in mergers | partnership		24
Remaining obligation (in MBOE) | MBoe			0
Changes in deferred revenue from the VPP
Beginning of period			$ 5,470	$ 23,129	$ 23,129
Proceeds from volumetric production payment			0		2,866
Amortization of deferred revenue from volumetric production payment			(1,066)	(5,181)	(6,822)
Termination of volumetric production payment			0	$ (13,703)	(13,703)
End of period			$ 4,404		$ 5,470
Southwest Royalties, Inc. | Limited partnerships
Deferred Revenue Arrangement [Line Items]
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 MBOE) | MBoe		725
Volumetric production payment terminated during period (in MBOE) | MBoe	277
Changes in deferred revenue from the VPP
Termination of volumetric production payment	$ (13,700)

Non-Equity Award Plans (Details

Non-Equity Award Plans (Details) $ in Thousands	1 Months Ended	3 Months Ended		9 Months Ended
	Jan. 31, 2007well	Sep. 30, 2016USD ($)awardareashares	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)awardshares	Sep. 30, 2015USD ($)	Dec. 31, 2015USD ($)
Non-Equity Award Plans
Compensation expense recorded		$ (1,100)	$ (2,000)	$ 7,200	$ 6,600
Current liabilities:
Accrued liabilities and other		1,355		1,355		$ 1,251
Non-current liabilities:
Accrued compensation under non-equity award plans		22,585		22,585		16,254
Total accrued compensation under non-equity award plans		$ 23,940		$ 23,940		$ 17,505
Long Term Incentive Plan
Non-Equity Award Plans
Aggregate amount of shares on common stock (in shares) | shares		1,400,000		1,400,000
APO Incentive Plan | Minimum
Non-Equity Award Plans
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
Non-Equity Award Plans
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
Non-Equity Award Plans
Number of specified areas in which awards granted | area		15
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%
Number of awards with specified vesting date | award		15		15
APO Reward Plan | Minimum
Non-Equity Award Plans
Vesting period				2 years
APO Reward Plan | Maximum
Non-Equity Award Plans
Vesting period				5 years
SWR Reward Plan
Non-Equity Award Plans
Percentage of working interest in well	22.50%
Number of wells, working interest | well	1
SWR Reward Plan | Full vesting date, October 25, 2011
Non-Equity Award Plans
Percentage of subsequent quarterly bonus amounts after full vesting date payable to participants	100.00%

Compensation Plans Stock Option

Compensation Plans Stock Option Assumptions (Details)	9 Months Ended
	Sep. 30, 2016$ / shares
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Grant-date fair value	$ 63.80
Expected volatility	76.30%
Expected term (in years)	5 years
Risk-free rate	1.20%

Compensation Plans Stock Opti48

Compensation Plans Stock Option Activity (Details) - USD ($) $ / shares in Units, $ in Thousands	9 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Number of Shares
Shares outstanding at January 1, 2016	0
Granted (shares)	152,000
Exercised (shares)	0
Shares outstanding at September 30, 2016	152,000
Weighted Average Exercise Price
Granted (usd per share)	$ 63.80
Exercised (usd per share)	0
Outstanding (usd per share)	$ 63.80	$ 0
Vested and expected to vest at September 30, 2016 (shares)	152,000
Weighted average exercise price, vested and expected to vest (usd per share)	$ 63.80
Weighted average remaining term, vested and expected to vest	6 years 11 months
Aggregate intrinsic value, vested and expected to vest	$ 3,290
Exercisable at September 30, 2016 (shares)	0
Weighted average exercise price, exercisable (usd per share)	$ 0
Weighted average remaining term, exercisable	0 years
Aggregative intrinsic value, exercisable	$ 0

Compensation Plans Additional (

Compensation Plans Additional (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Employee Stock Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to granted stock options	$ 5,800,000		$ 5,800,000
Weighted average period of recognition			2 years 11 months
Vesting period			3 years
Stock based compensation	0	$ 0	$ 800,000	$ 0
Expiration period			7 years
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average period of recognition			2 years 7 months
Fair value of restricted stock shares granted			$ 17,400,000
Unrecognized compensation cost	16,700,000		16,700,000
Stock based compensation	$ 800,000	$ 0	$ 800,000	$ 0
Minimum | Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period			1 year
Maximum | Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period			3 years

Compensation Plans Restricted S

Compensation Plans Restricted Stock Activity (Details) - Restricted Stock Units (RSUs) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock based compensation	$ 800,000	$ 0	$ 800,000	$ 0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Shares unvested at January 1, 2016			0
Granted (shares)			272,850
Vested (shares)			0
Forfeited (shares)			0
Shares unvested at September 30, 2016	272,850		272,850
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Shares unvested, weighted average grant date fair value (usd per share)	$ 0		$ 0		$ 0
Shares granted, weighted average grant date fair value (usd per share)			63.69
Shares vested, weighted average grant date fair value (usd per share)			0
Shares forfeited, weighted average grant date fair value (usd per share)			$ 0

Net Positions In Open Commodity

Net Positions In Open Commodity Derivatives (Details)	Sep. 30, 2016MBbls$ / bbl
Crude Oil Costless Collar
Derivative [Line Items]
Notional amount	1,415
Crude Oil
Derivative [Line Items]
Notional amount	1,026
Crude Oil | Swap, Fourth Quarter
Derivative [Line Items]
Notional amount	619
Derivative price | $ / bbl	41.18
Crude Oil | Current Swap, 2017
Derivative [Line Items]
Notional amount	407
Derivative price | $ / bbl	45.58
Crude Oil | Costless Collar, 2017
Derivative [Line Items]
Notional amount	1,415
Floor price | $ / bbl	42.27
Ceiling price | $ / bbl	51.66

Accounting For Commodity Deriva

Accounting For Commodity Derivatives (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Effect of Derivative Instruments on the Consolidated Balance Sheets
Asset derivatives, fair value	$ 0	$ 0
Fair value of derivative liabilities, current	10,136	0
Fair value of derivative liabilities, noncurrent	1,490	0
Liability derivatives, fair value	11,626	0
Assets
Fair value of derivatives-gross presentation	0	0
Effects of netting arrangements	0	0
Asset derivatives, fair value	0	0
Liabilities
Fair value of derivatives-gross presentation	11,626	0
Effects of netting arrangements	0	0
Liability derivatives, fair value	11,626	0
Nondesignated | Commodity Derivatives
Effect of Derivative Instruments on the Consolidated Balance Sheets
Fair value of derivative assets, current	0	0
Fair value of derivatives	0	0
Asset derivatives, fair value	0	0
Fair value of derivative liabilities, current	10,136	0
Fair value of derivative liabilities, noncurrent	1,490	0
Liability derivatives, fair value	11,626	0
Assets
Asset derivatives, fair value	0	0
Liabilities
Liability derivatives, fair value	$ 11,626	$ 0

Derivatives Effect Of Commodity

Derivatives Effect Of Commodity Derivatives on Income Statement (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Derivative [Line Items]
Gain (loss) on commodity derivatives	$ 1,330	$ 18,099	$ (13,997)	$ 10,431
Nondesignated
Derivative [Line Items]
Gain (loss) on commodity derivatives	1,330	18,099	(13,997)	10,431
Nondesignated | Commodity Derivatives
Derivative [Line Items]
Gain (loss) on commodity derivatives	$ 1,330	$ 18,099	$ (13,997)	$ 10,431

Fair Value of Financial Instr54

Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Assets:
Fair value of commodity derivatives	$ 0	$ 0
Liabilities:
Fair value of commodity derivatives	11,626	0
Fair value of common stock warrants	171,720	0
Fair value of commodity derivatives	10,136	0
Fair value of commodity derivatives	1,490	0
Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Fair value of commodity derivatives	0	0
Total assets	0	0
Liabilities:
Fair value of commodity derivatives	11,626	0
Fair value of common stock warrants	171,720
Total liabilities	$ 183,346	$ 0

Fair Value of Other Financial I

Fair Value of Other Financial Instruments (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015	Mar. 31, 2011
7.75% Senior Notes due 2019
Fair Value of Other Financial Instruments
Interest rate (as a percent)	7.75%	7.75%	7.75%
Level 1 | Carrying Amount | 7.75% Senior Notes due 2019
Fair Value of Other Financial Instruments
Long-term debt	$ 494,989	$ 599,759
Level 1 | Estimated Fair Value | 7.75% Senior Notes due 2019
Fair Value of Other Financial Instruments
Long-term debt	481,250	462,750
Level 3 | Carrying Amount | Term Loan Credit Facility
Fair Value of Other Financial Instruments
Long-term debt	351,518	0
Level 3 | Estimated Fair Value | Term Loan Credit Facility
Fair Value of Other Financial Instruments
Long-term debt	$ 275,301	$ 0

Income Taxes (Details)

Income Taxes (Details)	9 Months Ended
	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Effective federal and state income tax expense rate (as a percent)	18.30%
Statutory federal rate (as a percent)	35.00%

Other Operating Revenues and 57

Other Operating Revenues and Expenses (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Other Operating Revenues [Abstract]
Gain on sales of assets	$ 10,430	$ 1,774	$ 10,699	$ 8,655
Marketing revenue	0	0	0	23
Total other operating revenues	10,430	1,774	10,699	8,678
Other Operating Expense [Abstract]
Loss on sales of assets	482	345	1,387	410
Marketing expense	50	445	333	660
Impairment of inventory	47	4,842	1,374	7,409
Total other operating expenses	$ 579	$ 5,632	$ 3,094	$ 8,479

Investment in Dalea Investmen58

Investment in Dalea Investment Group, LLC (Details) - USD ($)	1 Months Ended	3 Months Ended		9 Months Ended
	Jun. 30, 2012	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Investment in Dalea Investment Group, LLC
Impairment on investment		$ 0	$ 500,000	$ 8,400,000	$ 1,400,000
Dalea Investment Group, LLC
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

Costs of Oil and Gas Properti59

Costs of Oil and Gas Properties (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Oil and Gas Property, Successful Effort Method, Gross [Abstract]
Proved properties	$ 2,562,372	$ 2,539,480
Unproved properties	60,570	46,022
Total capitalized costs	2,622,942	2,585,502
Accumulated depletion	(1,546,087)	(1,460,404)
Net capitalized costs	$ 1,076,855	$ 1,125,098

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Millions	1 Months Ended		12 Months Ended
	Oct. 31, 2013USD ($)	Jul. 31, 2013defendantlawsuit	Dec. 31, 2013USD ($)	Nov. 30, 2013lawsuit
LOUISIANA
Loss Contingencies [Line Items]
Loss contingency, pending claims | lawsuit		3
BMT O&G TX, L.P.
Loss Contingencies [Line Items]
Loss contingency settlement amount | $	$ 2.9
Legal fees | $	$ 0.8
Loss related to litigation settlement | $			$ 1.4
Plaquemines Parish
Loss Contingencies [Line Items]
Loss contingency, pending claims | lawsuit				2
South Louisiana Flood Protection Authority-East
Loss Contingencies [Line Items]
Loss contingency, pending claims | lawsuit		1
Loss contingency, number of defendants | defendant		95

Impairment of Property and Eq61

Impairment of Property and Equipment (Details) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)method	Sep. 30, 2015USD ($)
Impaired Long-Lived Assets Held and Used [Line Items]
Number of methods to determine fair value of impaired property | method			3
Impairment of properties	$ 1,091	$ 3,089	$ 3,438	$ 5,620
Proved Properties | Non Core Properties
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of properties	1,100	3,100	3,400	5,600
Unproved Properties | Level 3
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of properties	$ 2,100	$ 300	$ 2,300	$ 2,700

Segment Information (Details)

Segment Information (Details) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)segment	Sep. 30, 2015USD ($)	Dec. 31, 2015USD ($)
Segment Reporting [Abstract]
Number of reportable operating segments | segment			2
Segment Information
Revenues	$ 55,438	$ 54,581	$ 127,947	$ 191,954
Depreciation, depletion and amortization	39,440	39,950	118,578	127,256
Other operating expenses	29,011	34,370	92,524	115,677
Interest expense	26,580	13,565	70,224	40,451
Other (income) expense	116,687	(18,842)	170,818	(12,738)
Loss before income taxes	(156,280)	(14,462)	(324,197)	(78,692)
Income tax (expense) benefit	7,504	5,039	59,223	27,705
NET LOSS	(148,776)	(9,423)	(264,974)	(50,987)
Total assets	1,436,952	1,391,826	1,436,952	1,391,826	$ 1,287,420
Additions to property and equipment	37,638	28,403	84,344	107,188
Operating Segments | Oil and Gas
Segment Information
Revenues	55,372	54,571	127,799	191,873
Depreciation, depletion and amortization	36,540	37,091	109,328	118,090
Other operating expenses	27,886	32,441	89,111	110,118
Interest expense	26,580	13,565	70,224	40,451
Other (income) expense	116,687	(19,337)	162,387	(14,155)
Loss before income taxes	(152,321)	(9,189)	(303,251)	(62,631)
Income tax (expense) benefit	6,118	3,215	51,892	21,998
NET LOSS	(146,203)	(5,974)	(251,359)	(40,633)
Total assets	1,459,652	1,383,193	1,459,652	1,383,193
Additions to property and equipment	34,627	28,005	81,292	105,742
Operating Segments | Contract Drilling
Segment Information
Revenues	66	1,606	148	2,328
Depreciation, depletion and amortization	2,900	3,196	9,250	9,606
Other operating expenses	1,125	3,126	3,413	7,610
Interest expense	0	0	0	0
Other (income) expense	0	495	8,431	1,417
Loss before income taxes	(3,959)	(5,211)	(20,946)	(16,305)
Income tax (expense) benefit	1,386	1,824	7,331	5,707
NET LOSS	(2,573)	(3,387)	(13,615)	(10,598)
Total assets	25,457	52,363	25,457	52,363
Additions to property and equipment	3,011	460	3,052	1,202
Intersegment Eliminations
Segment Information
Revenues	0	(1,596)	0	(2,247)
Depreciation, depletion and amortization	0	(337)	0	(440)
Other operating expenses	0	(1,197)	0	(2,051)
Interest expense	0	0	0	0
Other (income) expense	0	0	0	0
Loss before income taxes	0	(62)	0	244
Income tax (expense) benefit	0	0	0	0
NET LOSS	0	(62)	0	244
Total assets	(48,157)	(43,730)	(48,157)	(43,730)
Additions to property and equipment	$ 0	$ (62)	$ 0	$ 244

Guarantor Financial Informati63

Guarantor Financial Information Narrative (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	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	$ 3,967,000	$ 0
2019 Senior Notes
Performance and payment guaranteed
Aggregate principal amount of notes issued						$ 250,000,000	$ 50,000,000	$ 300,000,000
Amount of debt redeemed					$ 100,000,000
Discount on debt extinguishment			5,000,000
Write off of debt issuance costs			$ 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 Balance Sheet (Detail

Guarantor Balance Sheet (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Condensed consolidating financial statements
Current assets	$ 281,971	$ 68,805
Property and equipment, net	1,147,327	1,201,284
Investments in subsidiaries	0	0
Other assets	7,654	17,331
Total assets	1,436,952	1,287,420	$ 1,391,826
Current liabilities	92,795	65,739
Non-current liabilities:
Long-term debt	846,507	742,410
Fair value of commodity derivatives	1,490	0
Fair value of common stock warrants	171,720	0
Deferred income taxes	52,025	108,996
Other	89,635	70,677
TOTAL NON-CURRENT LIABILITIES	1,161,377	922,083
Equity	182,780	299,598
Total liabilities and equity	1,436,952	1,287,420
Adjustments/Eliminations
Condensed consolidating financial statements
Current assets	(322,099)	(317,807)
Property and equipment, net	0	0
Investments in subsidiaries	(296,918)	(324,484)
Other assets	0	0
Total assets	(619,017)	(642,291)
Current liabilities	(307,111)	(312,999)
Non-current liabilities:
Long-term debt	0	0
Fair value of commodity derivatives	(10,136)
Fair value of common stock warrants	0
Deferred income taxes	(110,670)	(110,626)
Other	0	0
TOTAL NON-CURRENT LIABILITIES	(120,806)	(110,626)
Equity	(191,100)	(218,666)
Total liabilities and equity	(619,017)	(642,291)
Issuer
Condensed consolidating financial statements
Current assets	333,198	112,861
Property and equipment, net	862,866	892,791
Investments in subsidiaries	296,918	324,484
Other assets	5,509	6,681
Total assets	1,498,491	1,336,817
Current liabilities	298,879	276,354
Non-current liabilities:
Long-term debt	846,507	742,410
Fair value of commodity derivatives	11,626
Fair value of common stock warrants	171,720
Deferred income taxes	47,758	90,387
Other	45,039	33,886
TOTAL NON-CURRENT LIABILITIES	1,122,650	866,683
Equity	76,962	193,780
Total liabilities and equity	1,498,491	1,336,817
Guarantor Subsidiaries
Condensed consolidating financial statements
Current assets	269,858	272,310
Property and equipment, net	281,133	304,936
Investments in subsidiaries	0	0
Other assets	2,145	10,650
Total assets	553,136	587,896
Current liabilities	100,964	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	117,051	130,471
Other	44,296	36,539
TOTAL NON-CURRENT LIABILITIES	161,347	167,010
Equity	290,825	318,619
Total liabilities and equity	553,136	587,896
Non-Guarantor Subsidiary
Condensed consolidating financial statements
Current assets	1,014	1,441
Property and equipment, net	3,328	3,557
Investments in subsidiaries	0	0
Other assets	0	0
Total assets	4,342	4,998
Current liabilities	63	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	(2,114)	(1,236)
Other	300	252
TOTAL NON-CURRENT LIABILITIES	(1,814)	(984)
Equity	6,093	5,865
Total liabilities and equity	$ 4,342	$ 4,998

Guarantor Statement of Operatio

Guarantor Statement of Operations (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Condensed consolidating financial statements
Total revenue	$ 55,438	$ 54,581	$ 127,947	$ 191,954
Costs and expenses	68,451	74,320	211,102	242,933
Operating loss	(13,013)	(19,739)	(83,155)	(50,979)
Other income (expense)	(143,267)	5,277	(241,042)	(27,713)
Equity in earnings of subsidiaries	0	0	0	0
Income tax benefit	7,504	5,039	59,223	27,705
NET LOSS	(148,776)	(9,423)	(264,974)	(50,987)
Adjustments/Eliminations
Condensed consolidating financial statements
Total revenue	0	0	0	0
Costs and expenses	0	0	0	0
Operating loss	0	0	0	0
Other income (expense)	0	0	0	0
Equity in earnings of subsidiaries	4,069	4,059	24,567	8,991
Income tax benefit	0	0	0	0
NET LOSS	4,069	4,059	24,567	8,991
Issuer
Condensed consolidating financial statements
Total revenue	41,983	39,500	89,819	140,902
Costs and expenses	48,308	52,630	142,557	177,041
Operating loss	(6,325)	(13,130)	(52,738)	(36,139)
Other income (expense)	(143,695)	4,912	(233,664)	(28,720)
Equity in earnings of subsidiaries	(4,069)	(4,059)	(24,567)	(8,991)
Income tax benefit	5,313	2,854	45,995	22,863
NET LOSS	(148,776)	(9,423)	(264,974)	(50,987)
Guarantor Subsidiaries
Condensed consolidating financial statements
Total revenue	13,219	14,765	37,442	49,906
Costs and expenses	19,867	21,133	67,619	64,042
Operating loss	(6,648)	(6,368)	(30,177)	(14,136)
Other income (expense)	236	53	(7,968)	(488)
Equity in earnings of subsidiaries	0	0	0	0
Income tax benefit	2,244	2,210	13,351	5,118
NET LOSS	(4,168)	(4,105)	(24,794)	(9,506)
Non-Guarantor Subsidiary
Condensed consolidating financial statements
Total revenue	236	316	686	1,146
Costs and expenses	276	557	926	1,850
Operating loss	(40)	(241)	(240)	(704)
Other income (expense)	192	312	590	1,495
Equity in earnings of subsidiaries	0	0	0	0
Income tax benefit	(53)	(25)	(123)	(276)
NET LOSS	$ 99	$ 46	$ 227	$ 515

Guarantor Statement of Cash Flo

Guarantor Statement of Cash Flows (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Condensed consolidating financial statements
Operating activities	$ 7,966	$ 54,996
Investing activities	(74,140)	(119,270)
Financing activities	241,387	45,000
Net increase (decrease) in cash and cash equivalents	175,213	(19,274)
Beginning of period	7,780	28,016
End of period	182,993	8,742
Adjustments/Eliminations
Condensed consolidating financial statements
Operating activities	0	439
Investing activities	0	(439)
Financing activities	0	0
Net increase (decrease) in cash and cash equivalents	0	0
Beginning of period	0	0
End of period	0	0
Issuer
Condensed consolidating financial statements
Operating activities	(3,780)	44,249
Investing activities	(67,166)	(101,921)
Financing activities	246,040	41,674
Net increase (decrease) in cash and cash equivalents	175,094	(15,998)
Beginning of period	4,663	21,217
End of period	179,757	5,219
Guarantor Subsidiaries
Condensed consolidating financial statements
Operating activities	12,090	9,330
Investing activities	(6,955)	(16,741)
Financing activities	(4,608)	3,631
Net increase (decrease) in cash and cash equivalents	527	(3,780)
Beginning of period	1,855	6,693
End of period	2,382	2,913
Non-Guarantor Subsidiary
Condensed consolidating financial statements
Operating activities	(344)	978
Investing activities	(19)	(169)
Financing activities	(45)	(305)
Net increase (decrease) in cash and cash equivalents	(408)	504
Beginning of period	1,262	106
End of period	$ 854	$ 610

Subsequent Events (Details)

Subsequent Events (Details) - USD ($) $ in Thousands	Oct. 24, 2016	Sep. 30, 2016	Sep. 30, 2015
Subsequent Event [Line Items]
Proceeds from sale of wells		$ 27,369	$ 47,484
Scenario, Forecast | Giddings Area, TX
Subsequent Event [Line Items]
Proceeds from sale of wells	$ 400,000