Clayton Williams Energy (CWEI) 10-Q 7 Aug 15 2015 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Aug. 03, 2015
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	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Jun. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding		12,169,536

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
CURRENT ASSETS
Cash and cash equivalents	$ 7,634	$ 28,016
Accounts receivable:
Oil and gas sales	25,262	36,526
Joint interest and other, net of allowance for doubtful accounts of $1,329 at June 30, 2015 and $1,204 December 31, 2014	4,802	14,550
Affiliates	307	322
Inventory	40,907	42,087
Deferred income taxes	9,389	6,911
Prepaids and other	3,655	4,208
TOTAL CURRENT ASSETS	91,956	132,620
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	2,733,183	2,684,913
Pipelines and other midstream facilities	59,795	59,542
Contract drilling equipment	123,415	122,751
Other	20,465	20,915
PROPERTY AND EQUIPMENT, GROSS	2,936,858	2,888,121
Less accumulated depreciation, depletion and amortization	(1,626,571)	(1,539,237)
Property and equipment, net	1,310,287	1,348,884
OTHER ASSETS
Debt issue costs, net	11,299	12,712
Investments and other	16,274	16,669
TOTAL OTHER ASSETS	27,573	29,381
TOTAL ASSETS	1,429,816	1,510,885
Accounts payable:
Trade	29,316	93,650
Oil and gas sales	32,233	41,328
Affiliates	159	717
Fair value of derivatives	5,901	0
Accrued liabilities and other	19,139	20,658
TOTAL CURRENT LIABILITIES	86,748	156,353
NON-CURRENT LIABILITIES
Long-term debt	746,728	704,696
Deferred income taxes	144,411	164,599
Asset retirement obligations	50,326	45,697
Deferred revenue from volumetric production payment	20,135	23,129
Accrued compensation under non-equity award plans	24,761	17,866
Other	477	751
TOTAL NON-CURRENT LIABILITIES	$ 986,838	$ 956,738
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock, par value $.10 per share, authorized — 3,000,000 shares; none issued	$ 0	$ 0
Common stock, par value $.10 per share, authorized — 30,000,000 shares; issued and outstanding — 12,169,536 shares at June 30, 2015 and December 31, 2014	1,216	1,216
Additional paid-in capital	152,686	152,686
Retained earnings	202,328	243,892
TOTAL STOCKHOLDERS' EQUITY	356,230	397,794
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 1,429,816	$ 1,510,885

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 1,329	$ 1,204
Preferred stock, par value (in dollars per share)	$ 0.10	$ 0.10
Preferred stock, authorized shares	3,000,000	3,000,000
Preferred stock, issued shares	0	0
Common stock, par value (in dollars per share)	$ 0.10	$ 0.10
Common stock, authorized shares	30,000,000	30,000,000
Common stock, issued shares	12,169,536	12,169,536
Common stock, outstanding shares	12,169,536	12,169,536

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
REVENUES
Oil and gas sales	$ 68,662	$ 113,303	$ 127,232	$ 223,889
Midstream services	1,603	1,837	3,214	3,453
Drilling rig services	0	8,493	23	15,372
Other operating revenues	2,966	6,262	6,904	11,786
Total revenues	73,231	129,895	137,373	254,500
COSTS AND EXPENSES
Production	23,093	24,632	46,523	51,079
Exploration:
Abandonments and impairments	2,508	2,887	4,131	6,726
Seismic and other	105	225	971	1,708
Midstream services	534	490	933	1,024
Drilling rig services	1,620	5,482	3,496	10,338
Depreciation, depletion and amortization	42,121	38,950	84,775	75,205
Impairment of property and equipment	0	0	2,531	3,406
Accretion of asset retirement obligations	977	901	1,935	1,787
General and administrative	11,328	21,351	20,471	33,169
Other operating expenses	2,003	238	2,847	740
Total costs and expenses	84,289	95,156	168,613	185,182
Operating income (loss)	(11,058)	34,739	(31,240)	69,318
OTHER INCOME (EXPENSE)
Interest expense	(13,609)	(12,845)	(26,886)	(25,366)
Loss on derivatives	(12,300)	(8,324)	(7,668)	(13,365)
Other	871	1,049	1,564	1,889
Total other income (expense)	(25,038)	(20,120)	(32,990)	(36,842)
Income (loss) before income taxes	(36,096)	14,619	(64,230)	32,476
Income tax (expense) benefit	12,764	(5,292)	22,666	(11,757)
NET INCOME (LOSS)	$ (23,332)	$ 9,327	$ (41,564)	$ 20,719
Net income (loss) per common share:
Basic (in dollars per share)	$ (1.92)	$ 0.77	$ (3.42)	$ 1.70
Diluted (in dollars per share)	$ (1.92)	$ 0.77	$ (3.42)	$ 1.70
Weighted average common shares outstanding:
Basic (in shares)	12,170	12,166	12,170	12,166
Diluted (in shares)	12,170	12,166	12,170	12,166

CONSOLIDATED STATEMENT OF STOCK

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY - 6 months ended Jun. 30, 2015 - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Additional Paid-In Capital	Retained Earnings
BEGINNING BALANCE at Dec. 31, 2014	$ 397,794	$ 1,216	$ 152,686	$ 243,892
BEGINNING BALANCE (in shares) at Dec. 31, 2014		12,170
Increase (Decrease) in Stockholders' Equity
Net loss	(41,564)			(41,564)
ENDING BALANCE at Jun. 30, 2015	$ 356,230	$ 1,216	$ 152,686	$ 202,328
ENDING BALANCE (in shares) at Jun. 30, 2015		12,170

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ (41,564)	$ 20,719
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	84,775	75,205
Impairment of property and equipment	2,531	3,406
Abandonments and impairments	4,131	6,726
Gain on sales of assets and impairment of inventory, net	(4,249)	(9,469)
Deferred income tax expense (benefit)	(22,666)	11,757
Non-cash employee compensation	7,084	16,374
Loss on derivatives	7,668	13,365
Cash settlements of derivatives	(1,767)	(4,591)
Accretion of asset retirement obligations	1,935	1,787
Amortization of debt issue costs and original issue discount	1,495	1,644
Amortization of deferred revenue from volumetric production payment	(3,501)	(3,957)
Other	404	0
Changes in operating working capital:
Accounts receivable	21,027	434
Accounts payable	(26,211)	(5,027)
Other	(2,472)	(3,306)
Net cash provided by operating activities	28,620	125,067
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(125,267)	(184,218)
Proceeds from volumetric production payment	507	552
Proceeds from sales of assets	32,740	73,773
Decrease in equipment inventory	1,027	11,523
Other	(9)	(133)
Net cash used in investing activities	(91,002)	(98,503)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	42,000	22,522
Repayments of long-term debt	0	(40,000)
Net cash provided by (used in) financing activities	42,000	(17,478)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(20,382)	9,086
CASH AND CASH EQUIVALENTS
Beginning of period	28,016	26,623
End of period	7,634	35,709
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	25,463	23,712
Cash paid for income taxes	$ 227	$ 1,600

Nature of Operations

Nature of Operations	6 Months Ended
	Jun. 30, 2015
Nature of Operations Disclosures [Abstract]
Nature of Operations	Nature of Operations Clayton Williams Energy, Inc., a Delaware corporation, is an independent oil and gas company engaged in the exploration for and development and production of oil and natural gas primarily in its core areas in Texas, Louisiana 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. Clayton W. Williams, Jr., our Chairman of the Board and Chief Executive Officer, beneficially owns, either individually or through his affiliates, 25.6% of the outstanding shares of our common stock. In addition, The Williams Children’s Partnership, Ltd. (“WCPL”), a limited partnership of which Mr. Williams’ adult children are the limited partners, owns an additional 25% of the outstanding shares of our common stock. Mel G. Riggs, our President, is the sole general partner of WCPL and has the power to vote or direct the voting of the shares held by WCPL. 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	6 Months Ended
	Jun. 30, 2015
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 interest 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 June 30, 2015 and for the three and six months ended June 30, 2015 and 2014 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, 2015 . 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, 2014 . Recent Accounting Pronouncements In July 2015, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“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,” that requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this Update. An entity is required to apply ASU 2015-03 for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years, with early adoption permitted. An entity should apply ASU 2015-03 on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. Upon transition, an entity is required to comply with the applicable disclosures for a change in an accounting principle. These disclosures include the nature of and reason for the change in accounting principle, the transition method, a description of the prior-period information that has been retrospectively adjusted, and the effect of the change on the financial statement line items (that is, debt issuance cost asset and the debt liability). We currently present debt issuance costs on the balance sheet as an asset. As of June 30, 2015 , we had $11.3 million of debt issuance costs, which under this standard would be reclassified from an asset to a direct deduction to the related debt liability. 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. An entity is required to apply ASU 2014-09 for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. 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	6 Months Ended
	Jun. 30, 2015
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Long-term debt consists of the following: June 30, December 31, (In thousands) 7.75% Senior Notes due 2019, net of unamortized original issue discount of $272 at June 30, 2015 and $304 at December 31, 2014 $ 599,728 $ 599,696 Revolving credit facility, due April 2019 (a) 147,000 105,000 $ 746,728 $ 704,696 _______ (a) Renewed and extended in April 2014. Senior Notes In March 2011, we issued $300 million of aggregate principal amount of 7.75% Senior Notes due 2019 (the “2019 Senior Notes”). The 2019 Senior Notes 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. We may redeem some or all of the 2019 Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 101.938% beginning on April 1, 2016 and 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 provides that we may only incur indebtedness if the ratio of consolidated EBITDAX to consolidated interest expense (as these terms are defined in the Indenture) exceeds 2.25 times. These covenants are subject to a number of important exceptions and qualifications as described in the Indenture. We were in compliance with these covenants at June 30, 2015 and December 31, 2014 . Revolving Credit Facility We borrow money under an amended and restated credit facility with a syndicate of 16 banks led by JPMorgan Chase Bank, N.A. The credit facility provides for a revolving line of credit of up to $1 billion , limited to the lesser of the borrowing base amount, as determined by the banks, and the aggregate lender commitments, as determined by us. The credit facility matures in April 2019 and is subject to an accelerated maturity date of October 1, 2018 unless our existing 2019 Senior Notes are refinanced or extended in accordance with the terms of the 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 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). Increases in aggregate lender commitments require the consent of each lender. The borrowing base under the credit facility was $600 million at December 31, 2014 and was decreased in February 2015 to $500 million . The aggregate lender commitment remained at $500 million . At June 30, 2015 , we had $147 million of borrowings outstanding on the credit facility, leaving $351.1 million available after allowing for outstanding letters of credit totaling $1.9 million . The credit facility is collateralized primarily by 80% or more of the adjusted engineered value (as defined in the credit facility) of our oil and gas interests evaluated in determining the borrowing base. The obligations under the credit facility are guaranteed by each of CWEI’s material domestic subsidiaries except for CWEI Andrews Properties, GP, LLC (see Note 17). At our election, annual interest rates under the credit facility are determined by reference to (1) LIBOR plus an applicable LIBOR margin or (2) if an alternate base rate loan, the greatest of (A) the prime rate , (B) the federal funds rate plus 0.50% , or (C) one-month LIBOR plus 1% , plus an applicable base rate margin. The LIBOR margin ranges between 1.75% and 2.75% per year (as amended in February 2015), and the base rate margin ranges between 0.75% and 1.75% per year (as amended in February 2015). We also pay a commitment fee on the unused portion of the credit facility at an applicable margin that ranges between 0.375% and 0.50% per year. Applicable margins are based on actual borrowings outstanding as a percentage of the borrowing base. Interest and fees are payable no less often than quarterly. The effective annual interest rate on borrowings under the credit facility, excluding bank fees and amortization of debt issue costs, for the six months ended June 30, 2015 was 2.1% . The 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 . Another financial covenant is a consolidated leverage ratio that limits our consolidated indebtedness to consolidated EBITDAX (determined as of the end of each fiscal quarter for the then most-recently ended four fiscal quarters) from being greater than 4 to 1. In February 2015, the credit facility was amended to temporarily replace the consolidated leverage ratio covenant with a consolidated senior debt leverage ratio covenant, which may be no greater than 2.5 times consolidated EBITDAX and to add a consolidated interest coverage ratio covenant of 1.5 times consolidated EBITDAX. These temporary amendments apply to each of the quarterly periods from January 1, 2015 through June 30, 2016. The computations of consolidated current assets, current liabilities, EBITDAX, indebtedness and interest are defined in the credit facility. We were in compliance with all financial and non-financial covenants at June 30, 2015 and December 31, 2014 .

Sales of Assets

Sales of Assets	6 Months Ended
	Jun. 30, 2015
Sale Of Assets [Abstract]
Sale of Assets	Sales of Assets In June 2015, we sold approximately 3,700 net acres in Burleson County, Texas (the “Acreage”) for cash consideration of $22.1 million . The Acreage, located east of our contiguous acreage block, was sold under a term assignment that terminates on October 27, 2015 unless the buyer commences a 90 -day continuous development program on the Acreage. We retained our rights to all depths and formations other than the Eagle Ford formation and also retained our interest in acreage and production associated with the Porter E Unit #1, our only Eagle Ford well situated on the Acreage. During the first half of 2015, we sold our interests in selected leases in Oklahoma and sold our interests in certain wells in Martin and Yoakum Counties, Texas for proceeds totaling $7.3 million . In March 2014, we closed a transaction to sell our interests in selected wells and leases in Wilson, Brazos, La Salle, Frio and Robertson Counties, Texas for $71 million , subject to customary closing adjustments. At closing, $6.8 million of the total proceeds was placed in escrow pending resolution of certain title requirements. As of May 2015, the title requirements have been satisfied and the remaining proceeds have been released. In February 2014, we sold a property in Ward County, Texas for $5.1 million , subject to customary closing adjustments. Net proceeds from each of these transactions were applied to reduce indebtedness outstanding under the revolving credit facility.

Asset Retirement Obligations

Asset Retirement Obligations	6 Months Ended
	Jun. 30, 2015
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 six months ended June 30, 2015 and the year ended December 31, 2014 : June 30, December 31, (In thousands) Beginning of period $ 45,697 $ 49,981 Additional ARO from new properties 293 1,209 Sales or abandonments of properties (670 ) (5,246 ) Accretion expense 1,935 3,662 Revisions of previous estimates 3,071 (3,909 ) End of period $ 50,326 $ 45,697

Deferred Revenue from Volumetri

Deferred Revenue from Volumetric Production Payment	6 Months Ended
	Jun. 30, 2015
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 are 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 have been delivered to the third party, the term overriding royalty interest will 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 has been accounted for as a sale of reserves, with the sales proceeds being deferred and amortized into oil and gas sales as the scheduled volumes are produced. The net proceeds from the VPP are recorded as a non-current liability in the consolidated balance sheets. Deferred revenue from the VPP will be amortized over the life of the VPP and will be recognized in oil and gas sales in the consolidated statements of operations and comprehensive income (loss). As of June 30, 2015 , we have a remaining obligation to deliver approximately 324 MBOE. The following table reflects the changes in the deferred revenue during the six months ended June 30, 2015 and the year ended December 31, 2014 : June 30, December 31, (In thousands) Beginning of period $ 23,129 $ 29,770 Deferred revenue from VPP 507 1,067 Amortization of deferred revenue from VPP (3,501 ) (7,708 ) End of period $ 20,135 $ 23,129

Compensation Plans

Compensation Plans	6 Months Ended
	Jun. 30, 2015
Compensation Plans [Abstract]
Compensation Plans	Compensation Plans 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 (“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 the APO Reward Plan are not included in the APO Incentive Plan. Likewise, wells included in the APO Incentive Plan are not included in the APO Reward Plan. Although conceptually similar to the APO Incentive Plan, the APO Reward Plan is a compensatory bonus plan through which we pay participants a bonus equal to a portion of the APO cash flows received by us from our working interest in wells in a specified area. Unlike the APO Incentive Plan, however, participants in the APO Reward Plan are not immediately vested in all future amounts payable under the plan. To date, we have granted awards under the APO Reward Plan in 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. Of these 15 awards, 10 awards are fully vested, two awards fully vested on August 1, 2015 and three awards will fully vest on June 23, 2016. In January 2007, we granted awards under the Southwest Royalties Reward Plan (the “SWR Reward Plan”), a one-time incentive plan which established a quarterly bonus amount for participants equal to the APO cash flow from a 22.5% working interest in one well. The plan is fully vested and 100% of subsequent quarterly bonus amounts are payable to participants. To continue as a participant in the APO Reward Plan or the SWR Reward Plan, participants must remain in the employment or service of the Company through the full vesting date established for each award. The full vesting date may be accelerated in the event of a change of control or sale transaction, as defined in the plan documents. We recognize compensation expense related to the APO Partnerships based on the estimated value of economic interests conveyed to the participants. Estimated compensation expense applicable to the APO Reward Plan and 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 June 30, 2015 and 2014 and six months ended June 30, 2015 and 2014 were $6.5 million and $13.5 million , $8.6 million and $18.2 million , respectively. Accrued compensation under non-equity award plans is reflected in the accompanying consolidated balance sheets as detailed in the following schedule: June 30, December 31, (In thousands) Current liabilities: Accrued liabilities and other $ 2,503 $ 2,317 Non-current liabilities: Accrued compensation under non-equity award plans 24,761 17,866 Total accrued compensation under non-equity award plans $ 27,264 $ 20,183

Derivatives

Derivatives	6 Months Ended
	Jun. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	Derivatives Commodity Derivatives From time to time, we utilize commodity derivatives in the form of swap contracts to attempt to optimize the price received for our oil and gas production. Under swap contracts, 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. 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 June 30, 2015 . The settlement prices of commodity derivatives are based on NYMEX futures prices. Swaps Oil MBbls Price Production Period: 3rd Quarter 2015 697 $ 55.65 4th Quarter 2015 592 $ 55.65 1,289 We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of our commodity derivatives. As of June 30, 2015 , a $1 per barrel change in the price of oil would change the fair value of our commodity derivatives by approximately $1.3 million . Accounting For Derivatives We did not designate any of our currently open 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, are recorded as other income (expense) in our consolidated statements of operations and comprehensive income (loss). Effect of Derivative Instruments on the Consolidated Balance Sheets Fair Value of Derivative Instruments as of June 30, 2015 Asset Derivatives Liability Derivatives Balance Sheet Balance Sheet Location Fair Value Location Fair Value (In thousands) (In thousands) Derivatives not designated as hedging instruments: Commodity derivatives Fair value of derivatives: Fair value of derivatives: Current $ — Current $ 5,901 Non-current — Non-current — Total $ — $ 5,901 Fair Value of Derivative Instruments as of December 31, 2014 Asset Derivatives Liability Derivatives Balance Sheet Balance Sheet Location Fair Value Location Fair Value (In thousands) (In thousands) Derivatives not designated as hedging instruments: Commodity derivatives Fair value of derivatives: Fair value of derivatives: Current $ — Current $ — Non-current — Non-current — Total $ — $ — Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities June 30, 2015 Assets Liabilities (In thousands) Fair value of derivatives — gross presentation $ — $ 5,901 Effects of netting arrangements — — Fair value of derivatives — net presentation $ — $ 5,901 December 31, 2014 Assets Liabilities (In thousands) Fair value of derivatives — gross presentation $ — $ — Effects of netting arrangements — — Fair value of derivatives — net presentation $ — $ — Our derivative contracts are with JPMorgan Chase Bank, N.A. We have elected to net the outstanding positions with this counterparty between current and non-current assets or liabilities since we have the right to settle these positions on a net basis. Effect of Derivative Instruments Recognized in Earnings on the Consolidated Statements of Operations and Comprehensive Income (Loss) Amount of Gain or (Loss) Recognized in Earnings Three Months Ended Six Months Ended June 30, June 30, Location of Gain or (Loss) Recognized in Earnings 2015 2014 2015 2014 (In thousands) (In thousands) Derivatives not designated as hedging instruments: Commodity derivatives: Other income (expense) - Loss on derivatives $ (12,300 ) $ (8,324 ) $ (7,668 ) $ (13,365 ) Total $ (12,300 ) $ (8,324 ) $ (7,668 ) $ (13,365 )

Fair Value of Financial Instrum

Fair Value of Financial Instruments	6 Months Ended
	Jun. 30, 2015
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 our revolving credit facility was estimated to have a fair value approximating the carrying amount since the interest rate is generally market sensitive. Fair Value Measurements We follow a framework for measuring fair value, which outlines a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements. Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued. We categorize our assets and liabilities recorded at fair value in the accompanying consolidated balance sheets based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities, are as follows: Level 1 - Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date. Level 2 - Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life. Level 3 - Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model. The financial assets and liabilities measured on a recurring basis at June 30, 2015 and December 31, 2014 were commodity derivatives. The fair value of all derivative contracts is reflected on the consolidated balance sheet as detailed in the following schedule: June 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 $ 5,901 $ — Total liabilities $ 5,901 $ — Fair Value of Other Financial Instruments We estimate the fair value of our 2019 Senior Notes using quoted market prices (Level 1 inputs). Fair value is compared to the carrying value in the table below: June 30, 2015 December 31, 2014 Carrying Estimated Carrying Estimated Description Amount Fair Value Amount Fair Value (In thousands) 7.75% Senior Notes due 2019 $ 599,728 $ 572,300 $ 599,696 $ 510,000

Income Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2015
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Our effective federal and state income tax rate for the six months ended June 30, 2015 of 35.3% differed from the statutory federal rate of 35% due primarily to 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. We file federal income tax returns with the United States Internal Revenue Service and state income tax returns in various state tax jurisdictions. Our tax returns for fiscal years after 2011 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	6 Months Ended
	Jun. 30, 2015
Other Operating Revenues [Abstract]
Other Operating Revenues and Expenses	Other Operating Revenues and Expenses Other operating revenues and expenses for the three and six months ended June 30, 2015 and June 30, 2014 are as follows: Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 (In thousands) (In thousands) Other operating revenues: Gain on sales of assets $ 2,966 $ 5,067 $ 6,881 $ 10,209 Marketing revenue — 1,195 23 1,577 Total other operating revenues $ 2,966 $ 6,262 $ 6,904 $ 11,786 Other operating expenses: Loss on sales of assets $ 4 $ 238 $ 65 $ 730 Marketing expense 215 — 215 — Impairment of inventory 1,784 — 2,567 10 Total other operating expenses $ 2,003 $ 238 $ 2,847 $ 740 During the three months ended June 30, 2015, gain on sales of assets included 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 and the sale of leases in Oklahoma in May and June 2015. During the six months ended June 30, 2015, gain on sales of assets included the sale of selected wells in Martin and Yoakum Counties, Texas in March 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 and the sale of leases in Oklahoma in May and June 2015 (see Note 4). During the three months ended June 30, 2014, gain on sales of assets included a $4.9 million gain on sale of certain non-core Austin Chalk/Eagle Ford assets in March 2014. Most of the gain during the three months ended June 30, 2014 related to the release of sales proceeds previously held in escrow pending resolution of title requirements. During the six months ended June 30, 2014, gain on sales of assets included the sale of certain non-core Austin Chalk/Eagle Ford assets in March 2014 and the sale of a property in Ward County, Texas in February 2014 (see Note 4). We maintain an inventory of tubular goods and other well equipment for use in our exploration and development drilling activities. Inventory is carried at the lower of average cost or estimated fair market value. We categorize the measurement of fair value of inventory as Level 2 under applicable accounting standards. To determine estimated fair value of inventory, we subscribe to market surveys and obtain quotes from equipment dealers for similar equipment. We then correlate the data as needed to estimate the fair value of the specific items (or groups of similar items) in our inventory. If the estimated fair values for those specific items (or groups of similar items) in our inventory are less than the related average cost, a provision for impairment is made.

Investment in Dalea Investment

Investment in Dalea Investment Group, LLC	6 Months Ended
	Jun. 30, 2015
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 is carried at cost of $11 million . As of June 30, 2015 , we have performed a qualitative assessment based on the difference between the carrying value and the estimated fair value of our investment. We estimated the fair value of our investment by comparing our interest of the equity in Dalea to our carrying value at June 30, 2015 and December 31, 2014. In comparing the estimated fair value to our carrying value at June 30, 2015 , we recorded no impairment on our investment in Dalea for the three months ended June 30, 2015 , none for the three months ended June 30, 2014 , $0.9 million for the six months ended June 30, 2015 and none for the six months ended June 30, 2014 . 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	6 Months Ended
	Jun. 30, 2015
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 June 30, 2015 and December 31, 2014 . June 30, December 31, (In thousands) Proved properties $ 2,684,265 $ 2,585,279 Unproved properties 48,918 99,634 Total capitalized costs 2,733,183 2,684,913 Accumulated depletion (1,510,368 ) (1,430,699 ) Net capitalized costs $ 1,222,815 $ 1,254,214

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Legal Proceedings SWR is a defendant in a suit filed in April 2011 in the Circuit Court of Union County, Arkansas where the plaintiffs initially sought in excess of $8 million for the costs of environmental remediation to a lease on which operations were commenced in the 1930s. In June 2013, the plaintiffs, SWR and the remaining defendants agreed to a settlement of $0.8 million , of which SWR would pay $0.7 million . To accomplish the settlement, the case was converted to a class action, and each member of the class was offered the right to either participate or opt out of the class and continue a separate action for damages. One plaintiff opted out and will be subject to all previous rulings of the court, including an order dismissing certain claims on the basis that such claims were time barred. A loss on settlement of $0.7 million was recorded for the year ended December 31, 2013 in connection with this proposed settlement. The settlement was entered by the Court on December 19, 2014, and all settlement funds were paid to plaintiffs’ counsel in January 2015. The case against the single plaintiff will continue in 2015. 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. CWEI expects Plaintiffs to appeal the Court of Appeals’ decision to the Texas Supreme Court. 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. All parties have filed their initial briefs with the Fifth Circuit. The Court has not yet scheduled oral argument. 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 and have since been remanded in 2015 back to the state court. Our overall exposure to these three 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 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	6 Months Ended
	Jun. 30, 2015
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 no provision for impairment of proved properties for the three months ended June 30, 2015 and none for the three months ended June 30, 2014 . We recorded a provision for impairment of proved properties of $2.5 million for the six months ended June 30, 2015 and $3.4 million for the six months ended June 30, 2014 . The provision for the six months ended June 30, 2015 was related to the write-down of certain non-core properties located in Louisiana to their estimated fair value. The provision for the six months ended June 30, 2014 was related to the write-down of certain non-operated properties located in North Dakota 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 aggregating $2.3 million for the three months ended June 30, 2015 , $1.5 million for the three months ended June 30, 2014 , $2.5 million for the six months ended June 30, 2015 and $5 million for the six months ended June 30, 2014 , and charged these impairments to abandonments and impairments in the accompanying consolidated statements of operations and comprehensive income (loss).

Segment Information

Segment Information	6 Months Ended
	Jun. 30, 2015
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 six months ended June 30, 2015 and 2014 : For the Three Months Ended June 30, 2015 (Unaudited) Contract Intercompany Consolidated (In thousands) Oil and Gas Drilling Eliminations Total Revenues $ 73,222 $ 42 $ (33 ) $ 73,231 Depreciation, depletion and amortization (a) 38,923 3,206 (8 ) 42,121 Other operating expenses (b) 40,476 1,696 (4 ) 42,168 Interest expense 13,609 — — 13,609 Other (income) expense 11,429 — — 11,429 Income (loss) before income taxes (31,215 ) (4,860 ) (21 ) (36,096 ) Income tax (expense) benefit 11,063 1,701 — 12,764 Net income (loss) $ (20,152 ) $ (3,159 ) $ (21 ) $ (23,332 ) Total assets $ 1,416,665 $ 56,476 $ (43,325 ) $ 1,429,816 Additions to property and equipment $ 23,226 $ 106 $ (21 ) $ 23,311 For the Six Months Ended June 30, 2015 (Unaudited) Contract Intercompany Consolidated (In thousands) Oil and Gas Drilling Eliminations Total Revenues $ 137,302 $ 722 $ (651 ) $ 137,373 Depreciation, depletion and amortization (a) 80,999 6,410 (103 ) 87,306 Other operating expenses (b) 77,677 4,484 (854 ) 81,307 Interest expense 26,886 — — 26,886 Other (income) expense 5,182 922 — 6,104 Income (loss) before income taxes (53,442 ) (11,094 ) 306 (64,230 ) Income tax (expense) benefit 18,783 3,883 — 22,666 Net income (loss) $ (34,659 ) $ (7,211 ) $ 306 $ (41,564 ) Total assets $ 1,416,665 $ 56,476 $ (43,325 ) $ 1,429,816 Additions to property and equipment $ 77,737 $ 742 $ 306 $ 78,785 For the Three Months Ended June 30, 2014 (Unaudited) Contract Intercompany Consolidated (In thousands) Oil and Gas Drilling Eliminations Total Revenues $ 121,403 $ 15,242 $ (6,750 ) $ 129,895 Depreciation, depletion and amortization (a) 36,333 3,420 (803 ) 38,950 Other operating expenses (b) 50,603 11,014 (5,411 ) 56,206 Interest expense 12,845 — — 12,845 Other (income) expense 7,275 — — 7,275 Income (loss) before income taxes 14,347 808 (536 ) 14,619 Income tax (expense) benefit (5,009 ) (283 ) — (5,292 ) Net income (loss) $ 9,338 $ 525 $ (536 ) $ 9,327 Total assets $ 1,374,443 $ 62,231 $ (33,779 ) $ 1,402,895 Additions to property and equipment $ 92,587 $ 5,209 $ (536 ) $ 97,260 For the Six Months Ended June 30, 2014 (Unaudited) Contract Intercompany Consolidated (In thousands) Oil and Gas Drilling Eliminations Total Revenues $ 239,123 $ 28,662 $ (13,285 ) $ 254,500 Depreciation, depletion and amortization (a) 73,715 6,588 (1,692 ) 78,611 Other operating expenses (b) 96,050 20,928 (10,407 ) 106,571 Interest expense 25,366 — — 25,366 Other (income) expense 11,476 — — 11,476 Income (loss) before income taxes 32,516 1,146 (1,186 ) 32,476 Income tax (expense) benefit (11,356 ) (401 ) — (11,757 ) Net income (loss) $ 21,160 $ 745 $ (1,186 ) $ 20,719 Total assets $ 1,374,443 $ 62,231 $ (33,779 ) $ 1,402,895 Additions to property and equipment $ 177,779 $ 12,866 $ (1,186 ) $ 189,459 _______ (a) Includes impairment of property and equipment. (b) Includes the following expenses: production, exploration, midstream services, drilling rig services, accretion of ARO, G&A and other operating expenses.

Guarantor Financial Information

Guarantor Financial Information	6 Months Ended
	Jun. 30, 2015
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 an additional $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 same indenture (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 17. The financial information which follows sets forth our condensed consolidating financial statements as of and for the periods indicated. Condensed Consolidating Balance Sheet June 30, 2015 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Current assets $ 125,831 $ 294,425 $ 1,415 $ (329,715 ) $ 91,956 Property and equipment, net 961,590 330,584 18,113 — 1,310,287 Investments in subsidiaries 352,344 — — (352,344 ) — Other assets 15,172 12,401 — — 27,573 Total assets $ 1,454,937 $ 637,410 $ 19,528 $ (682,059 ) $ 1,429,816 Current liabilities $ 296,739 $ 108,948 $ 185 $ (319,124 ) $ 86,748 Non-current liabilities: Long-term debt 746,728 — — — 746,728 Deferred income taxes 116,647 139,694 4,479 (116,409 ) 144,411 Other 44,411 51,044 244 — 95,699 907,786 190,738 4,723 (116,409 ) 986,838 Equity 250,412 337,724 14,620 (246,526 ) 356,230 Total liabilities and equity $ 1,454,937 $ 637,410 $ 19,528 $ (682,059 ) $ 1,429,816 Condensed Consolidating Balance Sheet December 31, 2014 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Current assets $ 153,373 $ 293,613 $ 546 $ (314,912 ) $ 132,620 Property and equipment, net 986,110 344,174 18,600 — 1,348,884 Investments in subsidiaries 359,777 — — (359,777 ) — Other assets 16,077 13,304 — — 29,381 Total assets $ 1,515,337 $ 651,091 $ 19,146 $ (674,689 ) $ 1,510,885 Current liabilities $ 352,889 $ 113,746 $ 586 $ (310,868 ) $ 156,353 Non-current liabilities: Long-term debt 704,696 — — — 704,696 Deferred income taxes 129,105 141,130 4,227 (109,863 ) 164,599 Other 36,671 50,591 181 — 87,443 870,472 191,721 4,408 (109,863 ) 956,738 Equity 291,976 345,624 14,152 (253,958 ) 397,794 Total liabilities and equity $ 1,515,337 $ 651,091 $ 19,146 $ (674,689 ) $ 1,510,885 Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Three Months Ended June 30, 2015 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Total revenue $ 55,714 $ 17,099 $ 418 $ — $ 73,231 Costs and expenses 63,390 20,234 665 — 84,289 Operating income (loss) (7,676 ) (3,135 ) (247 ) — (11,058 ) Other income (expense) (24,605 ) (720 ) 287 — (25,038 ) Equity in earnings of subsidiaries (2,480 ) — — 2,480 — Income tax (expense) benefit 11,429 1,349 (14 ) — 12,764 Net income (loss) $ (23,332 ) $ (2,506 ) $ 26 $ 2,480 $ (23,332 ) Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Six Months Ended June 30, 2015 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Total revenue $ 101,402 $ 35,141 $ 830 $ — $ 137,373 Costs and expenses 124,411 42,909 1,293 — 168,613 Operating income (loss) (23,009 ) (7,768 ) (463 ) — (31,240 ) Other income (expense) (33,632 ) (541 ) 1,183 — (32,990 ) Equity in earnings of subsidiaries (4,933 ) — — 4,933 — Income tax (expense) benefit 20,010 2,908 (252 ) — 22,666 Net income (loss) $ (41,564 ) $ (5,401 ) $ 468 $ 4,933 $ (41,564 ) Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Three Months Ended June 30, 2014 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Total revenue $ 92,114 $ 36,801 $ 980 $ — $ 129,895 Costs and expenses 70,368 24,216 572 — 95,156 Operating income (loss) 21,746 12,585 408 — 34,739 Other income (expense) (20,719 ) 244 355 — (20,120 ) Equity in earnings of subsidiaries 8,835 — — (8,835 ) — Income tax (expense) benefit (535 ) (4,490 ) (267 ) — (5,292 ) Net income (loss) $ 9,327 $ 8,339 $ 496 $ (8,835 ) $ 9,327 Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Six Months Ended June 30, 2014 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Total revenue $ 174,082 $ 78,615 $ 1,803 $ — $ 254,500 Costs and expenses 129,761 54,342 1,079 — 185,182 Operating income (loss) 44,321 24,273 724 — 69,318 Other income (expense) (37,991 ) 479 670 — (36,842 ) Equity in earnings of subsidiaries 16,995 — — (16,995 ) — Income tax (expense) benefit (2,606 ) (8,663 ) (488 ) — (11,757 ) Net income (loss) $ 20,719 $ 16,089 $ 906 $ (16,995 ) $ 20,719 Condensed Consolidating Statement of Cash Flows Six Months Ended June 30, 2015 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Operating activities $ 19,608 $ 7,395 $ 1,514 $ 103 $ 28,620 Investing activities (88,774 ) (1,955 ) (170 ) (103 ) (91,002 ) Financing activities 50,952 (8,632 ) (320 ) — 42,000 Net increase (decrease) in cash and cash equivalents (18,214 ) (3,192 ) 1,024 — (20,382 ) Cash at beginning of period 21,217 6,693 106 — 28,016 Cash at end of period $ 3,003 $ 3,501 $ 1,130 $ — $ 7,634 Condensed Consolidating Statement of Cash Flows Six Months Ended June 30, 2014 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Operating activities $ 78,858 $ 41,052 $ 3,465 $ 1,692 $ 125,067 Investing activities (76,913 ) (16,460 ) (3,438 ) (1,692 ) (98,503 ) Financing activities 9,985 (27,486 ) 23 — (17,478 ) Net increase (decrease) in cash and cash equivalents 11,930 (2,894 ) 50 — 9,086 Cash at beginning of period 19,693 6,886 44 — 26,623 Cash at end of period $ 31,623 $ 3,992 $ 94 $ — $ 35,709

Subsequent Events

Subsequent Events	6 Months Ended
	Jun. 30, 2015
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events We have evaluated events and transactions that occurred after the balance sheet date of June 30, 2015 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)	6 Months Ended
	Jun. 30, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Recent Accounting Pronouncements	In July 2015, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“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,” that requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this Update. An entity is required to apply ASU 2015-03 for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years, with early adoption permitted. An entity should apply ASU 2015-03 on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. Upon transition, an entity is required to comply with the applicable disclosures for a change in an accounting principle. These disclosures include the nature of and reason for the change in accounting principle, the transition method, a description of the prior-period information that has been retrospectively adjusted, and the effect of the change on the financial statement line items (that is, debt issuance cost asset and the debt liability). We currently present debt issuance costs on the balance sheet as an asset. As of June 30, 2015 , we had $11.3 million of debt issuance costs, which under this standard would be reclassified from an asset to a direct deduction to the related debt liability. 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. An entity is required to apply ASU 2014-09 for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. 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 (Tables)

Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2015
Debt Disclosure [Abstract]
Schedule of long-term debt	Long-term debt consists of the following: June 30, December 31, (In thousands) 7.75% Senior Notes due 2019, net of unamortized original issue discount of $272 at June 30, 2015 and $304 at December 31, 2014 $ 599,728 $ 599,696 Revolving credit facility, due April 2019 (a) 147,000 105,000 $ 746,728 $ 704,696 _______ (a) Renewed and extended in April 2014.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	6 Months Ended
	Jun. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
Schedule of changes in asset retirement obligations	The following table reflects the changes in ARO during the six months ended June 30, 2015 and the year ended December 31, 2014 : June 30, December 31, (In thousands) Beginning of period $ 45,697 $ 49,981 Additional ARO from new properties 293 1,209 Sales or abandonments of properties (670 ) (5,246 ) Accretion expense 1,935 3,662 Revisions of previous estimates 3,071 (3,909 ) End of period $ 50,326 $ 45,697

Deferred Revenue from Volumet28

Deferred Revenue from Volumetric Production Payment (Tables)	6 Months Ended
	Jun. 30, 2015
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 six months ended June 30, 2015 and the year ended December 31, 2014 : June 30, December 31, (In thousands) Beginning of period $ 23,129 $ 29,770 Deferred revenue from VPP 507 1,067 Amortization of deferred revenue from VPP (3,501 ) (7,708 ) End of period $ 20,135 $ 23,129

Compensation Plans (Tables)

Compensation Plans (Tables)	6 Months Ended
	Jun. 30, 2015
Compensation Plans [Abstract]
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: June 30, December 31, (In thousands) Current liabilities: Accrued liabilities and other $ 2,503 $ 2,317 Non-current liabilities: Accrued compensation under non-equity award plans 24,761 17,866 Total accrued compensation under non-equity award plans $ 27,264 $ 20,183

Derivatives (Tables)

Derivatives (Tables)	6 Months Ended
	Jun. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of information concerning the entity's net positions in open commodity derivatives	The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to June 30, 2015 . The settlement prices of commodity derivatives are based on NYMEX futures prices. Swaps Oil MBbls Price Production Period: 3rd Quarter 2015 697 $ 55.65 4th Quarter 2015 592 $ 55.65 1,289
Schedule of effect of derivative instruments on the consolidated balance sheet	Effect of Derivative Instruments on the Consolidated Balance Sheets Fair Value of Derivative Instruments as of June 30, 2015 Asset Derivatives Liability Derivatives Balance Sheet Balance Sheet Location Fair Value Location Fair Value (In thousands) (In thousands) Derivatives not designated as hedging instruments: Commodity derivatives Fair value of derivatives: Fair value of derivatives: Current $ — Current $ 5,901 Non-current — Non-current — Total $ — $ 5,901 Fair Value of Derivative Instruments as of December 31, 2014 Asset Derivatives Liability Derivatives Balance Sheet Balance Sheet Location Fair Value Location Fair Value (In thousands) (In thousands) Derivatives not designated as hedging instruments: Commodity derivatives Fair value of derivatives: Fair value of 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 Derivative Assets and Liabilities June 30, 2015 Assets Liabilities (In thousands) Fair value of derivatives — gross presentation $ — $ 5,901 Effects of netting arrangements — — Fair value of derivatives — net presentation $ — $ 5,901 December 31, 2014 Assets Liabilities (In thousands) Fair value of derivatives — gross presentation $ — $ — Effects of netting arrangements — — Fair value of derivatives — net presentation $ — $ —
Schedule of effect of derivative instruments on the consolidated statement of operations and Comprehensive Income (Loss)	Effect of Derivative Instruments Recognized in Earnings on the Consolidated Statements of Operations and Comprehensive Income (Loss) Amount of Gain or (Loss) Recognized in Earnings Three Months Ended Six Months Ended June 30, June 30, Location of Gain or (Loss) Recognized in Earnings 2015 2014 2015 2014 (In thousands) (In thousands) Derivatives not designated as hedging instruments: Commodity derivatives: Other income (expense) - Loss on derivatives $ (12,300 ) $ (8,324 ) $ (7,668 ) $ (13,365 ) Total $ (12,300 ) $ (8,324 ) $ (7,668 ) $ (13,365 )

Fair Value of Financial Instr31

Fair Value of Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2015
Fair Value Disclosures [Abstract]
Schedule of financial assets and liabilities measured on a recurring basis	The fair value of all derivative contracts is reflected on the consolidated balance sheet as detailed in the following schedule: June 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 $ 5,901 $ — Total liabilities $ 5,901 $ —
Schedule of comparison of fair value to the carrying value of the 2019 Senior Notes	Fair value is compared to the carrying value in the table below: June 30, 2015 December 31, 2014 Carrying Estimated Carrying Estimated Description Amount Fair Value Amount Fair Value (In thousands) 7.75% Senior Notes due 2019 $ 599,728 $ 572,300 $ 599,696 $ 510,000

Other Operating Revenues and 32

Other Operating Revenues and Expenses (Tables)	6 Months Ended
	Jun. 30, 2015
Other Operating Revenues [Abstract]
Schedule of other operating revenues and expenses	Other operating revenues and expenses for the three and six months ended June 30, 2015 and June 30, 2014 are as follows: Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 (In thousands) (In thousands) Other operating revenues: Gain on sales of assets $ 2,966 $ 5,067 $ 6,881 $ 10,209 Marketing revenue — 1,195 23 1,577 Total other operating revenues $ 2,966 $ 6,262 $ 6,904 $ 11,786 Other operating expenses: Loss on sales of assets $ 4 $ 238 $ 65 $ 730 Marketing expense 215 — 215 — Impairment of inventory 1,784 — 2,567 10 Total other operating expenses $ 2,003 $ 238 $ 2,847 $ 740

Costs of Oil and Gas Properti33

Costs of Oil and Gas Properties (Tables)	6 Months Ended
	Jun. 30, 2015
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 June 30, 2015 and December 31, 2014 . June 30, December 31, (In thousands) Proved properties $ 2,684,265 $ 2,585,279 Unproved properties 48,918 99,634 Total capitalized costs 2,733,183 2,684,913 Accumulated depletion (1,510,368 ) (1,430,699 ) Net capitalized costs $ 1,222,815 $ 1,254,214

Segment Information (Tables)

Segment Information (Tables)	6 Months Ended
	Jun. 30, 2015
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 six months ended June 30, 2015 and 2014 : For the Three Months Ended June 30, 2015 (Unaudited) Contract Intercompany Consolidated (In thousands) Oil and Gas Drilling Eliminations Total Revenues $ 73,222 $ 42 $ (33 ) $ 73,231 Depreciation, depletion and amortization (a) 38,923 3,206 (8 ) 42,121 Other operating expenses (b) 40,476 1,696 (4 ) 42,168 Interest expense 13,609 — — 13,609 Other (income) expense 11,429 — — 11,429 Income (loss) before income taxes (31,215 ) (4,860 ) (21 ) (36,096 ) Income tax (expense) benefit 11,063 1,701 — 12,764 Net income (loss) $ (20,152 ) $ (3,159 ) $ (21 ) $ (23,332 ) Total assets $ 1,416,665 $ 56,476 $ (43,325 ) $ 1,429,816 Additions to property and equipment $ 23,226 $ 106 $ (21 ) $ 23,311 For the Six Months Ended June 30, 2015 (Unaudited) Contract Intercompany Consolidated (In thousands) Oil and Gas Drilling Eliminations Total Revenues $ 137,302 $ 722 $ (651 ) $ 137,373 Depreciation, depletion and amortization (a) 80,999 6,410 (103 ) 87,306 Other operating expenses (b) 77,677 4,484 (854 ) 81,307 Interest expense 26,886 — — 26,886 Other (income) expense 5,182 922 — 6,104 Income (loss) before income taxes (53,442 ) (11,094 ) 306 (64,230 ) Income tax (expense) benefit 18,783 3,883 — 22,666 Net income (loss) $ (34,659 ) $ (7,211 ) $ 306 $ (41,564 ) Total assets $ 1,416,665 $ 56,476 $ (43,325 ) $ 1,429,816 Additions to property and equipment $ 77,737 $ 742 $ 306 $ 78,785 For the Three Months Ended June 30, 2014 (Unaudited) Contract Intercompany Consolidated (In thousands) Oil and Gas Drilling Eliminations Total Revenues $ 121,403 $ 15,242 $ (6,750 ) $ 129,895 Depreciation, depletion and amortization (a) 36,333 3,420 (803 ) 38,950 Other operating expenses (b) 50,603 11,014 (5,411 ) 56,206 Interest expense 12,845 — — 12,845 Other (income) expense 7,275 — — 7,275 Income (loss) before income taxes 14,347 808 (536 ) 14,619 Income tax (expense) benefit (5,009 ) (283 ) — (5,292 ) Net income (loss) $ 9,338 $ 525 $ (536 ) $ 9,327 Total assets $ 1,374,443 $ 62,231 $ (33,779 ) $ 1,402,895 Additions to property and equipment $ 92,587 $ 5,209 $ (536 ) $ 97,260 For the Six Months Ended June 30, 2014 (Unaudited) Contract Intercompany Consolidated (In thousands) Oil and Gas Drilling Eliminations Total Revenues $ 239,123 $ 28,662 $ (13,285 ) $ 254,500 Depreciation, depletion and amortization (a) 73,715 6,588 (1,692 ) 78,611 Other operating expenses (b) 96,050 20,928 (10,407 ) 106,571 Interest expense 25,366 — — 25,366 Other (income) expense 11,476 — — 11,476 Income (loss) before income taxes 32,516 1,146 (1,186 ) 32,476 Income tax (expense) benefit (11,356 ) (401 ) — (11,757 ) Net income (loss) $ 21,160 $ 745 $ (1,186 ) $ 20,719 Total assets $ 1,374,443 $ 62,231 $ (33,779 ) $ 1,402,895 Additions to property and equipment $ 177,779 $ 12,866 $ (1,186 ) $ 189,459 _______ (a) Includes impairment of property and equipment. (b) Includes the following expenses: production, exploration, midstream services, drilling rig services, accretion of ARO, G&A and other operating expenses.

Guarantor Financial Informati35

Guarantor Financial Information (Tables)	6 Months Ended
	Jun. 30, 2015
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 June 30, 2015 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Current assets $ 125,831 $ 294,425 $ 1,415 $ (329,715 ) $ 91,956 Property and equipment, net 961,590 330,584 18,113 — 1,310,287 Investments in subsidiaries 352,344 — — (352,344 ) — Other assets 15,172 12,401 — — 27,573 Total assets $ 1,454,937 $ 637,410 $ 19,528 $ (682,059 ) $ 1,429,816 Current liabilities $ 296,739 $ 108,948 $ 185 $ (319,124 ) $ 86,748 Non-current liabilities: Long-term debt 746,728 — — — 746,728 Deferred income taxes 116,647 139,694 4,479 (116,409 ) 144,411 Other 44,411 51,044 244 — 95,699 907,786 190,738 4,723 (116,409 ) 986,838 Equity 250,412 337,724 14,620 (246,526 ) 356,230 Total liabilities and equity $ 1,454,937 $ 637,410 $ 19,528 $ (682,059 ) $ 1,429,816 Condensed Consolidating Balance Sheet December 31, 2014 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Current assets $ 153,373 $ 293,613 $ 546 $ (314,912 ) $ 132,620 Property and equipment, net 986,110 344,174 18,600 — 1,348,884 Investments in subsidiaries 359,777 — — (359,777 ) — Other assets 16,077 13,304 — — 29,381 Total assets $ 1,515,337 $ 651,091 $ 19,146 $ (674,689 ) $ 1,510,885 Current liabilities $ 352,889 $ 113,746 $ 586 $ (310,868 ) $ 156,353 Non-current liabilities: Long-term debt 704,696 — — — 704,696 Deferred income taxes 129,105 141,130 4,227 (109,863 ) 164,599 Other 36,671 50,591 181 — 87,443 870,472 191,721 4,408 (109,863 ) 956,738 Equity 291,976 345,624 14,152 (253,958 ) 397,794 Total liabilities and equity $ 1,515,337 $ 651,091 $ 19,146 $ (674,689 ) $ 1,510,885
Schedule of Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)	Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Three Months Ended June 30, 2015 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Total revenue $ 55,714 $ 17,099 $ 418 $ — $ 73,231 Costs and expenses 63,390 20,234 665 — 84,289 Operating income (loss) (7,676 ) (3,135 ) (247 ) — (11,058 ) Other income (expense) (24,605 ) (720 ) 287 — (25,038 ) Equity in earnings of subsidiaries (2,480 ) — — 2,480 — Income tax (expense) benefit 11,429 1,349 (14 ) — 12,764 Net income (loss) $ (23,332 ) $ (2,506 ) $ 26 $ 2,480 $ (23,332 ) Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Six Months Ended June 30, 2015 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Total revenue $ 101,402 $ 35,141 $ 830 $ — $ 137,373 Costs and expenses 124,411 42,909 1,293 — 168,613 Operating income (loss) (23,009 ) (7,768 ) (463 ) — (31,240 ) Other income (expense) (33,632 ) (541 ) 1,183 — (32,990 ) Equity in earnings of subsidiaries (4,933 ) — — 4,933 — Income tax (expense) benefit 20,010 2,908 (252 ) — 22,666 Net income (loss) $ (41,564 ) $ (5,401 ) $ 468 $ 4,933 $ (41,564 ) Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Three Months Ended June 30, 2014 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Total revenue $ 92,114 $ 36,801 $ 980 $ — $ 129,895 Costs and expenses 70,368 24,216 572 — 95,156 Operating income (loss) 21,746 12,585 408 — 34,739 Other income (expense) (20,719 ) 244 355 — (20,120 ) Equity in earnings of subsidiaries 8,835 — — (8,835 ) — Income tax (expense) benefit (535 ) (4,490 ) (267 ) — (5,292 ) Net income (loss) $ 9,327 $ 8,339 $ 496 $ (8,835 ) $ 9,327 Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Six Months Ended June 30, 2014 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Total revenue $ 174,082 $ 78,615 $ 1,803 $ — $ 254,500 Costs and expenses 129,761 54,342 1,079 — 185,182 Operating income (loss) 44,321 24,273 724 — 69,318 Other income (expense) (37,991 ) 479 670 — (36,842 ) Equity in earnings of subsidiaries 16,995 — — (16,995 ) — Income tax (expense) benefit (2,606 ) (8,663 ) (488 ) — (11,757 ) Net income (loss) $ 20,719 $ 16,089 $ 906 $ (16,995 ) $ 20,719
Schedule of Condensed Consolidating Statement of Cash Flows	Condensed Consolidating Statement of Cash Flows Six Months Ended June 30, 2015 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Operating activities $ 19,608 $ 7,395 $ 1,514 $ 103 $ 28,620 Investing activities (88,774 ) (1,955 ) (170 ) (103 ) (91,002 ) Financing activities 50,952 (8,632 ) (320 ) — 42,000 Net increase (decrease) in cash and cash equivalents (18,214 ) (3,192 ) 1,024 — (20,382 ) Cash at beginning of period 21,217 6,693 106 — 28,016 Cash at end of period $ 3,003 $ 3,501 $ 1,130 $ — $ 7,634 Condensed Consolidating Statement of Cash Flows Six Months Ended June 30, 2014 (Unaudited) (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Operating activities $ 78,858 $ 41,052 $ 3,465 $ 1,692 $ 125,067 Investing activities (76,913 ) (16,460 ) (3,438 ) (1,692 ) (98,503 ) Financing activities 9,985 (27,486 ) 23 — (17,478 ) Net increase (decrease) in cash and cash equivalents 11,930 (2,894 ) 50 — 9,086 Cash at beginning of period 19,693 6,886 44 — 26,623 Cash at end of period $ 31,623 $ 3,992 $ 94 $ — $ 35,709

Nature of Operations (Details)

Nature of Operations (Details)	6 Months Ended
	Jun. 30, 2015
Nature of Operations Disclosures [Abstract]
Percentage of outstanding common stock beneficially owned by Mr.William's	25.60%
Percentage of outstanding common stock owned by a partnership in which Mr. William's adult children are limited partners	25.00%

Presentation (Details)

Presentation (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
The percentage of consolidated total assets and total revenues derived from oil and gas partnerships is less than	5.00%
Debt issue costs, net	$ 11,299	$ 12,712

Long-Term Debt (Details)

Long-Term Debt (Details)	1 Months Ended			6 Months Ended
	Feb. 28, 2015USD ($)	Apr. 30, 2014installment	Apr. 30, 2011USD ($)	Jun. 30, 2015USD ($)BankQuarter	Dec. 31, 2014USD ($)	Oct. 31, 2013USD ($)	Mar. 31, 2011USD ($)
Long-Term Debt
Long-term debt				$ 746,728,000	$ 704,696,000
7.75% Senior Notes due 2019
Long-Term Debt
Long-term debt				$ 599,728,000	$ 599,696,000
Aggregate principal amount of notes issued			$ 50,000,000			$ 250,000,000	$ 300,000,000
Interest rate (as a percent)				7.75%	7.75%		7.75%
Original issue discount (as a percent)			1.00%
Unamortized original issue discount			$ 500,000	$ 272,000	$ 304,000
Minimum ratio of EBITDA to consolidated interest expense				2.25
7.75% Senior Notes due 2019 | Beginning on April 1, 2016
Long-Term Debt
Redemption price of debt instrument (as a percent)				101.938%
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%
Revolving credit facility, due November 2015
Long-Term Debt
Long-term debt				$ 147,000,000	105,000,000
Number of banks syndicated to provide for line of credit | Bank				16
Maximum borrowing capacity				$ 1,000,000,000	$ 600,000,000
Borrowing base	$ 500,000,000
Aggregate commitment amount	$ 500,000,000
Amount available under the revolving credit facility				351,100,000
Outstanding letters of credit				$ 1,900,000
Effective annual interest rate (as a percent)				2.10%
Number of consecutive quarters for which ratio of consolidated funded indebtedness to consolidated EBITDAX is required to be maintained | Quarter				4
Revolving credit facility, due November 2015 | Minimum
Long-Term Debt
Percentage of adjusted engineered value of oil and gas interests serving as collateral				80.00%
Commitment fee on unused portion (as a percent)				0.375%
Current ratio				1
Covenant, senior debt to EBITDAX, ratio	2.5
Covenant, interest to EBITDAX, ratio	1.5
Revolving credit facility, due November 2015 | Maximum
Long-Term Debt
Number of equal monthly installments to prepay the deficiency | installment		5
Commitment fee on unused portion (as a percent)				0.50%
Consolidated funded indebtedness to consolidated EBITDAX ratio				4
Revolving credit facility, due November 2015 | LIBOR
Long-Term Debt
Variable rate basis				LIBOR
Revolving credit facility, due November 2015 | LIBOR | Minimum
Long-Term Debt
Applicable margin (as a percent)				1.75%
Revolving credit facility, due November 2015 | LIBOR | Maximum
Long-Term Debt
Applicable margin (as a percent)				2.75%
Revolving credit facility, due November 2015 | Prime rate
Long-Term Debt
Variable rate basis				prime rate
Revolving credit facility, due November 2015 | Federal funds rate
Long-Term Debt
Variable rate basis				federal funds rate
Applicable margin (as a percent)				0.50%
Revolving credit facility, due November 2015 | Base rate | Minimum
Long-Term Debt
Applicable margin (as a percent)				0.75%
Revolving credit facility, due November 2015 | Base rate | Maximum
Long-Term Debt
Applicable margin (as a percent)				1.75%
Revolving credit facility, due November 2015 | One-month LIBOR
Long-Term Debt
Variable rate basis				one-month LIBOR
Applicable margin (as a percent)				1.00%

Sale of Assets (Details)

Sale of Assets (Details) $ in Thousands	1 Months Ended			6 Months Ended
	Jun. 30, 2015USD ($)a	Mar. 31, 2014USD ($)	Feb. 28, 2014USD ($)	Jun. 30, 2015USD ($)a	Jun. 30, 2014USD ($)
Sale Of Assets [Line Items]
Proceeds from sale of interests				$ 32,740	$ 73,773
Escrow deposits related to property sales		$ 6,800
Wells and Related Equipment and Facilities
Sale Of Assets [Line Items]
Proceeds from sale of interest in wells and related leasehold interest		$ 71,000		$ 7,300
Proceeds from sale of property			$ 5,100
Burleson County, TX
Sale Of Assets [Line Items]
Area of leasehold in oil and gas properties | a	3,700			3,700
Proceeds from sale of interests	$ 22,100
Term assignment, period of continuous development program	90 days

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Changes in asset retirement obligations
Beginning of period			$ 45,697	$ 49,981	$ 49,981
Additional ARO from new properties			293		1,209
Sales or abandonments of properties			(670)		(5,246)
Accretion expense	$ 977	$ 901	1,935	$ 1,787	3,662
Revisions of previous estimates			3,071		(3,909)
End of period	$ 50,326		$ 50,326		$ 45,697

Deferred Revenue from Volumet41

Deferred Revenue from Volumetric Production Payment (Details) $ in Thousands	1 Months Ended	6 Months Ended		12 Months Ended
	Mar. 31, 2012USD ($)MBoepartnership	Jun. 30, 2015USD ($)MBoe	Jun. 30, 2014USD ($)	Dec. 31, 2014USD ($)
Deferred Revenue Arrangement [Line Items]
Number of limited partnerships involved in mergers | partnership	24
Remaining obligation (in MBOE) | MBoe		324
Changes in deferred revenue from the VPP
Beginning of period		$ 23,129	$ 29,770	$ 29,770
Deferred revenue from VPP		507		1,067
Amortization of deferred revenue from volumetric production payment		(3,501)	$ (3,957)	(7,708)
End of period		$ 20,135		$ 23,129
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

Compensation Plans (Details)

Compensation Plans (Details) $ in Thousands	1 Months Ended	3 Months Ended		6 Months Ended
	Jan. 31, 2007well	Jun. 30, 2015USD ($)award	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)areaaward	Jun. 30, 2014USD ($)	Dec. 31, 2014USD ($)
Non-Equity Award Plans
Compensation expense recorded | $		$ 6,500	$ 13,500	$ 8,600	$ 18,200
Current liabilities:
Accrued liabilities and other | $		2,503		2,503		$ 2,317
Non-current liabilities:
Accrued compensation under non-equity award plans | $		24,761		24,761		17,866
Total accrued compensation under non-equity award plans | $		$ 27,264		$ 27,264		$ 20,183
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		15		15
Number of award fully vested		10		10
APO Reward Plan | Full Vesting Date 1 August 2015 [Member]
Non-Equity Award Plans
Number of award expected to vest				2
APO Reward Plan | Full Vesting Date, June 23, 2016
Non-Equity Award Plans
Number of award expected to vest				3
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%

Derivatives (Details)

Derivatives (Details) - Jun. 30, 2015 - Commodity Derivatives $ in Millions	USD ($)MBbls$ / MBbls
Derivatives
Sensitivity analysis, impact of $1 per barrel change in derivative fair values | $	$ 1.3
Oil
Derivatives
Notional amount	1,289
Oil | Swap, Third Quarter
Derivatives
Notional amount	697
Fixed price | $ / MBbls	55.65
Oil | Swap, Fourth Quarter
Derivatives
Notional amount	592
Fixed price | $ / MBbls	55.65

Derivatives (Details 2)

Derivatives (Details 2) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Effect of Derivative Instruments on the Consolidated Balance Sheets
Asset Derivatives, Fair Value	$ 0	$ 0
Fair value of derivatives	5,901	0
Liability Derivatives, Fair Value	5,901	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	5,901	0
Effects of netting arrangements	0	0
Liability Derivatives, Fair Value	5,901	0
Commodity Derivatives | Nondesignated
Effect of Derivative Instruments on the Consolidated Balance Sheets
Fair value of derivative assets, current	0	0
Fair value of derivative assets, noncurrent	0	0
Asset Derivatives, Fair Value	0	0
Fair value of derivatives	5,901	0
Fair value of derivative liabilities, noncurrent	0	0
Liability Derivatives, Fair Value	5,901	0
Assets
Asset Derivatives, Fair Value	0	0
Liabilities
Liability Derivatives, Fair Value	$ 5,901	$ 0

Derivatives (Details 3)

Derivatives (Details 3) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Amount of Gain or (Loss) Recognized in Earnings
Loss on derivatives	$ (12,300)	$ (8,324)	$ (7,668)	$ (13,365)
Commodity Derivatives | Nondesignated
Amount of Gain or (Loss) Recognized in Earnings
Loss on derivatives	$ (12,300)	$ (8,324)	$ (7,668)	$ (13,365)

Fair Value of Financial Instr46

Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Assets:
Fair value of commodity derivatives	$ 0	$ 0
Liabilities:
Fair value of commodity derivatives	5,901	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	5,901	0
Total liabilities	$ 5,901	$ 0

Fair Value of Financial Instr47

Fair Value of Financial Instruments (Details 2) - 7.75% Senior Notes due 2019 - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014	Mar. 31, 2011
Fair Value of Other Financial Instruments
Interest rate (as a percent)	7.75%	7.75%	7.75%
Level 1 | Carrying Amount
Fair Value of Other Financial Instruments
Long-term debt	$ 599,728	$ 599,696
Level 1 | Estimated Fair Value
Fair Value of Other Financial Instruments
Long-term debt	$ 572,300	$ 510,000

Income Taxes (Details)

Income Taxes (Details)	6 Months Ended
	Jun. 30, 2015
Income Tax Disclosure [Abstract]
Effective federal and state income tax expense rate (as a percent)	35.30%
Statutory federal rate (as a percent)	35.00%

Other Operating Revenues and 49

Other Operating Revenues and Expenses (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Property, Plant and Equipment [Line Items]
Gain on sales of assets	$ 2,966	$ 5,067	$ 6,881	$ 10,209
Marketing revenue	0	1,195	23	1,577
Total other operating revenues	2,966	6,262	6,904	11,786
Other Operating Expense [Abstract]
Loss on sales of assets	4	238	65	730
Marketing expense	215	0	215	0
Impairment of inventory	1,784	0	2,567	10
Total other operating expenses	$ 2,003	238	$ 2,847	$ 740
Austin Chalk and Eagle Ford
Other Operating Expense [Abstract]
Proceeds from sale of property		$ 4,900

Investment in Dalea Investmen50

Investment in Dalea Investment Group, LLC (Details) - Dalea Investment Group, LLC - USD ($)	1 Months Ended	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Investment in Dalea Investment Group, LLC
Note receivable cancelled	$ 11,000,000
Non-controlling Membership interest (as a percent)	7.66%
Recorded investment		$ 11,000,000		$ 11,000,000
Cost-method investments, realized gain (loss)		$ 0	$ 0	$ 900,000	$ 0

Costs of Oil and Gas Properti51

Costs of Oil and Gas Properties (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Oil and Gas Property, Successful Effort Method, Gross [Abstract]
Proved properties	$ 2,684,265	$ 2,585,279
Unproved properties	48,918	99,634
Total capitalized costs	2,733,183	2,684,913
Accumulated depletion	(1,510,368)	(1,430,699)
Net capitalized costs	$ 1,222,815	$ 1,254,214

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Millions	1 Months Ended					12 Months Ended
	Nov. 30, 2013lawsuit	Oct. 31, 2013USD ($)	Jul. 31, 2013defendantlawsuit	Jun. 30, 2013USD ($)plaintiff	Apr. 30, 2011USD ($)	Dec. 31, 2013USD ($)
Loss Contingencies [Line Items]
Number of lawsuits | 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
SELFPA
Loss Contingencies [Line Items]
Number of lawsuits | lawsuit			1
Number of defendants | defendant			95
Plaquemines Parish
Loss Contingencies [Line Items]
Number of lawsuits | lawsuit	2
Environmental Remediation Case 2001
Loss Contingencies [Line Items]
Loss contingency, damages sought, value					$ 8
Loss contingency settlement amount				$ 0.8
Loss contingency, settlement amount paid				$ 0.7		$ 0.7
Loss contingency, number of plaintiffs opting out | plaintiff				1

Impairment of Property and Eq53

Impairment of Property and Equipment (Details) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)method	Jun. 30, 2014USD ($)
Property, Plant and Equipment Impairment or Disposal [Abstract]
Number of methods to determine fair value of impaired property | method			3
Impairment of proved property and equipment	$ 0	$ 0	$ 2,531	$ 3,406
Provisions for impairment of unproved properties	$ 2,300	$ 1,500	$ 2,500	$ 5,000

Segment Information (Details)

Segment Information (Details) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)segment	Jun. 30, 2014USD ($)	Dec. 31, 2014USD ($)
Segment Reporting [Abstract]
Number of reportable operating segments | segment			2
Segment Information
Revenues	$ 73,231	$ 129,895	$ 137,373	$ 254,500
Depreciation, depletion and amortization	42,121	38,950	87,306	78,611
Other operating expenses	42,168	56,206	81,307	106,571
Interest expense	13,609	12,845	26,886	25,366
Other (income) expense	11,429	7,275	6,104	11,476
Income (loss) before income taxes	(36,096)	14,619	(64,230)	32,476
Income tax (expense) benefit	12,764	(5,292)	22,666	(11,757)
Net income (loss)	(23,332)	9,327	(41,564)	20,719
Total assets	1,429,816	1,402,895	1,429,816	1,402,895	$ 1,510,885
Additions to property and equipment	23,311	97,260	78,785	189,459
Oil and Gas
Segment Information
Revenues	73,222	121,403	137,302	239,123
Depreciation, depletion and amortization	38,923	36,333	80,999	73,715
Other operating expenses	40,476	50,603	77,677	96,050
Interest expense	13,609	12,845	26,886	25,366
Other (income) expense	11,429	7,275	5,182	11,476
Income (loss) before income taxes	(31,215)	14,347	(53,442)	32,516
Income tax (expense) benefit	11,063	(5,009)	18,783	(11,356)
Net income (loss)	(20,152)	9,338	(34,659)	21,160
Total assets	1,416,665	1,374,443	1,416,665	1,374,443
Additions to property and equipment	23,226	92,587	77,737	177,779
Contract Drilling
Segment Information
Revenues	42	15,242	722	28,662
Depreciation, depletion and amortization	3,206	3,420	6,410	6,588
Other operating expenses	1,696	11,014	4,484	20,928
Interest expense	0	0	0	0
Other (income) expense	0	0	922	0
Income (loss) before income taxes	(4,860)	808	(11,094)	1,146
Income tax (expense) benefit	1,701	(283)	3,883	(401)
Net income (loss)	(3,159)	525	(7,211)	745
Total assets	56,476	62,231	56,476	62,231
Additions to property and equipment	106	5,209	742	12,866
Intercompany Eliminations
Segment Information
Revenues	(33)	(6,750)	(651)	(13,285)
Depreciation, depletion and amortization	(8)	(803)	(103)	(1,692)
Other operating expenses	(4)	(5,411)	(854)	(10,407)
Interest expense	0	0	0	0
Other (income) expense	0	0	0	0
Income (loss) before income taxes	(21)	(536)	306	(1,186)
Income tax (expense) benefit	0	0	0	0
Net income (loss)	(21)	(536)	306	(1,186)
Total assets	(43,325)	(33,779)	(43,325)	(33,779)
Additions to property and equipment	$ (21)	$ (536)	$ 306	$ (1,186)

Guarantor Financial Informati55

Guarantor Financial Information (Details) - 2019 Senior Notes - USD ($)	Oct. 31, 2013	Apr. 30, 2011	Mar. 31, 2011
Performance and payment guaranteed
Aggregate principal amount of notes issued	$ 250,000,000	$ 50,000,000	$ 300,000,000
Guarantor Subsidiaries | Guarantee on senior notes
Performance and payment guaranteed
Aggregate principal amount of notes issued	$ 250,000,000	$ 350,000,000

Guarantor Financial Informati56

Guarantor Financial Information (Details 2) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014
Condensed consolidating financial statements
Current assets	$ 91,956	$ 132,620
Property and equipment, net	1,310,287	1,348,884
Investments in subsidiaries	0	0
Other assets	27,573	29,381
TOTAL ASSETS	1,429,816	1,510,885	$ 1,402,895
Current liabilities	86,748	156,353
Non-current liabilities:
Long-term debt	746,728	704,696
Deferred income taxes	144,411	164,599
Other	95,699	87,443
Total non-current liabilities	986,838	956,738
Equity	356,230	397,794
Total liabilities and equity	1,429,816	1,510,885
Issuer
Condensed consolidating financial statements
Current assets	125,831	153,373
Property and equipment, net	961,590	986,110
Investments in subsidiaries	352,344	359,777
Other assets	15,172	16,077
TOTAL ASSETS	1,454,937	1,515,337
Current liabilities	296,739	352,889
Non-current liabilities:
Long-term debt	746,728	704,696
Deferred income taxes	116,647	129,105
Other	44,411	36,671
Total non-current liabilities	907,786	870,472
Equity	250,412	291,976
Total liabilities and equity	1,454,937	1,515,337
Guarantor Subsidiaries
Condensed consolidating financial statements
Current assets	294,425	293,613
Property and equipment, net	330,584	344,174
Investments in subsidiaries	0	0
Other assets	12,401	13,304
TOTAL ASSETS	637,410	651,091
Current liabilities	108,948	113,746
Non-current liabilities:
Long-term debt	0	0
Deferred income taxes	139,694	141,130
Other	51,044	50,591
Total non-current liabilities	190,738	191,721
Equity	337,724	345,624
Total liabilities and equity	637,410	651,091
Non-Guarantor Subsidiaries
Condensed consolidating financial statements
Current assets	1,415	546
Property and equipment, net	18,113	18,600
Investments in subsidiaries	0	0
Other assets	0	0
TOTAL ASSETS	19,528	19,146
Current liabilities	185	586
Non-current liabilities:
Long-term debt	0	0
Deferred income taxes	4,479	4,227
Other	244	181
Total non-current liabilities	4,723	4,408
Equity	14,620	14,152
Total liabilities and equity	19,528	19,146
Adjustments/Eliminations
Condensed consolidating financial statements
Current assets	(329,715)	(314,912)
Property and equipment, net	0	0
Investments in subsidiaries	(352,344)	(359,777)
Other assets	0	0
TOTAL ASSETS	(682,059)	(674,689)
Current liabilities	(319,124)	(310,868)
Non-current liabilities:
Long-term debt	0	0
Deferred income taxes	(116,409)	(109,863)
Other	0	0
Total non-current liabilities	(116,409)	(109,863)
Equity	(246,526)	(253,958)
Total liabilities and equity	$ (682,059)	$ (674,689)

Guarantor Financial Informati57

Guarantor Financial Information (Details 3) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Condensed consolidating financial statements
Total revenue	$ 73,231	$ 129,895	$ 137,373	$ 254,500
Costs and expenses	84,289	95,156	168,613	185,182
Operating income (loss)	(11,058)	34,739	(31,240)	69,318
Other income (expense)	(25,038)	(20,120)	(32,990)	(36,842)
Equity in earnings of subsidiaries	0	0	0	0
Income tax (expense) benefit	12,764	(5,292)	22,666	(11,757)
Net income (loss)	(23,332)	9,327	(41,564)	20,719
Issuer
Condensed consolidating financial statements
Total revenue	55,714	92,114	101,402	174,082
Costs and expenses	63,390	70,368	124,411	129,761
Operating income (loss)	(7,676)	21,746	(23,009)	44,321
Other income (expense)	(24,605)	(20,719)	(33,632)	(37,991)
Equity in earnings of subsidiaries	(2,480)	8,835	(4,933)	16,995
Income tax (expense) benefit	11,429	(535)	20,010	(2,606)
Net income (loss)	(23,332)	9,327	(41,564)	20,719
Guarantor Subsidiaries
Condensed consolidating financial statements
Total revenue	17,099	36,801	35,141	78,615
Costs and expenses	20,234	24,216	42,909	54,342
Operating income (loss)	(3,135)	12,585	(7,768)	24,273
Other income (expense)	(720)	244	(541)	479
Equity in earnings of subsidiaries	0	0	0	0
Income tax (expense) benefit	1,349	(4,490)	2,908	(8,663)
Net income (loss)	(2,506)	8,339	(5,401)	16,089
Non-Guarantor Subsidiaries
Condensed consolidating financial statements
Total revenue	418	980	830	1,803
Costs and expenses	665	572	1,293	1,079
Operating income (loss)	(247)	408	(463)	724
Other income (expense)	287	355	1,183	670
Equity in earnings of subsidiaries	0	0	0	0
Income tax (expense) benefit	(14)	(267)	(252)	(488)
Net income (loss)	26	496	468	906
Adjustments/Eliminations
Condensed consolidating financial statements
Total revenue	0	0	0	0
Costs and expenses	0	0	0	0
Operating income (loss)	0	0	0	0
Other income (expense)	0	0	0	0
Equity in earnings of subsidiaries	2,480	(8,835)	4,933	(16,995)
Income tax (expense) benefit	0	0	0	0
Net income (loss)	$ 2,480	$ (8,835)	$ 4,933	$ (16,995)

Guarantor Financial Informati58

Guarantor Financial Information (Details 4) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Condensed consolidating financial statements
Operating activities	$ 28,620	$ 125,067
Investing activities	(91,002)	(98,503)
Financing activities	42,000	(17,478)
Net increase (decrease) in cash and cash equivalents	(20,382)	9,086
Beginning of period	28,016	26,623
End of period	7,634	35,709
Issuer
Condensed consolidating financial statements
Operating activities	19,608	78,858
Investing activities	(88,774)	(76,913)
Financing activities	50,952	9,985
Net increase (decrease) in cash and cash equivalents	(18,214)	11,930
Beginning of period	21,217	19,693
End of period	3,003	31,623
Guarantor Subsidiaries
Condensed consolidating financial statements
Operating activities	7,395	41,052
Investing activities	(1,955)	(16,460)
Financing activities	(8,632)	(27,486)
Net increase (decrease) in cash and cash equivalents	(3,192)	(2,894)
Beginning of period	6,693	6,886
End of period	3,501	3,992
Non-Guarantor Subsidiaries
Condensed consolidating financial statements
Operating activities	1,514	3,465
Investing activities	(170)	(3,438)
Financing activities	(320)	23
Net increase (decrease) in cash and cash equivalents	1,024	50
Beginning of period	106	44
End of period	1,130	94
Adjustments/Eliminations
Condensed consolidating financial statements
Operating activities	103	1,692
Investing activities	(103)	(1,692)
Financing activities	0	0
Net increase (decrease) in cash and cash equivalents	0	0
Beginning of period	0	0
End of period	$ 0	$ 0