Clayton Williams Energy (CWEI) 10-K 11 Mar 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Mar. 07, 2014	Jun. 30, 2013
Document and Entity Information [Abstract]	'	'	'
Entity Registrant Name	'CLAYTON WILLIAMS ENERGY INC /DE	'	'
Entity Central Index Key	'0000880115	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Amendment Flag	'false	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Filer Category	'Accelerated Filer	'	'
Entity Public Float	'	'	$256,371,078
Entity Common Stock, Shares Outstanding	'	12,165,536	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
CURRENT ASSETS	'	'
Cash and cash equivalents	$26,623	$10,726
Accounts receivable:	'	'
Oil and gas sales	39,268	32,371
Joint interest and other, net of allowance for doubtful accounts of $1,184 at December 31, 2013 and $1,193 at December 31, 2012	17,121	16,767
Affiliates	264	353
Inventory	39,183	41,703
Deferred income taxes	7,581	8,560
Fair value of derivatives	2,518	7,495
Prepaids and other	5,753	6,495
TOTAL CURRENT ASSETS	138,311	124,470
PROPERTY AND EQUIPMENT	'	'
Oil and gas properties, successful efforts method	2,403,277	2,570,803
Pipelines and other midstream facilities	54,800	49,839
Contract drilling equipment	96,270	91,163
Other	20,620	20,245
PROPERTY AND EQUIPMENT, GROSS	2,574,967	2,732,050
Less accumulated depreciation, depletion and amortization	-1,375,860	-1,311,692
Property and equipment, net	1,199,107	1,420,358
OTHER ASSETS	'	'
Debt issue costs, net	12,785	10,259
Fair value of derivatives	0	4,236
Investments and other	16,534	15,261
TOTAL OTHER ASSETS	29,319	29,756
Total assets	1,366,737	1,574,584
Accounts payable:	'	'
Trade	75,872	73,026
Oil and gas sales	37,834	32,146
Affiliates	874	164
Fair value of derivatives	208	0
Accrued liabilities and other	21,607	15,578
TOTAL CURRENT LIABILITIES	136,395	120,914
NON-CURRENT LIABILITIES	'	'
Long-term debt	639,638	809,585
Deferred income taxes	140,809	155,830
Asset retirement obligations	49,981	51,477
Deferred revenue from volumetric production payment	29,770	37,184
Accrued compensation under non-equity award plans	15,469	20,058
Other	892	920
TOTAL NON-CURRENT LIABILITIES	876,559	1,075,054
COMMITMENTS AND CONTINGENCIES (see Note 15)	'	'
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 — 12,165,536 shares at December 31, 2013 and 12,164,536 shares at December 31, 2012	1,216	1,216
Additional paid-in capital	152,556	152,527
Retained earnings	200,011	224,873
TOTAL STOCKHOLDERS' EQUITY	353,783	378,616
Total liabilities and equity	$1,366,737	$1,574,584

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, except Share data, unless otherwise specified
Statement of Financial Position [Abstract]	'	'
Allowance for doubtful accounts	$1,184	$1,193
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	12,165,536	12,164,536
Common stock, outstanding shares	12,165,536	12,164,536

CONSOLIDATED_STATEMENTS_OF_OPE

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
REVENUES	'		'		'
Oil and gas sales	$399,950		$403,143		$405,216
Midstream services	4,965		1,974		1,408
Drilling rig services	17,812		15,858		4,060
Other operating revenues	6,488		2,077		15,744
Total revenues	429,215		423,052		426,428
COSTS AND EXPENSES	'		'		'
Production	108,405		124,950		101,099
Exploration:	'		'		'
Abandonments and impairments	5,887		4,222		20,840
Seismic and other	3,906		11,591		5,363
Midstream services	1,816		1,228		1,039
Drilling rig services	16,290		17,423		5,064
Depreciation, depletion and amortization	150,902		142,687		104,880
Impairment of property and equipment	89,811		5,944		10,355
Accretion of asset retirement obligations	4,203		3,696		2,757
General and administrative	33,279		30,485		41,560
Other operating expenses	2,101		1,033		1,666
Total costs and expenses	416,600		343,259		294,623
Operating income	12,615		79,793		131,805
OTHER INCOME (EXPENSE)	'		'		'
Interest expense	-43,079		-38,664		-32,919
Loss on early extinguishment of long-term debt	0		0		-5,501
Gain (loss) on derivatives	-8,731		14,448		47,027
Other	1,905		1,534		5,553
Total other income (expense)	-49,905		-22,682		14,160
Income (loss) before income taxes	-37,290		57,111		145,965
Income tax (expense) benefit	12,428		-22,008		-52,142
NET INCOME (LOSS)	($24,862)		$35,103		$93,823
Net income (loss) per common share:	'		'		'
Basic (in dollars per share)	($2.04)	[1]	$2.89	[1]	$7.72
Diluted (in dollars per share)	($2.04)	[1]	$2.89	[1]	$7.71
Weighted average common shares outstanding:	'		'		'
Basic (in shares)	12,165		12,164		12,161
Diluted (in shares)	12,165		12,164		12,162
[1]	The sum of the individual quarterly net income (loss) per share amounts may not agree to the total for the year since each period’s computation is based on the weighted average number of common shares outstanding during each period.

CONSOLIDATED_STATEMENT_OF_STOC

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (USD $)	Total	Common Stock	Additional Paid-In Capital	Retained Earnings
In Thousands, unless otherwise specified
BALANCE at Dec. 31, 2010	$249,452	$1,215	$152,290	$95,947
BALANCE (in shares) at Dec. 31, 2010	'	12,155	'	'
Increase (Decrease) in Stockholders' Equity	'	'	'	'
Net income (loss)	93,823	0	0	93,823
Issuance of stock through compensation plans, including income tax benefits, shares	'	9	'	'
Issuance of stock through compensation plans, including income tax benefits, Value	226	1	225	0
BALANCE at Dec. 31, 2011	343,501	1,216	152,515	189,770
BALANCE (in shares) at Dec. 31, 2011	'	12,164	'	'
Increase (Decrease) in Stockholders' Equity	'	'	'	'
Net income (loss)	35,103	0	0	35,103
Issuance of stock through compensation plans, including income tax benefits, shares	'	1	'	'
Issuance of stock through compensation plans, including income tax benefits, Value	12	0	12	0
BALANCE at Dec. 31, 2012	378,616	1,216	152,527	224,873
BALANCE (in shares) at Dec. 31, 2012	'	12,165	'	'
Increase (Decrease) in Stockholders' Equity	'	'	'	'
Net income (loss)	-24,862	0	0	-24,862
Issuance of stock through compensation plans, including income tax benefits, shares	'	1	'	'
Issuance of stock through compensation plans, including income tax benefits, Value	29	0	29	0
BALANCE at Dec. 31, 2013	$353,783	$1,216	$152,556	$200,011
BALANCE (in shares) at Dec. 31, 2013	'	12,166	'	'

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES	'	'	'
Net income (loss)	($24,862)	$35,103	$93,823
Adjustments to reconcile net income (loss) to cash provided by operating activities:	'	'	'
Depreciation, depletion and amortization	150,902	142,687	104,880
Impairment of property and equipment	89,811	5,944	10,355
Abandonments and impairments	5,887	4,222	20,840
Gain on sales of assets and impairment of inventory, net	-3,024	-463	-14,078
Deferred income tax expense (benefit)	-14,042	22,008	52,550
Non-cash employee compensation	-3,493	-404	12,866
Gain (loss) on derivatives	8,731	-14,448	-47,027
Cash settlements of derivatives	690	-3,410	42,521
Accretion of asset retirement obligations	4,203	3,696	2,757
Amortization of debt issue costs and original issue discount	3,266	2,554	2,342
Loss on early extinguishment of long-term debt	0	0	5,501
Amortization of deferred revenue from volumetric production payment	-8,746	-8,295	0
Changes in operating working capital:	'	'	'
Accounts receivable	-7,163	7,299	-10,739
Accounts payable	12,740	-9,386	7,551
Other	5,676	2,115	-4,095
Net cash provided by operating activities	220,576	189,222	280,047
CASH FLOWS FROM INVESTING ACTIVITIES	'	'	'
Additions to property and equipment	-288,133	-526,521	-413,013
Proceeds from volumetric production payment	1,332	45,479	0
Proceeds from sales of assets	259,799	3,778	13,902
(Increase) decrease in equipment inventory	-726	1,313	-5,305
Other	-1,315	-82	-497
Net cash used in investing activities	-29,043	-476,033	-404,913
CASH FLOWS FROM FINANCING ACTIVITIES	'	'	'
Proceeds from long-term debt	268,335	280,000	547,710
Repayments of long-term debt	-444,000	0	-411,500
Premium on early extinguishment of long-term debt	0	0	-2,765
Proceeds from exercise of stock options	29	12	226
Net cash provided by (used in) financing activities	-175,636	280,012	133,671
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	15,897	-6,799	8,805
CASH AND CASH EQUIVALENTS	'	'	'
Beginning of period	10,726	17,525	8,720
End of period	26,623	10,726	17,525
SUPPLEMENTAL DISCLOSURES	'	'	'
Cash paid for interest, net of amounts capitalized	35,219	35,932	23,923
Cash paid for income taxes	$0	$0	$0

Nature_of_Operations

Nature of Operations	12 Months Ended
	Dec. 31, 2013
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.  Approximately 26% of CWEI’s outstanding Common Stock is beneficially owned by Clayton W. Williams, Jr. (“Mr. Williams”), Chairman of the Board, President and Chief Executive Officer of the Company, and approximately 25% is owned by a partnership in which Mr. Williams’ adult children are limited partners.
	Substantially all of our oil and gas production is sold under short-term contracts which are market-sensitive.  Accordingly, our results of operations and capital resources are highly dependent upon prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control.  These factors include the level of global supply and demand for oil and natural gas, market uncertainties, weather conditions, domestic governmental regulations and taxes, political and economic conditions in oil producing countries, price and availability of alternative fuels and overall domestic and foreign economic conditions.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Summary of Significant Accounting Policies	'
	Summary of Significant Accounting Policies
	Estimates and Assumptions
	The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods.  Actual results could differ materially from those estimates.  The accounting policies most affected by management’s estimates and assumptions are as follows:
	•	Provisions for depreciation, depletion and amortization and estimates of non-equity plans are based on estimates of proved reserves;
	•	Impairments of long-lived assets are based on estimates of future net cash flows and, when applicable, the estimated fair values of impaired assets;
	•	Exploration expenses related to impairments of unproved acreage are based on estimates of fair values of the underlying leases;
	•	Impairments of inventory are based on estimates of fair values of tubular goods and other well equipment held in inventory;
	•	Exploration expenses related to well abandonment costs are based on the judgments regarding the productive status of in-progress exploratory wells; and
	•	Asset retirement obligations (“ARO”) are based on estimates regarding the timing and cost of future asset retirements.
	Principles of Consolidation
	The consolidated financial statements include the accounts of CWEI and its wholly owned subsidiaries.  We also account for our undivided interests in oil and gas limited partnerships using the proportionate consolidation method.  Under this method, we consolidate our proportionate share of assets, liabilities, revenues and expenses of these limited partnerships.  Less than 5% of the Company’s consolidated total assets and total revenues are derived from oil and gas limited partnerships.  All significant intercompany transactions and balances associated with the consolidated operations have been eliminated.
	Oil and Gas Properties
	We follow the successful efforts method of accounting for oil and gas properties, whereby costs of productive wells, developmental dry holes and productive leases are capitalized into appropriate groups of properties based on geographical and geological similarities.  These capitalized costs are amortized using the unit-of-production method based on estimated proved reserves. Proceeds from sales of properties are credited to property costs, and a gain or loss is recognized when a significant portion of an amortization base is sold or abandoned.
	Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to exploration expense if and when the well is determined to be nonproductive.  The determination of an exploratory well’s ability to produce must be made within one year from the completion of drilling activities.  The acquisition costs of unproved acreage are initially capitalized and are carried at cost, net of accumulated impairment provisions, until such leases are transferred to proved properties or charged to exploration expense as impairments of unproved properties.
	Pipelines and Other Midstream Facilities and Other Property and Equipment
	Pipelines and other midstream facilities consist of pipelines to transport oil, gas and water, gas processing facilities and compressors.  Other property and equipment consists primarily of field equipment and facilities, office equipment, leasehold improvements and vehicles.  Major renewals and betterments are capitalized while repairs and maintenance are charged to expense as incurred.  The cost of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and any gain or loss is included in operating income in the accompanying consolidated statements of operations and comprehensive income (loss).
	Depreciation of pipelines and other midstream facilities and other property and equipment is computed on the straight-line method over the estimated useful lives of the assets, which generally range from 3 to 30 years.
	Contract Drilling
	We conduct contract drilling operations through Desta Drilling, a wholly owned subsidiary of CWEI.  Desta Drilling recognizes revenues and expenses from daywork drilling contracts as the work is performed, but defers revenues and expenses from footage or turnkey contracts until the well is substantially completed or until a loss, if any, on a contract is determinable.
	Property and equipment, including buildings, major replacements, improvements and capitalized interest on construction-in-progress, are capitalized and are depreciated using the straight-line method over estimated useful lives of 3 to 40 years.  Upon disposition, the costs and related accumulated depreciation of assets are eliminated from the accounts and the resulting gain or loss is recognized.
	Valuation of Property and Equipment
	Our long-lived assets, including proved oil and gas properties and contract drilling equipment, are assessed for potential impairment in their carrying values, based on depletable groupings, whenever events or changes in circumstances indicate such impairment may have occurred.  An impairment is recognized when the estimated undiscounted future net cash flows of the asset are less than its carrying value.  Any such impairment is recognized based on the difference in the carrying value and estimated fair value of the impaired asset.
	Unproved oil and gas properties are periodically assessed, and any impairment in value is charged to exploration costs.  The amount of impairment recognized on unproved properties which are not individually significant is determined by impairing the costs of such properties within appropriate groups based on our historical experience, acquisition dates and average lease terms.  The valuation of unproved properties is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values.
	Asset Retirement Obligations
	We recognize a liability for the present value of all legal obligations associated with the retirement of tangible, long-lived assets and capitalize an equal amount as a cost of the asset.  The cost associated with the asset retirement obligation, along with any estimated salvage value, is included in the computation of depreciation, depletion and amortization.
	Income Taxes
	We utilize the asset and liability method to account for income taxes.  Under this method of accounting for income taxes, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the consolidated financial statement carrying amounts of existing assets and liabilities and their respective tax bases.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.  The effect on deferred tax assets and liabilities of a change in enacted tax rates is recognized in the consolidated statements of operations and comprehensive income (loss) in the period that includes the enactment date.  We also record any financial statement recognition and disclosure requirements for uncertain tax positions taken or expected to be taken in a tax return.  Financial statement recognition of the tax position is dependent on an assessment of a 50% or greater likelihood that the tax position will be sustained upon examination, based on the technical merits of the position.  Any interest and penalties related to uncertain tax positions are recorded as interest expense.
	Hedging Transactions
	From time to time, we utilize derivative instruments, consisting of swaps, floors and collars, to attempt to optimize the price received for our oil and gas production.  All of our derivative instruments are recognized as assets or liabilities in the balance sheet, measured at fair value.  The accounting for changes in the fair value of a derivative depends on both the intended purpose and the formal designation of the derivative.  Designation is established at the inception of a derivative, but subsequent changes to the designation are permitted.  For derivatives designated as cash flow hedges and meeting the effectiveness guidelines under applicable accounting standards, changes in fair value are recognized in other comprehensive income (loss) until the hedged item is recognized in earnings.  Hedge effectiveness is measured quarterly based on relative changes in fair value between the derivative contract and the hedged item over time.  Any change in fair value resulting from ineffectiveness is recognized immediately in earnings.  Changes in fair value of derivative instruments which are not designated as cash flow hedges or do not meet the effectiveness guidelines are recorded in earnings as the changes occur.  If designated as cash flow hedges, actual gains or losses on settled commodity derivatives are recorded as oil and gas revenues in the period the hedged production is sold, while actual gains or losses on interest rate derivatives are recorded in interest expense for the applicable period.  Actual gains or losses from derivatives not designated as cash flow hedges are recorded in other income (expense) as gain (loss) on derivatives.
	Inventory
	Inventory consists primarily of tubular goods and other well equipment which we plan to utilize in our exploration and development activities and is stated at the lower of average cost or estimated market value.
	Capitalization of Interest
	Interest costs associated with our inventory of unproved oil and gas property lease acquisition costs are capitalized during the periods for which exploration activities are in progress.  During the years ended December 31, 2013, 2012 and 2011, we capitalized interest totaling approximately $1.4 million, $1 million and $0.7 million, respectively.
	Cash and Cash Equivalents
	We consider all cash and highly liquid investments with original maturities of three months or less to be cash equivalents.
	Net Income (Loss) Per Common Share
	Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of Common Shares outstanding for the period.  Diluted net income per share reflects the potential dilution that could occur if dilutive stock options were exercised, calculated using the treasury stock method.  The diluted net income per share calculations for 2012 and 2011 include changes in potential shares attributable to dilutive stock options.
	Stock-Based Compensation
	We measure and recognize compensation expense for all share-based payment awards, including employee stock options, based on estimated fair values. The value of the portion of the award that is ultimately expected to vest is recognized as expense on a straight-line basis over the requisite service periods, if any.
	We estimate the fair value of stock option awards on the date of grant using an option-pricing model.  We use the Black-Scholes option-pricing model as our method of valuation for share-based awards granted on or after January 1, 2006.  Our determination of fair value of share-based payment awards on the date of grant using an option-pricing model is affected by our stock price, as well as assumptions regarding a number of subjective variables.  These variables include, but are not limited to, our expected stock price volatility over the term of the awards, as well as actual and projected exercise and forfeiture activity.
	Fair Value Measurements
	We follow a framework for measuring fair value, which outlines a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements.  Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.  We categorize our assets and liabilities recorded at fair value in the accompanying consolidated balance sheets based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities are as follows:
	Level 1 -	Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.
	Level 2 -	Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.
	Level 3 -	Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.
	Revenue Recognition and Gas Balancing
	We utilize the sales method of accounting for oil, natural gas and NGL revenues whereby revenues, net of royalties, are recognized as the production is sold to purchasers.  The amount of gas sold may differ from the amount to which we are entitled based on our revenue interests in the properties.  We did not have any significant gas imbalance positions at December 31, 2013, 2012 or 2011.  Revenues from midstream services and drilling rig services are recognized as services are provided.
	Comprehensive Income (Loss)
	There were no differences between net income (loss) and comprehensive income (loss) in 2013, 2012 and 2011.
	Concentration Risks
	We sell our oil and natural gas production to various customers, serve as operator in the drilling, completion and operation of oil and gas wells, and enter into derivatives with various counterparties.  When management deems appropriate, we obtain letters of credit to secure amounts due from our principal oil and gas purchasers and follow other procedures to monitor credit risk from joint owners and derivatives counterparties.  Allowances for doubtful accounts at December 31, 2013 and 2012 relate to amounts due from joint interest owners.
	Recent Accounting Pronouncements
	In December 2011, the Financial Accounting Standards Board (the “FASB”) issued ASU No. 2011-11, “Balance Sheet (Topic 210), Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”).  ASU 2011-11 will require entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement.  In January 2013, the FASB issued Accounting Standards Update No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“ASU 2013-01”). The amendments in ASU 2013-01 clarify that the disclosure requirements of ASU 2011-11 are limited to derivatives, including bifurcated embedded derivatives, repurchase and reverse repurchase agreements, and securities borrowing and lending transactions that are either offset in the statement of financial position or subject to an enforceable master netting arrangement or similar agreement. ASU 2013-01 is effective retrospectively for annual periods beginning on or after January 1, 2013. The adoption of these new accounting rules did not have a material effect on our financial condition, results of operations or cash flows.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Long-Term Debt	'
	Long-Term Debt
	Long-term debt consists of the following:
		December 31,		December 31,
		2013		2012
		(In thousands)
	7.75% Senior Notes due 2019, net of unamortized original issue discount of $362 at December 31, 2013 and $415 at December 31, 2012	$	599,638	$	349,585
	Revolving credit facility, due November 2015	40,000		460,000
		$	639,638	$	809,585
	Aggregate maturities of long-term debt at December 31, 2013 are as follows: 2015- $40 million; 2019 - $599.6 million, net of unamortized original issue discount of $362,000.
	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, beginning October 1, 2011.  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 $250 million of aggregate principal amount of the 2019 Senior Notes at par to yield 7.75% to maturity. These 2019 Senior Notes 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. We may redeem some or all of the 2019 Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.875% beginning on April 1, 2015, 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) does not exceed certain ratios specified in the Indenture.  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 December 31, 2013.
	Revolving Credit Facility
	We have a revolving credit facility with a syndicate of banks that provides for a revolving line of credit of up to $415 million, limited to the amount of a borrowing base as determined by the banks.  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 our revolving credit facility, we will be required to (1) provide additional security, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the deficiency (or by a combination of such additional security and such prepayment eliminate such deficiency), or (3) prepay the deficiency in not more than five equal monthly installments plus accrued interest.
	In April 2013, the borrowing base was reduced from $585 million to $470 million due to the sale of a substantial portion of our Andrews County assets discussed in Note 5 and was further reduced to $407.5 million in October 2013 in connection with the issuance of $250 million of the 2019 Senior Notes. In November 2013, the borrowing base was increased to its current level of $415 million. At December 31, 2013, after allowing for outstanding letters of credit totaling $5.1 million, we had $369.9 million available under our revolving credit facility.
	Our revolving credit facility is collateralized primarily by 80% or more of the adjusted engineered value (as defined in our revolving credit facility) of our oil and gas interests evaluated in determining the borrowing base.  The obligations under our revolving credit facility are guaranteed by each of CWEI’s material domestic subsidiaries except for CWEI Andrews Properties, GP, LLC (see Note 19).
	At our election, annual interest rates under our revolving credit facility are determined by reference to (1) LIBOR plus an applicable margin between 1.75% and 2.75% per year 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, if any of (A), (B) or (C), an applicable margin between 0.75% and 1.75% per year.  We also pay a commitment fee on the unused portion of our revolving credit facility at a rate between 0.375% and 0.50%.  The 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 our revolving credit facility, excluding bank fees and amortization of debt issue costs, for the year ended December 31, 2013 was 2.6%.
	Our revolving credit facility also contains various covenants and restrictive provisions that may, among other things, limit our ability to sell assets, incur additional indebtedness, make investments or loans and create liens.  One such covenant requires that we maintain a ratio of consolidated current assets to consolidated current liabilities of at least 1 to 1.  Another financial covenant prohibits the ratio of our consolidated funded 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 connection with the issuance of the 2019 Senior Notes effective October 1, 2013, the consolidated funded indebtedness ratio was temporarily increased to 4.5 to 1 through the fourth quarter of 2014. The computations of consolidated current assets, current liabilities, EBITDAX and funded indebtedness are defined in our revolving credit facility.  We were in compliance with all financial and non-financial covenants at December 31, 2013 and December 31, 2012.

Acquisition_of_Southwest_Royal

Acquisition of Southwest Royalties, Inc. Limited Partnerships	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
Acquisition of Southwest Royalties, Inc. Limited Partnerships	'
	Acquisition of Southwest Royalties, Inc. Limited Partnerships
	On March 14, 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 (the “SWR Partnerships”) into SWR, with SWR continuing as the surviving entity in the mergers. At the effective time of the mergers, all of the units representing limited partnership interests in the SWR Partnerships, other than those held by SWR, were converted into the right to receive cash. SWR did not receive any cash payment for its partnership interests in the SWR Partnerships. However, as a result of the mergers, SWR acquired 100% of the assets and liabilities of the SWR Partnerships. SWR paid aggregate merger consideration of $38.6 million in the mergers. Pro forma financial information is not presented as it would not be materially different from the information presented in the consolidated statements of operations and comprehensive income (loss) of the Company.
	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 725,000 BOE 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 related to the adequacy of the associated reserves to fully recoup the scheduled volumes and also 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 (see Note 7).
	The following table summarizes the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):
	Cash and cash equivalents	$	4,118
	Oil and gas properties	41,098
	Other non-current assets	210
	Total assets acquired	45,426
	Asset retirement obligations	(6,864		)
	Total liabilities assumed	(6,864		)
	Net assets acquired	$	38,562

Sales_of_Assets_Notes

Sales of Assets (Notes)	12 Months Ended
	Dec. 31, 2013
Sale Of Assets [Abstract]	'
Sales of Assets	'
	Sales of Assets
	In April 2013, we closed a transaction to monetize a substantial portion of our Andrews County Wolfberry oil and gas reserves, leasehold interests and facilities (the “Assets”). The Assets accounted for approximately 20% of our total proved reserves at December 31, 2012. At closing, we contributed 5% of the Assets to a newly formed limited partnership in exchange for a 5% general partner interest, and a unit of GE Energy Financial Services contributed cash of $215.2 million to the limited partnership in exchange for a 95% limited partnership interest. The limited partnership then purchased 95% of the Assets from us for $215.2 million, subject to customary closing adjustments. As of December 30, 2013, all title requirements were satisfied and we received the remaining escrow balance of $25.9 million. Upon the attainment by the limited partner of predetermined rates of return, our general partner interest in the partnership may increase.
	In April 2013, we sold a 75% interest in our rights to the base of the Delaware formation in approximately 12,000 net undeveloped acres in Loving County, Texas for $6.8 million. In December 2013, we sold our remaining interest in the same acreage for $34.5 million, subject to customary closing adjustments. The proceeds from these sales were used to repay a portion of our outstanding balance on our revolving credit facility.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Asset Retirement Obligations	'
	Asset Retirement Obligations
	We record the ARO associated with the retirement of our long-lived assets in the period in which they are incurred and become determinable. Under this method, we record a liability for the expected future cash outflows discounted at our credit-adjusted risk-free interest rate for the dismantlement and abandonment costs, excluding salvage values, of each oil and gas property. We also record an asset retirement cost to the oil and gas properties equal to the ARO liability. The fair value of the asset retirement cost and the ARO liability is measured using primarily Level 3 inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, inflation rate and well life.  The inputs are calculated based on historical data as well as current estimated costs. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted over the useful life of the related asset.
	The following table reflects the changes in ARO for the years ended December 31, 2013 and December 31, 2012:
		2013			2012
		(In thousands)
	Beginning of year	$	51,477		$	40,794
	Additional ARO from new properties	795			7,868
	Sales or abandonments of properties	(5,892		)	(2,184		)
	Accretion expense	4,203			3,696
	Revisions of previous estimates	(602		)	1,303
	End of year	$	49,981		$	51,477

Deferred_Revenue_from_Volumetr

Deferred Revenue from Volumetric Production Payment	12 Months Ended
	Dec. 31, 2013
Deferred Revenue Disclosure [Abstract]	'
Deferred Revenue from Volumetric Production Payment	'
	Deferred Revenue from Volumetric Production Payment
	The net proceeds from the VPP discussed in Note 4 are recorded as a non-current liability in the consolidated balance sheets.  Deferred revenue from 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).
	The following table reflects the changes in deferred revenue during the years ended December 31, 2013 and December 31, 2012:
		2013			2012
		(In thousands)
	Beginning of period	$	37,184		$	—
	Deferred revenue from VPP	1,332			45,479
	Amortization of deferred revenue from VPP	(8,746		)	(8,295		)
	End of period	$	29,770		$	37,184
	Under the terms of the VPP, SWR conveyed to a third party a term overriding royalty interest covering approximately 725,000 BOE of estimated future oil and gas production. As of December 31, 2013, we have a remaining obligation to deliver approximately 485,000 BOE.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	Income Taxes
	Deferred tax assets and liabilities are the result of temporary differences between the consolidated financial statement carrying values and the tax basis of assets and liabilities. Significant components of net deferred tax assets (liabilities) at December 31, 2013 and 2012 are as follows:
		2013			2012
		(In thousands)
	Deferred tax assets:
	Net operating loss carryforwards	$	65,814		$	122,393
	Statutory depletion carryforwards	8,658			8,159
	Asset retirement obligations and other	22,470			21,814
		96,942			152,366
	Deferred tax liabilities:
	Fair value of derivatives	(598		)	(4,208		)
	Property and equipment	(229,572		)	(295,428		)
		(230,170		)	(299,636		)
	Net deferred tax liabilities	$	(133,228	)	$	(147,270	)
	Components of net deferred tax liabilities:
	Current assets	$	7,581		$	8,560
	Non-current liabilities	(140,809		)	(155,830		)
	Net deferred tax liabilities	$	(133,228	)	$	(147,270	)
	For the years ended December 31, 2013, 2012 and 2011, effective income tax rates were different than the statutory federal income tax rates for the following reasons:
		2013			2012			2011
		(In thousands)
	Income tax expense at statutory rate of 35%	$	(13,052	)	$	19,989		$	50,921
	Tax depletion in excess of basis	(518		)	(581		)	(425		)
	Revision of previous tax estimates	373			700			217
	State income taxes, net of federal tax effect	76			1,513			1,310
	Other	693			387			119
	Income tax expense (benefit)	$	(12,428	)	$	22,008		$	52,142
	Current	$	1,614		$	—		$	(408	)
	Deferred	(14,042		)	22,008			52,550
	Income tax expense (benefit)	$	(12,428	)	$	22,008		$	52,142
	We derive a tax deduction when options are exercised under our stock option plans.  To the extent these tax deductions are used to reduce currently payable taxes in any period, we record a tax benefit for the excess of the tax deduction over cumulative book compensation expense as additional paid-in capital and as a financing cash flow in the accompanying consolidated financial statements.  At December 31, 2013, our cumulative tax loss carryforwards were approximately $209.5 million, of which $21.8 million relates to excess tax benefits from exercise of stock options.  The cumulative tax loss carryforwards are scheduled to expire if not utilized between 2024 and 2028.
	In assessing the ability to realize deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized.  The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. If it is more likely than not that some portion or all of the assets will not be realized, the assets are reduced by a valuation allowance. Based on our analysis of future taxable income, no valuation allowance is required.
	CWEI and its subsidiaries file federal income tax returns with the United States Internal Revenue Service and state income tax returns in various state tax jurisdictions.  As a general rule, the Company’s tax returns for fiscal years after 2009 currently remain subject to examination by appropriate taxing authorities.  None of our income tax returns are under examination at this time.  We do not have any uncertain tax positions as of December 31, 2013 and 2012.

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Derivatives	'
	Derivatives
	Commodity Derivatives
	From time to time, we utilize commodity derivatives, consisting of swaps, floors and collars, to attempt to optimize the price received for our oil and gas production.  When using swaps to hedge oil and natural gas production, we receive a fixed price for the respective commodity and pay a floating market price as defined in each contract, generally New York Mercantile Exchange (“NYMEX”) futures prices, resulting in a net amount due to or from the counterparty.  In floor transactions, we receive a fixed price (put strike price) if the market price falls below the put strike price for the respective commodity.  If the market price is greater than the put strike price, no payments are due from either party.  Costless collars are a combination of puts and calls, and contain a fixed floor price (put strike price) and ceiling price (call strike price).  If the market price for the respective commodity exceeds the call strike price or falls below the put strike price, then we receive the fixed price and pay the market price.  If the market price is between the call and the put strike prices, no payments are due from either party. Commodity derivatives are settled monthly as the contract production periods mature.
	The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to December 31, 2013.  The settlement prices of commodity derivatives are based on NYMEX futures prices.
	Swaps
		Oil
		Bbls			Price
	Production Period:
	1st Quarter 2014	606,000			$	96.74
	2nd Quarter 2014	560,600			$	96.81
	3rd Quarter 2014	530,200			$	96.87
	4th Quarter 2014	503,200			$	96.92
		2,200,000
	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.  A $1 per barrel change in the price of oil and a $0.50 per MMBtu change in the price of gas would change the fair value of our outstanding commodity derivatives at December 31, 2013 by approximately $2.2 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 December 31, 2013
		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		$	2,518			Current		$	208
		Non-current		—				Non-current		—
	Total			$	2,518					$	208
		Fair Value of Derivative Instruments as of December 31, 2012
		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		$	7,495			Current		$	—
		Non-current		4,236				Non-current		—
	Total			$	11,731					$	—
	Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities
		31-Dec-13
		Assets				Liabilities
		(In thousands)
	Fair value of derivatives — gross presentation	$	3,909			$	1,599
	Effects of netting arrangements	(1,391		)		(1,391		)
	Fair value of derivatives — net presentation	$	2,518			$	208
		31-Dec-12
		Assets				Liabilities
		(In thousands)
	Fair value of derivatives — gross presentation	$	17,851			$	6,120
	Effects of netting arrangements	(6,120		)		(6,120		)
	Fair value of derivatives — net presentation	$	11,731			$	—
	Our derivative contracts are with JPMorgan Chase Bank, N.A. and Union Bank, N.A.  We have elected to net the outstanding positions with these counterparties between current and noncurrent 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
			Year Ended December 31, 2013
	Location of Gain or (Loss) Recognized in Earnings		Realized				Unrealized				Total
			(In thousands)
	Derivatives not designated as hedging instruments:
	Commodity derivatives:
	Other income (expense) - Gain (loss) on derivatives		$	690			$	(9,421	)		$	(8,731	)
	Total		$	690			$	(9,421	)		$	(8,731	)
			Amount of Gain or (Loss) Recognized in Earnings
			Year Ended December 31, 2012
	Location of Gain or (Loss) Recognized in Earnings		Realized				Unrealized				Total
		(In thousands)
Derivatives not designated as hedging instruments:
Commodity derivatives:
Other income (expense) - Gain (loss) on derivatives		$	(3,410	)		$	17,858			$	14,448
Total		$	(3,410	)		$	17,858			$	14,448
		Amount of Gain or (Loss) Recognized in Earnings
		Year Ended December 31, 2011
Location of Gain or (Loss) Recognized in Earnings		Realized				Unrealized				Total
		(In thousands)
Derivatives not designated as hedging instruments:
Commodity derivatives:
Other income (expense) - Gain (loss) on derivatives		$	42,521			$	4,506			$	47,027
Total		$	42,521			$	4,506			$	47,027

Fair_Value_of_Financial_Instru

Fair Value of Financial Instruments	12 Months Ended
	Dec. 31, 2013
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.
	The financial assets and liabilities measured on a recurring basis at December 31, 2013 and 2012 were commodity derivatives. The fair value of all derivative contracts is reflected on the consolidated balance sheet as detailed in the following schedule:
		December 31,
		2013		2012
		Significant Other
		Observable Inputs
	Description	(Level 2)
		(In thousands)
	Assets:
	Fair value of commodity derivatives	$	2,518	$	11,731
	Total assets	$	2,518	$	11,731
	Liabilities:
	Fair value of commodity derivatives	$	208	$	—
	Total liabilities	$	208	$	—
	Fair Value of Other Financial Instruments
	We estimate the fair value of the 2019 Senior Notes using quoted market prices (Level 1 inputs). Fair value is compared to the carrying value in the table below:
		31-Dec-13				31-Dec-12
		Carrying		Estimated		Carrying		Estimated
	Description	Amount		Fair Value		Amount		Fair Value
		(In thousands)
	7.75% Senior Notes due 2019	$	599,638	$	616,500	$	349,585	$	348,700

Compensation_Plans

Compensation Plans	12 Months Ended
	Dec. 31, 2013
Compensation Plans [Abstract]	'
Compensation Plans	'
	Compensation Plans
	Stock-Based Compensation
	Initially, we reserved 86,300 shares of Common Stock for issuance under the Outside Directors Stock Option Plan (the “Directors Plan”).  Since the inception of the Directors Plan, CWEI has issued options covering 52,000 shares of Common Stock at option prices ranging from $3.25 to $41.74 per share.  All outstanding options expire ten years from the grant date and are fully exercisable upon issuance.  No options were granted under the Directors Plan in 2013 or 2012.  At December 31, 2013, 4,000 options were outstanding under this plan.  In December 2009, the Board reduced the number of shares available for issuance under the Directors Plan to a level sufficient to cover only the remaining outstanding shares.
	The following table sets forth certain information regarding our stock option plans as of and for the year ended December 31, 2013:
		Shares		Weighted			Weighted		Aggregate
				Average			Average		Intrinsic
				Exercise			Remaining		Value(a)
				Price			Contractual
							Term
	Outstanding at January 1, 2013	5,000		$	32.21
	Exercised (b)	(1,000	)	$	28.93
	Outstanding at December 31, 2013	4,000		$	33.03		2.5		$	195,690
	Vested at December 31, 2013	4,000		$	33.03		2.5		$	195,690
	Exercisable at December 31, 2013	4,000		$	33.03		2.5		$	195,690
	_______
	(a)	Based on closing price at December 31, 2013 of $81.95 per share.
	(b)	Cash received for options exercised totaled $28,930.
	The following table summarizes information with respect to options outstanding at December 31, 2013, all of which were granted under the Directors Plan and are currently exercisable.
		Outstanding and Exercisable Options
							Weighted
		Shares		Weighted			Average
				Average			Remaining
				Exercise			Life in
				Price			Years
	Range of exercise prices:
	$22.90 - $41.74	4,000		$	33.03		2.5
	The following table presents certain information regarding stock-based compensation amounts for the years ended December 31, 2013, 2012 and 2011.
		2013			2012			2011
		(In thousands, except per share)
	Weighted average grant date fair value of options granted per share	$	—		$	—		$	—
	Intrinsic value of options exercised	$	53		$	28		$	594
	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, by the participants.  The plan generally provides for the creation of a series of partnerships or participation arrangements, which are treated as partnerships for tax purposes (the “APO Partnerships”), between us and the participants, to which we contribute a portion of our economic interest in wells drilled or acquired within certain areas.  Generally, we pay all costs to acquire, drill and produce applicable wells and receive all revenues until we have recovered all of our costs, plus interest (“payout”).  At payout, the participants receive 99% to 100% of all subsequent revenues and pay 99% to 100% of all subsequent expenses attributable to the economic interests that are subject to the APO Partnerships.  Between 5% and 7.5% of our economic interests in specified wells drilled or acquired by us subsequent to October 2002 are subject to the APO Incentive Plan.  We record our allocable share of the assets, liabilities, revenues, expenses and oil and gas reserves of these APO Partnerships in our consolidated financial statements.  Participants in the APO Incentive Plan are immediately vested in all future amounts payable under the plan.
	The Compensation Committee has also adopted an APO reward plan (the “APO Reward Plan”), which offers eligible officers, key employees and consultants the opportunity to receive bonus payments that are based on certain profits derived from a portion of our working interest in specified areas where we are conducting drilling and production enhancement operations.  The wells subject to an APO Reward Plan are not included in the APO Incentive Plan.  Likewise, wells included in the APO Incentive Plan are not included in the APO Reward Plan.  Although conceptually similar to the APO Incentive Plan, the APO Reward Plan is a compensatory bonus plan through which we pay participants a bonus equal to a portion of the APO cash flows received by us from our working interest in wells in a specified area.  Unlike the APO Incentive Plan, however, participants in the APO Reward Plan are not immediately vested in all future amounts payable under the plan.  To date, we have granted awards under the APO Reward Plan in 17 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 May 1, 2013.  Of these 17 awards, 13 awards are fully vested, two awards will fully vest on May 1, 2015 and two awards will fully vest on August 1, 2015.
	In January 2007, we granted awards under the Southwest Royalties Reward Plan (the “SWR Reward Plan”), a one-time incentive plan which established a quarterly bonus amount for participants equal to the APO cash flow from a 22.5% working interest in one well.  The plan is fully vested and 100% of subsequent quarterly bonus amounts are payable to participants.
	To continue as a participant in the APO Reward Plan or the SWR Reward Plan, participants must remain in the employment or service of the Company through the full vesting date established for each award.  The full vesting date may be accelerated in the event of a change of control or sale transaction, as defined in the plan documents.
	We recognize compensation expense related to the APO Partnerships based on the estimated value of economic interests conveyed to the participants.  Estimated compensation expense applicable to the APO Reward Plan and the SWR Reward Plan is recognized over the applicable vesting periods, which range from two years to five years.  Compensation expense related to non-equity award plans was $2.1 million in 2013, $2.1 million in 2012 and $14.4 million in 2011.
	Accrued compensation under non-equity award plans is reflected in the accompanying consolidated balance sheets as detailed in the following schedule:
		December 31,			December 31,
		2013			2012
		(In thousands)
	Current liabilities:
	Accrued liabilities and other	$	3,317		$	2,220
	Non-current liabilities:
	Accrued compensation under non-equity award plans	15,469			20,058
	Total accrued compensation under non-equity award plans	$	18,786		$	22,278

Transactions_with_Affiliates

Transactions with Affiliates	12 Months Ended
	Dec. 31, 2013
Transactions with Affiliates [Abstract]	'
Transactions with Affiliates	'
	Transactions with Affiliates
	The Company and other entities (the “Williams Entities”) controlled by Mr. Williams are parties to an agreement (the “Service Agreement”) pursuant to which the Company furnishes services to, and receives services from, such entities.  Under the Service Agreement, as amended from time to time, CWEI provides legal, computer, payroll and benefits administration, insurance administration, tax preparation services, tax planning services, and financial and accounting services to the Williams Entities, as well as technical services with respect to certain oil and gas properties owned by the Williams Entities.  The Williams Entities provide business entertainment to or for the benefit of CWEI.  The following table summarizes the charges to and from the Williams Entities for the years ended December 31, 2013, 2012 and 2011.
		2013		2012		2011
		(In thousands)
	Amounts received from the Williams Entities:
	Service Agreement:
	Services	$	715	$	671	$	566
	Insurance premiums and benefits	837		920		821
	Reimbursed expenses	427		566		371
		$	1,979	$	2,157	$	1,758
	Amounts paid to the Williams Entities:
	Rent(a)	$	1,560	$	1,478	$	843
	Service Agreement:
	Business entertainment(b)	344		116		116
	Reimbursed expenses	216		267		289
		$	2,120	$	1,861	$	1,248
	_______
	(a)	Rent amounts were paid to a partnership within the Williams Entities.  The Company owns 31.9% of the partnership and affiliates of the Company own 25.8%.
	(b)	Consists primarily of hunting and fishing recreation for business associates and employees of the Company on land owned by affiliates of Mr. Williams.
	Accounts receivable from affiliates and accounts payable to affiliates include, among other things, amounts for customary charges by the Company as operator of certain wells in which affiliates own an interest.

Other_Operating_Revenues_and_E

Other Operating Revenues and Expenses	12 Months Ended
	Dec. 31, 2013
Other Income and Expenses [Abstract]	'
Other Operating Revenues and Expenses	'
	Other Operating Revenues and Expenses
	Other operating revenues and expenses for the years ended December 31, 2013, 2012 and 2011 are as follows:
		2013			2012			2011
		(In thousands)
	Other operating revenues:
	Gain on sales of assets	$	4,467		$	1,496		$	15,744
	Marketing revenue	2,021			581			—
	Total other operating revenues	$	6,488		$	2,077		$	15,744
	Other operating expenses:
	Loss on sales of assets	$	(1,233	)	$	(523	)	$	(945	)
	Marketing expense	(658		)	—			—
	Impairment of inventory	(210		)	(510		)	(721		)
	Total other operating expenses	$	(2,101	)	$	(1,033	)	$	(1,666	)
	During 2013, gain or loss on sales of assets included the sale of a portion of our Andrews County Wolfberry assets (see Note 5) and certain other non-core properties in Walker County, Texas.
	In February 2011, we sold two 2,000 horsepower drilling rigs and related equipment for $22 million of total consideration.  In connection with the sale, we recorded a gain of $13.2 million during the first quarter of 2011. Proceeds from the sale consisted of $11 million cash and an $11 million promissory note that was subsequently exchanged for a membership interest in Dalea Investment Group, LLC (“Dalea”) in June 2012 (see Note 14).
	We maintain an inventory of tubular goods and other well equipment for use in our exploration and development drilling activities.  Inventory is carried at the lower of average cost or estimated fair market value.  We categorize the measurement of fair value of inventory as Level 2 under applicable accounting standards.  To determine estimated fair value of inventory, we subscribe to market surveys and obtain quotes from equipment dealers for similar equipment.  We then correlate the data as needed to estimate the fair value of the specific items (or groups of similar items) in our inventory.  If the estimated fair values for those specific items (or groups of similar items) in our inventory are less than the related average cost, a provision for impairment is made.

Investment_in_Dalea_Investment

Investment in Dalea Investment Group, LLC	12 Months Ended
	Dec. 31, 2013
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 (see Note 13) in exchange for a 7.66% non-controlling membership interest in 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 December 31, 2013, we have performed a qualitative assessment and determined there has been no indication of any impairment of our investment in Dalea.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	Commitments and Contingencies
	Leases
	We lease office space from affiliates and nonaffiliates under noncancelable operating leases.  Rental expense pursuant to the office leases amounted to $1.8 million, $1.6 million and $1 million for the years ended December 31, 2013, 2012 and 2011, respectively.
	Future minimum payments under noncancelable leases at December 31, 2013, are as follows:
		Leases
		Capital(a)		Operating(b)		Total
		(In thousands)
	2014	$	1,001	$	3,818	$	4,819
	2015	620		3,998		4,618
	2016	213		3,684		3,897
	Thereafter	—		338		338
	Total minimum lease payments	$	1,834	$	11,838	$	13,672
	_______
	(a)          Relates to vehicle leases.
	(b)         Includes leases for two drilling rigs.
	Legal Proceedings
	In a case pending since 2001, SWR is a defendant in a suit filed in April 2011 in the Circuit Court of Union County, Arkansas where the plaintiffs are suing for the costs of environmental remediation to a lease on which operations were commenced in the 1930s. The plaintiffs are seeking in excess of $8 million. 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 would be converted to a class action, and each member of the class would be offered the right to either participate or opt out of the class and continue a separate action for damages. If more than 25% of the plaintiffs were to opt out of the settlement, SWR would have the right to terminate the settlement. Any plaintiffs opting out would be subject to all previous rulings of the court, including an order dismissing a significant number of the plaintiffs’ claims on the basis that such claims were time barred. SWR believes that the judge will approve the settlement and the number of the plaintiffs opting out of the settlement, if any, will be insignificant. We recorded a loss on settlement of $0.7 million for the year ended December 31, 2013 in connection with this proposed settlement. We are now awaiting finalization of the settlement by the court.
	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 the Chesapeake farm-in agreement. 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. The case was tried to the judge in October 2013 who 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. As a result, CWEI recorded a loss of $1.4 million for the year ended December 31, 2013 in connection with the judgment. As a prerequisite for appeal, CWEI filed a motion with the trial court for new trial. In March 2014, rather than ruling on the motion, the trial court ordered the parties to a mediation.
	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_Equ

Impairment of Property and Equipment	12 Months Ended
	Dec. 31, 2013
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 recorded provisions for impairment of proved properties triggered by a combination of well performance and lower reserve estimates due to performance and changes in oil and gas prices aggregating $89.8 million in 2013, $5.9 million in 2012 and $10.4 million in 2011 to reduce the carrying value of those properties to their estimated fair values.  The 2013 provision of $89.8 million related to the write-down of our Andrews County Wolfberry assets and certain non-core properties in the Permian Basin.  The 2012 provision related to $5.4 million for certain non-core properties in the Permian Basin.  The 2011 provision of $10.4 million related primarily to certain non-core properties in the Permian Basin and other non-core areas.
	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 these assets as Level 3 inputs. We recorded provisions for impairment of unproved properties aggregating $3.4 million, $1.4 million and $6.2 million in 2013, 2012 and 2011, respectively, and charged these impairments to abandonments and impairments in the accompanying consolidated statements of operations and comprehensive income (loss).

Costs_of_Oil_and_Gas_Propertie

Costs of Oil and Gas Properties	12 Months Ended
	Dec. 31, 2013
Oil and Gas Property, Successful Effort Method, Gross [Abstract]	'
Costs of Oil and Gas Properties	'
	Costs of Oil and Gas Properties
	The following table sets forth certain information with respect to costs incurred in connection with the Company’s oil and gas producing activities during the years ended December 31, 2013, 2012 and 2011.
		2013			2012			2011
		(In thousands)
	Property acquisitions:
	Proved	$	—		$	41,098		$	—
	Unproved	50,104			72,235			61,236
	Developmental costs	218,341			349,972			328,418
	Exploratory costs	3,932			10,898			27,425
	Total	$	272,377		$	474,203		$	417,079
	The following table sets forth the net capitalized costs for oil and gas properties as of December 31, 2013 and 2012.
		2013			2012
		(In thousands)
	Proved properties	$	2,317,053		$	2,482,185
	Unproved properties	86,224			88,618
	Total capitalized costs	2,403,277			2,570,803
	Accumulated depletion	(1,282,989		)	(1,234,626		)
	Net capitalized costs	$	1,120,288		$	1,336,177

Segment_Information

Segment Information	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Segment Information	'
	Segment Information
	We have two reportable operating segments, which are (1) oil and gas exploration and production and (2) contract drilling services. The following tables present selected financial information regarding our operating segments for the years ended December 31, 2013, 2012 and 2011.
						Contract			Intercompany			Consolidated
	For the Year Ended December 31, 2013		Oil and Gas			Drilling			Eliminations			Total
			(In thousands)
	Revenues		$	411,403		$	37,255		$	(19,443	)	$	429,215
	Depreciation, depletion and amortization(a)		229,460			13,844			(2,591		)	240,713
	Other operating expenses(b)		159,294			32,817			(16,224		)	175,887
	Interest expense		43,079			—			—			43,079
	Other (income) expense		6,826			—			—			6,826
	Income (loss) before income taxes		(27,256		)	(9,406		)	(628		)	(37,290		)
	Income tax (expense) benefit		9,136			3,292			—			12,428
	Net income (loss)		$	(18,120	)	$	(6,114	)	$	(628	)	$	(24,862	)
	Total assets		$	1,339,920		$	54,697		$	(27,880	)	$	1,366,737
	Additions to property and equipment		$	280,173		$	5,107		$	(628	)	$	284,652
						Contract			Intercompany			Consolidated
	For the Year Ended December 31, 2012		Oil and Gas			Drilling			Eliminations			Total
			(In thousands)
	Revenues		$	407,194		$	57,218		$	(41,360	)	$	423,052
	Depreciation, depletion and amortization(a)		140,967			14,442			(6,778		)	148,631
	Other operating expenses(b)		176,922			52,678			(34,972		)	194,628
	Interest expense		38,664			—			—			38,664
	Other (income) expense		(15,979		)	(3		)	—			(15,982		)
	Income (loss) before income taxes		66,620			(9,899		)	390			57,111
	Income tax (expense) benefit		(25,473		)	3,465			—			(22,008		)
	Net income (loss)		$	41,147		$	(6,434	)	$	390		$	35,103
	Total assets		$	1,535,544		$	64,045		$	(25,005	)	$	1,574,584
	Additions to property and equipment		$	500,161		$	15,207		$	390		$	515,758
						Contract			Intercompany			Consolidated
	For the Year Ended December 31, 2011		Oil and Gas			Drilling			Eliminations			Total
			(In thousands)
	Revenues		$	422,368		$	52,716		$	(48,656	)	$	426,428
	Depreciation, depletion and amortization(a)		112,863			12,214			(9,842		)	115,235
	Other operating expenses(b)		174,027			44,318			(38,957		)	179,388
	Interest expense		32,919			—			—			32,919
	Other (income) expense		(33,280		)	(13,799		)	—			(47,079		)
	Income (loss) before income taxes		135,839			9,983			143			145,965
	Income tax (expense) benefit		(48,648		)	(3,494		)	—			(52,142		)
	Net income (loss)		$	87,191		$	6,489		$	143		$	93,823
	Total assets		$	1,178,725		$	62,846		$	(15,300	)	$	1,226,271
	Additions to property and equipment		$	429,142		$	17,578		$	143		$	446,863
	_______
	(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_Informatio

Guarantor Financial Information	12 Months Ended
	Dec. 31, 2013
Guarantor Financial Information Disclosure [Abstract]	'
Guarantor Financial Information	'
	Guarantor Financial Information
	In March and April 2011, we issued $350 million of aggregate principal amount of 2019 Senior Notes. In October 2013, we issued $250 million of aggregate principal amount of the 2019 Senior Notes. The 2019 Senior Notes issued in October 2013 and the 2019 Senior Notes originally issued in March and April 2011 are treated as a single class of debt securities (see Note 3). Presented below is condensed consolidated financial information of CWEI (the “Issuer”) and the Issuer’s material wholly owned subsidiaries. Other than CWEI Andrews Properties, GP, LLC, the general partner of CWEI Andrews Properties, L.P., an affiliated limited partnership formed in April 2013, all of the Issuer’s wholly owned and active subsidiaries (“Guarantor Subsidiaries”) have jointly and severally, irrevocably and unconditionally guaranteed the performance and payment when due of all obligations under the 2019 Senior Notes. The guarantee by a Guarantor Subsidiary of the 2019 Senior Notes may be released under certain customary circumstances as set forth in the Indenture. CWEI Andrews Properties, GP, LLC, is not a guarantor of the 2019 Senior Notes and its accounts are reflected in the “Non-Guarantor Subsidiary” column in this Note 19.
	The financial information which follows sets forth our condensed consolidating financial statements as of and for the periods indicated.
	Condensed Consolidating Balance Sheet
	December 31, 2013
	(Dollars in thousands)
		Issuer			Guarantor			Non-Guarantor			Adjustments/			Consolidated
					Subsidiaries			Subsidiary			Eliminations
	Current assets	$	140,100		$	248,314		$	538		$	(250,641	)	$	138,311
	Property and equipment, net	833,980			351,171			13,956			—			1,199,107
	Investments in subsidiaries	342,416			—			—			(342,416		)	—
	Other assets	16,032			13,287			—			—			29,319
	Total assets	$	1,332,528		$	612,772		$	14,494		$	(593,057	)	$	1,366,737
	Current liabilities	$	290,327		$	93,055		$	976		$	(247,963	)	$	136,395
	Non-current liabilities:
	Long-term debt	639,638			—			—			—			639,638
	Deferred income taxes	118,438			129,880			988			(108,497		)	140,809
	Other	36,161			59,829			122			—			96,112
		794,237			189,709			1,110			(108,497		)	876,559
	Equity	247,964			330,008			12,408			(236,597		)	353,783
	Total liabilities and equity	$	1,332,528		$	612,772		$	14,494		$	(593,057	)	$	1,366,737
	Condensed Consolidating Balance Sheet
	December 31, 2012
	(Dollars in thousands)
		Issuer			Guarantor			Non-Guarantor			Adjustments/			Consolidated
					Subsidiaries			Subsidiary			Eliminations
	Current assets	$	133,080		$	224,210		$	—		$	(232,820	)	$	124,470
	Property and equipment, net	1,053,453			366,905			—			—			1,420,358
	Investments in subsidiaries	305,899			—			—			(305,899		)	—
	Fair value of derivatives	4,236			—			—			—			4,236
	Other assets	12,112			13,408			—			—			25,520
	Total assets	$	1,508,780		$	604,523		$	—		$	(538,719	)	$	1,574,584
	Current liabilities	$	241,200		$	112,534		$	—		$	(232,820	)	$	120,914
	Non-current liabilities:
	Long-term debt	809,585			—			—			—			809,585
	Deferred income taxes	143,699			117,950			—			(105,819		)	155,830
	Other	41,499			68,140			—			—			109,639
		994,783			186,090			—			(105,819		)	1,075,054
	Equity	272,797			305,899			—			(200,080		)	378,616
	Total liabilities and equity	$	1,508,780		$	604,523		$	—		$	(538,719	)	$	1,574,584
	Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)
	Year Ended December 31, 2013
	(Dollars in thousands)
		Issuer			Guarantor			Non-Guarantor			Adjustments/			Consolidated
					Subsidiaries			Subsidiary			Eliminations
	Total revenue	$	280,423		$	146,556		$	2,236		$	—		$	429,215
	Costs and expenses	302,898			112,441			1,261			—			416,600
	Operating income (loss)	(22,475		)	34,115			975			—			12,615
	Other income (expense)	(50,601		)	(25		)	721			—			(49,905		)
	Equity in earnings of subsidiaries	23,261			—			—			(23,261		)	—
	Income tax (expense) benefit	24,953			(11,931		)	(594		)	—			12,428
	Net income (loss)	$	(24,862	)	$	22,159		$	1,102		$	(23,261	)	$	(24,862	)
	Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)
	Year Ended December 31, 2012
	(Dollars in thousands)
		Issuer			Guarantor			Non-Guarantor			Adjustments/			Consolidated
					Subsidiaries			Subsidiary			Eliminations
	Total revenue	$	291,782		$	132,690		$	—		$	(1,420	)	$	423,052
	Costs and expenses	230,033			114,646			—			(1,420		)	343,259
	Operating income (loss)	61,749			18,044			—			—			79,793
	Other income (expense)	(25,495		)	2,813			—			—			(22,682		)
	Equity in earnings of subsidiaries	13,557			—			—			(13,557		)	—
	Income tax (expense) benefit	(14,708		)	(7,300		)	—			—			(22,008		)
Net income (loss)	$	35,103		$	13,557		$	—		$	(13,557	)	$	35,103
Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)
Year Ended December 31, 2011
(Dollars in thousands)
	Issuer			Guarantor			Non-Guarantor			Adjustments/			Consolidated
				Subsidiaries			Subsidiary			Eliminations
Total revenue	$	280,359		$	147,015		$	—		$	(946	)	$	426,428
Costs and expenses	191,012			104,557			—			(946		)	294,623
Operating income (loss)	89,347			42,458			—			—			131,805
Other income (expense)	6,816			7,344			—			—			14,160
Equity in earnings of subsidiaries	32,371			—			—			(32,371		)	—
Income tax (expense) benefit	(34,711		)	(17,431		)	—			—			(52,142		)
Net income (loss)	$	93,823		$	32,371		$	—		$	(32,371	)	$	93,823
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2013
(Dollars in thousands)
	Issuer			Guarantor			Non-Guarantor			Adjustments/			Consolidated
				Subsidiaries			Subsidiary			Eliminations
Operating activities	$	128,146		$	87,433		$	2,406		$	2,591		$	220,576
Investing activities	10,544			(34,121		)	(2,875		)	(2,591		)	(29,043		)
Financing activities	(125,027		)	(51,122		)	513			—			(175,636		)
Net increase (decrease) in cash and cash equivalents	13,663			2,190			44			—			15,897
Cash at the beginning of the period	6,030			4,696			—			—			10,726
Cash at end of the period	$	19,693		$	6,886		$	44		$	—		$	26,623
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2012
(Dollars in thousands)
	Issuer			Guarantor			Non-Guarantor			Adjustments/			Consolidated
				Subsidiaries			Subsidiary			Eliminations
Operating activities	$	92,521		$	89,923		$	—		$	6,778		$	189,222
Investing activities	(432,433		)	(36,822		)	—			(6,778		)	(476,033		)
Financing activities	333,703			(53,691		)	—			—			280,012
Net increase (decrease) in cash and cash equivalents	(6,209		)	(590		)	—			—			(6,799		)
Cash at the beginning of the period	12,239			5,286			—			—			17,525
Cash at end of the period	$	6,030		$	4,696		$	—		$	—		$	10,726
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2011
(Dollars in thousands)
	Issuer			Guarantor			Non-Guarantor			Adjustments/			Consolidated
				Subsidiaries			Subsidiary			Eliminations
Operating activities	$	209,886		$	60,319		$	—		$	9,842		$	280,047
Investing activities	(389,681		)	(5,390		)	—			(9,842		)	(404,913		)
Financing activities	186,994			(53,323		)	—			—			133,671
Net increase (decrease) in cash and cash equivalents	7,199			1,606			—			—			8,805
Cash at the beginning of the period	5,040			3,680			—			—			8,720
Cash at end of the period	$	12,239		$	5,286		$	—		$	—		$	17,525

Subsequent_Events

Subsequent Events	12 Months Ended
	Dec. 31, 2013
Subsequent Events [Abstract]	'
Subsequent Events	'
	Subsequent Events
	On February 10, 2014, our wholly owned subsidiary, SWR, sold property in Ward County, Texas for $5.1 million, subject to customary closing adjustments.
	In February 2014, we entered into a purchase and sale agreement with a third party 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. The transaction is expected to close in March 2014. Net proceeds from the sale, if consummated, will be used to repay the outstanding balance on our revolving bank credit facility and to fund a portion of our planned capital expenditures for 2014.
	We have evaluated events and transactions that occurred after the balance sheet date of December 31, 2013 and have determined that no other events or transactions have occurred that would require recognition in the consolidated financial statements or disclosures in these notes to the consolidated financial statements.

Supplemental_Quarterly_Financi

Supplemental Quarterly Financial Information	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Supplemental Quarterly Financial Information	'
	Supplemental Quarterly Financial Data
	The following table summarizes results for each of the four quarters in the years ended December 31, 2013 and 2012.
		First			Second			Third			Fourth		Year
		Quarter			Quarter			Quarter			Quarter
		(In thousands, except per share)
	Year ended December 31, 2013:
	Total revenues	$	106,867		$	98,916		$	111,165		$	112,267	$	429,215
	Operating income (loss)	$	(50,883	)	$	5,003		$	33,918		$	24,577	$	12,615
	Net income (loss)	$	(41,209	)	$	(1,029	)	$	10,951		$	6,425	$	(24,862	)
	Net income (loss) per common share(a):
	Basic	$	(3.39	)	$	(0.08	)	$	0.9		$	0.53	$	(2.04	)
	Diluted	$	(3.39	)	$	(0.08	)	$	0.9		$	0.53	$	(2.04	)
	Weighted average common shares outstanding:
	Basic	12,165			12,165			12,165			12,165		12,165
	Diluted	12,165			12,165			12,165			12,165		12,165
	Year ended December 31, 2012:
	Total revenues	$	109,069		$	104,610		$	107,763		$	101,610	$	423,052
	Operating income	$	26,795		$	20,837		$	21,573		$	10,588	$	79,793
	Net income (loss)	$	7,779		$	32,822		$	(7,176	)	$	1,678	$	35,103
	Net income (loss) per common share(a):
	Basic	$	0.64		$	2.7		$	(0.59	)	$	0.14	$	2.89
	Diluted	$	0.64		$	2.7		$	(0.59	)	$	0.14	$	2.89
	Weighted average common shares outstanding:
	Basic	12,164			12,164			12,164			12,164		12,164
	Diluted	12,164			12,164			12,164			12,164		12,164
	_______
	(a)	The sum of the individual quarterly net income (loss) per share amounts may not agree to the total for the year since each period’s computation is based on the weighted average number of common shares outstanding during each period.

Supplemental_Oil_and_Gas_Reser

Supplemental Oil and Gas Reserve Information	12 Months Ended
	Dec. 31, 2013
Extractive Industries [Abstract]	'
Supplemental Oil and Gas Reserve Information	'
	Supplemental Oil and Gas Reserve Information
	The estimates of proved oil and gas reserves utilized in the preparation of the consolidated financial statements were prepared by independent petroleum engineers.  Such estimates are in accordance with guidelines established by the Securities and Exchange Commission and the FASB.  All of our reserves are located in the United States.  For information about our results of operations from oil and gas activities, see the accompanying consolidated statements of operations and comprehensive income (loss).
	We emphasize that reserve estimates are inherently imprecise.  Accordingly, the estimates are expected to change as more current information becomes available.  In addition, a portion of our proved reserves are classified as proved developed nonproducing and proved undeveloped, which increases the imprecision inherent in estimating reserves which may ultimately be produced.
	We did not have any capital costs relating to exploratory wells pending the determination of proved reserves for the years ended December 31, 2013, 2012 and 2011.
	The following table sets forth estimated proved reserves together with the changes therein (oil and NGL in MBbls, gas in MMcf, gas converted to MBOE by dividing MMcf by six) for the years ended December 31, 2013, 2012 and 2011.
		Oil			Natural Gas Liquids			Natural Gas			MBOE
	Proved reserves:
	December 31, 2010	34,379			3,436			79,497			51,065
	Extensions and discoveries	16,121			1,449			19,864			20,881
	Revisions	(1,809	)		7			(1,227	)		(2,007	)
	Sales of minerals-in-place	(45	)		—			(664	)		(156	)
	Production	(3,727	)		(275	)		(8,594	)		(5,434	)
	December 31, 2011	44,919			4,617			88,876			64,349
	Extensions and discoveries	13,501			3,175			22,604			20,443
	Revisions	(7,303	)		1,805			(6,699	)		(6,615	)
	Purchases of minerals-in-place	2,456			18			6,182			3,504
	Sales of minerals-in-place	(633	)		—			(555	)		(725	)
	Production	(3,821	)		(433	)		(8,072	)		(5,599	)
	December 31, 2012	49,119			9,182			102,336			75,357
	Extensions and discoveries	20,540			3,562			21,389			27,666
	Revisions	85			1,806			(16,753	)		(901	)
	Sales of minerals-in-place	(17,387	)		(5,531	)		(23,605	)		(26,852	)
	Production	(3,692	)		(532	)		(6,188	)		(5,255	)
	December 31, 2013	48,665			8,487			77,179			70,015
	Proved developed reserves:
	December 31, 2011	26,198			2,764			61,811			39,264
	December 31, 2012	27,641			5,044			64,013			43,354
	December 31, 2013	25,989			4,293			47,839			38,255
	CLAYTON WILLIAMS ENERGY, INC.
	SUPPLEMENTAL INFORMATION (Continued)
	(UNAUDITED)
	Net downward revisions of 901 MBOE consisted of downward revisions of 1,504 MBOE primarily related to well performance offset in part by upward revisions of 603 MBOE, which were attributable to the effects of higher commodity prices on estimated quantities of proved reserves.
	The standardized measure of discounted future net cash flows relating to estimated proved reserves as of December 31, 2013, 2012 and 2011 was as follows:
		2013				2012				2011
		(In thousands)
	Future cash inflows	$	5,162,702			$	5,222,621			$	4,811,837
	Future costs:
	Production	(1,724,560		)		(1,819,356		)		(1,558,067		)
	Abandonment	(131,747		)		(137,499		)		(110,833		)
	Development	(592,695		)		(651,292		)		(510,709		)
	Income taxes	(786,196		)		(673,686		)		(757,253		)
	Future net cash flows	1,927,504				1,940,788				1,874,975
	10% discount factor	(1,000,581		)		(1,000,957		)		(936,462		)
	Standardized measure of discounted net cash flows	$	926,923			$	939,831			$	938,513
	Changes in the standardized measure of discounted future net cash flows relating to estimated proved reserves for the years ended December 31, 2013, 2012 and 2011 were as follows:
		2013				2012				2011
		(In thousands)
	Standardized measure, beginning of period	$	939,831			$	938,513			$	684,438
	Net changes in sales prices, net of production costs	13,292				(196,930		)		206,357
	Revisions of quantity estimates	(10,680		)		(144,899		)		(53,089		)
	Accretion of discount	130,736				137,369				99,028
	Changes in future development costs, including development costs incurred that reduced future development costs	46,068				148,733				84,638
	Changes in timing and other	(10,249		)		(58,323		)		(45,055		)
	Net change in income taxes	(84,673		)		76,593				(130,562		)
	Future abandonment cost, net of salvage	232				(9,230		)		925
	Extensions and discoveries	502,619				289,999				399,068
	Sales, net of production costs	(289,035		)		(277,248		)		(305,769		)
	Purchases of minerals-in-place	—				80,744				—
	Sales of minerals-in-place	(311,218		)		(45,490		)		(1,466		)
	Standardized measure, end of period	$	926,923			$	939,831			$	938,513
	CLAYTON WILLIAMS ENERGY, INC.
	SUPPLEMENTAL INFORMATION (Continued)
	(UNAUDITED)
The estimated present value of future cash flows relating to estimated proved reserves is extremely sensitive to prices used at any measurement period.  Average prices for December 31, 2013, 2012 and 2011 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period from January through December during each respective calendar year. The average prices used for each commodity for the years ended December 31, 2013, 2012 and 2011 were as follows:
	Average Price
	Oil				Natural Gas Liquids				Natural Gas
As of December 31:
2013	$	94.88			$	31.63			$	3.59
2012	$	90.45			$	43.74			$	3.7
2011	$	91.35			$	51.19			$	5.31

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Estimates and Assumptions	'
	Estimates and Assumptions
	The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods.  Actual results could differ materially from those estimates.  The accounting policies most affected by management’s estimates and assumptions are as follows:
	•	Provisions for depreciation, depletion and amortization and estimates of non-equity plans are based on estimates of proved reserves;
	•	Impairments of long-lived assets are based on estimates of future net cash flows and, when applicable, the estimated fair values of impaired assets;
	•	Exploration expenses related to impairments of unproved acreage are based on estimates of fair values of the underlying leases;
	•	Impairments of inventory are based on estimates of fair values of tubular goods and other well equipment held in inventory;
	•	Exploration expenses related to well abandonment costs are based on the judgments regarding the productive status of in-progress exploratory wells; and
	•	Asset retirement obligations (“ARO”) are based on estimates regarding the timing and cost of future asset retirements.
Principles of Consolidation	'
	Principles of Consolidation
	The consolidated financial statements include the accounts of CWEI and its wholly owned subsidiaries.  We also account for our undivided interests in oil and gas limited partnerships using the proportionate consolidation method.  Under this method, we consolidate our proportionate share of assets, liabilities, revenues and expenses of these limited partnerships.  Less than 5% of the Company’s consolidated total assets and total revenues are derived from oil and gas limited partnerships.  All significant intercompany transactions and balances associated with the consolidated operations have been eliminated.
Oil and Gas Properties	'
	Oil and Gas Properties
	We follow the successful efforts method of accounting for oil and gas properties, whereby costs of productive wells, developmental dry holes and productive leases are capitalized into appropriate groups of properties based on geographical and geological similarities.  These capitalized costs are amortized using the unit-of-production method based on estimated proved reserves. Proceeds from sales of properties are credited to property costs, and a gain or loss is recognized when a significant portion of an amortization base is sold or abandoned.
	Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to exploration expense if and when the well is determined to be nonproductive.  The determination of an exploratory well’s ability to produce must be made within one year from the completion of drilling activities.  The acquisition costs of unproved acreage are initially capitalized and are carried at cost, net of accumulated impairment provisions, until such leases are transferred to proved properties or charged to exploration expense as impairments of unproved properties.
Pipelines and Other Midstream Facilities and Other Property and Equipment	'
	Pipelines and Other Midstream Facilities and Other Property and Equipment
	Pipelines and other midstream facilities consist of pipelines to transport oil, gas and water, gas processing facilities and compressors.  Other property and equipment consists primarily of field equipment and facilities, office equipment, leasehold improvements and vehicles.  Major renewals and betterments are capitalized while repairs and maintenance are charged to expense as incurred.  The cost of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and any gain or loss is included in operating income in the accompanying consolidated statements of operations and comprehensive income (loss).
	Depreciation of pipelines and other midstream facilities and other property and equipment is computed on the straight-line method over the estimated useful lives of the assets, which generally range from 3 to 30 years.
Contract Drilling	'
	Contract Drilling
	We conduct contract drilling operations through Desta Drilling, a wholly owned subsidiary of CWEI.  Desta Drilling recognizes revenues and expenses from daywork drilling contracts as the work is performed, but defers revenues and expenses from footage or turnkey contracts until the well is substantially completed or until a loss, if any, on a contract is determinable.
	Property and equipment, including buildings, major replacements, improvements and capitalized interest on construction-in-progress, are capitalized and are depreciated using the straight-line method over estimated useful lives of 3 to 40 years.  Upon disposition, the costs and related accumulated depreciation of assets are eliminated from the accounts and the resulting gain or loss is recognized.
Valuation of Property and Equipment	'
	Valuation of Property and Equipment
	Our long-lived assets, including proved oil and gas properties and contract drilling equipment, are assessed for potential impairment in their carrying values, based on depletable groupings, whenever events or changes in circumstances indicate such impairment may have occurred.  An impairment is recognized when the estimated undiscounted future net cash flows of the asset are less than its carrying value.  Any such impairment is recognized based on the difference in the carrying value and estimated fair value of the impaired asset.
	Unproved oil and gas properties are periodically assessed, and any impairment in value is charged to exploration costs.  The amount of impairment recognized on unproved properties which are not individually significant is determined by impairing the costs of such properties within appropriate groups based on our historical experience, acquisition dates and average lease terms.  The valuation of unproved properties is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values.
Asset Retirement Obligations	'
	Asset Retirement Obligations
	We recognize a liability for the present value of all legal obligations associated with the retirement of tangible, long-lived assets and capitalize an equal amount as a cost of the asset.  The cost associated with the asset retirement obligation, along with any estimated salvage value, is included in the computation of depreciation, depletion and amortization.
Income Taxes	'
	Income Taxes
	We utilize the asset and liability method to account for income taxes.  Under this method of accounting for income taxes, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the consolidated financial statement carrying amounts of existing assets and liabilities and their respective tax bases.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.  The effect on deferred tax assets and liabilities of a change in enacted tax rates is recognized in the consolidated statements of operations and comprehensive income (loss) in the period that includes the enactment date.  We also record any financial statement recognition and disclosure requirements for uncertain tax positions taken or expected to be taken in a tax return.  Financial statement recognition of the tax position is dependent on an assessment of a 50% or greater likelihood that the tax position will be sustained upon examination, based on the technical merits of the position.  Any interest and penalties related to uncertain tax positions are recorded as interest expense.
Hedging Activities	'
	Hedging Transactions
	From time to time, we utilize derivative instruments, consisting of swaps, floors and collars, to attempt to optimize the price received for our oil and gas production.  All of our derivative instruments are recognized as assets or liabilities in the balance sheet, measured at fair value.  The accounting for changes in the fair value of a derivative depends on both the intended purpose and the formal designation of the derivative.  Designation is established at the inception of a derivative, but subsequent changes to the designation are permitted.  For derivatives designated as cash flow hedges and meeting the effectiveness guidelines under applicable accounting standards, changes in fair value are recognized in other comprehensive income (loss) until the hedged item is recognized in earnings.  Hedge effectiveness is measured quarterly based on relative changes in fair value between the derivative contract and the hedged item over time.  Any change in fair value resulting from ineffectiveness is recognized immediately in earnings.  Changes in fair value of derivative instruments which are not designated as cash flow hedges or do not meet the effectiveness guidelines are recorded in earnings as the changes occur.  If designated as cash flow hedges, actual gains or losses on settled commodity derivatives are recorded as oil and gas revenues in the period the hedged production is sold, while actual gains or losses on interest rate derivatives are recorded in interest expense for the applicable period.  Actual gains or losses from derivatives not designated as cash flow hedges are recorded in other income (expense) as gain (loss) on derivatives.
Inventory	'
	Inventory
	Inventory consists primarily of tubular goods and other well equipment which we plan to utilize in our exploration and development activities and is stated at the lower of average cost or estimated market value.
Capitalization of Interest	'
	Capitalization of Interest
	Interest costs associated with our inventory of unproved oil and gas property lease acquisition costs are capitalized during the periods for which exploration activities are in progress.
Cash and Cash Equivalents	'
	Cash and Cash Equivalents
	We consider all cash and highly liquid investments with original maturities of three months or less to be cash equivalents.
Net Income Per Common Share	'
	Net Income (Loss) Per Common Share
	Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of Common Shares outstanding for the period.  Diluted net income per share reflects the potential dilution that could occur if dilutive stock options were exercised, calculated using the treasury stock method.  The diluted net income per share calculations for 2012 and 2011 include changes in potential shares attributable to dilutive stock options.
Stock-Based Compensation	'
	Stock-Based Compensation
	We measure and recognize compensation expense for all share-based payment awards, including employee stock options, based on estimated fair values. The value of the portion of the award that is ultimately expected to vest is recognized as expense on a straight-line basis over the requisite service periods, if any.
	We estimate the fair value of stock option awards on the date of grant using an option-pricing model.  We use the Black-Scholes option-pricing model as our method of valuation for share-based awards granted on or after January 1, 2006.  Our determination of fair value of share-based payment awards on the date of grant using an option-pricing model is affected by our stock price, as well as assumptions regarding a number of subjective variables.  These variables include, but are not limited to, our expected stock price volatility over the term of the awards, as well as actual and projected exercise and forfeiture activity.
Fair Value Measurements	'
	Fair Value Measurements
	We follow a framework for measuring fair value, which outlines a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements.  Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.  We categorize our assets and liabilities recorded at fair value in the accompanying consolidated balance sheets based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities are as follows:
	Level 1 -	Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.
	Level 2 -	Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.
	Level 3 -	Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.
Revenue Recognition and Gas Balancing	'
	Revenue Recognition and Gas Balancing
	We utilize the sales method of accounting for oil, natural gas and NGL revenues whereby revenues, net of royalties, are recognized as the production is sold to purchasers.  The amount of gas sold may differ from the amount to which we are entitled based on our revenue interests in the properties.  We did not have any significant gas imbalance positions at December 31, 2013, 2012 or 2011.  Revenues from midstream services and drilling rig services are recognized as services are provided.
Comprehensive Income (Loss)	'
	Comprehensive Income (Loss)
	There were no differences between net income (loss) and comprehensive income (loss) in 2013, 2012 and 2011.
Concentration Risks	'
	Concentration Risks
	We sell our oil and natural gas production to various customers, serve as operator in the drilling, completion and operation of oil and gas wells, and enter into derivatives with various counterparties.  When management deems appropriate, we obtain letters of credit to secure amounts due from our principal oil and gas purchasers and follow other procedures to monitor credit risk from joint owners and derivatives counterparties.  Allowances for doubtful accounts at December 31, 2013 and 2012 relate to amounts due from joint interest owners.
Recent Accounting Pronouncements	'
	Recent Accounting Pronouncements
	In December 2011, the Financial Accounting Standards Board (the “FASB”) issued ASU No. 2011-11, “Balance Sheet (Topic 210), Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”).  ASU 2011-11 will require entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement.  In January 2013, the FASB issued Accounting Standards Update No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“ASU 2013-01”). The amendments in ASU 2013-01 clarify that the disclosure requirements of ASU 2011-11 are limited to derivatives, including bifurcated embedded derivatives, repurchase and reverse repurchase agreements, and securities borrowing and lending transactions that are either offset in the statement of financial position or subject to an enforceable master netting arrangement or similar agreement. ASU 2013-01 is effective retrospectively for annual periods beginning on or after January 1, 2013. The adoption of these new accounting rules did not have a material effect on our financial condition, results of operations or cash flows.

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Schedule of long-term debt	'
	Long-term debt consists of the following:
		December 31,		December 31,
		2013		2012
		(In thousands)
	7.75% Senior Notes due 2019, net of unamortized original issue discount of $362 at December 31, 2013 and $415 at December 31, 2012	$	599,638	$	349,585
	Revolving credit facility, due November 2015	40,000		460,000
		$	639,638	$	809,585

Acquisition_of_Southwest_Royal1

Acquisition of Southwest Royalties, Inc. Limited Partnerships (Tables)	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
Summary of estimated fair value of the assets acquired and liabilities assumed	'
	The following table summarizes the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):
	Cash and cash equivalents	$	4,118
	Oil and gas properties	41,098
	Other non-current assets	210
	Total assets acquired	45,426
	Asset retirement obligations	(6,864		)
	Total liabilities assumed	(6,864		)
	Net assets acquired	$	38,562

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Schedule of changes in asset retirement obligations	'
	The following table reflects the changes in ARO for the years ended December 31, 2013 and December 31, 2012:
		2013			2012
		(In thousands)
	Beginning of year	$	51,477		$	40,794
	Additional ARO from new properties	795			7,868
	Sales or abandonments of properties	(5,892		)	(2,184		)
	Accretion expense	4,203			3,696
	Revisions of previous estimates	(602		)	1,303
	End of year	$	49,981		$	51,477

Deferred_Revenue_from_Volumetr1

Deferred Revenue from Volumetric Production Payment (Tables)	12 Months Ended
	Dec. 31, 2013
Deferred Revenue Disclosure [Abstract]	'
Schedule of changes in deferred revenue from the VPP	'
	The following table reflects the changes in deferred revenue during the years ended December 31, 2013 and December 31, 2012:
		2013			2012
		(In thousands)
	Beginning of period	$	37,184		$	—
	Deferred revenue from VPP	1,332			45,479
	Amortization of deferred revenue from VPP	(8,746		)	(8,295		)
	End of period	$	29,770		$	37,184

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Schedule of deferred tax assets and liabilities	'
	Significant components of net deferred tax assets (liabilities) at December 31, 2013 and 2012 are as follows:
		2013			2012
		(In thousands)
	Deferred tax assets:
	Net operating loss carryforwards	$	65,814		$	122,393
	Statutory depletion carryforwards	8,658			8,159
	Asset retirement obligations and other	22,470			21,814
		96,942			152,366
	Deferred tax liabilities:
	Fair value of derivatives	(598		)	(4,208		)
	Property and equipment	(229,572		)	(295,428		)
		(230,170		)	(299,636		)
	Net deferred tax liabilities	$	(133,228	)	$	(147,270	)
	Components of net deferred tax liabilities:
	Current assets	$	7,581		$	8,560
	Non-current liabilities	(140,809		)	(155,830		)
	Net deferred tax liabilities	$	(133,228	)	$	(147,270	)
Schedule of effective income tax rate reconciliation	'
	For the years ended December 31, 2013, 2012 and 2011, effective income tax rates were different than the statutory federal income tax rates for the following reasons:
		2013			2012			2011
		(In thousands)
	Income tax expense at statutory rate of 35%	$	(13,052	)	$	19,989		$	50,921
	Tax depletion in excess of basis	(518		)	(581		)	(425		)
	Revision of previous tax estimates	373			700			217
	State income taxes, net of federal tax effect	76			1,513			1,310
	Other	693			387			119
	Income tax expense (benefit)	$	(12,428	)	$	22,008		$	52,142
	Current	$	1,614		$	—		$	(408	)
	Deferred	(14,042		)	22,008			52,550
	Income tax expense (benefit)	$	(12,428	)	$	22,008		$	52,142

Derivatives_Tables

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2013
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 December 31, 2013.  The settlement prices of commodity derivatives are based on NYMEX futures prices.
	Swaps
		Oil
		Bbls			Price
	Production Period:
	1st Quarter 2014	606,000			$	96.74
	2nd Quarter 2014	560,600			$	96.81
	3rd Quarter 2014	530,200			$	96.87
	4th Quarter 2014	503,200			$	96.92
		2,200,000
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 December 31, 2013
		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		$	2,518			Current		$	208
		Non-current		—				Non-current		—
	Total			$	2,518					$	208
		Fair Value of Derivative Instruments as of December 31, 2012
		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		$	7,495			Current		$	—
		Non-current		4,236				Non-current		—
	Total			$	11,731					$	—
Schedule of gross to net presentation reconciliation of derivative assets and liabilities	'
	Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities
		31-Dec-13
		Assets				Liabilities
		(In thousands)
	Fair value of derivatives — gross presentation	$	3,909			$	1,599
	Effects of netting arrangements	(1,391		)		(1,391		)
	Fair value of derivatives — net presentation	$	2,518			$	208
		31-Dec-12
		Assets				Liabilities
		(In thousands)
	Fair value of derivatives — gross presentation	$	17,851			$	6,120
	Effects of netting arrangements	(6,120		)		(6,120		)
	Fair value of derivatives — net presentation	$	11,731			$	—
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
			Year Ended December 31, 2013
	Location of Gain or (Loss) Recognized in Earnings		Realized				Unrealized				Total
			(In thousands)
	Derivatives not designated as hedging instruments:
	Commodity derivatives:
	Other income (expense) - Gain (loss) on derivatives		$	690			$	(9,421	)		$	(8,731	)
	Total		$	690			$	(9,421	)		$	(8,731	)
			Amount of Gain or (Loss) Recognized in Earnings
			Year Ended December 31, 2012
	Location of Gain or (Loss) Recognized in Earnings		Realized				Unrealized				Total
			(In thousands)
	Derivatives not designated as hedging instruments:
	Commodity derivatives:
	Other income (expense) - Gain (loss) on derivatives		$	(3,410	)		$	17,858			$	14,448
	Total		$	(3,410	)		$	17,858			$	14,448
			Amount of Gain or (Loss) Recognized in Earnings
			Year Ended December 31, 2011
	Location of Gain or (Loss) Recognized in Earnings		Realized				Unrealized				Total
			(In thousands)
	Derivatives not designated as hedging instruments:
	Commodity derivatives:
	Other income (expense) - Gain (loss) on derivatives		$	42,521			$	4,506			$	47,027
	Total		$	42,521			$	4,506			$	47,027

Fair_Value_of_Financial_Instru1

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2013
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:
		December 31,
		2013		2012
		Significant Other
		Observable Inputs
	Description	(Level 2)
		(In thousands)
	Assets:
	Fair value of commodity derivatives	$	2,518	$	11,731
	Total assets	$	2,518	$	11,731
	Liabilities:
	Fair value of commodity derivatives	$	208	$	—
	Total liabilities	$	208	$	—
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:
		31-Dec-13				31-Dec-12
		Carrying		Estimated		Carrying		Estimated
	Description	Amount		Fair Value		Amount		Fair Value
		(In thousands)
	7.75% Senior Notes due 2019	$	599,638	$	616,500	$	349,585	$	348,700

Compensation_Plans_Tables

Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2013
Compensation Plans [Abstract]	'
Schedule of stock options activity	'
	The following table sets forth certain information regarding our stock option plans as of and for the year ended December 31, 2013:
		Shares		Weighted			Weighted		Aggregate
				Average			Average		Intrinsic
				Exercise			Remaining		Value(a)
				Price			Contractual
							Term
	Outstanding at January 1, 2013	5,000		$	32.21
	Exercised (b)	(1,000	)	$	28.93
	Outstanding at December 31, 2013	4,000		$	33.03		2.5		$	195,690
	Vested at December 31, 2013	4,000		$	33.03		2.5		$	195,690
	Exercisable at December 31, 2013	4,000		$	33.03		2.5		$	195,690
	_______
	(a)	Based on closing price at December 31, 2013 of $81.95 per share.
	(b)	Cash received for options exercised totaled $28,930.
Schedule of shares authorized under stock option plans, by exercise price range	'
	The following table summarizes information with respect to options outstanding at December 31, 2013, all of which were granted under the Directors Plan and are currently exercisable.
		Outstanding and Exercisable Options
							Weighted
		Shares		Weighted			Average
				Average			Remaining
				Exercise			Life in
				Price			Years
	Range of exercise prices:
	$22.90 - $41.74	4,000		$	33.03		2.5
Disclosure of share-based compensation arrangements by share-based payment award	'
	The following table presents certain information regarding stock-based compensation amounts for the years ended December 31, 2013, 2012 and 2011.
		2013			2012			2011
		(In thousands, except per share)
	Weighted average grant date fair value of options granted per share	$	—		$	—		$	—
	Intrinsic value of options exercised	$	53		$	28		$	594
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:
		December 31,			December 31,
		2013			2012
		(In thousands)
	Current liabilities:
	Accrued liabilities and other	$	3,317		$	2,220
	Non-current liabilities:
	Accrued compensation under non-equity award plans	15,469			20,058
	Total accrued compensation under non-equity award plans	$	18,786		$	22,278

Transactions_with_Affiliates_T

Transactions with Affiliates (Tables)	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Summary of charges to and from Williams Entities	'
	The following table summarizes the charges to and from the Williams Entities for the years ended December 31, 2013, 2012 and 2011.
		2013		2012		2011
		(In thousands)
	Amounts received from the Williams Entities:
	Service Agreement:
	Services	$	715	$	671	$	566
	Insurance premiums and benefits	837		920		821
	Reimbursed expenses	427		566		371
		$	1,979	$	2,157	$	1,758
	Amounts paid to the Williams Entities:
	Rent(a)	$	1,560	$	1,478	$	843
	Service Agreement:
	Business entertainment(b)	344		116		116
	Reimbursed expenses	216		267		289
		$	2,120	$	1,861	$	1,248
	_______
	(a)	Rent amounts were paid to a partnership within the Williams Entities.  The Company owns 31.9% of the partnership and affiliates of the Company own 25.8%.
	(b)	Consists primarily of hunting and fishing recreation for business associates and employees of the Company on land owned by affiliates of Mr. Williams.

Other_Operating_Revenues_and_E1

Other Operating Revenues and Expenses (Tables)	12 Months Ended
	Dec. 31, 2013
Other Income and Expenses [Abstract]	'
Schedule of net gain on sales of assets and impairment of inventory	'
	Other operating revenues and expenses for the years ended December 31, 2013, 2012 and 2011 are as follows:
		2013			2012			2011
		(In thousands)
	Other operating revenues:
	Gain on sales of assets	$	4,467		$	1,496		$	15,744
	Marketing revenue	2,021			581			—
	Total other operating revenues	$	6,488		$	2,077		$	15,744
	Other operating expenses:
	Loss on sales of assets	$	(1,233	)	$	(523	)	$	(945	)
	Marketing expense	(658		)	—			—
	Impairment of inventory	(210		)	(510		)	(721		)
	Total other operating expenses	$	(2,101	)	$	(1,033	)	$	(1,666	)

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Schedule Future minimum payments under noncancelable leases	'
	Future minimum payments under noncancelable leases at December 31, 2013, are as follows:
		Leases
		Capital(a)		Operating(b)		Total
		(In thousands)
	2014	$	1,001	$	3,818	$	4,819
	2015	620		3,998		4,618
	2016	213		3,684		3,897
	Thereafter	—		338		338
	Total minimum lease payments	$	1,834	$	11,838	$	13,672
	_______
	(a)          Relates to vehicle leases.
	(b)         Includes leases for two drilling rigs.

Costs_of_Oil_and_Gas_Propertie1

Costs of Oil and Gas Properties (Tables)	12 Months Ended
	Dec. 31, 2013
Oil and Gas Property, Successful Effort Method, Gross [Abstract]	'
Costs incurred in connection with the company's oil and gas producing activities	'
	The following table sets forth certain information with respect to costs incurred in connection with the Company’s oil and gas producing activities during the years ended December 31, 2013, 2012 and 2011.
		2013			2012			2011
		(In thousands)
	Property acquisitions:
	Proved	$	—		$	41,098		$	—
	Unproved	50,104			72,235			61,236
	Developmental costs	218,341			349,972			328,418
	Exploratory costs	3,932			10,898			27,425
	Total	$	272,377		$	474,203		$	417,079
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 December 31, 2013 and 2012.
		2013			2012
		(In thousands)
	Proved properties	$	2,317,053		$	2,482,185
	Unproved properties	86,224			88,618
	Total capitalized costs	2,403,277			2,570,803
	Accumulated depletion	(1,282,989		)	(1,234,626		)
	Net capitalized costs	$	1,120,288		$	1,336,177

Segment_Information_Tables

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Schedule of selected financial information regarding operating segments	'
	The following tables present selected financial information regarding our operating segments for the years ended December 31, 2013, 2012 and 2011.
						Contract			Intercompany			Consolidated
	For the Year Ended December 31, 2013		Oil and Gas			Drilling			Eliminations			Total
			(In thousands)
	Revenues		$	411,403		$	37,255		$	(19,443	)	$	429,215
	Depreciation, depletion and amortization(a)		229,460			13,844			(2,591		)	240,713
	Other operating expenses(b)		159,294			32,817			(16,224		)	175,887
	Interest expense		43,079			—			—			43,079
	Other (income) expense		6,826			—			—			6,826
	Income (loss) before income taxes		(27,256		)	(9,406		)	(628		)	(37,290		)
	Income tax (expense) benefit		9,136			3,292			—			12,428
	Net income (loss)		$	(18,120	)	$	(6,114	)	$	(628	)	$	(24,862	)
	Total assets		$	1,339,920		$	54,697		$	(27,880	)	$	1,366,737
	Additions to property and equipment		$	280,173		$	5,107		$	(628	)	$	284,652
						Contract			Intercompany			Consolidated
	For the Year Ended December 31, 2012		Oil and Gas			Drilling			Eliminations			Total
			(In thousands)
	Revenues		$	407,194		$	57,218		$	(41,360	)	$	423,052
	Depreciation, depletion and amortization(a)		140,967			14,442			(6,778		)	148,631
	Other operating expenses(b)		176,922			52,678			(34,972		)	194,628
	Interest expense		38,664			—			—			38,664
	Other (income) expense		(15,979		)	(3		)	—			(15,982		)
	Income (loss) before income taxes		66,620			(9,899		)	390			57,111
	Income tax (expense) benefit		(25,473		)	3,465			—			(22,008		)
	Net income (loss)		$	41,147		$	(6,434	)	$	390		$	35,103
	Total assets		$	1,535,544		$	64,045		$	(25,005	)	$	1,574,584
	Additions to property and equipment		$	500,161		$	15,207		$	390		$	515,758
						Contract			Intercompany			Consolidated
	For the Year Ended December 31, 2011		Oil and Gas			Drilling			Eliminations			Total
			(In thousands)
	Revenues		$	422,368		$	52,716		$	(48,656	)	$	426,428
	Depreciation, depletion and amortization(a)		112,863			12,214			(9,842		)	115,235
	Other operating expenses(b)		174,027			44,318			(38,957		)	179,388
	Interest expense		32,919			—			—			32,919
	Other (income) expense		(33,280		)	(13,799		)	—			(47,079		)
	Income (loss) before income taxes		135,839			9,983			143			145,965
	Income tax (expense) benefit		(48,648		)	(3,494		)	—			(52,142		)
	Net income (loss)		$	87,191		$	6,489		$	143		$	93,823
	Total assets		$	1,178,725		$	62,846		$	(15,300	)	$	1,226,271
	Additions to property and equipment		$	429,142		$	17,578		$	143		$	446,863
	_______
	(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_Informatio1

Guarantor Financial Information (Tables)	12 Months Ended
	Dec. 31, 2013
Guarantor Financial Information Disclosure [Abstract]	'
Schedule of Condensed Consolidating Balance Sheet	'
	Condensed Consolidating Balance Sheet
	December 31, 2013
	(Dollars in thousands)
		Issuer			Guarantor			Non-Guarantor			Adjustments/			Consolidated
					Subsidiaries			Subsidiary			Eliminations
	Current assets	$	140,100		$	248,314		$	538		$	(250,641	)	$	138,311
	Property and equipment, net	833,980			351,171			13,956			—			1,199,107
	Investments in subsidiaries	342,416			—			—			(342,416		)	—
	Other assets	16,032			13,287			—			—			29,319
	Total assets	$	1,332,528		$	612,772		$	14,494		$	(593,057	)	$	1,366,737
	Current liabilities	$	290,327		$	93,055		$	976		$	(247,963	)	$	136,395
	Non-current liabilities:
	Long-term debt	639,638			—			—			—			639,638
	Deferred income taxes	118,438			129,880			988			(108,497		)	140,809
	Other	36,161			59,829			122			—			96,112
		794,237			189,709			1,110			(108,497		)	876,559
	Equity	247,964			330,008			12,408			(236,597		)	353,783
	Total liabilities and equity	$	1,332,528		$	612,772		$	14,494		$	(593,057	)	$	1,366,737
	Condensed Consolidating Balance Sheet
	December 31, 2012
	(Dollars in thousands)
		Issuer			Guarantor			Non-Guarantor			Adjustments/			Consolidated
					Subsidiaries			Subsidiary			Eliminations
	Current assets	$	133,080		$	224,210		$	—		$	(232,820	)	$	124,470
	Property and equipment, net	1,053,453			366,905			—			—			1,420,358
	Investments in subsidiaries	305,899			—			—			(305,899		)	—
	Fair value of derivatives	4,236			—			—			—			4,236
	Other assets	12,112			13,408			—			—			25,520
	Total assets	$	1,508,780		$	604,523		$	—		$	(538,719	)	$	1,574,584
	Current liabilities	$	241,200		$	112,534		$	—		$	(232,820	)	$	120,914
	Non-current liabilities:
	Long-term debt	809,585			—			—			—			809,585
	Deferred income taxes	143,699			117,950			—			(105,819		)	155,830
	Other	41,499			68,140			—			—			109,639
		994,783			186,090			—			(105,819		)	1,075,054
	Equity	272,797			305,899			—			(200,080		)	378,616
	Total liabilities and equity	$	1,508,780		$	604,523		$	—		$	(538,719	)	$	1,574,584
Schedule of Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)	'
	Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)
	Year Ended December 31, 2013
	(Dollars in thousands)
		Issuer			Guarantor			Non-Guarantor			Adjustments/			Consolidated
					Subsidiaries			Subsidiary			Eliminations
	Total revenue	$	280,423		$	146,556		$	2,236		$	—		$	429,215
	Costs and expenses	302,898			112,441			1,261			—			416,600
	Operating income (loss)	(22,475		)	34,115			975			—			12,615
	Other income (expense)	(50,601		)	(25		)	721			—			(49,905		)
	Equity in earnings of subsidiaries	23,261			—			—			(23,261		)	—
	Income tax (expense) benefit	24,953			(11,931		)	(594		)	—			12,428
	Net income (loss)	$	(24,862	)	$	22,159		$	1,102		$	(23,261	)	$	(24,862	)
	Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)
	Year Ended December 31, 2012
	(Dollars in thousands)
		Issuer			Guarantor			Non-Guarantor			Adjustments/			Consolidated
					Subsidiaries			Subsidiary			Eliminations
	Total revenue	$	291,782		$	132,690		$	—		$	(1,420	)	$	423,052
	Costs and expenses	230,033			114,646			—			(1,420		)	343,259
	Operating income (loss)	61,749			18,044			—			—			79,793
	Other income (expense)	(25,495		)	2,813			—			—			(22,682		)
	Equity in earnings of subsidiaries	13,557			—			—			(13,557		)	—
	Income tax (expense) benefit	(14,708		)	(7,300		)	—			—			(22,008		)
	Net income (loss)	$	35,103		$	13,557		$	—		$	(13,557	)	$	35,103
	Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)
	Year Ended December 31, 2011
	(Dollars in thousands)
		Issuer			Guarantor			Non-Guarantor			Adjustments/			Consolidated
					Subsidiaries			Subsidiary			Eliminations
	Total revenue	$	280,359		$	147,015		$	—		$	(946	)	$	426,428
	Costs and expenses	191,012			104,557			—			(946		)	294,623
	Operating income (loss)	89,347			42,458			—			—			131,805
	Other income (expense)	6,816			7,344			—			—			14,160
	Equity in earnings of subsidiaries	32,371			—			—			(32,371		)	—
	Income tax (expense) benefit	(34,711		)	(17,431		)	—			—			(52,142		)
	Net income (loss)	$	93,823		$	32,371		$	—		$	(32,371	)	$	93,823
Schedule of Condensed Consolidating Statement of Cash Flows	'
	Condensed Consolidating Statement of Cash Flows
	Year Ended December 31, 2013
	(Dollars in thousands)
		Issuer			Guarantor			Non-Guarantor			Adjustments/			Consolidated
					Subsidiaries			Subsidiary			Eliminations
	Operating activities	$	128,146		$	87,433		$	2,406		$	2,591		$	220,576
	Investing activities	10,544			(34,121		)	(2,875		)	(2,591		)	(29,043		)
	Financing activities	(125,027		)	(51,122		)	513			—			(175,636		)
	Net increase (decrease) in cash and cash equivalents	13,663			2,190			44			—			15,897
	Cash at the beginning of the period	6,030			4,696			—			—			10,726
	Cash at end of the period	$	19,693		$	6,886		$	44		$	—		$	26,623
	Condensed Consolidating Statement of Cash Flows
	Year Ended December 31, 2012
	(Dollars in thousands)
		Issuer			Guarantor			Non-Guarantor			Adjustments/			Consolidated
					Subsidiaries			Subsidiary			Eliminations
	Operating activities	$	92,521		$	89,923		$	—		$	6,778		$	189,222
	Investing activities	(432,433		)	(36,822		)	—			(6,778		)	(476,033		)
	Financing activities	333,703			(53,691		)	—			—			280,012
	Net increase (decrease) in cash and cash equivalents	(6,209		)	(590		)	—			—			(6,799		)
	Cash at the beginning of the period	12,239			5,286			—			—			17,525
	Cash at end of the period	$	6,030		$	4,696		$	—		$	—		$	10,726
	Condensed Consolidating Statement of Cash Flows
	Year Ended December 31, 2011
	(Dollars in thousands)
		Issuer			Guarantor			Non-Guarantor			Adjustments/			Consolidated
					Subsidiaries			Subsidiary			Eliminations
	Operating activities	$	209,886		$	60,319		$	—		$	9,842		$	280,047
	Investing activities	(389,681		)	(5,390		)	—			(9,842		)	(404,913		)
	Financing activities	186,994			(53,323		)	—			—			133,671
	Net increase (decrease) in cash and cash equivalents	7,199			1,606			—			—			8,805
	Cash at the beginning of the period	5,040			3,680			—			—			8,720
	Cash at end of the period	$	12,239		$	5,286		$	—		$	—		$	17,525

Supplemental_Quarterly_Financi1

Supplemental Quarterly Financial Information (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Schedule of Quarterly Financial Information	'
	The following table summarizes results for each of the four quarters in the years ended December 31, 2013 and 2012.
		First			Second			Third			Fourth		Year
		Quarter			Quarter			Quarter			Quarter
		(In thousands, except per share)
	Year ended December 31, 2013:
	Total revenues	$	106,867		$	98,916		$	111,165		$	112,267	$	429,215
	Operating income (loss)	$	(50,883	)	$	5,003		$	33,918		$	24,577	$	12,615
	Net income (loss)	$	(41,209	)	$	(1,029	)	$	10,951		$	6,425	$	(24,862	)
	Net income (loss) per common share(a):
	Basic	$	(3.39	)	$	(0.08	)	$	0.9		$	0.53	$	(2.04	)
	Diluted	$	(3.39	)	$	(0.08	)	$	0.9		$	0.53	$	(2.04	)
	Weighted average common shares outstanding:
	Basic	12,165			12,165			12,165			12,165		12,165
	Diluted	12,165			12,165			12,165			12,165		12,165
	Year ended December 31, 2012:
	Total revenues	$	109,069		$	104,610		$	107,763		$	101,610	$	423,052
	Operating income	$	26,795		$	20,837		$	21,573		$	10,588	$	79,793
	Net income (loss)	$	7,779		$	32,822		$	(7,176	)	$	1,678	$	35,103
	Net income (loss) per common share(a):
	Basic	$	0.64		$	2.7		$	(0.59	)	$	0.14	$	2.89
	Diluted	$	0.64		$	2.7		$	(0.59	)	$	0.14	$	2.89
	Weighted average common shares outstanding:
	Basic	12,164			12,164			12,164			12,164		12,164
	Diluted	12,164			12,164			12,164			12,164		12,164
	_______
	(a)	The sum of the individual quarterly net income (loss) per share amounts may not agree to the total for the year since each period’s computation is based on the weighted average number of common shares outstanding during each period.

Supplemental_Oil_and_Gas_Reser1

Supplemental Oil and Gas Reserve Information (Tables)	12 Months Ended
	Dec. 31, 2013
Extractive Industries [Abstract]	'
Schedule of estimated proved oil and gas reserves	'
	The following table sets forth estimated proved reserves together with the changes therein (oil and NGL in MBbls, gas in MMcf, gas converted to MBOE by dividing MMcf by six) for the years ended December 31, 2013, 2012 and 2011.
		Oil			Natural Gas Liquids			Natural Gas			MBOE
	Proved reserves:
	December 31, 2010	34,379			3,436			79,497			51,065
	Extensions and discoveries	16,121			1,449			19,864			20,881
	Revisions	(1,809	)		7			(1,227	)		(2,007	)
	Sales of minerals-in-place	(45	)		—			(664	)		(156	)
	Production	(3,727	)		(275	)		(8,594	)		(5,434	)
	December 31, 2011	44,919			4,617			88,876			64,349
	Extensions and discoveries	13,501			3,175			22,604			20,443
	Revisions	(7,303	)		1,805			(6,699	)		(6,615	)
	Purchases of minerals-in-place	2,456			18			6,182			3,504
	Sales of minerals-in-place	(633	)		—			(555	)		(725	)
	Production	(3,821	)		(433	)		(8,072	)		(5,599	)
	December 31, 2012	49,119			9,182			102,336			75,357
	Extensions and discoveries	20,540			3,562			21,389			27,666
	Revisions	85			1,806			(16,753	)		(901	)
	Sales of minerals-in-place	(17,387	)		(5,531	)		(23,605	)		(26,852	)
	Production	(3,692	)		(532	)		(6,188	)		(5,255	)
	December 31, 2013	48,665			8,487			77,179			70,015
	Proved developed reserves:
	December 31, 2011	26,198			2,764			61,811			39,264
	December 31, 2012	27,641			5,044			64,013			43,354
	December 31, 2013	25,989			4,293			47,839			38,255
Standardized measure of discounted future net cash flows relating to estimated proved reserves	'
	The standardized measure of discounted future net cash flows relating to estimated proved reserves as of December 31, 2013, 2012 and 2011 was as follows:
		2013				2012				2011
		(In thousands)
	Future cash inflows	$	5,162,702			$	5,222,621			$	4,811,837
	Future costs:
	Production	(1,724,560		)		(1,819,356		)		(1,558,067		)
	Abandonment	(131,747		)		(137,499		)		(110,833		)
	Development	(592,695		)		(651,292		)		(510,709		)
	Income taxes	(786,196		)		(673,686		)		(757,253		)
	Future net cash flows	1,927,504				1,940,788				1,874,975
	10% discount factor	(1,000,581		)		(1,000,957		)		(936,462		)
	Standardized measure of discounted net cash flows	$	926,923			$	939,831			$	938,513
Schedule of changes in the standardized measure of discounted future net cash flows relating to estimated proved reserves	'
	Changes in the standardized measure of discounted future net cash flows relating to estimated proved reserves for the years ended December 31, 2013, 2012 and 2011 were as follows:
		2013				2012				2011
		(In thousands)
	Standardized measure, beginning of period	$	939,831			$	938,513			$	684,438
	Net changes in sales prices, net of production costs	13,292				(196,930		)		206,357
	Revisions of quantity estimates	(10,680		)		(144,899		)		(53,089		)
	Accretion of discount	130,736				137,369				99,028
	Changes in future development costs, including development costs incurred that reduced future development costs	46,068				148,733				84,638
	Changes in timing and other	(10,249		)		(58,323		)		(45,055		)
	Net change in income taxes	(84,673		)		76,593				(130,562		)
	Future abandonment cost, net of salvage	232				(9,230		)		925
	Extensions and discoveries	502,619				289,999				399,068
	Sales, net of production costs	(289,035		)		(277,248		)		(305,769		)
	Purchases of minerals-in-place	—				80,744				—
	Sales of minerals-in-place	(311,218		)		(45,490		)		(1,466		)
	Standardized measure, end of period	$	926,923			$	939,831			$	938,513
Schedule of average prices used for each commodity	'
	The average prices used for each commodity for the years ended December 31, 2013, 2012 and 2011 were as follows:
		Average Price
		Oil				Natural Gas Liquids				Natural Gas
	As of December 31:
	2013	$	94.88			$	31.63			$	3.59
	2012	$	90.45			$	43.74			$	3.7
	2011	$	91.35			$	51.19			$	5.31

Nature_of_Operations_Details

Nature of Operations (Details)	12 Months Ended
	Dec. 31, 2013
Nature of Operations Disclosures [Abstract]	'
Percentage of outstanding common stock beneficially owned by Mr.William's	26.00%
Percentage of outstanding common stock owned by a partnership in which Mr. William's adult children are limited partners	25.00%

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Concentration Risk [Line Items]	'	'	'
Capitalized interest costs	$1.40	$1	$0.70
Maximum | Assets, Total [Member] | Partnership Concentration Risk [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
The percentage of consolidated total assets and total revenues derived from oil and gas partnerships is less than	5.00%	'	'

Summary_of_Significant_Account3

Summary of Significant Accounting Policies - Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2013
Pipelines and other midstream facilities | Minimum	'
Property, Plant and Equipment [Line Items]	'
Useful life	'3 years
Pipelines and other midstream facilities | Maximum	'
Property, Plant and Equipment [Line Items]	'
Useful life	'30 years
Building and Building Improvements | Minimum	'
Property, Plant and Equipment [Line Items]	'
Useful life	'3 years
Building and Building Improvements | Maximum	'
Property, Plant and Equipment [Line Items]	'
Useful life	'40 years

LongTerm_Debt_Details

Long-Term Debt (Details) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Oct. 31, 2013

Apr. 30, 2011

Mar. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Oct. 31, 2013

Apr. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Oct. 02, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

7.75% Senior Notes due 2019

7.75% Senior Notes due 2019

7.75% Senior Notes due 2019

7.75% Senior Notes due 2019

7.75% Senior Notes due 2019

7.75% Senior Notes due 2019

7.75% Senior Notes due 2019

7.75% Senior Notes due 2019

Revolving credit facility, due November 2015

Revolving credit facility, due November 2015

Revolving credit facility, due November 2015

Revolving credit facility, due November 2015

Revolving credit facility, due November 2015

Revolving credit facility, due November 2015

Revolving credit facility, due November 2015

Revolving credit facility, due November 2015

Revolving credit facility, due November 2015

Revolving credit facility, due November 2015

Revolving credit facility, due November 2015

Revolving credit facility, due November 2015

Revolving credit facility, due November 2015

Revolving credit facility, due November 2015

Revolving credit facility, due November 2015

Revolving credit facility, due November 2015

Beginning on April 1, 2015

Beginning on April 1, 2016

On or after April 1, 2017

Quarter

Minimum

Maximum

Maximum

LIBOR

LIBOR

LIBOR

Prime rate

Federal funds rate

Base rate

Base rate

One-month LIBOR

installment

Minimum

Maximum

Minimum

Maximum

Long-Term Debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt

$639,638,000

$809,585,000

'

'

'

$599,638,000

$349,585,000

'

'

'

$40,000,000

'

'

'

$460,000,000

'

'

'

'

'

'

'

'

'

'

'

Aggregate maturities of long term debt in 2015

40,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Aggregate maturities of long term debt in 2019

599,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unamortized original issue discount

'

'

'

500,000

'

362,000

415,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Aggregate principal amount of notes issued

'

'

250,000,000

50,000,000

300,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest rate (as a percent)

'

'

'

'

7.75%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Original issue discount (as a percent)

'

'

'

1.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Redemption price of debt instrument (as a percent)

'

'

'

'

'

'

'

103.88%

101.94%

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum borrowing capacity

'

'

'

'

'

'

'

'

'

'

415,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of equal monthly installments to prepay the deficiency

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5

'

'

'

'

'

'

'

'

Borrowing base

'

'

'

'

'

'

'

'

'

'

'

407,500,000

470,000,000

585,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Outstanding letters of credit

'

'

'

'

'

'

'

'

'

'

5,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount available under the revolving credit facility

'

'

'

'

'

'

'

'

'

'

$369,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of adjusted engineered value of oil and gas interests serving as collateral

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

80.00%

'

'

'

'

'

'

'

'

'

'

Variable rate basis

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'LIBOR

'

'

'prime rate

'federal funds rate

'

'

'one-month LIBOR

Applicable margin (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.75%

2.75%

'

0.50%

0.75%

1.75%

1.00%

Commitment fee on unused portion (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.38%

'

0.50%

'

'

'

'

'

'

'

'

Effective annual interest rate (as a percent)

'

'

'

'

'

'

'

'

'

'

2.60%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Current ratio

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1

'

'

'

'

'

'

'

'

'

'

Number of consecutive quarters for which ratio of consolidated funded indebtedness to consolidated EBITDAX is required to be maintained

'

'

'

'

'

'

'

'

'

'

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Consolidated funded indebtedness to consolidated EBITDAX ratio

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4.5

4

'

'

'

'

'

'

'

'

Acquisition_of_Southwest_Royal2

Acquisition of Southwest Royalties, Inc. Limited Partnerships (Details) (Southwest Royalties, Inc., Limited partnerships, USD $)	0 Months Ended	1 Months Ended
	Mar. 14, 2012	Mar. 31, 2012
	Boe	Boe
	partnership
Southwest Royalties, Inc. | Limited partnerships	'	'
Acquisition	'	'
Number of limited partnerships acquired	24	'
Percentage of assets and liabilities acquired	100.00%	'
Aggregate merger consideration paid	$38,600,000	'
Upfront cash proceeds under VPP	44,400,000	'
Deferred future advances under VPP	4,700,000	'
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	725,000	725,000
Cash and cash equivalents	4,118,000	'
Oil and gas properties	41,098,000	'
Other non-current assets	210,000	'
Total assets acquired	45,426,000	'
Asset retirement obligations	-6,864,000	'
Total liabilities assumed	-6,864,000	'
Net assets acquired	$38,562,000	'

Sales_of_Assets_Details

Sales of Assets (Details) (USD $)	1 Months Ended
	Dec. 31, 2013	Apr. 30, 2013	Dec. 31, 2012
		acre
Sale Of Assets [Line Items]	'	'	'
Assets as percent of total proved reserves	'	'	20.00%
Contribution to limited partnership, percentage of assets	'	5.00%	'
Limited partnership, percentage of assets purchased from entity	'	95.00%	'
Limited partnership, assets purchased from entity	'	$215.20	'
Sale of Assets to Limited Partnership, Amount In Escrow Received	25,900,000	'	'
Sale of interest in wells, percent	'	75.00%	'
Gas and Oil Area, Undeveloped, Sold	'	12,000	'
Net proceeds from sale of interest in wells and related leasehold interest	34,500,000	6,800,000	'
General Partner [Member]	'	'	'
Sale Of Assets [Line Items]	'	'	'
General partner ownership interest	'	5.00%	'
GE Energy Financial Services [Member] | Limited Partner [Member]	'	'	'
Sale Of Assets [Line Items]	'	'	'
Payments to acquire limited partnership interests	'	$215.20	'
Limited partner ownership interest	'	95.00%	'

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Changes in asset retirement obligations	'	'	'
Beginning of period	$51,477	$40,794	'
Additional ARO from new properties	795	7,868	'
Sales or abandonments of properties	-5,892	-2,184	'
Accretion of asset retirement obligations	4,203	3,696	2,757
Revisions of previous estimates	-602	1,303	'
End of period	$49,981	$51,477	$40,794

Deferred_Revenue_from_Volumetr2

Deferred Revenue from Volumetric Production Payment (Details) (USD $)	12 Months Ended			0 Months Ended	1 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Mar. 14, 2012	Mar. 31, 2012
	Boe			Southwest Royalties, Inc.	Southwest Royalties, Inc.
				Limited partnerships	Limited partnerships
				Boe	Boe
Changes in deferred revenue from the VPP	'	'	'	'	'
Beginning of period	$37,184	$0	'	'	'
Deferred revenue from VPP	1,332	45,479	'	'	'
Amortization of deferred revenue from VPP	-8,746	-8,295	0	'	'
End of period	$29,770	$37,184	$0	'	'
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	'	'	'	725,000	725,000
Business Acquisition, Volumetric Production Payment Barrels of Oil Equivalents of Remaining Obligation To Deliver	485,000	'	'	'	'

Income_Taxes_Details

Income Taxes (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Deferred tax assets:	'	'
Net operating loss carryforwards	$65,814	$122,393
Statutory depletion carryforwards	8,658	8,159
Asset retirement obligations and other	22,470	21,814
Deferred tax assets, gross	96,942	152,366
Deferred tax liabilities:	'	'
Fair value of derivatives	-598	-4,208
Property and equipment	-229,572	-295,428
Deferred tax liabilities, gross	-230,170	-299,636
Net deferred tax liabilities	-133,228	-147,270
Components of net deferred tax liabilities:	'	'
Current assets	7,581	8,560
Non-current liabilities	-140,809	-155,830
Net deferred tax liabilities	($133,228)	($147,270)

Income_Taxes_Income_Taxes_Deta

Income Taxes Income Taxes (Details 2) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Expense (Benefit), Continuing Operations, Income Tax Reconciliation [Abstract]	'	'	'
Income tax expense at statutory rate of 35%	($13,052)	$19,989	$50,921
Tax depletion in excess of basis	-518	-581	-425
Revision of previous tax estimates	373	700	217
State income taxes, net of federal tax effect	76	1,513	1,310
Other	693	387	119
Income tax expense (benefit)	-12,428	22,008	52,142
Current	1,614	0	-408
Deferred	-14,042	22,008	52,550
Income tax expense (benefit)	($12,428)	$22,008	$52,142
Statutory rate	35.00%	35.00%	35.00%

Income_Taxes_Income_Taxes_Deta1

Income Taxes Income Taxes (Details - Textuals) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Operating Loss Carryforwards [Line Items]	'	'
Tax carryforward amount	$209,500,000	'
Uncertain tax positions	0	0
Stock Option Exercise Tax Benefit	'	'
Operating Loss Carryforwards [Line Items]	'	'
Tax carryforward amount	$21,800,000	'

Derivatives_Details

Derivatives (Details) (Commodity Derivatives, Swaps, Oil)	12 Months Ended
	Dec. 31, 2013
	bbl
Derivatives	'
Volume (in Bbls or MMBtu)	2,200,000
1st Quarter 2014	'
Derivatives	'
Volume (in Bbls or MMBtu)	606,000
Price (in dollars per barrel)	96.74
2nd Quarter 2014	'
Derivatives	'
Volume (in Bbls or MMBtu)	560,600
Price (in dollars per barrel)	96.81
3rd Quarter 2014	'
Derivatives	'
Volume (in Bbls or MMBtu)	530,200
Price (in dollars per barrel)	96.87
4th Quarter 2014	'
Derivatives	'
Volume (in Bbls or MMBtu)	503,200
Price (in dollars per barrel)	96.92

Derivatives_Details_2

Derivatives (Details 2) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Effect of Derivative Instruments on the Consolidated Balance Sheets	'	'
Fair value of derivative assets, current	$2,518	$7,495
Fair value of derivative assets, noncurrent	0	4,236
Asset Derivatives, Fair Value	2,518	11,731
Fair value of derivative liabilities, current	208	0
Liability Derivatives, Fair Value	208	0
Assets	'	'
Fair value of derivatives — gross presentation	3,909	17,851
Effects of netting arrangements	-1,391	-6,120
Asset Derivatives, Fair Value	2,518	11,731
Liabilities	'	'
Fair value of derivatives — gross presentation	1,599	6,120
Effects of netting arrangements	-1,391	-6,120
Liability Derivatives, Fair Value	208	0
Nondesignated	'	'
Effect of Derivative Instruments on the Consolidated Balance Sheets	'	'
Fair value of derivative liabilities, current	208	'
Fair value of derivative liabilities, noncurrent	0	'
Commodity Derivatives | Nondesignated	'	'
Effect of Derivative Instruments on the Consolidated Balance Sheets	'	'
Fair value of derivative assets, current	2,518	7,495
Fair value of derivative assets, noncurrent	0	4,236
Asset Derivatives, Fair Value	2,518	11,731
Fair value of derivative liabilities, current	'	0
Fair value of derivative liabilities, noncurrent	'	0
Liability Derivatives, Fair Value	208	0
Assets	'	'
Asset Derivatives, Fair Value	2,518	11,731
Liabilities	'	'
Liability Derivatives, Fair Value	$208	$0

Derivatives_Details_3

Derivatives (Details 3) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Amount of Gain or (Loss) Recognized in Earnings	'	'	'
Realized	$690	($3,410)	$42,521
Unrealized	-9,421	17,858	4,506
Total	-8,731	14,448	47,027
Commodity Derivatives | Nondesignated	'	'	'
Amount of Gain or (Loss) Recognized in Earnings	'	'	'
Realized	690	-3,410	42,521
Unrealized	-9,421	17,858	4,506
Total	($8,731)	$14,448	$47,027

Derivatives_Derivative_Details

Derivatives Derivative (Details-Textuals) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Derivatives	'
Expected change in fair value of outstanding derivative due to change in underlying asset	$2.20
Price of Oil [Member]	'
Derivatives	'
Expected change in fair value of outstanding derivative, change in price of underlying asset, per unit (in dollars per unit)	1
Price of Gas [Member]	'
Derivatives	'
Expected change in fair value of outstanding derivative, change in price of underlying asset, per unit (in dollars per unit)	0.5

Fair_Value_of_Financial_Instru2

Fair Value of Financial Instruments (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Assets:	'	'
Fair value of commodity derivatives	$2,518	$11,731
Liabilities:	'	'
Fair value of commodity derivatives	208	0
Recurring | Significant Other Observable Inputs (Level 2)	'	'
Assets:	'	'
Fair value of commodity derivatives	2,518	11,731
Total assets	2,518	11,731
Liabilities:	'	'
Fair value of commodity derivatives	208	0
Total liabilities	$208	$0

Fair_Value_of_Financial_Instru3

Fair Value of Financial Instruments (Details 2) (Level 1, 7.75% Senior Notes due 2019, USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Carrying Amount	'	'
Fair Value of Other Financial Instruments	'	'
Long term debt	$599,638	$349,585
Estimated Fair Value	'	'
Fair Value of Other Financial Instruments	'	'
Long term debt	$616,500	$348,700

Compensation_Plans_Details

Compensation Plans (Details) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]	'		'	'
Options outstanding, in shares at beginning	5,000		'	'
Options exercised, in shares	-1,000	[1]	'	'
Options outstanding, in shares at end	4,000		5,000	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward]	'		'	'
Options outstanding, weighted average exercise price (in dollars per share), at beginning	$32.21		'	'
Options exercised, weighted average exercise price (in dollars per share)	$28.93	[1]	'	'
Options outstanding, weighted average exercise price (in dollars per share), at end	$33.03		$32.21	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]	'		'	'
Vested, in shares at end of year	4,000		'	'
Exercisable, in shares, at end of year	4,000		'	'
Options, vested, weighted average exercise price (in dollars per share)	$33.03		'	'
Options, exercisable, weighted average exercise price (in dollars per share)	$33.03		'	'
Options outstanding, weighted average remaining contractual term (in years)	'2 years 6 months		'	'
Options vested weighted average remaining contractual term (in years)	'2 years 6 months		'	'
Options exercisable, weighted average remaining contractual term (in years)	'2 years 6 months		'	'
Options outstanding, aggregate intrinsic value	$195,690	[2]	'	'
Options, vested, aggregate intrinsic value	195,690	[2]	'	'
Options exercisable, aggregate intrinsic value	195,690	[2]	'	'
Market price of common stock (in dollars per share)	$81.95		'	'
Proceeds from exercise of stock options	$29,000		$12,000	$226,000
[1]	Cash received for options exercised totaled $28,930.
[2]	Based on closing price at December 31, 2013 of $81.95 per share.

Compensation_Plans_Compensatio

Compensation Plans Compensation Plans (Details 2) ($22.90 - $41.74 [Member], USD $)	12 Months Ended
	Dec. 31, 2013
$22.90 - $41.74 [Member]	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'
Range of exercise price, lower range limit	$22.90
Range of exercise price, upper range limit	$41.74
Shares outstanding	4,000
Average exercise price	$33.03
Remaining life in years	'2 years 6 months

Compensation_Plans_Compensatio1

Compensation Plans Compensation Plans (Details 3) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]	'	'	'
Weighted average grant date fair value of options granted per share	$0	$0	$0
Intrinsic value of options exercised	$53	$28	$594

Compensation_Plans_Compensatio2

Compensation Plans Compensation Plans (Details 4) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Shares issue price	33.03	32.21
Options outstanding number	4,000	5,000
Directors Plan [Member]	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Number of shares authorized	86,300	'
Shares issued in period	52,000	'
Options outstanding, expiry term	'10 years	'
Options, grants in period	0	0
Options outstanding number	4,000	'
Directors Plan [Member] | Minimum [Member]	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Shares issue price	3.25	'
Directors Plan [Member] | Maximum	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Shares issue price	41.74	'

Compensation_Plans_Details_5

Compensation Plans (Details 5) (USD $)

12 Months Ended

1 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Jan. 31, 2007

Jan. 31, 2007

Minimum

Maximum

APO Incentive Plan

APO Incentive Plan

APO Reward Plan

APO Reward Plan

APO Reward Plan

SWR Reward Plan

SWR Reward Plan

Minimum

Maximum

area

Full vesting date, May 1, 2015

Full vesting date, August 1,2015

well

Full vesting date, October 25, 2011

award

award

award

Non-Equity Award Plans

'

'

'

'

'

'

'

'

'

'

'

'

Subsequent revenues received by participants (as a percent)

'

'

'

'

'

99.00%

100.00%

'

'

'

'

'

Subsequent expenses paid by participants (as a percent)

'

'

'

'

'

99.00%

100.00%

'

'

'

'

'

Economic interests in specified wells drilled or acquired as part of the plan (as a percent)

'

'

'

'

'

5.00%

7.50%

'

'

'

'

'

Number of specified areas in which awards granted

'

'

'

'

'

'

'

17

'

'

'

'

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 award fully vested

'

'

'

'

'

'

'

13

2

2

'

'

Number of awards with specified vesting date

'

'

'

'

'

'

'

17

'

'

'

'

Percentage of working interest in well

'

'

'

'

'

'

'

'

'

'

22.50%

'

Number of wells, working interest

'

'

'

'

'

'

'

'

'

'

1

'

Percentage of subsequent quarterly bonus amounts after full vesting date payable to participants

'

'

'

'

'

'

'

'

'

'

'

100.00%

Vesting period

'

'

'

'2 years

'5 years

'

'

'

'

'

'

'

Compensation expense recorded

$2,100,000

$2,100,000

$14,400,000

'

'

'

'

'

'

'

'

'

Current liabilities:

'

'

'

'

'

'

'

'

'

'

'

'

Accrued liabilities and other

3,317,000

2,220,000

'

'

'

'

'

'

'

'

'

'

Non-current liabilities:

'

'

'

'

'

'

'

'

'

'

'

'

Accrued compensation under non-equity award plans

15,469,000

20,058,000

'

'

'

'

'

'

'

'

'

'

Total accrued compensation under non-equity award plans

$18,786,000

$22,278,000

'

'

'

'

'

'

'

'

'

'

Transactions_with_Affiliates_D

Transactions with Affiliates (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Amounts paid to the Williams Entities:	'		'		'
Percentage of ownership of affiliates of the company in the partnership	31.90%		'		'
Percentage of owner of company in affiliated partnership	25.80%		'		'
Affiliated Entity [Member]	'		'		'
Amounts received from the Williams Entities:	'		'		'
Services	$715		$671		$566
Insurance premiums and benefits	837		920		821
Reimbursed expenses	427		566		371
Amount received from Williams Entities	1,979		2,157		1,758
Amounts paid to the Williams Entities:	'		'		'
Rent	1,560	[1]	1,478	[1]	843	[1]
Business entertainment	344	[2]	116	[2]	116	[2]
Reimbursed expenses	216		267		289
Amounts paid to the Williams Entities	$2,120		$1,861		$1,248
[1]	Rent amounts were paid to a partnership within the Williams Entities. The Company owns 31.9% of the partnership and affiliates of the Company own 25.8%.
[2]	Consists primarily of hunting and fishing recreation for business associates and employees of the Company on land owned by affiliates of Mr. Williams.

Other_Operating_Revenues_and_E2

Other Operating Revenues and Expenses (Details) (USD $)	1 Months Ended		3 Months Ended	12 Months Ended
	Jun. 30, 2012	Feb. 28, 2011	Mar. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
		Drillingrig
		hp
Other operating revenues:	'	'	'	'	'	'
Gain on sales of assets	'	'	'	$4,467,000	$1,496,000	$15,744,000
Marketing revenue	'	'	'	2,021,000	581,000	0
Total other operating revenues	'	'	'	6,488,000	2,077,000	15,744,000
Other operating expenses:	'	'	'	'	'	'
Loss on sales of assets	'	'	'	-1,233,000	-523,000	-945,000
Marketing expense	'	'	'	-658,000	0	0
Impairment of inventory	'	'	'	-210,000	-510,000	-721,000
Total other operating expenses	'	'	'	-2,101,000	-1,033,000	-1,666,000
Number of drilling rigs sold	'	2	'	'	'	'
Capacity of drilling rigs sold (in horsepower)	'	2,000	'	'	'	'
Total consideration received from sale of assets	'	22,000,000	'	259,799,000	3,778,000	13,902,000
Gain on sale of drilling rigs and related equipment	'	'	13,200,000	'	'	'
Consideration from sale of assets	11,000,000	'	'	'	'	'
Proceeds from the sale consisting of promissory note	$11,000,000	'	'	'	'	'

Investment_in_Dalea_Investment1

Investment in Dalea Investment Group, LLC (Details) (Dalea Investment Group, LLC, USD $)	1 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2013
Dalea Investment Group, LLC	'	'
Investment in Dalea Investment Group, LLC	'	'
Note receivable cancelled	$11	'
Non-controlling Membership interest (as a percent)	7.66%	'
Recorded investment	'	$11

Commitments_and_Contingencies_1

Commitments and Contingencies (Details) (USD $)	12 Months Ended					1 Months Ended	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Oct. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
					Drilling Rigs [Member]	BMT O&G TX, L.P. [Member]	BMT O&G TX, L.P. [Member]	Environmental Remediation Case 2001 [Member]
					Drillingrig
Leases	'		'	'	'	'	'	'
Operating Leases, Rent Expense	$1,800,000		$1,600,000	$1,000,000	'	'	'	'
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]	'		'	'	'	'	'	'
2014	1,001,000	[1]	'	'	'	'	'	'
2015	620,000	[1]	'	'	'	'	'	'
2016	213,000	[1]	'	'	'	'	'	'
Thereafter	0	[1]	'	'	'	'	'	'
Total minimum lease payments	1,834,000	[1]	'	'	'	'	'	'
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]	'		'	'	'	'	'	'
2014	3,818,000	[2]	'	'	'	'	'	'
2015	3,998,000	[2]	'	'	'	'	'	'
2016	3,684,000	[2]	'	'	'	'	'	'
Thereafter	338,000	[2]	'	'	'	'	'	'
Total minimum lease payments	11,838,000	[2]	'	'	'	'	'	'
Non-Cancelable Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]	'		'	'	'	'	'	'
2014	4,819,000		'	'	'	'	'	'
2015	4,618,000		'	'	'	'	'	'
2016	3,897,000		'	'	'	'	'	'
Thereafter	338,000		'	'	'	'	'	'
Total minimum lease payments	13,672,000		'	'	'	'	'	'
Number of drilling rigs subject to operating leases	'		'	'	2	'	'	'
Plaintiffs contend of cost to remediate the surface	'		'	'	'	'	'	8,000,000
Loss contingency, settlement amount	'		'	'	'	2,900,000	'	800,000
Loss contingency, settlement amount paid	'		'	'	'	'	'	700,000
Minimum percentage of plaintiffs if opt out the settlement can be terminated	'		'	'	'	'	'	25.00%
Attorney fees	'		'	'	'	800,000	'	'
Loss related to litigation settlement	'		'	'	'	'	($1,400,000)	'
[1]	Relates to vehicle leases.
[2]	Includes leases for two drilling rigs.

Impairment_of_Property_and_Equ1

Impairment of Property and Equipment (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Impaired Long-Lived Assets Held and Used [Line Items]	'	'	'
Provisions for impairment of proved properties	$89.80	$5.90	$10.40
Provisions for impairment of unproved properties	3.4	1.4	6.2
Non Core Properties [Member]	'	'	'
Impaired Long-Lived Assets Held and Used [Line Items]	'	'	'
Provisions for impairment of proved properties	$89.80	$5.40	$10.40

Costs_of_Oil_and_Gas_Propertie2

Costs of Oil and Gas Properties Costs of Oil and Gas Properties (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Oil and Gas Property, Successful Effort Method, Gross [Abstract]	'	'	'
Property acquisitions, Proved	$0	$41,098	$0
Property acquisitions, Unproved	50,104	72,235	61,236
Developmental costs	218,341	349,972	328,418
Exploratory costs	3,932	10,898	27,425
Total	$272,377	$474,203	$417,079

Costs_of_Oil_and_Gas_Propertie3

Costs of Oil and Gas Properties (Details 2) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Oil and Gas Property, Successful Effort Method, Gross [Abstract]	'	'
Proved properties	$2,317,053	$2,482,185
Unproved properties	86,224	88,618
Total capitalized costs	2,403,277	2,570,803
Accumulated depletion	-1,282,989	-1,234,626
Net capitalized costs	$1,120,288	$1,336,177

Segment_Information_Details

Segment Information (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	segment
Segment Reporting [Abstract]	'	'	'
Number of reportable operating segments	2	'	'
Segment Information	'	'	'
Revenues	$429,215	$423,052	$426,428
Depreciation, depletion and amortization	240,713	148,631	115,235	[1]
Other operating expenses	175,887	194,628	179,388	[2]
Interest expense	43,079	38,664	32,919
Other (income) expense	6,826	-15,982	-47,079
Income (loss) before income taxes	-37,290	57,111	145,965
Income tax (expense) benefit	12,428	-22,008	-52,142
Net income (loss)	-24,862	35,103	93,823
Total assets	1,366,737	1,574,584	1,226,271
Additions to property and equipment	284,652	515,758	446,863
Oil and Gas	'	'	'
Segment Information	'	'	'
Revenues	411,403	407,194	422,368
Depreciation, depletion and amortization	229,460	140,967	112,863	[1]
Other operating expenses	159,294	176,922	174,027	[2]
Interest expense	43,079	38,664	32,919
Other (income) expense	6,826	-15,979	-33,280
Income (loss) before income taxes	-27,256	66,620	135,839
Income tax (expense) benefit	9,136	-25,473	-48,648
Net income (loss)	-18,120	41,147	87,191
Total assets	1,339,920	1,535,544	1,178,725
Additions to property and equipment	280,173	500,161	429,142
Contract Drilling	'	'	'
Segment Information	'	'	'
Revenues	37,255	57,218	52,716
Depreciation, depletion and amortization	13,844	14,442	12,214	[1]
Other operating expenses	32,817	52,678	44,318	[2]
Interest expense	0	0	0
Other (income) expense	0	-3	-13,799
Income (loss) before income taxes	-9,406	-9,899	9,983
Income tax (expense) benefit	3,292	3,465	-3,494
Net income (loss)	-6,114	-6,434	6,489
Total assets	54,697	64,045	62,846
Additions to property and equipment	5,107	15,207	17,578
Intercompany Eliminations	'	'	'
Segment Information	'	'	'
Revenues	-19,443	-41,360	-48,656
Depreciation, depletion and amortization	-2,591	-6,778	-9,842	[1]
Other operating expenses	-16,224	-34,972	-38,957	[2]
Interest expense	0	0	0
Other (income) expense	0	0	0
Income (loss) before income taxes	-628	390	143
Income tax (expense) benefit	0	0	0
Net income (loss)	-628	390	143
Total assets	-27,880	-25,005	-15,300
Additions to property and equipment	($628)	$390	$143
[1]	Includes impairment of property and equipment.
[2]	Includes the following expenses: production, exploration, midstream services, drilling rig services, accretion of ARO, G&A and other operating expenses.

Guarantor_Financial_Informatio2

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

Guarantor_Financial_Informatio3

Guarantor Financial Information (Details 2) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Thousands, unless otherwise specified
Condensed consolidating financial statements	'	'	'	'
Current assets	$138,311	$124,470	'	'
Property and equipment, net	1,199,107	1,420,358	'	'
Investments in subsidiaries	0	0	'	'
Fair value of derivatives	0	4,236	'	'
Other assets	29,319	25,520	'	'
Total assets	1,366,737	1,574,584	1,226,271	'
Current liabilities	136,395	120,914	'	'
Non-current liabilities:	'	'	'	'
Long-term debt	639,638	809,585	'	'
Deferred income taxes	140,809	155,830	'	'
Other	96,112	109,639	'	'
TOTAL NON-CURRENT LIABILITIES	876,559	1,075,054	'	'
Equity	353,783	378,616	343,501	249,452
Total liabilities and equity	1,366,737	1,574,584	'	'
Issuer	'	'	'	'
Condensed consolidating financial statements	'	'	'	'
Current assets	140,100	133,080	'	'
Property and equipment, net	833,980	1,053,453	'	'
Investments in subsidiaries	342,416	305,899	'	'
Fair value of derivatives	'	4,236	'	'
Other assets	16,032	12,112	'	'
Total assets	1,332,528	1,508,780	'	'
Current liabilities	290,327	241,200	'	'
Non-current liabilities:	'	'	'	'
Long-term debt	639,638	809,585	'	'
Deferred income taxes	118,438	143,699	'	'
Other	36,161	41,499	'	'
TOTAL NON-CURRENT LIABILITIES	794,237	994,783	'	'
Equity	247,964	272,797	'	'
Total liabilities and equity	1,332,528	1,508,780	'	'
Guarantor Subsidiaries	'	'	'	'
Condensed consolidating financial statements	'	'	'	'
Current assets	248,314	224,210	'	'
Property and equipment, net	351,171	366,905	'	'
Investments in subsidiaries	0	0	'	'
Fair value of derivatives	'	0	'	'
Other assets	13,287	13,408	'	'
Total assets	612,772	604,523	'	'
Current liabilities	93,055	112,534	'	'
Non-current liabilities:	'	'	'	'
Long-term debt	0	0	'	'
Deferred income taxes	129,880	117,950	'	'
Other	59,829	68,140	'	'
TOTAL NON-CURRENT LIABILITIES	189,709	186,090	'	'
Equity	330,008	305,899	'	'
Total liabilities and equity	612,772	604,523	'	'
Non-Guarantor Subsidiary	'	'	'	'
Condensed consolidating financial statements	'	'	'	'
Current assets	538	0	'	'
Property and equipment, net	13,956	0	'	'
Investments in subsidiaries	0	0	'	'
Fair value of derivatives	'	0	'	'
Other assets	0	0	'	'
Total assets	14,494	0	'	'
Current liabilities	976	0	'	'
Non-current liabilities:	'	'	'	'
Long-term debt	0	0	'	'
Deferred income taxes	988	0	'	'
Other	122	0	'	'
TOTAL NON-CURRENT LIABILITIES	1,110	0	'	'
Equity	12,408	0	'	'
Total liabilities and equity	14,494	0	'	'
Adjustments/ Eliminations	'	'	'	'
Condensed consolidating financial statements	'	'	'	'
Current assets	-250,641	-232,820	'	'
Property and equipment, net	0	0	'	'
Investments in subsidiaries	-342,416	-305,899	'	'
Fair value of derivatives	'	0	'	'
Other assets	0	0	'	'
Total assets	-593,057	-538,719	'	'
Current liabilities	-247,963	-232,820	'	'
Non-current liabilities:	'	'	'	'
Long-term debt	0	0	'	'
Deferred income taxes	-108,497	-105,819	'	'
Other	0	0	'	'
TOTAL NON-CURRENT LIABILITIES	-108,497	-105,819	'	'
Equity	-236,597	-200,080	'	'
Total liabilities and equity	($593,057)	($538,719)	'	'

Guarantor_Financial_Informatio4

Guarantor Financial Information (Details 3) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Condensed consolidating financial statements	'	'	'	'	'	'	'	'	'	'	'
Total revenue	'	'	'	'	'	'	'	'	$429,215	$423,052	$426,428
Costs and expenses	'	'	'	'	'	'	'	'	416,600	343,259	294,623
Operating income	24,577	33,918	5,003	-50,883	10,588	21,573	20,837	26,795	12,615	79,793	131,805
Other income (expense)	'	'	'	'	'	'	'	'	-49,905	-22,682	14,160
Equity in earnings of subsidiaries	'	'	'	'	'	'	'	'	0	0	0
Income tax (expense) benefit	'	'	'	'	'	'	'	'	12,428	-22,008	-52,142
NET INCOME (LOSS)	'	'	'	'	'	'	'	'	-24,862	35,103	93,823
Issuer	'	'	'	'	'	'	'	'	'	'	'
Condensed consolidating financial statements	'	'	'	'	'	'	'	'	'	'	'
Total revenue	'	'	'	'	'	'	'	'	280,423	291,782	280,359
Costs and expenses	'	'	'	'	'	'	'	'	302,898	230,033	191,012
Operating income	'	'	'	'	'	'	'	'	-22,475	61,749	89,347
Other income (expense)	'	'	'	'	'	'	'	'	-50,601	-25,495	6,816
Equity in earnings of subsidiaries	'	'	'	'	'	'	'	'	23,261	13,557	32,371
Income tax (expense) benefit	'	'	'	'	'	'	'	'	24,953	-14,708	-34,711
NET INCOME (LOSS)	'	'	'	'	'	'	'	'	-24,862	35,103	93,823
Guarantor Subsidiaries	'	'	'	'	'	'	'	'	'	'	'
Condensed consolidating financial statements	'	'	'	'	'	'	'	'	'	'	'
Total revenue	'	'	'	'	'	'	'	'	146,556	132,690	147,015
Costs and expenses	'	'	'	'	'	'	'	'	112,441	114,646	104,557
Operating income	'	'	'	'	'	'	'	'	34,115	18,044	42,458
Other income (expense)	'	'	'	'	'	'	'	'	-25	2,813	7,344
Equity in earnings of subsidiaries	'	'	'	'	'	'	'	'	0	0	0
Income tax (expense) benefit	'	'	'	'	'	'	'	'	-11,931	-7,300	-17,431
NET INCOME (LOSS)	'	'	'	'	'	'	'	'	22,159	13,557	32,371
Non-Guarantor Subsidiary	'	'	'	'	'	'	'	'	'	'	'
Condensed consolidating financial statements	'	'	'	'	'	'	'	'	'	'	'
Total revenue	'	'	'	'	'	'	'	'	2,236	0	0
Costs and expenses	'	'	'	'	'	'	'	'	1,261	0	0
Operating income	'	'	'	'	'	'	'	'	975	0	0
Other income (expense)	'	'	'	'	'	'	'	'	721	0	0
Equity in earnings of subsidiaries	'	'	'	'	'	'	'	'	0	0	0
Income tax (expense) benefit	'	'	'	'	'	'	'	'	-594	0	0
NET INCOME (LOSS)	'	'	'	'	'	'	'	'	1,102	0	0
Adjustments/ Eliminations	'	'	'	'	'	'	'	'	'	'	'
Condensed consolidating financial statements	'	'	'	'	'	'	'	'	'	'	'
Total revenue	'	'	'	'	'	'	'	'	0	-1,420	-946
Costs and expenses	'	'	'	'	'	'	'	'	0	-1,420	-946
Operating income	'	'	'	'	'	'	'	'	0	0	0
Other income (expense)	'	'	'	'	'	'	'	'	0	0	0
Equity in earnings of subsidiaries	'	'	'	'	'	'	'	'	-23,261	-13,557	-32,371
Income tax (expense) benefit	'	'	'	'	'	'	'	'	0	0	0
NET INCOME (LOSS)	'	'	'	'	'	'	'	'	($23,261)	($13,557)	($32,371)

Guarantor_Financial_Informatio5

Guarantor Financial Information (Details 4) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Condensed consolidating financial statements	'	'	'
Operating activities	$220,576	$189,222	$280,047
Investing activities	-29,043	-476,033	-404,913
Financing activities	-175,636	280,012	133,671
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	15,897	-6,799	8,805
Beginning of period	10,726	17,525	8,720
End of period	26,623	10,726	17,525
Issuer	'	'	'
Condensed consolidating financial statements	'	'	'
Operating activities	128,146	92,521	209,886
Investing activities	10,544	-432,433	-389,681
Financing activities	-125,027	333,703	186,994
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	13,663	-6,209	7,199
Beginning of period	6,030	12,239	5,040
End of period	19,693	6,030	12,239
Guarantor Subsidiaries	'	'	'
Condensed consolidating financial statements	'	'	'
Operating activities	87,433	89,923	60,319
Investing activities	-34,121	-36,822	-5,390
Financing activities	-51,122	-53,691	-53,323
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	2,190	-590	1,606
Beginning of period	4,696	5,286	3,680
End of period	6,886	4,696	5,286
Non-Guarantor Subsidiary	'	'	'
Condensed consolidating financial statements	'	'	'
Operating activities	2,406	0	0
Investing activities	-2,875	0	0
Financing activities	513	0	0
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	44	0	0
Beginning of period	0	0	0
End of period	44	0	0
Adjustments/ Eliminations	'	'	'
Condensed consolidating financial statements	'	'	'
Operating activities	2,591	6,778	9,842
Investing activities	-2,591	-6,778	-9,842
Financing activities	0	0	0
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	0	0	0
Beginning of period	0	0	0
End of period	$0	$0	$0

Subsequent_Events_Subsequent_E

Subsequent Events Subsequent Events (Details) (USD $)	1 Months Ended		0 Months Ended	1 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Apr. 30, 2013	Feb. 10, 2014	Feb. 28, 2014
			Subsequent Event [Member]	Scenario, Forecast [Member]
				Subsequent Event [Member]
Subsequent Event [Line Items]	'	'	'	'
Proceeds from sale of property	'	'	$5.10	'
Net proceeds from sale of interest in wells and related leasehold interest	$34.50	$6.80	'	$71

Supplemental_Quarterly_Financi2

Supplemental Quarterly Financial Information (Details) (USD $)	3 Months Ended																12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2012		Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Quarterly Financial Information Disclosure [Abstract]	'		'		'		'		'		'		'		'		'		'		'
Total revenues	$112,267		$111,165		$98,916		$106,867		$101,610		$107,763		$104,610		$109,069		$429,215		$423,052		'
Operating income	24,577		33,918		5,003		-50,883		10,588		21,573		20,837		26,795		12,615		79,793		131,805
Net income (loss)	$6,425		$10,951		($1,029)		($41,209)		$1,678		($7,176)		$32,822		$7,779		($24,862)		$35,103		'
Net income (loss) per common share:	'		'		'		'		'		'		'		'		'		'		'
Basic (in dollars per share)	$0.53	[1]	$0.90	[1]	($0.08)	[1]	($3.39)	[1]	$0.14	[1]	($0.59)	[1]	$2.70	[1]	$0.64	[1]	($2.04)	[1]	$2.89	[1]	$7.72
Diluted (in dollars per share)	$0.53	[1]	$0.90	[1]	($0.08)	[1]	($3.39)	[1]	$0.14	[1]	($0.59)	[1]	$2.70	[1]	$0.64	[1]	($2.04)	[1]	$2.89	[1]	$7.71
Weighted average common shares outstanding:	'		'		'		'		'		'		'		'		'		'		'
Basic (in shares)	12,165		12,165		12,165		12,165		12,164		12,164		12,164		12,164		12,165		12,164		12,161
Diluted (in shares)	12,165		12,165		12,165		12,165		12,164		12,164		12,164		12,164		12,165		12,164		12,162
[1]	The sum of the individual quarterly net income (loss) per share amounts may not agree to the total for the year since each period’s computation is based on the weighted average number of common shares outstanding during each period.

Supplemental_Oil_and_Gas_Reser2

Supplemental Oil and Gas Reserve Information (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
	Boe	Boe	Boe	Boe
	MBoe
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Net (BOE)	70,015,000	75,357,000	64,349,000	51,065,000
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates (BOE)	-901,000	-6,615,000	-2,007,000	'
Proved Developed and Undeveloped Reserves, Downward Revisions of Previous Estimates Related to Well Performance	1,504	'	'	'
Proved Developed and Undeveloped Reserves, Upward Revisions of Previous Estimates Attributable to Effects of Higher Commodity Prices	603	'	'	'
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions (BOE)	27,666,000	20,443,000	20,881,000	'
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place (BOE)	'	3,504,000	'	'
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place (BOE)	-26,852,000	-725,000	-156,000	'
Proved Developed and Undeveloped Reserves, Production (BOE)	-5,255,000	-5,599,000	-5,434,000	'
Proved Developed Reserves (BOE)	38,255,000	43,354,000	39,264,000	'
Oil	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved developed and undeveloped reserves, net (at beginning)	49,119,000	44,919,000	34,379,000	'
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	85,000	-7,303,000	-1,809,000	'
Extensions and discoveries	20,540,000	13,501,000	16,121,000	'
Purchases of minerals-in-place	'	2,456,000	'	'
Sales of minerals-in-place	-17,387,000	-633,000	-45,000	'
Production	-3,692,000	-3,821,000	-3,727,000	'
Proved developed and undeveloped reserves, net (at end)	48,665,000	49,119,000	44,919,000	'
Proved Developed Reserves (Volume)	25,989,000	27,641,000	26,198,000	'
Natural Gas Liquids	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved developed and undeveloped reserves, net (at beginning)	9,182,000	4,617,000	3,436,000	'
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	1,806,000	1,805,000	7,000	'
Extensions and discoveries	3,562,000	3,175,000	1,449,000	'
Purchases of minerals-in-place	'	18,000	'	'
Sales of minerals-in-place	-5,531,000	0	0	'
Production	-532,000	-433,000	-275,000	'
Proved developed and undeveloped reserves, net (at end)	8,487,000	9,182,000	4,617,000	'
Proved Developed Reserves (Volume)	4,293,000	5,044,000	2,764,000	'
Natural Gas	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved developed and undeveloped reserves, net (at beginning)	102,336,000	88,876,000	79,497,000	'
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	-16,753,000	-6,699,000	-1,227,000	'
Extensions and discoveries	21,389,000	22,604,000	19,864,000	'
Purchases of minerals-in-place	'	6,182,000	'	'
Sales of minerals-in-place	-23,605,000	-555,000	-664,000	'
Production	-6,188,000	-8,072,000	-8,594,000	'
Proved developed and undeveloped reserves, net (at end)	77,179,000	102,336,000	88,876,000	'
Proved Developed Reserves (Volume)	47,839,000	64,013,000	61,811,000	'

Supplemental_Oil_and_Gas_Reser3

Supplemental Oil and Gas Reserve Information (Details 1) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure [Abstract]	'	'	'
Future cash inflows	$5,162,702	$5,222,621	$4,811,837
Future costs, production	-1,724,560	-1,819,356	-1,558,067
Future costs, abandonment	-131,747	-137,499	-110,833
Future costs, development	-592,695	-651,292	-510,709
Future costs, income taxes	-786,196	-673,686	-757,253
Future net cash flows	1,927,504	1,940,788	1,874,975
10% discount factor	-1,000,581	-1,000,957	-936,462
Standardized measure of discounted net cash flows	$926,923	$939,831	$938,513

Supplemental_Oil_and_Gas_Reser4

Supplemental Oil and Gas Reserve Information (Details 2) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]	'	'	'
Standardized measure, beginning of period	$939,831	$938,513	$684,438
Net changes in sales prices, net of production costs	13,292	-196,930	206,357
Revisions of quantity estimates	-10,680	-144,899	-53,089
Accretion of discount	130,736	137,369	99,028
Changes in future development costs, including development costs incurred that reduced future development costs	46,068	148,733	84,638
Changes in timing and other	-10,249	-58,323	-45,055
Net change in income taxes	-84,673	76,593	-130,562
Future abandonment cost, net of salvage	232	-9,230	925
Extensions and discoveries	502,619	289,999	399,068
Sales, net of production costs	-289,035	-277,248	-305,769
Purchases of minerals-in-place	0	80,744	0
Sales of minerals-in-place	-311,218	-45,490	-1,466
Standardized measure, end of period	$926,923	$939,831	$938,513

Supplemental_Oil_and_Gas_Reser5

Supplemental Oil and Gas Reserve Information (Details 3)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Oil	'	'	'
Average Sales Price and Production Costs Per Unit of Production [Line Items]	'	'	'
Average sales price	94.88	90.45	91.35
Natural Gas Liquids	'	'	'
Average Sales Price and Production Costs Per Unit of Production [Line Items]	'	'	'
Average sales price	31.63	43.74	51.19
Natural Gas	'	'	'
Average Sales Price and Production Costs Per Unit of Production [Line Items]	'	'	'
Average sales price	3.59	3.7	5.31