Unit (UNTC) 10-K 24 Feb 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Feb. 13, 2015	Jun. 30, 2014
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Trading Symbol	unt
Entity Registrant Name	UNIT CORP
Entity Central Index Key	798949
Current Fiscal Year End Date	-19
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		49,824,530
Entity Well-known Seasoned Issuer	Yes
Entity Public Float			$1,841,089,922
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current assets:
Cash and cash equivalents	$1,049	$18,593
Accounts receivable (less allowance for doubtful accounts of $5,039 and $5,342 at December 31, 2014 and 2013, respectively)	189,812	139,788
Materials and supplies	5,590	10,998
Current derivative asset (Note 13)	31,139	515
Current deferred tax asset (Note 8)	11,527	13,585
Assets held for sale (Note 3)	0	15,621
Prepaid expenses and other	13,374	12,931
Total current assets	252,491	212,031
Oil and natural gas properties, on the full cost method:
Proved properties	4,990,753	4,235,712
Unproved properties not being amortized	485,568	545,588
Drilling equipment	1,620,692	1,477,093
Gas gathering and processing equipment	628,689	549,422
Saltwater disposal systems	56,702	44,579
Transportation equipment	40,693	39,666
Other	57,706	42,856
Property, plant and equipment, gross, total	7,880,803	6,934,916
Less accumulated depreciation, depletion, amortization, and impairment	3,747,412	3,212,225
Net property and equipment	4,133,391	3,722,691
Debt issuance cost	10,255	11,844
Goodwill (Note 2)	62,808	62,808
Other assets	14,783	13,016
Total assets	4,473,728	4,022,390
Current liabilities:
Accounts payable	218,500	154,062
Accrued liabilities (Note 5)	70,171	64,363
Income taxes payable	481	7,474
Current derivative liabilities (Note 13)	0	5,561
Current portion of other long-term liabilities (Note 6)	15,019	12,113
Total current liabilities	304,171	243,573
Long-term debt (Note 6)	812,163	645,696
Other long-term liabilities (Note 6)	148,785	158,331
Deferred income taxes (Note 8)	876,215	801,398
Commitments and contingencies (Note 16)	0	0
Shareholders' equity:
Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued	0	0
Common stock, $0.20 par value, 175,000,000 shares authorized, 49,593,812 and 49,107,004 shares issued as of December 31, 2014 and 2013, respectively	9,732	9,659
Capital in excess of par value	468,123	445,470
Retained earnings	1,854,539	1,718,263
Total shareholders' equity	2,332,394	2,173,392
Total liabilities and shareholders' equity	$4,473,728	$4,022,390

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, except Share data, unless otherwise specified
Statement of Financial Position [Abstract]
Accounts receivable, allowance for doubtful accounts	$5,039	$5,342
Preferred stock, par value	$1	$1
Preferred stock, shares authorized	5,000,000	5,000,000
Preferred stock, 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	49,593,812	49,107,004

Consolidated_Statements_of_Inc

Consolidated Statements of Income (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues
Oil and natural gas	$740,079	$649,718	$567,944
Contract drilling	476,517	414,778	529,719
Gas gathering and processing	356,348	287,354	217,460
Total revenues	1,572,944	1,351,850	1,315,123
Oil and natural gas
Operating costs	187,916	184,001	150,212
Depreciation, depletion, and amortization	276,088	226,498	211,347
Impairment of oil and natural gas properties (Note 2)	76,683	0	283,606
Contract drilling
Operating costs	274,933	247,280	289,524
Depreciation and impairment (Note 2)	159,688	71,194	81,007
Gas gathering and processing
Operating costs	306,831	243,406	187,292
Gas Gathering Transportation Marketing And Processing Depreciation, Amortization, and Impairment	47,502	33,191	24,388
General and administrative	42,023	38,323	33,086
Gain on disposition of assets	-8,953	-17,076	-253
Total expenses	1,362,711	1,026,817	1,260,209
Income from operations	210,233	325,033	54,914
Other income (expense):
Interest, net	-17,371	-15,015	-14,137
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net	30,147	-8,374	-1,243
Other	-70	-175	-132
Total other expense	12,706	-23,564	-15,512
Income before income taxes	222,939	301,469	39,402
Income tax expense:
Current	9,378	15,991	696
Deferred	77,285	100,732	15,530
Total income taxes	86,663	116,723	16,226
Net income	$136,276	$184,746	$23,176
Net income per common share:
Basic	$2.80	$3.83	$0.48
Diluted	$2.78	$3.80	$0.48

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Net income	$136,276	$184,746	$23,176
Change in value of derivative instruments used as cash flow hedges, net of tax of $0, ($4,717), and $12,094	0	-7,349	18,635
Reclassification - derivative settlements, net of tax of $0, ($249), and ($20,171)	0	-354	-31,682
Ineffective portion of derivatives, net of tax of $0, $74, and $1,008	0	116	1,608
Total comprehensive income	$136,276	$177,159	$11,737

Consolidated_Statements_of_Com1

Consolidated Statements of Comprehensive Income Consolidated Statements of Comprehensive Income (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Change in value of derivative instruments used as cash flow hedges, tax	$0	($4,717)	$12,094
Reclassification - derivative settlements, tax	0	-249	-20,171
Ineffective portion of derivatives, tax	$0	$74	$1,008

Consolidated_Statements_of_Cha

Consolidated Statements of Changes in Shareholders' Equity (USD $)	Total	Common Stock	Capital In Excess of Par Value	Accumulated Other Comprehensive Income	Retained Earnings
In Thousands, unless otherwise specified
Beginning balances at Dec. 31, 2011	$1,947,017	$9,541	$408,109	$19,026	$1,510,341
Comprehensive income:
Net income	23,176	0	0	0	23,176
Other comprehensive loss, net of tax	-11,439	0	0	-11,439	0
Total comprehensive income	11,737
Activity in employee compensation plans	15,547	53	15,494	0	0
Ending balances at Dec. 31, 2012	1,974,301	9,594	423,603	7,587	1,533,517
Comprehensive income:
Net income	184,746	0	0	0	184,746
Other comprehensive loss, net of tax	-7,587	0	0	-7,587	0
Total comprehensive income	177,159
Activity in employee compensation plans	21,932	65	21,867	0	0
Ending balances at Dec. 31, 2013	2,173,392	9,659	445,470	0	1,718,263
Comprehensive income:
Net income	136,276	0	0	0	136,276
Other comprehensive loss, net of tax				0
Total comprehensive income	136,276
Activity in employee compensation plans	22,726	73	22,653	0	0
Ending balances at Dec. 31, 2014	$2,332,394	$9,732	$468,123	$0	$1,854,539

Consolidated_Statements_of_Cha1

Consolidated Statements of Changes in Shareholders' Equity (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Activity in employee compensation plans (shares)	486,808	525,056	430,506
Other comprehensive income, tax	$0	($4,892)	($7,069)

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
OPERATING ACTIVITIES:
Net income	$136,276	$184,746	$23,176
Adjustments to reconcile net income to net cash provided (used) by operating activities:
Depreciation, depletion, and amortization	404,943	333,907	319,021
Impairment of properties (Note 2)	158,069	0	283,606
(Gain) loss on derivatives	-30,147	7,771	-50,610
Cash (payments) receipts on derivatives settled	-6,038	-1,161	51,853
Gain on disposition of assets	-8,953	-17,076	-253
Deferred tax expense	77,285	100,732	15,530
Employee stock compensation plans	24,320	21,317	16,956
Bad debt expense	3,562	0	90
ARO liability accretion	4,599	5,450	4,615
Other, net	1,068	2,250	781
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable	-60,800	2,967	13,994
Materials and supplies	2,602	-2,435	-361
Prepaid expenses and other	-444	1,813	-3,466
Accounts payable	4,715	15,715	10,187
Accrued liabilities	-1,297	17,198	6,911
Contract advances	-767	1,137	-1,119
Net cash provided by operating activities	708,993	674,331	690,911
INVESTING ACTIVITIES:
Capital expeditures	-981,374	-703,984	-762,381
Producing property and other acquisitions	-5,723	0	-598,485
Proceeds from disposition of property and equipment	66,197	120,910	281,824
Other	303	3,894	0
Net cash used in investing activities	-920,597	-579,180	-1,079,042
FINANCING ACTIVITIES:
Borrowings under line of credit	725,800	222,500	735,300
Payments under line of credit	-559,800	-293,600	-714,200
Proceeds from issuance of senior subordinated notes, net of debt issuance costs and discount	0	0	386,274
Payments on capitalized leases	-2,392	0	0
Proceeds from exercise of stock options	1,083	574	215
Tax benefit from stock options	1,614	8	121
Increase (decrease) in book overdrafts (Note 2)	27,755	-7,014	-19,440
Net cash provided by (used in) financing activities	194,060	-77,532	388,270
Net increase (decrease) in cash and cash equivalents	-17,544	17,619	139
Cash and cash equivalents, beginning of year	18,593	974	835
Cash and cash equivalents, end of year	1,049	18,593	974
Supplemental disclosure of cash flow information:
Interest paid (net of capitalization)	13,620	12,485	14,880
Income taxes	15,898	9,100	5,116
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment	-31,968	-6,550	-4,753
Non-cash (additions) reductions to oil and natural gas properties related to asset retirement obligations	37,689	17,952	-45,097
Non-cash additions to property, plant, and equipment acquired under capital leases	($28,202)	$0	$0

Organization

Organization	12 Months Ended
	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Unless the context clearly indicates otherwise, references in this report to “Unit”, “Company”, “we”, “our”, “us”, or like terms refer to Unit Corporation and its subsidiaries.
	We are primarily engaged in the exploration, development, acquisition, and production of oil and natural gas properties, the land contract drilling of natural gas and oil wells, and the buying, selling, gathering, processing, and treating of natural gas. Our operations are located principally in the United States and are organized in the following three reporting segments: (1) Oil and Natural Gas, (2) Contract Drilling, and (3) Mid-Stream.
	Oil and Natural Gas.  Carried out by our subsidiary, Unit Petroleum Company, we explore, develop, acquire, and produce oil and natural gas properties for our own account. Our producing oil and natural gas properties, unproved properties, and related assets are located mainly in Oklahoma and Texas, and to a lesser extent, in Arkansas, Colorado, Kansas, Louisiana, Mississippi, Montana, New Mexico, North Dakota, and Wyoming.
	Historically, our contract drilling segment experienced more demand for natural gas drilling as opposed to drilling for oil and NGLs. With the current natural gas market, operators have been focusing on drilling for oil and NGLs.
	Contract Drilling.  Carried out by our subsidiary, Unit Drilling Company and its subsidiary Unit Texas Drilling, L.L.C., we drill onshore oil and natural gas wells for our own account as well as for a wide range of other oil and natural gas companies. Our drilling operations are mainly located in Oklahoma, Texas, Louisiana, Kansas, Wyoming, and North Dakota.
	Mid-Stream.  Carried out by our subsidiary, Superior Pipeline Company, L.L.C. and its subsidiaries, we buy, sell, gather, transport, process, and treat natural gas for our own account and for third parties. Mid-stream operations are performed in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia.

Summary_Of_Significant_Account

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Summary Of Significant Accounting Policies	Principles of Consolidation.  The consolidated financial statements include the accounts of Unit Corporation and its subsidiaries. Our investment in limited partnerships is accounted for on the proportionate consolidation method, whereby our share of the partnerships’ assets, liabilities, revenues, and expenses are included in the appropriate classification in the accompanying consolidated financial statements.
	Certain amounts in the accompanying 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.
	Accounting Estimates.  The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
	Drilling Contracts.  We recognize revenues and expenses generated from “daywork” drilling contracts as the services are performed, since we do not bear the risk of completion of the well. Under “footage” and “turnkey” contracts, we bear the risk of completion of the well; therefore, revenues and expenses are recognized when the well is substantially completed. Under this method, substantial completion is determined when the well bore reaches the negotiated depth as stated in the contract. The entire amount of a loss, if any, is recorded when the loss is determinable. The costs of uncompleted drilling contracts include expenses incurred to date on “footage” or “turnkey” contracts, which are still in process at the end of the period, and are included in other current assets. Typically, any one of these three types of contracts can be used for the drilling of one well which can take from 20 to 90 days. At December 31, 2014, all of our contracts were daywork contracts of which 30 were multi-well and had durations which ranged from six months to three years, 26 of which expire in 2015 and four expiring in 2016. These longer term contracts may contain a fixed rate for the duration of the contract or provide for the periodic renegotiation of the rate within a specific range from the existing rate.
	Cash Equivalents and Book Overdrafts.  We include as cash equivalents all investments with maturities at date of purchase of three months or less which are readily convertible into known amounts of cash. Book overdrafts are checks that have been issued before the end of the period, but not presented to our bank for payment before the end of the period. At December 31, 2014, book overdrafts were $27.8 million. There were no book overdrafts at December 31, 2013.
	Accounts Receivable.  Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been unsuccessful.
	Financial Instruments and Concentrations of Credit Risk and Non-performance Risk.  Financial instruments, which potentially subject us to concentrations of credit risk, consist primarily of trade receivables with a variety of oil and natural gas companies. We do not generally require collateral related to receivables. Our credit risk is considered to be limited due to the large number of customers comprising our customer base. Below are the third-party customers that accounted for more than 10% of our segment’s revenues:
		2014		2013		2012
	Oil and Natural Gas:
	Valero Energy Corporation	24	%	25	%	26	%
	Sunoco Partners Marketing	14	%	8	%	8	%
	Drilling:
	QEP Resources, Inc.	19	%	18	%	15	%
	Whiting Petroleum Corp. (formerly Kodiak Oil and Gas Corp.)	9	%	10	%	10	%
	Mid-Stream:
	ONEOK Partners, L.P.	44	%	57	%	54	%
	Tenaska Resources, LLC	22	%	16	%	7	%
	Laclede Gas Company	10	%	2	%	—	%
	Gavilon, LLC	—	%	—	%	10	%
	We had a concentration of cash of $18.4 million and $52.1 million at December 31, 2014 and 2013, respectively with one bank.
	The use of derivative transactions also involves the risk that the counterparties will be unable to meet the financial terms of the transactions. We considered this non-performance risk with regard to our counterparties and our own non-performance risk in our derivative valuation at December 31, 2014 and determined there was no material risk at that time. At December 31, 2014, the fair values of the net assets (liabilities) we had with each of the counterparties with respect to all of our commodity derivative transactions are listed in the table below:
		31-Dec-14
		(In millions)
	Bank of Montreal	$	27.8
	Scotiabank	3.3
	Total assets	$	31.1
	Property and Equipment.  Drilling equipment, transportation equipment, gas gathering and processing systems, and other property and equipment are carried at cost less accumulated depreciation. Renewals and enhancements are capitalized while repairs and maintenance are expensed. Depreciation of drilling equipment is recorded using the units-of-production method based on estimated useful lives starting at 15 years , including a minimum provision of 20% of the active rate when the equipment is idle. We use the composite method of depreciation for drill pipe and collars and calculate the depreciation by footage actually drilled compared to total estimated remaining footage. Depreciation of other property and equipment is computed using the straight-line method over the estimated useful lives of the assets ranging from 3 to 15 years.
	We review the carrying amounts of long-lived assets for potential impairment annually, typically during the fourth quarter, or when events occur or changes in circumstances suggest that these carrying amounts may not be recoverable. Changes that could prompt such an assessment may include equipment obsolescence, changes in the market demand for a specific asset, changes in commodity prices, periods of relatively low rig utilization, declining revenue per day, declining cash margin per day, or overall changes in general market conditions. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. The estimate of fair value is based on the best information available, including prices for similar assets. Changes in these estimates could cause us to reduce the carrying value of property and equipment. Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets and reflect management’s assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates, and costs. The use of different estimates and assumptions could result in materially different carrying values of our assets.
	On a periodic basis, we evaluate our fleet of drilling rigs for marketability based on the condition of inactive rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type. The components comprising inactive rigs are evaluated, and those components with continuing utility to the Company’s other marketed rigs are transferred to other rigs or to its yards to be used as spare equipment. The remaining components of these rigs are retired. In December 2014, we removed from service 31 drilling rigs, some older top drives, and certain drill pipe no longer marketable in the current economic environment. We estimated the fair value of the rigs and other assets based on the estimate market value from third-party assessments (Level 3 fair value measurement). Based on these estimates, we recorded a write-down of approximately $74.3 million, pre-tax. When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed from the accounts and any resulting gain or loss is generally reflected in operations. For dispositions of drill pipe and drill collars, an average cost for the appropriate feet of drill pipe and drill collars is removed from the asset account and charged to accumulated depreciation and proceeds, if any, are credited to accumulated depreciation.
	In December 2014, our mid-stream segment had a $7.1 million, pre-tax write-down of three of its systems, Weatherford, Billy Rose, and Spring Creek due to anticipated future cash flow and future development around these systems supporting their carrying value. The estimated future cash flows were less than the carrying value on these systems (Level 3 fair value measurement). In December 2012, our mid-stream segment had a $1.2 million write-down of its Erick system. There was no volume from the wells connected to this system, the compressor and related surface equipment have been removed from this location and there is no future activity anticipated from this gathering system. No significant impairments were recorded in 2013.
	We record an asset and a liability equal to the present value of the expected future ARO associated with our oil and gas properties. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by accreting an interest charge. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense.
	Capitalized Interest.  During 2014, 2013, and 2012, interest of approximately $32.2 million, $33.7 million, and $18.9 million, respectively, was capitalized based on the net book value associated with unproved properties not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems. Interest is being capitalized using a weighted average interest rate based on our outstanding borrowings.
	Goodwill.  Goodwill represents the excess of the cost of acquisitions over the fair value of the net assets acquired. Goodwill is not amortized, but an impairment test is performed at least annually to determine whether the fair value has decreased and is performed additionally when events indicate an impairment may have occurred. For purposes of impairment testing, goodwill is evaluated at the reporting unit level. Our goodwill is all related to our contract drilling segment, and accordingly, the impairment test is generally based on the estimated discounted future net cash flows of our drilling segment, utilizing discount rates and other factors in determining the fair value of our drilling segment. Inputs in our estimated discounted future net cash flows include rig utilization, day rates, gross margin percentages, and terminal value (these are all considered level 3 inputs). No goodwill impairment was recorded for the years ended December 31, 2014, 2013, or 2012. There were no additions to goodwill in 2014, 2013, or 2012. Goodwill of $3.1 million is deductible for tax purposes.
	Intangible Assets.  Intangible assets are capitalized and amortized over the estimated period benefited. Such amounts are reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. No intangible asset impairment was recorded for the years ended December 31, 2014, 2013, or 2012. Amortization of $0.7 million and $1.2 million was recorded in 2013 and 2012, respectively. Accumulated amortization for 2013 and 2012 was $18.0 million and $17.3 million, respectively. Our intangible assets became fully amortized in 2013, so no amortization was recorded in 2014.
	Oil and Natural Gas Operations.  We account for our oil and natural gas exploration and development activities using the full cost method of accounting prescribed by the SEC. Accordingly, all productive and non-productive costs incurred in connection with the acquisition, exploration and development of our oil, NGLs, and natural gas reserves, including directly related overhead costs and related asset retirement costs, are capitalized and amortized on a units-of-production method based on proved oil and natural gas reserves. Directly related overhead costs of $23.7 million, $21.5 million, and $17.6 million were capitalized in 2014, 2013, and 2012, respectively. Independent petroleum engineers annually audit our internal evaluation of our reserves. The average rates used for depreciation, depletion, and amortization (DD&A) were $14.82, $13.32, and $14.70 per Boe in 2014, 2013, and 2012, respectively. The calculation of DD&A includes estimated future expenditures to be incurred in developing proved reserves and estimated dismantlement and abandonment costs, net of estimated salvage values. Our unproved properties totaling $485.6 million are excluded from the DD&A calculation.
	No gains or losses are recognized on the sale, conveyance, or other disposition of oil and natural gas properties unless a significant reserve amount to our total reserves is involved.
	Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties.
	Under the full cost rules, at the end of each quarter, we review the carrying value of our oil and natural gas properties. The full cost ceiling is based principally on the estimated future discounted net cash flows from our oil and natural gas properties discounted at 10%. We use the unweighted arithmetic average of the commodity prices existing on the first day of each of the 12 months before the end of the reporting period to calculate discounted future revenues, unless prices were otherwise determined under contractual arrangements. In the event the unamortized cost of oil and natural gas properties being amortized exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period during which such excess occurs. 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 at June 30, 2012, consisted of swaps and collars, covering production of 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.
	For the quarter ended December 31, 2012, the 12-month average commodity prices, including the discounted value of our cash flow hedges, decreased further, resulting in an additional non-cash ceiling test write-down of $167.7 million pre-tax ($104.4 million, net of tax). Our qualifying cash flow hedges used in the ceiling test determination at December 31, 2012, consisted of swaps and collars covering 6.9 MMBoe in 2013. The effect of those hedges on the December 31, 2012 ceiling test was a $29.8 million pre-tax increase in the discounted net cash flows of our oil and natural gas properties. Our oil and natural gas derivatives are discussed in Note 13 of the Notes to our Consolidated Financial Statements.
	In December 2014, we determined the value of certain unproved oil and gas properties were diminished (in part or in whole) based on an impairment evaluation and our anticipated future exploration plans. That determination resulted in $73.7 million of costs associated with the unproved properties being added to the capitalized costs to be amortized. We incurred a non-cash ceiling test write-down of our oil and natural gas properties of $76.7 million pre-tax ($47.7 million net of tax). Subsequent to December 31, 2014, commodity prices have continued to decrease below December 31, 2014 levels. We anticipate that these reduced prices will require an additional write-down of the carrying value of our oil and natural gas properties for the quarter ending March 31, 2015 and potentially subsequent quarters.
	Our contract drilling segment provides drilling services for our exploration and production segment. Depending on their timing some of the drilling services performed on our properties are also deemed to be associated with the acquisition of an ownership interest in the property. Revenues and expenses for such services are eliminated in our income statement, with any profit recognized as a reduction in our investment in our oil and natural gas properties. The contracts for these services are issued under the same conditions and rates as the contracts entered into with unrelated third parties. We eliminated revenue of $89.5 million, $64.3 million, and $49.6 million for 2014, 2013, and 2012, respectively from our contract drilling segment and eliminated the associated operating expense of $62.4 million, $46.9 million, and $34.1 million during 2014, 2013, and 2012, respectively, yielding $27.1 million, $17.4 million, and $15.5 million during 2014, 2013, and 2012, respectively, as a reduction to the carrying value of our oil and natural gas properties.
	Gas Gathering and Processing Revenue. Our gathering and processing segment recognizes revenue from the gathering and processing of natural gas and NGLs in the period the service is provided based on contractual terms.
	Insurance.  We are self-insured for certain losses relating to workers’ compensation, control of well and employee medical benefits. Insured policies for other coverage contain deductibles or retentions per occurrence that range from zero to $1.5 million. We have purchased stop-loss coverage in order to limit, to the extent feasible, per occurrence and aggregate exposure to certain types of claims. However, there is no assurance that the insurance coverage will adequately protect us against liability from all potential consequences. We have elected to use an ERISA governed occupational injury benefit plan to cover all Texas drilling operations in lieu of covering them under Texas Workers’ Compensation. If insurance coverage becomes more expensive, we may choose to self-insure, decrease our limits, raise our deductibles or any combination of these rather than pay higher premiums.
	Derivative Activities.  All derivatives are recognized on the balance sheet and measured at fair value. 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 Consolidated Statements of Income. The commodity derivative instruments we had under cash flow accounting expired as of December 2013. Previous changes in the fair value of derivatives designated as cash flow hedges, to the extent they were effective in offsetting cash flows attributable to the hedged risk, were recorded in OCI until the hedged item was recognized into earnings. When the hedged item was recognized into earnings, it was reported in oil and natural gas revenues. Any change in fair value resulting from ineffectiveness was recognized in gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net. In August 2012, we determined on a prospective basis, to enter into economic hedges without electing cash flow hedge accounting.
	We do not engage in derivative transactions for speculative purposes. We document our risk management strategy, and for the cash flow hedges, we tested the hedge effectiveness at the inception of and during the term of each hedge.
	Limited Partnerships.  Unit Petroleum Company is a general partner in 15 oil and natural gas limited partnerships sold privately and publicly. Some of our officers, directors, and employees own the interests in most of these partnerships. We share in each partnership’s revenues and costs in accordance with formulas set out in each of the limited partnership agreement. The partnerships also reimburse us for certain administrative costs incurred on behalf of the partnerships.
	Income Taxes.  Measurement of current and deferred income tax liabilities and assets is based on provisions of enacted tax law; the effects of future changes in tax laws or rates are not included in the measurement. Valuation allowances are established where necessary to reduce deferred tax assets to the amount expected to be realized. Income tax expense is the tax payable for the year and the change during that year in deferred tax assets and liabilities.
	The accounting for uncertainty in income taxes prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a return. Guidance is also provided on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. We have $0.4 million of unrecognized tax benefits.
	Natural Gas Balancing.  We use the sales method for recording natural gas sales. This method allows for recognition of revenue, which may be more or less than its share of pro-rata production from certain wells. We estimate our December 31, 2014 balancing position to be approximately 5.1 Bcf on under-produced properties and approximately 4.4 Bcf on over-produced properties. We have recorded a receivable of $2.0 million on certain wells where we estimate that insufficient reserves are available for us to recover the under-production from future production volumes. We have also recorded a liability of $3.6 million on certain properties where we believe there are insufficient reserves available to allow the under-produced owners to recover their under-production from future production volumes. Our policy is to expense the pro-rata share of lease operating costs from all wells as incurred. Such expenses relating to the balancing position on wells in which we have imbalances are not material.
	Employee and Director Stock Based Compensation.  We recognize in our financial statements the cost of employee services received in exchange for awards of equity instruments based on the grant date fair value of those awards. The amount of our equity compensation cost relating to employees directly involved in exploration activities of our oil and natural gas segment is capitalized to our oil and natural gas properties. Amounts not capitalized to our oil and natural gas properties are recognized in general and administrative expense and operating costs of our business segments. We utilize the Black-Scholes option pricing model to measure the fair value of stock options and stock appreciation rights (SARs). The value of our restricted stock grants is based on the closing stock price on the date of the grants.
	Impact of Financial Accounting Pronouncements.
	Presentation of Financial Statements-Going Concern: Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. The FASB has issued ASU 2014-15. This is intended to define management's responsibility to evaluate whether there is substantial doubt about an organization's ability to continue as a going concern and to provide related footnote disclosures. For each reporting period, management will be required to evaluate whether there are conditions or events that raise substantial doubt about a company's ability to continue as a going concern within one year from the date financial statements are issued. The amendments are effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016. Early application is permitted for annual or interim reporting periods for which the financial statements have not previously been issued.
	Compensation - Stock Compensation: Accounting for Share-Based Payments When the Terms of an Award Provide that a Performance Target Could Be Achieved after the Requisite Service Period. The FASB has issued ASU 2014-12, the amendments in the ASU require that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. A reporting entity should apply existing guidance in Topic 718, Compensation – Stock Compensation, as it relates to awards with performance conditions that affect vesting to account for such awards. The performance target should not be reflected in estimating the grant-date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved.The amendments in this ASU are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Earlier adoption is permitted. We do not have any stock compensation awards with these conditions at this time.
	Revenue from Contracts with Customers. The FASB has issued ASU 2014-09. This affects any entity using U.S. GAAP that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (e.g., insurance contracts or lease contracts). The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early application is not permitted. We are in the process of evaluating the impact it will have on our financial statements.
	Presentation of Financial Statements and Property, Plant, and Equipment: Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The FASB has issued ASU 2014-08, the amendments in this update change the criteria for reporting discontinued operations while enhancing disclosures in this area. It also addresses sources of confusion and inconsistent application related to financial reporting of discontinued operations guidance in U.S. GAAP. Under the new guidance, only disposals representing a strategic shift that would have a major effect on the organization's operations and financial results should be presented as discontinued operations. In addition, it requires expanded disclosures about discontinued operations that will provide financial statement users with more information about the assets, liabilities, income, and expenses of discontinued operations. It also requires disclosure of pre-tax income attributable to a disposal of a significant part of an organization that does not qualify for discontinued operations reporting. The updates are effective for fiscal years, and interim periods within those years, beginning after December 15, 2014. Early adoption is permitted. We currently do not have any discontinued operations or disposals of components of an entity.

Acquisitions_and_Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2014
Acquisitions and divestitures [Abstract]
Acquisitions and Divestitures	On September 17, 2012, we closed on the acquisition of certain oil and natural gas assets from Noble Energy, Inc. (Noble). After final closing adjustments, 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 adjusted amount paid was $592.6 million.
	As of the effective date of the Noble acquisition (April 1, 2012), 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 other plays in western Oklahoma and the Texas Panhandle was approximately 59,000 net acres and is characterized by high working interest and operatorship, 95% of which was 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 required that the acquired assets and liabilities be recorded at their fair values as of the acquisition date. The following table summarizes the adjusted purchase price and the estimated values of assets acquired and liabilities assumed. It was based on information available to us at the time these consolidated financial statements were prepared and we believe these estimates are reasonable(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
	Unproved oil and natural gas properties	353,343
	Total oil and natural gas properties included in the full cost pool (1)	614,142
	Gas gathering and processing equipment and other	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, 2012. 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 Notes issued along with additional borrowings under our credit agreement 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.
		Twelve months ended December 31,
		2012
		(In thousands, except per share amounts)
	Pro forma:
	Revenues	$	1,376,393
	Net income	$	83,940
	Net income per common share:
	Basic	$	1.75
	Diluted	$	1.74
	From September 17, 2012, the date of the acquisition, through December 31, 2012, the portion of our revenues that were attributable to Noble were $21.4 million with a net loss of $0.8 million.
	2012 Divestitures
	In September 2012, we sold our interest in certain Bakken properties. The proceeds, net of related expenses were $226.6 million. In addition, we sold certain oil and natural gas assets located in Brazos and Madison Counties, Texas, for approximately $44.1 million. Proceeds from these dispositions reduced the net book value of the full cost pool with no gain or loss recognized.
	2012 Other
	In conjunction with the acquisition and divestitures completed in the third quarter 2012, we took the necessary steps to secure like-kind exchange tax treatment for the transactions under Section 1031 of the Internal Revenue Code.
	2013 Divestitures and Assets Held for Sale
	In August 2013, we sold additional Bakken property interests. The proceeds, net of related expenses, were $57.1 million. In addition, we had other non-core asset sales with proceeds, net of related expenses, of $21.7 million for 2013. Proceeds from these dispositions reduced the net book value of the full cost pool with no gain or loss recognized.
	During 2013, we sold five 2,000-3,000 horsepower drilling rigs to unaffiliated third-parties for a gain of $16.5 million. Four of our idle drilling rigs were classified as assets held for sale at December 31, 2013.
	2014 Divestitures
	The four drilling rigs classified as assets held for sale at December 31, 2013 were sold to an unaffiliated third party in the first quarter of 2014. The proceeds of this sale, less costs to sell, exceeded the $16.3 million net book value of the drilling rigs, both in the aggregate and for each drilling rig, resulting in a gain of $9.6 million.
	We sold non-core oil and natural gas assets, net of related expenses, for $33.1 million during 2014. Proceeds from those dispositions reduced the net book value of our full cost pool with no gain or loss recognized.

Earnings_Per_Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Earnings Per Share	The following data shows the amounts used in computing earnings per share:
		Income		Weighted		Per-Share
		(Numerator)		Shares		Amount
				(Denominator)
		(In thousands except per share amounts)
	For the year ended December 31, 2014:
	Basic earnings per common share	$	136,276	48,611		$	2.8
	Effect of dilutive stock options, restricted stock, and SARs	—		472		(0.02		)
	Diluted earnings per common share	$	136,276	49,083		$	2.78
	For the year ended December 31, 2013:
	Basic earnings per common share	$	184,746	48,218		$	3.83
	Effect of dilutive stock options, restricted stock, and SARs	—		354		(0.03		)
	Diluted earnings per common share	$	184,746	48,572		$	3.8
	For the year ended December 31, 2012:
	Basic earnings per common share	$	23,176	47,909		$	0.48
	Effect of dilutive stock options, restricted stock, and SARs	—		245		—
	Diluted earnings per common share	$	23,176	48,154		$	0.48
	The following options and their average exercise prices were not included in the computation of diluted earnings per share because the option exercise prices were greater than the average market price of our common stock for the years ended December 31:
		2014		2013			2012
	Options and SARs	73,500		149,665			250,901
	Average exercise price	$	64.43	$	58.41		$	52.72

Accrued_Liabilities

Accrued Liabilities	12 Months Ended
	Dec. 31, 2014
Accrued Liabilities [Abstract]
Accrued Liabilities	Accrued liabilities consisted of the following as of December 31:
		2014		2013
		(In thousands)
	Employee costs	$	31,451	$	27,633
	Lease operating expenses	20,709		16,073
	Interest payable	6,654		6,504
	Taxes	3,284		2,313
	Deposits on assets held for sale	—		3,750
	Derivative settlements	—		416
	Other	8,073		7,674
	Total accrued liabilities	$	70,171	$	64,363

LongTerm_Debt_And_Other_LongTe

Long-Term Debt And Other Long-Term Liabilities	12 Months Ended
	Dec. 31, 2014
Long-term debt and other long-term liabilites [Abstract]
Long-term Debt	Long-Term Debt
	Long-term debt consisted of the following as of December 31:
		2014			2013
		(In thousands)
	Credit agreement with an average interest rates of 2.9% at December 31, 2014	$	166,000		$	—
	6.625% senior subordinated notes due 2021, net of unamortized discount of $3.8 million and $4.3 million at December 31, 2014 and 2013, respectively	646,163			645,696
	Total long-term debt	$	812,163		$	645,696
	Credit Agreement. Under our Senior Credit Agreement (credit agreement), the amount we can borrow is the lesser of the amount we elect (from time to time) as the commitment amount or the value of the borrowing base as determined by the lenders, but in either event not to exceed the maximum credit agreement amount of $900.0 million. Our current commitment amount is $500.0 million. Our current borrowing base is $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. The fee varies based on the amount borrowed as a percentage of the amount of the total borrowing base. The credit agreement matures as of September 13, 2016. In connection with the most recent amendment of the credit agreement, 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 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 with the October 2014 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 December 31, 2014, we had $166.0 million outstanding borrowings under our credit agreement.
	We can use borrowings for financing 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 December 31, 2014, we were in compliance with the covenants contained in the credit agreement.
	6.625% Senior Subordinated Notes. We have issued and outstanding an aggregate principal amount of $650.0 million, 6.625% senior subordinated notes (the Notes). The interest is payable semi-annually (in arrears) on May 15 and November 15 of each year, and the Notes will mature on May 15, 2021. In connection with the issuance of the Notes, we incurred $14.7 million of fees that are being amortized as debt issuance cost over the life of the Notes.
	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), as supplemented by the First Supplemental Indenture dated as of May 18, 2011, between us, the Guarantors, and the Trustee, and as further supplemented by that the Second Supplemental Indenture dated as of January 7, 2013, between us, the Guarantors and the Trustee (as supplemented, the 2011 Indenture), establishing the terms and providing for the issuance of the Notes. The Guarantors are all of our direct and indirect subsidiaries. The discussion of the Notes in this report is qualified by and subject to the actual terms of the 2011 Indenture.
	Unit, as the parent company, has no independent assets or operations. The guarantees by the Guarantors of the Notes (registered under registration statements) are full and unconditional, joint and several, subject to certain automatic customary releases, are subject to certain restrictions on the sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, and other conditions and terms set out in the Indenture. Any of our subsidiaries that are not Guarantors are minor. There are no significant restrictions on our ability to receive funds from our subsidiaries through dividends, loans, advances or otherwise.
	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. 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. 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 2011 Indenture contains customary events of default. The 2011 Indenture also 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 December 31, 2014.
	Other Long-Term Liabilities
	Other long-term liabilities consisted of the following as of December 31:
		2014			2013
		(In thousands)
	ARO liability	$	100,567		$	133,657
	Capital lease obligations	25,876			—
	Workers’ compensation	17,997			20,041
	Separation benefit plans	11,276			9,382
	Gas balancing liability	3,623			3,775
	Deferred compensation plan	4,055			3,589
	Other	410			—
		163,804			170,444
	Less current portion	15,019			12,113
	Total other long-term liabilities	$	148,785		$	158,331
	Estimated annual principal payments under the terms of debt and other long-term liabilities from 2015 through 2019 are $15.0 million, $204.0 million, $8.4 million, $7.2 million, and $7.6 million, respectively.
	Capital Leases
	During 2014, our mid-stream segment entered into capital lease agreements for twenty compressors with initial terms of seven years. The underlying assets are included in gas gathering and processing equipment. The current portion of our capital lease obligations of $3.4 million is included in current portion of other long-term liabilities and the non-current portion of $22.5 million is included in other long-term liabilities in the accompanying Consolidated Balance Sheets as of December 31, 2014. These capital leases are discounted using annual rates of 4.0%. Total maintenance and interest remaining related to these leases are $11.4 million and $3.7 million, respectively at December 31, 2014. Annual payments, net of maintenance and interest, average $3.9 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of the fair market value of the assets at that time.
	Future payments required under the capital leases at December 31, 2014 are as follows:
			Amount
	Ending December 31,		(In thousands)
	2015		$	6,195
	2016		6,195
	2017		6,195
	2018		6,195
	2019		6,195
	2020 and thereafter		9,967
	Total future payments		40,942
	Less payments related to:
	Maintenance		11,395
	Interest		3,671
	Present value of future minimum payments		$	25,876

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
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 (AROs). 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 plugging costs associated with our oil and gas wells.
	The following table shows certain information about our AROs for the periods indicated:
		2014			2013
		(In thousands)
	ARO liability, January 1:	$	133,657		$	146,159
	Accretion of discount	4,599			5,450
	Liability incurred	6,246			4,857
	Liability settled	(4,490		)	(4,751		)
	Liability sold	(1,206		)	(2,622		)
	Revision of estimates (1)	(38,239		)	(15,436		)
	ARO liability, December 31:	100,567			133,657
	Less current portion	3,204			2,954
	Total long-term ARO liability	$	97,363		$	130,703
	_________________________
	-1	Plugging liability estimates were revised in both 2014 and 2013 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.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Taxes	A reconciliation of income tax expense, computed by applying the federal statutory rate to pre-tax income to our effective income tax expense is as follows:
		2014			2013			2012
		(In thousands)
	Income tax expense computed by applying the statutory rate	$	78,029		$	105,514		$	13,791
	State income tax, net of federal benefit	6,131			8,290			1,084
	Statutory depletion and other	2,503			2,919			1,351
	Income tax expense	$	86,663		$	116,723		$	16,226
	For the periods indicated, the total provision for income taxes consisted of the following:
		2014			2013			2012
		(In thousands)
	Current taxes:
	Federal	$	8,594		$	15,845		$	2,084
	State	784			146			(1,388		)
		9,378			15,991			696
	Deferred taxes:
	Federal	68,360			87,839			13,768
	State	8,925			12,893			1,762
		77,285			100,732			15,530
	Total provision	$	86,663		$	116,723		$	16,226
	Deferred tax assets and liabilities are comprised of the following at December 31:
		2014			2013
		(In thousands)
	Deferred tax assets:
	Allowance for losses and nondeductible accruals	$	55,231		$	77,285
	Net operating loss carryforward	54,901			61,055
	Alternative minimum tax and research and development tax credit carryforward	25,991			17,258
		136,123			155,598
	Deferred tax liability:
	Depreciation, depletion, amortization, and impairment	(1,000,811		)	(943,411		)
	Net deferred tax liability	(864,688		)	(787,813		)
	Current deferred tax asset	11,527			13,585
	Non-current—deferred tax liability	$	(876,215	)	$	(801,398	)
	Realization of the deferred tax assets are dependent on generating sufficient future taxable income. Although realization is not assured, management believes it is more likely than not that the deferred tax asset will be realized. The amount of the deferred tax asset considered realizable, however, could be reduced in the near-term if estimates of future taxable income are reduced. At December 31, 2014, we have federal net operating loss carryforwards of approximately $128.0 million which expire from 2020 to 2034.
	We file income tax returns in the U.S. federal jurisdiction and various states. We are no longer subject to U.S. federal or state income tax examinations by tax authorities for years before 2011. We are currently under examination by the state of Texas for the 2011-2013 return years but have not been made aware of any adjustments that would be material to our financial statements. During 2014, we recognized a tax benefit relating to a research and development tax credit carryforward in conjunction with our BOSS drilling rig activities. Due to the nature and subjectivity surrounding the research and development credit and historical challenges by the IRS against companies who claim the credit, it is our belief that the full amount of the credit may not be eventually allowed by the IRS once we are no longer in an AMT tax paying position. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
		2014			2013			2012
		(In thousands)
	Balance at January 1:	$	—		$	—		$	—
	Additions based on tax positions related to current year	410			—			—
	Additions for tax positions of prior years	—			—			—
	Reductions for tax positions of prior years	—			—			—
	Settlements	—			—			—
	Balance at December 31:	$	410		$	—		$	—
	At December 31, 2014, there was $0.4 million of unrecognized tax benefits that if recognized would affect the annual effective tax rate. We did not have any unrecognized tax benefits in 2013 or 2012.

Employee_Benefit_Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2014
Employee benefit plans [Abstract]
Employee Benefit Plans	Under our 401(k) Employee Thrift Plan, employees who meet specified service requirements may contribute a percentage of their total compensation, up to a specified maximum, to the plan. We may match each employee’s contribution, up to a specified maximum, in full or on a partial basis. We made discretionary contributions under the plan of 120,333, 111,995, and 95,598 shares of common stock and recognized expense of $5.2 million, $6.0 million, and $5.5 million in 2014, 2013, and 2012, respectively.
	We provide a salary deferral plan (Deferral Plan) which allows participants to defer the recognition of salary for income tax purposes until actual distribution of benefits which occurs at either termination of employment, death or certain defined unforeseeable emergency hardships. The liability recorded under the Deferral Plan at December 31, 2014 and 2013 was $4.1 million and $3.6 million, respectively. We recognized payroll expense and recorded a liability at the time of deferral.
	Effective January 1, 1997, we adopted a separation benefit plan (Separation Plan). The Separation Plan allows eligible employees whose employment is involuntarily terminated or, in the case of an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to receive benefits equivalent to four weeks salary for every whole year of service completed up to a maximum of 104 weeks. To receive payments, the recipient must waive any claims against us in exchange for receiving the separation benefits. On October 28, 1997, we adopted a Separation Benefit Plan for Senior Management (Senior Plan). The Senior Plan provides certain officers and key executives of Unit with benefits generally equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the selection of the individuals covered in this plan. On May 5, 2004 we also adopted the Special Separation Benefit Plan (Special Plan). This plan is identical to the Separation Benefit Plan with the exception that the benefits under the plan vest on the earliest of a participant’s reaching the age of 65 or serving 20 years with the company.
	On December 31, 2008, we amended all three Plans to be in compliance with Section 409A of the Internal Revenue Code of 1986, as amended. The key amendments to the Plans address, among other things, when distributions may be made, the timing of payments, and the circumstances under which employees become eligible to receive benefits. None of the amendments materially increase the benefits, grants or awards issuable under the Plans. We recognized expense of $2.7 million, $2.4 million, and $2.2 million in 2014, 2013, and 2012, respectively, for benefits associated with anticipated payments from these separation plans.
	We have entered into key employee change of control contracts with three of our current executive officers. These severance contracts have an initial three-year term that is automatically extended for one year on each anniversary, unless a notice not to extend is given by us. If a change of control of the company, as defined in the contracts, occurs during the term of the severance contract, then the contract becomes operative for a fixed three-year period. The severance contracts generally provide that the executive’s terms and conditions for employment (including position, work location, compensation, and benefits) will not be adversely changed during the three-year period after a change of control. If the executive’s employment is terminated (other than for cause, death, or disability), the executive terminates for good reason during such three-year period, or the executive terminates employment for any reason during the 30-day period following the first anniversary of the change of control, and on certain terminations prior to a change of control or in connection with or in anticipation of a change of control, the executive is generally entitled to receive, in addition to certain other benefits, any earned but unpaid compensation; up to 2.9 times the executive’s base salary plus annual bonus (based on historic annual bonus); and the company matching contributions that would have been made had the executive continued to participate in the company’s 401(k) plan for up to an additional three years.
	The severance contract provides that the executive is entitled to receive a payment in an amount sufficient to make the executive whole for any excise tax on excess parachute payments imposed under Section 4999 of the Code. As a condition to receipt of these severance benefits, the executive must remain in the employ of the company prior to change of control and render services commensurate with his position.

Transactions_With_Related_Part

Transactions With Related Parties	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Transactions With Related Parties	Unit Petroleum Company serves as the general partner of 15 oil and gas limited partnerships. Two investments by third parties and 13 (the employee partnerships) were formed to allow certain of our qualified employees and our directors to participate in Unit Petroleum’s oil and gas exploration and production operations. The partnerships for the third party investments were formed in 1984 and two in 1986. Effective December 31, 2014, the 1984 partnership was dissolved. Employee partnerships have been formed for each year beginning with 1984 and ending with 2011. Interests in the employee partnerships were offered to the employees of Unit and its subsidiaries whose annual base compensation was at least a specified amount and to the directors of Unit.
	The employee partnerships formed in 1984 through 1990 were consolidated into a single consolidating partnership in 1993 and the employee partnerships formed in 1991 through 1999 were also consolidated into the consolidating partnership in 2002. The consolidation of the 1991 through the 1999 employee partnerships was done by the general partners under the authority contained in the respective partnership agreements and did not involve any vote, consent or approval by the limited partners. The employee partnerships have each had a set percentage (ranging from 1% to 15%) of our interest in most of the oil and natural gas wells we drill or acquire for our own account during the particular year for which the partnership was formed. The total interest the employees have in our oil and natural gas wells by participating in these partnerships does not exceed one percent.
	Amounts received in the years ended December 31, from both public and private Partnerships for which Unit is a general partner are as follows:
		2014		2013		2012
		(In thousands)
	Contract drilling	$	4	$	16	$	246
	Well supervision and other fees	435		470		434
	General and administrative expense reimbursement	39		36		39
	Related party transactions for contract drilling and well supervision fees are the related party’s share of such costs. These costs are billed to related parties on the same basis as billings to unrelated parties for such services. General and administrative reimbursements are both direct general and administrative expense incurred on the related party’s behalf and indirect expenses allocated to the related parties. Such allocations are based on the related party’s level of activity and are considered by management to be reasonable.
	The Chairman of our Board, John Nikkel is a 6.5% owner of Toklan Oil and Gas Company (Toklan), an oil and gas exploration and production company located in Tulsa, Oklahoma. Mr. Nikkel's son, Robert Nikkel is Toklan's President, and he owns approximately 35.3% of the company. In the ordinary course of business, there were two wells drilled for Toklan during 2014, with no activity in 2013 or 2012. Under its usual standard dayrate contract terms available generally to all similarly-situated customers at that time and in the same general drilling area, the Company received payments from Toklan of approximately $1.1 million in 2014 and had an accounts receivable balance of $0.4 million at December 31, 2014. The Company also paid royalties in 2014, in the ordinary course of business, of approximately $0.2 million to Toklan. There were no amounts to disclose for 2013 or 2012.
	One of our directors, G. Bailey Peyton IV, also serves as the President and a significant investor in Upland Resources, L.L.C., a small independent oil and natural gas exploration company, and as Manager of Peyton Royalties, LP, a family-controlled limited partnership that owns royalty rights in wells in the Texas and Oklahoma Panhandles. In the ordinary course of business, there were no wells drilled for Upland Resources, L.L.C. during 2014 or 2013 and the Company drilled three wells during 2012, under its usual standard dayrate contracts, in which Upland Resources, L.L.C. was a participant, for which the Company received payments of approximately $1.6 million from Upland Resources, L.L.C. The Company also paid royalties, primarily due to its status as successor in interest to prior transactions and as operator of the wells involved and, in some cases, as lessee, with respect to certain wells in which Mr. Peyton, members of Mr. Peyton's family, and Peyton Royalties, LP have an interest. Such payments totaled approximately $1.3 million, $1.4 million, and $1.2 million during 2014, 2013, and 2012, respectively.
	Our Audit Committee and the board, in accordance with our related party transaction policy, have determined that these arrangements are in the best interest of the Company.

Shareholder_Rights_Plan

Shareholder Rights Plan	12 Months Ended
	Dec. 31, 2014
Shareholder Rights Plan [Abstract]
Shareholder Rights Plan	We maintain a Shareholder Rights Plan (the Plan) designed to deter coercive or unfair takeover tactics, to prevent a person or group from gaining control of us without offering fair value to all our shareholders and to deter other abusive takeover tactics, which are not in the best interest of shareholders.
	Under the terms of the Plan, each share of common stock is accompanied by one right, which given certain acquisition and business combination criteria, entitles the shareholder to purchase from us one one-hundredth of a newly issued share of Series A Participating Cumulative Preferred Stock at a price subject to adjustment by us or to purchase from an acquiring company certain shares of its common stock or the surviving company’s common stock at 50% of its value.
	The rights become exercisable 10 days after we learn that an acquiring person (as defined in the Plan) has acquired 15% or more of the outstanding common stock of Unit or 10 business days after the commencement of a tender offer, which would result in a person owning 15% or more of our shares. We can redeem the rights for $0.01 per right at any date before the earlier of (i) the close of business on the 10th day following the time we learn that a person has become an acquiring person or (ii) May 19, 2015 (the “Expiration Date”). The rights will expire on the Expiration Date, unless redeemed earlier by Unit.

StockBased_Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-Based Compensation	For restricted stock awards and stock options, we had:
		2014				2013			2012
		(In millions)
	Recognized stock compensation expense	$	17.4			$	16.1		$	11.4
	Capitalized stock compensation cost for our oil and natural gas properties	3.7				3.5			2.7
	Tax benefit on stock based compensation	6.7				6.2			4.5
	The remaining unrecognized compensation cost related to unvested awards at December 31, 2014 is approximately $17.4 million of which $2.7 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.
	At our annual meeting of stockholders held on May 2, 2012, our stockholders approved the Unit Corporation Stock and Incentive Compensation Plan Amended and Restated May 2, 2012 (the amended plan). The amended plan allows us to grant stock-based and cash-based compensation to our employees (including employees of subsidiaries) as well as non-employee directors. The amended plan succeeds the Non-employee Directors' 2000 Stock Option Plan (the option plan), with 2011 being the last year options were granted under the option plan.
	The amended plan allows for the issuance of 3.3 million shares of common stock with 2.0 million shares being the maximum number of shares that can be issued as “incentive stock options.” Awards under this plan may be granted in any one or a combination of the following:
	•	incentive stock options under Section 422 of the Internal Revenue Code;
	•	non-qualified stock options;
	•	performance shares;
	•	performance units;
	•	restricted stock;
	•	restricted stock units;
	•	stock appreciation rights;
	•	cash based awards; and
	•	other stock-based awards.
	This plan also contains various limits as to the amount of awards that can be given to an employee in any fiscal year. All awards are generally subject to the minimum vesting periods, as determined by our Compensation Committee and included in the award agreement.
	Expected volatilities are based on the historical volatility of our stock. We use historical data to estimate option exercise and termination rates within the model and aggregate groups that have similar historical exercise behavior for valuation purposes. To date, we have not paid dividends on our stock. The risk free interest rate is computed from the United States Treasury Strips rate using the term over which it is anticipated the grant will be exercised.
	SARs
	Activity pertaining to SARs granted under the Unit Corporation Stock and Incentive Compensation Plan is as follows:
		Number of			Weighted
		Shares			Average
					Price
	Outstanding at January 1, 2012	145,901			$	46.59
	Granted	—			—
	Exercised	—			—
	Forfeited	—			—
	Outstanding at December 31, 2012	145,901			46.59
	Granted	—			—
	Exercised	—			—
	Forfeited	—			—
	Outstanding at December 31, 2013	145,901			46.59
	Granted	—			—
	Exercised	(14,131	)		46.5
	Forfeited	—			—
	Outstanding at December 31, 2014	131,770			$	46.6
	There were no SARs granted or vested during 2014, 2013, or 2012.
		Outstanding and exercisable SARs at
		31-Dec-14
	Exercise Prices	Number		Weighted Average Remaining		Weighted Average
		of Shares		Contractual Life		Exercise Price
	$44.31	91,255		3.0 years		$44.31
	$51.76	40,515		1.9 years		$51.76
	The intrinsic value of SARs exercised in 2014 was $0.2 million. No cash is received from SARs exercised. The SARs expire after 10 years from the date of the grant. There was no aggregate intrinsic value on the 131,770 shares outstanding at December 31, 2014. The remaining weighted average contractual term is 2.6 years.
	Restricted Stock
	Activity pertaining to restricted stock awards granted under the amended plan is as follows:
	Employees	Number of			Weighted
		Shares			Average
					Price
	Nonvested at January 1, 2012	447,961			$	47.44
	Granted	376,445			47.37
	Vested	(220,788	)		45.66
	Forfeited	(14,091	)		45.37
	Nonvested at December 31, 2012	589,527			48.11
	Granted	453,549			48.2
	Vested	(248,003	)		46.46
	Forfeited	(18,330	)		47.85
	Nonvested at December 31, 2013	776,743			48.7
	Granted	455,122			53.72
	Vested	(304,804	)		49.68
	Forfeited	(26,775	)		51.92
	Nonvested at December 31, 2014	900,286			$	50.81
Non-Employee Directors	Number of			Weighted
	Shares			Average
				Price
Nonvested at January 1, 2012	—			$	—
Granted	24,606			40.23
Vested	—			—
Forfeited	—			—
Nonvested at December 31, 2012	24,606			$	40.23
Granted	21,128			41.65
Vested	(10,030	)		40.23
Forfeited	—			—
Nonvested at December 31, 2013	35,704			$	41.07
Granted	13,768			63.91
Vested	(14,336	)		40.93
Forfeited	—			—
Nonvested at December 31, 2014	35,136			$	50.08
The restricted stock awards vest in periods ranging from 2 to 3 years, except for a portion of those granted to certain executive officers. As to those executive officers, 40% of the shares granted, or 71,674 shares in 2014, and 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 2017, 2016, and 2015, respectively. The actual number of performance shares that vest in 2015, 2016, and 2017 will be based on the company’s achievement of certain stock performance measures at the end of the term, and will range from 0% to 150% of the restricted shares granted as performance shares. Based on the selected performance criteria, the participants are estimated to receive the targeted amount (or approximately 100%) of the performance based shares.
The fair value of the restricted stock granted in 2014, 2013, and 2012 at the grant date was $24.1 million, $21.3 million, and $16.9 million, respectively. The aggregate intrinsic value of the 319,140 shares of restricted stock that vested in 2014 on their vesting date was $20.2 million. The aggregate intrinsic value of the 935,422 shares of restricted stock outstanding subject to vesting at December 31, 2014 was $31.9 million with a weighted average remaining life of 0.7 of a year.
Employee Stock Option Plan
The Stock Option Plan, provided the granting of options for up to 2,700,000 shares of common stock to officers and employees. The option plan permitted the issuance of qualified or nonqualified stock options. Options granted typically became exercisable at the rate of 20% per year one year after being granted and expire after 10 years from the original grant date. The exercise price for options granted under this plan was the fair market value of the common stock on the date of the grant. In 2006, as a result of the approval of the adoption of the Unit Corporation Stock and Incentive Compensation Plan, no further awards were made under this plan.
Activity pertaining to the Stock Option Plan is as follows:
	Number of			Weighted
	Shares			Average
				Exercise
				Price
Outstanding at January 1, 2012	138,980			$	31.39
Granted	—			—
Exercised	(18,850	)		20.38
Forfeited	(2,100	)		37.83
Outstanding at December 31, 2012	118,030			33.03
Granted	—			—
Exercised	(48,110	)		26.09
Forfeited	(1,000	)		37.83
Outstanding at December 31, 2013	68,920			37.81
Granted	—			—
Exercised	(21,490	)		37.83
Forfeited	(37,930	)		37.83
Outstanding at December 31, 2014	9,500			$	37.69
There were no shares that vested in 2014, 2013, or 2012. The intrinsic value of options exercised in 2014 was $0.4 million. Total cash received from the options exercised in 2014 was $0.4 million.
	Outstanding and Exercisable Options at December 31, 2014
Exercise Price	Number		Weighted Average Remaining		Weighted Average
	of Shares		Contractual Life		Exercise Price
$37.69	9,500		0.4 years		$37.69
There was no aggregate intrinsic value on the 9,500 shares outstanding subject to options at December 31, 2014. The remaining weighted average contractual term is 0.4 of a year.
Non-Employee Directors' Stock Option Plan
Under the Unit Corporation 2000 Non-Employee Directors’ Stock Option Plan, on the first business day following each annual meeting of shareholders, each person who was then a member of our Board of Directors and who was not then an employee of the company or any of its subsidiaries was granted an option to purchase 3,500 shares of common stock. The option price for each stock option was the fair market value of the common stock on the date the stock options were granted. The term of each option is 10 years and cannot be increased and no stock options were to be exercised during the first six months of its term except in case of death. As mentioned above, on May 2, 2012, our stockholders approved the amended plan which succeeds this plan, and no further awards were made under the non-employee director option plan.
Activity pertaining to the Directors’ Plan is as follows:
	Number of			Weighted
	Shares			Average
				Exercise
				Price
Outstanding at January 1, 2012	199,500			$	48.37
Granted	—			—
Exercised	(7,000	)		20.28
Forfeited	—			—
Outstanding at December 31, 2012	192,500			49.39
Granted	—			—
Exercised	(17,500	)		32.53
Forfeited	(3,500	)		20.46
Outstanding at December 31, 2013	171,500			51.7
Granted	—			—
Exercised	(21,000	)		33.94
Forfeited	—			—
Outstanding at December 31, 2014	150,500			$	54.18
The intrinsic value of the 21,000 options exercised in 2014 was $0.6 million. Total cash received from options exercised in 2014 was $0.7 million.
	Outstanding and Exercisable
	Options at December 31, 2014
Weighted Average Exercise Price	Number			Weighted Average Remaining		Weighted Average
	of Shares			Contractual Life		Exercise Price
$31.30 - $41.21	45,500			4.2 years		$	37.88
$53.81 - $73.26	105,000			3.5 years		$	61.24
The aggregate intrinsic value of the shares outstanding subject to options at December 31, 2014 was less than $0.1 million with a weighted average remaining contractual term of 3.7 years.

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
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 subject to a derivative contract is based, in part, on our view of current and future market conditions. As of December 31, 2014, our derivative transactions consisted of the following types of hedges:
	•	Swaps. We receive or pay a fixed price for the 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 instruments. 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. As a result, the change in fair value, on all commodity derivatives entered into after that determination, is reflected in the income statement and not in accumulated other comprehensive income (OCI). As of December 31, 2013, all cash flow hedges had expired.
	At December 31, 2014, the following non-designated hedges were outstanding:
	Term		Commodity	Contracted Volume		Weighted Average	Contracted Market
						Fixed Price for Swaps
	Jan’15 – Dec’15		Natural gas – swap	40,000 MMBtu/day		$3.98	IF – NYMEX (HH)
	Jan’15 – Mar’15		Natural gas – collar	30,000 MMBtu/day		$4.20-$5.03	IF – NYMEX (HH)
	Jan’15 – Dec'15		Crude oil – swap	1,000 Bbl/day		$95.00	WTI – NYMEX
	Subsequent to December 31, 2014, the following non-designated hedges were entered into:
	Term		Commodity	Contracted Volume		Weighted Average	Contracted Market
						Fixed Price for Swaps
	Apr’15 – Jun'15		Natural gas – swap	30,000 MMBtu/day		$3.10	IF – NYMEX (HH)
	Apr’15 – Jun'15		Natural gas – collar	30,000 MMBtu/day		$2.92-$3.26	IF – NYMEX (HH)
	Jul’15 – Sep'15		Natural gas – collar	30,000 MMBtu/day		$2.58-$3.04	IF – NYMEX (HH)
	The following tables present the fair values and locations of the derivative transactions recorded in our Consolidated Balance Sheets at December 31:
				Derivative Assets
				Fair Value
			Balance Sheet Location	2014			2013
				(In thousands)
	Commodity derivatives:
	Current		Current derivative assets	$	31,139		$	515
	Long-term		Non-current derivative assets	—			—
	Total derivative assets			$	31,139		$	515
				Derivative Liabilities
				Fair Value
			Balance Sheet Location	2014			2013
				(In thousands)
	Commodity derivatives:
	Current		Current derivative liabilities	$	—		$	5,561
	Long-term		Non-current derivative liabilities	—			—
	Total derivative liabilities			$	—		$	5,561
	If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty in our Consolidated Balance Sheets.
	For hedges designated under cash flow accounting, we recognized in OCI the effective portion of any changes in fair value and reclassified the recognized gains (losses) on the sales to oil and natural gas revenue as the underlying transactions were settled. Because our cash flow hedges expired as of December 31, 2013, we had no balance in accumulated OCI at December 31, 2014 or 2013.
	For our economic hedges that we elected not to 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 Consolidated Statements of Income. Changes in the fair value of derivatives that were designated as cash flow hedges, to the extent they were effective in offsetting cash flows attributable to the hedged risk, were recorded in OCI until the hedged item was recognized into earnings. When the hedged item was recognized into earnings, it was reported in oil and natural gas revenues. Any change in fair value that resulted from ineffectiveness was recognized in gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net.
	Effect of derivative instruments on the Consolidated Statements of Income (cash flow hedges) for the year ended December 31:
	Derivative Instrument		Location of Gain or (Loss) Reclassified from Accumulated OCI into Income & Location of Gain or (Loss) Recognized in Income	Amount of Gain or (Loss) Reclassified from						Amount of Gain
				Accumulated OCI into						or (Loss) Recognized in Income (2)
				Income (1)
				2014			2013			2014		2013
				(In thousands)
	Commodity derivatives		Oil and natural gas revenue (1)	$	—		$	603		$	—	$	—
	Commodity derivatives		Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net (2)	—			—			—		(190		)
			Total	$	—		$	603		$	—	$	(190	)
	_________________________
	-1	Effective portion of gain (loss).
	-2	Ineffective portion of gain (loss).
	Effect of Derivative Instruments on the Consolidated Statements of Income (derivatives not designated as hedging instruments) for the year ended December 31:
	Derivatives Not Designated as Hedging Instruments		Location of Gain or (Loss)	Amount of Gain or (Loss)
			Recognized in Income on	Recognized in Income on
			Derivative	Derivative
				2014			2013
				(In thousands)
	Commodity derivatives		Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net (1)	$	30,147		$	(8,184	)
	Total			$	30,147		$	(8,184	)
	_________________________
	-1	Amount settled during the period is a loss of $6,038 and $1,764, respectively.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
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 into three levels with the highest priority given to Level 1 and the lowest priority 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.
	The following tables set forth our recurring fair value measurements:
		31-Dec-14
		Level 2				Level 3			Effect of Netting			Total
		(In thousands)
	Financial assets (liabilities):
	Commodity derivatives:
	Assets	$	27,784			$	3,355		$	—		$	31,139
	Liabilities	—				—			—			—
		$	27,784			$	3,355		$	—		$	31,139
		31-Dec-13
		Level 2				Level 3			Effect of Netting			Total
		(In thousands)
	Financial assets (liabilities):
	Commodity derivatives:
	Assets	$	1,978			$	20		$	(1,483	)	$	515
	Liabilities	(4,429		)		(2,615		)	1,483			(5,561		)
		$	(2,451	)		$	(2,595	)	$	—		$	(5,046	)
	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 December 31, 2014.
	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:
		Net Derivatives
		For the Year Ended,
		31-Dec-14				31-Dec-13
		(In thousands)
	Beginning of period	$	(2,595	)		$	(595	)
	Total gains or losses:
	Included in earnings (1)	6,108				(2,637		)
	Included in other comprehensive income (loss)	—				—
	Settlements	(158		)		637
	End of period	$	3,355			$	(2,595	)
	Total gains (losses) for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period	$	5,950			$	(2,000	)
	_________________________
	-1	Commodity sales collars are reported in the consolidated statements of income in oil and gas revenues (for cash flow hedges), and gain (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 December 31, 2014:
	Commodity (1)	Fair Value			Valuation Technique	Unobservable Input	Range
		(In thousands)
	Natural gas collar	$	3,355		Discounted cash flow	Forward commodity price curve	$0.00 - $1.32
	_________________________
	-1	The commodity contracts detailed in this category include non-exchange-traded natural gas collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be received within the settlement period.
	Based on our valuation at December 31, 2014, we determined that the non-performance risk with regard to 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 the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.
	At December 31, 2014, the carrying values on the 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 December 31, 2014 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 Consolidated Balance Sheets at December 31, 2014 and December 31, 2013 were $646.2 million and $645.7 million, respectively. We estimate the fair value of these Notes using quoted marked prices at December 31, 2014 and December 31, 2013 were $605.5 million and $688.2 million, respectively. These Notes would be classified as Level 2.

Accumulated_Other_Comprehensiv

Accumulated Other Comprehensive Income	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Accumulated other comprehensive income	Changes in accumulated other comprehensive income (loss) by component, net of tax, are as follows:
		Net Gains (Losses) on Cash Flow Hedges
		2014		2013			2012
		(In thousands)
	Balance at January 1:	$	—	$	7,587		$	19,026
	Other comprehensive income before reclassification	—		(7,349		)	18,635
	Amounts reclassified from accumulated other comprehensive income	—		(238		)	(30,074		)
	New current-period other comprehensive income	—		(7,587		)	(11,439		)
	Balance at December 31:	$	—	$	—		$	7,587
	Amounts reclassified from accumulated other comprehensive income (loss) into the Consolidated Statements of Income for the year ended December 31:
		2014		2013			2012			Affected Line Item in the Statement Where Net Income is Presented
		(In thousands)
	Net gains (loss) on cash flow hedges
	Commodity derivatives	$	—	$	603		$	51,853		Oil and natural gas revenues
	Commodity derivatives	—		(190		)	(2,616		)	Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net
		—		413			49,237			Total before tax
		—		(175		)	(19,163		)	Tax expense
	Total reclassification for the period	$	—	$	238		$	30,074		Net of tax

Commitments_And_Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitments And Contingencies	We lease office space or yards in Edmond, Oklahoma City, and Tulsa, Oklahoma; Houston, Texas; Englewood, Colorado; Pinedale, Wyoming; and Pittsburgh, Pennsylvania under the terms of operating leases expiring through July 2019. Additionally, we have several compressor rentals, equipment leases, and lease space on short-term commitments to stack excess drilling rig equipment and production inventory. Future minimum rental payments under the terms of the leases are approximately $6.8 million, $2.7 million, $0.2 million, and less than $0.1 million in 2015 through 2018, respectively. Total rent expense incurred was $13.6 million, $16.9 million, and $14.0 million in 2014, 2013, and 2012, respectively.
	During 2014, our mid-stream segment entered into capital lease agreements for twenty compressors with initial terms of seven years. Future capital lease payments under the terms are approximately $6.2 million each year through 2019 and approximately $10.0 million thereafter. Total maintenance and interest remaining related to these leases are $11.4 million and $3.7 million, respectively at December 31, 2014. Annual payments, net of maintenance and interest, average $3.9 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of the fair market value of the assets at that time.
	The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy Income Limited Partnership agreements along with the employee oil and gas limited partnerships require, on the election of a limited partner, that we repurchase the limited partner’s interest at amounts to be determined by appraisal in the future. These repurchases in any one year are limited to 20% of the units outstanding. We made repurchases of $45,000, $16,000, $56,000 in 2014, 2013, and 2012, respectively. Effective December 31, 2014, the Unit 1984 Oil and Gas Limited Partnership was dissolved.
	We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. We also conduct periodic reviews, on a company-wide basis, to identify changes in our environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, we may exclude a property from the acquisition, require the seller to remediate the property to our satisfaction, or agree to assume liability for the remediation of the property.
	We have not historically experienced any environmental liability while being a contract driller since the greatest portion of risk is borne by the operator. Any liabilities we have incurred have been small and have been resolved while the drilling rig is on the location and the cost has been included in the direct cost of drilling the well.
	For 2015 and 2016, we have committed to purchase approximately $22.3 million and $3.8 million, respectively, of new drilling rig components, drill pipe, drill collars, and related equipment. We have also committed to paying $1.4 million for Enterprise Resource Planning software over the next year and then $0.5 million for maintenance one year following implementation. Also over the next twelve months, we have $0.2 million remaining towards a gas accounting system.
	We are subject to various legal proceedings arising in the ordinary course of our various businesses none of which, in our opinion, will result in judgments which would have a material adverse effect on our financial position, operating results or cash flows.

Industry_Segment_Information

Industry Segment Information	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Industry Segment Information	We have three main business segments offering different products and services:
	•	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 the 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 oil and natural gas production outside the United States is not significant.
	The following table provides certain information about the operations of each of our segments:
		2014				2013			2012
		(In thousands)
	Revenues:
	Oil and natural gas	$	740,079			$	649,718		$	567,944
	Contract drilling	566,012				479,091			579,368
	Elimination of inter-segment revenue	(89,495		)		(64,313		)	(49,649		)
	Contract drilling net of inter-segment revenue	476,517				414,778			529,719
	Gas gathering and processing	445,934				378,397			290,773
	Elimination of inter-segment revenue	(89,586		)		(91,043		)	(73,313		)
	Gas gathering and processing net of inter-segment revenue	356,348				287,354			217,460
	Total revenues	$	1,572,944			$	1,351,850		$	1,315,123
	Operating income:
	Oil and natural gas	$	199,392		(5)	$	239,219		$	(77,221	)	(5)
	Contract drilling	41,896			(6)	96,304			159,188
	Gas gathering and processing	2,015			(7)	10,757			5,780			(7)
	Total operating income (1)	243,303				346,280			87,747
	General and administrative	(42,023		)		(38,323		)	(33,086		)
	Gain on disposition of assets	8,953				17,076			253
	Interest expense, net	(17,371		)		(15,015		)	(14,137		)
	Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net	30,147				(8,374		)	(1,243		)
	Other	(70		)		(175		)	(132		)
	Income before income taxes	$	222,939			$	301,469		$	39,402
	Identifiable assets:
	Oil and natural gas	$	2,856,833			$	2,441,792		$	2,214,029
	Contract drilling	1,059,980				1,042,661			1,079,736
	Gas gathering and processing	500,255				473,717			413,708
	Total identifiable assets (2)	4,417,068				3,958,170			3,707,473
	Corporate assets	56,660				64,220			53,647
	Total assets	$	4,473,728			$	4,022,390		$	3,761,120
	Capital expenditures:
	Oil and natural gas (3)	$	740,262			$	531,233		$	1,145,337
	Contract drilling	176,683				64,325			77,520
	Gas gathering and processing	79,268			(4)	96,085			183,162
	Other (3)	17,067				4,483			11,083
	Total capital expenditures	$	1,013,280			$	696,126		$	1,417,102
	Depreciation, depletion, amortization, and impairment:
	Oil and natural gas
	Depreciation, depletion, and amortization	$	276,088			$	226,498		$	211,347
	Impairment of oil and natural gas properties	76,683			(5)	—			283,606			(5)
	Contract drilling	159,688			(6)	71,194			81,007
	Gas gathering and processing	47,502			(7)	33,191			24,388			(7)
	Other	3,051				3,024			2,279
	Total depreciation, depletion, amortization, and impairment	$	563,012			$	333,907		$	602,627
	_________________________
	-1	Operating income is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, (gain) loss on disposition of assets, gain (loss) on non-designated hedges and hedge ineffectiveness, interest expense, other income (loss), or income taxes.
	-2	Identifiable assets are those used in Unit’s operations in each industry segment. Corporate assets are principally cash and cash equivalents, short-term investments, corporate leasehold improvements, furniture and equipment.
	-3	In 2013, we reclassified salt water disposal capital expenditures out of other and into oil and natural gas of $17.0 million for 2012.
	-4	In 2014, we entered into capital leases for $28.2 million.
	-5	In 2014 and 2012, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $76.7 million and $283.6 million pre-tax ($47.7 million and $176.5 million, net of tax), respectively.
	-6	Depreciation, depletion, amortization, and impairment for contract drilling includes a $74.3 million pre-tax write-down for 31 drilling rigs, some older top drives, and certain drill pipe removed from service.
	-7	Depreciation, depletion, amortization, and impairment for gas gathering and processing for 2014 includes a $7.1 million pre-tax write-down for three of our systems, Weatherford, Billy Rose, and Spring Creek and for 2012 includes a $1.2 million write-down of our Erick system.

Selected_Quarterly_Financial_I

Selected Quarterly Financial Information	12 Months Ended
	Dec. 31, 2014
Selected Quarterly Financial Information [Abstract]
Selected Quarterly Financial Information	Summarized unaudited quarterly financial information is as follows:
		Three Months Ended
		31-Mar		30-Jun		September 30		December 31
		(In thousands except per share amounts)
	2014
	Revenues	$	387,988	$	405,431	$	400,974	$	378,551
	Gross profit (loss)	$	115,143	$	113,973	$	103,983	$	(89,796	)	(1)
	Net income (loss)	$	56,945	$	54,360	$	67,522	$	(42,551	)
	Net income (loss) per common share:
	Basic	$	1.17	$	1.12	$	1.39	$	(0.88	)
	Diluted	$	1.17	$	1.11	$	1.37	$	(0.88	)	(2)
	2013
	Revenues	$	318,532	$	340,421	$	333,776	$	359,121
	Gross profit	$	83,683	$	90,823	$	79,082	$	92,692		(1)
	Net income	$	40,206	$	59,007	$	34,232	$	51,301
	Net income per common share:
	Basic	$	0.84	$	1.22	$	0.71	$	1.06
	Diluted	$	0.83	$	1.22	$	0.7	$	1.05
	_________________________
	-1	Gross profit excludes general and administrative expense, interest expense, (gain) loss on disposition of assets, gain (loss) on non-designated hedges and hedge ineffectiveness, income taxes, and other income (loss).
	-2	Due to the effect of the loss in the fourth quarter, the diluted earnings per share for the year's four quarters does not equal annual earnings per share.

Supplemental_Oil_And_Gas_Discl

Supplemental Oil And Gas Disclosures	12 Months Ended
	Dec. 31, 2014
Supplemental Oil and Gas Disclosures [Abstract]
Supplemental Oil And Gas Disclosures	Our oil and gas operations are substantially located in the United States. The capitalized costs at year-end and costs incurred during the year were as follows:
		2014				2013				2012
		(In thousands)
	Capitalized costs:
	Proved properties	$	4,990,753			$	4,235,712			$	3,822,381
	Unproved properties	485,568				545,588				521,659
		5,476,321				4,781,300				4,344,040
	Accumulated depreciation, depletion, amortization, and impairment	(2,786,678		)		(2,439,458		)		(2,216,787		)
	Net capitalized costs	$	2,689,643			$	2,341,842			$	2,127,253
	Cost incurred:
	Unproved properties acquired	$	76,041			$	76,304			$	420,467
	Proved properties acquired	5,723				—				225,669
	Exploration	68,811				33,373				46,467
	Development	615,252				424,314				390,649
	Asset retirement obligation	(37,687		)		(17,951		)		45,097
	Total costs incurred	$	728,140			$	516,040			$	1,128,349
	The following table shows a summary of the oil and natural gas property costs not being amortized at December 31, 2014, by the year in which such costs were incurred:
		2014				2013				2012			2011 and Prior		Total
		(In thousands)
	Unproved properties acquired and wells in progress	$	102,930			$	64,795			$	310,891		$	6,952	$	485,568
	Unproved properties not subject to amortization relates to properties which are not individually significant and consist primarily of lease acquisition costs. The evaluation process associated with these properties has not been completed and therefore, the company is unable to estimate when these costs will be included in the amortization calculation.
	The results of operations for producing activities are as follows:
		2014				2013				2012
		(In thousands)
	Revenues	$	723,566			$	633,792			$	557,003
	Production costs	(165,315		)		(162,822		)		(131,389		)
	Depreciation, depletion, amortization, and impairment	(347,220		)		(222,672		)		(492,475		)
		211,031				248,298				(66,861		)
	Income tax (expense) benefit	(82,028		)		(96,091		)		27,533
	Results of operations for producing activities (excluding corporate overhead and financing costs)	$	129,003			$	152,207			$	(39,328	)
	Estimated quantities of proved developed oil, NGLs, and natural gas reserves and changes in net quantities of proved developed and undeveloped oil, NGLs, and natural gas reserves were as follows:
		Oil			NGLs			Natural Gas
		Bbls			Bbls			Mcf
		(In thousands)
	2014
	Proved developed and undeveloped reserves:
	Beginning of year	21,765			41,205			581,784
	Revision of previous estimates (1)	(3,174	)		(2,266	)		(32,790	)
	Extensions and discoveries	5,327			10,850			113,541
	Infill reserves in existing proved fields	2,775			3,577			47,189
	Purchases of minerals in place	236			88			368
	Production	(3,844	)		(4,629	)		(58,854	)
	Sales	(418	)		(296	)		(4,277	)
	End of year	22,667			48,529			646,961
	Proved developed reserves:
	Beginning of year	15,594			30,437			464,234
	End of year	17,448			35,850			500,950
	Proved undeveloped reserves:
	Beginning of year	6,171			10,768			117,550
	End of year	5,219			12,679			146,011
	2013
	Proved developed and undeveloped reserves:
	Beginning of year	21,998			35,166			555,647
	Revision of previous estimates (1)	(2,113	)		836			2,421
	Extensions and discoveries	4,678			7,273			68,611
	Infill reserves in existing proved fields	2,299			1,945			21,573
	Purchases of minerals in place	—			—			11
	Production	(3,360	)		(3,914	)		(56,757	)
	Sales	(1,737	)		(101	)		(9,722	)
	End of year	21,765			41,205			581,784
	Proved developed reserves:
	Beginning of year	16,441			25,657			452,844
	End of year	15,594			30,437			464,234
	Proved undeveloped reserves:
Beginning of year	5,557			9,509			102,803
End of year	6,171			10,768			117,550
2012
Proved developed and undeveloped reserves:
Beginning of year	20,255			22,087			442,135
Revision of previous estimates (1)	(1,747	)		(2,682	)		(55,110	)
Extensions and discoveries	5,014			4,819			54,761
Infill reserves in existing proved fields	4,196			3,018			25,057
Purchases of minerals in place	2,830			11,098			141,494
Production	(3,279	)		(2,796	)		(48,930	)
Sales	(5,271	)		(378	)		(3,760	)
End of year	21,998			35,166			555,647
Proved developed reserves:
Beginning of year	15,618			16,649			372,311
End of year	16,441			25,657			452,844
Proved undeveloped reserves:
Beginning of year	4,637			5,438			69,824
End of year	5,557			9,509			102,803
_________________________
-1	Natural gas revisions of previous estimates decreased primarily due to a decline in natural gas prices.
Estimates of oil, NGLs, and natural gas reserves require extensive judgments of reservoir engineering data. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature of such reserve estimates. Indeed the uncertainties inherent in the disclosure are compounded by applying additional estimates of the rates and timing of production and the costs that will be incurred in developing and producing the reserves. The information set forth in this report is, therefore, subjective and, since judgments are involved, may not be comparable to estimates submitted by other oil and natural gas producers. In addition, since prices and costs do not remain static, and no price or cost escalations or de-escalations have been considered, the results are not necessarily indicative of the estimated fair market value of estimated proved reserves, nor of estimated future cash flows.
The standardized measure of discounted future net cash flows (SMOG) was calculated using 12-month average prices and year-end costs and statutory tax rates, adjusted for permanent differences that relate to existing proved oil, NGLs, and natural gas reserves. SMOG as of December 31 is as follows:
	2014				2013				2012
	(In thousands)
Future cash flows	$	6,398,236			$	5,573,119			$	4,522,351
Future production costs	(2,069,636		)		(1,734,985		)		(1,405,773		)
Future development costs	(560,102		)		(571,170		)		(431,673		)
Future income tax expenses	(1,228,533		)		(1,044,608		)		(762,519		)
Future net cash flows	2,539,965				2,222,356				1,922,386
10% annual discount for estimated timing of cash flows	(1,104,221		)		(996,380		)		(842,430		)
Standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves	$	1,435,744			$	1,225,976			$	1,079,956
The principal sources of changes in the standardized measure of discounted future net cash flows were as follows:
	2014				2013				2012
	(In thousands)
Sales and transfers of oil and natural gas produced, net of production costs	$	(558,252	)		$	(470,970	)		$	(425,626	)
Net changes in prices and production costs	(33,259		)		188,826				(321,099		)
Revisions in quantity estimates and changes in production timing	(135,125		)		(10,650		)		(148,648		)
Extensions, discoveries, and improved recovery, less related costs	635,752				426,377				432,058
Changes in estimated future development costs	96,339				26,629				51,587
Previously estimated cost incurred during the period	164,430				96,457				104,377
Purchases of minerals in place	8,395				9				283,774
Sales of minerals in place	(19,135		)		(43,435		)		(112,359		)
Accretion of discount	179,190				147,579				157,842
Net change in income taxes	(98,119		)		(170,091		)		94,678
Other—net	(30,448		)		(44,711		)		(124,537		)
Net change	209,768				146,020				(7,953		)
Beginning of year	1,225,976				1,079,956				1,087,909
End of year	$	1,435,744			$	1,225,976			$	1,079,956
Certain information concerning the assumptions used in computing SMOG and their inherent limitations are discussed below. We believe this information is essential for a proper understanding and assessment of the data presented.
The assumptions used to compute SMOG do not necessarily reflect our expectations of actual revenues to be derived from those reserves nor their present worth. Assigning monetary values to the reserve quantity estimation process does not reduce the subjective and ever-changing nature of reserve estimates. Additional subjectivity occurs when determining present values because the rate of producing the reserves must be estimated. In addition to difficulty inherent in predicting the future, variations from the expected production rate could result from factors outside of our control, such as unintentional delays in development, environmental concerns or changes in prices or regulatory controls. Also, the reserve valuation assumes that all reserves will be disposed of by production. However, other factors such as the sale of reserves in place could affect the amount of cash eventually realized.
The December 31, 2014, future cash flows were computed by applying the unescalated 12-month average prices of $94.99 per barrel for oil, $45.25 per barrel for NGLs, and $4.36 per Mcf for natural gas (then adjusted for price differentials) relating to proved reserves and to the year-end quantities of those reserves. Future price changes are considered only to the extent provided by contractual arrangements in existence at year-end.
Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil, NGLs, and natural gas reserves at the end of the year, based on continuation of existing economic conditions.
Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the future pretax net cash flows relating to proved oil, NGLs, and natural gas reserves less the tax basis of our properties. The future income tax expenses also give effect to permanent differences and tax credits and allowances relating to our proved oil, NGLs, and natural gas reserves.
Care should be exercised in the use and interpretation of the above data. As production occurs over the next several years, the results shown may be significantly different as changes in production performance, petroleum prices and costs are likely to occur.

Schedule_II_Valuation_And_Qual

Schedule II - Valuation And Qualifying Accounts And Reserves	12 Months Ended
	Dec. 31, 2014
Valuation and Qualifying Accounts [Abstract]
Valuation And Qualifying Accounts And Reserves	Allowance for Doubtful Accounts:
	Description	Balance at		Additions		Deductions			Balance at
		Beginning		Charged to		& Net			End of
		of Period		Costs &		Write-Offs			Period
				Expenses
		(In thousands)
	Year ended December 31, 2014	$	5,342	$	3,562	$	(3,865	)	$	5,039
	Year ended December 31, 2013	$	5,343	$	—	$	(1	)	$	5,342
	Year ended December 31, 2012	$	5,343	$	90	$	(90	)	$	5,343

Summary_Of_Significant_Account1

Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Principles of Consolidation	The consolidated financial statements include the accounts of Unit Corporation and its subsidiaries. Our investment in limited partnerships is accounted for on the proportionate consolidation method, whereby our share of the partnerships’ assets, liabilities, revenues, and expenses are included in the appropriate classification in the accompanying consolidated financial statements.
	Certain amounts in the accompanying 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.
Accounting Estimates	The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Drilling Contracts	We recognize revenues and expenses generated from “daywork” drilling contracts as the services are performed, since we do not bear the risk of completion of the well. Under “footage” and “turnkey” contracts, we bear the risk of completion of the well; therefore, revenues and expenses are recognized when the well is substantially completed. Under this method, substantial completion is determined when the well bore reaches the negotiated depth as stated in the contract. The entire amount of a loss, if any, is recorded when the loss is determinable. The costs of uncompleted drilling contracts include expenses incurred to date on “footage” or “turnkey” contracts, which are still in process at the end of the period, and are included in other current assets. Typically, any one of these three types of contracts can be used for the drilling of one well which can take from 20 to 90 days. At December 31, 2014, all of our contracts were daywork contracts of which 30 were multi-well and had durations which ranged from six months to three years, 26 of which expire in 2015 and four expiring in 2016. These longer term contracts may contain a fixed rate for the duration of the contract or provide for the periodic renegotiation of the rate within a specific range from the existing rate.
Cash Equivalents and Book Overdrafts	We include as cash equivalents all investments with maturities at date of purchase of three months or less which are readily convertible into known amounts of cash. Book overdrafts are checks that have been issued before the end of the period, but not presented to our bank for payment before the end of the period. At December 31, 2014, book overdrafts were $27.8 million. There were no book overdrafts at December 31, 2013.
Accounts Receivable	Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been unsuccessful.
Financial Instruments and Concentrations Of Credit Risk and Non-Performance Risk	Financial instruments, which potentially subject us to concentrations of credit risk, consist primarily of trade receivables with a variety of oil and natural gas companies. We do not generally require collateral related to receivables. Our credit risk is considered to be limited due to the large number of customers comprising our customer base. Below are the third-party customers that accounted for more than 10% of our segment’s revenues:
		2014		2013		2012
	Oil and Natural Gas:
	Valero Energy Corporation	24	%	25	%	26	%
	Sunoco Partners Marketing	14	%	8	%	8	%
	Drilling:
	QEP Resources, Inc.	19	%	18	%	15	%
	Whiting Petroleum Corp. (formerly Kodiak Oil and Gas Corp.)	9	%	10	%	10	%
	Mid-Stream:
	ONEOK Partners, L.P.	44	%	57	%	54	%
	Tenaska Resources, LLC	22	%	16	%	7	%
	Laclede Gas Company	10	%	2	%	—	%
	Gavilon, LLC	—	%	—	%	10	%
	We had a concentration of cash of $18.4 million and $52.1 million at December 31, 2014 and 2013, respectively with one bank.
	The use of derivative transactions also involves the risk that the counterparties will be unable to meet the financial terms of the transactions. We considered this non-performance risk with regard to our counterparties and our own non-performance risk in our derivative valuation at December 31, 2014 and determined there was no material risk at that time. At December 31, 2014, the fair values of the net assets (liabilities) we had with each of the counterparties with respect to all of our commodity derivative transactions are listed in the table below:
		31-Dec-14
		(In millions)
	Bank of Montreal	$	27.8
	Scotiabank	3.3
	Total assets	$	31.1
Property and Equipment	Drilling equipment, transportation equipment, gas gathering and processing systems, and other property and equipment are carried at cost less accumulated depreciation. Renewals and enhancements are capitalized while repairs and maintenance are expensed. Depreciation of drilling equipment is recorded using the units-of-production method based on estimated useful lives starting at 15 years , including a minimum provision of 20% of the active rate when the equipment is idle. We use the composite method of depreciation for drill pipe and collars and calculate the depreciation by footage actually drilled compared to total estimated remaining footage. Depreciation of other property and equipment is computed using the straight-line method over the estimated useful lives of the assets ranging from 3 to 15 years.
	We review the carrying amounts of long-lived assets for potential impairment annually, typically during the fourth quarter, or when events occur or changes in circumstances suggest that these carrying amounts may not be recoverable. Changes that could prompt such an assessment may include equipment obsolescence, changes in the market demand for a specific asset, changes in commodity prices, periods of relatively low rig utilization, declining revenue per day, declining cash margin per day, or overall changes in general market conditions. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. The estimate of fair value is based on the best information available, including prices for similar assets. Changes in these estimates could cause us to reduce the carrying value of property and equipment. Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets and reflect management’s assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates, and costs. The use of different estimates and assumptions could result in materially different carrying values of our assets.
	On a periodic basis, we evaluate our fleet of drilling rigs for marketability based on the condition of inactive rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type. The components comprising inactive rigs are evaluated, and those components with continuing utility to the Company’s other marketed rigs are transferred to other rigs or to its yards to be used as spare equipment. The remaining components of these rigs are retired. In December 2014, we removed from service 31 drilling rigs, some older top drives, and certain drill pipe no longer marketable in the current economic environment. We estimated the fair value of the rigs and other assets based on the estimate market value from third-party assessments (Level 3 fair value measurement). Based on these estimates, we recorded a write-down of approximately $74.3 million, pre-tax. When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed from the accounts and any resulting gain or loss is generally reflected in operations. For dispositions of drill pipe and drill collars, an average cost for the appropriate feet of drill pipe and drill collars is removed from the asset account and charged to accumulated depreciation and proceeds, if any, are credited to accumulated depreciation.
	In December 2014, our mid-stream segment had a $7.1 million, pre-tax write-down of three of its systems, Weatherford, Billy Rose, and Spring Creek due to anticipated future cash flow and future development around these systems supporting their carrying value. The estimated future cash flows were less than the carrying value on these systems (Level 3 fair value measurement). In December 2012, our mid-stream segment had a $1.2 million write-down of its Erick system. There was no volume from the wells connected to this system, the compressor and related surface equipment have been removed from this location and there is no future activity anticipated from this gathering system. No significant impairments were recorded in 2013.
	We record an asset and a liability equal to the present value of the expected future ARO associated with our oil and gas properties. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by accreting an interest charge. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense.
Capitalized Interest	During 2014, 2013, and 2012, interest of approximately $32.2 million, $33.7 million, and $18.9 million, respectively, was capitalized based on the net book value associated with unproved properties not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems. Interest is being capitalized using a weighted average interest rate based on our outstanding borrowings.
Goodwill	Goodwill represents the excess of the cost of acquisitions over the fair value of the net assets acquired. Goodwill is not amortized, but an impairment test is performed at least annually to determine whether the fair value has decreased and is performed additionally when events indicate an impairment may have occurred. For purposes of impairment testing, goodwill is evaluated at the reporting unit level. Our goodwill is all related to our contract drilling segment, and accordingly, the impairment test is generally based on the estimated discounted future net cash flows of our drilling segment, utilizing discount rates and other factors in determining the fair value of our drilling segment. Inputs in our estimated discounted future net cash flows include rig utilization, day rates, gross margin percentages, and terminal value (these are all considered level 3 inputs). No goodwill impairment was recorded for the years ended December 31, 2014, 2013, or 2012. There were no additions to goodwill in 2014, 2013, or 2012. Goodwill of $3.1 million is deductible for tax purposes.
Intangible Assets	Intangible assets are capitalized and amortized over the estimated period benefited. Such amounts are reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. No intangible asset impairment was recorded for the years ended December 31, 2014, 2013, or 2012. Amortization of $0.7 million and $1.2 million was recorded in 2013 and 2012, respectively. Accumulated amortization for 2013 and 2012 was $18.0 million and $17.3 million, respectively. Our intangible assets became fully amortized in 2013, so no amortization was recorded in 2014.
Oil and Natural Gas Operations	We account for our oil and natural gas exploration and development activities using the full cost method of accounting prescribed by the SEC. Accordingly, all productive and non-productive costs incurred in connection with the acquisition, exploration and development of our oil, NGLs, and natural gas reserves, including directly related overhead costs and related asset retirement costs, are capitalized and amortized on a units-of-production method based on proved oil and natural gas reserves. Directly related overhead costs of $23.7 million, $21.5 million, and $17.6 million were capitalized in 2014, 2013, and 2012, respectively. Independent petroleum engineers annually audit our internal evaluation of our reserves. The average rates used for depreciation, depletion, and amortization (DD&A) were $14.82, $13.32, and $14.70 per Boe in 2014, 2013, and 2012, respectively. The calculation of DD&A includes estimated future expenditures to be incurred in developing proved reserves and estimated dismantlement and abandonment costs, net of estimated salvage values. Our unproved properties totaling $485.6 million are excluded from the DD&A calculation.
	No gains or losses are recognized on the sale, conveyance, or other disposition of oil and natural gas properties unless a significant reserve amount to our total reserves is involved.
	Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties.
	Under the full cost rules, at the end of each quarter, we review the carrying value of our oil and natural gas properties. The full cost ceiling is based principally on the estimated future discounted net cash flows from our oil and natural gas properties discounted at 10%. We use the unweighted arithmetic average of the commodity prices existing on the first day of each of the 12 months before the end of the reporting period to calculate discounted future revenues, unless prices were otherwise determined under contractual arrangements. In the event the unamortized cost of oil and natural gas properties being amortized exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period during which such excess occurs. 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 at June 30, 2012, consisted of swaps and collars, covering production of 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.
	For the quarter ended December 31, 2012, the 12-month average commodity prices, including the discounted value of our cash flow hedges, decreased further, resulting in an additional non-cash ceiling test write-down of $167.7 million pre-tax ($104.4 million, net of tax). Our qualifying cash flow hedges used in the ceiling test determination at December 31, 2012, consisted of swaps and collars covering 6.9 MMBoe in 2013. The effect of those hedges on the December 31, 2012 ceiling test was a $29.8 million pre-tax increase in the discounted net cash flows of our oil and natural gas properties. Our oil and natural gas derivatives are discussed in Note 13 of the Notes to our Consolidated Financial Statements.
	In December 2014, we determined the value of certain unproved oil and gas properties were diminished (in part or in whole) based on an impairment evaluation and our anticipated future exploration plans. That determination resulted in $73.7 million of costs associated with the unproved properties being added to the capitalized costs to be amortized. We incurred a non-cash ceiling test write-down of our oil and natural gas properties of $76.7 million pre-tax ($47.7 million net of tax). Subsequent to December 31, 2014, commodity prices have continued to decrease below December 31, 2014 levels. We anticipate that these reduced prices will require an additional write-down of the carrying value of our oil and natural gas properties for the quarter ending March 31, 2015 and potentially subsequent quarters.
	Our contract drilling segment provides drilling services for our exploration and production segment. Depending on their timing some of the drilling services performed on our properties are also deemed to be associated with the acquisition of an ownership interest in the property. Revenues and expenses for such services are eliminated in our income statement, with any profit recognized as a reduction in our investment in our oil and natural gas properties. The contracts for these services are issued under the same conditions and rates as the contracts entered into with unrelated third parties. We eliminated revenue of $89.5 million, $64.3 million, and $49.6 million for 2014, 2013, and 2012, respectively from our contract drilling segment and eliminated the associated operating expense of $62.4 million, $46.9 million, and $34.1 million during 2014, 2013, and 2012, respectively, yielding $27.1 million, $17.4 million, and $15.5 million during 2014, 2013, and 2012, respectively, as a reduction to the carrying value of our oil and natural gas properties.
Gas Gathering and Processing Revenue	Our gathering and processing segment recognizes revenue from the gathering and processing of natural gas and NGLs in the period the service is provided based on contractual terms.
Insurance	We are self-insured for certain losses relating to workers’ compensation, control of well and employee medical benefits. Insured policies for other coverage contain deductibles or retentions per occurrence that range from zero to $1.5 million. We have purchased stop-loss coverage in order to limit, to the extent feasible, per occurrence and aggregate exposure to certain types of claims. However, there is no assurance that the insurance coverage will adequately protect us against liability from all potential consequences. We have elected to use an ERISA governed occupational injury benefit plan to cover all Texas drilling operations in lieu of covering them under Texas Workers’ Compensation. If insurance coverage becomes more expensive, we may choose to self-insure, decrease our limits, raise our deductibles or any combination of these rather than pay higher premiums.
Derivative Activities	All derivatives are recognized on the balance sheet and measured at fair value. 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 Consolidated Statements of Income. The commodity derivative instruments we had under cash flow accounting expired as of December 2013. Previous changes in the fair value of derivatives designated as cash flow hedges, to the extent they were effective in offsetting cash flows attributable to the hedged risk, were recorded in OCI until the hedged item was recognized into earnings. When the hedged item was recognized into earnings, it was reported in oil and natural gas revenues. Any change in fair value resulting from ineffectiveness was recognized in gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net. In August 2012, we determined on a prospective basis, to enter into economic hedges without electing cash flow hedge accounting.
	We do not engage in derivative transactions for speculative purposes. We document our risk management strategy, and for the cash flow hedges, we tested the hedge effectiveness at the inception of and during the term of each hedge.
Limited Partnerships	Unit Petroleum Company is a general partner in 15 oil and natural gas limited partnerships sold privately and publicly. Some of our officers, directors, and employees own the interests in most of these partnerships. We share in each partnership’s revenues and costs in accordance with formulas set out in each of the limited partnership agreement. The partnerships also reimburse us for certain administrative costs incurred on behalf of the partnerships.
Income Taxes	Measurement of current and deferred income tax liabilities and assets is based on provisions of enacted tax law; the effects of future changes in tax laws or rates are not included in the measurement. Valuation allowances are established where necessary to reduce deferred tax assets to the amount expected to be realized. Income tax expense is the tax payable for the year and the change during that year in deferred tax assets and liabilities.
	The accounting for uncertainty in income taxes prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a return. Guidance is also provided on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. We have $0.4 million of unrecognized tax benefits.
Natural Gas Balancing	We use the sales method for recording natural gas sales. This method allows for recognition of revenue, which may be more or less than its share of pro-rata production from certain wells. We estimate our December 31, 2014 balancing position to be approximately 5.1 Bcf on under-produced properties and approximately 4.4 Bcf on over-produced properties. We have recorded a receivable of $2.0 million on certain wells where we estimate that insufficient reserves are available for us to recover the under-production from future production volumes. We have also recorded a liability of $3.6 million on certain properties where we believe there are insufficient reserves available to allow the under-produced owners to recover their under-production from future production volumes. Our policy is to expense the pro-rata share of lease operating costs from all wells as incurred. Such expenses relating to the balancing position on wells in which we have imbalances are not material.
Employee And Director Stock Based Compensation	We recognize in our financial statements the cost of employee services received in exchange for awards of equity instruments based on the grant date fair value of those awards. The amount of our equity compensation cost relating to employees directly involved in exploration activities of our oil and natural gas segment is capitalized to our oil and natural gas properties. Amounts not capitalized to our oil and natural gas properties are recognized in general and administrative expense and operating costs of our business segments. We utilize the Black-Scholes option pricing model to measure the fair value of stock options and stock appreciation rights (SARs). The value of our restricted stock grants is based on the closing stock price on the date of the grants.
Impact of Financial Accounting Pronouncements	Presentation of Financial Statements-Going Concern: Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. The FASB has issued ASU 2014-15. This is intended to define management's responsibility to evaluate whether there is substantial doubt about an organization's ability to continue as a going concern and to provide related footnote disclosures. For each reporting period, management will be required to evaluate whether there are conditions or events that raise substantial doubt about a company's ability to continue as a going concern within one year from the date financial statements are issued. The amendments are effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016. Early application is permitted for annual or interim reporting periods for which the financial statements have not previously been issued.
	Compensation - Stock Compensation: Accounting for Share-Based Payments When the Terms of an Award Provide that a Performance Target Could Be Achieved after the Requisite Service Period. The FASB has issued ASU 2014-12, the amendments in the ASU require that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. A reporting entity should apply existing guidance in Topic 718, Compensation – Stock Compensation, as it relates to awards with performance conditions that affect vesting to account for such awards. The performance target should not be reflected in estimating the grant-date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved.The amendments in this ASU are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Earlier adoption is permitted. We do not have any stock compensation awards with these conditions at this time.
	Revenue from Contracts with Customers. The FASB has issued ASU 2014-09. This affects any entity using U.S. GAAP that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (e.g., insurance contracts or lease contracts). The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early application is not permitted. We are in the process of evaluating the impact it will have on our financial statements.
	Presentation of Financial Statements and Property, Plant, and Equipment: Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The FASB has issued ASU 2014-08, the amendments in this update change the criteria for reporting discontinued operations while enhancing disclosures in this area. It also addresses sources of confusion and inconsistent application related to financial reporting of discontinued operations guidance in U.S. GAAP. Under the new guidance, only disposals representing a strategic shift that would have a major effect on the organization's operations and financial results should be presented as discontinued operations. In addition, it requires expanded disclosures about discontinued operations that will provide financial statement users with more information about the assets, liabilities, income, and expenses of discontinued operations. It also requires disclosure of pre-tax income attributable to a disposal of a significant part of an organization that does not qualify for discontinued operations reporting. The updates are effective for fiscal years, and interim periods within those years, beginning after December 15, 2014. Early adoption is permitted. We currently do not have any discontinued operations or disposals of components of an entity.

Summary_Of_Significant_Account2

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Schedule of Segment's Revenue [Table Text Block]	Below are the third-party customers that accounted for more than 10% of our segment’s revenues:
		2014		2013		2012
	Oil and Natural Gas:
	Valero Energy Corporation	24	%	25	%	26	%
	Sunoco Partners Marketing	14	%	8	%	8	%
	Drilling:
	QEP Resources, Inc.	19	%	18	%	15	%
	Whiting Petroleum Corp. (formerly Kodiak Oil and Gas Corp.)	9	%	10	%	10	%
	Mid-Stream:
	ONEOK Partners, L.P.	44	%	57	%	54	%
	Tenaska Resources, LLC	22	%	16	%	7	%
	Laclede Gas Company	10	%	2	%	—	%
	Gavilon, LLC	—	%	—	%	10	%
Schedule Of Fair Values Of The Net Assets (Liabilities) [Table Text Block]	At December 31, 2014, the fair values of the net assets (liabilities) we had with each of the counterparties with respect to all of our commodity derivative transactions are listed in the table below:
		31-Dec-14
		(In millions)
	Bank of Montreal	$	27.8
	Scotiabank	3.3
	Total assets	$	31.1

Acquisitions_and_Divestitures_

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2014
Acquisitions and divestitures [Abstract]
Schedule of Purchase Price Allocation [Table Text Block]	The Noble acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which required that the acquired assets and liabilities be recorded at their fair values as of the acquisition date. The following table summarizes the adjusted purchase price and the estimated values of assets acquired and liabilities assumed. It was based on information available to us at the time these consolidated financial statements were prepared and we believe these estimates are reasonable(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
	Unproved oil and natural gas properties	353,343
	Total oil and natural gas properties included in the full cost pool (1)	614,142
	Gas gathering and processing equipment and other	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 [Table Text Block]	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, 2012. 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 Notes issued along with additional borrowings under our credit agreement 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.
		Twelve months ended December 31,
		2012
		(In thousands, except per share amounts)
	Pro forma:
	Revenues	$	1,376,393
	Net income	$	83,940
	Net income per common share:
	Basic	$	1.75
	Diluted	$	1.74

Earnings_Per_Share_Earnings_Pe

Earnings Per Share Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Schedule of Earnings Per Share [Table Text Block]	The following data shows the amounts used in computing earnings per share:
		Income		Weighted		Per-Share
		(Numerator)		Shares		Amount
				(Denominator)
		(In thousands except per share amounts)
	For the year ended December 31, 2014:
	Basic earnings per common share	$	136,276	48,611		$	2.8
	Effect of dilutive stock options, restricted stock, and SARs	—		472		(0.02		)
	Diluted earnings per common share	$	136,276	49,083		$	2.78
	For the year ended December 31, 2013:
	Basic earnings per common share	$	184,746	48,218		$	3.83
	Effect of dilutive stock options, restricted stock, and SARs	—		354		(0.03		)
	Diluted earnings per common share	$	184,746	48,572		$	3.8
	For the year ended December 31, 2012:
	Basic earnings per common share	$	23,176	47,909		$	0.48
	Effect of dilutive stock options, restricted stock, and SARs	—		245		—
	Diluted earnings per common share	$	23,176	48,154		$	0.48
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share [Table Text Block]	The following options and their average exercise prices were not included in the computation of diluted earnings per share because the option exercise prices were greater than the average market price of our common stock for the years ended December 31:
		2014		2013			2012
	Options and SARs	73,500		149,665			250,901
	Average exercise price	$	64.43	$	58.41		$	52.72

Accrued_Liabilities_Tables

Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2014
Accrued Liabilities [Abstract]
Accrued Liabilities [Table Text Block]	Accrued liabilities consisted of the following as of December 31:
		2014		2013
		(In thousands)
	Employee costs	$	31,451	$	27,633
	Lease operating expenses	20,709		16,073
	Interest payable	6,654		6,504
	Taxes	3,284		2,313
	Deposits on assets held for sale	—		3,750
	Derivative settlements	—		416
	Other	8,073		7,674
	Total accrued liabilities	$	70,171	$	64,363

LongTerm_Debt_And_Other_LongTe1

Long-Term Debt And Other Long-Term Liabilities (Tables)	12 Months Ended
	Dec. 31, 2014
Long-term debt and other long-term liabilites [Abstract]
Long Term Debt [Table Text Block]	Long-term debt consisted of the following as of December 31:
		2014			2013
		(In thousands)
	Credit agreement with an average interest rates of 2.9% at December 31, 2014	$	166,000		$	—
	6.625% senior subordinated notes due 2021, net of unamortized discount of $3.8 million and $4.3 million at December 31, 2014 and 2013, respectively	646,163			645,696
	Total long-term debt	$	812,163		$	645,696
Other Long Term Liabilities [Table Text Block]	Other long-term liabilities consisted of the following as of December 31:
		2014			2013
		(In thousands)
	ARO liability	$	100,567		$	133,657
	Capital lease obligations	25,876			—
	Workers’ compensation	17,997			20,041
	Separation benefit plans	11,276			9,382
	Gas balancing liability	3,623			3,775
	Deferred compensation plan	4,055			3,589
	Other	410			—
		163,804			170,444
	Less current portion	15,019			12,113
	Total other long-term liabilities	$	148,785		$	158,331
Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block]	Future payments required under the capital leases at December 31, 2014 are as follows:
			Amount
	Ending December 31,		(In thousands)
	2015		$	6,195
	2016		6,195
	2017		6,195
	2018		6,195
	2019		6,195
	2020 and thereafter		9,967
	Total future payments		40,942
	Less payments related to:
	Maintenance		11,395
	Interest		3,671
	Present value of future minimum payments		$	25,876

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Schedule Of Asset Retirement Obligations [Table Text Block]	The following table shows certain information about our AROs for the periods indicated:
		2014			2013
		(In thousands)
	ARO liability, January 1:	$	133,657		$	146,159
	Accretion of discount	4,599			5,450
	Liability incurred	6,246			4,857
	Liability settled	(4,490		)	(4,751		)
	Liability sold	(1,206		)	(2,622		)
	Revision of estimates (1)	(38,239		)	(15,436		)
	ARO liability, December 31:	100,567			133,657
	Less current portion	3,204			2,954
	Total long-term ARO liability	$	97,363		$	130,703
	_________________________
	-1	Plugging liability estimates were revised in both 2014 and 2013 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.

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Reconciliation Of Income Tax Expense [Table Text Block]	A reconciliation of income tax expense, computed by applying the federal statutory rate to pre-tax income to our effective income tax expense is as follows:
		2014			2013			2012
		(In thousands)
	Income tax expense computed by applying the statutory rate	$	78,029		$	105,514		$	13,791
	State income tax, net of federal benefit	6,131			8,290			1,084
	Statutory depletion and other	2,503			2,919			1,351
	Income tax expense	$	86,663		$	116,723		$	16,226
Schedule Of Total Provision For Income Taxes [Table Text Block]	For the periods indicated, the total provision for income taxes consisted of the following:
		2014			2013			2012
		(In thousands)
	Current taxes:
	Federal	$	8,594		$	15,845		$	2,084
	State	784			146			(1,388		)
		9,378			15,991			696
	Deferred taxes:
	Federal	68,360			87,839			13,768
	State	8,925			12,893			1,762
		77,285			100,732			15,530
	Total provision	$	86,663		$	116,723		$	16,226
Schedule Of Deferred Tax Assets And Liabilities [Table Text Block]	Deferred tax assets and liabilities are comprised of the following at December 31:
		2014			2013
		(In thousands)
	Deferred tax assets:
	Allowance for losses and nondeductible accruals	$	55,231		$	77,285
	Net operating loss carryforward	54,901			61,055
	Alternative minimum tax and research and development tax credit carryforward	25,991			17,258
		136,123			155,598
	Deferred tax liability:
	Depreciation, depletion, amortization, and impairment	(1,000,811		)	(943,411		)
	Net deferred tax liability	(864,688		)	(787,813		)
	Current deferred tax asset	11,527			13,585
	Non-current—deferred tax liability	$	(876,215	)	$	(801,398	)
Schedule of Unrecognized Tax Benefits [Table Text Block]	A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
		2014			2013			2012
		(In thousands)
	Balance at January 1:	$	—		$	—		$	—
	Additions based on tax positions related to current year	410			—			—
	Additions for tax positions of prior years	—			—			—
	Reductions for tax positions of prior years	—			—			—
	Settlements	—			—			—
	Balance at December 31:	$	410		$	—		$	—

Transactions_With_Related_Part1

Transactions With Related Parties (Tables)	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Schedule Of Amount Received In Public And Private Partnerships [Table Text Block]	Amounts received in the years ended December 31, from both public and private Partnerships for which Unit is a general partner are as follows:
		2014		2013		2012
		(In thousands)
	Contract drilling	$	4	$	16	$	246
	Well supervision and other fees	435		470		434
	General and administrative expense reimbursement	39		36		39

StockBased_Compensation_Tables

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule Of Restricted Stock Awards Stock Options And SAR [Table Text Block]	For restricted stock awards and stock options, we had:
		2014				2013			2012
		(In millions)
	Recognized stock compensation expense	$	17.4			$	16.1		$	11.4
	Capitalized stock compensation cost for our oil and natural gas properties	3.7				3.5			2.7
	Tax benefit on stock based compensation	6.7				6.2			4.5
Activity Pertaining to Stock Appreciation Rights [Table Text Block]	Activity pertaining to SARs granted under the Unit Corporation Stock and Incentive Compensation Plan is as follows:
		Number of			Weighted
		Shares			Average
					Price
	Outstanding at January 1, 2012	145,901			$	46.59
	Granted	—			—
	Exercised	—			—
	Forfeited	—			—
	Outstanding at December 31, 2012	145,901			46.59
	Granted	—			—
	Exercised	—			—
	Forfeited	—			—
	Outstanding at December 31, 2013	145,901			46.59
	Granted	—			—
	Exercised	(14,131	)		46.5
	Forfeited	—			—
	Outstanding at December 31, 2014	131,770			$	46.6
Shares Authorized Under Stock Appreciation Rights By Exercise Price [Table Text Block]
		Outstanding and exercisable SARs at
		31-Dec-14
	Exercise Prices	Number		Weighted Average Remaining		Weighted Average
		of Shares		Contractual Life		Exercise Price
	$44.31	91,255		3.0 years		$44.31
	$51.76	40,515		1.9 years		$51.76
Activity Pertaining To Restricted Stock Awards [Table Text Block]	Activity pertaining to restricted stock awards granted under the amended plan is as follows:
	Employees	Number of			Weighted
		Shares			Average
					Price
	Nonvested at January 1, 2012	447,961			$	47.44
	Granted	376,445			47.37
	Vested	(220,788	)		45.66
	Forfeited	(14,091	)		45.37
	Nonvested at December 31, 2012	589,527			48.11
	Granted	453,549			48.2
	Vested	(248,003	)		46.46
	Forfeited	(18,330	)		47.85
	Nonvested at December 31, 2013	776,743			48.7
	Granted	455,122			53.72
	Vested	(304,804	)		49.68
	Forfeited	(26,775	)		51.92
	Nonvested at December 31, 2014	900,286			$	50.81
	Non-Employee Directors	Number of			Weighted
		Shares			Average
					Price
	Nonvested at January 1, 2012	—			$	—
	Granted	24,606			40.23
	Vested	—			—
	Forfeited	—			—
	Nonvested at December 31, 2012	24,606			$	40.23
	Granted	21,128			41.65
	Vested	(10,030	)		40.23
	Forfeited	—			—
	Nonvested at December 31, 2013	35,704			$	41.07
	Granted	13,768			63.91
	Vested	(14,336	)		40.93
	Forfeited	—			—
	Nonvested at December 31, 2014	35,136			$	50.08
Activity Pertaining to the Stock Option Plan [Table Text Block]	Activity pertaining to the Stock Option Plan is as follows:
		Number of			Weighted
		Shares			Average
					Exercise
					Price
	Outstanding at January 1, 2012	138,980			$	31.39
	Granted	—			—
	Exercised	(18,850	)		20.38
	Forfeited	(2,100	)		37.83
	Outstanding at December 31, 2012	118,030			33.03
	Granted	—			—
	Exercised	(48,110	)		26.09
	Forfeited	(1,000	)		37.83
	Outstanding at December 31, 2013	68,920			37.81
	Granted	—			—
	Exercised	(21,490	)		37.83
	Forfeited	(37,930	)		37.83
	Outstanding at December 31, 2014	9,500			$	37.69
Shares Authorized Under Stock Option Plans By Exercise Price Range [Table Text Block]
		Outstanding and Exercisable Options at December 31, 2014
	Exercise Price	Number		Weighted Average Remaining		Weighted Average
		of Shares		Contractual Life		Exercise Price
	$37.69	9,500		0.4 years		$37.69
Activity Pertaining to Nonemployee Director Stock Award Plan [Table Text Block]	Activity pertaining to the Directors’ Plan is as follows:
		Number of			Weighted
		Shares			Average
					Exercise
					Price
	Outstanding at January 1, 2012	199,500			$	48.37
	Granted	—			—
	Exercised	(7,000	)		20.28
	Forfeited	—			—
	Outstanding at December 31, 2012	192,500			49.39
	Granted	—			—
	Exercised	(17,500	)		32.53
	Forfeited	(3,500	)		20.46
	Outstanding at December 31, 2013	171,500			51.7
	Granted	—			—
	Exercised	(21,000	)		33.94
	Forfeited	—			—
	Outstanding at December 31, 2014	150,500			$	54.18
Shares Authorized Under Nonemployee Director Option Plans By Exercise Price Range [Table Text Block]
		Outstanding and Exercisable
		Options at December 31, 2014
	Weighted Average Exercise Price	Number			Weighted Average Remaining		Weighted Average
		of Shares			Contractual Life		Exercise Price
	$31.30 - $41.21	45,500			4.2 years		$	37.88
	$53.81 - $73.26	105,000			3.5 years		$	61.24

Derivatives_Tables

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Non-designated Hedges Outstanding [Table Text Block]	At December 31, 2014, the following non-designated hedges were outstanding:
	Term		Commodity	Contracted Volume		Weighted Average	Contracted Market
						Fixed Price for Swaps
	Jan’15 – Dec’15		Natural gas – swap	40,000 MMBtu/day		$3.98	IF – NYMEX (HH)
	Jan’15 – Mar’15		Natural gas – collar	30,000 MMBtu/day		$4.20-$5.03	IF – NYMEX (HH)
	Jan’15 – Dec'15		Crude oil – swap	1,000 Bbl/day		$95.00	WTI – NYMEX
Schedule Of Subsequent Non-designated Hedges [Table Text Block]	Subsequent to December 31, 2014, the following non-designated hedges were entered into:
	Term		Commodity	Contracted Volume		Weighted Average	Contracted Market
						Fixed Price for Swaps
	Apr’15 – Jun'15		Natural gas – swap	30,000 MMBtu/day		$3.10	IF – NYMEX (HH)
	Apr’15 – Jun'15		Natural gas – collar	30,000 MMBtu/day		$2.92-$3.26	IF – NYMEX (HH)
	Jul’15 – Sep'15		Natural gas – collar	30,000 MMBtu/day		$2.58-$3.04	IF – NYMEX (HH)
Fair Value Of Derivative Instruments And Locations In Balance Sheets [Table Text Block]	The following tables present the fair values and locations of the derivative transactions recorded in our Consolidated Balance Sheets at December 31:
				Derivative Assets
				Fair Value
			Balance Sheet Location	2014			2013
				(In thousands)
	Commodity derivatives:
	Current		Current derivative assets	$	31,139		$	515
	Long-term		Non-current derivative assets	—			—
	Total derivative assets			$	31,139		$	515
				Derivative Liabilities
				Fair Value
			Balance Sheet Location	2014			2013
				(In thousands)
	Commodity derivatives:
	Current		Current derivative liabilities	$	—		$	5,561
	Long-term		Non-current derivative liabilities	—			—
	Total derivative liabilities			$	—		$	5,561
Gain Or Loss Of Reclassified Accumulated Other Comprehensive Income And Recognized Income [Table Text Block]	Effect of derivative instruments on the Consolidated Statements of Income (cash flow hedges) for the year ended December 31:
	Derivative Instrument		Location of Gain or (Loss) Reclassified from Accumulated OCI into Income & Location of Gain or (Loss) Recognized in Income	Amount of Gain or (Loss) Reclassified from						Amount of Gain
				Accumulated OCI into						or (Loss) Recognized in Income (2)
				Income (1)
				2014			2013			2014		2013
				(In thousands)
	Commodity derivatives		Oil and natural gas revenue (1)	$	—		$	603		$	—	$	—
	Commodity derivatives		Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net (2)	—			—			—		(190		)
			Total	$	—		$	603		$	—	$	(190	)
	_________________________
	-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 [Table Text Block]	Effect of Derivative Instruments on the Consolidated Statements of Income (derivatives not designated as hedging instruments) for the year ended December 31:
	Derivatives Not Designated as Hedging Instruments		Location of Gain or (Loss)	Amount of Gain or (Loss)
			Recognized in Income on	Recognized in Income on
			Derivative	Derivative
				2014			2013
				(In thousands)
	Commodity derivatives		Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net (1)	$	30,147		$	(8,184	)
	Total			$	30,147		$	(8,184	)
	_________________________
	-1	Amount settled during the period is a loss of $6,038 and $1,764, respectively.

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Recurring Fair Value Measurements [Table Text Block]	The following tables set forth our recurring fair value measurements:
		31-Dec-14
		Level 2				Level 3			Effect of Netting			Total
		(In thousands)
	Financial assets (liabilities):
	Commodity derivatives:
	Assets	$	27,784			$	3,355		$	—		$	31,139
	Liabilities	—				—			—			—
		$	27,784			$	3,355		$	—		$	31,139
		31-Dec-13
		Level 2				Level 3			Effect of Netting			Total
		(In thousands)
	Financial assets (liabilities):
	Commodity derivatives:
	Assets	$	1,978			$	20		$	(1,483	)	$	515
	Liabilities	(4,429		)		(2,615		)	1,483			(5,561		)
		$	(2,451	)		$	(2,595	)	$	—		$	(5,046	)
Reconciliations Of Level 3 Fair Value Measurements [Table Text Block]	The following tables are reconciliations of our level 3 fair value measurements:
		Net Derivatives
		For the Year Ended,
		31-Dec-14				31-Dec-13
		(In thousands)
	Beginning of period	$	(2,595	)		$	(595	)
	Total gains or losses:
	Included in earnings (1)	6,108				(2,637		)
	Included in other comprehensive income (loss)	—				—
	Settlements	(158		)		637
	End of period	$	3,355			$	(2,595	)
	Total gains (losses) for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period	$	5,950			$	(2,000	)
	_________________________
	-1	Commodity sales collars are reported in the consolidated statements of income in oil and gas revenues (for cash flow hedges), and gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net, respectively.
Schedule Of Quantitative Information About Unobservable Inputs [Table Text Block]	The following table provides quantitative information about our Level 3 unobservable inputs at December 31, 2014:
	Commodity (1)	Fair Value			Valuation Technique	Unobservable Input	Range
		(In thousands)
	Natural gas collar	$	3,355		Discounted cash flow	Forward commodity price curve	$0.00 - $1.32
	_________________________
	-1	The commodity contracts detailed in this category include non-exchange-traded natural gas collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be received within the settlement period.

Accumulated_Other_Comprehensiv1

Accumulated Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Changes in accumulated other comprehensive income [Table Text Block]	Changes in accumulated other comprehensive income (loss) by component, net of tax, are as follows:
		Net Gains (Losses) on Cash Flow Hedges
		2014		2013			2012
		(In thousands)
	Balance at January 1:	$	—	$	7,587		$	19,026
	Other comprehensive income before reclassification	—		(7,349		)	18,635
	Amounts reclassified from accumulated other comprehensive income	—		(238		)	(30,074		)
	New current-period other comprehensive income	—		(7,587		)	(11,439		)
	Balance at December 31:	$	—	$	—		$	7,587
Schedule of accumulated other comprehensive income [Table Text Block]	Amounts reclassified from accumulated other comprehensive income (loss) into the Consolidated Statements of Income for the year ended December 31:
		2014		2013			2012			Affected Line Item in the Statement Where Net Income is Presented
		(In thousands)
	Net gains (loss) on cash flow hedges
	Commodity derivatives	$	—	$	603		$	51,853		Oil and natural gas revenues
	Commodity derivatives	—		(190		)	(2,616		)	Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net
		—		413			49,237			Total before tax
		—		(175		)	(19,163		)	Tax expense
	Total reclassification for the period	$	—	$	238		$	30,074		Net of tax

Industry_Segment_Information_T

Industry Segment Information (Tables)	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Revenue From Different Segments [Table Text Block]	The following table provides certain information about the operations of each of our segments:
		2014				2013			2012
		(In thousands)
	Revenues:
	Oil and natural gas	$	740,079			$	649,718		$	567,944
	Contract drilling	566,012				479,091			579,368
	Elimination of inter-segment revenue	(89,495		)		(64,313		)	(49,649		)
	Contract drilling net of inter-segment revenue	476,517				414,778			529,719
	Gas gathering and processing	445,934				378,397			290,773
	Elimination of inter-segment revenue	(89,586		)		(91,043		)	(73,313		)
	Gas gathering and processing net of inter-segment revenue	356,348				287,354			217,460
	Total revenues	$	1,572,944			$	1,351,850		$	1,315,123
	Operating income:
	Oil and natural gas	$	199,392		(5)	$	239,219		$	(77,221	)	(5)
	Contract drilling	41,896			(6)	96,304			159,188
	Gas gathering and processing	2,015			(7)	10,757			5,780			(7)
	Total operating income (1)	243,303				346,280			87,747
	General and administrative	(42,023		)		(38,323		)	(33,086		)
	Gain on disposition of assets	8,953				17,076			253
	Interest expense, net	(17,371		)		(15,015		)	(14,137		)
	Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net	30,147				(8,374		)	(1,243		)
	Other	(70		)		(175		)	(132		)
	Income before income taxes	$	222,939			$	301,469		$	39,402
	Identifiable assets:
	Oil and natural gas	$	2,856,833			$	2,441,792		$	2,214,029
	Contract drilling	1,059,980				1,042,661			1,079,736
	Gas gathering and processing	500,255				473,717			413,708
	Total identifiable assets (2)	4,417,068				3,958,170			3,707,473
	Corporate assets	56,660				64,220			53,647
	Total assets	$	4,473,728			$	4,022,390		$	3,761,120
	Capital expenditures:
	Oil and natural gas (3)	$	740,262			$	531,233		$	1,145,337
	Contract drilling	176,683				64,325			77,520
	Gas gathering and processing	79,268			(4)	96,085			183,162
	Other (3)	17,067				4,483			11,083
	Total capital expenditures	$	1,013,280			$	696,126		$	1,417,102
	Depreciation, depletion, amortization, and impairment:
	Oil and natural gas
	Depreciation, depletion, and amortization	$	276,088			$	226,498		$	211,347
	Impairment of oil and natural gas properties	76,683			(5)	—			283,606			(5)
	Contract drilling	159,688			(6)	71,194			81,007
	Gas gathering and processing	47,502			(7)	33,191			24,388			(7)
	Other	3,051				3,024			2,279
	Total depreciation, depletion, amortization, and impairment	$	563,012			$	333,907		$	602,627
	_________________________
	-1	Operating income is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, (gain) loss on disposition of assets, gain (loss) on non-designated hedges and hedge ineffectiveness, interest expense, other income (loss), or income taxes.
	-2	Identifiable assets are those used in Unit’s operations in each industry segment. Corporate assets are principally cash and cash equivalents, short-term investments, corporate leasehold improvements, furniture and equipment.
	-3	In 2013, we reclassified salt water disposal capital expenditures out of other and into oil and natural gas of $17.0 million for 2012.
	-4	In 2014, we entered into capital leases for $28.2 million.
	-5	In 2014 and 2012, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $76.7 million and $283.6 million pre-tax ($47.7 million and $176.5 million, net of tax), respectively.
	-6	Depreciation, depletion, amortization, and impairment for contract drilling includes a $74.3 million pre-tax write-down for 31 drilling rigs, some older top drives, and certain drill pipe removed from service.
	-7	Depreciation, depletion, amortization, and impairment for gas gathering and processing for 2014 includes a $7.1 million pre-tax write-down for three of our systems, Weatherford, Billy Rose, and Spring Creek and for 2012 includes a $1.2 million write-down of our Erick system.

Selected_Quarterly_Financial_I1

Selected Quarterly Financial Information (Tables)	12 Months Ended
	Dec. 31, 2014
Selected Quarterly Financial Information [Abstract]
Schedule Of Quarterly Financial Information [Table Text Block]	Summarized unaudited quarterly financial information is as follows:
		Three Months Ended
		31-Mar		30-Jun		September 30		December 31
		(In thousands except per share amounts)
	2014
	Revenues	$	387,988	$	405,431	$	400,974	$	378,551
	Gross profit (loss)	$	115,143	$	113,973	$	103,983	$	(89,796	)	(1)
	Net income (loss)	$	56,945	$	54,360	$	67,522	$	(42,551	)
	Net income (loss) per common share:
	Basic	$	1.17	$	1.12	$	1.39	$	(0.88	)
	Diluted	$	1.17	$	1.11	$	1.37	$	(0.88	)	(2)
	2013
	Revenues	$	318,532	$	340,421	$	333,776	$	359,121
	Gross profit	$	83,683	$	90,823	$	79,082	$	92,692		(1)
	Net income	$	40,206	$	59,007	$	34,232	$	51,301
	Net income per common share:
	Basic	$	0.84	$	1.22	$	0.71	$	1.06
	Diluted	$	0.83	$	1.22	$	0.7	$	1.05
	_________________________
	-1	Gross profit excludes general and administrative expense, interest expense, (gain) loss on disposition of assets, gain (loss) on non-designated hedges and hedge ineffectiveness, income taxes, and other income (loss).
	-2	Due to the effect of the loss in the fourth quarter, the diluted earnings per share for the year's four quarters does not equal annual earnings per share.

Supplemental_Oil_And_Gas_Discl1

Supplemental Oil And Gas Disclosures (Tables)	12 Months Ended
	Dec. 31, 2014
Supplemental Oil and Gas Disclosures [Abstract]
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]	The capitalized costs at year-end and costs incurred during the year were as follows:
		2014				2013				2012
		(In thousands)
	Capitalized costs:
	Proved properties	$	4,990,753			$	4,235,712			$	3,822,381
	Unproved properties	485,568				545,588				521,659
		5,476,321				4,781,300				4,344,040
	Accumulated depreciation, depletion, amortization, and impairment	(2,786,678		)		(2,439,458		)		(2,216,787		)
	Net capitalized costs	$	2,689,643			$	2,341,842			$	2,127,253
	Cost incurred:
	Unproved properties acquired	$	76,041			$	76,304			$	420,467
	Proved properties acquired	5,723				—				225,669
	Exploration	68,811				33,373				46,467
	Development	615,252				424,314				390,649
	Asset retirement obligation	(37,687		)		(17,951		)		45,097
	Total costs incurred	$	728,140			$	516,040			$	1,128,349
Schedule Of The Oil And Natural Gas Property Costs Not Being Amortized [Table Text Block]	The following table shows a summary of the oil and natural gas property costs not being amortized at December 31, 2014, by the year in which such costs were incurred:
		2014				2013				2012			2011 and Prior		Total
		(In thousands)
	Unproved properties acquired and wells in progress	$	102,930			$	64,795			$	310,891		$	6,952	$	485,568
Results Of Operations For Producing Activities [Table Text Block]	The results of operations for producing activities are as follows:
		2014				2013				2012
		(In thousands)
	Revenues	$	723,566			$	633,792			$	557,003
	Production costs	(165,315		)		(162,822		)		(131,389		)
	Depreciation, depletion, amortization, and impairment	(347,220		)		(222,672		)		(492,475		)
		211,031				248,298				(66,861		)
	Income tax (expense) benefit	(82,028		)		(96,091		)		27,533
	Results of operations for producing activities (excluding corporate overhead and financing costs)	$	129,003			$	152,207			$	(39,328	)
Schedule Of Proved Developed And Undeveloped Oil And Gas Reserve Quantities [Table Text Block]	Estimated quantities of proved developed oil, NGLs, and natural gas reserves and changes in net quantities of proved developed and undeveloped oil, NGLs, and natural gas reserves were as follows:
		Oil			NGLs			Natural Gas
		Bbls			Bbls			Mcf
		(In thousands)
	2014
	Proved developed and undeveloped reserves:
	Beginning of year	21,765			41,205			581,784
	Revision of previous estimates (1)	(3,174	)		(2,266	)		(32,790	)
	Extensions and discoveries	5,327			10,850			113,541
	Infill reserves in existing proved fields	2,775			3,577			47,189
	Purchases of minerals in place	236			88			368
	Production	(3,844	)		(4,629	)		(58,854	)
	Sales	(418	)		(296	)		(4,277	)
	End of year	22,667			48,529			646,961
	Proved developed reserves:
	Beginning of year	15,594			30,437			464,234
	End of year	17,448			35,850			500,950
	Proved undeveloped reserves:
	Beginning of year	6,171			10,768			117,550
	End of year	5,219			12,679			146,011
	2013
	Proved developed and undeveloped reserves:
	Beginning of year	21,998			35,166			555,647
	Revision of previous estimates (1)	(2,113	)		836			2,421
	Extensions and discoveries	4,678			7,273			68,611
	Infill reserves in existing proved fields	2,299			1,945			21,573
	Purchases of minerals in place	—			—			11
	Production	(3,360	)		(3,914	)		(56,757	)
	Sales	(1,737	)		(101	)		(9,722	)
	End of year	21,765			41,205			581,784
	Proved developed reserves:
	Beginning of year	16,441			25,657			452,844
	End of year	15,594			30,437			464,234
	Proved undeveloped reserves:
	Beginning of year	5,557			9,509			102,803
	End of year	6,171			10,768			117,550
	2012
	Proved developed and undeveloped reserves:
	Beginning of year	20,255			22,087			442,135
	Revision of previous estimates (1)	(1,747	)		(2,682	)		(55,110	)
	Extensions and discoveries	5,014			4,819			54,761
	Infill reserves in existing proved fields	4,196			3,018			25,057
	Purchases of minerals in place	2,830			11,098			141,494
	Production	(3,279	)		(2,796	)		(48,930	)
	Sales	(5,271	)		(378	)		(3,760	)
	End of year	21,998			35,166			555,647
	Proved developed reserves:
	Beginning of year	15,618			16,649			372,311
	End of year	16,441			25,657			452,844
	Proved undeveloped reserves:
	Beginning of year	4,637			5,438			69,824
	End of year	5,557			9,509			102,803
	_________________________
	-1	Natural gas revisions of previous estimates decreased primarily due to a decline in natural gas prices.
Standardized Measure Of Discounted Future Cash Flows Relating To Proved Reserves Disclosure [Table Text Block]	The standardized measure of discounted future net cash flows (SMOG) was calculated using 12-month average prices and year-end costs and statutory tax rates, adjusted for permanent differences that relate to existing proved oil, NGLs, and natural gas reserves. SMOG as of December 31 is as follows:
		2014				2013				2012
		(In thousands)
	Future cash flows	$	6,398,236			$	5,573,119			$	4,522,351
	Future production costs	(2,069,636		)		(1,734,985		)		(1,405,773		)
	Future development costs	(560,102		)		(571,170		)		(431,673		)
	Future income tax expenses	(1,228,533		)		(1,044,608		)		(762,519		)
	Future net cash flows	2,539,965				2,222,356				1,922,386
	10% annual discount for estimated timing of cash flows	(1,104,221		)		(996,380		)		(842,430		)
	Standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves	$	1,435,744			$	1,225,976			$	1,079,956
Schedule Of Principal Sources Of Changes In Standardized Measure Of Discounted Future Net Cash Flows [Table Text Block]	The principal sources of changes in the standardized measure of discounted future net cash flows were as follows:
		2014				2013				2012
		(In thousands)
	Sales and transfers of oil and natural gas produced, net of production costs	$	(558,252	)		$	(470,970	)		$	(425,626	)
	Net changes in prices and production costs	(33,259		)		188,826				(321,099		)
	Revisions in quantity estimates and changes in production timing	(135,125		)		(10,650		)		(148,648		)
	Extensions, discoveries, and improved recovery, less related costs	635,752				426,377				432,058
	Changes in estimated future development costs	96,339				26,629				51,587
	Previously estimated cost incurred during the period	164,430				96,457				104,377
	Purchases of minerals in place	8,395				9				283,774
	Sales of minerals in place	(19,135		)		(43,435		)		(112,359		)
	Accretion of discount	179,190				147,579				157,842
	Net change in income taxes	(98,119		)		(170,091		)		94,678
	Other—net	(30,448		)		(44,711		)		(124,537		)
	Net change	209,768				146,020				(7,953		)
	Beginning of year	1,225,976				1,079,956				1,087,909
	End of year	$	1,435,744			$	1,225,976			$	1,079,956

Summary_Of_Significant_Account3

Summary Of Significant Accounting Policies (Schedule Of Segment's Revenues) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Valero Energy Corporation | Oil and Natural Gas
Revenue, Major Customer [Line Items]
Segment's revenues	24.00%	25.00%	26.00%
Sunoco Partners Marketing | Oil and Natural Gas
Revenue, Major Customer [Line Items]
Segment's revenues	14.00%	8.00%	8.00%
QEP Resources, Inc. | Drilling
Revenue, Major Customer [Line Items]
Segment's revenues	19.00%	18.00%	15.00%
Whiting Petroleum Corp. (formerly Kodiak Oil and Gas Corp.) | Drilling
Revenue, Major Customer [Line Items]
Segment's revenues	9.00%	10.00%	10.00%
ONEOK Partners, L.P. | Mid-Stream
Revenue, Major Customer [Line Items]
Segment's revenues	44.00%	57.00%	54.00%
Tenaska Resources, LLC | Mid-Stream
Revenue, Major Customer [Line Items]
Segment's revenues	22.00%	16.00%	7.00%
Laclede Gas Company | Mid-Stream
Revenue, Major Customer [Line Items]
Segment's revenues	10.00%	2.00%	0.00%
Gavilon, LLC | Mid-Stream
Revenue, Major Customer [Line Items]
Segment's revenues	0.00%	0.00%	10.00%

Summary_Of_Significant_Account4

Summary Of Significant Accounting Policies (Schedule Of Fair Values Of The Net Assets (Liabilities)) (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Derivative Counterparty [Line Items]
Total assets	$31,100
Bank of Montreal
Derivative Counterparty [Line Items]
Total assets	27,800
Scotiabank
Derivative Counterparty [Line Items]
Total assets	$3,300

Summary_Of_Significant_Account5

Summary Of Significant Accounting Policies (Narrative) (Details) (USD $)	3 Months Ended		12 Months Ended
	Dec. 31, 2012	Jun. 30, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
			contract
			Unit
Summary Of Significant Accounting Policies [Line Items]
Number of daywork contracts			30
Number of contracts, daywork expiring in one year			26
Number of contracts, daywork expiring in two years			4
Book Overdrafts			$27,800,000	$0
Concentration of cash			18,400,000	52,100,000
Minimum depreciation percentage for idle drilling rigs			20.00%
Impairment of long-lived assets held-for-use			0	0
Interest Costs Capitalized			32,200,000	33,700,000	18,900,000
Goodwill impairment			0	0	0
Additions to goodwill			0	0	0
Goodwill deductible for tax purposes			3,100,000
Intangible asset impairment			0	0	0
Amortization on intangible assets			0	700,000	1,200,000
Accumulated amortization on intangible assets	17,300,000			18,000,000	17,300,000
Directly related overhead costs capitalized	17,600,000		23,700,000	21,500,000	17,600,000
Average rates used for depreciation, depletion, and amortization per Boe			14.82	13.32	14.7
Unproved properties not being amortized	521,659,000		485,568,000	545,588,000	521,659,000
Future discounted net cash flows discounted			10.00%
Impairment of oil and natural gas properties	167,700,000	115,900,000	76,683,000	0	283,606,000
Non-cash ceiling test write-down net of tax	104,400,000	72,100,000	47,700,000		176,500,000
Effects of cash flow hedges	29,800,000	32,500,000
Unproved properties included in amortization			73,700,000
Revenues from transactions with operating segments of same entity			89,500,000	64,300,000	49,600,000
Eliminated associated operating expense			62,400,000	46,900,000	34,100,000
Eliminated yielding			27,100,000	17,400,000	15,500,000
Number of partnerships			15
Unrecognized Tax Benefits	0		410,000	0	0	0
Minimum
Summary Of Significant Accounting Policies [Line Items]
Number of days for drilling of one well			20 days
Duration length of contracts			6 months
Insurance coverage			0
Maximum
Summary Of Significant Accounting Policies [Line Items]
Number of days for drilling of one well			90 days
Duration length of contracts			3 years
Insurance coverage			1,500,000
Under-Produced Properties [Member]
Summary Of Significant Accounting Policies [Line Items]
Natural gas balancing (MMcf)			5,100
Over-Produced Properties [Member]
Summary Of Significant Accounting Policies [Line Items]
Natural gas balancing (MMcf)			4,400
Natural Gas Balancing [Member]
Summary Of Significant Accounting Policies [Line Items]
Accounts receivable			2,000,000
Liability recognized to under production			3,600,000
Jul'12 - Dec'12 [Member]
Summary Of Significant Accounting Policies [Line Items]
Portion of future oil and gas production being hedged, as of the reporting period (MMBoe)		2.9
Jan'13 - Dec'13 [Member]
Summary Of Significant Accounting Policies [Line Items]
Portion of future oil and gas production being hedged, as of the reporting period (MMBoe)	6.9	4.5
Drilling Equipment | Minimum
Summary Of Significant Accounting Policies [Line Items]
Useful life, years			15 years
Property, Plant and Equipment, Other Types [Member] | Minimum
Summary Of Significant Accounting Policies [Line Items]
Useful life, years			3 years
Property, Plant and Equipment, Other Types [Member] | Maximum
Summary Of Significant Accounting Policies [Line Items]
Useful life, years			15 years
Drilling Equipment
Summary Of Significant Accounting Policies [Line Items]
Number of drilling rigs removed from service			31
Impairment of long-lived assets held-for-use			74,300,000
Gas Gathering and Processing Equipment
Summary Of Significant Accounting Policies [Line Items]
Impairment of long-lived assets held-for-use			$7,100,000	$0	$1,200,000
Number of gas gathering systems impaired			3

Acquisitions_and_Divestitures_1

Acquisitions and Divestitures - Fair Value of Acquired Assets and Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 17, 2012
In Thousands, unless otherwise specified
Oil and natural gas properties included in the full cost pool:
Asset retirement obligation	($100,567)	($133,657)	($146,159)
Western Oklahoma and Texas Panhandle | Noble Energy, Inc.
Adjusted 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
Unproved oil and natural gas properties				353,343
Total oil and natural gas properties included in the full cost pool				614,142	[1]
Gas gathering and processing equipment and other				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.

Acquisitions_and_Divestitures_2

Acquisitions and Divestitures - Pro Forma (Details) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2012
Pro forma:
Revenues	$1,376,393
Net income	$83,940
Net income per common share:
Basic	$1.75
Diluted	$1.74

Acquisitions_and_Divestitures_3

Acquisitions and Divestitures - Narrative (Details) (USD $)	3 Months Ended								12 Months Ended			1 Months Ended		3 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Aug. 31, 2013	Sep. 30, 2012	Dec. 31, 2012	Jul. 24, 2012	Sep. 17, 2012
					rig				rig	rig						acre
																locations
Business Combination, Description [Abstract]
Aggregate principal amount	$650,000,000								$650,000,000
Revenues	378,551,000	400,974,000	405,431,000	387,988,000	359,121,000	333,776,000	340,421,000	318,532,000	1,572,944,000	1,351,850,000	1,315,123,000
Net income	-42,551,000	67,522,000	54,360,000	56,945,000	51,301,000	34,232,000	59,007,000	40,206,000	136,276,000	184,746,000	23,176,000
Asset Divestiture [Abstract]
Proceeds from divestiture of assets									33,100,000	21,700,000
Number of rigs sold									4	5
Gain (Loss) on Disposition of Property Plant Equipment									9,600,000	16,500,000
Number of rigs held for sale					4					4
Net book value of drilling rigs sold									16,300,000
Bakken
Asset Divestiture [Abstract]
Proceeds from divestiture of assets												57,100,000	226,600,000
Brazos and Madison Counties
Asset Divestiture [Abstract]
Proceeds from divestiture of assets													44,100,000
Noble Energy, Inc.
Business Combination, Description [Abstract]
Aggregate principal amount															400,000,000
Revenues														21,400,000
Net income														-800,000
Noble Energy, Inc. | Granite Wash
Business Combination, Description [Abstract]
Land acquired (in acres)																24,000
Number of horizontal driling locations included in the land acquired																600
Noble Energy, Inc. | Other Plays
Business Combination, Description [Abstract]
Land acquired (in acres)																59,000
Acquired land with existing production capacity, percent																95.00%
Western Oklahoma and Texas Panhandle | Noble Energy, Inc.
Business Combination, Description [Abstract]
Land acquired (in acres)																83,000
Total consideration given																592,627,000
Proved developed reserves (BOE)																44,000,000
Natural gas gathering systems received as part of acquisition																4

Earnings_Per_Share_Schedule_Of

Earnings Per Share (Schedule Of Earnings Per Share) (Details) (USD $)	3 Months Ended									12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Share [Abstract]
Income of basic earnings per common share	($42,551)		$67,522	$54,360	$56,945	$51,301	$34,232	$59,007	$40,206	$136,276	$184,746	$23,176
Income of effect of dilutive stock options, restricted stock, and SARs										0	0	0
Income of diluted earnings per common share										$136,276	$184,746	$23,176
Weighted shares of basic earnings per common share										48,611	48,218	47,909
Weighted shares of effect of dilutive stock options, restricted stock, and SARs										472	354	245
Weighted shares of diluted earnings per common share										49,083	48,572	48,154
Per share amount of basic earnings per common share	($0.88)		$1.39	$1.12	$1.17	$1.06	$0.71	$1.22	$0.84	$2.80	$3.83	$0.48
Per share amount of effect of dilutive stock options, restricted stock, and SARs										($0.02)	($0.03)	$0
Per share amount of diluted earnings per common share	($0.88)	[1]	$1.37	$1.11	$1.17	$1.05	$0.70	$1.22	$0.83	$2.78	$3.80	$0.48
[1]	Due to the effect of the loss in the fourth quarter, the diluted earnings per share for the year's four quarters does not equal annual earnings per share.

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 $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Stock options and SARs
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Options and SARs	73,500	149,665	250,901
Average Exercise Price	$64.43	$58.41	$52.72

Accrued_Liabilities_Accrued_Li

Accrued Liabilities (Accrued Liabilities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Accrued Liabilities [Abstract]
Employee costs	$31,451	$27,633
Lease operating expenses	20,709	16,073
Interest Payable	6,654	6,504
Taxes	3,284	2,313
Deposits on assets held for sale	0	3,750
Derivative settlements	0	416
Other	8,073	7,674
Total accrued liabilities	$70,171	$64,363

LongTerm_Debt_And_Other_LongTe2

Long-Term Debt And Other Long-Term Liabilities (Long-Term Debt) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Long-term debt and other long-term liabilites [Abstract]
Credit agreement with an average interest rates of 2.9% at December 31, 2014	$166,000,000	$0
6.625% senior subordinated notes due 2021, net of unamortized discount of $3.8 million and $4.3 million at December 31, 2014 and 2013, respectively	646,163,000	645,696,000
Total long-term debt	812,163,000	645,696,000
Line of Credit Facility, Interest Rate at Period End	2.90%	0.00%
Debt Instrument, Unamortized Discount	$3,800,000	$4,300,000

LongTerm_Debt_And_Other_LongTe3

Long-Term Debt And Other Long-Term Liabilities (Other Long-Term Liabilities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Long-term debt and other long-term liabilites [Abstract]
ARO liability	$100,567	$133,657	$146,159
Capital lease obligations	25,876	0
Workers' compensation	17,997	20,041
Separation benefit plans	11,276	9,382
Gas balancing liability	3,623	3,775
Deferred compensation plan	4,055	3,589
Other	410	0
Other liabilities	163,804	170,444
Less current portion	15,019	12,113
Total other long-term liabilities	$148,785	$158,331

LongTerm_Debt_And_Other_LongTe4

Long-Term Debt And Other Long-Term Liabilities Long-Term Debt and Other Long-Term Liabilities (Capital Leases) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Ending December 31, [Abstract]
2015	$6,195
2016	6,195
2017	6,195
2018	6,195
2019	6,195
2020 and thereafter	9,967
Total future payments	40,942
Less payments related to:
Maintenance	11,395
Interest	3,671
Present value of future minimum payments	$25,876	$0

LongTerm_Debt_And_Other_LongTe5

Long-Term Debt And Other Long-Term Liabilities (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Credit Facility Maximum Credit Amount	$900,000,000
Commitment fee under credit facility standard	1.00%
Origination, agency and syndication fees	1,500,000
Debt Instrument, Variable Interest Rate, Payable Assessment Period	90 days
LIBOR interest rate plus one percent	LIBOR plus 1.00%
Credit agreement with an average interest rates of 2.9% at December 31, 2014	166,000,000	0
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%
Debt Instrument, Maturity Date	15-May-21
Deducting fees for debt issuance	14,700,000
Equal redemption price percentage of principal amount of debt	100.00%
Senior notes repurchase price in percentage	101.00%
Current Year	15,000,000
Year Two	204,000,000
Year Three	8,400,000
Year Four	7,200,000
Year Five	7,600,000
Number of compressors under capital lease agreement	20
Capital lease term	7 years
Capital Lease Obligations, Current	3,400,000
Capital Lease Obligations, Noncurrent	22,500,000
Discount rate capital leases	4.00%
Maintenance	11,395,000
Interest	3,671,000
Capital leases, future minimum payments, average annual payment	3,900,000
Capital lease fair market value percentage for purchase	10.00%
Minimum
Debt Instrument [Line Items]
Commitment fee percentage under credit facility	0.38%
LIBOR plus interest rate	1.75%
Maximum
Debt Instrument [Line Items]
Commitment fee percentage under credit facility	0.50%
LIBOR plus interest rate	2.50%
Payments of dividends exceeding percentage	30.00%
Senior Unsecured Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility maturity date	13-Sep-16
Line Of Credit Facility Commitment Amount [Member]
Debt Instrument [Line Items]
Credit facility current credit amount	500,000,000
Line Of Credit Facility Lender Determined Amount [Member]
Debt Instrument [Line Items]
Credit facility current credit amount	$900,000,000

Asset_Retirement_Obligations_S

Asset Retirement Obligations (Schedule Of Asset Retirement Obligations) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
ARO liability, January 1:	$133,657		$146,159
Accretion of discount	4,599		5,450
Liability incurred	6,246		4,857
Liability settled	-4,490		-4,751
Liability sold	-1,206		-2,622
Revision of estimates	-38,239	[1]	-15,436	[1]
ARO liability, December 31:	100,567		133,657
Less current portion	3,204		2,954
Total long-term ARO liability	$97,363		$130,703
[1]	Plugging liability estimates were revised in both 2014 and 2013 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.

Income_Taxes_Reconciliation_Of

Income Taxes (Reconciliation Of Income Tax Expense) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Income tax expense computed by applying the statutory rate	$78,029	$105,514	$13,791
State income tax, net of federal benefit	6,131	8,290	1,084
Statutory depletion and other	2,503	2,919	1,351
Total income taxes	$86,663	$116,723	$16,226

Income_Taxes_Schedule_Of_Total

Income Taxes (Schedule Of Total Provision For Income Taxes) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Current taxes, Federal	$8,594	$15,845	$2,084
Current taxes, State	784	146	-1,388
Current taxes	9,378	15,991	696
Deferred taxes, Federal	68,360	87,839	13,768
Deferred taxes, State	8,925	12,893	1,762
Deferred taxes	77,285	100,732	15,530
Total provision	$86,663	$116,723	$16,226

Income_Taxes_Schedule_Of_Defer

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Income Tax Disclosure [Abstract]
Allowance for losses and nondeductible accruals	$55,231	$77,285
Net operating loss carryforward	54,901	61,055
Alternative minimum tax and research and development tax credit carryforward	25,991	17,258
Deferred tax assets, total	136,123	155,598
Depreciation, depletion, amortization, and impairment	-1,000,811	-943,411
Net deferred tax liability	-864,688	-787,813
Current deferred tax asset	11,527	13,585
Non-current-deferred tax liability	($876,215)	($801,398)

Income_Taxes_Income_Taxes_Sche

Income Taxes Income Taxes (Schedule of Unrecognized Tax Benefits) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Balance at January 1:	$0	$0	$0
Additions based on tax positions related to current year	410	0	0
Additions for tax positions of prior years	0	0	0
Reductions for tax positions of prior years	0	0	0
Settlements	0	0	0
Balance at December 31:	$410	$0	$0

Income_Taxes_Narrative_Details

Income Taxes (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	128,000,000
Unrecognized Tax Benefits	410,000	$0	$0	$0
Start
Operating Loss Carryforwards [Line Items]
Operating loss expiration period	31-Dec-20
End
Operating Loss Carryforwards [Line Items]
Operating loss expiration period	31-Dec-34

Employee_Benefit_Plans_Details

Employee Benefit Plans (Details) (USD $)	12 Months Ended			0 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jan. 01, 1997	5-May-04
Defined Benefit Plan Disclosure [Line Items]
Recognized stock compensation expense	$17.40	$16.10	$11.40
Separation benefit plans expense	2.7	2.4	2.2
Employment contract period extension, years	1 year
Grace period following the first anniversary	30 days
Employee Thrift Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Contribution of shares, common stock	120,333	111,995	95,598
Recognized stock compensation expense	5.2	6	5.5
Salary Deferral Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Liability recorded under deferral plan	$4.10	$3.60
Separation Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service period, years				20 years
Maximum period benefit, weeks				104
Special Separation Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service period, years					20 years
Age limit					65
Change Of Control Contracts [Member]
Defined Benefit Plan Disclosure [Line Items]
Employee contract period, years	3
Multiple for determination compensation	2.9
Plan 401k [Member]
Defined Benefit Plan Disclosure [Line Items]
Additional period for 401k, years	3 years

Transactions_With_Related_Part2

Transactions With Related Parties Transactions With Related Parties (Schedule of Amount Received in Public and Private Partnerships) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Related Party Transaction [Line Items]
Contract drilling	$4	$16	$246
Well supervision and other fees	435	470	434
General and administrative expense reimbursement	$39	$36	$39

Transactions_With_Related_Part3

Transactions With Related Parties (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Related Party Transaction [Line Items]
Number of oil and gas limited partnerships	15
Number of oil and gas limited partnerships for third party investment	2
Number of oil and gas limited partnerships for employee investment	13
Minimum
Related Party Transaction [Line Items]
Interest rate of employee partnerships in oil and gas properties	1.00%
Maximum
Related Party Transaction [Line Items]
Interest rate of employee partnerships in oil and gas properties	15.00%
John Nikkel
Related Party Transaction [Line Items]
Related party ownership percentage in Toklan	0.065
Number of wells drilled	2	0	0
Revenue from related parties	$1,100,000	$0	$0
Related party accounts receivable balance	400,000	0	0
Payments for royalties	200,000	0	0
Robert Nikkel
Related Party Transaction [Line Items]
Related party ownership percentage in Toklan	0.353
G. Bailey Peyton IV
Related Party Transaction [Line Items]
Number of wells drilled	0	0	3
Revenue from related parties	0	0	1,600,000
Payments for royalties	$1,300,000	$1,400,000	$1,200,000

Shareholder_Rights_Plan_Detail

Shareholder Rights Plan (Details) (USD $)	12 Months Ended
	Dec. 31, 2014
Shareholder Rights Plan [Abstract]
Right of common stock	one
Percentage of fair value of common stock that can be acquired	50.00%
Rights become exercisable period, in days	10 days
Minimum percentage of common stock that should be acquired	15.00%
Redemption price per share	$0.01
Shareholder rights plan expiration date	19-May-15

StockBased_Compensation_Schedu

Stock-Based Compensation (Schedule Of Restricted Stock Awards Stock Options And SAR) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Recognized stock compensation expense	$17.40	$16.10	$11.40
Capitalized stock compensation cost for our oil and natural gas properties	3.7	3.5	2.7
Tax benefit on stock based compensation	$6.70	$6.20	$4.50

StockBased_Compensation_StockB

Stock-Based Compensation Stock-Based Compensation (Activity Pertaining to Stock Appreciation Rights) (Details) (Stock Appreciation Rights (SARs), USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Stock Appreciation Rights (SARs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	145,901	145,901	145,901
Weighted average price, beginning balance	$46.59	$46.59	$46.59
Number of shares, granted	0	0	0
Weighted average price, granted	$0	$0	$0
Number of shares, exercised	-14,131	0	0
Weighted average price, exercised	$46.50	$0	$0
Number of shares, forfeited	0	0	0
Weighted average price, forfeited	$0	$0	$0
Number of shares, ending balance	131,770	145,901	145,901
Weighted average price, ending balance	$46.60	$46.59	$46.59

StockBased_Compensation_StockB1

Stock-Based Compensation Stock-Based Compensation (Shares Authorized Under Stock Appreciation Rights By Exercise Price) (Details) (Stock Appreciation Rights (SARs), USD $)	12 Months Ended
	Dec. 31, 2014
$44.31
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding and exercisable options, number of shares	91,255
Outstanding and exercisable options weighted average remaining contractual life, years	3 years
Outstanding and exercisable options, weighted average exercise price	$44.31
$51.76
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding and exercisable options, number of shares	40,515
Outstanding and exercisable options weighted average remaining contractual life, years	1 year 10 months 24 days
Outstanding and exercisable options, weighted average exercise price	$51.76

StockBased_Compensation_Activi

Stock-Based Compensation (Activity Pertaining To Restricted Stock Awards) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted Stock - Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	776,743	589,527	447,961
Weighted average price, beginning balance	$48.70	$48.11	$47.44
Number of shares, granted	455,122	453,549	376,445
Weighted average price, granted	$53.72	$48.20	$47.37
Number of Shares, Vested	-304,804	-248,003	-220,788
Weighted average price, exercised	$49.68	$46.46	$45.66
Number of shares, forfeited	-26,775	-18,330	-14,091
Weighted average price, forfeited	$51.92	$47.85	$45.37
Number of shares, ending balance	900,286	776,743	589,527
Weighted average price, ending balance	$50.81	$48.70	$48.11
Non-employee Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	35,704	24,606	0
Weighted average price, beginning balance	$41.07	$40.23	$0
Number of shares, granted	13,768	21,128	24,606
Weighted average price, granted	$63.91	$41.65	$40.23
Number of Shares, Vested	-14,336	-10,030	0
Weighted average price, exercised	$40.93	$40.23	$0
Number of shares, forfeited	0	0	0
Weighted average price, forfeited	$0	$0	$0
Number of shares, ending balance	35,136	35,704	24,606
Weighted average price, ending balance	$50.08	$41.07	$40.23

StockBased_Compensation_StockB2

Stock-Based Compensation Stock-Based Compensation (Activity Pertaining to Stock Options) (Details) (Stock Options, USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	68,920	118,030	138,980
Weighted average price, beginning balance	$37.81	$33.03	$31.39
Number of shares, granted	0	0	0
Weighted average price, granted	$0	$0	$0
Number of shares, exercised	-21,490	-48,110	-18,850
Weighted average price, exercised	$37.83	$26.09	$20.38
Number of shares, forfeited	-37,930	-1,000	-2,100
Weighted average price, forfeited	$37.83	$37.83	$37.83
Number of shares, ending balance	9,500	68,920	118,030
Weighted average price, ending balance	$37.69	$37.81	$33.03

StockBased_Compensation_Shares

Stock-Based Compensation (Shares Authorized Under Stock Option Plans By Exercise Price Range) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014
Stock Options | $37.69
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Outstanding and exercisable options, number of shares	9,500
Outstanding and exercisable options weighted average remaining contractual life, years	4 months 24 days
Outstanding and exercisable options, weighted average exercise price	$37.69
Directors Plan | $31.30 - $41.21
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Minimum Limit	$31.30
Maximum limit	$41.21
Outstanding and exercisable options, number of shares	45,500
Outstanding and exercisable options weighted average remaining contractual life, years	4 years 2 months 12 days
Outstanding and exercisable options, weighted average exercise price	$37.88
Directors Plan | $53.81 - $73.26
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Minimum Limit	$53.81
Maximum limit	$73.26
Outstanding and exercisable options, number of shares	105,000
Outstanding and exercisable options weighted average remaining contractual life, years	3 years 6 months
Outstanding and exercisable options, weighted average exercise price	$61.24

StockBased_Compensation_StockB3

Stock-Based Compensation Stock-Based Compensation (Activity Pertaining to Nonemployee Director Stock Award Plan) (Details) (Directors Plan, USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Directors Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, beginning balance	171,500	192,500	199,500
Weighted average price, beginning balance	$51.70	$49.39	$48.37
Number of shares, granted	0	0	0
Weighted average price, granted	$0	$0	$0
Number of shares, exercised	-21,000	-17,500	-7,000
Weighted average price, exercised	$33.94	$32.53	$20.28
Number of shares, forfeited	0	-3,500	0
Weighted average price, forfeited	$0	$20.46	$0
Number of shares, ending balance	150,500	171,500	192,500
Weighted average price, ending balance	$54.18	$51.70	$49.39

StockBased_Compensation_Narrat

Stock-Based Compensation (Narrative) (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to unvested awards	$17.40
Unrecognized compensation cost, expect to be capitalized	2.7
Weighted average years over which this cost will be recognized	0 years 9 months 18 days
Maximum number of shares of common stock allowed for the issuance	3,300,000
Incentive Stock Grants
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum number of shares of common stock allowed for the issuance	2,000,000
Stock Appreciation Rights (SARs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, granted	0	0	0
Expire years	10 years
Shares vested	0	0	0
Number of shares, ending balance	131,770	145,901	145,901	145,901
Exercisable options intrinsic value	0
Weighted average remaining contractual term, years	2 years 7 months 6 days
Exercised intrinsic value	0.2
Cash received from the options exercised	0
Weighted average price, ending balance	$46.60	$46.59	$46.59	$46.59
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares, ending balance	935,422
Exercisable options intrinsic value	31.9
Percentage of restricted stock awards to be vested as performance shares to executives	40.00%	30.00%	30.00%
Grant date fair value	24.1	21.3	16.9
Number of Shares, Vested	-319,140
Exercised intrinsic value	20.2
Restricted stock weighted average remaining contractual term, years	8 months 12 days
Restricted Stock | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period	2 years
Performance percentage criteria	0.00%
Restricted Stock | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period	3 years
Performance percentage criteria	150.00%
Restricted Stock | First Half of 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted stock awards granted to designated executive officers	71,674
Restricted Stock | First Half of 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted stock awards granted to designated executive officers		57,405
Restricted Stock | First Half of 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted stock awards granted to designated executive officers			46,441
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expire years	10 years
Shares vested	0	0	0
Weighted average remaining contractual term, years	4 months 24 days
Exercised intrinsic value	0.4
Maximum Number of Shares of Common Stock Previously Allowed for the Issuance	2,700,000
Vesting rate of options	20.00%
Cash received from the options exercised	0.4
Options Outstanding	9,500	68,920	118,030	138,980
Weighted average price, ending balance	$37.69	$37.81	$33.03	$31.39
Exercisable options intrinsic value	0
Options granted	0	0	0
Number of shares, exercised	-21,490	-48,110	-18,850
Directors Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expire years	10 years
Exercisable options intrinsic value	0
Weighted average remaining contractual term, years	3 years 8 months 12 days
Vesting Period	0 years 6 months
Exercised intrinsic value	0.6
Cash received from the options exercised	$0.70
Options Outstanding	150,500	171,500	192,500	199,500
Weighted average price, ending balance	$54.18	$51.70	$49.39	$48.37
Director option awards	3,500
Options granted	0	0	0
Number of shares, exercised	-21,000	-17,500	-7,000
2014 | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	100.00%
2013 | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	100.00%
2012 | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance percentage criteria	100.00%

Derivatives_Derivatives_Schedu

Derivatives Derivatives (Schedule of Non-designated Hedges Outstanding) (Details)	12 Months Ended
	Dec. 31, 2014
	MMBTU
	Unit
Natural Gas | Swap | If Nymex | Jan'15 - Dec'15
Derivative Instruments, Gain (Loss) [Line Items]
Non Designated Derivative Instrument Weighted Average Fixed Price For Swaps	3.98
Hedged Volume (MMBtu/day)	40,000
Natural Gas | Collar | If Nymex | Jan'15 - Mar'15
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (MMBtu/day)	30,000
Crude Oil | Swap | Wti Nymex | Jan'15 - Dec'15
Derivative Instruments, Gain (Loss) [Line Items]
Non Designated Derivative Instrument Weighted Average Fixed Price For Swaps	95
Hedged Volume (Bbl/day)	1,000
Minimum | Natural Gas | Swap | If Nymex | Jan'15 - Dec'15
Derivative Instruments, Gain (Loss) [Line Items]
Commodity Derivatives Description Terms	Jan'15
Minimum | Natural Gas | Collar | If Nymex | Jan'15 - Mar'15
Derivative Instruments, Gain (Loss) [Line Items]
Non Designated Derivative Instrument Weighted Average Fixed Price For Swaps	4.2
Commodity Derivatives Description Terms	Jan'15
Minimum | Crude Oil | Swap | Wti Nymex | Jan'15 - Dec'15
Derivative Instruments, Gain (Loss) [Line Items]
Commodity Derivatives Description Terms	Jan'15
Maximum | Natural Gas | Swap | If Nymex | Jan'15 - Dec'15
Derivative Instruments, Gain (Loss) [Line Items]
Commodity Derivatives Description Terms	Dec'15
Maximum | Natural Gas | Collar | If Nymex | Jan'15 - Mar'15
Derivative Instruments, Gain (Loss) [Line Items]
Non Designated Derivative Instrument Weighted Average Fixed Price For Swaps	5.03
Commodity Derivatives Description Terms	Mar'15
Maximum | Crude Oil | Swap | Wti Nymex | Jan'15 - Dec'15
Derivative Instruments, Gain (Loss) [Line Items]
Commodity Derivatives Description Terms	Dec'15

Derivatives_Schedule_Of_Subseq

Derivatives (Schedule Of Subsequent Non-designated Hedges) (Details) (Subsequent to December 31, 2014, Natural Gas, If Nymex)	2 Months Ended
	Feb. 24, 2015
	MMBTU
	Unit
Apr'15 - Jun'15 | Swap
Derivative Instruments, Gain (Loss) [Line Items]
Non Designated Derivative Instrument Weighted Average Fixed Price For Swaps	3.1
Hedged Volume (MMBtu/day)	30,000
Apr'15 - Jun'15 | Collar
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (MMBtu/day)	30,000
Jul'15 - Sep'15 | Collar
Derivative Instruments, Gain (Loss) [Line Items]
Hedged Volume (MMBtu/day)	30,000
Start | Apr'15 - Jun'15 | Swap
Derivative Instruments, Gain (Loss) [Line Items]
Commodity Derivatives Term	Apr'15
Start | Apr'15 - Jun'15 | Collar
Derivative Instruments, Gain (Loss) [Line Items]
Non Designated Derivative Instrument Weighted Average Fixed Price For Swaps	2.92
Commodity Derivatives Term	Apr'15
Start | Jul'15 - Sep'15 | Collar
Derivative Instruments, Gain (Loss) [Line Items]
Non Designated Derivative Instrument Weighted Average Fixed Price For Swaps	2.58
Commodity Derivatives Term	Jul'15
End | Apr'15 - Jun'15 | Swap
Derivative Instruments, Gain (Loss) [Line Items]
Commodity Derivatives Term	Jun'15
End | Apr'15 - Jun'15 | Collar
Derivative Instruments, Gain (Loss) [Line Items]
Non Designated Derivative Instrument Weighted Average Fixed Price For Swaps	3.26
Commodity Derivatives Term	Jun'15
End | Jul'15 - Sep'15 | Collar
Derivative Instruments, Gain (Loss) [Line Items]
Non Designated Derivative Instrument Weighted Average Fixed Price For Swaps	3.04
Commodity Derivatives Term	Sep'15

Derivatives_Fair_Value_Of_Deri

Derivatives (Fair Value Of Derivative Instruments And Locations In Balance Sheets) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivatives, Fair Value [Line Items]
Current derivative assets	$31,139	$515
Total derivatives assets	31,139	515
Current derivative liabilities	0	5,561
Total derivative liabilities	0	5,561
Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Current derivative assets	31,139	515
Non-current derivative assets	0	0
Current derivative liabilities	0	5,561
Non-current derivative liabilities	$0	$0

Derivatives_Gain_Or_Loss_Of_Re

Derivatives (Gain Or Loss Of Reclassified Accumulated Other Comprehensive Income And Recognized Income) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	$0		$0
Commodity Contract
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income	0		603
Amount of Gain or (Loss) Recognized in Income	0		-190
Commodity Contract | Oil and natural gas revenue
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income	0	[1]	603	[1]	51,853
Commodity Contract | Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) Recognized in Income	$0	[2]	($190)	[2]	($2,616)
[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 $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain or (loss) recognized in income on derivative	$30,147		($8,184)
Loss on derivatives not designated as hedging instruments, amount settled during period	-6,038		-1,764
Commodity Contract
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain or (loss) recognized in income on derivative	$30,147	[1]	($8,184)	[1]
[1]	Amount settled during the period is a loss of $6,038 and $1,764, respectively.

Derivatives_Narrative_Details

Derivatives (Narrative) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Accumulated OCI gain net of tax	$0	$0

Fair_Value_Measurements_Recurr

Fair Value Measurements (Recurring Fair Value Measurements) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financial assets (liabilities)	$31,100
Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	31,139	515
Liabilities	0	-5,561
Financial assets (liabilities)	31,139	-5,046
Commodity Contract | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	27,784	1,978
Liabilities	0	-4,429
Financial assets (liabilities)	27,784	-2,451
Commodity Contract | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	3,355	20
Liabilities	0	-2,615
Financial assets (liabilities)	3,355	-2,595
Commodity Contract | Effect of Netting
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	0	-1,483
Liabilities	0	1,483
Financial assets (liabilities)	$0	$0

Fair_Value_Measurements_Reconc

Fair Value Measurements (Reconciliations Of Level 3 Fair Value Measurements) (Details) (Collar, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Collar
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Beginning of period	($2,595)		($595)
Included in earnings	6,108	[1]	-2,637	[1]
Included in other comprehensive income (loss)	0		0
Settlements	-158		637
End of period	3,355		-2,595
Total gains (losses) for the period included in earnings attributable to the change in unrealized gain relating to assets still held at end of period	$5,950		($2,000)
[1]	Commodity sales collars are reported in the consolidated statements of income in oil and gas revenues (for cash flow hedges), and gain (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) (Natural Gas, Level 3, Collar, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014
Derivative assets, Fair Value	$3,355	[1]
Derivatives assets, Valuation Technique(s)	DiscountedB cashB flow	[1]
Unobservable Input	ForwardB commodityB priceB curve	[1]
Minimum
Derivative, Forward Price	0
Maximum
Derivative, Forward Price	1.32
[1]	The commodity contracts detailed in this category include non-exchange-traded natural gas collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be received within the settlement period.

Fair_Value_Measurements_Narrat

Fair Value Measurements (Narrative) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Option, Qualitative Disclosures Related to Election [Line Items]
Collateral Already Posted, Aggregate Fair Value	$0
6.625% senior subordinated notes due 2021, net of unamortized discount of $3.8 million and $4.3 million at December 31, 2014 and 2013, respectively	646,163,000	645,696,000
Estimated fair value of long-term debt	$605,500,000	$688,200,000

Accumulated_Other_Comprehensiv2

Accumulated Other Comprehensive Income (Changes in accumulated other comprehensive income) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Balance at January 1:	$0	$7,587	$19,026
Other comprehensive income before reclassification	0	-7,349	18,635
Amounts reclassified from accumulated other comprehensive income	0	-238	-30,074
New current-period other comprehensive income		-7,587	-11,439
Balance at December 31:	$0	$0	$7,587

Accumulated_Other_Comprehensiv3

Accumulated Other Comprehensive Income (Schedule of accumulated other comprehensive income (loss)) (Details) (Commodity Contract, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Amounts reclassified from accumulated other comprehensive income	$0		$603
Derivative Instruments, Gain (Loss) Recognized in Income	0		-190
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax	0		413		49,237
Tax expense	0		-175		-19,163
Total reclassification for the period	0		238		30,074
Oil and natural gas revenue
Amounts reclassified from accumulated other comprehensive income	0	[1]	603	[1]	51,853
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness
Derivative Instruments, Gain (Loss) Recognized in Income	$0	[2]	($190)	[2]	($2,616)
[1]	Effective portion of gain (loss).
[2]	Ineffective portion of gain (loss).

Commitments_And_Contingencies_

Commitments And Contingencies (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Other Commitments [Line Items]
Lease expiration date	31-Jul-19
Future minimum rental payments under leases, year one	$6,800,000
Future minimum rental payments under leases, year two	2,700,000
Future minimum rental payments under leases, year three	200,000
Future minimum rental payments under leases, year four	41,000
Rent expense incurred	13,600,000	16,900,000	14,000,000
Number of compressors under capital lease agreement	20
Capital lease term	7 years
2015	6,195,000
2016	6,195,000
2017	6,195,000
2018	6,195,000
2019	6,195,000
2020 and thereafter	9,967,000
Maintenance	11,395,000
Interest	3,671,000
Capital leases, future minimum payments, average annual payment	3,900,000
Capital lease fair market value percentage for purchase	10.00%
Repurchase of limited units outstanding	20.00%
Repurchase of limited units outstanding amount	45,000	16,000	56,000
Drilling Equipment
Other Commitments [Line Items]
Other Commitment, Due in Next Twelve Months	22,300,000
Other Commitment, Due in Second Year	3,800,000
Corporate, Non-Segment
Other Commitments [Line Items]
Other Commitment, Due in Next Twelve Months	1,400,000
Other Commitment, Due in Second Year	500,000
Gas Gathering and Processing Equipment
Other Commitments [Line Items]
Other Commitment, Due in Next Twelve Months	$200,000

Industry_Segment_Information_R

Industry Segment Information (Revenue From Different Segments) (Details) (USD $)	3 Months Ended													12 Months Ended
	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012		Jun. 30, 2012	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Revenues
Oil and natural gas														$740,079,000		$649,718,000		$567,944,000
Contract drilling														566,012,000		479,091,000		579,368,000
Elimination of inter-segment revenue														-89,495,000		-64,313,000		-49,649,000
Contract drilling net of inter-segment revenue														476,517,000		414,778,000		529,719,000
Gas gathering and processing														445,934,000		378,397,000		290,773,000
Elimination of inter-segment revenue														-89,586,000		-91,043,000		-73,313,000
Gas gathering and processing net of inter-segment revenue														356,348,000		287,354,000		217,460,000
Total revenues	378,551,000		400,974,000	405,431,000	387,988,000	359,121,000		333,776,000	340,421,000	318,532,000				1,572,944,000		1,351,850,000		1,315,123,000
Operating Income:
Oil and natural gas														199,392,000	[1]	239,219,000		-77,221,000	[1]
Contract drilling														41,896,000	[2]	96,304,000		159,188,000
Gas gathering and processing														2,015,000	[3]	10,757,000		5,780,000	[3]
Total operating income														243,303,000	[4]	346,280,000	[4]	87,747,000	[4]
General and administrative														-42,023,000		-38,323,000		-33,086,000
Gain on disposition of assets														8,953,000		17,076,000		253,000
Interest expense, net														-17,371,000		-15,015,000		-14,137,000
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net														30,147,000		-8,374,000		-1,243,000
Other														-70,000		-175,000		-132,000
Income before income taxes														222,939,000		301,469,000		39,402,000
Identifiable assets:
Oil and natural gas	2,856,833,000					2,441,792,000					2,214,029,000			2,856,833,000		2,441,792,000		2,214,029,000
Contract drilling	1,059,980,000					1,042,661,000					1,079,736,000			1,059,980,000		1,042,661,000		1,079,736,000
Gas gathering and processing	500,255,000					473,717,000					413,708,000			500,255,000		473,717,000		413,708,000
Total identifiable assets	4,417,068,000	[5]				3,958,170,000	[5]				3,707,473,000	[5]		4,417,068,000	[5]	3,958,170,000	[5]	3,707,473,000	[5]
Corporate assets	56,660,000					64,220,000					53,647,000			56,660,000		64,220,000		53,647,000
Total assets	4,473,728,000					4,022,390,000					3,761,120,000			4,473,728,000		4,022,390,000		3,761,120,000
Capital expenditures:
Oil and natural gas														740,262,000	[6]	531,233,000	[6]	1,145,337,000	[6]
Contract drilling														176,683,000		64,325,000		77,520,000
Gas gathering and processing														79,268,000	[7]	96,085,000		183,162,000
Other														17,067,000	[6]	4,483,000	[6]	11,083,000	[6]
Total capital expenditures														1,013,280,000		696,126,000		1,417,102,000
Depreciation, depletion, amortization, and impairment
Oil and natural gas depreciation, depletion, and amortization														276,088,000		226,498,000		211,347,000
Impairment of oil and natural gas properties											167,700,000		115,900,000	76,683,000		0		283,606,000
Contract drilling														159,688,000		71,194,000		81,007,000
Gas Gathering Transportation Marketing And Processing Depreciation, Amortization, and Impairment														47,502,000		33,191,000		24,388,000
Reclassified salt water disposal expenditures																		17,000,000
Capital Lease Obligations Incurred														28,200,000
Non-cash ceiling test write-down net of tax											104,400,000		72,100,000	47,700,000				176,500,000
Impairment of long-lived assets held-for-use														0		0
Drilling Equipment
Depreciation, depletion, amortization, and impairment
Impairment of long-lived assets held-for-use														74,300,000
Number of drilling rigs removed from service														31
Gas Gathering and Processing Equipment
Depreciation, depletion, amortization, and impairment
Impairment of long-lived assets held-for-use														7,100,000		0		1,200,000
Number of gas gathering systems impaired														3
Operating Segments [Member]
Depreciation, depletion, amortization, and impairment
Oil and natural gas depreciation, depletion, and amortization														276,088,000		226,498,000		211,347,000
Impairment of oil and natural gas properties														76,683,000	[1]	0		283,606,000	[1]
Contract drilling														159,688,000	[2]	71,194,000		81,007,000
Gas Gathering Transportation Marketing And Processing Depreciation, Amortization, and Impairment														47,502,000	[3]	33,191,000		24,388,000	[3]
Other														3,051,000		3,024,000		2,279,000
Total depreciation, depletion, amortization and impairment														$563,012,000		$333,907,000		$602,627,000
[1]	In 2014 and 2012, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $76.7 million and $283.6 million pre-tax ($47.7 million and $176.5 million, net of tax), respectively.
[2]	Depreciation, depletion, amortization, and impairment for contract drilling includes a $74.3 million pre-tax write-down for 31 drilling rigs, some older top drives, and certain drill pipe removed from service.
[3]	Depreciation, depletion, amortization, and impairment for gas gathering and processing for 2014 includes a $7.1 million pre-tax write-down for three of our systems, Weatherford, Billy Rose, and Spring Creek and for 2012 includes a $1.2 million write-down of our Erick system.
[4]	Operating income is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, (gain) loss on disposition of assets, gain (loss) on non-designated hedges and hedge ineffectiveness, interest expense, other income (loss), or income taxes.
[5]	Identifiable assets are those used in Unitbs operations in each industry segment. Corporate assets are principally cash and cash equivalents, short-term investments, corporate leasehold improvements, furniture and equipment.
[6]	In 2013, we reclassified salt water disposal capital expenditures out of other and into oil and natural gas of $17.0 million for 2012.
[7]	In 2014, we entered into capital leases for $28.2 million.

Selected_Quarterly_Financial_I2

Selected Quarterly Financial Information (Details) (USD $)	3 Months Ended																12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Selected Quarterly Financial Information [Abstract]
Revenues	$378,551		$400,974		$405,431		$387,988		$359,121		$333,776		$340,421		$318,532		$1,572,944	$1,351,850	$1,315,123
Gross profit (loss)	-89,796	[1]	103,983	[1]	113,973	[1]	115,143	[1]	92,692	[1]	79,082	[1]	90,823	[1]	83,683	[1]
Net income	($42,551)		$67,522		$54,360		$56,945		$51,301		$34,232		$59,007		$40,206		$136,276	$184,746	$23,176
Net income (loss) per common share:
Basic	($0.88)		$1.39		$1.12		$1.17		$1.06		$0.71		$1.22		$0.84		$2.80	$3.83	$0.48
Diluted	($0.88)	[2]	$1.37		$1.11		$1.17		$1.05		$0.70		$1.22		$0.83		$2.78	$3.80	$0.48
[1]	Gross profit excludes general and administrative expense, interest expense, (gain) loss on disposition of assets, gain (loss) on non-designated hedges and hedge ineffectiveness, income taxes, and other income (loss).
[2]	Due to the effect of the loss in the fourth quarter, the diluted earnings per share for the year's four quarters does not equal annual earnings per share.

Supplemental_Oil_And_Gas_Discl2

Supplemental Oil And Gas Disclosures (Schedule Of Capitalized Costs And Costs Incurred On Oil And Gas Properties) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Capitalized costs:
Proved properties	$4,990,753	$4,235,712	$3,822,381
Unproved properties not being amortized	485,568	545,588	521,659
Capitalized costs gross	5,476,321	4,781,300	4,344,040
Accumulated depreciation, depletion, amortization, and impairment	-2,786,678	-2,439,458	-2,216,787
Net capitalized costs	2,689,643	2,341,842	2,127,253
Costs incurred:
Unproved properties acquired	76,041	76,304	420,467
Proved properties acquired	5,723	0	225,669
Exploration	68,811	33,373	46,467
Development	615,252	424,314	390,649
Asset retirement obligation	-37,687	-17,951	45,097
Total costs incurred	$728,140	$516,040	$1,128,349

Supplemental_Oil_And_Gas_Discl3

Supplemental Oil And Gas Disclosures (Schedule Of The Oil And Natural Gas Property Costs Not Being Amortized) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Unproved properties acquired and wells in progress	$485,568	$545,588	$521,659
2014
Unproved properties acquired and wells in progress	102,930
2013 [Member]
Unproved properties acquired and wells in progress	64,795
2012 [Member]
Unproved properties acquired and wells in progress	310,891
2011 and prior [Member]
Unproved properties acquired and wells in progress	$6,952

Supplemental_Oil_And_Gas_Discl4

Supplemental Oil And Gas Disclosures (Results Of Operations For Producing Activities) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Supplemental Oil and Gas Disclosures [Abstract]
Revenues	$723,566	$633,792	$557,003
Production costs	-165,315	-162,822	-131,389
Depreciation, depletion, amortization, and impairment	-347,220	-222,672	-492,475
Results of operations, income before income taxes	211,031	248,298	-66,861
Income tax (expense) benefit	-82,028	-96,091	27,533
Results of operations for producing activities (excluding corporate overhead and financing costs)	$129,003	$152,207	($39,328)

Supplemental_Oil_And_Gas_Discl5

Supplemental Oil And Gas Disclosures (Schedule Of Proved Developed And Undeveloped Oil And Gas Reserve Quantities) (Details)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
	bbl		bbl		bbl
Oil (bbls)
Proved developed and undeveloped reserves:
Beginning of year	21,765,000		21,998,000		20,255,000
Revision of previous estimates	-3,174,000	[1]	-2,113,000	[1]	-1,747,000	[1]
Extensions and discoveries	5,327,000		4,678,000		5,014,000
Infill reserves in existing proved fields	2,775,000		2,299,000		4,196,000
Purchases of minerals in place	236,000		0		2,830,000
Production	-3,844,000		-3,360,000		-3,279,000
Sales	-418,000		-1,737,000		-5,271,000
End of year	22,667,000		21,765,000		21,998,000
Proved developed reserves:
Beginning of year	15,594,000		16,441,000		15,618,000
End of year	17,448,000		15,594,000		16,441,000
Proved undeveloped reserves
Beginning of year	6,171,000		5,557,000		4,637,000
End of year	5,219,000		6,171,000		5,557,000
Natural Gas Liquids (bbls)
Proved developed and undeveloped reserves:
Beginning of year	41,205,000		35,166,000		22,087,000
Revision of previous estimates	-2,266,000	[1]	836,000	[1]	-2,682,000	[1]
Extensions and discoveries	10,850,000		7,273,000		4,819,000
Infill reserves in existing proved fields	3,577,000		1,945,000		3,018,000
Purchases of minerals in place	88,000		0		11,098,000
Production	-4,629,000		-3,914,000		-2,796,000
Sales	-296,000		-101,000		-378,000
End of year	48,529,000		41,205,000		35,166,000
Proved developed reserves:
Beginning of year	30,437,000		25,657,000		16,649,000
End of year	35,850,000		30,437,000		25,657,000
Proved undeveloped reserves
Beginning of year	10,768,000		9,509,000		5,438,000
End of year	12,679,000		10,768,000		9,509,000
Natural Gas (Mcf)
Proved developed and undeveloped reserves:
Beginning of year	581,784,000		555,647,000		442,135,000
Revision of previous estimates	-32,790,000	[1]	2,421,000	[1]	-55,110,000	[1]
Extensions and discoveries	113,541,000		68,611,000		54,761,000
Infill reserves in existing proved fields	47,189,000		21,573,000		25,057,000
Purchases of minerals in place	368,000		11,000		141,494,000
Production	-58,854,000		-56,757,000		-48,930,000
Sales	-4,277,000		-9,722,000		-3,760,000
End of year	646,961,000		581,784,000		555,647,000
Proved developed reserves:
Beginning of year	464,234,000		452,844,000		372,311,000
End of year	500,950,000		464,234,000		452,844,000
Proved undeveloped reserves
Beginning of year	117,550,000		102,803,000		69,824,000
End of year	146,011,000		117,550,000		102,803,000
[1]	Natural gas revisions of previous estimates decreased primarily due to a decline in natural gas prices.

Supplemental_Oil_And_Gas_Discl6

Supplemental Oil And Gas Disclosures (Standardized Measure Of Discounted Future Cash Flows Relating To Proved Reserves Disclosure) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Supplemental Oil and Gas Disclosures [Abstract]
Future cash flows	$6,398,236	$5,573,119	$4,522,351
Future production costs	-2,069,636	-1,734,985	-1,405,773
Future development costs	-560,102	-571,170	-431,673
Future income tax expenses	-1,228,533	-1,044,608	-762,519
Future net cash flows	2,539,965	2,222,356	1,922,386
10% annual discount for estimated timing of cash flows	-1,104,221	-996,380	-842,430
Standardized measure of discounted future net cash flows relating to proved oil, NGLs and natural gas reserves	$1,435,744	$1,225,976	$1,079,956	$1,087,909
Percentage of annual discount for estimated timing of cash flows	10.00%	10.00%	10.00%

Supplemental_Oil_And_Gas_Discl7

Supplemental Oil And Gas Disclosures (Schedule Of Principal Sources Of Changes In Standardized Measure Of Discounted Future Net Cash Flows) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Reserve Quantities [Line Items]
Sales and transfers of oil and natural gas produced, net of production costs	($558,252)	($470,970)	($425,626)
Net changes in prices and production costs	-33,259	188,826	-321,099
Revisions in quantity estimates and changes in production timing	-135,125	-10,650	-148,648
Extensions, discoveries, and improved recovery, less related costs	635,752	426,377	432,058
Changes in estimated future development costs	96,339	26,629	51,587
Previously estimated cost incurred during the period	164,430	96,457	104,377
Purchases of minerals in place	8,395	9	283,774
Sales of minerals in place	-19,135	-43,435	-112,359
Accretion of discount	179,190	147,579	157,842
Net change in income taxes	-98,119	-170,091	94,678
Other-net	-30,448	-44,711	-124,537
Net change	209,768	146,020	-7,953
Beginning of year	1,225,976	1,079,956	1,087,909
End of year	$1,435,744	$1,225,976	$1,079,956

Supplemental_Oil_And_Gas_Discl8

Supplemental Oil And Gas Disclosures Supplemental Oil and Gas Disclosures (Narrative) (Details)	12 Months Ended
	Dec. 31, 2014
Oil (bbls)
Average Sales Prices	94.99
Natural Gas Liquids (bbls)
Average Sales Prices	45.25
Natural Gas (Mcf)
Average Sales Prices	4.36

Schedule_II_Valuation_And_Qual1

Schedule II - Valuation And Qualifying Accounts And Reserves (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Valuation and Qualifying Accounts [Abstract]
Balance at Beginning of Period	$5,342	$5,343	$5,343
Additions Charged to Costs And Expenses	3,562	0	90
Deductions And Net Write-Offs	-3,865	-1	-90
Balance at End of Period	$5,039	$5,342	$5,343