Unit (UNTC) 10-Q 5 Nov 13 2013 Q3 Quarterly report Financial data

Document_And_Entity_Informatio

Document And Entity Information	9 Months Ended
	Sep. 30, 2013	Oct. 25, 2013
Document And Entity Information [Abstract]	'	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	30-Sep-13	'
Document Fiscal Year Focus	'2013	'
Document Fiscal Period Focus	'Q3	'
Trading Symbol	'unt	'
Entity Registrant Name	'UNIT CORP	'
Entity Central Index Key	'0000798949	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Large Accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	49,106,378

Condensed_Consolidated_Balance

Condensed Consolidated Balance Sheets (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets:	'	'
Cash and cash equivalents	$1,741	$974
Accounts receivable, net of allowance for doubtful accounts of $5,342 and $5,343 at September 30, 2013 and at December 31, 2012, respectively	141,817	146,046
Materials and supplies	10,330	8,563
Current derivative asset (Note 10)	4,514	16,552
Current income tax receivable	1,389	901
Current deferred tax asset	9,371	8,765
Prepaid expenses and other	12,413	13,843
Total current assets	181,575	195,644
Oil and natural gas properties on the full cost method:	'	'
Proved properties	4,061,108	3,822,381
Undeveloped leasehold not being amortized	589,227	521,659
Drilling equipment	1,484,928	1,478,645
Gas gathering and processing equipment	538,258	461,629
Transportation equipment	39,286	37,728
Other	74,802	62,840
Property, plant and equipment, gross, total	6,787,609	6,384,882
Less accumulated depreciation, depletion, amortization, and impairment	3,133,717	2,907,660
Net property and equipment	3,653,892	3,477,222
Debt issuance cost	12,241	13,432
Goodwill	62,808	62,808
Other intangible assets, net	0	680
Non-current derivative asset (Note 10)	1,133	0
Other assets	13,046	11,334
Total assets	3,924,695	3,761,120
Current liabilities:	'	'
Accounts payable	132,633	138,811
Accrued liabilities (Note 5)	78,557	54,098
Current portion of derivative liabilities (Note 10)	6,480	1,948
Current portion of other long-term liabilities (Note 6)	11,985	12,282
Total current liabilities	229,655	207,139
Long-term debt (Note 6)	645,584	716,359
Non-current derivative liabilities (Note 10)	938	562
Other long-term liabilities (Note 6)	158,161	166,983
Deferred income taxes	773,412	695,776
Shareholders' equity:	'	'
Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued	0	0
Common stock, $.20 par value, 175,000,000 shares authorized, 49,091,928 and 48,581,948 shares issued, respectively	9,655	9,594
Capital in excess of par value	441,291	423,603
Accumulated other comprehensive income (loss) (Note 12)	-963	7,587
Retained earnings	1,666,962	1,533,517
Total shareholders' equity	2,116,945	1,974,301
Total liabilities and shareholders' equity	$3,924,695	$3,761,120

Condensed_Consolidated_Balance1

Condensed Consolidated Balance Sheets (Parenthetical) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, except Share data, unless otherwise specified
Statement of Financial Position [Abstract]	'	'
Accounts receivable, allowance for doubtful accounts	$5,342	$5,343
Preferred stock, par value	$1	$1
Preferred stock, shares authorized	5,000,000	5,000,000
Preferred stock, shares issued	0	0
Common stock, par value	$0.20	$0.20
Common stock, shares authorized	175,000,000	175,000,000
Common stock, shares issued	49,091,928	48,581,948

Condensed_Consolidated_Stateme

Condensed Consolidated Statements Of Operations (USD $)	3 Months Ended		9 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Revenues:	'	'	'	'
Oil and natural gas	$157,320	$135,435	$475,728	$402,366
Contract drilling	100,647	133,420	313,180	421,198
Gas gathering and processing	75,809	52,935	203,821	159,977
Total revenues	333,776	321,790	992,729	983,541
Oil and natural gas:	'	'	'	'
Operating costs	50,139	36,147	138,171	105,035
Depreciation, depletion, and amortization	56,294	44,489	163,612	153,839
Impairment of oil and natural gas properties (Note 2)	0	0	0	115,874
Contract drilling:	'	'	'	'
Operating costs	58,988	72,988	188,580	223,980
Depreciation	17,402	20,094	52,570	62,660
Gas gathering and processing:	'	'	'	'
Operating costs	63,098	46,267	172,065	136,243
Depreciation and amortization	8,773	5,884	24,143	16,330
General and administrative	9,936	8,434	28,288	23,814
Gain on disposition of assets	-4,345	-44	-7,744	-1,283
Total operating expenses	260,285	234,259	759,685	836,492
Income from operations	73,491	87,531	233,044	147,049
Other income (expense):	'	'	'	'
Interest, net	-3,625	-7,087	-11,777	-11,455
Loss on derivatives not designated as hedges and hedge ineffectiveness, net	-13,760	-4,015	-3,340	-4,621
Other	-14	-59	-171	-123
Total other income (expense)	-17,399	-11,161	-15,288	-16,199
Income before income taxes	56,092	76,370	217,756	130,850
Income tax expense:	'	'	'	'
Current	2,111	2,516	6,745	450
Deferred	19,749	27,268	77,566	50,677
Total income taxes	21,860	29,784	84,311	51,127
Net income	$34,232	$46,586	$133,445	$79,723
Net income per common share:	'	'	'	'
Basic	$0.71	$0.97	$2.77	$1.66
Diluted	$0.70	$0.97	$2.75	$1.66

Condensed_Consolidated_Stateme1

Condensed Consolidated Statements Of Comprehensive Income (Loss) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Statement of Other Comprehensive Income [Abstract]	'	'	'	'
Net income	$34,232	$46,586	$133,445	$79,723
Other comprehensive income (loss), net of taxes:	'	'	'	'
Change in value of derivative instruments used as cash flow hedges, net of tax of ($3,013), ($8,838), ($5,517), and $7,377	-4,797	-14,137	-8,617	11,353
Reclassification - derivative settlements, net of tax of $1,240, ($5,523), $63, and ($14,793)	1,970	-8,720	139	-23,296
Ineffective portion of derivatives, net of tax of $97, $1,560, ($44), and $1,792	155	2,455	-72	2,829
Comprehensive income	$31,560	$26,184	$124,895	$70,609

Condensed_Consolidated_Stateme2

Condensed Consolidated Statements Of Comprehensive Income (Loss) (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Statement of Other Comprehensive Income [Abstract]	'	'	'	'
Change in value of derivative instruments used as cash flow hedges, tax	($3,013)	($8,838)	($5,517)	$7,377
Reclassification - derivative settlements, tax	1,240	-5,523	63	-14,793
Ineffective portion of derivatives, tax	$97	$1,560	($44)	$1,792

Condensed_Consolidated_Stateme3

Condensed Consolidated Statements Of Cash Flows (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
OPERATING ACTIVITIES:	'	'
Net income	$133,445	$79,723
Adjustments to reconcile net income to net cash provided by operating activities:	'	'
Depreciation, depletion, and amortization	242,590	234,350
Impairment of oil and natural gas properties (Note 2)	0	115,874
Loss on derivatives	1,765	4,621
Deferred tax expense	77,566	50,677
Gain on disposition of assets	-7,744	-1,283
Stock compensation plans	16,652	12,271
Other, net	4,263	3,376
Changes in operating assets and liabilities increasing (decreasing) cash:	'	'
Accounts receivable	1,888	4,516
Accounts payable	320	-11,753
Material and supplies	-1,767	-1,949
Accrued liabilities	31,041	23,195
Other, net	942	-1,478
Net cash provided by operating activities	500,961	512,140
INVESTING ACTIVITIES:	'	'
Capital expenditures	-512,574	-584,858
Producing property and other acquisitions (Note 3)	0	-600,321
Proceeds from disposition of assets	89,916	296,582
Net cash used in investing activities	-422,658	-888,597
FINANCING ACTIVITIES:	'	'
Borrowings under credit agreement	222,500	543,700
Payments under credit agreement	-293,600	-593,700
Proceeds from issuance of senior subordinated notes, net of debt issuance costs and discount	0	386,274
Proceeds from exercise of stock options	578	90
Book overdrafts	-7,014	40,281
Net cash provided by (used in) financing activities	-77,536	376,645
Net increase in cash and cash equivalents	767	188
Cash and cash equivalents, beginning of period	974	835
Cash and cash equivalents, end of period	1,741	1,023
Supplemental disclosure of cash flow information:	'	'
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment	-516	26,477
Non-cash additions (reductions) to oil and natural gas properties related to asset retirement obligations	($16,417)	$45,188

Basis_Of_Preparation_And_Prese

Basis Of Preparation And Presentation	9 Months Ended
	Sep. 30, 2013
Basis Of Preparation And Presentation [Abstract]	'
Basis Of Preparation And Presentation	'
	BASIS OF PREPARATION AND PRESENTATION
	The accompanying unaudited condensed consolidated financial statements in this quarterly report include the accounts of Unit Corporation and all its subsidiaries and affiliates and have been prepared under the rules and regulations of the SEC. The terms “company,” “Unit,” “we,” “our,” “us,” or like terms refer to Unit Corporation, a Delaware corporation, and, as appropriate, one or more of its subsidiaries and affiliates, except as otherwise indicated or as the context otherwise requires.
	The accompanying condensed consolidated financial statements are unaudited and do not include all the notes in our annual financial statements. This quarterly report should be read in conjunction with the audited consolidated financial statements and notes included in our Form 10-K, filed February 26, 2013, for the year ended December 31, 2012.
	In our management's opinion, the accompanying unaudited condensed consolidated financial statements contain all normal recurring adjustments (including the elimination of all intercompany transactions) necessary to fairly state the following:
	• Balance Sheets at September 30, 2013 and December 31, 2012;
	• Statements of Income for the three and nine months ended September 30, 2013 and 2012;
	• Statements of Comprehensive Income for the three and nine months ended September 30, 2013 and 2012; and
	• Statements of Cash Flows for the nine months ended September 30, 2013 and 2012.
	Our financial statements are prepared in conformity with generally accepted accounting principles in the United States (GAAP). GAAP requires us to make certain estimates and assumptions that may affect the amounts reported in our unaudited condensed consolidated financial statements and accompanying notes. Actual results may differ from those estimates. Results for the nine months ended September 30, 2013 and 2012 are not necessarily indicative of the results to be realized for the full year in the case of 2013, or that we realized for the full year of 2012.
	Certain amounts in the accompanying unaudited condensed consolidated financial statements for prior periods have been reclassified to conform to current year presentation. Certain financial statement captions were expanded or combined with no impact to consolidated net income or shareholders' equity.
	With respect to the unaudited financial information for the three and nine month periods ended September 30, 2013 and 2012, our auditors, PricewaterhouseCoopers LLP, reported that it applied limited procedures in accordance with professional standards in reviewing that information. Its separate report, dated November 5, 2013, which is included in this quarterly report, states that it did not audit and it does not express an opinion on that unaudited financial information. Accordingly, the degree of reliance placed on its report should be restricted in light of the limited review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 (Act) for its report on the unaudited financial information because that report is not a “report” or a “part” of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Act.

Oil_And_Natural_Gas_Properties

Oil And Natural Gas Properties	9 Months Ended
	Sep. 30, 2013
Extractive Industries [Abstract]	'
Oil And Natural Gas Properties	'
	OIL AND NATURAL GAS PROPERTIES
	Full cost accounting rules require us to review the carrying value of our oil and natural gas properties at the end of each quarter. Under those rules, the maximum amount allowed as the carrying value is referred to as the ceiling. The ceiling is the sum of the present value (using a 10% discount rate) of the estimated future net revenues from our proved reserves (using the unescalated 12-month average price of our oil, NGLs, and natural gas adjusted for any cash flow hedges), plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, less related income taxes. In the event the net book value of the oil, NGLs, and natural gas properties being amortized exceeds the full cost ceiling, the excess amount is charged to expense in the period during which the excess occurs, even if prices are depressed for only a short period of time. Once incurred, a write-down of oil and natural gas properties is not reversible.
	For the quarter ended June 30, 2012, the 12-month average commodity prices, including the discounted value of our cash flow hedges, decreased significantly resulting in a non-cash ceiling test write down of $115.9 million pre-tax ($72.1 million, net of tax). Our qualifying cash flow hedges used in the ceiling test determination as of June 30, 2012, consisted of swaps covering 2.9 MMBoe in 2012 and 4.5 MMBoe in 2013. The effect of those hedges on the June 30, 2012 ceiling test was a $32.5 million pre-tax increase in the discounted net cash flows of our oil and natural gas properties.
	At September 30, 2013, the 12-month average commodity prices, including the discounted value of our cash flow hedges, were at levels that did not require us to take a write-down of our oil and natural gas properties. If there are declines in the 12-month average prices, including the discounted value of our cash flow hedges, we may be required to record a write-down in future periods.
	Our qualifying cash flow hedges used in the ceiling test determination as of September 30, 2013, consisted of swaps and collars covering 1.7 MMBoe in 2013. The effect of those hedges on the September 30, 2013 ceiling test was a $2.1 million pre-tax increase in the discounted net cash flows of our oil and natural gas properties. Even without the impact of those hedges, we would not have been required to take a write-down for the quarter. Our oil, NGLs, and natural gas hedging is discussed in Note 10 of the Notes to our Unaudited Condensed Consolidated Financial Statements.

Acquisitions_and_Divestitures

Acquisitions and Divestitures	9 Months Ended
	Sep. 30, 2013
Acquisitions and divestitures [Abstract]	'
Acquisitions and Divestitures	'
	ACQUISITIONS AND DIVESTITURES
	On September 17, 2012, we closed on the acquisition of certain oil and natural gas assets from Noble Energy, Inc. (Noble). The acquisition included approximately 83,000 net acres primarily in the Granite Wash, Cleveland, and various other plays in western Oklahoma and the Texas Panhandle. The amount paid after final closing adjustments was $592.6 million.
	As of April 1, 2012, the effective date of the Noble acquisition, the estimated proved reserves of the acquired properties were 44 million barrels of oil equivalent (MMBoe). The acquisition added approximately 24,000 net acres to our Granite Wash core area in the Texas Panhandle with significant resource potential including approximately 600 horizontal drilling locations. The total acreage acquired in western Oklahoma was approximately 59,000 net acres and is characterized by high working interest and operatorship, 95% of which is held by production. We also received four gathering systems as part of the transaction and other miscellaneous assets.
	The Noble acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which requires that the acquired assets and liabilities be recorded at their fair values as of the acquisition date. The following table summarizes the purchase price and the estimated values of assets acquired and liabilities assumed. It was based on information available to us at the time the unaudited condensed consolidated financial statements were prepared. We believe these estimates are reasonable; however, the estimates are subject to change as additional information becomes available and is assessed by us (in thousands):
	Adjusted Purchase Price
	Total consideration given	$	592,627
	Adjusted Allocation of Purchase Price
	Oil and natural gas properties included in the full cost pool:
	Proved oil and natural gas properties	$	260,799
	Undeveloped oil and natural gas properties	353,343
	Total oil and natural gas properties included in the full cost pool (1)	614,142
	Equipment and facilities	25,163
	Asset retirement obligation	(46,678		)
	Fair value of net assets acquired	$	592,627
	(1) We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates.
	Pro Forma Financial Information
	The following unaudited pro forma financial information is presented to reflect the operations of the acquired assets as if the acquisition had been completed on January 1, 2011. The unaudited pro forma financial information was derived from the historical accounting records of the seller adjusted for estimated transaction costs, depreciation, depletion and amortization, ceiling test impact, general and administrative expenses, capitalized interest, and interest on the 400.0 million of bonds issued along with additional borrowings under our credit facility to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of our expected future results of operations. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the acquisition or any estimated costs that will be incurred to integrate these assets. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors.
		Three Months Ended			Nine Months Ended
		September 30,			September 30,
		2012			2012
		(In thousands, except per share data)
	Pro forma:
	Revenues	$	335,394		$	1,041,350
	Net income	$	47,186		$	140,670
	Net income per common share:
	Basic	$	0.98		$	2.94
	Diluted	$	0.98		$	2.92
	2012 Divestitures
	We completed the following divestitures in 2012, all of which were accounted for as adjustments to the full cost pool with no gain or loss recognized:
	•	In September 2012, we sold our interest in certain Bakken properties (located in North Dakota). The proceeds, net of related expenses, were $226.6 million.
	•	In September 2012, we sold certain oil and natural gas assets located in Brazos and Madison counties of Texas, for approximately $44.1 million.
	2013 Divestitures
	In August 2013, we sold additional Bakken property interests. The proceeds, net of related expenses, were $57.1 million. These proceeds were accounted for as adjustments to the full cost pool with no gain or loss recognized.
	Other
	The acquisition and divestitures completed in the third quarter 2012, were structured to allow us to secure like-kind exchange tax treatment for the transactions under Section 1031 of the Internal Revenue Code.

Earnings_Per_Share

Earnings Per Share	9 Months Ended
	Sep. 30, 2013
Earnings Per Share [Abstract]	'
Earnings Per Share	'
	EARNINGS PER SHARE
	Information related to the calculation of earnings per share follows:
		Income		Weighted		Per-Share
		(Numerator)		Shares		Amount
				(Denominator)
		(In thousands except per share amounts)
	For the three months ended September 30, 2013
	Basic earnings per common share	$	34,232	48,254		$	0.71
	Effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs)	—		404		(0.01		)
	Diluted earnings per common share	$	34,232	48,658		$	0.7
	For the three months ended September 30, 2012
	Basic earnings per common share	$	46,586	47,938		$	0.97
	Effect of dilutive stock options, restricted stock, and SARs	—		263		—
	Diluted earnings per common share	$	46,586	48,201		$	0.97
	The following table shows the number of stock options and SARs (and their average exercise price) not included in the prior calculation because their option exercise prices were greater than the average market price of our common stock:
		Three Months Ended
		September 30,
		2013		2012
	Stock options and SARs	149,665		278,901
	Average exercise price	$	58.41	$	51.57
		Income		Weighted		Per-Share
		(Numerator)		Shares		Amount
				(Denominator)
		(In thousands except per share amounts)
	For the nine months ended September 30, 2013
	Basic earnings per common share	$	133,445	48,193		$	2.77
	Effect of dilutive stock options, restricted stock, and SARs	—		317		(0.02		)
	Diluted earnings per common share	$	133,445	48,510		$	2.75
	For the nine months ended September 30, 2012
	Basic earnings per common share	$	79,723	47,891		$	1.66
	Effect of dilutive stock options, restricted stock, and SARs	—		215		—
	Diluted earnings per common share	$	79,723	48,106		$	1.66
	The following table shows the number of stock options and SARs (and their average exercise price) not included in the prior calculation because their option exercise prices were greater than the average market price of our common stock:
		Nine Months Ended
		September 30,
		2013		2012
	Stock options and SARs	149,665		250,901
	Average exercise price	$	58.41	$	52.72

Accrued_Liabilities

Accrued Liabilities	9 Months Ended
	Sep. 30, 2013
Accounts Payable and Accrued Liabilities, Current [Abstract]	'
Accrued Liabilities	'
	ACCRUED LIABILITIES
	Accrued liabilities consisted of the following:
		September 30, 2013		December 31, 2012
		(In thousands)
	Employee costs	$	23,944	$	24,632
	Interest payable	17,747		6,568
	Lease operating expenses	14,738		10,903
	Taxes	11,563		7,308
	Other	10,565		4,687
	Total accrued liabilities	$	78,557	$	54,098

LongTerm_Debt_And_Other_LongTe

Long-Term Debt And Other Long-Term Liabilities	9 Months Ended
	Sep. 30, 2013
Debt Disclosure [Abstract]	'
Long-Term Debt And Other Long-Term Liabilities	'
	LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES
	Long-Term Debt
	Our long-term debt consisted of (or arose under) the following:
		September 30, 2013		December 31, 2012
		(In thousands)
	Credit agreement with an average interest rate of 2.9% at December 31, 2012	$	—	$	71,100
	6.625% senior subordinated notes due 2021, net of unamortized discount of $4.4 million	645,584		645,259
	at September 30, 2013 and $4.7 million at December 31, 2012
	Total long-term debt	$	645,584	$	716,359
	Credit Agreement. On September 5, 2012, we amended our Senior Credit Agreement (credit agreement). The amount available to be borrowed is the lesser of the amount we elect (from time to time) as the commitment amount (currently $500.0 million) or the value of the borrowing base as determined by the lenders (currently $800.0 million), but in either event not to exceed the maximum credit agreement amount of $900.0 million. We are charged a commitment fee ranging from 0.375 to 0.50 of 1% on the amount available but not borrowed. That fee varies based on the amount borrowed as a percentage of the amount of the total borrowing base. In connection with the amendment, we paid $1.5 million in origination, agency, syndication, and other related fees. We are amortizing these fees over the life of the credit agreement. The credit agreement is currently scheduled to mature on September 13, 2016.
	The amount of the borrowing base–which is subject to redetermination by the lenders on April 1st and October 1st of each year–is based primarily on a percentage of the discounted future value of our oil and natural gas reserves. There was no change to the borrowing base as of the October 1, 2013 redetermination. We or the lenders may request a onetime special redetermination of the borrowing base between each scheduled redetermination. In addition, we may request a redetermination following the completion of an acquisition that meets the requirements set forth in the credit agreement.
	At our election, any part of the outstanding debt under the credit agreement may be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the sum of the LIBOR base for the applicable term plus 1.75% to 2.50% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the credit agreement that in any event cannot be less than LIBOR plus 1.00%. Interest is payable at the end of each month and the principal may be repaid in whole or in part at anytime, without a premium or penalty. At September 30, 2013, there were no outstanding borrowings under our credit agreement.
	Funds under the credit agreement can be used to finance general working capital requirements for (a) exploration, development, production, and acquisition of oil and gas properties, (b) acquisitions and operation of mid-stream assets, (c) issuance of standby letters of credit, (d) contract drilling services, and (e) general corporate purposes.
	The credit agreement prohibits, among other things:
	•	the payment of dividends (other than stock dividends) during any fiscal year in excess of 30% of our consolidated net income for the preceding fiscal year;
	•	the incurrence of additional debt with certain limited exceptions; and
	•	the creation or existence of mortgages or liens, other than those in the ordinary course of business, on any of our properties, except in favor of our lenders.
	The credit agreement also requires that we have at the end of each quarter:
	•	a current ratio (as defined in the credit agreement) of not less than 1 to 1; and
	•	a leverage ratio of funded debt to consolidated EBITDA (as defined in the credit agreement) for the most recently ended rolling four fiscal quarters of no greater than 4 to 1.
	As of September 30, 2013, we were in compliance with the covenants contained in the credit agreement.
	6.625% Senior Subordinated Notes. On May 18, 2011, we completed the sale of $250.0 million of our 6.625% Senior Subordinated Notes (the 2011 Notes). The 2011 Notes were issued at par and mature on May 15, 2021. We received net proceeds of approximately $244.0 million after deducting fees of approximately $6.0 million. Those fees are being amortized as debt issuance cost over the life of the 2011 Notes. We used the net proceeds to repay outstanding borrowings under our credit agreement, which was $220.3 million on May 18, 2011. The remaining proceeds were used for general working capital purposes.
	On July 24, 2012, we completed the sale of $400.0 million aggregate principal amount of senior subordinated notes (the 2012 Notes) due May 15, 2021. Those notes also bear interest at a rate of 6.625% per year. The 2012 Notes were sold at 98.75% of par plus accrued interest from May 15, 2012. We used the net proceeds from the offering to partially finance our acquisition of certain oil and natural gas properties. We incurred $8.7 million of fees that are being amortized as debt issuance cost over the life of the 2012 Notes.
	On November 13, 2012, we registered with the SEC an offer on Form S-4 to exchange the 2012 Notes for additional notes with materially identical terms to our existing registered 2011 Notes. On January 7, 2013, the exchange of all the 2012 Notes was completed. The notes issued in exchange for the 2012 Notes are now registered and treated as a single series of debt securities with the 2011 Notes, bringing the total of the aggregate principal amount of 6.625% senior subordinated notes to $650.0 million (the Notes). Interest on the Notes is payable semi-annually (in arrears) on May 15 and November 15 of each year. The Notes will mature on May 15, 2021.
	The Notes are guaranteed by our 100% owned domestic direct and indirect subsidiaries (the Guarantors). Unit, as the parent company, has no independent assets or operations. The guarantees are full and unconditional and joint and several, subject to certain automatic customary releases, including sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, exercise of legal defeasance option or covenant defeasance option, and designation of a subsidiary guarantor as unrestricted in accordance with their respective Indentures described below. Any subsidiaries of Unit other than the Guarantors are minor. There are no significant restrictions on the ability of Unit to receive funds from its subsidiaries through dividends, loans, advances, or otherwise.
	The Notes are subject to an Indenture dated as of May 18, 2011, between us and Wilmington Trust, National Association (successor to Wilmington Trust FSB), as Trustee (the Trustee). The Indenture was supplemented by the First Supplemental Indenture dated as of May 18, 2011 and further supplemented by the Second Supplemental Indenture dated as of January 7, 2013. As supplemented, the Indenture establishes the terms and provides for the issuance of the Notes . The discussion of the Notes is qualified by and subject to the actual terms of the Indenture.
	On and after May 15, 2016, we may redeem all or, from time to time, a part of the Notes at certain redemption prices, plus accrued and unpaid interest. Before May 15, 2014, we may on any one or more occasions redeem up to 35% of the original principal amount of the Notes with the net cash proceeds of one or more equity offerings at a redemption price of 106.625% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, provided that at least 65% of the original principal amount of the Notes remains outstanding after each redemption. In addition, at any time before May 15, 2016, we may redeem the Notes, in whole or in part, at a redemption price equal to 100% of the principal amount plus a “make whole” premium, plus accrued and unpaid interest, if any, to the redemption date. If a “change of control” occurs, subject to certain conditions, we must offer to repurchase from each holder all or any part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest, if any, to the date of purchase. The Indenture contains customary events of default. The Indenture contains covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to incur or guarantee additional indebtedness; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with other companies. We were in compliance with all covenants of the Notes as of September 30, 2013.
	Other Long-Term Liabilities
	As of the dates indicated, other long-term liabilities consisted of the following:
		September 30, 2013		December 31, 2012
		(In thousands)
	Asset retirement obligation (ARO) liability	$	133,894	$	146,159
	Workers’ compensation	20,207		18,517
	Separation benefit plans	8,991		7,972
	Gas balancing liability	3,838		3,838
	Deferred compensation plan	3,216		2,779
		170,146		179,265
	Less current portion	11,985		12,282
	Total other long-term liabilities	$	158,161	$	166,983
	Estimated annual principal payments under the terms of debt and other long-term liabilities during each of the five successive twelve month periods beginning October 1, 2013 (and through 2018) are $12.0 million, $40.8 million, $5.2 million, $3.9 million, and $3.8 million, respectively.

Asset_Retirement_Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Asset Retirement Obligations	'
	ASSET RETIREMENT OBLIGATIONS
	We are required to record the estimated fair value of the liabilities relating to the future retirement of our long-lived assets. Our oil and natural gas wells are plugged and abandoned when the oil and natural gas reserves in those wells are depleted or the wells are no longer able to produce. The plugging and abandonment liability for a well is recorded in the period in which the obligation is incurred (at the time the well is drilled or acquired). None of our assets are restricted for purposes of settling these AROs. All of our AROs relate to the plugging costs associated with our oil and gas wells.
	The following table shows certain information about our AROs:
		Nine Months Ended
		September 30,
		2013			2012
		(In thousands)
	ARO liability, January 1:	$	146,159		$	96,446
	Accretion of discount	4,152			3,215
	Liability incurred	3,820			52,306
	Liability settled	(4,071		)	(1,606		)
	Revision of estimates (1)	(16,166		)	(4,254		)
	ARO liability, September 30:	133,894			146,107
	Less current portion	2,954			2,857
	Total long-term ARO	$	130,940		$	143,250
	-1	Plugging liability estimates were revised in both 2013 and 2012 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments as well as changes in estimated timing of cash flows.

New_Accounting_Pronouncements

New Accounting Pronouncements	9 Months Ended
	Sep. 30, 2013
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]	'
New Accounting Pronouncements	'
	NEW ACCOUNTING PRONOUNCEMENTS
	Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. In July 2013, ASU 2013-11 was issued because GAAP does not include explicit guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The amendment provides explicit guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The amendments in this Update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. Early adoption is permitted.  The amendments should be applied prospectively to all unrecognized tax benefits that exist at the effective date. Retrospective application is permitted. We anticipate there will be no effect on our financial position or results of operations when adopted.
	Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes. The FASB has issued ASU 2013-10, the amendments in this update permit the Fed Funds Effective Swap Rate (OIS) to be used as a U.S. benchmark interest rate for hedge accounting purposes under Topic 815, in addition to U.S. Treasury and LIBOR. The amendments also remove the restriction on using different benchmark rates for similar hedges. The amendments are effective prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. We currently do not have any interest rate hedges at this time.
	Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. In February 2013, the FASB issued ASU 2013-02 to address the presentation of comprehensive income related to ASU 2011-05. The standard requires that companies present, either in a single note or parenthetically on the face of the financial statements, the effect of significant amounts reclassified from each component of accumulated other comprehensive income based on its source (e.g., the release due to cash flow hedges from interest rate contracts) and the income statement line items affected by the reclassification (e.g., interest income or interest expense). The amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2012. We chose to present the information in a single note (Note 11 of the Notes to our Unaudited Condensed Consolidated Financial Statements).
	Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. In January 2013, the FASB issued ASU 2013-01 to limit the scope of balance sheet offsetting disclosures contained in previously issued guidance in ASU 2011-11—Disclosures about Offsetting Assets and Liabilities. Specifically, ASU 2011-11 applies only to derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with specific criteria contained in the FASB Accounting Standards or subject to a master netting arrangement or similar agreement.
	Unlike IFRS, GAAP allows companies the option to present net in their balance sheets derivatives that are subject to a legally enforceable netting arrangement with the same party where rights of set-off are only available in the event of default or bankruptcy. To address these differences between IFRS and GAAP, the FASB and the IASB (the Boards) issued an exposure draft that proposed new criteria for netting that were narrower than the current conditions currently in GAAP. Nevertheless, in response to feedback from their respective stakeholders, the Boards decided to retain their existing offsetting models. Instead, the Boards have issued common disclosure requirements related to offsetting arrangements to allow investors to better compare financial statements prepared in accordance with IFRS or GAAP. The amendments in this ASU require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. An entity is required to apply the amendments for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. An entity should provide the disclosures required by those amendments retrospectively for all comparative periods presented. Derivatives subject to a master netting agreement are the only transactions in this accounting standard that affect us. We provide the effect of netting on our financial position in Note 11 of the Notes to our Unaudited Condensed Consolidated Financial Statements.

StockBased_Compensation

Stock-Based Compensation	9 Months Ended
	Sep. 30, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Stock-Based Compensation	'
	STOCK-BASED COMPENSATION
	For the three and nine months ended September 30, 2013, we recognized stock compensation expense for restricted stock awards of $4.4 million and $12.0 million, respectively. For the same period we also capitalized stock compensation cost for oil and natural gas properties of $1.0 million and $2.6 million, respectively. For these same periods, the tax benefit related to this stock based compensation was $1.8 million and $4.7 million, respectively. The remaining unrecognized compensation cost related to unvested awards at September 30, 2013 is approximately $20.7 million of which $3.3 million is anticipated to be capitalized. The weighted average period of time over which this cost will be recognized is 0.8 of a year.
	For the three and nine months ended September 30, 2012, we recognized stock compensation expense for restricted stock awards of $2.9 million and $8.2 million, respectively. For the same period we also capitalized stock compensation cost for oil and natural gas properties of $0.7 million and $2.0 million, respectively. For these same periods, the tax benefit related to this stock based compensation was $1.2 million and $3.2 million, respectively.
	We grant stock-based and cash-based compensation to our employees (including employees of subsidiaries) as well as to non-employee directors under our Unit Corporation Stock and Incentive Compensation Plan Amended and Restated May 2, 2012 (the amended plan). A total of 3,300,000 shares of the company's common stock is authorized for issuance to eligible participants under the amended plan. The amended plan succeeds our previous Non-employee Directors' 2000 Stock Option Plan (the option plan).
	We did not grant any SARs or stock options during either of the three or nine month periods ending September 30, 2013 and 2012. The following table shows the fair value of the restricted stock awards granted to employees and non-employee directors:
		Three Months Ended					Nine Months Ended
		September 30,					September 30,
		2013		2012			2013			2012
	Shares granted:
	Employees	—		2,509			448,549			370,445
	Non employee directors	—		—			21,128			24,606
		—		2,509			469,677			395,051
	Estimated fair value (in millions):
	Employees	$	—	$	0.1		$	21		$	15.7
	Non employee directors	—		—			0.9			1
		$	—	$	0.1		$	21.9		$	16.7
	Percentage of shares granted expected to be distributed:
	Employees	N/A		95		%	94		%	94		%
	Non employee directors	N/A		—		%	100		%	100		%
	The restricted stock awards granted during the three and nine months ended September 30, 2013 and 2012 are being recognized over a three year vesting period, except for a portion of those awards made to certain executive officers. As to those executive officers, 30% of the shares granted, or 57,405 shares in 2013 and 46,441 shares in 2012 (the performance shares), will cliff vest in the first half of 2016 and 2015, respectively. The actual number of performance shares that vest in 2015 and 2016 will be based on the company’s achievement of certain performance criteria over a three-year period, and will range from 50% to 150% of the restricted shares granted as performance shares. Based on the performance criteria, the participants could receive more than 100% of the performance based shares. The total aggregate stock compensation expense and capitalized cost related to oil and natural gas properties for 2013 awards for the first nine months of 2013 was $7.1 million.

Derivatives

Derivatives	9 Months Ended
	Sep. 30, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Derivatives	'
	DERIVATIVES
	Commodity Derivatives
	We have entered into various types of derivative transactions covering some of our projected natural gas, NGLs, and oil production. These transactions are intended to reduce our exposure to market price volatility by setting the price(s) we will receive for that production. Our decisions on the price(s), type, and quantity of our production hedged is based, in part, on our view of current and future market conditions. As of September 30, 2013, our derivative transactions consisted of the following types of hedges:
	•	Swaps. We receive or pay a fixed price for the hedged commodity and pay or receive a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.
	•	Collars. A collar contains a fixed floor price (put) and a ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party.
	We have documented policies and procedures to monitor and control the use of derivative transactions. We do not engage in derivative transactions for speculative purposes. In August 2012, we determined–on a prospective basis–that we would no longer elect to use cash flow hedge accounting for our economic hedges. Therefore, the change in fair value on all commodity derivatives entered into after that determination will be reflected in the income statement and not in accumulated other comprehensive income (OCI).
	At September 30, 2013, we had the following outstanding cash flow hedges:
	Term	Commodity	Hedged Volume	Weighted Average Fixed	Hedged Market
				Price for Swaps
	Oct'13 - Dec'13	Crude oil – swap	5,500 Bbl/day	$99.71	WTI – NYMEX
	Oct'13 - Dec'13	Natural gas – swap	60,000 MMBtu/day	$3.56	IF – NYMEX (HH)
	Oct'13 - Dec'13	Natural gas – collar	20,000 MMBtu/day	$3.25-3.72	IF – NYMEX (HH)
	At September 30, 2013, we had the following outstanding non-designated hedges:
	Term	Commodity	Hedged Volume	Weighted Average Fixed	Hedged Market
				Price for Swaps
	Oct'13 - Dec'13	Crude oil – swap	3,000 Bbl/day	$94.59	WTI – NYMEX
	Jan'14 - Dec'14	Crude oil – swap	3,000 Bbl/day	$91.77	WTI – NYMEX
	Jan'14 - Jun'14	Crude oil – swap	500 Bbl/day	$100.03	WTI – NYMEX
	Jan'14 - Dec'14	Crude oil – collar	4,000 Bbl/day	$90.00-96.08	WTI – NYMEX
	Oct'13 - Dec'13	Natural gas – swap	20,000 MMBtu/day	$3.94	IF – NYMEX (HH)
	Jan'14 - Dec'14	Natural gas – swap	50,000 MMBtu/day	$4.24	IF – NYMEX (HH)
	The following tables present the fair values and locations of the derivative transactions recorded in our Unaudited Condensed Consolidated Balance Sheets:
			Derivative Assets
			Fair Value
		Balance Sheet Location	September 30, 2013				December 31, 2012
			(In thousands)
	Derivatives designated as hedging instruments
	Commodity derivatives:
	Current	Current derivative asset	$	486			$	13,674
	Long-term	Non-current derivative asset	—				—
	Total derivatives designated as hedging instruments		486				13,674
	Derivatives not designated as hedging instruments
	Commodity derivatives:
	Current	Current derivative asset	4,028				2,878
	Long-term	Non-current derivative asset	1,133				—
	Total derivatives not designated as hedging instruments		5,161				2,878
	Total derivative assets		$	5,647			$	16,552
			Derivative Liabilities
			Fair Value
		Balance Sheet Location	September 30, 2013				December 31, 2012
			(In thousands)
	Derivatives designated as hedging instruments
	Commodity derivatives:
	Current	Current derivative liabilities	$	1,750			$	1,005
	Long-term	Non-current derivative liabilities	—				—
	Total derivatives designated as hedging instruments		1,750				1,005
	Derivatives not designated as hedging instruments
	Commodity derivatives:
	Current	Current derivative liabilities	4,730				943
	Long-term	Non-current derivative liabilities	938				562
	Total derivatives not designated as hedging instruments		5,668				1,505
	Total derivative liabilities		$	7,418			$	2,510
	If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty in our Unaudited Condensed Consolidated Balance Sheets.
	We recognize in accumulated OCI the effective portion of any changes in fair value for derivatives designated as cash flow hedges and reclassify the recognized gains (losses) on the sales to oil and natural gas revenue as the underlying transactions are settled. As of September 30, 2013 and 2012, we had recognized a loss of $1.0 million and a gain of $9.9 million, net of tax, respectively, in accumulated OCI.
	Based on market prices at September 30, 2013, we expect to transfer over the next three months (in the related month of settlement) a loss of approximately $1.0 million, net of tax, into revenue. The cash flow derivative instruments existing as of September 30, 2013 are expected to mature by December 2013.
	For our economic hedges that we did not apply cash flow accounting to, any changes in their fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net in our Unaudited Condensed Consolidated Statements of Income. Changes in the fair value of derivatives designated as cash flow hedges, to the extent they are effective in offsetting cash flows attributable to the hedged risk, are recorded in OCI until the hedged item is recognized into earnings. When the hedged item is recognized into earnings, it is reported in oil and natural gas revenues. Any change in fair value resulting from ineffectiveness is recognized in gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net. Before October 2012, we reported all gains (losses) associated with derivatives in oil and natural gas revenues. We reflect gains (losses) on non-designated hedges and ineffectiveness from cash flow hedges along with other revenue items in other income (expense) below income from operations. Prior year amounts have been reclassified to conform to current year presentation.
	This table shows the effect of derivative instruments on our Unaudited Condensed Consolidated Statements of Income (cash flow hedges) for the nine months ended September 30:
	Derivatives in Cash Flow Hedging	Amount of Gain or (Loss) Recognized in
	Relationships	Accumulated OCI on Derivative (Effective Portion) (1)
		2013				2012
		(In thousands)
	Commodity derivatives	$	(963	)		$	9,912
	(1) Net of taxes.
This table shows the effect of derivative instruments on our Unaudited Condensed Consolidated Statements of Income (cash flow hedges) for the three months ended September 30:
Derivative Instrument	Location of Gain or (Loss) Reclassified	Amount of Gain or (Loss)						Amount of Gain or (Loss)
	from Accumulated OCI into Income	Reclassified from Accumulated						Recognized in Income (2)
	& Location of Gain or (Loss) Recognized in Income	OCI into Income (1)
		2013				2012		2013			2012
		(In thousands)
Commodity derivatives	Oil and natural gas revenue	$	(3,210	)		$	14,243	$	—		$	—
Commodity derivatives	Loss on derivatives not designated as hedges and hedge ineffectiveness, net	—				—		(252		)	(4,015		)
Total		$	(3,210	)		$	14,243	$	(252	)	$	(4,015	)
-1	Effective portion of gain (loss).
-2	Ineffective portion of gain (loss).
This table shows the effect of derivative instruments on our Unaudited Condensed Consolidated Statements of Income (derivatives not designated as hedging instruments) for the three months ended September 30:
Derivatives Not Designated as Hedging	Location of Gain or (Loss)	Amount of Gain or (Loss) Recognized in
Instruments	Recognized in Income on	Income on Derivative (1)
	Derivative
		2013				2012
		(In thousands)
Commodity derivatives	Loss on derivatives not designated as hedges and hedge ineffectiveness, net	$	(13,508	)		$	—
Total		$	(13,508	)		$	—
-1	Amount settled during the period is a loss of ($2.434) and $0, respectively.
This table shows the effect of derivative instruments on our Unaudited Condensed Consolidated Statements of Income (cash flow hedges) for the nine months ended September 30:
Derivative Instrument	Location of Gain or (Loss) Reclassified	Amount of Gain or (Loss)						Amount of Gain or (Loss)
	from Accumulated OCI into Income	Reclassified from Accumulated						Recognized in Income (2)
	& Location of Gain or (Loss) Recognized in Income	OCI into Income (1)
		2013				2012		2013			2012
		(In thousands)
Commodity derivatives	Oil and natural gas revenue	$	(202	)		$	38,088	$	—		$	—
Commodity derivatives	Loss on derivatives not designated as hedges and hedge ineffectiveness, net	—				—		116			(4,621		)
Total		$	(202	)		$	38,088	$	116		$	(4,621	)
-1	Effective portion of gain (loss).
-2	Ineffective portion of gain (loss).
This table shows the effect of derivative instruments on our Unaudited Condensed Consolidated Statements of Income (derivatives not designated as hedging instruments) for the nine months ended September 30:
Derivatives Not Designated as Hedging	Location of Gain or (Loss)	Amount of Gain or (Loss) Recognized in
Instruments	Recognized in Income on	Income on Derivative (1)
	Derivative
		2013				2012
		(In thousands)
Commodity derivatives	Loss on derivatives not designated as hedges and hedge ineffectiveness, net	$	(3,456	)		$	—
Total		$	(3,456	)		$	—
-1	Amount settled during the period is a loss of ($1.575) and $0, respectively.

Fair_Value_Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Measurements	'
	FAIR VALUE MEASUREMENTS
	Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (in either case, an exit price). To estimate an exit price, a three-level hierarchy is used prioritizing the valuation techniques used to measure fair value. The highest priority is given to Level 1 and the lowest priority is given to Level 3. The levels are summarized as follows:
	•	Level 1 - unadjusted quoted prices in active markets for identical assets and liabilities.
	•	Level 2 - significant observable pricing inputs other than quoted prices included within level 1 that are either directly or indirectly observable as of the reporting date. Essentially, inputs (variables used in the pricing models) that are derived principally from or corroborated by observable market data.
	•	Level 3 - generally unobservable inputs which are developed based on the best information available and may include our own internal data.
	The inputs available to us determine the valuation technique we use to measure the fair values of our financial instruments. We corroborate these inputs based on recent transactions and broker quotes and compare the fair value with actual settlements.
	The following tables set forth our recurring fair value measurements:
		September 30, 2013
		Level 2				Level 3			Gross Amounts			Effect of Netting			Net Amounts Presented
		(In thousands)
	Financial assets (liabilities):
	Commodity derivatives:
	Assets	$	8,473			$	—		$	8,473		$	(2,826	)	$	5,647
	Liabilities	(7,622		)		(2,622		)	(10,244		)	2,826			(7,418		)
		$	851			$	(2,622	)	$	(1,771	)	$	—		$	(1,771	)
		December 31, 2012
		Level 2				Level 3			Gross Amounts			Effect of Netting			Net Amounts Presented
		(In thousands)
	Financial assets (liabilities):
	Commodity derivatives:
	Assets	$	18,555			$	—		$	18,555		$	(2,003	)	$	16,552
	Liabilities	(3,918		)		(595		)	(4,513		)	2,003			(2,510		)
		$	14,637			$	(595	)	$	14,042		$	—		$	14,042
	All of our counterparties are subject to master netting arrangements. If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty. We are not required to post any cash collateral with our counterparties and no collateral has been posted as of September 30, 2013.
	Certain natural gas fixed price swaps were transferred from Level 3 to Level 2 as of June 30, 2012 because of improvements in our ability to obtain and corroborate observable significant inputs to assess the fair value. Our policy is to recognize transfers either in or out of fair value hierarchy levels as of the end of the quarterly reporting period in which the event or change in circumstances causing the transfer occurred.
	The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above:
	Level 2 Fair Value Measurements
	Commodity Derivatives. We measure the fair values of our crude oil and natural gas swaps using estimated internal discounted cash flow calculations based on the NYMEX futures index.
	Level 3 Fair Value Measurements
	Commodity Derivatives. The fair values of our natural gas and crude oil collars are estimated using internal discounted cash flow calculations based on forward price curves, quotes obtained from brokers for contracts with similar terms, or quotes obtained from counterparties to the agreements.
	The following tables are reconciliations of our level 3 fair value measurements:
		Commodity Collars
		Three Months Ended							Nine Months Ended
		September 30,							September 30,
		2013				2012			2013			2012
		(In thousands)
	Beginning of period	$	1,446			$	8,130		$	(595	)	$	33,615
	Total gains or losses:
	Included in earnings (1)	(3,949		)		2,241			(2,544		)	19,114
	Included in other comprehensive income (loss)	(119		)		(4,194		)	(119		)	(7,770		)
	Settlements	—				(4,574		)	636			(21,432		)
	Transfers out of Level 3 into Level 2	—				—			—			(21,924		)
	End of period	$	(2,622	)		$	1,603		$	(2,622	)	$	1,603
	Total losses for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period	$	(3,949	)		$	(2,333	)	$	(1,908	)	$	(2,318	)
	-1	Commodity collars are reported in the Unaudited Condensed Consolidated Statements of Income in oil and natural gas revenues (for cash flow hedges) and loss on derivatives not designated as hedges and hedge ineffectiveness, net, respectively.
	The following table provides quantitative information about our Level 3 unobservable inputs at September 30, 2013:
	Commodity (1)	Fair Value			Valuation Technique	Unobservable Input	Range
		(In thousands)
	Oil collars	$	(2,503	)	Discounted cash flow	Forward commodity price curve	($7.79) - $6.86
	Natural gas collar	$	(119	)	Discounted cash flow	Forward commodity price curve	($0.19) - $0.03
	-1	The commodity contracts detailed in this category include non-exchange-traded natural gas and crude oil collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be paid or received within the settlement period.
	Based on our valuation at September 30, 2013, we determined that risk of non-performance by our counterparties was immaterial.
	Fair Value of Other Financial Instruments
	The following disclosure of the estimated fair value of financial instruments is made in accordance with accounting guidance for financial instruments. We have determined the estimated fair values by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop these estimates. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.
	At September 30, 2013, the carrying values on the Unaudited Condensed Consolidated Balance Sheets for cash and cash equivalents (classified as Level 1), accounts receivable, accounts payable, other current assets, and current liabilities approximate their fair value because of their short term nature.
	Based on the borrowing rates currently available to us for credit agreement debt with similar terms and maturities and also considering the risk of our non-performance, long-term debt under our credit agreement at September 30, 2013 approximates its fair value. This debt would be classified as Level 2.
	The carrying amounts of long-term debt, net of unamortized discount, associated with the Notes reported in the Unaudited Condensed Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012 were $645.6 million and $645.3 million, respectively. We estimated the fair value of these Notes using quoted market prices at September 30, 2013 and December 31, 2012 which were $666.3 million and $687.7 million, respectively. These Notes would be classified as Level 2.

Accumulated_Other_Comprehensiv

Accumulated Other Comprehensive Income (Loss)	9 Months Ended
	Sep. 30, 2013
Accumulated Other Comprehensive Income [Abstract]	'
Accumulated other comprehensive income	'
	ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
	Changes in accumulated other comprehensive income (loss) by component, net of tax, for the three months ended September 30 are as follows:
		Net Gains (Losses) on Cash Flow Hedges
		2013			2012
		(In thousands)
	Balance at July 1:	$	1,709		$	30,314
	Other comprehensive income (loss) before reclassification	(4,797		)	(14,137		)
	Amounts reclassified from accumulated other comprehensive income (loss)	2,125			(6,265		)
	New current-period other comprehensive income (loss)	(2,672		)	(20,402		)
	Balance at September 30:	$	(963	)	$	9,912
	Amounts reclassified from accumulated other comprehensive income (loss) into the Unaudited Condensed Consolidated Statements of Income for the three months ended September 30 are as follows:
		2013			2012			Affected Line Item in the Statement Where Net Income is Presented
		(In thousands)
	Net gains (loss) on cash flow hedges
	Commodity derivatives	$	(3,210	)	$	14,243		Oil and natural gas revenues
	Commodity derivatives	(252		)	(4,015		)	Loss on derivatives not designated as hedges and hedge ineffectiveness, net
		(3,462		)	10,228			Total before tax
		1,337			(3,963		)	Tax expense (benefit)
	Total reclassification for the period	$	(2,125	)	$	6,265		Net of tax
	Changes in accumulated other comprehensive income (loss) by component, net of tax, for the nine months ended September 30 are as follows:
		Net Gains (Losses) on Cash Flow Hedges
		2013			2012
		(In thousands)
	Balance at January 1:	$	7,587		$	19,026
	Other comprehensive income (loss) before reclassification	(8,617		)	11,353
	Amounts reclassified from accumulated other comprehensive income (loss)	67			(20,467		)
	New current-period other comprehensive income (loss)	(8,550		)	(9,114		)
	Balance at September 30:	$	(963	)	$	9,912
	Amounts reclassified from accumulated other comprehensive income (loss) into the Unaudited Condensed Consolidated Statements of Income for the nine months ended September 30 are as follows:
		2013			2012			Affected Line Item in the Statement Where Net Income is Presented
		(In thousands)
	Net gains (loss) on cash flow hedges
	Commodity derivatives	$	(202	)	$	38,088		Oil and natural gas revenues
	Commodity derivatives	116			(4,621		)	Loss on derivatives not designated as hedges and hedge ineffectiveness, net
		(86		)	33,467			Total before tax
		19			(13,000		)	Tax expense (benefit)
	Total reclassification for the period	$	(67	)	$	20,467		Net of tax

Industry_Segment_Information

Industry Segment Information	9 Months Ended
	Sep. 30, 2013
Segment Reporting [Abstract]	'
Industry Segment Information	'
	INDUSTRY SEGMENT INFORMATION
	We have three main business segments offering different products and services. They are:
	•	Oil and natural gas,
	•	Contract drilling, and
	•	Mid-stream
	The oil and natural gas segment is engaged in the development, acquisition, and production of oil, NGLs, and natural gas properties. The contract drilling segment is engaged in the land contract drilling of oil and natural gas wells and the mid-stream segment is engaged in buying, selling, gathering, processing, and treating of natural gas and NGLs.
	We evaluate each segment’s performance based on its operating income, which is defined as operating revenues less operating expenses and depreciation, depletion, amortization, and impairment. Our production in Canada is not significant.
	The following table provides certain information about each segment's operations:
		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2013			2012			2013			2012
		(In thousands)
	Revenues:
	Oil and natural gas	$	157,320		$	135,435		$	475,728		$	402,366
	Contract drilling	119,105			145,561			357,118			458,945
	Elimination of inter-segment revenue	(18,458		)	(12,141		)	(43,938		)	(37,747		)
	Contract drilling net of inter-segment revenue	100,647			133,420			313,180			421,198
	Gas gathering and processing	99,007			70,394			272,073			210,550
	Elimination of inter-segment revenue	(23,198		)	(17,459		)	(68,252		)	(50,573		)
	Gas gathering and processing net of inter-segment revenue	75,809			52,935			203,821			159,977
	Total revenues	$	333,776		$	321,790		$	992,729		$	983,541
	Operating income:
	Oil and natural gas	$	50,887		$	54,799		$	173,945		$	27,618		(2	)
	Contract drilling	24,257			40,338			72,030			134,558
	Gas gathering and processing	3,938			784			7,613			7,404
	Total operating income (1)	79,082			95,921			253,588			169,580
	General and administrative	(9,936		)	(8,434		)	(28,288		)	(23,814		)
	Gain on disposition of assets	4,345			44			7,744			1,283
	Loss on derivatives not designated as hedges and hedge ineffectiveness, net	(13,760		)	(4,015		)	(3,340		)	(4,621		)
	Interest expense, net	(3,625		)	(7,087		)	(11,777		)	(11,455		)
	Other	(14		)	(59		)	(171		)	(123		)
	Income before income taxes	$	56,092		$	76,370		$	217,756		$	130,850
	-1	Total operating income is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include non-operating revenues, general corporate expenses, gain on disposition of assets, interest expense, or income taxes.
	-2	In June 2012, we had a non-cash ceiling test write-down of $115.9 million pre-tax ($72.1 million, net of tax).

Subsequent_Event

Subsequent Event	9 Months Ended
	Sep. 30, 2013
Subsequent Events [Abstract]	'
Subsequent Events	'
	SUBSEQUENT EVENT
	In October 2013, five of our idle drilling rigs met the criteria for classification as assets held for sale. One drilling rig was sold in October and the other four drilling rigs are under contract to be sold with closings anticipated to occur during the fourth quarter of 2013 and the first quarter of 2014. The drilling rigs are being sold to two separate unaffiliated third-parties. The proceeds for the sale of these assets, less costs to sell, is expected to exceed the approximate $17.2 million net book value of the drilling rigs, both in the aggregate and for each drilling rig.

Acquisitions_and_Divestitures_

Acquisitions and Divestitures (Tables)	9 Months Ended
	Sep. 30, 2013
Acquisitions and divestitures [Abstract]	'
Schedule of Purchase Price Allocation	'
	We believe these estimates are reasonable; however, the estimates are subject to change as additional information becomes available and is assessed by us (in thousands):
	Adjusted Purchase Price
	Total consideration given	$	592,627
	Adjusted Allocation of Purchase Price
	Oil and natural gas properties included in the full cost pool:
	Proved oil and natural gas properties	$	260,799
	Undeveloped oil and natural gas properties	353,343
	Total oil and natural gas properties included in the full cost pool (1)	614,142
	Equipment and facilities	25,163
	Asset retirement obligation	(46,678		)
	Fair value of net assets acquired	$	592,627
	(1) We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates.
Pro Forma Results	'
	Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors.
		Three Months Ended			Nine Months Ended
		September 30,			September 30,
		2012			2012
		(In thousands, except per share data)
	Pro forma:
	Revenues	$	335,394		$	1,041,350
	Net income	$	47,186		$	140,670
	Net income per common share:
	Basic	$	0.98		$	2.94
	Diluted	$	0.98		$	2.92

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	9 Months Ended
	Sep. 30, 2013
Earnings Per Share [Abstract]	'
Schedule Of Earnings Per Share	'
		Income		Weighted		Per-Share
		(Numerator)		Shares		Amount
				(Denominator)
		(In thousands except per share amounts)
	For the nine months ended September 30, 2013
	Basic earnings per common share	$	133,445	48,193		$	2.77
	Effect of dilutive stock options, restricted stock, and SARs	—		317		(0.02		)
	Diluted earnings per common share	$	133,445	48,510		$	2.75
	For the nine months ended September 30, 2012
	Basic earnings per common share	$	79,723	47,891		$	1.66
	Effect of dilutive stock options, restricted stock, and SARs	—		215		—
	Diluted earnings per common share	$	79,723	48,106		$	1.66
	Information related to the calculation of earnings per share follows:
		Income		Weighted		Per-Share
		(Numerator)		Shares		Amount
				(Denominator)
		(In thousands except per share amounts)
	For the three months ended September 30, 2013
	Basic earnings per common share	$	34,232	48,254		$	0.71
	Effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs)	—		404		(0.01		)
	Diluted earnings per common share	$	34,232	48,658		$	0.7
	For the three months ended September 30, 2012
	Basic earnings per common share	$	46,586	47,938		$	0.97
	Effect of dilutive stock options, restricted stock, and SARs	—		263		—
	Diluted earnings per common share	$	46,586	48,201		$	0.97
Schedule Of Antidilutive Securities Excluded From Computation Of Earnings Per Share	'
	The following table shows the number of stock options and SARs (and their average exercise price) not included in the prior calculation because their option exercise prices were greater than the average market price of our common stock:
		Three Months Ended
		September 30,
		2013		2012
	Stock options and SARs	149,665		278,901
	Average exercise price	$	58.41	$	51.57
		Nine Months Ended
		September 30,
		2013		2012
	Stock options and SARs	149,665		250,901
	Average exercise price	$	58.41	$	52.72

Accrued_Liabilities_Tables

Accrued Liabilities (Tables)	9 Months Ended
	Sep. 30, 2013
Accounts Payable and Accrued Liabilities, Current [Abstract]	'
Accrued Liabilities	'
	Accrued liabilities consisted of the following:
		September 30, 2013		December 31, 2012
		(In thousands)
	Employee costs	$	23,944	$	24,632
	Interest payable	17,747		6,568
	Lease operating expenses	14,738		10,903
	Taxes	11,563		7,308
	Other	10,565		4,687
	Total accrued liabilities	$	78,557	$	54,098

LongTerm_Debt_And_Other_LongTe1

Long-Term Debt And Other Long-Term Liabilities (Tables)	9 Months Ended
	Sep. 30, 2013
Debt Disclosure [Abstract]	'
Long-Term Debt	'
	Our long-term debt consisted of (or arose under) the following:
		September 30, 2013		December 31, 2012
		(In thousands)
	Credit agreement with an average interest rate of 2.9% at December 31, 2012	$	—	$	71,100
	6.625% senior subordinated notes due 2021, net of unamortized discount of $4.4 million	645,584		645,259
	at September 30, 2013 and $4.7 million at December 31, 2012
	Total long-term debt	$	645,584	$	716,359
Other Long-Term Liabilities	'
	As of the dates indicated, other long-term liabilities consisted of the following:
		September 30, 2013		December 31, 2012
		(In thousands)
	Asset retirement obligation (ARO) liability	$	133,894	$	146,159
	Workers’ compensation	20,207		18,517
	Separation benefit plans	8,991		7,972
	Gas balancing liability	3,838		3,838
	Deferred compensation plan	3,216		2,779
		170,146		179,265
	Less current portion	11,985		12,282
	Total other long-term liabilities	$	158,161	$	166,983

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Schedule Of Asset Retirement Obligations	'
	The following table shows certain information about our AROs:
		Nine Months Ended
		September 30,
		2013			2012
		(In thousands)
	ARO liability, January 1:	$	146,159		$	96,446
	Accretion of discount	4,152			3,215
	Liability incurred	3,820			52,306
	Liability settled	(4,071		)	(1,606		)
	Revision of estimates (1)	(16,166		)	(4,254		)
	ARO liability, September 30:	133,894			146,107
	Less current portion	2,954			2,857
	Total long-term ARO	$	130,940		$	143,250
	-1	Plugging liability estimates were revised in both 2013 and 2012 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments as well as changes in estimated timing of cash flows.

StockBased_Compensation_Tables

Stock-Based Compensation (Tables)	9 Months Ended
	Sep. 30, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Schedule Of Fair Value Of The Restricted Stock Awards Granted During The Periods	'
	The following table shows the fair value of the restricted stock awards granted to employees and non-employee directors:
		Three Months Ended					Nine Months Ended
		September 30,					September 30,
		2013		2012			2013			2012
	Shares granted:
	Employees	—		2,509			448,549			370,445
	Non employee directors	—		—			21,128			24,606
		—		2,509			469,677			395,051
	Estimated fair value (in millions):
	Employees	$	—	$	0.1		$	21		$	15.7
	Non employee directors	—		—			0.9			1
		$	—	$	0.1		$	21.9		$	16.7
	Percentage of shares granted expected to be distributed:
	Employees	N/A		95		%	94		%	94		%
	Non employee directors	N/A		—		%	100		%	100		%

Derivatives_Tables

Derivatives (Tables)	9 Months Ended
	Sep. 30, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Cash Flow Hedges Outstanding	'
	At September 30, 2013, we had the following outstanding cash flow hedges:
	Term	Commodity	Hedged Volume	Weighted Average Fixed	Hedged Market
				Price for Swaps
	Oct'13 - Dec'13	Crude oil – swap	5,500 Bbl/day	$99.71	WTI – NYMEX
	Oct'13 - Dec'13	Natural gas – swap	60,000 MMBtu/day	$3.56	IF – NYMEX (HH)
	Oct'13 - Dec'13	Natural gas – collar	20,000 MMBtu/day	$3.25-3.72	IF – NYMEX (HH)
Non-designated hedges outstanding	'
	At September 30, 2013, we had the following outstanding non-designated hedges:
	Term	Commodity	Hedged Volume	Weighted Average Fixed	Hedged Market
				Price for Swaps
	Oct'13 - Dec'13	Crude oil – swap	3,000 Bbl/day	$94.59	WTI – NYMEX
	Jan'14 - Dec'14	Crude oil – swap	3,000 Bbl/day	$91.77	WTI – NYMEX
	Jan'14 - Jun'14	Crude oil – swap	500 Bbl/day	$100.03	WTI – NYMEX
	Jan'14 - Dec'14	Crude oil – collar	4,000 Bbl/day	$90.00-96.08	WTI – NYMEX
	Oct'13 - Dec'13	Natural gas – swap	20,000 MMBtu/day	$3.94	IF – NYMEX (HH)
	Jan'14 - Dec'14	Natural gas – swap	50,000 MMBtu/day	$4.24	IF – NYMEX (HH)
Fair Value Of Derivative Instruments And Locations In Balance Sheets	'
	The following tables present the fair values and locations of the derivative transactions recorded in our Unaudited Condensed Consolidated Balance Sheets:
			Derivative Assets
			Fair Value
		Balance Sheet Location	September 30, 2013				December 31, 2012
			(In thousands)
	Derivatives designated as hedging instruments
	Commodity derivatives:
	Current	Current derivative asset	$	486			$	13,674
	Long-term	Non-current derivative asset	—				—
	Total derivatives designated as hedging instruments		486				13,674
	Derivatives not designated as hedging instruments
	Commodity derivatives:
	Current	Current derivative asset	4,028				2,878
	Long-term	Non-current derivative asset	1,133				—
	Total derivatives not designated as hedging instruments		5,161				2,878
	Total derivative assets		$	5,647			$	16,552
			Derivative Liabilities
			Fair Value
		Balance Sheet Location	September 30, 2013				December 31, 2012
			(In thousands)
	Derivatives designated as hedging instruments
	Commodity derivatives:
	Current	Current derivative liabilities	$	1,750			$	1,005
	Long-term	Non-current derivative liabilities	—				—
	Total derivatives designated as hedging instruments		1,750				1,005
	Derivatives not designated as hedging instruments
	Commodity derivatives:
	Current	Current derivative liabilities	4,730				943
	Long-term	Non-current derivative liabilities	938				562
	Total derivatives not designated as hedging instruments		5,668				1,505
	Total derivative liabilities		$	7,418			$	2,510
Amount Of Gain Or (Loss) Recognized In Accumulated OCI On Derivative	'
	This table shows the effect of derivative instruments on our Unaudited Condensed Consolidated Statements of Income (cash flow hedges) for the nine months ended September 30:
	Derivatives in Cash Flow Hedging	Amount of Gain or (Loss) Recognized in
	Relationships	Accumulated OCI on Derivative (Effective Portion) (1)
		2013				2012
		(In thousands)
	Commodity derivatives	$	(963	)		$	9,912
	(1) Net of taxes.
Gain Or Loss Of Reclassified Accumulated Other Comprehensive Income And Recognized In Income	'
	This table shows the effect of derivative instruments on our Unaudited Condensed Consolidated Statements of Income (cash flow hedges) for the three months ended September 30:
	Derivative Instrument	Location of Gain or (Loss) Reclassified	Amount of Gain or (Loss)						Amount of Gain or (Loss)
		from Accumulated OCI into Income	Reclassified from Accumulated						Recognized in Income (2)
		& Location of Gain or (Loss) Recognized in Income	OCI into Income (1)
			2013				2012		2013			2012
			(In thousands)
	Commodity derivatives	Oil and natural gas revenue	$	(3,210	)		$	14,243	$	—		$	—
	Commodity derivatives	Loss on derivatives not designated as hedges and hedge ineffectiveness, net	—				—		(252		)	(4,015		)
	Total		$	(3,210	)		$	14,243	$	(252	)	$	(4,015	)
	-1	Effective portion of gain (loss).
	-2	Ineffective portion of gain (loss).
	This table shows the effect of derivative instruments on our Unaudited Condensed Consolidated Statements of Income (cash flow hedges) for the nine months ended September 30:
	Derivative Instrument	Location of Gain or (Loss) Reclassified	Amount of Gain or (Loss)						Amount of Gain or (Loss)
		from Accumulated OCI into Income	Reclassified from Accumulated						Recognized in Income (2)
		& Location of Gain or (Loss) Recognized in Income	OCI into Income (1)
			2013				2012		2013			2012
			(In thousands)
	Commodity derivatives	Oil and natural gas revenue	$	(202	)		$	38,088	$	—		$	—
	Commodity derivatives	Loss on derivatives not designated as hedges and hedge ineffectiveness, net	—				—		116			(4,621		)
	Total		$	(202	)		$	38,088	$	116		$	(4,621	)
	-1	Effective portion of gain (loss).
	-2	Ineffective portion of gain (loss).
Effect Of Derivative Instruments Recognized In Statement Of Operations, Not Designated As Hedging Instruments	'
	This table shows the effect of derivative instruments on our Unaudited Condensed Consolidated Statements of Income (derivatives not designated as hedging instruments) for the three months ended September 30:
	Derivatives Not Designated as Hedging	Location of Gain or (Loss)	Amount of Gain or (Loss) Recognized in
	Instruments	Recognized in Income on	Income on Derivative (1)
		Derivative
			2013				2012
			(In thousands)
	Commodity derivatives	Loss on derivatives not designated as hedges and hedge ineffectiveness, net	$	(13,508	)		$	—
	Total		$	(13,508	)		$	—
	-1	Amount settled during the period is a loss of ($2.434) and $0, respectively.
	This table shows the effect of derivative instruments on our Unaudited Condensed Consolidated Statements of Income (derivatives not designated as hedging instruments) for the nine months ended September 30:
	Derivatives Not Designated as Hedging	Location of Gain or (Loss)	Amount of Gain or (Loss) Recognized in
	Instruments	Recognized in Income on	Income on Derivative (1)
		Derivative
			2013				2012
			(In thousands)
	Commodity derivatives	Loss on derivatives not designated as hedges and hedge ineffectiveness, net	$	(3,456	)		$	—
	Total		$	(3,456	)		$	—
	-1	Amount settled during the period is a loss of ($1.575) and $0, respectively.

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2013
Fair Value Disclosures [Abstract]	'
Recurring Fair Value Measurements	'
	The following tables set forth our recurring fair value measurements:
		September 30, 2013
		Level 2				Level 3			Gross Amounts			Effect of Netting			Net Amounts Presented
		(In thousands)
	Financial assets (liabilities):
	Commodity derivatives:
	Assets	$	8,473			$	—		$	8,473		$	(2,826	)	$	5,647
	Liabilities	(7,622		)		(2,622		)	(10,244		)	2,826			(7,418		)
		$	851			$	(2,622	)	$	(1,771	)	$	—		$	(1,771	)
		December 31, 2012
		Level 2				Level 3			Gross Amounts			Effect of Netting			Net Amounts Presented
		(In thousands)
	Financial assets (liabilities):
	Commodity derivatives:
	Assets	$	18,555			$	—		$	18,555		$	(2,003	)	$	16,552
	Liabilities	(3,918		)		(595		)	(4,513		)	2,003			(2,510		)
		$	14,637			$	(595	)	$	14,042		$	—		$	14,042
Reconciliations Of Level 3 Fair Value Measurements	'
	The following tables are reconciliations of our level 3 fair value measurements:
		Commodity Collars
		Three Months Ended							Nine Months Ended
		September 30,							September 30,
		2013				2012			2013			2012
		(In thousands)
	Beginning of period	$	1,446			$	8,130		$	(595	)	$	33,615
	Total gains or losses:
	Included in earnings (1)	(3,949		)		2,241			(2,544		)	19,114
	Included in other comprehensive income (loss)	(119		)		(4,194		)	(119		)	(7,770		)
	Settlements	—				(4,574		)	636			(21,432		)
	Transfers out of Level 3 into Level 2	—				—			—			(21,924		)
	End of period	$	(2,622	)		$	1,603		$	(2,622	)	$	1,603
	Total losses for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period	$	(3,949	)		$	(2,333	)	$	(1,908	)	$	(2,318	)
	-1	Commodity collars are reported in the Unaudited Condensed Consolidated Statements of Income in oil and natural gas revenues (for cash flow hedges) and loss on derivatives not designated as hedges and hedge ineffectiveness, net, respectively.
Schedule Of Quantitative Information About Unobservable Inputs	'
	The following table provides quantitative information about our Level 3 unobservable inputs at September 30, 2013:
	Commodity (1)	Fair Value			Valuation Technique	Unobservable Input	Range
		(In thousands)
	Oil collars	$	(2,503	)	Discounted cash flow	Forward commodity price curve	($7.79) - $6.86
	Natural gas collar	$	(119	)	Discounted cash flow	Forward commodity price curve	($0.19) - $0.03
	-1	The commodity contracts detailed in this category include non-exchange-traded natural gas and crude oil collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be paid or received within the settlement period.

Accumulated_Other_Comprehensiv1

Accumulated Other Comprehensive Income (Loss) (Tables)	9 Months Ended
	Sep. 30, 2013
Statement of Other Comprehensive Income [Abstract]	'
Changes in accumulated other comprehensive income (loss)	'
	Changes in accumulated other comprehensive income (loss) by component, net of tax, for the three months ended September 30 are as follows:
		Net Gains (Losses) on Cash Flow Hedges
		2013			2012
		(In thousands)
	Balance at July 1:	$	1,709		$	30,314
	Other comprehensive income (loss) before reclassification	(4,797		)	(14,137		)
	Amounts reclassified from accumulated other comprehensive income (loss)	2,125			(6,265		)
	New current-period other comprehensive income (loss)	(2,672		)	(20,402		)
	Balance at September 30:	$	(963	)	$	9,912
	Changes in accumulated other comprehensive income (loss) by component, net of tax, for the nine months ended September 30 are as follows:
		Net Gains (Losses) on Cash Flow Hedges
		2013			2012
		(In thousands)
	Balance at January 1:	$	7,587		$	19,026
	Other comprehensive income (loss) before reclassification	(8,617		)	11,353
	Amounts reclassified from accumulated other comprehensive income (loss)	67			(20,467		)
	New current-period other comprehensive income (loss)	(8,550		)	(9,114		)
	Balance at September 30:	$	(963	)	$	9,912
Schedule of Accumulated Other Comprehensive Income (Loss)	'
	Amounts reclassified from accumulated other comprehensive income (loss) into the Unaudited Condensed Consolidated Statements of Income for the three months ended September 30 are as follows:
		2013			2012			Affected Line Item in the Statement Where Net Income is Presented
		(In thousands)
	Net gains (loss) on cash flow hedges
	Commodity derivatives	$	(3,210	)	$	14,243		Oil and natural gas revenues
	Commodity derivatives	(252		)	(4,015		)	Loss on derivatives not designated as hedges and hedge ineffectiveness, net
		(3,462		)	10,228			Total before tax
		1,337			(3,963		)	Tax expense (benefit)
	Total reclassification for the period	$	(2,125	)	$	6,265		Net of tax
	Amounts reclassified from accumulated other comprehensive income (loss) into the Unaudited Condensed Consolidated Statements of Income for the nine months ended September 30 are as follows:
		2013			2012			Affected Line Item in the Statement Where Net Income is Presented
		(In thousands)
	Net gains (loss) on cash flow hedges
	Commodity derivatives	$	(202	)	$	38,088		Oil and natural gas revenues
	Commodity derivatives	116			(4,621		)	Loss on derivatives not designated as hedges and hedge ineffectiveness, net
		(86		)	33,467			Total before tax
		19			(13,000		)	Tax expense (benefit)
	Total reclassification for the period	$	(67	)	$	20,467		Net of tax

Industry_Segment_Information_T

Industry Segment Information (Tables)	9 Months Ended
	Sep. 30, 2013
Segment Reporting [Abstract]	'
Industry segment information	'
	The following table provides certain information about each segment's operations:
		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2013			2012			2013			2012
		(In thousands)
	Revenues:
	Oil and natural gas	$	157,320		$	135,435		$	475,728		$	402,366
	Contract drilling	119,105			145,561			357,118			458,945
	Elimination of inter-segment revenue	(18,458		)	(12,141		)	(43,938		)	(37,747		)
	Contract drilling net of inter-segment revenue	100,647			133,420			313,180			421,198
	Gas gathering and processing	99,007			70,394			272,073			210,550
	Elimination of inter-segment revenue	(23,198		)	(17,459		)	(68,252		)	(50,573		)
	Gas gathering and processing net of inter-segment revenue	75,809			52,935			203,821			159,977
	Total revenues	$	333,776		$	321,790		$	992,729		$	983,541
	Operating income:
	Oil and natural gas	$	50,887		$	54,799		$	173,945		$	27,618		(2	)
	Contract drilling	24,257			40,338			72,030			134,558
	Gas gathering and processing	3,938			784			7,613			7,404
	Total operating income (1)	79,082			95,921			253,588			169,580
	General and administrative	(9,936		)	(8,434		)	(28,288		)	(23,814		)
	Gain on disposition of assets	4,345			44			7,744			1,283
	Loss on derivatives not designated as hedges and hedge ineffectiveness, net	(13,760		)	(4,015		)	(3,340		)	(4,621		)
	Interest expense, net	(3,625		)	(7,087		)	(11,777		)	(11,455		)
	Other	(14		)	(59		)	(171		)	(123		)
	Income before income taxes	$	56,092		$	76,370		$	217,756		$	130,850
	-1	Total operating income is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include non-operating revenues, general corporate expenses, gain on disposition of assets, interest expense, or income taxes.
	-2	In June 2012, we had a non-cash ceiling test write-down of $115.9 million pre-tax ($72.1 million, net of tax).

Oil_And_Natural_Gas_Properties1

Oil And Natural Gas Properties (Details) (USD $)	3 Months Ended	9 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2012	Sep. 30, 2013
Oil And Natural Gas Properties [Line Items]	'	'
Discount rate used to calculate ceiling, percentage	'	10.00%
Impairment of oil and gas properties	$115.90	'
Impairment of oil and gas properties, net of taxes	72.1	'
Effects of cash flow hedges	$32.50	$2.10
Jul'12 - Dec'12	'	'
Oil And Natural Gas Properties [Line Items]	'	'
Oil and gas production volume covered by hedges that affect ceiling determination, MMBoe	2.9	'
Jan'13 - Dec'13	'	'
Oil And Natural Gas Properties [Line Items]	'	'
Oil and gas production volume covered by hedges that affect ceiling determination, MMBoe	4.5	'
Octb13 b Decb13	'	'
Oil And Natural Gas Properties [Line Items]	'	'
Oil and gas production volume covered by hedges that affect ceiling determination, MMBoe	'	1.7

Acquisitions_and_Divestitures_1

Acquisitions and Divestitures - Narrative (Details) (USD $)	Nov. 13, 2012	Aug. 31, 2013	Sep. 30, 2012	Sep. 30, 2012	Jul. 24, 2012	Sep. 17, 2012	Sep. 17, 2012	Sep. 17, 2012
		Bakken [Member]	Bakken [Member]	Brazos and Madison Counties [Member]	Noble Energy, Inc. [Member]	Noble Energy, Inc. [Member]	Noble Energy, Inc. [Member]	Western Oklahoma and Texas Panhandle [Member]
						Granite Wash [Member]	Other Plays [Member]	Noble Energy, Inc. [Member]
						acre	acre	acre
								boe
Business Combination, Description [Abstract]	'	'	'	'	'	'	'	'
Land acquired (in acres)	'	'	'	'	'	24,000	59,000	83,000
Total consideration given	'	'	'	'	'	'	'	$592,627,000
Proved developed reserves (BOE)	'	'	'	'	'	'	'	44,000,000
Number of horizontal driling locations included in the land acquired	'	'	'	'	'	600	'	'
Acquired land with existing production capacity, percent	'	'	'	'	'	'	95.00%	'
Natural gas gathering systems received as part of acquisition	'	'	'	'	'	'	'	4
Aggregate principal amount	650,000,000	'	'	'	400,000,000	'	'	'
Asset Divestiture [Abstract]	'	'	'	'	'	'	'	'
Proceeds from divestiture of assets, net of related expenses	'	$57,100,000	$226,600,000	$44,100,000	'	'	'	'

Acquisitions_and_Divestitures_2

Acquisitions and Divestitures - Fair Value of Acquired Assets and Liabilities (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2011	Sep. 17, 2012
In Thousands, unless otherwise specified					Western Oklahoma and Texas Panhandle [Member]
					Noble Energy, Inc. [Member]
Preliminary Purchase Price [Abstract]	'	'	'	'	'
Total consideration given	'	'	'	'	$592,627
Oil and natural gas properties included in the full cost pool:	'	'	'	'	'
Proved oil and natural gas properties	'	'	'	'	260,799
Undeveloped oil and natural gas properties	'	'	'	'	353,343
Total oil and natural gas properties included in the full cost pool	'	'	'	'	614,142	[1]
Equipment and facilities	'	'	'	'	25,163
Asset retirement obligation	-133,894	-146,159	-146,107	-96,446	-46,678
Fair value of net assets acquired	'	'	'	'	$592,627
[1]	(1) We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates.

Acquisitions_and_Divestitures_3

Acquisitions and Divestitures - Pro Forma (Details) (USD $)	3 Months Ended	9 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Sep. 30, 2012	Sep. 30, 2012
Pro forma:	'	'
Revenues	$335,394	$1,041,350
Net income	$47,186	$140,670
Net income per common share:	'	'
Basic	$0.98	$2.94
Diluted	$0.98	$2.92

Earnings_Per_Share_Schedule_Of

Earnings Per Share (Schedule Of Earnings Per Share) (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Earnings Per Share [Abstract]	'	'	'	'
Income of basic earnings per common share	$34,232	$46,586	$133,445	$79,723
Income of effect of dilutive stock options, restricted stock and stock appreciation rights (SARs)	0	0	0	0
Income of diluted earnings per common share	$34,232	$46,586	$133,445	$79,723
Weighted shares of basic earnings per common share	48,254	47,938	48,193	47,891
Weighted shares of effect of dilutive stock options, restricted stock and stock appreciation rights (SARs)	404	263	317	215
Weighted shares of diluted earnings per common share	48,658	48,201	48,510	48,106
Per-Share amount of basic earnings per common share	$0.71	$0.97	$2.77	$1.66
Per-Share amount of effect of dilutive stock options, restricted stock and stock appreciation rights (SARs)	($0.01)	$0	($0.02)	$0
Per-Share amount of diluted earnings per common share	$0.70	$0.97	$2.75	$1.66

Earnings_Per_Share_Schedule_Of1

Earnings Per Share (Schedule Of Antidilutive Securities Excluded From Computation Of Earnings Per Share) (Details) (Stock options and SARs, USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Stock options and SARs	'	'	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'	'	'
Stock options and SARs	149,665	278,901	149,665	250,901
Average exercise price	$58.41	$51.57	$58.41	$52.72

Accrued_Liabilities_Accrued_Li

Accrued Liabilities (Accrued Liabilities) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Accounts Payable and Accrued Liabilities, Current [Abstract]	'	'
Employee costs	$23,944	$24,632
Interest payable	17,747	6,568
Lease operating expenses	14,738	10,903
Taxes	11,563	7,308
Other	10,565	4,687
Total accrued liabilities	$78,557	$54,098

LongTerm_Debt_And_Other_LongTe2

Long-Term Debt And Other Long-Term Liabilities (Long-Term Debt) (Details) (USD $)	0 Months Ended			9 Months Ended
	Nov. 13, 2012	Jul. 24, 2012	18-May-11	Sep. 30, 2013	Dec. 31, 2012
Debt Instrument [Line Items]	'	'	'	'	'
Credit agreement with an average interest rate of 2.9% at December 31, 2012	'	'	'	$0	$71,100,000
6.625% senior subordinated notes due 2021, net of unamortized discount of $4.4 million at September 30, 2013 and $4.7 million at December 31, 2012	'	'	'	645,584,000	645,259,000
Total long-term debt	'	'	'	645,584,000	716,359,000
Revolving credit facility interest rate	'	'	'	0.00%	2.90%
Interest percentage of senior subordinated notes	6.63%	6.63%	6.63%	6.63%	'
Debt instrument maturity date	15-May-21	15-May-21	15-May-21	15-May-21	'
Debt instrument, unamortized discount	'	'	'	$4,400,000	$4,700,000

LongTerm_Debt_And_Other_LongTe3

Long-Term Debt And Other Long-Term Liabilities (Other Long-Term Liabilities) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Debt Disclosure [Abstract]	'	'	'	'
Asset retirement obligation (ARO) liability	$133,894	$146,159	$146,107	$96,446
Workers' compensation	20,207	18,517	'	'
Separation benefit plans	8,991	7,972	'	'
Gas balancing liability	3,838	3,838	'	'
Deferred compensation plan	3,216	2,779	'	'
Other liabilities	170,146	179,265	'	'
Less current portion	11,985	12,282	'	'
Total other long-term liabilities	$158,161	$166,983	'	'

LongTerm_Debt_And_Other_LongTe4

Long-Term Debt And Other Long-Term Liabilities (Narrative) (Details) (USD $)	0 Months Ended			9 Months Ended
	Nov. 13, 2012	Jul. 24, 2012	18-May-11	Sep. 30, 2013	Dec. 31, 2012	Sep. 05, 2012
Debt Instrument [Line Items]	'	'	'	'	'	'
Credit facility maturity date	'	'	'	'9/13/2016	'	'
Credit facility maximum credit amount	'	'	'	$900,000,000	'	'
Commitment fee under credit facility standard	'	'	'	1.00%	'	'
Origination, agency and syndication and other related fees	'	'	'	'	'	1,500,000
Payable assessment term for LIBOR	'	'	'	'90 days	'	'
LIBOR interest rate plus one percent	'	'	'	'LIBOR plus 1.00%	'	'
Line of credit facility, amount outstanding	'	'	'	0	71,100,000	'
Current ratio of credit facility	'	'	'	'1 to 1	'	'
Leverage ratio of long-term debt	'	'	'	'4 to 1	'	'
Aggregate principal amount	650,000,000	'	'	'	'	'
Interest percentage of senior subordinated notes	6.63%	6.63%	6.63%	6.63%	'	'
Debt instrument issued at discount, percent of par	'	98.75%	'	'	'	'
Debt instrument maturity date	15-May-21	15-May-21	15-May-21	15-May-21	'	'
Deducting fees for debt issuance	'	8,700,000	'	'	'	'
Repayment of outstanding borrowings under unsecured credit facility	'	'	220,300,000	'	'	'
Percentage of maximum, aggregate principal equity amount	'	'	'	35.00%	'	'
Proceed from equity offerings redemption price percentage	'	'	'	106.63%	'	'
Minimum redemption percentage of debt outstanding	'	'	'	65.00%	'	'
Equal redemption price percentage of principal amount of debt	'	'	'	100.00%	'	'
Senior notes repurchase price in percentage	'	'	'	101.00%	'	'
2014	'	'	'	12,000,000	'	'
2015	'	'	'	40,800,000	'	'
2016	'	'	'	5,200,000	'	'
2017	'	'	'	3,900,000	'	'
2018	'	'	'	3,800,000	'	'
Minimum [Member]	'	'	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'	'	'
Commitment fee percentage under credit facility	'	'	'	0.38%	'	'
LIBOR plus interest rate	'	'	'	1.75%	'	'
Maximum [Member]	'	'	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'	'	'
Commitment fee percentage under credit facility	'	'	'	0.50%	'	'
LIBOR plus interest rate	'	'	'	2.50%	'	'
Maximum payment of dividends as a percentage of consolidated net income, prohibited under credit agreement	'	'	'	30.00%	'	'
6.625% Senior Subordinated Notes Due 2021 [Member]	'	'	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'	'	'
Aggregate principal amount	'	400,000,000	250,000,000	'	'	'
Proceeds from sale of notes	'	'	244,000,000	'	'	'
Deducting fees for debt issuance	'	'	6,000,000	'	'	'
Line Of Credit Facility Lender Determined Amount [Member]	'	'	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'	'	'
Credit facility current credit amount	'	'	'	800,000,000	'	'
Line Of Credit Facility Commitment Amount [Member]	'	'	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'	'	'
Credit facility current credit amount	'	'	'	$500,000,000	'	'

Asset_Retirement_Obligations_S

Asset Retirement Obligations (Schedule Of Asset Retirement Obligations) (Details) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012
Asset Retirement Obligation Disclosure [Abstract]	'		'
ARO liability, January 1:	$146,159		$96,446
Accretion of discount	4,152		3,215
Liability incurred	3,820		52,306
Liability settled	-4,071		-1,606
Revision of estimates	-16,166	[1]	-4,254	[1]
ARO liability, September 30:	133,894		146,107
Less current portion	2,954		2,857
Total long-term ARO	$130,940		$143,250
[1]	Plugging liability estimates were revised in both 2013 and 2012 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments as well as changes in estimated timing of cash flows.

StockBased_Compensation_Schedu

Stock-Based Compensation (Schedule Of Fair Value Of The Restricted Stock Awards Granted During The Periods) (Details) (Restricted Stock [Member], USD $)	3 Months Ended		9 Months Ended
In Millions, except Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Shares granted	0	2,509	469,677	395,051
Estimated fair value (in millions)	$0	$0.10	$21.90	$16.70
Employees [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Shares granted	0	2,509	448,549	370,445
Estimated fair value (in millions)	0	0.1	21	15.7
Percentage of shares granted expected to be distributed	'	95.00%	94.00%	94.00%
Non-employee Directors [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Shares granted	0	0	21,128	24,606
Estimated fair value (in millions)	$0	$0	$0.90	$1
Percentage of shares granted expected to be distributed	'	0.00%	100.00%	100.00%

StockBased_Compensation_Narrat

Stock-Based Compensation (Narrative) (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, except Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	2-May-12
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'
Allocated share-based compensation expense	4.4	2.9	12	8.2	'
Capitalized stock compensation cost for oil and natural gas properties	1	0.7	2.6	2	'
Tax benefit on stock based compensation	1.8	1.2	4.7	3.2	'
Unrecognized compensation cost related to unvested awards	20.7	'	20.7	'	'
Unrecognized compensation cost, expected to be capitalized	3.3	'	3.3	'	'
Weighted average years over which this cost will be recognized	'	'	'9 months 24 days	'	'
Vesting period	'	'	'3 years	'	'
Increase in stock compensation expense due to the restricted stock awards granted	'	'	7.1	'	'
Minimum [Member]	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'
Performance percentage criteria	'	'	50.00%	'	'
Percentage of performance based shares received based on most recent fiscal year results	'	'	100.00%	'	'
Maximum [Member]	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'
Performance percentage criteria	'	'	150.00%	'	'
Restricted Stock [Member]	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'
Number of shares authorized	'	'	'	'	3,300,000
Shares granted	0	2,509	469,677	395,051	'
Performance Shares [Member]	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'
Restricted stock awards granted in period, percent	'	'	30.00%	'	'
Performance Shares [Member] | First Half Of 2016 [Member]	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'
Shares granted	'	'	57,405	'	'
Performance Shares [Member] | First Half Of 2015 [Member]	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'
Shares granted	'	'	46,441	'	'

Derivatives_Cash_Flow_Hedges_O

Derivatives (Cash Flow Hedges Outstanding) (Details) (Designated as Hedging Instrument [Member], Octb13 b Decb13)	9 Months Ended
	Sep. 30, 2013
	bbl
Swap [Member] | WTI - NYMEX [Member] | Crude Oil [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Weighted Average Fixed Price For Swaps	99.71
Hedged Volume (in Bbl/day)	5,500
Swap [Member] | WTI - NYMEX [Member] | Crude Oil [Member] | Start [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Commodity Derivatives Term	'Oct'13
Swap [Member] | WTI - NYMEX [Member] | Crude Oil [Member] | End [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Commodity Derivatives Term	'Dec'13
Swap [Member] | If Nymex [Member] | Natural Gas [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Weighted Average Fixed Price For Swaps	3.56
Hedged Volume (MMBtu/day)	60,000
Swap [Member] | If Nymex [Member] | Natural Gas [Member] | Start [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Commodity Derivatives Term	'Oct'13
Swap [Member] | If Nymex [Member] | Natural Gas [Member] | End [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Commodity Derivatives Term	'Dec'13
Collar [Member] | If Nymex [Member] | Natural Gas [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Hedged Volume (MMBtu/day)	20,000
Collar [Member] | If Nymex [Member] | Natural Gas [Member] | Start [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Weighted Average Fixed Price For Swaps	3.25
Commodity Derivatives Term	'Oct'13
Collar [Member] | If Nymex [Member] | Natural Gas [Member] | End [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Weighted Average Fixed Price For Swaps	3.72
Commodity Derivatives Term	'Dec'13

Derivatives_Derivatives_Schedu

Derivatives Derivatives (Schedule of Non-designated Hedges Outstanding) (Details) (Not Designated as Hedging Instrument [Member])	9 Months Ended
	Sep. 30, 2013
	bbl
Swap [Member] | Octb13 b Decb13 | Crude Oil [Member] | WTI - NYMEX [Member]	'
Derivative [Line Items]	'
Weighted Average Fixed Price For Swaps	94.59
Hedged Volume (in Bbl/day)	3,000
Swap [Member] | Octb13 b Decb13 | Crude Oil [Member] | WTI - NYMEX [Member] | Start [Member]	'
Derivative [Line Items]	'
Commodity Derivatives Term	'Oct'13
Swap [Member] | Octb13 b Decb13 | Crude Oil [Member] | WTI - NYMEX [Member] | End [Member]	'
Derivative [Line Items]	'
Commodity Derivatives Term	'Dec'13
Swap [Member] | Octb13 b Decb13 | Natural Gas [Member] | If Nymex [Member]	'
Derivative [Line Items]	'
Weighted Average Fixed Price For Swaps	3.94
Hedged Volume (in MMBtu/day)	20,000
Swap [Member] | Octb13 b Decb13 | Natural Gas [Member] | If Nymex [Member] | Start [Member]	'
Derivative [Line Items]	'
Commodity Derivatives Term	'Oct'13
Swap [Member] | Octb13 b Decb13 | Natural Gas [Member] | If Nymex [Member] | End [Member]	'
Derivative [Line Items]	'
Commodity Derivatives Term	'Dec'13
Swap [Member] | Jan'14 - Dec'14 | Crude Oil [Member] | WTI - NYMEX [Member]	'
Derivative [Line Items]	'
Weighted Average Fixed Price For Swaps	91.77
Hedged Volume (in Bbl/day)	3,000
Swap [Member] | Jan'14 - Dec'14 | Crude Oil [Member] | WTI - NYMEX [Member] | Start [Member]	'
Derivative [Line Items]	'
Commodity Derivatives Term	'Jan'14
Swap [Member] | Jan'14 - Dec'14 | Crude Oil [Member] | WTI - NYMEX [Member] | End [Member]	'
Derivative [Line Items]	'
Commodity Derivatives Term	'Dec'14
Swap [Member] | Jan'14 - Dec'14 | Natural Gas [Member] | If Nymex [Member]	'
Derivative [Line Items]	'
Weighted Average Fixed Price For Swaps	4.24
Hedged Volume (in MMBtu/day)	50,000
Swap [Member] | Jan'14 - Dec'14 | Natural Gas [Member] | If Nymex [Member] | Start [Member]	'
Derivative [Line Items]	'
Commodity Derivatives Term	'Jan'14
Swap [Member] | Jan'14 - Dec'14 | Natural Gas [Member] | If Nymex [Member] | End [Member]	'
Derivative [Line Items]	'
Commodity Derivatives Term	'Dec'14
Swap [Member] | Jan'14 - Jun'14 | Crude Oil [Member] | WTI - NYMEX [Member]	'
Derivative [Line Items]	'
Weighted Average Fixed Price For Swaps	100.03
Hedged Volume (in Bbl/day)	500
Swap [Member] | Jan'14 - Jun'14 | Crude Oil [Member] | WTI - NYMEX [Member] | Start [Member]	'
Derivative [Line Items]	'
Commodity Derivatives Term	'Jan'14
Swap [Member] | Jan'14 - Jun'14 | Crude Oil [Member] | WTI - NYMEX [Member] | End [Member]	'
Derivative [Line Items]	'
Commodity Derivatives Term	'Jun'14
Collar [Member] | Jan'14 - Dec'14 | Crude Oil [Member] | WTI - NYMEX [Member]	'
Derivative [Line Items]	'
Hedged Volume (in Bbl/day)	4,000
Collar [Member] | Jan'14 - Dec'14 | Crude Oil [Member] | WTI - NYMEX [Member] | Start [Member]	'
Derivative [Line Items]	'
Weighted Average Fixed Price For Swaps	90
Commodity Derivatives Term	'Jan'14
Collar [Member] | Jan'14 - Dec'14 | Crude Oil [Member] | WTI - NYMEX [Member] | End [Member]	'
Derivative [Line Items]	'
Weighted Average Fixed Price For Swaps	96.08
Commodity Derivatives Term	'Dec'14

Derivatives_Fair_Value_Of_Deri

Derivatives (Fair Value Of Derivative Instruments And Locations In Balance Sheets) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivatives, Fair Value [Line Items]	'	'
Current derivative asset	$4,514	$16,552
Non-current derivative asset	1,133	0
Total derivatives assets	5,647	16,552
Current derivative liabilities	6,480	1,948
Non-current derivative liabilities	938	562
Total derivative liabilities	7,418	2,510
Designated as Hedging Instrument [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Current derivative asset	486	13,674
Non-current derivative asset	0	0
Total derivatives designated as hedging instruments, assets	486	13,674
Current derivative liabilities	1,750	1,005
Non-current derivative liabilities	0	0
Total derivatives designated as hedging instruments, liabilities	1,750	1,005
Not Designated as Hedging Instrument [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Current derivative asset	4,028	2,878
Non-current derivative asset	1,133	0
Total derivatives designated as hedging instruments, assets	5,161	2,878
Current derivative liabilities	4,730	943
Non-current derivative liabilities	938	562
Total derivatives designated as hedging instruments, liabilities	$5,668	$1,505

Derivatives_Amount_Of_Gain_Or_

Derivatives (Amount Of Gain Or (Loss) Recognized In Accumulated OCI On Derivative) (Details) (Commodity Derivatives [Member], USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012
Commodity Derivatives [Member]	'		'
Derivative Instruments, Gain (Loss) [Line Items]	'		'
Amount of Gain Recognized in Accumulated OCI on Derivative (Effective Portion)	($963)	[1]	$9,912	[1]
[1]	Net of taxes.

Derivatives_Gain_Or_Loss_Of_Re

Derivatives (Gain Or Loss Of Reclassified Accumulated Other Comprehensive Income And Recognized In Income) (Details) (Commodity Derivatives [Member], USD $)	3 Months Ended				9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'		'
Amount of gain or (loss) reclassified from accumulated OCI into income	($3,210)		$14,243		($202)		$38,088
Derivative Instruments, Gain Recognized in Income	-252		-4,015		116		-4,621
Oil and natural gas revenue [Member]	'		'		'		'
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'		'
Amount of gain or (loss) reclassified from accumulated OCI into income	-3,210	[1]	14,243	[1]	-202	[1]	38,088	[1]
Derivative Instruments, Gain Recognized in Income	0		0		0		0
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net [Member]	'		'		'		'
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'		'
Amount of gain or (loss) reclassified from accumulated OCI into income	0		0		0		0
Derivative Instruments, Gain Recognized in Income	($252)	[2]	($4,015)	[2]	$116	[2]	($4,621)	[2]
[1]	Effective portion of gain (loss).
[2]	Ineffective portion of gain (loss).

Derivatives_Effect_Of_Derivati

Derivatives (Effect Of Derivative Instruments Recognized In Statement of Operations, Not Designated As Hedging Instruments) (Details) (USD $)	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'		'
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net	($13,760,000)		($4,015,000)		($3,340,000)		($4,621,000)
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net [Member] | Commodity Derivatives [Member]	'		'		'		'
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'		'
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net	-13,508,000	[1]	0	[1]	-3,456,000	[2]	0	[2]
Loss on derivatives not designated as hedging instruments, amount settled during period	($2,434,000)		$0		($1,575,000)		$0
[1]	Amount settled during the period is a loss of ($2.434) and $0, respectively.
[2]	Amount settled during the period is a loss of ($1.575) and $0, respectively.

Derivatives_Narrative_Details

Derivatives (Narrative) (Details) (USD $)	9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012
Derivative Instruments, Gain [Line Items]	'		'
Period over which gain included in AOCI will be transferred to earnings, months	'3 months		'
Expected earnings transfer	$1,000,000		'
Expected derivative maturity date	31-Dec-13		'
Commodity Derivatives [Member]	'		'
Derivative Instruments, Gain [Line Items]	'		'
Accumulated OCI gain, net of tax	($963,000)	[1]	$9,912,000	[1]
[1]	Net of taxes.

Fair_Value_Measurements_Recurr

Fair Value Measurements (Recurring Fair Value Measurements) (Details) (Commodity Derivatives [Member], USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Gross Assets	$8,473	$18,555
Gross Liabilities	-10,244	-4,513
Assets	5,647	16,552
Liabilities	-7,418	-2,510
Financial assets (liabilities)	-1,771	14,042
Level 2 [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Gross Assets	8,473	18,555
Gross Liabilities	-7,622	-3,918
Financial assets (liabilities)	851	14,637
Level 3 [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Gross Assets	0	0
Gross Liabilities	-2,622	-595
Financial assets (liabilities)	-2,622	-595
Effect of Netting [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Effect of netting on assets	-2,826	-2,003
Effect of netting on liabilities	2,826	2,003
Financial assets (liabilities)	$0	$0

Fair_Value_Measurements_Reconc

Fair Value Measurements (Reconciliations Of Level 3 Fair Value Measurements) (Details) (Collar [Member], USD $)	3 Months Ended				9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Collar [Member]	'		'		'		'
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]	'		'		'		'
Beginning of period	$1,446		$8,130		($595)		$33,615
Included in earnings	-3,949	[1]	2,241	[1]	-2,544	[1]	19,114	[1]
Included in other comprehensive income (loss)	-119		-4,194		-119		-7,770
Settlements	0		-4,574		636		-21,432
Transfers out of Level 3 into Level 2	0		0		0		-21,924
End of period	-2,622		1,603		-2,622		1,603
Total gains for the period included in earnings attributable to the change in unrealized gain relating to assets still held at end of period	($3,949)		($2,333)		($1,908)		($2,318)
[1]	Commodity collars are reported in the Unaudited Condensed Consolidated Statements of Income in oil and natural gas revenues (for cash flow hedges) and loss on derivatives not designated as hedges and hedge ineffectiveness, net, respectively.

Fair_Value_Measurements_Schedu

Fair Value Measurements (Schedule Of Quantitative Information About Unobservable Inputs) (Details) (Level 3 [Member], Collar [Member], USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013
Crude Oil [Member]	'
Derivative assets, Fair Value	($2,503)	[1]
Derivatives assets, Valuation Technique(s)	'DiscountedB cashB flow
Unobservable Input	'ForwardB commodityB priceB curve
Crude Oil [Member] | Minimum [Member]	'
Forward commodity price curve	-7.79
Crude Oil [Member] | Maximum [Member]	'
Forward commodity price curve	6.86
Natural Gas [Member]	'
Derivative assets, Fair Value	($119)	[1]
Derivatives assets, Valuation Technique(s)	'DiscountedB cashB flow
Unobservable Input	'ForwardB commodityB priceB curve
Natural Gas [Member] | Minimum [Member]	'
Forward commodity price curve	-0.19
Natural Gas [Member] | Maximum [Member]	'
Forward commodity price curve	0.03
[1]	The commodity contracts detailed in this category include non-exchange-traded natural gas and crude oil collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be paid or received within the settlement period.

Fair_Value_Measurements_Narrat

Fair Value Measurements (Narrative) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Carrying value of long-term debt	$645.60	$645.30
Level 2 [Member]	'	'
Estimated fair value of long-term debt	$666.30	$687.70

Accumulated_Other_Comprehensiv2

Accumulated Other Comprehensive Income (Loss) (Changes in accumulated other comprehensive income) (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'	'	'	'
Beginning of Period:	$1,709	$30,314	$7,587	$19,026
Other comprehensive income before reclassification	-4,797	-14,137	-8,617	11,353
Amounts reclassified from accumulated other comprehensive income	2,125	-6,265	67	-20,467
New current-period other comprehensive income	-2,672	-20,402	-8,550	-9,114
Ending of Period:	($963)	$9,912	($963)	$9,912

Accumulated_Other_Comprehensiv3

Accumulated Other Comprehensive Income (Loss) (Schedule of accumulated other comprehensive income (loss)) (Details) (Commodity Derivatives [Member], USD $)	3 Months Ended				9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Amounts reclassified from accumulated other comprehensive income	($3,210)		$14,243		($202)		$38,088
Derivative Instruments, Gain Recognized in Income	-252		-4,015		116		-4,621
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax	-3,462		10,228		-86		33,467
Tax expense	1,337		-3,963		19		-13,000
Total reclassification for the period	-2,125		6,265		-67		20,467
Oil and natural gas revenue [Member]	'		'		'		'
Amounts reclassified from accumulated other comprehensive income	-3,210	[1]	14,243	[1]	-202	[1]	38,088	[1]
Derivative Instruments, Gain Recognized in Income	0		0		0		0
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net [Member]	'		'		'		'
Amounts reclassified from accumulated other comprehensive income	0		0		0		0
Derivative Instruments, Gain Recognized in Income	($252)	[2]	($4,015)	[2]	$116	[2]	($4,621)	[2]
[1]	Effective portion of gain (loss).
[2]	Ineffective portion of gain (loss).

Industry_Segment_Information_I

Industry Segment Information (Industry Segment Information) (Details) (USD $)	3 Months Ended			9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012		Sep. 30, 2013	Sep. 30, 2012
Revenues:	'	'		'	'
Oil and natural gas	$157,320	$135,435		$475,728	$402,366
Contract drilling	119,105	145,561		357,118	458,945
Elimination of inter-segment revenue	-18,458	-12,141		-43,938	-37,747
Contract drilling net of inter-segment revenue	100,647	133,420		313,180	421,198
Gas gathering and processing	99,007	70,394		272,073	210,550
Elimination of inter-segment revenue	-23,198	-17,459		-68,252	-50,573
Gas gathering and processing net of inter-segment revenue	75,809	52,935		203,821	159,977
Total revenues	333,776	321,790		992,729	983,541
Operating income:	'	'		'	'
Oil and natural gas	-50,887	-54,799		-173,945	-27,618	[1]
Contract drilling	-24,257	-40,338		-72,030	-134,558
Gas gathering and processing	-3,938	-784		-7,613	-7,404
Total operating income (1)	79,082	95,921	[2]	253,588	169,580	[2]
General and administrative	-9,936	-8,434		-28,288	-23,814
Gain on disposition of assets	4,345	44		7,744	1,283
Loss on derivatives not designated as hedges and hedge ineffectiveness, net	-13,760	-4,015		-3,340	-4,621
Interest expense, net	-3,625	-7,087		-11,777	-11,455
Other	-14	-59		-171	-123
Income before income taxes	$56,092	$76,370		$217,756	$130,850
[1]	In June 2012, we had a non-cash ceiling test write-down of $115.9 million pre-tax ($72.1 million, net of tax).
[2]	Total operating income is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include non-operating revenues, general corporate expenses, gain on disposition of assets, interest expense, or income taxes.

Subsequent_Event_Details

Subsequent Event (Details) (Subsequent Event [Member], USD $)	1 Months Ended
In Millions, unless otherwise specified	Oct. 31, 2013
	buyer
	rig
Subsequent Event [Member]	'
Subsequent Event [Line Items]	'
Drilling rigs considered for sale	5
Drilling rigs considered for sale, units sold	1
Drilling rigs considered for sale, remaining units	4
Number of buyers of the drilling rigs	2
Net book value of drilling rigs considered for sale	$17.20